HP_2011_04

APRIL 2011

HPIMPACT

SPECIALREPORT

TECHNOLOGY

A new era for natural gas

PETROCHEMICAL DEVELOPMENTS

Keys to improved alarm management

Research predicts workplace failures

New technologies sustain safety and profitability

Investigation on condenser failure

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Fired Package Boilers / Wasteheat Boilers / HRSG Maintenance & Service Strategies / Boiler Repair Services / SCR and CO Systems

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BOILERS FOR PEOPLE WHO KNOW AND CARE

APRIL 2011 • VOL. 90 NO. 4 www.HydrocarbonProcessing.com

SPECIAL REPORT: PETROCHEMICAL DEVELOPMENTS Optimize cracked-gas compressors with smart-automation technology

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Machine health monitors can provide critical information to avoid unit and plant-wide shutdowns P. Cox

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Improve evaluations for your industrial gas needs

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Better control-loop management lowers energy costs

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Accurate feedstock selection and planning are critical to profitability

Petrochemical and refining complexes are major consumers of industrial gases; here are some tips in planning process-gas needs G. H. Shahani and R. Koehler This petrochemical producer found improved output and became more energy efficient through new software G. Montes, L. Lang and J. R. Mahlstadt

Linear programming plays a vital role for ethylene producer K. Funahashi, H. Kobayashi, K. Saiki, M. Suzuki and D. J. Adams

RELIABILITY AND MAINTENANCE Investigation: Failure of a surface condenser titanium tube

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Advanced analytic methods determine contributing factors in heat exchanger corrosion problem A. Al-Meshari, M. Diab and S. Al-Enazi

ENVIRONMENT Consider becoming more familiar with the wet gas scrubbing process

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New ways to calculate adiabatic saturation temperature R. G. Kunz

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Cover Qatofin is a joint venture between Qatar Petrochemical Co. (63.63%), Total Petrochemicals France (36.36%) and Qatar Petroleum (0.01%) established in June 2002 to implement the Qatofin project.

This project includes participation in one of the world’s largest ethane crackers in Ras Laffan, a linearlow-density polyethylene (LLDPE) plant in Mesaieed and the related ethylene pipeline linking both sites.

See page 24 for the complete project profile. Photo Courtesy of TOTAL Petrochemicals France.

HPIMPACT 15

Valero confirms purchase of Chevron’s Pembroke refinery and other assets

15

Natural gas enters a new era of abundance

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Research anticipates failures in workplace

Low-pressure absorption of CO2 from flue gas Case study accomplished 95% sequestration using methyldiethanolamine aqueous solution M. Tellini and P. Centola

CLEAN FUELS Meeting diesel specifications at sustained production

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New approach rethinks crude and vacuum distillation units operation to recover more distillate D. Singh

SAFETY Keys to successful alarm management

85

Innovation will play a key role in catalyst technologies

PROJECT MANAGEMENT How to properly apply a plant asset management strategy

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Facilities employing leak-detection and custody-transfer systems receive many benefits with this program J. Norinder

PLANT DESIGN AND ENGINEERING How you can precommission process plants systematically

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HPIN RELIABILITY Tutors can provide answers

13

HPINTEGRATION STRATEGIES HPI needs to develop standards for asset information management

Here are the features you want in alarm management software J. Gooch

CATALYST 2011—SUPPLEMENT Catalyst 2011

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COLUMNS

Follow these guidelines for the best logical sequence for startup preparations V. Ramnath

DEPARTMENTS 9 HPIN BRIEF • 19 HPINNOVATIONS • 23 HPIN CONSTRUCTION 28 HPI CONSTRUCTION BOXSCORE UPDATE 126 HPI MARKETPLACE • 129 ADVERTISER INDEX

130 HPIN EUROPE Nervous Petroleum Week crowd thinks the geopolitically unthinkable

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Hydrocarbon Processing will host the 2nd International Refining & Petrochemicals Conference–Asia, 19–21 July 2011 in Singapore. This conference, organized by Gulf Publishing Company Events, offers you an effective means to market to engineering and operations management in the hydrocarbon processing industry. Like Hydrocarbon Processing, the International Refining & Petrochemicals Conference will focus on providing the industry leading-edge technology-based presentations and information. You are invited to be a part of this technical forum by submitting an abstract to be considered for the proceedings.

Topics to be covered include (but are not limited to): • Market trends in petrochemical and refining in the Asia-Pacific regions • Transportation fuels for Asia-Pacific region • Refining/petrochemical integration • Automobile market development in Asia-Pacific region and impact on fuels demand • Biofuels/alternative fuels • Gasification

• • • • • •

Catalyst technology: Refining/petrochemical Information and asset management Environment Safety Refining processes/products developments Petrochemical processes/products developments

Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (who will present the paper). Please submit via email to Events@GulfPub.com.

The International Refining & Petrochemicals Conference Advisory Board carefully identifies the topics to be addressed at the conference and are confident that this forum will benefit all of those actively engaged and employed in the global refining and petrochemical industries.

John Baric

Antonio Di Pasquale

Licensing Technology Manager, Shell Global Solutions International B.V.

Vice President, Refining Product Line, Technip

Eric Benazzi

Giacomo Fossataro

Marketing Director, Axens

Technical and Operation Manager, Walter Tosto S.p.A.

Carlos Cabrera

Giacomo Rispoli

President & CEO, NICE

Senior Vice President, Research & Development, eni–Refining & Marketing Division

Dr. Charles Cameron

Stephany Romanow

Head of Research & Technology, BP plc

Editor, Hydrocarbon Processing

Dr. Madhukar O. Garg

Michael Stockle

Director, Indian Institute of Petroleum in Dehradun

Chief Engineer - Refining Technology, Foster Wheeler

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To sponsor or exhibit, please contact your local Hydrocarbon Processing representative or Bill Wageneck, Publisher of Hydrocarbon Processing at +1.713.520.4421/ Bill.Wageneck@GulfPub.com or Hadley McClellan at +1.713.520.4475/ Hadley.McClellan@GulfPub.com.

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HPIN BRIEF BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Eni recently presented its 2011–2014 strategic plan to the financial community in London. In the new plan, Eni confirms the consolidation of its leadership in the Italian and European gas markets and a cost-reduction program aimed at recovering profitability in refining and marketing. The gas market scenario over the plan period will be characterized by a growth in European consumption, as well as by a rapid rise in demand from emerging markets; both factors will contribute to absorb the oversupply in Europe.

Eni’s strategy in refining and marketing is aimed at increasing operational efficiency, thereby reducing fixed and variable costs by €200 million by 2014. In refining, Eni will increase the flexibility of the plants and the yield in middle distillates, exploiting its proprietary technologies. In marketing, Eni plans to improve results by rebranding its distribution network, growing in key European markets and the expansion of non-oil activities.

In the US Congress, several bills have been introduced that seek to strip ethanol tax credits from the federal budget. These various pieces of legislation, introduced by several influential US lawmakers, aim to either allow the tax credits for ethanol to expire or to immediately repeal them outright. Pressure is also coming from broad coalitions (including one campaign that has drawn more than 100 varied industry groups together) to repeal the volumetric ethanol excise tax credit, and resist ethanol industry calls for spending on infrastructure. A recent Government Accountability Office report identifying duplicative federal programs that lawmakers say is providing a roadmap for cutting spending, noted that the ethanol tax credit is unnecessary because of the Renewable Fuels Standard implemented by the Environmental Protection Agency. According to the report, eliminating these programs “could reduce federal revenue losses by up to $5.7 billion annually.”

Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a contract by Cynar Plc to provide basic process engineering design services for a 6,000-tpy plant to convert non-recyclable waste plastics into liquid fuels, primarily diesel. The plant will use Cynar’s pyrolysis technology, supplemented with Foster Wheeler’s refining knowledge to produce liquid fuels. The basic design package is expected to be completed during the first quarter of 2011. The demonstration plant is located in Portlaoise, Ireland. Foster Wheeler has been working with Cynar over the past year to improve the quality of the fuel produced there.

Last month, an undertaking began to allow more than 3,000 European polypropylene (PP) processors the opportunity to provide extensive feedback to their resin suppliers regarding product and service offerings. The effort is being spearheaded by global market research firm Townsend Solutions. The 2011 Europe Polypropylene Customer Satisfaction and Loyalty Survey (CLASS) is sponsored by major polymer suppliers including Borealis, INEOS, LyondellBasell and SABIC. The CLASS programs offer an independent, third-party perspective and insight into the needs and expectations of the plastic processing community. CLASS will explore plastic processors’ changing priorities and their satisfaction with the performance of resin suppliers on more than 15 key issues ranging from product performance to sustainability.

Last year, BASF reduced specific greenhouse gas emissions by 29% when compared with 2002 emissions. This means that the company reached its emissions goal pathway for 2020 for the first time. A report issued in March details the achievement of this climate protection goal and further explains BASF’s goals in the realms of economic, ecological and social aspects. It documents BASF’s entrepreneurial performance and shows how sustainability contributes to corporate success. HP

■ Next-gen oil sands A next generation of oil sands development in Canada is set to emerge amid rising world demand for energy resources, according to Imperial Oil CEO Bruce March. Mr. March’s remarks, in which he said that Canada’s 170 billion barrels of recoverable oil sands reserves are needed to help provide the energy required to fuel improving living standards throughout the developing world, were captured during last month’s annual IHS CERA executive conference in Houston, Texas.

“Oil sands investments are now in a period of recovery, driven by resurgent world demand for energy resources and by a positive long-term outlook for energy,” said Mr. March.

Oil sands development also represents an important economic opportunity for Canada and the US in terms of energy security, job creation and economic activity. Mr. March said that oil sands development will be a key component of the US economy, and could generate 340,000 new US jobs plus 590,000 jobs in Canada over the next 25 years.

While recognizing there are important environmental considerations from oil sands development, positive progress as a result of new technology is being achieved, Mr. March said, citing the Kearl project in northern Alberta as a next-generation oil sands facility. The project, currently under construction, is scheduled for startup in late 2012.

Mr. March said that Kearl tailings will be smaller, mined land will be reclaimed faster, and greater quantities of water will be recycled. Kearl will also adopt technologies to reduce greenhouse-gas emissions.

“The September IHS CERA study indicates that our Kearl project will result in life-cycle greenhouse-gas emissions no greater than the average of oil refined in the US,” Mr. March said. “The oil sands industry has a positive story to tell and North Americans shouldn’t have to choose between energy security, economic well-being and a cleaner environment.” HP

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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR HB@HydrocarbonProcessing.com

Tutors can provide answers As you read this column, much additional data on the nuclear disaster on the east coast of Japan’s main island will have become available. But, the terms safety and reliability will still be on our minds, and the results of human suffering will be indelibly etched in the minds of millions.

We at HP have no special insights and don’t profess to have the answers to the hundreds of questions that have already been raised. Nevertheless, and for what it’s worth, we wish to highlight a few of the detailed questions we would ask, if we had an involvement in failure analysis and failure avoidance of any kind. No, this has nothing to do with nuclear engineering and design, but it has to do with elusive failure causes of rotating equipment such as emergency power generators and centrifugal pumps. It also pertains to compressors and stationary equipment such as steam traps.

Issues. On the Japan disaster, we would

look at the issue of 13 emergency generators reportedly failing in a very short time span and would, for now, assume that this report is verified as accurate. We would separate the listing of potential reasons into three categories: 1) issues with the diesel engines driving emergency generators, 2) cooling water pump hydraulics unsuitable for parallel operation, and 3) serious concerns with generator bearing lubrication.

Excessive water or solids contamination of diesel fuel (Item 1) would have caused engines to cease operating; ascertaining (or ruling out) such a cause is not too difficult.

While it’s on our list of questions, we can be certain that it also shows up on the lists prepared by other investigators.

have caused one or more pumps to fail.

Although this is a well-known issue, it is sometimes overlooked.

Then there’s Item 3. About 10 years ago, I was asked to visit a nuclear facility, which experienced frequent bearing failures on emergency generating equipment. The most probable cause was a fanlike blower wheel that had been fitted to the shaft at a location close to the bearing housing. While the fan may have promoted increased air flow to the bearing housing, it very probably caused a pressure difference between the inboard and outboard sides of the bearing. We recall that oil starvation was found on one side of the bearing. No such starvation problems were reported on equipment that did not come equipped with the “novel” fan-like blower.

Lube oils. Still on Item 3, we would certainly want to know the viscosity grade of the lubricant used in the generator bearings.

Misguided attempts to “standardize” on certain lubricants have proved costly, but we are slow learners. Whenever oil needs to be lifted into the bearings with slinger rings, oils that are too high in viscosity will cause slinger rings to malfunction. Slinger rings that are out-of-round will also malfunction, as will slinger rings that are too deeply immersed in an oil sump. And just think what happens when some of these deviations occur simultaneously, or when violent shaking causes the slinger rings to dislodge, or cold ambient temperatures will turn the oil into a more viscous mass. So, we should examine issues common to certain maintenance practices, certain “standardization” practices, and elusive problems that are rooted in deviation events that combine.

Make books your tutor.1

Books as tutors. Regarding Item 2,

we would examine the head/flow (H/Q) curves of the cooling water pumps, and ask if a counter-productive attempt was made to operate too many of these pumps simultaneously. Depending on prevailing H/Q relationships, operation at the resulting low (or even zero) flow could

Manufacturers as tutors. Experi-

enced manufacturers can be your tutors.

These tutors should be the best-qualified vendors, and purchasers should put into their budgets the cost of the best-technology equipment they provide. The relevance of this plea was re-emphasized when a

FIG. 1

The smallest twin-screw compressor rotor (arrow “B”) is dwarfed by the largest rotor made by the same manufacturer (Source: Aerzen USA, Coatesville, Pennsylvania).

manufacturer presumably proposed plastic internal parts for a line of high-temperature (due to the high-compression ratio) compressors. Working with a highly experienced manufacturer, perhaps one that makes the widest possible range of singlestage air compressors (Fig. 1), might have allowed the purchaser to understand what is, and what is not, technologically feasible.

The tutor would surely have pointed out the pitfalls of certain components.

Reliability focus. Finally, we believe that a reliability-focused purchaser must examine how systems work and how parts function. If, as an example, we had to choose from the large variety of steam traps available today, we would make it our first endeavor to understand how different trap types function and how they each perform long-term. We would obtain that information from a manufacturer whose product slate encompasses the widest possible range, and we should pay this manufacturer a premium for becoming our tutor. HP The author is Hydrocarbon Processing’s Reliability/ Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost-avoidance topics. 1This excerpt is taken from Bloch, Heinz P., “Pump Wisdom: Problem Solving for Operators and Specialists,” John Wiley & Sons, Hoboken, New Jersey.

HYDROCARBON PROCESSING APRIL 2011

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HPINTEGRATION STRATEGIES PAUL MILLER, CONTRIBUTING EDITOR PMiller@Arcweb.com

HPI needs to develop standards for asset information management ARC Advisory Group’s 15th Annual World Industry Forum in Orlando, Florida, Feb. 7-10, 2011, attracted more than 650 participants, representing 250 different organizations from 20 different countries. One of the keynote speakers, Bechtel Senior Vice President, Geir Ramleth, gave an interesting and well-received presentation on the need for suppliers; engineering procurement and construction (EPC) companies such as Bechtel; and owneroperators in the hydrocarbon processing and other asset-intensive industries to develop and implement standards for managing asset-related information.

Bechtel’s view. Geir prefaced his presentation with, “We

(Forum participants], as a collection of industries, need to mature by developing some basic standards (for asset information management).” Geir then gave some examples of common standards that make life and business easier. These included calendars, standard gauge railways, boxcars for shipping, standard couplers for fire hydrants, and credit cards, which can be used anywhere around the world.

According to Geir, “it’s important to consider both standards and functionality.” Using cars as an analogy, “The capital projects industry builds and maintains custom ‘street rods,’ but really desires standard production car-like efficiency.” Geir went on to explain that many standards already exist in the capital project industry, including ISA/ISO/ANSI/IEEE standards; local design and regulatory standards; EPC standards; and owner-specific design, operations and maintenance standards. “Current standards primarily address physical assets, but progress is being made for information-related standards. ISO, FIATECH, POSC and EPRI all have initiatives underway. Geir also believes that the resurgence of nuclear power and associated regulatory requirements will drive increased (asset) information standards.

Improving performance. Geir described the owner/operator challenge of poor information. These include the time it takes to achieve design capacity at new facilities, increased regulatory requirements, the aging workforce, low “wrench time” due to poor access to accurate information, and a move toward centralized operations. Geir said, “We, the builders, should help owner/ operators deal with their information challenges. For example, while the owner/operator may purchase a single turbine, it can contain hundreds of different parts that may need to be repaired or replaced over time. We have to take a life cycle view. We need to be custodians of the information, which is why we need to have standards.”

For EPCs, a large part of the problem is that every project is different, with different customers, partners, suppliers and technology. According to Geir, “Our goal for every project is to get the right information to the right people in their environment at the right time, securely and cost-effectively.” To this end, “ISO

15926 provides a common set to determine how information should be exchanged. ISO 15926 creates master data to be in a dynamic model for improved access to information based on user roles and preferences.” According to Geir, this approach is not common today in the capital project industry, but is well along in other industries such as for internet technology.

He agrees with ARC’s new model for the asset information process, which allows for a smooth, rather than disjointed flow of relevant information for stakeholders over the asset lifecycle.

Information goals. According to Geir, “80 percent of users only read data and do not contribute or edit data; yet, the majority of today’s tools focus on the latter users. However, if you can get the right information to the right people in the right time frame, it can be a valuable resource.” Bechtel’s goals include: • Early standards-based progressive information handover • Improved pre-startup processes (reliability planning, operator training, commissioning and spare parts inventory consolidation) • Vertical start up delivering design capacity/on-spec product earlier for new facilities • Improved wrench-time metrics • Easier compliance with regulatory requirements • Improved financial performance and reputation of individual stakeholders and the industry as a whole.

Geir concluded, “To deliver the full potential of asset information management, we need everyone— suppliers, EPCs, software providers and owner/operators—to work together, support standards and deliver solutions. Most people don’t disagree that standards are needed, but not many are doing much about it.”

ARC has produced numerous reports on this important topic in recent years and is working actively to help speed these standards development activities. For more information, readers can visit www.arcweb.com. HP

Paul Miller is a senior editor/analyst at ARC Advisory Group and has 25 years of experience in industrial automation industry. He has published numerous articles in industry trade publications. Mr. Miller follows both the terminal automation and water/wastewater sectors for ARC. HYDROCARBON PROCESSING APRIL 2011

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HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Valero confirms purchase of Chevron’s Pembroke refinery and other assets Valero Energy has agreed to acquire Chevron’s Pembroke refinery in Wales, UK, as well as extensive marketing and logistics assets throughout the UK and Ireland, for $730 million, excluding working capital.

Based on current market prices, working capital has an estimated value of $1 billion, although the final value for working capital will be determined at closing. The company expects to fund the transaction from available cash, and it is expected to close in the third quarter of 2011, subject to regulatory approvals.

The Pembroke refinery has a total throughput capacity of 270,000 bpd, of which 220,000 bpd is crude capacity, and is one of Western Europe’s largest and most complex refineries, with a Nelson complexity rating of 11.8. The refinery has been well maintained and managed, and has an estimated cash operating cost 25% below Valero’s average, making it a competitive addition to Valero’s portfolio.

Pembroke can process a large and flexible slate of feedstocks, having used more

FIG. 1

than 60 different types of crude oil in the past decade. It has access to discounted crudes, and has a product slate of 44% gasoline, 40% distillates, 11% fuel oil and 5% other products. It receives feedstock cargoes by ship at its eight-berth deepwater dock, which can accommodate very large crude carriers.

In addition, the purchase price includes ownership interests in four major product pipelines and 11 fuel terminals, a 14,000bpd aviation fuels business, and a network of more than 1,000 Texaco-branded wholesale sites, which is the largest branded dealer network in the UK and the second largest in Ireland. In total, more than half of the refinery’s production is distributed through this integrated marketing and logistics system.

Valero expects to retain the employees in the UK and Ireland currently engaged in the businesses being acquired.

“We have been looking for some time to expand and improve our portfolio of assets, but only if we could get an attractive price for assets that would add significant long-term value for our shareholders,” said Valero Chairman and CEO Bill Klesse.

“This acquisition of quality assets enhances

The Pembroke refinery has a total throughput capacity of 270,000 bpd, of which 220,000 bpd is crude capacity. Photo courtesy of the Energy Institute.

our portfolio and gives us opportunities for profitable growth. After exiting refining in the US East Coast last year, this acquisition provides an opportunity for our company to supply that market more competitively, when it’s economic to do so.

“The Pembroke refinery remained profitable and cash-flow positive even during the depths of the economic downturn in 2009,” Mr. Klesse said. “We expect that it will be immediately accretive to earnings per share.”

Once the transaction closes, Valero expects that the addition of the Pembroke refinery and the associated marketing and logistics assets will enhance its Atlantic Basin margin optimization strategy.

Natural gas enters a new era of abundance Technological advances in the production and transportation of natural gas are raising new opportunities for the fuel but also challenging traditional ways of doing business in gas markets, according to a new comprehensive report by IHS Cambridge Energy Research Associates (IHS CERA) and the World Economic Forum.

The report, “Energy Vision Update 2011: A New Era for Gas,” says that advances in unconventional gas production coupled with growing liquefied natural gas (LNG) trade are changing long-standing assumptions about natural gas markets around the world.

“The unconventional gas revolution is the most important energy development so far this century and it has the potential to boost gas production far beyond North America,” said Daniel Yergin, IHS CERA chairman and Pulitzer Prize-winning author of The Prize. “The resulting changes to the supply outlook and fundamental economics of natural gas will be transformative. They can have far-reaching impact on the electric power industry and the fuel choices in the years ahead. Understanding what this may mean is a top-level topic for the energy industry worldwide.”

As a result of the shale gas revolution, North America has sufficient recoverable gas to meet current levels of consumption for well over 100 years. Global LNG HYDROCARBON PROCESSING APRIL 2011

I 15

HPIMPACT trade doubled in the decade from 2000 to 2010 and is expected to increase another 50% or more in the next 10 years. Recent advances in technology mean that natural gas is likely to be more available, and less expensive, than was assumed just a few years ago.

The North American “shale gale” served to slow, if not reverse, the move toward the convergence of prices and a truly global gas market, the report says.

1,500+

refining, chemicals & petrochemical projects

North America is much less dependent on LNG than was projected just three years ago, disconnecting the market from gas prices elsewhere.

“In the context of a world with increasing demand for energy, gas is playing a critical role. It is particularly attractive for power generation as a relatively cheaper and cleaner source of energy,” said Roberto Bocca, senior director and head of energy at the World Economic Forum. “With

60+ years

refinery & petrochemical engineering experience

200+

long-term alliance relationships

many policy discussions today focusing on emissions and carbon reduction, natural gas represents an opportunity for progress, since a modern natural gas plant can produce electricity with half the greenhousegas emissions of an older coal-fired plant.”

“Growing demand for LNG in Asia brings increasing interconnectedness between Asian and European gas markets,” Mr. Yergin said. “But with a mostly selfsufficient North American gas market, one should expect an inter-regional, rather than a global, market.”

The surge of gas supply that occurred during the global recession also challenged some longstanding tenets of the world’s gas markets, particularly in Europe, the report notes. The traditional linking of gas prices to oil in Europe, though likely here to stay, is nonetheless evolving as long-standing gas suppliers are offering more flexibility in contract terms and pricing to compete with growing volumes of LNG. In contrast to the revolution in supply, the demand outlook for gas is more evolutionary, the report finds. The primary uses for gas remain the same—space and water heating in residential and commercial applications, fuel and feedstock for industrial applications, and power generation.

Natural gas use in power generation, in particular, will be the main source of demand growth in the future, the report says. Natural gas is the cleanest of the fossil fuels, emitting the least greenhouse-gas (GHG) emissions and other pollutants than coal or oil, making it a preferred fossil fuel, given the imperative to reduce emissions.

Research anticipates failures in workplace

WorleyParsons provides a comprehensive range of petrochemical services backed by over 60 years of global experience in grassroots, revamp, and expansion projects. Our global network of 32,900 employees allows us to provide customers with a single source for the resources and technology needed to meet the unique requirements of petrochemical and polymer units.

For more information, contact

petrochemicals@worleyparsons.com refining@worleyparsons.com

Select 152 at www.HydrocarbonProcessing.com/RS 16

A new independent research report has presented industry with a practical way to measure the human factors health of their safety regimes, potentially opening the way to significant advances in workplace safety, environmental stewardship and operational efficiency.

The report, a collaborative effort between the Energy Institute (EI), Lloyd’s Register EMEA and the UK Health and Safety Executive (UK HSE), is expected to be welcomed by the energy and related process and transportation sectors, but it also will have relevance for most companies looking to better understand and manage the impact their employees have on safe and efficient operations.

HPIMPACT “This report is significant, in that it proposes a set of metrics and provides information that will allow the process industry to accurately measure the human factors that affect the safety performance of the organization, particularly concerning how the workforce interacts with high-risk assets,” said Richard Sadler, chief executive for Lloyd’s Register. “What recent investigations of industrial incidents continue to show is that strategies for asset safety are not enough. Effective risk management must include the human part of the interaction between people, plant and process, and that is why we continue to invest heavily in this particular area.”

“During our inspections and investigations, we are placing increasing emphasis on the role of safety-leaders,” said Rob Miles, head of human and organizational factors at HSE. “A key element of this is what information reaches those in leadership roles, how they understand that information and what actions they then take.

We see this report as providing the framework for how such information is gathered and used, particularly on the challenging human-factors issues.”

Identifying leading performance indicators for human factors—known as the “human element” in the marine sector— will help companies to identify the areas in which they need to proactively manage the factors that affect workforce performance before they become a problem, demonstrating the appropriate levels of control to stakeholders such as regulators and insurers.

While the new practical methodology for measuring the factors that affect performance of the workforce will have obvious benefits for the energy industry, the report’s authors believe it also has relevance for companies operating high-risk assets in the chemicals, power, nuclear, rail and marine sectors.

“Major accident hazard site operators who are seeking to demonstrate continuous improvement in the management of the human element of risk should read this research report. It introduces the latest thinking on performance measurement and proposes leading and lagging indicators for the HSE Human Factors Key Topics,” said Graham Reeves, chairman of the EI’s Human and Organizational Factors Committee. “Simple, concise information is provided that stresses workforce involvement combined with a design template to support the design of human factors per-

formance indicators for implementation within a business. This research report marks the beginning of a journey, but it is one which we will all have to embark on.

Fortunately, the route we have to take is well defined. After all, ‘you don’t improve what you don’t measure.’”

“This is the first time a set of key performance indicators, supported by a transparent methodology aligned with UK HSE guidance, has been made available to help

companies operating in the oil, gas and process industries to manage the human aspects of safety more effectively,” said Dr. Kevin Fitzgerald, research project manager and a member of Lloyd’s Register’s Aberdeen, Scotland, based consulting services team. “We have taken an established HSE methodology, adapted it, and stated how to use that to select the right KPIs to measure the factors that affect performance of the workforce and turn that information into action.” HP

See us at OTC Exhibition, Houston, Texas, 2-5 May 2011, Booth #4749

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EBARA CORPORATION

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HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

Product line extended on process gas compressors API 618 Burckhardt Compression introduced its extended range of process gas compressors, enabling the company to offer a costeffective compressor solution for a broad range of applications within the hydrocarbon processing industry. The development is based on long-term experience and a successful history in developing, engineering and manufacturing process gas compressors API 618. Proven parts and elements of the existing frame sizes were implemented ensuring top-quality standards and high reliability.

This product range significantly expands Burckhardt Compression’s ability to cover the whole variety of process requirements of today’s and future customer demands. Generations of experience, together with the aim to fully comply with the API 618 fifth-edition guidelines, are the base of Burckhardt Compression’s successful manufacturing of high performance compressors.

Product development is an important part of the company’s certified business processes. State-of-the-art in-house analysis and the wide experience from the existing compressor range of the even larger and more powerful hyper compressors, confirmed the high-quality designs that result in a maximum durability and best performance at the highest safety levels. Burckhardt Compression’s process gas compressor represents the highest availability and a long meantime between overhauls, also thanks to in-house engineered and manufactured high-quality compressor components and valves. Practice-oriented design principles result in easy maintenance work and short As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our website at www.HydrocarbonProcessing.com/rs and select the reader service number.

downtime for overhauls. Burckhardt Compression’s aim is to deliver compressor solutions with the lowest life cycle costs. The company’s process gas compressors API 618 are used in the refinery and petrochemical/ chemical industry, as well as for industrial gases and gas transport and storage.

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Mass-transfer rate-based simulator offers new capabilities Optimized Gas Treating recently added several new solvents and capabilities to the ProTreat suite of mass-transfer rate-based simulation software. The new solvents include: • Dimethylether of polyethyleneglycol (DMPEG), [also known as SELEXOL, Genosorb and AGR solvent] a physical solvent for acid-gas removal • Amino acid salts promoted with amines for CO2 capture • Glycol dehydration • Effect of heat-stable salts on process performance.

ProTreat does all column calculations using powerful mass- and heat-transfer rate-based models that are fully predictive without adjustable parameters of any kind.

In parallel with using the equipment’s heattransfer characteristics in exchanger design software, ProTreat uses the mass-transfer characteristics of specific trays, and random and structured-packings to predict column and treating-plant performance. Tray details and packing size, type, material and vendor make a difference that cannot be accounted for by rules-of-thumb, be they efficiencies,

FIG. 1

tray residence times or height equivalent to the theoretical plate (HETPs). ProTreat sets up a virtual plant, accurate and realistic in every important respect.

All solvents, including the amines, amine blends, piperazine-promoted methyl diethanolamine (MDEA) including heat stable salts, and all INEOS GAS/SPEC products, as well as the new physical, amino acid and caustic solvents are simulated on a mass transfer rate basis. This allows ProTreat to predict the number of actual trays and the height of actual packing needed to do a specific job. The result is tighter, more competitive designs; well-founded plant operations decisions; and better-run units, whether in conventional and shalegas processing, acid gas enrichment and carbon capture.

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FTIR fuel analysis in seconds The Eraspec by Eralytics (Austria) is the first portable mid-Fourier transform infrared (FTIR) spectrometer designed as a fully automated multi-fuel analyzer (Fig. 1). The Eraspec spectrometer can perform a spectral analysis of gasoline, diesel fuel and jet fuel with a single portable analyzer. It generates highly accurate results for more than 40 fuel parameters and several important fuel properties, such as octane and cetane numbers. In addition, it measures biodiesel (FAME) concentration in conventional diesel and jet fuel (EN14078; ASTM standard in progress).

Results are presented on a large industry proven full-color touch screen in seconds.

Eralytics’ portable mid-FTIR spectrometer.

HYDROCARBON PROCESSING APRIL 2011

I 19

HPINNOVATIONS Graphic presentations of the fuel spectra can be analyzed and compared directly on the instrument’s color screen.

The unmatched precision, speed and ease of operation makes the Eraspec spectrometer the preferred analyzer for fuel compliance testing in the quality-control laboratory, with its fast at-line refining streams quality follow-up, fuel blending and research applications. It follows in each detail the requirements of the latest inter-

national standards ASTM D5845, ASTM D6277, EN 238 and EN 14078.

The heart of the system is a patented, rugged interferometer, that is field-proven to be also used in challenging environments. The internal components are mounted on anti-vibration platforms and the portable aluminum instrument housing allows for field tests directly at the point of sale.

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Designed specifically to meet the requirement of API 610, the API Maxum Series is available in 35 sizes to handle flows up to 9,900 GPM and 720 feet of head. Standard materials include S-4, S-6, C-6 and D-1. A wide range of options makes this the API 610 pump for you!

Fully scalable tank-gauging system improves efficiency Emerson Process Management’s new Raptor tank-gauging system (Fig. 2) makes it easy to install the devices needed today and to add or replace units in the future.

This flexibility protects users’ investments so that refineries and tank farms can easily become and stay efficient. Additional benefits include lower installation costs, high accuracy and built-in safety features.

The Raptor system consists of a complete range of tank-gauging instrumentation including high-performance, noncontact radar level gauges, temperature and pressure transmitters, plus water interface sensors and inventory management software. Tank hubs are used for communicating with the measuring instruments and control room via standard communication protocols. The design is based on open technology and is fully scalable with functionality and scope that can be adapted to any application and performance class.

The system includes new safety technologies to help protect plant assets, personnel and the environment. One example is the unique 2-in-1 functionality—with two independent radar gauges in one single enclosure—providing SIL 3 safety for overfill prevention. There are also a number of other dual redundant configurations available to suit individual tank safety requirements.

Raptor reduces installation costs substantially. Raptor’s unique, bus-powered 2-wire Tankbus communication is based on self-configuring Foundation fieldbus technology, allowing easy start-up and integration of all system units. The tank units

Creating Value.

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

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FIG. 2

Raptor gauges have drip-off antennas for undisturbed performance in tanks with condensing vapors.

HPINNOVATIONS are intrinsically safe, which means that no expensive cable conduits are required.

Further installation cost savings can be realized with Emerson’s Smart Wireless functionality, which eliminates the need for long distance signal wiring. This is especially valuable when no suitable ground cabling is available and it is necessary to cross roads, or when ground conditions make cabling expensive. Wireless communication can also be used as a redundant and independent communication path beside the traditional wired communication.

There are many tank farms with gauging based on older technology, even in fairly recent installations, leading to maintenance problems and low performance. Raptor can emulate gauges from other manufacturers.

Customers can add Raptor units to their existing system using the same cabling and control room infrastructure.

Raptor is built around a new line of Rosemount 0.5-mm (0.02-in.) precision radar level gauges, and ultra stable temperature transmitters with 3- or 4-wire multiplespot sensors. The result is the highest available precision in net volume calculations for custody transfer and inventory management. Having access to reliable and accurate tank-content information in real-time is key to high plant efficiency, as the operators can handle even more tanks, fill the tanks higher and better utilize the storage capacity.

Emerson’s Rosemount tank gauging is the world market leader in systems for high precision tank gauging used at refineries and bulk liquid storage plants. The systems are applied on all types of storage tanks, both fixed-roof and floating-roof tanks.

The radar gauges use the drip-off antenna concept, proven in 100,000+ installations world-wide. They can be used in virtually any liquid, ranging from light products to heavier products.

process conditions. It has a plugged bottom side drain connection that can be used for cleaning out or a freeze protection with a manual drain valve. All internals are stainless steel and have a high capacity single seat mechanism which has an infinite turn down ration on both pressure and flow extending the service life of the trap. The main valve assembly has a tight shut-off under no-load conditions, even if the water seal is lost which prevents steam wastage. A

fixed bleed air venting device is supplied to prevent air locking of the trap on startup.

Every trap is 100% steam tested at the factory to guarantee performance.

The standard offering is available in 11â „2-in. and 2-in. pipe connections that are direct inline with no change in elevation.

The flow direction is right-to-left with a removable strainer screen to the front of the trap that covers 50% more surface area.

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Ball-flow steam trap designed for pressures as high as 1,160 psig Spirax Sarco announced the release of the FTC80-FB ball float steam trap series.

This trap has been designed as a premium solution for process applications in the chemical, hydrocarbon processing, and pulp and paper industries where pressures can be as high as 1,160 psig.

