HP_2013_04

PETROCHEMICAL DEVELOPMENTS

速

HydrocarbonProcessing.com | APRIL 2013

Shale gas provides a renaissance for North American petrochemical producers and downstream chemicals

HPI FOCUS When does it make sense to build a new unit instead of revamping an existing facility?

REFINING DEVELOPMENTS Upgrading heavy crudes creates new hurdles to be solved with catalysts and better processing methods

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APRIL 2013 | Volume 92 Number 4 HydrocarbonProcessing.com

54

6

32 SPECIAL REPORT: PETROCHEMICAL DEVELOPMENTS 33 Shale energy resources driving resurgence for ethylene industry M. Eramo 37 North American olefin producers riding the shale gas wave R. Klavers and M. J. Tallman 43 Use model-based temperature control for fixed-bed reactors D. Weatherford and J. Ford 47 High-pressure polyethylene: Reemergence as a specialty chemical or not?

L. Farrell and J. Virosco

DEPARTMENTS

4 6 9 15 102 105

Industry Perspectives Brief Impact Innovations Marketplace Advertiser index

COLUMNS

HPI FOCUS: NEW VS. REVAMP 51 New vs. debottlenecking projects for the hydrocarbon processing industry

23

Reliability Fact-checking list from recent reliability conferences

BONUS REPORT: REFINING DEVELOPMENTS 55 Evaluate challenges in meeting clean-fuel specifications with heavier crude S. Al-Zahrani, S. Roy, and E. Bright 61 Improve coker efficiency with reliable valve automation B. Deters and R. Wolkart 65 Optimize value from FCC bottoms J. Paraskos and V. Scalco

25

Integration Strategies Industrial considerations for BYOD

27

Boxscore Construction Analysis Ethylene in evolution: 50 years of changing markets and economics

GAS PROCESSING DEVELOPMENTS 73 Take a quicker approach to staggered blowdown M. Sufyan Khan

106

Water Management Update: Online measurement of oxidizing biocides

TURBOMACHINERY DEVELOPMENTS 77 Select the right shaft-riding brushes for turbomachinery T. Sohre and H. P. Bloch GLOBAL TURNAROUND AND MAINTENANCE—SUPPLEMENT T-85 Overcome barriers to proper planning and scheduling J. Wanichko SAFETY/LOSS PREVENTION 99 Conceptually, accidents are a fallacy M. Sawyer Cover Image: In 2006, Technip began construction of the Map Ta Phut Olefins facility located in Thailand. The facility uses seven of Technip’s proprietary GK6 naphthacracking furnaces and one SMK furnace for ethane cracking. The olefins facility was successfully started up in March 2010.The GK6 units are the largest in operation, with an ethylene capacity of 175,000 tpy per furnace.

www.HydrocarbonProcessing.com

Industry Perspectives Key industry officials answer a poll question from HydrocarbonProcessing.com

Are Arctic projects safe?

Do global energy companies have sufficient safety protocols in place to deal with the challenges of Arctic projects? The answer, according to hundreds of votes cast in a recent Hydrocarbon Processing industry poll, is an old cliché: it depends.

Nearly half (48%) of readers surveyed believe practices vary enough throughout the industry that a single standard has not been adopted, making it dependent on the company in question. Another 28% said they believed the industry does have sufficient safety protocols, while 25% said it does not.

The topic became newsworthy after recent incidents involving Shell. That company, for its part, is postponing its planned summer drilling in the Arctic Ocean after a troubled 2012 drilling season marred by bad weather, mechanical failures and regulatory challenges. Shell had been widely expected to push back its contentious, multi-billion-dollar Arctic program after it announced that its rigs needed to be repaired and analysts said replacements would be hard to find.

“We’ve made progress in Alaska, but this is a long-term program that we are pursuing in a safe and measured way,” said Shell president Marvin Odum.

The Kulluk, a drilling ship owned by Shell and operated by Noble Corp., ran aground on an uninhabited island about 300 miles southwest of Anchorage on Jan. 1 after ships towing it to Seattle for the winter lost control of the rig during a storm (FIG. 1). It suffered damage to the hull and electrical systems.

The Noble Discoverer drill ship, which Shell was leasing, had an engine fire in December when it was on its way to Seward, Alaska, prompting a US Coast Guard inspection.

Investors and government officials are closely watching Shell’s Arctic plans. The company has spent nearly $5 billion on permits, personnel and equipment over the past six years to assure regulators and native Alaskans that the first drilling in the Arctic Ocean would be safe and environmentally benign.

—Additional reporting by Dow Jones Newswires

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FIG. 1. Shell Kulluk drilling rig in the Arctic.

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| Brief LyondellBasell plans to expand North American ethylene capacity LyondellBasell will raise its ethylene capacity in North America by 18% in coming years through several debottlenecking projects. Locations where ethylene capacity will be expanded include crackers in Corpus Christi, La Porte and Channelview, Texas, according to the company. The projects are scheduled to be finished in 2014 and 2015.

Jim Gallogly, CEO of LyondellBasell, made these remarks at the company’s annual investor day in New York. He said the company aims to finish its projects two to three years earlier than industry competitors building new plants, all at a lower cost.

Mr. Gallogly said he expects ethane to stay priceadvantaged in the US for at least the next five years. He noted that natural gas producers are still incentivized to produce wet gas and, as a result, LyondellBasell plans to raise its ability to crack natural gas liquids (NGLs) from 85% to 90%.

LyondellBasell also said it was “in the early stages” of evaluating a 1 million lb/year polyethylene plant in North America by 2016.

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

Brief Enterprise Products plans to develop a new 270mile pipeline header system that will deliver ethane

to petrochemical plants in the US Gulf Coast region. The Aegis pipeline will originate at Enterprise’s liquids storage complex in Mont Belvieu, Texas, and have the capacity to transport purity ethane to multiple petrochemical facilities in Texas and Louisiana. The final design, including capacity and delivery points, will be determined at the conclusion of the project’s open commitment period. Aegis is expected to begin commercial operations in 2014.

ceed the technological limitations of certain engines and refueling equipment. The result is a dramatic increase in the market price of ethanol renewable identification numbers (RINs), which has risen nearly 1,000% since early January. AFPM encourages the EPA to reevaluate the amount of ethanol that will be used to meet thresholds set as part of the RFS.” Technip will form a jointly-owned company with State Corp. Russian Technologies (Rostec) to provide

monomer (EPDM) production in Texas.

“Soft underlying demand in the second half of 2012 has continued into 2013 across most businesses, against the usual seasonal trend,” the company said in an unscheduled earnings update. “In order to counter the current soft demand, the company is applying its proven flexible asset management strategy.”

Lanxess said it expects demand to pick up during the year and “is strategically well positioned to benefit from the expected recovery in the global economic development.”

engineering, design and turnkey construction for oil refinery, petrochemical and gas chemical production projects in Russia. The joint venture agreement, aimed at improving the construction and renovation of refining and petrochemical units in Russia, was signed with Rostec subsidiary Rustechexport.

The deal includes facilities required for offshore oilfield operations. The two companies are also aiming to establish a joint venture to manufacture flexible pipelines and umbilicals in Russia. These would be used in the Russian Arctic and Black Sea for use in water depths up to 3,000 meters. The agreements were signed during an official meeting between French President François Hollande and Russian President Vladimir Putin in Moscow.

Russia’s OAO Lukoil has agreed to sell its refinery in Odessa, Ukraine, to Vetek Group. The refinery has a

An international court has awarded Dow Chemical $318 million as a resolution to its dispute with Petrochemical

Lanxess plans to temporarily shut down its butyl rubber plant in Belgium and its ethylene-propylene-diene

capacity of 3.9 million tpy and has been idle since the end of 2010. The decision to sell is part of a plan by Lukoil to restructure its international refining assets, the company said.

The deal is expected to be closed before June 1, after both sides fulfill a variety of conditions.

The American Fuel and Petrochemical Manufacturers (AFPM) issued a statement following the withdrawal of

its petition for waiver of the 2012 Cellulosic Biofuel Volumetric Requirements: “We appreciate the Environmental Protection Agency’s (EPA) prompt action to rescind the 2012 cellulosic renewable volume obligation (RVO) following a US Court of Appeals’ decision to vacate the 2012 cellulosic RVO. As a result of the EPA’s response, AFPM has withdrawn its waiver petition, since our members are no longer required to purchase credits for fuel that doesn’t exist. We believe that the EPA should reconsider proposed 2013 volumes, which suffer from the same shortcomings, and finalize a 2013 cellulosic biofuel RVO that reflects the Court’s directive to aim for accuracy.

“While EPA’s decision on the 2012 cellulosic RVO is the right one, it doesn’t alleviate the waste of resources and time spent correcting just this one example of an impracticable renewable fuel standard (RFS). A more immediate problem with the RFS is the fast-approaching blendwall, where the EPA is mandating the consumption of ethanol in quantities that ex-

Industries Company of Kuwait (PIC) related to the K-Dow transaction. This is in addition to the partial award of $2.16 billion announced last May. “Payment of these damages of nearly $2.5 billion will allow Dow to accelerate its priority uses for cash by further strengthening our balance sheet,” said Andrew Liveris, Dow’s chairman and chief executive officer. “Dow and Kuwait share a long history and strong partnership, and this award ruling brings suitable closure to the arbitration process. The Dow team fully expects, and we are resolved to ensure, that PIC honors its contractual commitments in a timely manner.”

A survey published by OilCareers.com and partner Air Energi declares that oil-related salaries will increase

in the future. The increase is attributed to heightened safety concerns, economic instability and strong oil prices, along with the ongoing skills shortage. While economic instability currently ranks as the highest concern for those surveyed, the shortage of skilled labor in the industry is a major consideration with far-reaching consequences for safety and security within the industry. Increasingly high levels of activity currently underway have contributed to a strong candidates’ market, the authors said, though rates remain stable and the trend toward permanent hires versus contractors observed in 2012 continues.

The authors said they surveyed more than 170,000 oil and gas professionals worldwide.

Hydrocarbon Processing | APRIL 2013 7

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The key to our success is the creativity and resourcefulness of our employees. And it is this that keeps turning major challenges into solutions that are not only brilliant and innovative, but often set the standard for the entire engineering sector.

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

Impact Asia-Pacific natural gas market transformation Amid the Asia-Pacific region’s growing reliance on imports, a report from the International Energy Agency (IEA) identifies obstacles and opportunities for establishing a gas market that reflects supply/demand fundamentals. Asia-Pacific is expected to become the world’s secondlargest gas market by 2015. And yet this market is dominated by long-term contracts in which the price of gas is linked, or indexed, to that of oil. In recent years, this has helped keep Asian gas prices much higher than those in other parts of the world (FIG. 1), leading to serious questions about the sustainability of the system and its effects on Asian competitiveness.

“Natural gas has the potential for improving energy security and yielding economic and environmental benefits in Asian-Pacific countries,” said IEA Executive Director Maria van der Hoeven. “Asia is already home to the world’s fastestgrowing gas market. But expanding the role of gas in Asia will depend on regional market conditions that allow the fuel to compete autonomously in local energy markets that are themselves connected to global energy markets. The future role of gas in Asia will depend considerably on

how the pricing of natural gas is tied to the fundamentals of supply and demand in the region.”

Asia-Pacific supply/demand balance.

Since 1990, the natural gas market in the Asia-Pacific region has undergone remarkable growth, to about 560 Bcm in 2010. Natural gas consumption has grown by more than 350% since 1990, representing an average year-on-year increase of 6% over two decades. Japanese consumption represented the mainstay of Asian natural gas demand, especially in liquefied natural gas (LNG), until 2010, when China surpassed Japan as the largest natural gas market in Asia.

Since 1998, total natural gas production in Asia-Pacific has lagged behind regional consumption. A few countries, such as Indonesia and Malaysia, were net exporters providing LNG for import-dependent countries such as Korea and Japan. In 2010, natural gas production in the region fell around 93 Bcm short of consumption, a shortfall that is expected to increase to about 200 Bcm in 2017, despite a considerable increase in regional production.

Dependence on natural gas imports from outside the Asia-Pacific region increased by 12% annually throughout 2000–2010. It is expected that this import

16

Japan (LNG import) Europe (German import) US (Henry Hub)

800 700

play a beneficial role in providing investment security, but their current pricing does not accurately reflect gas market fundamentals or the competitiveness of gas relative to other fuels. Moreover, without a competitive spot market for natural gas, there is little incentive and little scope to change current commercial practices. This leaves both consumers and producers with insufficient room to explore different options, and limits the degree to which natural gas can serve as a flexible source of energy for both growing and mature economies. Among the report’s key findings and recommendations are the following: • Current market structures discourage gas consumption and impact Asian competitiveness vis-à-vis more flexible markets in the US and even Europe • OECD experience suggests that the single biggest obstacle for an effective gas market is a lack of infrastructure access

Gas consumption, Asia-Pacific Gas production, Asia-Pacific IEA 2012 forecast IEA 2012 forecast

600

12

500

10

Bcm

$2012/MMBtu

14

400

8 6

300

4

200

2 0 1991

Key findings. Long-term contracts can

900

20 18

dependency will grow by 5% annually over the period 2011–2017 (FIG. 2). The relatively moderate increase reflects increasing gas production projected for China and Australia. Overall demand in the Asia-Pacific region is expected to follow global demand trends, growing at around 3% per annum to reach 875 Bcm in 2017.

10 1994

1997

2000

2003

2006

2009

FIG. 1. Relatively high gas prices lead to a competitive burden on Asian economies.

2012

0 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 FIG. 2. Asia-Pacific demand and production, 1990-2017.

Hydrocarbon Processing | APRIL 2013 9

Impact • The role of governments must change: Instead of focusing on price regulation along the value chain, governments must maintain and supervise competitive market conditions • Credible state commitment to regional gas market competition can instill confidence, encourage new market participants, and promote the use of transparent hubs to balance producer portfolios • Transport and commercial activi-

ties should be separated and prices deregulated at the wholesale level • Singapore holds the best initial prospects for gas hub development, with Japan, Korea and China as likely competitors in the future.

“The prospects are there, but even the prime candidates will need to do more,” said Ms. Van der Hoeven. “China’s fastgrowing domestic gas network is still underdeveloped, and the entire produc-

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tion chain remains heavily regulated.

Singapore’s small domestic market means that, to grow as a hub, it must rely on reexports, which are hindered by regulation. Last but not least, Japan has a great potential to act as a hub, but it will have to take some important steps.”

Promising forecast for the US re-refining industry

With a projected compound annual growth rate (CAGR) exceeding 23% over the next five years, the future of the US re-refined basestocks market looks promising, according to a recent study by Kline & Co. Given that all announcements pertaining to expansions and new capacities go as planned, it is anticipated that the rerefining industry will see a robust growth to an estimated 1,390 kilotons by 2016, suggesting a “golden decade” for many in the industry. However, this is contingent upon the successful and timely ramp-up of operational facilities.

Key drivers fueling this growth include enhanced technology and infrastructure, legislative imperatives and rising crude oil prices. The improving quality and viability of re-refined base oils, coupled with increased and more consistent collection rates due to stronger regulations enforcement, are helping the industry assert its largely untapped potential.

An emerging trend observed in the US re-refining industry consists of an influx of foreign re-refiners who, having identified the expanding opportunities within North America, are consequently establishing plants in the country. These include leading re-refiners from Western Europe and India.

Despite the encouraging potential, the report also identifies impediments concerning the otherwise strong re-refining business. These primarily include access to used oil and consumer acceptance of re-refined lubricants. To better ensure used oil access and supply, re-refiners are forming alliances or acquiring collectors and subsequently also reinforcing the general consolidation trend within the industry. The acceptance of re-refined lubricants is likely to be an incremental phenomenon assisted by more brands (especially major oil brands) entering this market, a more omnipresent availability and a greater emphasis upon intrinsic value with little or no compromise.

How Can KBR Answer Your Refining Challenges?

Owners of refineries continue to confront many challenges â&#x20AC;&#x201C; rising feedstock prices, shrinking margins, varying global demands and a changing regulatory landscape that includes ever-more stringent specifications on sulfur and carbon footprints. As refinery owners debottleneck and enhance existing facilities, they call on KBR to deliver.

To learn how KBR can address your refining challenges, go to:

refining.kbr.com/HP

refining.kbr.com / HP K13009 Š 2013 KBR, Inc. All Rights Reserved.

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Impact Driven by China, global methanol demand rises 23% in two years According to a new IHS Chemical global market study, global methanol demand increased 23% during the two-year period of 2010 to 2012, primarily driven

by Chinese demand.

Annual demand for the product is expected to increase by more than 8%,

from 61 MM metric tons in 2012, to an unprecedented level of 137 MM metric tons in 2022. These rapid demand increases are significant, particularly when the numbers are compared to the economic downturn of 2008 to 2009, when annual global methanol demand slowed to just 4% and 2%, respectively.

“Methanol is a key option for monetizing gas or coal,” said Mike Nash, global director of Syngas Chemicals at IHS.

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“An abundant supply of low-cost North American shale gas resources is driving methanol capacity additions in the US. The shale gas revolution is a major gamechanger; mothballed methanol units have started back up, and one Methanex unit has been relocated from Chile to Louisiana with considerations of moving another unit. Coal supplies in China are also driving projects there, as well, particularly as it relates to using cheap methanol supplies derived from coal to produce olefins.”

Geographically, China remains the growth center for methanol demand, with an average annual growth of slightly more than 12%, while the rest of the world is growing at just below 3%. China methanol consumption will triple from 31 MM metric tons in 2012 to 97 MM metric tons in 2022.

Traditional uses for methanol include derivatives such as formaldehyde, acetic acid and methyl methacrylate. With China at the epicenter of global growth, fuels applications are one of the primary demand drivers. Methanol demand in the gasoline pool is expected to increase from nearly 5 MM metric tons in 2012 to just over 11 MM metric tons in 2022, representing a penetration of nearly 12%. At blend ratios of 15% and slightly increased gasoline consumption trends, methanol consumption could rise to 15 MM metric tons.

China has become by far the largest methanol producing country in the world, representing 54% of world capacity and 43% of world methanol production in 2012. The global methanol industry is now reaching the end of a significant wave of capacity expansions.

Since 2007, capacity has been added at the rate of 14.3%/yr, in an industry where demand had been growing at around 8.6%/yr.

However, Chinese capacity utilization is only around 50%, since China adjusts operating rates accordingly to “balance” world supply and demand. China is nearing the end of a major capacity expansion wave, with only an additional 7.5 MM metric tons of new capacity for the merchant market expected to come onstream through 2022. This leaves well over 40 MM metric tons of new China methanol capacity integrated to methanol-toolefins/methanol-to-propylene coming online during the forecast period.

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This injector sprays liquid into gas and is just one of many used for gas cooling, water wash, desuperheating, steam quench, slurry backflush and more.

SUPERIOR SPRAY. SERIOUS RESULTS. Whether you need to cool gas, dissolve salts in an overhead line or inject chemicals to prevent corrosion, we can help optimize injector performance. Here's how: • Assistance with nozzle selection, spray direction and injector placement. There are dozens of factors to consider before choosing a spray nozzle, determining whether to spray co- or counter-current and identifying the proper placement of an injector in a vessel. We can help you evaluate your process conditions and then design an injector to provide optimal performance • Design validation using Computational Fluid Dynamics (CFD) and Fluid Structure Interaction (FSI).

We use powerful modeling tools to simulate your environment, confirm the injector will provide the expected spray performance and withstand process conditions such as thermal stresses, heat transfer, vortex shedding and more • Proven track record. Companies like Technip, Mustang Engineering, Bechtel, Shell and many others rely on us to manufacture B31.1 and B31.3 code-compliant injectors and conduct radiographic, hydrostatic, ferrite tests and more

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CFD MODEL ILLUSTRATES PERFORMANCE BASED ON INJECTOR PLACEMENT

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

Innovations Flowmeter uses Coriolis force in measurement The Sitrans FC430 flowmeter from Siemens AG is capable of measuring liquids and gases using the Coriolis principle. Flows can be measured with a precision of 0.1%, and different sensor sizes are available to address various applications.

The technical solution of state-of-theart flow devices based on the Coriolis force uses two vibrating tubes. The tubes are forced to vibrate using a magnetic driver, which is controlled by an electronic driver circuit and the appropriate software. Two electromagnetic transducers measure the velocity of the tube deflection between input and output. The driver and the transducers are part of a closed-loop control system that continuously causes the tubes to vibrate at their resonant frequency. The resonant frequency depends on the construction of the tubes and on the density of the fluid. The tube temperature is measured to compensate for changes in the material stiffness of the tubes.

The phase of the two velocity signals is proportional to the mass flow of the fluid, and the frequency of the velocity signal is equal to the density of the fluid. Volume flow is calculated based on the mass flow and density. The measurement calculations (software) are processed using a modern digital signal processor (DSP).

The Sitrans FC430 software is modular, with small blocks that provide structured and well-defined functions. This makes it easier to supervise and monitor the correctness of each of the smaller units. The various blocks are protected by advanced safety integrity measures to detect dangerous errors. For example, the result of a calculation in the algorithm is evaluated using well-defined and tested plausibility checks to ensure that the result is the expected one. Additional diagnostic software secures each block so that the software runs correctly and reliably.

The Sitrans FC430 flowmeter complies with safety standard IEC 61508. It can be used in safety circuits up to Safety Integri-

ty Level 2 (SIL 2) in a single-channel configuration and up to SIL 3 in a redundant configuration. No additional measures are required from the application side.

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Oil evaporator system ideal for shale oil analysis

JM Science’s AQUACOUNTER AQL-22320 automated oil evaporator system (FIG. 1) is an automated Karl Fischer titrator system consisting of the AQ-2200 (coulometric titrator) and the EV-2000L (oil evaporator) units. This titration system has been designed for analyzing moisture in difficult samples such as shale oil, grease, heavy lubricants and other materials.

Using an azeotropic distillation solvent, like toluene or xylene, moisture can be evaporated at a lower temperature, saving on expensive Karl Fischer reagents and lowering maintenance costs, since the titration cell remains clean and free of contaminants. This automated system allows the analyst to load the samples into glass vials and then place the vials on the sample tray of the system. The operator only needs to push the “start” button once to begin the analyses.

The sample changer holds up to 20 vials and can process large numbers of samples. It is equipped with the automatic Karl Fischer reagent exchanging function, reducing the cost of Karl Fischer reagent and waste disposal. Wide temperature settings cover the full range of azeotropic points.

Scotford Refinery upgrader near Edmonton, Alberta, and permanently store the gas deep underground at an injection site north of the facility. Quest will begin injecting CO2 underground in 2015. Shell ordered an integrally geared centrifugal compressor from MAN Diesel & Turbo for delivery in 2013.

MAN Diesel & Turbo Berlin will construct and hand over the RG90-8 frame size for the first time. Four pinions are engaged with a different gear ratio, leading to diverse rotating speeds. Each pinion mounts two impellers in a back-to-back arrangement. The CO2 is compressed in eight stages to a discharge pressure of 130 bar. This integrally geared centrifugal compressor handles 80,000 cubic meters of CO2 per hour. It will be constructed of familiar components that have proved reliable in different frame sizes over many years.

The discharge pressure of 130 bar is sufficient to send the compressed CO2 about 60 kilometers (km) via an underground pipeline to a wellhead, and to inject the dense-phase CO2 2.3 km below the surface into a saline rock formation for permanent storage (FIG. 2).

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Alarm/bypass solution enables real-time risk management

Invensys Operations Management has enhanced its Triconex critical control and safety offerings for industrial operations. The new Triconex Safety View

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Compressor technology will enhance CCS project

MAN Diesel & Turbo is providing compressor technology for Shell Canada’s Quest Carbon Capture and Storage (CCS) Project, located in Alberta, Canada. Quest will be the world’s first commercial-scale CCS project to tackle carbon emissions at an oil sands operation.

Quest will capture more than 1 million metric tons per year of CO2 from Shell’s

FIG. 1. The AQUACOUNTER AQL-22320 automated oil evaporator system analyzes moisture in difficult samples, such as shale oil.

Hydrocarbon Processing | APRIL 2013 15

Q

Customers:

Q

Challenge:

Q

Result:

Global oil and gas producers.

Changing compression requirements as fields mature and production peaks.

Flexible, reliable compressor designs for extended, cost-efficient operations.

They turned to Elliott for reliable compression solutions.

From Aberdeen to Rio de Janeiro, Calgary to Jakarta, Elliott compressors, turbines, and expanders deliver the reliable, efficient performance that producers and processors require.

And every piece of Elliott equipment is backed by our unmatched global service network.

Customers throughout the world turn to Elliott for critical turbomachinery and service because our resources are global and our execution is local. Who will you turn to?

EBARA CORPORATION

C O M P R E S S O R S

Q

T U R B I N E S

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G L O B A L

S E R V I C E

The world turns to Elliott. www.elliott-turbo.com

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Innovations solution is the worldâ&#x20AC;&#x2122;s first software for alarm and bypass management certified

by TĂ&#x153;V Rheinland to IEC61508 Systematic Capability 3 for use in applications up to Safety Integrity Level 3 (SIL 3). Additionally, the companyâ&#x20AC;&#x2122;s Triconex Trident and Tricon general-purpose safety instrumented systems (SISs) now support OPC Unified Architecture (UA) for greater communications connectivity.

Triconex draws attention to changes in process conditions that require immediate attention, giving operators, maintenance engineers and shift personnel better visibility into the process so they can take actions that reduce risk, optimize the total cost of ownership and increase overall asset performance. It is built on the companyâ&#x20AC;&#x2122;s ArchestrA System Platform and Wonderware InTouch HMI software, which have been adapted specifically for use in safety applications.

Invensys has also embedded OPC UA communications with its industry-leading Triconex, Trident and Tricon general-purpose SISs. OPC UA maximizes interoperability between systems and streamlines connectivity through open-platform architecture and future-proof design. The new communications interface module contains an embedded OPC UA server that supports up to 10 concurrent clients, delivering high-performance and secure, reliable communication of real-time data, alarms and historical events.

OPC UA provides a single communications solution from the device level to the enterprise level, maintaining platform independence without sacrificing performance. It provides better interoperability (complete with certification), reliability by design, access via firewalls

From Engineering Through Fabrication Valve (numerous options) Sieve or perforated Bubble cap trays Cartridge trays 'XDO Ă&#x20AC; RZ %DIĂ&#x20AC; H

For top performing mass transfer and tower internal components let AMACS Process Tower Internals use your existing drawings or modify them to improve your process. Our experienced in-house engineering and full scale fabrication capabilities can streamline your project from inception to installation.

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FIG. 2. Flow diagram of the Quest CCS process. Image courtesy of Shell Canada Ltd. Select 153 at www.HydrocarbonProcessing.com/RS Hydrocarbon Processingâ&#x20AC;&#x201A;|â&#x20AC;&#x201A;APRIL 2013 17

A new name, a long history.

Selas Fluid Processing is now Linde Engineering North America Inc. For over 60 years, we’ve been there for our reļning and petrochemical customers. Linde Engineering North America Inc. offers single source responsibility for technology, engineering, procurement and construction.

• • • • •

Selas Fluid reľnery and petrochemical ľred heaters Oxidation/incineration technologies Engineered revamps and rebuilds Hydrogen and synthesis gas plants Air separation plants

We’re local. We’re global.

And we’re proud to be both.

Head Ofľce: Five Sentry Parkway East, Suite 300, Blue Bell, PA 19422 USA 610-834-0300 Texas: 3700 West Sam Houston Pkwy. South, Suite 425, Houston, TX 77042 USA 281-717-9090

LENAsales@linde-le.com www.lindeus-engineering.com Select 73 at www.HydrocarbonProcessing.com/RS

Innovations and across the internet, and reduced configuration time with built-in information and security models.

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Laser-scan point cloud simplifies pipeline construction

Intergraph has released CloudWorx for SmartPlant Isometrics 2012 R1, an add-on to its SmartPlant Isometrics solution that allows users to quickly create accurate, as-built piping isometrics directly from a laser-scan point cloud.

CloudWorx for SmartPlant Isometrics 2012 R1 leverages Leica Geosystems’ industry-leading Cyclone software technology to efficiently display the laser-scan point cloud and navigate through it in a window with measured piping data overlaid graphically, a revolutionary method of creating as-built piping asset documentation.

CloudWorx for SmartPlant Isometrics supports the rapid creation of piping isometric documents, using Intergraph ISOGEN. The easily understood sketching functionality and automated drawing creation means computer-assisted design (CAD) and 3D skills are not required, but it also allows experienced piping designers to be highly productive in creating as-built piping data.

The software is complementary to 3D model-based solutions based on Smart 3D, Plant Design System or CADWorx, since the same ISOGEN software is used to produce the deliverable. Results are consistent, and underlying data can be used to create documentation for inspection of piping systems, including the automated, rule-based placement of inspection location points.

When used in conjunction with SmartPlant Enterprise for owner/operators (SPO), the comprehensive, as-built documentation can be managed to ensure the integrity of the piping asset. SPO adds change-management and audit capabilities when the piping documents are published to the plant engineering data store and maintained through time.

With the new SPO TruView integration capability, CloudWorx for SmartPlant Isometrics can use the same pointcloud data to create piping documentation as needed for operating and maintaining a facility, or to document the as-built asset in line with industry regulations.

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Pulse input flowmeter ideal for hazardous locations Precision Digital’s PD6830 ProtExRTP Pulse Input Rate/Totalizer flowmeter (FIG. 3) has a rugged, explosion-proof, NEMA 4X enclosure and is designed for quick and easy display of local or remote flow information in hazardous areas or in the harshest safe area applications. The SafeTouch through-glass buttons allow operation without removing the cover.

Flowmeter K-factor units are automatically converted to the desired display units; this means that no conversion factors are needed. The pulse input accepts a wide range of flow transmitter signals, including millivolt input from a magnetic flowmeter, as well as high-frequency signals. The PD6830 flowmeter includes backlighting and two open-collector outputs as standard.

The PD6830 flowmeter features an upper display that is 0.7 inches high and shows five digits of flowrate or total. The lower display is 0.4 inches high and shows a combination of flowrate, total, grand total or a tag with seven alphanumeric characters. The meter is easy to read from a distance, under various lighting conditions and from wide viewing angles.

Unit conversions are automatically performed by the PD6830 flowmeter.

This means that no math or conversion factors are needed. The meter is capable of data logging up to 1,024 records in real time. Each record contains the date, time, rate, total, grand total and log number.

The flowmeter is designed to handle a wide variety of high-speed inputs and outputs. Inputs can be discerned with pulse widths as small as 5 microseconds.

BORSIG

Visit us at: Ethylene Producers´ Conference at the AIChE 2012 Spring Meeting

BORSIG TRANSFER LINE EXCHANGERS FOR ETHYLENE CRACKING FURNACES BORSIG is the world´s leading manufacturer of quench coolers for ethylene plants with more than 6,200 units installed worldwide.

