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MAY 2012




Industrial valve market growing



China hungry for thermoplastics

New methods increase unit and equipment availability

Prevention and monitoring are key to mitigating plant failures

RENTECH breaks new trails in the boiler industry with its focus on custom engineering and design. There’s no “on the shelf” inventory at RENTECH because we design and build each and every boiler to operate at peak efficiency in its own unique conditions. As an industry leader, RENTECH provides solutions to your most demanding specifications for safe, reliable boilers. From design and manufacture to installation and service, we are breaking new trails. Select 52 at

MAY 2012 • VOL. 91 NO. 5



Consider updating your lubricant system Oil mist extends equipment life over other lube methods D. Ehlert


Improve seal designs for ‘dirty’ services


When good pumps turn bad


Who should you call to repair your process pump?

Environmental rules require increased reliability for pumps in flue-gas applications H. P. Bloch and T. Grove

A straightforward methodology deals with troublesome pumps R. X. Perez

Independent shops can provide upgrade and repair services for key process equipment H. P. Bloch

Cover Total’s multi-billion-dollar project in Port Arthur, Texas, transformed its refinery into a deepconversion facility. Upon completion in 2011, the refinery has the ability to process heavy and sour crude oil. The coker unit was the centerpiece of the project and included a lift of the 404-ton drums into their place on the structure. Photo courtesy of Total Petrochemicals and Refining USA.



2012 Petrochemical Outlook: Middle East and United States Commercialization of new and expanded feedstocks are prompting changes in global markets


China hungry for thermoplastics


Major increase in Alberta oil sands employment


Industrial valve market growing


Society urges GHS compliance



Control moisture problems in slurry-based polyolefin operations Fouling and coking inhibit adsorbent-bed efficiencies S. Mitra



Severe jet fires and vapor explosions Treatment options and the limitations of the existing guidance are discussed I. Bradley


95 103 109

Control DEA corrosion in a gas refinery Corrosion inhibitor selection and protective scales are key to prevention A. Zamani Gharaghoosh, A. Atash-Jameh, A. R. Rashidfarokhi, M. Pakshir and M. H. Paydar


HPIN RELIABILITY Avoid unnecessary developments


HPINTEGRATION STRATEGIES Suppliers and users share responsibility for successful controlsystem migrations


HPIN ASSOCIATIONS A wealth of knowledge at AFPM annual meeting


HPIN ASSOCIATIONS Industry gears up for 2012 International Refining and Petrochemical Conference

Maximize FCC main air blower and wet gas compressor capacity Maintaining optimum performance is crucial for sustained profitability J. R. Wilcox

What are the corrosion issues for gasohol? New study investigates metal deterioration from ethanol-blended gasoline J. Rawat, P. V. C. Rao and N. V. Choudary


HP ONLINE EXCLUSIVES HPINSIGHT The HPI uses technology when solving global problems

118 ENGINEERING CASE HISTORIES Case 68: Pneumatic testing dangers

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EDITORIAL Editor Stephany Romanow Reliability/Equipment Editor Heinz P. Bloch Process Editor Adrienne Blume Technical Editor Billy Thinnes Online Editor Ben DuBose Associate Editor Helen Meche Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor ARC Advisory Group

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I MAY 2012

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An opportunity to learn from and network with hydrocarbon processing industry leaders Hydrocarbon Processing’s International Refining and Petrochemical Conference (IRPC) is a market-leading technical conference. IRPC 2012 emphasizes the latest technological and operational advances from both a local and global perspective, and provides you with a unique opportunity to network with industry leaders and learn how technological and operating advances can benefit your organization or plant.

An exclusive tour of eni’s Sannazarro de’ Burgondi Refinery EST Project By registering to attend IRPC 2012, you will have the chance to reserve your spot on an exclusive tour of eni’s Sannazzaro de’ Burgondi Refinery in Pavia, Italy. A short bus drive from Milan, the refinery is home to the first-ever industrial application of the company’s proprietary Eni Slurry Technology for the conversion of heavy oil residue.

Register today! Go to, or contact Gwen Hood at +1 (713) 520-4402 or

2012 IRPC Sponsors:

Event Host Sponsor

Silver Sponsor

Gold Sponsor

USB Key Sponsor

Delegate Bag Sponsor

2012 International Refining and Petrochemical Conference This year, the conference agenda gives special focus to the topics of heavy oil, hydrogen management, environment/ safety, energy efficiency, petrochemical/refinery integration, and biofuels/clean fuels. In all, the conference will feature more than 40 presentations from esteemed speakers who are experts in their respective fields. At IRPC 2012, you will learn from some of the HPI’s most accomplished practitioners, including speakers from Indian Oil, Foster Wheeler, Criterion, Chevron Research, KBR, eni, Indian Institute of Petroleum, Ivanhoe Energy, Chevron Lummus Global and CB&I, Shell Global Solutions, and more.

2012 IRPC Speakers Include: Giacomo Rispoli

Michael Lane

Keynote Speaker Executive Vice President, Research & Development and Projects eni

Keynote Speaker Secretary General CONCAWE

Jerome Bonnardot

Luigi Bressan

Deputy Product Line Manager, VGO and Resid Fixed Bed Hydroconversion Axens

Director—Process and Technology Foster Wheeler

Latest Improvements in VGO based Hydrocracking Technologies

CONCAWE’s views on safety performance of the European downstream oil industry

Balancing Hydrogen Demand and Production: Optimizing the Lifeblood of a Refinery

S.M. Vaidya

Alan Munns

Deputy General Manager (Technical Services) Panipat Naphtha Cracker Indian Oil

Manager, Oil Refining Products & Solutions Centre ABB

Refinery & Petrochemical Integration— IOCL’s Experience & Future Option

Oil Refinery Product Blending—Getting Closer to the Sales Target

See the full list of speakers and download the complete agenda at Exhibit or Sponsor: Bill Wageneck, Vice President and Publisher, Hydrocarbon Processing at +1 (713) 520-4421 or For more information: Teresa Wright, Director, Global Events, Gulf Publishing Company at +1 (713) 520-4475, or


Learn. Discover. Engage. Attend IRPC 2012 to…. • Learn about both general and area-specific topics from key industry players • Be one of the first to see the cutting-edge EST Project at eni’s Sannazzaro de’ Burgondi Refinery • Benefit from various networking opportunities between technical sessions • Be part of a focused forum dedicated to exploring the latest developments within the international hydrocarbon processing industry • Have the opportunity to participate in real-time information sharing with HPI leaders representing a range of operating and technology companies • Expand your technical knowledge through a compelling dual-track agenda featuring more than 40 presentations assembled by IRPC’s esteemed advisory board

2012 IRPC Advisory Board: Giacomo Rispoli Executive Vice President, Research & Development and Projects IRPC Advisory Board Chair eni–Refining & Marketing Division John Baric Licensing Technology Manager Shell Global Solutions International B.V. Eric Benazzi Marketing Director Axens Carlos Cabrera Executive Co-Chairman Ivanhoe Energy Dr. Charles Cameron Head of Research & Technology BP Antonio Di Pasquale Vice President Refining Product Line Technip Giacomo Fossataro General Manager Walter Tosto S.p.A.

Dr. Madhukar Onkarnath Garg FNAE Director Indian Institute of Petroleum in Dehradun Rajkumar Ghosh Director (Refineries) Indian Oil Andrea Gragnani Refining Product Line Director Technip Dr. Syamal Poddar President Poddar & Associates Andrea Amoroso Vice President Process Technology eni Stephany Romanow Editor Hydrocarbon Processing Michael Stockle Chief Engineer Refining Technology Foster Wheeler


Make Your Plans to Attend IRPC 2012 To reserve your spot at the conference, register online at or contact Gwen Hood, Events Manager, Gulf Publishing Company, at +1 (713) 520-4402 or

Location MiCo – Milano Congressi | Piazzale Carlo Magno, 1 | 20149 Milano IRPC 2012 will be held at the MiCo – Milano Congressi, which is located in Milan’s city center and is one of the largest conference venues in Europe.

IRPC 2012 Registration Rates: • Single Attendee Early Bird (by 9 May): USD $930 | Regular (by 1 June): USD $1,095 • Team of Two Early Bird (by 9 May): USD $1,674 | Regular (by 1 June): USD $1,969 • Team of Five Early Bird (by 9 May): USD $4,246 | Regular (by 1 June): USD $4,995 • Pack of 10* Early Bird (by 9 May): USD $8,415 | Regular (by 1 June): USD $9,900 Register a team of 2 or more and save an additional 15 percent through 1 June.

Accommodations Enterprise Hotel | Corso Sempione 91 | 20149 Milano | +39 02 31818 1 Please visit to check room availability for 12–14 June 2012. Enter code irpc2012 in the customer code box to receive the special per-night rates of €135 (Single), €155 (Double), €165 (Executive Single) or €185 (Executive Double)—subject to availability. Admiral Hotel |

Domodossola 16 | 20145 Milano | +39 023492151

Please visit to check room availability for 12–14 June 2012. Click on the International Refining and Petrochemical Conference link under offers to receive the special per-night rates of €99 (Single), €119 (Double Single Use) or €149 (Double)—subject to availability. Meliá Milano | Via Masaccio 19 | 20149 Milano, Italia | +39 02 44406 1 Visit to check room availability for 12-14 June 2012. Enter 00155089DXF in the Corporate Code field to receive the special per-night rates of €149 (Single), €174 (Double), €179 (Deluxe Single) or €204 (Deluxe Double) plus VAT—subject to availability.

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The American Petroleum Institute (API) and American Fuel and Petrochemical Manufacturers (AFPM) trade groups are critical of the US EPA’s recent decision to approve higher levels of ethanol in gasoline (E15) before testing is complete, alleging that it could put consumers at risk. The groups said the EPA decision comes before the completion of thorough testing by the automobile and oil industries to ensure the safety and performance of the new fuel for vehicles. According to the API, testing results so far have revealed problems with E15 and that engine damage from its use may not be covered under vehicle manufacturer warranties. In March, the EPA approved the first applications to make E15, a 50% increase from the E10 blend allowed at present.

Technip has signed a cooperation agreement in the green chemistry business with Compagnie Industrielle de la Matière Végétale (CIMV). The two companies have been working together for the past five years, during which Technip provided CIMV with technological expertise in the fields of engineering and construction, enabling CIMV to pass from the pilot unit stage to the industrial unit stage. During this period, a CIMV process has been identified as a disruptive technology in the field of green chemistry. This technology is among the only ones in the market capable of converting solid biomass into hydrocarbons that can be used as a feedstock by the petrochemical industry. The CIMV technology can thus be seen as a key enabler for the sustainable green chemistry sector based on nonedible feedstock, Technip officials said. In conjunction with the technical collaboration, Technip has established a sales force to promote the CIMV process outside of France, along with the wide range of bio-sourced applications it offers industrial companies.

Gulf Cooperation Council (GCC) petrochemical companies’ fourth quarter 2011 earnings declined by 11.9% year-on-year to $732.2 million, compared to $831.6 million in the same period in 2010. This is according to a recent report from Global Investment House. Performances for petrochemical companies overall were marred by lower pricing in global markets. On a country level, the UAE stood out with major profitability growth, followed by Qatar. On the other end of the spectrum, net earnings in the Saudi Arabia and Oman petrochemical sectors dropped by over 16% each. Overall, performances of regional petrochemical companies were mixed. The leading contributor to the sector’s profitability was Saudi Basic Industries Corp. Other GCC petrochemical companies in the black for this time period included Industries Qatar and Safco. Companies reporting substantial losses were Saudi Kayan and Nama Chemicals.

BP’s previously announced sale of its Canadian natural gas liquids business to Plains Midstream Canada has been completed. The sale, which also included BP’s liquefied petroleum gas business in Canada, was made for $1.67 billion in cash. As of April 1, BP’s remaining business in Canada—including the integrated supply and trading business, the oil sands and existing Arctic discovery licenses—will be under BP Canada Energy Group, the company said.

W. R. Grace & Co. has entered into an agreement with Dow Chemical to develop new catalysts for polypropylene production. The catalysts, which use one of Dow’s non-phthalate internal donor technologies and Grace proprietary catalyst expertise, will be sold by Grace. These catalysts will help producers make resins to improve the performance of plastics, including better clarity, stiffness and impact strength. Customers can use the resins in a broad range of applications such as films, highperformance pipe, automobile parts, household appliances and household containers. Grace expects to begin commercial production of the new catalysts later this year. HP

■ Marathon limits flaring The US Environmental Protection Agency (EPA) and the Department of Justice recently announced an agreement with Marathon Petroleum Co. that has already reduced air pollution from all six of the company’s refineries. In a first for the refining industry, Marathon has agreed to controls on flares and to a cap on the volume of waste gas it will send to its flares. When fully implemented, the agreement is expected to reduce air pollution by approximately 5,400 tpy. A recently filed consent decree resolves Marathon’s alleged violations of the Clean Air Act. As part of the effort to reach this agreement, Marathon spent more than $2.4 million to develop and conduct pioneering combustion efficiency testing of flares. In addition, beginning in 2009, Marathon installed equipment, such as flow monitors and gas chromatographs, to improve the combustion efficiency of its flares. To date, Marathon has spent approximately $45 million on this equipment and projects, and plans to spend an additional $6.5 million. Marathon also will spend an as-yet undetermined sum to comply with the flaring caps required in the consent decree. At the same time, Marathon indicates that the equipment it already has installed is saving it approximately $5 million per year through reduced steam usage and product recovery. From 2008 to the end of 2011, the controls Marathon installed eliminated approximately 4,720 tpy of volatile organic compounds (VOCs) and 110 tpy of hazardous air pollutants (HAPs). An additional 530 tpy of VOCs and 30 tpy of HAPs are projected to be eliminated in the future. Under the agreement, Marathon will also implement a project at its Detroit, Michigan, refinery to remove another 15 tpy of VOCs and another 1 tpy of benzene from the air. At an estimated cost of $2.2 million, Marathon will install controls on numerous sludge handling tanks and equipment. Marathon will pay a civil penalty of $460,000. HP HYDROCARBON PROCESSING MAY 2012

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Repair is an Opportunity for Pump Improvement Pump Upgrades and Rerates Hydro Engineers have been improving pump performance since 1969. Many pumps operating today were designed and manufactured decades ago. Operating requirements of the plant or process may have changed and the pump is no longer operating at its BEP. By reviewing the pump’s original design in relation to today’s requirements, Hydro’s engineering staff can recommend upgrades for improving performance and extending pump life.



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Hydro, Inc. l HydroAire, Inc. l Hydro East, Inc. l Evans Hydro, Inc. l Hydro South, Inc. l HydroTex Golden Triangle l HydroTex Dynamics, Inc. HydroTex Deer Park, Inc. l CW Hydro, Inc. l Hydro Australia, Pty. Ltd. l Hydro Vietnam, Co. Ltd. l Safe-T Hydro, Inc. Hydro Scotford, Inc. l Hydro Middle East, Inc.


Avoid unnecessary developments Innovative thinking is appropriate in the hydrocarbon processing industry, and tremendous forward movement has occurred over the past 30 years. Innovation is to be commended, unless we invent or discover something that others have already done in earlier decades. Duplication of efforts is found when people no longer read; unfortunately, entire technologies are sometimes reinvented due to negligence by not researching earlier information. Case 1 experience. In this example, a major mechanical-seal

manufacturer apparently developed a mechanical-seal assembly as a replacement for carbon rings used in the gland areas of small steam turbines. However, 20 years earlier, this type of steam turbine seal gland upgrade cartridge (STSGUC) had been pursued and fully implemented by a user company in Texas. A conference paper was then written and presented at an American Society of Lubrication Engineers (ASLE) conference in 1985.1 Several manufacturers of small- and medium-size steam turbines were contacted by the Texasbased STSGUC users. But the manufacturers showed no interest in commercially developing cost-justified STSGUC retrofits. Later, a major seal manufacturer started marketing STSGUClike products. Could the manufacturer have saved money by investigating earlier developments? Could they have saved time and effort by researching the 1985 product releases? If the design team examined the matter, then why wasn’t there an acknowledgment to the conference paper and article that pointed the way?

FIG. 1

Acoustic IFD transducers mounted on a pump and its electric drive motor. The high-frequency amplitude excursions signaled bearing defects.3

FIG. 2

Acoustic IFD monitoring station, 1976.

Case 2 experience. Recently, a company developed a bearing

mounting arrangement that could accommodate vertical shafts. Apparently, the effort was in response to bearing failures with vertically oriented cooling fan shafts. Again, the developers were oblivious that well-established major bearing manufacturers had, for a long time, been providing spherical roller bearings with thrust load and angular misalignment capabilities. This knowledge could have saved money spent on developments that were largely a duplication of prior work. Case 3 experience. In 2009, a startup company began commer-

cializing technology aimed at capturing bearing degradation before it had progressed to failure. It is a predictive maintenance (PdM) approach, which could be best described as Bearing Housing Metal Stress Propagation Sensing. When asked for more data, it became evident that the company staffers had not read pre-existing conference proceedings, articles or chapters in books dealing with a pump PdM method known as incipient failure detection (IFD). Fig. 1 shows IFD transducers mounted on an electric motor driver and a pump bearing housing. In the early 1980s, several publications had highlighted IFD technology and explained why a major multinational petrochemical company in the US had discontinued supporting its IFD program.2 The short explanation is that each baseline electronic signature (displayed on the 1970s monitor in Fig. 2) is different from the next.

There was no cost-effective way to accurately predetermine an intervention threshold. Until such thresholds are defined and incorporated in a cost-effective, wireless signal transmission technology, the developments will meet with low user interest. Then again, good books may shed much light on similar issues.3 HP LITERATURE CITED Bloch, H. P. and H. Elliott, “Mechanical seals in medium-pressure steam turbines,” Lubrication Engineering, November 1985. 2 Bloch, H. P. and R. Finley, “A decade of experience with plant-wide acoustic IFD systems,” Vibration Institute Conference, Houston, Texas, April 1983. 3 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New York. 2011. 1

The author is Hydrocarbon Processing’s Reliability/Equipment Editor and a consulting engineer residing in Westminster, Colorado. Mr. Bloch is the author of 18 comprehensive texts. He is an ASME Life Fellow. HYDROCARBON PROCESSING MAY 2012

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Visit us at the May trade shows and see how Total Lubrication Management SM can help keep your operation performing reliably. Noria Reliable Plant 2012, Booth 308. Indianapolis, IN, May 1-3

AFPM Reliability and Maintenance Exhibition, Booth 519 San Antonio, TX, May 22-25

Good night. Rest easy, your operation is running smoothly, efficiently, safely. That’s because you manage your operation successfully, without the worry of persistent lubrication issues that divert attention away from the core business. You turned to Total Lubrication Management from Colfax Fluid Handling. They gave you the on-site team of specialists, the long-term commitment, the customized program of products, services and expertise, the sustainable, continuous improvement to take one heavy load off your shoulders. Dedicated to keep you Up and Running, so that you have many more good nights. And good days too. Total Lubrication Management … Up and Running

Call 888.478.6996 for more information COLFAX is a registered trademark of the Colfax Corporation and TOTAL LUBRICATION MANAGEMENT is a service mark of Total Lubrication Management Company. ©2012 Total Lubrication Management Company. All rights reserved.

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Suppliers and users share responsibility for successful control-system migrations Owner-operators and suppliers face many complex issues relative to when and how to migrate obsolete control systems and technology. ARC Advisory Group estimates that $65 billion of obsolete technology is still presently in use today, and much of it can be found in hydrocarbon processing plants. While many older systems are still performing well beyond the original life expectancy, this can introduce appreciable risk for owner-operators. Some issues relate to the lack of availability from automation system components. However, another major concern is the skill shortage needed to support obsolete systems. Owner-operators must decide how to justify and manage risk to their manufacturing business; while suppliers must develop solutions that simplify the process, and enable owner-operators to migrate successfully from the obsolete systems to a better operating platform. A half-day workshop at the recent ARC World Industry Forum in Orlando, Florida, brought together over 100 end users, suppliers, system integrators, and engineering contractors to discuss issues, needs and wants associated with migrating control systems. Suppliers and end users came away from the workshop with very useful information on planning out migration strategies. Justifying control-system migrations. Justifying a

control-system migration may be one of the biggest challenges owner-operators will face. While plant engineers are most efficient on determining equipment reliability and predicting end of life, this task is more difficult with control systems. It is challenging to convince management of the need and urgency to replace or to migrate to new control-system technology. In particular, one problem is that assets such as pumps, pipes, conveyer systems and other mechanical devices are designed to be repaired or replaced as components. In contrast, automation assets, in many cases, have to be replaced in their entirety. Key practices in justifying migrations. The ARC

workshop highlighted common practices used to justify migrations. Some reflect internal practices that might be executed during a migration project. Others represent “open season” for many technology suppliers, engineering contractors and system integrators, and include: • Developing a financial assessment for the cost— NOT the migration • Improving the rigor of control-systems reliability data to include actual failure events • Developing a technology maturity model across industry. Some facilities are late adopters, while others are current with technology • Benchmarking against other companies that are running obsolete systems • Driving value by creating long-term contracts and usersupplier relationships. Remember: Supplier evaluations are 70% technical and 30% commercial.

• Practicing standardization within the organization; it can help lower total cost of ownership significantly. Do a solid market assessment before beginning your migration. Migration approach selection. The workshop made it

very clear that migration approaches vary not just from industryto-industry, but from company-to-company. Operating companies must decide whether to do migrations while the plant is operating (via hot cutovers) or while the plant is offline (using a phased or vertical migration). According to some workshop participants, while it’s important to be aware of these general options, they don’t necessarily reduce migration complexity. In general, owner-operators of refineries and petrochemical plants (which “never sleep”) prefer to use the hot cut over approach, since turnarounds are done at long (typically five-year) intervals. Conversely, most chemical and polymer plants have more frequent turnarounds and other plant outages, making it easier to coordinate and manage an offline cutover. One leading integrated refiner/petrochemical/specialty-chemical company performs approximately 85% of its migrations using the hot cutover approach and 15% using the offline cutover approach. A leading global SI found that hot cut-overs are more cost-effective. Some users indicated that, regardless of planning, hurricanes and other Acts of God can force unplanned migrations. Supplier selection considerations. While the migration strategy is a key factor in vendor selection, workshop participants agreed that most migrations are done on a per-site basis. One global chemical company is now minimizing the number of vendors and is standardizing to lower total cost of ownership. Another major integrated energy company looks to the automation supplier to come back and manage the hardware inventory and to also help the company decide when system components should be replaced. Many end users also believed that it was important to manage a technology roadmap with suppliers on an ongoing basis. Having all plant sites near obsolescence at the same time would be extremely detrimental to operations. Supplier evaluation techniques that work well in the early stages of a migration project included a weighted scorecard against all criteria using KT or Six-Sigma approaches. Workshop participants noted that a wide range of definition and weighting for each criterion were used based on differences and priorities by the organizations. Developing a functional specification upfront proved to be invaluable for any project. Develop appropriate risk-management strategies.

Owner-operators and control-system end users must develop risk-management strategies for automation technologies that align with their operational philosophy, corporate directives and risk-management guidelines. This will ensure that investment HYDROCARBON PROCESSING MAY 2012

I 15

HPINTEGRATION STRATEGIES TABLE 1. Automation supplier and end user requirements for successful system migrations Automation supplier responsibilities

Automation user responsibilities

Maintain ongoing technology roadmap

Develop better understanding of how migrations relate to plant profits

Develop partnership relationship with owner-operator

Include support, training, parts, interfaces and vendor stability into TCO evaluations

Provide better technology migration plans, including common form factor for I/O

Make plant staff better aware about coming changes and training options

Provide better patch management and cyber-security tools

Highlight cases in which migration was delayed too long to help justify project

Reduce risks associated with migrations

Management should measure automation risk with corporate risk

Deliver adequate technological improvements to help justify system upgrades

Document actual failures and communicate potential risks associated with obsolete technology

Develop less costly and easier-to-use migration software

Develop and manage supplier relationships to encourage loyalty

Provide better training tools for operators and maintenance technicians

Develop human resources programs to retain core technical staff

Provide virtualization tools to link to legacy systems

Develop internal change management strategy to support operations

Provide analysis to help accurately determine wiring end-of-life

Develop better documentation for current state

Explicitly define how long the supplier will support technology

Consider beginning migration projects in pilot plants using simulation tools

Reduce complexity of automation systems designed on open systems

Consider including APC within migration scope

decisions for plant automation are made at the highest level within the organization and that the project team will have appropriate corporate-level support. Suppliers and end users must also jointly develop long-term strategies. This will ensure that obsolete equipment is sustained until a migration project can be planned. End users, suppliers and any third-party engineering and procurement contractor or system integrator firms must be involved in migration projects. Successful migration projects need the proper mix of resources and involve

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management experts at an early stage. Ultimately, the owneroperator must balance the risks of failure and lost opportunities against new capabilities and standardization. HP The author has more than 20 years of professional experience in process control, advanced automation applications, information technology, enterprise and supply chain in the downstream oil refining and petroleum product marketing industry. Prior to joining ARC in 2011, Mr. Reynolds served as the strategic planning manager for automation and IT at Irving Oil in Saint John, New Brunswick, Canada. Irving Oil operates Canada’s largest refinery. tubular filter




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Need to incorporate custom processing equipment or property calculations into your simulations? We’re on it. See other ways CHEMCAD helps advance engineering at ← Alejandra Peralta, CHEMCAD Support Expert

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Solutions for real technical challenges Siemens always goes the extra mile to supply innovative and reliable oil and gas solutions. Solutions for the oil and gas industry

Decades of experience in the oil and gas industry, leading technical expertise, and our own product development and production facilities are the solid foundation for a wide range of high-performance products and services. We offer comprehensive solutions for the entire life cycle of a plant and along the entire oil and gas value chain. The basis is our global engineering and project manage-

ment expertise as well as extensive experience in turnkey projects. Siemens’ early involvement in the concept phase results in the best possible technical solutions and limits project risks. And packages for entire functionalities reduce interface conflicts to help optimize a plant’s CAPEX and OPEX. Select 67 at


Selas Fluid’s Revamp Group builds on our history of proven results serving the reļning, petrochemical, and chemical industries. A world class designer and supplier of ľred process plant equipment for over 60 years, Selas Fluid also delivers cost effective solutions to optimize your existing plant assets from concept to reality.

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A wealth of knowledge at AFPM annual meeting At March’s American Fuel and Petrochemical Manufacturers (AFPM, formerly known as the NPRA) annual meeting in San Diego, California, it seems everyone had some important knowledge to share. Nowhere was this more evident than in the technical sessions, which covered many issues relevant to refiners. Hydrocarbon Processing was privileged to produce the official show daily newspaper for the event. We have assembled information on some of the more standout presentations. Maximizing diesel production. Phillip Niccum, KBR,

spoke about maximizing diesel production in the FCC-centered refinery. One of Mr. Niccum’s key points examined how FCCbased refinery diesel production can be maximized while taking advantage of existing FCC assets. The simple answer is to avoid the loss of virgin distillate to the FCC feedstock and to maximize the production of hydroprocessed LCO and diesel synthesized from the oligomerization of lower boiling FCC olefins. Mr. Niccum indicated that after a refiner has taken the steps necessary to minimize the loss of straight-run diesel to the FCC feedstock, some FCC operating adjustments can be commonly applied in the interest of increasing refinery diesel production. These include a lower FCC naphtha endpoint; increased FCC catalyst matrix activity and lower rare earth/hydrogen transfer activity; and a maximized LCO endpoint. While these are somewhat commonly applied strategies, Mr. Niccum also advocated two other approaches. The first is to reduce FCC cracking severity, allowing for maximized LCO production, while taking action, if need be to mitigate the associated loss of FCC naphtha octane and LPG production. The second would be to increase FCC cracking severity to maximize the production of lower-molecular-weight olefinic products from the FCC unit and oligomerize these olefins to produce high-quality synthetic diesel. CO2 capture project. The technical and economic results from Air Products’ CO2 capture project in Port Arthur, Texas, will be critical to determining the most effective commercialization path for future projects, according to Bill Baade, an Air Products official involved with the project. “As of now, the existing CO2 market does not support current CO2 capture economics without external funding,” he said. Because of that, the Air Products project was accomplished via $284 million in funding from the US Department of Energy, which represents about 66% of the overall cost, Mr. Baade said. When complete, CO2 captured from hydrogen steam methane reformers (SMRs) at Valero’s refinery in Port Arthur will be compressed and purified, then sent to Denbury for injection into Texas oil fields for enhanced oil recovery. Mechanical construction began in January 2012. One plant is expected to start up in late 2012 and the other unit in 2013.

Predictive analytics. Refinery and plant operators are increasingly using predictive analytics when it comes to safety and operational risk management. Those were the thoughts of Mark Weitner, global leader of operational risk management at Connecticut-based IBM Global Business Services. Mr. Weitner applauded the industry, saying predictive analytics are emerging as an important technique to identify organizational, operational and safety risk factors. Moreover, those analytics are becoming core to companies’ performance management programs, he said. “We’re seeing a natural progression of using the increasingly sophisticated tools available,” Mr. Weitner said. “It’s especially become more common in the chemicals and petroleum industry in areas like predictive maintenance.” Distinguished Safety Awards. AFPM’s most prestigious

safety award is presented annually to the member company facilities that have attained a superior level of safety performance in the refining and petrochemical manufacturing industries. Recipients are chosen by a selection committee comprised of members of the AFPM Safety and Health Committee. Winners will also be recognized at a dinner in San Antonio, Texas, as part of the AFPM National Occupational and Process Safety Conference. This year’s award winners are: • ConocoPhillips’ Santa Maria facility located in Arroyo Grande, California • The Michigan refining division of Marathon Petroleum • Valero Energy’s refinery in Houston, Texas. HP —With reporting from Ben DuBose

AFPM Chairman Jim Mahoney presents Layne Riggs of Valero Energy with a safety award.


I 19

Total integrated solutions for downstream? Absolutely.

A partnership with ABB means world class expertise and continuity. We provide fully integrated power, automation, safety and telecoms solutions for oil refineries, heavy oil conversion and associated downstream processes. We minimize customers’ risks, project delivery time and optimize the operational benefit of the installed system by providing integrated products and solutions as the Main Automation Contractor (MAC) and the Main Electrical Contractor (MEC). ABB is your ideal partner to extend your refinery boundaries Select 69 at

Milan, 12-14 June 2012 Visit us at booth #14



Industry gears up for 2012 International Refining and Petrochemical Conference Leading hydrocarbon processing industry (HPI) executives and technical experts will come together 12–14 June in Milan, Italy, to share ideas and knowledge relating to the industry at Hydrocarbon Processing’s third annual International Refining and Petrochemical Conference (IRPC). Returning to Italy—the 2010 event was held in Rome—IRPC 2012 will provide leading-edge technical coverage and emphasize the latest technological and operational advances from both a local and global perspective. In recognition of a challenge facing many operators in today’s international HPI, the conference will give special focus to the issue of heavy oil conversion. Flexibility has become a crucial factor where a company’s ability to efficiently process heavier, less-sweet oil is concerned, especially at existing facilities. At IRPC 2012, company leaders, managers, engineers and other staff will be able to familiarize themselves with the latest technological developments and applications. Conference participants will have numerous chances to brainstorm with one another about how best to implement these new systems and technologies at their own companies.

EST is just one of the many technologies changing the way refiners approach the heavy oil challenge. At IRPC 2012, companies like ABB, Applied Rigaku Technologies, Axens, Chevron Lummus Global, CRI Catalyst Co., DeltaValve, Foster Wheeler, General Atomics, Indian Institute of Petroleum, Indian Oil, Invensys, Ivanhoe Energy, Lummus Technology, Siemens Oil & Gas and Walter Tosto will all have a presence. In a track entirely devoted to the discussion of heavy oil refining, representatives from these companies will share their experiences with technology and what best practices they have discovered over time. Talking points. Not only do certain

companies in the refining and petrochemicals industries stand out for their contributions, but so, too, do the individuals leading these industry players. Take, for example, eni. The company

is in the midst of completing a refining project that will allow for 99 percent conversion of heavy oil with zero fuel oil or coke production. Leaders like Giacomo Rispoli, eni’s Executive Vice President of Research and Development and Projects, guide their companies forward and ensure that innovations like EST are always a top priority. Rispoli, who is currently coordinating, among other projects, the EST implementation at Sannazzaro, will open the technical sessions of IRPC 2012 as a keynote speaker on day two of the conference. He has been with eni since the mid-1980s, after graduating from the University of Rome with a degree in chemical engineering and getting his start as a process engineer. Having held both management and practical engineering positions, Rispoli will be able to share his invaluable professional experience with conference attendees through his speech.

Where innovation happens. IRPC

2012 is a forum within which HPI professionals can devote real time to valuable, strategic problem-solving efforts. The conference also offers participants the unique opportunity to see where and how heavy oil conversion takes place. In an exclusive partnership with eni, IRPC 2012 attendees will have the chance to tour the Italian major’s Sannazzaro de’ Burgondi Refinery EST Project in Pavia, Italy. The soon-tobe-completed project is home to the first full-scale application of the company’s Eni Slurry Technology (EST), used for the conversion of heavy oil residues in fine products, gasoline and gasoil. The facility is scheduled for completion at the end of 2012 and will have a capacity of 23 Mbpd.

