Pumps & Systems - August 2015

Component or CartridgeChoose the Right Seal

How Remote MonitoringEmpowers Plant Employees

Trade Show PreviewTurbomachinery &

Pump Symposia

OPTIMIZE SYSTEM

PERFORMANCE

The Leading Magazine for Pump Users Worldwide

AUGUST 2015

PUMPSANDSYSTEMS.COM

®

SYSTEMS

4 highly engineered solutions to help you get the most from your pumps

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Circle 100 on card or visit psfreeinfo.com.

August 2015 | Pumps & Systems

2

From the Editor

As you � ip through the pages of

this issue, the Pumps & Systems

team is gearing up for a busy season of

trade shows and travel. Next month,

we will be heading to Houston for

the 44th Turbomachinery & 31st

Pump Symposia (TPS), Sept. 14-17,

where optimizing pumping systems—

including piping, lubrication,

motors, drives, seals, couplings and

alignment—will be a core focus.

Because system optimization is

a goal for every pump user, we are

bringing you coverage of four highly

engineered solutions that will help

you get the most from your pumps.

Beginning on page 60, this month’s cover series will highlight how technological

advances are allowing end users to cost-e� ectively revamp existing equipment for

more e� cient operation. � e series continues with “10 � ings You Need to Know about

NPSH” (page 68), which outlines how thorough and accurate NPSH calculations can

provide users the information they need to enhance system performance. � e series

also discusses the bene� ts of engineered composites (page 72) and electrical inspections

(page 78) for minimizing costs, improving reliability and eliminating downtime.

You also don’t want to miss our newest column, Common Pumping Mistakes, authored

by Jim “Maddog” Elsey. Introduced in February as a bimonthly piece, the column will

now appear in every issue. A seasoned industry expert, Elsey shares lessons learned from

40 years in the � eld that will help readers further improve their equipment operation.

How do you optimize your pumping systems? Drop by our booth (#1318) at TPS to

share your thoughts, ideas and best practices. We’d love to hear from you! We’ll also be at

WEFTEC in Chicago, Sept. 26-30, so feel free to stop by our booth (#4256) there as well.

As always, we appreciate your insight and hope to see you soon!

Best regards,

EDITORIAL

SENIOR EDITOR, PUMPS DIVISION: Alecia [email protected] • 205-314-3878

SENIOR TECHNICAL EDITOR: Mike [email protected]

MANAGING EDITOR: Amelia Messamore [email protected] 205-314-8264

MANAGING EDITOR: Savanna [email protected] • 205-278-2839

ASSOCIATE EDITOR: Amy [email protected] • 205-278-2826

CONTRIBUTING EDITORS: Laurel Donoho, Lev Nelik, Ray Hardee, Jim Elsey

CREATIVE SERVICES

SENIOR ART DIRECTOR: Greg Ragsdale

ART DIRECTOR: Melanie Magee

WEB DEVELOPER: Greg Caudle

PRINT ADVERTISING TRAFFIC: Lisa [email protected] • 205-212-9402

CIRCULATION

AUDIENCE DEVELOPMENT MANAGER: Lori Masaoay [email protected] • 205-278-2840

ADVERTISING

NATIONAL SALES MANAGER: Derrell Moody [email protected] • 205-345-0784

ACCOUNT EXECUTIVES:

Mary-Kathryn [email protected] • 205-345-6036

Mark [email protected] • 205-345-6414

Addison [email protected] • 205-561-2603

Garrick [email protected] • 205-212-9406

MARKETING ASSOCIATES:

Ashley Morris [email protected] • 205-561-2600

Sonya [email protected] • 205-314-8276

PUBLISHER: Walter B. Evans Jr.

VP OF SALES: Greg Meineke

CREATIVE DIRECTOR: Terri J. Gray

CONTROLLER: Brandon Whittemore

P.O. Box 530067Birmingham, AL 35253

EDITORIAL & PRODUCTION

1900 28th Avenue South, Suite 200Birmingham, AL 35209205-212-9402

ADVERTISING SALES

2126 McFarland Blvd. East, Suite ATuscaloosa, AL 35404205-345-0784

PUMPS & SYSTEMS (ISSN# 1065-108X) is published monthly by Cahaba Media Group, 1900 28th Avenue So., Suite 200, Birmingham, AL 35209. Periodicals postage paid at Birmingham, AL, and additional mailing offi ces. Subscriptions: Free of charge to qualifi ed industrial pump users. Publisher reserves the right to determine qualifi cations. Annual subscriptions: US and possessions $48, all other countries $125 US funds (via air mail). Single copies: US and possessions $5, all other countries $15 US funds (via air mail). Call 630-739-0900 inside or outside the U.S. POSTMASTER: Send changes of address and form 3579 to Pumps & Systems, Subscription Dept., 440 Quadrangle Drive, Suite E, Bolingbrook, IL 60440. ©2015 Cahaba Media Group, Inc. No part of this publication may be reproduced without the written consent of the publisher. The publisher does not warrant, either expressly or by implication, the factual accuracy of any advertisements, articles or descriptions herein, nor does the publisher warrant the validity of any views or opinions offered by the authors of said articles or descriptions. The opinions expressed are those of the individual authors, and do not necessarily represent the opinions of Cahaba Media Group. Cahaba Media Group makes no representation or warranties regarding the accuracy or appropriateness of the advice or any advertisements contained in this magazine. SUBMISSIONS: We welcome submissions. Unless otherwise negotiated in writing by the editors, by sending us your submis-sion, you grant Cahaba Media Group, Inc., permission by an irrevocable license to edit, reproduce, distribute, publish and adapt your submission in any medium on multiple occasions. You are free to publish your submission yourself or to allow others to republish your submission. Submissions will not be returned. Volume 23, Issue 8.

This month, we welcome Mike Pemberton as the newest member of the Pumps & Systems team. With more than 25 years of experience in the pump industry, Pemberton will serve as the magazine’s senior technical editor, responsible for ensuring that Pumps & Systems continues to provide readers with the most respected, authoritative, relevant and timely content possible. A well-known leader in the pump industry and a long-time member of the Pumps & Systems Editorial Advisory Board, Pemberton will play a valuable role in providing the high-quality content that makes Pumps & Systems the leading magazine for pump users worldwide.