- BORSIG Linear Quencher (BLQ) - BORSIG Tunnelflow Transfer Line Exchanger (TLE) A practical design, highly qualified personnel and modern manufacturing and testing methods ensure the high quality standards to meet all requirements with regard to stability, operational reliability and service life.

BORSIG - Always your first choice

www.borsig.de BORSIG GmbH Phone: ++49 (30) 4301-01 Fax: ++49 (30) 4301-2236 E-mail: info@borsig.de FIG. 3. The PD6830 ProtEx-RTP flowmeter is designed for display of local or remote flow information in both hazardous and safe areas.

Egellsstrasse 21, D-13507 Berlin/Germany

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Innovations Two open-collector outputs are individually programmable for rate, total or grand total alarms; rate, total or grand total pulse outputs; retransmission of pulse inputs; quadrature paired output; or constant timed pulse output. Operating temperatures range from −40°C to 75°C. Select 6 at www.HydrocarbonProcessing.com/RS

Portfolio update improves rod, valve monitoring

The Smart Machinery Health portfolio from Emerson Process Management now provides an integrated protection and prediction solution for critical reciprocating compressors. Common compressor issues can be predicted before they cause a process upset, greatly reducing lost production and repair costs.

Reciprocating compressors are often maintenance-intensive machines at a production facility and are critical to production uptime. With Emerson’s integrated approach for reciprocating assets, rotating and reciprocating machines can now be monitored through one maintenance management system.

Emerson’s reciprocating compressor solution includes standard protection functionality as specified in American Petroleum Institute (API) 670 and API 618, and it adds powerful predictive monitoring to identify a user’s most troublesome issues: valves, pressure packing, rider bands and rod faults.

Emerson’s CSI 6500 Machinery Health Monitor with PeakVue technology monitors ultrasonic emissions to determine valve health, which is reported as the No. 1 maintenance issue by users. Transient monitoring of rod position identifies abnormal or excessive changes in rod position before they impact pressure packing; it also monitors vertical rod position to track rider band wear. Advanced assetmanagement capabilities enable users to view rod position via 2D plots, illustrating piston rod dynamic motion that can be viewed live, paused and replayed.

Emerson’s integrated solution also delivers compressor frame vibration shutdown protection as specified by API 618, and piston rod monitoring as specified by API 670. AMS Suite provides additional

Looking for a highly efficient and compact filter system to improve your gas filtration application?

Our custom-made filter systems combine all-welded elements and metal fiber based media. The high porosity of this media allows state-of-the-art surface filtration, which results in low differential pressures and longer cycle-times. Thanks to their improved blow-back unit design, Bekaert gas filter systems are not only compact in size, they are also highly efficient and they offer a long life-performance.

Benefits of bekaert hot gas filtration elements - Low emissions: 1 mg/Nm³ for particulate materials - High efficiency: filtration up to 99,9995% at 1μ - Continuous & reliable operations, no shutdown - Increased cycle-time and long-life performance - Compact size and footprint

performance and machine condition information through monitoring parameters such as adiabatic efficiency, volumetric flow, rod tension and rod compression.

Combining shutdown protection with predictive diagnostics delivers the information that users need to protect their equipment health while avoiding production downtime.

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SiGNa Chemistry acquires Jadoo Power H2 assets

SiGNa Chemistry Inc. has acquired the hydrogen (H2) storage and fuelcartridge assets of Jadoo Power Systems.

The purchase includes all of Jadoo Power’s portable H2 products, including the company’s well-known N-Stor cartridge, as well as associated H2 storage materials and patents, and supporting laboratory and analysis assets.

Since its founding in 2005, SiGNa has commercialized a range of sustainable chemistry products that are based on the company’s core competency in transforming reactive alkali metals, which historically have been dangerous to use and store, into safe, free-flowing powders.

The resulting stabilized materials enable improvements in safety, efficiency, cost and environmental sustainability across a number of chemical processes in power generation, pharmaceuticals, petrochemicals, enhanced oil recovery and other widely used products.

SiGNa works with a number of fuel cell integrators and OEMs to develop customized H2-delivery cartridges. SiGNa’s H2 cartridges enable energy-dense, lightweight and wearable power systems and can be designed for any proton-exchange membrane fuel cell system. In partnership with Swedish-based myFC, SiGNa was responsible for the release of the world’s first fuel cell product certified by the International Electrotechnical Commission.

SiGNa anticipates several new product releases in 2013 and continues to seek new development partners interested in commercializing fuel cell-powered products for portable military power, emergency and disaster relief, backup and standby power, outdoor power and consumer electronics.

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Contact Pavlos Papadopoulos - pavlos.papadopoulos@bekaert.com - +32 (4) 2283976 www.bekaert.com/baf

20

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Additional items can be found online at HydrocarbonProcessing.com.

We create chemistry that makes building blocks love strong foundations.

Todayâ&#x20AC;&#x2122;s petrochemical industry provides the building blocks for a wide range of materials. As the global leader in catalysis, BASF provides a strong foundation of product and process innovations across the petrochemical value chain. The result is a broad petrochemical catalyst and adsorbent portfolio backed by dedicated customer and technical service and enabled through the strength of BASF â&#x20AC;&#x201C; The Chemical Company. At BASF, we create chemistry for a sustainable future. www.catalysts.basf.com/petrochemicals

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Reliability

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

Fact-checking list from recent reliability conferences Whenever HP editors attend technical conferences, their primary goals include observing industry practices, finding facts and spotting trends.

TABLE 1. The relationship between reliability and maintenance • Reliability and maintenance are inextricably linked • One cannot cost-cut one’s path to improved reliability • Maintenance costs are driven by reliability or the lack thereof • Best performers achieve high reliability at low costs • Poor performers have high costs with low reliability • Each 1% increase in mechanical availability can translate into a 10% reduction in maintenance costs 20

45

18

40

16 14

35

12 30

10 8 6 4

12 months per pump routine maintenance cost 12 months rolling pump MTBF, months 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 Year one Year two

Pump MTBF, months

mere anecdotes of questionable veracity. So, technical columnists must come to grips with snippets of information. Should the reporters relate the snippets as amusing anecdotes, or should they withhold the snippets because they add no value? Most professionals use reasonable judgment and try not to allow erroneous information to go unchallenged.

Here are a few recollections, claims, counterclaims and issues amassed from several 2012 reliability conferences attended

by HP editors: 1. In best-of-class (BOC) plants, use of nonpolluting closed oil-mist systems is increasing. These systems include electric motor drivers and all standby equipment at BOC plants. Finding: Fact.

2. Oil mist can cause motor insulation to degrade. Finding: True for motors made in the 1940s and early 1950s. Not true for motors with epoxy insulation, typically made from 1965 to the present.

3. Pump vendors always use the best available lube application; therefore, oil rings and constant level lubricators should not be questioned. Finding: Not 100% factual.

4. Some reciprocating compressor purchasers insist on metal-disc pack couplings. Finding: Some do, but they do so at their own risk. Mandating metal-disc couplings rarely serves the purchaser’s best interests. Elastomeric elements are usually (although not always) safer and more reliable in these machines.

5. Some coupling manufacturers know little about coupling stiffness under actual operating conditions. Finding: True, unfortunately. Repeat failures have resulted.

6. Large electric motors are again being built in the US by at least one competent legacy manufacturer. Finding: True, and this is a pleasant development.

7. Plants that spend more money on maintenance are typically those that don’t invest reasonable funds or resources on reliability improvements. Finding: True. The issue was neatly summarized by Alan Poling of Solomon Associates at the 2012 ARAMCO Global Reliability Forum, held in Houston, Texas; see TABLE 1.

8. Plants that have replaced traditional repair-thinking and now use reliability-thinking invest 5% of the actual equipment cost in up-front machinery quality assessment (MQA). Finding: True. Effective MQA has been successfully practiced since the early 1960s.

9. New formulations of polyether-ether-ketone (PEEK) have joined proprietary formulations of polyimide resins as an

Per pump outlay, $ thousand

Fact or fiction. Unfortunately, presenters sometimes relate

25 20

FIG. 1. As MTBF decreases, maintenance costs increase at this location.

advantageous pump-wear part material. Finding: True, but be mindful of possible increases in axial load on the pump’s thrust bearing that can result from close-clearance PEEK wear rings.

10. The Southwest Research Institute has refined and validated methods to better predict turbomachinery vibration. Rotor behavior modeling, often expressed as the log decrement in critical damping values, is now more accurate. Finding: True.

11. There is a narrowing of the gap in reliability performance and profitability of top-quartile companies (upper 25%) as compared to fourth-quartile (lower 25%) companies. Finding: Not true. Regrettably, the gap is widening.

12. As more maintenance money is spent, pump MTBF increases. Finding: The opposite is true, as shown in FIG. 1.

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 | APRIL 2013 23

Flexible H2S Removal

Sweet Solutions®

LO-CAT

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LO-CAT’s flexible technologies and worldwide services are backed by over three decades of reliability. Over 200 licensees in 29 countries are meeting today’s compliance requirements by turning nasty H2S into elemental sulfur with the use of LO-CAT technologies. Efficient, effective and environmentally sound, LO-CAT is the technology of choice for H2S removal / recovery.

www.merichem.com Select 84 at www.HydrocarbonProcessing.com/RS

Integration Strategies

HARRY FORBES, CONTRIBUTING EDITOR HForbes@ARCweb.com

Industrial considerations for BYOD With the “bring your own device” (BYOD) trend beginning to take hold in the process industries, plant managers and IT groups are taking more interest. Not only do they have legitimate security concerns, but, in refineries and petrochemical plants, field devices must be certified to operate in hazardous locations—a requirement that excludes most consumer devices.

Mobile computing. Mobility is the core value proposition of

the BYOD trend. Mobile computing is rapidly becoming the normal use-case for enterprise IT, rather than the exception. In processing facilities, most workers already own their personal mobile devices, which they often prefer to use. And in every industry, workers have distain over mandates forcing them to carry multiple devices.

Ubiquitous wireless Internet access enables BYOD systems.

Carrier cellular coverage saturated the strategic areas in developed economies many years ago. However, in recent years, carriers have rolled out higher-capacity 4G networks capable of much greater data rates to support the growing numbers of smartphones served by their networks. These service levels compare well with what was provided by wire-line enterprise networks only recently.

The huge volume of the consumer market has also revolutionized the price/performance of smart devices, especially smartphones. At the same time, there has been a convergence of the networks and platforms. Most smartphones support LTE carrier networks, Wi-Fi and Bluetooth local networking along with GPS. There has been a huge convergence in terms of operating platforms toward Android and iOS, with the former champions BlackBerry and Symbian both losing market share, and Windows volumes remaining almost invisible. For industrial service, smartphones, tablets and other mobility devices require enhanced ruggedness, hazardouslocation certification, and, in some cases, dedicated higherperforming interfaces for barcode scanning or other job-specific capabilities.

Management is now the biggest challenge. While

ubiquitous connectivity and technological convergence have enabled the BYOD trend, it has been constrained by the limited capability of enterprises to manage the more complex demands represented by mobile consumer devices operating within the enterprise. Like all management, network management involves the allocation of resources according to policies and rules to achieve enterprise objectives. Effective network management balances a number of objectives. One of these is to improve cost behavior. Enterprise total cost of ownership (TCO) will scale well when network management reduces the labor intensiveness of network operation as the network

grows. But TCO is only one of the attributes of BYOD requiring management attention. Other major factors are: Policy. Organizations need to make policy decisions at the outset of BYOD. These decisions include a set of supported devices and platforms—BYOD does not mean the same thing as bring any device. Likewise, a set of carriers must be selected and rules developed for network selection when multiple networks are available. A set of applications must be supported.

Finally, the policies for cost sharing between employees and the enterprise need to be developed, with a view to keeping the rules simple and understandable, yet comprehensive.

Device management. Dozens of companies offer solutions for mobile device management. This includes provisioning, configuring and updating devices, and deactivating devices as they are retired, as well as protecting/destroying (“zapping”) the content on devices that are lost or stolen. Some level of security and protection from malware is involved. Billing and network policies need to be implemented. These solutions can come from either the carrier or from a third-party enterprise solution.

Mobile application management. Effective mobile application management is critical because the apps come from multiple sources. Besides managing the set of supported applications, distribution of apps must be managed via the major online stores or other means.

Mobile identity management. For BYOD, identity management requires more rigorous authentication, authorization and accounting. Enterprises need an architecture for distributed systems that enables control over user access to services and resources. Multi-factor user authentication is just the first step.

Mobile information management. The coexistence of enterprise and personal data on the same device is drawing attention to the concept of managing device data through various means such as tracking, sand-boxing, encryption and automated data time-outs.

Mobile expense management. This consideration is nontechnical, but nevertheless a pain point for real-world implementations. Enterprises can hardly expect service providers to manage their costs optimally. They have to implement their own policies based on both cost and technical considerations.

HARRY FORBES is a senior analyst at ARC Advisory Group. His research focuses on the impact of industrial networking and wireless technologies on today’s manufacturing. He also covers smart grid and electric power vertical industries. His research topics include the smart-grid, smart-metering and smart-energy technologies. Mr. Forbes is a graduate of Tufts University with a BS in electrical engineering and has an MBA from the Ross School of Business at the University of Michigan.

Hydrocarbon Processing | APRIL 2013 25

platinum standard

UOP’s propylene production technologies outshine the rest Low cost feedstocks, high yield products. There’s no better combination for generating petrochemical profits. As an industry leader in petrochemical process technology for more than 70 years, UOP continues to deliver proven, flexible solutions with high-yield returns. UOP advanced Methanol-to-Olefins (MTO) and Oleflex™ processes provide a higher return on investment, smaller environmental footprint and innovation that is second to none. For advanced MTO, you can use alternative feedstocks such as coal, natural gas and more, and you can produce the high-value olefin of your choice, including propylene and ethylene. Recyclable, platinum-based Oleflex catalysts offer the best performance for environmentally friendly on-purpose propylene production. From low-energy solutions to eco-friendly innovations, UOP sets a standard that shines.

For more information about UOP olefins solutions, visit www.uop.com/olefins. © 2013 Honeywell International Inc. All rights reserved.

Boxscore Construction Analysis

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

Ethylene in evolution: 50 years of changing markets and economics Ethylene is the key building block for the petrochemical industry. This olefin supports 70% of petrochemical industry production and is used to manufacture a wide variety of products for industrial and consumer markets. Adhesives, chemicals, coatings, packaging, construction materials, textiles, rubber and plastics are based on this organic olefin.

The strength of the petrochemical market is directly related to the supply and demand for ethylene. Ethylene consumption is consumer product-driven. This fundamental economic concept has dictated the cyclical nature of the ethylene market.

When supply exceeds demand, petrochemical profits decline, producers curtail construction plans and capital spending, inefficient plants are permanently shut down or mothballed, and global capacity declines. When demand outpaces supply, companies competitively build and expand production capacity.

Supply and demand. Ethylene witnessed double-digit growth rates in the 1960s and 1970s. Supply increased steadily throughout the 1970s, outpacing demand, which declined during the recession of the early 1980s. Demand then increased during the mid-1980s, holding steady at a growth rate of 3%–4% for the remainder of the decade. Global ethylene capacity increased from 46 million tons per year (46 MMtpy) in 1979 to 54 MMtpy in 1990.

By the mid-1990s, over 50% of new ethylene capacity was located in the AsiaPacific region. The US and Western Europe saw improved profits due to high product demand, low feedstock costs and capacity reductions. Some petrochemical producers closed older, inefficient plants, and other operators debottlenecked and upgraded plants with new technologies to reduce operating and maintenance costs, increase capacity, reduce wastes and emis-

sions, and improve reliability and safety.

Most plants constructed during this time had a capacity of 400 thousand tons per year (400 Mtpy) to 900 Mtpy and a cost of $400 million (MM) to $800 MM. Global ethylene capacity increased to 92 MMtpy by the end of the decade.

The new millennium saw the continuation of the cyclical wave of demand chasing supply. Advancements in construction materials and technologies enabled the design and construction of larger ethylene facilities. Global ethylene capacity exceeded 140 MMtpy by the end of 2010, with the main wave of construction occurring in the Middle East and Asia-Pacific regions. The Middle East benefitted from low-cost natural gas feedstock that helped facilitate expansions to support global trade aimed at the European and Asian markets. China’s petrochemical industry

experienced incredible growth by producing raw materials for the overall manufacturing base, with the goal of exporting petrochemical-based goods.

Presently, demand is outpacing supply, and new project announcements have dominated the petrochemical landscape. Global ethylene capacity is expected to rise 17% through 2016, reaching over 170 MMtpy. Ethylene plant capacities now exceed 1 MMtpy at a cost of over $1 billion (B).

The majority of new capacity will be located in the Asia-Pacific and Middle East regions. In China alone, domestic ethylene demand will spur a 50% rise in output by 2015, to 25 MMtpy. Meanwhile, over the past five years, Middle Eastern ethylene capacity has doubled to over 26 MMtpy. Much of the new construction has taken place in Saudi Arabia,

FIG. 1. Linde’s first all-inclusive ethylene plant built for Veba Chemie in Scholven, Germany.

Hydrocarbon Processing | APRIL 2013 27

Boxscore Construction Analysis which accounted for 65% of new ethylene capacity in the Middle East. Cheap ethane feedstocks and proximity to export markets in Asia and Europe have provided the Middle East with an advantage over AsianPacific facilities, which are naphtha-based.

This scenario could change over the near term, however, as cheap ethane feedstocks become available in other regions.

An increase in olefins demand and the availability of cheap ethane are transform-

ing the petrochemical landscape of the US. Project additions, debottlenecks, expansions and restarts could add almost 30%, or 10 MMtpy, of new domestic ethylene capacity by 2017. This would increase US ethylene capacity to over 30 MMtpy.

Additional ethylene capacity could reach even higher levels should additional projects be greenlighted. If so, the US could rival the Middle East in new project activity over the next decade.

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Licensors. Ethylene producers face challenges in processing, energy efficiency and feedstock availability. Although the process of cracking ethylene is fairly similar among licensors, their stories are unique and varied.

CB&I Lummus was created in November 2007 when CB&I acquired Lummus Global from ABB for $250 MM. At that time, Lummus had licensed 40% of all global ethylene and olefins technology projects over the past decade. In the mid-1950s, Lummus was acquired by Combustion Engineering (C-E) to create C-E Lummus.

In 1990, C-E became a wholly owned subsidiary of ABB, which merged with Alstom Power in 1999, forming ABB-Alstom Power. During that time, CB&I was acquired by Praxair. Praxair kept the Liquid Carbonic business and sold CB&I to an investor group, which spun off CB&I in a public offering as a Dutch-incorporated company called CB&I NV. The parent company was organized into two operating subsidiaries: CB&I, consisting of the company’s North American operations, and CB&I BV, consisting of non-US operations.

For the next two decades, CB&I would acquire many new business units, including Lummus from ABB in 2007 and The Shaw Group in February 2013 for $3 B. KBR was created when M. W. Kellogg, constructor of Europe’s first crude oil-based liquid ethylene cracking facility, merged with Brown and Root under the direction of parent company Halliburton.

Halliburton acquired Brown and Root in 1962. In the 1980s, Dresser purchased M.W. Kellogg. A decade later, Halliburton acquired Dresser and formed the large subsidiary company Kellogg, Brown and Root (KBR). KBR eventually broke away from Halliburton in 2007.

To date, KBR has designed more than 20 new ethylene plants with a combined capacity of over 13 MMtpy.

Linde’s origins began in 1870 after founder Carl von Linde published his ideas on improved refrigeration units in the Polytechnic Association’s Bavarian Industry and Trade Journal.

Linde constructed the first plant to recover ethylene by low-temperature rectification in 1931. The company built its first all-inclusive ethylene plant in 1965 for Veba Chemie (FIG. 1). Additional plants were constructed in Europe and on other continents. Linde’s ethylene technology

There is more to Metso than meets the eye.

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Boxscore Construction Analysis has since produced over 20 MMt of ethylene at more than 50 plants worldwide.

Technip has become one of the world’s leading engineering groups through acquisitions of companies with strong technical expertise. In 1999, Technip acquired KTI to obtain its ethylene and steam reforming/hydrogen technology. In 2000, Technip merged with Coflexip.

In 2012, Technip acquired Stone & Webster Process Technology Group from

The Shaw Group. In 2000, The Shaw Group acquired Stone & Webster at auction for $150 MM after Stone & Webster filed for Chapter 11 bankruptcy. Technip purchased most of The Shaw Group’s energy and chemical business, including Stone & Webster. This transaction created the new business unit Technip Stone & Webster Process Technology.

Technip’s merger with Coflexip and its acquisitions of KTI and Stone & Web-

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ster deliver ethylene technologies such as SPYRO furnace design and optimization software, SMK and USC coil technology for gas cracking, GK6, USC coil technology for liquid cracking, SFT technology and the T-PAR Process.

UOP was founded by Jesse Dubbs in 1914. The company was originally named National Hydrocarbon Co., but it was changed in 1914 to Universal Oil Products (UOP). In 1988, UOP became part of Union Carbide and Allied Signal’s joint venture. Honeywell purchased UOP from Union Carbide and Allied Signal in 2005.

UOP’s gas cracking ethylene technology utilizes the Advanced Methanol-toOlefins (MTO) Process, which combines UOP/Hydro’s MTO Process with Total Petrochemicals/UOP’s olefin-cracking process. For naphtha crackers, UOP utilizes the MaxEne process. This application is the latest development in the UOP Sorbex process for adsorptive separation.

The cost, size and scope of ethylene plants have risen dramatically over the past 50 years. However, the acquisitions of ethylene licenses by other companies have compressed the playing field. As global ethylene capacity increases over the next few years, the licensors that can increase energy efficiency, reduce wastes and emissions, and provide the highest cost-efficiency to their customers will dominate future licensing and construction activities.

An expanded version can be found online at HydrocarbonProcessing.com.

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.

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Sulzer Chemtech Tower Technical Bulletin Tray designs for extreme fouling applications Background Today refiners experience a lot of problems with processing of opportunity or heavy crudes. Such crudes have vey high sulfur content and require the addition of amine scavengers before desalting. These amines decompose in the heater and create ammonium chlorides in the presence of water in the top of the crude tower. Dissolved salts start to precipitate and crystallize when solution becomes saturated and water is vaporized. Such fouling starts to grow below and above trays and is hard to remove because deposits are firmly attached to the surface. Eventually, tray orifices become blocked and pressure drop increases drastically, creating a situation where the column needs to be shut down to have the trays replaced or cleaned. Other traditionally fouling services such as sour water strippers and FCC and Coker fractionators face these challenges as well.

SVG-HTM Valves: Solutions for Extreme Conditions While the above solution is ideal for fouling from sediment, it does not completely address the issues of severe particle deposition. In these applications, fouling materials deposit and grow on all surfaces including the underside of the trays and around the edges of the deck orifice. This fouling material then gradually closes the orifice opening from around the perimeter.

Run lengths for small valves in these cases are not long. Such applications require very large openings with large side valve open area.

Sulzer has developed special high lift SVG-H valves for these services. These valves have the proven trapezoidal V-Grid shape with very large openings to resist fouling from particle deposition. The lift of these valves may be larger then 0.7” (17 mm) and can be adjusted depending on the fouling severity.

Historically, standard raised orifice devices such as Sulzer V-GridTM valves have proven to be resistant to scale and fouling.

However, in such aggressively fouling environments, special designs need to be considered.

Anti-fouling VG AF TM Trays Industrial practice shows that trays with large, elevated orifices operate substantially longer in fouling services. The large orifices take longer to foul and the raised design keeps the opening away from the heavier sediment near the tray deck.

In these difficult applications, Sulzer typically uses large fixed valves such as SVG or LVG valves in combination with push valves and a stepped outlet weir. The push valves keep the Tray Deck with SVG-HTM and Push Valves liquid and solids moving uniformly across the tray deck and the stepped outlet weir keeps the solids from accumulating at the end of the tray deck. This design can often increase column run When used in combination with VG AF anti-fouling tray features, lengths by a factor of 2-3 as compared to conventional designs. the SVG-H valve can delay deposition fouling substantially. A general rule of thumb would be that run length should increase proportional to the valve lift. In many cases, that results in a 50-100% increase in run length over previous best available fouling resistant tray technology.

The Sulzer Refinery Applications Group Sulzer Chemtech has over 50 years of operating and design experience in refinery applications. Sulzer has the know-how and the technology to provide reliable, high performance designs in severely fouling applications.

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| Special Report PETROCHEMICAL DEVELOPMENTS The outlook for the global petrochemical industry is tied to the accessibility of low-cost feedstocks, especially natural gas. The ethane-based petrochemical industry is thriving and supported by abundant, lower-cost shale gas.

Investment in more energy-efficient technologies is driving new project and revamp activity for petrochemical facilities worldwide.

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Special Report

Petrochemical Developments M. ERAMO, IHS Chemical, Houston, Texas

Shale energy resources driving resurgence for ethylene industry The abundant supply of North American shale energy resources is proving to be not only a boon for exploration and production (E&P) companies and energy consumers, but it is also changing the profitability landscape for the continent’s ethylene producers. According to a recently published report, these shale energy resources are driving chemical industry job growth, low-cost ethylene production, significant profitability, and a competitive resurgence for the continent’s producers of ethylene, one of the most essential building-block chemicals in the petrochemical industry.1 Renaissance for North American producers. In the US, due to the fore-

casted low-cost feedstock scenario providing for globally competitive economics, nearly 11 million metric tons (MM mt tons) of new ethylene capacity has been announced for North America, which is a significant amount of new capacity given the lack of any investment activity for more than a decade. This news is a welcome development for ethylene producers in the region, who were, until recently, executing plans that included capacity closures and asset consolidation.

Not only does this increased capacity mean more low-cost production to both domestic and export markets, but it also means that new, long-term, highly skilled and well-paying jobs will be added in the US, including operators, engineers and maintenance personnel. According to industry research, for every one of these chemical jobs added, three others are created elsewhere, so the job market impact is considerable. Pennsylvania, Ohio and West Virginia are several of the US states likely to see petrochemical job growth, thanks to shale energy resource availability.

Reverse trend. The US ethylene industry is experiencing a complete turnaround. Five years ago, the industry was trying to determine who was going to shut down capacity. Now the US ethylene industry is running at near-maximum capacity utilization and is seeking to add significant increments of new production.

As a result of increasing the availability of low-cost feedstocks, there is a tremendous amount of capital investment underway, including new infrastructure needed for feedstock supply, ethylene and ethylene-derivative capacity, and new logistics investments to support higher levels of ethylene-derivative exports. Present forecasts are calling for the first wave of new investment to start up as early as 2016. What’s exciting for the long-term health of the industry is that many of these investments are not just being made

by US-based producers, but also from producers based in other regions, including the Middle East, Asia and Europe.

‘Bellwether’ effect. Why are these de-

velopments in ethylene capacity additions and production so important? Quite simply, it is because ethylene is the “bell weather” product for assessing the health of the petrochemical industry. Considered the workhorse of the petrochemical industry, the ethylene market is by far the largest market of the basic petrochemical building blocks, including olefins, aromatics, chlor-alkali and syngas chemicals.

Polyethylene—which is the largest ethylene-derivative market, consuming nearly 60% of all ethylene produced— is used primarily in a wide variety of nondurable goods applications such as packaging materials. Ethylene oxide (used in antifreeze, polyester fibers and detergents), ethylene dichloride [used in polyvinyl chloride (PVC) films, coatings

and pipes], and ethylbenzene/styrene (which is used in polystyrene packaging and ABS resins) are also important ethylene consumers. The ethylene steamcracker typically represents the heart of a petrochemical complex.

The ethylene industry tends to be a very cyclical industry in terms of profitability. However, in the US, low regional ethane prices are supporting high ethylene margins and are creating a very profitable environment for producers, despite a global oversupply situation. According to new research, ample supplies of natural gas liquids from shale development are keeping ethane prices low relative to other steam-cracker feedstocks.1 As a result, US ethane-based producers experienced excessively strong profits in 2012, which contrasted with naphthabased producers in the US and in other parts of the world.

These US capacity additions will bring much more supply than the domestic market demands, so there will be significant quantities of higher-value ethylene derivatives exported to Asia, where demand is greatest. This supply resurgence is causing a substantial shift in ethylene-derivative trade patterns, to the benefit of North American producers.

Global market. The global demand for ethylene reflects a mixed demand growth environment—rapid expansion in developing regions and slower growth in developed regions. After contracting considerably in 2008, world ethylene demand is forecast to be approximately 135 MM mt tons in 2013, which is higher than the previous demand peak of nearly 130 MM mt tons in 2012. In the next five years, global ethylene demand is forecast to grow at more than 4%/yr, reaching nearly 160 MM mt tons by 2017.1 Hydrocarbon Processing | APRIL 2013 33

Petrochemical Developments Asian market. Demand in Asia, particularly China, continues to grow since China’s chemical industry remains unable to meet the rapidly growing domestic consumption requirements. Sharp increases in consumption, stemming from China’s rapid industrialization, have spurred the development of numerous new domestic ethylene and derivative complexes that are either under construction or planned for the next five years, including several coal-

based facilities. The emergence of coal as a potential olefins feedstock in Northeast Asia, however, warrants close monitoring.

As a result of high oil prices in the past several years, there has been tremendous domestic interest to further develop and utilize the abundant coal resources in China. Although the investment involved is often massive, the operating costs of the coal-to-olefins units will be very low, and the units will be competitive

Velan ABV designs, manufactures, and supports highly reliable actuated valves and control systems for the energy market.

Based in Italy, the company has recently opened a second plant and serves the oil and gas; up-stream, mid-stream, and down-stream applications; geothermal processes; chemical and petrochemical industries; and oil and gas transportation.

Our new optimized KEY-C (caged ball control) valve has an innovative anti-cavitation trim that ensures long service life, no vibrations in your system, and lower noise levels. It also offers a wider range of options and higher capacity than most single-seated globe valves.

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compared to domestic naphtha-based steam-cracker complexes, as well as most imports of olefin derivatives. Assuming that China’s strong economic growth can be sustained, this nation will continue to be a major target for petrochemical and derivative exports originating from the Middle East, other parts of Asia and North America.

The net-equivalent imports of ethylene and ethylene derivatives into Northeast Asia increased significantly in 2012, reaching an estimated 8.8 MM mt tons.1 That trend is expected to continue, with the net deficit expected to approach 10 MM mt tons by 2017 and to exceed 15 MM mt tons by 2022.