FIG. 1

Lifting columns into place at eni’s Sannazzaro de’ Burgondi Refinery EST Project.


I 21

Reliability has no quitting time. Think about ITT.

In oil and gas facilities around the world, ITT delivers pumps, valves, composite piping, switches, regulators and vibration isolation systems that can handle harsh conditions and keep going. After all, in the 24/7/365 refinery business, the last thing you want is a piece of equipment that fails. With ITT, your processes stay up—and your total cost of ownership stays down. For more information, and to receive our Oil and Gas catalog, visit or call 1-800-734-7867. Conoflow | Enidine | Fabri-Valve | Fiberbond | Goulds | ITT Standard | Midland-ACS | Neo-Dyn Select 77 at

HPIN ASSOCIATIONS ■ “I attended IRPC 2010 in Rome and IRPC 2011 in Singapore. I am impressed with the event’s high organizational standards. IRPC provides a strong forum to share our experience, expertise and vision to meet evergrowing challenges in the hydrocarbon industry, particularly in refining.” —Suresh Gorana, Technical Specialist (Engineering Solutions), Petrofac OEC Joining Rispoli as a fellow keynote speaker and HPI leader is Michael Lane, Secretary General of CONCAWE. Lane was elected in 2009 to his current position within the oil companies’ European association for environment, health and safety in refining and distribution. In speaking to IRPC 2012 attendees, Lane, a Chartered Environmentalist, will provide insight into CONCAWE’s views on safety performance of the European downstream oil industry. Prior to joining the organization, he held regional and global positions with ExxonMobil, most recently serving as Global Environment and Health Manager for the company’s Downstream and Chemical businesses. Lane is a Fellow of the Institution of Chemical Engineers and received master’s degrees in natural sciences and chemical engineering from the University of Cambridge. Technically speaking. These days, refiners around the world are looking to maintain the profitability of their businesses, while ensuring that their facilities continue to operate at realistic levels of environmental sustainability. The keys to successfully balancing those, among other priorities like energy security and safety, are technology and innovation. At IRPC 2012, subject matter experts and experienced industry professionals will present

FIG. 2

Final fabrication review.

the latest technological developments and best practices from areas throughout the HPI. Technical sessions are dedicated to topics like hydrogen, environment and safety, energy efficiency, petrochemical/ refining integration and biofuels/clean fuels, in addition to the conference-headlining theme of heavy-oil conversion. This year, presentations dealing with topics other than heavy oil will be made by members of companies like ABIQUIM (Brazilian Chemical Industry Association), GTC Technology US, Industeel, ITS Reaktortechnik GmbH, WorleyParsons, Lukoil Neftochim Bourgas, Petkim, ORLEN Projekt, Saipem, Hyperion Systems Engineering, Saudi Aramco, Shell and Tecnimont KT. Selected for their relevance to the challenges facing today’s international HPI, papers chosen for presentation at IRPC 2012 will cover the following topics, among others: hydrogen management, high-temperature refining reactors, sulfur recovery, effluence management, flare minimization, process simulation, greenhouse gas management, reliability, shale gas harvesting, renewable fuels and fluid catalytic cracking. At the forefront of the industry.

In the global HPI, the success of a business opportunity often hinges on a company or representative’s ability to make the right connections, with the right people. At IRPC 2012, HPI professionals will have face-to-face access to the organizations and professionals with which you are looking to make contact. Attendees from around the world come together and are able to brainstorm and network during various breakfast, lunch and refreshment breaks. During these betweensession times, many IRPC speakers and advisory board members will be present to chat with attendees and participate in the ongoing discussion process. For more information about the 2012 International Refining and Petrochemical Conference, hosted by Gulf Publishing Company and Hydrocarbon Processing, please visit HP

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

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Discrepancies between actual and measured levels—due to temperature and fluid changes— may result in unnecessary maintenance. I need accurate PV measurements from my instruments.


The DLC3020f fieldbus digital level controller provides next generation performance and information access to help users improve operations. In addition to displacement sensor technology for measuring liquid level, the DLC3020f uses the digital FOUNDATION™ fieldbus communication protocol to help users improve performance, while avoiding unexpected downtime. Intuitive graphical displays, real-time access to historical operating logs, and easily-configured process fluids add real value to level control systems. The capability to easily select and define process fluids allows on-the-fly fluid changes for batch or continuous applications without calibration, saving time and recalibration costs. For more information visit Select 76 at

The Emerson logo is a trademark and service mark of Emerson Electric Co. ©2012 Fisher Controls International LLC. D352040X012 MY41 (H:)


China hungry for thermoplastics Newly discovered plastic blends are helping to satisfy the huge demand for thermoplastics being brought about by China’s swelling home retail industry, according to a new report by market intelligence company GBI Research. The report found that new blends, which have expanded the potential uses for acrylonitrile butadiene styrene (ABS) (Fig. 1), have enabled the plastics market to keep up with orders from end-use sectors such as household appliances, electrical and electronics products. While the demand for ABS has been steadily increasing across the world over the last decade, a significant portion of this increase has stemmed from Asia-Pacific, with the region accounting for 77.3% of global demand in 2010. Due to high demand, China has rapidly emerged as a global petrochemical products manufacturing hub, threatening to overtake many of its competitor regions, such as the Middle East. China is the leader of the Asia-Pacific ABS market, due to a high demand for thermoplastics upheld by a rapidly growing population and an increasing average income. However, the country imports a considerable amount of ABS in order to meet demand for the production of appliances and electronics, creating potential for ABS capacity additions in locations with low operating costs.

FIG. 1

Further technological advancement are expected in the sector, similar to manufacturers who are currently blending new compounds like polybutylene terephthalate (PBT), nylon 6 and liquid crystalline polymer (LCP) with ABS to create novel plastics. Constant innovation in the field is expected to further increase the demand for ABS in a wider range of applications in the future. In 2000, global ABS demand stood at 4.6 million tons, before increasing to 6.4 million tons in 2010, at a compound annual growth rate (CAGR) of 3.4%. Global demand for ABS is expected to grow at a CAGR of 5.5% from 2010–2020, reaching 10.9 million tons in 2020.

Major increase in Alberta oil sands employment Alberta’s oil sands industry, which employed just over 20,000 workers in 2011, is projected to grow its workforce by 73% by 2021, according to a new report released by the Petroleum Human Resources (HR) Council of Canada. The report states that some oil sands operations and occupations are forecasted to add over 100% of their current workforce by 2021. The Petroleum HR Council’s outlook provides oil sands labor demand projections and analysis based on data for 55 core occupations within three facility/operation types: in situ, mining and upgrading. It describes how technological changes, as well as shifts in the regulatory and busi-

Acrylonitrile butadiene styrene is in high demand in China.

FIG. 2

ness environments, are impacting how the oil sands sector does business and what types of workers are required. For example, employment within insitu operations will experience the greatest growth, driving a number of emerging occupations and an increased reliance on the oil and gas support services workforce, the report says. Increased mining and upgrading activities will also contribute to the sector’s employment growth (Fig. 2). “The oil sands sector entered 2012 with a healthy dose of optimism, with all indicators (notably stable oil prices and strong international investment) pointing to continued expansion,” said Cheryl Knight, CEO of the Petroleum HR Council. “Demand for more workers is being driven primarily by growth in the sector, however, our research tells us that the supply of skilled workers remains very tight. Going forward, age-related attrition and competition from other industries will further escalate labor and skills shortages faced by the sector. In fact, the sector may need to hire 116% of its current employment levels due to industry expansion, retirements and losing people to other industries.” The report also states that industry will be challenged to manage workforce costs in this employee-driven labor market. The oil sands sector will have to give considerable thought to effective and efficient strategies to work with the construction, maintenance, and oil and gas support

Alberta’s oil sands industry is projected to grow its workforce by 73% by 2021. Photo courtesy of Suncor. HYDROCARBON PROCESSING MAY 2012

I 25

HPIMPACT services sectors, which are critical to the growth and sustainability of oil sands operations, the report’s authors say. The study was funded by the Government of Alberta.

Industrial valve market growing The world market for valves used by industry will grow to $65 billion per year in 2017 (Table 1), adding more than $10

billion to current annual sales. This projection is in the latest forecast by the McIlvaine Company. East Asia will account for more than 30% of the market in 2017. The growth in this region will be driven mostly by new infrastructure and heavy industrial spending. More power plants will be built in East Asia over the next five years than in the rest of the world combined, the study says. The investment in municipal wastewater

treatment and drinking water facilities will also outstrip the other regions. East Asia is projected to dominate the production of semiconductor chips, flat panels, solar voltaic cells and other devices requiring high performance valves for ultrapure water. The growth in North America will be led by the nonconventional oil and gas sector. Pennsylvania, Texas and other states will expand their production of gas and oil from shale. This will generate substantial investments in valves. Western Europe will be a slow growth market characterized by a large percentage of replacement valves for existing plants as opposed to valves for new plants. Eastern Europe will reflect growth in expenditures to meet environmental regulations required for European Union membership. Middle East expenditures will rise as the region increasingly becomes a supplier of refined rather than raw products. Valve sales in this region will also be boosted by desalination plant investments. The ocean will play a role in several ways. New regulations for ballast water treatment and scrubbing of vessel stack emissions will boost the sales of valves for existing and new vessels. Expanded production of oil and gas from subsea sources will require many large and expensive valves.

Society urges GHS compliance The American Society of Safety Engineers (ASSE) has been preparing health, safety and environment (HSE) professionals for major compliance changes that are required by the United Nations’ (UN’s) Globally Harmonized System (GHS). GHS, a consistent way to globally comTABLE 1. Projected worldwide valve sales, 2017 ($ billions) World region Africa




East Asia


Middle East

5.2 12.6

South and Central America


West Asia


Western Europe


Total Select 154 at


Eastern Europe

North America


Year: 2017


Select 61 at


FIG. 3

Examples of the new globalized product/chemical hazard identifier symbols that are a part of the UN’s Globally Harmonized System.

municate chemical hazard information, was adopted by the UN in 1992 and by the Occupational Safety and Health Administration (OSHA) on March 20, 2012. The US Federal Register published the final rule on March 26, with the effective date coming 60 days after the date of publication. Companies that work with chemicals are expected to have trained their employees on how to read the new material safety data sheets (MSDS) and labels by June 1,

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2013, and to have all employee training completed by June 1, 2016. ASSE members recommend that companies and their employees become familiar with the new globalized product/ chemical hazard identifier symbols (Fig. 3), which have been redesigned to include a red border. A new symbol has also been added to the group under the jurisdiction of GHS, which indicates that a chemical is an environmental hazard. Risks associated with exposure to chemicals are broad and can range from burning of the skin or eyes; damage to the body’s respiratory or neurological system; birth defects; or deadly diseases, including cancer. In today’s world of global trade, it has become necessary to have a harmonized system for the classification and labeling of chemicals. Such systems will make it easier for employees around the world to understand the hazards of certain substances they come into contact with and to take the necessary precautions to stay safe on the job. The revised GHS hazard communication standard (HCS) now focuses on an employee’s right to understand the hazards of materials they come into contact with while on the job. Differences in chemical regulations, classifications and labeling of chemicals in various countries have led to problems in communicating the dangers of hazardous materials. In addition, compliance with multiple regulations can be costly and time consuming for corporations. These burdens can make it difficult for them to compete internationally. “The GHS requires consistent communication in labeling,” explained ASSE member Glen Trout, president and CEO of Chicago-based MSDSonline. Experts strongly urge those affected by GHS to begin implementation and employee training as soon as possible to ensure that they are not mired with compliance requirements at the last minute. Companies are encouraged to begin a dialogue with their employees to ensure that they understand the changes. They should also talk to their chemical suppliers to find out their plans to transition to GHS. OSHA estimates that once GHS is fully implemented, employers will save approximately $32.2 million as a result of higher efficiency in transporting products around the globe, as well as a decrease in workers’ compensation and lost work time due to chemical exposure. HP


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Lewis® Pumps products are right t e g r a t n o

Weir Minerals Lewis Pumps is the world standard for manufacturing pumps and valves in the sulphur chemicals industry. Offering a family of Lewis® steam-jacketed sulphur pumps, outstanding reliability in high-temperature sulphuric acid applications, and a complete family of valves, Weir Minerals Lewis Pumps continues a long tradition of offering superior products and services. With its strong commitment to service, Weir Minerals Lewis Pumps can ship standard replacement wear parts in 72 hours to most international airports in emergency situations. With a complete line of pumps and valves, Lewis® Pumps products are right on target. Customers in more than 100 countries can’t be wrong. Select 94 at

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Copyright © 2011, EnviroTech Pumpsystems, Inc. All rights reserved. LEWIS and LEWIS PUMPS are registered trademarks of Envirotech Pumpsystems, Inc.; WEIR is a registered trademark of Weir Engineering Services Ltd.


Catalyst boosts H2 output, cuts costs Haldor Topsøe recently introduced a low-methanol, low-temperature shift (LTS) catalyst, LK-853 FENCE, which presents new opportunities for hydrogen and ammonia producers. The catalyst reduces operating costs, improves process efficiency and increases daily H2 and NH3 production. The FENCE technology enables the separation of nano-sized copper particles by multiple metal oxide barriers, thereby stabilizing the catalytic active sites. The result is a state-of-the-art LTS catalyst providing increased activity, improved poison resistance and longer lifetimes. Furthermore, the promoter content in the catalyst has been optimized to inhibit byproduct formation, minimizing the formation of methanol. Select 1 at

Picarro analyzer simplifies gas leak detection The recently debuted Surveyor for Natural Gas analyzer provides rapid, accurate leak detection for improved safety. Based on Picarro’s globally deployed Cavity RingDown Spectroscopy (CRDS) analyzers, the Surveyor measures methane plumes in the air, maps them, and then immediately alerts users and repair teams upon leak detection in real time while traveling at normal driving speeds. Picarro’s technology is up to 1,000 times more sensitive and faster-scanning than incumbent technologies typically used on foot patrol. The Surveyor consists of instrument hardware mounted in a vehicle, and software running on P-Cubed, Picarro’s cloud-based processing platform that uses patent-pending algorithms to analyze data that it wirelessly receives and stores during surveys. All data are simultaneously available in real time to vehicle operators, supervisors, response teams or anyone granted secure web access. Users can choose to view their information on a tablet, desktop or even a mobile phone. The solution combines ultra-trace methane concentration measurements in air with high-resolution GPS location, a time stamp, and wind speed and direction. When the system suspects a natural gas leak, it automatically determines the stable

isotope signature of the methane to confirm a methane source as natural gas and rule out false positives from naturally occurring methane. It then analyzes the recorded wind speed and direction to indicate the likely location of leaks. The combined features of the Surveyor solution substantially increase the frequency and accuracy of leak surveys for natural gas utilities. Picarro was honored as a 2012 Energy Innovation Pioneer by energy consultancy IHS CERA at CERAWeek in Houston, Texas, in March. Picarro CEO Michael Woelk spoke with Hydrocarbon Processing about the Surveyor’s superior leakdetection and time-saving capabilities. “To compare, it takes about 280 man-hours to do a [manual gas leak] survey, versus 10 hours to do the survey with our technology,” Mr. Woelk explained. “So that’s massively transformational for companies, because you’re talking about 3% of the total time necessary to do these surveys. Also, you find more leaks, you eliminate false positives, and you can communicate the [leak discoveries] wirelessly to anyone with a broadband connection.” Mr. Woelk also touted the Surveyor’s ability to cut costs and improve safety. “Cost per survey is going to drop through the floor,” he asserted. “Which means, of course, that you have an opportunity to increase the frequency of surveys. If you increase the frequency of surveys, that means you’re learning more about the inventory of leaks in your grid, and that makes you smarter. It also makes the communities safer.” Additionally, Mr. Woelk expanded on the ways in which Picarro’s gas analyzers will be used in the future to address environmental concerns generated by the increased production of shale gas. “We’ve heard a lot of discussion from people that are real leaders, both on the industrial side and on the policy side, acknowledging that, for natural gas—particularly shale gas—to get the support it needs, there must be a level of transparency about the emissions that are leaking from these wellheads,” he stated. “That’s what our technology can do. We’ll provide that information, and we’ll make that information really cheap to access and very simple to

interpret using some very complicated algorithms, and we’ll embed that on the cloud to scale the accessibility and interpretation of that information.” Select 2 at

Software simplifies pipe support design LISEGA’s 3D computer-aided design (CAD) software program, LICAD, allows engineers and architects to plan and design a pipe support system within minutes. The logistical complexity involved in the planning and design of intricate pipe systems means that pipe support design often takes place at the end of the planning chain, even though it is needed onsite prior to pipe installation. However, the LICAD software makes it simpler to electronically design, specify and order the needed products all at once, saving time and reducing the expense typically required when the process is performed manually. With LICAD, the relevant data for individual support points is entered using a menu-driven program control. Six parameters are required to find the optimum solution: pipe diameter, pipe temperature, operating load, travel, installation height and support configuration. From this input, the appropriate load chains are created automatically, in less than a second.

FIG. 1

Picarro’s gas analyzer is up to 1,000 times more sensitive and faster-scanning than technologies used on foot patrol.

As HP editors, we hear about new products, patents, software, processes and services 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 and select the reader service number.


I 31

HPINNOVATIONS The optimum selection of supports—such as variable spring and constant hangers—is performed simultaneously by the program. LICAD references LISEGA’s 10,000 standard pipe support components to design standard pipe support configurations. From the standard component catalog, support configurations that cover 90% of pipe installation situations can be designed. LICAD generates true-to-scale drawings of support chains, which are saved

as complete assemblies and can be printed or plotted as a drawing at any time. Additionally, LICAD can be used to create customized products for special applications, usually at a relatively low cost in terms of added purchase price or turnaround time. The program also aids in the replacement of worn-out pipe supports and the provision of supports for retrofit applications. Furthermore, LICAD can be exported into popular 2D programs, such as Auto-

CAD and 3D programs from software development companies including Intergraph, AVEVA, Bentley and Navisworks. Select 3 at

Bluetooth module enables laser shaft alignment Ludeca Inc. recently introduced the first wireless module for laser alignment that is certified for use in explosive environments. Measurement data is transferred between the measurement sensor and the alignment computer using the ATEX/IECEx certified EX RF module, making alignment easier and more convenient without compromising operator safety. The module operates with the OPTALIGN smart EX or ROTALIGN smart EX laser shaft alignment systems by PRÜFTECHNIK Group. Only Ludeca and PRÜFTECHNIK offer this technologically advanced capability for machinery alignment in explosive atmospheres common in petrochemical, mining and other industries. Select 4 at

Shaw, Total form global polystyrene licensing alliance

Find Leaks

The Shaw Group Inc. recently formed an alliance with Total Petrochemicals to jointly market and license Total Petro-

And Take Control Without Delay FLIR GF320 optical gas imaging cameras s give you the power to see and locate invisible gas leaks faster and more reliably bly than traditional “sniffer” detectors. Scan large areas quickly and pinpoint escaping gas in real time so you can get safety hazards under control immediately, stop the flow of lost revenues, and avoid costly fines.

Visit to download a free guide to using IR for gas detection, or call 866.477.3687 to schedule a demo. NASDAQ: FLIR

FIG. 2


Select 156 at

The LICAD software simplifies pipe support design.

HPINNOVATIONS chemicals’ polystyrene (PS) technology on a worldwide basis. Shaw has had a similar alliance with Total Petrochemicals for styrene monomer for 15 years. Total Petrochemicals’ PS technology produces both general-purpose PS, a rigid and transparent material used in applications such as insulation and packaging; and high-impact PS, a tough, colored plastic used in dairy packaging, electronics, refrigeration and other applications. With more than 45 years of PS manufacturing, licensing, and research and development experience, Total Petrochemicals is a major worldwide producer of PS with production facilities in Europe, the Far East and Pacific Rim, and the US. It has a worldwide PS production capacity of 1,580 kilotons per year.

sound levels when compared to conventional compressor-based systems. Many industrial and commercial facilities require higher gas supply pressure than is available from adjacent gas utility pipelines or conventional onsite tank systems. As a result, end-use customers must absorb costly pipeline pressure upgrades, install gas pressure-boosting equipment or bear the inherently higher costs associated with delivering and refilling onsite, higher-pres-

sure gas storage and distribution systems. In response, Emerson’s new offering provides cost-effective, flexible gas pressure/flow delivery and automated control. The systems feature standardized equipment assemblies configured for the specific application. Pressure and flow control systems are integrated to match specific site or process operating conditions. Many applications require a constant discharge pressure as high as 150–200

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Gas pressure delivery system improves stream control Emerson Climate Technologies recently introduced an automated gas pressure boosting and control solution featuring the variable-speed Copeland Scroll compressor technology. The configurable solution offers increased application flexibility, higher single-stage pressure capability, lower maintenance costs and reduced




It also interfaces with many process simulators and physical property packages either directly or via CAPE-OPEN. FIG. 3

The wireless module is certified for laser alignment in hazardous areas. ÂŽ

Now reads Honeywell UniSim Heat Exchangers * and AspenTech .EDR case files!

We’re changing the future of heat transfer.™

FIG. 4

The automated gas pressure delivery system improves control of dry gas streams.

*Service Pack 3 includes functionality to load and convert files from Honeywell’s UniSimŽ $ESIGN 3HELL 4UBE %XCHANGER Modeler files (.STEI), as well as legacy HTFSŽAND!SPEN3HELL4UBE%XCHANGER (.TAI and .EDR) files. “Honeywell� and “UniSim� are trademarks of Honeywell International, Inc. “HTFS� and “!SPEN3HELL4UBE%XCHANGERv are trademarks of Aspen Technology, Inc. “HTRI�, the HTRI logo, the “H2� logo, “We’re changing the future of heat transfer� and h8CHANGER3UITEvARETRADEMARKSOF(EAT4RANSFER2ESEARCH )NC4HESEMARKSMAYBEREGISTEREDINSOMECOUNTRIES

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HPINNOVATIONS psig, independent of the flow condition or demand change. With Emerson’s automated gas system, many dry gas streams can be boosted and controlled to discharge pressures of up to 300 psig. These systems can be deployed in a wide variety of industrial facilities and processes, including industrial boilers and furnaces, process gas recovery, power generation and marginal gas well production. Select 6 at

GTC to license ConocoPhillips’ sulfur recovery technology GTC Technology, a global licensor of process and equipment technologies, recently struck an exclusive, worldwide agreement with ConocoPhillips for its Selective Partial Oxidation of Sulfur (SPOC) technology for sulfur recovery. The agreement expands GTC’s platform of acid gas removal technology, which currently includes GT-CO2, a process technology for CO2 removal; GT-SSR, a Claus process for sulfur recovery; and GT-DOS, an innovative direct oxidation technology. Dr. Matt Thundyil, sulfur business leader for GTC Technology US, said, “SPOC technology eliminates the Claus furnace and addresses many of the endemic issues associated with conventional modified Claus technology, such as COS and CS2 formation, and challenges with startup and shutdown.” “In addition, it is anticipated to offer better efficiencies than conventional modi-

fied Claus technology, with significant savings in capital cost. This technology may also be able to upgrade conventional modified Claus plants, delivering improved performance with minor capital outlay,” Dr. Thundyil noted. Select 7 at

Mass flowmeter provides comprehensive solution

The built-in web server allows customers to monitor flow and meter health through the Internet. Digital communications deliver information on demand using Modbus RTU, BACnet MS/TP and Modbus TCP/IP technology with standard analog and pulse outputs. The VLM10 flowmeter is available in a wide range of connections and pressure ranges. Select 8 at

Spirax Sarco’s VLM10 inline vortex flowmeter is designed for mass, volumetric and energy flow measurement on steam, liquid and gas applications in sizes from 1 in. to 12 in. The VLM10 flowmeter combines an inline vortex meter, a built-in flow computer and a piezo-electric temperature sensor, giving users an all-in-one solution for their metering needs. The VLM10 flowmeter is precise and reliable, with a steam or gas mass flow accuracy of ± 1.5% over a 20:1 flow range. The fully welded, no-gasket design ensures safe measurement of steam and allows the sensors and resistive temperature devices (RTDs) to be removed without a line shutdown.

Invensys expands virtualization technology certification Invensys Operations Management recently expanded its certification for the VMware and Microsoft Hyper-V virtualization platforms, making it the first industrial automation provider to be certified for high-availability, disaster-recovery and fault-tolerance solutions in these supervisory control applications. The company’s ArchestrA System Platform 2012 and Wonderware InTouch 2012 software are now certified for VMware vSphere version 5.0 and ESXi version 5.0 for mission-critical applications. Select 9 at



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Aerogel Calcium Silicate

Ceramic Fiber Mineral Wool









Thermal Conductivity (W/m-K) at 600 °C Mean

FIG. 5

The inline vortex flowmeter measures mass, volume and energy flow of steam, liquids and gases.

C1676 ASTM Standard for Microporous

0.160 Data Per ASTM Testing Standards Microtherm Inc. +1 865 681 0155 Microtherm NV +32 3 760 19 80 Nippon Microtherm +81 3 3377 2821

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Want hands-on experience? We’ve got it – HANDS DOWN. Even the most seasoned refinery managers may see four to five FCCU revamps throughout their career. AltairStrickland’s managers and craftsmen have performed, on average, four to five FCCU revamps per year since 1976. This experience is the kind of advantage you need to help you manage and execute a successful project. We address constructability issues early on through preplanning, computer imaging, 3-D surveys and AutoCAD® models. Then, unlike most mechanical contractors, we often construct life-size wooden mock-ups of various sections to make sure a human, with tools, can access and work effectively and safely in tightly confined spaces. Our crews, from craft to top management, have worked on so many turnarounds and revamps that they can identify and quickly correct a problem, and work around a snag or lagging schedule. We also don’t choose between quality and safety. We think our clients should have the best of both. Our safety record is amazing. We just completed a 1,317,269-work-hour job for a client with zero BLS/ OSHA recordable injuries. Zero injury is our goal on every project we do. Our quality is evident during start-up. Our level of productivity is evident when you look at the project’s final time/cost. If there’s an FCCU revamp in your future, make the process as pain free as possible by putting the best hands in the business to work for you.

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North America Fluor Corp. has been awarded an engineering, procurement and construction management (EPCM) contract by Joule to design and build a renewable fuel production facility in New Mexico. The facility is intended to test and scale up a process for the commercial production of liquid fuels via Joule’s novel technology, which uses sunlight to convert industrial waste carbon dioxide into liquid hydrocarbons, ethanol or chemical products. Fluor’s Greenville, South Carolina, office is leading the EPCM services project. Engineering, procurement and site mobilization are underway. Motiva Enterprises LLC plans to convert all of its high-sulfur diesel heating oil (2,000 ppm) storage to ultra-low-sulfur diesel (ULSD) (15 ppm) at Motiva’s Sewaren terminal in New Jersey. Motiva’s conversion aims to meet its customers’ needs under a new State of New York mandate that all heating oil sold in the state be no more than 15-ppm sulfur by July 1, 2012. It will also allow Motiva Sewaren, a 5 million-plus-barrel refined products terminal, to take deliveries of ULSD for NYMEX-based contracts via marine and pipeline. Additionally, Motiva is also undertaking a project to convert two tanks of current heating oil storage to B100 biodiesel at its Sewaren terminal. Necessary permits and approvals will be sought from the appropriate authorities, including the local planning board. Motiva is working to complete the conversion of tankage to ULSD in the second quater of 2012, and the biodiesel project in the third quarter of 2012.

Dow will license UOP’s proprietary UOP C3 Oleflex process technology for manufacturing on-purpose propylene from propane. Dow has also signed catalyst supply and performance-guarantee agreements with UOP. Shell Chemical LP has signed a land option agreement with Horsehead Corp. to evaluate a site in the US Appalachian region for a potential petrochemical complex. The complex includes an ethane cracker that would upgrade locally produced ethane from Marcellus shale gas production. The site is located in the Potter and Center Townships of Beaver County, near Monaca, Pennsylvania. This positive development marks another phase as Shell continues to assess the commercial feasibility of a petrochemical complex in the Appalachian region. The next steps for this project include the site’s additional environmental analysis, further engineering design studies, assessment of the local ethane supply, and continued evaluation of the project’s economic viability. Shell looked at various factors to select the preferred site, including good access to liquids-rich natural-gas resources, water, road- and rail-transportation infrastructure, power grids, economics and sufficient acreage to accommodate facilities for a worldscale petrochemical complex and potential future expansions. In addition to an ethane cracker, Shell is also considering polyethylene and monoethylene glycol units to help meet increasing demands in the North American market.

Latin America The Dow Chemical Co.’s board of directors has authorized capital to finalize detailed engineering and to purchase long lead-time equipment for a new, world-scale propylene production facility to be constructed at Dow Texas Operations. Basic engineering work for the facility has commenced, and the project is on track for production startup in 2015. In December 2011, Dow and UOP LLC, a Honeywell company, signed a technology licensing agreement, enabling on-purpose propylene production at Dow Texas Operations. Under agreement terms,

The Siemens Industry Automation Division will equip the Refineria de Cartagena S.A. (Reficar) refinery in Cartagena, Colombia, with an integrated water-treatment solution that is to form the heart of a combined system for treating both process and wastewater. Siemens technologies will be applied to prepare river water for use as boiler feed water, and to purify wastewater before discharge. The order, worth over $30 million, is part of a project to expand and modernize the refinery, which is scheduled to be completed in the first half of 2013.

The expansion project will not only double the refinery’s capacity to 165,000 bpd of crude oil, but it will also produce betterquality, low-sulfur fuel. This will improve the fulfillment of national and international environmental directives. Reficar is a subsidiary company of Ecopetrol S.A. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has been awarded the basic design and front-end engineering design contract by Complejo GNL del Este for a new liquefied natural gas (LNG) receiving terminal and jetty to be built in San Pedro de Marcorís in the Dominican Republic. Foster Wheeler has previously completed a feasibility study for the selection of the most suitable technology for the new terminal, which will be designed for a send-out capacity of 240 million scfd, with an LNG storage tank of 160,000 m3. The design will also consider future expansion(s) up to 700 million scfd. Foster Wheeler will work with a local partner in executing this work, which is expected to be completed in September 2012.

Europe BASF will increase its capacity for cyclohexane oxidation at its Antwerp Verbund site by about 50,000 tpy. The total investment amounts to about €10 mil-

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: Lee Nichols P.O. Box 2608, Houston, Texas 77252-2608 713-525-4626 • HYDROCARBON PROCESSING MAY 2012

I 37

HPIN CONSTRUCTION lion. Cyclohexane oxidation products are important intermediates for caprolactam and adipic acid, starting materials for polyamide 6 and polyamide 6.6. The expansion will be implemented as part of two long-term planned turnarounds, and is intended to be completed by the end of 2014.

When the Going gets HOT… Non-intrusive flow measurement up to 400°C Trouble free operation at f extreme pipe temperatures f No clogging, no pressure losses Installation and maintenance f without process interruption Independent of fluid f or pressure f Hazardous area approved

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Cynar Plc has awarded an $11-million contract to Rockwell Automation to design and build a new end-of-life, plasticto-fuel conversion plant in Bristol, UK, for SITA UK Ltd., a Cynar customer and partner in the development. Cynar has developed a technology that converts end-of-life plastics into fuel. The Rockwell Automation Global Solutions team has worked with Cynar over the past two years developing the engineering, modularization and process improvements of Cynar’s waste end-of-life, plastic-to-fuel conversion plant. With this contract award, Rockwell Automation will enter the project’s design and build phase. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a contract by CJSC Antipinsky Refinery for the engineering and material supply of a new fired heater and air preheating system for the Antipinsky refinery in Tyumen, Russia. The fired heater will be part of a new crude-distillation unit being built as part of the Antipinsky refinery’s modernization. Foster Wheeler’s scope of work is scheduled to be completed by the end of 2012. This award follows a previous award by CJSC Antipinsky Refinery in 2011 for the technology license and basic design package for Foster Wheeler’s Selective Yield Delayed Coking (SYDEC) technology, and the basic design package for a vacuum-distillation unit. This scope of work is scheduled to be completed during the third quarter of 2012.