Pumps & Systems is a member of the following organizations:

Managing Editor, Amelia Messamore

[email protected]

HYDRAULIC DISC PUMPS show great advantages in the transportation

of fluid in general industry, including: oil and petrochemical,

chemical processing, municipal water/wastewater, food and

beverage, pharmaceutical manufacturing, pulp and paper, steel

manufacturing, general industrial and specialty applications.

For more information, please contact Sonia Ruiz: [email protected].

DISCFLO CORP. SANTEE, CA 619-596-3181 DISCFLO.COM

Discflo’s pumps have been solving the pumping problems of

the general industry for over 30 years. The powerful combination

of superior abrasion resistance, gas-entrained pumping ability,

and non-emulsifying laminar flow make the disc pump the ideal

choice for some of the toughest applications.

Experimental studies and field tests show that the Hydraulic

Disc Pump manufactured by Discflo Corporation is a

feasible solution for multiphase flow pumping, including gas,

liquid and solid. The pumping mechanism of our Disc Pump

is based on the effect of boundary layer and viscous drag,

resulting in lower NPSH levels.

THE POWER OF

NON-IMPINGEMENT


4


60 OPTIMIZE HIGH-ENERGY PUMPS WITH IMPROVED IMPELLER DESIGN

By Bob Jennings & Dr. Gary Dyson, Hydro, Inc.

As new design and manufacturing technologies are developed, end users can a� ordably upgrade their systems and verify better performance.

68 10 THINGS YOU NEED TO KNOW ABOUT NPSHBy Simon Bradshaw, ITT Goulds Pumps

Because cavitation is unavoidable in pump operations, understanding how to reduce it using NPSH calculations is necessary to maintain pump functionality and health.

72 ENGINEERED COMPOSITES OFFER OPPORTUNITIES FOR UPGRADING EQUIPMENTBy John A. Kozel, Sims Pump Valve Company, Inc.

� ese pumps prevent equipment from corroding, provide lower costs and increase e� ciency.

78 ELECTRICAL INSPECTIONS REDUCE COST OF OWNERSHIPBy James Jette, KSB Pumps Inc.

O� ine and online testing can improve reliability and reduce downtime.

COVERS E R I E S

2 FROM THE EDITOR

8 NEWS

82 TRADE SHOW PREVIEW

106 PRODUCTS

107 ADVERTISERS INDEX

108 PUMP USERS MARKETPLACE

112 PUMP MARKET ANALYSIS

PUMP SYSTEM OPTIMIZATION

PUMPING PRESCRIPTIONS

14 By Lev Nelik, Ph.D., P.E. Pumping Machinery, LLC

E� ciency Monitoring Saves Plants Millions

PUMP SYSTEM IMPROVEMENT

18 By Ray Hardee Engineered Software, Inc.

Piping System Controls

Last of Two Parts

COMMON PUMPING MISTAKES

22 By Jim Elsey

Rethinking NPSH

COLUMNS

Image courtesy of Hydro, Inc.

60

PRACTICE & OPERATIONS

102 CENTRIFUGAL PUMP SAVES SAND MINE MORE THAN $1.5 MILLIONBy Chris DunnCrisp Industries&

Bill Schlittler Cornell Pump Company

104 HOW REMOTE MONITORING EMPOWERS PLANT EMPLOYEESBy Jason Vick & Jack Creamer Schneider Electric

102

68

Component or CartridgeChoose the Right Seal

How Remote MonitoringEmpowers Plant Employees

Trade Show PreviewTurbomachinery & Pump Symposia

OPTIMIZE SYSTEM

PERFORMANCE

The Leading Magazine for Pump Users Worldwide

AUGUST 2015

PUMPSANDSYSTEMS.COM

®

SYSTEMS

4 highly engineered solutions to help you get the most from your pumps

This issue AUGUSTVolume 23 • Number 8

6


DEPARTMENTS

84 BUSINESS OF

THE BUSINESSPrecision Agriculture & Remote Monitoring Modernize Pump Systems

By Arun Prasath

Frost & Sullivan

86 EFFICIENCY MATTERSInternal Gear Pumps Handle Harsh Conditions

By Chrishelle Rogers

Maag Industrial Pumps

90 MAINTENANCE MINDERSOil & Gas Facilities Detect Costly Faults Early

By Cynthia Stone

GE Intelligent Platforms

92 MOTORS & DRIVESUnderstanding System E� ciency in Motor-Driven Rotating Equipment

By William Livoti

WEG Electric Corporation

95 SEALING SENSEEnergy E� ciency of Compression Packings in Rotodynamic Pump Applications

By Henri Azibert

FSA Technical Director

100 HI PUMP FAQSDynamic Analysis in the Petroleum Market & Piping Installation for Rotary Pumps

By Hydraulic Institute

SPECIALS P E C I A LS E C T I O N

BEARINGS, COUPLINGS & SEALS

26 VALIDATE SEALING SYSTEMS FOR OPTIMIZED PERFORMANCE By Larry Castleman,

Trelleborg Sealing Solutions

Investment at the start of a project can lead to improved safety, reliability and savings.

30 COMPONENT OR CARTRIDGE: HOW TO CHOOSE THE RIGHT SEALBy Eugene Vogel, EASA

� e balance between cost and ease of installation should be the major deciding factor.

34 HOW TO INTERPRET PUBLISHED SEALING DATA By Jim Drago,

Garlock Sealing Technologies, LLC

Gasket information and the tests used to generate it can help users make the best possible equipment selections.

38 WHY BEARINGS FAILBy Chris Rehmann, AESSEAL

Modern labyrinth bearing protection seals can protect precision elements from contamination.

42 HYBRID BEARINGS ENHANCE PERFORMANCE OF DRY-START VERTICAL PUMPS By Fumitaka Kikkawa & Yoshimasa

Kachu, Mikasa Corp. & Hiroshi Satoh,

Oridea Inc.

� is equipment exploits the elasticity of synthetic rubber and ensures stable bearing behavior.

48 THE BASICS OF COUPLING SELECTIONBy Robert Bramer, Fischer Process Industries

Users should consider these important factors when choosing the best equipment for their applications.

52 POLYMER SEALS PERFORM RELIABLY AFTER YEARS OF USE By Jim Hebel, Quadrant

Two sets of seals, in service for 11 and 15 years, still meet baseline standards.

58 COMPOSITE BEARINGS RESIST WEAR IN CIRCULATING WATER PUMPSBy Greg Gedney, Greene, Tweed & Co.

A thermoplastic composition in abrasive applications helped bearings meet end user speci� cations.

