HP_2010_08 by androsov.info

AUGUST 2010

HPIMPACT

SPECIALREPORT

SPECIALSUPPLEMENT

MIT studies natural gas future

FLUID FLOW AND ROTATING EQUIPMENT

PROCESS CONTROL AND INSTRUMENTATION

PLC market to rebound

Pumps, valves, drives and compressors

Report includes 2010 trends and spending forecasts

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AUGUST 2010 • VOL. 89 NO. 8 www.HydrocarbonProcessing.com

SPECIAL REPORT: FLUID FLOW AND ROTATING EQUIPMENT Prevent electric erosion in variable-frequency drive bearings

Here are the reasons and remedial actions H. P. Bloch

Valve design reduces costs and increases safety for US refineries The goals were achieved by using alloys with superior corrosion resistance R. D. Johnson and B. Lee

Pump aftermarket offers solutions for abrasive services

How the inertia number points to compressor system design challenges

Upgrades substantially increased MTBR S. McPherson

C o v e r L . A . Tu r b i n e p r o v i d e s Turboexpander service for clients worldwide. Here on location at Total’s LPG N’Kossa Offshore Processing Plant in the Republic of Congo, L.A. Turbine remanufactured two Turboexpanders with Active Magnetic Bearings which are being re-installed supervised by experienced field service personnel. Photo courtesy of L.A. Turbine

It facilitates predicting compressor system performance M. Kapadia, R. Tellez-Schmill and I. Ajdari

ENVIRONMENT/LOSS PREVENTION Gas refineries can benefit from installing a flare gas recovery system

Take a look at these environmental and economic paybacks O. Zadakbar, A. Vatani and S. Mokhatab

STORAGE/LOSS PREVENTION Estimating tank calibration uncertainty

Better recovery definition of C3s and C4s from gas absorber/stripper can lower costs J. Nava

PROCESS CONTROL AND INSTRUMENTATION 2010—SUPPLEMENT Process Control and Instrumentation 2010 Report includes trends and spending forecasts

HEAT TRANSFER Increase crude unit capacity through better integration

15 PLC and PLC-based PAC market poised to rebound

Use these calculations for a specific tank calibration S. Sivaraman, A. Bertotto and D. Comstock

GAS PROCESSING DEVELOPMENTS Optimize operating parameters of absorbers/strippers in gas plants

HPIMPACT 15 MIT studies the future of natural gas

In revamp projects, better energy integration provides more benefits with less capital investment and lower operating costs A. S. Aseeri, M. S. Amin and M. S. Ibrahim

DEPARTMENTS 7 HPIN BRIEF • 17 HPINNOVATIONS • 21 HPIN CONSTRUCTION 25 LETTERS TO THE EDITOR • 26 HPI CONSTRUCTION BOXSCORE UPDATE 82 HPI MARKETPLACE • 85 ADVERTISER INDEX

HP ONLINE EXCLUSIVES Petrochemical Processes 2010 Just released, HP’s Petrochemical Processes 2010 handbook is an inclusive catalog of established and leading-edge licensed technologies for existing and grassroots facilities. Over 191 petrochemical technologies from 40 licensing companies are presented in this handbook. Features include flow diagrams, process descriptions, economic data and more. A free PDF copy is available to subscribers for a limited time at www.HydrocarbonProcessing.com.

COLUMNS 9 HPIN RELIABILITY Consider bearing protection for small steam turbines 11 HPIN ASSOCIATIONS International Refining Conference debuts in Rome 13 HPIN CONTROL Process control practice renewal 2010—purpose 86 HPIN AUTOMATION SAFETY Cyber security certification for automation products and suppliers

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HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2010 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

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AVEVA Plant Integrated plant engineering and design technology Engineering IT has come of age. The days of inconsistent, disconnected 2D drawings, incompatible CAD formats and ‘over the wall’ project handover are being consigned to the history books. Today, a powerful, integrated and collaborative IT environment supports every stage of project execution – AVEVA.

Whether on complex new-build projects or in-service revamps, the smallest inefficiencies or delays cost real money. AVEVA Plant enables maximum productivity at every stage, reducing costs and timescales, eliminating the causes of errors, waste and rework, and removing limitations on project scale and global collaboration. And it’s the no-risk solution, proven on tens of thousands of projects by many of the world’s most successful engineering businesses.

Find out how AVEVA Plant can make your business more competitive Visit www.aveva.com to learn about the AVEVA Plant solutions, or www.aveva.com/events for opportunities to see them in action.

Head office: High Cross, Madingley Road Cambridge CB3 0HB UK marketing.contact@aveva.com Tel +44 (0)1223 556655 Select 54 at www.HydrocarbonProcessing.com/RS

HPIN BRIEF BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Curtiss-Wright Corp. has received an order from Petrobras for 12 top and bottom fully-automated coke drum unheading systems. The units are expected to be delivered to the Petrobras Abreu e Lima refinery located in Pernambuco, Brazil. During the opening of a coke drum, known as “unheading,” extreme temperatures can be present. Curtiss-Wright’s system safely opens the top or bottom of a coke drum during the delayed coking process. Unlike traditional unheading systems, this remotely operated device creates a totally enclosed, fully automated coking system, from the top of the coke drum down to the coke pit, minimizing safety risks to personnel.

Total Petrochemicals has successfully demonstrated UOP technology that will enable the use of feedstocks other than petroleum to produce plastics and other petrochemicals. A demonstration unit built by Total Petrochemicals at its complex in Feluy, Belgium, used UOP’s methanol-toolefins (MTO) technology to convert methanol to ethylene and propylene. The propylene was then successfully converted to polypropylene product. This demonstration proves that propylene produced from methanol at a semi-commercial scale is suitable for plastics production. The demonstration unit has run consistently for more than 150 days since its start-up last year and has met product yield expectations. The unit has processed up to 10 metric tpd of methanol to produce the light olefins ethylene and propylene. The demonstration plant integrates MTO process technology with Total Petrochemicals’ and UOP’s olefin cracking process (OCP). Use of the OCP could boost the total yield of usable ethylene and propylene while minimizing hydrocarbon byproducts. The OCP unit is scheduled to start up later this year after initial testing of the MTO unit is completed. The demonstration plant was designed to assess, on a semi-commercial industrial scale, the technical feasibility of the integrated MTO and OCP processes with full product recovery and purification.

ProSep Inc. was awarded a $2 million contract to provide process engineering and specialized internals for crude separation. This contract was awarded through a commercial alliance with the engineering and manufacturing company Thermo Design and will be installed at an oil and gas producer’s steam-assisted gravity drainage facility located in Alberta’s oil sands. The crude separation equipment will be built using ProSep’s vessel designs and internals, allowing for efficient separation of crude, natural gas, water and solids from the production stream.

Refineria de Cartagena SA (REFICAR) has selected Merichem to provide multiple technologies for treatment of hydrocarbons and spent caustic at its refinery in Cartagena, Colombia. Merichem will license its technologies and supply modular equipment to treat coker LPG and saturated LPG at the facility. Merichem will also license other technologies to supply modular equipment, including salt and clay beds for treatment of kerosene/jet fuel. In addition, REFICAR has also selected Merichem’s technology and equipment for the treatment of spent caustic generated by new and existing units.

CPFD Software LLC, which created the Barracuda simulation package for particle-fluid systems, announced the signing of a distribution agreement with Hi-Key Technology to distribute and support Barracuda in China. Barracuda is used by oil and gas, chemical, petrochemical and power equipment manufacturers for simulating, understanding and optimizing the operation of fluidized systems. Common applications are fluidized catalytic cracking (FCC) reactors and regenerators, fluidized bed reactors (FBRs) for chemical manufacturing and circulating fluidized bed (CFB) boilers in coal-fired power plants. HP

■ A diamond in the rough Although problem-free pump operation is the primary goal of all pump operators, achieving that goal is not a simple matter. The key components of a pump—mechanical seals, impellers, couplings, roller bearings and housings—are all subject to wear. Keeping a pump in good working condition is essential for cost-effective and reliable operation of plants and systems. Unplanned downtime can ruin production schedules and adversely affect a facility’s bottom line. Mechanical seals are recognized to be responsible for most pump failures and consequently represent the highest cost for pump repairs. Therefore, reducing the mean time between failure (MTBF) or the mean time between repair (MTBR) can significantly improve pump operations and save money. Industry surveys have shown that dry running and inadequate lubrication are responsible for more than 50% of all mechanical seal damages; consequently, it is safe to state that approximately 20% of all pump failures are due to poor lubrication or dry running of the mechanical seal faces. To combat the problem of dry running, EagleBurgmann has developed a seal face coating based in diamond. Diamond is the hardest natural mineral known and offers excellent chemical and thermal resistance. The new technology is a synthetically manufactured, ultra-pure diamond with the same characteristics as the natural stone. It has a microcrystalline coating of 8-µm thickness on a silicon carbide seal face extends the life of the seal, reducing maintenance costs and minimizing life-cycle costs for pump users. In an analysis of the service life of pump components, it was found that mechanical seals, with an average service life of only 1.2 years, are the weakest link in terms of pump components, compared to the next weakest component, bearings, with an average service life of three years. It is thought that by using mechanical seals coated with diamond, the average service life of mechanical seals substantially increases. HP HYDROCARBON PROCESSING AUGUST 2010

THE ORIGINAL BEARING ISOLATOR STRONGER THAN EVER

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Trust Inpro/Seal, the clear leader in bearing isolators.

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

Consider bearing protection for small steam turbines In most small machines there is a need to limit both contaminant ingress and oil leakage. Inexpensive lip seals are sometimes used for sealing at the bearing housing, but lip seals typically last only about 2,000 operating hours—three months. When lip seals are too tight, they cause shaft wear and, in some cases, lubricant discoloration known as “black oil.” Once lip seals have worn and no longer seal tightly, oil is lost through leakage. This fact is recognized by the API-610 standard for process pumps, which disallows lip seals and calls for either rotating labyrinth-style or contacting face seals. Small steam turbines often suffer from steam leakage at both drive- and governor-end sealing glands. Each bearing housing (Fig. 1) is located adjacent to one of these two glands, which contain carbon rings. It is a well-known fact that, as soon as the internally split carbon rings start to wear, high-pressure and high-velocity leakage steam finds its way into the bearing housings. Traditional labyrinth seals have proven ineffective in many such cases and only solidly engineered bearing protector seals now manage to block leakage steam passage. The bearing housing protector seal in Fig. 2 was designed for steam turbines. It incorporates a small- and a large-diameter dynamic O-ring. This bearing protector seal is highly stable and not likely to wobble on the shaft; it is also field-repairable. With sufficient shaft rotational speed, one of the rotating (“dynamic”) O-rings is flung outward and away from the larger O-ring. The larger cross-section O-ring is then free to move axially and a micro-gap opens up. When the turbine is stopped, the outer of the two dynamic O-rings will move back to its stand-still position. At stand-still, the outer O-ring contracts and touches the larger cross-section O-ring. In this highly purposeful design, the larger cross-section O-ring touches a relatively large contoured area. Because Contact Pressure = Force/Area, a good design aims for low pressure. Good designs differ greatly from technologically outdated configurations wherein contact with the sharp edges of an O-ring groove will cause O-ring damage. Fortunately, concerns as to the time it might take to upgrade to advanced bearing protector seals have been alleviated. In June 2009 Total Raffinaderij Nederland (TRN) asked for the installation of the bearing protector seal shown in Fig. 2 in one of its 350 kW/3,000-rpm steam turbines. No modifications were allowed on the existing equipment and installation of three LabTecta-STAX seals on the first machine had to take place during a scheduled plant shutdown in June 2009. With no detailed drawings of the bearing housings available, the exact installation geometry could only be finalized after dismantling the Turbodyne turbine. One of the main problems was the short outboard length: less than 0.25 in. (6.35 mm) was available due to the presence of steam deflectors and oil flingers. But the manufacturer’s engineers were able to modify the advanced design in Fig. 2 to fit into the existing OEM labyrinth seal groove. Delivery was made within one week of taking steam turbine and

bearing housing measurements and the turbine has been running flawlessly since June 2009. Our point is that highly cost-effective equipment upgrades are possible at hundreds of refineries. However, superior bearing protector products for use in steam turbines must be purposefully developed. The type described here has important advantages compared with standard products typically used in pumps: • It is suitable for high temperatures. • It incorporates Aflas O-rings as the standard elastomer. • Extra axial clearance is provided to accommodate thermal expansion. • High-temperature graphite gaskets are incorporated in this design. There should no longer be any reason for water intrusion into the bearing housings of small steam turbines at reliability-focused HPI facilities. HP The author is HP’s Equipment/Reliability Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost-avoidance topics. Mr. Bloch has authored or coauthored 17 textbooks on machinery reliability improvement and over 470 papers or articles dealing with related subjects.

Drive-end Drive-end outboard inboard

Governor-end inboard

FIG. 1

Small steam turbine cross-section view (Source: Worthington-Turbodyne S.A.).

FIG. 2

Cross-sectioned half-view of a bearing housing protector seal for small steam turbines (Source: LabTecta-STAX, AESSEAL Inc., Rotherham, UK and Rockford, TN). HYDROCARBON PROCESSING AUGUST 2010

Sharper Detection of Off-Angle Cracks Team Phased Array Scanner Improves Inspection Results

Leak Repairs Field Heat Treating Field Machining

NDE/NDT INSPECTION Hot Taps / Line Stops Technical Bolting Valve Repair Valve Insertion

he world leader in NDE/NDT Inspection, Team now brings you the Phased Array Scanner. Lower costs, higher quality, greater speed … you get all the advantages of phased array in a highly advanced system. Driven by high-speed electronics and real-time imaging, Team’s Phased Array Scanner reveals the precise location and size of off-angle cracks, f laws and defects. Inspection time and costs are reduced as Team technicians produce fast, detailed cross-sectional images of welds and other internal features. Flaws or defects are measured accurately and marked for repair immediately following examination. From small boiler tubes to massive turbines and vessels, Team’s Phased Array Scanner saves you time and money by delivering fast, accurate results. Call +1-800-662-8326 or visit www.teamindustrialservices.com/phasedarray. Select 73 at www.HydrocarbonProcessing.com/RS

Emissions Control Pipe Repair Services

HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

International Refining Conference debuts in Rome Hydrocarbon Processing’s International Refining Conference (IRC) debuted June 21–23 in Rome, Italy. Hosted by eni, the event included a two-day, twotrack technical conference as well as an exhibition. Attendance surpassed initial projections and the conference received a “good to excellent” rating from over 80% of the delegates. “The first IRC in Rome has demonstrated that this event gathers highly qualified speakers who provide leadingedge presentations that cover a wide array of technical matters,” said Simberto Senni Buratti, senior vice president for technical development and projects at eni. “Overall, IRC is an outstanding gathering of elite professionals from the global refining industry.” The two track (technology and maintenance and operations) format proved to be a hit with attendees. One gentleman remarked, “A two day, two track conference is the sweet spot. It isn’t overloaded, but it’s not slim on time, either.” Those present were also quite receptive to the focus of the presentations, which zeroed in on technology, lessons learned and prognostications about the future. Speaking of the present and looking to the future, all at the IRC agreed that energy demands will be met by crude oil and natural gas. However, the manner in which the HPI will meet future energy demand growth will evolve from methods and policies under development. Francois Paul Goarin, senior director for energy with Accenture, presented several key messages that describe how the hydrocarbon processing will take shape in the future. He said to expect a future that combines biochemical and thermochemical processes as new mandates require refiners to include more renewable/biofuels for transportation fuel supplies. Existing and developing technologies can and will be leveraged across multiple pathways. To be viable, biofuels must find a way to be included inside the battery limit (ISBL) of the

refinery, not blended at terminals before distribution. “Markets will optimize around their own domestic agendas, resources and economic development opportunities,” Mr. Goarin said. In other words, use what you have or what you can get in order to make it work. IRC attendees agreed that, globally speaking, crude oils are becoming heavier. New refinery feedstocks will include a greater share of unconventional oils such as Canadian oil sands. Such feeds will entail revising refinery operations to yield “cleaner” products with less residuals. As the global appetite for energy shifts to lighter products, refiners must likewise find opportunities to upgrade residuals into distillates. Such dilemmas look at hydrogen addition or carbon reject. Hydrogen addition is making new advances with proven and developing technologies. In a presentation by KBR’s Dr. Anand Subramanian, it was revealed that KBR and BP have developed improvements to the veba combi cracking (VCC) process, which is a slurry-phase resid hydrocracking process. Originally, the VCC was developed to process coal. Advances enable this existing process to yield blendable product streams that do not require further treatment and can compete against coking processes. eni, too, is developing an advanced slurry-phase hydrocracking process known as the eni slurry technology (EST). This process is based on a nano-dispersed

The IRC Advisory Board was happy to be in Rome for the new two-day conference.

(slurry) non-aging catalyst, and a homogeneous and isothermal slurry bubblecolumn reactor. EST can process residual products, heavy oils and bitumen. With successful results from the 1,200-bpd commercial-demonstration plant at eni’s Taranto, Italy, refinery, the first full-scale industrial unit using EST will be constructed at eni’s Sannazzaro dé Burgondi refinery in Pavia. Better catalyst systems were also a hot topic of conversation at the conference, as refiners plan their strategy to convert more of the barrel into distillates, especially ultra-low-sulfur diesel. Albemarle Catalyst BV, Axens, Criterion Catalysts Technologies (Shell) and Grace are making advances in catalyst structure and activity. The goal is producing more diesel while destroying fuel oil, which is experiencing demand decline. In particular, “drop-in” catalyst solutions that will yield more diesel over gasoline make in fluid catalytic cracking units are of high interest. IRC was supported by 25 sponsors and exhibitors. The major sponsors were eni, Walter Tosto and Ansaldo. Exhibitors included Shell Global Solutions, Ametek, Grace, Flowserve, United Labs and other global suppliers to the downstream industry. The IRC Advisory Board was made up of representatives from eni, Shell, BP, Axens, Technip, Walter Tosto, Hydrocarbon Processing and Foster Wheeler. HP

Networking was a jovial affair in the Walter Tosto booth.