Middle East W. R. Grace & Co. has signed a memorandum of understanding to form a joint venture (JV) with Al Dahra Agricultural Co. to build and operate a fluid catalyticcracking (FCC) catalysts and additives plant in the Middle East. The JV production plant would be located in Abu Dhabi, United Arab Emirates, and used to supply oil refiners in the Middle East and South Asia markets. There are expected to be 16 FCC units built in these regions in the next five years, which

would increase the region’s catalyst opportunity by approximately $150 million. The plant in Abu Dhabi would reportedly be the first FCC catalysts and additives plant in the region, and is an important step for Grace to reinforce the reliable and timely distribution of FCC catalysts and additives to the region’s refineries. Grace expects that the growth in the region will be more than adequate for the capacity of the new plant by the time it is anticipated to come onstream in late 2015. Toyo Engineering Corp. and ENPPI (an engineering company under the Egyptian Ministry of Petroleum) have been jointly awarded a contract to build a 460,000-tpy ethylene plant and a 20,000tpy butadiene-extraction plant. The plants will be part of Egyptian Ethylene and Derivatives Co.’s (Ethydco’s) petrochemical complex that is to be established in Alexandria, Egypt. TOYO and ENPPI, based on the most advanced ethylene technology of Lummus Technology, will execute the engineering, procurement, construction and commissioning under a lump-sum turnkey contract. TOYO will lead the entire project execution, undertaking project management, basic engineering, a part of detailed engineering and procurement of key equipment. ENPPI will be in charge of joint project management, and the detailed engineering and procurement of other equipment and materials. Both companies will execute the construction and commissioning in collaboration with PETROJET, an Egyptian construction company as a subcontractor. The contract amount is approximately $600 million, and the plant is scheduled for startup in early 2015.

Asia Pacific Jacobs Engineering Group Inc. has a contract from Solvay for a major specialty polymers production plant to be built at Solvay’s industrial site in Changshu, Jiangsu, China. Officials estimate the contract value to be approximately $9 million. Jacobs is executing the engineering, procurement and construction management services contract from its Shanghai operations in China. Solvay is investing approximately $160 million into this plant, which will produce its products SOLEF PVDF and TECNOFLON FKM, as well as its essential VF2 monomer. The plant is scheduled to become operational in the first quarter

HPIN CONSTRUCTION of 2014, and is expected to significantly boost Solvay’s global production capacity for these specialty polymers. PETRONAS and BASF are moving forward with the previously announced €1-billion investment that will expand their partnership in Malaysia, involving projects at their existing venture in Kuantan and at a new site within PETRONAS’ proposed Refinery and Petrochemical Integrated Development (RAPID) complex in Pengerang, Johor. These projects are to be implemented between 2015 and 2018. The two partners have entered into a heads of agreement (HOA) for developing the new project in Pengerang. Under HOA terms, the partners have agreed to form a new entity (BASF 60%; PETRONAS 40%) to jointly own, develop, construct and operate production facilities for isononanol, highly reactive polyisobutylene, non-ionic surfactants, methanesulfonic acid and plants for precursor materials. These world-scale facilities will become an integral part of PETRONAS’ RAPID project. PETRONAS, through its subsidiary PETRONAS Chemicals Group Bhd, and BASF are also making progress with the feasibility study to expand the operation of BASF PETRONAS Chemicals Sdn Bhd in Kuantan. The two partners are considering the expansion of their C3 value chain with a new plant for superabsorbent polymers, along with the expansion of the production capacity of their existing glacial acrylic-acid unit.

and will use Stamicarbon’s Urea2000Plus technology, featuring a pool reactor, minimum equipment and minimum plant height. The granulation plant will be using Stamicarbon’s Fluid Bed Granulation technology. Startup is planned in 2015. Stamicarbon will deliver the process design package, the training, pre-commissioning and startup services. CHENGDA is responsible for the basic and detailed engineering, plus procurement. COMPLANT is responsible for the construction and commissioning, although this will be partly executed by CHENGDA. Chemtura Corp. has held a groundbreaking ceremony for its new, multipurpose manufacturing facility in the Nantong Economic and Technological Development Area to support its growth strategy in China and the greater Asia Pacific region. The Nantong facility, first announced in June 2011, will be operational within the next two years, with four production units supporting Chemtura’s Industrial Performance Products segment’s petroleum additives and urethanes businesses, with the first production unit expected to be opera-

tional in the fourth quarter of 2013. There also are plans to manufacture additional products in future phases. The state-of-the-art facility will include production lines, administrative and maintenance buildings, as well as utilities, a centralized control room and quality-control labs. LANXESS will break ground for its new neodymium polybutadiene rubber (NdPBR) plant in Singapore on September 11, 2012. The company plans to invest roughly €200 million in a 140,000 metric-tpy facility in Jurong Island Chemical Park. The facility will reportedly be the largest of its kind in the world and serve the growing market for “green tires,” especially in Asia. About 100 jobs will be created. The plant is expected to start up in the first half of 2015. Engineering work has advanced considerably since June 2011, when the company announced it had selected Singapore as the site for the new plant. Petrochemical Corp. of Singapore (Private) Ltd. (PCS) has agreed on a long-term supply of butadiene to LANXESS. Butadiene is the raw material LANXESS needs to produce Nd-PBR. PCS is building a new butadiene-extraction unit

Stamicarbon, the licensing and IP center of Maire Tecnimont S.p.A., has signed license and process design and services agreements with China Chengda Engineering Co. (CHENGDA) and China National Plant Import and Export Corp. (COMPLANT) for a urea melt and urea granulation plant for the Shahjalal Fertilizer Project in Bangladesh. The project has been planned for more than 10 years, however, the Bangladesh government has now decided to engage in the project with the support of the Chinese government. The plant will be operated by Bangladesh Chemical Industries Corp. (BCIC) as a representative of the Bangladeshi government, but will mainly be financed by the Chinese government. It will be located adjacent to the existing Natural Gas Fertilizer Factory Ltd. at Fenchuganj, Sylhet, Bangladesh. The urea plant synthesis and granulation will have a capacity of 1,760 metric tpd Select 160 at


HPIN CONSTRUCTION and the associated infrastructure necessary to supply the raw material. Essar Oil Ltd. has commissioned a new hydrogen manufacturing unit with an installed capacity to generate 130,000 Nm3/hr of hydrogen gas, making it one of the largest hydrogen manufacturing units in the world. The unit is unique because of the installation of a Haldor Topsøe exchange reformer (HTER) in parallel with the conventional steam methane reformer. The hydrogen manufacturing unit is designed to operate on six feedstock options, including natural gas, saturated refinery fuel gas, saturated liquefied petroleum gas (LPG), hydrotreated naphtha, sweet stabilized naphtha, a blend of saturated LPG and hydrotreated naphtha. The agreement for supply of the knowhow and process package was signed between Haldor Topsøe and Essar Oil Vadinar Ltd. in October 2007. Topsøe’s scope included license, basic engineering, supply of the HTER tube bundle and Topsøe catalysts for three 130,000-Nm3/hr hydrogen plants. Essar plans to start work on the second hydrogen plant soon.

JGC Corp. has been awarded a contract from PETRONAS for the front-end engineering design (FEED) work and early works of engineering, procurement, construction and commissioning for the PETRONAS liquefied natural gas (LNG) Train 9 Project, which is located in Bintulu, Sarawak, Malaysia. The contract, which adopts a dualFEED competition scheme, will increase the existing LNG plant facilities with an additional capacity of 3.6 million tpy. The FEED is planned to be completed in the fourth quarter of 2012. Linde Group has been selected to supply air gases to chemicals producer Dahua Group on Songmu Island in Dalian, Northeast China. Linde will be investing around €70 million in the project. An agreement outlining the terms of the deal was signed by both parties. Under agreement terms, Linde acquires the customer’s two existing air-separation units (ASUs) in Dalian, and will operate these. In addition, Linde’s Engineering Division will build a new ASU onsite with a production capacity of 38,000 Nm3/h.

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Scheduled to go onstream in 2014, the new ASU will replace the two older plants, also meeting rising demand for gaseous oxygen at Dahua’s operations. The new arrangement gives the customer a much greater degree of reliability in its gas supply. The new ASU will also produce surplus liquid gases for the regional market. As part of the contract agreement, the upgraded gas-production facility will be jointly managed by a newly formed 50/50 joint-venture gases company between Linde and Dahua. Linde-Dahua (Dalian) Gases Co., Ltd., will also offer industrial gaseous and liquid products, and provide relevant engineering services to neighboring industrial hubs. The new coal to substitute natural gas (SNG) plant for the Yinan SNG Project will convert locally mined sub-bituminous coal into SNG with the aim of reducing imports of natural gas for power and heat generation. In its first stage of completion, the plant is to produce around 2 billion Nm 3 /yr of SNG. The customer is the power provider CPI Xinjiang Energy Co. Ltd., a subsidiary of China Power Invest-

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HPIN CONSTRUCTION ment Corp., one of the five biggest power generators in China. The plant is scheduled to go online by the end of 2014. Haldor Topsøe will supply license, engineering design, catalyst and services. As licensor, it will use its TREMP technology for the methanation section. The produced SNG will meet the stringent requirements of the pipeline operators, and will be delivered through existing natural-gas lines. Axens has created Axens South East Asia Sdn Bhd, a subsidiary that is 100% owned by Axens. This new subsidiary located in Kuala Lumpur, Malaysia, will take direct responsibility for catalyst and adsorbent sales in Southeast Asia, as well as in Australia and New Zealand. In addition, Axens South East Asia Sdn Bhd will provide the base for a technical assistance hub for users of Axens’ technologies and products in Asia, in coordination with the local subsidiaries in this part of the world. Technip has a front-end engineering design contract for PETRONAS’ proposed Refinery and Petrochemical Integrated Development (RAPID) project

located in the state of Johor, Malaysia. The RAPID project will be a world-scale integrated refinery and petrochemical complex to answer the growing need for specialty chemicals, and to meet the demand for petroleum and commodity petrochemical products in the Asia Pacific region by 2016. The proposed refinery will have a capacity of 300,000 bpsd and will supply naphtha and liquid petroleum gas feedstock for the RAPID petrochemical complex, as well as produce gasoline and diesel that meet European specifications. The petrochemical units, on the other hand, will enhance the value of the olefinic streams coming from the RAPID steam cracker by producing various merchantgrade petrochemical products, such as polyethylene, polypropylene, synthetic rubbers and more. The contract is scheduled for completion in the second quarter of 2013.

random copolymers and impact copolymers. The 300-kiloton/yr plant, located in Yulin City, Shaanxi Province, will serve the rapidly growing Chinese PP market. China Shenhua is a major coal chemical producer in China. It was reportedly the first company to commercialize the methanol-to-olefins (MTO) process. This Innovene PP plant will be part of China Shenhua’s second MTO complex. The Shaw Group Inc. has been awarded contracts to provide a processdesign package and technology license for the addition of a 30,000-bpd deep catalytic-cracking (DCC) unit to IRPC’s 215,000-bpd refinery in Rayong, Thailand. The upgrade project will maximize the production of polymer-grade propylene and recovery of polymer-grade ethylene to be used as feedstock for petrochemical derivative units at the same site. Shaw will also function as the super licensor for four additional supporting technologies provided by Axens. As super licensor, Shaw has single-point responsibility for execution and performance guarantees for these technologies.

INEOS Technologies has licensed the Innovene polypropylene (PP) process to China Shenhua, Coal to Liquid and Chemical Corp. Ltd.’s, Beijing Engineering branch for the manufacture of polypropylene resins including, homopolymers,

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I 41

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THE LASEREXACT DELIVERS RELIABLE, STABLE MEASUREMENTS AND EXCEPTIONALLY LOW PPM/ PPB TRACE GAS DETECTION LIMITS IN A ROBUST AND COMPACT ANALYSER DESIGN. Offering the latest Tuneable Diode Laser technology augmented by Frequency Modulated (FM) signal processing, the LaserExact’s unique PeakLock technology delivers unsurpassed measurement stability resulting in exceptional accuracy and low maintenance costs. The result is the virtually maintenance-free TDL analyser you can fit with confidence: ideal for a range of process applications including measurement of H2S and CO2 in Natural Gas, O2 in Flare Gas Recovery Systems and HCl or HF Emissions, Contaminants in Bulk Gas, Flare Gas O2 and Glovebox O2.

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CONSTRUCTION Shaw is the exclusive licensed provider of DCC technology outside of China, and together with the technology’s developer, Sinopec Research Institute of Petroleum Processing in the People’s Republic of China, has licensed a total of 16 DCC units. Total has signed a comprehensive memorandum of understanding (MOU) with Kuwait Petroleum International and Petrochemicals Industries Co., two wholly owned subsidiaries of Kuwait Petroleum Corp. The MOU relates to a targeted participation in the Zhanjiang project in China. This project consists of the planned development of a large-size 300,000-bpd full-conversion refinery integrated with petrochemicals and marketing, in partnership with Sinopec. The proposed refining and petrochemicals platform will be designed to process Kuwaiti crude as feedstock and to produce high-quality refined and petrochemical products. Synthesis Energy Systems, Inc., is undertaking a study for its strategic partner, Coalworks Ltd., to determine the potential for additional cost savings resulting from the use of high-pressure U-GAS gasifiers at Coalworks’ planned coal-toliquids plant in Oaklands, New South Wales, Australia. The agreement follows on the companies’ 2009 strategic alliance for development of the Oaklands facility. Celanese Corp. has received the key government approvals necessary to proceed with its previously announced plans to modify and enhance its existing integrated acetyl facility at the Nanjing Chemical Industrial Park to produce ethanol for industrial uses. The unit, based on Celanese TCX ethanol process technology, is expected to start up in mid-2013. The new ethanol production is expected to increase the facility’s overall profitability by enhancing the mix of products manufactured with the current capacity of certain critical raw materials available at the site. Total investment for the project is expected to be a fraction of the required capital for a greenfield facility. Based upon continued advancements to its TCX ethanol process technology, the company now expects to have approximately 30% to 40% additional ethanolproduction capacity than the originally announced 200,000 tons, with no increase in the capital investment for the modification and enhancement. HP


BRINGING THE WORLD’S LEADING TECHNOLOGIES TOGETHER HOWDEN’S ACKNOWLEDGED EXPERTISE IN AIR AND GAS HANDLING TECHNOLOGY IS BUILT ON 150 YEARS OF HISTORY AND EXPERIENCE THAT SPANS THE GLOBE. Along the way, we have sought out companies whose products and abilities mesh with our own and brought them into the Howden portfolio to broaden and reinforce the services and range we can offer our customers. Today, we have the technologies and OEM documentation of over 40 companies including Buffalo Forge, Joy/Green Fans, Westinghouse, Novenco and American Blower. Our installed base includes 90,000 fans, compressors and legacy products worldwide, and we offer a commitment to support each one’s life cycle and retrofit services based on the original OEM documentation. From installation to decommissioning, 24/7/365, we’re there when you need us.

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Ex Capacity Unit

Cost Status Yr Cmpl Licensor



Chengda Eng Complant

Complant Chengda Eng





China China China China India India India

Arkema SK Group/BP/Sinopec PetroChina/Shell/Qatar Shenhua Group Corp Reliance Industries Ltd IOCL/TIDCO JV Essar Oil Ltd

Changshu Chongqing Taizhou Yulin Jamnagar Kattupalli Vadinar

Polyamide Petrochemical Complex Petrochemical Complex Polyethylene Refinery (1) LNG Terminal Coker, Delayed

Malaysia Pakistan Thailand


Johor Bahru Khalifa Point Rayong

Refinery Refinery Cracker, DCC

1760 Mtpd EX



6 Mm-t None 1.2 MMtpy 300 kty None 2.5 MMtpy 6 MMtpy 300 bpd 250 Mtpy 30 bpd






2012 2015 2016 2013 2014 2015 2012

1000 650


1670 6000



KBR|Stamicarbon Hofung Technology Arkema



Lummus Technology


Aker Solutions Mumbai CB&I Technip


CB&I|WorleyParsons Aker Solutions

Aker Solutions |CB&I WorleyParsons FW

Shaw |Axens

EUROPE Kazakhstan



Processing, Oil/Gas

300 Mbpd



Russian Federation Russian Federation Russian Federation Russian Federation

Lukoil- Nizhegorodnefteorgsintez ZAO FEPCO CJSC Antipinsky Refinery Mariisky NPZ

Nizhny Novgorod Primorsk Tyumen Yoshkar-Ola

Waste Heat Boiler Petrochemical Complex Heater, Crude Refinery




None 3.4 MMtpd None 90 bbl

2012 2012

FW Shell Global

Serbia Spain

NIS-Refinery Novi Sad Repsol YPF

Pancevo Cartagena

Hydrogen Generation Cogeneration (3)


40 t/a 220 bbl


2012 2012

Haldor Topsøe Axens

Cartagena San Pedro de Macoris Tula Aruba

Waste Water Trmt. LNG Receiving Termin Refinery Refinery

None 240 MMscfd 300 bpd 235 bpd


2013 2012 2016

Doha Mesaieed Mesaieed Mesaieed Mesaieed Ras Laffan Ras Laffan

Carbon Dioxide Recov Ammonia (5) Ammonia (7) Urea (5) Urea (7) Ethane Cracker Olefins, Alpha

500 3.8 5.7 4.3 5.7 1.3 300


2014 2012 2012 2012 2012 2016 2017

Sewaren El Paso Glasscock Co Sweeny Sinclair Sinclair Sinclair

Diesel, ULSD Refinery Natural Gas Plant Natural Gas Plant Hydrodesulf (HDS) Hydrotreater, Kerosene Sour Water Stripper


2012 2015 2013 2013 2012 2012 2012


Axens FW Foster Wheeler Italiana Shell Global Heurtey|Jacobs Intecsa-Uhde

Heurtey Intecsa-Uhde|Fluor

LATIN AMERICA Colombia Dominican Republic Mexico Netherlands Antilles

Ecopetrol Complejo GNL del Este Pemex Valero Energy Corp


Siemens FW ICA Fluor

MIDDLE EAST Qatar Qatar Qatar Qatar Qatar Qatar Qatar

Qatar Fuel Additives QAFCO QAFCO QAFCO QAFCO Shell Royal Dutch Shell Chemical

tpd MMtpy MMtpy MMtpy MMtpy MMtpy tpy

6000 6500

Haldor Topsøe

MHI Saipem




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Consider updating your lubricant system Oil mist extends equipment life over other lube methods D. EHLERT, Lubrication System Co., Houston, Texas


il-mist lubrication has been applied successfully to pumps and motors in the hydrocarbon processing industry (HPI) since the late 1960s.1 Many large-scale installations have served industry well all over the world (Fig. 1). As of 2011, the US and Canadian refining industries alone had over 1,500 large-scale oil-mist systems in operation. Of the more than 60,000 machines lubricated by these systems, around half were purchased with oil mist as the intended lube application method. The other half had been originally furnished with conventional oil lubrication and was later converted to oil-mist lubrication. Since overhung process pumps and their electric-motor drivers are the most common machines in the HPI, one can expect pumps and motors to predominate among equipment lubricated by oil mist. However, it is important to note that numerous other machine types also benefit from oil mist; these include gearboxes, blowers, turbines and pillow-block bearings, to name a few. After a brief recap and introduction, this article will highlight strategies for lubrication system conversion for pumps and electric motors.

Why oil mist? In and of itself, oil-mist lubrication does not “cure” or prevent every conceivable lubrication-related failure of rotating equipment. Oil mist will not “heal” a compromised bearing, and a pre-existing defect can culminate in a bearing failure. However, properly applied oil mist will indeed extend bearing life when compared to most alternative lubrication methods. The main reason for this life extension is that oil mist provides an ultra-clean environment. Introduced into a bearing housing at slightly higher than atmospheric pressure, oil mist precludes the entry of atmospheric contaminants into running, as well as nonrunning, machinery. Oil mist lubricates, preserves and protects; large-scale oil-mist systems also require far less maintenance than do virtually all of the traditional methods. Risk-inducing components or items that often require considerable maintenance attention (such as oil-slinger rings and constant-level lubricators) are completely eliminated in equipment lubricated by pure oil mist. History of use. Since the late 1970s, many papers and several books have been written and published about oil-mist lubrication.2–6 These references remind the reader that much of the early reluctance to use oil mist was attributable to plugging issues caused by wax-containing paraffinic oils. There also were failures due to not following proper pipe installation procedures. With modern installation practices and the use of non-paraffinic oils, plugging events have become a thing of the past.

Less-than-optimum oil-mist delivery methods presented another hurdle for early oil-mist applications on pumps. In old systems, a single reclassifier was typically mounted at or near the center of the bearing housing; venting took place through the bearing housing shaft protrusion (Fig. 2) or at the housing end seals. Bearing windage (a fan effect), unbalanced housinginternal pressures, and housing-internal passageways also could cause mist to bypass certain bearings.2 These unanticipated conditions led to occasional bearing failures that were primarily observed on double-row thrust bearings. Fortunately, competent oil-mist system suppliers have been successful in pointing out these oversights. Their modern oil-mist systems are virtually trouble-free and require less maintenance than does any other method of lube application. Pure oil-mist application. Although oil mist occasionally is used to simply purge the vapor space above liquid lubricants in bearing housings, the experience-tested conversion strategies described in this article pertain exclusively to the more prevalent “pure” oil mist applied to rolling-element bearings in modern hydrocarbon processing plants. Pure mist, sometimes described as feeling dry to the touch, is produced (or “generated”) at the oil-mist generator module (Fig. 3, left side). It initially exists as atomized, transportable, small-size globules. These sub-micron-sized, fog-like globules are conveyed

FIG. 1

A modern, large-scale oil-mist console.


I 47



via a piping or header system to the various bearing locations. A reclassifier fitting near the bearing converts the oil mist to large, wet-to-the-touch oil globules. Another way to describe the “dry” oil mist is an oil fog that ultimately has to pass through a reclassifier, which essentially is an orifice fitting. This orifice fitting must be located no farther than 2 meters (6.6 feet) from the bearing to be lubricated. Reclassifiers create a turbulent region where mist velocity increases. At high velocities, the small, atomized mist particles contact each other and then combine into larger droplets. Larger droplets are heavy and cannot remain suspended in the carrier air. They become “wet” mist—large enough to plate-out and fully coat rolling bearing components. The preferred through-flow mist application method shown in Fig. 4 was adopted by the American Petroleum Institute (API) a number of years ago. Here, oil mist passes through the rolling elements from side to side or top to bottom. Oil-mist throughflow will ensure proper lubrication of the bearings. At low flow or no flow, oil globules would ultimately fall out of suspension, and only carrier air deprived of oil would then surround the bearings. After the oil mist flows through the bearing, it continues to travel toward the vent or drain (outlet) shown in Fig. 4. Should


FIG. 2

Old-style oil-mist application was wasteful and imprecise.

FIG. 3

Mid-sized oil-mist console serving 10 to 20 pump sets in a refinery (left). A collecting vessel (right) allows total environmental compliance and resource-friendliness of this closed oil-mist system.

I MAY 2012

the vent/drain/outlet port be too small, it would create back pressure in the housing that could restrict the flow through the bearing. The decreased flow into and through the bearings would, of course, reduce the amount of oil actually reaching the bearings. Experience shows that vent/drain port diameters should be three to four times larger than the diameter of the reclassifier or orifice. Adherence to this general rule and to related parameters should be closely monitored. The rule takes on greater importance when more than two reclassifiers are feeding into a common bearing housing. Process pumps that comply with current editions of API-610, both overhung and between bearing styles, are designed for oilmist flow through the bearings (Fig. 4) prior to exiting the housing. Modern systems are closed; i.e., the coalesced lubricating oil or spent oil mist leaving at the drain is returned to a collecting vessel (Fig. 3, right side). The through-flow arrangement of Fig. 4 is more important on multiple-row bearings; however, through-flow is not always necessary with single-row bearings in applications such as electric motors, where the load is constant and the thrust is not usually excessive. Oil-mist retrofitting to pumps. Overhung and betweenbearing pumps are fairly easy to retrofit or convert to pure oil mist in the field. Such retrofitting is entirely possible without equipment shutdown since the bearing housings are essentially selfcontained and are not contacted by process fluids. Draining the original liquid lubricant and applying oil mist are accomplished by removing drain plugs; these can be left open or connected to a common drain header. The oil mist inlet/supply tubing is then attached to the bearing housing or to the housing end caps. Again, pure mist is used in rolling-element bearings at reliability-focused plants, whereas purge mist is often used on machines equipped with sliding, or “sleeve-type,” bearings. (It should be noted that, with purge mist, additional components are required to maintain proper levels of liquid oil and to contain the oil mist.)5 When lubricating rotating equipment with pure mist, no liquid oil level is maintained in the bearing housing. The oil sump is empty; it is a dry sump. Power input (driver hp), shaft speed (rpm), bearing housing internal configuration and bearing housing seal selection are of interest and will govern the selection of reclassifier size. When the driver is 150 kW (200 hp) and above, and when the rpm is 3,000 or higher, the reclassifiers should be sized for a heavy service factor. When below 150 kW (200 hp) and at 3,000 rpm or less, the reclassifiers may be sized for a moderate service factor. Older API-style and many ANSI pumps typically have a single oil refill port located at the bearing housing top. This is where oil mist can be applied with a single reclassifier sized to serve both the thrust and radial bearings. With this application, the oil mist creates pressure in the central housing; the pressure then forces the mist through bearings and housing seals. The oil mist provides lubrication for the outboard rolling element of the multiple-row bearing, as well as for the single-row radial bearing found in typical pumps. Many of the older bearing housing internal configurations benefit from plugging drain-back ports that connect the two bearing faces. This precautionary plugging2,5 ensures that oil mist will pass through the bearings, thereby removing the remote possibility of oil mist circumventing or bypassing the bearing. In a situation where older bearing housings are present and oil mist is applied per the now-superseded method shown in Fig. 2, the low-point vent/drain would require a defined restriction

MAINTENANCE AND RELIABILITY to ascertain that the oil mist passes through the bearings before exiting via the housing seals. Although simple-fixed, rotating-labyrinth and even-lip seals are often retrofitted on bearing housings of the type depicted in Fig. 2, blocking the mist exit at the shaft protrusions may impede through-flow and deprive lube supply to the outer element on multiple-row bearings. This makes it all the more important to consider implementing the through-flow scheme shown in Fig. 4. Debate has centered on whether oil rings (slinger rings) should remain in place or be removed when converting to pure oil mist. Best practice calls for lifting or suspending these rings until the pump is taken to the shop for any reason.6 At that time, the oil rings should be removed. Some sources report that oil rings pose no threat to the application of pure oil mist; they believe the additional labor to remove them is unnecessary. The same sources have observed that increases in noise and vibration readings likely occur when the rings are run dry after conversion to pure mist. Since noise and vibration are forms of energy, experienced reliability professionals are encouraged to draw the right conclusions from the various claims and counter-claims. A recent book2 argues in favor of foregoing oil rings altogether. Field conversions from conventional oil sump to pure oil mist involve taking bearing temperature and vibration readings before, during and after draining the oil. Observing and recording bearing temperatures and vibration amplitudes prior to draining the oil provide a baseline reference. Readings should be taken immediately after the oil is drained and then again every five minutes for at least 20 minutes. Typically, bearing temperatures will drop 10°F to 20°F (6°C to 12°C) in the first 10 minutes. This indicates that the bearings are in good condition, and one should not expect any issues to arise. If the temperature holds steady or increases, conventional lube application may need to be resumed, and a high-grade synthetic lubricant of suitable viscosity should be chosen. As a standard precaution, the occasional pump experiencing a bearing temperature increase should be scheduled for bearing replacement. Chances are that bearing life was already compromised or the pump impeller produces high axial thrust loads. Load and temperature are interrelated, and a different reclassifier may be needed. In the event that bearing temperatures escalate, or if the pump is operating at 3,000 rpm and the driver is 150 kW (200 hp) or greater, the bearing housing may require two lubrication points so as to provide sufficient lubrication to the thrust bearing. This modification also may be performed in the field without taking the pump to the repair shop. It would, however, require that a small (1⁄8-inch national pipe thread) port be tapped into the bearing end cap to allow for another reclassifier to provide lubrication directly to the thrust bearing. This dual-orifice arrangement would resolve lubrication issues. Should bearing failure persist regardless of the dual-port provision, other pump-related issues should be investigated. As the pump goes into the repair shop for work, it would be wise to remove the oil (slinger) rings, plug the drain-back ports, and tap both end caps to accept oil-mist reclassifiers. Being certain that the bearing housing seals are containing the oil mist, configuring the mist path per the schematic in Fig. 4, and allowing excess mist to vent only at the bottom port will make an oil-mist application perform flawlessly. Older-model between-bearing pumps commonly have the oil inlet and drain ports on the same plane, which does not


favor the flow of oil mist through the rolling elements (Fig. 2). Until a shop modification to Fig. 4 is made, a directional reclassifier must be used in Fig. 2 configurations. Directional reclassifiers extend down into the bearing housing; the orifice opening is “directed” at the midpoint of the top rolling element. The relative proximity to the top rolling element—typically 12 mm (1⁄2 inch)—allows the mist to overcome bearing windage effects. Directed reclassifiers are important on double- or multiple-row bearings arranged for applications per Fig. 2. At times, the bearing housing may require minor modifications to accommodate directional reclassifiers. On cylindrical, spherical and tapered roller bearings, additional measures are necessary to ensure proper oil-mist application. Due to the high frictional load typically acting at the end of the rollers, care must be taken to ensure that ample oil mist is directed precisely at the shoulders of the bearing element. At all times, the through-flow application shown in Fig. 4 will be superior to older-style applications. Retrofitting oil mist to electric motors. Electric motor

construction is not governed by detailed industry standards such

FIG. 4

Through-flow oil-mist application per the current edition of API-610. A modern bearing protector seal is shown at each end of this bearing housing.

FIG. 5

Oil mist applied to motor bearings featuring magnetic face seals. HYDROCARBON PROCESSING MAY 2012

I 49



as API. As a result, oil-mist conversions for motors, although not complicated, require more labor than do conversion efforts for process pumps. However, motor manufacturers are making significant strides to meet user demands and requirements for oilmist applications. In fact, some manufacturers have motor designs that inherently accommodate oil mist with little to no extra work. Over 40 years ago, one foresighted manufacturer in New Jersey simply stamped its standard totally enclosed fan-cooled (TEFC) electric motors as “Suitable for oil-mist lubrication.”6 Many decades of experience proved that these motors could last just as long as products advertised by other manufacturers as being specifically engineered for oil mist. TEFC motors (Figs. 5 and 6) that are grease lubricated are excellent candidates for pure oil mist. Typically, 15 kW (20 hp) and greater show significant payback values for oil-mist conversion. For motors not manufactured specifically to accommodate oil mist, several factors must be considered during the conversion. First, all grease must be removed from the bearing cavity and the inlet/outlet lines prior to applying oil mist. Since the low-

pressure oil mist is not capable of displacing grease lodged in motor bearing cavities, grease removal is accomplished by briefly applying an intermittent air-gun blast from the plant’s air supply header. Next, winding epoxy and lead wire insulation must be confirmed as compatible with the oil. Most epoxies and insulation materials used since 1980 have no compatibility issues; however, this deserves to be reconfirmed. Also, the internal porting to the junction box (where the lead wires enter) must be well sealed with a potting compound to prevent oil mist from entering the box. Additionally, as oil mist will enter the housing around the rotor, and since running the motor will cause the mist to wet out and settle in the lower housing of the motor, a case drain (Fig. 6) must be installed in the condensate drain plug port on the coupling end of the motor. Finally, the fan-end condensate drain plug must be removed and replaced with a standard plug to prevent mist leakage and venting at the fan end. Mature technology. Oil-mist lubrication is a proven tech-

nology when systems are properly installed and mist is properly applied to rotating equipment. Many systems have been performing in the HPI for 40 years and have consistently provided costjustified results. Closed-loop oil-mist systems represent the best available technology5 for lubrication, preservation and protection of process equipment. Electric motor lubrication (Fig. 7) is always an integral part of any plantwide lubrication strategy. Oil-mist systems’ low maintenance requirements, reduced operating expenses and improved rotating equipment reliability have resulted in maintenance credits as high as 95% over conventional lubrication in some major HPI facilities.2,3 Their versatility—which includes flawless operation in all climates, a lack of temperature limits, prevention of airborne contaminants, and lubrication for operating equipment that protects and preserves standby equipment—makes these systems valuable to reliabilityfocused users. HP Note: Figs. 1, 3, 6 and 7 are provided courtesy of Lubrication Systems Co. Figs. 2, 4 and 5 are provided courtesy of AESSEAL Inc.

FIG. 6

FIG. 7


A typical oil-mist application on a standard electric motor.

Oil-mist application on a large electric motor.

I MAY 2012

LITERATURE CITED Towne, C. A., “Practical Experience with Oil-Mist Lubrication,” ASLE Preprint No. 82-4C-1, ASLE annual meeting, Cincinnati, Ohio, 1982. 2 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, 2011. 3 Bloch, H. P., “Large-Scale Application of Pure Oil Mist in Petrochemical Plants,” ASME Paper 80-C12/LUB-25, 1980. 4 Towne, C. A. and D. J. Sheppard, “Oil-Mist Lubrication for Electric Motors— Where It Stands Today,” IEEE Transactions on Industry Applications, Vol. IA 22, No. 6, November/December 1986. 5 Rehman, C. and H. P. Bloch, “Is Closed Oil-Mist Lubrication the Best Available Technology?” Machinery Lubrication, November/December 2010. 6 Bloch, H. P. and A. Shamim, Oil Mist Application: Practical Applications, Fairmont Press, Lilburn, Georgia, 1998. 1

Don Ehlert is the manager for EPC sales at Lubrication Systems Co., a Colfax company, located in Houston, Texas. Since joining LSC in 1984, he has held positions in equipment assembly, field maintenance, field installation, field management, sales and sales management. He has been instrumental with the development of oil-mist-related products and accessories for special applications. He also provides technical support to oil-mist users worldwide. Among his current responsibilities are technical training, quotations and sales presentations to both domestic and foreign engineering firms and user companies. Prior to his employment with LSC, Mr. Ehlert spent time in the US Navy, providing maintenance and operations support on aircraft hydraulic and flight control systems.