26

This issue

THOMAS L. ANGLE, P.E., MSC, Vice President Engineering, Hidrostal AG

ROBERT K. ASDAL, Executive Director, Hydraulic Institute

BRYAN S. BARRINGTON, Machinery Engineer, Lyondell Chemical Co.

KERRY BASKINS, VP/GM, Milton Roy Americas

WALTER BONNETT, Vice President Global Marketing, Pump Solutions Group

R. THOMAS BROWN III, President, Advanced Sealing International (ASI)

CHRIS CALDWELL, Director of Advanced Collection Technology, Business Area Wastewater Solutions, Sulzer Pumps, ABS USA

JACK CREAMER, Market Segment Manager – Pumping Equipment, Square D by Schneider Electric

BOB DOMKOWSKI, Business Development Manager – Transport Pumping and Amusement Markets/Engineering Consultant, Xylem, Inc., Water Solutions USA – Flygt

DAVID A. DOTY, North American Sales Manager, Moyno Industrial Pumps

WALT ERNDT, VP/GM, CRANE Pumps & Systems

JOE EVANS, Ph.D., Customer & Employee Education, PumpTech, Inc.

DOUG VOLDEN, Global Engineering Director, John Crane

LARRY LEWIS, President, Vanton Pump and Equipment Corp.

TODD LOUDIN, President/CEO North American Operations, Flowrox Inc.

JOHN MALINOWSKI, Sr. Product Manager, AC Motors, Baldor Electric Company, A Member of the ABB Group

WILLIAM E. NEIS, P.E., President, Northeast Industrial Sales

LEV NELIK, Ph.D., P.E., APICS, President, PumpingMachinery, LLC

HENRY PECK, President, Geiger Pump & Equipment Company

SCOTT SORENSEN, Oil & Gas Automation Consultant & Market Developer, Siemens Industry Sector

ADAM STOLBERG, Executive Director, Submersible Wastewater Pump Association (SWPA)

JERRY TURNER, Founder/Senior Advisor, Pioneer Pump

KIRK WILSON, President, Services & Solutions, Flowserve Corporation

JAMES WONG, Associate Product Manager – Bearing Isolator, Garlock Sealing Technologies

EDITORIAL ADVISORY BOARD

AUGUST

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Colfax Fluid Handling delivers what no other pump supplier can –

a single source for trusted product brands, the most complete

line of pumping technologies on the market and direct

access to global experts in locations near you –

to help your business succeed.

Discover the many ways we’re redefining what’s possible.

colfaxfluidhandling.com/redefining


8 NEWS


NEW HIRES, PROMOTIONS & RECOGNITIONS

MIKE DUPUIS, JIM SMITH &

LENWOOD IRELAND, EASA

ST. LOUIS (June 25, 2015) – The Electrical Apparatus Service Association (EASA) announces new international oficers for the 2015-2016 administrative year. The new oficers are:

• Chairman of the Board: Mike Dupuis of Morrish Electro Mechanical Company in Windsor, Ontario, Canada

• Vice-Chairman: Jim Smith of Advanced Electric Equipment in La Crosse, Wisconsin

• Secretary/Treasurer: Lenwood Ireland of Ireland Electric in Virginia Beach, Virginia

Dupuis has more than 30 years of experience in the electrical apparatus industry. He previously served as president of EASA’s Ontario Chapter and as director of Region 8. Serving on the Executive Committee with the above oficers are Immediate Past Chairman Doug Moore of Kentucky Service Company in Lexington, Kentucky; Gary Byars of Heavy Machines, Inc, in Memphis, Tennessee; and Brian Larry of Larry Electric Motor Services, Ltd., in Peterborough, Ontario, Canada. easa.com

NORMAN ZOMBOR,

NETZSCH CANADA, INCORPORATED

EXTON, Pa. (June 25, 2015) – NETZSCH Canada, Incorporated, recently expanded its sales force by hiring Norman Zombor as western regional manager for the oil and gas market. He is responsible for supporting and promoting NETZSCH products in Alberta and British Columbia. Zombor has a CET in mechanical engineering and a career of increasing levels of responsibility in the oil and gas industry. netzsch.com

SHAWN KELLY, PIONEER PUMP

CANBY, Ore. (June 25, 2015) – Pioneer Pump appointed Shawn Kelly as the regional sales manager for the South Central Region. Kelly’s responsibilities will include managing distribution and increasing the region’s sales in all markets, including industrial, municipal, oil and gas, and rental. Kelly has more than 20 years of experience in pump rental and sales and has been instrumental in managing large municipal, industrial and utility bypass projects. Kelly has also lead multiple major lood recovery efforts following events such as Hurricanes Katrina and Ivan. pioneerpump.com

THOMAS DONATO,

ROCKWELL AUTOMATION

ABU DHABI, UAE (June 24, 2015) – Thomas Donato was appointed president of Rockwell Automation’s Europe, Middle East and Africa (EMEA) region. Donato was most recently Rockwell Automation’s regional vice president in Canada. He is now responsible for driving growth in this important region. He has 18 years of automation industry experience and holds a Diplom-Ingenieur degree in automation and controls engineering from the University of Applied Sciences in Darmstadt, Germany. rockwellautomation.com

STEFAN HANTKE,

SCHAEFFLER INDUSTRIAL

SCHWEINFURT, Germany (June 22, 2015) – Stefan Hantke has assumed global management of sales and engineering of the Industrial division of Schaefler Technologies AG & Co. KG. In this new position, Hantke is a member of the Industrial Division’s Management Board and is responsible for the global sales management for rolling and plain bearing components and systems for about 60 industrial sectors. He is also responsible for the 27 Schaefler Technology Centers (STC) worldwide. Hantke has more than 20 years of sales and engineering experience in the mechanical engineering sector, particularly in the ield of bearing and linear technology. schaeffler.com

JOHN CONWAY, GRIFFCO VALVE

AMHERST, N.Y. (June 19, 2015) – Griffco Valve, Inc., announced the appointment of John Conway as its new national sales manager for North American Sales. In this role, he will be responsible for the sales and promotion of Griffco Valve chemical-feed accessories across the U.S. and Canada. Conway has an MBA from Canisius College in Buffalo, New York. griffcovalve.com

Shawn Kelly

Norman Zombor

Jim Smith

Lenwood Ireland

Mike Dupuis Thomas Donato

FCX Performance, Inc., acquired Process Control Services, Inc. June 16, 2015

Sulzer acquired Precision Gas Turbine Inc. June 4, 2015

Jason Industries acquired DRONCO GmbH. June 1, 2015

MERGERS & ACQUISITIONS

John Conway

Stefan Hantke

9

pumpsandsystems.com | August 2015

GENE KOONTZ, AWWA

ANAHEIM, Calif. (June 17, 2015) – Gene Koontz of Harrisburg, Pennsylvania, recently began his one-year term as president of the American Water Works Association (AWWA). A specialist in water quality and treatment, Koontz oversees the national water market for Gannett Fleming, a global infrastructure firm that provides planning, design, technology and construction management services for a diverse range of markets and disciplines. Koontz has been an AWWA member since 1982. awwa.org

ROBERT RICHTER, LEISTRITZ

ADVANCED TECHNOLOGIES CORP.