With the opportunities and challenges presented by this rapidly developing abundant shale resource in North America, there is doubt that the industry will continue to witness the snowball effect of investments that are sure to follow. Refining and petrochemical investments are tied to midstream investments, as well as to other transportation, storage and shipping investments. Increasing capacities at individual petrochemical facilities add high-paying and, equally important, longterm jobs that help fuel local economies and small businesses that, in turn, support the workers who operate these facilities.

It is an exciting time to be a part of this industry, but also an opportunity for the many professionals who work in this industry to educate and remind our fellow consumers about the positive impacts of the shale energy developments happening in North America, but also the interconnected petrochemical value chain that helps drive much of both the US and world economies, and delivers products that enrich and enhance daily life.

1

NOTES IHS Chemical 2013 World Ethylene Analysis covers historical developments and future projections for supply, demand, capacity and trade in the global ethylene and ethylene derivative markets for 2007 to 2022. www.IHS.com.

MARK ERAMO is vice president, chemical market insights, at IHS Chemical, a leading provider of information, insight and analysis for the global chemical industry. He oversees the chemical market insight teams that provide in-depth market research and analysis on nearly 300 chemical and plastics products. Mr. Eramo joined IHS is 2011 through the acquisition of CMAI, where he was employed 14 years.

Before joining IHS, he worked for more than 12 years in the petrochemicals, vinyls and surfactants industries with Vista Chemical Co. Mr. Eramo holds a BS degree in chemical engineering from Cornell University.

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Special Report

Petrochemical Developments R. KLAVERS and M. J. TALLMAN, KBR, Houston, Texas

North American olefin producers riding the shale gas wave

20

100

16 14

80

Crude (WTI) Natural gas (US) Gas as % of crude

12 10

60

8

40

6 4

20

2 0

0 00 01 02 03 04 05 06 07 08 09 10 11

12 13 14 15 16

Source: IHS Chemical

FIG. 1. Energy pricing trends for crude oil and natural gas, 2000–2012.

C2H4 peak

Furnace developments. When revamping or expanding ex-

0.10 sec 0.15 sec 0.4 sec

Ethylene yield

isting crackers, proper selection of pyrolysis technology with high-ethylene selectivity is critical. A higher ethylene yield means less furnace effluent for a given ethylene production level, thus less impact on the recovery section of the plant.

“One-pass” coils are designed for typical coil residence time in the range of 0.1 sec to 0.15 sec, providing a much shorter residence time than other designs. The short residence time results in higher ethylene yields, as shown in FIG. 2.1 Another important factor in applications for existing plants is the ability to run the furnaces at high ethane conversions; unconverted ethane must be processed by the recovery section and then recycled back to the furnaces. The unconverted products take up space in both the recovery section and furnaces. FIG. 3 illustrates the impact of ethane conversion on the

120

Forecast

18

Gas pricing as % of crude

Renaissance for North America. Nearly 15 years have elapsed since the last grassroots ethylene plant was built in North America. However, with the prospect of abundant lowcost ethane, several producers have announced intentions to construct new ethylene capacity. As many as 12 producers have announced such plans. While it remains to be seen how many plants will actually be built, there is little doubt that there will be a significant increase in ethylene production capacity in North America in the near term. Most North American ethylene producers are also investing in their existing crackers to increase capacities and light feedstock cracking ability.

recycle ratio. Furnaces using “one-pass” coils are capable of consistently running at 75+% ethane conversions. The combination of high ethylene selectivity and high ethane conversions allows for up to 10% more ethylene production for an existing recovery section.1 Finally, the furnace layout is also a key factor for expansion or replacement projects. Compact, cabin-style firebox arrangements allow very-large-capacity furnaces [more than 200,000 tpy (200 Mtpy)] when cracking ethane and up to 200 Mtpy when cracking naphtha in a single-cell firebox. Such designs use less plot space than twin-cell arrangements to achieve the

Energy cost, $/MMBtu

Feedstock prices are a major determinant factor in ethylene production costs. Feedstocks for steam cracking are derived from natural gas (ethane, propane and butane) or crude oil— naphtha and gasoil (GO). Steam crackers in Western Europe and Asia are mostly based on naphtha feedstock, while crackers in the Middle East, North America and parts of Southeast Asia are mostly based on gas feeds. Development of shale gas in North America has led to a significant drop in natural gas prices relative to crude oil prices. FIG. 1 shows the near-term trends for energy prices, especially for crude oil and natural gas (US), and the resultant ratio.

Most natural gas fields have a quantity of associated heavier hydrocarbons, ranging from ethane to liquefied petroleum gas (C3 and C4 ) and, in some cases, gas condensate with wide boiling ranges. One consequence of the increased availability of natural gas is the sudden increase in ethane availability at very low prices.

0.7+ sec

Ethane conversion

FIG. 2. Ethylene yields vs. ethane conversion.

Hydrocarbon Processing | APRIL 2013 37

Petrochemical Developments same capacity. The available footprint for the new furnace is often an important consideration in revamp situations.1 Liquid crackers—How to avoid getting crushed. At the other end of the spectrum, the world’s liquid crackers, largely operating in Europe and Northeast Asia, incur the highest ethylene production costs, as illustrated in FIG. 4. Operating companies struggle to remain profitable under the present market conditions. These liquid crackers have become the “marginal producers,” and they will be under pressure from a margin and operating rate perspective.

1.8

Recycle ratio

1.6

1.4

1.2

1.0

55

60

65 70 Ethane conversion, %

75

80

FIG. 3. Impact of conversion on the recycle ratio.

Defining issues. Availability and pricing of coproducts are

among the key issues reshaping the olefins industry. On a global basis, the total yield of coproducts from steam crackers relative to ethylene is declining. This is a direct result of the shift toward ethane and other natural gas liquids (NGLs) feedstocks.

Ethane is a very good feed for ethylene production. With modern cracking furnaces, the ultimate ethylene yield from ethane based on recycle-to-extinction operation is 80+%. However, the yields of propylene and butadiene are very low relative to other feeds, roughly 2% for each.

The global supply of propylene and butadiene has historically been produced primarily as byproducts from steam crackers processing liquid feed such as naphtha or GO. There is a resultant supply shortage for butadiene and propylene. This condition has fostered unprecedented increases and volatility of prices for both hydrocarbons, particularly for butadiene, as shown in FIG. 5. Both propylene and butadiene prices are forecasted to remain well above historical levels. A key strategy for liquid crackers to maintain competitiveness is maximizing the production of higher-value coproducts, such as propylene, butadiene and aromatics. Most liquid crackers can achieve this by lowering cracking severity and increasing propylene/ethylene (P/E) ratios.

New processing choices. Opportunities to improve profitability have many producers seeking alternative means to produce propylene and butadiene. Several companies have invested in propane dehydrogenation (PDH) units. This pro-

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NEW DELHI, INDIA | 9–11 JULY

IRPC 2013 Agenda Day 1 | Wednesday, 10 July 8:30-9:15 a.m.

CONTINENTAL BREAKFAST

9:15-9:30 a.m.

OPENING REMARKS: John Royall, President and CEO, Gulf Publishing Company

9:30-10:45 a.m.

KEYNOTE SPEAKERS R.K. Ghosh, Director (Refineries), Indian Oil Corporation Limited (Refineries Division) Future Challenges and Opportunities for Refining in Asia - Suresh Sivanandam, Wood Mackenzie

10:45-11 a.m.

COFFEE BREAK

11 a.m.-1 p.m.

TRACK 1 - REFINING

TRACK 2 - PETROCHEMICALS

SESSION 1 Session Chair: Syamal Poddar, President, Poddar and Associates

SESSION 2 Session Chair: Eric Benazzi, Marketing Director, Axens

Diesel from Waste Plastics: Use in Vehicles - SK Singal, CSIR-Indian Institute of Petroleum

Catalytic Olefins Technology Enhances Olefins Producers’ Flexibility and Economics - Michael Tallman, KBR

Liquid Fuel from Coal – New Horizons - Atul Choudhari, Aker

Optimization of Olefin Plants - Vera Varaprasad, Indian Oil Corporation Limited

Hydroprocessed Diesel Produced as Byproduct of Bio-Jet Fuel Process: A Superior Fuel in IC Engines - M.O. Garg, Director, CSIR-Indian Institute of Petroleum

Maximizing pX Production Through Optimizing the Phenyl-methyl Group - Chuck Fink, GTC Technologies

Minimizing Impact on Carbon Footprint while Processing Opportunity Crudes - Tammy Traphdar, Technip

Polymer Process Developments and Second Generation Metallocene Catalysis - Howard Paul, SK E&C USA, Inc.

1-2 p.m.

LUNCH

2-2:30 p.m.

COFFEE & DESSERTS - EXHIBIT HALL

2:30-4:30 p.m.

TRACK 1 - REFINING

TRACK 2 - PETROCHEMICALS

SESSION 3 Session Chair: P.P. Upadhya, Managing Director, MRPL

SESSION 4 Session Chair: Giacomo Fossataro, General Manager, Walter Tosto S.p.A

Axens Solutions for Middle Distillate Hydroprocessing: A Focus on Revamping Challenges of Integrating Future Refineries and Petrochemical Plants, and How to Deal with Them - Romel Bhullar, Fluor Corporation and New Catalyst Technology - Stefania Archambeau, Axens

4:30-5 p.m.

5-6:30 p.m.

6:30-8 p.m.

Implementation of an Integrated Refinery Complex Production Reconciliation: Benefits and Challenges - Srinivas Badithela, HMEL

Economics-Refinery/Petrochemical Integration - Sanjiv Singh, Panipat Refinery and Petrochemical Complex, Indian Oil Corporation Limited

Effect of Reliability on Return of Invested Capital ROIC - Logan Anjaneyulu, Valero

Dynamic Simulation: An Efficient Tool for Verifying Plant Integrity and Control System Design - Sheo Raj Singh, Engineers India Limited

Challenges in Design and Engineering of High Pressure Hydro Treaters and Avenues for Energy Optimization - K. Sudhaker, L&T Chiyoda Ltd.

Optimum Isolation Valve Sealing on Black Powder-Generated Gas Processing - Omar Al Amri, Saudi Aramco

AFTERNOON BREAK TRACK 1 - REFINING

TRACK 2 - PETROCHEMICALS

SESSION 5 Session Chair: A.S. Basu, Managing Director, Chennai Petroleum Corporation Ltd.

SESSION 6 Session Chair: Carlos Cabrera, Executive Chairman, Ivanhoe Energy

New Solutions from Eco-friendly Gasoline Production - Adarsh Tripathi, RRT Global

Maximizing Operational Efficiency and Safety by the Use of a Digital Plant Sloane Whiteley, AVEVA

Overcoming Pressure Drop Limitations in Hydroprocessing Reactors Mahendranadh Desu, Hindustan Petroleum Corporation

Case Study: Design, Development and Deployment of Energy Management System (ISO-50001 : 2011) at an Integrated Petrochemicals Complex Mayur Talati, Reliance Industries Ltd.

Optimum Refinery for Changing Feed and Product Demands - Samir Saxena, KBR

Computational Fluid Dynamics as an Emerging Tool to Improve the Reliability of the Plant Operations - S. Sathish Kumaran, Technip

CLOSING RECEPTION - Exhibit Hall

IRPC 2013 Agenda Day 2 | Thursday, 11 July 8:30-9:15 a.m.

CONTINENTAL BREAKFAST

9:15-9:30 a.m.

OPENING REMARKS: Stephany Romanow, Editor, Hydrocarbon Processing KEYNOTE SPEAKERS

9:30-10:15 a.m.

Dr. Ajit Sapre, Group President, Research and Technology, Reliance Technology Group

10:15-10:45 a.m.

ExxonMobil Singapore (invited)

10:45-11 a.m.

COFFEE BREAK

11 a.m.-1 p.m.

TRACK 1 - REFINING

TRACK 2 - PETROCHEMICALS

SESSION 7 Session Chair: K.Venkataramanan, CEO and Managing Director, Larsen Toubro

SESSION 8 Session Chair: John Baric, Licensing Technology Manager, Shell Global Solutions International B.V.

Petrobras ULSD Revamps - Silvio Jose Vieira Machado, Petrobras

Phyrophoric Hazard of Catalyst Handling in Refining and Petrochemical Industry - Renato Benintendi, Foster Wheeler Energy Limited

Advanced Techniques for Enhancing Hydrogen Availability - Sanjiv Ratan, Technip

Catalysis Solution for Acetylene and Methyl-Acetylene & Propadiene (MAPD) Selective Hydrogenation - Shankhaneel Borah, Sud Chemie India Limited, a Clariant Group Company

Improve Profitability by Flexibility Hydrocracking Technologies - Sing Yong Extending the Performance of Maximum Propylene Catalyst and Additives - Vipan Goel, Grace Catalysts Technologies Lim, Criterion Catalyst & Technology Recovery of Valuables from Refinery Off Gases to Increase Profit Margins Siddartha Murkerjee, Lurgi India Company Pct. Ltd. 1-2 p.m.

LUNCH

2:00 - 2:30

COFFEE & DESSERTS - EXHIBIT HALL

2:30-4:30 p.m.

4:30-5 p.m.

5-6:30 p.m.

6:30-8 p.m.

Comparative Study of Conventional Petrochemicals (Ethylene Glycol) With the Bio Based (Bio-Ethylene Glycol) Production with the Application of Life Cycle Methodology and Foot Printing Tools - Sharma Rajeev Kumar, India Glycols Limited

TRACK 1 - REFINING

TRACK 2 - PETROCHEMICALS

SESSION 9 Session Chair: B.K. Namdeo, Executive Director-International Trade & Supplies, Hindustan Petroleum Corporation Limited

SESSION 10 Session Chair: Chakrapany Manoharan, Director-Refinery, Essar Oil, Ltd.

Energy Consumption Update in Amuay Refinery of Paraguaná Refining Center (CRP) - Daniel Reyes, PDVSA

EDC Pyrolysis Furnace Radiant Section Tube Failure-Case Study - K. Ramesh, Reliance Industries

Profit Improvement Program in KNPC Refineries - Abbas Shamash, Kuwait National Petroleum Company

Temperature Dependent Catalysts: Optimizing Performance and ROI with Advanced Temperature Measurement Systems - Eric Heidt, Daily Thermetrics Corporation

A Study of the Mechanical Failure of Spent Acid Regeneration Combustion Chamber - Subratat Saha, Reliance Refinery

Controlling Corrosion in Process Refrigeration Systems and Gas Compression Packages - Amey Majgaonkar, Kirloskar Pneumatic Co. Ltd.

Refinery Operation Planning: The Same Application Manages Both Mid-term Planning and Optimized Scheduling – Aurelio Ferrucci, PROMETHEUS S.r.k.

Best Practices for Mitigation of Corrosion in Hydrocarbon Processing Industry - K. Sudhakar, L&T Chiyoda Limited

AFTERNOON BREAK TRACK 1 - REFINING

TRACK 2 - PETROCHEMICAL

SESSION 11 Session Chair: Stephany Romanow, Editor, Hydrocarbon Processing

SESSION 12 Session Chair: A.K. Purwaha, Chairman and Managing Director, Engineers India, Ltd.

Analysis of FCC Reactor Cyclone Flow - Bontu N. Murthy, Reliance Industries, Ltd.

Virtual Reality as Effective Tool for Training Field Operators and Making Decisions: Experiment Results - Simpone Colombo, Virthualis

Sour Water Stripper Units with High Cyanides Contents - Vikas Kapoor, Fluor

E-Learning and Universal Simulation for Competency Development - Santosh Joshi , GSE EnVision

Coke Drum Unheading - Curtiss Wright

Regaining Operating Excellence Through Enhanced Training - Michael A. Taube, S&D Consulting LLC

CLOSING RECEPTION

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Conference registration includes: • Pre-conference tour of Indian Oil’s Panipat Refinery & Petrochemicals Complex (9 July 2013)* • Two-day conference program (10-11 July 2013) including keynote addresses, general presentations and panel discussions • Breakfasts, lunches and refreshment breaks • Access to exhibition floor throughout conference activity *Refinery tour registration is offered on a first-come, first-served basis. Space is limited.

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Petrochemical Developments

US price ratio to ethylene, %

yield (ethylene plus propylene) and the total P/E production cess is capital-intensive projects. PDH units can be justified as ratio will be substantially increased. long as sufficient margin exists between low-cost propane feed and high-value propylene products. In China, as well as in other parts of Asia, there is great activity for onpurpose butadiene via oxidative dehydrogenation; Many olefins producers are seeking this is also a highly capital-intensive option. methods to improve operating margins, Catalytic-cracking technology for olefins production can provide synergistic effects with tradiand also seeking alternative “on purpose” tional steam cracking. These catalytic technologies propylene production technologies, which target propylene and aromatics yields as a primary focus; the design can be tailored depending on the will necessarily become more prevalent. available feedstocks. Such catalytic olefin technoloNew olefins technologies offer superior gies use fluid catalytic cracking (FCC) processes, which are similar to a traditional refinery FCC unit economics. Availability of coproducts are (FCCU).2 FIG. 6 is a flow scheme of the catalytic olealso reshaping the olefins industry. fins reactor.2 Like any refinery FCCU, the reactor (converter) has of four sections: riser/reactor, where all of the cracking reactions occur; disengager, where the cracked gas Flexibility: Key to future competitiveness. In the last deis separated from the catalyst; a stripper, where product gases cade, we have seen tremendous changes in the olefins industry: entrained with the catalyst are recovered; and a regenerator • North America has gone from being least competitive to where coke formed on the catalyst is removed by burning it being second; Europe has gone from second to last. with air. Accessory systems for the FCCU include air supply, • Coproduct prices have reached historical highs. Some flue-gas handling, heat recovery and catalyst storage. coproducts, such as butadiene, have endured huge volatilities, Fresh naphtha can be cracked catalytically, resulting a prowith prices skyrocketing to above $4,000/ton and then declinpylene yield nearly doubled relative to steam cracking, with a ing to $1,500/ton within months. typical P/E production ratio of nearly 1 as compared to 0.5– While we can foresee the next couple of years with some 0.6 for traditional steam cracking. Olefin-rich streams, such as level of confidence, ethylene plants are expected to run for deolefins plant C4 /C5 byproducts, can produce up to 40% of the cades. It is impossible to forecast with any level of confidence what will happen to the industry over the long term. Thus, opultimate propylene yield, with a P/E ratio of approximately 2.

This technology can be especially beneficial to present-day 250 naphtha-cracking olefin producers. Studies show that the ad225 dition of a catalytic olefin converter (designed to recycle crack US propylene-to-ethylene price ratio US butadiene-to-ethylene price ratio 200 to extinction C4 raffinate), single-stage hydrogenated C5s and 175 gasoline nonaromatic raffinate, integrated with the cracker, 150 can improve the operating margin of an existing 1 million125 tpy steam cracker by $55–65 million/yr. There is tremendous 100 flexibility allowable with such an approach. For example, the 75 C4s can be recycled to the catalytic olefins converter after the 90 extraction of butadiene, isobutylene (for MTBE production) 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 and/or 1-butene (as a comonomer for polyethylene). This can Source: IHS Chemical also be done in a new grassroots cracker and it is an excellent FIG. 5. US P/E pricing and C4-to-ethylene price ratio, 1990–2016. strategy in a capacity expansion/revamp project. The olefins

2010 ethylene production cost, $/metric ton

1,250

To flue gas system

1,050

Catalyst fines

West Europe

BFW

850 650

Catalytic olefins reactor/ regenerator

Northeast Asia

North America Southeast Asia

450

Reactor effluent to recovery

Steam Fuel oil

Oil-wash tower Catalyst storage and handling

250 50 50

Recycle

Middle East 20

Source: IHS Chemical

80 100 40 60 Cumulative production capacity, million metric tons

FIG. 4. 2010 Ethylene industry production cash cost.

Fresh feed

120

140

Regeneration air

FIG. 6. Flow diagram of the catalytic olefins process.2 Hydrocarbon Processing | APRIL 2013 39

Petrochemical Developments erating flexibility should be a keystone of any new grassroots plant or revamp project. Such flexibility will allow the producer—at small, justifiable increases in capital outlay—superior ability to respond to changing market dynamics and continuously adjust operations to maximize profit at any given time.

The ability to crack fresh naphtha feed in both pyrolysis furnaces and a catalytic olefins converter provides the operator with significant flexibility to meet changing market conditions and demands with respect to the product slate. On a monthly or even weekly basis, there can be volatility in the relative prices of ethylene, propylene, butadiene and aromatics. Diversity, with respect to cracking technologies, provides operators the flexibility to respond to changing market conditions. In general, from most feeds, conventional pyrolysis will provide higher yield of butadiene and slightly higher yield of ethylene, while the catalytic olefins converter will provide higher yields of propylene and aromatics. Having the flexibility to divert fresh feed (or recycles) either to cracking furnaces or to an FCC-type reactor allows the operator to continuously shift operations and maximize return regardless of the prevailing market conditions.

Catalytic olefin units also allow significantly greater flexibility in feeds. In addition to fresh naphtha and the steam cracker byproduct C4 and C5 streams, it would be possible to also integrate: • Olefin-rich feeds from other sources—such as a nearby refinery FCC, coker or visbreaker unit—into the olefins plant,

which would not be possible with steam cracking alone, unless the feeds were first hydrogenated • Oxygenates, such as methanol, ethanol or others, which are converted to olefins in the FCC-type reactor.

NOTES Advance furnace technology by KBR features “one-pass” coil designs. New designs increase conversion, thus reducing recycle. KBR’s unique furnace design and configuration offers several key advantages for the expansion of existing crackers.

2 KBR’s catalytic olefins technologies use process hardware very similar to a traditional refinery FCCU. KBR’s catalytic olefin designs incorporate unique and innovative patented design aspects that can more efficiently handle lighter feeds than in a traditional refinery FCCU. 1

RIK KLAVERS is the vice president of petrochemicals for KBR’s technology business unit and is responsible for KBR’s olefins and chemicals technologies. KBR Technology covers process licensing, basic engineering, catalysts, proprietary equipment, and technical services. Mr. Klavers is a mechanical engineering graduate from the University of Twente in The Netherlands, and has worked in the process industries for 25 years.

MICHAEL J. TALLMAN is the manager of KBR’s catalytic olefins technology. His duties include developing, marketing and licensing KBR proprietary catalytic technologies for the production of olefins. Mr. Tallman has 32 years of industry experience. He holds a BS degree in chemical engineering from the Rose-Hulman Institute of Technology, and holds four US patents. Mr. Tallman is a registered Professional Engineer in the state of Texas.

M

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aeSShiel Safety Lifecycle Management aeShield™ System Sys stem is a comprehensive platform for executing exe ecuti a sustainable risk management pro ogram through automation of the safety program lifecycle life ecycle process. The system provides a complete comp solution by maintaining rela ation relationships among the risk reduction ttargets, ta rrgets design verification calculations, inspection in nspecti and test plans for integrity ma anage management, and actual historical data. aaeShield ae SShiel tracks and analyzes PSI, providing aalerts al eerts and a reports on process safety health in real r ti time. aeShield facilitates work flow w an and compliance with ISA84.00.01/ IEC C 61511 615 and the related requirements of O OSH OSHA 1910.119.

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Hazardous events pose serious threats to operating companies by negatively impacting reputation and commercial performance as well as endangering people or the environment. A key goal of sustainability is to prevent these hazardous events from occurring and to maintain compliance and conformance as efficiently as possible through improved data management. A sustainable operation can be difficult to maintain when vital process safety information is found in multiple places and cannot be readily analyzed. By connecting real-time operating data back to a single model of the safety provisions of the facility, aeShield™ tracks and analyzes the health of risk management systems.

Key features of aeShield include failure rate data validation, override risk assessment, and Management of Change (MOC) tracking, and health meter displays.

same risk, and a projection of risk reduction gaps created when the function is bypassed.

Management of Change (MOC) Tracking

aeShield offers a revision tracking feature that supports capital projects or continuous improvement efforts. PSI is tracked in the same system as the master data and users can create “sandbox” projects to assess potential changes without affecting the master records.

Users can see changes made by others in real time thereby eliminating the confusion of flat files. The AsBuilt step in the MOC process allows users to view what information was changed before updating the master record. This step also notifies others who have checked out a copy of that file.

Failure Rate Data Validation

aeShield maintains sustainable operations by evaluating real test results to compare actual failure rates recorded in operations to the failure rates assumed when the SIL verification was completed. This comparison allows plants to make the best use of resources by increasing test intervals and analyzing ongoing equipment performance.

Equipment Unavailability

Rolling Annual Average

Historian Tag: TT-1001

0.6%

Logic Solver: AES-101

| | ||| | | | ||| || |||

| ||

|| | | | |||||| ||

|||||||||||

|| | |

0.8%

|||

|||

0%

||

||

0.2%

||

||

SIF: AES-101-001 Achieved SIL: 2

0.4%

1%

1.2%

FIG. 1. Easily monitor safety related equipment unavailability.

Override Risk Assessment

A key component of sustaining integrity in the safety instrumented system (SIS) is to visualize the impact on risk reduction caused by bypassing critical equipment. aeShield generates override analysis reports for technicians and operations personnel to evaluate what risks these maintenance activities could create.

Risk analysis reports in aeShield allow users to search by tag name to find consequences a safety function is applied to, other protection layers preventing the

FIG. 2. Management of Change (MOC) tracking model.

Focusing on the sustainability of process safety will not only help maintain compliance but also help prevent hazardous events that can lead to serious injuries and loss of production. Organizations can select from a variety of implementation options and services that best fit their needs. aeShield monitors the performance of the safety provisions to provide leading indicators that predict potential failures and incidents. Health meters provide visualization of the safety performance of the facility at multiple levels and alert companies to deviations from the risk management strategy. As an industry leader in process safety and SIS design and implementation, aeSolutions is prepared to assist you at every step of the Process Safety Lifecycle helping achieve compliance and sustainability.

WƌŽĚƵĐƟŽŶ &ĂĐŝůŝƚLJ KǀĞƌĂůů ,ĞĂůƚŚ FIG. 3. Visually monitor the overall safety health of a facility.

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Petrochemical Developments

Special Report

D. WEATHERFORD, BASF Corp., Geismar, Louisiana; and J. FORD, MAVERICK Technologies, Baton Rouge, Louisiana

Use model-based temperature control for fixed-bed reactors A process unit at BASF’s Geismar, Louisiana manufacturing facility contains a series of six packed-bed reactors filled with a proprietary catalyst. This catalyst promotes an exothermic reaction, which then allows for recovery of high-value product.

A process flow diagram is shown in FIG. 1. The steam flow to the first exchanger determines the inlet temperature to the first reactor, while the refrigerated water flow to the second exchanger determines the inlet temperature to the third reactor.

The key operating and control variable is reactor temperature. Higher temperatures favor higher conversion and higher production rate, but the catalyst is extremely heat-labile; i.e., the excursion of only a few degrees Celsius above a critical limit leads to rapid activity loss.

Substantial data analysis has established an optimum temperature profile for setting targets for the second and sixth reactor outlet temperatures. These targets represent operating temperatures that maintain the necessary compromise between high conversion and extended catalyst life.

Periodically, one of the six catalyst beds must be dumped and refilled with new, active catalyst. The bed to be replaced is in the first reactor position. After being filled with fresh catalyst, this reactor goes back into service in the sixth reactor position, with each reactor moving up one position. While the reactor is offline being refilled with fresh catalyst, only one reactor is in service between the two exchangers. A complex system of motor-operated valves (MOVs) and a multiple piping manifold is required to automatically achieve the movement of the reactors into their new positions as the catalyst replacements occur.

problem. Proportional-integral-derivative (PID) controllers were previously configured and implemented in the distributed control system (DCS) for control of the second and third reactor outlet temperatures. The second reactor outlet temperature controller adjusted the steam flow to the first exchanger, and the third reactor outlet temperature controller adjusted the refrigerated water flow to the second exchanger.

The operator was expected to adjust the setpoint of the third reactor outlet temperature to achieve the desired sixth reactor outlet temperature. Due to the significant dead time and lag time between changes in steam and refrigerated water flows to the respective exchangers, and the effect of those changes on the temperatures being controlled, both controllers were detuned with large proportional band and long reset time. The second reactor outlet temperature controller was being utilized by the operators in auto mode only sparingly, and the third reactor controller was not used at all.

Temperature control was observed to be ragged, especially during and immediately after reactor bed recharging. In addition, the reactor temperature profile was influenced, in a diurnal cycle, by the heating up of equipment during the day

Control

FC

LP steam

and cooling at night. The lack of good temperature profile control caused excessive catalyst activity loss, which, in turn, caused unit productivity to suffer.

BASF sought a DCS resident solution to achieve more stable reactor temperature control, and decided to team with a technology solutions firm to design and implement a solution. solution. The temperature rise across any reactor bed is a direct measure of conversion, and this is the case for any given reactor charge rate. At constant feed composition, as is the case for this process, the temperature rise is a function solely of inlet temperature and catalyst activity. At any given time, and at steady state, the inlet and outlet temperatures can be related by a non-rigorous, but effectively simple expression (Eq. 1):

Control

To = K × Ti

(1)

Here, K is directly related to catalyst activity. As the catalyst ages and loses activity, K decreases.

During a typical run between catalyst changes, catalyst activity slowly degrades in all the beds, causing the reaction to shift downstream. The inlet temperature to the first reactor must be gradually increased, while the inlet

Refrigerated water

TC

TC

Feed 1

TI

FPC

Feed 2

Rx 1

Rx 2

Rx 3

Rx 4

Rx 5

Rx 6

To purification and recovery

FIG. 1. Diagram showing packed-bed reactors with proprietary catalyst.

Hydrocarbon Processing | APRIL 2013 43

Petrochemical Developments was perfectly sufficient to describe the behavior of this system. A typical dead time for one reactor at normal feedrates is around 30 minutes.

Since the prediction is never perfect, a model bias is maintained (Eq. 3):

temperature to the third reactor must be gradually decreased to maintain constant outlet temperatures from the second and sixth reactors, respectively. Even so, if K is known at any given time during the run, then the outlet temperature can be predicted from the simple relationship described in Eq. 1. Furthermore, K can be calculated at any time by inverting the above equation.

Dynamically, the outlet temperature can be predicted in real time by time-delaying the inlet temperature and applying it as shown in Eq. 2: To, pred = K × Ti, lagged

Bias = To − To, pred

K is calculated independently (Eq. 4): Kfiltered = (To ÷ Ti, lagged)heavily filtered

(2)

SP

Feed-forward compensation

Feed 1

SPTi = (SPTo – bias) ÷ Kfiltered

TI

Operator entry

Reactor 2 outlet PV temperature control (model-based) SP Reactor 1 inlet temperature control (smart PID) PV

Reactor 6 outlet PV temperature control (model-based) SP Reactor 3 outlet PV temperature control (model-based) SP Reactor 3 inlet temperature control (smart PID) PV

TI

TI

TI

TI

TI

FPC

Rx 1

Feed 2

(5)

Implementation in the DCS. The control solution was implemented in the DCS, making use primarily of advanced calculator blocks. These blocks allow

LP steam

FC

(4)

A 60–90-minute linear filter eliminates high-frequency measurement variance and noise.