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Improve seal designs for ‘dirty’ services Environmental rules require increased reliability for pumps in flue-gas applications H. P. BLOCH, P. E., Consulting Engineer, Westminster, Colorado; and T. GROVE, AESSEAL Inc., Rockford, Tennessee


he Cross-State Air Pollution Rule (CSAPR) is at the center of the regulatory debate in the US. The Environmental Protection Agency (EPA) rule replaces the 2005 Clean Air Interstate Rule (CAIR), tightening caps on sulfur oxides (SOx) and nitrogen oxides. Regardless of the Appeals Court stay in early January, equipment reliability is now more important with regard to efficient utilization of existing pollution control technologies. In December 2011, the Department of Energy (DOR) outlined “near-term compliance pathways” highlighting the need for increased utilization and reliable performance of wet and dry flue-gas desulfurization (FGD) units.1 Selecting reliable mechanical seals is of most critical importance and is the subject of this article.

Industry convention is of interest. The industry cus-

tom is to fit single-type, heavy-duty mechanical seals in FGD applications, thus sealing the lime slurry and preventing its exiting at the rotating shaft region of pumps and other fluid movers. Often, the seal is the first component to fail, and seal performance can be unpredictable. How have FGD distinct operating parameters been addressed by industry standards? Standards are written collaboratively by industry experts to apply to a wide range of applications. The unique issues in FGD units encourage the plant reliability professional to produce an add-on company standard or purchaser’s amendment to ensure predictable sealing performance.

variables impact the stability of the seal’s fluid film. Adding proprietary sorbents with reagent enhancers or additives and the resulting unknown fluid properties make seal performance even more unpredictable. As detailed by Mohamad Hassibi, Chemco Systems, LP, “For SO2 capture with ground limestone in wet FGD, much of the coarser particles never react with the gases. Because of a short contact period, many of these particles are basically wasted. For limestone to react with SO2 gas, there should be some dissolution of limestone so that it can ionize. Fine pulverization generally improves the rate of dissolution, thus increasing SO2 capture efficiency.”2 This applies to dry FGD installations, as well. The greatly increased surface area in fine-micron particles means less absorbent is required. At one facility, particle distribution sampling determined that approximately 50% of the particles were 8 microns or less. The small particles enter into the micro-gap between the seal faces, thus leading to unpredictable seal performance. Air injection is used to ensure a fully oxidized gypsum product. Oxidation may be through a sparging grid system or through air lances mounted near side-entering agitators. Air injection can be problematic for the seal face set. The cost of a maintenance event on large equipment can be as much as $50,000 per occurrence. Managing these costs has led some

Single vs. dual designs. The referenced single-type,

heavy-duty mechanical seal design, as shown in Fig. 1, has a single set of precision-lapped silicon-carbide components (faces) to contain the lime slurry. Stability of the fluid film between the face set is essential for long-term performance. Failure margins narrow when operating conditions impact the stability of this fluid film. Failure mechanisms. Operating practices necessary for optimum FGD efficiency may adversely affect seal performance. The utilization efficiency of the FGD unit is improved with fine pulverized limestone and forced oxidation. High-speed pumps are used to feed rotary atomizers, in the case of dry FGD. These

FIG. 1

Single-type, heavy-duty mechanical seal for limestone slurry service. Source: AESSEAL, Rockford Tennessee, and Rotherham, UK. HYDROCARBON PROCESSING MAY 2012

I 53



utilities to try horizontally split mechanical seals with a single set of faces. Retrofitted to existing large-bore bell housing designed seal chambers, it is believed that an external flush water injection [American Petroleum Institute (API) Piping Plan 32] will protect the seal faces. However, experience-based industry guidelines state that this strategy is impractical. In dry FGD applications, higher-speed pumps generate pressure (head) for the rotary spray atomizers. In one example, a

FIG. 2

A dual-mechanical seal. The space between the shaft sleeve and the bore diameters of both sets of seal faces is filled with a barrier fluid, usually water. Source: AESSEAL, Rockford, Tennessee, and Rotherham, UK.

6-in. suction/4-in. discharge pump were specified to operate at 1,800 rpm. The pump thrust loads are balanced by back vanes (pump-out vanes) in the pump impeller. The industry practice is to modify the back-vanes to accommodate operating limitations of single-slurry mechanical seals. Industry standards. The industry standard for rotodynamic equipment is the American National Standards Institute (ANSI) /Hydraulic Institute (HI) Rotodynamic (Centrifugal) Slurry Pump Standard ANSI/HI 12.1-12.6-2011.3 This comprehensive document is recognized as the authoritative reference for slurry pumps. Written collaboratively by HI members who are experts in the industry, the standard covers a wide range of topics. Section 12.3.8 describes general arrangement details for mechanical shaft seals. With respect to this section, a number of cautionary statements highlight the difficulties associated with predictable seal performance. Summarizing the cautionary statements in Section 12.3.8, industry practice is to use “... bell housings, large tapered bore seal chambers, or large tapered bore seal chambers with vortex breakers (to) improve seal life by preventing a buildup of the slurry around the sealing faces that can cause excessive erosion …” The standard goes on to state: “If air bubbles surround the seal faces, the seal can run dry, leading to seal face damage and potential seal failure … the slurry concentration and particle size limits (100 microns to 1,000 microns/0.004 in.–0.04 in. for d50 particle size at 50% concentration) when using an external injection are only limited by the ability of the injection system to exclude the slurry from the seal chamber. The associated product dilution needed to accomplish this task needs to be assessed … (with) large-diameter shafts; this is normally not practical as the required bushing radial clearances to account for shaft deflections will result in excessive flowrates or dilution into the product.” The standard continues and notes: “… dual pressurized seals have the advantage of providing enhanced lubrication to the faces with a pressurized barrier fluid. This arrangement prevents process fluid leakage to the atmosphere to improve safety … dual pressurized seals are used when the limits (of heavy-duty single mechanical seals) are exceeded, when there is a potential for entrained air in the slurry, or when large volumes of air can be introduced into the pump.” Dual-seal designs. Fig. 2 shows a dual pressurized seal

FIG. 3


Pre-engineered seal-contained water management system for dual seals in FGD slurry services. Source: AESSEAL, Rockford Tennessee, and Rotherham, UK.

I MAY 2012

design. With two sets of seal faces, the process lime slurry is contained by an inboard set of faces, and a secondary barrier fluid (water) is pressurized higher than the process. The barrier fluid is contained by an outboard set of seal faces. The higher pressurization means the secondary barrier forms the inboard seal-face fluid film. Constraints caused by small micron particles and air injection are mitigated because the seal face is operating in clean and stable water. Delivery of the water-barrier fluid is important. Traditional piping configurations are API Plan 53-A and API Plan 54. Plan 53-A is limited by a fixed volume of barrier fluid; a fluidcontaining vessel or “seal pot” is externally pressurized by air or nitrogen. During upset process conditions, the pressurized fluid crosses the inboard seal face, and the seal pot must be recharged during operation. This recharging process is not operator friendly; there is a high probability that the seal will run dry. Plan 54 is a centralized water-barrier distribution

MAINTENANCE AND RELIABILITY system, usually through multiple pumps. This means the circulating system must always be pressurized at 15 psig to 30 psig above any seal chamber pressures to avoid cross-contamination of the barrier fluid. Hybrid programs. Leading user companies have success with the suggested hybrid solution, which combines Plan 53 and Plan 54 with water delivery to a water-management system designed to control pressure and cool the seal faces. This system, as shown in Fig. 3, uses a regulator and a back-flow preventer to set the correct water-barrier pressure for the seal faces. The water is recirculated, thus reducing actual water consumption to just a few gallons per year. An inline filter, connected to the continuous source water, filters the barrier fluid to 1 micron absolute. A three-way valve on the line returning from the seal to the reservoir enables the operator to inspect the barrier fluid’s condition in the seal without compromising performance. In the event that particles cross the inboard seal face, then the threeway valve is activated to flush the seal. An internal standpipe on the supply line to the seal protects the seal from contaminants. By connecting a valve and drain line to the bottom of the tank, an operator can purge contaminants from the reservoir while the connected water source automatically replenishes the system with clean water. If process air bubbles accumulate at the seal face, the secondary liquid provides sufficient cooling to ensure consistent seal performance. Independent control of the seal environment broadens the success margin for the seal. An add-on company standard or purchaser’s amendment couples specific operating conditions with available industry standards and provides for the optimum utilization of the FGD unit.


• The tank capacity must be a minimum of 25 l (6.6 gal) and self-filling. Inboard seal face integrity must be visually confirmable at the support system with a flow indicator. • The system must deliver barrier fluid at pressure differentials 15 psig (minimum) above the process pressure in the pump stuffing box at all times. • The seal system must include inline filtration of plant seal water to 1 micron. An internal standpipe on the supply leg, a three-way valve on the return leg, and a blow-off valve at the bottom of the tank must be included to allow clearing contamination from the system after the initial installation and during the service life of the application. • As part of the initial supply package, documentation must include a heat-generation report for each installation. The report must refer to the operating conditions for the intended shaft diameter, speed, process/barrier pressure, temperature and induced flow. The data must provide the input for thermal equilibrium estimation and result in a calculation of the heat generated by the specific seal supplied in each case. Better performance insurance. As regulatory legislation issues persist, a compliance strategy will drive solutions to optimize reliability of rotating equipment. This will lead to technology and revisions of current standards that meet increased demand for viable solutions. While in no way pre-empting the existing standard documents, this article gives experience-based guidance to FGD plants. The authors encourage reliability professionals to structure add-ons or amendments based on the feedback and recommendations contained in this article. HP LITERATURE CITED US Department of Energy, December 2011, “Resource Adequacy Implications of Forthcoming EPA Air Quality Regulations,” pp. 1, 6–13., Regulations%20Report_120111.pdf. 2 Hassibi, M., “A New Approach for Particle Size Reduction in Lime Slaking and Wet Limestone Grinding,” pp. 1–3;,posted; posted 2005; revised February 2009, Admin/Publications/A_NEW_APPROACH_FOR_PARTICLE_SIZE_ REDUCTION.pdf. 3 Hydraulic Institute, 2011, “American National Standard for Rotodynamic (Centrifugal) Slurry Pumps for Nomenclature, Definitions, Applications and Operation,” pp. 75–77, Hydraulic Institute Standards, Standards. 1

Bridging the gap. Plant reliability professionals will consider

bridging the distinct operating parameters of FGD processes with existing industry standards for slurry sealing. Their add-on wording will incorporate the options outlined here. These options will constitute an important amendment to present equipment standards: • The mechanical seal must be a heavy-duty, dual-cartridge mechanical seal suitable for slurry duty and designed to operate at a higher pressure than the process pressure at all times. • Seal-internal cross-sections must have large radial clearances, and the inboard face set must be hydraulically balanced to the barrier fluid. • Tungsten-carbide (TC) and/or silicon-carbide (SiC) faces paired with solid TC must be used when the pH is greater than 5; solid SiC must be used when the pH is 5 or less. Pin drives must be designed to minimize face fracturing. • Large pump sizes must be configured to accept a front-load seal design that can be installed from the wet end of the pump to minimize overhaul costs. • Wetted alloys must be abrasion resistance. • Mechanical seals must perform equally with or without impeller back-vanes, and the user requests that back-vanes be incorporated in the equipment impellers. • The seal chamber must be an open-frame plate liner with vortex breakers or a closed-frame plate liner designed to prevent excessive erosion. • A mechanical seal support system must be provided as a preengineered turnkey system; it must include all instrumentation and fittings necessary to install at the site.

Heinz P. Bloch is a consulting engineer residing in Westminster, Colorado. He has held machinery-oriented staff and line positions with Exxon affiliates in the US, Italy, Spain, England, The Netherlands and Japan in a career spanning several decades, prior to retirement as Exxon Chemical’s regional machinery specialist for the US. Mr. Bloch is the author of 18 comprehensive texts and close to 500 other publications on machinery reliability improvement. He advises process plants worldwide on equipment uptime extension and maintenance cost-reduction opportunities. He is also the reliability and equipment editor for Hydrocarbon Processing. He is an ASME Life Fellow and maintains registration as a professional engineer in Texas and New Jersey.

Tom Grove is executive vice president of AESSEAL Inc., a whollyowned subsidiary of the AES Engineering Group of Companies. AES is a global manufacturer of mechanical seals based in the UK. Mr. Grove was responsible for the startup of the AESSEAL operation (North American Operational Headquarters) in Knoxville, Tennessee (now in Rockford, Tennessee, and served as CEO from 1992 to 2009. He obtained an MBA from Clemson University. Mr. Grove is also a member of the Hydraulic Institute and serves on the Mechanical Seal Committee. HYDROCARBON PROCESSING MAY 2012

I 55

GE Works to redefine pump efficiencies.

In processing industries, GE’s SPS pumping systems work to increase efficiency, reduce environmental impact and provide versatile pumping solutions. For example, our multi-stage centrifugal SPS pumps are a widely-used, efficient solution for circulation, transfer, boosting and disposal applications. Our SPS systems provide enhanced pumping efficiencies by lowering noise and vibration levels, decreasing construction lead times and delivering improved reliability and extended runtimes. With GE, you have a worldwide support system ready to provide engineering, field service or sales support. Take a look at our results, and see how GE can work for you. Call +1 281 492 5160 or e-mail Select 70 at



When good pumps turn bad A straightforward methodology deals with troublesome pumps R. X. PEREZ, Pumpcalcs, San Antonio, Texas


e all have them. They cause us to worry incessantly, lose sleep and frequently miss precious time with our families. They are often the bane of processes that require liquids to be transferred from one location to another. These mechanical monsters are pumps that fail repeatedly and are widely and unflatteringly known as “bad actors.” By definition, bad actors are pumps that fail so frequently that they stand apart from the rest of the pump population. There are bad actors that have failed as many as 16 times in one year, some even more often. These troublesome machines sap precious resources from our maintenance departments and prevent us from achieving world-class reliability performance. Chances are these troublemakers were all carefully selected by well-intentioned vendors and project engineers, and installed dutifully by construction companies. But the devil is in the details. Fatal flaws—ranging from slender shafts (poor L/D ratios) to poor operating practices—crept into these pumping systems. They crippled performance and forced pumps to lead notorious lives. The inordinate number of failures experienced by bad actors tends to dramatically skew downward the mean time between repairs (MTBR) for a plant average. For this reason, a key strategy for improving plant MTBR starts by identifying and improving the reliability of one’s most troublesome pumps. This article presents a straightforward methodology for addressing the most problematic pumps at an operating plant.

thetical data set for a bad actor. To construct a data format similar to Table 2, one needs to know the date of each failure and the repair cost for every past failure in the time frame of interest. A starting point must be defined, as well. In the following example, the first failure occurred 15 months after the defined starting time and the repair cost was $5,000. The next failure occurred 12 months after the first failure and resulted in a repair cost of $5,500. This means that the cumulative time (third column) for the second failure was 27 months and the cumulative repair cost (fourth column) for the second was $10,500. For each subsequent failure, you keep accumulating the failure numbers, time and repair costs, as seen in the cumulative failure, time and cost columns in Table 2. Plotting the cumulative failure number and cumulative repair cost value vs. the cumulative time will yield a plot similar to the one shown in Fig. 2. One might call these reliability growth plots because they clearly illustrate if the failure rate is constant or

Addressing bad actors. To address bad actors, one must FIG. 1

A troublesome centrifugal pump.

Reliability growth plots

Failure growth Repair cost growth

20 15

Change in slope 10 5 0 0

FIG. 2


100 150 Time, months


200,000 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 250

Cumulative repair, $ costs

Note: Left axis is for cumulative failure, and the right axis is for cumulative repair costs

25 Cumulative failures

first define what constitutes such pumps. Usually, definitions contain a combination of failure rate and repair cost criteria. For example, one may define a bad actor as any pump that fails two or more times and has caused more than $10,000 in repair costs over the previous 12-month period. Of course, these criteria can be modified to satisfy management preferences. Some plants also include lost opportunity costs during the same reporting period. It is possible to simplify reporting by combining repair cost and production losses into a single figure called “losses.” These multiple criteria tend to cull nuisance pumps that fail many times each year but do not have a large annual repair total. By using the multiple criteria of failure rate and repair costs, one can quickly identify the pumps having the greatest impact on reliability. Go after the top. After creating a list similar to Table 1, one simply sorts in descending order of the most to the least costly pump. The top 10 on this list represents bad actors. This list should probably be compiled quarterly, semi-annually or annually. It is customary to start by attacking the worst of the bad actors. Examine the equipment history. The next steps describe more closely how to attack each bad actor. Let’s examine a hypo-

Reliability growth plot for a hypothetical pump.


I 57



TABLE 1. List of bad actors

TABLE 2. Hypothetical bad actor data

Number of Repair cost Production losses Pump failures in last over last over last number 12 months 12 months 12 months

Total losses in last 12 months

Cumulative failures

Time since last failure, months

Cumulative time, months

Repair cost

Cumulative costs









































































































































































































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MAINTENANCE AND RELIABILITY changing over time and if the rate of cost to perform maintenance is changing over time. A constant slope means the failure rate is constant, while a curving plot means the failure rate is changing. The reliability growth plot in Fig. 2 shows a constant failure rate up until months 160 to 170. After that time, the failure rate and expenditure rate begin to increase and eventually settle into a new higher failure rate for some undefined reason. These reliability growth plots offer a wealth of information. First, the cumulative failure plot shows if the failure rate is constant or changing with time. If the failure rate did change, it tells the analyst when the change occurred. One can discover if the failure rate was always bad or if it changed at some time in that past. Similarly, examining cumulative repair cost data allows the analyst to determine if something changed in the past or if failure costs have been constant from the beginning. If there is a defining moment when reliability decreased, the analyst might ask what changed. Interviews with operators and mechanics allow us to find reasons for the observed change in reliability. Field personnel very often provide key insights that assist in complex root cause failure analyses (RCFAs). Among the clues, we may find mechanical and procedural changes, such as: • The nature of the process has changed • The control scheme was modified in the past • The seal flush source was modified due to process contamination concerns. Interviewing personnel close to the equipment is a great way to uncover subtle issues that may be affecting reliability performance. Here, then, is a telling example involving pumps that were failing every few months. It was discovered that a production engineer decided to eliminate the use of an external seal flush because he felt it was contaminating the process. After convincing him to reinstate the flush at a lower, friendlier rate, seal life returned to the anticipated norm. Suppose the general trends observed on reliability growth plots are fairly constant over the operational lives of the pumps in question. It would then be fair to assume there is something wrong with the basic design of the pumping system. Possible causes may include: • Poor installation • Poor L/D ratio • Poor pump selection • Excessive piping strain. The reliability growth plots also tell reviewers how much the pumps are costing. In this particular example one can quickly conclude that $126,700 was spent over a period of 219 months. This equates to an annual rate of $6,942. The annual rate of expenditure conveys the value of solving the problem. If one were to assume that annual repair costs can be reduced to 25% of the starting value, one might expect to save about $5,200 per year. For a two-year payback needed to justify capital expenditures, spending about $10,000 on a solution would be justified. To ensure an acceptable return on investment, the author tries to avoid working on pumps that have annual repair and process losses below $10,000. Although it is often assumed that finding economic justification of reliability projects for pumps with annual losses less than $10,000 is next to impossible, this rule will not hold whenever simple seal improvements, bearing upgrades or procedural changes are involved. Conducting detailed design audits and RCFAs. The next step in dealing with troublesome pumps requires conducting a design, installation and performance audit. Such an audit involves:


• Reviewing the pump selection, driver selection, seal design, piping design and control system design • Conducting a detailed vibration analysis of the pump, motor and piping system • Reviewing the base plate and foundation design • Assessing current hydraulic performance vs. what was expected or ascertained on earlier occasions. It can be said that this phase of an audit includes ascertaining that the correct pump and system design are used for the service in question. The “cold eye review” will often be appropriate. It refers to the fresh assessment of a system or process by an experienced, unbiased third party. This party could be another pump engineer or technician accompanying the audit engineer on his or her field visit and inspecting the pump in question. The intent of the cold eye review is to look for anything that might be considered unacceptable. Excessive vibration, lack of piping supports, inattention to thermal growth and absence of pressure gauges are among the many things noted and requiring remedial action. After living with a problem pump for a long period, we can become oblivious to issues right in front of us. The cold eye review can help uncover potentially important issues that were overlooked by those living and working close to chronic bad actors. Once the analyst has reviewed the failure history and conducted a design audit, some seemingly elusive contributing factors begin to stand out. The next analysis step requires us to determine the root causes of failures. It is important not to stop at a physical root cause, such as the pump failed due to a bearing failure or shaft failure. A good investigative team will uncover any latent root causes, ones

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that often lurk beneath the figurative surface. The key point here is that an investigative team must be open-minded during the data collection and evaluation. Parts fail for a reason and the decisions of people led to whatever issues we now experience. Your goal is to seek the truth and back it up by science. Determine a path, then track progress. Once the root cause and contributing factors are established by the team, it is time to formulate a plan of attack. It has been said that less is more. In other words, it is easier to sell two recommendations to management than 20 recommendations. It is also easier to implement two recommendations than 20. This doesn’t mean that no more than two recommendations can be made. It simply means that, by only presenting the highest priority recommendations to management, one’s chances of securing approval dramatically improve. Don’t be afraid to fail; we all fail occasionally. The best approach involves gathering lots of data, analyzing the data in exhaustive detail, and using a repeatable and structured RCFA approach. The RCFA process is a process of continuous improvement. Some problems are so complex that they may take several tries to solve. After obtaining management approvals, it is time to implement remedial recommendations in a timely fashion and to track the benefits of the improvements. Proof of success will be seen in an updated reliability growth plot, where, hopefully, reliability improvements are manifested and sustained. Whenever clear improvement is seen, the news deserves to be published. Management, operating personnel, and contributors will be motivated to continue working toward reducing, and even eliminating, bad actors until plant-wide MTBR targets are reached.

Critically important steps. There are seemingly insignifi-

cant buying decisions and other events that can occur during the early life of a pump that eventually lead to below-average reliability performance. However, reliability improvements and systematic upgrading of weak links can turn things around. Successful reliability improvement programs require that latent root causes be identified and corrected. Starting with one’s most troublesome pumps, failure lists must be systematically reduced until world class reliability is achieved. Remember these critical steps in bad actor reviews: • Define, list and compare • Go after the top bad actors • Examine the equipment history • Conduct a detailed audit • Perform an RCFA • Determine a path forward • Track your progress. There will always be another pump failure from which to analyze and learn. Every failure should be considered an opportunity to learn more about equipment, processes and systems, and improve them. HP

Robert Perez is the author of Operator’s Guide to Centrifugal Pumps and co-creator and editor of the website. He has more than 30 years of rotating equipment experience in the petrochemical industry and has numerous machinery reliability articles to his credit. Mr. Perez holds a BS degree in mechanical engineering from Texas A&M University at College Station and an MS degree in mechanical engineering from the University of Texas at Austin. He holds a Texas PE license.

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Who should you call to repair your process pump? Independent shops can provide upgrade and repair services for key process equipment H. P. BLOCH, P. E., Consulting Engineer, Westminster, Colorado


or the hydrocarbon processing industry (HPI) to routinely rebuild an “older” or “vintage” centrifugal pump to original equipment manufacturer (OEM) specifications is not practical, given present pump rebuilding and testing technology. Pump users realize that changes to system performance do occur over time, and technology advances make efficiency gains possible. A highly qualified independent rebuild shop with up-to-date design tools and experienced personnel can verifiably offer high-quality upgrades that improve both uptime and efficiency consistent with current system performance requirements. Considerable consolidation has taken place within the pump industry; thus, the distinct possibility exists that a particular OEM is no longer able to offer the same engineering competence they had provided decades ago. In addition, some equipment vendors have “downsized” or “right-sized” their traditional inspection departments into oblivion. The user-owner often sees the consequences reflected in unexpected pump downtime and repeat failures. Fig. 1 shows how consolidation has taken place.

Changing times and services. Some OEMs are no longer

staffed by mostly experienced personnel. The order processing and availability of spare parts are often less than seamless. It is intuitively evident that considerable legacy brand experience has been lost. Unfortunately, the remaining staff (with less experience) is prone to display more evidence of imperfection than their precursor organizations. This article will focus on the OEM vs. non-OEM competent pump rebuild shop (CPRS) issue, and it investigates a real case history objectively. The cost advantages of critically timed hydraulic efficiency upgrades and a fair number of tangible pump improvement details will be described. With some HPI facilities reporting pump mean-times-between-failure (MTBF) rates in excess of 10 years and others struggling to reach an MTBF of three years, this article aims to allude to management issues and hardware selection details that account for the differences in pump failures experienced.

Condition review and pump-repair scope definition.

A CPRS has both the tools and the experience needed to define a work scope beyond the routine upgrading. Moreover, a superior shop has testing capabilities that set the facility apart from its competition. The CPRS takes a lead role in defining the repair scope, and all parties realize that reasonably accurate definitions will be possible only after first making a thorough “incoming inspection.” A formal document in written form or electronic version should include owner-customer, pump manufacturer, pump type, model designation, plant location, service, direction of rotation and other data of interest, along with operating and performance data. The main efforts should be directed into providing a complete description addressing the general condition of a pump, and this effort is followed by a more detailed description of the work to be considered. Documentation constitutes the condition review of the pump to be repaired; all data will have great value. What condition reviews include. Condition reviews should

include photos of the as-received equipment and close-up photos of parts and components with special interest. End floats, lifts and


Ebara KSB

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Critical needs. We will to cover critical and important aspects

of a vendor’s participation in this process. We will take the position that cooperation between pump user and CPRS facilities is in the HPI user’s best interest and that “fix it quick and cheap” approaches serve neither party. Essential non-OEM capabilities in defining pre-repair and post-repair hydraulic efficiencies are discussed, and general guidance is mapped out for HPI facilities.




Warman Floway

FIG. 1

BWIP (United and BJ)

Wilson Snyder

Consolidation within and among pump manufacturers during recent times. HYDROCARBON PROCESSING MAY 2012

I 63



other detailed measurements are taken and placed on a dimensionalrecord form both before and after total dismantling. Components are marked or labeled, and the hardware is counted and cataloged. Bearings, bushings and impellers are removed. Bead blasting, steam or other cleaning methods are identified, and a completion date for these preliminary steps is agreed upon by the CPRS and ownercustomer. Only now would a competent shop consider it time to arrive at the next phase in its repair-scope definition. Nondestructive testing (NDT) is the next step and it must be used where applicable. A good pump-rebuild shop will issue a form 80 70 60 50 40 30

Large-equipment issues. On very large equipment items, the inspection process may include electrical run-out readings at eddy current probe locations, rotor (shaft) total indicator readings (TIR), individual impeller balance, rotor balance and residual unbalance. The inspection form would also list the authority for performing these inspections, acceptance criteria, condemnation limits and other items of interest. Some of the ultimate inspection results would be documented on this form; other inspection results would be listed on separate forms. Remember our term “form” refers to both paper and electronic (computerized) formats. There is a transitioning from documents that define initial work scope, to documents that deal with material certification, documentation of as-achieved (or as-built)


0 FIG. 2


Efficiency, %

Head, ft

Model: I-R 4X11CA-8 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0

that identifies the chosen inspection method, such as liquid-dye penetrant or magnetic-particle methods. While a detailed discussion of NDT inspection is beyond the scope of this article, we stress the importance of NDT imprecation as part of the refurbish process and that a quality CPRS will recognize this need for this inspection.



800 600 Capacity, gpm



10 0 1,400

Original pump performance curve (solid) and desired performance (dotted).

FIG. 3

IR 4x11 CA-8 stage process pump in the as-received condition. Source: Hydro, Inc., Chicago, Illinois.

FIG. 4

Suction end after initial cutting. Source: Hydro, Inc., Chicago, Illinois.

I MAY 2012

FIG. 5

Machining the weld bevel and register fit. Source: Hydro, Inc., Chicago, Illinois.

FIG. 6

Ready for welding of the modified pump. Source: Hydro, Inc., Chicago, Illinois.



dimensions, adequacy or fitness-for-service of auxiliary components, or repair quality. The condition review and repair scope definition are important first steps in the repair process. OEMs as well as CPRS facilities, will show abilities in this regard. Case history: Upgrade for an Ingersoll-Rand 4x11 CA 8-stage pump. How revamps and repair events lend them-

selves to becoming upgrade opportunities is demonstrated here. In this case history, an owner planned to expand site production. The facility elected to find a surplus pump in the used equipment market and modify it to suit the process upgrade needs rather than purchase a new pump. Only one experienced CPRS offered a realistic solution to both a challenging engineering problem and an intensely demanding production schedule. With guidance from the CPRS, the plant examined various pump-performance curves and directed its focus to a pump with the characteristics shown in Fig. 2. This IR 4x11 Model CA 8-stage pump (Fig. 3) was purchased because it could be modified to meet the new owner’s specific needs, delivering 740 gpm at 1,700 ft of head. A thorough engineering review was made and trade-offs related to efficiency were explained. The existing pump was inspected, and the CPRS offered upgrades to improve both pump performance and reliability under toxic liquid service. The upgrades included: • Shorten the barrel and de-stage the pump from previously eight stages to only five. Why: The shorter pump shaft would provide improved rotor stability. • Change from a single- to a dual-mechanical seal. Due to the toxic nature of the product being pumped, a stronger, more reliable sealing design was required. • Change stuffing box design to accommodate new seal.

FIG. 9

Pump on the test stand. Source: Hydro, Inc., Chicago, Illinois

FIG. 10A Test stand with de-staged finished process pump. Source: Hydro, Inc., Chicago, Illinois.

Model: IR 4X11CA-5


Finish-welded barrel of the modified pump.

70 Head

Head (ft) and Hp

2,000 1,500

40 30



Hp Hp

0 0

Rotor of the modified pump re-assembled and balanced.

60 50


FIG. 8



Efficiency and NPSH, ft

FIG. 7


0 100 200 300 400 500 600 700 800 900 1,000 Capacity, gpm

FIG. 10B Certified test performance curve delivered after repair for an IR 4x11 CA 5-stage process pump. Source: Hydro, Inc., Chicago, Illinois. HYDROCARBON PROCESSING MAY 2012

I 65


MAINTENANCE AND RELIABILITY took place in preparation for welding. The two halves were tack welded, as shown in Fig. 6. The sub-arc technique was used for welding. The finish-welded barrel is shown in Fig. 7; next, the rotor was re-assembled and balanced (Fig. 8).

FIG. 11

Upgraded process pump and driver assembled on baseplate and ready for shipment to owner. Source: Hydro, Inc., Chicago, Illinois.

â&#x20AC;˘ Engineer a better way to vent and drain the pump. â&#x20AC;˘ Because of the possibility that the pump might â&#x20AC;&#x153;run-dry,â&#x20AC;? the CPRS suggested tungsten carbide be used on wear rings, bushings and balance drum. â&#x20AC;˘ Modify the baseplate for the shorter pump and new motor. â&#x20AC;˘ Add a modern bearing housing seal. While it is not uncommon to de-stage a multi-stage pump to meet changes in operating requirements, the shortening of the barrel is a highly creative solution. A dimensional drawing of the pump had to be prepared. The cut barrel had to be rejoined with specialized welding techniquesâ&#x20AC;&#x201D;procedures not offered by most repair shops. CPRSâ&#x20AC;&#x2122;s repair process. As a first remanufacturing step, the barrel was marked for saw cutting. After cutting, Fig. 4 shows the condition of the pump. Bevel and register fit machining (Fig. 5)

A modern CPRS and its testing capabilities. Once the project was completed, the CPRS tested the pump (see Figs. 9 and 10) and provided a certified performance curve. Fig. 9 shows that the modifications did, in fact, produce the specified head and flow. New thinking on equipment. The plant requested a pump that would process 740 gpm at 1,700 ft of head and that is exactly what the CPRS achieved. Not only did this CPRS meet or exceed all of the engineering design conditions, it also matched a customerâ&#x20AC;&#x2122;s very demanding 44-day schedule. Ordering a new pump to meet their needs would have meant a 6â&#x20AC;&#x201C;8 month delay; it would also have cost millions of dollars in lost production. We often explain to readers that modern pump upgrade shops are â&#x20AC;&#x153;solutions-based,â&#x20AC;? not â&#x20AC;&#x153;product-basedâ&#x20AC;? companies. Their product is service and our â&#x20AC;&#x153;ready-to-shipâ&#x20AC;? example, as shown in Fig. 11, proved it. HP

Heinz P. Bloch is a consulting engineer residing in Westminster, Colorado. He has held machinery-oriented staff and line positions with Exxon affiliates in the US, Europe and Japan prior to retirement as Exxon Chemicalâ&#x20AC;&#x2122;s regional machinery specialist for the US. Mr. Bloch is the author of 18 comprehensive texts and close to 500 other publications on machinery reliability improvement. He is also the reliability and equipment editor for Hydrocarbon Processing. He is an ASME Life Fellow and maintains registration as a professional engineer in Texas and New Jersey.