ALLENDALE, N.J. (June 15, 2015) – Leistritz Advanced Technologies Corp. appointed Robert Richter as chief financial officer. His responsibilities include the pump, machine tool and turbine component business units based in Allendale, New Jersey, as well as the extruder business unit based in Somerville, New Jersey. Richter is a graduate of Lehigh University in Bethlehem, Pennsylvania. leistritzcorp.com

JAYANTHI IYENGAR,

XYLEM INC.

RYE BROOK, N.Y. (June

15, 2015) – Xylem Inc. has appointed Jayanthi (Jay) Iyengar as senior vice president and chief innovation and technology officer. In this newly created position, Iyengar will lead the company’s global research and development, technology, and innovation activities. Iyengar has a bachelor’s degree in mechanical engineering and two master’s degrees in mechanical engineering. xyleminc.com

STEVE MARTINEZ, DAN ADAMS &

PAT TRENTLER, DXP

HOUSTON (June 10, 2015) – As part of its western region expansion, DXP/Quadna has promoted and assigned several leaders to new responsibilities. Steve Martinez, an area manager based in Farmington, New Mexico, and Dan Adams, an area manager based in Denver, Colorado, will jointly manage sales and operations for DXP branches located in Minot, North Dakota; Billings, Montana; Gillette and Rock Springs, Wyoming; Farmington, New Mexico; and Boise, North Dakota. Pat Trentler, an area manager, will oversee sales and operations for Casper, Wyoming; and Dickinson and Williston, North Dakota. dxpe.com

To have a news item considered, please

send the information to Amelia Messamore,

[email protected].

Jayanthi Iyengar

5300 Business Drive, Huntington Beach, CA 92649 USA 714-893-8529 • fax: 714-894-9492 • [email protected]

www.blue-white.com

Leading Edge Features and Materials.SMOOTH

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It’s ultra-bright for excellent readability.

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A smooth full stroke everytime helps reduce the risk of vapor lock.

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PVDF DIAPHRAGM: PATENT PENDING

• Single piece injection molded design with zero breakdown or delamination, reducing �eld maintenance requirements and down time.

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• Manufactured 100% in-house exclusively for use on Chem-Pro® Diaphragm Metering Pumps.

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10 NEWS


Nidec & IBM Japan to Jointly Develop IoT Technology KYOTO, Japan (June 22, 2015) – Nidec Corporation announced that it has launched a joint development of a big data analysis technology with IBM Japan with the main purpose of “improving production ratio via early detection of problems” and “shortening downtime via better factor analysis eficiency” for various production equipment and machinery equipped with the Nidec Group’s motors.

Nidec is executing a strategy of equipping its group’s products with Internet of Things (IoT) functions to increase their added value in order to create new, large-scale businesses to achieve the group’s 10 trillion yen sales target set for the iscal year ending March 31, 2031.

This joint project aims to establish a system which, by analyzing data obtained based on correlations among various sensors, will detect problems before humans do and execute measures for such problems even before they occur. Eventually, they plan to start offering this technology to companies outside of the Nidec Group as well. nidec.com

Water Crisis Leads to Development of New Way to Connect Industry LeadersSANTA MONICA, Calif. (June 19, 2015) – The challenges of the water crisis have led to the creation of an online deal platform, watercluster.com, designed to connect technology, talent and investors that can solve urgent water problems compounded by record drought on the West Coast.

Founder Thomas Schumann was inspired to launch the online venture by the U.S. Environmental Protection Agency Water Technology Innovation Cluster Program and seeks “disruptive collaboration” through the website, which allows members to work together and match needs with solutions in a real-time environment.

The watercluster.com platform enables water industry leaders, tech companies, investors, universities, corporations, utilities, governments, NGOs and service providers to connect, communicate, collaborate and conduct business. watercluster.com

HI Publishes New Guidebook for Wastewater Treatment Plant Pumps PARSIPPANY, N.J. (June 15, 2015) – The Hydraulic Institute (HI) recently published a guide on wastewater treatment plant pumps. “Wastewater Treatment Plant Pumps: Guidelines for Selection, Application, and Operation” is intended to assist in the understanding of the general layout, components and operation of a typical wastewater treatment plant. The book also provides readers with the guidance necessary to select pump types, pump materials and auxiliary components so the pumping system performs effectively, eficiently and reliably in the various plant operations.

Topics in this guidebook include, but are not limited to:• Processes, applications, and pump

selection in an aerobic wastewater treatment plant.

• Proper pump selection for each application including information about the materials of construction.

• Proper motor and mechanical seal selection to improve overall system reliability. pumps.org

DOE Releases New Pump Energy Index Calculation Tool PARSIPPANY, N.J. (June 12, 2015) – The Hydraulic Institute (HI) and its members have worked closely with the Department of Energy (DOE) throughout the rule-making process for the Energy Conservation Standard on Commercial Industrial Pumps.

As part of that process, HI’s Pump System Performance Metric committee worked with the DOE to develop a tool to evaluate the pump energy index (PEI) of pumps. This tool will help pump manufacturers evaluate how their pump eficiencies stack up to the proposed minimum eficiency levels which will be set in the Energy Conservation Standard.

The DOE released the PEI calculation tool to the public June 12. pumps.org

Asahi/America Opens New HeadquartersLAWRENCE, Mass. (June 11, 2015) –Asahi/America, Inc. oficially opened its new headquarters in Lawrence, Massachusetts, on April 23 with a ribbon-cutting ceremony and open

house. Guests from across the U.S. and around the world gathered for the celebration.