Finally, the setpoint for the reactor inlet temperature predicted to maintain the reactor outlet temperature can be calculated as shown in Eq. 5:

Here, Ti, lagged is the inlet temperature appropriately lagged to “line up” in time with the outlet temperature. The relationship between the outlet temperature and the lagged inlet temperature is often referred to as a process identification model.

Step-testing of the reactor inlet temperatures confirmed that a model consisting of dead time and a first-order lag Operator entry

(3)

Rx 2

Rx 3

Rx 4

Rx 5

Rx 6

To purification and recovery

FIG. 2. Diagram showing stabilization of first reactor inlet temperature.

70

70

60

Rx 2 outlet

60

Rx 2 outlet

50

Rx 6 outlet

50

Rx 6 outlet

40

Rx 3 outlet Rx 3 inlet

Rx 3 outlet

30

°C

°C

40

user-written programs that provide both calculation and logic functionality, and that can read and write most system variables. Each program allows a maximum of 50 steps, which was entirely adequate for these controls.

The control solution described below is for the second reactor outlet temperature control adjusting the setpoint of the first reactor inlet temperature control.

Similar, but simpler, solutions were implemented for the third and sixth reactors, where the sixth reactor outlet temperature control adjusted the setpoint of the third reactor outlet temperature control using a similar model (with long dead time and lag time); and the third reactor outlet temperature control adjusted the setpoint of the third reactor inlet temperature control using a similar model.

The first phase of the solution involved stabilizing the first reactor inlet temperature to eliminate it as a disturbance variable and as a secondary in the control cascade (see FIG. 2). A first reactor inlet temperature controller was configured using a proprietary PID control algorithm combined with adaptive feedforward compensation for the exchanger inlet temperature and charge rate.

The most important feature of the PID algorithm is discontinuous integral action. Logic built into the algorithm determines, at each controller execution, whether or not integral action should be applied and, if so, how much should be applied based on the progress of the process variable returning to the setpoint.

At each control cycle, a sequence of actions is performed: 1. Identify the second reactor outlet temperature by examining the status of digital inputs for MOVs associated with the flows out of the reactors and into the intercooler. The reactor with the outlet

Rx 3 inlet Rx 1 inlet

30

20

20

10

10

FIG. 3. Reactor temperatures over one-week duration prior to APC installation.

44 APRIL 2013 | HydrocarbonProcessing.com

Setpoint change

Rx 1 inlet

FIG. 4. Reactor temperatures over one-week duration after APC installation.

Petrochemical Developments stream flowing into the intercooler is the second reactor.

2. Determine whether or not a reactor is out of service (i.e., being refilled with fresh catalyst) by examining the status of the inlet and outlet MOVs for each bed.

3. Adjust the inlet temperature deadtime and lag-time compensation constants based on the unit charge rate and on whether one or two beds are in service.

4. Apply the dead-time and lag-time compensation to the inlet temperature measurement.

5. Update the rolling filtered value of K. 6. Calculate the predicted value of the second reactor outlet temperature (K × Ti, lagged).

7. Compare the value found in Step 6 to the actual measured variable; i.e., calculate the model bias (To − To, pred).

8. Calculate the setpoint of the first reactor inlet temperature control as predicted to maintain the second reactor outlet temperature on target [(SPTo – bias) ÷ Kfiltered ].

9. Download the setpoint to the first bed inlet temperature control.

These sets of controls were scheduled to run every 10 seconds, but they could have run on a less frequent basis if processor execution free time had been an issue.

Results. The capability to control the reactor temperatures prior to advanced process control (APC) installation is shown in FIG. 3.

Note: The target temperature of 60°C for the second reactor was only approximately maintained. Sustaining the target temperature of 50°C for the sixth reactor was even more difficult due to the longer lag time. Poor control made it impossible to adjust the operating temperatures while compensting for changes in catalyst activity.

A complicating element is that, for this process, the catalyst activity constantly changes. In addition, the rate of change depends on the reactor location in the sequence, which also must be periodically changed. This makes for a very dynamic system, which is difficult to control with manual intervention, despite the operator’s best efforts.

Long-term testing using the new APC system indicated a catalyst lifetime improvement of 20%. This was due to the improved temperature stability of the reactors, as well as the ability to fine-tune

the reactors’ operating temperatures based on catalyst activity level (FIG. 4).

This improvement resulted in a return on project investment cost of over 600%.

FIG. 3 also demonstrates a lesson often learned in APC projects: The greatest benefits often result from the most basic control improvements. Comparing the behavior of the inlet temperatures of the first and third reactors in FIG. 3 and FIG. 4 shows significant improvement in stability achieved post-APC installation. The greater stability is a result of the seemingly simple first step taken in implementing the hierarchy of the controls; e.g., feedforward and PID feedback for control of the first and third reactor inlet temperatures. This control strategy was critical for achieving stable second and third reactor outlet temperatures. However, it should be noted that the sixth reactor temperature benefited from the stabilization of the inlet temperatures, as did the second reactor temperature.

The old control scheme required extensive effort by the plant operator to manually control the reactor tempera-

tures and make constant adjustments due to changing ambient conditions. As a final and very important benefit, the APC installation at the Geismar processing unit has allowed for the implementation of “set-and-forget” protocols that greatly decrease the need for manual intervention to maintain reactor temperatures.

DAVE WEATHERFORD is a technologist with BASF Corp., responsible for chemical process development and optimization. He has worked for BASF for 24 years. His fields of work have included research and development, operations engineering and process technology. Dr. Weatherford holds a BS degree in chemistry from Texas State University and a PhD in chemistry from Texas A&M University.

JIM FORD is a senior engineering consultant with 40 years of industry experience, including 30 years in APC. In his present role, Dr. Ford assists MAVERICK Technologies’ business development managers in pursuit of domestic APC and related opportunities.

He provides consulting services for APC definition and justification, DCS migration planning and justification, and implementation of state-based control strategies.

Dr. Ford has worked at MAVERICK since 2005. Prior to this, he co-owned and managed a small APC engineering consulting company. Mr. Ford holds a BChE degree from Georgia Institute of Technology, an MS degree and PhD from Tulane University and an MBA degree from Syracuse University.

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Special Report

Petrochemical Developments L. FARRELL and J. VIROSCO, Nexant, White Plains, New York

High-pressure polyethylene: Reemergence as a specialty chemical or not?

Mature PE technology. However, history indicates that such

a dire forecast was premature for several reasons. First, LLDPE processes use catalysts that are very sensitive to polar comonomers, meaning that LDPE copolymer materials that incorporate a polar monomer, such as vinyl acetate for ethylene vinyl acetate (EVA), could not be made in these processes. Second, in spite of decades of development, LLDPEs remain very difficult to process; thus, LLDPEs are not preferred by fabricators with older or underpowered converter equipment. Third, the processing characteristics of LLDPEs cannot match the fabrication ease of LDPEs in some processes, most notably extrusion coatings.

Growth. LDPE is the the smallest and slowest growing of the

polyolefin markets, due to ongoing substitution by LLDPE and the maturity of many LDPE applications. However, LDPE has maintained slow but steady growth on a global basis. LDPE has very strong growth in places such as China, India and Eastern Europe, even as LLDPE has steadily increased its share of the combined market, as shown in FIG. 1. In many applications, LLDPE substitution has been nearly completed, as proven by the decreasing rate of penetration.

The dominant end use for both LDPE and LLDPE is film applications, and this is where most of the substitution occurred. However, the end-use pattern for LDPE is more diversified than for LLDPE, with nonfilm applications accounting for about 35% of the global demand compared with less than 20% for LLDPE. These applications, and especially EVA (which comprises about 12% of LDPE demand) have shown ongoing growth and have been insulated from LLDPE replacement.

Value-added properties. The value of LDPE resin to con-

vertors depends on material properties such as ease of processing, optical clarity and tensile strength. LDPE has the best clarity and optical properties, and this polymer is the easiest PE

type to process, which is especially important to fabrication processes such as extrusion coating, wire and cable, and blow molding. In contrast, LDPE is of less interest in applications where tensile strength, puncture resistance and/or low temperature properties are desirable—all important film properties.

Therefore, in many film applications, LDPE has experienced significant substitution by LLDPE. LDPE defends its market share based upon its ease of processing compared to LLDPE and that it is also used as a blendstock with LLDPE. Considerable volumes of film are produced with some LDPE in the blend to aid processability and optical performance of the film. Demand for EVA, especially for foam molding for footwear in China and India, has also helped bolster LDPE demand and growth. Another high-growth area for EVA is as an encapsulation material in photovoltaic applications.

Second-generation LLDPE technology advancements are aimed at improving/enhancing LLDPE properties to extend its performance into LDPE applications that have historically been insulated from LLDPE penetration. A combination of process and catalyst options results in a balance of resin properties. Some are improved at the expense of others, and each must be considered with respect to the final cost (investment and production) of the polymer products. Typically, increasing the strength of a polymer will result in more difficult processing, while production of an easy-processing bimodal-LLDPE resin will reduce clarity. Balancing these property trade-offs is a key challenge for polymer producers, as illustrated in FIG. 2. In some situations, the trade-offs can be compensated by blending polymers.

Low pressure vs. high pressure. LDPE is the original PE

form, and it is produced using high-pressure autoclave or tu-

PE capacity, million tons

Just over 30 years ago, the first third-party commercial license was signed for a low-pressure gas-phase polyethylene (PE) process. This development ushered in the age of the linear-low-density polyethylene (LLDPE). Benefits of the LLDPE process were stated as lower capital investment and much lower energy costs. At the time, it appeared that the conventional high-pressure tubular and autoclave processes for low-density polyethylene (LDPE) had been eclipsed by new technology.

Result: Investment in high-pressure PE plants came to a halt.

75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0

LLDPE LDPE 63%

24%

34%

1990

1995

43%

2000

50%

2005

54%

2010

58%

2015

61%

2020

2025

FIG. 1. LLDPE penetration into the combined LDPE/LLDPE market.

Hydrocarbon Processing | APRIL 2013 47

Petrochemical Developments bular reactors. Current installed LDPE capacity favors tubular reactors (with 62% of the global capacity), which are available at a much larger scale. Autoclaves have been favored for specialty polymers, but technology advancements have increased the product range of tubular reactors. LLDPE is the newest PE form, and it is produced using gas-phase, solution, slurry and autoclave reactors. The original gas-phase process still continues to dominate new capacity additions, with 74% of global capacity.

Economics. One major aspect of technology selection is eco-

nomics. This includes not only the initial capital investment but also the operating costs. In this time of rapidly advancing developments, where many technologies are available for license, the choice between a low-pressure LLDPE process and a high-pressure LDPE process has become less obvious. Based on the global proliferation of LLDPE technology, it was generally found that an LLDPE plant was the least expensive to build and operate; however, history has shown that this did not directly correlate to the highest return on investment (ROI).

To assess the LDPE, EVA and LLDPE businesses, the commercial, technical, cost structure and historical margins of each polymer must be analyzed. This is especially important for highStrength

e LL

oda

cen

l LL

allo

DPE

Met

Developing PE markets. With the focus of polyolefins in China, a recently completed case study modeled a series of PE plants to evaluate historical cash cost margins for the past 11 years and the corresponding ROI.1 The plants modeled included: • LLDPE gas-phase plant, 400,000 tpy (400 Mtpy) of capacity—butene-1 comonomer • LDPE tubular plant, 400 Mtpy of capacity—no comonomer • EVA tubular plant, 250 Mtpy of capacity—18% vinyl acetate monomer (VAM) comonomer • EVA autoclave plant, 135 Mtpy of capacity—28% VAM comonomer.

Cash margins were calculated, and ROIs derived, as shown in FIG. 3. Note: This analysis does not include post-plant costs, such as license fees, sales and marketing, etc.; these costs can vary considerably and have a significant impact on project profitability.

The analysis results indicate that, while investment capital for new plants favors LLDPE, plant profitability—which is a function of product slate (revenue) and cost—is, in many cases, higher for LDPE plants. Higher revenues have generally offset higher operating costs, making the LDPE business more attractive on an ROI basis than the LLDPE business. Accordingly, the LDPE business has stubbornly remained as the most attractive segment of the global polyolefin business. New LDPE plants will continue to be built around the world, even as older, less-efficient plants are closed. This leaves one to wonder: are we witnessing the reemergence of low-pressure PE as a specialty product?

DPE

Bim

pressure LDPE and EVA, as pricing continues to offer substantial premiums over LLDPE products, thus complicating LDPE/ LLDPE investment decisions. This is in spite of numerous forecasts of the demise of the high-pressure PE processes at the hands of the more energy-efficient low-pressure LLDPE processes.

1

Traditional LDPE

Processability

Clarity

FIG.2. Performance balancing for LDPE and LLDPE.

Relative ROI, %

100

50

LDPE, tube, 400 Mtpy EVA (18%), tube, 250 Mtpy LLDPE, gas-phase, 400 Mtpy EVA (28%), a/c, 135 Mtpy

0

–50 2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

FIG. 3. Relative ROI for LDPE, LLDPE and EVA facilities in China.

48 APRIL 2013 | HydrocarbonProcessing.com

2012

NOTES Nexant recently modeled a series of plants in China to evaluate historical cash cost margins for the past 11 years and the corresponding return on investment.

LUANN FARRELL is a senior consultant in Nexant’s Global Chemicals and Polymers consulting practice. In this role, she has responsibility for Nexant’s polyolefins technology reports for the Process Evaluation/Research Planning (PERP) and PolyOlefins Planning Service (POPS) multi-client programs. In addition, Ms. Farrell has worked on numerous technical, financial modeling, competitive economics, and market research projects covering olefins, polymers and other petrochemicals. She has 17 years of consulting experience. Before joining Nexant, Ms. Farrell was a project engineer for Praxair and the Linde Division of Union Carbide in applications, research and development. She holds a BE degree in chemical engineering from Manhattan College and an MS degree in chemical engineering practice from the Massachusetts Institute of Technology.

JAMES VIROSCO is a principal in Nexant’s Global Chemicals and Polymers consulting practice. In this role, he is responsible for Nexant’s North American polymers practice, covering materials such as commodity polymers, engineering and performance polymers, thermoplastic elastomers, and other specialty polymers. He assists clients in market analysis, competitive economics, trend analysis, and growth strategy development.

Mr. Virosco also manages and contributes to strategic planning engagements, such as long-term strategic plan formulation, market and industry analyses, competitive positioning, and feasibility studies. He has 26 years of consulting experience. Before joining Nexant, he was a research engineer in Union Carbide’s Polyolefins Division.

He holds BS degrees in chemistry and chemical engineering from the Massachusetts Institute of Technology, and an MBA degree from the University of Michigan.

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HPI Focus

New vs. Revamp New vs. debottlenecking projects for the hydrocarbon processing industry

Owners of hydrocarbon processing (HP) facilities frequently analyze their markets and unit operations to determine if adding new units and/or debottlenecking existing units are economically attractive. The choice between building a new unit or revamping an existing unit for higher capacity can be influenced by many factors. HP owners have several options.

Major question. What needs to be ac-

JAMES TURNER Exective Process Director, Fluor Corp., Sugar Land, Texas James Turner is an executive process director in Fluor ’s Sugar Land, Texas office. He manages the Houston Process Technology and Engineering Group, which has over 250 process engineers working on projects for Fluor clients.

Mr. Turner has more than 25 years of experience in process design for a wide range of projects in the refining and gas processing industries, in domestic and international locations. He has published numerous technical articles about process design and project execution, and he holds patents for a combined hydrotreater process design. In 2006, he was a panelist at the NPRA Q&A and Technology Forum. Active in several professional organizations, he is the Past Chair of the South Texas Section of the American Institute of Chemical Engineers (AIChE). Mr. Turner is also on the AIChE Board of Trustees, and he has held several offices with AIChE in the past, including member of the Executive Board Programming Committee, and several positions with the Fuels and Petrochemicals Division, including Chair of the Division. In 2012, he received the Fuels and Petrochemicals Service Award for distinguished service to the division and industry. Mr. Turner is a graduate of Texas A&M University with a BS degree in chemical engineering. In 2011, he was inducted into the Texas A&M Chemical Engineering Academy of Distinguished Alumni.

complished? Is there a specific capacity increase in mind, or does the owner want to determine the best return on investment (ROI) for several competing cases?

Are there other changes in processing objectives, such as changing feedstocks?

Many units built before 1985 were designed with healthy design margins and could be easily revamped for higher capacities. Most new units built in the last 20 years were designed with much tighter margins; these facilities are less likely to have inexpensive debottlenecking options or “free” capacity. A unit that was designed with a healthy design margin and never revamped may only have a few equipment items that limit it from increased capacity. Conversely, a unit that has already been revamped a few times will likely have numerous equipment items at or near the operating limits.

Result: Significantly more scope will be required to increase capacity for the facility that was revamped earlier.

New unit conundrum—add or retire?

HP operating companies have two potential options to consider when examining a new unit vs. revamping an existing unit: • Build a smaller unit to work in parallel with existing facilities, or • Build a larger unit and retire the existing unit.

One advantage of building a parallel unit is the possible higher reliability for the facility, due to more operational flexibility when one of the units is down for

maintenance. Conversely, the operating costs to run two smaller units will likely exceed the costs for one larger unit. A new, larger unit could be favored if expensive equipment in the existing unit is reaching the end of its useful life, or if major upgrades of the existing unit will be required to meet owner specifications.

Advantages for new units. Potential

benefits for a new unit are: • Less disruption to existing operations during construction.

• Less lost production if the turnaround is extended.

• Grassroots design will enhance safety during construction since it eliminates pre-turnaround construction in an operating unit. Work permitting will be simplified, and construction productivity will be higher.

• More technology options are available. The project is not locked to the original unit configuration and design conditions. Higher energy efficiency and state-of-the-art designs can be used.

• Optimal layout reduces capital cost.

• Modular and/or standard designs from previous projects can be used.

• Less post-startup surprises, with existing equipment not meeting performance expectations.

• Global engineering resources can be used.

Debottleneck vs. revamp. Revamp-

ing an existing unit for higher capacity is often a cost-effective approach to gain incremental capacity, and it is frequently the option with the lowest capital cost. However, it is easy for owners of HP facilities to underestimate revamp costs early in a project, particularly if the state and capabilities of the existing equipment are not well understood. Other potential advantages for revamping a unit are: • Possible shorter project schedules, if reusing long-lead time equipment • Less total plot space required Hydrocarbon Processing | APRIL 2013 51

New vs. Revamp • May make better use of existing infrastructure for utilities, OSBL piping, etc.

A key issue for all revamp projects is: what can the existing unit really do? Are there good operating data under various conditions to show the limits of each system or equipment item? Are test runs of the unit under a wide range of conditions required?

If possible, when examining revamp options, consider studying the existing unit to take advantage of natural equip-

MARTIN J. VAN SICKELS President, MVS Consulting LLC, Houston, Texas Mr. Van Sickels is a registered professional engineer and holds BS and MS degrees in chemical engineering. He has over 47 years of experience in the engineering and construction (E&C) industry. Through his firm, MVS Consulting LLC, he provides a wide range of services to clients in the process and E&C industries and the US Department of Energy. Mr. Van Sickels also serves as executive director and member of the board of the Rice Global E&C Forum. During a 30-year career with KBR and its predecessor companies, he was a member of the executive committee, vice president and chief technology officer, responsible for the management, marketing, licensing and development of all KBR-licensed and specialexecution technologies. Prior to that position, he held various executive management positions, serving in a wide range of managerial, technical and commercial assignments. Before joining KBR, Mr. Van Sickels served in various management and engineering positions with J.F. Pritchard and Co., Haldor Topsøe Inc. and The Chemical Construction Corp.

52 APRIL 2013 | HydrocarbonProcessing.com

ment capacity “breakpoints” instead of specifying a specific revamp throughput up front. However, this approach may not be practical if other considerations set the required throughput.

Know that revamp options need to be considered early and in enough depth to avoid over-optimism that can lead to underestimating the scope and complexity of the project, which can cause the cost and schedule to increase significantly later.

Lessons learned. To determine the optimum path forward between different options, a conceptual study comparing the alternatives and determining the likely scope and capital cost is a wise approach. As most owners do not have adequately skilled engineering teams to study these scenarios, engaging an experienced, qualified engineering contractor to support the conceptual study is often warranted.

As demand for a product rises, manufacturing companies are faced with two options: 1. Increase their organization’s capacity to meet new demand in a timely manner 2. Surrender potential market share to a competitor or new producer, and allow others to fill this demand.

Assuming that the manufacturing company desires to maintain, and possibly increase, its market share, the organization owner must either build a new facility or expand the existing site via debottlenecking or revamping it. Further considerations are building at a greenfield site or, better yet, constructing the new capacity at a brownfield site adjacent to an existing plant, to share support utilities and other infrastructure.

than for a greenfield plant due to easier environmental permitting. However, a debottlenecking project requiring major new equipment (e.g., a large compressor), working within tight space limitations or working within an existing planned turnaround can have completion schedules similar to those for a greenfield plant.

Decision-making process. Information is required to determine the appropriate path forward, and questions to be raised and answered are usually extensive. For all options, several vital questions should be addressed: • Should the new capacity be located near the growing demand center or the facility’s feedstock source?

• Is new technology available that is more economical than existing methods?

If so, can the new technology be retrofitted into an existing facility?

• Is the new demand such that the present process facility will not cover the demand gap?

• What will be the environmental impact? While the permitting process is generally thought to be easier for debottlenecking an existing facility or for building at a brownfield site, this is not always the case.

• What is the schedule requirement to meet market needs? The schedule to complete debottlenecking and brownfieldbased projects generally can be shorter

Design approach. The design approach

to a debottlenecking project is different from that used for greenfield projects. As greenfield plants are basically designed from scratch, the engineering of these facilities is straightforward. Engineers start from a clean slate and have the most options. The engineering for a revamp is like reverse engineering, and it is usually a significantly more complex and tedious effort due to the constraints of using existing equipment, piping and instrumentation. The new design must fit with the existing equipment and plot plan. For each bottleneck uncovered, the impact of removing that bottleneck must be examined to determine the next subsequent bottleneck and if the cost of removing that bottleneck is justified. Brownfield projects, depending on the degree of shared facilities, will fall between greenfield and debottlenecking projects in engineering approach and complexity.

Debottleneck vs. brownfield projects.

Debottlenecking or new brownfield projects require more information, such as: • Is the existing plant well maintained?

• Are plant drawings current?

• What are the plot and equipment layout constraints?

• What area is available for equipment laydown during construction?

• What are the plant’s equipment constraints to increasing capacity, and what must be done to remove them?

• What upgrades for supporting util-

New vs. Revamp ity systems and infrastructure, including the control room, will be required?

• Does any equipment requiring upgrading need to be moved to a shop?

• Can equipment to be replaced be used for another service in the revamp?

• What is the estimated downtime and lost production while performing inspections and implementing the revamp?

• What equipment, piping and instrumentation must be inspected?

• Will removal or disturbance of asbestos insulation be required?

• Are there any laws requiring changes to the facility that are not related to the revamp if the facility is changed in any way?

The capital cost of a debottlenecking or brownfield project on an absolute basis will be less than a greenfield plant due to the reduced work involved. However, for the same level of engineering, the accuracy of the estimated cost for a debottlenecking project will be much less due to the uncertainties associated with the design basis and the potential unanticipated problems during construction. Estimates for proj-

ects involving debottlenecking should include a contingency that realistically reflects these uncertainties. Contingency should be part of the economic evaluation to justify the debottlenecking project. Due to the uncertainties with debottlenecking projects, contractors are loath to undertake such projects on a fixed-price basis.

When the subject of new installations vs. debottlenecking arises, the decision depends on a variety of criteria, including time frame allowed, size of the increased throughput, available plant space, permitting, construction schedule and craft availability, and, of course, capital and downtime costs.

well over 1 billion pounds per year of SM. SM plants have approximately 18–24 months of catalyst run time before a changeout is required during a scheduled turnaround. Most turnarounds on the Gulf Coast take three to four weeks. Also, the market price of SM can be significantly affected if this period is extended, not to mention the impact on the profitloss statement for the SM facility due to the downtime.

The execution plan was to purchase all new equipment in the reaction area and to design and install new foundations and undergrounds, as well as to modify existing structures. Interesting outcomes resulted from the fact that a new exchanger structure had to be modified to accommodate differential settling between already settled equipment and the structure from 12 years of operation, in comparison to the extended equipment and structure on new foundations, which will result in some future settling.

The new equipment in the reactor area was placed on new foundations, and the final tie-ins were minimized by maximizing the preturnaround activities. The final three weeks in the field required daily planning sessions with the client and all construction contractors to describe, in detail, firewater system shutdowns, plant road closures and the heavy lifts.

Ultimately, success was evident by the 18-day turnaround, surpassing the liquidated-damages initiation point, successful performance test run and perfect safety record. In this case, the old equipment was left in place to either abandon in place or remove at a later date. The new facility was operational at a 133% nameplate capacity with updated technology, and it was done during the already scheduled three-week turnaround.

Example. Consider a throughput increase

GARY LUCK Vice President of Project Management, SNC-Lavalin, Hydrocarbons & Chemicals, Calgary, Alberta, Canada G a r y L u c k h a s b e e n w i t h S N C- L ava l i n Hydrocarbons & Chemicals since September 2012. He brings over 30 years of experience in engineering and project leadership. In his current role, he is responsible for overall project management activities for the Hydrocarbons & Chemicals business unit globally. Prior to joining SNC-Lavalin, he served as plant manager, over operations and maintenance, for a new ammonia plant in Egypt with Kellogg, Brown and Root. Mr. Luck holds a BS degree in chemical engineering from Northeastern University in Boston.

of more than 20%, which is generally more than the built-in design allowances, and assume downtime is critical and the project work could be accomplished during a scheduled turnaround. Permitting within the existing site plan should not be a problem unless the project modifications result in increased emissions, which should be a red flag in any organization.

Gulf Coast project. This example is

from my experience in the early 1990s within an existing ethylbenzene (EB)/ styrene monomer (SM) plant on the Texas Gulf Coast. The challenge was to increase the SM throughput by 33% and to upgrade the SM technology as part of the process license agreement.

Once the limiting capacity equipment was identified, the dehydrogenation reactors, integrated reactor area heat exchangers, and product distillation column needed to be replaced or modified considerably for the higher throughput.

Fabrication time for some of this equipment was 12–14 months due to the fullvacuum high-temperature conditions requiring exotic metallurgy. The piping and expansion joints in the dehydrogenation reactor area were high-nickel alloy and up to 96 in. in diameter. The decision was made to buy new equipment due to the excessive downtime required to modify the existing facility, which produced

Bottom line. The path to achieving significant capacity increases is rarely obvious, and careful study is required to determine the optimum outcome.

Hydrocarbon Processing | APRIL 2013 53

| Bonus Report REFINING DEVELOPMENTS Energy is the driving force behind the global economy. Transportation fuel supplies are a critical factor in present and future economic growth. To meet growing clean fuel demand, refiners are constantly applying new energy-efficiency methods and process changes to increase product yields while maintaining safe operations.

Photo courtesy of the National Cooperative Refining Association (NCRA), McPherson, Kansas.

Refining Developments

Bonus Report

S. AL-ZAHRANI, S. ROY, and E. BRIGHT, Saudi Aramco, Dhahran, Saudi Arabia

Evaluate challenges in meeting clean-fuel specifications with heavier crude At a Saudi Aramco refinery, a revamp was planned for processing a different crude oil blend to meet Euro 5 diesel and gasoline specifications. The refinery, which processes semi-light crude oil, is scheduled to run a blend of light and medium crude oils in the future to meet clean diesel and gasoline specifications.

Simulation models were used to determine the yields and properties of various petroleum fractions from crude and vacuum distillation units (CDUs and VDUs) that meet Euro 5 specifications. The data helped establish the appropriate feedstock characteristics for secondary processing units, such as hydrocracking (HC), hydrotreating (HT) and catalytic reforming (CR) plants.

The evaluation revealed that a crude oil quality change will result in lower distillates recovery from the CDU, along with a reduction in crude oil processing, due to the hardware bottleneck in the downstream units. The charge rate to the vacuum distillation columns will be higher, which will result in extra vacuum gasoil (VGO) and vacuum bottoms production, compared to the base-case operation.

During the study, the equipment— i.e., reduced crude oil (RCO) pumps, crude column bottom trays, the vacuum furnace, the vacuum column and vacuum bottom pumps—was found to be limiting. To mitigate the vacuum furnace heat duty, it was proposed that a portion of the overflash material from the CDU tower be diverted to the VDU tower, bypassing the vacuum furnace. Moreover, several modifications—including revamping of the vacuum tower internals and pumparund (PA)—were anticipated to enhance separation between the VGO and the vacuum bottoms, despite the production of deep-cut VGO.

Additionally, the VGO output from crude oil processed at the present refinery charge rate is expected to be 20% higher than the HC charge rate needed to meet ultra-low-sulfur diesel (ULSD) distillation specifications. Therefore, the HC unit will pose a major bottleneck for the upgrading of extra VGO recovered from clean fuel. The HC will also hinder reprocessing of the additional inventory of VGO streams, such as HC fresh feed filter backwash and additional VGO inventory, during catalyst changeouts.

Furthermore, increased vacuum bottoms production will force the refinery to sell more fuel oil (FO) to the customer under post-clean-fuel scenarios. The feedstream quality for catalytic processing units, such as the HT unit, the catalytic reformer and the HC unit, will also be relatively inferior.

LSRN

Refinery overview. The current configuration of the refinery is shown in FIG. 1. The refinery produces liquefied petroleum gas (LPG), gasoline, diesel, jet fuel, FO, asphalt and sulfur, and the remaining crude oil is sold directly to local customers for power generation.

The refinery is operating at full capacity to meet growing regional demand for gasoline and other transportation fuels.

At present, the refinery is undergoing a major revamp to reduce the sulfur content of its fuels, and to meet new environmental regulations.

Under present operating conditions, 85% volume distillation temperature (T85) for diesel is a maximum of 350°C. For clean diesel fuels, 95% volume distillation temperature (T95) is kept at a maximum of 360°C, in line with Euro 5 specifications.