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Process Insight: Physical solvents such as DEPG, NMP, Methanol, and Propylene Carbonate are often used to treat sour gas. These physical solvents differ from chemical solvents such as ethanolamines and hot potassium carbonate in a number of ways. The regeneration of chemical solvents is achieved by the application of heat whereas physical solvents can often be stripped of impurities by simply reducing the pressure. Physical solvents tend to be favored over chemical solvents when the concentration of acid gases or other impurities is very high and the operating pressure is high. Unlike chemical solvents, physical solvents are non-corrosive, requiring only carbon steel construction. A physical solventâ&#x20AC;&#x2122;s capacity for absorbing acid gases increases VLJQLÂżFDQWO\DVWKHWHPSHUDWXUHGHFUHDVHVUHVXOWLQJLQUHGXFHGFLUFXODWLRQUDWHDQG associated operating costs.

Typical Physical Solvent Process

Comparing Physical Solvents for Acid Gas Removal PC (Propylene Carbonate) The Fluor Solvent process uses JEFFSOLÂŽ PC and is by Fluor Daniel, Inc. The light hydrocarbons in natural gas and hydrogen in synthesis gas are less soluble in PC than in the other solvents. PC cannot be used for selective H2S treating because it is unstable at the high temperature required to completely strip H2S from the rich solvent. The FLUOR Solvent process is generally limited to treating feed gases containing less than 20 ppmv; however, improved stripping with medium SUHVVXUH Ă&#x20AC;DVK JDV LQ D YDFXXP VWULSSHU DOORZV WUHDWPHQW WR  SSPY IRU JDVHV containing up to 200 ppmv H2S. The operating temperature for PC is limited to a minimum of 0°F (-18°C) and a maximum of 149°F (65°C).

Gas Solubilities in Physical Solvents

All of these physical solvents are more selective for acid gas than for the main constituent of the gas. Relative solubilities of some selected gases in solvents relative to carbon dioxide are presented in the following table. The solubility of hydrocarbons in physical solvents increases with the molecular weight of the hydrocarbon. Since heavy hydrocarbons tend to accumulate in the solvent, physical solvent processes are generally not economical for the treatment of hydrocarbon streams that contain a substantial amount of pentane-plus unless a stripping column with a reboiler is used.

DEPG at 25°C

PC at 25°C

NMP at 25°C

MeOH at -25°C































Gas Component

DEPG (Dimethyl Ether of Polyethylene Glycol) DEPG is a mixture of dimethyl ethers of polyethylene glycol. Solvents containing DEPG are marketed by several companies including Coastal Chemical Company (as Coastal AGRÂŽ), Dow (Selexolâ&#x201E;˘), and UOP (Selexol). DEPG can be used for selective H26UHPRYDODQGFDQEHFRQÂżJXUHG to yield both a rich H2S feed to the Claus unit as well as bulk CO2 removal. DEPG is suitable for operation at temperatures up to 347°F (175°C). The minimum operating temperature is usually 0°F (-18°C).

MeOH (Methanol) The most common Methanol processes for acid gas removal are the Rectisol process (by Lurgi AG) and IfpexolŽ process (by Prosernat). The PDLQ DSSOLFDWLRQ IRU WKH 5HFWLVRO SURFHVV LV SXUL¿FDWLRQ RI V\QWKHVLV JDVHV GHULYHG IURP WKH JDVL¿FDWLRQ RI KHDY\ RLO DQG FRDO UDWKHU WKDQ QDWXUDO JDV treating applications. The two-stage Ifpexol process can be used for natural gas applications. Methanol has a relatively high vapor pressure at normal process conditions, so deep refrigeration or special recovery methods are required to prevent high solvent losses. The process usually operates between -40°F and -80°F (-40°C and -62°C).

NMP (N-Methyl-2-Pyrrolidone) The Purisol Process uses NMPÂŽ and is marketed by Lurgi AG. 7KH Ă&#x20AC;RZ VFKHPHV XVHG IRU WKLV VROYHQW DUH VLPLODU WR WKRVH IRU '(3* 7KH process can be operated either at ambient temperature or with refrigeration down to about 5°F (-15°C). The Purisol process is particularly well suited to the SXULÂżFDWLRQRIKLJKSUHVVXUHKLJK&22 synthesis gas for gas turbine integrated JDVLÂżFDWLRQFRPELQHGF\FOH ,*&& V\VWHPVEHFDXVHRIWKHKLJKVHOHFWLYLW\IRU H2S.
















Methyl Mercaptan





Choosing the Best Alternative A detailed analysis must be performed to determine the most economical choice of solvent based on the product requirements. Feed gas composition, minor components present, and limitations of the individual physical solvent processes are all important factors in the selection process. Engineers can easily investigate the available DOWHUQDWLYHVXVLQJDYHULÂżHGSURFHVVVLPXODWRUVXFKDV3UR0D[ÂŽZKLFKKDVEHHQYHULÂżHG with plant operating data. For additional information about this topic, view the technical article â&#x20AC;&#x153;A Comparison of Physical Solvents for Acid Gas Removalâ&#x20AC;? at For more information about ProMax, contact Bryan Research & Engineering or visit

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2012 PETROCHEMICAL OUTLOOK Petrochemicals bounce back. Petrochemicals are used to produce durable and nondurable consumer products that improve the quality of life. Demand for petrochemical-based products is dramatically increasing in developing nations. Asia is responsible for much of this new demand. A growing middle class in both India and China will reshape demand patterns for all petrochemical and chemical products. The petrochemical industry continues to follow cycles of expansion and contraction as more efficient production units put pressure on older facilities. While Asia remains the epicenter for growing demand, the Middle East continues to expand petrochemical capacity based on cost-advantaged feedstocks. Much of the new production will be exported to Asia and Europe. In North America, the growing supply of shale gas has reset regional natural gas prices. North American petrochemical producers have transformed themselves and are now visibly competitive in the global market. Commercialization of new and expanded feedstocks and raw materials are prompting changes in the global petrochemical market.

feedstock prices for petrochemical projects in Saudi Arabia could even increase to over $2/MMBtu—well above the $0.75/MMBtu price seen in the past. Even with higher feed gas prices, ME petrochemical projects are still economical, but they are certainly less attractive for new investment. The larger issue will be getting feedstock committed for new projects. ME ETHYLENE AND PROPYLENE PRODUCTION

R. SMITH, S. ADIBI and S. KHIMASIA, FACTS Global Energy, Dubai, United Arab Emirates

Ethylene and propylene are the principal petrochemical products and a major feedstock for other polymers. In recent years, the world witnessed possibly the largest expansion ever for new ethylene and propylene plants, and most of it was located in the ME. These additions will have a significant influence on the global petrochemical industry in the near term. The 2008–2012 boom saw an average annual growth rate in ethylene capacity of nearly 12%, from 16.9 million tpy (MMtpy) to 26.3 MMtpy. While such growth will be limited to a 5.6% average annual growth rate from 2012 to 2016, we will still likely see ethylene production capacity reach 32.6 MMtpy. The wild card is Iran; as this nation tries to complete its current projects, we are cautiously optimistic. It is possible, however, that the political situation in Iran and the potential for petrochemical sanctions may result in further delays. With Iran removed from the picture, the average annual growth rate from 2012 to 2016 drops to just 2.8%, with the largest growth coming from Borouge III in Abu Dhabi. Fig. 1 illustrates the ethylene capacity expansion in this region.

Saudi Arabia. This nation is the largest ethylene producer

The Middle East (ME) olefin boom has concluded, and the era of great expansions has slowed for the decade. Most of the Middle Eastern countries are looking to expand further into downstream petrochemicals as opposed to exporting the building blocks. Previously, the ME had a great advantage in the production of ethylene, propylene and their derivatives due to abundant, cheap feedstocks. The abundance continues, but only for those projects that have it guaranteed and set aside at a certain price. It is unlikely to see any new projects this decade due to supply and price restraints. Iraq may see a boom sometime after 2020, but that’s a long way off as this nation continues to rebuild and focus on more pressing issues, such as gas-fired power generation. Although the availability of inexpensive gas prompted many companies to move forward with massive expansion plans, the region is facing new uncertainties in providing sufficient feedstock. This is a serious concern for proposed projects, especially in Iran and Saudi Arabia. ME domestic gas prices are expected to eventually increase as production costs have risen significantly. This may push governments to set higher prices for petrochemical feedstocks. New

in the region. At present, ethylene production in Saudi Arabia is 14.5 MMtpy, up by 5 MMtpy from nearly three years ago. Ethylene is produced in large Saudi petrochemical complexes such as Sadaf, Yanpet, United, PetroKemya, Tasnee, Yansab, PetroRabigh, Saudi Kayan, Saudi Ethylene and Propylene Company (SEPC) and Sharq III. Propylene capacity in Saudi Arabia has grown to 3.38 MMtpy. The wave of the Saudi petrochemical sector’s massive increase in ethylene and propylene production capacity is beginning to recede. While Saudi Arabia will remain a global leader in the petrochemical industry, the large ethane-based projects are a thing of the past due to a lack of feedstock availability. At present, two petrochemical projects are likely to be constructed in Saudi Arabia, and these projects are scheduled for completion in 2015 and 2016. We only list the reported ethylene capacities at this time, as the final configurations have yet to be decided, as shown in Table 1. Even with Aramco as a partner, feedstock availability and price weigh heavily due to shortages in the Kingdom. It should be noted that Aramco provides feed gas for petrochemical projects at a fixed price of $0.75/MMBtu. The cheap feedstock is a great advantage for the petrochemical industry in Saudi Arabia.



I 69

2012 PETROCHEMICAL OUTLOOK Iran. In spite of various sanctions, Iran continues to be a major petrochemical player in the region. Iran’s petrochemical developments owe their recent success to affordable feedstock and a 10-year tax holiday for investors. In 2010, Iran produced around 40 million tons of petrochemical products. The continued expansion of the domestic petrochemical industry has resulted in an average annual growth rate of 22% for petrochemical product output and a 28% increase for export volumes since 2005. Iran’s ethylene capacity stands at 5.3 MMtpy, which represents about 21% of the ME’s ethylene capacity. Propylene capacity stands at 1.1 MMtpy. Figs. 2 and 3 illustrate Iran’s ethylene and propylene production capacities by project in 2011. The Jam petrochemical complex remains the largest ethylene producer in Iran. Ethylene production capacity of this complex is approximately 1.32 MMtpy. The plant also produces 305,000 tpy (305 Mtpy) of propylene. FACTS Global Energy (FGE) forecasts that Iran’s ethylene and propylene production capacities will increase significantly after the completion of petrochemical projects now under construction, as summarized in Table 2. By 2014, Iran’s ethylene production capacity is expected to increase to 8.5 MMtpy, while its propylene

Ethylene production capacity, MMtpy

35 30

Iraq Kuwait UAE

Qatar Iran Saudi Arabia

25 20 15 10 5

Qatar. Ethylene is now produced by three major petrochemical companies in Qatar with a total production capacity of 2.6

0 2008

2012 Year


TABLE 1. New ethylene and propylene capacity under construction in Saudi Arabia

FIG. 1. Ethylene production capacity in the ME, 2008–2016.


Total: 5.3 Mtpy Tabriz 2.6%

Aryal Sasol 18.8%

production capacity will increase to 1.4 MMtpy. In spite of its difficulties in attracting foreign investment, Iran continues to achieve its goals of increasing petrochemical production capacity. While expansion plans continue, Iran’s new projects will be challenged by such issues as long delays in completion dates due to a lack of financial resources and/or feedstock availability. In recent years, several petrochemical projects have faced feedstock supply shortages, thus forcing them to run well below nameplate capacities. For instance, the largest ethylene producer in the country, Jam, has experienced a feedstock (ethane) shortage since 2009. The Jam ethane cracker operates at 50%–60% of its capacity due to insufficient ethane supplies from the South Pars gas projects. This also resulted in the derivative plants cutting production due to the ethylene shortages. Iran is blessed with abundant and easy-to-develop gas resources that have allowed the country to sell feed gas to petrochemical projects at very low prices—around $0.4/MMBtu– $0.5/MMBtu. Accordingly, Iranian projects have significant economic advantages compared to other international petrochemical producers. However, a recent price increase is a major concern, particularly for the private players in Iran’s petrochemical industry. This is seriously threatening the projects’ economics and future expansion of the domestic petrochemical industry. It is worth noting that, in October 2009, the Iranian Parliament finally approved the general outline for increasing energy prices and passed a bill to cut energy subsidies. Based on the approval, the price of natural gas will be set gradually to market prices from the start of the reform plan on Dec. 19, 2010. Industrial projects, including the petrochemical projects, now have to pay around $2/ MMBtu for natural gas for the first year of the reform plan, which is considerably higher than the past price of $0.53/MMBtu in early 2010. The ethane price has been set at $145.1/ton for the first year of the reform plan. For the longer term, Iran is planning to increase gas prices for industrial projects to 65% of the average export gas price within 10 years. These higher gas prices will make many new gas-based projects economically unfeasible.

Abadan 0.5%

Maroon 20.7%


Ethylene capacity, Mtpy

PetroRabigh II (Aramco-Sumitomo)



Sadara (Aramco-Dow)


Jam 24.8%

Bandar Imam (Faravaresh) 7.7%

Arak 5.8% Morvarid 9.4%


I MAY 2012

Ethylene Propylene Startup capacity, Mtpy capacity, Mtpy

11th Olefin (Kavyan Petrochemical Co.)



13th Olefin (Ilam Petrochemical Co.)





Gachsaran Olefin

FIG. 2. Iran’s ethylene production capacity by project in 2011.


TABLE 2. New ethylene and propylene capacity under construction in Iran Projects

Amir Kabir 9.8%









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MMtpy. Qatar Petrochemical Co. (Qapco), Qatar Chemical Co. (Q-Chem) and Ras Laffan Olefins Co. (RLOC) are the ethylene producers in this nation. Qapco’s ethylene production capacity is roughly 800 Mtpy, Q-Chem has a production capacity of 500 Mtpy, and RLOC has a production capacity of 1.3 MMtpy. At present, the country has no propylene production; however, some of Qatar’s future plans could involve propylene production. As the configurations are not yet finalized for newbuilds, it is too soon to comment, and it seems unlikely at this stage. At present, Qatar Petroleum has two agreements to construct steam crackers. One is a joint venture between Qapco and Total that has an HOA professing an output of 1.4 MMtpy of ethylene. The other is a Qatar Petroleum/Shell HOA for a $6.5 billion steam cracker with a monoethylene glycol plant yielding up to 1.5 MMtpy. Realistically, we foresee both projects targeting a 2018 startup. It should be noted that, while undisclosed, feed gas prices for Qatari petrochemical projects remain extremely competitive and continue to ensure the viability of the petrochemical industry. ETHYLENE AND PROPYLENE PROJECTS IN OTHER MIDDLE EAST COUNTRIES


us a t V is i t 2012 EM A h C75 ACH ot .1, bo 1 1 l l a

The UAE. Abu Dhabi has a number of projects, and ethane is the only feedstock. Borouge I operates a 600-Mtpy ethylene plant, and Borouge II operates a 1.5-MMtpy ethylene plant that also produces 825 Mtpy of propylene. As Borouge II only uses ethane feedstock, the propylene primarily comes from the world’s largest metathesis unit, which has a capacity of 752 Mtpy. The Borouge III petrochemical company is under construction, and it should be operational by mid-2014. The ethane cracker will produce 1.5 MMtpy of ethylene, thus raising total ethylene production to 3.6 MMtpy. The ChemaWEyaat project is the other planned petrochemical venture. It is a 1.45MMtpy naphtha cracker and grassroots olefins, aromatics and urea complex at Taweelah. While the project continues to be discussed, naphtha feedstock pricing issues from the Ruwais refinery appear to be the cause of the delays. At this point, the project is not included on FGE’s list of firm projects. Kuwait. Kuwait’s ethylene production capacity is 1.65 MMtpy.

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Equate Petrochemical Co. operates an 800-Mtpy facility, and Kuwait Olefins Co. (TKOC) operates an 850-Mtpy facility. Both are located at Shuaiba. The only additional project to be menTotal: 1.32 Mtpy Bandar Imam (Faravaresh) Abadan 10% 1% Fanavaran 11%

Bandar Imam (Basparan) 3%

Amir Kabir 14%


Arak 11%

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Maroon 18%

Tabriz 5% Jam 27%

FIG. 3. Iran’s propylene production capacity by project in 2011. 䉳 Select 176 at

2012 PETROCHEMICAL OUTLOOK tioned is the Petrochemical Industries Co. (PIC) Olefins III project. While a feasibility study was completed in 2011, no details have emerged as to the intended configuration and feedstock. We understand that it will be a mixed-feed plant, which makes sense considering the uncertainties in Kuwait’s gas supply. The project’s location was moved to Al Zour, near the planned new refinery. Oman. Oman continues to produce propylene at the Sohar

refinery. The refinery operates in an olefin mode to produce roughly 327 Mtpy of propylene feedstock for the polypropylene plant owned by Oman Polypropylene LLC (OPP). There are no olefin expansion plans in Oman. Iraq. At present, Petrochemical Complex No. 1 (PC1) in Khor al-Zubair, near Basrah, is producing ethylene from ethane feedstock supplied by the Rumaila oil field. The plant has the capacity to produce 132 Mtpy of ethylene, 110 Mtpy of ethylene dichloride, 66 Mtpy of vinyl chloride monomer, 60 Mtpy of polyvinyl chloride and 90 Mtpy of low-density polyethylene (LDPE) and high-density PE (HDPE). However, the plant is operating below its nameplate capacity and needs revamping. South Korea’s STX Heavy Industries signed a memorandum of understanding (MOU) with Iraq in 2010 to revamp the facility, but they have yet to be successful in enacting the MOU. This construction project

UNITED STATES DR. T. K. SMITH, Chief Economist and Managing Director—Economics and Statistics, American Chemistry Council (ACC), Arlington, Virginia The global economy has reached a critical state. Last year represented the third year of the global economic recovery. However, the pace of improvement slowed as higher energy prices, the disasters in Japan, the Eurozone crisis and the influence of other negative factors spread. A global soft patch emerged and has been centered in manufacturing. Unfortunately for chemistry, the manufacturing sector represents its major end-use or customer base. The consensus forecast is for continued but slow economic growth, well below trend growth through 2013. This is consistent with a recovery from a financial crisis, and it is likely that economic growth will not reach long-term trend levels until 2014. The recovery is fragile, however, and multiple risks remain. Sharply higher oil prices present the gravest risk. The European debt crisis (and recession) continues to weigh on the world economy; as does a potential hard landing in China and the uncertainty about US debt levels, policy and long-term economic prospects. The wrong trade, tax or other policy initiatives could derail activity. Economic prospects going forward represent a two-speed world in which the developed nations (constrained by debt and adverse demographic factors) grow slowly, while the emerging markets grow rapidly as a result of industrialization and rising consumer-driven economies. Most major end-use markets for chemistry have recovered in the US, especially those tied to export markets and business investment. The manufacturing sector, which is the largest consumer of chemistry, strongly rebounded during the recovery, but

remains delayed at this time. Iraq will likely continue to focus its efforts on increasing oil production and electrical power generation before focusing on its petrochemical industry. ME growth is stymied by shortages of cheap natural gas feedstock. Low gas prices in the ME have provided an

attractive environment for gas-based petrochemical projects. With the possible exception of Qatar and Iraq, these advantages have slipped away due to increased domestic gas consumption. Dubai and Kuwait are now importing liquefied natural gas (LNG), with others exploring LNG as an option. With world economic growth remaining slow and feedstock prices rising (natural gas or naphtha), the global olefins market continues to be oversupplied for the near term. However, existing ME olefin suppliers will be less affected than Asian petrochemical producers due to available low-feedstock prices. Elsewhere, naphtha-based projects will be most affected. The outlook for new projects is less optimistic, unless investors can lock in a feedstock source and price from the government or build a combined complex with a refinery to provide naphtha feedstock. The boom era of olefins growth has ended in the ME, barring any additional, huge gas finds. This means that the existing businesses will remain economical, but we will likely see investment moving further downstream in the petrochemical value chain to more intermediates and potentially beyond. HP growth slowed in 2011 as demand weakened. US manufacturing output still remains below its pre-recession peak. A two-speed manufacturing sector, with about one-half industries soft and others doing well, has emerged. The boom in oil and gas is creating both demand side (e.g., pipe mills, oilfield machinery) and supply-side (e.g., chemicals, fertilizers, direct iron reduction) opportunities. There is strength in light vehicles and aircraft; a recovery in construction materials and industries involved with business investment (iron and steel, foundries, computers, etc.) are still strong. Elsewhere, industry dynamism is sapped, with some structural issues remaining in a number of industries (textiles, paper, printing, etc.) Forward momentum depends on demand for consumer goods, which ultimately drives factory output. But weakening foreign demand presents challenges for the manufacturing sectors. Unfortunately, petrochemicals are early on in supply chain, and exports to Europe have evaporated at present. Balance sheets are strong, and lower input costs have benefited manufacturers. Nonetheless, an uncertain business and regulatory environment is constraining business optimism (and hiring). The softening of the manufacturing recovery will likely dampen chemical demand. Inventories can mean the difference between a slowdown and a recession. In general, lean inventories along the supply chain support future production gains. Chemical inventories in the US are relatively balanced, although some destocking emerged during the fourth quarter. With the exception of Europe, chemical exports continue to grow, driven by a favorable oil-to-gas price ratio. The consensus is that US chemical output is expected to improve during 2012 and further gain through 2016. As a result, petrochemicals and derivatives, following the 6.9% gain in volumes during 2010 and essentially flat performance in 2011, are expected to have a 1% gain in 2012 before improving to 3.3% by mid-decade. Strong growth is expected in synthetic rubber and later in petrochemicals, organic derivatives and plastic resins as export markets revive. For the long term, domestic petrochemiHYDROCARBON PROCESSING MAY 2012

I 73

2012 PETROCHEMICAL OUTLOOK TABLE 1. US petrochemistry outlook 2007








































Synthetic rubber











Man-made fibers











Total petrochemicals and derivatives, % change in production volume Bulk petrochemicals and organics Plastic resins

from NG liquids. Over eight years ago, the US Gulf Coast (USGC) petrochemicals 10 were being written off by many industry observers. The industry was in a position 5 near the top of the cost curve and it was in 0 a worse position than Western Europe and Northeast Asia. A pending wave of capacity -5 in the Middle East (ME) only added to dour sentiments. With the revolution in shale -10 gas, however, this has changed radically (and GDP Overall industrial production for the better). By 2011, the USGC cost -15 Petrochemicals and derivatives position had so improved that this region -20 now follows the ME. Moreover, ethane ’99 ’00 ’01 ’02 ’03 ’04 ’05 ’06 ’07 ’08 ’09 ’10 ’11 ’12 ’13 ’14 ’15 ’16 supplies are tightening in the ME and are constrained. The era of low-cost feedstocks FIG. 1. Trends in US GDP, total industrial production and petrochemicals production growth, in the ME may end soon. % change in volume. As a rough rule of thumb, when the ratio of the Brent oil price divided by the Henry cal growth is expected to expand at a pace exceeding that of the Hub price for NG is above a band between overall US economy. 6:1 and 7:1, then the competitiveness of (US) Gulf Coast-based Strong gains in capital spending by US chemistry are expected petrochemicals and derivatives such as plastic resins vs. other major over the next several years, stemming from new investment in petproducing regions is enhanced. Other factors such as co-product rochemicals and derivatives arising from shale gas developments. prices, exchange rates and capacity utilization have played a role The need to add capacity and to improve operating efficiencies in competitiveness as well. As a result of shale gas, this important will play a role as well. This emerging shale gas story is noteworthy. ratio has been above 7:1 for several years. The ratio of oil prices to Access to vast, new supplies of natural gas (NG) from previNG has recently been around 40:1, and it is very favorable for US ously untapped shale deposits is one of the most exciting domescompetitiveness and exports of petrochemicals, plastics and other tic energy developments of the past 50 years. After years of high, derivatives. This condition has fostered strong gains in US plastic volatile NG prices, the new economics of shale gas are a “game exports. The only reason that thermoplastics exports have stabichanger.” Low NG prices are creating a competitive advantage lized has been the crisis in Europe and weakness in that region’s for US manufacturers, thus leading to greater investment and economy; all have dampened US exports. In addition, capacity industry growth. US manufacturers use NG as fuel and power constraints have occurred. Due to rising domestic demand for for a wide variety of chemical processing facilities to produce a plastic resins in North America, some overseas customers need to vast variety of manufactured goods. The relatively low NG price source elsewhere, as the ability to export is hindered somewhat. provides US manufacturers an advantage over many competitors In the US, shale gas has been a game changer in the domestic around the world. Growth in domestic shale gas production is NG markets and has improved the competitiveness of the US helping to reduce US NG prices and is creating more stable NG petrochemical sector, resulting in boosting exports. The benefits supplies for fuel and power. As economic theory teaches and are being felt beyond petrochemicals and now include fertilizers history shows, a reduction in the cost of a factor input, such and other downstream products. Capital investment in North as NG, leads to renewed competitiveness and a positive supply America is being reconsidered, and a slew of projects have been response. This, in turn, leads to new private-sector investment, announced. For petrochemicals alone, the new project investwhich fosters job creation. ments could total $20 billion with an additional $23 billion likely For the petrochemical industry, the stakes are even higher. In for other downstream and specialty products. With an eventual addition to using NG for fuel and power, this industry also uses recovery in Europe’s economy, along with the startup of some of NG as a raw material or feedstock. In the US, it is historically these projects and sustained competitiveness, the medium- and cheaper to crack ethane, propane and other NG liquids than to long-term outlook for US production and exports of petrochemicrack naphtha (from oil refining)—the primary petrochemical cals and plastic resins is quite good, with the US beginning to feedstock in Western Europe and Northeast Asia. The steamcapture market share in global markets. In turn, this will generate cracking process using ethane is simpler, and the hardware is less new business and, importantly, jobs, and it will play a large role expensive. Nearly 90% of North American ethylene is now derived in the resurgence of US manufacturing. HP 15


I MAY 2012

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Control moisture problems in slurry-based polyolefin operations Fouling and coking inhibit adsorbent-bed efficiencies S. MITRA, University of Newcastle, New South Wales, Australia


roper moisture removal from the polymerization-reaction medium is the key to successfully operating a high-density polyethylene (HDPE) plant designed based on low-pressure, slurry-process technology. Due to the low-pressure operation and no catalyst recovery system, the Ziegler-Natta catalyst is highly sensitive to moisture in the reaction medium. The reaction rate can be terminated due to a breakdown of the catalyst. n-Hexane serves as the reaction medium in this HDPE process; it is recycled through a comprehensive purification process that reduces water content to 10 ppm–20 ppm. Continuous operation of the mother-liquor purification unit is crucial. Too often, this purification unit is fouled, and its efficiency declines, thus creating a bottleneck. To identify the root causes of this problem, used and fresh adsorbent samples were analyzed. Significant pore blockage was observed in the used sample due to adsorption of hydrocarbons and aluminum. A detailed investigation identified several operational issues that fostered fouling.

mother-liquor hexane is separated in the decanter and sent to the purification unit before recycling. Additives are mixed with the PE powder to control optical properties and then is processed in a twin-screw extruder to produce PE pellets. Mother-liquor purification. Fig. 2 shows the unit process

flow sequence. The mother liquor is collected from various plant sources and stored in a tank. It contains hexane and minor quantities of ethylene, ethane, propylene, wax and active aluminum alkyls. The butene concentration may vary up to 1 wt% and 3 wt % for wax concentration. Wax is an oligomer produced mostly from butane and primarily used in pipe-grade applications. For purification purposes, the mother liquor is pumped to the preheater and heated to 55°C–60°C. The mother liquor is sent to the evaporator, where it is vaporized at 2 barg–2.3 barg and 105°C–110°C. The hexane vapor from the evaporator/separator is distributed to several points for energy-recovery purposes. The hexane condensates are collected and fed to the distillation column. This column separates ethylene, ethane, butane, ethylene and propylene from the hexane. The column pressure is set at 0.3

Catalyst and co-catalyst

Process description. The HDPE process under investigation is a well-known technology and it uses a Ziegler-Natta catalyst. The final products have a density range of 0.94 g/cc to 0.96 g/cc. HDPE is used To flare for various blow molding, film and pipegrade products. n-Hexane is used both as Ethylene a polymerization reaction medium and a Offgas handling unit H2 butene-1 cooling medium to absorb reaction-generated heat. This PE process is highly exoImpure mother Separation liquor to tank farm thermic with -952 kcal/kmol of ethylene of slurry by Polymerization centrifugal CSTR train produced. Polyethylene decantation This HDPE production facility has four product pellets Mother different sections, e.g., a polymerizationCooling Cooling liquor reaction unit, a powder-separation unit, a water in water out purification Slurry drying Powder powder-processing unit and a solvent-recovunit by fluidized storage and ery unit. Polymerization of ethylene monobed drying pelletization mer with butane-1 comonomer takes place Pure hexane Impure mother liquor recycled in continuous stirred-tank reactors (CSTRs) Catalyst Byproduct to reactor in the presence of Ziegler-Natta catalyst susTank farm preparation wax Purified hexane to tank farm pended in n-hexane. The fine-powder PE unit is produced in the reaction medium under tight temperature control and forms a slurry. Byproduct waste hexane Waste hexane The slurry is cooled. The wet PE powder handling unit is separated via a centrifugal decanter, dried FIG. 1 Process flow diagram for the low-pressure slurry-process HDPE plant. in a fluidized bed and sent to the powderprocessing section for pelletization. The HYDROCARBON PROCESSING MAY 2012

I 77

PETROCHEMICAL DEVELOPMENTS barg with a bottom temperature of 82°C and a top temperature of 70°C. Distilled hexane is drawn off from the bottom of the column and sent to the adsorbing tower and feed cooler for final purification purposes. Wax is collected from the bottom of the evaporator and sent to the wax-distillation vessel for further hexane recovery. The amount of wax generated depends on the product grade. A batch process distills hexane in the wax evaporator; the hexane is condensed and collected. The recovered hexane is pumped back to the mother-liquor tank. Offgases from the polymerization reactors are sent to the butene recovery column and scrubbed with cold hexane and mother-liquor hexane in the top and bottom bed, respectively. Scrubbed butene dissolved in the mother liquor is sent to adsorption column to remove moisture. The moisture-free mother liquid is sent to a storage tank. In addition to the polymerization reactor, purified hexane is also used to prepare catalyst and is later recovered as waste hexane.

nonpolar molecules that can fit into their specific framework. The adsorption process is exothermic.