Asahi/America’s Chief Financial Oficer Stephen Harrington emceed the opening ceremony which included remarks by Asahi/America President and CEO Daniel S. Anderson, City of Lawrence Mayor Daniel Rivera, and Koji Fujiwara, president of Asahi Organic Chemical, Asahi/America’s parent company in Japan. During his remarks, Anderson previewed what guests would see inside the renovated 200,000 square-foot facility including corporate ofices, warehousing, valve and actuation assembly shops, fabrication, skid assembly, powder-coating, a clean room, and machine shop. He also spoke about the company’s goals and intentions for the future.

“We are intensely focused on customer satisfaction. We strive to be innovative, goal driven, and trustworthy,” said Anderson said. “We will be an asset to our community, we will be a charitable company, and we will respect the environment where we conduct our business.” asahi-america.com

Clean Water Rule Protects Streams & Wetlands WASHINGTON (May 27, 2015) – In May, the U.S. Environmental Protection Agency (EPA) and the U.S. Army inalized the Clean Water Rule to protect the nation’s streams and wetlands from pollution and degradation. The rule ensures that waters protected under the Clean Water Act are more precisely deined and predictably determined, making permitting less costly, easier and faster for businesses and industry. The rule does not create any new permitting requirements for agriculture and maintains all previous exemptions and exclusions.

After receiving requests for more than a decade from members of Congress, state and local oficials, industry, agriculture, environmental groups, scientists, and the public, the EPA and the Army have taken action to provide clarity on protections under the Clean Water Act. Speciically, the Clean Water Rule does the following:

• Clearly deines and protects tributaries that impact the health of downstream waters

AROUND THE INDUSTRY

11


• Provides certainty in how far safeguards extend to nearby waters

• Protects the nation’s regional water treasures

• Focuses on streams, not ditches• Maintains the status of waters

within Municipal Separate Storm Sewer Systems (The rule does not change how those waters are treated and encourages the use of green infrastructure)

• Reduces the use of case-speciic analysis of waters

A Clean Water Act permit is only needed if a water is going to be polluted or destroyed. The Clean Water Rule only protects the types of waters that have historically been covered under the Clean Water Act. It does not regulate most ditches and does not regulate groundwater, shallow subsurface lows, or tile drains. It does not make changes to current policies on irrigation or water transfers or apply to erosion in a ield. The Clean Water Rule addresses the pollution and destruction of waterways—not land use or private property rights. epa.gov/cleanwaterrule and army.mil/asacw

ITT expands Westminster, S.C., Manufacturing OperationsWHITE PLAINS, N.Y. (May 21, 2015) – ITT Corporation announced that it is expanding its manufacturing operations in Westminster, South Carolina, by investing approximately $1 million to build a new test facility. The investment is part of a total of $2.5 million that the company expects to invest in the facility during the next ive years.

The addition provides a new specialized testing facility for natural gas vehicle (NGV) components, which are part of the company’s Conolow brand of products. These NGV components consist of compressed natural gas pressure regulators and liquid natural gas regulators for heavy vehicles. itt.com

SEPCO Awarded for Excellence in International TradeMONTGOMERY, Ala. (March 25, 2015) – SEPCO (Sealing and Equipment Products Co., Inc.) was recently awarded the Governor’s Trade Excellence Award by Alabama Governor Bentley. SEPCO’s accomplishments, which include

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NEWS

EVENTSALL-TEST Pro, LLC, Electrical Reliability Training SeminarAug. 10-14, 2015Holiday Inn OrlandoLake Buena Vista, Fla.860-399-4222 / alltestpro.com

5th Annual Pumps Hands-on Training: Maintenance, Energy and Reliability Conference (PumpTec-Israel)Aug. 18 – 19, 2015Tel Aviv, Israel770-310-0866pumpingmachinery.com/pump_school/pump_school.htm

IDA World CongressAug. 30 – Sept. 4, 2015San Diego Convention CenterSan Diego, Calif.wc.idadesal.org

TPS 2015Sept. 14 – 17, 2015George R. Brown Convention CenterHouston, Texas979-845-7417 / tps.tamu.edu

Pumps & Systems Webinar Presented by BaldorSept. 24, 2015pumpsandsystems.com/webinars

WEFTECSept. 26 – 30, 2015McCormick PlaceChicago, Ill.240-439-2554 / weftec.org

Pack Expo (PMMI)Sept. 28 – 30, 2015Las Vegas Convention CenterLas Vegas, Nev.703-205-0480 / packexpolasvegas.com

Centrifugal And Positive Displacement Pumps (Basics) Oct. 28 – 29, 2015Pumping Machinery Training CenterNorcross, Ga. / 770-310-0866pumpingmachinery.com/pump_school/pump_school.htm

exporting Alabama-made mechanical seals and compression packing to customers around the world, reflect the state’s economic growth strategy and have contributed to state job creation. Award winners are selected based on a wide range of criteria such as their level of export sales as a proportion of total sales, sustainable growth in export sales, quality of export marketing strategy, senior management commitment to export development, and exporting innovations. Established in 2005, The Governor’s Trade Excellence Awards Program recognizes Alabama manufacturers and service companies for excelling in international trade. SEPCO was one of eight companies awarded in 2015. sepco.com


13

pumpsandsystems.com | August 2015Circle 114 on card or visit psfreeinfo.com.

Effi ciency Monitoring Saves Plants Millions

Part 2

Editor’s Note: While running a pump at its best e� ciency point saves money, reduces downtime and improves performance, many plant managers

are unaware of how their equipment is actually performing. � is series, which began in the July 2015 issue of Pumps & Systems, depicts a real-

world scenario that is intended to illustrate the importance of monitoring pump e� ciency.

Despite the municipal

water plant’s tight budget,

maintenance manager Jim

decided to speak with his boss

about improving the facility’s pump

e� ciency. Charlie began working at

the Blue Creek water plant about a

year ago and was not aware of the

plant’s history or the details about

its pumps.

“What you got, Jim? Make it

quick. I have a corporate meeting

to be at after lunch. � ey want

to talk about the in� uent screen

problems at the Willow Wastewater

Processing Plant and asked all

watershed plant managers to go.”

“OK, boss. I just wanted to let

you know that Bob from the Duck

Pump Company did some energy

e� ciency testing of our main water

booster pumps and found they

need some � xing. He says their

e� ciency is low.”

“Really? I had a similar issues

back at my old company. We had a

ton of old light bulbs installed all

over the facility, and this guy came

and did some e� ciency testing

and suggested that we switch to

some sort of energy-e� cient light

� xtures. Tons of money involved,

but apparently we still saved some

money overall. How much savings

are you talking about?”