The FTC80-FB carbon steel series has a body and cover made of cast steel with all socket weld connections. This series is self modulating to provide soft and continuous discharge, which helps to maintain stable

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR HM@HydrocarbonProcessing.com

North America Chevron Lubricants will construct a lubricants manufacturing facility at the company’s Pascagoula refinery. The $1.4 billion Pascagoula base-oil project is projected to generate approximately 1,000 jobs over the next two years of construction and about 20 permanent positions once the facility is operating.

The facility will use Chevron’s Isodewaxing technology and manufacture 25,000 bpd of premium base oil. The main ingredient in the production of top-tier motor oil, base oil is said to help improve fuel economy, lower tail-pipe emissions and extend the time between oil changes. Construction is scheduled to be completed by year-end 2013.

Celanese Corp. is expanding ethylene vinyl acetate (EVA) capacity at its Edmonton manufacturing facility due to strong growth in strategic, high-value segments.

The company is expected to increase capacity by up to 15% for higher vinyl acetate content EVA grades at the Edmonton facility in the second half of 2011. The Edmonton plant’s diverse reactor capabilities and unique footprint allows for a more customized approach to product manufacturing.

It has the flexibility to produce a full range of EVA copolymers, specialty low-density polyethylene (LDPE) and compounds for a wide range of end uses.

Canadian Natural Resources Ltd. has a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding construction and operation of a bitumen refinery near Redwater, Alberta, Canada. In addition, the partnership has an agreement to process bitumen supplied by the Government of Alberta under the Bitumen Royalty In Kind (BRIK) initiative. Provided the project is sanctioned following detailed engineering, Phase 1 will process 50,000 bpd of bitumen to finished products and will incorporate an integrated CO2 management solution. The facility can be expanded in two additional identical phases of 50,000 bpd of bitumen at a future date.

Valero Energy Corp. has successfully started up advanced reformate splitters

at three of its US refineries. The three mobile-source air toxic (MSAT) II benzene concentration units—located at Valero’s Port Arthur and Sunray, Texas; and Memphis, Tennessee, refineries—utilize KBR’s advanced reformate splitter dividing-wall column (DWC) tower designs. A fourth unit, located at Valero’s St. Charles refinery in Norco, Louisiana, will be commissioned later this year.

The startups mark the first successful implementation of the DWC tower designs in the US and Western Hemisphere refining sector. Conceptually developed by Valero, the DWC towers were designed and optimized by KBR for each unique project, and have allowed Valero to meet its regulatory requirements.

The Dow Chemical Co. (Dow) has converted one of its ethylene oxide ethylene glycol (EOEG) production units (SCO1) at its operations in St. Charles, Louisiana, to EOonly. This move further strengthens EOEG business competitiveness and St. Charles as an EO production location for Dow. This project also supports Dow’s transformational strategy to become an earnings growth company by preferentially investing in market-driven performance businesses.

Dow will also implement a permanent shutdown of a second unit at St. Charles (SCO2), an EOEG plant the company idled in March 2009, as a result of the impact of world economic conditions.

Invensys Operations Management has successfully implemented an InFusion Enterprise Control System (ECS) for ExxonMobil Lubricants & Specialties Co. Through a joint Invensys and ExxonMobil team effort, the installation was successfully completed and the plant was back to full production on schedule with no safety incidents. Installed at ExxonMobil’s lubricants plant in Beaumont, Texas, the InFusion ECS will help manage the operating facility, controlling major processes and integrating the existing SAP enterprise resource planning, batch process, and final packaging and shipping systems.

INEOS New Planet BioEnergy, a joint venture between INEOS Bio and New

Planet Energy, has broken ground on what is said to be the first advanced wasteto-fuel commercial biorefinery in the US. The $130 million Indian River BioEnergy Center in Vero Beach, Florida, will manufacture advanced (cellulosic) biofuels using the INEOS Bio gasification and fermentation technology.

Starting in mid-2012, the Indian River BioEnergy Center will produce 8 million gpy of bioethanol and 6 Mw (gross) of renewable power.

CITGO Petroleum Corp. has completed the construction and startup of a 42,500-bpd unit utilizing the latest technology to produce ultra-low-sulfur diesel (ULSD) at its Corpus Christi, Texas, refinery. With the completion of this unit, which has been in operation since December 2010, CITGO can now produce 100% ULSD at all of its refineries. The CITGO shareholder, Petróleos de Venezuela, S.A. (PDVSA) was involved in the project. PDVSA’s research arm, INTEVEP, participated early in the ULSD process unit design, in such areas as reactor sizing, reactor internals and catalyst selection.

South America Braskem Idesa S.A.P.I., a joint venture of Braskem S.A. and Grupo Idesa S.A. de C.V., has selected LyondellBasell’s Lupotech T process technology for a new

Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting.

The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested.

You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact: Drew Combs P.O. Box 2608, Houston, Texas, 77252-2608 713-520-4409 • Drew.Combs@GulfPub.com HYDROCARBON PROCESSING APRIL 2011

I 23

HPIN CONSTRUCTION Inauguration of the Ras Laffan Olefins Co. (RLOC) Cracker, Qatar Qatofin is a joint venture between Qapco1 (63.63%), Total Petrochemicals France (36.36%) and QP (Qatar Petroleum)2 (0.01%) established in June 2002 to implement the Qatofin project. This project includes participation in one of the world’s largest ethane crackers in Ras Laffan (Fig. 1), a linear-low-density polyethylene (LLDPE) plant in Mesaiseed and the related ethylene pipeline linking both sites (Fig. 2).

The construction of this major project started in September 2005. The foundation stone of the Ras Laffan cracker was laid down on May 19, 2006; that of the polyethylene plant on May 22, in the presence of Qatari authorities and the representatives of Total Petrochemicals and Qapco.

The capital investment for Qatofin reached $1.2 billion; including its share of the cracker. Thanks to its implementation, the production of polyethylene (PE) on the Qapco/Qatofin site in Mesaieed will reach more than 1.1 million tpy.

Qatofin partners on one of the world’s largest ethane cracker.

FIG. 1

Gas field Gas pipeline Oil pipeline Ethylene pipeline

Al Ruwais

North Field

TABLE 1. Main milestones of the Qatofin project Jan. 13, 2001

A proposal for an integrated petrochemical project is presented to His Excellency, the Minister of Energy Abdullah bin Hamad Al-Attiyah. The name Qatofin was selected.

Oct. 2, 2001

Signature of MOU between QP, Qapco, CPC and ATOFINA (former name of Total’s chemical segment).

Qapco and ATOFINA intend to enter into a new joint venture “Qatofin,” which will acquire an interest in the Ras Laffan cracker and will own and operate an LLDPE plant at Mesaieed.

June 13, 2002

Signing of the Qatofin joint venture agreement between Qapco, ATOFINA and QP

July 27, 2005

Creation of Qatofin Incorporation

Sept. 11, 2005

Creation of RLOC (Ras Laffan Olefins Co.) Incorporation

May 19, 2006

Foundation stone laying of cracker at Ras Laffan

May 22, 2006

Foundation stone laying of LLDPE at Mesaieed

Dec. 26, 2006

Startup of construction activities for Logistics

Sept. 2009

Startup of production at the Qatofin plant at Mesaieed, based on Qapco ethylene

Nov. 24, 2009

Inauguration of Qatofin plant at Mesaieed

April 2010

Startup of the ethane cracker at Ras Laffan on April 13, 2010. Startup of LLDPE plant on RLOC ethylene on April 19, 2010.

May 4, 2010

Inauguration of Ras Laffan Olefins Co. cracker

Al-Kahalij

Ras Laffan

Ethane cracker

Dolphin Dolph

in pip

Rawdat Ráshid

Qatofin pipeline

Dukhan

eline

Ras Laffan Refinery

Al Jamaliyah

Hajul Island

Total research center Iran Doha Qatar Doha

25 km

Qatofin LLDPE

24

Qapco (Qatar Petrochemical Co.) was established in 1974 in line with the industrialization plan of the State of Qatar. Qapco is currently 80% owned by Industries of Qatar (IQ) and 20% owned by Total Petrochemicals France. The joint venture owns a 720,000 tpy ethane cracker and two polyethylene (LDPE) units with a total capacity of 400,000 tpy in Mesaieed.

A third line, with a capacity of 300,000 tpy, is being built with startup scheduled for early 2012.

2 Qatar Petroleum (QP) was established in 1974 as a national corporation completely owned by the State of Qatar. QP is responsible for all oil and gas industry processes in Qatar and abroad, including exploration and drilling for oil, natural gas and other hydrocarbon substances, production, refining, transport and storage of the aforementioned products and any of their derivatives and byproducts, as well as trading in, distribution, sale and export of these products.

3 Q-Chem II is a joint venture between QP (51%) and Chevron Phillips Chemical International Qatar Holdings LLC (49%). The joint venture has an equity participation of 53.31% in the new Ras Laffan ethane cracker and the related ethylene pipeline to Mesaieed.

Qatargas II

Gulf of Bahrain

FIG. 2

1

Oil field Gas/LNG plants Petrochemicals Refinery

Qatargas

0

The ethane cracker at Ras Laffan (RLOC–Ras Laffan Olefins Co.) and the ethylene pipe are owned jointly by Qatofin (45.69%), Q-Chem II3 (53.31%) and QP (1%). RLOC has been designed to process 1.3 million tpy of ethylene and is one of the biggest ethane crackers built worldwide. Qatofin and Q-Chem II’s ethylene allocated cracking capacities are 600,000 tpy (46.15%) and 700,000 tpy (53.85%), respectively. The cracker is being operated by Q-Chem II. The Qatofin plant, which is located next to the Qapco site, will process around 422,000 tons of ethylene per year as 450,000 tons of LLDPE, which will be marketed and distributed by Qapco and Total Petrochemicals. The production is intended for export to Asia-Pacific, Africa and Europe, as well as supplying the local market. HP

Mesaieed Qapco QVC

Saudi Arabia

UAE

Qatar Gas infastructure and Qatofin Project location.

I APRIL 2011 HydrocarbonProcessing.com

HPIN CONSTRUCTION 300 kilotons/yr low-density polyethylene (LDPE) plant. The plant will be built at the Coatzacoalcos Petrochemical Complex in Veracruz, Mexico, and is scheduled for startup in 2015.

Repsol YPF has registered its La Plata refinery industrial project with the United Nations as a Clean Development Mechanism (CDM), reported to be the first of its kind in the world. CDMs, a tool laid out in the Kyoto Protocol, allow development of emissions-reducing projects that favor sustainable development and implementation of clean technologies in the countries where the investment is made.

The project carried out by Repsol at its Argentine La Plata refinery will increase energy efficiency by reducing demand for fuel oil and natural gas, allowing an annual emissions reduction of approximately 200,000 tons of carbon dioxide.

Wood Group GTS has been awarded a contract, estimated to be worth up to $4.5 million, by Consorcio Camisea to provide overhaul and technical support for eight Solar Centaur 50 SoLoNOx gas turbines in two Peruvian gas plants. Wood Group GTS will deliver a turnkey project of major overhauls, logistics, commissioning, tuning and engineering surveillance on these turbine-generator packages at the Malvinas and Pisco gas-processing facilities onshore in Peru. Ongoing production maintenance support is provided by Wood Group GTS’s sister company Wood Group Peru.

Europe Technip has been awarded a lump-sum services contract by Burgasnefteproekt EOOD (a Lukoil engineering subsidiary) for phase 1 of a heavy-residue hydrocracking complex to be built at its refinery in Burgas, Bulgaria. The contract, worth approximately €70 million, covers the detailed engineering and procurement services for a 2.5 milliontpy residue hydrocracker based on Axens’ H-Oil process, as well as amine, sour-water stripper and hydrogen-production units.

Technip’s operating center in Rome, Italy, will execute this contract, which is scheduled to be completed in May 2013.

After 35 years of collaboration with RWE regarding the high-temperature Winkler process (HTW process), Uhde has now taken over the technology developed

by RWE Power and its predecessors. This makes Uhde the sole proprietor of the HTW

process, including all intellectual property rights, know-how and patents. From this point on, Uhde will act as the technology provider and licensor of this process.

Uhde is working on a new engineering contract for an HTW gasification plant in Sweden for VärmlandsMetanol AB. The aim of the plant will be to convert wood into methanol. Outside of Europe, Uhde is pursuing additional HTW projects, for example, in Australia and India.

Air Liquide has commissioned two air-separation units in Poland, both of the standardized YangO 2 type, located in Zakłady Azotowe in Puławy. The new air-separation units are said to be the biggest liquid and gas source in Central and Eastern Poland, with an aggregate production capacity of around 1,700 tpd. This investment is included in the €100 million overall investment in Poland announced in June 2010.

Energy conservation and optimization are key issues for process plant profitability and regulatory compliance. Proper evaluation and correction of energy losses can help bring significant cost savings and reduce greenhouse gas emissions.

Our complete optimization program can help you: ■ ■ ■ ■ ■ ■ ■

Evaluate opportunities for energy savings Develop AFE capital cost estimates Provide ROI calculations for management review Identify needed operation and procedure changes Perform front-end studies Integrate data for air emissions compliance Implement advanced process control

Contact us today for information on how Mustang can help reduce the energy stranglehold on your facility.

Email: ron.jackson@mustangeng.com

www.mustangeng.com

Select 156 at www.HydrocarbonProcessing.com/RS

25

HPIN CONSTRUCTION Africa

Guinea’s local fuel demand. It marks the first step away from the country’s dependency on imported fuel to meet local demand.

KBR has been awarded a contract by The Ministry of Mines, Industry and Energy of the Republic of Equatorial Guinea to provide a conceptual study and associated project-management services (PMS) for the development of a lowcomplexity, modular 20,000-bpd refinery at Mbini in the Republic of Equatorial Guinea, West Africa. The aim of the refinery is to meet the Republic of Equatorial

Middle East Jacobs Engineering Group Inc. has a contract from Saudi Aramco Lubricating Oil Refining Co. (Luberef ) to provide front-end engineering design (FEED) services to support an expansion project at its lube-oil refinery in Yanbu, Saudi Ara-

Paratherm GLT™ Synthetic Heat Transfer Fluid showed 30% less degradation than a widely used Synthetic Heat Transfer Fluid.

Degradation in heat transfer fluid can cause a multitude of problems from loss of production efficiency to unplanned system shutdown. According to the ASTM D6743 standard test method for thermal stability of organic heat transfer fluids, at 600°F for 500 hours Paratherm GLT Heat Transfer Fluid created 30% less product degradation than a widely used comparable alternative.

Additionally, Paratherm GLT Fluid is compatible for top-off with similar synthetics and is near colorless versus other yellowish colored fluids which show signs of impurities that may contribute to degradation.

Go to our website or call one of our Immersion Engineering™ team for more details and special services. All it takes is a short conversation with one of our sales engineers to greatly eliminate the risk of degradation in your system.

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Select 157 at www.HydrocarbonProcessing.com/RS 26

Services

800-222-3611

KBR has a contract with Saudi Aramco to provide front-end engineering and design (FEED) and project-management services (PMS) for its grassroots Jazan refinery, an anticipated 400,000-bpd facility to be located in Jazan, Saudi Arabia. KBR will provide FEED and PMS services to develop the facility’s process design, layout, integration and optimization, as well as its equipment and material specifications, preparing engineering procurement and construction (EPC) bid packages and developing an estimate for the refinery’s construction. Additionally, KBR will also assist Saudi Aramco in overseeing, managing and directing the work-related activities for all phases of the Jazan refinery and marine terminal project.

Work on the project is expected to begin in February 2011.

The Shaw Group Inc. has been awarded a contract by Qatar Petrochemical Co., Ltd. (QAPCO) to provide basic engineering services for the expansion of a 720 kilotons/yr ethylene plant in Mesaieed, Qatar.

The project will provide the design needed for expanding the plant’s capacity by up to 25%. The undisclosed value of the contract will be included in Shaw’s Energy & Chemicals segment’s backlog of unfilled orders in the second quarter of fiscal year 2011.

Fluid Analysis Fluid Maintenance Training Troubleshooting Consulting

Paratherm MG™ HTF Paratherm HR™ HTF Paratherm GLT™ HTF

bia. Based on the outcome of the feasibility study, the overall expansion project cost was estimated at approximately $1 billion.

Jacobs is providing FEED services for both inside battery limits (ISBL) and outside battery limits (OSBL). The ISBL services involve a new lube-oil unit (hydrocracking, iso-dewaxing/hydrofinishing), a new sulfur complex and a propanedeasphalting unit expansion; the OSBL services involve all utilities and infrastructure.

®

®

Borouge has awarded a contract worth $169 million to Hyundai Engineering and Construction to build a cross-linkable polyethylene (XLPE) unit at its petrochemical plant in Ruwais, Abu Dhabi. With a capacity of 80,000 tpy, the unit is an addedvalue complement to the low-density polyethylene (LDPE) unit.

This is the final major contract to be awarded for the Borouge 3 mega-expansion project already underway in Abu Dhabi in the UAE. Hyundai Engineering and Construction is also providing the project’s utilities and offsite facilities.

When fully operational in mid-2014, Borouge 3 will more than double the plant’s

HPIN CONSTRUCTION capacity to 4.5 million tpy and create what will reportedly be the largest integrated polyolefins plant in the world.

Burckhardt Compression has an order from International Polymers Co. (IPC), Jubail, Saudi Arabia, to deliver a Hyper compressor for its low-density polyethylene-ethylene vinyl acetate (LDPE-EVA) plant. The production process is licensed

by ExxonMobil Chemical Technology Licensing LLC. Burckhardt Compression secured the order, thanks to a large number of references in LDPE plants with similar or larger capacities. Hyper compressors are high-pressure reciprocating compressors for LDPE plants with discharge pressures up to 3,500 bar (50,000 psi).

IPC is a joint venture between Sipchem and Hanwha Corp. of South Korea. The 200,000 metric-tpy plant will be built at Sipchem’s site in Jubail Industrial City, Kingdom of Saudi Arabia, as part of Sipchem’s third-phase project. The project is targeted to be commissioned in 2013.

Asia-Pacific FasTech Srl has licensed its proprietary technology to manufacture high-cis polybutadiene rubber, based on the neodymium catalyst, to a petrochemical operator in East Asia. The license agreement includes engineering and other technical services.

This is the second neodymium polybutadiene rubber (Nd-BR) technology licensed by FasTech. The first one was granted to a petrochemical company based in the Middle East. The engineering work for a 45,000-tpy plant to be built in the region is in progress. FasTech, a technology and engineering company based in Ferrara, Italy, offers several synthetic-rubber and petrochemical technologies.

China Blue Chemical Co. Ltd. and Davy Process Technology, a Johnson Matthey Co., have announced the successful startup, performance test and plant acceptance of a 2,500 metric-tpd methanol plant in Hainan Island, China. The plant produces chemical-grade methanol that will supply the domestic Chinese market and also be available for export.

The plant was completed in 31 months from start of the contract. Its success is reportedly due to the excellent team work and co-operation between Davy Process Technology and Johnson Matthey Catalysts—as technology licensors and catalysts suppliers; China Blue Chemical Co., Ltd.,

the owner/operator; and Chengda, the Chinese Design Institute that performed the detail engineering and construction management.

Toyo Engineering Corp. (TOYO) and Hitachi, Ltd., have been appointed by Eastern Star Gas Ltd. (ESG) to undertake front-end engineering and design (FEED) for ESG’s LNG Newcastle (LNGN) project upon completion of feasibility studies that have been conducted since May 2010. ESG plans to determine its investment by the first quarter of 2012 and to start exporting products in 2015.

FEED work will be completed by the fourth quarter of 2011 and will involve optimization, design and detailed costing of the LNGN project, including the LNG storage tank, jetty and loading facilities.

TOYO and Hitachi will be closely supported by Chart Energy & Chemicals, Inc., which will provide IPSMR process technology and core equipment for the gasliquefaction process.

Uzbekistan is investing $1.2 billion on the upgrade of a polyethylene gas-chemical complex at a state-owned plant in Mubarek to 400,000 tons. It is reported that the project, to be financed jointly with Singapore’s Indorama group, will have $150 million from national gas company Uzbekneftegaz and $600 million from Indorama, while the Uzbekistan Fund for Reconstruction and Development will contribute $450 million. Upgrade of the plant, built in 1971, is expected to be completed by 2015.

This project constitutes part of the Uzbek government’s economic plan to stimulate investment in the country.

Technip, in a consortium with Daewoo Shipbuilding & Marine Engineering Co., Ltd., has been awarded a front-end engineering and design (FEED) contract for a floating liquefied natural gas (FLNG) unit by PETRONAS and MISC Berhad.

The FLNG, which will have a capacity of 1 million tpy, will be located in Malaysia.

Technip’s operating centers in Paris, France, and Kuala Lumpur, Malaysia, will execute the contract, which is scheduled to be completed by the second half of 2011.

BP is proceeding with a major increase in purified terephthalic acid (PTA) production capacity at the BP Zhuhai Chemical Co., Ltd., site in Guangdong Province, China, a joint venture between BP and

Zhuhai Port Co., Ltd. (formerly named Fu Hua Group). BP is also planning to build a new world-scale PTA plant at the same site.

The planned debottleneck at Zhuhai will increase capacity by more than 200,000 tpy from its second unit (Z2), making the total PTA production capacity of the Zhuhai site some 1.7 million tpy. BP has completed engineering design work for the Z2 debottleneck and expects the expansion to be fully operational in the first quarter of 2012.

A new third PTA plant in Zhuhai is under pre-engineering planning. With a capacity of 1,250,000 tpy, it will be the first to use BP’s latest generation PTA technology. Subject to approval from its shareholders and relevant Chinese government agencies, it is expected to come onstream at the earliest by 2014.

Evonik Industries and Gujarat Alkalies and Chemical Ltd. (GACL) are planning a new multimillion project. At its heart is the construction of a new hydrogen peroxide production plant by Evonik and a propylene oxide facility by GACL. The aim is to produce propylene oxide using the environment-friendly hydrogen peroxide to propylene oxide (HPPO) process developed jointly by Evonik and Uhde.

Representatives of Evonik and GACL have now signed a memorandum of understanding (MOU) on the proposed project in Dahej in the state of Gujurat, India. The project is contingent upon the approval of Evonik Industries’ executive and supervisory boards. The MOU is expected to mark the start of a close and lasting collaboration between Evonik and GACL, that intends to acquire a license from Evonik and Uhde to use the HPPO process to produce propylene oxide.

Mitsubishi Heavy Industries, Ltd. (MHI) has signed a license agreement for carbon-dioxide (CO2) recovery technology with National Fertilizers Ltd. (NFL), a state fertilizer company in India. NFL will use the technology to increase urea production at its existing Vijaipur plant in Guna District, Madhya Pradesh State. The recovery units can capture 450 metric-tpd of CO2, reportedly one of the world’s largest capacities. The CO2 recovery plant is slated for completion in June 2012. Mitsubishi Corp. is handling the trade particulars.

The CO2 recovery plant will be constructed by Tecnimont ICB Pvt. Ltd. at NFL’s Vijaipur plant, which already consists of two trains of ammonia-urea plants. HP HYDROCARBON PROCESSING APRIL 2011

I 27

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor

IPIC Undefined

Jorf Lasfar Hoima

Jorf Lasfar Hoima

Refinery Refinery

China BlueChemical Indian Oil Corp Ltd PT Tri Polyta Indonesia Byco Oil Pakistan Limited

Hainan Island Gujarat Cilegon Karachi

Hainan Island Gujarat Cilegon Karachi

Methanol Refinery Terminal, Gas Sulfur Recovery Unit

Syncrude Canada Ltd Murphy Oil Co Ltd

Fort McMurray West Tupper

Fort McMurray West Tupper

Sulfur Emission Reduction Gas Plant

Croatia Italy Italy Italy Netherlands

INA Industrija Nafte Raffineria di Gela SpA SARAS SpA Eni SpA Gate Terminal BV

Rijeka Gela Sarroch Taranto Rotterdam

Rijeka Gela Sarroch Taranto Maasvlakte

Desulfurization Hydrogen Cracker, Visbreaker (2) Hydrocracker LNG Terminal

RE

None 120 m-tpd None 15 Mbpd 12000 Mm3/y

539 C A C C 1150 U

2011 2011 2010 2010 2011

Poland Poland Spain Spain

Polskie LNG Anwil SA SAGGAS Repsol YPF

Swinoujscie Wloclawek Sagunto Tarragona

Swinoujscie Wloclawek Sagunto Tarragona

LNG Terminal Utilities LNG Storage Crude Unit

5 BNm3/y None EX 150 Mm3 150 bpd

E C 110 U 17 M

2014 2010 2011 2011

Camisea Talara Talara

Camisea Talara Talara

Nat Gas Liquids Cogeneration Distillation, Crude

RE

Mesaieed Al Jubail Jazan Jubail Marjan Yanbu Yanbu Aliaga

Mesaieed Al Jubail Jazan Jubail Ind City Marjan Yanbu Yanbu Aliaga

Ethylene Hydrogen (2) Refinery Ethyl Acetate Petrochemical Complex Clean Fuels Mercaptans Polyethylene, LD (2)

EX 720 132 400 TO 100 1650 400 12 TO 144

Bakersfield Benicia Rodeo Denver Lake Charles Pascagoula

Bakersfield Benicia Rodeo Commerce City Rfy Lake Charles Pascagoula

Cogeneration FCC Residue RE Coker, Delayed RE Cracker, FCC Reactor/Regenerator Coker, Delayed Lube Oil Plant

Engineering

Constructor

SAMIR

Tekfen Constr|SAMIR

AFRICA Morocco Uganda

250 bpd 60 bpd

5000 P 2000 P 2015

FW

ASIA/PACIFIC China India Indonesia Pakistan

2.5 m-tpd EX 274 bpd 1.7 Mtpy None

C 2011 1.029 P 2014 150 P 2014 2011

Davy Process|JM

Chengda Eng EIL

1600 U 2012 180 C 2011

URS Corp - Washington Div

URS Corp - Washington Div Gas Liquids Eng TAHK Projects Ltd

Haldor Topsøe

Techint Shell Global Snamprogetti|CLG Sener|Vinci Construction Techint SpA|ENTREPOSE Techint SpA|Saipem Chemeko Sener

ENTREPOSE|Techint SpA Vinci Construction |Sener

PlusPetrol Peru

Tecna Tecnicas Reunidas Tecnicas Reunidas

Tecna Tecnicas Reunidas Tecnicas Reunidas

Technip KTI

Shaw Tecnicas Reunidas

Tecnicas Reunidas

Exxon Cheml Co Haldor Topsøe

Burckhardt Compression Haldor Topsøe WorleyParsons Tecnicas Reunidas Technip

Vopak

CANADA Alberta British Columbia

150 t/a 180 MMcfd

EUROPE CLG Saipem|Techint ILF Consulting Engineering

Techint FW

Cobra|Sener

LATIN AMERICA Peru Peru Peru

PlusPetrol Peru Petroperu Petroperu

520 MMscfd None None

143 U 2012 E 2014 E 2014

MIDDLE EAST Qatar Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Turkey

QAPCO Saudi Aramco\Total JV Saudi Aramco Sipchem Marjan Petrochemical SAMREF Saudi Aramco Petkim Petrokimya Hldg

kty Nm3/h bpd m-tpy t/a None bpsd Mm-tpy

E E 1000 F U 212 U 200 F E U

2011 2013 2015 2013 2015 2013 2014 2011

35 5 6 10

2012 2011 2011 2011 2012 2013

Conoco Phillips Co SABTEC

Tecnicas Reunidas

UNITED STATES California California California Colorado Louisiana Mississippi

San Joaquin Rfg Co Valero Refining Co ConocoPhillips Suncor Energy Inc ConocoPhillips Chevron USA Inc

20 MW bbl bbl bbl bbl 25 Mbpd

E C U U P 1400 U

TJCROSS Engineers Anvil

Shaw AltairStrickland AltairStrickland AltairStrickland AltairStrickland

Chevron USA

BOXSCORE DATABASE

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning.

Now, we’ve made our best product even better!

Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects.

For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

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I APRIL 2011 HYDROCARBON PROCESSING

Select 158 at www.HydrocarbonProcessing.com/RS

“Advertisement”

Sulzer Chemtech

Tower Technical Bulletin Maximizing Diesel Recovery in Your Columns

Background Increased demand for automotive diesel is challenging refiners to adjust operating strategies to maximize middle distillate production. While some refiners choose to alter catalyst formulations or build new cracking units to increase diesel yields, optimizing the separation between gas oil and distillate in existing columns can be an excellent opportunity with little or no investment.

Areas of Opportunity to Optimize Diesel Cuts Diesel streams are drawn from the primary fractionators in the Atmospheric Crude, Vacuum, FCC, Coker, and Hydrocracker units. These cuts can be further treated and blended into the refinery diesel pool.

Product overlaps between the middle distillate and gas oil cuts in these columns can contribute to a significant portion of refinery gas oil volumes. Shrinking these overlaps is a major target for refinery operations.

Sulzer proposed two options to help improve diesel recovery: 1.

2.

Replace the conventional trays in the wash section with a higher number of Sulzer VGPlus trays with a shorter tray spacing.

Replace the conventional trays in the wash section with Sulzer Mellapak structured packing.

The wash section modifications were coupled with similar recommendations for the diesel–heavy gas oil fractionation section and an optimized design of the bottoms stripping section with Sulzer VGAFTM high capacity trays with anti-fouling properties.

These proposed options promised a decrease of in the dieselgas oil overlap and the loss of light product to the Vacuum unit, with an overall improvement in diesel recovery of over 1.0% of crude feed.

Targeting the Maximum Distillate Recovery Increasing distillate recovery and improving the separation between products can be accomplished through several strategies, as follows: -

Increase vaporization (higher flashing temp) Reduce over-flash rate Improve bottoms stripping Increasing the number of theoretical stages

The balance of heat and pumparound duties in the column required to achieve those conditions most often requires higher hydraulic capacity and / or improved stage fractionation efficiency.

Increasing hydraulic capacity and fractionation efficiency in diesel fractionation and bottoms stripping sections is possible with the help of the Sulzer design engineers and the installation of high performance mass transfer internals such as Sulzer VGPlusTM High Capacity Trays or Sulzer MellapakTM or MellapakPlusTM Structured Packing.

A Shrinking Gap Example In one refinery’s Crude Atmospheric column, the capacity of the wash section and the AGO/Diesel fractionation section were limiting the boardman’s ability to raise fired heater outlet temperatures. The design of this wash section with basic two-pass moveable valve trays also limited the separation efficiency. The refinery noted that the Vacuum unit feed heater was hydraulically limited and the vacuum overhead distillate yield was high.

The Sulzer Refinery Applications Group Sulzer Chemtech has over 50 years of operating and design experience in refinery applications. We understand your process and your economic drivers. Sulzer has the know-how and the technology to provide a scrubber internals design with reliable, high performance.

Sulzer Chemtech, USA, Inc. 8505 E. North Belt Drive | Humble, TX 77396 Phone: (281) 604-4100 | Fax: (281) 540-2777 TowerTech.CTUS@sulzer.com www.sulzerchemtech.com

Legal Notice: The information contained in this publication is believed to be accurate and reliable, but is not to be construed as implying any warranty or guarantee of performance.

Sulzer Chemtech waives any liability and indemnity for effects resulting from its application.

Select 68 at www.HydrocarbonProcessing.com/RS

Ask Kobelco! The Best Solution for Any Gas Compression.

The Best Compressor for Hydrogen Service Kobelco Screw Compressors With suction/discharge pressures up to 1500 psig (100 barg), Kobelco oil-injected screw compressors are excelling in many hydrogen applications, including: gasoline desulfurization diesel desulfurization hydrotreating

steam methane reformer PSA dissociation process

They are also ideal for other process gas services, such as fuel gas boosting for gas turbines, natural gas, coke oven gas, PP and PE process gas, helium and more.

The screw design is inherently reliable and can operate continuously for more than five years. Lube oil injected into the compressor acts as a sealant, lubricant and coolant – allowing the compressor to operate more efficiently with hydrogen and other low molecular weight gases.

Kobelco screw compressors are the environmental choice, too. They reduce power consumption, eliminate emissions and decrease noise, pulsation and vibration.

Kobelco manufactures screw, reciprocating and centrifugal compressors, allowing us to provide the optimum technology for you.

Kobelco EDTI Compressors, Inc. Tokyo +81-3-5739-6771 Munich +49-89-242-18424 www.kobelco.co.jp/compressor

Houston, Texas +1-713-655-0015 rotating@kobelcoedti.com www.kobelcoedti.com

Select 73 at www.HydrocarbonProcessing.com/RS

PETROCHEMICAL DEVELOPMENTS

SPECIALREPORT

Optimize cracked-gas compressors with smart-automation technology Machine health monitors can provide critical information to avoid unit and plant-wide shutdowns P. COX, Emerson Process Management, Brussels, Belgium

T

he cracked-gas compressor (CGC) is the single most critical piece of equipment in an ethylene plant (Fig. 1). This asset can cost as much as $50 million and operates 24/7 under demanding conditions. Because it has no backup, ethylene producers know that if their CGC trips—whether the trip is caused by excess vibration, a surge, an instrument malfunction or other problems—their entire ethylene process may be halted for up to a week.

Compressor operation must be fine-tuned to maximize performance and reduce spurious trips that result in downtime and unnecessary maintenance. By increasing operating efficiency, boosting unit availability and production, and reducing maintenance costs, producers can increase their ethylene plant’s throughput to meet market demands. But several challenges lie between the producer and attaining those goals.

compressors farther away from the surge line. Such actions prevent optimal operation and cause unnecessary energy consumption.

Fouling issues. The 108 ethylene plants polled in the survey, which are responsible for 62% of the world’s production, named compressor fouling as the second most frequent cause for compressor failure. The inevitable compressor blade fouling by the cracked-gas process leads to a blade imbalance that causes excess vibration and compressor trip.

Blade fouling also causes energy efficiency losses as great as 1%. For turbo-machinery, that can use up to 70 megawatts of power and translates into annual losses of $300,000. This is a controllable loss, but the decision to wash fouled blades to gain energy efficiency or to stop vibration must be an informed one or operators risk poorly timed maintenance that unnecessarily reduces throughput.

Challenges. Results of an olefin-compressor reliability survey

Mechanical problems. Surveyed producers also identified presented at the 2008 Ethylene Producers’ Conference highlight mechanical problems as causing the longest tripped compressor several of these issues.1 Producers named instrument problems as downtime. Operators need reliable, predictive diagnostics about the major cause for compressor trips. The ethylene production machinery health to detect shaft misalignment and cracks, couprocess itself is inherently tough on such devices. Probes become dirty and are subjected to extreme temperatures. This can result in measurement inaccuracies (i.e., drift) in temperature, flow and pressure signals from the process—all vital information used to calculate the proximity to the compressor’s surge line and its safe, optimal operating capacity.

When instruments drift—even by as little as 1%—operators cannot accurately assess actual compressor flow. Drifting instruments result in a reading that deviates from reality. If the reading is too low, then it could activate the antisurge system, leading to production loss. If the reading is too high, then the operation could be closer to the surge line than operators believe and the compressor can start to surge. This is likely to lead to compressor damage—and potentially extended downtime. Without FIG. 1 The cracked-gas compressor is an ethylene plant’s most critical asset. (Photo courtesy confidence in instrument readings, operaof Elliott Co.) tors afraid of causing a surge will run their HYDROCARBON PROCESSING APRIL 2011

I 31

SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

pling failure and bearing oil instability so they can act quickly to avoid a compressor trip or, worse, a catastrophic failure (Fig. 2).