Recovered hexane

Analysis of the adsorbent. Often, adsorption-tower fouling is diagnosed by reduced power consumption of the feed pumps. On one occasion, the two adsorption towers (C-312A, B), connected to the distillation column C-311 and butane-recovery column C-332B, were shut down. However, the columns’ feed pumps continued operating to keep the purification unit running. Later, these columns were severely fouled with PE powder, wax and coke. Adsorbent pellets collected from the three adsorption columns were analyzed. From experimental results, the used pellets had significant loss of water adsorption capacity. Mercury porosimetry analysis revealed that blocked pores were responsible for the adsorption loss. The root cause for the blocked pores was coke deposition and/or adsorption of residual heavy hydrocarbons from the recycled mother liquor. High surface-sensitive analytical techniques— electron spectroscopy for chemical analysis (ESCA) and energy The adsorbent. Adsorbent pellets are made of zeolite (aludispersive X-ray analysis (EDXA)—were used to determine how mino-silicate) mesoporous-type material; the zeolites have a pore the adsorbent was being fouled. radius in the range from 20°A–50°A. These crystalline materials Results showed that heavy hydrocarbons (heavier than n-hexwith very small pore sizes, have a large surface area, up to 1,000 ane) and aluminum were adsorbing onto the pellets’ surface, thus m2/gm. The building blocks of the zeolites are tetrahedras that consist of four oxygen anions and one centrally positioned silicon affecting the availability of the silica surface. Lower availability of or aluminum cation. These zeolites are classified according to the active sites was the primary cause for declining adsorption capactetrahedral frameworks. ity. Fig. 3 is a water-adsorption isotherm for all used adsorbent The aluminum and silicon atoms are positioned at the juncsamples, as well as the fresh adsorbent pellets at room temperature. tions while the oxygen atoms form bridges between the tetraThe fresh adsorbent pellets show a linear relationship of loadhedras. The difference in the electro-chemical charges between ing. However, pellets collected from the top bed of C-312A the aluminum and silicon atoms result in a non-compensated demonstrate less linearity, and, thus, indicate bed saturation. negative charge. The balance is restored by metal cations occupyHexane adsorption of the top bed of C-312B shows comparaing preferred positions. Due to the strong local electrical dipole tively more linearity and indicates less saturation. In contrast, moment of the lattice framework, the zeolites adsorb all polar and the bottom bed of C-312A shows less linearity than the top bed; more saturation is present at the bottom of this adsorption bed. The top bed (C-332 Offgases Fresh hexane makeup A) shows slightly less linearity than the from road tanker C-312A top bed, thus indicating more satMother liquor to tank farm Polymerization CSTR train uration. The different saturation profiles R121/122/123 Various destinations indicate that more saturation occurs at in plant for heat the bottom of the column than at the top. Tank farm recovery Condensate T-411,412,413 A mass-transfer zone thus exists from the Offgas to flare collection bottom to the top of the adsorption colCondenser Vapor E-313 umns. With the exception of fresh adsorbent pellets, used pellets typically show Butene Preheater Distillation Distillation Feed nonlinear isotherms. Such trends indicate recovery E-311 and column feed vessel pump column evaporatorvarying degrees of saturation. C-311 V-312 P-311 C-331 separator Fig. 4 illustrates a comparison of merV-311/E-312 cury intrusion for fresh and used adsorFeed cooler bent pellets (pore diameter 45°A). Mercury E-315 Wax treatment section intrusion, measured in ml/g, is greater for V-321 V-342 V-344 fresh pellets, so blocked pores are present. E-322 E341A Feed pump Feed pump However, mercury intrusion decreases as P-332 P-312 indicated from the pellets collected from Wax out the C-312A top bed and further decreases Adsorption Adsorption in pellets from the C-312A bottom bed. tower tower C-312A/B/C C-332A/B The large number of blocked pores in the C-312A bottom bed indicates that more saturation occurred as compared to the Purified hexane to tank farm top bed. This analysis confirms the varying FIG. 2 Flow diagram of the mother-liquor purification process unit that removes moisture. degrees of bed saturation as established by water-adsorption isotherms (Fig. 3). 78

I MAY 2012

Select 92 at

PETROCHEMICAL DEVELOPMENTS Fouling problem. From the experimental observations, sev-

eral inferences could be drawn: 1. The C-312A bottom adsorbent lost its capacity by about 70%, whereas the C-312A top and C-332A adsorbents had lost only 60% capacity, and C-312B top bed lost only 40%, as shown in Fig. 3. 2. These trends are further confirmed in column C-312A with mercury porosimetry data. 3. High-sensitive analytical techniques also show that there is ingress of heavy hydrocarbons and aluminum on used adsorbent pellets. Therefore, the service life and performance of adsorbent pellets are affected by high concentrations of hydrocarbons and aluminum. To identify these sources, all process streams entering and leaving the purification plant were reviewed carefully for root cause analysis (RCA). Sources of aluminum ingress. Higher flowrates of the

co-catalyst/activator, tri-ethyl aluminum (TEAL), are used to arrest moisture ingression. During the THB-catalyst run for highmolecular weight products, more TEAL is injected, along with the catalyst. THB catalyst is very susceptible to moisture. This practice increases the active aluminum concentration in the mother liquor.

For reaction safety, the active aluminum concentration is maintained at 0.5 millimole/l. Considering the maximum mother-liquor flow is approximately 15 metric ton (mton)/hr—the same as fresh hexane flow during a pipe-grade run at steady state of 20 mton/ hr plant load—the rate of ingress of the active aluminum into the purification system is (0.5  15,000 / 0.68) / 1,000 = 11 mole/hr. A mass balance of TEAL, considering 20 mton/hr of distillation rate indicates active aluminum concentration at the inlet of adsorption column is [11 / (20,000/0.68)]  1,000 = 0.374 millimole/l. With this much active aluminum present in the mother liquor, the moisture content can reach 35 ppm as found at the inlet of the C-312A/B adsorption columns. This was confirmed by regular moisture samples taken from the discharge of pump P-312. A small amount of moisture cannot be quelled by injecting TEAL. The reaction rate becomes negligible at very low moisture levels. Options. Since low moisture levels in the mother liquor could not be reduced by TEAL injections and an overdose of TEAL blocks adsorbent pores, TEAL additions must be controlled, especially in the THB catalyst-grade run. Overdosing TEAL can occur due to an unreliable active-aluminum analyzer reading. This essential analytical instrument can malfunction, and its reliability must improve to prevent excess TEAL dosing.


25 Moisture content, wt%

Heavy-hydrocarbon sources. To identify heavy-hydrocarbon sources, mother-liquor samples were taken from different locations within the purification unit. The samples were analyzed using gas chromatography techniques. Table 1 summarizes the compositions of the mother liquor samples. From Table 1, the distilled hexane (tank T-411), which is a fresh hexane source, contained some oligomers and heavy compounds. After analyzing the other streams for the mother liquor, it was noted that heavy hydrocarbons entered the process through the recovered hexane from wax distillation.

Fresh C-332A top bed C-312A top bed C-312A bottom bed C-312B top bed




5 0 0

FIG. 3



30 40 50 Relative humidity, %




Water-adsorption isotherms indicate the reduced adsorption capacity of the adsorbent pellets collected from different columns.

Incremental intrusion, ml/g

0.025 0.020 0.015 0.010 0.005 0.000 1e+03

FIG. 4


1e+02 Radius, °A


Pore size distribution of C-312A and fresh pellet – Fresh pellets > C-312 top > C-312A bottom. Red line: adsorbent pellets from C-312A bottom; Black line: adsorbent pellet from tower C-312A top and Blue line: Fresh adsorbent pellets.

I MAY 2012

Recommendations. Hexane forms an azeotropic mixture with water at 67°C during wax distillation under atmospheric conditions. As per the facility’s practice, wax distillation is considered complete at 95°C; the wax is drained from the vessel. The heavy compounds, present in the mother liquor, indicate that wax distillation is done at a higher temperature than necessary. The waxdraining temperature should be a temperature in which the least amount of heavy compounds is transferred to the distilled mother liquor. During distillation, the outlet for condensers E-322 and E-341A can be sampled to detect heavy hydrocarbons at different temperature intervals until the wax is drained. Lighter oligomers, e.g., 3-Me-2 butene-1-ol, 2,2 dimethyl C4, 2,3 dimethyl C4 + 2 Me C5, may boil along with the n-hexane since they have the same molecular weight. Other heavy compounds, e.g., vinyl cyclopentane, 3-Hexene-1-ol and me-hexane, have higher molecular weights than n-hexane. If these compounds are present, then a lower wax distillation temperature is recommended. If n-hexane is completely boiled off as an azeotrope with water or if the temperature at which all the n-hexane is completely distilled out, then it is recommended to divert the outlet from the condensers E-322/E-341A to a wastehexane handling system to collect all heavy compounds. This can be achieved by installing a temperature-control valve with input from the wax distillation vessel’s bottom temperature. During replacement of adsorbent pellets in C-312C, the sieves on the bottom bed were observed to be heavily fouled. PE powder and hard black pieces were clogging the sieves. The formation of hard materials on the sieves may be attributed to coking of wax/


Distillation in wax vessel. Dur-

ing the plant shutdown, reactors and the suspension receiver are emptied into the wax distillation vessel V-342 to minimize inventory. The slurry transferred to V-342 is distilled with live steam. Since there are no high-level indicators in the vessel, filling is done manually. There is always the possibility of over-filling the vessel. During distillation, if the live steam flowrate is too high, powder and wax can be entrained along with vapor that is collected in the distilled mother-liquor vessel, V-344, through condenser E-341/E-341A. During a recent event for condenser E-341/E-341A, fouling along with choking in pump P-342’s discharge line proved powder and wax carryover possibility. Since discharge from pump P-342 (fed from vessel V-344) goes directly to tank T-412, this can support the root cause for powder and wax accumulation in tank T-412. A high-level indicator is

Provision of woven strainer/impingement baffles

Wax distillation vessel V-321

Wax drain

Hexane vapor


Wax distillation vessel V-342

Waste hexane from catalyst preparation vessel

Waste hexane separation vessel V-314

Waste hexane storage tank V-343

Distilled mother liquor collection vessel V-344


trifugal decanter separates polymer powder from the mother liquor. Improper separation can entrain powder in the mother liquor. After separation, the mother liquor is sent to a feed vessel, V205. The mother liquor is fed into the reactors, and the remainder is sent to a storage tank, T-412. Periodic sampling of the mother liquor can detect polymer powder at levels reaching 0.15 wt%. Because the process is a closed-loop system, powder can accumulate in storage tank T-412 due to poor separation. This powder can potentially choke the adsorption columns. Powder entrainment in the mother liquor occurs when the polymer powder has a low bulk density, which depends on processing conditions. Another factor is adequate residence time, which is determined by decanter loading. The slurry-feed valve of the decanter should open gradually to increase retention time and reduce powder carryover into the Hexane mother liquor. Adjusting the overflow weir vapor of the decanter can increase retention time.

Provision of high-level switch

Wax drain TC

Condensed hexane

Powder carryover into the mother liquor. The cen-


Regeneration of adsorption column follows a cycle of heating with air, nitrogen and steam. Coke, if present, is oxidized by air. If the oxidization process is properly completed, then no coke should remain. As exposure to higher temperatures reduces the service life of the adsorbent pellets, regeneration durations must be extended to ensure complete oxidation of coke content. Carbon monoxide (CO) and carbon dioxide (CO2) analyzers indicate oxidation level of the carbon content. These analytical instruments are often not properly functioning. Periodic calibration of the CO and CO2 analyzers is necessary.

Evaporation step. The mother liquor is fed into separator V-311. By thermosiphoning, it is sent to the tube side of evaporator E-312. The level in separator V-311 is controlled by injecting steam on the shell side of the evaporator E-312. The evaporator performs well at level ranges of 20%–25%. If the level decreases, then disengagement space above the liquid level increases and causes sudden vapor expansion. Such vapor expansion causes higher velocity, thus entraining wax and powder downstream with accumulation in the adsorption column. Maintaining proper level control of the evaporator/separator has a great impact on the adsorption-column availability. This is very crucial during pipegrade polymer runs, which generate a huge amount of byproduct wax. Jacket pressure of evaporator E-312 in the pipe-grade run can increase over 3 barg (usually 1.5–2 barg), thus indicating a high concentration of wax. If the evaporator level is not properly maintained, it may cause wax carryover with the vapor. Evaporator-level control is the key to avoiding wax and powder carryover, along with hexane vapor. Installing an inline strainer on the vapor line to condenser E-313 can prevent this carryover. Field observation shows that pump P-311 and P-312 suctions were fouled on several occasions with waxy materials. A strainer is required at the suction of both pumps, along with a current monitor that is tied to the distributed-control system.


Inadequate regeneration of adsorption column.

needed for vessel V-342; to prevent excess slurry loading. During distillation, control of the dosing steam could prevent powder carryover with the steam. A woven strainer or impingement baffles installed the vapor line would mitigate powder entrainment further downstream (Fig. 5).

Condensed hexane

heavy compounds at high temperatures during regeneration. To eliminate wax carryover, woven strainers or impingement baffles can be installed on the wax-distillation-vessel vapor lines. For further safety, suction strainers can be installed on the mother-liquor transfer pump (P-342) to prevent wax carryover to the storage tank (T-412). All of these suggested changes are shown in Fig. 5.

Provision of temperature controllers

Pump P-342

Mother liquor to tank T-412

Provision of suction strainer FIG. 5

Flow chart of the suggested changes in the wax-distillation unit to prevent ingress of powder and heavy hydrocarbons into mother liquor. Dashed line blocks indicate the waste-hexane unit. HYDROCARBON PROCESSING MAY 2012

I 81

PETROCHEMICAL DEVELOPMENTS TABLE 1. Composition analysis of mother-liquor samples collected from various stages of the purification process— heavier (than n-hexane) compounds indicated in bold fonts1 Compound

Molecular weight, MW

C-312B inlet, wt%

C-312B outlet, wt%

Wax distilled hexane product, wt%

Recycled distilled hexane product in tank T-411, wt%






C3 + C4 Cyclo-methyl C4






2,2-dimethyl C4






2,3-dimethyl C4 + 2-Me C5






3-Me C5































































Vinyl cyclopentane









1-Hexene/allyl vinyl ether UI

UI (t) 3-hexene-1-ol




























1.69 0.007

Gas chromatograph composition analysis carried out in Restek 5 capillary column


ND = not detected

Monitoring saturation levels in adsorption column.

There are many online moisture analyzers commercially available based on microwave, near infrared, radio frequency, conductance and capacitance. A novel online monitoring method for adsorption column saturation/regeneration cycles has been reported.1 The bedsaturation measurement uses the changing electrical resistance of the packed-bed adsorbents to indicate adsorption and desorption conditions. This change can be measured reliably and is reproducible. For example, the two systems studied online in real time are methyl chloride (MeCl) adsorption on zeolite-molecular sieve and water vapor adsorption on basic alumina. The sequential change in electrical readings at localized points within the column indicated the movement of the adsorption front, tracking the onset of breakthrough. The electrical readings returned to their original values upon desorption, and the results were reproducible. Concurrently with the electrical measurements, the effluent gas of the MeCl/ zeolite-molecular-sieve system was monitored for MeCl, using an online gas chromatograph. The resistance change of the zeolitemolecular sieve was found to be proportional to the square root of the amount of MeCl adsorbed. Installing this type of analytical instrument on the adsorption column could correctly provide saturation status, which would help in determining column changeover.


UI = unidentified

of the adsorbent pellets. Adsorbent service life is affected by the ingress of active aluminum, heavy hydrocarbons and oligomers. To optimize operations, the adsorption tower should be in operation until it reaches the end of the breakthrough curve. However, without a moisture analyzer and a stringent low-moisture requirement in the purified hexane, a conservative changeover practice of passing 8,000 m3 of distilled hexane through the adsorption column is possible. Under this practice, a column stays in operation, considering 20 mton/hr of distillation load for (8,000  0.68 / 20) = 272 hrs (11.33 days). This duration can be increased once the breakthrough curve of the adsorption column is established with a reliable moisture analyzer. This would reduce the number of regeneration cycles, which directly affect the adsorbent service life. It is expected that the service life of adsorbent pellets could be significantly enhanced once ingress of fouling materials is prevented and a reliable moisture analyzer system is incorporated at the outlet of the adsorption column. HP 1

LITERATURE CITED Vecchio Del, D. N., et al., “New method for monitoring adsorption column saturation and regeneration II online measurement,” Chemical Engineering Science.

Subhasish Mitra is a research scholar at University of Newcastle, NSW, Aus-

Options. A persistent and frequent fouling of the mother liquor

purification plant of low-pressure slurry-based HDPE plant is a problem. Purified hexane in the polymerization reactors is a processing must. Availability of the adsorption columns to control the moisture content in purified hexane is limited by the service life 82

I MAY 2012

tralia. Prior to joining the PhD program, he was a process engineer with over seven years of experience in process development, troubleshooting and process design in nuclear, petrochemicals, and oil and gas industries. He holds an M.Tech degree in chemical engineering from the Indian Institute of Technology in Kanpur and a B.Tech degree in chemical engineering from Vidyasagar University in India. Mr. Mitra is an associate member of the Indian Institute of Chemical Engineers.

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SEVERE JET FIRES AND VAPOR EXPLOSIONS Treatment options and the limitations of the existing guidance are discussed I. BRADLEY, International Paint, Felling, UK

Jet fires are pressurized releases of hydrocarbons that result in impinging flames with significant momentum. The potential for jet fire exists wherever storage, process equipment or pipe work contains flammable gas or liquid/gas (two-phase) mixtures at pressures approximately 2 bar or greater. At such pressures, choked flow occurs and the gas, flashing liquid or two-phase flow reaches sonic velocities. Jet fires can, therefore, have a significant erosive force, unlike hydrocarbon pool fires. Jet fire characteristics vary significantly depending on a number of factors, such as the type of jet fire previously described and the mass release rate (which itself depends on the pressure and hole shape/size). The potential flame lengths involved mean that the heat flux to steel can be significant within a large fire scenario envelope. Fabig technical note 111 gives the following benchmark flame lengths from test data on various size releases: • 3 kg/s gives a 22-meter (m) flame • 10 kg/s gives a 34-m flame • 50 kg/s gives a 50-m flame. Table 1 is adapted from the Fabig technical note and gives an estimate of typical heat fluxes to objects engulfed by a jet fire. These are considered conservative estimates of the initial heat flux, but it can clearly be seen that the values are significantly higher than those expected in hydrocarbon pool fires. Gas jet fires generally have higher exit velocities than flashing liquid jet fires and so produce less buoyant flames with greater horizontal reach. The fraction of heat radiated from gas jet fires is lower than that of liquid jet fires, as well-ventilated gas flames typically burn cleaner, producing less soot, than liquid jet flames. The majority of radiation emitted by gas flames is from water and carbon dioxide. Flashing liquid jet fires generally have higher release rates for a given aperture size, but the lower exit velocities result in less air entrainment. This reduces the combustion efficiency and, combined with the higher carbon content in liquids, produces sooty flames that radiate more heat to their surroundings. Two-phase jet fires are generally worst case scenarios, as they can combine the worst aspects of both gas and flashing-liquid jet fires, which are high exit velocities and highly radiant, sooty flames.2

API 2218 and UL1709 limitations. API 2218 (second edition) clearly states within its scope that it does not address jet fires. Jet fires are commented on in Appendix C of the document, but at the time of its writing, there was no standard UL, ASTM or ISO test procedure. The Appendix C comments are now outdated, due to publication in 2007 of ISO 22899-1: Determination of the resistance to jet fires of passive fire protection materials. This standard provides, for the first time, an internationally recognized test procedure suitable as a basis for assessment and certification. A third edition of API 2218 is in draft, and within the latest version it does recognize ISO 22899-1; it actually goes so far as stating it is accepted as the preferred method of fire test. The recommended test procedure for pool fires within API 2218’s second edition (and upcoming third edition) is UL 1709. It is important

not to assume that a UL 1709 listing provides information on the ability of a material to withstand jet fire. Furnace-based pool fire testing cannot replicate the severe heat flux and erosion conditions found in jet fires. The key differences between the two fire test procedures are compared in simplistic terms within Table 2. Such differences make it necessary to consider alternative test procedures, capable of reproducing the conditions found within jet fires.

Jet fire testing. Jet fire testing can fall into three categories, generally characterized by the relative size of the jet flame: large, medium or small. All tests use a directional jet flame impacting on a test specimen to simulate the erosive and rapid heat-rise conditions within a jet fire, with each test having its advantages and disadvantages. The large-scale tests (Fig. 1) replicate realistic release rates by using the types of fuels that may be expected in real release scenarios, such as crude oil or natural gas. A significant number of large-scale jet fire tests have been conducted by industry and academia, and they together form the basis for the majority of current knowledge on jet fire behavior. Despite the obvious benefit of being the most accurate type of test, the ability for fire protection manufacturers to perform such testing was limited due to the extreme cost. An economic, yet consistent and representative, test was required for industry to use for fire protection evaluation. The small-scale tests, commonly known as torch tests, do involve an impinging flame, but the release rates, temperatures, erosive forces and heat fluxes are significantly less than those experienced in large-scale realistic jet fire testing. Examples of small-scale torch tests include the test procedures in NFPA 58 and NFPA 290. Materials tested and certified to these standards demonstrate they perform under the specific conditions described within the test procedure; however, the materials should not be considered as having been characterized for resistance against realistic jet fires on the basis of such tests.

TABLE 1. Indicative jet fire heat fluxes Mass release rate, kg/s 0.1 1 10 > 30 Gas jet fire initial total heat flux, kW/m2 Two-phase jet fire initial total heat flux,










FIG. 1. Large-scale jet fire test. HYDROCARBON PROCESSING




Medium-scale tests are the recommended method of assessing the resistance to jet fire of passive fire protection (PFP) materials. Extensive work has been undertaken comparing both the erosive forces and the heat fluxes obtained in the medium-scale tests with those experienced in large-scale tests. The results have shown the tests to be representative of the conditions found in the majority of potential jet fire releases, attesting to the suitability of the test procedure.3 ISO 22899-1 is the preferred medium-scale test, with suitable alternatives being OTI 95-634 or the SINTEF high-heat-flux jet fire test procedure. Figs. 2 and 3 show the ISO22899-1 test setup. It consists of a 1.5 m × 1.5 m × 0.5 m box with a central web or tube as required. Propane is the fuel used, released from the nozzle visible in Fig. 2. Eighteen thermocouples are used to measure the temperature of the steel, as visible in Fig. 3 from the rear of the specimen.

TABLE 2. Comparison of key test standard parameters Parameter

UL 1709

ISO 22899-1


< 250 to > 300

Degree of erosive force


Relatively high

Specimens tested

W10x49 “I-shape” column

Web, tube or box

Failure temperature


As necessary

Heat flux,


FIG. 2. The front of the ISO test specimen.

Specifying ISO 22899-1. In order to ensure protection against jet fires, it is recommended that the hydrocarbon extraction and processing industries make certification to ISO 22899-1 a requirement when specifying jet fire protection. The benefits of specifying the ISO standard are: • An internationally recognized and accepted test procedure • Standardized method of assessment to ensure a level playing field between materials • Takes limiting steel temperature into account • Allows type approval certification from all classification societies, not reliant on technical reports • Type approval ensures that products are part of ongoing surveillance and factory audit schemes. To ensure the correct sizing of PFP against jet fires, operators should ensure that they consider and provide to the PFP manufacturer the following: • Fire scenario (pool, jet or combination) • Fire durations (including separate pool/jet durations, if applicable) • Heat flux • Limiting steel temperature • Steel dimensions. Vessels and BLEVEs. Boiling liquid expanding vapor explosions (BLEVEs) are potentially catastrophic incidents that can occur when fire engulfs storage or process vessels containing volatile liquids. Simultaneous heating of the contents and weakening of the shell cause the internal pressure to increase to the point where the stress on the steel is greater than the yield stress. The consequent rupture of the shell can result in an explosion with far-reaching consequences, as the full energy content of the vessel inventory is released almost instantaneously (as opposed to pool or jet fires where the energy release is often over a substantial period of time). If the pressure release valve or blowdown system is not capable of reducing the pressure to a point where rupture cannot occur, the resulting risk to life and property can be extremely high. It should be noted that pressure relieving valves alone are generally insufficient to prevent a BLEVE of a vessel exposed to jet fire. Some form of active or passive protection is usually necessary to delay the temperature rise and give the blowdown system or PRV time to work. The occurrence of a jet fire is particularly dangerous around process and storage vessels, as the possibility for escalation of the incident and the domino effect is high. A study of 84 historical jet fire events undertaken by Catalonia University showed that 56% of these caused a subsequent explosion or BLEVE.4 One such example was from 1984 in Mexico City, when the escalation of an incident led to multiple BLEVEs and an overall loss of more than 500 lives and the evacuation of 200,000 people. During this incident, one of the BLEVEs occurred within 69 seconds of an impinging jet fire commencing.4 API fire protection guidance. Fireproofing of liquefied petroleum gas

FIG. 3. The rear of the ISO test specimen. T-86


(LPG) vessels is covered by the API guidance documents 2510 and 2510A. The recommended practice is to fireproof the supports in accordance with UL 1709 testing and use an active (water deluge) system on the sphere body for protection against pool fires. For jet fires, fixed water monitors capable of delivering sufficient water to the impingement point of the jet have been shown to be effective, so long as the water application rates listed in Table 3 are achieved.5 Water deluge systems have been shown to be effective against vessels engulfed in hydrocarbon pool fires, limiting the shell temperature to no more than 120°C by maintaining a water film on the surface of the vessel. In instances of jet fire, research has shown that water application rates of a typical deluge system (10–12 l/m2/min) cannot be relied


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TERMINALS AND STORAGE TABLE 3. Water application rates from API 2510A Fire exposure

Application rate

Exposure to radiant heat (no direct flame impingement)

5 l/min/m2

Direct flame impingement

5-12.5 l/min/m2

Jet fire impingement

12,500–25,000 l/min

upon to form a continuous water film on the surface of the vessel. At the point of impact, the force of the jet can result in a localized dry spot, leading to failure of the vessel and a BLEVE. Fixed water monitors delivering significantly higher water rates have been shown to be effective against jet fires; however, both water deluge systems and fixed water monitors have a number of disadvantages. The primary one is the potential for the system to be inactive during a fire due to corrosion or maintenance or damage from a vapor cloud explosion possibly preceding a fire. Other potential problems include delays in operation, if the fire is shielded from the detector, risk of danger to an operator if they are manually controlled (in the case of water monitors) or the potential for corrosion of the vessel and the legs/saddles due to regular testing of the deluge system. For these reasons, operators routinely consider installing PFPs to vessel bodies as well as supports in areas at risk of jet fire.

Specifying vessel fire protection. Having decided to specify passive fire protection to a vessel shell, operators quickly encounter a problem: there is currently no internationally recognized test standard for PFP to vessels. Although a number of guidance documents (such as those published by API) offer advice on what types or what duration of protection to apply, there is limited information available on how tests should be performed to prove PFP fire resistance. ISO TC92 SC2 is currently working on a test standard that should solve this problem; however, this will not provide a solution over the next couple of years. Having no internationally recognized test standard makes it currently impossible to get type approval certification of fireproofing materials for vessels, meaning the sizing of protection requirements is usually left to manufacturers themselves, done on the basis of their own testing and assessment. The lack of a standardized test makes it very difficult for operators to compare fireproofing materials, and leaves them in the position of having to decide for themselves, which company’s recommendations are correct and suitable. As a minimum, operators should insist on a product that has undergone testing on an actual pressure vessel containing LPG or other suitable flammable inventory. Testing conducted solely on plates, bulkheads or structural sections should be avoided, although such data may be used to assist in characterizing the performance of the material. Examples of bad practice are: • Treating the vessel as a structural section and taking the thickness directly from existing type approvals without further validation • Using a bulkhead or a deck certificate of similar rating (e.g. H120) • Treating the vessel as plate and using thicknesses derived from plate testing (without further validation). To ensure the correct specification of any PFP, the operator should consider and provide to the manufacturer the following: • Fire scenario (pool, jet or combination) • Failure temperature of the vessel • Steel shell material, thickness and vessel diameter T-88


• Vessel inventory, typical fill level and expected minimum fill level during service • Pressure-relieving valve type and settings.

Additional considerations. In addition to ensuring that the product is correctly tested and the thickness correctly calculated, operators should take into consideration a number of factors that affect the ability of a PFP material to perform its function throughout the life cycle of the vessel or structural steel. Such factors include, but are not limited to: • The ability of the material to withstand mechanical stresses and deformations (e.g., due to filling of a vessel, transportation of a steel section or stresses induced due to thermal expansion as a result of nonuniform heating) • The ability of the material to withstand the environmental conditions (including those during testing of deluge systems). Norsok M501-rev 5 and UL 1709 exterior listing test procedures are recommended methods of testing for fire protection materials • The blast resistance of the PFP material. Be aware. Despite the consequences of jet fires being potentially far more severe than hydrocarbon pool fires, API 2218 second edition does not provide sufficient guidance on how to specify passive fire protection to mitigate against these hazards. Although there are a number of test procedures available to test against torch or jet fires, past research has shown that the medium-scale jet fire test methods are the most suitable for characterizing the ability of PFP to resist jet fire. The standard ISO 22899-1 is the preferred method of test (as is likely to be stated within API 2218 third edition), as it brings a number of benefits including standardized methods of assessment, the consideration of steel failure temperature and type approval certification. When applying PFP to vessels, operators should be aware of the lack of test standards and the current impossibility of referring to type approved certification for sizing of the PFP. They should seek guidance from reputable manufacturers that have conducted tests on actual pressure vessels, avoiding thicknesses provided on the basis of unrepresentative structural section or bulkhead tests. In instances of jet fire exposure operators should consider the need to apply PFP to a vessel shell and not necessarily rely solely on a water-deluge system, insisting that jet fire tests have been conducted to ISO 22899-1. Whether specifying PFP for structural steelwork or vessels it is important that operators know what information is necessary to ensure correct sizing of the PFP, and that they take every effort to provide this information to the PFP manufacturer. HP LITERATURE CITED 1

Fabig, TN11: Fire Loading and Structural Response, 2009. 2 Lowesmith B. G., G. Hankinson, M. R. Acton and G. Chamberlain, “An overview of the nature of hydrocarbon jet fire hazards in the oil and gas industry and a simplified approach to assessing the hazards,” Process Safety and Environmental Protection, Vol. 85, 2007. 3 International Standardization Organization, ISO TR22899-2, 2011. 4 Gomez-Mares, M., L. Zarate, and J. Casal, “Jet fires and the domino effect,” Fire Safety Journal, Vol. 43, 2008. 5 American Petroleum Institute, “Fire-protection considerations for the design and operation of liquefied petroleum gas storage facilities,” API publication 2510A, 1996.

Ian Bradley is the standards and certification manager of worldwide fire protection for International Paint Ltd. His current responsibilities include testing, assessment and certification of fire protection products and industry representation to a number of trade associations and standards committees. He is a UK delegate to TC92 SC2 WG8: Jet Fires. He holds an MEng degree in materials engineering from the University of Sheffield, UK.

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real time responsiveness

In an industry driven by tight turnarounds and critical paths, there’s no time to waste. Waiting for the call back. Waiting for quotes, parts, and startup... Built on a foundation of deep industry experience and having engineered the most challenging combustion equipment in use today, the ZEECO® Rapid Response Team changes everything. Whether our burners, flares, and incinerators or the competitions’ equipment, we help you stop waiting and start running.

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ZEECO RAPID RESPONSE TEAM DELIVERS ON DEMAND Aftermarket shouldn’t equal afterthought. At Zeeco, we took a long look at the typical challenges our customers faced in getting the right parts within the demanding timeframes that define the petrochemical and related industries. After years of aiding customers who have faced a sudden need for replacement parts or equipment, the Zeeco Aftermarket Parts and Service team decided to change nearly every aspect of tight turnaround projects for customers. Our answer is the Rapid Response Team, or RRT. Designed to shrink production times through the development of a separate aftermarket workflow, the RRT eliminates the common problem of bottlenecking, or interrupting the existing project schedule. Featuring a separate production facility with machining, welding, plasma cutting, pipe bending, cutting and threading all in-house are what separates Zeeco’s RRT production capabilities from the approach of typical aftermarket parts suppliers. With the addition of a separate quality control/inspection team, purchasing and supply chain management, and in-house packaging and shipping, our RRT has international manufacturing capabilities for an urgent project response on a worldwide level. Why the Zeeco RRT? Zeeco’s combustion engineers understand the challenges of meeting emissions regulations and project deadlines in the Gulf Coast. Refineries and chemical plants experiencing an unplanned outage due to equipment failure or damage count the cost per hour until the plant is up and running again, and the pressure to deliver a replacement part as soon as possible can be intense. Zeeco’s RRT is built from the ground up to handle the pressure from the quote/engineering process through to shipment or installation of the new part. When a Gulf Coast refinery recently experienced a plant upset in production on a Friday, initiating what is known as a ‘Friday fire drill’ as the maintenance and operations team at the plant tried to source must-have parts, they called Zeeco. The RRT went into action and had pilots, auxiliary lances, wind boxes, gas tip and riser assemblies, plenums, and burner tiles all produced and ready to ship in four days. The RRT regularly replaces gas tips or other parts on an expedited basis, whether ZEECO® brand or a competitor’s, keeping customer outage times to a minimum. A follow up visit from the Zeeco Houston office experts ensured the problem was fixed for good and was the final step in quickly responding and solving a maintenance crisis. Our Zeeco Houston Service Center provides local service to the Gulf Coast region 24/7 including boiler/heater tuning, start-up assistance, installation, burner cleaning, controls upgrading, and more. With approximately 17,000 square feet of manufacturing space and the largest Gulf Coast permanent presence of sales and service personnel of any combustion company in the world, Zeeco achieves better support and response times for our customers than anyone in the region. Beyond just a quick response when something goes wrong, Zeeco works with customers to do proactive and preventative maintenance. Zeeco’s industry-leading combustion experts have deep experience and knowledge from working on-site in the world’s largest facilities. Our team conducts preventative and cost-saving pre-turnaround maintenance inspections. We perform a complete inventory analysis and component checklist to help customers order the necessary parts and components needed for the next plant turnaround. The customer will not only save on expediting fees but also save by eliminating potential SPONSORED CONTENT

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CONTACT INFORMATION 22151 East 91st Street Broken Arrow, Oklahoma USA 74014 Ph: +1 918–258–8551, Fax: +1 918–251–5519 HYDROCARBON PROCESSING




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Control DEA corrosion in a gas refinery Corrosion inhibitor selection and protective scales are key to prevention A. ZAMANI GHARAGHOOSH, A. ATASH-JAMEH and A. R. RASHIDFAROKHI, Sarkhoon & Qeshm Gas Treating Co., Iran; M. PAKSHIR and M. H. PAYDAR, Shiraz University, Iran


he sweetening unit is a key component of the gas processing plant, and the amine regeneration tower is one of the major parts of this unit. The amine tower in the Sarkhoon gas plant in southern Iran has experienced severe corrosion [40–50 mils per year (mpy)] over a 2.5-year period. The corrosion area is limited to the vapor and vapor/liquid interface spaces. The material in this area is carbon steel (A-516-GR-70) and is located on the inside of the tower shell. A recent study investigated the cause of this corrosion, along with the corrosion’s tendency to move from the top trays of the tower to the bottom trays. The performance of the chosen corrosion inhibitor was also scrutinized during the investigation. Results showed that an amine solution in the unit was degraded by dissolved oxygen (O2), exposing the inside of the tower shell to corrosive amine degradation products. The injection of an O2 scavenger inhibitor into the amine solution has not corrected the problem, and design issues with the injection point and its piping have been discovered.