C1/C2

H2 PLT

LSRN treater No. 3

Fuel gas amine

Fuel gas

H2 Raw crude

Stabilized crude

LPG

CSF

H2 PLT amine

Naphtha + LPG

Stabilizer

Whole naphtha Crude distillation No. 2 Crude sales RC

Kerosine LDO HDO Vacuum distillation unit No. 3

Vacuum bottoms to FO

C1/C4 LPG

GCU

LSRN

LSRN

LSRN treater No. 2 C4

Splitter HSRN

NHT

Premium gasoline

CR C3/C4

Kerosine hydrotreater

Jet fuel

Naphtha Diesel

LVGO HVGO

VGO/DMO HC

Kerosine HC fractionator LDO HDO

DMO Solvent extraction

Asphalt plant PHC

Asphalt

Direct recycle

DHT Low-sulfur diesel Frac BTMS to fuel

FIG. 1. Process flow overview of the refinery.

Hydrocarbon Processing | APRIL 2013 55

Refining Developments Methodology. The methodology used in the study included:

• The primary units (CSF, CDU, VDU, stabilizers and naphtha splitters)

TABLE 1. Simulation operating parameters vs. actual operating parameters for the CSF Simulation number 2

Flash drum temperature

3

Flash drum pressure

10

Debutanizer bottom temperature

Unit

Plant data

Simulation data

°C

142.88

142.88

kg/cm2g

.8

.7

°C

174.6

174

11

Debutanizer top temperature

°C

75.3

75

12

Debutanizer top pressure

kg/cm2g

10.33

10.33

13

Debutanizer bottom pressure

kg/cm2g

11.27

11.27

m /hr

61

80

14

Debutanizer reflux rate

3

15

Tray 6 temperature

°C

85.5

91

16

Naphtha splitter (NS) top temperature

°C

78.7

64

17

NS top pressure

kg/cm2g

.84

.84

Base case validation. The model is

18

NS bottom temperature

°C

227

239

1.7

45

Unit

Plant data

Simulation data

considered to be validated, as there was a close match between the plant data and the simulated data. See TABLES 1–7 for the validation results for the primary units.

The parameters that did not match with the plant data are shown in red. The deviations have been carried forward while predicting the flowrates for the new crude blend case. Deviations found in the crude column top section are not expected to affect the final conclusion, as the new crude blend loads the bottom section rather than the top section.

19 1

CSF parameter

NS reflux rate

1

3

m /hr

A 25-m3/hr quench flow at 225°C is taken.

TABLE 2. Simulation lab data vs. actual lab data for the CSF Simulation number

CSF parameter

CSF LN 1

5% distillation temperature

°C

44

31

2

Final boiling point

°C

91

91

3

5% distillation temperature

°C

85

60

4

Final boiling point

°C

171

172

5

Specific gravity

.736

.72

6

Sulfur

178

364

CSF HN

ppm

Yields comparison Current crude New crude oil blend

Volume distilled, %

96 92 88 84 80 76 72 68 64 60 56 52 48 44 40 36 32 28 24 20 16 12 8 4 0

0

were simulated, and the model was validated with the current crude assay • The crude assay was replaced with the new crude assay; see the true boiling point (TBP) distillation curve in FIG. 2 for the existing and new crude blends • For diesel HT units, light gasoil (LGO) and heavy gasoil (HGO) streams were considered • For HC fresh feed, light vacuum gasoil (LVGO) and heavy VGO (HVGO) were considered • For the naphtha hydrotreater (NHT), 85°C to 171°C ASTM D86 cutpoints were considered • The crude charge rate for the primary units was kept the same as in the base case.

50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1,000 1,050 1,100 1,150 Temperature, °F

FIG. 2. Yield comparison between the present crude blend and the new crude blend.

56 APRIL 2013 | HydrocarbonProcessing.com

Target case capacities. The vali-

dated models were used to predict the capacities of the downstream units for clean-fuel specifications. TABLE 8 lists the expected incremental unit capacities, as percentages, for the new crude blend.

Results and observations. For the new crude assay, it was found that the product yields from the CDU had decreased, except for kerosine and RCO. The reduction in diesel was expected, since Euro 5 diesel specifications require a reduction in the heavy end of the diesel fraction to meet the T95 distillation specification. Therefore, the reduced crude circuit, including pumps, piping, the vacuum charge heater, the vacuum tower and associated equipment, are prone to bottlenecks due to increased flow, especially when meeting clean-diesel specifications.

A suggested modification was to avoid revamping the vacuum heater by diverting the CDU overflash material directly to the vacuum tower, bypassing

Refining Developments the heater. This option will eliminate the need for increased vacuum charge heater capacity.

The vacuum bottoms flow with the new crude blend is expected to be increased by about 8%. Therefore, FO sales from the refinery must be raised to maintain the management of black oil (i.e., reduced crude oil, VGO and vacuum bottoms) in the refinery. Alternatively, the capacity of the asphalt plant must be increased to consume extra vacuum bottoms as asphalt product, to maintain sustainable refinery charge rates with the new crude oil blend. TABLES 2, 4, 6 and 7 show the properties of the streams from the crude stabilization facility (CSF), the CDU and the VDU. In conclusion, black oil management will be impacted significantly at present refinery capacity with 100% new crude oil blend processing, especially when meeting clean-diesel specifications.

Sustaining the present refinery charge rate is not an option for meeting cleanfuel specifications with 100% of the new crude blend, until black oil management is improved.

Expected throughput reduction without investment. The expected throughput reduction for the new crude oil blend, without any capital investment, was determined by keeping the VDU heater capacity the same as the original installed capacity. The CDU throughput will be reduced to 94% if the current diesel specification is to be maintained, and to 91% to meet the Euro 5 diesel specification.

Expected HC capacity. The VGO production with the new crude oil blend will be higher than with the existing crude oil blend. Therefore, the HC capacity with the new crude oil blend will be constrained during catalyst changeout, plant shutdowns and other occasions to reprocess the extra VGO in storage. The required HC capacity for processing VGO generated during catalyst changeout is 20% higher than the present HC capacity.

Semi-regenerative reformer and HT capacities. The semi-regenerative catalytic reformer will not be operating at full capacity at the present CSF and CDU throughputs, as the heart-cut naphtha yield is lower in the new crude blend.

Moreover, the reformer feed precursor N + 2A content of the heart-cut

naphtha was also found to be lower for the new crude blend. This will severely

affect the octane number of fuel from the reformer; consequently, total gaso-

TABLE 3. Simulation operating parameters vs. actual operating parameters for the CDU Simulation number 5 6

CSF parameter Top tower temperature

7

Reflux drum temperature Reflux drum pressure

Simulation data

131

131

kg/cm g

1.02

1.02

°C

42

42

kg/cm2g

.4

.4

°C 2

Top tower pressure

8

Plant data

Unit

3

9

Reflux flowrate

m /hr

8.97

2

10

Top pumparound (PA) flowrate

m3/hr

400

400

11

Top PA drawoff temperature

°C

153

158

12

Top PA return temperature

°C

63

63

13

Top PA ⌬T

°C

90

95

15

Kerosine drawoff temperature

°C

195

202

17

LGO drawoff temperature

°C

250

255

LGO PA flowrate

3

m /hr

379

379

18 19

LGO PA return temperature

°C

174

174

20

LGO PA ⌬T

°C

76

81

22

HGO drawoff temperature

°C

337

329

23

HGO PA return temperature

°C

215

215

24

HGO PA ⌬T

°C

122

114

25

Flash zone temperature

26

Flash zone pressure

°C

371

371

kg/cm2g

1.28

1.28

27

Tower bottom temperature

°C

363

365.8

28

Tower bottom pressure

°C

1.4

1.4

kg/hr

5,511

5,511

Unit

Plant data

Simulation data

m3/hr

138

136

°C

172

176.5

.7

.7265

.05

.05

30

2

Stripping steam at 3.5 kg/cm g

TABLE 4. Simulation lab data vs. actual lab data for CDU Simulation number 1

CDU parameter Overhead liquid flowrate

2

Final boiling point

3

Specific gravity

4

Sulfur

wt% 3

5

Kerosine flowrate

m /hr

88

88

6

Final boiling point

°C

267

258

.789

.8053

wt%

.1871

.382

176

176

7

Specific gravity

8

Sulfur

9

LGO flowrate

°C

10

Final boiling point

°C

11

Specific gravity

12

Sulfur

13

HGO flowrate

14

100% distillation temperature

15

Specific gravity

16

Sulfur

363

357

.8415

.8463

wt%

1.1

1.14

m3/hr

97

97

°C

407

417

.88

.8957

1.9

1.8

wt%

Hydrocarbon Processing | APRIL 2013 57

Refining Developments line production will be reduced. To fill the capacity of the semi-regenerative reformer, a deep stabilization operation must be carried out at the CSF, which will recover more heavy naphtha (HN) from the crude before it is sold to power

plants. This will make crude oil to the CDU relatively heavier; consequently, more black oil production is expected.

Another option is to increase the cutpoint of HN from the CDU. Since the gasoline endpoint is 210°C and, typical-

TABLE 5. Simulation operating parameters vs. actual operating parameters for the VDU Simulation number

VDU parameter

1

Top tower temperature

2

Top tower pressure

3

LVGO PA flowrate

4

LVGO PA drawoff temperature

5

LVGO PA return temperature

7

HVGO PA flowrate

8

HVGO PA drawoff temperature

9

HVGO PA return temperature

11

Indirect recycle flowrate1

12

Indirect recycle temperature

13

Indirect recycle pressure

Unit

Plant data

Simulation data

°C

48

52

mmhg

18

18

3

m /hr

137

158

°C

101

101

°C

49

49

m3/hr

212

220

°C

281

287

°C

101

101

m3/hr

50

50

°C

350

350

kg/cm2

3.5

3.5

m /hr

13

19.7

3

14

Slop wax flowrate

15

Slop wax drawoff temperature

°C

386

381

16

Flash zone temperature

°C

392

391.4

17

Flash zone pressure

mmhg

35.65

35.65

18

Tower bottom temperature2

°C

366

365.3

19

Vacuum tower bottoms flowrate (vacuum slop included)

3

m /hr

165

161

20

Stripping steam at 3.5 kg/cm2g

kg/hr

2,298

2,298

338

339

Plant data

Simulation data

21

RCO flowrate

3

m /hr

1

Indirect recycle is the HC main fractionator bottoms used as a wash liquid.

2 A 25-m3/hr quench flow at 225°C is taken.

TABLE 6. Simulation lab data vs. actual lab data for the VDU Simulation number

VDU parameter

Unit

LVGO 1

5% distillation temperature

°C

287

272

2

90% distillation temperature

°C

463

441

3

Specific gravity

0.8984

0.8728

4

Sulfur

1.98

1.93

wt%

HVGO 5

5% distillation temperature

°C

387

386

6

90% distillation temperature

°C

539

524

7

95% distillation temperature

°C

562

551

0.9196

0.9254

2.3

2.6

8

Specific gravity

9

Sulfur

wt%

HC feed 10

Specific gravity

11

Sulfur

58 APRIL 2013 | HydrocarbonProcessing.com

0.919 wt%

2.53

ly, the final boiling point of the reformate increases by around 7°C in the semi-regenerative reformer, the endpoint for the NHT feed can be raised further. However, other contaminants and reformer catalyst performance at such high NHT feed endpoints should be investigated before making such a decision. Therefore, a thorough investigation with the reformer licensor is recommended to evaluate the potential consequences of increasing the HN endpoint.

As the diesel specification has been changed from a T85 of 350°C maximum to a T95 of 360°C maximum for cleanfuels production, the diesel output from the CDU will be reduced by 83%. The tail-end of the diesel fraction goes to the HC, and it is eventually converted to naphtha and diesel. Therefore, neither the semi-regenerative reformer nor the DHT is expected to have capacity constraints. The capacity available in the distillate hydrotreater (DHT) can be supplemented with kerosine feed and normal sour diesel feed during low jet fuel lifting from the refinery.

Feed sulfur to the kerosine HT unit is around 0.2 wt%. Sour kerosine can be processed in the DHT, along with normal sour diesel feed, during the catalyst changeover in the kerosine unit, through proper tank management. The time required to consume this extra inventory in the DHT is less than one month. Although there is no capacity limit in the DHT for processing this kerosine, meeting the diesel flashpoint will be a challenge, and the DHT stripper should have adequate capacity to produce an onspecification diesel flashpoint when the DHT feed is blended with atmospheric gasoil and kerosine.

With only LGO and HGO, the flashpoint of diesel is 60°C, and the required diesel flashpoint specification is 55°C. A small quantity of diesel is cracked in the DHT, and the DHT stripper removes the light ends to meet the diesel flashpoint specification.

The present kerosine flashpoint is 46°C. Blending this kerosine in a diesel feed pool will decrease the diesel flashpoint; therefore, the DHT stripper requires an additional reboiling duty to meet the diesel flashpoint. A minor modification is required in the DHT stripper to meet the diesel flashpoint. During this operation, the DHT

Refining Developments stripper overhead produces more light naphtha (LN), which must be accommodated in the overall naphtha balance for the refinery to fill the NHT and the catalytic reformer.

Takeaway. In summary, changing the

crude oil slate from semi-light crude to a mixture of light and medium crude will result in several changes. The changes have been identified using process simulation software.

Distillate recovery from the CDU will be impacted at the expense of extra VGO and vacuum bottoms production.

The extra VGO production requires an increase in HC capacity and, therefore, an HC revamp is required. The extra vacuum bottoms production increases FO production.

Therefore, with the new crude blend, no spare capacity is available at the HC to reprocess VGO recovered from the HC feed filter backwash, or to maintain the present refinery charge rate during occasions such as catalyst changeout.

The feed quality for catalytic process units, such as the CR, the DHT, the HC and others, will be inferior and will im-

pact yields, catalyst performance and cycle lengths. A revamp is required to process this new crude oil blend and to meet clean-fuel specifications.

SAID A. AL-ZAHRANI is the general supervisor in the process and control systems department at Saudi Aramco. He is the chairman of the multi-disciplinary product specifications committee, tasked with managing various issues related to Saudi Aramco products and fuel specifications. Mr. Al-Zahrani holds a degree in chemical engineering from King Fahd University of Petroleum and Minerals, and began his career at Saudi Aramco as a process engineer in the Ras Tanura refinery. He is a member of several local and international societies and an officer of the American Institute of Chemical Engineers, Saudi Arabian chapter.

Unit parameter

Unit parameter CSF NS flowrate

Final boiling point

Sulfur

Final boiling point

172

176.5

171

0.7

0.7265

0.7307

wt%

0.05

0.05

0.075

°C

267

258

254

0.789

0.8053

0.8055

wt%

0.1871

0.382

0.3525

°C

363

357

360

0.8415

0.8463

0.8492

1.1

1.14

1.22

Specific gravity

LGO

Specific gravity Sulfur

wt%

HGO 100%

99

Specific gravity

CSF HN

69

Sulfur

CSF LPG

62

LVGO

CDU LPG

62

90%

CDU LN

100

Specific gravity

CDU HN

86

Sulfur

NHT feed (excluding HC naphtha)

86

90%

Kerosine

105

95%

LGO plus HGO

°C

407

417

410

0.88

0.8957

0.9

wt%

1.9

1.8

1.94

°C

463

441

470

0.8984

0.8728

0.878

1.98

1.93

2.1

°C

539

524

524

°C

562

551

551

0.9196

0.9254

0.923

2.3

2.6

2.6

0.85

0.8638

0.8604

1.4

1.4

1.4

0.92

0.919

0.9168

2.3

2.5

2.5

wt%

HVGO

83

Specific gravity

RCO

115

Sulfur

HC combined feed1

120

DHT feed

HC fresh feed

124

Specific gravity

Vacuum bottoms

108

Sulfur

Indirect recycle2

100

HC feed

2

°C

Kerosine

82

3

Simulation: 100% new crude

Plant data

Specific gravity

CSF LN

1

Simulation: 30% new crude

Unit

CDU overhead liquid

Final boiling point With 100% new crude, specification of T95 at 360°C for diesel, % of current operation

EDWIN BRIGHT has over 17 years of experience in the petroleum refining industry. Before joining Saudi Aramco, he worked for Reliance Industries Ltd., Indian Oil Corp., ATV Petrochemicals and Foster Wheeler India Ltd. He holds a bachelor’s degree in chemical engineering and master’s degrees in petroleum refining and petrochemicals from Anna University’s Alagappa College of Technology in Chennai, India.

He also earned a master’s degree in management from the Asian Institute of Management in Manila.

TABLE 7. Key properties of the feed to secondary processing units

Sulfur

TABLE 8. Required capacities of different units for the new crude blend

SAMIT ROY is an engineering consultant at Saudi Aramco’s downstream process engineering division.

A chemical engineering graduate, he has more than 33 years of experience in process engineering and technical services. His experience includes 21 years in Saudi Aramco refining and engineering services and 12 years at Indian refineries. He has worked at most refinery units associated with distillation, hydroprocessing and gas treating.

A 25-m /hr quench flow at 225°C is taken.

Indirect recycle is the HC main fractionator bottoms used as a wash liquid.

wt%

wt%

Specific gravity Sulfur

wt%

Hydrocarbon Processing | APRIL 2013 59

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Refining Developments B. DETERS, Calabrian Corp., Port Neches, Texas; and R. WOLKART, Emerson Process Management, Houston, Texas

Improve coker efficiency with reliable valve automation A refinery’s delayed coker unit (FIG. 1) operates under what are perhaps the harshest conditions of any process in the plant. Equipment with moving parts, notably valves and the actuators that operate them (FIG. 2), are especially vulnerable to these severities. The following case history discusses conditions occurring in delayed coker operations at two refineries in Louisiana, US; the impacts on valve performance; and a solution that provides extended life, increased reliability and other benefits at the facilities.

Controlled by a programmable logic command, the valves’ sequential event must be consistently and reliably executed by an actuator (FIG. 3). To maintain process control, valves have safety interlocks restricting their opening and closing through limit switches. An inoperable valve actuator must be reinstated quickly so that the system can continue functioning. If actuators fail, the valves must be opened or closed manually. This is a strenuous, time-consuming and potentially dangerous process

Severe conditions in the coker. Severe operating conditions, including excessive heat, vibration and corrosion, exist in every refinery’s delayed coker operation. High inlet temperatures of the residual oil flowing from the fractionator through the transfer line into the coke drum exceed 800°F (425°C) at low pressures of 10 psig to 15 psig.

As the operating drum fills with coke, torques on the valves’ wetted parts tend to increase, putting additional stress on the transfer line ball valve and added operational torque on the multi-turn electric valve actuators. During the coke removal process, there is extreme vibration. The high-pressure water lines used to drill out and cut the coke from the drum internals create pressures of up to 4,000 psi. The steam and quench water piping used in the decoking process is susceptible to rapid expansion and temperature fluctuations of condensate and/or water, producing an often violent water hammer effect. Corrosion is present as the coke’s traces of sulfur combine with the unit’s washdown water.

During the washdown phase, a significant amount of abrasive, airborne dust is created, covering all surfaces within the drum and its immediate surroundings. The coke dust not only creates challenges for corrosion protection, but also builds up in crevices, impeding instrument and equipment functionality.

In addition to the harsh conditions present, the space available for performing maintenance is confined, hot and potentially dangerous for plant personnel.

Impact on valves and actuators. Typically, there are eight

to 10 valves for each drum in the coking process. These valves perform multiple services including recirculation, switching, quenching, washdown, steam hydrocarbon stripping and drum steam reheating. They control flow in piping that transports steam, water, slurry, hydrocarbons and product, and they are critical to the operation.

FIG. 1. Multiple valves and actuators control the coking/decoking process.

Hydrocarbon Processing | APRIL 2013 61

Refining Developments for the unit operator, although it is necessary to keep the coking/decoking process in sequence and on schedule.

Automated valve performance and mean time between failure (MTBF) are constant and costly problems for the refinery.

While valves are not as susceptible to failure and can generally be serviced during periodically scheduled shutdowns, actuators have been prone to early, unplanned failures and the need for continual repair.

Coker actuator failure can occur almost immediately after installation, and normal life expectancy is less than one year. Experience has shown that actuator failure can be attributed to a variety of conditions that are fairly consistent in any coker application.

Water hammer and vibration effects can break internal electrical connections and dislodge sensitive microprocessor components.

Also, motors can become disconnected from the actuator housing through vibration. When inspected, these motors have been found precariously hanging from their wires—and nothing else.

Furthermore, coke dust fines regularly penetrate the actuator housing, causing inoperability of electronic components and on/off pushbuttons to become clogged and faulty. Corrosive elements erode aluminum actuator housings, wiring and even the external handwheel, rendering this sole backup device useless.

Maintenance costs can be excessive, accumulating with continual callout and overtime repair charges. Ongoing actuator problems have even necessitated the use of a full-time, dedicated troubleshooter whose sole function is to keep the valves operating as scheduled, or repaired in a timely manner.

A successful solution. In the case of two Louisiana refineries

FIG. 2. Actuators are compact and versatile so as to be configured in a variety of mounting configurations

with delayed coker operations, the search for a robust and reliable actuator solution to provide extended service life resulted in the testing and selection of a modified, multi-turn, electric design that had provided exceptional service in other applications.

While not the newest version of the technology, this established actuator had been engineered to provide the necessary

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Refining Developments features for success in this challenging service. The selected unit used industrial-grade epoxy coatings on all external surfaces as standard construction to provide excellent corrosion resistance.

Also standard was its marine-grade aluminum enclosure with stainless-steel captured bolting.

Unlike some newer and more sophisticated actuator designs, this solution had no microprocessor components. Rather, it featured incorporated, reliable circuit boards with no termination wiring, and compact internal limit switches and relays that could withstand the high temperatures in a delayed coking unit.

The actuator could be remotely managed from a hardwired push-button panel unaffected by the dust; yet, the control was within sight of the actuator to verify its proper operation. Internal control components were smaller, compact and lightweight to resist self-destruction from inertia and the momentum generated from vibration and water hammer effects. Its linear drive train and gearbox assembly were specifically configured to withstand high torque and thrust loads while maintaining alignment.

Sizing safety factors were also considered. For reliable operation, this actuator was sized to provide a two-times safety factor, which is highly recommended to account for the variable and generally higher torques needed as the process progresses and as piping expands and contracts, requiring higher torques not included in new torque values. The overall actuator footprint and weight were sufficient for operation in confined spaces and for accommodating a variety of horizontal and vertical valve installation positions.

After being tested and installed, the selected actuator provided the refineries with immediate relief from failure. The units have been in continuous service for more than six years in one refinery and for more than three years in the other. There have been virtually no failures, and the limited need for maintenance can be completed during scheduled plant shutdowns.

Takeaway. The importance of valves and the electric actuators that control the operation in a delayed coker unit cannot

FIG. 3. An actuator executes sequential events for coker valves.

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Hydrocarbon Processing | APRIL 2013 63

Refining Developments be minimized. As a batch process, the coker becomes the potential bottleneck in an otherwise continuous refining operation. If the critical coke drum filling, drum switching and decoking schedule is significantly interrupted, it can impact the entire refinery throughput, costing the company millions of dollars per day in lost production.

Delayed coker facts â&#x20AC;˘ What is delayed coking?

A semi-batch thermal cracking process used to upgrade and recover residual liquid and gas streams while leaving behind petroleum coke, which is usable as an industrial fuel source or can be further refined for additional industrial purposes â&#x20AC;˘ Inlet temperature: 900°F (480°C) â&#x20AC;˘ Inlet pressure: 15 psig to 35 psig â&#x20AC;˘ Process temperature: 700°F (371°C) â&#x20AC;˘ Coke drum size range: Height: 55 ft to 120 ft Diameter: 15 ft to 30 ft â&#x20AC;˘ Cycle length: Online coke drum filling: 10 to 12 hours Drum decoking process: 4 to 6 hours

The valve actuator, seemingly a very small item in the total process, has a significant importance and a great impact on the delayed coking operation. Premature failure can lead to extra costs for operator overtime, additional labor and safety risks for manual valve operation, replacement costs and potential refinery downtime.

The robust, reliable solution was found to be a field-proven, ductile iron-housed, powder-coated actuator with external control in proximity of the valve. Its compact physical size and weight, unique internal electric circuitry configuration and modified hardwired operation have provided the refineries with considerable cost savings and have averted potential production outages.

The refineries using the selected actuators have been able to increase production, improve personnel safety and conduct regularly scheduled shutdowns, thereby significantly reducing maintenance costs.

BENNY DETERS is the director of manufacturing at Calabrian Corp., a specialty chemical manufacturer in Port Neches, Texas. He is an electrical engineering graduate from McNeese State University, and he has more than 25 years of management experience in delayed coking and plant operations.

ROSS WOLKART is the gas and pneumatic product manager for Emerson Process Managementâ&#x20AC;&#x201D;Valve Automationâ&#x20AC;&#x2122;s EIM line. He is the companyâ&#x20AC;&#x2122;s refining and pipeline application specialist and a graduate of Southeastern Louisiana University. Mr. Wolkart has more than 16 years of sales and service experience and expertise in delayed coking operations.

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Bonus Report

Refining Developments J. PARASKOS, PRO-TECH Associates, San Francisco, California; and V. SCALCO, General Atomics, San Diego, California

Optimize value from FCC bottoms Fluid catalytic cracking (FCC) is one of the most versatile and profitable upgrading processes in a refinery. FCC has maintained its place in the refinery through a series of evolutionary changes to meet changing demands. FCC slurry oil (SO) is the lowest value product from the unit (typically, a 5% yield). It is a highly aromatic, low API material containing FCC catalysts.

Because of the catalyst content and high aromaticity, possible environmental restrictions make easy sludge disposal from settling tanks expensive. Meanwhile, processing the catalyst-laden slurry can cause severe erosion of refinery equipment. Within this context, possible product uses for SO include fuel-oil (FO) blending, carbon-black feedstock, needle-coke feedstock and upgrading to lighter fuels. By using an electrostatic separator, catalyst fines in SO can be reduced, allowing for the production of specialty product feedstocks, higher value fuels and blendstocks that reduce erosion and disposal concerns.

SO is a high boiling, viscous, aromatic, high-density material containing FCC catalyst particles. The key to improving the value of this stream is to economically remove the solids to low levels. Historically, refiners have used heated holding tanks with very long residence times to allow the solids to settle. Once settling occurs, decant oil is removed from the upper part of the tank, and the bottoms sludge (which is listed as a hazardous waste) is also periodically removed. Other approaches for removing catalyst include hydroclones, filtration and, in some cases, centrifugation. Electrostatic separation is different; a charge causes the catalyst particles to become trapped in beds of glass beads while maintaining flow without significant pressure drop. In this way, electrostatic separators have been able to remove over 97% of the catalyst present in most SOs. As the concentration of vacuum-tower bottoms in FCC feeds grows, modern techniques used for catalyst removal selection from SO will increasingly favor electrostatic separation, because it is inherently less likely to foul or coke due to increasing asphaltene levels in the slurry.

As refiners introduce more resid into FCC units, SO yields will increase and the quality of the SO will decrease. The level of asphaltenes in the SO becomes a factor in deciding which technology is best for removing particulate solids. Asphaltenes are the most hydrogen-deficient constituents of SO. They become more active and react with one another at higher temperatures— and especially in the presence of metal surfaces—and form coke.

inversely proportional to such factors as catalyst activity, temperature and catalyst-to-oil ratio. They are directly proportional to nitrogen, sulfur and asphaltene (or alternatively, vacuum bottoms) FCC feed content. SO yields ranging from about 1 vol% to 2 vol% for paraffinic feeds to as much as 15 vol % on RFCC feeds have been observed. TABLE 1 shows a range of typical SO properties. SO quality is a function FCC feed, severity of the operation, catalyst type and operating conditions in the FCCU. Most SOs contain asphaltenes. Asphaltenes are large chemical structures with a high carbon-to-hydrogen ratio, which also generally contain nickel (Ni) and vanadium (V) and promote coke generation when deposited on FCC catalysts. They are complex structures defined by their solubility. When cracking residual feedstocks, the FCC catalyst pore size is not large enough to allow the asphaltene structures to enter.

The asphaltene conversion level in a RFCC unit is then a function of the catalyst matrix activity.1 If the FCC feed contains significant asphaltene levels, as it would in RFCC, the SO will most likely also contain higher asphaltene concentrations.

When asphaltenes are present, Ni and V will also be present on the catalyst, initially deposited as part of the coke and in the slurry as metallorganic compounds. Catalyst particles in the slurry, besides containing Ni and V, can also bring in sodium and trap iron. Other materials that may be present on the catalyst or in the slurry include antimony and tin, which are used as metal passivators. SO may also contain other FCC additives used to control carbon monoxide, sulfur oxide and nitrogen oxide emissions.

Particle-size distribution ranges from a variety of SOs are shown in TABLE 2. Note that for these SOs, over 90% of the particles range in size from 0 microns to 25 microns in particle diameter. This means that very large holding tanks and long TABLE 1. Range of properties for typical SOs Property

Range (Min. to max.)

API gravity

–6 to +8

Sulfur, wt%

0.3 to 5.0

Nitrogen, wt%

0.1 to 0.5

Nickel, ppmw

0 to 110

Vanadium, ppmw

5 to 200

Yields and properties. SO yields from FCC and residue FCC

Asphaltenes, vol%

Nil to –8

(RFCC) are a function of operational severity and are generally

Solids, ppmw

1,000 to 6,000 Hydrocarbon Processing | APRIL 2013 65

Refining Developments holding times are required to meet higher value product specifications; some benefits are possible with settling aids in this service.2 However, sludge from SO holding tanks is listed as a hazardous waste by the US Environmental Protection Agency (EPA), so frequent cleaning of these tanks becomes expensive.

Applications and markets. Worldwide FCC SO production is estimated to be about 750,000 bpd. North America represents about 45%, while Europe and Asia-Pacific have 42% of the total production. Possible applications for SO include: • Recycle to extinction in the FCC • Charge to a coker • Use as fuel in the refinery • Market as a FO blending stock, as carbon-black feedstock or as a component of anode-grade/needle-coke feedstock • Further refine to a higher-value fuel.

Each end use has a differnt specifications on the SO. Typical solids specifications allowable in SOs are shown in TABLE 3.

FO blending accounts for about 80% of the production, while TABLE 2. Typical particle size distribution in SOs Particle diameter, microns

% in Range

0–5

30–60

5–15

30–55

15–25

2–12

25+

1–5

TABLE 3. Typical permissible solids content for various SO product applications Market

Clarified slurry oil solids, ppm

Carbon-black feedstock

50–500

Refinery use, fuel or coker feed

50–150

Marine fuel, No. 6

50–150

Pitch feedstock

25–100

Needle/anode coke feedstock

25–100

Hydroprocessing feedstock

10–50

Carbon-fiber feedstock

5–10

TABLE 4. Typical carbon-black feedstock requirements Property

Value

BMCI, min.

120

°API, max.

2

Specific gravity, min.

1.06

Sulfur, wt% max.

0.5–4

Ash, wt% max.