If the compressor trips, operators have a 10- to 30-minute window during which they must assess the trip’s cause and determine whether it’s safe to restart the machine. After that, the rest of the plant will move too far from its normal operating conditions and the process will be saturated. A compressor shutdown has a domino effect on the rest of the plant that can necessitate product flaring and even a full plant shutdown for up to a week.

Spurious trips can be problematic, but a compressor surge must be avoided at all costs. Operators must rely on the compressor’s antisurge valve reaction time, which utilizes a dedicated control system, to both optimize process operations and react quickly and accurately to prevent surge. In case of an emergency, the antisurge valve may have to travel up to 20 in. within 0.75 seconds. Unless it is very tightly controlled, such a large stroke in a short time could cause the valve to overshoot.

Because this important turbomachinery rotates at very high speed, the situation degenerates rapidly when things start to go wrong. The control room needs an API 670-compliant machinery health-protection system to ensure a safe compressor train shut down to protect assets and personnel, and to minimize flaring.

Financial performance

Theoretical maximum availability

Scheduled downtime

Spurious compressor trips

Target availability Possible availability improvement Break even

Time

FIG. 2

FIG. 3

32

Increase compressor uptime by avoiding spurious trips and extending the time between scheduled downtime.

Solutions. Contemporary automation technology lets ethylene producers meet these multiple challenges head-on. Plant operators can safely maximize throughput, gain energy efficiencies and reap maintenance cost savings by using a combined automation strategy that includes a smart digital machinery health- and assetmanagement system; a robust, high-performance antisurge valve; and reliable, accurate instruments.

Machinery health monitoring and asset management.

Producers can benefit by using a machinery health- and assetmanagement system that integrates protection capabilities with predictive diagnostics and performance monitoring to improve compressor availability, protect this valuable asset, tighten energy efficiency, reduce maintenance costs, improve throughput and decrease environmental costs. The field-based diagnostics provided by these systems give operators the ability to recognize faults many months in advance and to prevent excess vibration, mechanical breakdowns and compressor trips. Whether it’s a shaft misalignment, a cracked shaft, a coupling failure, bearing wipe, oil instability, excess imbalance or blade fouling, operators and maintenance staff have the information that they can use to take corrective actions. This reduces maintenance and improves throughput, and if a trip can be avoided because of early machinery health information, it provides real machinery health protection—safeguarding the plant’s bottom line.

If a trip does occur, the monitor delivers a rapid transient analysis of all vibration waveforms collected before, during and after the event. Its ability to analyze and replay the event assists with diagnosing the mechanical problems that led to the trip.

Operators can quickly determine whether the machine suffered a severe mechanical problem and can assess whether it can be restarted before other plant areas are adversely affected. These monitors prevent false machine trips by monitoring sensor health and networking with intelligent field instrumentation tuned to automatically recognize bad cables and sensors, adjust trip logic and notify operators so action can be taken.

Critical information in realtime. In addition, the technol-

The intuitive graphics allow the operator to easily check rotating-equipment efficiency by viewing current process and alarm data along with diagnostic data and any predictions of impending problems.

I APRIL 2011 HydrocarbonProcessing.com

ogy helps plants avoid catastrophic failure by continuously measuring critical information about machinery operation, including relative and absolute vibration, thrust position, case and differential expansion, shaft eccentricity, temperature and speed.

By applying these measurements, the system conforms to API 670 machinery-protection standards for compressor trains and allows for safe shut down when unsafe operating modes occur. Critical assets and personnel are protected, flaring is minimized, and insurance requirements are met.

The performance-advisor feature of this automation technology allows for lower operational cost through improved process control and energy use. Operators can view key performance indicators—such as compressor efficiency, blade fouling, head generation, power consumption and operating costs—to easily see if the compressor train is running within its optimal operating window. They can even drill down to

PETROCHEMICAL DEVELOPMENTS

• Have an air-cushioned actuator that tightly controls deceleration to protect valve and actuator components • Are specially designed to reduce noise by up to 40 dBA, and to protect the compressor and piping system from damaging vibration Process limit

Surge line

Actual available operating zone

Rc

check performance of specific compressor sections and compare actual to design (expected) efficiency. In addition, automation partners experienced with this tool can tune the performance advisor system to accommodate seasonal or operational variations that affect the process.

Contemporary machinery health- and asset-management technology can be easily integrated into an existing control system. Because it provides native systems with intuitive graphical interfaces presented in a format that ethylene-plant operators recognize, they can make fast, accurate decisions. For example, when operators perform an online water wash in response to compressor fouling, they receive real-time feedback about performance increases as well as machinery health monitoring data alerting them to blade cracking that can commonly occur during this sensitive process. The machinery health- and asset-management data covering the 4Ps of machinery monitoring—protection, prediction, performance and integration with process—is made available directly from the plant’s existing control system through user-friendly screens, and without the need for extra engineering (Fig. 3).

SPECIALREPORT

Antisurge valves. Because of the critical role that the

antisurge valve plays in preventing surge, it is the most vital valve on the ethylene plant’s important asset. The best control valves today have been engineered to be accurate and reliable and to respond quickly. These smart valves also have built-in features that protect the critical asset and ensure that it performs accurately under the most demanding conditions. Optimized antisurge valves:

Stable zone of operation Qs, volume FIG. 4

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HYDROCARBON PROCESSING APRIL 2011

I 33

SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

• Have fine control and rapid, accurate stroke response to prevent surge • Deliver diagnostic information that uncovers problems such as dirty instrument air, actuator and tubing leaks, insufficient air supply, I/P integrity and worn-out instrument elastomers—all without the need to move the in-service valve • Capture additional diagnostic data—while the valve is moving—to determine potential valve blockage, plug binding, broken or loose linkages, poor calibration or valve friction issues.

These multiple features deliver confidence to operators who know they can rely on the valve to perform, when needed, as they operate as close to the surge line as possible. The larger the CGC, the greater the operational costs savings.

And because downtime equals lost production, it’s important to note that these valves can be easily commissioned and tuned remotely within minutes and they require only half the usual actuation accessories compared to most traditional systems. When there are problems with the valve, the performance diagnostics will help operators quickly diagnose the root cause (Fig. 4).

Intelligent, accurate instruments. Smart digital instru-

ments can assist ethylene producers by delivering accurate, integrated pressure, temperature and flow data—critical data for efficient and safe operation close to the surge line. Intelligent devices bring reliability, repeatability and stability to this process.

Calculating your position relative to the compressor’s surge line is only as reliable as the data it’s calculated with. Precise flow calculations are possible with data delivered from a number of robust, smart instruments that offer advanced diagnostic capa-

bility, rapid operating speed and hot backup.

• Smart flowmeters—Using the latest-generation innovative flowmeters on your compressor makes a big difference. Devices with a very high-speed update rate of 22 times per second are now available. They provide rapid insight into surge-line proximity. In addition, statistical process monitoring and advanced diagnostics allow for rapid identification of flow reversal, alerting the process operator to problems with the antisurge control system.

• Integrated flowmeter with a conditioning orifice plate—For installations with insufficient space for piping, flow-conditioning orifice plates are available. This device requires a much shorter pipe length for accurate measurement than a conventional orifice plate (2x pipe diameter upstream and downstream). Enhanced control is also enabled through the flow correction provided by this device. It measures differential pressure, temperature and operating pressure to arrive at the volumetric flow.

• Temperature transmitters with hot backup—The redundant temperature measurements taken by this device automatically detect instrument drift or failure. Its inherent hot-backup feature allows operators to switch control or monitoring to the healthy sensor without need to shut down the process to replace the device. HP 1

LITERATURE CITED Shah, R., ”Olefins compressors’ reliability performance survey results,” 2008 Ethylene Producers’ Conference.

Peter Cox is the global chemical industry leader at Emerson Process Management for the past three years. Previously, he was employed with BASF for 15 years at its Antwerp location, where he held positions in maintenance, engineering and operations. Mr. Cox is located in the Diegem office in Brussels, Belgium.

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PETROCHEMICAL DEVELOPMENTS

SPECIALREPORT

Improve evaluations for your industrial gas needs Petrochemical and refining complexes are major consumers of industrial gases; here are some tips in planning process-gas needs G. H. SHAHANI and R. KOEHLER, Linde Engineering, Blue Bell, Pennsylvania

Gas production technologies.

Cryogenic air separation was first demonstrated on a commercial scale in 1902. Since then, the technology has been constantly improved to reduce cost and to increase reliability and flexibility. Using advanced engineering techniques, including proprietary process simulation, and modern fabrication techniques, it is possible to build air separation plants that are both low cost and high quality. Now, hydrogen (H2), carbon monoxide (CO) and syngas plants can be designed to handle the entire gamut of hydrocarbon feedstock from natural gas, LPG, refinery offgases, naphtha up to heavy fuel oil, and asphalt. These technologies are steam reforming with pressure swing adsorption (PSA) systems for light

hydrocarbons and partial oxidation (PO) followed by shift, desulfurization and purification for heavy hydrocarbon feedstocks.

Turnkey air separation and hydrogen plants can deliver a complete solution so that the refiner or petrochemical producer can focus on their core business. By using global procurement and construction capabilities, it is possible to reduce cost and optimize project execution, thereby making industrial gas plant procurement simpler and cheaper for the refining and petrochemical sectors.

Background. Under the present gloomy

economic environment, it is easy to forget that world gross domestic product (GDP) has more than doubled in real terms during the last 30 years. While current market turbulence may continue, the long-term trend is unmistakably upward. Living standards are rising all over the world, thereby creating demand for food, clothing, transportation and housing. This translates into tremendous demand for products from the refining and petrochemical sectors. New capacity and plant expansions will be necessary in the future. These investments, which typically

have a life span of 30+ years, will have to be based on long-term economic considerations rather than present market conditions.

A good indication of volatility in the refining and petrochemical sector is depicted by the price of crude oil (Fig. 1) and natural gas (Fig. 2). Crude oil, which peaked at over $140/bbl in mid-2008, has stabilized at approximately $70/bbl–$80/ bbl. Natural gas has been even more volatile than crude oil. It peaked at over $14/ MMBtu and has subsequently declined to around $4/MMBtu. Similar fluctuations in the pricing of petrochemical “building block compounds” such as naphtha, benzene, ethylene, propylene and butadiene have exacerbated market turmoil, making investment decisions difficult.

The challenge for the refining and petrochemical sectors is to manage through the peaks and valleys in the economy to make informed investment decisions. Typically, investments made at the bottom of an economic cycle perform better than those made at the top of a cycle. Since capital is relatively scarce during economic downturns, these investments must be carefully conceived, developed and executed.

Weekly US spot price FOB weighted by estimated import volume

140 120 Dollars per barrel

T

he present refining and petrochemical sectors are being impacted by highly fluctuating supply/demand conditions, extreme price volatility and tremendous market uncertainty on a worldwide basis. There have been innumerable plant closings, project cancellations and employee layoffs.

In particular, large consumers of industrial gases (oxygen, nitrogen, hydrogen, carbon monoxide and syngas) must make informed investment decisions during uncertain economic times. Petrochemical plant owners/operators must carefully examine their individual industrial gas needs to develop the most economical industrial gas plant configuration.

All industrial gas needs, as well as steam and utility requirements in conjunction with available feedstock and waste streams are considered to develop the best possible long-term solution. Industrial gas requirements have to be examined over a longterm horizon in a holistic manner.

100 80 60 40 20 0 1980

1985

1990

1995

2000

2005

2010

Source: US Energy Information Administration

FIG. 1

Average weekly spot price for crude oil.

HYDROCARBON PROCESSING APRIL 2011

I 37

Dollars per thousand cubic feet

SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

12 10 8 6 4 2 0 1975

1980

1985

1990

1995

2000

2005

2010

Source: US Energy Information Administration

FIG. 2

Monthly US wellhead natural gas prices.

TABLE 1. Industrial gases in refining and petrochemicals Oxygen

Hydrogen

Carbon monoxide

Syngas

Oxygen-enriched air

Ethylene oxide

Ammonia

Acetic acid

Methanol

Terephthalic acid

Propylene oxide

Aniline

Formic acid

Oxo-alcohols

Vinyl chloride monomer

1,4 Butanediol

Polycarbonates

Vinyl acetate

Caprolactum

Phenol

Hydrotreating

2-Ethylhexanol

Isophthalic anhydride

Hydrocracking

Hexamethylenediame (HMDA)

Sulfur recovery

Hydrogen peroxide

Fluid catalytic cracking

Maleic anhydride Acrylonitrile

Isononyl alcohol Toluene diamine (TDI)

Industrial gases in petrochemicals.

The refining and petrochemical industries consume large quantities of industrial gases —oxygen (O2), nitrogen (N2), H2, CO and syngas. Oxygen requirements include: oxygen-enriched and oxy-fuel combustion, hydrocarbon oxidation, wastewater treatment, gasification and power generation.

Nitrogen is used for inerting and blanketing in chemical processes. Hydrogen is used for refining crude oil. In addition, H2, CO and syngas are used in various chemical synthesis reactions. Table 1 summarizes the major industrial gas applications in refining and petrochemicals.

The process plants that produce these gases are capital intensive. Air-separation plants require significant electrical power.

For example, H2, CO and synthesis gas plants require a hydrocarbon feedstock such as natural gas or naphtha. In both cases, utilities like cooling water are required. Given 1

2 3 4

38

On a volumetric basis, the composition of air is: 78.08% nitrogen 20.95% oxygen 0.93% argon Balance neon, helium, krypton and xenon For air, this is –221°F and 37.2 atm For certain applications, extremely high purity nitrogen with less than 0.1 ppb O2 is necessary.

It may be recalled that the first ASU built in 1902 was only 0.1 tpd in capacity.

I APRIL 2011 HydrocarbonProcessing.com

that these plants entail large investment, it is very important to understand the present and future costs of energy. This is essential to make the appropriate trade-off between capital cost and energy consumption.

In particular, large consumers of industrial gases all have to make informed investment decisions in this uncertain economic environment. Petrochemical plant owners/operators must carefully examine their industrial gas needs to develop the most cost-effective industrial gas plant configuration. This can be done by partnering with an experienced engineering company that owns a complete technology portfolio for producing O2, N2, H2, CO and syngas. Ideally, the engineering and manufacturing companies have to work together as a single team to identify the most efficient and economic plant design. This includes an in-depth assessment of capital and operating costs to deliver an optimal solution, taking plant reliability and process safety into account.

All the industrial gases, as well as steam and utility needs at a given manufacturing complex, in conjunction with available feedstock and wastes must be evaluated to develop the best possible long-term solution. These industrial gas requirements should be examined over a long-term in a holistic manner.

Air separation unit. The large quantities of atmospheric gas (O2, N2) required in most refining and petrochemical applications are most cost-effectively produced by cryogenic air-separation units (ASU).

In this process, air1 is separated into its components by distillation. This necessitates first liquefying air by operating at less than the critical point for air.2 In simple terms, air is cooled by reducing pressure according to the Joule-Thompson effect.

For one atmosphere decrease in pressure, air cools by approximately 0.5°F. Liquefied air is separated into its components by distillation. Typically, for energy efficiency, heat exchange between feed and products is maximized (Fig. 3).

This technology was first demonstrated at a commercial scale in 1902 by Carl von Linde in Munich, Germany. The first ASU was only approximately 0.1 tpd in capacity. It was manually operated and produced only gaseous oxygen (GOX). Today’s largest plants are four orders of magnitude (104) bigger, fully automated and produce multiple products including: gaseous and liquid oxygen (GOX and LOX), gaseous and liquid nitrogen (GAN and LIN) as well as gaseous and liquid argon (GAR and LAR) and other rare gases such as neon (Ne), krypton (Kr) and xenon (Xe) at different purities3 and pressures. It is important to consider all of these products in defining the scope of the most cost-effective ASU. The size of an ASU is usually described in terms of its O2 capacity. Plants that produce both gaseous and liquid products are known as piggy-back plants. The capacity of these plants is denoted by two numbers, namely GOX/total liquid. For example, a plant described as 300/500 produces 300 tpd of GOX and 500 tpd of LOX and LIN. Improvements in mature technologies such as cryogenic air separation are being constantly made to reduce cost and improve reliability and flexibility. Using advanced engineering techniques, including proprietary process simulation and modern fabrication techniques, it is possible to build air-separation plants that are both low-cost and high-quality at the same time. Recent improvements include: • Advanced structured packing • Modern compressors • High-efficiency heat exchangers • Internal compression (liquid pumping) • Advanced process control.

Structured packing reduces pressure drop and improves turn-down capability. Modern compressors and efficient heat exchangers reduce power consumption. Internal-liquid

PETROCHEMICAL DEVELOPMENTS pumping allows efficient product compression. Finally, advanced process control permits dynamic simulation and automatic load change with minimal onsite labor. Further improvements to the material, machinery, technology and engineering practices used in ASUs are expected to continue.

For example, an ASU, producing up to 69,000 tpd4 of high-pressure N2 from five separate trains for enhanced-oil recovery in Mexico is shown in Fig. 5. This plant was executed as a lump-sum, turnkey project in two phases: Four trains were built in 2000, when oil was relatively cheap after 2000, with a fifth train added in 2006. As oil prices increased to $70/bbl–$80/bbl, such projects are expected to deliver a good return on investment.

catalytic steam reforming is usually the preferred technology. If the desired product is CO or syngas and the feedstock is a heavier hydrocarbon (fuel oil, petroleum coke or coal), then non-catalytic PO is usually the preferred technology. A simplified block flow diagram for an H2 plant based on steam reforming is shown in Fig. 6.

Inputs include hydrocarbon feed, fuel, demineralized water and combustion air.

Depending on the value of feedstock and the need for steam locally, different levels of heat integration can be applied to minimize fuel consumption. The impure H2 produced by steam reforming and the shift reaction is purified by PSA before compression to the desired pressure.

Fig. 7 is a photo of a recent state-of-the art H2 plant built in Chile. For efficient

SPECIALREPORT

project execution, it is essential to pay special attention to the key interfaces, such as the reformer furnace, PSA unit and steamgeneration equipment.

In HYCO production, it is usually advantageous to examine different offgases available at a refinery for use as fuel

FIG. 5

Large ASU operating in Mexico.

Hydrogen, CO and syngas. It is common to refer to H2, CO and syngas (CO + H2) as HYCO. These products can be produced from either light or heavy hydrocarbons using steam reforming or PO. The overall reactions can be represented in a simplified form as:

Steam reforming (catalytic) CH4 + H2OjCO + 3H2 Endothermic CO + H2OjCO2 + H2 Exothermic Partial oxidation (non-catalytic) CnHm+ n⁄2 O2jnCO + m⁄2 H2 Exothermic The technology choice depends to a great extent on the available feedstocks and desired products. If the desired product is H2 and the feedstock is a light hydrocarbon (natural gas, LPG or naphtha), then

FIG. 4

Key components of ASU.

Double column Pure nitrogen

Fuel

HP steam

Liquid N2

Hydrogen

Pure oxygen

Condensor

Combustion air

Process air

Liquid with 35-40% O2

FIG. 3

Cryogenic air separation flow diagram.

Feed LP steam Demineralized water FIG. 6

Flow diagram of steam reforming in H2 production.

HYDROCARBON PROCESSING APRIL 2011

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SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

or feedstocks. As a percentage of the unit cost, feedstock is typically well over 50% of the unit cost of HYCO products. Therefore, the feedstock and technology have to be carefully selected, while keeping future flexibility in mind.

Cost competitiveness. The cost of producing industrial gases is a primary consideration for most owner-operators. Table

FIG. 7

Large HYCO plant operating in Chile.

2 lists the important cost considerations for an industrial gas complex. While some plant owner/operators may focus on initial capital cost, others pay equal attention to annual operating expenses. In reality, both capital and operating costs are important.

For a rigorous assessment, it is ultimately worth examining the unit cost of the industrial gas. This captures both capital and operating costs in a single metric that can be optimized as a function of size, scope and location.

In such evaluations, it is very important to consider the co-products that can be produced from a single process plant. In general, producing multiple products such as GOX, GAN, LOX, LIN and LAR from an ASU, or H2, CO, CO2, syngas, steam and electricity from a HYCO plant reduces the unit cost for each product. Producing multiple products from a single production plant can be very cost-effective, since the fixed capital and variable operating costs increase only incrementally. Furthermore, these increased costs can be allocated to multiple

TABLE 2. Design considerations for an industrial gas complex Cost

Other

Capital cost

Utility

Process cycle

Water availability

Size of plant

Electricity

Modularity

Final review. Ideally, it is important to

work with an engineering company that owns a complete portfolio of industrial gas technologies and functional engineering capabilities. Such a partnership can quickly identify the best solution for a given situation. By drawing on experience gained from hundreds of projects, it is possible to quickly optimize a given requirement.

Turn-key air separation and H 2 plants deliver a complete solution so that the refiner or petrochemical producer can focus on their core business. By using global procurement and construction capabilities, it is possible to reduce cost and improve project execution, thereby making industrial gas plant procurement simpler and cheaper for the refining and petrochemical sectors. HP

Stream

Infrastructure (cooling water, electrical) Operating costs (Energy/power)

Operations Reliability

Purity

Availability

Pressure

Time to full production

Liquid products

Turndown

Plant optimization Capital/energy trade-off Local cost of energy

Engagement

Labor and maintenance relatively minor costs

Stage I 1 year Pre-feasibility Market research Energy analysis Project scope Site screening

FIG. 8

40

Stage II 1 year Feasibility study Preliminary design Economic evaluation Project justification Authorization

Goutam Shahani is a business development manStage III 1 year Project development Request for quotation Estimate Proposal Permits

Timeline for typical project development for industrial gases.

I APRIL 2011 HydrocarbonProcessing.com

products, thereby reducing the unit cost of all products. To achieve this “sweet spot” it is essential to consider all possible scenarios early in project development. A high-level timeline of typical project development is presented in Fig. 8. Typically, a large, complex industrial gas plant can take up to five years from concept to startup.

During pre-feasibility (Stage 1), is important to consider all possible scenarios including co-products, alternative feedstock(s), capital vs. energy cost tradeoffs. As the project gets better defined, different process schemes can be examined in the feasibility stage (Stage 2). Once project development is authorized and permits are applied for in project development (Stage 3), further changes to scope should be resisted. While some changes may appear to be cost justified for a small portion of the project, usually these changes add cost to the overall project and delay the schedule. It is important to maintain discipline during project execution (Stage 4) as equipment is ordered and field work begins. Even the best conceived projects on paper can be disasters in the field if proper engineering work practices are not followed.

Stage IV 2 years Project execution Engineering Equipment Construction Start-up

ager for air separation plants for Linde Engineering North America. His prior positions include: VP of sales and marketing at HTI and commercial development manager at Air Products and Chemicals, Inc. Mr. Shahani specializes in the energy, refining and chemical industries. He holds BS and MS degrees in chemical engineering and an MBA.

Regina Koehler is lead process engineer in the HYCO business unit at Linde Engineering. She is an expert in hydrogen and synthesis gas generation, and in combustion technologies with experience in engineering, proposal development and plant operation. Ms. Koehler holds a Dipl.-Ing. in process engineering from Technical University in Clausthal, Germany.

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Results

Linde has built a history of proven results with over 250 synthesis gas plants and 2,800 air separation plants installed worldwide.

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PETROCHEMICAL DEVELOPMENTS

SPECIALREPORT

Better control-loop management lowers energy costs This petrochemical producer found improved output and became more energy efficient through new software G. MONTES and L. LANG, LyondellBasell, Channelview, Texas; and J. R. MAHLSTADT, Equistar, Houston, Texas

A

small team of LyondellBasell engineers at its plant in Channelview, Texas, helped this company save significant dollars in annual energy costs by addressing regulatory control-loop problems using a “control-loop monitoring” program. This program provided tools and methods for continuous process improvements.

forth, trying to get the intermediate fraction under control, as shown in Fig. 3.

Eliminate the obvious. Process control specialist Gilbert Montes was asked to look into the problem. According to Montes, “The APC controller models had been updated just a few weeks before the problem started. It seemed unlikely that there would

LyondellBasell Channelview facility. The LyondellBasell site in Channelview, Texas, produces a wide variety of petrochemical products (Fig. 1). This facility applies very energy-intensive processes. Separation of key components requires tall distillation towers with high reflux rates. To improve energy efficiency, LyondellBasell invested in advanced process control (APC) applications for the columns. Unfortunately, the results with the AP controllers were not always consistent.

Variable rates, variable results. Operators were initially

happy with the APC application. However, when asked to run at different feed rates, those changes led to severe upsets. Fig. 2 shows that, following a rate reduction, the reflux rate and steam flows started to swing wildly. The blue trace shows the reflux rate, and the red trace shows the steam flow. In an effort to regain control of the column, the operator had to disable the APC controller.

As expected, the distillation results followed the steam and reflux patterns. An undesirable intermediate byproduct is carried into the product stream. The column swings rapidly back and

FIG. 1

The LyondellBasell site in Channelview, Texas, produces a wide variety of petrochemical products.

FIG. 2

Column reflux and steam oscillate after rate reduction.

FIG. 3

Intermediate concentration swings and column response.

HYDROCARBON PROCESSING APRIL 2011

I 43

SPECIALREPORT

FIG. 4

FIG. 5

PETROCHEMICAL DEVELOPMENTS

Pressure control stabilized.

FIG. 7

Steam-flow reduction is almost immediate.

A detailed dashboard.

Oscillation details report.

be a model mismatch. We turned to our control-loop monitoring software.” This software monitors all of the plant’s control loops, 24 hours a day, applying engineering expertise and diagnostics to identify issues with instruments, valves and controller tuning.

Detailed dashboards, such as the one in Fig. 4, show all aspects of control-loop performance. Montes continued, “The reflux PID controller also showed no performance issues. Using a specific problem-solver report, we looked for all control loops oscillating at the same frequency.”

Finding the root cause. When the plant is oscillating, all loops affected by the oscillation will cycle at the same period. In 44

FIG. 6

I APRIL 2011 HydrocarbonProcessing.com

previous years, searching for oscillation sources was a tedious and time-consuming process: put suspect loops in manual and see if the oscillations subsided. If not, move upstream to another loop, and keep trying. This trial-and-error method would take days or even weeks for a process as complex as this unit.

However, with the control-loop monitoring tools, the team was able to view root cause oscillations across the entire unit, and even in the utilities areas. Fig. 5 shows the “Oscillation Details” report identifying loops that cycle at similar periods.

The plant was quickly able to pinpoint the column pressure controller as the source of the problem. “What’s interesting about this is that the column pressure is not part of our AP control scheme. No amount of work on the APC application could have solved this problem,” Montes said. The related regulatory control loop needed to be addressed.

Applying the fix. The new software also monitors control loop dynamics. Using “active model capture,” it determines dynamic process models using data from ordinary operator actions, such as setpoint changes. Using a dynamic model for the pressure controller, the team quickly retuned the loop.

It selected the option of more robust tuning. This provides stability through a wider range of process conditions. Fig. 6 shows the effect of retuning the pressure controller. The obvious result was the stabilization of the column pressure, followed by stability in the intermediate concentration, the reflux rate and steam demand.

PETROCHEMICAL DEVELOPMENTS Bottom-line benefits. Improved column stability allowed the

APC controller to do its job. The controls immediately moved the column into more profitable operation. Fig. 7 shows two column steam flows that were immediately reduced by over 7,000 lbs/hr.

John Mahlstadt, principal process control specialist at LyondellBasell, oversees control-loop monitoring efforts at several of the company’s sites. Mahlstadt said, “Our team delivered great value to our company, and achieved this in less than one full working day! These control loop monitoring tools make it so much easier to focus on the true root cause, which helps us to solve problems faster and keep our plants running at the lowest possible cost.”

Final thoughts. There are several key conclusions from this

work, and these include: 1. APC can only do its job well when the underlying control loops are performing well. This includes loops that may not be directly controlled by the APC controller. If APC is not running well, operators turn it off, and profitability suffers.

2. A continuous control-loop monitoring application can enable fixing problems in hours, rather than days or weeks. Realistically, it might have taken several weeks to solve the listed problem without these tools in place.

3. The control-loop monitoring application gave LyondellBasell the ability to leverage plant personnel in a way that was previously impossible. This continuous improvement program is driven by company-wide key performance indicators reported on a monthly basis for each production unit.

4. The LyondellBasell sites that are using these tools have found significant opportunities for process improvement. In some

SPECIALREPORT

cases, these result in energy savings. In other cases, savings in maintenance costs, increased operator awareness, sustained high production throughput or other benefits have been achieved does not appear to be promoting a particular software package we purchase; promoting products in this manner violates our media policy. HP NOTES ExperTune’s PlantTriage control loop monitoring software was used to deliver these results, and it provided some of the figures listed in this article.

BIBLIOGRAPHY http://www1.eere.energy.gov/industry/bestpractices/pdfs/steam15_benchmark.pdf Gilbert Montes is a principal control specialist in the control systems engineering group at LyondellBasell in Houston, Texas, with responsibilities for supporting DCS and DMC control applications. He has 10 years of experience as an operator and 20 years of experience as a control specialist.

Lothar Lang joined Lyondell 5 1/2 years ago in the corporate systems and electical engineering group. He holds a Ph.D from the University of Stuttgart, Germany, an MS degree from the University of Karlsruhe (Germany) and a BSc degree from the University of Minnesota, all in chemical engineering. He started his career with Bayer in Germany and stayed with the company for 15 years with positions in process design and development, process control and manufacturing. Dr. Lang headed Bayer’s advanced process control group and was also heavily involved in developing and rolling out of global KPI for overall equipment efficiency, controller performance monitoring and alarm management. Now, he leads LyondellBasell’s efforts on critical condition management (alarm management, controller performance management, operator HMI).

John R. Mahlstadt has 34 years of experience in the petrochemical industry involving operations, technical, optimization and control systems. At present, his responsibilities include supporting enterprise-wide critical condition management initiatives such as alarm management, control-loop performance and HMI.

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PETROCHEMICAL DEVELOPMENTS

SPECIALREPORT

Accurate feedstock selection and planning are critical to profitability Linear programming plays a vital role for ethylene producer K. FUNAHASHI and H. KOBAYASHI, Maruzen Petrochemical, Chiba, Japan; K. SAIKI and M. SUZUKI, Yamatake, Tokyo, Japan; and D. J. ADAMS, Honeywell, Wiesbaden, Germany

Background. For Maruzen, their main feedstock is naphtha, 85% of which is governed by a long-term contract and the remainder by spot contract. Of the spot purchases, 65% are imported naphtha. Recently, the price differential between naph-

TABLE 1. Process Units operated by Maruzen Joint venture

Capacity, Main product thousand tpy

Plant 3EP

Maruzen ethylene plant

Ethylene

480

X

4EP

Keiyo ethylene plant

Ethylene

690

X

BX1

Butadiene plant No. 1

Butadiene

90

X

BX2

Butadiene plant No. 2

Butadiene

AK

Alcohol ketone plant

MEK

170

2US

Unifiner sulfolane plant

Benzene

198

BP DAL

Benzene plant Dealkylation plant

Benzene

200

MX

Mixed xylene plant

Xylene

270

X

85

1,800 1,600 1,400

Ethylene NEA spot, $/ton Naphtha MOPJ, $/ton

1,200 1,000 800 600 400

FIG. 1

Oct-08 Jan-09 Apr-09

Oct-07 Jan-08 Apr-08 Jul-08

Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07

200 0 Jan-05 Apr-05 Jul-05

Tool kit. Linear-programming (LP) production tools have traditionally played a pivotal role in the planning of complex, continuous processing plants. These tools, which have been used for many years, take on a renewed importance and visibility, given the impact that they (the tools) can have on overall profitability for a petrochemical facility. While these tools are mature, it is critical to maintain an accurate representation of the facility’s capabilities and to ensure that the tools are consistently used.

For many producers, this means an assessment of the tools and processes being applied in that they are providing as much value as possible. Where LP-based planning tools are routinely in use, it is vital that the models being used to represent the plant are accurate and reflect current capabilities. For those not having adopted this level of sophistication, there remains a significant opportunity to improve the planning process by generating optimized plans and supporting rapid assessment for changing conditions.

Maruzen Petrochemical operates two ethylene plants with associated aromatics and butadiene extraction plants (see Table.

1). By implementing real-time optimization solutions, Maruzen was able to consistently maximize production and meet growing product demand through the last market expansion. With the global economic crisis, however, more rapid analysis of options and opportunities at the planning level has gained in importance.

This case study outlines Maruzen Petrochemical’s experience in the evaluation and application of improved production planning tools, thus improving profitability. Previously, Maruzen made use of Excel spreadsheets to select feedstocks and operating conditions for the olefins plants, which provided a limited view of the available options. Given that feedstock is the most significant cost, these tools enable Maruzen to perform a more detailed and rapid evaluation of potential feedstocks, thus optimizing the plant’s operating conditions.

Maruzen case study. Before the 2008 global crisis, Maruzen was operating its plant at full capacity. However, during the crisis, the price differential or spread between naphtha and ethylene became very small (Fig. 1). This required the company to determine its plant’s optimal operating mode, and to optimize the feedstock and product mix to maximize profits. A good production planning system indicates, in a timely manner, the proper course to take under difficult and changing market situations.

Ethylene NEA/MOPJ, $/ton

S

ince 2008, the global economic crisis has had a profound impact on the petrochemicals market globally, resulting in a significant drop in demand and prices. In response, producers reduced production and are looking for ways to manage with very thin margins. These market conditions have made it critical to optimize the mix of raw materials, plant operations and product slate to determine the best course of action. Efforts now imply a renewed focus on the planning process and supporting tools to enable more rapid analysis and decision-making. Improvements in this core process can have a tremendous impact on business performance and profitability.

Ethylene cost vs. naphtha cost.

HYDROCARBON PROCESSING APRIL 2011

I 47

SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

tha and butane had widened; so Maruzen increased the ratio of butane used for feedstock.

Feedstock is, in fact, the most important cost factor in ethylene production. But with Maruzen’s previous system, they were not able to evaluate many feedstock compositions and possibilities for blended feedstock in a limited time. Another important consideration in evaluating feedstock is the balance of inputs and outputs from utility plants. Maruzen’s early calculations did not include this level of detail. It was against this background that Maruzen began to evaluate the LP approach to feedstock evaluations and production planning. Several key issues to be resolved included: • No process was in place to determine if decisions being made were optimal; no program or process there was to recheck decisions against plant constraints.

• Checking all of the relevant factors for ethylene and utility plants was very time-consuming.

• Production planning required tremendous time ands was labor-intensive for many groups and entailed large amounts of data transfer.

• Each planner had a different spreadsheet and did a manual simulation. No spreadsheet showed the balance of materials for the whole ethylene plant.

• The furnace yield model was based on historical data. If the information was used for naphtha with a different composition, the accuracy of the data was not high; therefore, evaluating the effects of using a new type of naphtha was very difficult.

Feasibility study. To determine whether an LP approach was

suitable for Maruzen’s production planning issues, the company

48

I APRIL 2011 HydrocarbonProcessing.com

conducted a feasibility study to evaluate potential profit. This included a furnace-yield model that accounted for unit material balance, with separate factors for the plant’s cold section, fuel consumption and steam generation. The model, although relatively simple, was sufficient to show the company the approximate size of potential profits and to determine whether or not LP would be effective for production planning. Using this model, Maruzen ran several cases that compared profits and analyzed scenario results.