Foaming in the amine regeneration tower results in the increased contact of corrosive components of the amine solution with the tower internals, as well as in a loosening of the protective iron sulfide (FeSX) surface layer that is formed by H2S. Heat-stable salts play an important role in foaming and corrosion in the amine regeneration tower.6,7 Organic acids—such as formic acid, acetic acid and oxalic acid—at a temperature of 200°C contacting carbon steel would result in severe corrosion. However, the corrosion activity of these acids is significantly reduced in an MDEA solution.3 The corrosiveness of a 20% amine solution on carbon steel in an environment containing either CO2 or H2S gas at a temperature of 140°F to 212°F would increase dramatically. However, environments containing either CO2 or H2S gas in this temperature range tend to experience more aggressive corrosion compared with an environment containing a CO2:H2S mixture of 1:3 or 3:1.8 One method to prevent corrosion in sweetening units is to use corrosion inhibitors. Corrosion inhibitors manufactured from

Corrosion sources in a gas plant.

A portion of the Sarkhoon gas plant’s feed is sour gas. In the feed-sweetening process (Fig. 1), a solution of 70% water and 30% diethanolamine (DEA) is used to absorb H2S in the contactor tower (C-101). Absorbed H2S is released in the amine regeneration tower (C-103) in the presence of rising temperature and pressure drop.1 In comparison with other amines [e.g., monoethanolamine (MEA), methyldiethanolamine (MDEA), activated MDEA (aMDEA)], DEA is more susceptible to oxidation and degradation, and it produces organic acid bases that form heat-stable salts in an amine environment.2 One of the major sources of corrosion on carbon steel vessels in sweetening units is heat-stable materials, which are a product of amine degradation.3,4 Oxygen plays a major role in DEA degradation. The reaction of O2 and DEA produces organic acids, such as acetic acid, formic acid and so on. O2 solubility in a solution of amine (except DEA) and water is similar to the solubility of O2 in water.5

CMP 1210 P-101 A/B T-101

Sweet gas

Sweet gas

P-105 A/B E-103 A/B X-106

C-101 HP sour gas

D-103 LP sour C-102 gas

D-106 E-101 A/B


CMP 1203 CMP 1202

CMP 1201

Corrosion inhibitor

CMP 1209

Tray 1 No. 4 No. 20 C-103

CMP 1211

P-103 A/B CMP 1206 CMP 1207

To H-201 CMP 1206

P-102 A/B Send to T-101 FIG. 1

E-102 A/B

CMP 1208

CMP 1205

From H-201

From H-201 To H-201

Gas-sweetening unit at Sarkhoon gas plant.


I 95



TABLE 1. Field corrosion monitoring results Bottom of C-101 to D-106

Bottom of C-102 to D-106

After P-103 to C-103

Top of E-104B to C-103

C-103 to bottom of E-104B

Top of E-104A to C-103

C-103 to bottom of E-104A

Bottom of C-103 to E-102A

Top of E-102A to top of C-103

P-101 to C-101









Chemical-mechanical planarization 1,201












Test 2 0.4865 0.8080 (performed seven months after Test 1)









Corrosion, mpy Test 1

TABLE 2. Oxygen content of amine solution in cycle

Electrical potential (millivolt) vs. silver chloride electrode





Test no.


C-103 inlet

F-103 outlet, P-102 suction

F-103 outlet







6.3 ppm















7.4 ppm

























corrosion rates for a rich solution containing H2S, compared with a lean amine solution that does not contain H2S.12


-1,200 -8 FIG. 2

Corrosion tests. A number of field and laboratory tests have

-7 -6 -5 -4 -3 -2 Log(electric current)(Log(electric current vs. ampere))


Lean amine polarization test at three different temperatures.

heavy metals, such as arsenic and vanadium, have the ability to control corrosion in the aforementioned environments, although these heavy metals are incompatible with these environments. Furthermore, these types of corrosion inhibitors are unable to protect splash zones and vapor spaces. Film corrosion inhibitors prevent general corrosion, but are unable to control specific types of corrosion.8 To avoid certain corrosion types (e.g., sulfide stress cracking, hydrogen-induced cracking, etc.), guidelines contained in NACE MR-01-75 should be followed during the material selection of sweetening units.9 Organic amines are traditionally used in the refinery crude column overhead to neutralize and reduce pH as a means of corrosion control.10 Based on previous research on H2S concentration increases in oil, two types of scales form on contacting steel surfaces: Mackinawite and Pyrrhotite.11 Mackinawite scales have coarse grain in a loose and brittle form. Although Mackinawite scales reduce general corrosion, steel surfaces are still susceptible to aggressive, pitting corrosion. Pyrrhotite scales have fine grains and exist in continuous form, and are resistant to both general and pitting corrosion.12 There are three zones in the regeneration tower: the vapor space, the liquid/vapor interface and the liquid phase. In the vapor space, the formation of a protective layer of FeSX results in low 96

I MAY 2012

been performed to measure corrosion rates and levels at the Sarkhoon gas plant. Field tests included the following: Weight loss (coupon) test. This test was carried out based on standard test method ASTM-G-1 via coupon installation in 10 points of amine solution cycle input. Test results are presented in Table 1.13 Iron count test. To evaluate the corrosion rate of the unit, this test was performed according to the spectrophotometric method. Samples were taken from the circulating amine solution, and the amount of iron (which is generated by corrosion on vessels) was measured. The following iron counts were observed: 16.9 ppm (Test 1), 10.6 ppm (Test 2), 35.0 ppm (Test 3) and 38.0 ppm (Test 4). Based on these data, the presence of an amine solution containing concentrated heat-stable salts results in corrosion reactions. According to the unit design, the maximum allowable amount of iron in the amine solution is 10 mpy. Dissolved O2 in amine solution. The amount of O2 present in the amine solution, which is a major factor in DEA degradation, was measured according to test methods outlined in ASTM D-888 and ASTM D-5543. Results are represented in Table 2.14,15 Ultrasonic test. An ultrasonic thickness meter was used to measure tower wall thickness. The results of this test, which show a reduction in thickness, are represented in Tables 3 and 4. Laboratory corrosion tests included the following: Inlet gas analysis. This test was carried out according to ASTM D-1945 guidelines. A gas chromatography apparatus was used to pinpoint components of the feed gas entering the contactor tower.16 Results are shown in Table 5. Polarization test. To determine the corrosion rate of the lean amine solution containing 3.71% heat-stable salts, three tests at



TABLE 3. Tower wall thickness and corrosion depths at inspection period Tray no.














Clad with SS-316; no corrosion
















Uniform corrosion area



9.1, 9.3

7, 7.7, 8.47





Corrosion (valley type)



7, 8.18


Wall thickness, mm Design Actual Corrosion depth, mm

TABLE 4. Six-month thickness monitoring southeast of Tray 18

340 320

Monitoring session

Thickness, mm













temperatures of 25°C, 50°C and 70°C were performed according to ASTM G-3 methods. Respective corrosion rates of 2.0 mpy, 4.8 mpy and 8.8 mpy were observed at the various temperatures. These results are illustrated in Fig. 2.17 Immersion weight loss. To simulate corrosion in the three tower regions, this test was conducted according to ASTM G-31 guidelines in static condition, with lean amine containing 3.71% heat-stable salts at a temperature of 120°C. The corrosion rates observed for the liquid phase, liquid/vapor interface, and vapor phase were 2.10 mpy, 5.02 mpy and 8.16 mpy, respectively.18 Scanning electron microscope. To evaluate corrosion products on the carbon steel section of the tower shell, a sample from the bracket of the downcomer of the ninth tray was prepared and tested by microscope. Test results are shown in Fig. 3. Amine solution analysis. This test was performed to investigate lean amine solution components, and it is based on ion chromatography and National Iranian Gas Co.’s test method for heat-stable salts. Results are presented in Table 6. Corrosion inhibitor evaluation. To evaluate the O2 scavenging performance of a corrosion inhibitor injected into the amine cycle, this test was conducted according to methods outlined in ASTM D-888 and ASTM D-5543 for two samples of freshwater and a solution of 30% amine and 70% water. Test results are shown in Table 7.14,15 Corrosion test in acid/DEA environment. This test was conducted to evaluate the corrosion rate of carbon steel in a liquid phase contacting a lean amine solution. The solution contained organic acids at a temperature of 25°C to 30°C, which is the temperature of the circulated amine solution in the cycle. Eighteen separate samples from the fresh amine solution containing an organic acid (i.e., acetic, oxalic, malonic, formic, butyric, succinic or glycolic) were prepared, and corrosion coupons were installed. Test results showed a corrosion rate greater than or equal to 0.2 mpy for all of the above-named acids. X-ray diffraction. Samples from a non-corroded portion of the tower were used in this test, as it was not possible to prepare samples from the corroded area. The formation of iron disulfide (FeS2) was observed, as shown in Fig. 4.

300 280



200 180 160 140 120 100 80 5

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 Counts, 2 theta

FIG. 3

SEM test result on a specimen from the downcomer.

FIG. 4

XRD test—FeS2 scale.

Corrosion in the gas-sweetening unit. DEA is used in

the gas-sweetening unit. This unit was inspected one year after commissioning, at which time no corrosion or deterioration was detected. A second inspection was carried out 2.5 years after commissioning, and aggressive corrosion was detected in the vapor space of the tower shell, in the carbon steel section. HYDROCARBON PROCESSING MAY 2012

I 97



This tower consists of 20 trays. The tower shell is made up of 316L stainless steel from the top head through Tray 8, and the remaining 12 trays are annealed SA516 Grade 70 carbon steel. The tower wall thickness is 12 mm, with 3 mm of corrosion allowance. The chemical composition of the aforementioned alloy is presented in Table 8. Due to the existence of chloride ions in the feed, the chloride ion content of the circulating amine was higher than the allowed limit during the first three months of operation. An anionic resin bed was used to absorb the negative ions. After feed quality improved and the ion chloride content was reduced, the bed was taken out of service. Corrosion was observed in several forms. “Local” or “islandshaped” corrosion resembled several concentric, closed curves, with each curve having an almost equal center and differentiation in the borders between it and the next curve (Fig. 5). The corrosion morphology was described as “step-down edges.” The most corroded areas were found at the centers of the curves. Here, the tower thickness was reduced by 3.5 mm to 4.0 mm.

The “valley” form of corrosion occurred in down-flowing liquid in the vapor/liquid interface of the shell. The depth of the valleys was 5.5 mm to 6.0 mm (Fig. 6). The corrosion shape was described as a “smooth valley” and an “escarpment.” Investigation of corroded areas for both forms showed: 1. Corrosion on the regions of the shell contacting the amine solution (liquid phase) was negligible. This was verified by coupon test results (Table 1). 2. Severe corrosion was observed on the tray vapor space and the liquid/vapor interface. 3. Corrosion severity in the aforementioned areas on trays 8 to 20 (top to bottom) increased in correlation with area and depth. Inlet gas to the contactor contains a maximum of 40 ppm H2S. Software was used to determine the H2S concentration in each tray of the regenerator tower; this process was simulated based on rich amine content. Results are presented in Table 9. In order to control corrosion, a corrosion inhibitor was injected into two lines with different pressures. These lines included a lean

TABLE 5. Analysis of inlet gas to contactor tower

TABLE 6. Lean amine analysis results

Component no.

Test result, mol%




















Lean amine Test 1 Component totals


Lean amine Test 2 Before After carbon filter carbon filter

Sulfur as SO4, ppm




Sulfate as SO4, ppm




Chloride as Cl, ppm




Calcium hardness as CaCo3, ppm

< 50



Magnesium hardness as CaCo3, ppm

< 50


<5 < 0.5







Copper as Cu, ppm


< 0.5


Iron as Fe, ppm












Sodium as Na, ppm


40 ppm


Potassium as K, ppm

< 50



Manganese as Mn, ppm




Phosphorus as PO4, ppm

< 50



Solids suspended, mg/l




Thiosulfate as S2O3, ppm




Thiocyanate as SON, ppm

< 20


< 20

< 20

Oxalate as C2O4, ppm




Chromium as Cr, ppm

< 2.5



Nickel as Ni, ppm



< 0.1

Total acid gas as w/w, % CO2




Acetic acid as C2H4O2, ppm




Butyric acid as C4H8O2, ppm

< 50



Formic acid as CH2O2, ppm







Glycolic acid as C2H4O3, ppm




DEA, %




< 0.01

< 0.01

< 0.01




Propionic acid as C3H6O2, ppm

H2S loading, mol H2S/mol amine Heat-stable salts, % DEA

TABLE 7. Laboratory test of corrosion inhibitor Dissolved O2 before increasing temperature of solution With inhibitor: 5.6 ppm Without inhibitor: 5.6 ppm FIG. 5


General corrosion at vapor phase area.

I MAY 2012

Dissolved O2 after increasing temperature of solution With inhibitor: 0.98 ppm Without inhibitor: 1.8 ppm


Tower corrosion (valley type).


Na sulfate


Na oxalate

Oxalic acid

Duplicate run Formic acid

Formic acid

Carbon steel corrosion in various acids and salt.

FIG. 7

FIG. 8

Ammonium thiocyanate


1,000 5,0000

Sodium thiocyanate

Sodium chloride

10,000 50,000


Ammonium thiosulfate

Sulfurous acid

1,000 5,000 10,000 10,000

HCI acid


Sulfuric acid


10,000 50,000

Acetic acid

Glycolic acid

Succinic acid



Malonic acid

10,000 50,000

Formic acid

Oxalic acid



250 225 200 175 150 125 100 75 50 25 0 No acid

FIG. 6


Acetic acid

250 ppm 500 ppm 1,000 ppm 5,000 ppm 10,000 ppm

Na formate

180 160 140 120 100 80 60 40 20 0


Corrosion rate, mpy

Amine analysis results. The results of the circulating amine analysis showed that the amine was degraded. Oxidation and degradation products are generally organic acids that cause severe corrosion on carbon steel at proportional concentrations (Fig. 7). The analysis showed that the amine produced heat-stable salts after contacting organic acids, which can also cause corrosion on carbon steel (Fig. 8). Visual inspection and thickness monitoring detected no significant corrosion in the liquid phase of the amine stream on pipelines, towers or other vessels in the gas sweetening unit. An analysis of corrosion-monitoring results (Table 1) observed during an aggressive period of corrosion (as well as subsequent corrosion periods) shows a corrosion rate of fewer than 2 mpy in the liquid phase. Field corrosion-monitoring results were verified by immersion weight-loss tests in the laboratory. The corrosion rate of the lean amine in the liquid phase was found to be within an acceptable industrial margin, according to a polarization test of the lean amine solution (Fig. 2), which contained 3.71% heat-stable salts. Organic acids were also present in the solution. Although the results of the polarization test showed rising temperature, the corrosion rate was less than 25% of the corrosion rate of the tower shell. Furthermore, the temperature increase was related to the rich amine stream in the unit. In a rich amine stream, the formation of an FeSX layer protects the surface. No H2S or FeSX layer was observed in the lean amine solution in either the polarization test or the laboratory weight-loss test. Use of oxygen scavenger inhibitor. To omit O2, which is introduced into the solution by a demineralized water makeup, an O2 scavenger inhibitor was injected. Based on the characteristics of the inhibitor, the required temperature for starting a reaction with dissolved O2 is higher than 80°C, while the amine temperature in the tank and onstream before entering the regenerator tower (–103°C) does not reach the specified temperature. Therefore, O2 cannot be entirely eliminated below 80°C. Test results showed a partial decrease in the amount of dissolved oxygen in the amine solution after the inhibitor was added, which

raised the temperature to 98°C for a period of 15 minutes. The O2 scavenging performance of this inhibitor at higher temperatures is in doubt, as it was found to be unsatisfactory during this test. Additionally, the results of the dissolved O2 field test are evidence of the presence of O2 in the solution, which verifies the unsatisfactory performance of the inhibitor. The poor performance was due to the amine coming into contact with O2. In other words, the presence of oxygen is a factor in the production of organic acids. The injection pump performs at a unique pressure, and it is not possible to inject the inhibitor into two points with different pressures, as setting the pressure on the reflux stream would result in lower-than-desired pressure in comparison with the contactor stream. If the pressure setting is based on contactor pressure (which is higher than reflux stream pressure), the high-pressure injection fluid would flow into the low-pressure stream (reflux); therefore, it cannot be injected into the contactor stream. Causes of corrosion. As mentioned above, corrosion observed on the interior of the tower is located on the vapor space or on the vapor/liquid interface. According to an analysis performed on degraded amine that was circulated during a period of severe corrosion, there are several organic acid anions in amine that cause corrosion. Since tests cannot be viably performed on liquids in the

Carbon steel corrosion, mpy

amine-to-contactor line with a pressure of 60 bar to 65 bar and a reflux stream line with a pressure of less than 2 bar. Oxygen scavengers function as the duty of this inhibitor as well as a protective layer (along with a surface scale of FeSX ), based on the information provided by the inhibitor manufacturer.


Carbon steel corrosion in various acids.


I 99



TABLE 8. Analysis of carbon steel (SA516 Grade 70) Composition, %

Mechanical property










Yield strength (MPa)

Tensile strength (MPa)



0.039 ⱕ



0.27 ⱕ



TABLE 9. Process results using simulation software Component of vapor phase of amine regenerator tower, mol% Temperature, Oxalic Acetic Tray no. °C DEA acid acid

Butyric acid

Formic acid




Propionic acid

Glycolic acid











Water 26.191





























































































































































































































































reflux drum or on outlet gases from the top of the tower, process simulation software was used to evaluate the existence of acidic anions in gases flowing from the top of the tower. Simulation results (Table 9) confirmed the presence of these anions in the vapor space of the tower. Vapor pressure research also indicated the presence of these anions in the tower’s vapor space. According to research and calculations, the corrosion rate is 40 mpy to 50 mpy. Taking into account the percentage of anion components found in field-sampled amine, the corrosion rate was applied to these test results, as shown in Figs. 7 and 8. The FeSX scale formation on carbon steel was found to have a smaller structure and to adhere better to metal in proportion to the increase in H2S concentration. In lower H2S concentrations, the FeSX scale has a larger structure and is less adhesive to metal. Organic acid anions overcome the sulfur element of FeSX and, in the process of destroying the scale, they form salts (e.g., iron acetate). An X-ray diffraction analysis was performed on an FeSX scale on the vapor space of Tray 9, in an area that was not affected by corrosion. Test results (Fig. 4) show the scale type to be Pyrrhotite, which adheres suitably to metal and offers better surface protection than a Mackinawite scale. The process simulation results presented in Table 9 show the decreasing presence of H2S in the carbon steel regions of Trays 8 through 20. Consequently, these trays have less adhesive FeSX scales. 100

I MAY 2012

The results of the sour gas-sweetening unit analysis show that the percentage of H2S is suitably low and meets conditions outlined in NACE MR-01-75, even though the gas is sour. On the other hand, the low concentration of H2S results in a loose and brittle FeSX scale, along with organic acid anions in the vapor phase, steam that allows for an electrochemical condition, and the inability to inject an inhibitor into the liquid phase. All of these factors create a tower environment that is susceptible to corrosion. Furthermore, internal temperatures approach 120°C on the lower trays of the tower and 100°C on the upper trays. The higher temperature and looseness of the FeSX scale on the lower trays accelerate corrosion on the lower section of the tower. Corrosion formed in a valley shape on the liquid/vapor interface due to FeS2 erosion from the use of an amine containing organic and inorganic contaminations. Low reforming potential and a high concentration of acidic components next to the liquid surface also contributed to the corrosion. Takeaway. According to the analysis, the water used to prepare the amine solution contained an unacceptable concentration of oxygen. Also, existing O2 in the reaction with DEA resulted in DEA oxidation in the circulating amine solution, producing organic acids that entered the vapor phase of the tower. In a corrosion-susceptible environment (i.e., the existence of water, high temperature, acids,

CORROSION CONTROL and no amine in the vapor phase), the presence of these acids contributed to corrosion on the shell interior of the tower. The selection of a corrosion inhibitor was not correctly performed, as attention was not given to the required temperature for rationing with O2. Furthermore, the design of the corrosion inhibitor injection system was corrupt, and the injection of an inhibitor into two points is not practical. The lesson learned is that the selection of a corrosion inhibitor should be carefully performed. A revamp of the injection process—one that considers simultaneous injection into two points at different pressures—is necessary. Also, the type of FeSX scale that forms on carbon steel must be considered, as this has a direct effect on the degree of surface protection achieved and the rate and extent of the corrosion that occurs. An anionic resin bed played an unexpected and important role in corrosion prevention during the first year. In a situation where O2 cannot be eliminated, the development and use of this type of bed is recommended. Also, the implementation of a suitable lining on the tower interior can provide temporary corrosion control. HP ACKNOWLEDGMENT Research for this survey was supported by Sarkhoon & Qeshm Gas Treating Co.


MDEA solution corrosivity,” Hydrocarbon Processing, March 1996. Rooney, C. P. and M. S. Dupart, “Corrosion in Alkanolamine Plants: Causes and Minimization.” NACE International, Corrosion 2000, Orlando, Fla., 2000. 5 Rooney, C. P. and D. Daniels, “Oxygen solubility in various alkanolamine/ water mixtures,” Petroleum Technology Quarterly, Spring 1998. 6 Stewart, E. J. and R. A. Leanning, “Reduce amine plant solvent losses,” Hydrocarbon Processing, May 1994. 4

Complete literature cited available at Ahmad Zamani Gharaghoosh is the managing director of Sarkhoon & Qeshm Gas Treating Co. He joined National Iranian Gas Co. in 1997 and has more than 15 years of experience in gas refineries as a senior corrosion and welding engineer, inspection department head and research committee member. He is an expert on static equipment inspection, risk-based inspection and corrosion investigation at gas refineries, and he has authored or co-authored five papers for ISI journals and national and international conferences.

Abolfazl Atash-Jameh heads the process engineering group at Sarkhoon & Qeshm Gas Treating Co. He joined National Iranian Gas Co. in 1999, and he has 10 years of experience in different aspects of process engineering for natural gas. He has published seven papers for national and international conferences. Amir Reza Rashidfarokhi is a mechanical engineer and heads the technical inspection group at Sarkhoon & Qeshm Gas Treating Co. He joined National Iranian Gas Co. in 2002, and he has eight years of experience in different aspects of the technical inspection industry. He has also participated in a number of industry studies and courses.

Mahmoud Pakshir is a tenured professor at the Department of Material SciLITERATURE CITED 1 Robert, N. and J. Morgan, Gas Conditioning and Processing, Vol. 4, Campbell Petroleum Series, Oklahoma, 1998. 2 Jenkins, H., “Understanding gas treating fundamentals,” Petroleum Technology Quarterly, Winter 2001. 3 Dupart, M. S., T. R. Bacon and P. C. Rooney, “Effect of heat-stable salts on

ence and Engineering at Shiraz University in Iran. He has published more than 70 papers on corrosion control and prevention.

M. H. Paydar is an associate professor at the Department of Material Science and Engineering at Shiraz University in Iran. He has published more than 20 papers in international magazines.


I 101

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Maximize FCC main air blower and wet gas compressor capacity Maintaining optimum performance is crucial for sustained profitability J. R. WILCOX, Albemarle, Baton Rouge, Louisiana


Both axial and centrifugal design air compressors are ideally suited to the low head, high capacity requirements of the FCC unit (Fig. 1). The centrifugal machine has a limited stable operating range, as reflected by the flatter operating curve. As such, a small increase in pressure can push the machine into a surge region, adversely affecting economics at a reduced rate. The headcapacity curve for the axial compressor is much steeper than that of a centrifugal compressor, resulting in a much narrower operating range between normal and surge. A benefit of the axial compressor is the higher efficiency and smaller footprint for larger volumes. At a fixed speed, the mass flow delivered by the blower will vary with ambient temperature. This will obviously impact the regen-

erator coke-burning capacity, cracking severity and, potentially, the FCC feedrate. Depending on location, seasonal temperature fluctuations can result in air blower discharge flow variations due to changing air density of as much as +/- 10%. As shown in Fig. 2, a 10°F increase in ambient temperature will reduce air mass flowrate by 2%. The scatter observed in this data at a given ambient air temperature reflects the fluctuations in coke burning 115

Relative air flowrate, %

110 105 100 95 90 85 1-Apr

FIG. 1







Both axial and centrifugal design air compressors are ideally suited to the low head, high capacity requirements of the FCC unit.


106 Relative air flowrate, %


aximizing transportation fuel yield and profitability continues to be the refiner’s primary objective. The heart of the typical gasoline producing refinery, the fluid catalytic cracking unit (FCCU), must be operated at maximum capacity to meet this objective. The FCCU has a significant impact on refinery economics due to its large contribution to the gasoline pool and overall volume expansion. As a result, small, incremental improvements to yields or throughput will have a positive impact on refinery profitability. Maximizing FCCU profitability requires the unit to simultaneously be operated against as many constraints and limitations as possible. Most FCC units have dozens of mechanical and operational constraints, but two of the most common are the main air blower and vapor recovery unit wet gas compressor. Relieving these two constraints provides the flexibility to either process more feed, crack lower quality feed or increase cracking severity. Debottlenecking these two machines offers potential benefits to the FCCU operation. Compressor performance can be described by the head flow curve. The head requirement may be expressed as either polytropic or adiabatic. Head is a function of gas molecular weight, compressibility, suction temperature and pressure, discharge pressure, and machine efficiency. The performance curve starts at the surge point and ends at the choke point. Stable operation and flow range is between these two points. The operating curve is relatively flat near the surge condition and becomes steeper as flow increases. Consequently, small head changes result in large increases in compressor capacity. As the operation moves toward the choke condition, the slope of the curve increases, and decreasing head will have less impact on inlet flowrate.



94 90 20

FIG. 2


60 80 Ambient temperature, °F


A 10°F increase in ambient temperature will reduce air mass flowrate by 2%. HYDROCARBON PROCESSING MAY 2012

I 103



resulting from unit operating severity and heat balance requirements. This constraint becomes most pronounced during the hot summer months when maximum gasoline yield and maximum FCC charge rate are the primary objectives. Because the blower suction conditions depend on ambient conditions, summer heat and humidity will reduce both the air density and molecular weight, resulting in reduced capacity. Depending on location, reducing the temperature of the air at the suction to the blower can, in some cases, provide a positive impact on unit profitability. Chilling the air to the blower increases the air density, resulting in increased mass flow through the machine (Fig. 3). Refrigeration and evaporative cooling have both successfully been used to reduce the air to the blower suction. Increases of 1%–7% in air mass flow have been reported. Maintaining the driver performance is essential to maximizing the air blower rate. The highest steam supply pressure should be TABLE 1. Effect of feed preheat on air rate Feed preheat, °F






Coke yield, wt%






Relative air rate






Cat/oil ratio






Regen temp., °F






Conversion, vol%







Relative air flowrate, %

110 105 100 95 Pre-chiller Chilled air

90 85 0 FIG. 3


40 60 Ambient air, °F



Chilling the air to the blower increases the air density, resulting in increased mass flow through the machine.

Capacity Increase, %

12 1 psi decrease 2 psi decrease 3 psi decrease

10 8 6 4 2 0 15

FIG. 4


25 Regenerator pressure, psig


The impact of regenerator pressure on air blower capacity.

I MAY 2012

used to power a steam turbine driver. Even a modest 5% speed increase will translate to 10%–15% more driver power. For a condensing system, maximizing vacuum by maximizing the steam rate to the ejector(s) will ensure optimum performance. During normal operation, some deterioration in performance of axial machines may occur due to fouling of the rotor. Often, some of this performance may be recovered by injecting an abrasive material, such as rice hulls or walnut shells, into the suction of the machine to remove deposits from the rotating elements. The impact of this online cleaning is usually immediately reflected by an increase in available horsepower. Operating the compressor within 3%–5% of the surge control point on the operating curve with the anti-surge valve completely closed will usually provide maximum performance. Process variable effects. Optimization of the operating

parameters is critical to maximizing the FCCU profitability. Key factors that impact the combustion air requirement include the reactor/regenerator/main column pressure balance, the FCC heat balance and the catalyst performance. Regardless of blower type, the reactor/regenerator/main fractionator system should be optimized to minimize the blower head requirement. Since the air blower compresses air from ambient conditions to the regenerator pressure, reducing regenerator pressure can allow for increased capacity, particularly when operating on the flat part of the head curve. The slope of the blower curve will determine the magnitude of the flow increase possible from a given adiabatic head reduction. Minimizing the regenerator pressure to the limit of the regenerated catalyst slide/plug valve pressure drop will provide increased air rate. Main column flooding or excessive top reflux will add significant pressure drop to the system. The main column heat balance should be optimized to reduce the overhead condenser system pressure drop. A heavily loaded fractionator overhead condensing system pressure drop can be as high as 8 psi–10 psi. Reducing overhead reflux by utilizing a heavy naphtha side draw can reduce the overhead system pressure drop by 2 psi–4 psi, which can then be used to reduce the air blower head requirement. Fig. 4 illustrates the impact of regenerator pressure on air blower capacity. The reactor/regenerator heat balance and coke production required to support the heat balance are set by the specific cracking conditions. Process variables that will determine coke yield and combustion air requirements include feed preheat, reaction temperature, recycle rate, regenerator combustion mode, and riser contact time. Feed injector dispersion steam and reactor spent catalyst stripper performance will affect ⌬ coke, which has a direct impact on coke yield. Feed preheat can have a significant impact on air rate. Increased feed preheat will result in reduced coke production, as less heat will be required from the regenerated catalyst to maintain the heat balance at the desired reaction temperature. A second potential benefit of increasing feed preheat, particularly with heavy, high viscosity feed, is improved feed injector performance. Complete vaporization of the hydrocarbon is essential to minimize ⌬ coke. The effects of feed preheat are shown in Table 1. As Table 1 illustrates, increasing feed preheat will lead to a reduced combustion air requirement, but also to increased ⌬ coke, as reflected by the higher regenerated catalyst temperature. Incremental feed or more contaminated feed can then be charged to the unit, bringing the total coke burn load back to the base


TABLE 2. Effect of reactor temperature on air rate Reactor temperature, °F






Coke yield, wt%






Relative air rate





















Cat/oil ratio Regen temp., °F Conversion, vol%

catalyst stripper. These hydrocarbons will consume air, which should be utilized to burn coke off the spent catalyst. Effective spent catalyst stripping is a function of the stripping steam rate and distribution, spent catalyst mass flux through the stripping zone and efficient contact between the steam and catalyst. Feed injector dispersion steam has a direct impact on ⌬ coke as well as hydrocarbon partial pressure in the riser. Optimizing dispersion steam in a well feed injection system usually will minimize thermal cracking, leading to reduced ⌬ coke, dry gas and diolefin production. Excess steam can lead to increased cooling and added coke yield, as well as added overhead condensing requirement. Adding steam to the feed typically reduces the hydrocarbon residence time in the riser. For each 1% steam added to the feed, the contact time will be reduced by about 5%. Typically, a 15% reduction in hydrocarbon residence time will result in a 3%–4% drop in air requirement. FCC units processing very heavy feeds often utilize catalyst coolers independently adjust the heat balance as well as maintain the regenerator temperature below the metallurgical limitations (Fig. 6). The heat removal duty should be minimized for a given feed quality and operating severity in order to minimize coke production and air requirement. Options for adding incremental air. Several refiners have alleviated the air blower constraint with oxygen enrichment to the combustion air. Injecting pure oxygen directly into the blower discharge will increase the coke burning capacity (Fig. 7). Increasing the oxygen level in the combustion air from 21 to 0.62

Complete CO combustion at 2% excess O2

0.61 Air/feed weight ratio

case level, and using the available air to burn the added coke. The impact on unit profitability is typically positive, as the additional product volume far exceeds the small drop in conversion. The cracking temperature, or riser outlet temperature, is typically optimized to achieve a target conversion or meet product quality specifications. Raising the reaction temperature requires additional heat, which is provided with increased coke production. As such, the riser outlet temperature should always be carefully controlled within the air blower limitation. The effect of reaction temperature on air capacity is shown in Table 2. Minimizing recycle of heavy unconverted material back to the riser reduces coke yield and air requirement. The impact of slurry recycle is shown in Table 3. The regenerator combustion mode will have an impact on the coke yield and combustion air requirement. If operating in complete combustion, the excess oxygen in the flue gas should be minimized while maintaining uniformly regenerated catalyst and minimum dilute phase afterburn. As shown in Fig. 5, the combustion air requirement decreases as the flue gas CO2/CO ratio is increased from 1 to about 4. The minimum air requirement occurs at about 95% combustion of CO to CO2. To operate at this condition, a CO boiler or incinerator will be required to meet environmental limitations. Catalyst formulation changes have very little impact on the air blower requirement at a given heat balance condition. Improving catalyst coke selectivity has little effect on coke yield, as well. The lower ⌬ coke increases the catalyst circulation rate, leading to a lower regenerated catalyst temperature and higher conversion at a given coke yield. The small impact of the circulating catalyst activity level is described in Table 4. Incremental ⌬ coke can be transferred to the regenerator from hydrocarbons entrained in the spent catalyst leaving the spent

0.60 0.59

Increasing O2 excess

0.58 0.57 0.56 0.55 1

FIG. 5

TABLE 3. Effect of combined feed ratio on air rate 1



Coke yield, wt%




Relative air rate




Cat/oil ratio




Regen temp., °F




Conversion, vol%









Coke yield, wt%






Relative air rate











Regen density, °F






Conversion, vol%






Cat/oil, lb/lb


4 5 6 7 Flue gas CO2/CO ratio




The combustion air requirement decreases as the flue gas CO2/CO ratio is increased from 1 to about 4.