HYDROCARBON PROCESSING AUGUST 2010

I 11

GE Oil & Gas

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HPIN CONTROL PIERRE R. LATOUR, GUEST COLUMNIST clifftent@hotmail.com

Process control practice renewal 2010—purpose In April 2010, I followed Allan Kern’s automation reassessment editorial1 with a call to renew the practice of process control and IT in the HPI. Now I follow his thoughtful July 2010 editorial2 on continuous improvement or core competency. After 50 years, it is time to restart with a reminder of the purpose of instrumentation, control systems, IT and CIM, critique weaknesses and offer ways to strengthen their financial performance. As I write this, BP is struggling to contain its Deepwater Horizon well and operate its Texas City, Texas, Refinery. Refiners are struggling for profitability and survival worldwide. The current HPI operating problem is not instruments, valves, control algorithms, tuning, modeling, alarm management, displays, computers, KPIs, best practices, Six-Sigma, ISO9000, SQC, software, information, technology, maintenance, training, management, organization, awareness or culture. These are useful ideas that should be converted to mathematically based actions with the appropriate performance measure. It’s KNOW HOW. Lack thereof. Insufficient competency. The HPI needs the knowhow to identify, capture and sustain maximum expected value profits to always operate right. Situation. HPI plants are operated by adjusting process operating conditions: setpoints, specs and limits on controlled variables (CVs) and key performance indicators (KPIs). All we can do is specify a CV mean and reduce its variance. While process control does the latter, there is no standard method for the former, so it is done by human experience. Therefore, the procedure for assessing the value of reduced variance or dynamic performance is incomplete and invalid. Process control, IT and CIM continue to suffer from a lack of a rigorous standard financial performance measure. People do not agree on the purpose of systems and how to keep score; like whether a touchdown is worth 6 points or 5. Purpose. The purpose of tools, products, layers and systems is to operate plants better: safely and efficiently, as measured by long-term profitability. This is done by identifying CV/KPI measurements that affect profitability, specifying setpoints that optimize the risky financial tradeoffs associated with each and controlling them tightly about those optimum setpoints. My assumption is the only thing operators can affect are process operating conditions (mean and variance), encompassed by sufficient CVs/KPIs. While the knowhow for step 3 has been commercialized since 1960, the failure to adopt a standard method3, 4 for step 2 impedes our ability to relate CVs/KPIs to financial performance. This causes confusion for step 1, inability to specify appropriate models and IT, ad hoc estimates of financial value of step 3 and inability to capture benefits from step 2 with IT. In April 2010 I blamed flawed logic used to quantify the financial value of all process control and IT since 1970 as a basic

cause of the crippling disconnects between the layers, components and technologies. Kern writes about core competencies for operational excellence.2 The method for establishing setpoints to optimize risky CV tradeoffs shows what those core competencies should be and provides the information requirements they should provide for operating excellence. The important inputs are near-term forecasts of CV uncertainties (variance from data historians), process and economic sensitivities to CV means and limit violation consequence cliffs (from models and business). This is the framework for IT requirements and continuous improvement to determine and maintain this information in real time and act upon it faithfully. New idea. The basic idea is to direct the attention of HPI oper-

ations management to the rigorous way3 to determine setpoints to maximize expected value profit from risky tradeoffs for every meaningful CV/KPI. This is essential to deal with disasters plaguing the HPI like refinery explosions, drill-hole well leaks and environmental damage, while maximizing real profit potential. Focusing on subcategory objectives like energy, yield, capacity, quality, inventory, safety, manpower and technology, rather than optimizing the risky financial tradeoffs among them is a basic handicap to success because they are all connected. While safety violations can never be eliminated permanently, surprises can be reduced, remedy plans deployed and learning from mistakes strengthened. Taking intelligent calculated risks is preferable to taking unintelligent uncalculated risks. Adopting the rigorous method3 for setpoints that optimize risky tradeoffs provides the way to evaluate the value of instruments, components, layers, models, IT and solutions. This is the proper path to renewal and success. In the end, Kern1, 2 and Latour3, 4 will unite to provide guidelines for renewing the practice of process control engineering during refinery golden ages and downturns. HP LITERATURE CITED Kern, Allan, “Back to the Future: A Process Control Strategy for 2010,” Hydrocarbon Processing, February 2010. 2 Kern, Allan, “Continuous improvement or core-competency,” Hydrocarbon Processing, July 2010. 3 Latour, P. R., “Process control: CLIFFTENT shows it’s more profitable than expected,” Hydrocarbon Processing, December 1996, pp. 75–80. Republished in Kane, Les, Ed., “Advanced Process Control and Information Systems for the Process Industries,” Gulf Publishing Co. 1999, pp. 31–37. 4 Latour, P. R., “Demise and keys to the rise of process control,” Hydrocarbon Processing, March 2006, pp. 71–80 and Letters to Editor, Process Control, The author Processing, is a principal Hydrocarbon Juneconsultant 2006, p. in 42.advanced process control and online 1

optimization with Petrocontrol. He specializes in the use of first-principles models for inferential process control and has developed a number of distillation and reactor models. Dr. Friedman’s experience spansInc., overis30 in the hydrocarbon industry, The author , president of CLIFFTENT anyears independent consulting chemical working with Exxon Research and Engineering, KBC sustaining Advanced Technology since engineer specializing in identifying, capturing and measurableand financial 1992 with holds acontrol, BS degree fromCIM the Israel Institute of Technology value fromPetrocontrol. HPI dynamicHe process IT and solutions (CLIFFTENT) using (Technion) and a PhDshared degreerisk–shared from Purdue University. performance-based reward (SR2) technology licensing.

HYDROCARBON PROCESSING AUGUST 2010

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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 www.ittoilgas.com or call 1-800-734-7867. Conoﬂow | Enidine | Fabri-Valve | Fiberbond | Goulds | ITT Standard | Midland-ACS | Neo-Dyn Select 86 at www.HydrocarbonProcessing.com/RS

HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

MIT studies the future of natural gas Natural gas will play a leading role in reducing greenhouse-gas emissions over the next several decades, largely by replacing older, inefficient coal plants with highly efficient combined-cycle gas generation. That’s the conclusion reached by a comprehensive study of the future of natural gas conducted by an MIT study group comprised of 30 MIT faculty members, researchers and graduate students. The two-year study, managed by the MIT Energy Initiative (MITEI), examined the scale of US natural gas reserves and the potential of this fuel to reduce greenhouse-gas emissions. The report examines the future of natural gas through 2050 from the perspectives of technology, economics, politics, national security and the environment. The report includes a set of specific proposals for legislative and regulatory policies, as well as recommendations for actions that the energy industry can pursue on its own, to maximize the fuel’s impact on mitigating greenhouse gas. The study also examined ways to control the environmental impacts that could result from a significant expansion in the production and use of natural gas— especially in electric power production. The study found that there are significant global supplies of conventional gas. How much of this gas gets produced and used, and the extent of its impact on greenhouse gas reductions, depends critically on some key political and regulatory decisions. Key findings. The US has a significant

natural gas resource base, enough to equal about 92 years’ worth at present domestic consumption rates. Much of this is from unconventional sources, including gas shales. Globally, baseline estimates show that recoverable gas resources probably amount to 16,200 trillion cf, enough to last over 160 years at current global consumption rates. In the US, unconventional gas resources are rapidly overtaking conventional resources as the primary source of gas production. The US currently consumes around 22 trillion cf per year and has a gas resource base now thought to exceed 2,000 trillion cf.

In order to bring about the kind of significant expansion in the use of natural gas identified in this study, substantial additions to the existing processing, delivery and storage facilities will be required in order to handle greater amounts and the changing patterns of distribution (such as the delivery of gas from newly developed sources in the Midwest and Northeast). Environmental issues associated with producing unconventional gas resources are manageable but challenging. Risks include: shallow freshwater aquifer contamination with fracture fluids; surface water contamination by returned fracture fluids; and surface and local community disturbance, due to drilling and fracturing activities. Natural-gas consumption will increase dramatically and will largely displace coal in the power generation sector by 2050 (the time horizon of the study) under a modeling scenario where, through carbon emissions pricing, industrialized nations reduce CO2 emissions by 50% by 2050, and large emerging economies, e.g. China, India and Brazil reduce CO2 emissions by 50 percent by 2070. This assumes incremental reductions in the current price structures of the alternatives, including renewables, nuclear and carbon capture and sequestration. The overbuilding of natural gas combined cycle (NGCC) plants starting in the mid-1990s presents a significant opportunity for near term reductions in CO2 emissions from the power sector. The current fleet of NGCC units has an average capacity factor of 41%, relative to a design capacity factor of up to 85%. However, with no carbon constraints, coal generation is generally dispatched to meet demand before NGCC generation because of its lower fuel price. Modeling of the ERCOT region (largely Texas) suggests that CO2 emissions could be reduced by as much as 22% with no additional capital investment and without impacting system reliability by requiring a dispatch order that favors NGCC generation over inefficient coal generation; preliminary modeling suggests that nationwide CO2 emissions would be reduced by over 10%. At the same time, this would also reduce air pollutants such as oxides of sulfur and nitrogen.

PLC and PLC-based PAC market poised to rebound The global programmable logic controller (PLC) and PLC-based programmable automation controller (PAC) market declined significantly across all regions of the world in 2009. The market declined in emerging economies as well, but the decline was much less severe in those regions due to substantial infrastructure stimulus funding, fewer financial institutional issues and a more rapid turnaround in local consumer demand for goods and services. While it is difficult to view any market growth through the lenses of the recent economic environment, there are many dynamics that will drive market growth over the next five-year forecast period. Industries will continue to invest in automation. As a result, the worldwide market for PLCs and PLC-based PACs is expected to grow over the next five years. “Growing demands for energy savings, higher infrastructure productivity, increased production accuracy, better product quality, greater machine agility, tighter process control and additional safety are some of the crucial factors that will fuel market growth,“ according to Himanshu Shah, a senior analyst at ARC Advisory Group. New stimulus packages from various governments added more investments in the infrastructure industries, including new road construction, water and wastewater infrastructure and electric power generating plants. Globalization has also created a large demand for modern infrastructure, especially in emerging economies. Airport facilities and new road construction are driving demand for products from the oil and gas and metals and mining industries. Emerging economies know that their current infrastructure is a huge bottleneck for their continuing high economic growth. PLCs and PLC-based PACs will benefit in this environment as it is a key component for any infrastructure development and operation. Europe, the Middle East and Africa (EMEA), the largest PLC and PLC-based PAC market, was particularly hit the hardest compared to other world regions. For more information on this study, go to: www.arcweb.com/res/plc. HP HYDROCARBON PROCESSING AUGUST 2010

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Select 55 at www.HydrocarbonProcessing.com/RS

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

Stackable reactor enables superior heat transfer The stackable structural reactor (SSR) from Catacel Corporation is a direct replacement for the loose ceramic catalyst media traditionally used in the stationary steam-reforming process by industrial plants to produce hydrogen from natural gas. The heat transfer increase gained from advanced SSR catalyst technology can enable an approximate 25% throughput improvement from most reformers to create significant energy and capital savings in hydrogen production as well as fuel cell, biofuel, alternative energy and solid/ gas-to-liquid applications. Conventional steam reforming.

Typically, ceramic catalyst beds must be replaced every three to five years due to mechanical degradation of the media. The ceramic media tends to crush to powder after several startup/shutdown cycles. Accumulating powder in the tube leads to the reactor plugging. This creates material replacement and hazardous waste disposal costs as well as downtime. Initial equipment expenses might also be higher due to built-in design provisions for changing out the catalyst. Catacel’s SSR solution. The SSR is a

honeycomb made from a special grade of high-temperature stainless steel foil coated

with a reforming catalyst. Individual reactors are approximately the size and shape of a one-pound coffee can and are stacked vertically to fill the reaction tube. Because it is made from metal foil, the SSR eliminates primary problems, such as crushing, plugging and replacing conventional loose ceramic media. Furthermore, its high surface area inhibits catalytic deterioration, potentially tripling a continuous operation lifespan over ceramic media. The corrugation/flow channels in the SSR are unique. They are positioned such that conductive, convective and radiant heat from the reformer tubes is efficiently transferred to all working catalytic surfaces. This improved surface utilization results in increased capacity and/or lower system cost. By contrast, catalyst surfaces near the center of ceramic systems are difficult to heat, which compromises their effectiveness. Alternatively, the higher heat transfer of the SSR promotes lower furnace temperatures with consequent energy savings and extended tube life (Fig. 1). Select 1 at www.HydrocarbonProcessing.com/RS

New technology analyzes difficult water samples New technology from GE will make it easier for the water process industry to analyze difficult industrial water samples. Expanding GE’s capabilities for process, ~50% hydrogen + .... H2 + CO + CO2 + CH4 + H2O

~50% hydrogen + .... H2 + CO + CO2 + CH4 + H2O Metal ﬁns coated with nickel catalyst

Ceramic pellets coated with nickel catalyst

Natural gas + steam CH4 + 3H2O Temperature, °C Furnace Tube Reaction New 1,036 918 824 5 years 1,062 939 837 Change +26 +21 +13 FIG. 1

Natural gas + steam CH4 + 3H2O Temperature, °C Furnace Tube Reaction New 983 877 824 5 years 998 885 824 Change +15 +8 0

A traditional ceramic delivery method vs. a Catacel SSR delivery method.

environmental and wastewater analysis, the Sievers InnovOx online total organic carbon (TOC) analyzer will allow users to analyze challenging water samples on a routine basis without requiring excessive preventive maintenance. Monitoring the levels of TOC in the water is an important step for industrial users to control processes that are critical to their operations and to comply with regulations. The Sievers InnovOx offers increased uptime and instrument reliability, two important features when it comes to analyzing difficult industrial samples. It has been designed by GE Power & Water’s analytical instruments unit, petroleum, pulp and paper, and food and beverage markets, as well as environmental organizations and municipalities. The InnovOx online, like its InnovOx laboratory model predecessor, uses an innovative supercritical water oxidation (SCWO) technique that offers enhanced reliability, greater ease of use and lower maintenance than other TOC analyzers. By utilizing SCWO, the InnovOx is the TOC instrument most capable of costeffectively analyzing difficult industrial process, environmental and wastewater samples on a routine basis. SCWO has historically been used to treat large volumes of aqueous-waste streams, sludges and contaminated soils. GE is the first company to use this technique in a commercially available TOC analyzer. The first commercial application for the new InnovOx online TOC analyzer is monitoring seawater in Taiwan. The seawater, which contains about 3% sodium chloride, is used as industrial-process water, and both incoming and outgoing water streams need to be monitored for environmental protection. A main source of contamination can be hydrocarbons As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our Website at www.HydrocarbonProcessing.com/rs and select the reader service number. HYDROCARBON PROCESSING AUGUST 2010

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HPINNOVATIONS coming from a petrochemical refining process. The InnovOx’s robust handling of the brine sample was a significant factor in the analyzer’s selection. “The TOC market demanded technology with greater reliability and uptime, two critical needs that were not being met,” said Stephen Poirier, vice president of business development for the analytical instruments unit of GE Power & Water. Select 2 at www.HydrocarbonProcessing.com/RS

Advanced technology converts CH4 and CO2 into gasoline Carbon Sciences, Inc., the developer of a breakthrough technology to transform greenhouse gases into gasoline and other portable fuels, announced the filing of the first of a series of patent applications for its highly scalable clean-tech CO2-based gas-to-liquids (GTL) fuel technology for transforming a combination of natural gas and CO2 directly into gasoline.

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This first patent application discloses the design and manufacturing of a novel chemical catalyst that converts methane gas and CO2 directly into gasoline. These greenhouse gases can be sourced from natural gas fields or human-made coalfired power plants, landfill gas, municipal waste and even algae. “This heralds a new era for Carbon Sciences and it means that our plan for delivering a market-ready technology could be delivered as soon as next year,” said Byron Elton, CEO of Carbon Sciences. “The ongoing tragic events involving BP’s unchecked flow of oil into the Gulf of Mexico further underscores the urgent need to reduce and eliminate our addiction to petroleum, foreign and domestic. Carbon Sciences’ breakthrough technology takes us closer to a world without petroleum by essentially transforming pollution into energy.” The announcement is related to the most important module of the company’s previously announced end-to-end CO2to-fuel system that recycles raw CO2 flue emissions from carbon emitters like coalfired power plants directly into gasoline and other portable fuels. The new module under development is designed to be a stand-alone system to substantially shorten the timeline to commercialization, and reduce the overall systems and operating costs and produce a fuel that can be used in the existing infrastructure, supply chain and vehicles. Dr. Naveed Aslam, the company’s chief technology officer, commented, “We are very excited about the stand-alone commercialization of our CO2—GTL gasoline module. This system will provide a sizable part of the energy industry with an immediate clean-tech solution for the energy and climate challenges we face. Unlike other technologies, such as those for algae biofuels, that may require decades for commercial deployment, our plan for delivering a market-ready technology may be available as soon as early next year. Within a short period of time, we believe that the world can stop drilling for oil and start converting natural gas and greenhouse gases to gasoline.” Mr. Elton added, “The clear and short path to commercialization with this new CO2-based gas-to-liquids technology makes it our singular focus for the next 12 to 18 months. The company’s Website has been updated to reflect this strategy and focus.” Select 3 at www.HydrocarbonProcessing.com/RS

Select 152 at www.HydrocarbonProcessing.com/RS 18

HPINNOVATIONS ‘Revolutionary’ new industrial insulation product Visionary Industrial Insulation recently announced that it has commenced sales as the master distributor what is claimed to be a revolutionary new insulation product (Fig. 2), high-temperature layered insulation (HITLIN), to industrial clients across North America. Typical clients include power plants, refineries, petrochemical plants, geothermal units and concentrating solar power plants. HITLIN is used in process applications up to 1,400°F. HITLIN insulation is being hailed as the new generation of industrial insulation for the many advantages it provides over traditional products offered by competitors. Energy savings, durability, reusability, labor savings and eco-friendliness. Together, these add up to significant cost savings, 50% or more, for HITLIN users and Visionary Industrial Insulation customers. Total installed costs and lifecycle costs can be much lower than competing products. HITLIN is made of continuous filament e-glass fibers that are bound through an enhanced mechanical needle-punching process then mandrel-wound into various pipe cover sizes. When compared to previous industry standards calcium silicate and perlite, HITLIN is proven to offer 49% less heat loss than Calcium Silicate and 57% less than perlite due to its low thermal conductivity properties. The patented manufacturing process yields a high-density product that is extremely durable and reusable. HITLIN

FIG. 2

is manufactured without using hazardous organic chemical binders that are traditionally used with fiberglass and mineral wool products. HITLIN is available in two-piece preformed standard piping sizes from ½ in. to 44 in. in diameter. It is also available preformed to fit the curvature of any tank, vessel, exchanger or other equipment. Thicknesses up to 6 in. are available often eliminating the need for multiple layers. With its durability and reusability,

HITLIN can outlast the pipes on which it is installed. HITLIN insulation sections can be removed and reinstalled; that it can be reused makes the product eco-friendly and the absence of hazardous chemical binders also cuts down on bio-waste. Low chloride content makes HITLIN a preferred product for reducing the possibility of stress corrosion cracking in stainless steel piping. Select 4 at www.HydrocarbonProcessing.com/RS

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HPIN CONSTRUCTION BILLY THINNES, NEWS EDITOR BT@HydrocarbonProcessing.com

North America Enterprise Products Partners’ refined products storage facility in Port Arthur, Texas, which was built to support the expansion of a nearby refinery, has commenced commercial operations and received its first deliveries. The new tank farm serves as the sole distribution point for output from the refinery as part of a 15-year throughput and volume dedication agreement. Enterprise’s storage facility, which represents an investment of approximately $330 million, features 20 storage tanks with 5.4 million barrels of capacity for gasoline, diesel and jet fuel. In addition, five pipelines transport the various products from the refinery to the storage site. Indorama Ventures Public Co.’s 432,000 tpy PET resin plant, known as AlphaPet Inc., recently completed construction and opened for operation in Decatur, Alabama. The plant, which is co-located on the site of BP Chemical’s PTA facility in Decatur, will serve North America with PET resin. AlphaPet employs melt-to-resin (MTR) technology provided under license by Uhde Inventa Fischer of Germany.

South America PERU LNG recently completed construction and has successfully produced its first cargo of LNG. The project is located in the remote Pampa Melchorita area, 170 kilometers south of Lima, Peru. The plant, with capacity of approximately 4.5 million tpy, cools the natural gas to –160°C, reducing the volume by approximately 600 times to facilitate storage and transportation. The liquefaction plant utilizes a propane pre-cooled mixed component refrigerant process, four refrigeration compressors, two gas turbines and associated systems. In addition, CB&I constructed a gas treatment plant, power generation utilities, two 130,000-cubic meter LNG storage tanks, the topsides of the 1,300-meter trestle and the ship loading facilities. Petrobras and Refinaria de Petróleos de Manguinhos SA are discussing the possibility of modernizing the Manguinhos, Brazil, refinery to enhance its production of gasoline, diesel and other products,

including biodiesel. The modernization would include upgrading transportation and logistics services. Mustang has been chosen by Corval Group as a partner in its study to determine the feasibility of increasing oil refining capacity in North Dakota. Mustang’s scope of work includes preparation of a site selection basis and plan, refinery emissions estimates, construction schedule, utility balances and process descriptions for all major systems. The genesis of this study was an April 2008 report issued by the US Geological Survey that said North Dakota and Montana have an estimated 3 to 4.3 billion barrels of undiscovered, technically recoverable oil in the Bakken formation. The US Department of Energy, through the National Energy Technology Laboratory, is funding the study, which is scheduled to be completed by July 2010, and the North Dakota Association of Rural Electric Cooperatives is the project administrator.

Europe Gazprom JSC and Siemens AG plan TREND ANALYSIS FORECASTING to construct a demo plant for LNG proHydrocarbon Processing maintains an duction based on liquefaction technology. extensive database of historical HPI projThey will also study the possibility of the ect information. Current project activity is published three times year in the HPI joint manufacturing of acomponents for Construction Boxscore. When a project Russian LNG plants.

is completed, it is removed from current listings and retained in a database. The Middle database East is a 35-year compilation of projects by Wheeler type, operating company, licenFoster AG’s Global Engineersor,and engineering/constructor, etc. ing Construction Grouplocation, has a feasibilMany companies use the historical data for itytrending study and front-end engineering design or sales forecasting.