“Well, he � gured we burn nearly

$125,000 extra in wasted energy,

and with just one repair, we could

recoup the cost in about a year.”

“So it’s about a $125,000

repair job? � at’s a lot of money.

I don’t think we have it in this

year’s budget.”

“� at’s what I told him, too.

Anyway, Charlie, just wanted you

to know.”

“� anks. Let’s talk more about

this tomorrow.”

� e next day, Jim and Charlie

got together to look over a fresh

quote from Bob on the pump repair

and upgrade. It was $143,600,

which was higher than the original

budgetary estimate. Bob explained

in his quote, however, that the

extra money was justi� ed by

switching from a single to double

mechanical seal, which would

save water and improve the

unit’s reliability.

“So, how long will it take them to

do the upgrade, Jim?” Charlie was

examining the numbers. “It says

eight to 10 weeks—will it really

take that long?

“Yeah, that’s not bad though. � e

last time they did this, it took them

about the same. � ey do a pretty

good job. We did the last pump

about four years ago, and that is

usually how they take care of us.”

“We need a major overhaul

every four years? Isn’t that a bit

too often?”

“� at’s right. Duck Pump gives

us a full one-year warranty, and

if the pump stays idle most of the

time, they extend the warranty to

two years. � at way, the less we

run the pumps, the more money

we save.”

“You know, Jim, let’s go to the

store room. I want to see one of

these pumps. Do you have a spare?”

“I sure do. Actually, I have two

spare units and four installed ones.

We usually only run one pump at a

time. During peak hours, we � re up

the second pump to get more water

to folks if the other plant is down

and we need to cover for them.”

Charlie and Jim, joined by

Rusty the mechanic, walked to

the shop to examine the pumps.

Store manager Grady Cricket put a

newspaper aside and got up to

meet them.

Charlie glanced around the shop.

“� is is the pump, Jim? Doesn’t

look like a $100,000 job to me!”

Image 1. Spare parts allow for fl exibility when repairs are necessary. (Courtesy of the author)

14 PUMPING PRESCRIPTIONS


By Lev Nelik, Ph.D., P.E.

Pumping Machinery, LLC, P&S Editorial Advisory Board

Troubleshooting & repair challenges

“Well, I meant we have a couple

of spare rotors, not a complete

pump. Usually, when they do a

repair, they keep the casing in

place, pop the top o� and just

remove the shaft with the impeller

and bearings with their housing.”

“OK, I see. So, in his quote, Bob

mentioned changing wear rings

to restore clearance. How big are

those clearances originally, and

how much do they open up as a

result of wear?”

“It’s all in the pump manual,

Charlie. I don’t remember the

exact number; the manuals are at

engineering downtown, and I don’t

get out there often. But I think

these are roughly 0.020-inch or so,

and they get bigger as they wear.”

“But how do they wear? Does

the impeller ring touch the casing

ring? I’m not an engineer, but I’d

imagine that Duck Pump Company

would design the shaft big and sti�

enough so it doesn’t de� ect very

much to touch.”

“I would think so. If they touch,

something is wrong—either the

design is bad or the bearings are

gone. � e main reason for wear is

probably the pumpage.”

“Pumpage? But we pump clean

drinking water! How abrasive can

it be?”

“Yeah, you’re right. I don’t know

either. � is pump is a bit above

my pay grade. We can ask Sandy

from the corporate engineering

department. I saw her a few times

when she came to see the plant a

couple of years ago. She would have

all the manuals and data. Rusty, is

this stainless?”

“Let’s see.” Rusty picked up a

dial indicator base and popped

the magnet over the shaft surface.

“Doesn’t stick. Must be stainless.”

Jim raised his eyebrows. “No

wonder it’s expensive. What about

the impeller and the ring?”

Rusty moved the magnet over

the impeller and determined that

it, too, was stainless. However,

when he moved it over the ring, the

magnet stuck.

“� e wear ring’s not stainless!”

Jim was perplexed. “What’s going

on here? Is this why it’s wearing

out? Maybe it just rusts away (no

15



pun intended, Rusty!). You know something—

we better get Sandy to come to the plant, and we

might as well set up a meeting with Bob to go

over his quote.”

Charlie was pleased with what he was

learning, but what he discovered left more

questions than answers. “Let me know when

you set up the meeting. Let’s do it some time

next month.”

In Part 3 of this series, Sandy visits the plant

and discusses the pump repairs and e� ciency with

Bob from Duck Pump Company. Will the non-

magnetic ring Charlie and Jim discovered cause

rusting and wear?

References

1. Nelik, L., “Pump Repair and Upgrade Standards”, pages

16-17, Pumps & System, May 2012

2. Kale R.D., and Sreedhar B.K., “A � eoretical Relationship

Between NPSH and Erosion Rate for a centrifugal Pump”,

ASME 1994, FED-Vol. 190, Cavitation and Gas-Liquid

Flow in Fluid Machinery”

3. Nelik L., “How Much Energy is Wasted When Wear Rings

are Worn to Double � eir Initial Value?”, March 2007

The pump performance and geometry

was hidden in the conversations

among Jim, Bob and Charlie in the

July and August issues. Can you

uncover the real versus expected pump

performance curves and geometry

data? Send your reconstructed curves

and a pump cross-sectional sketch to

[email protected]. The

correct answer will win admission to

the next Pump School session.

Dr. Nelik (aka “Dr. Pump”) is president of

Pumping Machinery, LLC, an Atlanta-based

fi rm specializing in pump consulting, training,

equipment troubleshooting and pump repairs.

Dr. Nelik has 30 years of experience in pumps

and pumping equipment. He may be reached

at pump-magazine.com. For more information,

visit pumpingmachinery.com/pump_school/

pump_school.htm.

16 PUMPING PRESCRIPTIONS


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GORMAN-RUPP PUMPS l P.O. BOX 1217 l MANSFIELD, OHIO 44901-1217 l USA l 419.755.1011 l [email protected] l GRPUMPS.COM538 © Copyright, The Gorman-Rupp Company, 2015 Gorman-Rupp Pumps USA is an ISO 9001:2008 and an ISO 14001:2004 Registered Company

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This series discusses the

control elements of a piping

system, which improve

the quality of the product. Part

1 (Pumps & Systems, July 2015)

covered passive controls, such as

over� ow and bypass controls, on/

o� controls, and manual controls.