TABLE 4. Effect of catalyst activity on air rate ECAT activity



Relative air flowrate, %

Combined feed ratio


105 100 95 90 85 0

FIG. 6


10 15 20 Cooler duty, MMBtu/hr



Catalyst coolers are often utilized to independently adjust the heat balance. HYDROCARBON PROCESSING MAY 2012

I 105



22 mol%–28 mol% is typical. As oxygen is added, the regenerator temperatures will increase due to a decrease in nitrogen partial pressure. The higher regenerated catalyst temperature will lead to a decrease in catalyst circulation and resulting catalyst/ oil ratio. A regenerator temperature increase of 6°F–10°F for each 1% added oxygen is typical. Another potential concern of oxygen addition is increased NOx and SOx emissions in the flue gas. However, the economics of oxygen enrichment to the combustion air are generally very favorable, as the cost of oxygen is less than FCC product value. Table 5 shows what typical coke burning increases are possible with increased oxygen concentration in the combustion air. 120

Relative air rate, %

24 28% O2 110

Operating/mechanical considerations. Before replacing

the compressor, several potentially cost effective modifications should be considered. Reducing the system pressure drop allows equipment operating pressures to be adjusted to relieve constraints. For example, the FCC main column typically operates with 5 psi–6 psi pressure drop, while replacing conventional trays with packing can reduce the tower pressure drop to about 1 psi. The 4 psi–5 psi can be recovered and used to debottleneck the air blower or wet gas compressor. Minimizing reactor vapor line coking and fouling will also help reduce pressure drop. Increasing suction pressure to the wet gas machine will allow more capacity and reduced driver requirement, while decreasing the air blower discharge pressure will provide for increased capacity. Relieving hydraulic constraints has resulted in increases of 10%– 40% without costly modifications to vessels and rotating equipment. Some other low cost modifications to be considered include: 1) A new gear set may provide a modest speed increase, within the motor power and compressor speed limitations, translating to added power and air rate


TABLE 5. Impact of oxygen enrichment 90 21% O2 80 3.0

3.4 3.6 Superficial velocity, FPS



Injecting pure oxygen directly into the blower discharge will increase the coke burning capacity.

Coke burn increase, wt%












FIG. 7


Oxygen concentration, vol%

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As with the air blower, the wet-gas compressor (WGC) is typically operated at maximum capacity and no additional wet or dry gas can be recovered. The WGC is typically a multi-stage centrifugal machine utilizing inter-stage cooling to remove heat from compression, minimize fouling and maximize machine efficiency. Centrifugal compressors develop a fixed head for a given inlet flowrate for typical molecular weight ranges encountered on the FCCU. Wet gas is a compressible fluid and changes in compressor suction conditions that increase gas density will reduce the actual volumetric wet gas flowrate. Increased gas density and reduced head frees up compressor capacity. Operating variables that decrease head and produce higher gas density increase the capacity of a centrifugal compressor. Decreasing cracking severity will reduce wet gas production, allowing additional feed to the unit. Increasing the FCC feed temperature, reducing the riser outlet temperature,

and reducing equilibrium catalyst activity will reduce wet gas production. Minimizing thermal cracking will reduce dry gas load to the compressor, increasing the molecular weight of the wet gas. As previously mentioned, a feed injection system, effective spent catalyst stripping, minimizing or eliminating heavy recycle and utilizing a coke selective catalyst will all help minimize thermal cracking. The wet gas molecular weight has a significant impact on compressor capacity and is determined by reaction severity. Raising the compressor inlet pressure decreases head requirement and increases gas density, even though the molecular weight is slightly reduced due to increased condensation of the heavier hydrocarbons. A 5% increase in gas molecular weight decreases inlet volume flow by 5% at a fixed inlet temperature and pres14 Increase in WGC capacity, %

2) Diffuser replacement on centrifugal machines may provide an increase in the pressure head developed from each stage 3) Replacement of the rotor and diffusers can produce significant capacity, head and power requirement increases 4) Modifications to the gas path size, combined with replacement of the stator blades, will add capacity to an axial compressor 5) Auxiliary machines, either in series or parallel, may be considered to augment the existing air blower. Installed costs for packaged, multi-stage centrifugal compressors are considerably less expensive compared to conventional single shaft trains for comparable capacities.


1 psi decrease 2 psi decrease 3 psi decrease

12 10 8 6 4 2 0 10

FIG. 8

20 Reactor pressure, psig


Impact of compressor suction pressure on capacity.

Select 171 at


I 107

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CORROSION CONTROL sure. Minimizing the impact of lower molecular weight components, primarily hydrogen yield due to metals contamination usually can be achieved with catalyst passivation technology. Heavy metals in the feed such as nickel, copper, vanadium and iron will deposit on the circulating catalyst in the riser. These metals are catalytically active and promote dehydrogenation reactions generating hydrogen and other light gases, reducing the molecular weight of the wet gas to the compressor. The result is reduced compressor capacity, leading to either reduced conversion or restricted feedrate. The benefits of optimizing the ratio of metal passivator to active metal on the circulating catalyst inventory have been well documented. The reactor/regenerator pressure balance should be optimized to maximize compressor capacity. Increasing the reactor pressure to the limit of the regenerated catalyst slide/plug valve will increase compressor capacity. Increasing compressor suction pressure will increase gas density and reduce gas volume for a given mass flow rate. Additionally, reductions in pressure drop in the overhead vapor piping system feeding the compressor will increase the compressor capacity. 2 ne 201 22. Ju 94 G h 18. to t o .0 · Bo Hall 8

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Hydraulic considerations. As with the air blower, small

adjustments to the pressure balance can translate to significant increases in compressor capacity. The impact of compressor suction pressure on capacity is illustrated in Fig. 8. Ensuring that the recycle (spillback/anti-surge) valves are closed typically will maximize compressor capacity. As with the air compressor, this machine should be regularly cleaned to minimize loss of performance due to fouling. The wet gas is highly olefinic and will polymerize fouling the internal surfaces of the compressor. Regular online washing with a naphtha quality material will keep these surfaces clean. Increasing the gas molecular weight raises gas density and reduces volume for a given mass flowrate. The WGC performance depends on: • Increasing capacity by reducing the polytropic head requirement and moving to the right on the operating curve • Increasing compressor suction pressure, decreasing suction temperature and reducing discharge pressure will all reduce the head requirement. Reducing discharge pressure is usually not practical. The sponge absorber offgas pressure controller normally controls this pressure, and any reduction in set point increases C3+ loss to the fuel gas. Key point. The importance of maintaining the optimum

performance of the main air blower and WGC on FCCU and refinery profitability cannot be overemphasized. These two machines are usually the first limitation to increasing the unit throughput. Optimizing the unit operation (including the reactor/regenerator pressure balance and cracking variables) will potentially provide some incremental coke burning or wet gas recovery capacity. In many cases, low-cost modifications may be possible to either or both machines to increase capacity. Debottlenecking the FCC main air blower and/or the WGC continues to be a primary objective of the refiner. HP Jack R. Wilcox is the fluid catalytic cracking process specialist in the Applications Technology group of Albemarle Corp. He has over 40 years of experience providing FCC technical services, process development and design engineering for Refining Process Services, Akzo-Nobel, Filtrol Catalysts and UOP. He holds a BS degree in chemical engineering from the University of Illinois and is a registered professional engineer in Illinois.



What are the corrosion issues for gasohol? New study investigates metal deterioration from ethanol-blended gasoline J. RAWAT, P. V. C. RAO and N. V. CHOUDARY, Bharat Petroleum Corp. Ltd., Surajpur, India


ue to the spiraling crude oil prices, refining companies along with federal governments are seriously considering alternative fuel strategies. These efforts involve blending alternate fuels, such as ethanol and biodiesel, into gasoline and diesel, respectively. For example, 5% blending of ethanol into gasoline is mandatory in several Indian states. In addition, the Indian government is proposing to increase the ethanol content to 10% in gasoline blends. Ethanol-blended gasoline will aid in reducing particulate emissions for compression-ignition engines due to more efficient combustion. Conversely, ethanol-blended gasoline can accelerate corrosion for susceptible metals used in the fuel infrastructure such as pipelines, storage tanks, car-fueling systems, etc. Ethanol’s hygroscopic nature fosters the corrosion processes.

Gasohol. Ethanol-blended gasoline is commonly known as gasohol. Gasohol refers to ethanol’s greater affinity to water; ethanolblended gasoline can absorb significant amounts of water (0.3 vol%/vol% to 0.5 vol%/vol%) without phase separation. The soluble water in the ethanol attacks metal and thus causes corrosion. Accordingly, corrosion inhibitors are added to ethanol-gasoline blends to reduce corrosion processes. The following examples report the effects of gasohol on corrosion rates for different construction materials, including carbon steel (CS), brass and copper. Energy-security options. The global energy/fuel crisis has triggered the awareness among many nations to develop energy-security and alternative-fuel programs. When ethanol is added to gasoline, it modifies the fuel properties, and it does affect exhaust and emissions from vehicles. In India, a 5% ethanol-fuel blend is referred to as E5, and E5 transportation fuel is mandatory for consumers. There are discussions to increase the ethanol concentration to 10% or E10. In European countries, ethanol blending in gasoline ranges from 20% to 85% ethanol. Brazil uses 100% ethanol as a transportation fuel. Ethanol and gasoline have different physical properties such as octane number, vapor pressure, etc. Ethanol-blended gasoline has a higher vapor pressure and a better octane number than the individual components. The important property changes are higher vapor pressure and octane number of the blended compounds to the base gasoline. They are enhancements to the air-to-fuel ratio and dilution effect of gasoline.1 Distribution issues. Ethanol is not easily transported via pipelines because it has a tremendous affinity to absorb water. Water accumulation in pipelines is a normal occurrence. In most cases, the water

enters the system through terminal or storage tank roofs, or it can be dissolved in fuels during the blending process (ethanol into gasoline). Ethanol-blended gasoline storage is very critical. Storage requires moisture-resistant tanks with good internal linings. Once blended at the terminals, the gasohol should be transported via truck/tanker to retail outlets and distributed like gasoline. Some preparatory steps are required to avoid water contamination.2 Ethanol is completely miscible in water. In the presence of moisture- (water) contaminated gasoline, ethanol-blended fuel shows phase separation, i.e., water dissolves in the ethanol and forms a layer that separates from the gasoline. The tank product is no longer an ethanol-gasoline blended fuel. It is two layers of product—a gasoline layer (top) and an ethanol layer (bottom).3 The phase separation can create problems for storage tanks and vehicle fuel lines. Ethanol can dissolve and carry impurities present inside the multi-product pipeline systems, causing more harm to the motor vehicle engines.4 Corrosion mechanisms. Ethanol, in high concentrations, can lead internal-stress corrosion cracking, which is difficult to detect and to manage. This process may be accelerated at the weld joints or “hard spots” where the steel metallurgy has been altered. To overcome these problems, improved post-weld heat treatment and coating of the internal critical zones (at pipeline weld points) should be explored.5 Ethanol can accelerate corrosion in the steel of storage-tank systems by scouring or loosening deposits on the internal surfaces of tanks and piping. If a corrosion cell exists, then the ethanol can accelerate (scour) the corrosion cell and cause perforations. Ethanol is not compatible with soft metals such as zinc, brass, copper, lead and aluminum. These metals will degrade or corrode when in contact with ethanol, and they could possibly contaminate a vehicle’s fuel system.6 Some nonmetallic materials may also degrade when in contact with ethanol such as natural rubber, polyurethane, adhesives (used in older fiberglass piping), as well as certain elastomers and polymers used in flex piping, bushings, gaskets, meters, filters and materials made of cork.7 It has been observed that the storage and transportation of ethanol-gasoline blended fuels are very critical issues. So, selecting suitable corrosion inhibitors for various metals under different moisture conditions is required. There is no systematic study available on this subject. This article addresses corrosion studies of CS, brass and copper (commonly used in storage tanks, and in fuel tanks of engines and pipelines) on various ethanol-gasoline blends under different moisture conditions along with the effect of corrosion inhibitors on test blends. HYDROCARBON PROCESSING MAY 2012

I 109



The experiment. The experiments were conducted to determine the corrosivity of ethanol blends with gasoline using different construction metals. The chemicals used in the study included: • Ethanol samples collected from BPCL installations • Gasoline from BPCL installations • Corrosion inhibitor, in-house synthesized • All reagents used in the lab experiments are analytical grade, and ultra-pure water was used for the dilutions. Corrosion studies. Ethanol was blended in gasoline at varying percentage—from 5% to 100%. Samples containing 5% ethanol with gasoline are referred to as E5, E10 and E20–E100. The weightloss studies were done using CS, brass and copper coupons according to ASTM G1-90 and ASTM G 31-72.8 The experimental setup consisted of a closed-reaction vessel and a constant temperature bath. Various corrosion coupons were placed with the help of specially

Corrosion rates, mmpy

12 CS Copper Brass


Potentiodynamic polarization studies. For potentiodynamic polarization studies, the metal strips were coated with a commercially available lacquer with an exposed area of 1 cm2, and all experiments were carried out at temperature (30°C ± 1°C). The equilibrium time leading to steady state was 30 minutes. The sweep rate in the potentiodynamic experiment was 1 mV/sec. An in-house-developed non-aqueous electrochemical probe was used for the electrochemical measurements. The corrosion inhibitor containing a fatty acid derivative and organic compounds was dissolved in ethanol. The experiments were conducted on E10 and E20 samples using copper, brass and CS coupons. The weights of the coupons were measured before and after the test, and the corrosion rates (CR) were calculated. The inhibition efficiency (IE) of the inhibitors was calculated using:

CR0 – CRi × 100 CR0 Where: CR0 = Corrosion rate of blank solution CRi = Corrosion rate after adding inhibitor IE =

8 6 4

Scanning electron microscopy. The scanning electron

2 0 E5


E20 E30 E40 E50 E60 E70 E80 Gasoline-ethanol blends, % ethanol

E90 E100

microscopy (SEM) studies were done to study the morphology of the corroded surface in the presence and absence of inhibitors. The specimens were thoroughly washed with double distilled TABLE 1. Comparison of ethanol, gasoline and its blends

Corrosion rates for various metals from ethanol-gasoline blends.

FIG. 1

14 Corrosion rate, mmpy

designed coupon holders. The temperature was kept at 50°C + 2°C. The specimens were degreased using acetone and finally dried. The cleaned specimens were weighed before and after the experiments.




Ethanol blends E10 E20




0.73–0.76 0.735–0.765




Oxygen content, wt%





Water solubility, %



> 0.5

> .7





Reid vapor pressure, kpa


CS without inhibitor CS with inhibitor

10 8

Stoichiometric Air to fuel ratio


TABLE 2. Potentiodynamic polarization data obtained from different concentrations of inhibitors with E5, E10 and E20 blends for CS, brass and copper metals

4 2 0 0.3


1.0 Moisture, %



The effects of moisture on corrosion rates of CS with E5 blend.

FIG. 2

Ecorr , mv

Icorr , mAcm–2

IE, %

E5 E5 + 10 ppm inhibitor E10 E10 + 15 ppm inhibitor E20 E20 + 15 ppm inhibitor

–560 –556 –554 –556 –558 –554

0.20 .010 0.28 0.016 0.36 0.020

– 95.0 – 94.3 – 94.4


E5 E5 + 10 ppm inhibitor E10 E10 + 15 ppm inhibitor E20 E20 + 15 ppm inhibitor

–360 –356 –346 –344 –350 –352

0.12 .006 0.14 .008 0.16 .010

– 95.0 – 94.2 – 93.8


E5 E5 + 10 ppm inhibitor E10 E10 + 15 ppm inhibitor E20 E20 + 15 ppm inhibitor

–310 –308 –320 –324 –328 –330

0.18 0.008 0.20 .012 0.24 0.014

– 95.6 – 94.00 – 94.2



Carbon steel

Corrosion rate, mmpy

12 CS without inhibitor CS with inhibitor Copper without inhibitor Copper with inhibitor Brass without inhibitor Brass with inhibitor

10 8 6 4 2 0 E5

FIG. 3




E20 E30 E40 E50 E60 E70 Gasoline-ethanol blends, % ethanol



The effects of inhibitors with various blends of ethanol and gasoline on metals.

I MAY 2012

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water before putting them onto the slide. The images were taken at appropriate magnifications (x 3,000 μ). To understand the morphology of the steel surface in the absence and presence of inhibitors, several cases were examined. –300

4 3

Potential, mV


5 2 1


–600 0.001

4 3 5 0.01 0.1 Current density, m Acm2


1 1

FIG. 4

Tafel plots.

FIG. 5

SEM results of CS immersed in gasohol with and without inhibitor treatment.


Select 177 at

Testing results. The experiments were done, using various

blends of ethanol by weight-loss studies and potentiodynamic studies. The blends were tested for their effect on different metallurgy with varying moisture content. The study also investigated the effect of corrosion inhibitors on corrosion for various metals. Different metals and ethanol. The experiments were conducted on CS, brass and copper with various ethanol-gasoline blends. The results are shown in Fig. 1. The data shows that the corrosion rate increases with a higher ethanol content in the gasoline. As corrosion mainly occurs due to the presence of water/ moisture in the blends, and with the increasing ethanol content, the moisture level, likewise, rises. The results are higher corrosion rates. The maximum increase in corrosion rate was observed for CS. This action is mainly due to the higher carbon and iron content in the alloy, which makes it even more susceptible to corrosion processes. Moisture and ethanol blends. Fig. 2 shows the effect of moisture on the corrosion rates of CS with E5 blends. The CS metallurgy is selected for its moisture effect on the corrosion rate as this condition is generally encountered in pipelines and storage tanks. From Fig. 2, there is an increase in the corrosion rate with rising moisture levels. For example, an increase in the moisture content from 0.3% to 55% caused the corrosion rate to increase from 2.5 mmpy to 12 mmpy. A significant decrease in the corrosion rate (< 2 mmpy) was observed after adding a corrosion inhibitor (10 ppm–20 ppm). Inhibitors and ethanol blends. The effects of inhibitors were studied with varying blends of ethanol and gasoline on metals including CS, copper and brass. The results are shown in Fig. 3. The observed results indicate that a significant decrease in corrosion rates occurred for all tested metals with all ethanol-gasoline

Select 178 at

CORROSION CONTROL blends when an inhibitor is added. The maximum increase in corrosion rate was observed for CS test materials. Overall, the inhibitor demonstrated a mitigation efficiency of 95% for all test blends when used in a concentration range of 10 ppmâ&#x20AC;&#x201C;20 ppm. Potentiodynamic polarization studies. Corrosion can

be measured through electrochemical parameters such as corrosion current density (Icorr ), corrosion potential (Ecorr ) and inhibition efficiency (IE). These measurements can be done for all the ethanol-gasoline blends using test metals such as CS, copper and brass metals. Table 2 summarizes the test results. The results indicate that Icorr values for all of the inhibited metal coupons are lower than for uninhibited coupons. For the E5 blend, the 10 ppm inhibitor can demonstrate 95% inhibition efficiency with all the metals. Conversely, in the cases using E10 and E20, increasing the inhibitor concentration to 15 ppm also demonstrated good inhibition efficiency at 94% to 95% levels, as shown in the Tafel plots (Fig. 4). From the Ecorr values, the inhibitor is a mixed type, i.e., it protects corrosion on both anodic and cathodic sites of the metals.10


Observations. Several conclusions can be drawn from this

study, and they include: 1. Corrosion rates in ethanol-gasoline blends increase with rising ethanol concentration. Because moisture susceptibility increases at higher ethanol concentrations, corrosion rates also increase. 2. Different metals will demonstrate varying corrosion rates with increasing ethanol concentration in gasoline. 3. CS has the maximum corrosion rate. 4. The corrosion rate of gasoline-ethanol blends increases with rising moisture content. Phase separation does occur, and it contributes to the corrosion process. Inhibitors are proven effective in managing corrosion rates. 5. An in-house synthesized corrosion inhibitor can demonstrate good performance on all the metals with varying blends of gasolineâ&#x20AC;&#x201C;ethanol as measured by potentiodynamic polarization methods. HP Acknowledgments and Literature Cited available online at

Scanning electron microscopy. SEM was done on the CS

Jaya Rawat is a deputy manager for R&D, at the Corporate R&D Centre of Bharat

surface blank, as well as after treating the blank with E-10 gasohol blend and corrosion inhibitor. Fig. 5 shows the SEM graphs for a polished mild-steel specimen and CS specimen after a 30-minute immersion in a gasohol blend containing 500 ppm inhibitor. The CS surface, immersed in the inhibited solution, was smoother than the blank immersed in the gasohol blend. Accordingly, the inhibitor is adsorbed onto the metal surface and forms a protective layer that mitigates acid attacks.11

Peddy V. C. Rao is senior manager for R&D, with Bharat Petroleum Corp., Ltd.

Petroleum Corp., Ltd., Surajpur, India. She holds a PhD in chemistry. Dr. Rawat has 10 years of professional experience at BPCL R&D in refinery corrosion problems and mitigation; core areas include developing corrosion inhibiting additives. Dr. Rawat holds five patents and has authored 50 articles.

He holds a PhD in chemistry from Indian Institute of Technology, Bombay, India.

N. V. Choudary is a chief manager for R&D with Bharat Petroleum Corp., Ltd. He holds a PhD in chemistry, has authored over 70 research papers and filed over 50 patents.

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ABB SpA—Process Automation Division . 20


Foster Wheeler . . . . . . . . . . . . . . . . T-84


Milliken Workwear . . . . . . . . . . . . . . 62


Altair Strickland. . . . . . . . . . . . . . . . . 36


Amistco . . . . . . . . . . . . . . . . . . . . . . 34


(53) (63)

BETA . . . . . . . . . . . . . . . . . . . . . . . . 107 (171)


Borsig GmbH. . . . . . . . . . . . . . . . . . . 23 (153)

Bryan Research & Engineering . . . . . . 67


CB&I . . . . . . . . . . . . . . . . . . . . . . . . T-90


Chemstations Inc. . . . . . . . . . . . . . . . 16 (152)

Colfax Americas . . . . . . . . . . . . . . . . 14


Cudd Energy Services . . . . . . . . . . . 107 (172)

Curtiss Wright Flow Control Company, Delta Valve . . . . . . . . . . . . . . . . . . . 46 (100)

Curtiss Wright Flow Control Company, Farris Engineering . . . . . . . . . . . . . . 52

Flexim Americas Corp. . . . . . . . . . . . . 38 (159) (93)

Flir Systems, Inc . . . . . . . . . . . . . . . . . 32 (156)

Quest Integrity Group LLC . . . . . . . . . 39 (161) Rentech Boiler Services . . . . . . . . . . . . 2



Idrojet . . . . . . . . . . . . . . . . . . . . . . . 112 (177)

Selas Fluid Processing Corp . . . . . . . . 18



Servomex Ltd. . . . . . . . . . . . . . . . . . . 42 (163)

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Shin Nippon Machinery Co., Ltd. . . . . 26 (154)

Inpro / Seal Company . . . . . . . . . . . . . 4 (151) (77)

Spraying Systems Co . . . . . . . . . . . . . 10


Sulzer Chemtech, USA Inc.. . . . . . . . . 29


Swagelok Co. . . . . . . . . . . . . . . . . . . 51


ThyssenKrupp Uhde GmbH . . . . . . . . 68



Trachte USA . . . . . . . . . . . . . . . . . . 106 (175)

Messe Dusseldorf North America . . . 108 (169)

United Laboratories International LLC 79



Microtherm . . . . . . . . . . . . . . . . . . . . 35 (158)

SO.CA.P. SRL . . . . . . . . . . . . . . . . . . 113 (179)

Metso Automation . . . . . . . . . . . . . . 75


Linde Process Plants . . . . . . . . . . . . 119

Siemens Ag . . . . . . . . . . . . . . . . . . . 17


Scott Safety . . . . . . . . . . . . . . . . . . . . 61


Pittsburgh Corning Corporation . . . . . 71


Levelese . . . . . . . . . . . . . . . . . . . . . T-87 (181)


Samson GmbH . . . . . . . . . . . . . . . . . 72 (176)

Lar Process Analysers. . . . . . . . . . . . 112 (178)

Eidos Sap SRL . . . . . . . . . . . . . . . . . . 39 (160)

PARCOL Spa . . . . . . . . . . . . . . . . . . . 27


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Egger & CIE S.A. . . . . . . . . . . . . . . . . 59 (165)

ONS . . . . . . . . . . . . . . . . . . . . . . . . T-89 Paharpur Cooling Towers, Ltd. . . . . . . 45 (102)

ITW Polymer Technologies/Chockfast 106 (174)

Dixon Valve . . . . . . . . . . . . . . . . . . . 101 (170)

Flexitallic LP . . . . . . . . . . . . . . . . . . . . 5

ITT Industries . . . . . . . . . . . . . . . . . . 22 (80)

Neptune Research . . . . . . . . . . . . . . 113 (180)

Hoerbiger . . . . . . . . . . . . . . . . . . 40–41 (162)

Emerson Process Management (Fisher) . . . . . . . . . . . . . . . . . . . . . . 24

ILTA . . . . . . . . . . . . . . . . . . . . . . . . T-94


Gulf Publishing Company Construction Boxscore . . . . . . . . . . . 58 HPI Market Data 2012. . . . . . . . . . 116 HPI Marketplace . . . . . . . . . . 114–115 IRPC 2012 Milan . . . . . . . . . . . . . . 6–9 Workforce Survey . . . . . . . . . . . . . 116 HTRI . . . . . . . . . . . . . . . . . . . . . . . . . 33 (157)

Hydro, Inc.. . . . . . . . . . . . . . . . . . . . . 12

Nace International. . . . . . . . . . . . . . 111

GEA Wiegand GmbH . . . . . . . . . . . . 106 (173)

Howden . . . . . . . . . . . . . . . . . . . . . . 43

MSA Instrument Division . . . . . . . . . . 28 (155)


Bete Fog Nozzle . . . . . . . . . . . . . . . . 76

GE Oil & Gas . . . . . . . . . . . . . . . . . . . 56

ARCA Valves . . . . . . . . . . . . . . . . . . 108 (168)

Baldor Electric Company . . . . . . . . . 102

FourQuest Energy . . . . . . . . . . . . . . . 60 (166)

Axens . . . . . . . . . . . . . . . . . . . . . . . 120

Weir Minerals Lewis Pumps . . . . . . . . 30


Zeeco . . . . . . . . . . . . . . . . . . . . . . . T-92


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Case 68: Pneumatic testing dangers Use caution on what defines a true ‘safe distance’ T. SOFRONAS, Consulting Engineer, Houston, Texas


’ve written previously on hydro and pneumatic testing and how it’s an engineer’s responsibility to question dangerous conditions.1,2 Unfortunately, I still see failures and have been asked what is a safe distance to be at when performing a pneumatic test.3,4 When defining “safe distances” from a pneumatic explosion, a major concern is defining the numerous flying fragments. To understand the energy involved in pneumatic testing, the pressurized air will be treated as a compressed spring. The energy released will be used to propel a fragment horizontally. Fig. 1 shows a fictitious gas spring in a vessel with a spring constant, k, in lb/in., and compressed , in. The diameter of the fragment is D, and the pressure is p, lb/in.2 In this example,  could be the length of a pipe or the diameter of a vessel, d. The pneumatic spring constant is: k = p  (π/4) D 2 /  (lb/in.) The potential energy (PE) in a spring is: PE = ½ k  2 = ½ p  (π/4) D 2   in.-lb The kinetic energy (KE) of the fragment W is: KE = ½ (W/g )  V 2 d ␦ k, p Fragment, W



Equate KE = PE and solve for fragment velocity, V: V = 17.4D ( p   / W ) ⁄ in./sec 1


This velocity can now be used in a simple trajectory calculation to estimate the distance that the fragment will travel horizontally. R is the horizontal range that W travels at initial velocity, V, from a height, h, ft: R = (V/24)  ( 2  h/32.2 ) ⁄ ft 1


Fig. 2 represents the fragment’s flight path with averaged velocity. Fragments of different sizes will have varying ranges. Stating a safe distance isn’t possible unless you know the size. For example, with a 200-lb/ in.2 pneumatic explosion of a pipe with D = 10 in., h = 10 ft and  = 50 in, a fragment, W = 0.1 lb, will have R = 1,800 ft. However, with a fragment of W = 25 lb and R = 114 ft, there are many possibilities. Detailed trajectory calculations considering departure angles and air friction still require that these variables are defined. It’s always prudent to look for alternatives when pneumatic testing large volumes. Options such as localized hydrotesting with small volumes involve sections of pipe instead of the whole pipeline. Nondestructive testing of welds and critical areas is another option. Consider reviewing the historical hydrotesting of a modified vessel and only testing the portions that were modified can be used. This may require temporary weld on caps. Strive to recognize codes if you must pneumatically test. Remember: There may be no reasonable “safe distance” or “exclusion zone.” The safe distance specified could reference a blast pressure wave, not flying fragments. A ruptured 25-lb pipe-end fragment with an air volume of 140 ft3 at 200 lb/in.2 is like a locomotive engine traveling at 15 mph or one pound of TNT. All possess about 1.5 million ft-lb of KE. It is something to seriously consider when discussing pneumatic testing. HP LITERATURE CITED Sofronas, T., “Case 34: Hydrotesting or pneumatic testing,” Hydrocarbon Processing, September 2006. 2 Sofronas, T., “Case 65: Taking risks and making high-level presentations,” Hydrocarbon Processing, November 2011. 3 “Pneumatic Test Explosion in Shanghai LNG Terminal,” Chemical & Process Technology, March 2009. 4 “Pneumatic Test Failure in Mississippi Pipeline Project,” Chemical & Process Technology, July 2009. 1

FIG. 1

A compressed air model.


Vavg h

Dr. Tony Sofronas, P.E., was the worldwide lead mechanical FIG. 2


Fragment range and flight path of debris.

I MAY 2012

engineer for ExxonMobil before his retirement. He is now the owner of Engineered Products, which provides consulting and engineering seminars. He can be reached through the website http://mechanical by clicking on the comments/question tab.

CRYO-PLUS™ Get More Valuable Liquid from your Gas Streams Linde Process Plants, Inc. provides engineering, design, fabrication and construction of cryogenic plants for the extraction of hydrocarbon liquid from natural gas, refinery and petrochemical gas streams. Recovered liquid components can include ethylene, ethane, propylene, propane, isobutane as well as other valuable olefinic and paraffinic hydrocarbons. Combine your CRYO-PLUS™ plant with a Linde PSA to recover high purity hydrogen from refinery and petrochemical off-gas streams.

Why choose Linde’s CRYO-PLUS™ – Proprietary technology with a proven track record in: – Refinery Off-Gas – Petrochemical Off-Gas – Natural Gas – Robust, adaptable and flexible design, and operation – Typical payout times of six (6) months to two (2) years

A member of The Linde Group Linde Process Plants, Inc. 6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA Phone: +1.918.477.1200, Fax: +1.918.477.1100,, e-mail: Select 85 at

Your objectives in focus Make the most of today’s and tomorrow’s challenges with leading-edge solutions from Axens - Clean and alternative fuel technologies - Petrochemicals - Energy efficiency - High performance catalysts & adsorbents - Revamps

Single source technology and service provider ISO 9001 – ISO 14001 – OHSAS 18001 Select 53 at


Hydrocarbon Processing [May 2012]

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