(FEED) contract with the Iraqi Ministry The historical information is available in ofcomma-delimited Oil for a new grassroots refinery at cusNasor Excel® and can be siriya, Iraq. The proposed refinery tom sorted to suit your needs. Thewill costhave of the sort depends on the size and complexa capacity of 300,000 bpd. ity of the sort you request and whether a customized program must be written. You Borouge awarded several major can focus on has a narrow request such as the engineering, andofconstruction history of aprocurement particular type project or you can obtain the entireat 35-year Boxscore (EPC) contracts valued approximately database, or portions thereof.

$2.6 billion for its Borouge 3 expansion Simplyin send a clear description of thesignifidata project Abu Dhabi, UAE. These you need and you will receive a prompt cant will expand the produccostinvestments quotation. Contact: tion capacity ofLee theNichols plant to 4.5 million tpy by 2013, making one of the largest P. O. Boxit2608 Houston, Texas,sites 77252-2608 integrated polyolefins in the world. A Fax:$1.25 713-525-4626 contract worth billion was awarded Lee.Nichols@gulfpub.com. to thee-mail: joint venture consortium of Tecni-

mont and Samsung Engineering for the construction of two enhanced polyethylene units and two enhanced polypropylene units, as well as a contract worth $400 million for the construction of a 350,000-tpy low density polyethylene (LDPE) unit.The annual capacity of the polyethylene units is 1 million tpy and the polypropylene units capacity is 960,000 tpy. Foster Wheeler AG’s Global Engineering and Construction Group has contracts with SOCAR & TURCAS Rafineri A.Ş. (STRAS) for its planned grassroots refinery to be built within the Petkim Petrokimya A.Ş. (PETKİM) facilities at Aliağa, Turkey. The contracts cover overall front-end engineering design for the new refinery and the license and basic design package for the delayed coker, which will use Foster Wheeler’s delayed coking technology. The planned new facility will have a capacity of 214,000 bpd. Naphtha and fuel oil from the hydrocracking unit will be delivered to PETKİM for petrochemical use. The refinery will include crude and vacuum distillation units, naphtha hydrotreating, a 40,000-bpd delayed coking unit, a 66,000 bpd hydrocracking unit, kerosine and diesel hydrotreaters, LPG caustic treatment 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 of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. 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 you need and you will receive a prompt cost quotation. Contact: Lee Nichols P. O. Box 2608, Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com HYDROCARBON PROCESSING AUGUST 2010

I 21

HPIN CONSTRUCTION units, a 28,000-bpd continuous catalytic reformer, a saturated gas unit, an amine and sour water stripper, sulfur and tail gas treatment units and a 160,000-Nm 3/h hydrogen unit, as well as utilities, auxiliary systems and offsite facilities. CB&I has a contract valued in excess of $70 million with Daewoo Engineering and Construction Co., Ltd. to provide the propylene storage tanks for the

Ruwais refinery expansion project in Abu Dhabi, UAE. CB&I’s scope of the project is expected to be completed in 2013.

Africa Foster Wheeler AG’s Global Engineering and Construction Group has an engineering, procurement, and construction management (EPCm) services contract with Société Nationale de Raffinage (SONARA) for Phase 1 of the Limbé

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refinery upgrade and modernization project in Cameroon. KBR has received final change order agreements with its joint venture partners Technip and JGC Corp. for the Yemen LNG plant. The contract for this lumpsum turnkey project, valued at more than $2 billion, was first announced in September 2005. Train 2 of the Yemen project was ready for startup status on March 12 and care, custody and control of the project has been turned over to the client. Foster Wheeler AG’s Global Engineering and Construction Group has a contract with GDF SUEZ to carry out the pre-front-end engineering design (preFEED) for the development of an onshore LNG plant and offshore gas gathering infrastructure. The project seeks to establish a national gas transportation network linking Cameroon’s offshore gas resources with the state-sanctioned onshore site near Kribi on the southern coastline of Cameroon.

Asia-Pacific Technip has three lump sum turnkey contracts from Mangalore Refinery & Petrochemicals Ltd. (MRPL). The contracts are worth a total value of approximately €25 million. They are for an expansion project at MRPL’s refinery located in Mangalore, India. This project will increase the refinery’s crude refining capacity to 15 million tpy. The contracts cover the design, engineering, supply and installation of fired heaters in four major units of the MRPL refinery: the crude distillation, vacuum distillation, delayed coking and petrochemical fluid catalytic cracking units.

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Air Products’ joint venture company based in Sichuan, China, has signed a longterm agreement to build a hydrogen production facility for PetroChina Co. Ltd. The steam methane reformer will produce hydrogen and syngas to support PetroChina’s Sichuan refinery and petrochemical facilities. The facility will produce over 90 million standard cfd of hydrogen and is targeted to be on stream in early 2012. Enersul has a contract from Hyundai Engineering Co., Ltd. to provide sulfur granulation technology for a new gas plant in Turkmenistan. These granulation units will be a part of the gas plant’s sulfur facility operated by state-owned Turkmengas which produces, processes and exports all gas reserves. HP

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Simulated computer modeling, dimensional testing, and electron scanning of raw materials – you name it, we’ll go to any lengths to ensure that if it’s from Swagelok, it’s top quality. Because Quality isn’t just one of our values. It’s our attitude. It’s the focus of every associate, affecting everything from our services to our products. And by using the same disciplines, practices, and technologies through every ofﬁce in every country, that focus is constant. We know that quality isn’t just a well-made product, it’s customers served beyond what they were expecting. To see what that attitude can do for you, visit swagelok.com/quality.

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LETTERS TO THE EDITOR editorial@HydrocarbonProcessing.com

Chemical process safety chat Thank you for publishing the process safety-related article by Mr. Shah about layers of protection (p. 67, April 2010). I am a long-time reader and have seen very few, if any, articles in Hydrocarbon Processing that I would classify as pure process safety. Mr. Shah’s article is a very good high-level overview of LOPA and I hope it prompts readers to make the effort to learn more about this valuable risk-management tool. I am a process safety professional and teach several process safety related classes. LOPA is included in most of them as a tool for improved risk management. Reading Mr. Shah’s article gives me the incentive to offer process safety-related articles for publication in Hydrocarbon Processing. There is one minor correction to the article that should be made. Mr. Shah references CCPS as “Center Chemical and Process Safety.” That is not the correct title. CCPS is the “Center for Chemical Process Safety” and was formed in early 1985 by AIChE after the Bhopal tragedy. The mission was (and still is) to eliminate catastrophic process incidents by advancing state-of-the-art technology and management practices, serving as the premier resource for information on process safety, supporting process safety in engineering, and promoting process safety as a key industry value. Originally, there were 17 members. CCPS now has over 120 member companies in 19 countries. To learn more about CCPS, go to http://www. aiche.org/ccps/. Adrian L. Sepeda, P.E. A. L. Sepeda Consulting Inc. Plano, Texas

ration unit (Chem. Eng. Progr., June 1975). Obviously, this is not news. Out of respect for client privilege, I am not at liberty to present recent success stories of stable dual-temperature controls. Those who are interested should not draw any conclusions from Friedman’s one-page editorial without first reading my entire 10-page article, “Multivariable Control of Distillation,” appearing in Control in May, June and July 2009.

In his March 2010 “HPIn Control” column (p. 17), Y. Zak Friedman challenged me “to write an article showing a real column having stable dual-temperature control.” I have written many such articles in the past, so the history of success is well established. For example, see the application to a styrene-ethylbenzene column (Oil & Gas J., July 14, 1969), to an alkylation deisobutanizer (Oil & Gas J., July 28, 1969) and to a series of columns in an NGL sepa-

Eva-Maria Baumann Siemens AG Energy Sector Erlangen, Germany

A plastics fan F. G. Shinskey Process Control Consultant Wolfeboro, New Hampshire

Author’s response Mr. Shinskey’s 1969 and 1975 papers are not relevant to the current argument. The papers are about mass balance control structure with analyzer feedback, sometimes with a single tray temperature controller. Neither paper contains any process data to support Mr. Shinskey’s position, but in any case, the argument that mass balance is sometimes a useful control technique is not controversial. What is controversial is dual composition control implemented on top of unstable dual-temperature control. I would repeat that the only reasonable way to promote a theory is to show that it works in practice. I am actually surprised to hear that clients have declined to release Mr. Shinskey’s technical papers. In my experience, clients who are proud of their APC applications are eager to publish papers and participate as authors. Y. Zak Friedman

Correcting a misperception A dual-temperature control challenge

Patent Office granted a patent. This patent was granted in 1995. As such, the title of the article should read, “Pressure-relief software awarded a US patent.” This change removes the ambiguity for your readers and is grounded in the aforementioned facts.

There was “misinformation” in the January 2010 issue. I am referring to the “HPInnovations” section (p. 19) which indicates that Curtiss-Wright’s pressure-relief software has now been awarded a US patent. However, the title gives an incorrect impression to your readers (“Pressure-relief software awarded first US patent”). The title implies that Curtiss-Wright has obtained the firstever US patent that was awarded for pressure-relief software. We wish to point out that Siemens Pressure Protection Manager was the first software for which the US

I want to thank you for publishing the article, “Plastics enable better automobile designs” in your April 2010 issue (p. 43). As someone who has been involved in the automotive and petrochemical industries for over 20 years, I can’t tell you how much advances in polymers have made vehicles safer, lighter, more responsive and proportionally less expensive. The fact that automakers can use plastics in fenders and bumpers, instead of more expensive metals, ups profit margins for producers and lowers sticker prices for consumers. By my reckoning, that’s a good deal for everyone. While the world may not know how much it depends on plastics, this community does and we should continue to develop even more advanced polymers. Peter Sanderson, P.E. Grand Rapids, Michigan

An expression of love I just love this statement by Heinz P. Bloch, “Don’t employ the nonteachable,” from his May 2010 “HPIn Reliability” column. Sorry but it had me and our engineers in stitches. If this rule were applied at the CEO, COO and CFO levels, we might begin to get somewhere! Harry J. Gatley, Chem.E., P.Eng, P.E. West Jordan, Utah Hydrocarbon Processing welcomes and encourages feedback from its readers. Send your comments to:

Hydrocarbon Processing Attention: Letters to the editor P.O. Box 2608, Houston, Texas 77046 editorial@HydrocarbonProcessing.com HYDROCARBON PROCESSING AUGUST 2010

I 25

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor

Granite City Granite City Catlettsburg Kinross Green River

Air Separation Unit (1) Air Separation Unit (2) RE Hydrocrack, Gasoil Bio-ethanol Refinery

500 500 70 40 25

Santos Tres Lagoas Barrancabermeja Barrancabermeja Barrancabermeja Barrancabermeja Pampa Melchorita Pampa Melchorita Pampa Melchorita Anzoategui

LNG Floating (FLNG) Ammonia Coker, Delayed Coker, Naphtha Crude Unit Hydrocracker LNG Liquefaction Plant Storage Train, LNG (1) Utilities Upgrader, Heavy Oil

2.7 2.2 54 30 100 50 4.5 130

MMtpy F 2013 Mm-tpd F 2013 Mbpd E 2013 Mbpd E 2013 Mbpd E 2013 Mbpd E 2013 MMtpy 3800 C 2010 Mm3 3800 C 2010 None 3800 C 2010 200 Mbpd P 2014

Technip KBR

Ningbo Ningbo Xinjiang Mangalore Mangalore Mangalore Mangalore

Ningbo Ningbo Yili Mangalore Mangalore Mangalore Mangalore

Methanol-to-Olefins (MTO) Olefins Conversion Coal to SNG Plant Heater, Coker Heater, Crude Heater, FCC Heater, Vacuum

600 Mm-tpy 90 Mm-tpy 6 MMNm3/d None None None None

F F P F F F F

2012 2012 2012 2011 2011 2011 2011

CB&I CB&I Davy Process

Kribi Ain Sokhna Ain Sokhna Ain Sokhna Lekki

Kribi Ain Sokhna Ain Sokhna Ain Sokhna Lekki Free Trade Zone

LNG Polyethylene (1) Polyethylene (2) Polyethylene (3) Refinery

3.5 450 450 450 500

F F F F S

2012 2012 2012 2012 2014

Basra Aliaga Aliaga Aliaga Aliaga Aliaga Aliaga Ruwais

Al Basrah Aliaga Aliaga Aliaga Aliaga Aliaga Aliaga Ruwais

Cracker, FCC CCR Coker, Delayed Hydrocracker Hydrogen Offsites Refinery Polyethylene, LD

55 28 40 66 160

Engineering

Constructor

UNITED STATES Illinois Illinois Kentucky Michigan Utah

Air Products Air Products Marathon Petroleum FRONTIER RENEWABLE RES PM Petroleum

tpd tpd Mbpd MMgal Mbpd

P P C F P

2012 2012 2010 2013 2014

Air Products Air Products Shaw

LATIN AMERICA Brazil Brazil Colombia Colombia Colombia Colombia Peru Peru Peru Venezuela

Petrobras/BG/Repsol/Galp Energia Petrobras Ecopetrol Ecopetrol Ecopetrol Ecopetrol PERU LNG PERU LNG PERU LNG Petronas/PDVSA/ONGC/Repsol/IOCL Jv

Chiyoda|SBM Offshore|Technip FW FW FW FW CB&I CB&I CB&I

CB&I CB&I CB&I

ASIA/PACIFIC China China China India India India India

Ningbo Heyuan Chemical Ningbo Heyuan Chemical Xinwen Mining Group Mangalore Rfg & Petrochemicals Mangalore Rfg & Petrochemicals Mangalore Rfg & Petrochemicals Mangalore Rfg & Petrochemicals

Technip Technip Technip Technip

AFRICA Cameroon Egypt Egypt Egypt Nigeria

GDF SUEZ Carbon Holdings Carbon Holdings Carbon Holdings Nigerian Natl Petr Corp

MMtpy Mtpy Mtpy Mtpy Mm-tpy

FW Univation Univation Univation

MIDDLE EAST Iraq Turkey Turkey Turkey Turkey Turkey Turkey UAE

Iraq Ministry of Oil Petkim/SOCAR/Turcas JV Petkim/SOCAR/Turcas JV Petkim Petrokimya Hldg Petkim/SOCAR/Turcas JV Petkim/SOCAR/Turcas JV Petkim/SOCAR/Turcas JV Borouge III

Mbpsd 17.9 F 2011 Mbpsd F 2014 Mbpsd F 2014 Mbpsd F 2014 MNm3/h F 2014 None F 2014 214 Mbpsd F 2014 350 Mtpy 400 U 2013

APS Eng Co Roma FW FW FW FW FW Tecnimont

FW FW Samsung Eng

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companies’ abbreviations, along with the complete update of the HPI Construction Boxscore.

BOXSCORE DATABASE

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning. Now, we’ve made our best product even better! Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects. For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

I AUGUST 2010 HYDROCARBON PROCESSING

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How H ow m much uch nitrogen nitrogen do you do you waste waste during during your your ethylene cracker ethylene cracker shutdown? shutdown?

The one company you can rely on to deliver efficient world-class nitrogen performance during your shutdown is BJ Services. Nitrogen is critical to a safe and successful ethylene cracker turnaround. Why risk using your operational resources or a gas supply company when BJ Services provides a dedicated, engineered nitrogen capability that can save you time and money while reducing your risk? The BJ Services difference is our expertise and focus on achieving an efďŹ cient turnaround by minimizing nitrogen consumption and time. BJ has built a resource capability that optimizes product freeing, accelerated cooling, hot stripping and safe inerting operations to get your cracker unit ready for access quickly. And when you are ready to start up, BJ will help ensure that you achieve a clean, dry, leak-free and inert unit ready to receive product. For a no-cost assessment of your ethylene cracker needs, contact your BJ Services process and pipeline representative.

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The Best Compressors for Productivity… and the Environment When you need the optimal solution for your gas compression application, look to Kobelco. We offer all types of compressors, so we can custom-engineer the best possible combination of reliability, efficiency, economy and environmental benefits. Whether you need the operating cost savings of a screw compressor, the large volume of a centrifugal compressor or the high efficiency of a reciprocating compressor – we’re the ones to call.

Ask Kobelco! The Best Solution for Any Gas Compression. Kobelco EDTI Compressors, Inc. Tokyo +81-3-5739-6771 Munich +49-89-242-18424 www.kobelco.co.jp/compressor

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FLUID FLOW AND ROTATING EQUIPMENT

SPECIALREPORT

Prevent electric erosion in variable-frequency drive bearings Here are the reasons and remedial actions H. P. BLOCH, HP Reliability/Equipment Editor

he problem of electric current passing through electrical machine rolling bearings and causing damage in the inner and outer ring ball or roller and raceway contact areas has been known for decades. In addition to the bearing element damage, it was also understood that the lubricant structure might change under the influence of a passing current. Both AC and DC motors potentially suffer from the electric-current passage phenomenon. However, since the 1990s, increasing use of variable-frequency drives (VFDs) has had a measurable effect on the number of motor bearing failures. This article examines the reasons and recommends remedial action to be considered. Modern induction machines are controlled via fast-switching voltage-source frequency converters that, in motors, provide the possibility for precise control and adjusting rotational speed and torque as well as energy regeneration at braking operations. The power-switching semiconductor devices used in frequency converters have changed from thyristors to gate turn-off transistors (GTOs) and further to the insulated-gate bi-polar transistors (IGBTs) that dominate the VFD market today. While IGBTs are used to create the pulse-width-modulated (PWM) output voltage waveform and thereby improve drive efficiency and dynamic performance, these advantages are not achieved without certain drawbacks. New effects have been observed when power is supplied from a PWM converter. Depending on the power range, switching frequencies of several kHz are employed and associated voltages and currents are encountered apart from the classic voltages and currents generated by the motor itself. Bearing damage is now caused by a high-frequency (spanning a relatively wide

kHz to MHz range) current flow that is induced by these fast-switching (100 ns) IGBT semiconductor devices.1 The basic causes and sources for bearing currents are: â&#x20AC;˘ Electrostatic charging â&#x20AC;˘ Magnetic flux asymmetries in the motor â&#x20AC;˘ Frequency converters and their common-mode voltage in combination with high-slew-rate voltage pulses. The first two phenomena are well known and considered classical reasons for bearing currents. All electric motors and generators, whether they are main- or converter-fed, are at risk with respect to the first two phenomena. This would explain that insulated bearings were used by risk-averse reliability professionals decades ago. However, common-mode voltages in combination with high-slew-rate voltage pulses, the third bearing current cause or source, only exists for converter-fed motors and generators. Current damage explained. When an electric current passes through a roll-

FIG. 1

ing bearing, electric discharges take place through the lubricant between the inner and outer ring raceways and the rolling elements. Spark discharge then causes local bearing metal surface melting. Craters are formed and molten material particles are transferred and partly break loose. The crater material is rehardened and is much more brittle than the original bearing material. An annealed material layer lies below the rehardened layer and the annealed layer is, of course, softer than the surrounding material. In rolling bearings three major types of current damage: pitting, fluting and microcratering have been identified and characterized by their appearance. One prominent type of electric current damage is called electric pitting. It is mostly related to single-crater damage and was, in the past, typically seen in DC applications such as railway traction motors. The crater diameter is typically from 0.1 up to 0.5 mm and can be seen with the unaided eye. The predominant source of such craters is a very high voltage; it can be extremely powerful.