The condition cases included: • Base Case: Reproduction of the company’s actual operation (same feedstock, method of operation, sales volume) • Optimal Case 1: Freedom in operating furnaces and utilities, keeping feedstock and sales volume the same • Optimal Case 2-1: Freedom of feedstock, operation and sales, under the current market conditions • Optimal Case 2-2: Freedom of feedstock, operation and sales, under the past best market conditions • Optimal Case 2-3: Freedom of feedstock, operation and sales, under the past worst market conditions.

With regard to production, the feasibility study demonstrated that Maruzen could improve its profit by $2 million through optimizing its furnace operation (severity of cracking and feedstock recycling). With regard to sales, the study confirmed that LP is very effective for analyzing the merits of spot sales. Normally, spot sales must be evaluated within a very short time, making it quite difficult to weigh their merits to the total profit for the company. Also with regard to sales, Maruzen confirmed the usefulness of LP for making sales plans that would serve as a baseline for ethylene plant production. Lastly, the study con-

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SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

firmed that LP would enable Maruzen to evaluate many feedstocks within a short time period—another potential source of increased profitability. Based on these results, Maruzen decided to introduce an LP planning system.

Choosing a planning tool. There were a number of key

considerations in choosing the new planning system: 1) Since the yield of the cracking furnace affects the total costs for an ethylene plant, it was very important that the linear model also represent the nonlinear characteristics of furnace yield.

2) Fuel consumption and steam generation in furnaces have a great an impact on manufacturing cost. So, changes in consumption and generation caused by changes in feed composition or in furnace operating condition should be considered. This is important, especially for feedstock evaluation.

3) To achieve complete optimization, the model had to cover a wide range of areas such as feedstock purchasing, furnace yield, cold section, BTX (benzene, toluene and xylene) and other C4 products, utility plant and product sales.

4) The model needed to cover Maruzen’s two ethylene plants—one that is 100% owned, and the other, which is a joint venture. For the plant that is co-owned, the costs and profits are split based on the investment ratio. The model needed to take the profit sharing rules into account.

5) The system had to be easy to use, or else there was a risk that the planners would avoid it, continuing to make plans as they always had. To alleviate this concern, Maruzen added a condition that the system had to have a MS Excel interface for planners’ input and output.

50

I APRIL 2011 HydrocarbonProcessing.com

Key of modeling. Maruzen particularly focused on the accuracy of furnace yield, fuel consumption and steam generation in furnaces. After examining various methods for meeting Maruzen’s requirements, Maruzen adopted the delta base approach for yield model. Regarding fuel consumption and steam generation, Maruzen generated the equations that were used from data for radiant duty obtained from a kinetic simulator.

Furnace type

Combination of feedstock 1

SRT-1

Naphtha

2

Recycle C2

3

Naphtha and recycle C2

4

Recycle C2 and butane

5

Naphtha and butane

In the model, there are five delta base models for major feed type

Naphtha Recycle C2 Butane

FIG. 2

Delta base model Delta base model Delta base model Delta base model Delta base model for type-1

Delta base models for major feed types in ethylene production.

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SPECIALREPORT

PETROCHEMICAL DEVELOPMENTS

32 Ethylene Propylene

30 28

Yield, %

26 24 22 20 18 16 14 12 0.59 FIG. 3

0.61

0.63

0.67 0.65 P/E ratio

0.69

0.71

0.73

Ethylene yield vs. P/E and propylene yield vs. P/E.

TABLE 2. Delta base modeling technique mathematics YLD (i) = YLD (i) base (∂YLD(i)/∂xf(1)) xf(1)actual – xf(1)base ) (∂YLD(i)/∂COT) (COTactual – COTbase ) YLD(i)

Yield for effluent component i

YLD (i) base

Base yield for component i

∂YLD(i)/∂xf(i)

Shift vector for component i of naphtha

xf(i)base

Wt (%) of component i for naphtha feed

xf(i)actual

Wt (%) of component i in each optimization cycle

TABLE 3. Comparison of delta base and kinetic simulator Average of wt% error Ethylene

0.02

Propylene

0.08

Delta base model. The delta base methodology is illustrated in Table 2. It was developed by using a kinetic simulator. Maruzen developed separate delta base models for major feed types (naphtha only, naphtha with recycled effluent, etc.) to prevent the margin of error from widening (Fig. 2).

The yield of the furnace is adjusted for varying feed composition or furnace operating conditions in a linear fashion. However, Maruzen found that coil outlet temperature (COT) was not sufficiently linear throughout the operation range to be modeled as a delta base structure. For cases in which COT was unsatisfactory, Maruzen recreated the delta base model based on the propylene-ethylene (P/E) ratio instead of COT, and evaluated various operating points. Fig. 3 and Table 3 list the results from this modification.

Expected results. Prior to this project, Maruzen’s production

planning handled material selection by using a simple model that emphasized past actual material balances and did not consider the complexities of operating mode changes. The company’s production planning was now more practical, thus allowing Maruzen to change operating conditions within the model according to the plant circumstances.

Thanks to a rare long-term economic boom, production in the olefins market was increasing until 2008. And it was this increase, rather than Mauruzen’s cost reduction steps, that contributed to the company’s fiscal growth. Under those circumstances, it was possible for Maruzen to turn a profit by operating its plant at near 52

I APRIL 2011 HydrocarbonProcessing.com

peak capacity with an online real-time optimizer. Now, however, in the current unprecedented economic downturn, cost reduction has become Maruzen’s first priority. The company views the LP model as playing an even more important role in the future.

Because in the absence of demand for all-out production, there will be more flexibility as shown: • Furnace load • Recycle feedstock (C2, C3, C4, C5 ) • Sales/purchase.

In addition, bottlenecks will change according to changes in market conditions and, therefore, production priorities. The LP model is essential for analyzing different bottlenecks.

Maruzen also sees diversification of feedstock becoming increasingly important. As the company moves forward, Maruzen plans to use the LP model to calculate the advantages of feedstock diversification, and, if necessary, to invest in the facilities required to handle jet fuel and gasoline, among others.

Production planning is very complicated, not only because of the mutual interactions of the production processes, but also because of the interconnectedness of the various departments concerned, from headquarters to factories. This complicated undertaking has in the past depended heavily upon the skills of individuals; however, with the LP system sorting out and analyzing each constituent task, the process has been made more manageable and apprehensible for Maruzen. HP

Katsuyuki Funahashi is the manager of the corporate planning department of Maruzen Petrochemical Co., Ltd. He was engaged in the construction of the ethylene plant and worked as an engineer for 14 years at the Chiba site. He has experience in olefin sales and also in feedstock procurement. Mr. Funahashi has a degree in chemical engineering from Kyoto University.

Hidenori Kobayashi is the assistant manager of the production administration department of the Chiba plant of Maruzen Petrochemical Co., Ltd. He has worked as a process engineer for 16 years. Mr. Kobayashi holds an MS degree in engineering from Mie University. He is also a Nationally Licensed Class I Information Technology Engineer.

Mike Suzuki is the leader of the LP business team for Yamatake Corp. He has focused on consulting and implementing of LP planning systems, using Honeywell’s RPMS, especially for refinery, petrochemical, caustic soda, utility and LPG distribution optimization.

Mr. Suzuki holds a degree in electronics from Waseda University.

Kenji Saiki is a lead engineer in the LP business team for Yamatake Corp. He has been the lead engineer on various projects to implement planning systems in refineries, petrochemical and caustic soda plants. He holds a degree in chemical engineering from Tokyo University of Agriculture and Technology.

David J. Adams is manager of Honeywell’s Center of Excellence for Advanced Planning and Scheduling in Wiesbaden, Germany. Mr. Adams has been managing planning and modeling projects for oil, petrochemical and chemical companies throughout the world for almost 40 years. He holds an honors degree in chemical engineering and fuel technology from the University of Sheffield, UK. Mr. Adams is also a corporate member of the Institute of Chemical Engineers, a member of the Institute of Petroleum, a chartered engineer registered in the UK, and a foreign member of the Georgian Academy of Engineering.

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RELIABILITY AND MAINTENANCE

Investigation: Failure of a surface condenser titanium tube Advanced analytic methods determine contributing factors in heat exchanger corrosion problem A. AL-MESHARI, M. DIAB and S. AL-ENAZI, SABIC Technology Centre, Jubail Industrial City, Saudi Arabia

T

his case history focuses on the investigation of localized thinning of titanium (Ti) tubes in a surface condenser in an ammonia unit. Several characterization techniques were applied, including stereomicroscopy, optical microscopy and other methods. Detailed analyses showed that the tube thinning is attributed to iron-induced crevice corrosion. Possible root causes for failure involved the presence of high concentrations of iron (Fe) particles and chloride (Cl) ions in the steam condensate, which can accelerate the corrosion process. Another factor was tube flow-induced vibration that may have occurred at high processing flowrates, leading to a “localized” Fe deposition on the tube surface. This case history outlines the sources for the failures as well as the recommendation to prevent future events.

Background. Localized thinning was observed on Ti tubes of a

surface condenser for an ammonia unit. The condenser is a horizontal exchanger using straight tubes with two passes. The tube thinning was detected by eddy current testing performed on 34% of the exchanger tubes. External wall loss was located in the middle of the top two rows of tubes, i.e., between baffles 5 and 7 (Fig. 1).

The surface condenser had been in service for about 16.5 years.

In the condenser, steam condensate flows into the shell side, whereas seawater is introduced in the tube side. The materials of tubes, tube sheets, and shell are B338 Gr.2 welded (Ti), SB265 Gr.2 Ti clad on SA516-70 carbon steel, and A516-70 carbon Steam inlet with impingement plate Location of tube thinning

steel, respectively. The tubes are 7-m long, 0.7-mm thick and have 19-mm outer diameter. Table 1 lists the steam condenser design and operating conditions.

Visual examination. One tube sample, approximately 75-cm long, was submitted for analysis (see Fig. 2a). The sample was TABLE. 1. Surface condenser design and operating conditions Shell side Design inlet flowrate, Kg/h

48,690–Vapor + 5,810–Liquid

Design outlet flowrate, Kg/h

54,500–Liquid

Operating inlet flowrate, Kg/h

61,088–Total

Design pressure,

Kg/cm2 A

0.15

Design temperature, °C

120

Operating temperature, °C

62

Tube side Design flowrate, thousand Kg/h

2,650

Operating flowrate, thousand Kg/h

3,937

Design pressure,

Kg/cm2

G

3

Design temperature, °C

TInlet: 37°C, TOutlet: 48°C

Operating temperature

TInlet: 32.6°C, TOutlet: 42°C

Water outlet

Water inlet Condensate outlet FIG. 1

Schematic of the surface condenser showing the steam condensate and seawater flow direction, as well as the location of the severe tube thinning.

FIG. 2

Rounded, button-like, dark spots observed at the 12 o’clock position on the tube external surface.

HYDROCARBON PROCESSING APRIL 2011

I 55

RELIABILITY AND MAINTENANCE

FIG. 3

Close-up views of one of the dark spots observed on the tube.

FIG. 6

FIG. 4

SEM image of the spot surface showing the nature of corrosion.

Thick oxide layer observed at the spot.

deformed by the tube pulling process. Rounded, button-like, dark spots were observed at the 12 o’clock position on the tube (Fig. 2b–2c). The spots were perfectly rounded and equally spaced, having a diameter of about 8 mm. The distance between the centers of adjacent spots is approximately 13 mm. Fig. 3 is a close up photo of the spots. Stereomicroscopic examination of the spot surfaces revealed significant thinning that produced smooth grooves covered with blackish layers.

Chemical analysis. The chemical composition of the tube material was determined using X-ray fluorescence (XRF) spectrometry and C/S analyzer (Table 2). The material conforms to the chemical requirement for B338 Gr.2 (Ti).1 Surface analysis. The sample was examined under Scanning Electron Microscope/Energy Dispersive X-ray (SEM/EDX).

The metal loss at the rounded spots produced a smooth, grooved surface (Fig. 4). EDX of the blackish layer formed at the spot showed that it is composed mainly of Ti and iron oxides (Fig. 5).

Some Na, Si, Cl and P were also detected in the layer.b A thicker layer, containing higher concentrations of iron oxides, was noticed in the spot (Fig. 6). Interestingly, no Ti was found in that layer.

Metallographic examination. Cross-sections from the tube sample were prepared for metallographic examination. Two crosssections of the thinned areas are shown in Fig. 7. Severe thinning occurred in some areas (Fig. 7a), whereas milder thinning was observed in others (Fig. 7b). The minimum thickness measured was approximately 0.12 mm. The tube material microstructure possesses equiaxed grains, typical of annealed Ti type 2 (Fig. 8).

EDX of the oxide layer formed at reaction front confirmed the presence of high Fe concentrations (Figs. 9 and 10).

Discussion. In general, Ti alloys exhibit excellent corrosion

FIG. 5

56

SEM/EDX of the oxide layer formed at the spots.

I APRIL 2011 HydrocarbonProcessing.com

resistance in many environments. They have always been one of the best choices for such applications as surface-condenser tubes.

Titanium owes its corrosion resistance to the formation of a protective, passive titanium oxide (TiO) scale. Nevertheless, Ti is not completely immune to corrosion. Indeed, Ti may readily corrode in certain conditions. For instance, the thinning observed on the subject surface-condenser tube appears to have been caused by a special type of crevice corrosion, often referred to as iron-induced crevice corrosion. As its name implies, iron-induced crevice cor-

RELIABILITY AND MAINTENANCE TABLE 2. Chemical composition of the tube material (wt%) a C

Al

Si

O

N

H

Fe

Cu

Ni

Mn

Cr

Ti

Others max. each

Tube

0.02

0.16

0.05

–

–

–

0.25

0.10

0.01

0.01

0.02

Bal.

–

–

B338 Gr.2

0.08

–

–

0.25

0.03

0.02

0.30

–

–

–

–

Bal.

0.1

0.4

a

Others max. total

Maximum, unless range or minimum is indicated.

FIG. 7

FIG. 8

Tube material microstructure has equiaxed grains, typical of annealed Ti, as etched.

FIG. 9

SEM/EDX analysis of the layers formed at the affected areas.

Cross-sections of the tube wall showing different degrees of localized thinning.

rosion occurs when Fe particles deposit on or are smeared into the Ti surface forming crevices, thus leading to disruption of the protective TiO scale.2,3 As a consequence, a galvanic cell is established between Ti (cathodic) and Fe (anodic), where Fe particles corrode preferentially. The anodic dissolution of the Fe generates Fe ions that combine with Cl ions in the condensate to form iron chloride that in turn reacts with water to produce hydrochloric acid (HCl) and metal hydroxide (MOH):4 MCl + H2O r HCl + MOH Obviously, the formation of HCl results in a significant reduction in the solution pH at the crevice and that prevents the reformation of the passive TiO film. Inevitably, the reaction will proceed until the tube is perforated. The attack caused by Fe-induced crevice corrosion manifests itself by a very characteristic circular pit morphology. Iron-induced crevice corrosion is known to be catalyzed by temperature rise and/or high Cl concentration in the condensate. Therefore, the increase in the surface-condenser shell-side-inlet temperature would have aggravated the attack.

Iron carried over in the steam may have originated from corrosion and/or erosion of steel pipes and other components (e.g., impingement plate). Further, the surface-condenser tubes at the steam-condensate inlet were probably subject to some vibration induced by the above-design flowrates in both tubes and shell sides. It is suggested that the Fe particles carried over in the steam hit, deposited and accumulated on the tube surface. The tube vibration led to redistribution of the Fe particles on the tube surface, such that Fe accumulation occurred at equally spaced areas, inducing the localized thinning.

However, it cannot be ruled out that the Fe particles could have been smeared over the tube surface during fabrication and

installation processes. Localized corrosion of Ti tubing has been attributed to scratches in which traces of Fe were detected.4 It is interesting to note that the surface condenser had been in service for about 16.5 years without any failures (or thinning), implying that the Fe particles were most likely carried over in the steam condensate, than rather being smeared onto the tube surface during fabrication. This may be supported as the external tube-wall loss was located in the middle of the top two rows of tubes.

Conclusions. The steam condenser tube thinning is attributed

to Fe-induced crevice corrosion. Presence of high concentrations of Fe particles and Cl ions in the condensate accelerates the Feinduced crevice corrosion. Tube flow-induced vibration may have occurred due to the above-design flowrates.

HYDROCARBON PROCESSING APRIL 2011

I 57

RELIABILITY AND MAINTENANCE 2 3 4

and Titanium Alloy Tubes for Condensers and Heat Exchangers.

ASM Handbook, Vol. 13, Corrosion, ASM International, 1993. http://www.azom.com/, May 16, 2010.

Donachie, Jr., M. J., Titanium: A Technical Guide, ASM International, 2000.

Al C Ca Cl Cu Cr Fe K

FIG. 10

SEM/EDX analysis of the layers formed on the condenser thinned tube.

Aluminum Carbon Calcium Chloride Copper Chromium Iron Potassium

NOMENCLATURE Mn Ni N O P Si Na Ti

Magnesium Nickel Nitrogen Oxygen Phosphorus Silicon Sodium Titanium

Abdulaziz Al-Meshari is a failure analyst at SABIC Technology Centre-Jubail, Saudi Arabia. He has a PhD degree in material science and metallurgy from the University of Cambridge (UK) and MS degree in corrosion science and engineering from UMIST (UK).

He has been a NACE and ASM member since 2000.

Recommendations. The study generated several recommen-

dations for the facility: • Surface condenser operating conditions should be kept within the design conditions.

• Concentrations of Fe and Cl in the condensate must be monitored and controlled.

• Source of Fe particles should be identified and eliminated to avoid formation of crevices. HP 1

LITERATURE CITED ASTM B338-09, Standard Specifications for Seamless and Welded Titanium

Mohammad Diab is a failure analyst at SABIC Technology Centre-Jubail, Saudi Arabia. He has a BS degree in mechanical engineering from King Fahd University of Petroleum & Minerals (KSA).

Saad Al-Enazi is a failure analyst at SABIC Technology Centre-Jubail, Saudi Arabia. He has a MS degree in manufacturing management and BS degree in mechanical engineering from the University of Toledo.

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ENVIRONMENT

Consider becoming more familiar with the wet gas scrubbing process New ways to calculate adiabatic saturation temperature R. G. KUNZ, RGK Environmental Consulting, LLC, Hillsborough, North Carolina

A

sulfur dioxide (SO2) emission limit of 5 parts per million by volume on a dry basis (ppmvd) at 0% O2 has been proposed for fluid catalytic cracking units (FCCUs) in California’s Los Angeles Area Air Basin.1 This performance level has been demonstrated in practice on a commercial scale by wet gas scrubbing of FCCU regenerator flue gas. Since rulemaking in this jurisdiction is often the standard for the rest of the regulated community, it is conceivable that this emission standard and associated technology may become the norm for best achievable control everywhere else.

In anticipation of this possibility, it would behoove affected stakeholders to become familiar with the wet scrubbing process.

SO2. Regulatory state of the art for effluent SO2 from cat crack-

ers is 25 ppmvd at 0% O2, 365-day rolling average, based on US Environmental Protection Agency (EPA) Reasonably Available Control Technology/Best Available Control Technology/Lowest Achievable Emission Rate Clearinghouse values.2,3 It is possible, however, to achieve even lower values. Stack test data at two different FCCU wet scrubber installations show an outlet concentration of 1 ppmvd at 0% O2.3,4 As of June 2009, long term demonstrated performance for one of these was 3.80 ppmv, based on nine months of continuous emission monitoring system (CEMS) data.4 Particulates. Flue gas exiting the regenerator vessel can be expected to contain a suspended particulate catalyst loading of 200-300 milligrams per normal cubic meter (mg/Nm3) (0.0870.13 grains per dry standard cubic foot, gr/DSCF).5 Example regulatory standards for effluent particulate include 0.02, 0.01 and 0.005 gr/DSCF.6–8 Considerations—how wet-gas scrubbers work. Fig. 1, redrawn from the EPA Air Pollution Control Cost Manual depicts the scrubbing process.9 In this diagram, combustion flue gas contacts with water in the throat of a high energy venturi scrubber. The scrubbed gas, reduced in particulate matter (PM) and sulfur oxides (SOx—primarily SO2), proceeds through an entrainment separator/mist eliminator and is exhausted through the stack located atop the scrubber. A wet-gas scrubber (WGS) is the only particulatecollection device capable of simultaneously removing entrained PM plus SO2 in the gas phase—with the venturi scrubber being the most efficient type of WGS.10,11 Mist eliminators are said to remove between 90%–99% of the liquid droplets from the waste-gas stream.9 One process licensor reports a 99.99+% or more separation of liquid from the exhaust-gas stream, resulting in minimum entrainment in the scrubber stack.11,12

The scrubber water circulates in a continuous loop in a feedand-bleed configuration, with makeup water (MU) added to replace that lost by evaporation (E) and blowdown (BD). For minimal liquid entrainment, MU = E ⫹ BD

(1)

The recirculation rate is set by the desired liquid-to-gas ratio (L/G). Evaporation takes place in cooling the hot flue gas from its elevated inlet temperature to its cooler water-saturated condition in the scrubber. According to EPA Manual AP-42, the FCCU regenerator temperature is usually 1,100°F–1,250°F (590°C–675°C).13 Heat exchange may be employed upstream of the scrubber to reduce the evaporation and lower the adiabatic saturation temperature (AST).

The amount of blowdown is set to control the concentration of certain critical parameters in the recirculating scrubbing liquid.

The important items are total suspended solids, total dissolved solids and the concentration of chloride ion.14 Volume of blowdown to maintain the limiting constituent within the control limit may well be as much as the same order of magnitude as the evaporation.

Controlling particulate suspended solid concentration is important because of the erosive nature of the collected catalyst fines. Dissolved solids consist primarily of sodium sulfite, bisulfite, and sulfate formed from the captured SO2 and a sodium based pH-control agent such as sodium hydroxide (NaOH) or soda ash (Na2CO3). Chlorides arise from both the makeup water and from impurities in the pH-control reagent used; a higher chloride level can be expected when caustic soda (NaOH) is employed instead of Na2CO3.3,14 The purpose of the chloride limit is to minimize the potential for stress corrosion cracking of austenitic stainless steels, materials commonly employed in the construction of the scrubber. Stress corrosion cracking can occur when these alloys are exposed to excessive chlorides in the scrubbing liquor.3,14,15 Evaporative cooling. When a flue gas is scrubbed with water,

some water is evaporated, cooling the gas. The water evaporates to the extent governed by the saturation vapor pressure at the final temperature achieved and the moisture content of the original hot gas. The heat given up by the gas in cooling from its original temperature to the final temperature is balanced by the heat necessary for the evaporative phase change of the scrubbing water. At steady state, the scrubbing water and the water-saturated gas exit at the same temperature. This is known as the theoretical AST. The emitted gas is saturated with water vapor. Under certain climatic conditions—notably, high humidity situations—contact HYDROCARBON PROCESSING APRIL 2011

I 61

ENVIRONMENT with atmospheric air will cause condensation, resulting in a steam plume.9,17–19 Photographs in the literature provide numerous examples.3,11,12,14,16–22 To the public, this is often an aesthetic problem or an indicator of some sort of suspected pollution masked by steam, and energy-intensive plume-reheat or other mitigation measures are employed to dissipate the plume.18,22 Some refineries have mounted a proactive public relations campaign to educate their neighbors about the steam-plume phenomenon.17–19 Evaporative cooling calculations. In modeling this pro-

cess as a simple evaporative cooling, no heat losses are considered, the mass flowrate of dry gas remains constant and ideal gas behavior is assumed. The sensible heat in raising the liquid makeup from the supply temperature to the AST without phase change also contributes to gas cooling, but to a much lesser extent, and it is often neglected in calculations. Liquid makeup consists of the water necessary to replace the evaporation plus whatever blowdown is taken to control the concentrations of critical species in the water circulating in the scrubber.

Rigorous calculations with no sensible heat. The

proper procedure to calculate the AST requires the heat capacity (Cp) of each flue-gas constituent, the enthalpy change upon TABLE 1. Constants for Antoine Equation24 Temperature range

A

B

C

0–60°C (32–140°F)

8.10765

1750.286

235.0

60–150°C (140–302°F)

7.96681

1668.21

228.0

evaporation (ΔHv) for the scrubbing water, and the vapor pressure of water, all as functions of temperature. The calculations summarized neglect the minor heat effect from adding cold scrubber makeup water to replace the evaporation and blowdown from the scrubber. The resulting evaporation (and, hence, makeup) without the sensible heat effect is slightly higher and more conservative than when the sensible heat effect is included. To consider the sensible heat, the heat capacity of liquid water is needed, along with the amount of blowdown, which, when added to the evaporation, determines total makeup.

The heat effect of cooling the gas is calculated as follows: m = mass or n = moles of gas

Energy change(ΔH)=(m or n)∫

T2

T1

Cp dt

(2)

Heat-capacity equations in the temperature range of interest are listed below.22 Units of Cp are cal/(g mole ˚C) or Btu/(lb mole ˚F).

N2 O2 CO2 H2O

Cp = 6.50 + 0.00100 T (°K) Range (300–3,000°K) (3) Cp = 8.27 + .000258 T (°K) – 187,700/[T (°K)]2 Range (300–3,500°K) (4) Cp = 10.34 + 0.00274 T (°K) – 195,500/[T (°K)]2 Range (273–1,200°K) (5) Cp = 8.22 + 0.00015 T (°K) + 0.00000134 [T (°K)]2 Range (300–3,000°K) (6)

Maximum uncertainty ranges from 1% for O2 through 1.5% for CO2 to 3% for N2. Uncertainty for H2O is not specified.

Mean molar heat capacity for each component is computed by integrating Eqs. 3–6 over the temperature difference (ΔT) from the flue-gas temperature to the ASU:

Cpi

(1 / T )

Tfinal Tinitial

Cpi dt

(7)

Mean molar heat capacity equations in integrated form (˚K): Cp = (1/ΔT) [6.50(ΔT) + 0.0005 (Tfg2 – Tast2) (8) Cp = (1/ΔT) [8.27(ΔT) + 0.000129 (Tfg 2 – Tast2) + 187,700{(1/Tfg) – (1/Tast)}] (9) CO2 Cp = (1/ΔT) [10.34(ΔT) + 0.000137 (Tfg2 – Tast2) +195,500{(1/Tfg) – (1/Tast)}] (10) H2O Cp = (1/ΔT) [8.22(ΔT) + 0.000075 (Tfg 2 – Tast2) + (0.00000134/3)(Tfg3 – Tast3)] (11) The composite mean heat capacity of the flue gas is obtained using the constituent mole fractions (Xi) as weighting factors.

N Cp = ∑ Xi Cpi (12) i=1 Finally, gas cooling of n moles of flue gas from the initial gas temperature to the AST is given by:

N2 O2

ΔH = n Cp ΔT

(13)

This energy requirement is balanced against the enthalpy change (ΔHv) of the amount of water evaporating at the AST. Regression of steam table entries at every 10°F between 100°F and 180°F gives: 23 ΔHv (Btu/lbm) = 1095.895 – 0.586 T (°F)

(14)

The flue gas is saturated at the final condition–only so much water can be evaporated–depending on the vapor pressure at that Select 165 at www.HydrocarbonProcessing.com/RS 62

ENVIRONMENT condition and the moisture already in the gas. Vapor pressure of water as a temperature function is conveniently provided by the Antoine Equation: log10 pvap (mm Hg) = A – B/[C + t (°C)]

(15)

The equations from Table 1 have been shown to reproduce steam-table values in the range of interest to within 0.02%.23,25 Calculations are trial and error—repeatedly guessing a temperature for AST until the heat effects are in balance, with an allowable amount of water having evaporated to saturate the gas. The primary variables affecting the calculated AST are the temperature of the hot flue gas and its moisture content. An example problem is shown in Appendix A. When the sensible heat to raise the temperature of the makeup from the water-supply temperature to the AST is considered, the calculated AST is lowered by a few °F and the required evaporation is decreased somewhat. These calculations are addressed, as well, in the example problem.

Shortcut technique. A shortcut method derived here for the case of no sensible heat provides a high quality approximation of the AST and theoretical evaporation without sensible heat. It uses average constant heat capacities—one value for moisture and another for all other flue gas constituents. The technique is especially useful for quick estimates and rapid screening of multiple cases, especially when details of flue gas composition are unknown. This methodology is intended for estimating purposes, not for design.

The procedure uses an easy-to-remember constant heat capacity of 0.5 Btu/lbm per °F for flue gas moisture and half that value, 0.25 Btu/lbm per °F, for all other (non-water) constituents. To convert from mass to molar basis, a molecular weight (MW) of 18 is used for water; average MW of everything else is taken as 30.

Cp = (%H2O/100) (18) (0.5) + [(100 – %H2O)/100] (30) (0.25)

Calculations considering sensible heat. Heat capacity

of liquid water is required in the calculations when the sensible heat effect of the makeup water is considered. When the sensible heat to raise the temperature from the makeup-water supply temperature to the AST is evaluated using Eq. 2 for the liquid, the calculated AST is lowered by a few °F and the required evaporation is somewhat decreased. This calculation is addressed, as well, in the example problem. An approximate relationship between the evaporation with sensible heat and that without is as follows: Evap (with sensible heat) = Evap (without) [1,000/{1,000 + (x) (Tast – Tsupply)}]

With the factor x the ratio of makeup water (evaporation + blowdown) to evaporation. The approximation occurs in neglecting the minor change in AST with and without considering sensible heat and the use of a constant 1,000 Btu/lbm for ΔHv. Required evaporation when sensible heat is considered, is roughly 92%, 85% and 79% of the evaporation without sensible heat, for liquid makeup of one, two and three times evaporation and a water-supply temperature of 60°F. Blowdown treatment. The scrubber blowdown shown as

exiting at the lower right in Fig. 1 is conditioned for discharge in TABLE 2. Saturation temperature calculated by shortcut method (°F) % H2O in flue gas j Flue-gas temperature (°F)

164

168

172

176

1,200

162

166

170

174

1,100

160

164

168

172

1,000

157

162

166

170

900

154

159

164

168

800

150

156

161

166

700

146

152

158

164

600

141

149

155

161

500

135

144

151

157

400

129

138

147

154

300

120

132

141

149

Vapor pressure (pvap) and heat of evaporation (ΔHv) of water are calculated as in the rigorous case. If desired, the method can be further simplified by utilizing a constant 1,000 Btu/lbm for ΔHv, but this is less accurate.

Estimates of AST to the nearest °F for flue-gas temperature ranging from 1,300°F down to 300°F and flue-gas moisture 5%, 10%, 15% and 20% are shown in Table 2. Values for intermediate points can be obtained by interpolation. Values of AST differ only slightly from those calculated on a case-by-case basis by the rigorous method. As in the rigorous method, the ASU is reduced by only a few °F by the effect of sensible heat.

Estimated evaporation per unit volume of wet flue gas from the shortcut procedure is correlated with flue-gas temperature by the following empirical equation:

This function, fitted to the calculated point values and plotted in Fig. 2, reproduces results over the range investigated. It displays an almost linear increase having minimal curvature. As it turns out, evaporation per unit volume of wet flue gas is nearly constant at each temperature for flue-gas moisture from 5% to 20%, giving rise to the single line depicted. The standard cubic ft (SCF) employed, with an ideal gas molar volume of 385.3 SCF/lb mole, is defined at 68°F and 1 atmosphere (14.696 psia, 29.92 mm Hg), a common regulatory-agency basis.

5 10 15 20 Approximate saturation temperature (°F)

1,300

(16)

Evap (gal/SCF wet) = –2.8495 × 10–4 + 2.20710 × 10–6 Tfg + 7.72 × 10–11 (Tfg)2 (17)

(18)

Discharge

Ductwork

From combustion source

Scrubber

Entrainment separator

Water makeup

Stack

Chemical makeup

Induced draft gas Recirculation tank

To disposal or treatment

Pump

FIG. 1

Schematic of a venturi scrubber system.

HYDROCARBON PROCESSING APRIL 2011

I 63

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ENVIRONMENT what is termed a purge treatment unit (PTU).3,20,22 The PTU is not shown, but it reduces suspended solids and chemical oxygen demand (COD) to environmentally acceptable levels. Steps in the treatment of scrubber blowdown consist of sedimentation, filtration of settled solids, oxidation of the supernatant/liquid overflow by aerating and agitating to reduce its COD, as well as pH adjustment, if necessary. Whatever residual sulfite/bisulfite survives the oxidation step will impart a COD to an internal or external treatment plant or to the receiving water. The underflow is a wet solid of 50 wt.% concentration, said to be suitable for disposal in a sanitary landfill, or it can be put to beneficial use in cement manufacturing.19,20,22 APPENDIX—EXAMPLE PROBLEM Part 1—Rigorous calculations with no sensible heat.

Calculate the AST and evaporation in a flue gas scrubber using a rigorous approach, but neglect sensible heat from the makeup water added to replace the scrubber water lost by evaporation and blowdown.

Flue-gas composition and temperature tabulated (Table 3) were adapted from referenced literature.26 Flue gas flow is arbitrarily set at 150,000 SCFM (68°F, 1 atm)—equivalent to 285,000 ACFM at heat-recovery temperature, and higher at regenerator temperature. This is in the mid-range of flows in the commercial experience listed for cat-cracker scrubber installations.12

Subtracting the 12% moisture already in the flue gas [12/ (100–12) = 0.136363] moles/mole dry gas, moisture evaporated is the difference between saturation minus actual: 0.325993 – 0.136363 = 0.189630 moles/mole dry gas × [(18 lbm H2O/lb mol H2O)/(8.34 lb H2O/gal × 385.3 SCF/lb mol)] [(100 – 12)/100] (dry/wet) = 0.0009348 gal/SCF of wet flue gas Composite mean molar heat capacity from Eq. 12 over the temperature range from 543.2°F to just below 149°F: [(0.72) (6.9476) + (0.01) (7.3889) + (0.15) (10.5285) + (0.12) (8.5610) = 7.6828 Btu/lb mol °F] where the factors are the constituent mole fractions from Table 2 and their individual average molar heat capacities calculated from Eqs. 8–11.

Heat necessary to cool 1 SCFM of wet flue gas = 471.8099+ Btu/hr.

Heat necessary to evaporate water at 1,008.7 Btu/lbm (Eq. (14)) = 471.8099+ Btu/hr Total evaporation = (0.0009348 gal/SCF wet flue gas) (150,000 SCF/min) =140.2 gal/min (gpm) × (8.34 lb H2O/gal) (60 min/hr) h 70,170 lb/hr.

Part 2—Rigorous calculations with sensible heat.

Repeat Part 1, but consider the sensible heat in raising the temperature of the liquid makeup water, assumed to be at 60°F with a constant heat capacity of 1 Btu/lbm per °F over the range of interest from the supply temperature to the AST.24 Total scrubber makeup

Solution. From heat balance neglecting sensible heat, Eqs.

13 and 14, trial-and-error solution yields a temperature of 148.8352408°F (rounded to 149°F) for the final trial. Vapor pressure at the AST = 3.612990 psia, and the saturation moisture content at temperature is: pvap H2O/(PT – pvap H2O) = 3.612990/(14.696 – 3.612990) = 0.325993 moles H2O per mole of dry gas.