Active Control Operation

Active controls maintain a set

value of a process variable under

changing system operating

conditions. � ey are often referred

to as a control loop (see Figure 3).

� e level in the destination tank is

measured by the level transmitter

that sends the measured value

(MV) to the level controller. � e

desired tank level set point (SP)

is entered into the controller. � e

controller compares the MV to the

SP, and a controller output (CO) is

sent to the � nal control element—a

control valve in this case. � e � ow

rate into the tank (Qin) is adjusted

to maintain the desired tank level.

� e destination tank level can

vary for several reasons, such as

changes in:

• pump � ow rate, caused by

changes in the static head

• pump � ow rate, caused by

mechanical wear

• the � ow rate out of the tank

caused by a change in the

system � ow demand

• the tank level set point caused

by the operator

Level control loop operation

can be examined by looking

at a low-level condition in the

destination tank. � e set point

for the destination tank level is

� ve feet above the tank bottom.

Because of a change in system

� ow demand (Qout), the tank

level drops to 4.9 feet. � e level

transmitter senses the measured

value of 4.9 feet and sends the

information to the level controller.

Because the level controller SP is

5 feet, the controller compares the

measured value of 4.9 feet to the

set point of 5 feet.

� e error between the measured

value and the set point causes the

control to send an open signal

to the control valve. � e valve

positioner causes the valve to

open. � is results in less head

loss across the control valve,

causing an increase in the � ow

rate. If the resulting

� ow rate through the

control valve is greater

than the system � ow

demand, the level

of the destination

tank increases. Over

time, the level in

the destination tank

reaches a steady state

condition.

Level Control with a

Control Valve

� e pump curve in

Figure 2, Part 1 of this

series (Pumps & Systems,

July 2015) shows that

the pump produces

125 feet of head at 400

gallons per minute (gpm). � e sum

of the static and dynamic head

for 400 gpm through the system

is 76 feet. At 400 gpm, the pump

produces 125 feet of head, but the

system only needs 76 feet of head.

As a result, the control valve must

absorb 49 feet of head to limit the

� ow rate to the set value.

� e advantage of level control

with a control valve is the ability

to minimize process variability

by maintaining a more consistent

tank level. � e disadvantage is

the added cost of the control loop,

the need to tune and maintain

the control loop, and the added

head loss across the control valve

necessary to maintain control.

� e annual operating cost of a

control valve appears in Table 3

(see page 20).

A better understanding of complete system operation

Figure 3. An example of an active control loop maintaining tank level by adjusting the fl ow rate into the tank (Graphics courtesy of the author)

Piping System Controls

Last of Two Parts

18 PUMP SYSTEM IMPROVEMENT


By Ray Hardee

Engineered Software, Inc.

19


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Level Control with a

Variable Speed Drive

Figure 2 in Part 1 of this series

shows that for the pump with

the 10.5-inch impeller diameter

running at 1,780 rpm, the

maximum possible � ow rate is

616 gpm. � is is where the energy

supplied by the pump equals the

energy required by the process

elements. Under this condition, no

di� erential pressure is required

across a control.

If we were able to adjust the

pump performance so it only

produces the head required by the

process elements at the desired

� ow rate, the control valve could

be eliminated. � at is the function

of a variable speed drive. By

adjusting the pump’s rotational

speed, the head can be maintained

to be equal to the head required to

meet the � ow rate.

Adjusting the rotation speed of

the impeller changes the pump

performance curve. Figure 4 shows

the pump performance for a range

of speeds. When the pump is

running at 1,424 rpm, it produces

76 feet of head, which is equal to

the head required by the process

elements at 400 gpm. � e pump

e� ciency lines are superimposed

on the system curve as well.

� e advantage of level control

with a variable speed drive is to

minimize process variability by

maintaining a more consistent

tank level and eliminate the

excess head required across the

control valve.

� e disadvantage is the added

capital cost of the control loop and

variable speed drive. In addition,

the losses across the variable speed

drive need to be taken into account

in power requirement.

Conclusion

Passive controls have simple

designs and low installation costs,

but they can have greater process

variability and operating costs.

Active controls can maintain a set

point with minimal changes in the

process variable. � ese systems

have tighter control that comes

at a higher original cost, but the

operating cost can be much lower.

Ray Hardee is a principal founder

of Engineered Software, creators of

PIPE-FLO and PUMP-FLO software.

At Engineered Software, he helped

develop two training courses

and teaches these courses in the

U.S. and internationally. He is a

member of the ASME ES-2 Energy

Assessment for Pumping Systems

standards committee and the ISO

Technical Committee 115/Working

Group 07 “Pumping System

Energy Assessment.” Hardee was

a contributing member of the HI/

Europump Pump Life Cycle Cost

and HI/PSM Optimizing Piping

System publications. He may be

reached at ray.hardee@eng-

software.com.

Table 3. The annual operating costs for using a control valve to control the fl ow. This is the same operating cost calculation for the manual control.

Annual Operating Cost Mode: Control Valve

Flow rate (gpm) 400

Pump head (feet) 125

Pump effi ciency (%) 0.69

Motor effi ciency (%) 0.93

Fluid density (lb/ft3) 62

Annual operation (hr) 8000

Power cost ($/kWh) 0.08

Annual pumping cost $9,337

Figure 4. A pump system curve showing the pump operating at various speeds. The pump operating at 1,424 rpm provides 76 feet of head, equal to the process requirements at 400 gpm.

20 PUMP SYSTEM IMPROVEMENT


21


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Net positive suction head

(NPSH) and its two

main components—

NPSHR and NPSHA—are an often

misunderstood mystery to a

large percentage of people in the

pump industry. I have studied and

catalogued more than 150 technical

articles on NPSH in the last 40

years, and most have begun with

comments about the complexity

of the topic. A common statement

in the pump industry is that 80

percent of all pump problems are

on the suction side of the pump. I

would state that, with the exception

of operating the pump away from

the best e� ciency point (BEP), the

percentage is much higher.

Rethinking the Concept

� e responsibility and purpose of

the centrifugal pump is to receive

the liquid that the suction system

delivers and move it downstream.

� e suction-side system, if properly

designed and operated, delivers the

� uid to the pump. � e pump does

not reach upstream and retrieve the

� uid, nor is it capable of doing so.

� e common misconception

is that the pump will “suck” the

� uid from the suction system into

the pump.