Fluting (electric erosion) in rolling-element bearings (SKF USA, Kulpsvlle, Pennsylvania). HYDROCARBON PROCESSING AUGUST 2010

I 29

Number 1 :KHQ LW FRPHV WR VDIH DQG HIĂ&#x;FLHQW WXUQDURXQGV \RXU IDFLOLW\ ZDQWV WR EH QXPEHU RQH $OWDLU6WULFNODQG LV WKH RQH PHFKDQLFDO FRQWUDFWRU ZKR FDQ DGG WR \RXU VXFFHVV :H KDYH DQ H[FHOOHQW UHFRUG RI SHUIRUPLQJ WXUQDURXQGV QRW MXVW VDIHO\ DQG HIĂ&#x;FLHQWO\ EXW ZLWK DQ LQFUHGLEO\ KLJK SURGXFWLYLW\ UDWH 7R DFKLHYH \RXU WXUQDURXQG JRDO RI H[FHOOHQFH FDOO XV LQ WKH SODQQLQJ VWDJH :H SODQ PDQDJH DQG H[HFXWH WXUQDURXQGV IRU WKH UHĂ&#x;QLQJ SHWURFKHPLFDO SRZHU IHUWLOL]HU DQG SXOS SDSHU LQGXVWULHV Q

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Select 56 at www.HydrocarbonProcessing.com/RS

FLUID FLOW AND ROTATING EQUIPMENT Fluting or ”washboarding” is another frequently encountered type of current damage (Fig. 1). It consists of a multiple grey line pattern across the raceways that then appear both shiny and darkly discolored. The reason for this fluting is a mechanical resonance vibration caused by the rolling element dynamic effect when they are moving over smaller craters. Note that fluting is not a primary failure mode produced by the current flow through the bearing itself. Instead, fluting represents secondary bearing damage that becomes visible only after some time and has small craters as points of initiation. Because frequency converters are common, the third type of defect—microcratering—is by far the most common type of current damage. The damaged surface appears dull and is characterized by molten pit marks. Multiple microcraters cover the rolling element and raceway surfaces. Crater sizes are small, mostly with diameters from 5 to 8 μm, regardless of the craters being found on an inner ring, outer ring or a rolling element. The true crater shape can only be seen under a microscope with very high magnification. Electric current discharges also cause the bearing lubricant to change its composition and degrade rapidly. Localized high temperatures promote a reaction between additives and the base oil; base oil burning or charring can result. Additives will be used more quickly and the lubricant tends to harden and turn black. Rapid grease breakdown is thus a typical failure mode that results from current passage. Technology and failure avoidance.

A number of bearing failure avoidance measures exist, including reasonable steps such as insulating the bearings, ceramic bearings and certain mechanical contact-type shaftgrounding devices. Flawed measures include so-called “electrically conductive greases.” It turned out that electrically conductive greases do not represent a suitable solution, especially under high-frequency currents due to their too-high electrical resistance. Moreover, the “conductive particles” contained in the grease will often affect the bearing tribological properties. “Shaft grounding devices” usually connect the rotating shaft and stationary motor parts by a sliding contact. This sliding contact is made by carbon or graphite brushes located outside the motor—typically at the drive-end side. The brushes are often directly sliding on the shaft and varying degrees of contamination and malfunction

risk exist with some designs. In general, a measure of predictive or preventive brush maintenance is needed with some of these devices. Besides, the electric resistance of conventional brushes may become too high with respect to the electric regime, especially at high frequencies. To what extent purchase of these components and combination with countermeasures, such as insulated or hybrid (ceramic) bearings, make sound economic sense is influenced by train considerations that extend to the

SPECIALREPORT

driven equipment. 2 Shaft currents can travel across certain coupling types or styles and, unless protected, may thus damage the driven equipment bearings. Hybrids have been available for a number of years. They definitely solve problems with electric current and handle many issues traceable to poor lubrication. They are ideally suited for many VFDs and other industrial electric-motor applications. Even more prevalent are electrically insulated bearings, i.e., bearings provided

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FLUID FLOW AND ROTATING EQUIPMENT with an electrically insulated coated outer ring. The coatings supplied by one of the most widely known bearing manufacturers consist of aluminium oxide and are applied by a special process using plasma-spraying technology. The insulating properties are specified with a minimum electric resistance of 50 MΩ up to 1,000 V DC. These bearing dimensions and tolerances are the same as for standard bearings.

TaK Run

Induction motors, special bearings and motors. Nonvanishing com-

mon-mode voltages in combination with high-slew voltage pulses became problematic with the introduction of modern, fastswitching frequency converters. Problems arise due to high-frequency bearing currents that can be theoretically categorized according to their paths through the electric machine.

Trig’d

Ch 1 Pk–Pk 30.4 V

Ch1 E 5.00V~

FIG. 2

M 100μs A Ch1 E 16.2V T→640,000μs

Shaft-current activity without shaft-grounding rings (EST, Mechanic Falls, Maine).

TaK Run

Trig’d

Ch 1 Pk–Pk 3.90 V

Ch1 5.00V~

FIG. 3 Select 157 at www.HydrocarbonProcessing.com/RS

M 100μs A Ch1 E 1.80V T→640,000μs

Shaft-current activity with well-engineered shaft-grounding rings (EST, Mechanic Falls, Maine).

FLUID FLOW AND ROTATING EQUIPMENT High-frequency shaft grounding currents are induced because the sum of the three-phase voltages does not equal zero. If the return cable impedance is too high and the stator grounding is poor, the current will take a path from the stator, through the bearings and the shaft, via ground back to the converter. Due to the asymmetry between the three phases in the stator windings, the sum of the current over the stator circumference is not zero. A high-frequency flux variation surrounds the shaft, creating a high-frequency shaft voltage. This results in a potential risk for high-frequency circulating currents flowing axially along the rotor, through one bearing and back through the other bearing. In a rolling bearing that is working well, the rolling elements are separated from the rings (the raceways) by the lubricant film. From the electric point of view, this film acts as a capacitor and its capacitance depends on various parameters such as the lubricant type, temperature and viscosity, plus film thickness, generally on the actual operating conditions. If the voltage reaches a certain limit, the lubricant breakdown or threshold voltage, the capacitor will be discharged and a high-frequency capacitive discharge current occurs. In this case, the current is limited by the motor internal stray capacitances, but it will occur every time the converter switches.

Shaft grounding rings can be adapted as an integral part of the motor design. A well-designed product meets both spirit and intent of the NEMA MG1 Part 31.4.4.3 specification, 3 aimed at preventing bearing fluting failure in electric drive motors as well as in the coupled equipment. This specification identifies induced-shaft voltage in VFDs as a potential cause of motor failure and recommends shaft grounding as a solution to protect both motor bearings and attached

SPECIALREPORT

equipment. Figs. 2 and 3 show oscilloscopic traces of voltages prevailing with and without SGRs. Circumferential rows of fibers.

Properly designed shaft grounding rings provide a large number of small-diameter fibers to induce ionization and discharge voltages away from motor bearings and to ground. Selecting carbon fibers of specific mechanical strength and electrical characteristics is critically important to providing

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Shaft grounding rings (SGRs). Ini-

tially focused on mitigating static charges in the printing and imaging markets, one leading manufacturer has been manufacturing conductive microfiber grounding rings for rotating equipment since about 2005. This proprietary technology provides shaft grounding rings to mitigate the electrical erosion issues in motor bearings when electric motors are controlled by PWM VFDs. SGRs are perhaps of prime importance when the user or motor manufacturer decides—for whatever reasons—not to use insulated bearings on both driver and driven VFD equipment. It can be shown that a well-designed SGR provides the “path of least resistance to ground” for VFD-induced shaft voltages. If the shaft voltages are not diverted away from the bearings to ground, and unless the user and manufacturer select the right bearings, currents may discharge through bearings regions and cause the types of damage explained earlier as electrical discharge machining (EDM), pitting and fluting.

To prove it, one drum is free with your first order. If you’ve never tried us out, this is your chance and we will give you one drum free (for any first order of more than one drum of Paratherm GLT, HR or MG). Contact us by phone or on the web for details on how to order. The GLT heat transfer fluid is an alkylated-aromatic based fluid for mainly closed-loop, liquid-phase heating systems to 550°F using fired heaters (and to 575° in waste-heat recovery systems). The Paratherm HR heat transfer fluid is also an alkylated-aromatic based fluid formulated for liquid-phase heating to 650°F in fired heaters and 675°F in waste-heat recovery and full-convection heaters. Paratherm MG is biodegradable, aliphatic-hydrocarbon based and runs at 550°F in fired heaters and at 580°F

in full-convection heater and electric immersion units. For these fluids or any other of our nearly dozen fluids or cleaners pick up the phone and call one of our technical specialists. It’s part of our program called Immersion Engineering™ that insures you get the finest products and services for all your heat transfer fluid needs.

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SPECIALREPORT

FLUID FLOW AND ROTATING EQUIPMENT

break-free and nonwearing service. These carbon fibers must be allowed to flex within their elastic limit and while contacting the shaft with the proper overlap. Long-term reliable fibers are placed in an engineered holder or channel that protects against breaking and mechanical stress. As of 2010, the most reliable design is to arrange one or more rows of fibers in a continuous ring inside a protective channel completely surrounding the motor shaft. This design ensures that there are literally hundreds of thousands of fibers to handle discharge currents from VFDinduced voltages at the various prevailing high frequencies. One SGR brand has two full rows of fibers and its continuous circumferential “ring” design and fiber flexibility allows them to sweep small amounts of oil film, grease and dust particles away from the shaft surface. There are indications that using just a few fiber bundles is a less reliable design. An optimal placement in the protective channel is thought to ensure that the fibers overlap and maintain electrical contact with the shaft while preventing breaking and contamination problems.

The best available designs no doubt optimize fiber density to maintain the required fiber flexibility. If too many fibers are bundled together (as may be the case in less-than-optimal designs) the fibers will break. While there are compelling reasons to specify insulated (actually, aluminum oxide-coated) rolling-element or ceramic (“hybrid”) bearings for VFDs, there may be instances where bearing protector rings are well justified and further reduce the risk of shaft current-induced bearing distress. When specifying such shaft grounding rings, steer clear of knock-off products that use carbon fibers and mounting methods that compromise long-term reliable service. One can see that an induction motor fed by a frequency converter is a very complex drive system that is influenced by many parameters. The whole drive, including supply, DC link, switching elements, cables, motor and load, has to be regarded as a total system. In short, electric currents are often an unavoidable fact of life in bearing applications. Currents have potentially damaging consequences

HIGH ACCURACY FLOW METERS

when they pass through rolling bearings. Damage mainly occurs in the inner and outer ring ball or roller and raceway contact areas. Summary of recommended user practices. Logic tells us that bearing

selection for VFDs must be based on applying proven reliability engineering principles. Accordingly, we would encourage thoughtful professionals to work with VFD and motor suppliers that will have a thorough knowledge of insulated and ceramic (hybrid) bearings. Hybrid technology affords a measure of superiority in insulating along with the added tribological benefits. We would consider adding shaft grounding rings in instances where, for well-explained reasons, insulated or hybrid bearings cannot be used or present some definable risk. On SGRs or other externally-added rotating grounding devices, reliabilityfocused users are mindful of the unquestionable merits of overlapping carbon fiber designs placed in retainer structures that act as a protection. Relevant literature sources are available and some of these let us understand electrostatic technology parameters.6 Others will thoroughly explain the decadeold use of insulated bearings in protecting VFD bearings from these currents.1 Recall that hybrid bearings2 could be an important solution for VFD applications since ceramic rolling elements made of silicon nitride are excellent electric insulators. We would also pay attention to advertisements and commercial literature4,5 and review the science that supports or generates questions. When in doubt, science and peer-reviewed publications6 can provide us with answers regarding competing designs. HP

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5 6

LITERATURE CITED http://evolution.skf.com/zino.aspx?articleID =336&lan=en-gbn. “Consider Ceramic Bearings for Screw Compressors,” Hydrocarbon Processing, August 2009. National Electrical Manufacturers Association (NEMA) Specification MG1 Part 31.4.4.3 (MG 1 pertains to Definite-Purpose Inverter-Fed Polyphase Motor bearings, section 31.4.4.3 pertains to Shaft Voltages and Bearing Insulation). Commercial literature, Electro Static Technology Company (EST), Mechanic Falls, ME 04256; also sales@est-static.com. Commercial literature, INPRO/Seal Company, Rock Island, lL, 61201; also www.inpro-seal.com. Muetze, Annette and H. Will Oh; “Design Aspects of Conductive Microfiber Rings for Shaft Grounding Purposes,” Proceedings of the IEEE, September 2007, pp. 229–236.

Select 77 at www.HydrocarbonProcessing.com/RS

Compressionâ&#x20AC;Ś Without Exception

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FLUID FLOW AND ROTATING EQUIPMENT

SPECIALREPORT

Valve design reduces costs and increases safety for US refineries The goals were achieved by using alloys with superior corrosion resistance R. D. JOHNSON and B. LEE, Flowserve Flow Control Division, Cookeville, Tennessee

n the 1980s and early 1990s, methyl tertiary butyl ether (MTBE) was seen as an economical blending component that would eventually replace processes like hydrofluoric (HF) acid catalyzed alkylation (Fig. 1). However, MTBE was eventually banned in the US due to public health concerns after the chemical compound was detected in groundwater. As a result, refineries shifted their focus from MTBE back to established processes like HF alkylation to continue to produce high-quality gasoline. HF catalyzed alkylation is a long-proven process that refineries use to produce clean-burning, high-octane gasoline. However, HF units required frequent maintenance that can result in downtime and significant costs for refineries. This has prompted the industry to look for ways to increase the time between HF unit shutdowns. The solution that one supplier found was a valve design that not only saved refineries money, but also helped mitigate safety risks associated with hydrofluoric acid.

MTBE background. MTBE is a volatile, flammable and colorless liquid chemical compound created by the chemical reaction of methanol and isobutylene, and is used commercially to raise gasoline oxygen content. According to the US Environmental Protection Agency, refineries started using MTBE at low levels in 1979 to replace lead as an octane enhancer, which helps prevent automobile engines from “knocking.” In 1992, refineries started adding higher concentrations of the compound in some gasoline to fulfill oxygenate requirements set in 1990 by the Clean Air Act Amendments. Increasing the oxygen content by using MTBEs helps gasoline burn more completely and reduces harmful tailpipe emissions from pre-1948 vehicles. However, emission reduction in modern vehicles is negligible. In 1995, the US Geological Survey reported finding MTBE in shallow groundwater throughout the country, which raised public health concerns. All states now ban MTBE use, though most refineries voluntarily removed the compound from their products before the bans went into effect. MTBE removal from gasoline resulted in several challenges for refineries. The bans caused a volumetric reduction in the US gasoline supply and octane levels and emissions to the atmosphere were both adversely impacted. Refiners were left to find a viable oxygenate to replace MTBE to keep their gasoline quality high.

Ethanol it is blended into about 70% of the US gasoline supply. Adding 10% ethanol to gasoline raises the fuel’s octane rating by two or three points, which improves performance.

FIG. 1

The task force’s findings were used to develop a superior HF alkylation plug valve design. Features include the availability of an advanced stem seal design. The findings also led to developing a design that allows for repairing the valve in line.

Recycle isobutane Reactor Feedstock (oleﬁns, isobutane)

Fresh acid

Propane

Deisobutanizer Settler Acid puriﬁer Depropanizer

Alkylate Acid oils

Caustic washer

Ethanol—not a perfect substitute. Some refineries turned

to ethanol as an oxygenate substitute. Ethanol is commonly used in gasoline blends—according to the American Coalition for

FIG. 2

Improved valve designs reduces costs and improves safety.

HYDROCARBON PROCESSING AUGUST 2010

I 37

SPECIALREPORT

FLUID FLOW AND ROTATING EQUIPMENT

■ One of the key concerns for the

refineries is valves used in HF units. Valves were among the components that

However, 10% ethanol blends have a Reid vapor pressure (Rvp), a common measure of gasoline volatility, well above the levels allowed in most states. To meet Rvp requirements, 10% ethanol blends require removing lighter components such as butane and pentane, which adds to the refinery’s costs and complicates the production process.

needed the most repair and maintenance,

Alkylates help create high-quality gasoline. Alkylates are high-octane, low-Rvp blending components produced by and required the most attention and reacting C3 and C5 olefins and isobutene. The alkylation process does not contribute any additional aromatics, sulfur or olefins scrutiny during operation and shutdown. into the gasoline pool, and has been found to be an ideal blending component. There are two processes for producing alkylates: sulfuric and HF acid-catalyzed alkylation. HF alkylation is more common in US refineries because it is a more efficient process. It does not require refrigeration to maintain a low reactor temperature and has a significantly lower acid consumption rate. HF alkylation produces clean-burning, high-octane gasoline. However, due to the corrosive nature of the process, most HF units historically operated with turnaround times of just two years, which required refineries to shut down production so they could repair and upgrade the unit. The downtime for repairs and upgrades resulted in significant revenue loss for refineries, and the industry looked to suppliers to help increase the time between HF unit shutdowns. To accomplish this goal, suppliers needed to develop products that required less maintenance and provided Get the The right chemical is crucial longer service life (mean-time-betweenexpertise for process unit and failures) in HF environments. vessel decontamination. One of the key concerns for the refinerthat drives ies is valves used in HF units. Valves were For optimal results – shorter turnaround times, results faster vessel entry, lower costs, improved safety – among the components that needed the you need something more. most repair and maintenance, and required the most attention and scrutiny during That’s why our patented Zyme-Flow® chemistries operation and shutdown. One supplier are backed by world-class service – including rose to the challenge by developing a valve comprehensive planning, chemical recommendadesign that required significantly less maintions and project management. From the industry’s tenance, saving the refinery money while most experienced decontamination specialists. also helping them mitigate safety risks assoIf you’re ready to take decontamination results ciated with HF leaks. to the next level, we’re ready to help.

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HF alkylation task force. Because valves were among the most difficult components requiring frequent repair, a special task force was created by the valve supplier and charged with lengthening the process capability of its valves to reduce the meantime- between-maintenance-intervals. In certain unit areas, valves were experiencing higher corrosion levels than anticipated. The task force also found several valves with stem leaks that created an environmental hazard, and some valves were being

FLUID FLOW AND ROTATING EQUIPMENT

SPECIALREPORT

fouled by buildup of iron fluorides that would wash down from Improved valve design saves money. Using findings the adjacent carbon-steel pipe, inhibiting valve operation. from the task force, the valve supplier sought to improve prodThe task force recognized that the key to improving valve funcuct design to achieve higher mean-time-between-failure and tionality was gaining a better understanding of the HF alkylation mean-time-between-repairs (Fig. 2). This goal was achieved by process. They spent the next five years collecting information using alloys with superior corrosion resistance to manufacture from two turnarounds at two different refineries. They were able valves used in highly corrosive HF unit areas such as the rerun to observe unit maintenance first hand, including why valves were circuit. An advanced stem design option was introduced to replaced or repaired. handle areas where stem leaks were a problem. These features This investigation led the team to identify the circuits within were integrated into a plug-valve design that refineries preferred the HF unit that put the most strain on the valves; the most difbecause of superior sealing capability and longevity compared ficult being the acid rerun circuit. Valves in this circuit operate to the gate valves originally specified for HF units. in the highest temperatures, acid concentration and water levels The valve supplier offered the option of using an alternative found in the HF unit. These extreme conditions cause accelerated valve corrosion and result in decreased turnaround time and increased maintenance costs. One of the key findings of the task force was understanding that oxygen in the unit causes nickel to leach from the materials used to manufacture the valvesâ&#x20AC;&#x201D;ASTM A 494 M35-1 (monel). Monel is a nickelbased alloy composed of 60% nickel and 35% copper, with 5% trace elements. Where oxygen is present in the system, the nickel is leached out of the alloy at an unacceptable rate and leaves behind copper and the other components of the original monel. Because this chemical attack degrades the monel quality, the surface characteristics are compromised. As a result, the valve may begin to leak hydrofluoric acid. Therefore, it was found that many of the applications in the difficult unit areas, such as the rerun circuit, required using alternative alloys for the valves. The valves are constantly being exposed Designed specifically to meet the to HF acid. In cases where HF can become trapped in crevices where the acid is not requirement of API 610, the API Maxum allowed to refresh, it can cause pocket corSeries is available in 35 sizes to handle rosion. In those cases, the team found that HF might permeate through the stem seal. flows up to 9,900 GPM and 720 feet of When it meets the atmospheric moisture, it head. Standard materials include S-4, becomes very corrosive, causing valve stem S-6, C-6 and D-1. A wide range of pitting. This pitting can cause the stem to leak acid into the atmosphere. options makes this the API 610 pump Iron fluoride is created in the HF unit for you! when the carbon steel in the pipes reacts with the acid. The iron fluoride creates a desirable protective barrier that retards further pipe corrosion in the system. The valves used in the unit are generally made of monel or a similar alloy, which does not Creating Value. react with hydrofluoric acid. However, Carver Pump Company iron fluoride from the piping can wash 2415 Park Avenue into valves and other components. Because Muscatine, IA 52761 many of the valves are not operated fre563.263.3410 quently, these iron fluoride deposits can Fax: 563.262.0510 www.carverpump.com build up inside the valve, increasing the turning torque to make it more difficult to open and close the valve. Select 161 at www.HydrocarbonProcessing.com/RS 39

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FLUID FLOW AND ROTATING EQUIPMENT

material in the valves that is more resistant to the combination of challenges in the HF units. The new material eliminated nickel leaching from the monel, which significantly reduced corrosion. The supplier addressed the possibility of acid permeation that causes corrosion and eventual leakage. In those cases where permeation could be excessive, it developed a new stem design with a welded-metal diaphragm seal to prevent any primary fluoropolymer seal permeation from reaching the environment. The design incorporates additional outboard stem seals to prevent stem pitting. To prevent iron fluoride deposits from building up inside the valve, the team recommended refineries run partial-stroke tests periodically to wipe away the deposits and ensure the valve is

functional. To help refineries comply with its recommendation, the supplier identified new products, such as positioners and asset management, to make running partial-stroke tests simple and less costly. Many refineries are now welding valves into the pipeline to eliminate potential leak paths. This practice led the supplier to make recent improvements to the valve design that allows the refinery to repair the valve inline. This simplifies the maintenance process and saves significant time when maintenance must be performed. Other valve designs must be cut out of the pipeline and sent to a shop with special tools when any repairs are needed, which is costly and time-consuming. Safety concerns. Using the best equip-

Low tolerance for pump problems? No problem.