TABLE 3. FCCU flue-gas properties Component

Vol.%

N2

72

O2

1

CO2

15

TABLE 5. Summary of shortcut method results

Variable

Sensible heat for makeup at: No MU = 1×Evap. MU = 2×Evap. MU = 3×Evap. sensible heat No BD BD = Evap.

BD = 2×Evap.

AST, °F: “Exact” Rounded

148.8291347 149

147.4322012 147

146.21236305 146

145.1330871 145

0.0009344* 140.2 70,140

0.0008623 129.3 64,720

0.0008023 120.3 60,220

0.0007513 112.7 56,390

473.3189

474.7778

476.0686

Evaporation, gal/wet SCF gpm lb/hr

Heat effect, 471.6483 Btu/hr per SCFM of wet-flue gas

H2O

12

Total

100

Temperature following heat recovery, °C (°F)

284 (543.2)

Total wet flow, SCFM

150,000

*The

correlation of Eq. 17 depicted in Fig. 2 predicts an evaporation of 0.000936 gal/wet SCF with no sensible heat.

TABLE 4. Summary of sensible heat case

Variable

Sensible heat for makeup at: No MU = 1×Evap. MU = 2×Evap. MU = 3×Evap. sensible heat No BD BD = Evap.

BD = 2×Evap.

AST, °F: “Exact” Rounded

148.8352408 149

147.3617701 147

146.21461204 146

145.13391093 145

0.0009348 140.2 70,170

0.0008625 129.4 64,740

0.0008024 120.4 60,230

0.0007514 112.7 56,400

Heat effect, 471.8099 Btu/hr per SCFM of wet-flue gas

473.4295

474.8431

476.0935

Evaporation, gal/wet SCF gpm lb/hr

Evaporation, gal/wet SCF of flue gas

0.003

0.002

0.001

0.000 200 FIG. 2

400

600 800 1,000 Flue-gas temperature, °F

1,200

1,400

Approximate evaporation to reach AST.

HYDROCARBON PROCESSING APRIL 2011

I 65

ENVIRONMENT equals one, two or three times evaporation. During operation, makeup water is added to replace the evaporation plus whatever blowdown is needed to control the concentration of contaminants in the recirculating scrubbing liquor. When the makeup is computed using the input of blowdown determined from contaminant concentrations, rather than expressing makeup as a multiple of evaporation, the calculation becomes iterative (not shown here but performed elsewhere).28 Results are given in Table 4.

When the sensible heat of the makeup water is included in the calculations, less water has to be evaporated to cool the flue gas.

Since the original moisture content of the gas and its temperature are fixed, less water evaporating at the saturation temperature means that the AST must decrease by several °F to where the allowable vapor pressure is lower. This greater difference between the original gas temperature and the new AST means that more heat must be transferred to cool the gas, as reflected in the sum of heating of the liquid water and the evaporation.

Part 3—Shortcut technique. Parts 1 and 2 are reworked

ZZ

)R FR P ) U D Z DQD SUH 5(( ED O\ V OVW VLV VH RQ J G D ÀOW R W LU HU R V F RP FD

using the flue gas properties of Table 2 and the simplified approach presented here. Temperature-dependent heat of water evaporation is calculated from Eq. 14.

Solution: Composite gas heat capacity calculated from Eq. 6 works out to be a constant 0.7.683 Btu/lb mol °F. Results are listed in Table 5.

Agreement in this case between the shortcut technique and the rigorous method of the previous examples is excellent. Agreement of the shortcut method with rigorous calculations for another case with input parameters of 1,000°F gas temperature and 10% H2O

(not shown) is comparable.27 In that situation, the theoretical AST with no sensible heat comes out in the vicinity of 162°F (72°C) and decreases by about 2°F for each incremental increase in sensible heat.

Repetition of the case with no sensible heat over the range of flue gas temperatures from 1,300°F down to 300°F and moisture contents from 5%–20% results in the ASTs listed in Table 2 and the point values for evaporation plotted in Fig. 2. HP ACKNOWLEDGMENT Revised and updated from an earlier presentation at the NPRA 2010 Environmental Conference, San Antonio, Texas, September 20–21, 2010. The author thanks Roberta Kunz Fox, AIA, of fox2 design for assistance with the figures. The author is also grateful for the cooperation and participation of Dr. Theresa K. Toohil, PhD, Information Management Consultant.

LITERATURE CITED For complete literature cited, visit HydrocarbonProcessing.com.

Robert G. Kunz is currently an independent environmental consultant and the author of the recent John Wiley book, Environmental Calculations: A Multimedia Approach. He was previously associated with Cormetech, Inc.; Durham, North Carolina, Air Products and Chemicals, Inc., Allentown, Pennsylvania; Esso Research and Engineering Company, Florham Park, New Jersey; and The M.W. Kellogg Company, New York, New York. Dr. Kunz earned a BChE degree in chemical engineering from Manhattan College, a PhD in chemical engineering from Rensselaer Polytechnic Institute, an MS degree in environmental engineering from Newark College of Engineering, and an MBA from Temple University. He has contributed numerous items to the professional literature and is a recipient of the Water Pollution Control Federation’s Harrison Prescott Eddy Medal for noteworthy research in wastewater treatment.

Dr. Kunz is a member of AIChE, ACS, and Air and Waste Management Association, and he is a licensed professional engineer in several states.

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ENVIRONMENT

Low-pressure absorption of CO2 from flue gas Case study accomplished 95% sequestration using methyldiethanolamine aqueous solution M. TELLINI and P. CENTOLA, Politecnico di Milano, Milan, Italy

O

ver 60% of carbon dioxide (CO2) sent to the atmosphere comes from fired heaters and utility or industrial power systems based on fossilfuel combustion.1 The industrial capture of CO2 from emissions is possible with low pressure solvent absorption, a simple process operation that becomes particularly important for combustion furnaces, burners and incinerators. Traditionally, the absorption of acidic gases has been done under pressure with amine solutions, but typical combustion flue gases have large flowrates.

Inert N2 is the bulk constituent and CO2 is generally diluted to 10% vol–15% vol.

Fig. 1 shows the example of a tenfold polytropic compression at the 80% optimistic efficiency for 100,000 Nm3/h, a relatively small industrial gas flowrate. The compression requires 12 MWh or 3.2 kW per kmole of gas and determines a net loss, in spite of the power that can be recovered through a turbine expander, located on the lighter CO2-free gas returning from the absorber, and the heat recuperated from various intercoolers plus the reheated gases to the chimney. Higher losses are incurred if the gas is compressed to 4,000 kPa or more, for deepsea or sealed-cavern remote confinement, possibilities that lead to comparing CO2 sequestering costs versus carbon tax savings and other virtual benefits in specific regions.

CO2 absorption is mostly concerned with acid-gas solubility in selected solvent(s) and the absorber’s operating conditions, whereas the solvent stripping section of the regenerative absorption process generally optimizes steam quantity. Prior to any process modeling, acid-gas solubility knowledge in the solvent is essential, but it is often difficult because data is reported for pure gases, in specific pure solvents, or in fixed mixing ratios of solvents. Another difficulty

is that most oil refineries and gas-sweetening plants absorb acidic gases under pressure, and the chemical literature for CO2 and H2S solubility is rich for those operating conditions, but scarce data is published for CO2 solubility at low operating pressure.2–5 After constructing equilibrium curves for different amine solutions, the absorber was calculated at near atmospheric pressure with McCabe-Thiele and Kremser design methods. A 95%-vol CO2 absorption was obtained in water and N-methyldiethanolamine (MDEA). Higher pressure did not significantly improve gas capture and energy necessary for greater compression which offset the advantage of reducing the liquidto-gas ratio. Operating conditions and findings determined with the analytical design were helpful to decide suitable input parameters and run a process simulator to convergence. Without such pristine knowledge, simulations on flue-gas applications near Flue gas

atmospheric pressure failed to converge, or reached limited efficiency. The result of one simulator could differ from another simulator, even for the same case. Designers may dismiss or see immediate difficulties in simulating CO2 low pressure capture from combustion emissions, feasibility that can be supported by finding viable operating parameters through an early investigation.

CO2 solubility/solvent selection.

Gas solubility is easily identified by Henry constants and is commonly graphed as partial pressure pi of the pure gas vs. the concentration (molality, molarity or molar fraction) in its solution at constant temperature.6 For CO2 in water, the solubility is negligible and hardly useful at ambient conditions. Antoine or similar correlations provide the vapor tension of a single, pure component like water, Pi°, evaporating at a given temperature, from its pure liquid 14

1 13

Compressor 5 To chimney

CO2 free gas Cond.

20

Turbine

CW

17 12

19

16

15

To absorption CW return

18

LP steam

21 Stream Nm3/h Kmol/h CO2 Kmol/h H2O Kmol/h kPa °C

1 100,000 3,703 330 110 40

5

16

14

13

15

21

18

3,703 373 330 1,040 426

3,703 373 330 1,010 38

3,100 373 100 1,010 38

3,100 0 100 110

3,100

360

12,500

100 101 130

360 190 118

12,500 290 50

Compressor @ 80% efficiency Turbine @ 80% efficiency CW exchanger duty LP exchanger duty Chimney gas exchanger duty

FIG. 1

12 MWh (actual) -2.7 MWh (actual) 5,576 Mcal/h 3,402 Mcal/h 5,190 Mcal/h

Power loss 9.3 MWh

Flue-gas compression and partial recovery of compression energy after absorption.

HYDROCARBON PROCESSING APRIL 2011

I 69

ENVIRONMENT phase. As long as the solution is ideal, the nature of the solvent does not enter into consideration, but the absorption of CO2 is reactive and non-ideal. Compared to cases without chemical reaction, the absorption rate is greater due to enhanced absorption and, conversely, during the solvent regenerative desorption, CO2 release from the amine in the stripper will be hindered.7 Enthalpy variation. The enthalpy variation is also significant since the absorption reaction is exothermic. The absorption effectiveness is primarily due to alkalinity, and a variety of alkaline media are used by mixing chemically reacting solvents (organic amines) in a larger quantity physical solvent (water). When large proportions of acid gas (over 5%) are contained in the feed gas, the redundant water quantity accomplishes a temperature buffering effect that brings the scrubbing process closer to isothermal conditions.

The solvent’s high reactivity is useful to limit the operating pressure and the liquidto-gas ratio of the gas absorbers, having the downstream effect of reducing the solvent stripping section size. For many years, monoethanolamine (MEA) has been the mostly used amine, due to high reactivity and low cost, but it is corrosive for water solutions above 20 wt% and highly volatile.

It reacts irreversibly with SO2 and suffers easy degradation in the presence of O2 and NO2 that exist in the flue gas, even after effluent treatment.8 Excess oxygen, specifically, is present in combustion effluents at variable percentages and for precaution

against the release of CO downstream of combustion chambers. Additive-inhibited MEA has been commercialized and the proprietary process has been claimed to resolve O2 degradation and to work with flue gas at moderate pressures, notwithstanding the increased cost of electricity produced with the power-generation cycle equipped with such amine treatments.9–10 Alternatively, MDEA is essentially noncorrosive and it apparently acts as a base catalyst for the hydration of CO2 to carbonic acid, the slow step of the reaction, and the operation with water abundance becomes viable for flue-gas absorption at atmospheric pressure.11–12 With respect to primary and secondary amines, MDEA is a tertiary amine with good CO2 selectivity and does not form irreversible carbamates. MDEA lower volatility (247°C boiling point, at 760 mmHg) generates smaller solvent vaporization, limiting the necessity of overhead equipment to reclaim solvent losses and to control odors from the absorber.

MDEA is usable in concentrations up to 60% in water. The possibility of using higher concentrations, without the risk of heavy corrosion, allows to decrease the solvent recirculation rate, therefore, cutting costs, including the stripping section.13 MDEA is highly resistant to thermal and chemical degradation; it has low specific heat and its lower heat of reaction—333 kcal/Kg-CO 2 compared to 458 kcal/ Kg-CO2 for MEA—requires less energy for solvent regeneration.8 For the above advantages, the selection of MDEA aque-

ous solutions was preferred in our earlier comparative study of various amines that achieved 63% CO2 absorption efficiency, and we shall investigate identical operating conditions, at different solvent loadings supported by published data, to confirm the feasibility of obtaining higher efficiency.14 The solubility of CO2 in the ternary system is expressed as partial pressure pi of the gas over a solution characterized by xi or ␣, where ␣ is the molar ratio between CO2 and the amine that ties the gas loading to the two absorbents respective quantities, like if a combined pseudo-solvent is being considered. With no air dissolving in the solvent, ␣ also expresses the solute concentration and measures the solubility of the acid gas in the reactive solvent: ␣ = [CO2]/[MDEA] = Xi [MDEA+H2O]/[MDEA] with Xi = xi/(1–xi) or xi = Xi/(1+Xi) (1) formulas inside brackets are calculated in weight mol; Xi and xi are respectively the molar ratio and the molar fraction, which are used for design calculations.

CO2 partial pressures were reported for various conditions at a variety of temperatures and MDEA concentrations (up to 4.28M) for CO2 alone and for CO2 plus H2S.15–16 Literature data was gathered.17–19 Primarily, a comprehensive comparison of data generated via three experimental methods against an extensive literature review was referenced. Table 1 reports a portion of published values at low pressures and 40°C and calculates vapor-liquid

TABLE 1. Partial Pressures, ␣ and equilibrium V-L compositions for CO2-MDEA-H2O19 x1=xCO219

kPa tot19

␣ MDEA19

XCO2

[CO2]liq

xH2O

kPa H2O

yCO2

kPa CO2

yH2O

0.0000

7.37

0.0000

0.0000

0.0000

1.0000

7.37

0.0000

0.00

1.0000

0.0004

7.48

0.0080

0.0004

0.0017

0.9498

7.00

0.0641

0.48

0.9359

0.0013

7.58

0.0260

0.0013

0.0057

0.9490

6.99

0.0773

0.59

0.9227

0.0067

9.11

0.1350

0.0067

0.0293

0.9438

6.96

0.2364

2.15

0.7636

0.0120

11.78

0.2450

0.0122

0.0527

0.9388

6.92

0.4126

4.86

0.5874

0.0172

16.51

0.3510

0.0175

0.0760

0.9339

6.88

0.5831

9.63

0.4169

0.0224

22.44

0.4600

0.0229

0.0995

0.9289

6.85

0.6949

15.59

0.3051

0.0238

25.47

0.4900

0.0244

0.1059

0.9276

6.84

0.7316

18.63

0.2684

0.0274

32.69

0.5660

0.0282

0.1223

0.9242

6.81

0.7916

25.88

0.2084

0.0285

35.94

0.5890

0.0293

0.1274

0.9231

6.80

0.8107

29.14

0.1893

0.0322

49.89

0.6690

0.0333

0.1445

0.9196

6.78

0.8642

43.11

0.1358

0.0332

54.95

0.6890

0.0343

0.1491

0.9187

6.77

0.8768

48.18

0.1232

0.0367

81.15

0.7660

0.0381

0.1654

0.9153

6.75

0.9169

74.40

0.0831

0.0380

94.03

0.7940

0.0395

0.1715

0.9141

6.74

0.9284

87.29

0.0716

0.0407

141.02

0.8520

0.0424

0.1842

0.9115

6.72

0.9524

134.30

0.0476

0.0434

222.47

0.9110

0.0454

0.1970

0.9090

6.70

0.9699

215.77

0.0301

0.0438

253.99

0.9200

0.0458

0.1989

0.9086

6.70

0.9736

247.29

0.0264

0.0461

422.62

0.9710

0.0483

0.2099

0.9064

6.68

0.9842

415.94

0.0158

70

I APRIL 2011 HydrocarbonProcessing.com

ENVIRONMENT concentrations in an H2O/MDEA solution having a molar ratio of 4.126/.2162~19 (or 74.27/25.73 weight ratio). Water-vapor tension is calculated with Antoine’s formula and the xCO , yCO values enable building a 2 2 pure CO2/pseudo-absorbent xe–ye equilibrium curve. Table 1 is limited to about 400 kPa and the figures in bold highlight the operating range slightly above atmospheric pressure, with MDEA having the significance of referred to MDEA. Pure CO2 solubility data in water data and MDEA were taken from the data

banks of chemical process simulators to understand the consistency of results when running the programs. The programs used had built-in thermochemical data and proprietary calculation packages that account for chemical reactions on the basis of Kent-Eisenberg correlations for amine absorption cases.20 The chemical reaction enhancement factor built into each proprietary package was not necessarily tested or interpreted, but comparable results were taken as the criteria that one simulator could provide results equivalent to another.

Table 2 compares published data against yCO 2 data that were also calculated at 40°C. The x-y curve available from Program A was generated with an amine thermodynamic package, although the ideal gas or Peng-Robinson equation of state could be justified due to the gas phase low pressure. To generate data congruent with the MDEA/H 2O ratio of experimental data, the molar fraction for the third component in the solution, x3 = xMDEA was entered for values up to 0.054, equivalent to = 1. Data were also generated at half

TABLE 2. Comparison of yCO2 over MDEA-H2O solution MDEA

[CO2]solut.

x1=xCO

yCO (I)

yCO (II)

yCO (III)

0.10

0.0216

0.0050

0.19

0.13

0.20

0.20

0.0432

0.0100

0.36

0.36

0.55

0.30

0.0650

0.0150

0.52

0.57

0.80

0.40

0.0865

0.0195

0.65

0.70

0.92

0.50

0.1080

0.0235

0.75

0.79

0.95

0.60

0.1300

0.0285

0.84

0.86

0.96

0.70

0.1520

0.0333

0.89

0.92

0.98 0.99

2

2

2

2

yCO (IV) 2

0.25 0.40 0.60

0.80

0.1730

0.0375

0.94

0.95

0.90

0.1950

0.0425

0.97

0.97

0.82

0.78

1.00

0.2162

0.0474

0.99

0.99

1.00

yCO (V)

yCO (VI)

kPa tot

0.15

0.12

8

2

2

0.32

0.30

10

0.55

0.54

15

0.69

0.69

22

0.79

0.81

32

0.87

0.87

51

0.92

0.91

80

0.94

0.94

118

(I) Published data points (II) Program A x-y data (x3=.054) (III) Program B x-y data (x3=.027) (IV) Program C x-y data (V) Program D flash @ kPa total, 40° (VI) Program E flash @ kPa total, 40°

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ENVIRONMENT the concentration x3 = 0.027 for gaining appreciation of the greater yCO increase, 2 or, conversely, the CO2 partial pressure increase in the vapor that reaches the maximum values in the absence of MDEA, when the phase equilibrium is between CO2 and H2O only. Programs A and B x-y data could precisely read from the 2,000 data points tables specifically generated at the xMDEA concentrations.

Program C x-y data, yCO , were hardly 2 legible from the physical-chemical built-in graph, steeply close to the yCO ordinate 2 axis for the very low xCO concentrations.

2 It appeared that Program C data bank predicts lower liquid captures and therefore greater CO2 in the vapor. To obtain more accurate x-y data, the process simulators were used to calculate the non-ideal enhanced equilibria: CO2 quantities and

concentrations in the vapor and in the liquid phase were thus obtained for crossreferenced experimental data by flashing sample feeds at the respective calculated total pressure and 40°C. Program D flash was made with an amine package and the residence time factor was increased from 0.3 to 1, as MDEA has slower reactivity than primary amines included in the software package.

TABLE 3. Generation of X-Y equilibrium curve for CO2 in 2.2M MDEA-water solution â?Ł

0.008

0.026

0.135

0.245

0.351

0.490

0.589

0.689

kPa

0.48

0.59

2.15

4.86

9.63

18.63

29.14

48.18

Torr

3.6

4.4

16.2

36.6

72.5

140.2

219.3

362.5

CO2/MDEA 40°C pp CO2, from referenced Table 1 (**data)

X=â?Ł(MDEA)/(MDEA+H2O) multiply â?Ł times 0.0487

MDEA solution is 25.73 wt% in water CO2 molar ratio in H2O+MDEA

xCO2

â?Ś=1.017

estimated density

0.00039

0.00127

0.00657

0.01192

0.01708

0.02385

0.02867

0.03353

Molar fraction of CO2

X/(1+X)

xCO2

0.00039

0.00126

0.00653

0.01178

0.01680

0.02329

0.02787

0.03245

Molar fraction of MEA

xCO2/â?Ł

xMDEA

0.04865

0.04861

0.04835

0.04810

0.04785

0.04754

0.04731

0.04709

Molar fraction of H2O

1â€“âŒşxi

xH2O

0.95096

0.95013

0.94512

0.94012

0.93535

0.92917

0.92482

0.92046

T=40° water vapor pressure =

55 Torr

and Pt =

760 Torr

H2O mol fraction in vap

xP°/Pt

s

0.06882

0.06876

0.06840

0.06803

0.06769

0.06724

0.06693

0.06661

CO2 mol fraction in vap

pp/Pt

y

0.00475

0.00584

0.02129

0.04812

0.09535

0.18446

0.28851

0.47703

1-y-s

0.92643

0.92540

0.91032

0.88385

0.83696

0.74830

0.64456

0.45636

1-y

0.99525

0.99416

0.97871

0.95188

0.90465

0.81554

0.71149

0.52297

YCO2

0.00478

0.00588

0.02175

0.05055

0.10540

0.22617

0.40551

0.91215

Air molar fraction in vap y/(1-y)

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ENVIRONMENT 0.140 0.130 0.120 0.110

Y = .111 in

L/G

L/G min.

0.100 0.090 Y CO2 molar ratio

Although laborious, the results marked as yCO (V) were consistent with data obtained 2 by flashing the same input feed with Program E reported also in column yCO (VI).

2 Judging from the reported literature, the simulated equilibrium data are scarce or hardly reliable at the low-end concentrations of xCO ≤ 0.01, but the flash cases were 2 consistent with experimental data.

Corrosion prevention. Concerning the selection of amine quantity relative to CO2, higher absorbing capacity primary amines are generally limited to ␣ = 0.5, the stoichiometric loading to form carbamate and a safe limit to prevent corrosion. This is also true for higher operating pressure where carbamates partially reverse to bicarbonates by hydrolysis. Tertiary amines can perform well at double loadings because they form bicarbonates rather than stable carbamates.17,21 The concentration increase of the amine-water absorbent decreases the CO2 saturation loading of the solution, like, for instance, the loading of 1M MDEA is ␣ = 1.2 against a permissible loading of 1.1 for a 2M solution, for the same CO2 partial pressure of 700 kPa. Nonetheless, the absorption in identical volumes of 2M solution can dissolve 83% more CO2, with the benefit to reduce recirculation.

On the basis of systems operated with MDEA at near atmospheric pressure, the simulations aimed at reducing the water dilution of the absorbent. It started to absorb CO2 with ␣ = 0.87, the overstoichiometric quantity of MDEA/CO2 = 1.15, with MDEA diluted in water at 25.73 wt%, dilution factor = 19. This was similar to the experimental data referenced in Table 1. All flash trials at 101 kPa and ␣ = 0.87 achieved the expected CO2 vapor-liquid separation and were extended by increasing the amine strength up to 46.88 wt%, dilution factor = 7.5. This is the upper concentration of reported experimental data.19 The substantial dilution of H 2 O/ MDEA to the molar ratio of 19 yielded higher absorption rates, from 73.25% to 84.5% at 35°C. However, this meant to double the rich solution rate. The same 85% CO2 absorption into the liquor can be achieved with a solvent loading increase to ␣ = 1, an operation that causes only a marginal overload for the stripper. The molar absorption degree increases at lower operating temperatures: 91.27% at 20°C vs. 66.37% at 40°C. The operation around 40°C is compatible with industrial cooling water normal temperatures and sufficient to limit amine volatilization losses.

0.080 0.070

CO2 inlet Yin MEA 5M MEA 2M MDEA 2.2M 40° MDEA 2.2M 400 kPa MDEA 4M 40°

1

0.060 0.050 0.040 0.030

1

X in = .0 Yout 95% = .00556 (5 theor. plates) Yout 63% = .0411 (1+ theor. plate)

0.020 0.010

3ⴜ5

0.000 0.000 0.005 0.010 0.015 0.020 0.025 0.030 0.035 0.040 0.045 0.050 0.055 0.060 0.065 X CO molar ratio 2

FIG. 2

Equilibrium and operating curves for indicated amine absorbents.

TABLE 4. MDEA absorption summary at indicated operating conditions and compared to MEA 5

6

7 MEA

1

2

3

4

Molar conc.

2.2M

2.2M

2.2M

2.2M

4M

4M

5M

kPa

101

101

400

400

101

101

101

Absorption

63%

95%

63%

95%

63%

95%

95%

[kmol/h] Ls min

13,320

20,086

7,284

10,984

8,038

12,121

6,060

Ls

17,316

26,111

9,470

14,280

10,449

15,757

7,878

H2O

16,528

24,923

9,039

13,630

9,252

13,951

6,866

MDEA

788

1,188

431

650

1,197

1,806

1,012

H2O/MDEA

21.0

21.0

21.0

21.0

7.7

7.7

6.8

Theor. plates

2.7

8.3

2.7

8.2

2.7

8.2

7.9

Equilibrium flash of CO2. While pure

CO2 equilibrium flash in H2O and MDEA can achieve appreciable absorption yields at low atmospheric pressure, it does not work when air is introduced. This further step in the simulation is important because the CO2 in the flue gas is in the range of 10% vol. The simultaneous and substantial water increase, as a thermal regulator and dissolver, fails to obtain a significant CO2 dissolution. Also, a major increase of operating pressure and/or MDEA quantities, as a CO2 reagent, might be expected.

At vapor-liquid equilibrium, the CO2 concentrations in the two phases are not equal. The chemical potentials are, causing the net transfer of solute to stop when the driving forces to distribute between phases become equal. The CO2 tendency

to get into the water solution is hindered by the diffusion and dissolving barrier in the solvent phase, whereas the CO2 is already distributed or uniformly exists within the incoming gas stream. The tendency, measured by CO2 fugacity, can also be measured in good approximation with the CO2 partial pressure in the flue gas, or by its solution molar fraction times the CO2 vapor tension. Having mixed CO2 and combustion gases, the CO2 partial pressure in the diluted gas is one-tenth the pressure previously built by the pure CO2 feed. Aside from non-ideality coefficients, it is reasonable to expect that for each temperature, i.e. at a given vapor tension, the CO2 molar fraction in the solution is likely to reduce to one-tenth. The immediate result is, with other things remaining unchanged, that the HYDROCARBON PROCESSING APRIL 2011

I 73

ENVIRONMENT same CO2 absorption can be obtained from the diluted gas when the operating pressure is increased by a factor equal to or greater than the gas-diluting factor.

The operating pressure was increased from 101 to 2,530 kPa, [P2 = P1(V1/V2) k, a gas-dilution factor V /V = 10 and k = 1 2 1.39, polytropic exponent obtained by the cp/cv specific heat ratio]. The CO2 transfer into the liquid was still in the range of 90% as previously obtained in absorbing the same quantity of CO2 without the diluting gas in the same quantity and solvent quality. Reducing the operating pressure to 200 kPa reflects an abrupt reduction to 56% efficiency, while simultaneously decreasing the absorber top temperature to 25°C barely achieves 66% absorption efficiency. Other than changing the solvent, the alternate possibility is to operate at low pressure and to work around the low partial pressure and gas solubility. This implies that a greater solvent quantity is necessary for extracting the same solute quantity.

Absorber determination. The

equilibria study and various flash cases generated enough sensitivity to proceed with designing the absorber. The absorber

column is a series of flash equilibria that outperforms the trial single steps, and the mass balances can be driven to the desired specification, provided that feasible outlet concentrations are targeted to approach the absorption limiting concentrations xe and ye. For a given gas flow and desired absorption, a reduction in liquid flow decreases the slope of the operating line: holding the gas rate and the terminal concentrations xin, yin and yout, the decrease of L lays the operating curve closer to the equilibrium curve and the strong liquor concentration increases to its maximum possible value, limited by the equilibrium curve.

The pinch of the curves sets the minimum L and a taller absorber, i.e., the infinite number of stages. A greater L signifies to maintain the driving force and to shorten the absorber. However, a costlier stripper and more steam are needed to recover the absorbed solute gas from the diluted liquor.

For economical operation, the operating line is chosen approximately homothetic to the equilibrium line. As for the generic material balance of CO2, the component migrating from the vapor to the liquid phase, the countercurrent operating line is analytically written as:

L[x in/(1 – x in) – x/(1 – x)] = G[y in/ (1 – yin) – y/(1 – y)] (2) where L and G are the respective molar rates of CO2-free (non-migrating rates) solvent and inlet gas, x and y are generic points of the operating line and the subscript “in” refers to the inlet liquid and gas molar fractions.

By imposition of L, G and inlet concentrations, the outlet concentrations are found. If a given percent efficiency of absorption is imposed, the L/G ratio should be checked against the minimum permissible ratio. This method was preferred to study feasible absorptions with different amine concentrations and pressures, taking the earlier result of 63% as a minimum reference value and improving it at atmospheric or even higher pressure to target a 95% absorption of CO2. Analytical and graphical solutions were developed for all the cases and only the graphical result is presented here, since the limiting equilibrium point (xout min) had to be read in both cases from the equilibrium curve interpolated from the experimental data.

The equilibrium curve determined from the published data points of 2.2M MDEA in water (25.73 wt%) at 40°C was plotted

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ENVIRONMENT against the curves of other operating cases and amines at the same temperature. The starting data were CO2 partial pressure for various loadings â?Ł; the amine-water solution density was estimated by interpolating physical data, and, while concentrations in the solution were derived from â?Ł, the partial pressures of water and air were calculated after setting the overall gas pres-

sure. Table 3 reports the equilibrium curve X-Y calculations made for the atmospheric operation with 2.2M MDEA, deliberately restricted to very low liquid concentrations for our intended application.

Data for MEA and higher-concentration MDEA were used from referenced material, and the elaboration of the other relevant equilibrium curves for the com-

Absorption, %

100 95 90 85 80 75 70 65 60

2,000

Program B Program C 1,800

1,600 1,700 1,800 1,400 1,500 1,600 1,200 1,300 1,400 MDEA, kmol/h 1,000 800 1,200 1,100 H2O, kmol/h 900 1,000

FIG. 3

CO2 absorption simulated with Programs B and C for amine and water combinations.

parison followed the same procedure.17 Fig. 2 illustrates the equilibrium curves for the amines characterized in the legend for the McCabe-Thiele construction.

The flue-gas inlet was taken as 100,000 Nm3/h, i.e. 3,700 kmol/h containing 10 % vol CO2. To simplify calculations, the feed gas was not characterized in all its constituents: H2O, N2, O2 and impurities; made for CO2, all gases were considered exception as one carrier inert gas, assimilated to air. The 10% gas humidity was disregarded, water would add or evaporate from the solution depending on P, T without appreciable solvent rate change and it was assumed that the solvent entered the absorber with no CO2, Xin = 0.

All solvent rates L were increased by 30% with respect to the minimum rates Lmin, found by pinching the equilibrium curve at Yin with the L/G line originating in Xin, Yout. X-Y molar ratio coordinates were used for the clear advantage to straightening the operating lines and because the dry and wet equilibrium curves become the same line and overcome the explained assimilation of water vapor to simple inert gas. Different gas dilution CO2 rates were also tried if more air or inert were entering, and the

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ENVIRONMENT partial pressures reduction was equivalent to working at higher overall gas pressure. By confronting curves of different amine concentration, higher gas solubility is exhibited in diluted amines, but the ultimate overall loading is lower and a higher L/G ratio is required for the same operating pressure.

As reported, earlier simulations and the flash trials remained short from achieving 95% absorption unless unpractical low operation temperatures were chosen.

However, the graphical and analytical results constructed on the reported solubility data indicated the improvement that CO2 absorption is feasible at 95% or more.

This provided a sufficient reactive amine quantity entering the system, not necessarily increasing the absorber operating pressure.

Table 4 shows a summary of the main cases: the better absorption is accomplished at 101 but also at 400 kPa with increasing the circulating MDEA. Substantially increasing the amine quantity in column 2, referring to a lean MDEA concentration of 2.2M, increases the absorption to 95%. Similarly, column 4, operating at 400 kPa and with the same 2.2M concentration, exhibits an increase of amine from 431 kmole/h to 650 kmole/h and accomplishes absorbing CO2 at 95%. The amine quantity and concentration increase of columns 5 and 6 accomplish the same performance of columns 1 and 2, respectively. The water rate can be optimized and can reduce the absorbent regeneration rates. For comparison, the absorber was also calculated with 5M MEA, which is a stronger reactivity absorbent and exhibits a lower L/G ratio. Pressurized operation reduces the solvent rate L and does not affect the number of theoretical stages.

The calculation of theoretical stages with Kremser’s equation is known to apply to isothermal operation, but the method remains applicable, due to the large amount of water that makes operations near isothermal.

Absorber calculation. The calculated flowrates and concentrations of flue gas and solvents were finally fed to the process simulator, to replicate the cases and optimize operating conditions. The exercise was limited to the plant’s absorption section. Although solvent stripping is important and determines the greater portion of energy required for the whole process, stripping does not represent a feasibility problem, as steam and its operating parameters can be freely chosen for optimization.

Previous considerations were all focused on 40°C and 101 kPa, as it was important to validate the methods at the experimental

TABLE 5. MDEA process simulations for various solvent ratios and P = 111 kPa Earlier work

2.2M

2.2M

4M

4M

2.2M MDEA @400 kPa

5M MEA

T °C in, gas/solv.

38

38

38

38

38

38

38

T °C out, rich sol.

48

40

43

42

46

49

56

CO2, kmol/h

373

373

373

373

373

373

373

1,000

843

1,271

1,342

2,024

695

1,012

H2O, kmol/h

10,520

16,473

24,841

9,107

13,733

13,585

6,866

⌺ solvent, kmol/h

11,520

17,316

26,112

10,449

15,757

14,280

7,878

0.37

0.44

0.29

0.28

0.18

0.54

0.37

38

26

26

51

51

26

33

MDEA/CO2

2.68

2.26

3.41

3.60

5.43

1.86

2.71

H2O/MDEA

10.5

19.5

19.5

6.8

6.8

19.5

6.8

Absorption %

63

69

94

75

99

77

100

Theor. plates

10

5

6

3

9

9

8

Plates @ 30% effic.

33

17

20

10

30

30

27

MDEA, kmol/h

␣ Amine wt%

data points. The process simulations were run at slightly different conditions, 38°C and 111 kPa, to compare results with the earlier work runs and to allow for a moderate pressure drop in the absorber.

Solvent rates. The solvent rates calcu-

lated analytically were improved by amine and water gradual reductions. The absorber was calculated for 10 theoretical stages with a total stage efficiency of 30% chosen from various engineering reports and published design experiences.22 A summary for the few runs simulated with Program B is reported under Table 5. Columns identified at 4M concentration show that a water quantity increase gets equal or better absorption, provided that the amine quantity is also increased. Halving the water moles requires approximately 50% more amine, as columns 3 and 5 compared to columns 2 and 4, respectively. The right-side two columns (400 kPa MDEA and 5M MEA) are reported for comparative purposes.

The absorption can achieve 95% efficiency at atmospheric pressure, provided that enough amine is loaded and run at low ␣. To save on equipment and to limit stripping steam consumptions, more concentrated amine should be used. The 4M column exhibiting 2,024 kmol/h MDEA obtains a 99% CO2 capture. However, a double amine rate and a 40% water increase are necessary, as compared to earlier work shown in the first numerical column. The number of stages is practically unchanged.