0.05–0.07

Sodium, ppmw max.

10

carbon black and needle coke consume about 150,000 bpd. The market value is highest for needle-coke applications, but this is a very limited market.

SO has been recycled to the FCCU, but this route increases coke make, resulting in higher regenerator temperatures that can adversely affect selectivity to prime products and economics. In this application, however, one may not need to remove the catalyst to low levels, as long as FCC injector erosion and heat exchanger fouling are not an issue. Some refiners charge their SO to a coker avoid making shot coke.

SO use as fuel in the refinery is practiced routinely and is a good option as long as applications are well thought out and the equipment used is thoroughly vetted. Equipment such as piping, burner tips, nozzles and heat exchangers need to be evaluated for long-term viability when charging solids containing streams. To minimize downstream processing difficulties, it is advisable to remove the contained catalyst, keeping solids diluted below recommended concentration levels.

SO use as cutter stock for heavy FO blending has also historically been a major outlet. However, trace metals deposited on FCC catalysts can combine with other elements to form high melting point compounds that are corrosive to valve seats and exhaust valves in diesel engines. Solids contents for marine and refinery use in the range of 50 ppmw to 150 ppmw are generally permissible.

Beyond fuel use, clarified SO is also sold to make carbon black, which is used in automobile tires, belts and hoses. Typical carbon-black feedstock properties are given in TABLE 4.3 Worldwide consumption of carbon-black feedstock is about 130,000 bpd. The required density for carbon-black feedstock is high, and special attention must be given to operating the FCC fractionator at temperatures to obtain the desired density, which some refiners are unable to do.

Clarified SO can also be a component or the primary feed to make acceptable anode-grade coke and needle coke.4 Anodegrade coke is a sponge coke that is used in aluminum production. Needle coke is crystalline with aligned needle-like clusters and it is used for steel manufacturing, usually requiring specially designed cokers and calciners. Although the SO particle concentration can be readily reduced to meet anode-grade and needle-grade specifications, other properties such as Ni, sulfur and nitrogen content are far more problematic for the refiner.

Typical needle and anode-grade coke properties are shown in TABLE 5.5 Globally, only about 22,000 bpd of SO production is used for creating needle coke. It should also be noted that the coke’s feedstock price can be considerably greater than that for TABLE 5. Typical anode and needle coke properties Property

Anode-grade coke

Needle-grade coke

Green

Calcined

Green

Calcined

Sulfur, wt. %

4 max.

3.5

0.5

0.5

0.7

0.5

Ash, wt. %

0.4 max.

0.4 max.

0.1 max.

0.1 max.

5–7

–

Nitrogen, wt. %

Potassium, ppmw max.

5–10

Pentane insolubles, wt% max.

7

Water, wt% max.

0.2

Nickel, ppmw

250 max.

200 max.

Viscosity, Saybolt @210°F, sec max.

100

Vanadium, ppmw

400 max.

350 max.

Flash, °F, min.

180

Real density, g/cc

66 APRIL 2013 | HydrocarbonProcessing.com

2.05 min.

2.1–2.14

Refining Developments residual FO blending and fuel-grade coke manufacturing, most likely $1/bbl to $2/bbl higher than carbon-black uses.

Particulate removal technologies. Holding tanks have historically been used to settle out solids of the SO. The resulting decant oil solids content is a function of the sedimentation tank design, the physical characteristics of the slurry, the temperature of the storage tank, and whether or not settling aids are used. Another product is being generated along with clarified oil is sludge. SO holding tank sludge is a hazardous waste and, therefore, requires special treatment and expensive disposal.

Depending on the tank size and rate of SO production, costs range from $1 MM to $4 MM per cleaning. In the absence of countermeasures, increasing resid feed to the FCCU will increase SO production and sludge formation.

Perhaps the least expensive capital and maintenance cost method for removing solids from SO is the liquid-phase cyclone separator or hydroclone. Liquid-phase hydroclones have been in departiculating SO service for over 50 years. Unfortunately, this method only allows solids levels to be reduced to 300 ppmw to 500 ppmw at best. The hydroclone does not give the refiner as much product application flexibility as the other solids-removal methods. Because of the dynamics of the hydroclone, about 10% of the feed slurry is sent back to the riser.

Although centrifuges have been used to remove solids from SO, their use is limited and it is difficult to make generalizations.

The one refiner known to use centrifuges in this service has ex-

pressed satisfaction with their operation, but the ultimate disposition of that SO is not known.

The first membrane filters were put into SO service around 1990. Mechanical filtration operates at temperatures up to 600°F and apply tubular porous metal elements. The solids collect on the inside of the elements while the filtrate passes through to the outside. Some filters use porous, sintered, woven-wire-mesh metal filters and operate at 400°F to 650°F. Other filters use a micron woven-wire filter element and use light cycle oil as a backwash at 350°F, claiming 85% to 95% solids removal from the feed slurry.

Electrostatic precipitators are routinely used to remove catalyst fines from the FCCU stack and a similar principle is used to separate solids from liquids in the electrostatic separator. Electrostatic separation of FCC catalyst fines from SO has been in commercial operation for over 30 years. It has improved and is a robust, automatic process that removes catalyst fines from SO or other hydrocarbon streams. Because this technology is not affected by the presence of asphaltenes, it is an excellent choice for removing solids not only from resid FCC-derived SO but also from gasoil crackers. The separator comes in two design charge capacities, each constructed of multiple modules. The units are skid mounted, fully piped and instrumented and arranged in a small plot space configuration. All regulatory fabrication and electrical codes are followed in the design.

Design and operation. Electrostatic separators come in a

modular design. Each model is constructed of multiple separa-

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Hydrocarbon Processing | APRIL 2013 67

Refining Developments

FIG. 1. A high capacity electrostatic separator module.

tor modules. A 12-module electrostatic separator is shown in FIG. 1. Each module is filled with glass beads. In this case, the module is 18 in. in diameter and 11 ft in length. Flowrates to this module can range from 600 bpd to 1,000 bpd, and each module has a holding capacity of 40 lb for catalyst fines.

During the separation cycle, the beads become ionized in an electrostatic field, causing a loss of ions on the surface of the beads, thereby creating a depletion zone. Catalyst fines are attracted to, and held back at, the many points of contact between the glass beads, while the particle-free liquid flows through the module.

The separator operates in cyclic fashion, working through three cycles: separation, back flush and a brief purge. During the separation cycle, catalyst-laden SO is fed to the modules. Voltage is then applied to the glass bead bed, capturing the catalyst particles in the bed. This is followed by the back flush cycle, during which the voltage is turned off. Charge to the electrostatic separator during the back flush cycle is, in most cases, a portion of fresh FCC feed, which is then fed back to the FCCU, along with the catalyst particles recovered during the separation cycle.

In the back flush cycle, the beads are fluidized, and, as they rub against each other, they dislodge any sludge. This freshly exposes the glass bead surface, fully restoring the bead activity, with no change in capture efficiency. This cycle also features charge removal, allowing the catalyst particles to be liberated from between the beads.

FIG. 2 shows a corner view of an electrostatic separator. This unit takes up a minimum of plot space. For example, a high

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Refining Developments 9 8

2,000 pp

m cataly

st recove

Payout time in months

7

3,000 pp

m catalyst

6 5

4,000 ppm

4

4,000 ppm catal

ry, $2/B

recovery

uplift

, $2/B up

lift

catalyst reco

very, $2/B

uplift

yst recovery, $4

/B uplift

3 2 1,500

2,500

3,500 Catalyst price, $/mt

4,500

5,500

FIG. 4. Payout times when using an electrostatic separator.

FIG. 2. Side view of an electrostatic separator.

12 11

covery,

lyst re pm cata

4,000 p

10 9 Yearly savings, $MM

lift

$4/B up

B uplift

ery, $2/

8

pm

4,000 p

7

recov catalyst

ft

li y, $2/B up

er lyst recov

cata 3,000 ppm

6

, $2/B uplift

talyst recovery

2,000 ppm ca

5 4 3

2,000

3,000 4,000 Catalyst price, $/mt

5,000

FIG. 3. Estimated savings when using an electrostatic separator.

capacity unit with 12 modules is only 33 ft long, 16.5 ft high and 13.2 ft wide.

Economics. Using a separator to remove FCC catalyst fines from SO creates value. In this example, an 80,000-bpd gasoil FCCU has a SO yield of 4 vol%, or 3,200 bpd. SO catalyst content is 2,000 ppm, 3,000 ppm or 4,000 ppm. All cases are compared against the base case in which the refinery uses a holding tank to reduce its solids. The slurry holding tank is assumed to require cleaning once per year at 2,000 ppm slurry solids, at a cost of $1.5 MM. Increased catalyst loads will incur higher cleaning and total costs. A portion of the FCC feed is used to backwash the electrostatic separator, after which it and the associated catalyst are fed back to the FCCU, thus reducing fresh FCC catalyst costs. FCC catalyst costs are assumed to range from $2,000 to $5,000 per metric ton. It is estimated that the average product upgrade value for this clarified SO can range from $2/bbl to $4/bbl. The added savings from not having to pur70 APRIL 2013 | HydrocarbonProcessing.com

chase chemical settling aids were not considered, even though such costs are estimated to be in the order of 6 cents to 20 cents per barrel treated.2 Heating costs for maintaining the holding tank at temperature are also not included.

FIG. 3 shows graphical results of this analysis. Three cases with SO catalyst concentrations of 2,000 ppm, 3,000 ppm and 4,000 ppm and slurry uplift of $2/bbl are presented, along with one case for recovering 4,000 ppm of catalyst with $4/bbl uplift. Savings with the electrostatic separator range from about $4.5 MM to $11 MM. A six module electrostatic separator removes > 99% of the catalyst from the slurry to give a clarified SO product containing less than 50 ppm of FCC catalyst. This model costs about $3 MM installed and is sufficiently robust to handle any of the cases investigated.

FIG. 4 shows the estimated payout times for the various cases, which range from three to eight months for all the various cases.

Catalyst savings might not be as valuable for a resid unit, but would still be significant. Individual cases involving deep-resid cracking benefits would have to be calculated based on a thorough knowledge of the resid FCCU feed, operating conditions and catalyst characteristics. Smaller catalyst particles returned to the unit have an inherently larger surface-to-volume ratio and provide a considerably higher resid cracking activity than the larger equilibrium catalyst held in the unit.

LITERATURE CITED Silverman, L. D. and S. Winkler, “Matrix effects in catalytic cracking,” NPRA annual meeting, Los Angeles, California, March 23–25, 1986.

2 Minyard, W. F. and T. S. Woodson, “Upgrade FCC slurry oil with chemical settling aids,” World Refining, November/December 1999.

3 Guercio, V. J., “US producing, exporting more slurry oil,” Oil and Gas Journal, October 4, 2010.

4 Motaghi M., Shree, K. and S. Krishnamurthy, “Anode-grade coke from traditional crudes,” PTQ , Quarter 2, 2010.

5 Elliott, J. D., “Impact of feed properties and operating parameters on delayed coker petcoke quality,” ERTC Coking and Gasification Conference, 2008.

1

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Gas Processing Developments M. SUFYAN KHAN, WorleyParsons, Muscat, Oman

Take a quicker approach to staggered blowdown The design of a reliable blowdown system for a large sour gas-processing facility is one of the most important aspects of plant design. Safe design is vital for facility operation. With the development of advanced plant design techniques and the evolution of sophisticated engineering programs, large, complex plants processing highly sour gas are being built that require larger flare systems and more precise blowdown system design.

Faster blowdown is also required due to the tightening of design standards in the oil and gas industry to minimize risk— e.g., to blowdown the equipment to 50% of the design pressure, or 7 barg, in 15 minutes. Larger pieces of equipment operating at elevated pressures yield high blowdown loads, and it may be impractical or uneconomical to design a flare system to simultaneously handle the blowdown loads of the entire facility. A staggered blowdown technique is applied in such situations to optimize the flare system design capacity.

Staggered blowdown. This process is required when the simultaneous blowdown load of the facility is significantly higher than the largest relief load under governing contingency and when the design of the flare system for simultaneous blowdown load is impractical or uneconomical. The staggered blowdown system should be designed to optimize the flare system design capacity while maintaining the ability to blowdown the facility as quickly and safely as possible.

Zonal blowdown approach. The conventional approach to staggered blowdown is to divide the blowdown loads into different zones and carry out the blowdown zone by zone.

Zones can be made by two methods: • Physical separation of units • Combining the blowdown loads of adjacent units to make the total zonal blowdown load equal to the flare capacity.

Zones by physical separation. Preference should be given to physically segregate zones based on allowable radiation criteria. This is a more efficient way of staggered blowdown, since, during a fire or any other emergency, the entire affected zone will blowdown immediately, followed by the adjacent zones.

However, this approach is primarily effective for relatively small facilities where the number of units is less, and where all of the units are placed within a few blocks on the plot.

In this case, the largest zonal blowdown load dictates the flare capacity, if it is not challenged by any other relieving rates under simultaneous or individual contingency. However, if the largest zonal blowdown load is still big enough to make the

flare system design impractical or uneconomical, then layout changes should be considered to keep the blowdown load units in different zones.

Zones by blowdown load. If physical separation of zones is not possible, or if the blowdown load of a zone is still high, then the zones can be made on blowdown loads analysis. All unit blowdown loads should be listed, and the adjacent unit loads should be combined to make a reasonable total that will equalize the flare capacity.

Consideration should be given to individual relief valve capacities. Of course, one zone load should not be less than the largest relief valve capacity. For an initial guess of the flare system capacity, a comparison should be made between the largest relief valve load (typically the blocked discharge of the inlet separators) and the largest individual blowdown load. If the flare capacity is selected as the largest relief valve/blowdown load, then the next step is to determine how many zones will be needed to blowdown the entire facility and how long this process will take.

This evaluation will determine if flare capacity should be increased. It is not necessary to keep the flare capacity equal to the largest simultaneous or individual relief load if the relief load is not excessive. In this case, the flare capacity can be increased to optimize the staggered blowdown design.

In some emergency situations, certain units may have preference over others and may need to undergo blowdown first.

One example is a simultaneous loss of seal gas to all process compressors. If such a constraint is present, then the combined loads of all preferential units should be evaluated to match the flare capacity. Putting all of these units—which immediately require blowdown under an upset situation—in one zone, and setting the flare capacity equal to the combined zonal load, may help simplify the blowdown and emergency shutdown (ESD) system design. Once the flare capacity is selected, then different zones can be made, preferentially of adjacent units, with each zone totaling to the flare capacity.

Case study. A gas-processing facility has several processing

units, with a combined blowdown load of 93 million standard cubic meters per day (MMscmd). The flare capacity is 16.55 MMscmd, of which 3.13 MMscmd is reserved for a relief valve from the trunkline. The relief from the trunkline relief valve is coincidental with the blowdown and continues throughout the entire blowdown duration. The effective flare capacity Hydrocarbon Processing | APRIL 2013 73

Gas Processing Developments available for facility blowdown is 13.42 MMscmd. Therefore, the combined blowdown load of the facility is about six times the flare system capacity. Developing an effective staggered blowdown sequence for this case is a challenge due to the large combined blowdown load compared to the flare capacity.

sign and calls for a quicker approach to reduce the total facility blowdown time within the UPS backup time.

Reducing blowdown time. A quicker approach is adopted

to reduce the total blowdown time of the facility within the UPS backup time. The idea of the quicker approach lies in the fact that the peak depressuring rate occurs in the beginning of the blowdown and then deLarger pieces of equipment operating pletes exponentially. A typical depressuring curve is at elevated pressures yield high blowdown shown in FIG. 2. The depressuring rate falls rapidly in the beginning and then drops to half of the peak loads, and it may be impractical or rate in less than four minutes. uneconomical to design a flare system The quicker approach to staggered blowdown developed for the case study is depicted in FIG. 3. As to simultaneously handle the blowdown can be seen, the last unit starts to blowdown at 45 loads of the entire facility. minutes, which is about half of the blowdown time calculated by a conventional zonal blowdown approach; it is also within the UPS backup time.

Unit sizes are bigger due to the high processing capacity of the facility; therefore, the layout includes one processing Methodology of quicker approach. The blowdown load of unit or train per block. Categorizing zones based on physieach processing unit in the facility is listed in TABLE 1. The decal segregation of the units yields numerous zones, and each pressuring curve of each blowdown valve for each processing zone capacity is significantly lower than the effective flare unit is extracted from the simulation model and built into a system capacity. Therefore, zones are made based on blowcalculation program. The blowdown load of preferential units down load analysis. [reinjection compressor 2 and 3, low-pressure (LP) acid gas Based on the calculated blowdown loads for each processing compressor 1 and 2, the flash gas compressor and high-presunit, six zones of 13.42 MMscmd each were made. Adding the sure (HP) acid gas compressor 1] are combined, which gives relief valve load of the trunkline to each zone’s blowdown load nearly 13.14 MMscmd. The relief valve load from the trunk makes each zone’s total load equal to the flare system capacity. line is added, bringing the total to 16.3 MMscmd.

Under a plantwide blowdown situation, such as an instruAt zero time, when the plantwide depressurization is acment air failure or a power failure, all the zones will blowdown tivated by the ESD system, the first set of units will start to one by one. Since each zone’s combined load equals the flare blowdown (see peak 1 in FIG. 3). It can be seen from FIG. 3 that, capacity, the blowdown delay between two zones is about 15 after two minutes, the blowdown load has dropped to 10.46 minutes, since the first zone under blowdown will reach its MMscmd. TABLE 1 lists the blowdown load of reinjection comminimal load after about 15 minutes. Only then will blowpressor 1 and HP acid gas compressor 2 at 6.21 MMscmd, at down begin in the next zone, so that the total blowdown load which point the units can safely start to blowdown. does not exceed flare system capacity at any point. The last At 2.17 minutes, the blowdown of reinjection compreszone begins to blowdown at 84 minutes, as shown in FIG. 1. sor 1 and HP acid gas compressor 2 is started, which raises the total blowdown load to 16.4 MMscmd (peak 2 in FIG. 3).

In the case of a plantwide power failure scenario, the total blowdown time is found to exceed the given uninterrupted Similarly, after 4.5 minutes, the blowdown rate falls to 11.08 power supply (UPS) backup time and, therefore, a safe blowMMscmd, and inlet separator A can be safely started to blowdown cannot be conducted. This puts a challenge on the dedown (peak 3 in FIG. 3).

18

1

16

2

3

4

5

6

Flare capacity: 16.55 MMscmd 6 7

5 Depressuring rate, MMscmd

14 Flow, MMscmd

12 10 8 6 4

3 2 1

2 0

4

0 0

10

20

30

40

50 60 Time, minutes

70

80

FIG. 1. Staggered blowdown curve for zonal approach.

74 APRIL 2013 | HydrocarbonProcessing.com

90

100

0

60

120 180 240 300 360 420 480 540 600 660 720 780 840 900 Depressuring time, seconds

FIG. 2. Typical depressuring curve.

Gas Processing Developments 18 16

1 2 3

4

5 6

7 8 9 10 11 12 1314 15 16

Flare capacity: 16.55 MMscmd 17

TABLE 1. Blowdown loads for various units Unit

14

Flow, MMscmd

12 10 8 6 4

0

Inlet separator A

5.48

Inlet separator B

5.48

Inlet separator C

1.23

Test separator

0.53

Condensate stabilizer unit

2.21

Flash gas compressor

2 0

10

20

30 Time, minutes

40

50

60

FIG. 3. Staggered blowdown curve for quicker approach.

By this method, the moment that the total blowdown load in the flare system falls to a level where another unit’s load can be added, that unit’s blowdown is initiated. This method utilizes the maximum use of flare header capacity. As soon as the capacity becomes available in the header, the next blowdown is activated.

Units with smaller blowdown loads, such as the test separator and the seal gas compressor, will experience smaller peaks if blowdown is initiated independently. The combination of several smaller units is recommended to bring the total blowdown load to a reasonable level (e.g., 2 MMscmd– 3 MMscmd), so that the number of peaks will be less and ESD logic will have a reasonable time delay during which to initiate blowdown at additional units.

Making smaller groups to reduce the number of smaller peaks will not increase the total blowdown time of the facility.

In this case study, both options (blowing down each unit one by one, and combining smaller units into a reasonable capacity group) were examined. The difference was only a few minutes, with a gain of ESD logic simplicity.

ESD design for quicker approach. For the ESD system design of the facility, several staggered blowdown sequences may need to be developed, depending on the ESD philosophy of the project. If the project philosophy is to initiate a plantwide blowdown in case of fire detection in any area of the plant, the fire detection in each area of the facility will need a separate staggered blowdown sequence, as the area under fire will be the first unit in the sequence to blowdown.

In the case of common-mode failure scenarios (i.e., an instrument air failure or a plantwide power failure), a set of preferential units will blowdown first. Thus, the ESD system will be provided with several staggered blowdown sequences to accommodate different emergency situations.

Takeaway. This case study shows that a quicker approach to

blowdown can reduce the total time by around half, compared to the conventional zonal approach. A faster approach makes good use of the flare header capacity, as unit blowdowns begin the moment capacity becomes available in the flare header.

The quicker approach helps to expedite the total blowdown

Peak depressuring rate, MMscmd

1

Trunk line

3.13

Sweetening unit 1

5.42

Sweetening unit 2

5.42

Export gas compressors

2.48

Dewpoint control unit

7.31

Reinjection compressor 1

5.67

Reinjection compressor 2

5.67

Reinjection compressor 3

5.72

Dehydration unit 1

2.15

Dehydration unit 2

1.09

HP acid-gas compressor 1

0.54

HP acid-gas compressor 2

0.54

LP acid-gas compressor 1

0.11

LP acid-gas compressor 2

0.11

Piping segment 1

10.46

Piping segment 2

2.51

Piping segment 3

3.02

Piping segment 4

1.24

Piping segment 5

2.95

Piping segment 6

3.18

Seal gas compressor

0.18

Seal gas buffer vessel

6.53

Fuel gas unit Total

1.71 93.06

time and improves the design of the UPS system for instrumented protective system backup.

MUHAMMAD SUFYAN KHAN K.K. is a process engineer with WorleyParsons. He has over seven years of process design and engineering experience in the oil and gas sector, with emphases on process simulation, FEED development and detailed engineering. Mr. Khan has worked on greenfield and brownfield projects at oil refineries and gas processing plants around the world, and he has experience in dynamic simulation. He holds a degree in chemical engineering from the University of Karachi, Pakistan and is an associate member of the Institution of Chemical Engineers (IChemE).

Hydrocarbon Processing | APRIL 2013 75

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Turbomachinery Developments T. SOHRE, Sohre Turbomachinery, Monson, Massachusetts; and H. P. BLOCH, Reliability/ Equipment Editor, Westminster, Colorado

Select the right shaft-riding brushes for turbomachinery Since the mid-1950s, much progress has been accomplished in the development, design and production of shaftriding brushes for turbomachinery applications. The machinery includes steam and gas turbines, gears, turbocompressors and ship propulsion systems. The brushes assist in controlling shaft current problems, especially under conditions in which the shafts operate at high-surface velocity, oil-splash and other susceptible environments.

Shaft currents are often generated by nonelectric machines.

Of course, they also occur in equipment trains with electric motors and generators. Shaft currents can be of electrostatic or electromagnetic origin. They can cause severe damage to bearings, shafts, seals, gears and other machine elements. FIGS. 1 and 2 are typical examples of such damage.

The application of brushes (FIGS. 3–5) can assist in monitoring shaft voltage and determining how much shaft current is being developed. Brushes and proper monitoring will provide warnings of dangerous current buildup. This buildup can be caused by self-magnetization and self-excitation, among other reasons.

Strongly magnetized machines must be demagnetized. Residual electromagnetic currents of reasonable strength can be grounded to protect the machine against discharge damage.

Typical electrostatic currents can always be grounded through a brush because the amount of current is usually low in comparison to magnetically induced currents.

NEW SOLUTIONS Another application for modern brushes is signal transmission from strain gages or other instrumentation located on the rotor. For example, the measurement of torque, torsional and lateral vibration, blade vibration, temperatures and pressures on rotor components can be facilitated by brushes.

Good brushes provide a very low electrical noise level, even at high-surface velocity and in an aggressive environment. Together with a low-wear rate and easy replacement during operation, a low electrical noise level permits continuous, long-term monitoring and removal of modest amounts of current during both normal and abnormal equipment operation.

Competent brush manufacturers provide standardized products, and many parts are interchangeable. Models of

FIG. 1. This thrust bearing damage could have been prevented by a well-engineered shaft-riding brush.

FIG. 2. Spark damage of the type that can be prevented by using shaft-riding brushes for early detection of developing problems.

Hydrocarbon Processing | APRIL 2013 77

Turbomachinery Developments varying lengths are available from experienced vendors to accommodate requirements of various turbomachinery manufacturers, and to meet the requirements dictated by emergency-retrofit field installations. Many installations are in hydrocarbon processing industry (HPI) facilities and often in aggressive environments. It is vital to inform vendors of the processing conditions in which the brush will operate. It is very important to define if an installation will be in a hazardous, chemical attack-prone or otherwise severe environment.

Materials. Shaft material is also an important item, as most shaft-riding brushes will run best on carbon steel or low-alloy carbon steel. Other shaft materials should be avoided for HPI installations. For instance, operation of typical metal-fiber (bristle) brushes on aluminum, titanium, high-alloy austenitic steels, copper, brass or any material with poor wear characteristics can result in shaft grooving, rapid bristle depletion, or some other undesirable, perhaps catastrophic, consequences.

Never run a brush on a highly stressed surface, especially if vibratory stresses are present. Examples of such cases include thin-wall hollow shafts or spacers, areas of stress concentration and quill shafts. Running brushes on a shaft can introduce stress concentrations. For example, frosting can occur due to unusually high current above the brush rating. On a highly stressed surface, this can lead to catastrophic failure.

indicator. Brush elements can often be inspected or replaced within a few minutes while the machine is in operation.

Therefore, replacement is not restricted to periods of shutdown or plant turnaround.

Brushes installed by the original equipment manufacturers (OEMs) during initial construction of the machine often have longer bristle element life. Those installed as an emergency field retrofit typically have shorter wear lives—for reasons of much less than ideal shaft surface finish, out-of-roundness, cleanliness, and lubrication conditions. Also, the excessive shaft currents often found in field retrofit situations will drastically reduce bristle element life.

Well-designed shaft brushes work with shaft surfaces dry or wetted with oil, or the brush may operate in an oil-splash or submerged surrounding. Applications operating with a reasonable oil-splash or oil-spray work better and last somewhat longer than brushes running in completely dry applications.

The reasons are found in the effects of lubrication and the removal of dirt, gum and wear debris. The axial shaft space requirement for many brush installations can be of real importance because of the very restricted areas in typical machines.

One brush manufacturer’s standard version requires about ¾ in. (20 mm) of axial shaft space. The larger brushes require a minimum of approximately 2.5 in. (63 mm).

MATERIAL SELECTION IS IMPORTANT All brush materials used must have good stability in hightemperature service. The standard brush design is suitable for operation in environments to 400°F (205°C). Even the vendor’s standard brushes should be equipped with a wear

Description of typical models. There are two basic types of

brushes: The “toothbrush” type, shown in FIGS. 3 and 4, and the “plunger” type, as illustrated in FIG. 5. Different sizes and minor changes accommodate a very wide range of turbomachines.

Plunger applications. In general, “plunger” types are used where available space requires a radial- or axial-brush installation. It is especially suited for field retrofit applications, in which the mounting possibilities are usually very limited, and Bearing case or coupling guard

Brush raising screw Wear indicator Lead wire

Bristle element, (replaceable) silver/gold Internal cartridge can be removed while in service

FIG. 4. Typical mounting arrangement of a “toothbrush” type of shaftriding brush.

Bristle element silver/gold (replaceable in service)

Wear indicator Brush raising screw

Lead wire

Spring assist

FIG. 3. A “toothbrush” type of shaft-riding brush.

78 APRIL 2013 | HydrocarbonProcessing.com

FIG. 5. Cross-section view of a plunger type of shaft-riding brush.

Turbomachinery Developments the axial positioning in an outboard bearing case end cover may be especially attractive. Retrofits can sometimes be accomplished while the machine is in operation. A temporary cover plate has been used occasionally while the permanent cover is removed for machining and mounting of the brush.

For turbine generators, one manufacturer suggests experience-based sizing guidelines, as described in TABLE 1. These guidelines are approximations and actual figures will depend on particulars of a given installation. Some particulars may not be fully known in advance and may need to be established at the time of brush installation. There are many factors that can have a strong influence on the life expectancy of the sacrificial brush elements. Examples include residual magnetism in shafts and casings, or the design and condition of a motor or generator and exciter. At higher frequencies of current, the rate of bristle burn-off increases significantly, but its complexities are not yet well understood or predictable. Installations for retrofits are, by necessity, often difficult. OEMs have an opportunity during the design stage to select the most favorable arrangements.

These manufacturers can modify bearing housings and other components to provide good mounting conditions. Usually, OEMs design and manufacture their own mounting flanges, to which the brush casing is then welded at the assembly stage.

Typically, these flanges should be about ¼-in. (6-mm) thick and should be made of 300 series, nonmagnetic, stainless steel.

Frequently asked questions. Because details tend to vary considerably, a user may wish to consult a competent brush manufacturer’s guidelines. Manufacturers may refer to relevant instruction and installation manuals for additional information.

Frequently asked questions include: Q1. Why use shaft-riding brushes? To measure stray electrical currents (“shaft currents”) on the rotating shafts of machinery, and to ground modest amounts of electrical rotor currents. This should prevent or minimize electrical damage to bearings, seals, gears and other critical components.

Q2. What are the orientations in which well-designed brushes can be installed? Installation can be in any position with respect to the shaft: tangential, radial, axial or skewed, as well as vertical, horizontal or upside down.

Q3. What is the correct method of permanently installing the brush? There are six installation steps. A general summarized procedure is: • Prepare a stainless steel mounting flange • Mount flange to brush with temporary brackets • Bolt to machine and adjust • Weld flange to brush casing • Bolt and dowel brush and flange unit to machine • Make electrical connections, and check out everything.

Q4. What conditions are required on the shaft? A surface finish of 63 micro-inches root-mean-square (RMS) is acceptable, but 32 RMS is preferred. Shaft surface finish is an important factor in bristle element life. A rough shaft will result in an unacceptably high rate of bristle element replacement. On a smooth shaft, the rate of bristle depletion due to mechanical wear will be close to zero. Electrical burn-off will still be a factor. The shaft needs to be free of irregularities such as rust, nicks, dings, scratches and match marks. Some oilsplash, spray or mist is ideal but not essential.