Pressure to lower maintenance costs and reduce environmental impact has paved the way to better surface pumping solutions.

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Our multi-stage centrifugal SPS™ pumps provide versatile, lowmaintenance alternatives to many split-case centrifugal, positivedisplacement and vertical-turbine pump applications. The SPS pump is a cost-effective solution for processing, petroleum, mining, water and other industries that require high-pressure movement of fluids.

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ment possible in HF alkylation units makes sense, not only because it saves money but also because it improves plant operator safety and protects the environment. In 1993, the Occupational Safety and Health Administration (OSHA) released a bulletin warning of the potential safety and health risks posed by HF acid. OSHA has established a permissible exposure limit of three parts per million (ppm) averaged over an eight-hour work shift. Depending on the release conditions, HF acid can form a vapor cloud that can be dangerous to humans. The OSHA report sites a number of accidental HF acid releases from HF alkylation units at major petroleum refineries in the US. Valves designed for HF units have made great strides over the years to reduce the incidences of HF acid leaks that can be extremely dangerous to personnel and the environment. By utilizing the supplier’s superior valve design, refineries have been able to significantly lengthen the time between turnarounds to four to five years, greatly reducing costs. The supplier continues to look for ways to improve plug valve design to increase safety and lower costs for customers. HP

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Proven benefits include: • Lower initial and whole-life cost • Low noise and vibration levels • Short construction lead-time • Remote monitoring and control • Increased reliability and runtime • Worldwide support. Call +1 281 492 5160. Or e-mail sps@ woodgroup.com.

Roy Johnson is the director of marketing for the process/chemical sector of the Flow Control Division of Flowserve. In his 30-year tenure with the company, he has served in many management and supervision roles for the valve and automation businesses for the company. Mr. Johnson holds a business management degree from Tennessee Technological University.

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Ben Lee has been with Flowserve for 29 years working as a sales engineer and product manager. His current position is product manager for Durco plug and butterfly valves at the Flowserve facility in Cookeville, Tennessee. Mr. Lee holds a BS degree from Queen’s University and a bachelor of education degree from University of Toronto.

FLUID FLOW AND ROTATING EQUIPMENT

SPECIALREPORT

Pump aftermarket offers solutions for abrasive services Upgrades substantially increased MTBR S. McPHERSON, Sulzer Pumps (US) Inc. Service Center Houston, La Porte, Texas

he need to transport low-grade feed stocks containing varying amounts of abrasives such as catalyst and coke fines is part of the refining economic picture. Accordingly, abrasion and erosive wear can limit centrifugal pump component life. However, many other factors influence centrifugal pump life in an abrasive service: fluid velocity (a consequence of higher flow and pressure demands met by increased operating speeds and impeller diameters), curve fit, geometric design and material selection. Yet, in an aftermarket situation, geometric design and material selection are typically the only parameters that can be optimized due to time, cost and infrastructure constraints. Roadmap for increasing throughput and uptime.

To address the need for improved throughput with existing pumps, major pump manufacturers and one or two competent non-OEMs have compiled large portfolios of proven proprietary design guidelines and upgrade recommendations. With its full line of state-of-the-art pump designs, one such OEM can help its customers achieve increased throughput, boost efficiency and improve reliability of most pumps. In one case, challenged with the hot, dirty operations of coker-heater charge pumps and process pumps in Canadian oil sands, the manufacturer completed upgrades that improved mean-time-between-repair (MTBR) from the mere weeks and months typical of such operating conditions to years. Mature technology successfully fights sand-laden water erosion in high-speed, high-energy water-flood pumps. Case histories confirm uptime extension. At a refining company in the US Gulf Coast area, accelerated wear on an APIBB5 double-case diffuser-style coke-cutting jet pump resulted in costly downtime on an average seven-months cycle. Application requirements necessitated a pump capable of producing high differential head while accommodating varied fluid compositions and significant abrasive fines. The pump manufacturer’s engineers analyzed the recurring material wear patterns. Damage was generally characterized by impeller erosion and balance device wear surfaces (Fig. 1A), at the exposed impeller waterways and impeller abutment shoulders on the shaft (Fig. 1B), abrasive wear of the diffuser vane tips (Fig. 1C) and corrosion-erosion of the discharge head (Fig. 1D). After a thorough analysis, the OEM’s engineering team defined and discussed possible solutions and actions with the customer. Proven proprietary design guidelines were combined with the reverse-engineering capabilities of the company’s rapid-response

center and advanced coating technology affiliates. The result was a life-expectancy increase in excess of 300%. Steps responsible for dramatic pump operating life improvement. Three principal steps were pursued by this OEM: • A high-velocity oxygen fuel (HVOF) hard-surface coating was used liberally throughout the upgrade. This coating was specifically selected from the broad and experience-based pump coating portfolio for its proven abrasive wear resistance and chemical compatibility with the varying constituents found in recycled plant and coke-cutting water. • Smooth profile geometries were incorporated in the redesigned wear surfaces within the pump for abrasive service. Efficiency-enhancing small grooves were removed after a thorough rotor-dynamic analysis to ensure pump rotor critical speed changes would not become a problem. • A corrosion-resistant welded overlay was applied to the discharge head in addition to the HVOF coating (Fig. 2). This pump upgrade was carried out at the OEM’s service center and the pump sent back to the customer on time. After more than two years of operation, the upgraded pump was removed from service and inspected. All running clearances were found to have increased by no more than 27%, a substantial improvement over an average of three times design clearance increase in seven months prior to the design upgrade.

FIG. 1

Material wear problems.

HYDROCARBON PROCESSING AUGUST 2010

I 41

SPECIALREPORT

FLUID FLOW AND ROTATING EQUIPMENT

Reverse engineering modernizes a 1960s pump. A

refinery on the US West Coast had experienced numerous problems with its fluid catalytic cracking bottoms pumps. Primarily, the failures were the result of the abrasive and erosive nature of the service; however, the 1960’s vintage API OH2 end-suction-style pump had inherent design faults notorious in that era: • A small “B” gap (impeller discharge vane tip to volute tongue gap) resulted in high vane-pass frequency vibration. • The thin-case feet and flanges were not able to withstand the high nozzle loadings applied to this hot-application pump. Reverse engineering modeling showed that permanent distortion

FIG. 2

Diffuser/stage casing with installed smooth profile wear surface.

in the flanges and feet resulted in misalignment and shaft deflection at the mechanical seal. • Large L3/D4 (the industry standard indicator of shaft deflection), as well as inadequate cooling features, resulted in less than optimum mechanical-seal and bearing life. To provide its customer with an expedient solution, the OEM brought together a team that would draw on various divisional expertise. The manufacturer’s rapid response center delivered exact replications of non-OEM components, such as the volute and impeller. Engineers from the pump service center made the design review and determined the upgrade implementation steps

FIG. 3

End cover includes integral wear surfaces and antiswirl breaks.

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FLUID FLOW AND ROTATING EQUIPMENT

for the pump; the OEM’s affiliate again assisted with the selection of suitable hard-face overlays. The OEM’s pre-engineered API 10th edition OH2 upgrade package was applied to adapt the pump to latest standards. It included such upgrade features as: • API 610/API 682-compliant seal chamber • Improved cooling features: axial-flow flan, inboard heat sink, finned carbon-steel bearing housing • API 610 latest edition compliant antifriction bearings and housing isolators • Upgrade to controlled compression spiral-wound gaskets • Improved shaft stiffness (L3/D4 ) • Bearings selected for improved life. To address abrasion and erosion problems, the OEM’s upgrade solutions included several abrasive-service features: • Heavy case-wall thickness for increased corrosion-erosion allowance • Volute and cover redesigned specifically for abrasive service, including integral wear surfaces, removal of sharp corners and substitution with generous radii, antiswirl brakes added to reduce rotational velocities • Proprietary HVOF hard-surface coatings applied at all accessible areas. In addition, the OEM upgraded the 300# ANSI flanges to 900# ANSI thickness for increased nozzle-loading capability. The pump casing foot thickness was also increased to meet API latest edition nozzle-load capabilities. The pump volute was completely redesigned with new volute layout to accommodate a 6% “B” gap for reduced vibration severity at vane-pass frequencies (Fig. 3).

Since its installation in late 2007, the upgraded pump has been in continuous and highly satisfactory operation. It should be pointed out that this upgrade closely matches the features of a new API 610 10th edition pump without the infrastructural changes and costs of a new pump installation (e.g., foundation modifications, new base plate, modified piping, etc.). People are the agents of change. Using a pump rebuilder that agrees to work in close partnership with its customers pays huge dividends. A company dedicated to delivering customized service solutions that improve reliable performance in even the most demanding hydrocarbon processing operations quite obviously goes well beyond a simple repair and understands that reliability depends on the quality of both design and replacement part upgrading. Toptier service providers must be committed to doing the job right, the first time, every time. They will likely be among the leading global suppliers of reliable products and should explain innovative pumping solutions to end users. These solutions will concentrate on diagnostic and consulting services that lead to tangible upgrades. Such upgrades prove their value through greater operating efficiency and demonstrable extension of equipment run times. HP Scott McPherson is a field engineer for Sulzer Pumps (US) Inc. working within the Customer Support Services division at the Houston Service Center in La Porte, Texas. His responsibilities include centrifugal pump design, rerate, upgrade, retrofit and root cause-failure determination. Mr McPherson has been working within the pump manufacturing industry since 1996, and has been with Sulzer Pumps since 2005. He has a B.Eng. (hons) degree from the University of Strathclyde in Glasgow, Scotland.

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How the inertia number points to compressor system design challenges It facilitates predicting compressor system performance M. KAPADIA, R. TELLEZ-SCHMILL and I. AJDARI, SNC-Lavalin Inc., Calgary, Canada

faulty compressor system design could result in poor machine selection and incorrect antisurge valve sizing. Flawed designs of compressor systems could lead to erroneous determination of the relief loads for flare network design. This article presents a comprehensive methodology to design a compressor system considering all potential constraints and challenges to protect the compressor from abnormal operation and emergency shutdowns. In particular, this methodology emphasizes the influence of various components in the compressor loop, including rotating equipment performance curves, antisurge-valve dynamics, piping layout and mechanical design. The use of the inertia number provides an anticipated quantitative insight into the performance of the entire compressor system. This article also discusses the use of commercial simulation tools for compression system analysis. These tools are very useful to evaluate the results of various shutdown scenarios and their implications on the system mechanical integrity as well as the interconnecting systems such as the flare network. The methodology presented herein was applied to the design of a real compressor system. Introduction. By definition, a compressor is a machine designed to increase the gas pressure. Compressors are required mainly for gas transmission in pipelines and within a gas processing plant, and for gas re-injection into oil reservoirs. Gas is drawn into the centrifugal compressor through a suction nozzle and moves through impellers mounted on a rotating shaft. These impellers impart kinetic energy to the gas that is then converted to static pressure in the discharge volute. Compressors are an essential part of a gas transmission system and the system’s resistance to flow dictates the compressor performance. Moreover, the entire system’s dynamic behavior is very important since the compressor itself is sensitive to flowrate changes. Among the most important dynamic characteristics to be considered in a compressor system analysis are the compressor performance curves at different rotating speeds, the inertial effects of the compressor’s moving parts (rotor, shaft, associated gears and couplings, electric motor or steam turbine), gas velocity in the pipelines and control valve activation or stroke times, etc. For a process design engineer, it is very important to take into account all the factors that ensure systems to be safe and operational, as well as environmentally friendly. With many constraints such as piping layout, flare network design and environmental impact, a complete design methodology has to be considered.

The important process and layout parameters needed for the compressor system are: • Suction operating conditions, such as flowrate, gas composition, temperature and pressure • Discharge pressure • Discharge temperature • Discharge cooler type and the desired cooler outlet temperature • Primary driver type (fixed speed or variable speed) • Suction-drum design • Settling-out pressure • Layout of the antisurge control valves, which involves their takeoff location from the discharge line and connection with the compressor suction • Discharge check valve type and location • Approximate compressor system volume. Other factors to be considered for compressor system design are: • Control philosophy for surge and capacity regulation • Load-sharing philosophy (applicable to parallel compressors) • Shutdown scenarios • Flare capacity for accommodating compressor blowdown or depressuring volume. Based on these design considerations, and by following sound engineering practices and industry standards, design engineers Anti-surge valve (cold recycle) Anti-surge valve (hot recycle)

Cooler Check valve

Outlet isolation valve Blow down valve

Inlet isolation valve

. FIG. 1

Compressor

Driver

Suction scrubber Complete compressor system.

HYDROCARBON PROCESSING AUGUST 2010

I 45

SPECIALREPORT

FLUID FLOW AND ROTATING EQUIPMENT

Fuel gas HP compression

Injection compression

IP compression

LP compression

Gas cap injection

Gas dehydration

HPPT

IPPT

Dehydrator

Desalter

LPPT

can ensure that the compressor system will perform properly. However, there is a practical and easy-to-use dimensionless number of interest that provides important quantitative information, the “inertia number.”1 Although the inertia number requires some detail information about the rotating equipment and pipeline dimensions, its magnitude gives important clues regarding the appropriateness of the parameters that make up a compressor system. Inertia number. The inertia number is

defined by Eq. 1.

HPPT Crude to downstream units

WOSEP

Crude shipping pumps

To disposal wells SWD pumps FIG. 2

Gas-oil separation process flow diagram.

1.0

Surge region

Polytropic head

0.8 Normal operating conditions

0.6 0.4 0.2 Surge curve 0.0 0.0

FIG. 3

0.2

0.4

0.6

0.8 1.0 Flowrate

1.2

1.4

1.6

ESD dynamic behavior with only cold-recycle valve.

1.0

Surge region

Polytropic head

0.8 Normal operating conditions

0.6

Surge curve

0.4

N1 =

IN 2 wH

(1)

where: I = Effective compressor + driver rotor inertia, kg-m2 N = Operating Speed, rpm w = Normal operating mass flowrate, kg/s H = Normal operating compressor head, J/kg ␶ = Valve prestroke time in millisec (ms) As Mohitpour et al. point out, if the inertia number is less than 3, the compressor will surge during any abnormal operating situation. This will require re-evaluating the compressor system ensuring a shorter recycle system, the use of a hot recycle or a blowdown valve to prevent compressor surge. A detailed dynamic simulation of the compressor system will confirm if such situation exists. If the inertia number is between 3 and 10, a detailed dynamic simulation is highly recommended. A value larger than 10 indicates the compressor system is appropriate to guarantee no surge during operation upsets. Based on the information derived from the inertia number and the dynamic simulation, design engineers can decide the best strategy to protect the compressor. From Fig. 1, the following options are available for the compressor system design: • The preferred and also most common option is to have only a cold-recycle system. • Another option is to have a hot-recycle system, as long as both suction and discharge temperatures do not exceed the machinery design temperatures. This option is recommended for small compression ratios. A combination of both cold and hot recycles is recommended if required. • A combination of cold-recycle and blowdown line. However, this has an impact on the flare system performance. • Addition of rotor mass, to increase its inertia values. This has to be considered as a last resort, since it requires analyzing the mechanical implications on the machinery and input from the vendor.

0.2 0.0 0.0

FIG. 4

0.2

0.4

0.6

0.8 1.0 Flowrate

1.2

1.4

1.6

ESD dynamic behavior with cold-recycle and blowdown valves.