The simulation study was done for a mix of 100 H2O and MDEA combinations, obtaining a data point feasibility surface for absorptions above 60%. Program B study trials are shown in yellow in Fig. 3. Simi-

larly, the numbers in blue were obtained by repeating the trials with Program C. Given equal convergence of the two systems, Program B achieved higher absorptions, whereas Program C exhibited greater absorption with more amine at a higher dilution. In general, the absorption between 75% and 95% of incoming CO2 can be obtained with both simulators in a variety of low-pressure operating conditions. HP LITERATURE CITED For complete literature cited, visit HydrocarbonProcessing.com.

Marco Tellini has over 30 years experience in water, gas and waste treatments, petroleum engineering and manufacturing of chemicals acquired in process design. He has worked in many senior capacities for international companies. He earned a BS degree in chemical engineering from Politecnico di Milano and received an MBA from Fairleigh Dickinson University. While working in the US, Mr. Tellini became a licensed engineer in New Jersey, New York and Arizona. He earned a PhD in chemical engineering from the Politecnico di Milano in 2005 and continued on in environmental engineering studies and post-doctoral research in thermal processing of municipal/ industrial wastes.

Paolo Centola is full-time professor of environmental chemical engineering at Politecnico di Milano and has over 30 years faculty experience in the chemical engineering department with earlier academic positions in research and as an assistant professor in industrial chemical engineering.

He graduated with a BS degree in chemical engineering from Politecnico di Milan. Mr. Centola’s primary fields of expertise are synthesis of fine chemicals, catalytic processes and pollution control treatments. He is well known for hundreds of international scientific publications and consulting in various fields of the chemical industry and also initiated and directed the Olphactometry Laboratory of Politecnico di Milano since 1997.

HYDROCARBON PROCESSING APRIL 2011

I 77

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CLEAN FUELS

Meeting diesel specifications at sustained production New approach rethinks crude and vacuum distillation units operation to recover more distillate D. SINGH, Uhde Shedden (Australia) Pty Ltd., West Melbourne, Victoria, Australia

R

efiners will face a tough challenge over the coming years to cope with growing diesel demand at the expense of gasoline, while conforming to the progressively tighter diesel fuel specifications to meet environmental regulations. The more stringent specifications are likely to hurt the overall diesel yield due to possible rejection of heavy ends from the present product spread.

Future diesel will have a narrower density band, lower cloud point, lower T95 (D86) specification and less sulfur. Therefore, aligning the existing refineries with progressively tighter diesel specifications at a sustained diesel yield will be quite challenging.

Some recent compliance project experience is reported here; the goal is to identify the most cost-effective and appropriate modifications to an existing plant to achieve future diesel specifications at a sustained production cost and rate. Project constraints prompted applying engineering solutions rather than installing more expensive process technology options that would have required reconfiguring the existing refinery at high cost.

Study refinery. Finished diesel product in a refinery is a blend

of various distillate-grade streams, as shown in Fig. 1. A blend optimization is performed with refinery blending simulation software, utilizing the individual blend streams composition and associated proportions in the pool for maximum diesel production at the required market specifications. In a typical refinery configuration, these blend constituents are produced from the units, as illustrated in Fig. 2, and include: • Crude distillation unit (CDU). This is the main source of straight-run (high-cetane) saturated distillate-grade material to the pool.

• Hydrocracker unit. The main source for cracked but saturated distillate-grade material in a refinery designed for higher diesel production.

• Fluid catalytic cracking unit (FCCU). This unit produces cracked unsaturated (poor quality diesel) distillate material as a secondary product. The intent of the unit is to produce mainly high-quality gasoline or petrochemicals.

• Coker unit. This unit also produces cracked unsaturated poor-quality distillate-grade material as a secondary product.

A typical refinery contains either an FCCU or a hydrocracker unit, depending on whether higher gasoline or diesel production is targeted. A review of Figs. 1 and 2 identifies the CDU and vacuum distillation unit (VDU) as potential sources for improving the diesel production by improving fractionation

performance. In particular, for older refineries, these may have already been revamped to achieve greater throughput rates. This improved fractionation may enable the operator to compensate fully for the possible loss in diesel production due to tighter future specifications.

CDU upgrades. It is quite challenging to upgrade the atmo-

spheric distillation column to achieve higher diesel recovery while maintaining the stream cloud-point specification. In principle, such upgrades tend to lift more diesel-grade material by elevating the feed flash-zone temperature or stripping harder in the CDU bottom section. These require the refiner to implement several de-bottlenecking options, either individually or collectively: • Maximizing utilization of crude-feed heater duty and tactically upgrading the crude preheat train to maximize the heat recovery to increase the crude column feed flash-zone temperature.1 • Rectifying CDU bottom stripping steam rate to maximize diesel-grade material stripping from the atmospheric residue. This may require upgrading the stripping section and atmospheric gasoil (AGO) wash section (section between feed flash zone and AGO pumparound) to avoid any possible fouling or coking.

• Maximizing diesel recovery by minimizing diesel fraction overlap with AGO, kerosine and fractions.

Fig. 3 shows a typical configuration of an atmospheric crude column bottom section. Increasing the CDU feed flash-zone temperature for higher diesel lift also results in heavy constituents’ lift, responsible for diesel cloud-point specification. A typiStraight-run distillate from hydrotreater unit

Cracked and saturated distillate from hydrocracker unit Diesel pool Cracked and unsaturated distillate from FCC unit Hydrotreater Cracked and unsaturated distillate from coker unit FIG. 1

Typical product diagram for a refinery.

HYDROCARBON PROCESSING APRIL 2011

I 79

CLEAN FUELS ing trays with packed beds will overcome the impact of increased vapor loading on Amine treating the column pressure drop. The proposed sulfur H2S Claus Other gases sulfur plant LPG modifications of Fig. 4 can provide several Treaters Gas processing advantages over the existing conventional Gas Butanes Light atmospheric crude column: naphtha Isomerate Isomerization Hydrotreater • A controlled AGO wash rate ensures plant uninterrupted wetting of wash-section Heavy naphtha Reformate Catalytic packing needed for trapping the heavy tails, Crude oil Hydrotreater reformer Jet fuel responsible for off-spec diesel product on kerosine Jet fuel/ Treater cloud point. kerosine • A controlled AGO wash configuraHydrocracked gasoline Diesel oil Diesel oil Hydrotreater tion provides flexibility to optimize the Diesel oil AGO stream flow to minimize valuable AGO Vent Light naphtha and kighter loss from the wash section. In general, the i-Butane Alkylate Alkylation optimum AGO wash rate is achieved by LPG gas Heavy ensuring that the rate of liquid from the FCC naphtha gasoline LVGO wash section is approximately 3–3.5 mass% Hydrotreater HVGO Gas of the total column feedrate.

Light cycle GO Slurry • A guaranteed performance of the wash Vacuum (after hydrotreating) Fuel oil residuum Coker naphtha section enables optimizing stripping steam Coker GO (after hydrotreating) rate in the column bottom for improving diesel and AGO recovery from the column bottom stream while maintaining diesel Petroleum coke cloud-point specification. Depending on COT, 10 lb to 20 lb stripping steam per bbl FIG. 2 Process flow diagram of refinery. of the bottom product provides the optimum results.

• Replacing trays with packing increases the number of theoretical stages in the AGO and diesel sections, Atmospheric column which helps to minimize the distillation overlap between AGO and diesel fractions.

• Able to control diesel under-reflux flow to the AGO section to control slippage of valuable diesel material in the AGO fraction.

• Increased diesel and AGO recovery improves the crude Steam Diesel preheat-train performance (extra heat available for exchange) and also reduces feedrate to the VDU. The reduced VDU feedrate lowers the total ambient heat lost via the vacuum gasoil (VGO) air coolers, thus improving the overall heat efficiency.

Steam Crude • Reduced crude column bottom rate generates spare duty in Steam the VDU feed heater and the vacuum section for minimizing the AGO vacuum residue rate.

Crude preheat Bottom train The proposed upgrade of the studied tower is able to increase the diesel yield approximately 1.5 vol% to 2 vol% of the total FIG. 3 Configuration of the atmospheric crude column bottom crude feedrate. The proposed upgrades have a potential payback section. of three years.

Diesel pool

Thermal cracking delayed coker

Fluid catalytic cracker (FCC)

Vacuum distillation

OR

Hydrocracker

Atmospheric distillation

Atmospheric bottoms

Gasoline pool

Refinery fuel

Fuel gas

cal overloaded existing crude column cannot prevent these heavy tails entering into the diesel draw stream. A similar limitation occurs when the column bottom stripping steam rate is increased to enhance diesel recovery. Further, these operational changes increase the column’s pressure drop due to the increased vapor traffic and suppress the upgrades effectiveness to some extent.

Therefore, these operational changes should be accompanied by some mechanical modifications in a typical crude column bottom section, as suggested in Fig. 4, to obtain the desired results.

Controlled and optimum AGO wash rate will prevent heavy tails carryover into AGO and diesel sections that would otherwise occur at the increased feed flash-zone temperature and at the increased stripping steam rate. An optimum AGO wash rate minimizes valuable AGO loss from the wash section. Replac80

I APRIL 2011 HydrocarbonProcessing.com

VDU upgrades. Fig. 5 shows a typical dry VDU. A wet VDU

(stripping steam in the column bottom) is almost taken over by dry VDU once high vacuum generation and low pressure drop internals became feasible. No stripping steam in the column bottom makes the dry VDU column smaller in diameter and also requires a smaller vacuum section as compared to the wet VDU. The usual intent of a VDU in refinery is to recover the VGO fraction from the CDU bottom stream by separating the fuel-oil grade from the heavy tails. The recovered VGO fractions are processed further in downstream conversion units into a more valuable diesel or gasoline products. VGO is coarsely separated into heavy VGO (HVGO) and light VGO (LVGO) in the column upper section to provide required quality wash oil (HVGO) to HVGO wash section and also to minimize the column top sec-

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CLEAN FUELS Atmospheric column

P1-LVGO pumparound

Diesel section

AGO section

Diesel under FIC relfux

Steam

Crude Steam Crude preheat train

AGO wash

Diesel Waste section

Stripping section

LVGO section Addition HVGO section HVGO section HVGO wash section Slop oil wash section

P1 new-Hot LVGO under reflux P2-HVGO pumparound P3-hot HVGO under reflux

Steam AGO

FIC

LVGO

P4-Slop pump around

HVGO Feed heater inlet

CDU bottom

OR

Slop oil Fuel oil

Bottom Note: Required upgrades are shown in red color

Modified atmospheric crude column bottom section to increase diesel-product yield (modifications shown in red).

FIG. 4

FIG. 6

Scheme of a dry VDU with modifications to improve fractionation performance (modifications shown in red).

P1-LVGO pumparound LVGO section P2-HVGO pumparound P3-Hot HVGO under reflux

HVGO To feed surge drum

CDU bottom

FIG. 5

LVGO

P4-Slop pump around

OR

Slop oil Fuel oil

Typical scheme of a dry VDU.

tion diameter. Thereafter, LVGO and HVGO combined streams are usually sent to either the hydrocracker or FCC units for further processing.

A typical dry VDU has approximately eight theoretical stages in total, almost equally distributed in all four sections, i.e., the slop-oil wash section, HVGO wash section, HVGO section and LVGO section. The slop-oil wash section is an optional feature considered in some VDUs; it is used to further ensure that the heavy metals are retained in the slop oil, thereby eliminating contamination of the VGO stream.

Traditionally, VDUs are not designed for sharp separation between HVGO and LVGO. This can be clearly seen in a performance data plotted for a typical existing VDU in Fig. 7. This VDU was receiving lighter than the usual feed due to inadequate lift in the CDU feed flash zone, caused by the poor performance of the crude preheat train and a reduced stripping steam rate in the column bottom to maintain the diesel side-draw stream cloud-point specification. The reduced stripping rate had resulted in fouling/coking in the CDU stripping section, thereby causing further deterioration of the overall performance.

Poor performance in the CDU could be compensated by upgrading the downstream VDU for enhanced diesel recovery.

For example, an existing VDU modification can be justified if the upstream CDU is upgraded for a higher diesel recovery.

Cost-effective modifications of an existing CDU can reduce 82

I APRIL 2011 HydrocarbonProcessing.com

TBP, °C

HVGO section HVGO wash section Slop oil wash section

700 650 600 550 500 450 400 350 300 250 200 150 100 50 0

VDU Feed LVGO HVGO VDU bottom

0

FIG. 7

10

20

30

40 50 60 Vol % distilled

70

80

90

100

Performance of the existing VDU.

diesel loss in the bottom stream significantly but not completely.

Furthermore, a CDU fractionation efficiency cannot be stretched beyond a certain limit. Therefore, it has been observed that even a reasonably well-performing existing CDU in post-upgrade operation can slip diesel-grade material into the bottoms in sufficient quantity to justify the downstream VDU upgrades to recover the diesel. This upgrade option will not only compensate for the diesel-product loss due to the tighter specifications, but also may improve the refinery’s overall economics by increasing diesel recovery.

A study was conducted for upgrading a conventional dry VDU for recovering diesel-grade material from a poorly performing CDU bottom stream. The proposed modifications shown in Fig. 6 shifted VDU fractionation performance from Figs. 7 and 8. The improved separation recovered allowed approximately 80% of the diesel slipping from the CDU. The proposed modifications were able to recover almost 40 vol% of VDU feed as diesel-grade material for hydrotreating into a finished diesel product. In many conventional refinery configurations, this diesel fraction would have been recovered as VGO and would have been routed to either the hydrocracker or FCCU for conversion. The proposed upgrade was able to enhance the overall diesel production by 3 vol%–5 vol% of the CDU total feed in the diesel-based refinery (refinery with hydrocracker unit) and that could be even greater in a refinery

CLEAN FUELS

TBP, °C

operating with an FCCU. The estimated payback period for the proposed modifications is two years.

The VDU upgrades proposed in Fig. 6 (shown in red) can be explained as: • Tripling HVGO section theoretical stages for sharp separation (reduced overlap) between HVGO and LVGO. In this scenario, LVGO was essentially the diesel-grade material.

• Hot LVGO under-reflux (P1 new) to HVGO top section to maximize the diesel recovery in the LVGO section while maintaining the stream cloud-point specification.

• Doubling of the LVGO section theoretical stages reduces LVGO pumparound (P1) rate by achieving a close temperature approach between the vapor inlet and the liquid leaving the LVGO section.

700 650 600 550 500 450 400 350 300 250 200 150 100 50 0

VDU feed Diesel VGO VDU bottom

0

FIG. 8

Options. This study shows that future diesel specifications

can be met at sustained production rates, provided that refiners reorient their distillation operations to improve the diesel separation in CDU and VDU. This concept will allow refiners to improve diesel production while also meeting future specification at the nominal upgrade CAPEX. A similar distillation approach in the existing residual FCC or hydrocracker fractionation sections may further improve overall refinery diesel production. HP

10

20

30

40 50 60 Vol% distilled

70

80

90

100

Performance of the existing VDU after modification to increase diesel make.

refining, for reviewing and providing their valuable feedback to shape this article into its present form.

1

LITERATURE CITED Singh, D. and S. Van Wagensveld,” Redesign crude preheater train for efficiency,” Hydrocarbon Processing, May 2007, pp. 91–94.

Dinesh Singh is a principal engineer with Uhde Shedden (AusACKNOWLEDGMENT Special thanks to Graeme Cox, Uhde Shedden chief technology and sustainability officer; Patrick Cadenhouse-Beaty, Uhde Shedden manager of refining technology; and Richard O’Beirne, Uhde Shedden chief process engineer

LIVE

WEBCAST

tralia) Pty Ltd. He has over 18 years of worldwide process engineering experience in petroleum refining, offshore and onshore oil and gas projects. Mr. Singh holds a BS degree in chemical engineering from the Indian Institute of Technology, Roorkee, India. He is a recognized chartered engineer with IChemE UK.

THURSDAY, APRIL 28, 2011 • 10 a.m. CST/11 a.m. EST

HEINZ BLOCH:

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DURING THE WEBINAR, HEINZ TACKLES TOUGH AND IMPORTANT QUESTIONS INCLUDING: • How do you train an educated and informed employee who knows how to make the right decision?

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• Why and when should pump failures be viewed as system failures?

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SAFETY

Keys to successful alarm management Here are the features you want in alarm management software J. GOOCH, Consultant, Houston, Texas

O

ver the past few years, alarm management has become a very important topic within a number of articles, technical papers and books.

Most of the discussions have been centered on the importance of alarm management and how to implement and maintain an alarm-management process. However, not much has been written on the tools to support alarm management and, in particular, alarm-management software. This article is intended to meet that need.

A number of alarm-management software systems are on the market. As you might expect, each has its own strengths and weaknesses. This article will provide a vendor-neutral listing of key features, along with a brief discussion of each.

Connectivity. Although alarms can be generated on many systems such as distributed control system (DCS), emergency shut-down (ESD), tank-gauging or flowmeasurement systems, most companies bring alarms to the DCS since it is used as the primary device for presenting information to the operator. Therefore, it is absolutely vital that the alarm-management software has good connectivity to the DCS. Numerous ways to connect an alarm-management system (ALMS) to a DCS include: • Object linking and embedding for process control (OPC) data access (DA) • OPC alarms and events (AE) • Printer intercept • Open database connectivity (ODBC) • Event files.

The method does not matter much as long as the connectivity scheme is stable, collects information on all alarms and can collect at least a minimum set of parameters for each alarm. A suggested minimum list of parameters is: • Alarm time/date • Tag name

• Description • Alarm [e.g., process variable high (PVHI), process variable low (PVLO), change of state, etc.]

• Value at time of alarm.

For certain advanced features, it is useful if the connectivity solution provides the ability to write information back to the DCS. However, keep in mind that it is fundamental that the ALMS had good data with which to work. Therefore, if the ALMS you are considering does not have rock-solid connectivity, find another ALMS. Period.

Alarm analysis. Another fundamental feature is a suite of alarm analyses. Information from alarm analysis will be used to drive alarm monitoring and reduction efforts, as well as to provide information for reporting mechanisms. The bare minimum analyses to be included are: • Alarm frequency—A listing of alarms in order of frequency. The analysis should be able to show what percentage of total alarms comes from each alarm reported.

• Alarm rates—A listing of alarm rates per unit of time over an extended period, for a selected operator position. Typical time units are per day, hour and 10 mins.

The analysis must be able to distinguish between annunciated alarms and recorded alarms. This type of analysis can be used to give an estimate of operator and system alarm loading.

• Alarm floods—Alarm floods can be the bane of an operator’s life. Alarm floods are generally considered to occur when the alarm rate exceeds 10 alarms per 10-mins.

It is commonly considered that an alarm flood is a time when the system generates more alarms than the operator can process.

It represents a time when the alarm system is of no value.

• Chattering alarms—An alarm that occurs three or more times in a minute is

considered to be chattering. A listing of chattering alarms can be used by the maintenance and engineering groups to target resources on instrument and process problems.

Additional, very useful alarm analyses are: • Duplicate alarms—A listing of alarms where one alarm always follows another.

Effectively, the alarms are duplicates and the removal of one should be considered.

• Stale alarms—A listing of alarms that have been in the alarm state for more than 24 hrs. A stale alarm is not available to the operator and may be considered disabled.

Such an alarm should be reviewed and repaired or removed.

• Dynamic alarm priority distribution—A distribution of alarms by priority. This can be an indication of a problem with alarm priorities.

• Operator changes—A listing of changes initiated by an operator, such as changes to alarm, controller state or controller setpoints. A high change rate is indicative of problems with the alarm system or control loops. The more time an operator spends adjusting the system, the less time is spent managing the unit.

The alarm analysis system should support a very flexible set of alarm system parameters. This is generally accomplished by the use of filters that allow selecting such things as: • A specific operating area or set of areas • Time periods such as past seven days, complete week, 30 days or complete month • Alarm type • Alarm priority.

If a site can get control of the most frequent and chattering alarms and the major alarms during alarm floods, the average alarm rates will come down. Lowered alarm rates during an abnormal situation give the operator time to respond to the alarm. This means the operator is thinking rather than

I

HYDROCARBON PROCESSING APRIL 2011 85

SAFETY reacting. However, lowered alarm rates do not solve the entire problem. The alarm system must be reviewed to ensure that the optimum collection of alarms and priorities are included.

Alarm rationalization support.

An alarm rationalization (also known as an alarm objective analysis, or AOA) is the systematic review of all potential alarms within an operating area, applying a rigorous set of selection criteria. This is one

of the best ways to determine an effective alarm set for a control system. Typically, a site will develop a formal document, often called an alarm philosophy, that details for alarm selection and priority determination criteria. The ALMS must support the alarm selection and priority determination criteria. Most sites use a selection mechanism based on the maximum severity of the consequences if there is no response to the alarm and the time available for the operator to react. The details of developing

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selection criteria are much too complex to be discussed here. Please see the references included at the end. The ability to document the alarm rationalization results is crucial. This will allow others to determine the thought process later. Also, the alarm system is essentially part of the unit system.

Being able to show how and why an alarm has been set may be of importance during a thorough review of such systems.

Every alarmable parameter for each tag in the system must be presented for review.

This implies some knowledge of the system configuration by the ALMS which, in turn, implies that some mechanism for importing configuration information into the ALMS. This is not trivial. The vendor must be able to demonstrate a reliable configuration import method for all applicable control systems.

Other desirable features of an alarm rationalization support package are: • Filtering/selection capabilities—it is often good practice to look at a group of tags together. For example, it might be prudent to look at all of the tags related to a distillation column to create a consistent column alarm strategy for the column, as opposed to looking at individual tags in isolation.

• Copy/paste capabilities—once an alarm strategy is determined for one piece of equipment, it may be possible to use it for other similar pieces of equipment. This has the advantage of enforcing consistent strategies.

• Export of results—This can ease developing management of change (MOC) documentation.

• Results implementation—Results of an alarm rationalization are only useful if actually implemented. There are often hundreds, if not thousands, of changes that must be made to the alarm system. ALMS support is convenient and a reliable method to transfer the results to the control system.

Reporting. Reports often form the heart

of an alarm-system improvement process.

It has been said that if you cannot measure an activity, you cannot improve it. Most ALMS reporting packages are based on the analysis package. Reports should be: • Configurable to meet site needs • Able to run automatically • Available in multiple formats such as HTML, spreadsheets such as XML or flat files.

Most companies separate the control system from the IT business LAN by a firewall of some type. Most ALMS packages will be on the control-system side of the firewall.

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Reports are likely to be required on the business LAN for ease of reporting to management. Some method for transporting reports across the firewall will be beneficial.

Many companies use key performance indicators (KPIs) to measure performance.

KPIs for the alarm system will likely be developed as a part of the alarm philosophy.

The reporting package should have some means of generating reports that match the KPI requirements; otherwise, the site will need to process data to generate the required KPI. For example, import XML files into Excel and calculate the KPI data there.

Advanced features. The basic features listed previously can be used to improve alarm-system performance by focusing on remedial activities, developing an optimal set of alarms, and providing reporting facilities to support ongoing improvement processes. These features assume that the alarm system is static. There are features that are more real-time, where the alarm system is modified based on input from the system, or on predefined operator input. This is a broad field so only a few concepts can be briefly discussed.

• Audit and enforcement—Without attention, alarm systems will degrade and drift from the settings determined during alarm rationalization and implemented

by MOC processes. Inappropriate change comes from many sources and is, unfortunately, common. An alarm audit is the periodic comparison of the alarm-system settings with the values implemented. Lists of discrepancies can be reported as needed.

Also, the ALMS can correct discrepancies by implementing the correct value in the control system.

• Alarm shelving—Alarm-system malfunctions will occur at the most inconvenient times. Alarm shelving allows for the temporary alarm suppression in a controlled fashion. Care must be used with this feature since an alarm that is shelved forever is no alarm. To prevent this, alarm shelving should have the following characteristics: o Allow shelving of only one alarm at a time, not all alarms for a tag. o Provide security for access. o Provide control over the maximum shelving time allowed. o Record the identity of the person shelving the alarm.

• State-based alarms— Since some equipment can exist in multiple states (such as out-of-service, half rate or alternative feed stock), different alarms may apply at different times. Once the different states have

been identified, alarms for the affected tags will be rationalized for each state. The statebased alarm package will implement the different alarms as the different states occur.

This can be triggered by a change in a tag value, an operator action or a calculation. A good state-based alarm package will incorporate a method of performing a calculation to control the transitions between states.

• Alarm flood suppression—despite all efforts to create an optimum alarm parameter set, alarm floods may still happen, especially during an upset. An alarm-flood suppression package can help in this situation by detecting an abnormal situation and adjusting the alarm system by either modifying alarm priorities/settings or by suppressing the alarms. The flood trigger must be detectable and the alarms to be included must be known. The package must also be able to reverse the changes appropriately. It should be noted that it takes time for the event to be detected and the alarm changes made. There may well be an initial alarm burst, but the alarm rate will fall away very quickly, which reduces demands for operator attention.

These packages must be aware of each other and work together. For example, the audit and enforcement package must be aware of changes made by the alarmshelving package and the state-based alarm package to prevent errors in reporting and potentially enforcing the wrong alarm values. And there you have it—a brief discussion of features that, in my opinion, are in an ALMS. Hopefully this will provide some food for thought if the need should arise to evaluate an ALMS. HP BIBLIOGRAPHY The Equipment and Materials Users’ Association Publication No. 191, Alarm Systems: A Guide to Design, Management and Procurement, www.eemua.org.

ANSI/ISA—18.2-2009, Management of Alarm Systems for the Process Industries, www.isa.org.

Hollifield and Habibi, The Alarm Management Handbook, www.pas.com.

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Special Supplement to

CATALYST

2011

CONTENTS Innovation drives new catalyst developments C–93 Global demand for catalysts to exceed $17 billion in 2014 C–95 Rare earth dilemma forces catalyst changes C–95

Corporate Profiles Crealyst C–92 Axens C–97 BASF C–99 Catalyst Services C–101 Criterion C–103 Grace Davison C–105 Haldor Topsøe C–107 Europhtal Sweetening Catalyst C–109 Sabin Metal Corporation C–111 Saint-Gobain C–113 hte Aktiengesellschaft C–114 Cover photo courtesy of BASF.

CORPORATE PROFILE: CREALYST CATALYST 2011

CREALYST focuses on dense loading operations CREALYST is a company dedicated to providing state-of-the-art catalyst loading services. With more than 35 years of experience in the oil and refining industry.

“Calydens”advantages. CREALYST is a catalyst dense loading provider with proprietary and patented ‘CALYDENS apparatus’ always meeting guarantees and customer satisfaction with all major catalyst manufacturers. A homogeneous distribution of catalyst across the entire cross section of the catalyst bed from bottom to top reaching 12”–300mm from top plates. CALYDENS internals are designed for optimal catalyst distribution; with flow-rate regulator. The machine runs on a continuous flat bed profile, achieving up to 25% more catalyst loading on versatile reactor diameters ranging from 0.5m to 7.5m. Soft bristles/brushes for practically zero attrition of catalyst particles, reaching loading flow-rate of 20 m3/hour.

Reactor performances. Improve your unit life cycle through better reactor operation resulting from a fully homogenous and uniform catalyst bed. Catalyst dense loading with CALYDENS prevents “Channeling” of hydrocarbon streams and improving reactor yield and performance, ideal for revamp of existing units or new units.

Operator safety & ease-of-operation. CALYDENS is very light (15 kg), safe and easy-to-operate, with a bed profile control device. The CALYDENS installation is fast (approx 15 min) & fits all opening configurations.

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HYDROCARBON PROCESSING

Commercial aspect and reference. CREALYST remain a neutral and independent services provider, committed to continuous technological progress for the benefit of our customers. CREALYST established in 2004 has dense loaded with CALYDENS thousands of tons of catalyst for major refiners and catalyst manufacturers.

Contact information CREALYST France (head office) 3 ter rue de la forme, 78420 Carrières Sur Seine Phone/Fax: +33139148335 Email: info@crealyst.fr Website: www.crealyst.fr Two line caption

CREALYST India

Phone: +919650640798 Email: ugoel@crealyst.fr

CREALYST Asia Phone: +66847617915 Email: edomon@crealyst.fr

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CATALYST 2011

Innovation drives new catalyst developments W. LETZSCH, Warren Letzsch Consulting PC, Ellicott City, Maryland Future challenges in environment and product specifications involve more sophisticated catalyst systems The catalyst business continues to reflect the trends of the refining and petrochemical businesses it serves. These trends include globalization, consolidation, integration and diversification.

The worldwide refining community is shifting from North America and Western Europe to the Middle East and Pacific Rim. This is a consequence due to the location of major crude reserves and growth markets for refined-oil products. Catalyst suppliers have stepped up their presence in Asia-Pacific, and they are facing a new competitor in Sinopec. The Chinese are producing most of the standard refining catalysts for their own use and have started exporting some catalysts to neighboring countries.

Fluid catalytic cracking (FCC) catalysts made in China are now being used in several catalytic cracking units in the US, and a sales office has been opened in Texas. China is doing extensive research in catalysis for refining and petrochemical processes, and this is reflected in their many contributions to the technical literature in recent years. At some American Chemistry Society (ACS) meetings, conference papers presented by Chinese companies make up more than half of the papers in particular sessions. In due time, China will actively compete in the full spectrum of refining and petrochemical catalysts.

Rare earth challenges. China currently controls about 97% of the rare earth market; this nation cornered the market through pricing strategies that made all other sources uneconomical. Recently, there have been large price hikes for rare earth materials, and China has capped exports. Rare earth elements are used in a variety of strategic applications and have been used for years as a stabilizer for fluid cracking catalysts. This has catalyst suppliers both scrambling to secure supplies and to find ways to minimize the rare earth components in catalyst structures and makeup. Previously closed mines around the world will be reopened in the next few years, and some type of price floor will need to be established to ensure the mine’s on-going operation.

A global business. The evolution of the catalyst business is a natural phenomenon in the world of commerce. In the beginning, catalyst plants served indigenous markets and survived due to limited competition and protective trade laws. The elimination of trade barriers and more sophisticated technologies have caused many small plants to shut down. Those remaining have been increased in size, thus taking advantage of the economies of scale. This poses challenges to the catalyst manufacturer since clients want products customized to their specific applications.

When the industry that buys your product is being squeezed economically, all of its suppliers will feel the pinch. This prompts all companies to back integrate into raw materials and to find ways to lower costs while meeting ever more stringent environmental regulations for air and water emissions and solids disposal. Energy usage is a major cost to hydrocarbon processing industry (HPI) plants. The drop in US natural gas prices makes all of the US catalyst works more competitive. The depreciation of the US dollar compared to other currencies causes catalysts made in North America to be more financially attractive. Advanced automation and instrumentation can help reduce costs and improve product quality.

Market integration. With refineries growing in size and complexity and now increasingly being integrated with petrochemicals, it is natural that catalyst suppliers would want to serve both markets. Hydrogen plants are being installed in more refineries as the need for hydroprocessing of all refined products processed in the refinery is required to meet new product sulfur specifications.

Other petrochemical catalysts, such as those used to make polyethylene, polypropylene and styrene, are used in these large, integrated refining-petrochemical complexes. Some of the major catalyst suppliers currently serve both segments.

Expect more moves in the future in this direction.

Environment. Another area of market integration is combining refining with environmental catalysts. New regulations are reducing the level of Two line caption all contaminants in the water and air as well as in refined products produced.

Catalysts that reduce the amount of sulfur in flue gases or exhaust streams or in the various products have a lot in common with refinery catalysts. They tend to share in the same base materials such as silica gels, aluminas or combinations thereof. By increasing the volumes of these materials, the catalyst supplier can put in a large-scale plant to make base materials rather than having to purchase from an outside source. Similar products can be used as bases for treating transportation exhaust gases to remove nitrogen oxides (NOx),carbon monoxide (CO) and hydrocarbons. Metals impregnation techniques are also crucial for many catalyst systems to ensure maximum catalyst performance and to minimize the use of expensive raw materials such as platinum, cobalt, nickel and molybdenum.

Biofuels. The use of ethanol in gasoline has generally made octane a surplus commodity. More than half of the reformers in the US are operated for hydrogen production rather than for octane. Going to 15% ethanol would put almost every refiner in this category. Refiners are integrating into ethanol facilities, but the impact on the refinery would be very significant. The base blendstocks would have to be very low in vapor pressure (Rvp), and this would impact other refinery processing units. The conversion on the catalytic cracking unit might have to be lowered, isomerization units bypassed and continuous reformers operated for octanes of 90 or less. Hydrocrackers may split their naphtha into fractions, with the heaviest fraction becoming a blendstock.

New processes may be introduced that create high-boiling naphtha that can be used as a gasoline blending stock. Alkylation of single-ring light aromatics may become attractive. Some overcracking of gasoline would possibly be practiced to increase the amount of alkylate in the gasoline pool and amylenes (C5 olefins) could be a much more common alkylation feedstock.

Ethanol usage could grow even further if the current ethanol fuel mandate is left in place and enforced. This would require at least a doubling of the current production, along with the development of new technologies to make the ethanol using cellulosic material. Diesel made from biomass is also being pursued, which will require further processing. This will require processing with diesel streams produced from conventional oil. Hydrotreating will also be used in this service.

The use of ethanol would reduce the amount of oil processed in the US but it will not reduce greenhouse gas (GHG) emissions and could have adverse effects on water usage and storm-water run-off from agricultural lands. These facts could prompt a revision of present laws.

HYDROCARBON PROCESSING CATALYST 2011

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CATALYST 2011 ■ Research and developments continue to explore new opportunities to increase structure strength and minimize breakdown of catalyst and provide more reactivity per volume used in processing units.

Major trends. In looking forward, the major trends in crude-oil refining are dieselization and the reduction in fuel-oil usage. Both of these are being addressed by the use of more hydrocracking and bottoms-conversion technologies such as coking, residual catalytic cracking and hydrocracking. Residual desulfurization is sure to increase due to mandated sulfur reductions that will be mandated over the next 10 years. Total catalyst consumption for all of these processes will grow significantly.

Improved refining processes continue to be developed as venders probe every aspect of a particular unit. Fixed-bed reactors used graduated supports made of ceramic material both on the bottom and top of the bed. These were replaced by active-support products that had catalytic activity. Today, the supports not only have activity but may also possess a pore structure to trap and hold contaminants that could cause high pressure drops.

The marketplace is always demanding new products, and suppliers work harder to deliver them. In the area of hydrotreating, the ultra-low-sulfur diesel (ULSD) specifications implied that refiners would need to add additional reactor volume to deal with the most difficult-to-treat molecules. Hydrotreating catalysts had been in use for 40 years and any major breakthroughs seemed unlikely to

occur. Use of more sophisticated equipment—in this case a very powerful scanning, tunneling electron microscope—gave researchers a better look at the catalyst surface, and they were able to see what sites needed to be created to enhance the catalyst activity. Application of high-activity hydrotreating catalysts has saved considerable capital and energy since start-of-run temperatures can be reduced.

One of the new FCC catalysts introduced was accidentally discovered. The research program was trying to improve gasoline desulfurization, but a sample prepared that did not show promise for those reactions, was found to have exceptional activity. That provided a lead to the development of a whole new catalyst family.