Q5. How long will bristle elements normally last? On a smooth shaft, the sacrificial bristle element will typically last from one to three years. Actual performance depends very much on how much current is flowing through a brush, as well as, the shaft surface finish. The amount of current flowing through a brush is difficult to predict and can change significantly during operation, even on a daily basis.

So, then, the primary factors affecting the life of the sacrificial bristle element are the amount of current through a brush, and the shaft-surface finish. Bristles deplete due to electrical “burn off ” caused by the current, and the shaft surface finish affects the rate of bristle depletion attributable to mechanical wear.

An experienced manufacturer typically tries to select a model type and then a number of brushes that will result in about one year of bristle element life. (Note: In many cases, it will be possible to replace the bristle element while the unit is TABLE 1. Brush rating or “sizing” guidelines Up to 25-MW generator rating per brush, or up to 1 amp DC continuous for one year of bristle element life.

Up to 50-MW generator rating per brush, or up to 4 amp DC continuous for one year of bristle element life.

Up to 500-MW generator rating per brush, or up to 100 amp DC continuous for one year of bristle element life.

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79

Turbomachinery Developments often possible to reduce the burn-off rate by installing a larger brush, or by installing more than one brush. For instance, the time between brush insert replacement will be about four times as long if two brushes are used instead of just one.

Q6. Why pay more for silver/gold composite bristles when copper or carbon brushes work fine? Solid copper or carbon brushes are not suitable for high-shaft surface velocities; they will groove the shaft, spark or quit working altogether. Solid copper or carbon brushes will also stop performing at low levels of current. For instance, copper straps and carbon brushes do not function well in oil or in contaminated or dirty environments. Well-designed brushes are, by comparison, self-cleaning even in dirty environments; they actually benefit from an oil environment.

Q7. What is the advantage of silver/ gold bristles over other materials? The noble metals are corrosion-resistant, even in very hostile environments. Also, silver/gold bristles have exceptionally good electrical contact characteristics at the shaft surface and produce the lowest possible residual shaft voltage.

Q8. How many brushes should be installed, and what type of brush should be used? The quantity and 1967 Nova Pro Street model of grounding brush best used on a particular unit will depend on the peak current flowing to ground, as well as, on physical constraints. For this reason, reliability professionals should stay in touch Process Maxum with an experienced manufacturer and ask for competent guidance. Realistic Do you have flows up to professionals are prepared to pay for good 9,900 GPM (2,000 m3/hr), counseling and quality products. The heads up to 720 Ft (220 M), amount of current is difficult to predict, speeds up to 3,500 RPM, and since it depends on many factors such as temperatures up to 500째F (260째C)? Then you the strength of residual magnetism in the need Carver Pump Process Maxum Series muscle! machine (particularly in the rotor, stator, With an extended range of hydraulic coverage and rugged foundation, piping, etc.). With electrical construction, the Process Maxum Series is ideal for equipment, generator and exciter designs Industrial Process applications. Manufactured in 35 sizes, or conditions are also very important. standard materials include WCB, WCB/316SS, 316SS and In some situations, it may be necesCD4MCu, with others available upon request. A variety of options include various types of mechanical seals and sary to install more than one brush. For bearing lubrication/cooling arrangements, auxiliary example, if a turbine is driving a generator protection devices and certified performance testing. through a gear, then current could be genWhatever your requirements, let us build the erated either by the generator, turbine, muscle you need! gear or any combination of the three.

In case only one grounding brush is installed (on the turbine, for instance), current from the generator could be drawn Creating Value. across the gear teeth. This would result Carver Pump Company in damage to the gear teeth or bearings 2415 Park Avenue of the gear set. Installing brushes at both Muscatine, IA 52761 ends of the gear would eliminate this pos563.263.3410 Fax: 563.262.0510 sibility. It would ground the gear, as well, www.carverpump.com and prevent it from magnetizing the rest of the train. Gear-type couplings are susceptible to damage in a similar manner.

online.) However, there are many factors to consider, not all of which will be known at the time of brush installation. For that reason, it is not unusual for bristle elements to be depleted significantly sooner, or to last much longer than expected.

When considering the brush burn-off rate, remember that the brushes are sacrificial components. The bristles burn down to prevent spark damage to far more expensive parts of the machine (bearings, governor and gears). Consequently, a high burn-off rate would simply mean that the brush is doing what it was supposed to, i.e., preventing expensive damage, which would otherwise occur inside the machine. It is

80

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Turbomachinery Developments Generally speaking, a particular brush category is suitable for mechanical-drive equipment and small turbine generators. Another category is designed for central station power plants with units of 100 MW to over 1,000 MW. Of the smaller brushes, a “premium” type will carry about four times as much current as a certain related type will do for the same bristle “burn-off ” rate.

For this reason, one type may distinguish itself as the most economical of the small brushes in terms of ampere-hours per dollar and have the longest bristle element replacement interval in a type or configurational grouping. Working with a competent brush manufacturer is valuable and provides economic sense.

Q9. Why is residual magnetism in rotors and casings important and what should be done about it? Residual magnetism in rotors and stators is a common and troublesome cause of stray-electrical shaft currents. For this reason, it is appropriate to do a careful and thorough check for residual magnetism whenever a machine is disassembled.

It is mandatory that not only rotors should be demagnetized, but also the casings, piping, base plate, foundation and so on. If the demagnetization step is omitted, remagnetization will occur immediately when a rotor is placed in its casing. In fact, the entire unit, its mounting, and accessories will start to be magnetized as soon as the rotor is turned.

Here are very general rules-of-thumb for turbomachinery and similar equipment: • Rolling-element bearings are much more vulnerable to shaft current damage than hydrodynamic bearings. In the case of residual magnetism-induced stray electrical current damage to rolling-element bearings, the best remedial action would be to reduce all residual magnetic field levels as far as possible (1 gauss–2 gauss), especially in the bearing, its surroundings and the nearby shaft.

• Measure each component and de-gauss as necessary before installation, and as the machine is being assembled. Magnetic field levels will often increase as the parts are assembled and installed into the machine.

The suggested maximum allowable levels of residual magnetism for typical turbomachinery with hydrodynamic bearings are summarized in TABLE 2.

Q10. What is the suggested electrical arrangement for shaft-grounding brushes and voltage-sensing brushes? Experienced manufacturers will be pleased to supply drawings or schematics. The purpose of a shaft-grounding system is to bypass stray currents around the parts to be protected (for example, a thrust bearing). Connecting the brush to the lower half of the casing, close to the part to be protected, is suggested.

This is as close as possible to the current path, assuming it had traveled through the component. It is also desirable to have the shortest and simplest connection from the brush to ground.

Connecting directly to a plant grounding grid (rather than the lower half of the casing) can cause a high rate of bristle depletion and is not advisable. Also, grounding a brush to the frame of an electrically active machine, such as a motor or generator, will often result in a very high rate of bristle burn-off.

Q11. Are there additional issues to consider? Stray electrical shaft current situations and their remediation can become surprisingly complex. Consequently, reliability en-

TABLE 2. Maximum suggested levels of magnetism allowed with hydrodynamic bearings Bearing components, including pads and retainers, journals, thrust disc, seals, gears and coupling teeth

2 gauss

Bearing housings

4 gauss

Mid-shaft and wheel areas, diaphragms, etc.

6 gauss

Components remote from minimum clearance areas, such as casings, piping, etc.

10 gauss

gineers are encouraged to contact a competent provider for all new installations, as well as for installations exhibiting unexpected behavior. It should be recognized that, in some situations, simply installing a shaft-grounding brush without taking additional investigative and corrective action will not eliminate the problem. For example, if a machine has become highly magnetized, grounding brushes will not be able to protect the machine. The brushes will not draw off all the current generated, and the rate of bristle burn-off will be unacceptably rapid.

At worst, the unit could become electromagnetically selfexcited, resulting in a catastrophic failure. This phenomenon is described in the technical information kits supplied by highly experienced brush manufacturers. The correct action in the event of unusual behavior is to thoroughly investigate the situation. The equipment should be carefully monitored and surveyed for both residual magnetism and shaft-current activity. Again, the equipment may need to be carefully demagnetized without undue delay. Brushes should then be installed for the purpose of grounding and monitoring any remaining electromagnetic activity.

Certain electrical problems with generators and motors can create shaft current magnitudes far beyond the capacity of any shaft-grounding device. Electric motors or generators driving from both ends deserve special consideration, as will variable frequency drives.

Bottom line. There is no substitute for understanding preventive and proactive measures needed to preserve both physical and human assets. Reliability professionals are urged to stay abreast of shaft-current-elimination technologies and to work with a competent vendor-manufacturer. Both actions will pay great dividends over the long term.

TOM SOHRE has been professionally involved with turbomachinery for approximately 40 years and is the general manager of Sohre Turbomachinery, a manufacturer of shaft riding brushes for turbomachinery. His prior positions have included design and field service engineering at Westinghouse, GE, Brown Boveri, and the Hartford Steam Boiler Inspection and Insurance Co. Mr. Sohre is a graduate of the University of Connecticut.

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 | APRIL 2013 81

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GLOBAL TURNAROUND AND MAINTENANCE Overcome barriers to proper planning and scheduling

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OVERCOME BARRIERS TO PROPER PLANNING AND SCHEDULING J. WANICHKO, T.A. Cook Consultants Inc., Raleigh, North Carolina

Planning and scheduling must work hand-in-hand for a turnaround, outage or shutdown to be executed to budget and schedule. Unless proper diligence is given up-front to planning and scheduling, no amount of execution excellence will recover the waste associated with unclear work plans, inflated estimates and poorly defined schedules.

Scheduling practices in use today are examined here, and the common pitfalls encountered in planning and scheduling are explored. Additionally, tips to avoid these pitfalls are provided.

Present scheduling practices. In a survey of European companies involved in conducting shutdowns, turnarounds and outages, 57% of the respondents did not have detailed, step-bystep procedures for creating a schedule, and they did not reuse schedules from previous events as a starting point when building a new schedule.

Building a schedule is considered the exclusive domain of the scheduler, and it is dependent upon each scheduler’s experience and knowledge. A surprising 26% of schedulers have built less than 10 schedules, and 45% of schedulers have learned scheduling “by doing it” (FIGS. 1 and 2). When schedules are built, 77% are made either by hand or by importing data to create a new schedule. Only 23% of companies have an archive of schedule templates from previous events that they can modify to create a new schedule.

However, on the positive side, the use of a schedule during execution shows that 54% of companies provide continuous feedback and updates to the schedule. Only 17% produce a schedule, hang it on the wall, and then never update it. A full 70% of schedules are updated either at the end of the shift or at least once per day.

Expectations of planning and scheduling. When beginning

an event, it is important for all stakeholders involved to understand and agree to certain “ground rules” or expectations. For a schedule to be an accurate and useful tool, it requires the effective and timely interaction of planning, estimating, scheduling and operations departments, as well as the contractors working the job. If any one party is absent, the resulting schedule will not reflect the actual requirements of the event and will likely result in failure for the execution team.

There must also be a high degree of “information consistency” between all parties involved. Everyone must understand what the information requirements will be prior to and during the event, including but not limited to: • Timing of input • Frequency of updates • Information required (in what format and level of detail)

• How estimates for schedule progression will be calculated • Who is responsible for providing these estimates.

It is best to build a communications matrix prior to the event and to include all information requirements/updates, involved parties, frequencies and templates/level of detail. This matrix should be reviewed with all stakeholders in a pre-event coordination meeting (FIG. 3).

Expectations for the planners are straightforward; walk down jobs and build complete work packages for each job as defined by the scope of the event. Ideally, the planner will have a library of work packages from the last time the turnaround was conducted and can update the old work package to current conditions.

The planner and the scheduler must agree on who will build contingency into work estimates and where this contingency will be located. This is primarily the scheduler’s responsibility, but both the planner and the scheduler must understand how the contingency will be managed.

The objective of the scheduler (with the support of planning, estimating, operations and contractors) is to build a single turnaround schedule that incorporates all planned activities for the turnaround, any capital project work being done during

Less than 10 10 to 29 30 to 49 50 to 99 100 or more

9%

13%

26%

23%

29%

FIG. 1. Scheduling experience and training.

Learning by doing Once-off training (concerning software tools) Once-off training (methodologically in fundamentals of scheduling) Regular training and further qualification None

7%

20% 13%

45%

15%

FIG. 2. Level of scheduling training.

Immediately after a job has been completed At the end of the shift Once a day Continuously throughout the day

20% 38%

10% 32%

FIG. 3. Time of feedback (asked only if feedback is provided).

HYDROCARBON PROCESSING | GLOBAL TURNAROUND AND MAINTENANCE 2013

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GLOBAL TURNAROUND AND MAINTENANCE

TABLE 1. Common planning pitfalls and how to avoid them Pitfall

Details

Assigning the wrong person as planner

Availability is not a skill set. The skills a planner needs to have are mechanical understanding, attention to detail, discipline to follow a process, ability to think logically and computer skills.

Selecting an inadequately trained planner

Planners must know how to work the computerized maintenance management systems (CMMs) they will be using, how to process work requests and plan them to the agreed standard, how to extract data from the CMMS and generate reports, how the kitting and staging process works and how to follow the safety standards for the assigned area.

Hiring a multi-tasking planner

A planner’s job is to plan. A planner should not be used to expedite parts, to supervise if a backup is needed, to procure quotes from vendors, to order parts or to schedule.

Using a planner for emergency or unscheduled work

If a planner is firefighting, he or she is not planning. The right personnel must be used in emergency and unplanned situations; planners should not be counted on to assist with unscheduled work.

Hiring a “desk planner”

Every job requires a walk down. Even if a library of well-defined work packages exists, planners must assess each job in person and update the package. Planning is not a desk job!

Improperly allocating resources and materials

Planners must understand sequences, dependencies and space limitations, and plan for them. Work and resources must be planned in the sequence they will be performed, and jobs should be planned so that crews do not need to stop for anything (e.g., permits, tools or personal protection equipment).

Likewise, waste should be eliminated before it occurs.

Providing poor job instructions

Planners should use detailed, proper descriptions of work to be performed. “Open pump, fix it” is not sufficient. A new hire will benefit from a detailed description, while an experienced hire can use the information as a checklist.

Not providing feedback

To improve plans, planners must receive feedback from the field, especially when steps are missed, when estimates are too high or too low, or when required parts or equipment are missing.

Not kitting and staging

Planning is work preparation. The work crew should not need to stop for anything. The planner must communicate clearly with the person who is kitting. Note: planners should not rely on vendor promises.

Nothing should be added to the schedule unless all elements are accounted for and present.

Not gaining cooperation and commitment from operations

Work, no matter how well planned, cannot be performed in a vacuum. The operations department owns the equipment, signs the permits and locks out the equipment, and it must buy into the schedule prior to it being communicated. After agreeing to the schedule, the operations department must adhere to it and supply the right resources to honor the schedule.

Managing the backlog poorly

The backlog must be free and clear of old and obsolete work orders, duplicate work orders and completed work orders that have not been closed out.

the event, and the operations department’s detailed shutdown and startup plans for the unit.

The first 24 hours of the shutdown plan must be detailed and include sequenced hour increments, identified dependencies and specific resource requirements for each activity. The scheduler will provide operations with a date by which the plan must be delivered in sufficient detail and accuracy to be incorporated into the overall turnaround schedule.

The schedule should be built with the goal of having a high degree of repeatability and sustainability to support its reuse in future events, with some updates and modifications, vs. rebuilding a schedule from scratch each time.

Present turnaround planning and scheduling. Increasingly, contractors are doing more planning and scheduling on behalf of the operators. While the contractors must bring expertise and knowledge of the tools, the operator cannot abdicate the leadership role to the contractor. It must be the operator who defines which scheduling IT tool will be used, what level of detail will be seen in the schedule by each functional group involved in the turnaround, how job progression to the schedule will be calculated and when updates will occur.

Note: Although more contractors are being used, some level of expertise must be retained in-house. This is necessary T–86

GLOBAL TURNAROUND AND MAINTENANCE 2013 | HydrocarbonProcessing.com

to ensure that specific knowledge remains with the operator to validate or challenge work estimates and plans built by contractors for accuracy. This knowledge will also enable effective coordination between operations and contractors.

Differences exist in the area of work estimation using standardized work values, resulting in inconsistent and inaccurate work plan estimates. North American operators rely more on “expert” judgment, so it is not uncommon for work estimates to be inflated by as much as 40%. Europe, on the other hand, uses standardized work component estimation, providing greater consistency and accuracy. Work estimates and plans should always be validated by a credible source prior to being entered into the schedule.

With the increased use of contractors, contracts and how they are structured play an increasingly important role in the success of any event. More precisely, integrated and comprehensive job evaluations allow for the introduction of modern contract types for contractors, reducing the need to push risk to the contractor.

Frequently, the objective of the contract is to create a winwin agreement for both the operator and contractor. Establishing a win-win contract allows the operator and the contractor to work together instead of against each other. Time and material contracts, favored in North America, drive contractors

GLOBAL TURNAROUND AND MAINTENANCE

to integrate as many workers as possible into the turnaround.

This creates an immediate conflict, as operators prefer to complete the turnaround with the minimum resources required in the shortest time possible. To prevent these types of conflicts, improved accuracy based on better advance estimates and planning is required.

There are three phases to the scheduling process: • The concept phase, which is the foundation for an effective and efficient schedule • The creation phase • The usage and update phase.

During the concept phase, several parameters should be defined: the schedule structure, standards for the schedule elements and progress feedback procedures, and schedule reporting during the execution phase. Once these parameters are defined, they must be communicated to operations, to the execution team and to the contractor team.

A precondition for the creation phase is that the scope must be defined, and the detailed technical planning results must be available. Many companies seem to ignore this precondition and then do not understand why the event’s schedule and budget are not met. In conjunction with scope management and cost control, scheduling forms the “magic triangle” of project management for turnarounds.

There must be flexibility in schedules to enable a quick and easy response to any changes that become necessary. Schedules should be reasonably flexible without sacrificing the necessary

control mechanisms. Schedule flexibility is necessary because of unscheduled repair work, uncertainty about equipment availability and capacity, and logistical challenges and restrictions due to limited space in the plant.

The quality of the schedule is defined by scope freeze. The scope needs to be frozen and the schedule prepared using optimization techniques, ideally 12 months prior to the shutdown phase of the turnaround. Scope freeze begins with all stakeholders understanding and agreeing to the reason for the turnaround. Once the scope-freeze phase is finished, any suggested additions must be “challenged into the scope,” not out of it. A rigorous scope-management process should be well managed and based on a company’s defined risk-management processes.

The pitfalls of planning. Planning is the starting point, and the schedule can be no better than the items that go into it. With this point in mind, TABLE 1 reviews common planning pitfalls and recommendations for avoiding them.

JERRY WANICHKO is the director of consulting operations for T.A. Cook Consultants in North America. He has over 25 years of international consulting experience in several industries, with particular expertise in oil, gas and chemicals. Previously, he was director of operations for Fluor, where he provided routine maintenance, reliability, and planning and scheduling services at 13 different petrochemical sites. Mr. Wanichko provides consulting services to asset-intensive businesses in the refining and petrochemicals industries. His work supports clients with maintenance optimization, turnaround, outage, shutdown optimization and overall equipment effectiveness improvement.

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CURTISS-WRIGHT FLOW CONTROL

DELTAVALVE, TAPCOENPRO, AND TAS AFTERMARKET SERVICES Our aftermarket services group has a keen focus on safety, quality and on-time completion of all projects. Our team extends complete on and off-site services with DeltaValve, TapcoEnpro, or Total Automation Solutions (TAS) products in their facilities, anywhere in the world.

To meet customer needs, we maintain major service facilities staffed with certified technicians in the US and Europe. We are working to establish additional service facilities globally to service our growing list of worldwide customers. Our current network of field service technicians are on call around the clock, and are specifically trained to evaluate, troubleshoot and resolve problems in a timely, professional manner. Our teams focus on equipment installations and rebuilds, turnaround service, maintenance and repair, site acceptance tests and audits, commissioning supervision, hydraulic flush services, electrical loop checks, bolt tensioning and torqueing, on-site training, and more.

Whether you need on-site training or have an emergency at two o’clock in the morning, our aftermarket services group is ready to help.

Our 24-hour service number is 1-281-247-8100.

CONTACT INFORMATION Curtiss-Wright Flow Control Aftermarket Services 16315 Market Street Channelview, Texas 77530 Phone: 1-281-247-8100 Fax: 1-281-552-3424 tapcoenpro@curtisswright.com www.cwfc.com

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GLOBAL TURNAROUND AND MAINTENANCE SUPPLEMENT 2013 | HydrocarbonProcessing.com

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FabEnCo

FALL PROTECTION WITH FabEnCo SELF-CLOSING INDUSTRIAL SAFETY GATES As the world’s leading manufacturer of adjustable, self-closing industrial safety gates, FabEnCo is the “one-stop shop” for high-quality, American-made safety gates. With a full range of gates for fall protection as required by OSHA, FabEnCo gates fit unprotected openings up to 60 inches at ladders, platforms, stairs, catwalks, mezzanines and machine guarding.

FabEnCo’s family of safety gates includes the A Series (the original double bar gate), the XL Series (for extended vertical coverage), the R Series, (a competitively-priced, metal alternative that replaces aging and/ or deteriorating “plastic” gates) and the Z Series (designed specifically for new construction projects). FabEnCo also offers its Toe Board Kit as an optional clamp-on extension to the Z Series gate.

FabEnCo Self-Closing Safety Gates are available in carbon steel, as well as aluminum and stainless steel for special applications and environments. Finishes include galvanized and safety yellow powder coat. FabEnCoat™ finishes include galvanized and safety yellow powder coated.

Easy to install on all types of handrails (angle, flatbar, pipe) or to existing walls, FabEnCo Self-Closing Safety Gates save companies

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the time and money it takes to fabricate their own gates. Most gates can be mounted on either the left or right side of handrail openings, at different levels. Once the stop bolts have been adjusted, each safety gate’s reliable stainless steel spring automatically closes the gate to the customizable stop point set on the gate—up to a 90 degree angle.

Safety gates are shipped directly from FabEnCo’s manufacturing facilities in Houston, Texas, and arrive with all of the necessary mounting hardware. Easy-to-follow mounting tips are included with each gate.

In addition to contacting the company by phone, customers have the option of easy online ordering using a major credit card or charging their open account.

CONTACT INFORMATION Address: 2002 Karbach Houston, Texas 77092 Phone: (713) 686-6620 Fax: (713) 688-8031 Toll Free: (800) 962-6111 www.safetygate.com

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Real value behind every valve.

That’s the FAST Center guarantee.

Farris Engineering’s global FAST Center network adds value to every Farris valve.

Our FAST Centers offer total valve replacement, service and repair any hour, any day – 24/7/365. The FAST Centers employ factory trained valve repair technicians working in ASME and VR certified valve testing facilities. At Farris, our work is never done. Once we sell you a valve, our FAST Team is there to keep your valves in service and your plant safe.

To locate your local FAST Center: http://farris.cwfc.com or 1-877-FARRIS1 Select 56 at www.HydrocarbonProcessing.com/RS

FARRIS ENGINEERING

FARRIS GETS YOU BACK TO BUSINESS FAST A HISTORY OF INNOVATION Farris Engineering, a business unit of Curtiss-Wright Flow Control Company, is celebrating 70 years of innovation and manufacturing excellence. Farris’ legacy of providing unique pressure relief solutions started with the balanced bellows pressure relief valve (PRV) design.

Introduced in the 1950s, the balanced bellows mitigated the effects of back pressure and chemical erosion on internal valve components.

The balanced bellows remains a standard feature used in PRVs to this day. In the 1980s, Farris introduced SizeMaster, the original PRV sizing software. SizeMaster automated and simplified the complex process of sizing and selecting PRVs and is the foundation for our patented iPRSM™ software.

Farris manufactures a complete line of spring loaded and pilot operated relief valves, servicing refining and hydrocarbon processing facilities. Farris has earned its reputation as “the First Line of Safety” providing automatic and positive protection against overpressure situations in thousands of industrial facilities around the world.

FARRIS ENGINEERING’S FAST CENTER ADVANTAGE Another Farris legacy is our Farris Authorized Service Team, or “FAST” Center Network. Over the years, Farris Engineering has carefully developed our global network of independently owned and operated valve repair facilities. FAST Centers support aftermarket service and valve maintenance with factory trained technicians specializing in knowledge of the design, function and repair of PRVs. Our FAST Centers can diagnose and solve PRV problems, track and manage maintenance and repair history and reduce plant downtime with local service, inline testing and field service capabilities. FAST Centers provide you with the confidence that your valves will function properly during an overpressure situation. Our asset management solutions keep your plant safe and deliver peace of mind.

Local Inventory—Every FAST Center carries a large inventory of new PRVs and spare parts, backed by a web-based global inventory to draw upon.

24/7 Valve Service and Replacement—Enjoy quick, localized testing and repair of your valves, or the prompt installation of new ASME certified valves.

Factory Trained Technicians—FAST Center valve technicians go through certified training at the Farris factory and in the field.

OEM parts—FAST Centers use only OEM parts, restoring your valves to OEM specifications. All valves are assembled and tested to ASME standards.

ASME Certification—FAST Centers carry all the required certifications to assemble, set and test your valves.

VR Certification—FAST Centers have VR certification issued by The National Board of Boiler and Pressure Vessel Inspectors.

Mobile Repair Units—Available at select FAST Centers.

Global Access —FAST Centers work with our extensive representative network, providing support to all global regions Valve Expertise—Every FAST Center is technically supported

by Farris Engineering, a leader in valve design.

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Legend:

Manufacturing Facility

FAST Center

Representative

Farris’ Global FAST and Sales Representative Network

VALUE BEYOND THE VALVE With Farris, a trustworthy valve is only part of our promise. Farris provides customers with total pressure relief management solutions that support a facility’s entire lifecycle, transforming the way you ensure plant safety: Design—Using the power of iPRSM technology and our Farris Engineering Services team, correctly design your pressure relief system to respond to every overpressure scenario.

Build—Equip your plant with Farris’ full line of spring loaded and pilot operated PRV hardware, knowing your plant is protected by 70 years of manufacturing experience.

Monitor—Monitor your pressure relief valves with the SmartPRV™ and leverage the technology of proven leaders, Farris and Emerson.

Maintain—Localized aftermarket service and repair assistance through the Farris Authorized Service Team – or “FAST” Centers.

Audit—Our Farris Engineering Ser vices team and iPRSM technology will keep your pressure relief systems audited and in compliance.

CONTACT INFORMATION 10195 Brecksville Road, Brecksville, OH 44141 USA Telephone: 440-838-7690 Fax: 440-838-7699 Farris@curtisswright.com http://farris.cwfc.com

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FOURQUEST ENERGY

VAPOR PHASE CLEANING (DEGASSING) OVERVIEW Improved safety regulations, mandatory vessel inspections, and new environmental requirements are increasing the demand for system decontamination in the oil and gas industry. In the past, system decontamination involved a lengthy steaming process that was applied until the contaminant levels dropped under the required values. This process was both expensive and inefficient, consuming a significant amount of time and steam. Vapor phase cleaning is an enhanced steaming method used to speed up the decontamination process. It works by injecting a small amount of chemicals (usually less than 1%) into the steam Vapor just before it enters the system. The specialized chemicals accelerate the cleaning process, target specific contaminants, and reduce overall cleaning time by as much as 60% to 70%.

Vapor phase cleaning can be used with most types of process equipment, including: reactors, columns, vessels (in general), heat exchangers, compressors, storage tanks, filters, piping, etc., and is effective in decontaminating main contaminants, such as: hydrocarbons (LEL’s, Benzene), hydrogen sulfide (H2S), pyrophoric iron (FeS), ammonia (NH3), and mercaptans

VAPOR PHASE CLEANING PROCESS Vapor phase cleaning requires a saturated steam supply and specific cleaning agents to perform an efficient cleaning cycle. To establish a flow of chemicals throughout the vessel, it is essential to connect the top of the vessel (or unit being cleaned) to the flare line to ensure that aggressive contaminants are not released into the atmosphere before being incinerated. The best location to inject steam into a vessel is in its lower portion, and some vessels may require multiple injection points to improve or speed up the cleaning process. This is based on the number of trays or packings inside the vessel. Chemicals are injected into the steam upstream of the vessel entry point. They are then carried by the steam throughout the vessel. However, due to metal thermodynamic properties, steam tends to condense on metal surfaces inside the vessel with the chemicals. The chemicals carried further by the steam condensate react with deposits on the wetted metal surfaces inside the system. The reaction products then flow down to the bottom of the vessel toward a drain system. To improve cleaning performance, it is important to collect all condensed waste and drain it out of the vessel. This can be done using either a closed drain system or a vacuum unit equipped with a Vapor scrubber unit connected to the bottom of the system. To ensure effective cleaning throughout the system, part of the chemistry should be carried out through the top of the system in Vapor form and part should condense down the system walls. This crucial step of Vapor phase cleaning is controlled by making sure the temperature of the system is kept within the optimal range prior to and during chemical injection.

To ensure system cleanliness, emissions may be monitored by taking gas samples at system vents or monitoring liquid samples at drain points.

Vapor phase cleaning is typically completed in three phases: a) System preheating (heat the entire system to a temperature between 190°F and 210°F) b) Chemical injection (Vapor phase cleaning) c) Rinsing out the chemistry

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BENEFITS OF VAPOR PHASE CLEANING Vapor phase cleaning has several advantages over conventional chemical cleaning: • The time required to prepare process equipment for hot work or inspection is reduced significantly (over 60%), translating to lower maintenance costs and decreased system downtime.

• Vapor phase cleaning procedures and resources are both reliable and predictable, making it easier to schedule work with high accuracy and eliminating the risk of extended project schedules.

• Vapor phase cleaning requires less energy to maintain Vapor phase temperature than liquid phase temperature.

• Vapor phase cleaning increases the production efficiency of equipment, and therefore increases equipment lifespan.

• Vapor phase cleaning uses significantly lower amounts of chemicals, resulting in significantly less waste generated.

• The chemicals used in Vapor phase cleaning are biodegradable and therefore easy to handle, with no negative environmental footprint left behind.

CONTACT INFORMATION 4820 Railroad Street, Deer Park, Texas 77536 Office: +1 281-476-9249 info@fourquest.com www.fourquest.com

HYDROCARBON PROCESSING | GLOBAL TURNAROUND AND MAINTENANCE SUPPLEMENT 2013

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WE BUY AND SELL COMPLETE PROCESS PLANTS, PROCESS LINES AND PROCESS EQUIPMENT Featured Plants: Refinery Gasification (Syngas), LNG, Hydrogen, Methanol and Refineries 3,000 Metric Ton/Day Refinery Gasification (Syngas) Plant http://info.ippe.com/syngas‐gasification #600759 Converts Refinery Residues Into Clean Syngas And Can Be Converted To Use Coal As The Input Commercial Start‐Up: 2003 Still In Operation Designed to consume 59 Metric Ton/Hr (1,400 Metric Ton/Day) of heavy residues to produce 130 Metric Ton/Hr (3,000 Metric Ton/Day) of Clean Syngas, consisting primarily of CO and H2.