I AUGUST 2010 HYDROCARBON PROCESSING

Practical application case. The compressor system discussed in this article is part of an upstream oil and gas central processing facility in Saudi Arabia. The plant gas-gathering and compression sections consist of four compressors in series and a gas dehydration unit (Fig. 2). The gas comes from an oil-gas separation train working at three different pressure levels. The centrifugal compressor train is used to reinject the produced gas into the oil reservoir and

FLUID FLOW AND ROTATING EQUIPMENT

SPECIALREPORT

is comprised of one low-pressure, one intermediate-pressure, one seen when the suction temperatures rising with time. Eventually high-pressure and one injection compressors. The last compressor the cold gas coming from the cold recycle will take over, and that reaches a discharge pressure above the gas mixture critical pressure. moment can be seen when again the suction temperature starts A gas dehydration system is located between the intermediate- and to decrease with time. To avoid a discharge temperature increase high-pressure compression stages. All compressors are driven by an beyond the design value, it is very important to determine the electric motor and the high-pressure compressor dynamic analysis appropriate hot-recycle return location on the suction line to results are presented further. the compressor. All of the system compressors were designed on the same In response to the analysis a combination of hot- and coldphilosophy basis for surge and capacity control. The original recycle valves and a blowdown system with a restriction orifice compressor system consisted of a cold-recycle valve for surge prowas conceived as a potential solution. The complete comtection and a blowdown valve for venting the gas after shutdown. pressor system was simulated. The simulation results were The air coolers were located on a pipe rack and the cold-recycle checked by experienced personnel and against other software valve was located near the air coolers. From an earlier study using the inertia number criterion, it was found that the compressor would undergo a surge cycle during the initial compressor shutdown period. This implied that a change in the present physical setup was required. As information became available, the inertia number was also calculated for each compressor, at which time it was confirmed that all systems were having the problems predicted by the inertia numbers, which Combination MLI/Bridle ranged between 3 and 10. Therefore, a Measurement in a Single Chamber detailed study was initiated for ensuring robust compressor surge-protection The VEGAMAG Vantage utilizes VEGAPULS designs. Several options were scrutithrough-air radar to report level by nized and the most viable were found to tracking the float, which is also coupled include: to the magnetic level indicator. An • Blowdown valve with cold recycle optional full port ball valve provides operating together during emergency isolation in order to take the gauge out of shutdown (ESD). Both valves open at the service without interrupting the process. same time. The blowdown valve is expelConstructed in a 2” schedule 40 pipe as ling mass off of the compressor system, standard, the Vantage’s small profile fits while the isolation valves close completely into nearly any mounting arrangement. and the cold-recycle valve depressurizes The Vantage is ideal for processes with the compressor system high-pressure seclow dielectric constant values, flashing, foaming, or in light hydrocarbons. tion. As soon as the isolation valves close completely, the check valve opens and Key Specifications the cold-recycle valve allows gas from • -328 to 842°F (-200 to 450°C) the compressor discharge to go to the operating temperature compressor suction. This option has two • Up to 2,320 psi (160 bar) major implications: first, the blowdown operating pressure valve specification had to be revised. Its • Visual indication from up to 200 ft size and, most importantly, its actuator • SIL2 Qualified (IEC 61508/61511 type had to be changed. This blowdown Standards) valve was required to have a size and stroke • Compliant with ASME B31.1/31.3 time similar to the cold-recycle antisurge Standards valve. Secondly, the maximum blowdown flowrate could not be accommodated by the existing flare system. • Hot and cold recycle operating together during ESD. This required an extra analysis consisting of monitoring the discharge temperature making sure it does not exceed the compressor design temperature. Again, both hot- and cold-recycle 877.411.VIZE | info@vizellc.com | www.vizellc.com valves open at the same time. The hotrecycle valve initially keeps the compressor safe from surging and this period can be

Introducing The

Vantage

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SPECIALREPORT

FLUID FLOW AND ROTATING EQUIPMENT

available for compressor dynamic simulation. All were found to be consistent. Dynamic simulation studies. The information required for

dynamic modelling for this particular compressor system is: • Performance curves at different compressor speeds. These curves are required to be extended to flowrates below the surge point1 with the purpose of having a very detailed dynamic compressor simulation • Inertia information on both the compressor and the electricmotor sides • Electric-motor synchronous speed and full-load power

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• Electric-motor speed-vs-torque curve • Control valve pre- and full-stroke times of all (both cold and hot recycles and blowdown valve) • Isolation valve closing time • Nonslamming check valve dynamic behavior • Pipe sizes (diameters and lengths) • Suction scrubber dimensions • Air-cooler tube volume and length. Fig. 3 shows the compressor system dynamic behavior with solely the cold-recycle antisurge valve during an ESD; it confirms the predictions of the inertia number. As can be observed, the cold-recycle valve cannot save the compressor from surge. The compressor surges approximately 2.4 seconds after the electric motor is shut down. The path followed by the compressor from the initial normal operating conditions to surge is represented by the series of points between A and B in Fig. 3. A compressor in the surge region displays erratic behavior of its developed head with respect to flowrate. Unfortunately, the dynamic simulator used for this analysis cannot model negative flow rate and thus, any potential recovery from surge cannot be predicted. However, Botros2 has shown that compressor recovery from surge can be predicted by specialized and robust dynamic simulators. Fig. 4 shows the compressor dynamic behavior using the combination of blowdown and cold-recycle valve. As can be observed, the blowdown valve protects the compressor from surge. In this case the flare system resistance to flow is low compared to the compressor recycling system resistance. This results in a rapid compressor head decrease in time due to the loss of mass and the resulting compressor system depressuring. During the first 6.5 seconds of the ESD, the check valve was closed. As soon as the isolation valves completely close, this check valve opens, and then the cold-recycle valve is then able to keep the compressor out of the surge region. Fig. 4 confirms that during the first seconds of the ESD, flowrate though the blowdown valves is higher than the flowrate in the compressor suction line, and this condition will be maintained as long as the check valve is closed. As mentioned before, this option was declined because of its impact on the flare system. In this particular case, it was anticipated that the flare system had to accommodate flow only during depressurization from settlingout pressure, and not from blowdown during ESD. Moreover, during a global plant ESD, two trains of four compressors had to be blown down and this huge amount of mass represented 200% of the maximum flare system capacity. Fig. 6 shows the developed compressor head dynamic behavior for the combination

FLUID FLOW AND ROTATING EQUIPMENT 140

1.2

Design

1.0

120 Temperature difference, °C

Suction line

Discharge

100

Mass ﬂow rate

0.8 0.6 0.4

Hot recycle line

0.2 0.0

SPECIALREPORT

80 60 40 20 Suction

FIG. 7

10 12 Time, s

0 0

Mass flowrate dynamic behavior with cold- and hot-recycle valves.

FIG. 8

10 12 Time, s

Dynamic temperature behavior in compressor suction and discharge lines.

1.4 1.0

1.2 Blowdown line

0.8 Polytropic head

Mass ﬂow rate

1.0 0.8 0.6

Surge curve

0.4 0.2

0.2 0.0

FIG. 5

10 12 Time, s

0.0 0.0

Mass flowrates dynamic behavior with cold-recycle and blowdown valves.

of hot- and cold-recycle valves. Again this combination protects the compressor from surging. In this case, while the isolation valves closes, the flowrate from the hot-recycle valves takes over to decrease compressor head. Fig. 7 shows the flowrate dynamic behavior in the compressor suction and the hot-recycle lines. During the first seconds of the ESD, flowrate in the hot-recycle line increases the flowrate in the suction line, keeping the compressor safe from surge. One major constraint is not to exceed the design temperature, and this can be accomplished by determining the right hot-recycle return line location. The check valve closes and the cold-recycle depressurizes the compressor system high-pressure section. Fig. 8 shows both the suction and discharge temperature dynamic behaviors. When the isolation valves are completely closed, the check valve opens and the fresh cold gas flow mixes with the hot gas, whereupon a decrease in system temperatures is observed. Eventually, because of the low compression ratio, the compressor discharge gas temperature will not increase too much. Fig. 8 also shows that throughout the ESD the discharge temperature is safely below the compressor design temperature. HP

Normal operating conditions

0.6

Suction line 0.4

Surge region

LITERATURE CITED Mohitpour, M., K. K. Botros and T. van Hardeveld, Pipeline Pumping and Compression Systems—A Practical Approach, ASME Press, New York, 2008. Botros, K. K., P. J. Campbell and D. B. Mah, “Dynamic Simulation of Compressor Station Operation Including Centrifugal Compressor and Gas Turbine,” J. Engineering for Gas Turbines and Power, Vol. 113, April 1991, pp. 300–311.

FIG. 6

0.2

0.4

0.6

0.8 1.0 Flowrate

1.2

1.4

1.6

ESD dynamic behavior with cold- and hot-recycle valves.

Botros, K. K., W. M. Jungowski and D. J. Richards, “Compressor Station Recycle System Dynamics During Emergency Shutdown,” J. Engineering for Gas Turbines and Power, Vol. 118, July 1996, pp. 641–653.

Maheen Kapadia is a supervisor process engineer at SNC Lavalin Inc., Calgary, Alberta, Canada. He has 19 years of experience in SMR hydrogen, cryogenic operations and gas processing working with EPC and operating companies in Canada and India. Mr. Kapadia holds a BSc in chemical engineering from the Gujarat University, India. He has also worked for GSFC Ltd, Vadodara, India. He is registered Professional Engineer in the Province of Alberta, Canada

Rodolfo Tellez-Schmill is a senior consultant with WS Atkins Inc., in Houston TX, and has 15 years of experience in process design, quality control, project management, research and development. Prior to joining WS Atkins, he worked with SNC Lavalin as a senior process engineer. Dr. Tellez-Schmill received his B.Sc. and M.Sc. degrees from the National Autonomous University of Mexico, and his Ph.D. from the University of Calgary. He is a registered Professional Engineer in the Province of Alberta, Canada.

Iraj Ajdari is the deputy chief process engineer at SNC-Lavalin Inc., Calgary, Alberta, Canada. He has more than 20 years of experience in the oil & gas industry working with EPC and operating companies. Mr. Ajdari received his B.Sc. in chemical engineering from the University of Tehran, Iran in 1985, and his M.Sc. in petroleum engineering from the University of Wyoming, USA in 1995. He is registered Professional Engineer in the Province of Alberta, Canada HYDROCARBON PROCESSING AUGUST 2010

I 49

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ENVIRONMENT/LOSS PREVENTION

Gas refineries can benefit from installing a flare gas recovery system Take a look at these environmental and economic paybacks O. ZADAKBAR and A. VATANI, University of Tehran, Iran; and S. MOKHATAB, Consultant, Dartmouth, Nova Scotia, Canada

conomic and environmental considerations increase when using flare gas recovery systems (FGRSs) to reclaim gases from flare header systems for other uses. An FGRS reduces flaring noise; thermal radiation; operating and maintenance costs; air pollution and emissions; and fuel gas and steam consumption while increasing process stability and flare tip life without any impact on the existing safety relief system. The article details installing an FGRS at the Khangiran gas refinery in Iran and how the system was involved in the reduction, recovery and reuse of flare gases. The system’s operation, design guidelines and process economics will also be covered.

Table 1. Regarding the results of the data analysis—the mean value of the molecular weight of the flare gas is 18.16 and the flow discharge rate modulated between 2,500 m3/hr and the maximum of 10,000 m3/hr. The average temperature is 30°C and the average pressure is 6 psig. Advised practical methods to reduce, recover and reuse flare gases for the Khangiran gas refinery are presented in Table 2.

Introduction. Flaring is used to consume waste gases—including hydrogen sulfide (H2S) rich gases and gases burned during emergencies—in a safe and reliable manner through combustion in an open flame. It is used routinely to dispose of flammable gases that are either unusable or uneconomical to recover. Often, gas plant workers must do emergency flaring for safety purposes when equipment is depressurized for maintenance. Worldwide, final product costs for refinery operations are becoming proportionally more dependent on processing fuel costs, particularly in the current market where reduced demand results in disrupting the optimum energy network through slack capacity. Recovering hydrocarbon gases discharged to the flare relief system is probably the most cost-beneficial plant retrofit available to the refinery. Flare gas use to provide fuel for process heaters and steam generation leaves more in fuel processing, thus increasing yields. Advantages are also obtained by reducing flare pollution while extending tip life. In spite of the advantages, suitable projects for flare gas reduction and recovery have not yet been planned. Therefore, there is an essential need to emphasize installing FGRSs into the gas refinery to recover and reuse flare gases.

TABLE 1. Flare gas composition in flare header Test composition

No. 1 % mole

No. 2 % mole

No. 3 % mole

86.327

75.723

85.682

0.461

0.759

0.58

0.104

0.212

0.076

i-C4

0.03

0.062

0.012

n-C4

0.05

0.124

0.018

i-C5

0.028

0.07

0.028

n-C5

0.022

0.089

0.022

C6+

0.218

0.212

0.218

CO2

8.2

14.575

8.713

H2S

3.3

5.265

3.393

1.26

2.909

1.258

Total

100

TABLE 2. Advised practical methods to reduce, recover and reuse flare gases Objective

Advised practical methods

Reduce and/or reuse flare gases

• Improving structure of MDEA flash drum to reduce CO2 and H2S to send gases to the fuel gas header • Improving equipment with predicted streams to send gases to the fuel gas header • Improving inlet gas separator internals

Recover and reuse flare gases

• Installing the flare gas recovery system for the MDEA flash drum • Installing the overall flare gas recovery system

Khangiran gas refinery. Due to the large amount of flare

gases produced in the Khangiran gas refinery (21,000 m3/hr), operational conditions were investigated, especially in the units that produced flare gases.1 Based on the existing data, it was found that the methyl diethanolamine (MDEA) flash drum, MDEA regenerator column and MDEA regenerator reflux drum, residue gas filter and inlet gas separator into the gas treating unit (GTU) were the most critical when looking at producing flare gases. Flare gas composition in the flare header during three tests is given in

HYDROCARBON PROCESSING AUGUST 2010

I 51

ENVIRONMENT/LOSS PREVENTION To second and third FGRS units CB

Compressor

Three-phase separator TI

Cooler

FC FI

To ﬂare KO drum

Recommended FGRS.

FIG. 1

25,000 20,000 15,000

Max ﬂaring before installing FGRS, m3/hr Max ﬂaring after installing FGRS, m3/hr

10,000 5,000 0 1 FIG. 2

Maximum monthly gas flaring before and after installing an FGRS at the Khangiran gas refinery.

In addition, the flame igniter system, flame safeguards and the existing flare tip needed to be replaced. The existing flare control system was not compatible with the distributed control system (DCS) of the refinery and needed to be upgraded. FGRS design considerations. The design considerations include: flare relief operation and liquid seal drum, flare gas flow and composition, and refinery fuel systems. The considerations led to the unit design for normal capacity up to 21,000 m3/hr at 25°C–30°C and 5 bar. The proposed flare gas recovery system is a skid-mounted package, located downstream of the knockout drum since all flare gases from various units in the refinery are available at this single point. It is located upstream of the liquid seal drum, as pressure control at the suction to the compressor will be maintained precisely by keeping the increased height of the water column in the drum. The recommended system has a modular design, composed of three separate trains capable of handling varying gas loads and compositions. It consists mainly of com52

I AUGUST 2010 HYDROCARBON PROCESSING

pressors that take suction from the flare gas header upstream of the liquid seal drum, compresses the gas and cools it for reuse in the refinery fuel gas system. FGRS Unit 1 The compressor selection and design is crucial to the system capacity and turndown capability. 2,3 During the project To amine unit design phase, the most appropriate type and number of compressors were selected for the application. Liquid ring compressor technology is commonly used due to its rugged construction and resistance to liquid slugs and dirty gas fouling. A number of factors that must be taken into account when compressing flare gas are as follows: the gas amount is not constant, the gas composition varies over a wide range, the gas contains components that condense Feed gas from ﬂare during compression, and the gas contains corrosive components.4 The recommended system includes three liquid-ring (LR) compressors, three horizontal three-phase separators, three water coolers, piping and instruments. The FGRS that used an LR compressor at the Khangiran gas refinery is illustrated in Fig. 1. The compressed gas is routed to the amine treatment system for H2S removal. Some hydrocarbon vapor is condensed and discharged into the separator together with motive liquid. The condensate is separated from the motive liquid in the threephase separator and routed to storage. Fuel gas consumption. The expected effect of a devised

FGRS on flaring in the Khangiran gas refinery is shown in Fig. 2. The fuel gas at the Khangiran gas refinery is supplied by sweet gas. Using flare gases as an alternative fuel gas resource can significantly eliminate using sweet gas. The recommended FGRS can reduce 21,000 m3/hr of gas flaring and provide 4,810 m3/hr of sweet gas as an alternative fuel gas resource based on conditions of the FGRS outlet stream. This is similar to conditions of a fuel gas stream. Therefore, sweet gases that are used as fuel gas can be injected again into the GTU outlet stream. Another advantage of using an FGRS is that gas emissions are reduced. The recovery and use as an alternative fuel source will not only offset fuel consumption but also reduce gas emissions, a potent greenhouse gas.5–7 This waste put into fuel system significantly or entirely reduces the facility’s emissions (such as NOx, SOx, H2S, CO, CO2 and other hazardous air pollutants/ greenhouse gases) and the emissions are converted into a revenue stream and profit center.8–10 By installing an FGRS at the Khangiran gas refinery, gas emissions were decreased by 90%. Thermal radiation. An important factor when installing an FGRS is the reduction of thermal radiation. Installing an FGRS not only reduces gas flaring but also decreases the harmful impacts of flaring. Thus, some safety considerations in preliminary flare design can be neglected. When investigating the thermal radiation from the flame at the Khangiran gas refinery, the radiation fluxes that vary with distance from the flame were measured. Once the FGRS was installed, a simulation software was used to predict thermal radiation from the flame.11 Fig. 3

ENVIRONMENT/LOSS PREVENTION shows the distribution of the radiation fluxes that were calculated using reduced flowrate of flare gas from the flame, before installing an FGRS. Each black line in Fig. 3 indicates a 10 m distance from the flare stack. In addition, the impact of wind direction and wind speed is obvious. The results of thermal radiation reduction due to installing an FGRS are illustrated in Fig. 4. Comparing the results of our modeling before and after installing an FGRS shows that thermal radiation flux will be significantly reduced at the specific distance from the flame. The reduction of radiation fluxes increases the safe area around the flare stack.

This estimate includes maintenance, amortization and taxes corresponding to a payback period of approximately four months. These results have been obtained based on $0.15/m3 for fuel gas, $6/ton for steam and $0.05/KWH for electricity. HP 1 2 3

LITERATURE CITED www.khangiran.ir Fisher, P. W. and D. Brennan, “Minimize flaring by flare gas recovery,” Hydrocarbon Processing, pp. 83–85, June 2002. Ibragimov, E. R. and R. N. Shaikhutdinov, “Use of Screw Compressor Units for Flare Gas Recovery,” Chemical and Petroleum Engineering, Vol. 36, Nos. 5–6, pp. 290–291, 2000.

Noise level. Just as portions of energy released in burning waste

10.0 Before installing FGRS After installing FGRS Thermal radiation, kW/hr

gas go to thermal radiation other portions of energy go to sound and light. In some cases, the sound level becomes objectionable and is considered noise. Flaring noise is generated by at least three mechanisms: • From the gas jet as it exits the flare burner and mixes with surrounding air • From a smoke suppressant injection or mixing • From combustion.12 The noise generated by the first two, especially the second, can be mitigated by the use of low noise injectors, mufflers and careful distribution of a suppressant. The third important component when installing an FGRS is noise-level reduction. Flaring noise was investigated in a specific area, 100 m diameter from the stack. Comparisons between the results of modeling flare noise level at the Khangiran gas refinery before and after installing an FGRS are illustrated in Fig. 5. The results show that noise level will be significantly reduced at the specific distance from the flame. Also, reducing radiation fluxes creates an increase in the safe area around the flare stack.

1.00

0.10

0.01 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 Distance, m FIG. 4

Comparing the results of modeling before and after installing an FGRS (logarithmic scale).

GJP4.6e10

Economics. The FGRS includes three separate trains capable of handling varying gas load and compositions. Thus, three LR compressors, three horizontal 3-phase separators, three water coolers, piping and instruments are needed. Finally, capital investment to install an FGRS is approximately $1.4 million.

Jet Mixer System 2

1.8

2.29

1.6

1.4 1.2

Liquid jet mixers are used to mix and circulate liquids. With the jet mixers a three dimensional ﬂow is achieved in the tank without producing a rotating motion. Advantages: high eﬃciency, high operating safety, long life time, no turning parts so little wear and tear, simple construction, available in any material used in the equipment, resistant to fouling.

GEA Process Engineering

GEA Wiegand GmbH FIG. 3

The distribution of the radiation fluxes from the flame before installing an FGRS in the Khangiran gas refinery.

Einsteinstrasse 9-15, 76275 Ettlingen, Germany Telefon: +49 7243 705-0, Telefax: +49 7243 705-330 E-Mail: info.gewi.de@geagroup.com, Internet: www.gea-wiegand.com

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ENVIRONMENT/LOSS PREVENTION 4 5 6

Alcazar, C. and M. Amilio, “Get fuel gas from flare,” Hydrocarbon Processing, pp. 63–64, July 1984. Tarmoom, I., “Gas Conservation and Flaring Minimization,” SPE Middle East Oil Show, Bahrain, February 20–23, 1999. Akeredolu, F. A. and J. A. Sonibare, “A Review of the Usefulness of Gas Flares in Air Pollution Control,” Management of Environmental Quality: An International Journal, Vol. 15, Issue 6, pp. 574–583, 2004. Sharama, R. K., Y. B. Prasad and V. Harishbabu, “Minimize your refinery flaring,” Hydrocarbon Processing, February 2007.

■ The recommended system has a

modular design, composed of three

Cain, J., A. Lee and A. Mingst, “Developing and Using Technologies to Manage and Reduce Greenhouse Gas Emissions,” SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, April 2–4, 2006. 9 Veerkamp, W. and W. K. Heidug, “A Strategy for the Reduction of Greenhouse Gas Emissions,” SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, April 2–4, 2006. 10 Misellati, M., “The Path to Zero Flaring in ZADCO,” SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, April 2–4, 2006. 11 FLARES Simulation Software, Enviroware (www.enviroware.com), Italy. 12 Schwartz, R. E. and J. W. White, “Flare Radiation Prediction: A Critical Review,” 30th Annual Loss Prevention Symposium of AIChE, New Orleans, Louisiana, February 28, 1996.

separate trains capable of handling varying gas loads and compositions.

78 81 80 79 77 81.4 76 81.8

FIG. 5

65 63 64 62 66 61

Noise level (dB) around the stack before (left) and after (right) installing an FGRS at the Khangiran gas refinery.