Whether the innovations are incremental or breakthrough, one thing is sure: they will continue to occur, driven by a very competitive marketplace. Since the catalyst is the heart of most HPI processes, refiners and petrochemical plant operators can expect continued improvements that will increase capacity and product selectivity as well as reduce energy usage. Breakthroughs may even require substantial modifications to existing processes. HP

Warren S. Letzsch has 43 years of experience in petroleum refining including petroleum catalysts, refining and engineering and design. His positions have included R&D, technical service and sales, which led to senior management positions in sales, marketing and technology development and oversight. He was one of the developers of the Shaw/Axens R2R process. Mr. Letzsch has authored over 80 technical papers and holds eight patents in the field of fluid catalytic cracking. He was the FCC/ DCC program manager at Stone & Webster/Shaw for 10 years and is now a senior refining consultant for Shaw, as well as a private consultant to the refining industry.

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HydrocarbonProcessing.com

CATALYST 2011

Global demand for catalysts to exceed $17 billion in 2014 World demand for chemical synthesis, petroleum refining and polymerization catalysts will rise 6%/yr to $17.2 billion in 2014, reflecting a combination of healthy volume and price growth from a weak 2009 base. Chemical synthesis and polymerization catalysts will experience the strongest growth, benefiting from rapid gains in the Middle East and Asia, as well as in Brazil. While petroleum refining catalyst demand will expand at a healthy pace, advances will be limited by weak motor vehicle fuel demand in Japan, the United States and Western Europe. These and other trends are presented in World Catalysts, a new study from The Freedonia Group, Inc. The strongest growth through 2014 will occur in the Middle East, where Saudi Arabia and other countries will continue to invest in new chemical and polymer capacity in an effort to exploit their natural gas and petroleum reserves (Table 1). Refining capacity will also be expanded in the Middle East to satisfy the region’s rapidly rising fuel demand. In Asia-Pacific (AP), China and India will also drive rapid growth through 2014, offsetting slower growth in Japan.

Strong growth in Central and South America will be led by Brazil, which is well positioned to expand its regional dominance of the chemical, petroleum refining and polymer industries due to the recent discovery of plentiful natural gas and petroleum reserves off the country’s coast. The US, Canada and Western Europe will also realize gains in catalyst demand, though growth will trail the global average as companies avoid investing in new chemical and polymer capacity due to the mature nature of these markets.

TABLE 1. World catalyst demand, million dollars Annual growth,% 2004–2009 2009–2014

2004

2009

2014

Catalyst demand

9,470

12,830

17,200

6.3

6.0

North America

3,330

4,255

5,180

5.0

4.0

Western Europe

2,500

3,075

3,895

4.2

4.8

Asia/Pacific

2,405

3,640

5,360

8.6

8.0

Other Regions

1,235

1,860

2,765

8.5

8.3

© 2011 by The Freedonia Group, Inc.

Demand for all types of chemical synthesis catalysts will be strong going forward, though the pace of consumption of enzymes for ethanol production will moderate through 2014 following rapid growth over the 2004-2009 period. In polymerization catalysts, single-site and Ziegler-Natta catalysts will Two line achieve thecaption strongest gains. Hydrotreating catalysts will continue to achieve the best growth in the petroleum refining market, aided by the increasingly sour nature of the crude petroleum supplied to the market, as well as efforts by Brazil, China, India and Russia to improve their air quality by the introduction of low-sulfur fuels. Hydrocracking and fluid catalytic cracking catalysts will also achieve healthy advances, particularly in AP as the growing motor vehicle fleet stimulates new gasoline and diesel fuel demand. More information on this study can be found at www.freedoniagroup.com. HP

Rare earth dilemma forces catalyst changes at double digit rates, and consumption of consumer goods is rapidly expanding. Likewise, China’s domestic demand for RE elements is rapidly growing. Due to domestic demand, China has initiated export reductions for RE elements. In 2010, the Chinese government warned that its own rising demand will soon enforce RE export reductions.

125 100 75 50

Changing makeup. With a pending shortage of RE elements and rising prices, some catalyst companies are developing RE-free catalysts. RE elements are used in fluid catalytic cracking (FCC) catalysts and catalytic converters for vehicles. Grace Davison is developing an RE-free FCC catalyst called Resolution.

This catalyst is undergoing pilot-plant testing. HP

In rare earth metals, Chinese dominance China has a near monopoly on this group of 17 elements, some of which are used to make efficient light bulbs, electric car motors and wind turbines. And in recent years, the price of one of them, dysprosium, has soared.

China Rare-earth oxide production

120 100 Price, $/kg

150

Consumption, thousand tons

The success from catalysts depends on its structure and composition. Tremendous research has been devoted in fine-tuning the melding of structure and raw material makeup to provide efficient catalyst systems for the hydrocarbon processing system. Some very effective catalysts include rare earth (RE) elements to facilitate desired processing reactions. RE elements are very difficult to mine. As indicated by “rare” in its names, RE elements are under stress as more products and applications utilize these materials. In addition to catalysts, RE elements are used in camera lenses, jet engines, nuclear batteries, lasers, vanadium steel, high-temperature superconductors and other hi-tech products. Newer applications include wind turbines and hybrid and electric car batteries.

Demand for “greener” products, energy and vehicles continues to raise demand for RE element metals.

China is the major producer of RE elements and has surpassed the US, as shown in Fig. 1. Deposits of RE elements exist in the US, Canada and other countries. But only China’s government supports the mining and refining of RE elements. About 97% of RE elements are produced by China.

Looking forward, the future supply of RE elements is under high scrutiny. China’s economy is increasing

80 60 40

US

Rest of world

Dysprosium oxide export prices from China

25

20

0

0 ’50

’60

’70

’80 Years

Source: US Geological Survey, Asian Metal

’90

’00

’08

’01 ’03 ’05 ’07 ’09 Years Source: The New York Times

FIG. 1. Major RE element producers.

HYDROCARBON PROCESSING CATALYST 2011

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Our advanced catalytic engineering has powerful attraction Axens’ HR series ACE™ technology catalysts deliver sustained, on-spec ultralow-sulfur diesel. The powerful desulfurization activity of this new series is particularly enhanced in combination with EquiFlow™ reactor internals and Catapac™ dense loading technology.

With its submicron-level control, ACE technology provides dual activity for superior levels of sulfur and nitrogen removal in all applications. Easy to load and activate, HR series catalysts also offer excellent regeneration properties.

Axens’ quality products are based on reference technology – commercially proven, dependable, reliable and cost-effective.

The performance improvement specialists www.axens.net For more information Paris

+33 1 47 14 25 14

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Email Catalysts@axens.net

CORPORATE PROFILE: AXENS CATALYST 2011

The performance improvement specialists Axens is recognized as a worldwide technology benchmark for clean fuels production, conversion solutions, aromatics and olefins production and purification.

The combination of the technology and services with the catalyst and adsorbents manufacturing and supply business is an efficient organization that handles market needs as a single source.

With the improvement in fuel product specifications and increased demand for middle distillates, hydroprocessing catalyst technology has become crucial to the refining industry. Axens offers a complete product range of hydrotreating and hydroconversion catalysts from naphtha and gas oil to residue applications.

Recently, Axens has launched a full range of catalysts to meet high conversion and mild hydrocracking unit’s objectives.

Increasing Middle Distillate Selectivity HRK 658

HDK 776

HDK 876

HDK 776 HYK 762 HYK 752 HYK 742 HYK 732

Hydrocracking catalysts: Axens’ commercial hydrocracking catalyst suite upgrades a wide range of heavy feedstocks to produce the desired slate of products while meeting ultimate quality targets. It relies on a combination of products derived from HRK, HDK and HYK series depending upon operator conversion targets.

• Pretreating section: The combination of HRK 658 NiMo catalyst and HDK Series, including HDK 776, HDK 876 and HDK 766 catalysts is the most effective way to maximize HDN activity in the pretreatment section and to ensure that pretreating catalytic section will perform at its optimum during a long cycle length. It has proved to be superior to conventional hydroprocessing catalyst only options. This is of particular interest when processing heavier and more refractory feedstocks with high organo-nitrogen content.

Optimized catalyst combination between HR and HDK Series (HDK 776) is also suitable for achieving higher conversions in new mild hydrocracking unit or in revamped FCC pretreatment units.

• Hydrocracking section: HYK 700 Series, Axens latest generation zeolite products suite including HYK 732, HYK 742, HYK 752 and HYK 762, displays high activity coupled to utmost selectivity, improved hydrogenation activity, extended long-term stability and cycle lengths. This was made possible by optimizing the dispersion of zeolite crystals, improving metal impregnation technology to reduce the distance between acid and metal sites and by increasing the hydrogenation function efficiency.

The combination of HRK, HDK and HYK series enables to squeeze more middle distillates from heavy ends while reaching high conversion levels.

HR Series Hydroprocessing catalysts. For ultra-low sulfur diesel (ULSD) service, HR 626 (CoMo) and HR 648 (NiMo) catalysts are considered by many refiners as being the most stable catalysts available on the market. They offer an optimum activity and stability balance for ULSD service leading to very long cycles while maintaining industrially proven full regenerability by simple carbon burning, thus providing best in class cradle to grave economics.

Axens has also introduced a new and highly active tri-metallic CoMoNi catalyst HR 568 for VGO processing and FCC Feed Preparation applications. This catalyst displaying same basic properties as other HR Series products (activity, stability, regenerability) has established itself as a benchmark in the field according to several major companies.

Increasing Conversion Activity Hydrocracking catalyst performance mapping.

Reforming catalysts. Axens has recently completed the acquisition of the Willow Island (West Virginia) manufacturing plant for reforming catalyst and appropriate intellectual property rights to pursue such business from Criterion. This acquisition strengthens our offer in the area of catalytic reforming for gasoline and aromatics production and helps us to better serve customers by providing them a wider range of products from a larger manufacturing platform.

• For aromatics production, Axens offers AR 501, AR 505, AR 701 and AR 707 catalysts for ultimate CCR (continuous catalyst regeneration) severity technology.

• For gasoline production Axens provides a wide range of catalysts covering: o CCR technology (medium to high severity applications): CR 601, CR 607, CR 617, PS 40, PS 80, CR 702, CR 712 o Fixed bed technologies (all reactor types): RG 582, RG 586, PR 9, PR 15 • Cyclic reactors: RG 532, P 15, P 155 • Semi regenerative reactors: RG 682, RG 686, PR 29, PR 30.

Contact information 89, Bd Franklin Roosevelt – BP 50802 92508 Rueil-Malmaison Cedex – France Email: information@axens.net Website: www.axens.net

HR Series

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practicality loves imagination Progress begins with imagination, but effort brings an idea to life. As the global leader in catalysis, BASF leverages the creative imagination of over 650 scientists to create practical solutions that can drive new levels of customer performance and achievement, today and over the long term. At BASF, we create chemistry. www.catalysts.basf.com

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CORPORATE PROFILE: BASF CATALYST 2011

BASF—The global leader in catalysis We create chemistry BASF’s Catalysts’ division is the global market leader in catalysis. The division develops and produces mobile emissions catalysts as well as process catalysts and technologies for a broad range of customers worldwide. BASF Catalysts expands its leading role in catalyst technology through continuous process and product innovation.

Focus of R&D BASF remains committed to R&D investments in catalysis to sustain innovation.

In the area of process catalysts, recent developments for diesel maximization and propylene maximization from an FCC unit are designed to help customers achieve more revenue from their existing processes.

MAIN PRODUCTS Process catalysts and technologies BASF Process Catalysts and Technologies are the leading manufacturer of catalysts to the chemicals industry with solutions across the chemical value chain, as well as intermediates for pharmaceuticals and fine chemicals. We have provided groundbreaking oil refining technology catalysts for over 50 years including FCC catalysts, co-catalysts and additives. Our polyolefin catalysts use a proprietary platform to offer product differentiation and value to our customers. Finally, our adsorbents business offers guard bed and catalyst intermediate technologies for purification, moisture control and sulfur recovery.

Mobile emissions catalysts Mobile Emissions Catalysts enable cost-effective regulatory compliance by providing technologies that control emissions from gasoline- and diesel-powered passenger cars, trucks, buses, motorcycles and off-road vehicles.

Precious metal services Precious Metal Services support the catalysts business and BASF customers with services related to precious metals. The business purchases, sells, refines and distributes these metals and provides storage and transportation services.

Key capabilities of BASF • • • • • • •

Technology innovation Production efficiency Strict working capital management Technology leadership in mobile emissions and process catalysis Keen insight on global precious metal markets Partnerships with industry leaders Strong position in Asia through joint ventures

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Contact information Americas BASF Corporation Iselin, NJ 08830, USA Tel: +1-732-205-5000 E-mail: catalysts-americas@basf.com Asia Pacific BASF East Asia Regional HQ Ltd. Central, Hong Kong Tel: +852-2731-0191 E-mail: catalysts-asia@basf.com Europe, Middle East, Africa BASF SE Ludwigshafen, Germany Tel: +49-621-60-21153 E-mail: catalysts-europe@basf.com Wesbite: www.catalysts.basf.com

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Reduce Risk of Injury.

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CORPORATE PROFILE: CATALYST SERVICES CATALYST 2011

Catalyst Services—A success story Founded in 1977, Catalyst Services has grown to become one of the world’s largest and most experienced catalyst handling companies. Over the years, Catalyst Services has invested millions into state-of-the-art equipment, specialized techniques and training to ensure catalyst compounds within reactors and vessels are loaded and unloaded safely and quickly to maximize production.

Catalyst Services delivers catalyst handling services to help clients manage refineries and gas and chemical plants throughout the world. Catalyst Services has 400 employees operating in numerous locations throughout Texas, Louisiana, California, Indiana and Utah. Catalyst Services also has locations in Canada and Trinidad and Tobago.

Recognized as a 2010 Safety Award Winner by the National Petrochemical and Refiners Association (NPRA) in the United States, Catalyst Services is continuously evolving to incorporate new safety procedures and processes. Ten years ago, plant inspectors had to inspect catalyst by physically entering vessels which was extremely dangerous and time consuming. Today, Catalyst Services uses specialized equipment and automated processes to increase safety and decrease time spent on catalyst maintenance and changeouts.

Catalyst Services supplies catalyst handling, confined space inert entry and tubular loading for reactors. Other services include patented Softload® technology for loading of primary reformers as well as Densicat loading for fixed bed reactors.

Among its innovations, Catalyst Services was one of the pioneers in Lock-on-Life Support Systems. The company uses a helmet originally designed for NASA high altitude pilots. Catalyst Services uses this helmet which has 3 independent air supplies and a built-in communication system connected to a mobile control room. In the mid-1990’s, Catalyst Services acquired SAMS (supplied air monitoring systems) who developed the helmet. SAMS is ISO9001:2008 certified.

Through Softload®, Catalyst Services has developed a specialized technique for the loading of primary reformers. Since 2005, SoftLoad® technology has been used by Catalyst Services throughout the world to complete numerous catalyst loading projects. SoftLoad® is a fast and predictable loading method that reduces actual loading time by as much as 50% (compared to the conventional sock loading method). SoftLoad® removes human error from the loading process and has generated increased demand from energy companies around the globe.

Catalyst Services is the largest licensee to Petroval’s DENSICAT® loading system. Petroval’s “Densicat” loading process is the most commonly used dense loading system world wide, without sacrificing the speed of the load. Benefits of Densicat include increased density compared to sock loading (up to 20% higher), improved bed homogeneity and a loading rate of up to 28 tons per hour.

Catalyst Services continues to use its technologically advanced Mobile Life Support System. The Mobile Life Support System allows the remote monitoring of breathing circuits and atmospheric conditions for technicians working on vessels and reactors. Operators within the Mobile Life Support System can monitor internal conditions as well take real time digital video of all work performed.

Catalyst Services has invested millions into its fleet of Mobile Life Support Systems. Catalyst Services currently operates a fleet of more than 30 Mobile Life Support Systems. These mobile units are very versatile and can accommodate 4, 6 or 8 entrants depending upon job requirements. Smaller jobs are usually managed with 4 entrants while catalyst handling projects for larger vessels may require the use of 8 entrants.

Catalyst Services has a number of long-term clients. Some of these clients include Shell, Valero, Exxon, Chevron, Conoco Phillips and Lyondell Bassell.

The Catalyst Services management team and employees are driven to proSPONSORED CONTENT

Vacuum equipment and unload of catalyst.

vide clients with world class service. Dwane Ruiz and Mike Easter were recently appointed Vice-President and Assistant Vice-President respectfully and are responsible for all operations. Dwane is an accomplished leader with more than 30 years experience in the industrial services sector at the executive and management level.

Dwane spent 25 years with Halliburton. Most recently, Dwane held a senior leadership role at the United States Industrial Services as the Vice President of Strategic Business Development. Mike has been part of the Catalyst Services team for more than twenty years.

Catalyst Services is a subsidiary of CEDA International, one of the largest providers of industrial maintenance, turnaround and construction services in North America. Founded in 1973, CEDA International provides more than 100 industrial services helping clients manage refineries, power plants, petrochemical plants, pulp and paper plants, mines and other facilities. CEDA International is comprised of numerous subsidiaries and has more than 30 offices throughout North America.

2011 is poised to be a pivotal year for Catalyst Services. To learn more please visit www.cedagroup.com

Contact information US Head Office: Deer Park, Texas Phone: 1-855-478-2633 (Toll Free) Contact: Bruce Stagge, National Sales Manager, bstagge@catalystservices.com Website: www.cedagroup.com HYDROCARBON PROCESSING CATALYST 2011

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Based on your specific needs, CENTERA can help improve your refining capabilities. Whether you are facing challenges in cycle length, feedstock type, or process flexibility, our advanced technology offers a solution. Take a step forward with CENTERA. For more information, please contact CriterionPublicAffairs@CRI-Criterion.com.

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CORPORATE PROFILE: CRITERION CATALYST 2011

Advance to the next generation Increase flexibility. Maximize performance. Expand margin opportunities.

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While global economies begin to show signs of recovery, refinery margins have continued to challenge even the shrewdest planners and schedulers in 500 our industry. As global/regional margins and demands fluctuate, and as capital and operational budgets decline, the global drive toward clean fuels remains 400 resolute, requiring refiners to extract the most from their existing units. The Ultra Low Sulfur Diesel (“ULSD”) hydrotreating unit in particular, which has 300 grown from a peripherally-important unit a decade ago to a key component in the refinery profitability equation today, can offer real economic opportunities, 200 provided it is not activity constrained.

Over the last five years, industry data has shown that the versatile DHT unit plays a role in enabling 100 refineries to capitalize on changing economic drivers, 1980 1985 1990 1995 2000 2005 2010 including the following: Building on a long history of providing gains to refiners with catalyst technological • Increased heavy/sour crude processing advances, Criterion Catalysts & Technologies continues to meet current industry clean • Increased bottoms conversion fuels challenges with the development and release of the innovative CENTERA technology.

• Conversion to ultra-clean fuels quality (e.g., ULSD) • Increased distillates product demand To sum up, when used alone or in a custom catalyst system, CENTERA can In today’s dynamic environment, it has become important to have any and all provide a measurable increase in activity to help relieve unit constraints and of the above capabilities readily available. Flexibility with feed and product slates provide flexibility and reliability for a refinery. has now become one of the most important process capabilities of a ULSD unit.

As CENTERA development continues, additional product applications will be Maximizing activity/performance is a key to help deliver this desired flexibility and available with the potential to further impact hydroprocessing units. Given its gain more out of ULSD assets. com-mercial success, with almost 10 million pounds selected for use in multiple Driven by these challenges, Criterion Catalysts & Technologies (“Criterion”), a appli-cations, this technology demonstrates how, as refining objectives and ecowholly-owned subsidiary of CRI/Criterion Inc., which is part of Shell Group, offers nomics evolve, Criterion innovates and develops catalyst systems to best match its next generation of catalyst technology—CENTERA®. both the capabilities and the operational constraints of individual units.

CENTERA technology is the culmination of years of in-depth research on the fundamental structure of active sites combined with the commercial experience of Criterion’s proven CENTINEL, CENTINEL GOLD and ASCENT platforms. Based on highly active nano-structures, CENTERA technology creates new opportunities for refiners to capitalize on hydroprocessing opportunities, providing the potential to increase run length, process more difficult feedstocks or increase through-put.

This technology modifies the transformation process of oxidic metal nano-particle precursors to sulfided, active sites. The CENTERA process then locks these distinctive sites in place to promote retention of their high activity.

The higher activity offered by CENTERA can provide further opportunities to Contact information help reduce the base catalyst volumes required to meet processing targets. In Sal Torrisi, Business Manager —Distillate Catalysts ULSD applications, this provides an opportunity to incorporate catalyst for cetane Two Greenspoint Plaza, 16825 improvement, density reduction, cold flow improvement or conversion to naphtha.

Northchase Drive, Suite 1000, CENTERA technology is applicable across Criterion’s hydroprocessing catalyst Houston, Texas 77060, USA portfolio. In ULSD applications, CENTERA technology can enhance performance of Phone: (281) 874-2605 a broad range of ULSD scenarios, from the low-pressure CoMo catalyst regime of E-mail: Sal.Torrisi@cri-criterion.com revamped units to the higher-pressure NiMo catalyst environment of grassroots Website: http://www.criterioncatalysts.com units processing a high percentage of cracked feedstocks.

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CORPORATE PROFILE: GRACE DAVISON CATALYST 2011

Grace Davison—Investing in innovation, supported by technical service At Grace Davison, we invest in innovation because we believe that to build strong customer relationships we must meet current needs while anticipating future challenges. Investment in research allows our refining customers and Grace Davison to optimize operations on a daily basis . We support our broad portfolio of innovative catalysts and additives with our world-class technical service engineers.

What does investment in innovation look like?

Meeting current customer needs—Even before the current rare earth pricing and supply situation arose, Grace Davison’s Research scientists never lost focus on the importance of low and zero rare-earth catalysts and additives. We continue to examine the role of rare earth in catalyst performance and how to not only use less rare earth but to maximize its efficiency and minimize, or even eliminate, its use.

Our R&D commitment has resulted in our REplaceR ™ family of catalysts, which includes several new rare-earth free catalysts including REsolution™, REactoR™ , REplaceR™, REduceR™, REBEL™ and REMEDY™ catalysts.

Anticipating future challenges—Zeolite performance underlies FCC technology. That’s we’re pleased to join with Rive Technology on the revolutionary “Molecular Highway” technology, as we jointly commercialize advanced FCC catalysts that dramatically increase the yield of transportation fuels per barrel of crude oil. A refinery trial is planned for Spring 2011 and we will publish the commercial results as they become available.

Supported by Technical Service. Our world-class Technical Service engineers support refiners so they realize the maximum value from our products. Catalyst performance partnered with industry-leading technical service is what differentiates Grace Davison from its competitors. The best catalyst in one unit may not be the best catalytic fit for another application. Grace’s Technical Service team has the knowledge, experience, and application expertise to thoroughly understand a refiner’s FCCU configuration, operation, constraints, and objectives and then match that to the catalyst technology that delivers optimal performance.

Regular operational reviews with the refiner to assess catalyst performance versus changing unit objectives, constraints and feedstock are standard practice ensuring the refiner is always using the best catalyst technology available. Grace Davison’s highly specialized Technical Service engineers, with experience in both catalyst application and FCCU operations, are ready to assist refinery engineers with unit optimization. By working closely with refinery technical staff, our Technical Service team can help the unit engineers maintain a profitable reliable operation of the FCCU in even the difficult circumstances.

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The ReplaceR™ family of catalysts includes Grace Davison’s newest rare-earth free FCC catalysts, developed with the novel Z-21 and Z-22 zeolites.

A wide array of FCC additives to meet specific challenges. Our current portfolio of FCC additives allows refiners to reduce SOx, NOx, and CO emissions from their FCC units, as well as lower sulfur content in gasoline and diesel fuel. Grace also offers additives to maximize propylene yield from the FCC unit such as our leading ZSM-5 additive technologies, OlefinsMax® and OlefinsUltra®,. Similarly to base catalysts, we continue to invest R&D to minimize the use of rare earth in additive formulations. Currently we are commercializing several new environmental additives, Super Desox MCD and GDNOX-1 that deliver the desired performance with lower rare earth.

Grace Davison Refining Technologies offers a broad portfolio of state-of-the-art catalytic solutions to meet refiners’ needs. Our experience, backed by manufacturing excellence, has made us the world’s leading supplier of FCC catalysts and additives.

We are the only global producer of FCC catalysts and additives with manufacturing facilities in three countries and sales in 63 countries. We look forward to joining with you to help you optimize your operations.

Contact information 7500 Grace Drive, Columbia, MD 21044 USA Phone: +1-410-531-4000 Fax: +1-410-531-4540 E-mail: catalysts@grace.com Website: www.grace.com

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Stepping up performance – next generation BRIM™ technology W WW.T OPSOE.CO M

Are you looking to step up plant performance?

Topsøe’s next generation BRIM™ catalysts offer refiners the opportunity to increase performance through an increase in catalyst activity.

Using the original BRIM™ technology Topsøe has developed several new catalysts, resulting in higher activity at lower filling densities.

The next generation BRIM™ catalysts display -

high dispersion high porosity high activity

We look forward to stepping up your performance!

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CORPORATE PROFILE: HALDOR TOPSØE CATALYST 2011

Catalysing your business Through half a century’s dedication to heterogeneous catalysis, Topsøe has developed and strengthened its position as a leading market player in catalysts and technologies for process design.

Topsøe’s markets include oil refineries, chemical plants and the energy sector, where the catalysts and technologies ensure smooth-running and cost-efficient operations with optimal production results.

Hydroprocessing worldwide. Topsøe has developed process design and catalysts for virtually all areas of hydroprocessing and the catalysts and technologies are in operation in plants worldwide.

Topsøe’s hydroprocessing expertise offers integrated solutions including reactor internals, grading material, catalysts, process design and detailed reactor engineering. The supply of catalysts and technology offers clients a single point of expertise and responsibility.

In the design of new hydroprocessing units, Topsøe’s research and test facilities offer clients testing opportunities including detailed feedstock and process analyses, which form the basis of tailor-made solutions.

Topsøe’s refining competencies. Through extensive hydroprocessing research and development Topsøe offers • A broad hydroprocessing catalyst portfolio and tailor-made technologies for revamps and grassroots units meeting all specific needs of the refiner • In-depth knowledge of hydroprocessing reactor fluid dynamics and in-house developed designs for reactor internals ensuring efficient catalyst usage • More than 20 years of experience with graded bed catalyst design based on particle size, shape, void and catalytic activity for pressure drop abatement Research based catalysts and technologies. A fundamental understanding of catalyst behaviour at the nano scale enables Topsøe to continuously develop new and improved products to meet clients’ needs. One recent development was Topsøe’s BRIM™ catalyst preparation technology, which has led to a whole new generation of unmatched activity hydrotreating catalysts with great stability.

Related industries. Topsøe’s refining experience extends to related industries offering solutions for hydrogen supply, sulphur management and NOx emission.

Efficient hydrogen technology and catalysts from Topsøe ensure optimised processes with low energy consumption to capacities from 5,000 to more than 200,000 Nm3/h hydrogen.

Topsøe’s WSA and SNOX™ technologies remove sulphur and nitrogen oxides from flue gases, recover the sulphur oxides as concentrated sulphuric acid and reduce the nitrogen oxides to free nitrogen. The SNOX™ process is particularly suited for purification of flue gas from combustion of high-sulphur petcoke and other petroleum residues such as heavy fuel oil and tars as well as sour gases.

Topsøe’s SCR (Selective Catalytic Reduction) DeNOx process is the most efficient process for removing nitrogen oxides from gases and is suitable for treating offgases from a wide range of different industries and applications including fossilfuel and biomass fired utility boilers, gas turbines, oil refining and chemical plants, stationary diesel engines and waste incinerators.

Market experience. Topsøe has extensive market experience with all aspects of hydrotreating ranging from naphtha to heavy residue. More than 100 hydrotreating units have been licensed using Topsøe hydrotreating technology of which a large number are designed for production of ultra-low sulphur diesel with less than 10 wt ppm sulphur.

Topsøe has more than 140 references in operation or projected for the production of ultra-low sulphur diesel having less than 50 wt ppm sulphur, corresponding to 5 MMBPD. 100 of these references use catalysts produced with Topsøe’s BRIM™ technology.

Contact information Nymoellevej 55, DK-2800 Lyngby, Denmark Phone: +45 4527 2000 Fax: +45 4527 2999 Email: topsoe@topsoe.dk Website: www.topsoe.com

Renewables fuel. Topsøe has developed hydroprocessing catalysts and technology for processing a wide range of renewable feedstocks to gasoline, jet and diesel. Feedstocks include vegetable and animal oils, fatty acid methyl esters, waste oils and greases, tall oil and other forest waste products, algae and plastics.

These feeds can be converted to transport fuels, either in stand-alone plants or by co-processing with normal refinery feedstocks.

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Don’t look away for your desulphurization catalyst…

EUROPHTAL SAS - 772 chemin du mitan - 84300 Cavaillon - FRANCE Phone : +33 (0)4 90 78 70 50 - Fax : +33 (0)4 90 78 70 81 salesdepartment@europhtal.com Select 100 at www.HydrocarbonProcessing.com/RS

www.kariba-productions.com | 04 90 78 10 50 | crédit photo : © IStock

Close technical support | Performance monitoring | Pre impregnated catalyst Reliable mercaptan oxydation | Short delivery time

CORPORATE PROFILE: EUROPHTAL SWEETENING CATALYST CATALYST 2011

Europhtal’s desulfurization catalyst is well known and used in refineries worldwide Europhtal was founded in 1994 in collaboration with one of the major European petroleum company. In 1996 Europhtal catalysts were qualified by IFP (French Institute of Petroleum) as mercaptan oxidation catalyst for sweetening units to treat natural gas, LPG, gasoline and kerosene. The chemical expertise gives to Europhtal fundamental knowledge in catalyst properties, reactivity, use and fabrication.

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Our products. Europhtal developed different sweetening catalysts in accordance to existing mercaptan removal process.

• Mercaptan extraction. Europhtal additive 8090 and Europhtal additive 8090G are liquid catalysts used in liquid-liquid extraction units. These additives are tailor made catalysts to sweet respectively LPG and gasoline without side reaction.

Europhtal additive 8090 and 8090G allows to: – Sweet light hydrocarbons (LPG, gasoline) – Control catalyst consumption – Improve caustic consumption by reducing caustic adjustment.

– No side reaction – Easy handling • Mercaptan oxidation. Europhtal additive 8120 is specially employed to sweet heavy hydrocarbons (kerosene, heavy gasoline). This catalyst is a preimpregnated catalyst. The Europhtal additive 8120 was developed in partnership with an activated carbon specialist in order to improve catalyst activity (run length and catalytic performances).

Europhtal additive 8120 allows to: – Sweet heavy hydrocarbons (kerosene, heavy gasoline) – Improvement catalyst life – Guaranteed impregnation performance – Ready to be use – Easy handling For more than 15 years, Europhtal catalysts have been widely used in numerous refineries and gas production plants worldwide.

To keep in highly efficient desulfurization catalyst, Europhtal controls all critical production steps, from the selective synthesis, the selection of best carbon support to the carbon homogeneity impre-gnation. Our expertise in desulphurization catalyst is offered to our customer for technical support in order to optimize catalyst use in sweetening units and to advice on the best solution in case of drop of conversion rate.

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Contact information 772 chemin du Mitan 84300 Cavaillon - France Phone: +33 (0) 4-90-78-70-50 Email: Sales department@europhtal.com

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Elements of Success

Precious metal reďŹ ning with response and responsibility

Learn more about the art and science of sampling at Sabin Metal, one of many Elements Of Success we’ve provided to catalyst users around the world for over six decades.

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CORPORATE PROFILE: SABIN METAL CORPORATION CATALYST 2011

Recovery and refining of spent catalysts from hydrocarbon processing Sabin Metal Corporation is the largest secondary precious metals refiner in North America, serving a worldwide customer base. We recover and refine PGMs from spent catalysts used for hydrocarbon processing and end-of-pipe pollution control equipment. PGMs (Platinum Group Metals) include platinum, palladium, ruthenium and rhodium. Sabin Metal also recovers rhenium, gold, silver, and other precious metals from spent catalysts that typically are configured as pellets, beads, extrudates, and monolithic structures. Sabin recovers remaining precious metals from spent catalysts from soluble and insoluble alumina, silica-alumina, zeolite, and carbon supports. Precious metals are also recoverable from waste byproducts associated with catalyst materials. We handle all details from suggestions on packaging and shipping/logistics through accurate materials tracking to final settlement with many options.

Advance labs. Sabin Metal offers the industry’s most advanced analytical and processing capabilities, along with fair, straightforward treatment and high standards of service that we’ve provided to our customers for more than 65 years.

These include detailed weights and analyses of their materials, and the ability to follow their shipments throughout the entire recovery and refining process. Catalyst samples are assayed in triplicate to assure accuracy and fairness.

Sabin Metal is unique in that it is one of the only precious metals refiners in the world to provide “full service” and full “in-house” capabilities (from door-to-door shipping/handling) through pre-burning, sampling, and assaying to prompt return of refined materials instead of employing outside subcontractors for one or more of these activities. Use of these outside services can reduce returns, increase process turnaround time, and negatively impact the environment. These outside services may also introduce possibilities of materials loss, which can result from third-party handling (repackaging, shipping, etc.).

This electric arc furnace represents the latest technology in refining spent PGMs.

catalysts, and chemical catalysts. In-house “pre-burn” capability and electric arc furnace technology provide total-capability refining services for lower costs and faster turnaround. For full technical details about our facilities, capabilities, and services for recovering and refining precious metals from spent catalysts, please visit us at www.sabinmetal.com.

Meets international rules. Sabin Metal’s analytical and processing facilities are the most advanced in the industry, along with fastest possible processing turnaround time to reduce metals costs. We provide full documentation with regard to environmentally responsible handling and disposal of solids, liquids, or gaseous byproducts from our facilities. Because of complex rules, regulations, and laws (both internationally and domestically), Sabin Metal’s subsidiary, Sabin International Logistics Corp. (SILC) specializes in transporting large quantities of spent catalyst materials in compliance with the rules and regulations of the exporting country as well as the materials’ importation into the U.S.A. SILC operates on every continent except Antarctica, and holds all required permits needed to transport materials to and from its refining facilities.

Refining at our processing facilities is accomplished through a wide variety of equipment including rotary, crucible and electric arc furnaces, kilns, roasters, thermal processors, pulverizers, granulators, screens, blenders, auto samplers, reactors, dissolvers, precipitators, electrolytic cells, and filter presses. Pyrometallurgical and hydrometallurgical technologies are employed to achieve the highest possible metal recovery at the lowest possible processing costs.

Sabin’s analytical laboratory uses advanced X-ray fluorescence equipment, atomic absorption (AA) and inductively coupled plasma (ICP) emission spectroscopy instrumentation and also employs classic volumetric, gravimetric, and fire assay techniques.

Our new 120,000-sq-ft. refining facility in Williston, North Dakota U.S.A. is specially equipped to sample and process precious-metal-bearing catalysts from hydrocarbon processes such as petroleum catalysts, vinyl acetate monomer (VAM) SPONSORED CONTENT

Contact information Corporate Headquarters: 300 Pantigo Place, Suite 102 East Hampton, NY 11937 Phone: 631-329-1717 Fax: 631-329-1985 Main Plant/Sales Office: 1647 Wheatland Center Road Scottsville, NY 14546 Phone: 585-538-2194/Fax: 585-538-2593 Web: www.sabinmetal.com Email: sales@sabinmetal.com Additional Facilities: Williston, ND; Cobalt, Ontario, Canada; Europe; Asia; Mexico; Latin America

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CORPORATE PROFILE: SAINT-GOBAIN CATALYST 2011

Saint-Gobain NorPro Ceramic solutions for catalysis Tough environmental standards and the use of varying feedstocks present special challenges for today’s refining and petrochemical processors. As a result, there’s more being demanded of the catalyst. Profitability hinges on the catalyst bed operating reliably at maximum efficiency.