Technology: Texaco (GE Gasification), ABB, UOP, Parsons (Claus Units) and Praxair Over‐designed to accomodate crude oils other than the standard Arab Heavy, such as Basrah Medium high‐sulfur and Iranian Heavy feedstocks, Upgraded To High Alloy Piping Abundance Of Spare Parts Raw Materials: Natural Gas, Steam and Refinery Tar Sections: (Contact IPP For Equipment List And Process Descriptions) Gasification Unit (Texaco) Praxair Air Separation Unit (Produces 95% Pure O2) Carbon Extraction Unit Grey Water Treatment Unit Gas Cooling Unit Sour Water Stripper Unit Acid Gas Removal Unit Sulfur Recovery Unit (2 Parsons Claus Units) Complete Documentation Available (including Process Description)

Liquified Natural Gas (LNG) Peak Shaving Plant http://info.ippe.com/lng‐plant #600594

Liquefaction: 2,400 NM³/Hr NG, Resulting In 4 NM³/Hr LNG Storage: 22,700 M³ Liquid (6 Million Gallon) Can Be Vaporized Into 14 Million NM³ Of Gas; 600:1 Ratio € 20 Million Euro Spent On Upgrading Plant In Last 5 Years Shut Down: 2010 Natural Gas Transported Via Pipeline Is Liquified And Stored As LNG Liquify Natural Gas For Vehicle Transportation LNG Filling Station (for trucks): 34 NM³/Hr LNG Major Equipment: (Contact IPP For A Complete Equipment List) 6 Million Gallon, 37 M dia. x 32 M X8Ni9 (9% Nickel Alloy) Double‐Wall Cryogenic LNG Storage Tank (2) 80 CBM/Hr Submersible/retractable 2‐stage Centrifugal In‐Tank Pumps 8‐Stage Ingersoll Rand Reciprocating Compressor with 2,800 kW Motor (2) 81.5 CBM/Hr Bingham Centrifugal High Pressure Pumps (3) 2.5/2.9 M dia. x 12.7/13.7 M (10,000 Gallon) Double‐Wall Liquid Nitrogen Tanks (3) 5,000 CBM/Hr Liquid Nitrogen Pumps (2) 50,000 CBM/Hr (Gas Flow) LNG Vaporizers with Natural Gas Burners 875 CBM/Hr Burckhardt Boil‐Off Reciprocating Gas Compressor, 250 kW New Electronic Instruments and Siemens PCS‐7 Control System Site Has Good Rail And Truck Access And A Dock On A Major Waterway ½ Mile Away LNG Plant Uses Include: Associated Gas Liquefaction, Fuel Use And Delivery To Industrial Sites With No Natural Gas Pipeline. Contact IPP to discuss other uses for this plant.

Complete Documentation Available (including Complete Process Description)

400 Metric Ton/Day Methanol Plant

(5) Hydrogen Generation Plants

http://info.ippe.com/methanol‐plant #600304

http://info.ippe.com/hydrogen‐plants

Start Up: 1997; Shut Down: 2007 The process is a middle pressure process at 45 bar. The synthesis gas came out from the synthesis gas generation with 24 bar and have been compressed to 45 bar. The compressor is included.

Designed for the production of synthetic gases from heat value‐rich waste, bio‐waste and different types of coal.

Sections: Waste preparation by pelletizing of waste, Synthetic gas production by pressurized bed gasification, Methanol production and the Power plant.

Chemical quality to be used in: Acetic Acid, Solvents, Vitamin Products, Formaldehyde, Anti‐Knocking Agents, Antifreeze and Chemical Synthesis.

Complete Documentation Available

1,580 NM³/Hr to 25,000 NM³/Hr (2) Hydrogenation Reactor Systems Available

(11) Crude Oil Refineries http://info.ippe.com/refineries 15,000 Barrel/Day to 275,000 Barrel/Day Complete Refineries And Individual Units. Contact IPP For A List Of Available Units.

CONSULTANT NEEDED Have a knowledge base in the Hydrocarbon markets and looking to expand your horizon in 2013? IPP wants to speak with you. +1‐609‐454‐2932

In Addi on To Complete Plants, IPP Stocks Over 30,000 Pieces Of Process Equipment. Visit www.ippe.com.

Michael Joachim Director, Plants Dept.

Office +1 609 454 2932 Direct +1 609 838 5930 Mobile +1 609 516 9107 MichaelJ@ippe.com

We Are Cash Buyers For Closed Manufacturing Facilities, Land And Equipment Globally. +1 609 454 2932 http://info.ippe.com/syngas‐gasification Select 94 at www.HydrocarbonProcessing.com/RS

INTERNATIONAL PROCESS PLANTS (IPP)

WE BUY AND SELL COMPLETE PROCESS PLANTS, PROCESS LINES AND EQUIPMENT International Process Plants (IPP) is a self-funded global buyer and seller of surplus manufacturing facilities, process plants, industrial real estate, and individual equipment. IPP’s business model serves clients in two ways: 1. IPP provides companies the opportunity to acquire existing assets at competitive prices and in a fraction of the lead time of building or buying new 2. for companies looking to divest assets that have become surplus to their needs, IPP serves as an outlet to convert those assets into funds quickly in a fiscally and environmentally conscious manner.

IPP, started over 35 years ago by 2 brothers who still lead the company, has grown to company-owned operations in 17 countries serving a client base of 160,000 companies in the worldwide oil & gas, power generation, petrochemical, chemical, pharmaceutical and food processing industries. One of the largest companies in this business, IPP’s inventory includes over 100 complete plants, more than 30,000 individual pieces of process equipment and multiple industrial real estate development sites.

BUYING EXISTING PLANTS: A STRATEGIC WEAPON Many of IPP’s clients compete in mature industries where today’s challenging economic climate demands creative solutions for business success. Given that IPP’s plants cost a fraction of the capital needed to build new ones (savings typically reach 40–50%), buying an existing plant is the only economically viable option to satisfy plant needs for many of IPP’s clients. IPP’s clients also save valuable uptime as most plants can be relocated and ready for operation within 18 months or less compared to new plant construction that can take 3–4 years.

IPP’s stock of complete plants includes several properties of interest to the hydrocarbon processing industry: • IPP’s Gasification Plant: 3, 000 metric tons / day • LNG Peak Shaving Plant: • 11 Refinery Facilities: 15,000–275,000 barrels / day • 5 Hydrogen Plants: 1,580–25,000 NM³ / hr (99.9%+ pure) • Methanol Plant: 400 metric tons / day Gasification allows oil refineries to convert residue waste into valuable commodities. A study by the National Energy Technology Laboratory (NETL) estimated that typical US refineries using gasification to produce these commodities could save up to $55,000 / day. The syngas produced by gasification could also be sold. Refineries buying an existing gasification plant can save up to 50% of the capital required to build new (US $500–$800MM). Coupled with operating cost savings and potential revenue from syngas sales, refineries can fund a significant number of incremental projects.

IPP’s LNG plant can be used to store surplus natural gas for demand spikes, to liquefy associated gas in oil fields while reducing emissions and increasing pumping capacity, in industrial sites with no natural gas pipeline to delivery LNG and for vehicle fueling stations.

WHY BUY ASSETS FROM IPP? Buying existing plants or equipment assets from IPP maximizes the impact your fixed capital budget can have by saving you 30–50% vs. buying new plus you’ll get to market or back online faster. Plant clients tell SPONSORED CONTENT

Complete Process Plants, Process Lines, Industrial Real Estate and Major Pieces of Process Equipment us they are up and running in ½ the time it would have taken for a new plant. Equipment clients love reducing downtime when equipment fails because IPP delivers within days.

SELLING ASSETS TO IPP Unlike some companies in this business, IPP utilizes its own assets to purchase the entire plant site outright. With no 3rd parties involved, selling to IPP maximizes your plant’s value and generates your cash infusion faster, funds you can immediately use. IPP also purchases idle and surplus processing lines or individual equipment pieces, turning those non-productive assets into instant funds as well.

Selling your plant to IPP avoids the carrying costs of an idled plant.

IPP’s clients have saved as much as $700,000 a year in utilities, insurance, taxes, etc. From a human capital perspective, IPP’s clients don’t have to supervise plant or equipment shut downs, provide security or sell assets piecemeal. IPP can help manage any needed dismantling or environmental remediation, eliminating further costs.

IPP is highly experienced in extracting multiple revenue streams from our plant acquisitions, often achieving 100% recycling of the plant’s contents, a process that benefits the seller too. For example, one plant site included timber that IPP sold to a client in the paper business, value that was reflected in the plant’s purchase price.

CONTACT INFORMATION Address: 17A Marlen Drive, Hamilton, NJ 08691 Phone: +1-609-586-8004 Fax: +1-609-586-0002 sales@ippe.com http://www.ippe.com

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real time responsiveness

In an industry driven by tight turnarounds and critical paths, there’s no time to waste. Waiting for the call back.

Waiting for quotes, parts, and startup...

Built on a foundation of deep industry experience and having engineered the most challenging combustion equipment in use today, the ZEECO® Rapid Response Team changes everything. Whether our burners, flares, and incinerators or the competitions’ equipment, we help you stop waiting and start running.

Zeeco, Inc. 22151 E 91st St., Broken Arrow, OK 74014 USA ©Zeeco, Inc. 201

+1-918-258-8551 sales@zeeco.com zeeco.com

Select 87 at www.HydrocarbonProcessing.com/RS

ZEECO

ZEECO RAPID RESPONSE TEAM DELIVERS ON DEMAND Aftermarket shouldn’t equal afterthought. At Zeeco, we took a long look at the typical challenges our customers faced in getting the right parts within the demanding timeframes that define the petrochemical and related industries. After years of aiding customers who have faced a sudden need for replacement parts or equipment, the Zeeco Aftermarket Parts and Service team decided to change nearly every aspect of tight turnaround projects for customers. Our answer is the Rapid Response Team, or RRT. Designed to shrink production times through the development of a separate aftermarket workflow, the RRT eliminates the common problem of bottlenecking, or interrupting the existing project schedule.

Featuring a separate production facility with machining, welding, plasma cutting, pipe bending, cutting and threading all in-house are what separates Zeeco’s RRT production capabilities from the approach of typical aftermarket parts suppliers. With the addition of a separate quality control/inspection team, purchasing and supply chain management, and in-house packaging and shipping, our RRT has international manufacturing capabilities for an urgent project response on a worldwide level.

Why the Zeeco RRT? Zeeco’s combustion engineers understand the challenges of meeting emissions regulations and project deadlines in the Gulf Coast. Refineries and chemical plants experiencing an unplanned outage due to equipment failure or damage count the cost per hour until the plant is up and running again, and the pressure to deliver a replacement part as soon as possible can be intense. Zeeco’s RRT is built from the ground up to handle the pressure from the quote/engineering process through to shipment or installation of the new part. When a Gulf Coast refinery recently experienced a plant upset in production on a Friday, initiating what is known as a ‘Friday fire drill’ as the maintenance and operations team at the plant tried to source must-have parts, they called Zeeco. The RRT went into action and had pilots, auxiliary lances, wind boxes, gas tip and riser assemblies, plenums, and burner tiles all produced and ready to ship in four days. The RRT regularly replaces gas tips or other parts on an expedited basis, whether ZEECO® brand or a competitor’s, keeping customer outage times to a minimum.

A follow up visit from the Zeeco Houston office experts ensured the problem was fixed for good and was the final step in quickly responding and solving a maintenance crisis. Our Zeeco Houston Service Center provides local service to the Gulf Coast region 24/7 including boiler/ heater tuning, start-up assistance, installation, burner cleaning, controls upgrading, and more. With approximately 17,000 square feet of manufacturing space and the largest Gulf Coast permanent presence of sales and service personnel of any combustion company in the world, Zeeco achieves better support and response times for our customers than anyone in the region.

Beyond just a quick response when something goes wrong, Zeeco works with customers to do proactive and preventative maintenance.

Zeeco’s industry-leading combustion experts have deep experience and knowledge from working on-site in the world’s largest facilities. Our team conducts preventative and cost-saving pre-turnaround maintenance inspections. We perform a complete inventory analysis and component checklist to help customers order the necessary parts and components needed for the next plant turnaround. The customer will not only save on expediting SPONSORED CONTENT

The Zeeco service team in action.

Zeeco’s Rapid Response Team has separate manufacturing/fabrication facilities and workflow, including plasma cutting tables, welding, and purchasing to meet quick turnarounds and tight deadlines. fees but also save by eliminating potential errors caused by inexperienced technicians and avoid unnecessary plant downtime. By choosing an experienced Zeeco combustion expert, long-term maintenance costs are greatly reduced and the lifespan of the current equipment is prolonged.

CONTACT INFORMATION 22151 East 91st Street Broken Arrow, Oklahoma USA 74014 Ph: +1 918–258–8551, Fax: +1 918–251–5519 sales@zeeco.com www.zeeco.com

HYDROCARBON PROCESSING | GLOBAL TURNAROUND AND MAINTENANCE SUPPLEMENT 2013

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HydrocarbonProcessing.com/GTLTechnologyForum

JULY 30–31, 2013 Norris Conference Centers – CityCentre Houston, Texas

Hydrocarbon Processing Introduces the Inaugural Gas-to-Liquids Technology Forum Hydrocarbon Processing and Gulf Publishing Company are pleased to announce that the inaugural Gas-to-Liquids (GTL) Technology Forum will be held July 30–31, 2013, in Houston, Texas. The conference will investigate the technology and trends at work as GTL usage and projects become increasingly popular. The two-day technology forum will feature industry keynotes and presentations from GTL technology experts.

GTL is poised to become an increasingly important part of the North American energy industry. As the natural gas boom in North America continues and new technologies emerge to reduce costs, company interest is increasing—and so is investment. Project announcements and planning from industry innovators like Sasol, Shell and BP are beginning to ramp up in this energy niche.

How You Can Participate…

Submit an Abstract This is your chance to share your ideas and hear from top innovators and technology leaders from across the global hydrocarbon processing industry. Submission deadline: May 13. For a full list of suggested topics, please visit HydrocarbonProcessing. com/GTLTechnologyForum.

Sponsor or Exhibit Participation as a sponsor or exhibitor at GTL Technology Forum 2013 will benefit the following types of companies active in the GTL sector: GTL technology providers, GTL engineering companies, major and independent operators, catalyst companies, specialized equipment manufacturers, turbine specialists and others.

For more information, contact your local Hydrocarbon Processing sales representative or Bret Ronk, publisher, at +1 (713) 520-4421 or Bret.Ronk@GulfPub.com.

Safety/Loss Prevention M. SAWYER, Apex Safety Consultants, Houston, Texas

Conceptually, accidents are a fallacy Webster’s unabridged dictionary defines accident as “Literally, a befalling; an event that takes place without one’s foresight or expectation; an undesigned, sudden and unexpected event; chance; contingency; often, an undesigned and unforeseen occurrence of an afflictive or unfortunate character; a casualty; a mishap; as, to die by an accident.”

When viewed in conjunction with the workplace, no one dies or is injured by accident. Each worker fatality and injury is preventable. Yet, sadly, thousands of workplace fatalities, injuries, fires and other losses occur each year. Aside from the compassion for all worker’s well-being and the legal obligation of employers to provide a workplace free of recognized hazards, there are economic factors pertaining to losses. Significant and irrecoverable economic losses within the US are the result of workplace incidents each year. Large-scale incidents within industry segments, such as the oil and gas industries, can represent severe economic concern, as well as a national security issue. For example, refining capacity reductions due to incidents have caused regional shortages and inflated gasoline prices.

Redefining “accident.” The use of the word accident to de-

scribe a workplace loss is a misnomer. Although Webster’s definition is widely accepted and used extensively, it is nevertheless erroneous when used in relation to workplace losses. Quite simply, there are no accidents and no undesigned, unexpected events in the workplace. And, frankly, most losses could be prevented without incurring significant costs.

One of the primary axioms of risk is that there will always be some unknown, unforeseen residual risk associated with tasks and activities. Risk, however, should not be confused with the causal factors of an incident. Risk, as a product of probability and severity, is a quantitative term used to describe the various outcomes of an incident, along with its probability.

Known, repetitive causal factors of numerous incidents are chronicled among published textbooks, professional articles, litigation cases and engineering studies. Replication herein would be of little value, other than for sheer dramatic effect.

One caveat is that weather-related events—like floods, earthquakes, lightning and hurricanes—are not included. Even weather events are predictable to some extent, earthquakes being the likely exception. Prevention measures can mitigate some weather events. For example, flood gates, lightning protection and hurricane-resistant structures can be implemented to limit damage from weather-related events.

The word accident is a fallacy. Each purported accident comprises a well-choreographed series of events, often practiced multiple times. Each series of events has an array of possible outcomes. The ultimate or final unwanted outcome culminates into an incident. The formula for an incident requires that events (causal factors) align within a predetermined order, in proximity, and occur within a particular timed sequence.

Simply, an incident can occur when linked events align within a given proximity or boundary and time sequence. It may be explained as a matrix of events that are randomly generated within a continuum, whereby a select grouping within the sequence will result in an incident; i.e., loss. All factors or events must align to create the outcome of an incident. Introduction of any new event or absence of an event will break the chain, and the events will have to reform within another predetermined time for an incident to occur.

Predictable events. Once an incident occurs, the proximate causes can be identified through analysis and incident reconstruction. This ability to identify causes confirms that causal factors or conditions are not unforeseen occurrences and can be identified before the incident occurs. Thus, these events can be predicted and, therefore, should not be termed as accidents.

Much like the elements of a fire triangle, take away one of the causal factors and the outcome will change. But how does one know what to take away to prevent an incident?

The answer is straightforward; understand the hazard associated with the task and either eliminate the hazard or reduce t

A

o

B

C1

D

Job task completed safely

C2

D

Incident

C3

Where: A = hot work required on existing hydrocarbon system B = system not properly cleared of hydrocarbons or inerted/purged C1 = system properly cleared, isolated, and vented C2 = not isolated C3 = isolated with out proper venting D = hot work begins t = timing of sequence of events such that hydrocarbon vapors are present during hot work

FIG. 1. Interaction of events that can lead to a job well done or an unfortunate incident.

Hydrocarbon Processing | APRIL 2013 99

Safety/Loss Prevention it to a form that cannot evolve into an incident. Sounds too simplistic, right? This is not an attempt to trivialize incidents; however, most incidents that occur could have easily been avoided if those involved had simply understood the hazards and proper mitigation techniques.

this hypothetical. It should be understood that this hypothetical and FIG. 1 do not attempt to define various incident outcomes or severities, like fatality vs. injury and fire vs. explosion.

The key is to first understand the hazards and then apply corrective actions to “block” the events needed for the formation of an incident.

In the US, the Occupational Safety and Health The word accident is a fallacy. Each Administration and the National Fire Protection Association understand this concept, which is evipurported accident comprises a welldenced by their standards and recognized safe work choreographed series of events, often practices.1,2 Both explicitly state that hot work is propracticed multiple times. Each series hibited in the presence of explosive atmospheres.

Yet, numerous accounts of hot work being authoof events has an array of possible outcomes. rized without clearing tanks, equipment, or pipelines The ultimate or final unwanted outcome of flammables have resulted in incidents.

The capability to sustain a loss in conjunction culminates into an incident. with a capacity to cause a loss is typically present in most industrial settings. Therefore, understanding the setting and how hazards form under certain settings is This can be illustrated through an interaction of events, paramount in comprehending the anatomy of an incident. Unshown in FIG. 1. Without B in the sequence of events, the inciless blockers are developed and strategically implemented the dent does not occur; therefore ‘B’ is the incident blocker. Even events leading to an incident may form. if the system is not isolated, or is isolated without proper venting without B, the incident does not occur.

Using the FIG. 1 example, understanding the simple principle Hazard mitigation. Process safety engineers understand how that hydrocarbon systems must be thoroughly cleaned before hot to analyze hazards and develop mitigation techniques; howevwork helps to avoid an incident. Taking away event/condition B er, it’s the field service workers, contractors and maintenance by clearing hydrocarbons prior to hot work avoids an incident in technicians that are actually conducting the tasks. Until the actual worker is properly instructed and rewarded for analyzing hazards in the workplace prior to beginning an assignment, incidents will continue.

Focusing on process safety and prevention programs can be highly effective in reducing incidents. If companies will train and empower their workforces to not undertake assignments until they thoroughly understand the hazards and have verified that all identifiable hazards have been eliminated, incidents can be essentially reduced to zero.

The preparation of procedures stipulating that all workers must understand and eliminate hazards prior to attempting a task can easily be accomplished in short order. Implementation of such practices into the workplace and ensuring that everyone understands and maintains the practice remain the challenges for proactive companies.

In essence, failure to adhere to reasonable hazard mitigation measures will, in all likelihood, result in unsafe working conditions and subsequent losses. This does not imply that the conditions surrounding the loss were, as characterized by Mr. Webster, events occurring without one’s foresight or expectation. Failure to conduct reasonable mitigation of a known hazard is simply negligence.

Process losses are not comprised of unidentifiable events and they should not be characterized as accidents. Each is preventable.

LITERATURE CITED US Department of Labor Occupational Safety and Health Administration, General Industry Regulations 29 CFR 1910.252.

2 National Fire Protection Association 51B; Standard for Fire Prevention During Welding, Cutting and Other Hot Work; 2009.

1

MIKE SAWYER is a consulting engineer at Apex Safety Consultants in Houston, Texas. He has over 30 years of industry experience.

100

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ADVERTISERS INDEX / HydrocarbonProcessing.com The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company name, is the Reader Service Number. There are two ways readers can obtain product and service information: 1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

Company

Page

RS#

Website

Company

Page

RS#

Website

Company

Page

RS#

Website

AE Solutions .......................................................40–41 (160/65)

Foster Wheeler .........................................................22

(62)

Metso Automation.................................................... 29

(98)

AFPM.......................................................................101 AMACS ......................................................................17

(153)

FourQuest Energy.................................................. T-92

(78)

OMI Industries.......................................................... 42

(91)

Avondale ..................................................................71

(77)

Paratherm Corporation ..............................................10

(151)

Axens .....................................................................108

(51)

Pittsburgh Corning Corporation................................. 63

(163)

BASF Corporation ......................................................21

Quest Integrity Group LLC.......................................... 45

(161)

www.info.hotims.com/45678-160 www.info.hotims.com/45678-153

www.info.hotims.com/45678-62 www.info.hotims.com/45678-78

(70)

Gulf Publishing Company Events—GTL ...................................................... T-98 HP Webcast.......................................................... 68 HPI Market Data 2013 ......................................... T-84 Marketplace ................................................. 102–104 Hermetic Pumpen GmbH .......................................... 38

(159)

BASF SE .................................................................. 107

(100)

Heurtey Petrochem ...................................................22

(64)

Bekaert Advanced Filtration SA ................................. 20

(155)

HTRI ........................................................................ 28

(156)

BETE Fog Nozzle ....................................................... 60

(58)

Hytorc ..................................................................... 49

(54)

Borsig GmbH ............................................................19

(154)

Idrojet ..................................................................... 79

(166)

Burckhardt Compression AG ...................................... 69

(79)

Intergraph ................................................................12

(152)

Carboline Company .................................................. 64

(164)

International Process Plants (IPP) .......................... T-94

(94)

Carver Pump Company ............................................. 80

(167)

Intratec Solutions LLC ............................................... 67

(165)

CB&I .........................................................................13

(53)

KBR.......................................................................... 11

(96)

Curtiss-Wright ...................................................... T-88

(169)

Kobe Steel Ltd.......................................................... 50

(82)

Elliott Group .............................................................16

(52)

Koch-Glitsch ............................................................ 62

FabEnCo, Inc. ........................................................ T-89

(170)

Linde Engineering NA ................................................18

Farris Engineering ................................................. T-90

(56)

Flexitallic LP .............................................................. 5

(93)

www.info.hotims.com/45678-77 www.info.hotims.com/45678-51

www.info.hotims.com/45678-70

www.info.hotims.com/45678-100 www.info.hotims.com/45678-155 www.info.hotims.com/45678-58

www.info.hotims.com/45678-154 www.info.hotims.com/45678-79

www.info.hotims.com/45678-164 www.info.hotims.com/45678-167 www.info.hotims.com/45678-53

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www.info.hotims.com/45678-159 www.info.hotims.com/45678-64

www.info.hotims.com/45678-156 www.info.hotims.com/45678-54

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www.info.hotims.com/45678-151

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Smith & Burgess LLC ..................................................76

(72)

Spraying Systems Co .................................................14

(66)

www.info.hotims.com/45678-72

www.info.hotims.com/45678-66

Sulzer Chemtech, USA Inc...........................................31

(88)

Summit Industrial Products, Inc. ............................... 30

(157)

Team Industrial Services ............................................35

(95)

ThyssenKrupp Uhde GmbH ......................................... 8

(81)

Total Safety ............................................................. 36

(99)

www.info.hotims.com/45678-88

www.info.hotims.com/45678-157 www.info.hotims.com/45678-95 www.info.hotims.com/45678-81

www.info.hotims.com/45678-99

Toyo Engineering Corporation ..................................... 2

(86)

Trachte USA ............................................................100

(168)

(162)

UOP LLC ................................................................... 26 Velan ...................................................................... 34

(158)

(73)

Wood Group Mustang ............................................... 46

(89)

Linde Process Plants ................................................. 82

(85)

Zeeco ................................................................... T-96

(87)

Merichem Company.................................................. 24

(84)

ZymeFlow ................................................................72

(92)

www.info.hotims.com/45678-96 www.info.hotims.com/45678-82

www.info.hotims.com/45678-162 www.info.hotims.com/45678-73

www.info.hotims.com/45678-85

www.info.hotims.com/45678-84

www.info.hotims.com/45678-86

www.info.hotims.com/45678-168 www.info.hotims.com/45678-158 www.info.hotims.com/45678-89 www.info.hotims.com/45678-87

www.info.hotims.com/45678-92

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.

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Bret Ronk, Publisher Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 E-mail: Bret.Ronk@GulfPub.com www.HydrocarbonProcessing.com

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AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Diana Smith Phone/Fax: +1 (713) 520-4449 Mobile: +1 (713) 670-6138 E-mail: Diana.Smith@GulfPub.com

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Hydrocarbon Processing | APRIL 2013 105

Water Management

LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Update: Online measurement of oxidizing biocides Nearly all owners of industrial cooling towers feed oxidizing biocides—chlorine (Cl) and bromine (Br)—to kill bacteria in the recirculating cooling water. Minimizing the populations of bacteria is critical to avoid microbiological fouling and a subsequent loss of heat transfer and to eliminate pathogenic strains of bacteria being present in water droplets entrained in the cooling tower plume.

TABLE 1. Online biocide meter providers Colorimeters

Amperometric meters

Hach, Cl-17

Hach, 9184sc

Swan, Analyzer AMI Codes-II, II TC, II CC

Swan, Analyzer AMI Codes-II, II TC, II CC

Yokogowa, RC400G

Yokogowa, Fc400G, FC500G

Control is vital. Precise feed control for biocide systems

Prominent, Dulcometer D1C, D2C

is critical: too little biocide allows bacteria populations to thrive; conversely, too much biocide makes the system susceptible to corrosion. Oxidizing biocides may be fed continuously or intermittently (slug feed), depending on site-specific conditions such as the system size, constraints on discharge of spent blowdown, and compatibility with cooling water treatment chemicals.

Feedback is the optimal control strategy. Why? Because the consumption (the demand or feedrate) of oxidizing biocides strongly depends on the changes in ambient temperature and sunlight throughout a 24-hour period. This highly dynamic system requires an online sensor to measure the free halogen (chlorine and bromine) concentration and automatically adjust the biocide feedrate. Plant personnel typically install an online sensor in the cooling water line from the plant that returns to the cooling tower (the return).

Rosemont, FCLi

Key monitoring methods. There are two technologies for online meters: colorimetric and amperometric. Colorimetric technology has been the standard methodology for accurate and reliable online measurement. Recent developments in amperometric technology have improved the accuracy and maintainability of these sensors.

Colorimetric meters. This meter uses the same reagentbased, spectrophotometric method used in the laboratory. The analyzer adds chemical reagents to the sample to adjust the pH and react with the hypochlorite (OCl–) and hypochlorous acid (HOCl) forming a color. The analyzer’s spectrophotometer measures the transmittance of light through the colored sample that is proportional to the concentration of free Cl. Colorimetric meters require replacement of reagents on a monthly basis and replacement of the transfer tubing for the reagent delivery system on a semi-annual basis. TABLE 1 lists several suppliers of industrial analyzers with automatic pH compensation.

Amperometric meters. Process engineers commonly refer to amperometric meters as oxidation reduction potential (ORP) meters. The amperometric method is an electrochemical method. The sensor measures the very small currents produced by the HOCl that are directly proportional to the con106 APRIL 2013 | HydrocarbonProcessing.com

Disclaimer: Information about specific products is a service and does not signify any business relationship with the suppliers or an endorsement by the author.

centration of free Cl in the sample. The sensor’s accuracy is highly dependent on pH because the sensor detects only HOCl. Even small changes in the pH that do not change the concentration of free chlorine will affect the sensor’s current output, causing an inaccurate measurement result.

Conventional ORP sensors required extensive tuning for each installation to correlate the analyzer’s reading to the concentration of free Cl because there is no compensation for the pH dependence of the free Cl measurement. The latest sensor design has an acidic solution inside the sensor that converts all the OCl– ions to HOCl, eliminating the pH dependence of the measurement. The sensor requires a replacement of the selective membrane and acidic solution every three to six months, depending on the duty. Most suppliers have designed convenient replacement cartridges that eliminate exposure to the acidic solution and simplifies routine maintenance. TABLE 1 lists several amperometric meters for cooling water applications.

How to choose. The primary advantage of colorimetric meters

is the direct measurement of the halogen concentration. Like all reagent-based analyzers, these units require replenishing of reagents and periodic refurbishment of the reagent pumps. Amperometric meters are very versatile, and they solve the problem of pH dependence of the ORP measurements. These meters, likewise, require periodic replenishment of reagents but do not have any reagent pumps.

LORAINE A. HUCHLER is president of MarTech Systems, Inc., a consulting firm that provides technical advisory services to manage risk and optimize energyand water-related systems including steam, cooling and wastewater in refineries and petrochemical plants.

She holds a BS degree in chemical engineering, along with professional engineering licenses in New Jersey and Maryland, and is a certified management consultant.

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