Omid Zadakbar is a researcher at the Institute of Petroleum Engineering (IPE) at the University of Tehran, Iran. He earned an MSc degree in chemical engineering from the University of Tehran and a BSc degree in chemical engineering from Iran University of Science and Technology. Mr. Zadakbar has been involved with research concerning a wide range of energy related topics, including oil and gas process modeling and simulation.

Ali Vatani is a professor and head of the petroleum engineering department at the University of Tehran, Iran. He has written many research papers on various petroleum and natural gas engineering related topics and has conducted research on multiphase flow transmission and natural gas processing.

Saeid Mokhatab is an internationally recognized expert in the field of natural gas engineering with a particular emphasis on raw gas transmission and processing. He has been involved as a technical consultant in several international gasengineering projects and has published over 180 academic and industry oriented papers and four books on related topics. As a result of his work, Mr. Mokhatab has received a number of professional awards and is listed in several international biographical listings.

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I AUGUST 2010 HYDROCARBON PROCESSING

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STORAGE/LOSS PREVENTION

Estimating tank calibration uncertainty Use these calculations for a specific tank calibration S. SIVARAMAN, SS Tech Services, Setauket, New York; A. BERTOTTO, Soft Lab Inc., Buenos Aires, Argentina; and D. COMSTOCK, Comstock Consulting LLC, Houston, Texas

he volume of a vertical cylindrical storage tank in custody or inventory service for crude and refined products is established by tank calibration. The calibration process simply involves using a calibrated tape with a given tension to measure the tank circumference of each and every course on the tank by a manual method as detailed in API and ISO standards.1, 2 Tank external circumference may be measured with a tape in one single strap (i.e., using a tape that can traverse the entire tan circumference). The tape handling becomes extremely difficult due to its weight as the tank diameter increases. It becomes more and more difficult to maintain the tape in perfect contact with the tank shell, at a given tape tension. The tanks may also be strapped in successive segments, using a tape that is easy to handle, that can maintain full surface contact with the tank shell and yet maintain the tape in a truly horizontal plane for a given tension of the tape (Fig. 1). Three cases relating to the uncertainty of manual strapping:

1. 2. 3. n

50 ft small strapping tape 100 ft strapping tape Single tape that covers the circumference in one segment = Number of successive straps or number of strapping segments * D = Integer + 1 (for partial-length strapping tapes) L

= * D L

volume of a vertical cylindrical storage tank for the three tape lengths previously discussed. Uncertainty in diameter due to strapping procedure.

The tank strapping process that measures the circumference is subject to significant uncertainties due to the nature of the field procedures involved. These factors are broadly summarized: • Variations in tape tension at each segment • Variations in successive strap location (end point of the first and the start of the second strap) • Number of straps or segments involved • Non-uniform surface contact between the tape and the tank shell wall • Maintaining the tape in a true horizontal plane at any given level in a course or ring • Weather conditions such as wind or rain and lack of adequate light • The shell’s non uniformity resulting in gaps between the tape and the tank wall. All these factors result in random uncertainty in the strapped circumference, hence, the diameter at each course. The net uncertainty in circumference and diameter due to a strapping procedure at each course is computed as follows: CS = S n

DS = (for full-length strapping tape)

(1)

CS S n =

(2)

Starting point 3

where D = Tank’s nominal diameter L = Strapping tape length π = 22⁄7 assumed The thickness of each course is also measured from the circumference and tank course thickness. The internal diameter is computed which is the basis for calculating tank volume. In addition, the deadwood (miscellaneous piping and structures) is deducted from the computed volume to give the net tank volume. The volume computed is the basis for custody transfer calculations. There are two major factors that account for more than 70% to 80% of the total uncertainty and they are: • Circumference measurement by successive segmental strapping • Shell plate thickness measurement. These two parameters will be discussed further. A simple methodology is presented to estimate the impact on the calibrated

End point 2

End point 3

Segment 3

Starting point 1

Segment 2 Segment 1 Starting point 2 End point 1

FIG. 1

Three-segment tank strapping circumference measurement—an example. HYDROCARBON PROCESSING AUGUST 2010

I 55

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STORAGE/LOSS PREVENTION Uncertainty in diameter due to thickness measurement:

VC (4 t ) = , for a given course VC Do

(5)

Or, in more general terms, the thickness uncertainty as a % of the course volume is simply expressed as:

D1 = Do 2 t D1 = 2 t (absolute value) Total tank volume uncertainty calculation (per course and all courses) Thickness measurement impact per course. This can

be calculated as follows: D 21 (Do 2 t )2 VC = = , for unit height 4 4 2 (Do 2 t ) ( 2 t ) VC = 4

(3)

Expressing ΔVC as a total volume fraction for a given course leads to:

UTC

VC 4 t 100 = 100, for a given course VC D

(6)

Segmental strapping impact per course. By analysis similar to Eq. 6 with regards to diameter only and assuming that thickness is constant, the following equation is derived for uncertainty in diameter per course due to strapping procedure:

D12 (Do 2 t )2 = , for unit height 4 4 2 (Do 2 t ) ( Do ) VC = 4 VC 2 (Do 2 t )( Do ) 1 = 4 VC (Do 2 t )2

VC =

(7)

4 Since Do >>>> 2*t, Eq. 7 reduces to:

VC 2 (Do 2 t ) ( 2 t ) 1 = 4 VC (Do 2 t )2

VC 2 Do 2 D = = VC Do D

VC (4 t ) = , in absolute units (Do 2 t ) VC

(4)

Since 2*t is very small, compared to DO, Eq. 4 may be reduced to the following:

U DC =

(8)

VC 2 D 100 = 100, or a given course VC D

(9)

where ΔD is computed using Eq. 2, based on the number of segments and the uncertainty associated with each segment.

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HYDROCARBON PROCESSING AUGUST 2010

STORAGE/LOSS PREVENTION Total course volume uncertainty (UCV %). Total impact of uncertainty in diameter due to successive straps and due to

2 , % for a single course U CV = U 2DC + U TC

TABLE 1. Parameters used for development of uncertainty

U CV =

Tank diameter (ft)

50, 100, 200, 250 and 300

Number of courses or rings

6 for each tank diameter under consideration (C1 through C6) 50, 100 and full length tape (strap circumference in full)

Maximum target limit of uncertainty

0.05%

Desirable value of calibrated volume uncertainty

0.01% to 0.05%

Strapping uncertainty in mm (⌬s)

5 mm to 20 mm for segmental tapes and floating up to 50 mm 10 to 50 mm for full length tapes and floating up to 160 mm

TABLE 2. Tape length and number of segments 50

100

150

200

250

300

50 ft tape

D)2 (D)2

100 2 +

T )2

(10)

1002

(D)2

(11)

Total tank volume uncertainty—all courses. Total tank volume uncertainty is the statistical sum of all individual course uncertainties and is computed in Eq. 6. Since all course volumes are assumed equal (= UCV) for the current analysis, Eq. 12 is simplified and may be used directly in percentage.

Calibration tape length (ft)

Tank diameter (ft)

thickness uncertainty on course volume is the statistical sum of the two individual uncertainties (%) as computed in Eqs. 3 and 5.

100 ft tape

Full length tape

UTOV =

U CV (%)

(12)

where N = the number of courses (6 or 8 courses typical). It is generally good practice to use absolute volume units for a statistical sum. However, as long as the course volumes are almost equal, one can statistically add the percentages. Impact of deadwood and other parameters on tank uncertainty. Deadwood reflects the components

within the tank such as inlet and outlet piping, heating coils, roof drain piping and other support structures. The space occu-

TABLE 3. Tank calibrated volume uncertainty: UTOV (± %): 6 Courses Tank diameter (ft) 100

± ⌬t 1 to 3 mm

150

200

Tank Volume ± % ± ⌬t 1 to 3 mm ± ⌬t 1 to 3 mm

250

300

± ⌬t 1 to 3 mm

0.02–0.04

0.01–0.02

0.01

0.01–0.02

0.01

0.04–0.05

0.02–0.03

0.02

0.01

0.03

0.05–0.06

0.03–0.04

0.03

0.02

0.07–0.08

0.05

0.04

0.03

100

0.02–0.03

0.01–0.02

0.01

100

0.03–0.04

0.02

0.01–0.02

0.01

Tape length, ft

± ⌬s mm

0.05 0.05 0.05 0.05

100

0.04–0.05

0.03

0.02

100

0.05–0.06

0.03–0.04

0.03

0.02

100

0.05

Full-length

0.02–0.04

0.01–0.02

0.01

Full-length

0.04–0.05

0.02

0.01

0.05 0.05 0.05

Full-length

0.05

0.03

0.02

0.01

Full-length

0.09

0.04–0.05

0.03

0.02

Full-length

110

Full-length

140

Full-length

160

I AUGUST 2010 HYDROCARBON PROCESSING

0.05 0.05 0.05 0.05

STORAGE/LOSS PREVENTION pied by these components is measured and excluded from the tank volumes.1 When the tanks are newly constructed, the volume occupied by the deadwood is measured as entry into available tanks. The volumes are computed accurately using physical measurements with some residual deadwood uncertainty. Tanks undergo recalibration once every 10 to 15 years. Such recalibration is generally carried out using the deadwood’s original value since the tanks may be in service. Thus, the original uncertainty, if available, will be carried over. In addition, the deadwood is unique to each tank. To account for uncertainty, a safety or an experience factor of about 30 to 50% may be applied to the total tank volume uncertainty computed, using Eq. 12. This takes into account all other miscellaneous factors such as temperature correction, density correction, deadwood, etc.

º Carry cut calibration at stable ambient conditions with no wind or rain. • If the tank owner permits overall uncertainty around 0.05% for all diameters, then the corresponding strapping uncertainty (Δs) could be proportionately larger for varying diameters as illustrated under the shaded area of Table 3. • Using a full-length tape—while difficult to handle especially on large diameters (e.g., 300 ft)—gives more flexibility in strapping to achieve the same desired level of volume uncertainty of 0.05% for all diameters (e.g., for a full-length tape for 300 ft diameter, one can tolerate a strapping uncertainty of 160 mm to achieve a volume uncertainty of 0.05%). • The calibrated tank volume uncertainty compares very favorably with meter calibration residual uncertainty (allowable meter factor variation ± 0.025%). Conclusion. The primary objective in calibration or recalibra-

Total tank volume uncertainty including deadwood.

From Eq. 12, UTANK is computed and includes deadwood uncertainty. UTANK = 1.3 UTOV to 1.5 UTOV (13) UTANK = 1.3

U CV (%)

to 1.5

U CV (%)

(14) N N Basic parameters used for development of uncertainty are listed in Table 1. A typical application of the calculation methodology is illustrated under Example 1 for a 100 ft diameter tank using a 100 ft tape. Using the same procedure illustrated, estimated tank volume uncertainties (UTOV %) are presented in Table 2. Analysis of uncertainties. Table 1 provides a ready correlation between three parameters, namely, strapping uncertainty (Δs in mm), thickness uncertainty (Δt in mm) and overall calibrated tank volume uncertainty for diameters ranging from 50 ft to 300 ft. The following observations were deduced from Table 2 and are: • The resulting volume uncertainty (U%), for any given tank diameter is more or less the same for all three tape applications within the specified range of strapping uncertainties (Δs) • The choice of tape length, therefore, is not that critical as long as one can handle the larger tape length with the same level of precision (i.e., Δt, Δs) at all course heights from the bottom to the top of the tank. º It must be emphasized that a 50 ft or 100 ft tape is much easier to handle than the full length tape at all elevations. º The chance of random error propagation is also reduced with shorter lengths of tape. • Smaller tanks inherently are subject to higher volume uncertainty (%) since the divisor is small. A full-length tape under controlled condition provides the best option for smaller tanks • One can target for a 5mm best achievable segmental uncertainty for shorter-length tape or a 10 mm best achievable segmental uncertainty for full-length tape if the following conditions are met: º Maintain absolute contact between shell and the tape at all levels º Maintain the tape in true horizontal position at all levels º Compensate for the tape’s weight with proper supports º Maintain constant tension on the tape at all times and at all levels which requires sliding the tape to transmit equal tension across the tape

tion is to ensure that the uncertainty due to the field procedures is maintained and controlled at a minimum level. The guidelines presented will enable one to estimate quickly the overall volume or strapping uncertainty prior to calibration start. The methodology presented is simple and straight forward for quick evaluation and facilitates easy application of basic principles to estimate the uncertainty values and it does not call for complicated computer skills or tools. It will also help in controlling the segmental uncertainty (mm) for a given tank or the volume uncertainty (%) or vice versa. A full-length tape offers the best option as long as proper precautions are taken for its application as outlined. This does apply to the measurement of a reference strap on the bottom course which requires a master tape that is directly calibrated by a national metrological institute of the country (e.g., NIST in the US). Finally the calibration uncertainty is always systematic in nature and that will eventually manifest itself as a net loss or gain in mass balance in refining and chemical plants, as well as in pipeline terminal systems.3 This is why the calibration quality of a tank is so critical to subsequent measurement accuracy. Notations

UTANK = UTOV UDC UTC VC t D Do DI Δt Δs ΔCS, ΔDS ΔDt n N C

Overall tank calibration volume uncertainty % (includes deadwood) = Uncertainty in the total volume (%) = Uncertainty in course volume % due to segmental strapping = Uncertainty in course volume % due to thickness measurement = Course volume per unit height = Thickness of tank shell wall = Nominal tank diameter (ft) = External diameter of the tank shell (ft) = Internal diameter of the tank shell (ft) = Uncertainty in thickness of tank shell wall (mm) = Strapping uncertainty per strap segment (mm) = Computed uncertainty in circumference and diameter due to segments (mm) = Uncertainty in tank diameter due to thickness (mm) = Number of strapping segments for a given circumference (3 to 19 segments) = Number of courses (6 and 8 courses typical) = Course or ring HYDROCARBON PROCESSING AUGUST 2010

I 59

STORAGE/LOSS PREVENTION Example 1 calculation

Step 4: Total tank volume uncertainty—all courses

Assume course volumes are all equal = VC (for any single course) Total tank volume TOV = 6 * VC (for 6 courses) First course ΔVC = VC * (0.19/100) in volume units Second course ΔVC = VC * (0.19/100), etc.

Tank data:

Nominal tank OD Δt, thickness uncertainty Number of courses Per segment uncertainty Tape length

50 ft 3 mm 6 20 mm 50 ft

Total tank

Step 1: Thickness impact

4 3 mm 100 mm in. 25.4 50 ft 12 in ft = 0.08%

UTC =

UTC

ΔVT =

0.19 = VC 6 100

(6)

% Uncertainty

UTOV =

% Uncertainty

UTOV =

Step 2: Segmental strapping impact

4 DS = 20 mm 7 = 12.7 mm 22 2 12.7 mm 100 U DC = mm in. 50 ft 12 25.4 in ft UDC = 0.17%

(2) (9)

VC 6 VC

0.19 100

( 6)

0.19 6

Step 5: Total tank volume uncertainty including deadwood, etc.

UTANK = 1.3 * 0.08 % to 1.5 * 0.08% (12, 13) UTANK = 0.10% to 0.12% or an average value of 0.11%

(10, 11)

UCV = 0.19%

All net values are rounded off to the second decimal place. It’s recommended to round off at the completion of the total tank volume uncertainty calculation. HP

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I AUGUST 2010 HYDROCARBON PROCESSING

100

UTOV = 0.08%

Step 3: Course volume uncertainty

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LOSS PREVENTION NOTES 1. Table 3 reflects the impact of strapping and thickness measurements only. 2. As illustrated in Table 3, smaller tanks require a higher level of precision in strapping to maintain UTOV values within 0.05%. 3. Recommended not to exceed a level of 0.05% uncertainty 4. Values for eight courses almost similar to the above and slightly less 5. Full-length is the tape length long enough to span the tank circumference in one segment 6. Multiply the above values by a factor of 1.3 to 1.5 to compute for UTANK (accounting for deadwood, etc.) 7. All values rounded off to second decimal place after complete calculation of the total tank (UTOV) 8. Rounding off uncertainty ± 0.01%

1 2 3

LITERATURE CITED Measurement and Calibration of Upright Cylindrical Tanks by the Manual Strapping Method, API Chapter 2.2A. Calibration of Vertical Cylindrical Tanks—Part 1: Strapping Method, ISO 7507-1. Sivaraman, S. and A. Bertotto, “Determine unknown loss in refineries and terminals,” Hydrocarbon Processing, March 2006.

Srini Sivaraman retired from Exxon after almost 25 years of service and now manages his own consulting company (SS Tech Services). It specializes in the fields of custody transfer measurements, mass balance and oil-loss control in the petrochemical industry—from production to marketing and distribution. During his tenure with Exxon, he participated in many research projects in development and/or application of new technologies for custody transfer such as tank calibration technologies, automatic tank gauging systems, automatic sampling systems, etc. Mr. Sivaraman has authored more than a dozen papers in international journals. He has been very active within API and ISO for the past 20 years, and more than a half-dozen standards have been produced under his leadership. Mr. Sivaraman presently serves as Convener of the ISO tank calibration working groups and co-chair of the API tank calibration working group.

Ariel Bertotto is a reservoir engineer with 30 years of expertise, mainly in the upstream oil industry, transport and yield accounting. He has worked on petroleum thermodynamics, rheology, PVT analysis, laboratory special core tests, nodal calculation in wells and ducts, data reconciliation, custody transfer surveys, oil loss control, data acquisition, etc., having founded a core laboratory, with PVT capabilities, and a software house, SoftLab SRL, dedicated exclusively to developing oil databases and technical applications. Mr. Bertotto is general manager and CEO of SoftLab, a company with 20 years of consulting in the oil markets, having implemented more than 120 systems and different jobs, with a very well-known name in the South American markets. He is also a lead auditor in quality certification, both American and European licences, referee of papers and publications; and a member of SPE.

Dan Comstock has over 35 years field and management experience in petroleum and petrochemical measurement. He worked for Halmor Services Inc. and other service companies on meter provers, and measurement systems, waterdraw prover calibration, startup activities, etc. at domestic and foreign sites. Mr. Comstock served as project manager for the first successful introduction of ballistic provers in the hydrocarbon industry with Basic Resource Services, Inc. by taking an early model to the North Sea after extensive testing in Oklahoma. For many years he served as head of the measurement and instrumentation group for SGS North America Inc. in the US, whose activities included tank calibration, shipboard sampling by automatic inline sampler, meter proving (onshore and offshore), prover calibration, natural gas orifice meter inspection, chart integration, natural gas sampling and analyses. Mr. Comstock has served on many API committees on liquid, gas and marine measurements and presently serves as chairman of the API tank calibration working group. He regularly serves as a special advisor to the International School of Hydrocarbon Measurement (affiliated with the University of Oklahoma). Mr. Comstock currently works as a petroleum measurement training specialist for Petroleum Extension Service, continuing education (PETEX) at the University of Texas, and provides petroleum measurement consulting services through Comstock Consulting, LLC. He studied at Benedictine Heights College and the University of Tulsa.

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PROCESS INSIGHT Selecting the Best Solvent for Gas Treating Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are methanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.

Tertiary Amines A tertiary amine such as MDEA is often used to selectively remove H2S, especially for cases with a high CO2 to H2S ratio in the sour gas. One beneﬁt of selective absorption of H2S is a Claus feed rich in H2S. MDEA can remove H2S to 4 ppm while maintaining 2% or less CO2 in the treated gas using relatively less energy for regeneration than that for DEA. Higher weight percent amine and less CO2 absorbed results in lower circulation rates as well. Typical solution strengths are 40-50 weight % with a maximum rich loading of 0.55 mole/mole. Because MDEA is not prone to degradation, corrosion is low and a reclaimer is unnecessary. Operating pressure can range from atmospheric, typical of tail gas treating units, to over 1,000 psia.

Mixed Solvents In certain situations, the solvent can be “customized” to optimize the sweetening process. For example, adding a primary or secondary amine to MDEA can increase the rate of CO2 absorption without compromising the advantages of MDEA. Another less obvious application is adding MDEA to an existing DEA unit to increase the effective weight % amine to absorb more acid gas without increasing circulation rate or reboiler duty. Many plants utilize a mixture of amine with physical solvents. SULFINOL® is a licensed product from Shell Oil Products that combines an amine with a physical solvent. Advantages of this solvent are increased mercaptan pickup, lower regeneration energy, and selectivity to H2S.