Ceramics play a key role in catalysis and, therefore, a key role in the production of many materials essential to every-day life. Saint-Gobain NorPro is a world leader in providing ceramic solutions.

The catalyst carrier is considered integral to the catalyst system. Saint-Gobain NorPro has extensive experience and history in development and commercialization of catalyst carriers. We work with catalyst clients to tailor the physical and chemical properties of various materials and shapes to provide the optimal proprietary carrier for each customer-specific need.

Saint-Gobain NorPro’s proprietary MacroTrap® guard bed media—highly macroporous ceramic materials—work by trapping impurities to prevent contamination of the catalyst. The media extends the life of the fixed catalyst bed and eliminates the need for frequent shutdowns to skim and replace fouled catalyst.

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I C-113

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I C-114

PROJECT MANAGEMENT

How to properly apply a plant asset management strategy Facilities employing leak-detection and custody-transfer systems receive many benefits with this program J. NORINDER, Siemens, Hauppauge, New York

I

n today’s tough economy, plant asset management (PAM) has become a strategy that is hard to ignore. If applied properly, every aspect of every business in every industry can be optimized. In doing so, however, it is crucial to take issues, opportunities and benefits of each individual business into account if the efforts are to yield fruitful results. When applying asset management to processing plants within the hydrocarbon processing industry (HPI), for example, the most appropriate approach varies depending on the application area and whether it is an upstream, midstream or downstream installation. An area where this is particularly relevant is at hydrocarbon terminals, tank farms and storage facilities that employ leak-detection (LD) and custodytransfer (CT) systems.

At a general level, PAM is associated with managing an asset’s life cycle. It is a process that can potentially improve operational, environmental and financial performance, prolonging asset life and aiding rehabilitation, repair and replacement decisions through efficient and focused operations and maintenance. In other words, implementing PAM can help improve production reliability while reducing expenses, which has been demonstrated in several studies. According to the ARC Advisory Group, companies are reporting as much as a 30% reduction in maintenance budgets and up to a 20% reduction in production downtime as a result of implementing a PAM strategy. So, clearly, PAM does provide benefits, if implemented properly.

Process instrumentation is key to any PAM strategy.

As the name indicates, PAM focuses specifically on the assets related to running a processing or manufacturing plant, and as such, it is relevant for any industry. When applying PAM to the HPI, and more specifically to a liquid terminal or storage facility, numerous aspects and plant operation areas can be assessed: measuring the actual production in relation to quality, quantity, reliability and environmental standards; identifying assets critical to sustained performance; and collecting historical data to help predict future performance and life cycle costs.

While these are only a few examples, they underline the importance that process instrumentation such as valve positioners, flowmeters, temperature and pressure sensors play in PAM. It is the single most important source for controlling, monitoring and measuring overall equipment performance data, field device diagnostics and meter parameterization, all of which are considered key performance indicators of PAM.

Integrating process control and monitoring systems.

One method of optimizing a tank farm or storage facility’s production and distribution capabilities in a way that directly supports the overall goals of a PAM strategy is by taking a critical look at the various systems that make up a complete plant. Wherever possible, it may be beneficial to rethink the way things have been done. Two areas of particular interest in this regard are also two of the most important systems throughout the entire storage facility: the pipeline LD and CT systems.

Traditionally, LD and CT systems have not been fully integrated. They are looked upon as two completely different entities installed and operated independently, offering no measurement parameters to be used between them. Nonetheless, combining these two systems has the potential to provide numerous benefits, especially when looking at it in light of a PAM strategy. Before getting into these benefits, however, a brief description of each of the two systems and their primary functions is required.

Leak detection a must. From a PAM perspective, a pipeline LD system can be defined as an asset critical to sustained performance. If a product release occurs, the owner or operator will not only lose product, but will also most likely be fined for not detecting the release in a timely fashion or not at all, and may be faced with potentially enormous cleanup costs depending on the release size. In addition, outside factors—such as government law and regulations, rising energy prices, growing public concern about pipeline network reliability and security issues—all have an impact on how important an LD system is perceived to be. Having

FIG. 1

Storage facilities and liquid terminals can achieve substantial operational and cost-savings benefits by combining leak-detection and custody-transfer systems.

HYDROCARBON PROCESSING APRIL 2011

I 115

PROJECT MANAGEMENT an LD system is simply crucial and, therefore, it would be a good starting point to look for improvements related to a PAM strategy.

Many different LD system types are in operation today, but, basically, they can be divided into two main categories: external and internal. External systems, such as hydrocarbon sensing via fiber-optic or dielectric cables, detect leaks outside the pipe. Internal systems, on the other hand, utilize instruments to monitor internal pipeline parameters such as pressure, temperature and flow. Flow measurement is generally considered the most important process in pipeline operation and control for several reasons that coincide well with those of PAM. Most modern electronic flowmeters not only monitor the product flow, but also incorporate

FIG. 2

FIG. 3

116

Process automation instruments are considered the single most important source for controlling, monitoring and measuring overall equipment performance data, field device diagnostics and meter parameterization, all of which are considered key performance indicators of PAM.

When applying PAM to the HPI, and more specifically to a liquid terminal or storage facility, such areas as actual production measurement in relation to quality, quantity, reliability and environmental standards, and collection of historical data to help predict future performance and life cycle costs can be assessed.

I APRIL 2011 HydrocarbonProcessing.com

features like self-checking diagnostics and the ability to store data for future use.

A complete LD system is made up of two major components: the software and the hardware (process instruments such as flowmeters, pressure transmitters, etc.). LD system suppliers can therefore be divided into three categories, depending on which part(s) they deliver. Some manufacturers supply the software only while relying on the input from existing instruments to provide pipeline data. Others deliver the software and have agreements with third-party instrumentation providers to offer a complete solution, and others again provide both software and instrumentation in one integrated package.

One example of an internal LD system relies on clamp-on ultrasonic flowmeters based on the wide-beam measurement principle and a computer-based modeling package. It consists of one master station that collects and processes data, along with numerous site stations that measure and compute the variables required to run the LD system. The exact number of site stations depends on the pipeline length, but a minimum of two are required, one at each end of the pipe. Apart from the fact that this solution offers both the LD system software and hardware, it can also be easily integrated into a custody-transfer system. Advantages from a PAM viewpoint include the ability to install the instrumentation without shutting down the pipeline (thus reducing total life cycle costs), bidirectional measurement (decreasing operation cost by only requiring one meter to perform measurement tasks) and the capability to identify changes in liquid properties (product quality measurement).

Accurate product ownership transfer. As is the case with an LD system, a CT system can also be defined as an asset critical to sustained performance from a PAM viewpoint. Being that a custody transfer system is used to measure the product ownership transfer from, in this case, a liquid terminal to the endcustomer, it can mean the difference between making and losing money. Such a system, which is basically just a flowmeter, needs to be accurate and reliable, and it is required to constantly measure to very high standards. If it fails or is prone to performance issues or blackouts, a critical part of a terminal or storage facility’s function is inoperative. This is exactly what is sought to be avoided when utilizing PAM. By having a strategy in place that can diagnose health issues and predict remaining useful life, facility operators can engage in proactive as opposed to reactive maintenance.

Several flowmeter types are available for accurate CT measurement. Each of these has its strengths and weaknesses. Generally speaking, there are no set rules when it comes to choosing which technology is the most appropriate for a specific CT application.

It all depends on the operator’s preferences, installation and accuracy requirements. If a true integration between a CT and an LD system is to take place, however, the employed technology should be the same. So for, say, an LD system, relying on wide-beam ultrasonic flowmeters to be truly compatible with a CT system, they would both have to be based on the wide-beam ultrasonic flow-measurement principle.

‘Integrated’ systems. As mentioned, LD and CT have traditionally not been combined into an integrated system. Although real-world applications exist where data from a CT meter is used in an LD system, such solutions can hardly be considered truly integrated. This is mostly true for the software-based LD systems that rely on existing or third-party measurement equipment to feed the software with crucial real-time pipeline performance

PROJECT MANAGEMENT and operation. The instrumentation and software have not been manufactured to work with each other, making it necessary to customize communication protocols, data extraction and information analysis to mention only a few examples. The result is a system that depends on various factors that may or may not be compatible to produce an optimal performance. And this is a strategy that is incompatible with PAM. The future solution. In light of PAM and recent HPI product developments, however, truly integrated systems are now available. This has made the benefits of combining LD and CT systems much clearer.

In those cases where a wide-beam ultrasonic CT meter and one of the site stations of an LD system would be located close to each other, substantial cost benefits can be realized. With a combined system, one CT meter is installed that serves two purposes. First, it would be used for product ownership transfer and secondly, it would act as one of the LD system site stations. This would reduce capital costs, maintenance efforts and installation requirements, which are perfectly aligned with any PAM strategy goals.

Another combined LD and CT system benefit based on the same measurement technology and manufactured by the same supplier is the fact that it ensures overall compatibility. Everything from liquid sensing and communication protocol to data extraction and displayed information is based on the same principles.

This makes commissioning faster and easier, which potentially minimizes equipment installation and pipeline downtime.

Total cost of ownership (TCO)—or total life cycle costs, as it is referred to in PAM—is also positively addressed in a combined LD

and CT system. First, and as already mentioned, the most substantial upfront savings is achieved because less equipment is needed; secondly, less operator and maintenance training is required since they only need to manage one system and lastly, troubleshooting is made easier because the various combined system components have been designed with the same goal in mind. All these factors contribute to keeping the TCO down, which is one of the main goals of any PAM system.

Ultrasonic flowmeters come with a variety of diagnostic functions that add clear and distinct value to a PAM strategy when installed as part of a combined LD and CT system. One of the major benefits is that the flowmeter reports to the terminal or storage facility operator how the meter is doing, along with reporting the accuracy within the preset limits, and if the signal is strong enough to provide a measurement value, etc. This function eliminates the need for routine meter inspections. Another useful diagnostics tool is the totalizer function. It allows compiling historical data and adding time stamps or interval settings. This way a product amount can be determined, from which a product value can be derived, another important aspect of PAM. Finally, the diagnostic function can, in some cases, also be used to determine product quality variations, thereby enabling operators to look into what has caused the degradation in quality, which is clearly an asset in any PAM strategy. HP Jonas Norinder is a business development manager at Siemens Industry, Inc. in Hauppauge, New York. He has experience in marketing flow solutions in various industries. Over the years, Mr. Norinder has written numerous articles published in renowned industry-leading magazines on this topic.

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PLANT DESIGN AND ENGINEERING

How you can precommission process plants systematically Follow these guidelines for the best logical sequence for startup preparations V. RAMNATH, Engineers India Ltd., New Delhi, India

L

eading to engineering completion, operating personnel need to convey to the project/construction team which sections of the unit/plant are to be handed over chronologically so that the entire procedure is smooth. This information is conveyed by dividing the unit/plant into sections called systems. Each operating facility and associated units are divided into logical process and/or piping equipment systems. Normally, the precommissioning and commissioning of units in the chemical process industry are carried out on a system-by-system basis.

Systems are divided into process and utility systems. Process systems are those involving process fluids (e.g., the atmospheric distillation unit column’s overhead system), while utility systems involve utilities like instrument air, plant air, etc.

Precommissioning involves water flushing, air or steam blowing of piping and equipment, water trial of pumps, adsorbent loading, drying out fired heaters, etc.

Following these activities, hydrocarbon is put into designated plant areas such as cold circulation of crude oil, also termed as commissioning. Even though some parts of the plant are in this phase, others like the desalter, may still be in precommissioning mode.

System approach advantages.

The checking and testing phases of a new plant are relatively long and complicated processes—not all parts of the plant reach the same degree of completion at the same time. Hence, some areas or units of a plant may be complete and ready for precommissioning, while others are not. It’s therefore a waste of time to wait for the whole plant to be complete at the same time for precommissioning activities to begin.

Contrary to the construction work progress, which is essentially planned by trades and areas, the startup sequence of a new plant is driven by operational constraints with safety equipment and systems being given the highest priority; followed by utilities, power generation and other essential services required to supporting commissioning of the process equipment.

Therefore, a subdivision of an installation that performs a given operational function, with little or no interference from the

other parts of the plant, is undertaken to define, prepare and execute all mechanical completion and precommissioning. This benefits the operation by saving time and optimizing resources.

The systems will be identified at an early stage so that the mechanical completion of the systems can be expedited per priority.

This early stage of systems identification will also help properly sequence and integrate mechanical completion and precommissioning activities.

TABLE 1. System definition database Subsystem code

System description

Subsystem description

400 – P – 01

Reformate splitter

Feed to reformate splitter

400 – P – 02

Reformate splitter

Reformate splitter column

410 – P – 01

Clay treaters

Clay treater feed

410 – P – 02

Clay treaters

Clay treater equipment, V-111 and V-112

440 – P – 01

Adsorbent chambers

Adsorbent chambers, V-101 and V-102

810 – U – 01

Plant air

Plant air header

820 – U – 01

Nitrogen

Low pressure nitrogen

830 – U – 01

DM water

DM water supply

840 – U – 01

Cooling water

Cooling water supply

840 – U – 02

Cooling water

Cooling water return

Construction

Precommissioning

Commissioning

Product out

Test run Schedule advantage

Construction Precommissioning Commissioning Product out Test run FIG. 1

Comparison when using “systems.”

HYDROCARBON PROCESSING APRIL 2011

I 119

PLANT DESIGN AND ENGINEERING FI 6823 TI 6846

FQI 6823

TE 6846

PI 6850 FE 6823

FIT 6823

L

PIT 6850

TG 6891

PG 6801

6-in.–PA–68006–H1A–N

Plant air

Offsite

FI 6822 TI 6847

6-in.–TA–68004–H1A–N

FQI 6822

TE 6843

PI 6849

FIT 6822

FE 6822

L

PIT 6849

TG 6815

PG 6816

Instrument air

Offsite

FI 6842 TI 6843

FQI 6842

TE 6843

PI 6844

FIT 6842

FE 6842

L TG 6809

PIT 6844

PG 6810

Nitrogen

6-in.–NG–68005–A1A–N TI 6837

3-in.–FO–68002–B1B–LP

H L

FI 6836 FQI 6836

TE 6837 5

3-in.–FLO–68005–A1A–N

PI 6838

L

TG 6819

PIT 6838

FQIT 6838

5

2-in.–FO–59034–BLB–LP

H L

FI 6851 FQI 6851

PIT 6853 5

FQIT 6851

PI 6852

L

FIG. 2

5

Instrument air (820-U-001)

TG 6871

PG 6872

Offsite

Flushing oil supply

Offsite

PG 6890

5 B1B AIR

TG 6873

PG 6803

PG 6873

Fuel oil return Flushing oil return

Offsite

Offsite

Flushing oil (570-P-001) Nitrogen (850-P-001)

System markup at the unit battery limit.

This overall project planning will be better optimized if the mechanical test, pre-commissioning and commissioning activities are organized. As Fig. 1 indicates, there is a definite schedule advantage if the systematic approach is undertaken. This approach does not wait for the entire unit to be handed over, thus meeting the goal of early unit startup.

Systems and subsystems coding.

Systems are first identified per the agreed coding philosophy and defined on the unit piping and instrumentation diagrams (P&IDs). These define the boundaries between systems. Each system is then bro120

B1B AIR

TE 6852

2-in.

Fuel oil (560-P-001)

Fuel oil supply

H L

2-in.–FLO–68006–A1A–N

Plant air (810-U-001)

PG 6820

5 2-in.

TI 6853

Offsite

H L

I APRIL 2011 HydrocarbonProcessing.com

ken down into its components indicating the associated equipments, tie-ins, control valves, safety valves, instrumentation and any other component in its limit.

The system and subsystem identification code is generated with the goal that each system and its subsystems are uniquely defined. The coding identifies the unit, system type (process or utility) and corresponding subsystem.

The coding can be similar to: ABC – D – EFG ABC: System identification, three digit number (e.g., 100-799 for process systems and 800-999 for utility systems) D: P = process systems and U = utility

systems EFG: Progressive numbering, two or three digit number.

Table 1 details examples of a typical process and utility system database. This tabulation can include more information as required. Fig. 2 illustrates a mark-up of typical process and utility systems at the unit battery limit. As illustrated in Fig. 3, the hydrogen system 550-P-002 consists of the vessel, the overhead line HV-8003 to flare, to the isolation valve and safety valve upstream piping. Downstream, the safety valve is the system 850-U-001, part of the flare system. Fig. 3 is a typical diagram of systems marked-up within the unit.

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PLANT DESIGN AND ENGINEERING

1:500

4-in. x 3-in.

HS 8003A

ZLC 8003

ZLO 8003

ZSC 8003

ZSO 8003

HY 8003

S

Close

AS

HS 8003B

ATM Note–8,9 TSO

HV 8003

FC ¾-in.

Hydrogen (550-P-002)

TI 8001

TIT 8001

CSO

4-in. HG–80011–E25A–N

Close HS 8002

ATM

S

SDY 8002

R

AS

ZLO 8002

ZLC 8002

ZSO 8002

ZSO 8002

ATM

TSO

PG 8004

H L

CSO

½-in. SW

Distance by vendor

CSO CSO

Readable from grade

Flare (900-U-001)

2

2-in.

PI 8003

PIT 8003

H L

FC

SDV 8002

HS 8001

ATM

Close S

¾-in.

High-pressure close valve

I

Close

FO 8002

4-in.HG–80010–E25A–N

CSO

3-in. HG–80008–E25A–N

SDY 8001

R

ZLC 8001

AS

System mark-up within the unit.

System dossiers. All documentation pertaining to the precommissioning operations are compiled into a specific dossier.

All the facilities—including the equipment, instrument activities and all the subsystems pertaining to a particular system—should be grouped in the same system. The drawings, reports and all other related documents of the system may be maintained and retained as part of the same system.

Dossiers should include, as a minimum: • System description and markedup drawings. The systems are defined

by P&ID markups and have a detailed description, such that the systems are neither too broad or too narrow.

122

2

4-in. x 3-in. ¾-in.

Nipple ½-in.

Close

3-in. x 6-in.

31-1183

FIG. 3

A28A E25A

¾-in.

2

CSO

½-in.HG–80016–E25A–N

PSV 8001A

Distance by vendor CSO

A28A E25A

2

Set: 145 Kg/CW2G 16-in.NF–80003– Size: 3J4 A28A–N PSV 16-in. x 4-in.

8001B A28A E25A

½-in. SW LO

Set: 145 Kg/CW2G Size: 3J4

P

2-in.HG–80008–E25A–N

CSO

P

Tube ½-in. OD

HC–80012–E25A–N

Nipple ½-in. (Plxth.)

Open

2-in. NG–80009–AIA–N

1-in. x 2-in.

½-in. HG–80015–E25A–N

FO 8001

Tube ½-in. OD

6-in. NF–80006–E28A–N

A28A A1A

16-in.NF–80002–A28A–N

Min.

I APRIL 2011 HydrocarbonProcessing.com

• Functional test sheets—a spreadsheet showing the various stages of equipment installation from setting to sign-off.

• Operational test sheets—a spreadsheet showing the completion status of miscellaneous mechanical components (e.g., PSV’s, orifice plates, check valves, spring supports) • Specific procedures/reports—an example may include catalyst-loading procedures • Mechanical/electrical/instrumentation maintenance-related reports—an example may consist of a mechanical seal replacement on a process pump or replacing a faulty pressure transmitter

• Vendor reports—documentation on vendor’s acceptance of installation • Design-change notes/modifications—site modification, as required or suggested by licensor, should be well documented • As-built drawings—while it may not be entirely possible to issue as-built documentation during the precommissioning stage, all of it should be ready before completion of commissioning • Precommissioning punchlists— internal equipment inspection, e.g., vessel, column, tanks, etc.

• Leak test all defined systems as required or recommended from the punchlist

PLANT DESIGN AND ENGINEERING • Ready for commissioning certification—signed off by all stakeholders • System-related milestones—all major activities, as decided, should be planned and monitored.

Categorize your punchlists. Punch

list categories should be segregated critically—a minimum of three categories are suggested. Category PINK are those issues that prevent the subsystem/system from being precommissioned. Category RED are those issues that prevent the subsystem/ system from being commissioned or started up. Category GREEN are those issues that are not in Category PINK or RED. Define your milestones. The key milestones associated with transferring the responsibility from the precommissioning phase to the operation phase includes a subsystem ready to hand over when all precommissioning operations on that subsystem are complete. Another milestone is when a system is ready for commissioning/ startup when all checks are complete for introducing feedstock.

Be precise with your schedules.

Three schedule levels are recommended to control the mechanical completion and precommissioning activities. These are levels A, B and C. Level A schedule indicates the key dates for the entire plant with the overall period of precommissioning. Level B schedule highlights the key phases and milestones for a particular unit, and also highlights the expected construction completion dates, duration and timeframes for precommissioning phases per unit, etc. Level C schedule illustrates, per system, the various precommissioning main activities sorted per discipline/ trade (i.e., electrical, piping and process inspection activities, instrumentation and rotating equipment).

Before you begin. In breaking down

the facility by systems, the following is paramount: hydrostatic test packages normally do not cross subsystem boundaries. This will ensure no rework of hydrostatic packages by counterparts in construction. Also, subsystems shall not cross system boundaries and process systems shall not cross existing facilities boundaries.

Developing a schedule. A detailed

precommissioning schedule of sequential activities for each system should be developed. The planning and scheduling

groups of the engineering, procurement and construction contractor along with the client can work out the initial action— focusing on the systems most critical for a timely precommissioning. This schedule will identify, by system, the preferred sequence where each construction group should prepare and complete the scoped project systems. It will also identify walkdown dates for each system and specific precommissioning activities to precommission individual systems (i.e., reactor catalyst reduction, regeneration of water removal driers, etc.).

Systems record management. As the time required to hand over projects decreases, real-time monitoring and trouble-shooting assumes paramount importance. Software packages, i.e., structured database management systems, which are customized to be completion management systems are preferred for real-time information agents.

This enables a structured approach to manage, control and improve the ability to safely and successfully execute and integrate construction and commissioning activities. Within these packages should

be links to the equipment tag numbers that are fundamental to the requirements of inspection, testing and commissioning at each stage of the project. Tools for preservation and maintenance, as well as management and control on punch listing throughout the mechanical completion, precommissioning and commissioning phases, are to be provided.

Ideally, there are many desired functions, only limited examples are cited for each of these functions and include: • Employee wise departmental and functional access control—the commissioning group leader can restrict the deletion of records, thus controlling the modification of documents.

• Client/contractor/licensor access control has real-time access to punch lists and enables client/contractor/licensor to log in.

Access should be controlled while certain groups don’t need access, i.e., a pump vendor doesn’t need access to items not in their scope of work.

• A standard checklist for construction phases includes checklists for activities that are not limited to pump alignment, compressor alignment, hydrostatic tests and equipment installation.

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123

PLANT DESIGN AND ENGINEERING • A standard checklist for the precommissioning phase includes system flushing, air-blowing, steam blowing, chemical cleaning and inertizing. The checklists should include creating/using standard reports and creating/using a predefined blind list.

• Real-time monitoring includes integration with the planning department monitoring system to report real-time progress (punch list status, system’s “movement status,” etc.).

• The checklist needs to be operation friendly, allowing multiple views into the same organized data, by system or subsystems.

• Engineering database integration should be capable of importing engineering data sets from various engineering databases. These should provide a list of the add, delete, revise for review and optionally integrate with the systems defined.

• The “work anywhere” defines concepts that are able to handle multiple jobsites/geographic work locations in a collaborative environment.

• Be the “alarm clock” by prompting the next action in a workflow by way of

“inbox messages” or “notifications” for a particular user.

• Historization includes generating milestone completions records—w.r.t predefined or maybe redefined components.

• Maintenance management is the database integration with the company’s maintenance management system, while claims management is capable of managing and sending inputs to the company’s insurance’s claim system.

• The inspection test plan creates and manages the construction’s inspection test plan. This includes relating NDT records, action on hydrotest packs, etc.

• Stores integration will integrate project stores with the maintenance stores management system. A shortfall in material can be related to the bill of materials identification and appear as part of the exception list when a checklist is generated.

• Managing contractual manpower includes the labor/supervisor reported to site, millwright fitters that work on rotating equipment and manage contractual work passes, etc.

The list isn’t exhaustive and should be expanded with time, business sce-

HIGH ACCURACY FLOW METERS

narios and experience. As known, for a successful startup, the plant and equipment should be put through a thorough mechanical completion and inspection.

Commissioning procedures should be closely monitored with the availability of adequate spare parts and maintenance support and response. The company’s profitability, reputation, project success, plant effectiveness and pay are all at stake. With what was previously discussed, adequate overall planning, detailed long-term preparation and effective resource planning are required. All field equipment are subject to a full scope of work, as defined in bids, except for packaged equipment that have undergone rigorous factory acceptance testing (FAT) by the original equipment manufacturer (OEM). For these packages (packaged equipment are compressors, pressure swing adsorber units, etc.), typically a single checklist is handed out.

Commissioning engineers should ensure that every piece of equipment is subjected to the appropriate checks and tests during precommissioning.

During the mechanical completion checks and system tests, all discrepancies, damaged or missing equipment, malfunctions, missing documents, etc., should be categorized and recorded in the subsystem punchlists. Lists are kept updated throughout the mechanical completion operations, so a precise status of each subsystem is available at the “ready for precommissioning stage.” Additionally, arrival of startup staff can be scheduled when construction is nearly mechanically complete, saving time and money. By the systematic approach, these are all achievable. These summarize the basic skeleton of a structured approach to precommissioning a process unit. HP

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Engineers India Ltd., New Delhi, India, in the process plant design, safety/loss prevention and operations department. He has experience with design of offsites (FEED), HAZOP/Quantitive Risk Assesment (QRA), safety integrity level (SIL), process plant commisioning, preparing in-house precommisioning/commissioning completion software systems. Mr. Ramnath started his career with Reliance Industries, Hazira, Gujarat, India, and was involved with commissioning of the naphtha cracker unit (ethylene plant). He jointly implemented and operated APC and real-time optimizer (RTO) models across the naphtha cracker units, and was involved with debottlenecking studies and microplanning during normal operation and shutdown. Prior to working at the naphtha cracker plant, Mr. Ramnath operated a solution polymerization-type polyethylene plant at the same location.

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SALES OFFICES—EUROPE FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Bill Wageneck, Publisher Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 E-mail: Bill.Wageneck@GulfPub.com www.HydrocarbonProcessing.com

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FREE Product and Service Information—APRIL 2011 HOW TO USE THE INDEX: 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 several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www.

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ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

ABV Energy S.p.A. . . . . . . . . . . . . . . . 17 (153) ACS Industries Inc. . . . . . . . . . . . . . . 76 (171)

RS#

Company Website

Farris Engineering . . . . . . . . . . . . . . . 10

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Linde Ag . . . . . . . . . . . . . . . . . . . . . . 60 (101)

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Flexitallic LP . . . . . . . . . . . . . . . . . . . . 5

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Borsig GmbH. . . . . . . . . . . . . . . . . . . 89 (175)

Flowserve Pumps . . . . . . . . . . . . . . . 51

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HPI Marketplace . . . . . . . . . . 126–127 Site Licenses . . . . . . . . . . . . . . . . . 125 Software Instrucalc . . . . . . . . . . . . . 94 Software Winheat . . . . . . . . . . . . . . 94 Subscription . . . . . . . . . . . . . . . . . 117 (177)

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CB&I . . . . . . . . . . . . . . . . . . . . . . . . . 68

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Dresser-Rand. . . . . . . . . . . . . . . . . . . 36

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DuPont Vepsel . . . . . . . . . . . . . . . . . . 81

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Eaton Filtration . . . . . . . . . . . . . . . . . 78

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Eidos Sap SRL . . . . . . . . . . . . . . . . . . 49

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Elliott Company. . . . . . . . . . . . . . . . . 18

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Emerson Process Mgmt (Delta V) . . . . 54

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Webcasts—Heinz . . . . . . . . . . . . . . 83 (173) www.info.hotims.com/35902-173

(77)

Hermetic Pumpen GmbH . . . . . . . . . . 33 (159) (59)

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Quest Integrity Group LLC . . . . . . . . 123 (178) www.info.hotims.com/35902-178

Rentech Boiler System . . . . . . . . . . . . . 2

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Selas Fluid Processing Corp . . . . . . . . 42

(82)

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Socap SRL . . . . . . . . . . . . . . . . . . . . . 50 (163) Spraying Systems Co . . . . . . . . . . . . 131

(66)

Sulzer Chemtech, USA Inc.. . . . . . . . . 29

(68)

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TapcoEnpro International . . . . . . . . . . 87

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Team Industrial Services. . . . . . . . . . . 35

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K-Tek . . . . . . . . . . . . . . . . . . . . . . . . . 4 (151)

Thermo Fisher Scientific . . . . . . . . . . . 67

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ITT Industries . . . . . . . . . . . . . . . . . . 75

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(60)

Total Safety . . . . . . . . . . . . . . . . . . . 118

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Trachte USA . . . . . . . . . . . . . . . . . . . 76 (172)

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Koch-Glitsch . . . . . . . . . . . . . . . . . . . 48 (162)

Worley Parsons . . . . . . . . . . . . . . . . . 16 (152)

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KTI Corporation . . . . . . . . . . . . . . . . . 84

Kobe Steel Ltd . . . . . . . . . . . . . . . . . . 30

www.info.hotims.com/35902-69

Emirates . . . . . . . . . . . . . . . . . . . . . . 12

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Haldor Topsoe A/S . . . . . . . . . . . . . . . 46

Novozymes Biologicals . . . . . . . . . . . 71 (167) NPRA . . . . . . . . . . . . . . . . . . . . . . . 121

Carver Pump Company . . . . . . . . . . . 20 (154)

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Gas & Air Systems . . . . . . . . . . . . . . . 86 (174)

HPI Market Data Book . . . . . . . . . . . 74 (170)

Cameron . . . . . . . . . . . . . . . . . . . . . . . 8

Lurgi GmbH . . . . . . . . . . . . . . . . . . . 14

M3 Technology . . . . . . . . . . . . . . . . . 62 (165)

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Burckhardt Compression Ag . . . . . . . 59

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Events–IRPC . . . . . . . . . . . . . . . . . .6-7 Events–MITO. . . . . . . . . . . . . . . . . 128 (180)

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Flexim Americas Corp. . . . . . . . . . . . 124 (179) www.info.hotims.com/35902-179

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Axens . . . . . . . . . . . . . . . . . . . . . . . 132

Page

www.info.hotims.com/35902-91

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Aveva AB . . . . . . . . . . . . . . . . . . . . . 41

Company Website

www.info.hotims.com/35902-172

www.info.hotims.com/35902-73

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(89)

Zyme-Flow . . . . . . . . . . . . . . . . . . . . 21 (155) www.info.hotims.com/35902-155

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I 129

HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR tim.wright@gulfpub.com

Nervous Petroleum Week crowd thinks the geopolitically unthinkable These are nervous times in energy markets and on the bridges of oil tankers. Things are going belly up for oil users (which is everyone). And, as I fly home from International Petroleum (IP) week in London, the outlook for oil is similar to the chaotic adventure of my fellow passenger relates that he was chased through the Indian Ocean by pirates.

Nothing surprises me after weeks like this. The Middle East is in well-reported turmoil. In the UK, gasoline prices have never (ever) been so high, and the UK’s energy minister is warning of a 1970s oil price shock.

Spiral up. Brent crude prices are on a trajectory more astral

than they were at the beginning of 2008, according to a number of important metrics. There is a sense that the market is punch drunk from the blows that have rained in over the last 12 months.

The conditions of the energy market are similar to the adventure of young junior office.

“We took on supplies of razor wire, which we had to drape along the side of the vessel,” the young Swedish junior officer tells me. “We also rigged fire hoses which were permanently spraying salt water over the side.”

After joining the vessel at a Suez port, the officer spotted the pirate skiff in the early morning, and there followed nervous hours of pursuit as the captain swerved the vessel to make boarding more perilous. Eventually, the arrival of a Korean destroyer’s helicopter, four hours after the tanker issued its alert, persuaded the pirates to disengage.

His tale felt totemic of recent events. To say that a fear premium has re-entered the European oil market would be an understatement. By the time I’m writing this editorial, oil markets have priced in much bleaker prospects than piracy south of Suez. With the dust from two North African revolutions only now settling, and a third apparently underway, it is Saudi Arabia itself that is the barely mentionable elephant in the room.

Brent crude, currently considered the more reliable global oil benchmark, has at press time has increase $30 since it left a period of range-bound trading in the mid eighties in October 2010.

Update from IP. At IP Week, the Centre for Global Energy Studies (CGES) laid out just how dramatic the effects from events following the attempted suicide by fire of a young unemployed Tunisian university graduate have been. In fact, by many metrics, the oil market has risen more dramatically this year than it did in 2008, when Brent crude famously hit an intra-day high of $147/bbl.

Brent started 2011 $1.60/bbl higher than it did in 2008.

Prices then fell in 2008, whereas they rose in 2011. And in 2007-2008, global oil demand was falling. That is not happening this year.

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■ Much of the present unrest is due

to gross unequal distribution of wealth in MENA nations.

The big difference between now and then is that OPEC has more spare capacity to play with than it did. Even though Libyan production levels are currently in free fall, CGES estimates that OPEC spare capacity stands at some 5.3 million bpd, compared to 3.6 million bpd then.

In his presentation, Leo Drollos, the group’s Chief Economist also superimposed what happened next in 2008. I think he rather felt then that spare capacity would keep us from its excesses in the weeks ahead. Unfortunately, since IP Week, we’re ahead of the 2008 schedule. Based on his slide, oil prices that year spent March and the first half of April below $110/bbl. As I write in early March, Brent is changing hands for $115/bbl.

Gross inequalities forcing change. In oil market research

passing my desk this morning, BNP Paribas puts the fundamentals of Middle East unrest down to low gross domestic product per capita and gross inequality in the MENA nations.

Sweden’s Foreign Minister, Carl Bildt, has described a “demographic tsunami” facing the region, with 32% of the Egyptian population under the age of 15.

There are currently few signs of serious unrest in Saudi Arabia, which currently accounts for 3.84 million bpd of OPEC spare capacity. But, according to the CIA Factbook, 38% of the population is below 15 years of age.

As I write, a demonstration has been called for one week from now, and organisations like BNP Paribas are apparently calling for further political risk to be priced in.

And the Kingdom shares hallmarks with other countries that have recently seen large-scale unrest. “The situation in Bahrain, where a Sunni majority is being governed by a Shia minority, is the same in the eastern provinces of Saudi Arabia,” said Leo Drollos, “and there has been trouble there in the past.”

As I write, gasoline in the UK costs £1.30/liter or US $8/US gallon. The UK minister, Chris Huhne, is worried that there is “a threat here and now” that crude could reach $160/bbl on the back of further unrest. As Leo Drollos put it, any significant unrest in Saudi Arabia will mean “all price bets are off.” HP The author is HP’s European Editor and also a specialist in European distillate markets. He has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative.

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