Primary Amines The primary amine MEA removes both CO2 and H2S from sour gas and is effective at low pressure. Depending on the conditions, MEA can remove H2S to less than 4 ppmv while removing CO2 to less than 100 ppmv. MEA systems generally require a reclaimer to remove degraded products from circulation. Typical solution strength ranges from 10 to 20 weight % with a maximum rich loading of 0.35 mole acid gas/mole MEA. DGA® is another primary amine that removes CO2, H2S, COS, and mercaptans. Typical solution strengths are 50-60 weight %, which result in lower circulation rates and less energy required for stripping as compared with MEA. DGA also requires reclaiming to remove the degradation products.

Secondary Amines The secondary amine DEA removes both CO2 and H2S but generally requires higher pressure than MEA to meet overhead speciﬁcations. Because DEA is a weaker amine than MEA, it requires less energy for stripping. Typical solution strength ranges from 25 to 35 weight % with a maximum rich loading of 0.35 mole/mole. DIPA is a secondary amine that exhibits some selectivity for H2S although it is not as pronounced as for tertiary amines. DIPA also removes COS. Solutions are low in corrosion and require relatively low energy for regeneration. The most common applications for DIPA are in the ADIP® and SULFINOL® processes.

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GAS PROCESSING DEVELOPMENTS

Optimize operating parameters of absorbers/strippers in gas plants Better recovery definition of C3s and C4s from gas absorber/stripper can lower costs J. NAVA, SNC Lavalin, Energy and Infrastructure Division, Toronto, Ontario, Canada

everal factors affect the recovery of C3s and C4s in gas recovery refinery type plants, typically found in delayed cokers, fluid catalytic cracking (FCC) and other downstream gas processing units. These factors include: flowrates, stream compositions, pressures, recovery specifications, solvent temperatures and volume of solvents required.1,2 Operating efficiency of the absorber/stripper gas plant section also involves the amount of lean oil entering the secondary absorber and the volume of stabilized naphtha recycled back to the primary absorber.3,4 A sensitivity study was done to optimize the design of an absorber/ stripper gas plant section to improve recovery of C3s and C4s. Recovery targets of the evaluation are to be based on balancing an assumed refinery sour gas streams with liquefied petroleum gas (LPG) production while controlling both capital investment and operating costs.

recoveries, 11 different options were considered using a model developed in a commercial simulator (see Table 1) for a process

scheme proposed in Fig. 1. For evaluation purposes, the same process scheme is considered for all options presented here.

TABLE 1. Recovery factors for C3 and C4 in LPG product and naphtha streams Option

Recycle naphtha reduction

Base Case

Lean oil reduction

C3 vol%

C4 vol%

C3 vol%

Without considering recovery in naphtha

C4 vol%

Considering recovery in naphtha

98.13

93.68

99.07

98.84

0.59

81.14

92.26

90.57

97.15

0.55

77.02

93.59

88.51

98.48

0.63

85.12

93.63

92.56

98.58

0.71

90.39

93.65

95.19

98.64

0.80

93.59

93.67

96.79

98.69

0.88

95.48

93.68

97.74

98.72

0.74

97.88

93.05

98.94

98.13

0.59

97.79

92.40

98.90

97.46

0.44

97.71

91.81

98.85

96.85

0.29

97.62

91.34

98.81

96.34

0.55

0.29

76.21

91.04

88.11

95.83

C3s and C4s recoveries. Varying the

amount of lean oil entering the secondary absorber and stabilized naphtha in the primary absorber directly impacts C3s and C4s recoveries.5 This article reports a study developed to evaluate the economic impact of a grassroots design for an absorption/stripping gas plant applying variations in C3s and C4s recoveries. Fig. 1 shows a simplified process scheme used in this sensitivity analysis. Absorption/stripping sections of this type of gas recovery unit can be adapted for different configurations depending on process conditions and operating preferences. The chosen process configuration is a simple one; it uses a typical composition and common operating conditions to expedite the data generation and analysis.5 Simulation. To evaluate the effect of lean oil and recycled naphtha on C3s and C4s

Sour gas Lean oil Primary absorber

Secondary absorber Naphtha

Wet gas

Rich oil

Side CW stripper reboiler

ReďŹ&#x201A;ux to fractionator Stripper

Stabilizer

C3/C4

Stripper reboiler

FIG. 1

Simplified gas plant processing scheme.

HYDROCARBON PROCESSING AUGUST 2010

I 63

GAS PROCESSING DEVELOPMENTS 120 100 C3, vol%

C3, vol%

80 60 Without considering recovery in naphtha With considering recovery in naphtha

40 20 0 0.0

FIG. 2

0.2

0.4 0.6 0.8 Recycled naphtha reduction, %

1.0

1.2

C3s recovery efficiencies with varying absorption rates of naphtha.

100 99

97 96 95

Without considering recovery in naphtha With considering recovery in naphtha

94 93 0.0

FIG. 3

0.2

FIG. 4

100 99 98 97 96 95 94 93 92 91 90 0.0

C4, vol%

99.2 99.0 98.8 98.6 98.4 98.2 98.0 97.8 97.6 97.4 0.0

0.4 0.6 0.8 Recycle naphtha reduction, %

1.0

1.2

C4s recovery efficiencies with varying absorption rates of naphtha.

FIG. 5

1.08 1.07 Sour fuel gas increase ratio, volume ratio

Net present loss ratio

1.03 1.02 1.01 1.00 0.99

C3s recovery efficiencies with varying absorption rates of lean oil.

Without considering recovery in naphtha With considering recovery in naphtha

0.2

To estimate the C3s and C4s recoveries, two different recoveries are calculated. The first approach considers C3s and C4s recoveries only in the LPG product; C3s and C4s in the naphtha product are considered lost—LPG is the only reference. The second approach considers the amount of C3s and C4s in LPG, as well as in the naphtha streams, as recovery. Figs. 2 and 3 show the recovery changes of C 3s and C 4s for the Base Case and Options 2–6. For these options, only the rate of recycled naphtha changes and the rate of lean oil stream is constant, which is the same as the Base Case. Fig. 2 shows that

I AUGUST 2010 HYDROCARBON PROCESSING

0.4 0.6 0.8 Lean oil reduction, %

1.0

1.2

C4s recovery efficiencies with varying absorption rates of lean oil.

Loss of revenue

0.40 0.20

FIG. 7

Option 1

1.2

0.60

Fuel gas production rate using various absorber/stripper designs.

Option 4

1.0

0.80

0.00

Option 8

0.4 0.6 0.8 Lean oil reduction, %

1.00

Option 2

Base Case

0.2

1.20

1.06 1.05 1.04

FIG. 6

Without considering recovery in naphtha With considering recovery in naphtha

Base Case

Option 8

Option 4

Option 1

Option 2

Loss of revenue with various absorber/stripper designs.

changes for C3s recovery are not linear with equal variations of recycled naphtha sent to the absorber. These changes are more significant at lower flow rates. As illustrated in Fig. 3, C4s recovery does not vary significantly. Figs. 4 and 5 illustrate the recovery changes of C3s and C4s for the Base Case and Options 7–10. In these options, only the rate of lean oil is changed, and the rate for recycled naphtha is constant—it is the same as the Base Case. As shown in Fig. 5, C4s recovery is lowered by reducing the amount of lean oil stream sent to the secondary absorber (also referred to as a sponge oil absorber or B-B absorber).1

By using a commercial process simulator, the effects from these changes for the two streams is used to size key equipment for each option. By considering Figs. 2–5 with a simplified cost analysis, four options are selected for further analysis, i.e., Base Case, Option 1, Option 2, Option 4 and Option 8. C3s and C4s in fuel gas. With lower

recovery efficiencies, more C3s and C4s are routed to fuel gas. Consequently, the heating value of the fuel gas increases. Fig. 6 shows the volume changes of the sour fuel gas for the different cases.

BORSIG

GAS PROCESSING DEVELOPMENTS TABLE 2. Capital cost analysis for varying lean oil and recycled naphtha flowrates in the absorber/stripper unit Service

Option 8

Option 4 Option 1 Cost ratio

Option 2

Columns Primary absorber

1.00

0.81

0.73

0.81

Stripper

1.00

0.70

Secondary absorber

0.69

0.84

0.69

0.84

Stabilizer

1.00

0.67

0.59

0.55

1.00

0.78

1.39

0.63

Vessels Compressor discharge drum Pumps Stripper feed pump

1.00

0.74

0.67

0.64

Stabilizer bottoms pump

1.00

0.68

0.59

0.56

Lean oil booster pump

0.73

1.00

0.74

1.00

Stabilizer reflux pump

1.00

0.72

0.63

0.61

Compressor discharge trim cooler

1.00

0.81

0.72

0.69

Stabilizer bottoms trim cooler

1.00

0.70

0.59

0.57

LGO-lean sponge oil trim cooler

0.73

1.00

0.75

1.00

Stripper bottom reboiler

1.00

0.78

0.70

0.67

Stripper side reboiler

1.00

0.86

0.82

0.80

Stabilizer reboiler

1.00

0.51

0.83

Heat exchangers

Air cooler Stabilizer bottoms air cooler Total ratio to original cost

1.00

0.64

0.56

0.52

0.98

0.72

0.70

0.66

Note: Based on Base Case as 1.00

Cost estimate. Based on selected options, capital and operating costs (+/â&#x20AC;&#x201C; 50%) are estimated: Capital expenditure. The changes in the amount of recycled naphtha and lean oil streams have effects on the equipment sizing. Table 2 lists the changes related to the major equipment and related capital costs. The capital cost for the original design is kept as 1 as a reference, and the remaining options are evaluated based on the Base Case (Base Reference of 1). As shown in Table 2, Option 2 has the lowest capital cost for this specific study case. In this case, by reducing almost 12% in C3s recovery, the capital cost savings is approximately 34%. In Option 4, a 5% reduction in C3s recovery can yield a 28% savings in capital costs. For this option, there is a higher capital cost reduction without significant cuts in C3s recovery. Operating expenditure. Table 3 summarizes the operating cost for cooling water and horsepower requirements for five selected options. Since this calculation applies a multiplier, the table shows the ratios for both cooling water consumption and horsepower needs that are used by each option. This ratio applies to operating

costs. Option 2, which has the lowest capital cost, consumes 38% less cooling water and almost 50% less horsepower than the Base Case. Option 4, which also has significant capital cost savings, consumes 29% less cooling water and 34% less horsepower as compared to the Base Case.

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Cost analysis. As illustrated earlier,

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options with lower recovery efficiencies for C3s and C4s recoveries (mainly C3s) require lower capital investment and operating costs but with reduced LPG production. Consequently, higher heating value of the fuel gas produced from the gas plant is possible. Table 4 summarizes presented issues. Of all of the scenarios considered, Option 2 offers the highest savings. A simplified economic evaluation was done to determine the net present loss (NPL) at an interest rate of 9%. NPL was calculated based on:

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GAS PROCESSING DEVELOPMENTS TABLE 3. Cooling water and horsepower requirements and related operating cost ratios

Clean out your tank. Not your wallet.

Base case

Option 8

Option 4

Option 1

Option 2

Compressor discharge trim cooler

0.68

0.50

0.45

0.44

Stabilizer bottoms trim cooler

0.26

0.16

0.13

0.12

CW requirement ratio or cost ratio

LCGO-lean sponge oil trim cooler

0.06

0.04

0.06

0.04

0.06

1.00

0.98

0.71

0.62

Stripper feed pump

0.27

0.18

0.16

0.15

Stabilizer bottoms pump

0.53

0.32

0.26

0.25

Lean oil booster pump

0.01

Stabilizer reflux pump

0.19

0.13

0.11

0.10

1.00

0.64

0.53

0.51

Total (BHP/BHP total) or cost ratio

Total

TABLE 4. Cost comparison of possible operating scenarios for the absorber/ stripper in the gas plant Base Case Option 8 Option 4 TIC ratio

0.981

0.724

0.699

0.660

51.5

48.5

9.7

5.8

–

1.5

Incremental operating cost, %

100.0

50.0

0.0

–

Differential energy added (lost) to fuel gas, %

(4.7)

(4.2)

(2.3)

(0.27)

–

Incremental LPG production, %

5.7

5.3

2.0

0.82

–

Incremental capital cost, %

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Option 1 Option 2

Operating cost ratio

the income is assumed to start during the first year of the 20-year life cycle. Major maintenance turnarounds were considered every five years and it is considered as a fraction of the incremental income for that year. Fig. 7 shows the NPL values for five different operating options. The results are reported as a ratio to the Base Case. As illustrated in Fig. 7, Base Case and Option 8 show very high revenue losses as compared to Option 2. This value was significantly reduced for the other two options. Design considerations. It was proved

that lean oil flowrate changes going to the secondary absorber does affect the amount of C4s recovery. The amount of C3s recovery, as reported in different designs, is affected by varying recycled naphtha volume sent to the primary absorber. Lowering recoveries of C3s and C4s, as a result of reduction of the mentioned streams, can significantly decrease both capital investment and operating costs while keeping economically viable recovery factors. This type of analysis should be done on a case-by-case basis in conjunction with the fuel gas balance, as this fuel gas balance may impose restrictions to the recoveries of C3s and C4s. By comparing the costs and the percentage of recoveries, Option 4 could be selected as probably the best case. For this case, the

C 3 recovery is almost 95% and the C 4 recovery is almost 99%. NPL is lower than the Base Case. Although Options 1 and 2 show lower capital cost, the recoveries of C3 and C4 are also lower. The NPL is very close to Option 4. HP 1 2 3

LITERATURE CITED Nelson, W. L., Petroleum Refinery Engineering, McGraw Hill Book, Second Ed., 1941. Green, D. W. and R. H. Perry, Perry’s Chemical Engineers’ Handbook, Seventh Ed., McGraw-Hill. Golden, S., “Case studies reveal common design, equipment errors in revamps,” Oil and Gas Journal, April 1997. Golden, S., “Simple engineering changes fix product recovery problems,” Oil and Gas Journal, April 1997. Kaes, G. L., Refinery Process Modeling, Kaes Enterprises, Inc., First Ed., March 2000.

ACKNOWLEDGMENT The author thanks Dr. Shiva Habibi for guidance and technical review of this article. Dr. Habibi is a former researcher for the University of Toronto, and now she works for Ontario Power Generation, Canada.

Joe Nava is Manager of process engineering in SNC Lavalin, Energy and Infrastructure Division, Toronto, Canada. He has 19 years of experience in process engineering and design in refining, production, gas processing and renewable fuels. He holds a BS degree in mechanical engineering and an M. Eng. degree in chemical engineering. He is a professional engineer registered in Ontario.

AND

PROCESS CONTROL INSTRUMENTATION

CONTENTS

Special Supplement to

Process control and instrumentation trends and spending forecasts

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Corporate Profiles Emerson Process Management Yokogawa Micro Motion Honeywell

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PROCESS CONTROL AND INSTRUMENTATION 2010

Headline Process control and instrumentation (2 lines) trends and spending forecasts LES KANE, Editor

TABLE 1. HPI process control instrumentation spending, % dollars Item

Percent

According to the 2010 HPI Market Data Book, worldwide hydrocarbon processing industry (HPI) spending for process control systems and instrumentation is forecast to be nearly $10 billion in 2010. This is about 20% of all HPI equipment spending and is the largest equipment spending category. Table 1 shows the percentage of expenditures for various instrumentation categories.

Process control systems

Control valves and actuators

Purchased application software

Online process analyzers and sample systems

Flow transmitters and elements

Pressure transmitters

HPI process control and instrumentation requirements are so large because of the industries size and the many automation levels implemented (Fig. 1).

Temperature transmitters

Two line caption

Level transmitters

Miscellaneous (tubing, fittings, gauges, etc.)

These include: • Frontline instrumentation • Advanced regulatory control • Advanced process control • Real-time optimization • Planning and scheduling • Business information systems.

Note: Spending does not include control rooms, laboratory and portable analyzers, plant information/management computer systems, and engineering and installation costs. Process control system spending includes hybrid DCSs, operator displays, I/O systems and instrument cable.

TABLE 2. Five pillars of fieldbus justification

Fieldbus. One of the main focus areas is fieldbus, which is an all-digital communications protocol that enables microprocessor-based field instruments to communicate with each other and the control systems via a single network bus. The information provided includes not only the condition of the instrumentation and valves, but also the status of the monitored process equipment. This enables potential failures to be detected early so actions can be taken to avoid shutdowns and safety and environmental issues. Fieldbus is

• Superior return on assets • Reduced maintenance cost • Reduced unplanned downtime • Abnormal situation avoidance • Knowledge workforce creation Source: O’Brien, L., Hydrocarbon Processing, April 2005

Planning and scheduling

2,500 Days Hours

2,000

Advanced process control

Minutes

1,500

Analyzers and online inferentials

Minutes

1,000

Regulatory layer– PIDs, cascades, ...

Seconds

500

Optimization

Instrumentation layer – valves, I/Ps, sensors, ...

0 2006

2007

2008

2009

2010

FIG. 1. Typical plant process control hierarchy showing differences in timing requirements.

FIG. 2. Worldwide market for fieldbus solutions in the process industries (millions of dollars).

Source: Mitchell, M. P., and Shook, D. P., 2003 ERTC Computing Conference

Source: O’Brien, L., Hydrocarbon Processing, May 2007

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HYDROCARBON PROCESSING

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PROCESS CONTROL AND INSTRUMENTATION 2010 also enabling better asset management. Table 2 shows some of the benefits of implementing fieldbus. According to ARC Advisory Group (Dedham, Massachusetts), fieldbus adoption in the process industries is growing rapidly (Fig. 2).

Alarm management. Alarm management practices are also attracting a lot of attention as HPI companies strive to improve safety. It is easy and cheap to include alarms in modern distributed control systems, so many alarms are included that are not critical. This results in operator alarm overload and confusion. Thus, HPI companies are rethinking their alarm strategies and including only those alarms that are crucial to plant safety and operation. Table 3 shows some of the benefits of implementing better alarm management strategies.

construction trends. In addition, capital and maintenance spending, and spending for various types of equipment and services, are forecast. The Market Data Book also includes a CD ROM that shows over 10 years of construction activity, includes a worldwide plant directory and selected articles from Hydrocarbon Processing. To purchase a copy contact Bill Wageneck, publisher at e-mail: bill.wageneck@gulfpub.com. ■

Wireless sensors. The use of wireless instrumentation is also starting to take off. Because there is no need to run wires to the instruments, measurements that were too expensive to obtain before can now be obtained cost-effectively. Table 4 and Fig. 3 show some of the applications for wireless sensors in the process industries. More details are available. More details on process con-

FIG. 3. A self-organizing field network. Source: Marin, G., Hydrocarbon Processing, March 2009

trol and instrumentation use in the hydrocarbon processing industry are provided in our 2010 HPI Market Data Book. The publication also covers energy, refining, petrochemicals, gas processing, alternative fuels, biofuels, environment health and safety, maintenance and retrofitting, and

One-Hour Live Webinar and Question & Answer Session

H y d r o c a r b o n P r o c e s s i n g . c o m

TABLE 3. Key areas of alarm management justification Area

Benefits

Safety Unplanned downtime

Reduced risk of human injury and incidents Avoid plant shutdown, lost product and associated costs Avoid nuisance alarms, improved fault tracing Give operator more time to focus on the process, creating knowledge workforce

Information management Role of the operator

WEBCAST Live Event August 17th 10 a.m. CST, 11 a.m. EST

Process Control and Instrumentation Webinar – Part I

Source: O’Brien, L., Hydrocarbon Processing, April 2008

TABLE 4. Applications for wireless sensors • Process measurements can be taken from wireless transmitters. • Wireless video cameras can be used for perimeter security. • Radio frequency identification can be used for plant inventory or asset tracking. • Sensors can be used for real-time monitoring of equipment deterioration. • Wireless networks can enable technicians and engineers to process in-field work immediately rather than manually later back at their desks.

Y.Zak Friedman Contributing Editor, Hydrocarbon Processing

Les Kane Editor, Hydrocarbon Processing