Perhaps if liquids had tensile

strength characteristics, that could

be remotely possible (I acquiesce

that the impeller does create a

small di� erential pressure at the

eye), but the suction-side system

must have adequate energy to

deliver the � uid to the pump. Using

the analogy of a cellphone, if the

suction-side system does not have

enough “signal strength” (bars

of energy), then the “call” will be

dropped or be of poor quality—in

other words, the pump will cavitate.

Suction Pressure

One of the most common errors

I witness is confusing suction

pressure with net positive suction

head available (NPSHA). Even

people with decades of pump

experience and education seem

to make this mistake. A common

comment is, “I do not need to

calculate NPSHA because I have

135 psig of suction pressure.”

What they fail to understand is

that the temperature of the � uid in

this case is 350 degrees F. (Please

assume water as the � uid for all

examples in this article.)

� e formula for NPSHA indicates

that 100 percent of the negative

head caused by the vapor pressure

of the 350 degree � uid negates

the positive head contributed by

the pressure of 135 psig. After

accounting for the losses that

result from friction head, the only

positive head available to make

up the remaining energy (bars of

signal strength) is the static head.

Static head is the energy (bars)

contributed by the elevation of

the � uid over the centerline of

the impeller. (Note: � is article

does not account for velocity

head because of the fractional

contribution and, in this case,

� ooded suction.)

Pump users must also remember

that NPSH is not pressure. Pressure

is a force, but head is an energy

level, and the suction pressure is

only one of numerous components

in the total makeup of NPSH.

By Jim Elsey

Summit Pump, Inc.

Rethinking NPSH

Understanding this complex topic can help end users avoid common pitfalls.

The formula for calculating NPSHA is:

NPSHA = h abs.prs – h vpr.prs. – h static – h fric

(For a suction lift)

NPSHA = h abs.prs – h vpr.prs. + h static – h fric

(For a fl ooded suction)

Where:

h abs.prs = head due to absolute pressure

converted to feet

h vpr.prs. = head loss due to the vapor pressure

of the fl uid

h static = head due to static pressure; can be

negative or positive

h fric = head loss due to fl uid friction in the

pipe and all components

1 I suggest you convert all factors to feet (meters) and work in absolute values.

2 I have not included the fi fth factor of velocity head (hVel.) because it is typically so small. If present, it would be a positive factor.

3 Vapor pressure and friction never work in your favor.

4 Static head will be negative and works against you in a lift situation.

5 Static head will be positive and works for you in a fl ooded situation.

6 If you have NPSHA problems, use the formula as a road map to look for solutions.

7 Using a pump of lower speed, dual suction or different impeller geometry can also resolve NPSH issues.

7 TIPS FOR CALCULATING NPSHA


22

Another comment I often hear

in the � eld is, “I do not need to

calculate the NPSHA because I

have a � ooded suction.” Again,

these individuals are not taking

the negative factors of friction and

vapor pressure into account.

Submergence

Submergence is the vertical

distance from the top surface of

the � uid to the centerline of the

pump intake line. Submergence is

applicable to both � ooded and lift

situations. If the submergence is

not positively su� cient, then the

velocity of the � uid in the suction

line will create a vortex. � e

captured air will be ingested into

the pump. Centrifugal pumps are

not designed to pump (or compress)

air, and the average centrifugal

pump will drop performance

quickly even with small amounts

of entrained air. While certain

designs, such as recessed impeller

pumps, can handle up to 24 percent

entrainment, just 12 percent

will stall most pumps. � is is

vital because many people in the

� eld confuse cavitation with air

binding/entrainment.

Every pump suction-side

installation has a minimum

submergence below which air

will be ingested. � e � ow rate for

a pipe of a given size, geometry

and material makeup has a

corresponding � uid velocity. � e

resultant velocity corresponds

with an amount of required

submergence (distance) to prevent

the formation of a vortex. Keep in

mind that just because you cannot

see the vortex with the naked

eye does not mean the vortex

phenomenon is absent.

Vacuum

At the bottom section of most

steam condensers is a collection

area, usually a tank-shaped

reservoir for the condensate

commonly known as the hot

well. In these applications, end

users commonly make errors

determining the correct absolute

pressure when making the NPSHA

calculations. Pumps are subject

to vacuum on the suction side in

many other instances as well.

� e error is in the assumption

that the vacuum level is equal to

the absolute pressure. Consider

a condenser with a vacuum level

of 28 inches of mercury (Hg).


23

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Inexperienced users might incorrectly

assume that they need to convert the

vacuum level to a corresponding head,

which they determine is the absolute

value (see Equation 1). In reality, the

actual absolute pressure is the di� erence

between the existing vacuum and what

would be the perfect vacuum or zero

absolute pressure. � ink about it as how

much pressure remains if the vacuum

is at some level, X, (as in this case of 28

inches Hg). A perfect vacuum would be

14.69 (atmospheric pressure at sea level)

x 2.31 (the conversion factor) = 33.933

(rounded to 34 feet).

At sea level, the atmospheric pressure

typically supports a mercury column not

more than 29.92 inches high. � erefore,

the standard for atmospheric pressure

at sea level is 29.92 inches Hg, which

translates to an absolute pressure of

14.69 psia, which is usually rounded to

14.7 psia.

So the true absolute pressure (to

be converted to head) is really the

di� erence between the two (see

Equation 2). � e correct absolute

pressure converted to head is 2.22 feet

not 31.78 feet.

At some point, you will be required to

calculate the value for NPSH available.

Why not be ready to do it the right way

and avoid the unnecessary drama and

expensive corrections?

Jim Elsey is a mechanical engineer

who has focused on rotating

equipment design and applications for

the military and several large original

equipment manufacturers for 43 years

in most industrial markets around the

world. Elsey is an active member of

the American Society of Mechanical

Engineers, the National Association

of Corrosion Engineers and the

American Society for Metals. He is the

general manager for Summit Pump,

Inc., and the principal of MaDDog

Pump Consultants LLC. Elsey may be

reached at [email protected].

Equation 1 (Incorrect approach)

28 in/Hg vacuum x 1.135 conversion, in/Hg to feet of water = 31.78 feet

Equation 2 (Correct approach)

34 - 31.78 = 2.22 feet

(Note: I have rounded off and assumed sea level for the example)

24


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SPECIAL SECTION

BEARINGS, COUPLINGS & SEALS

26

S ealing systems can play a vital role in equipment

performance and are considered critical

components in the validation process of a design.

Engineers should closely examine the sealing

systems used in their equipment, because they do

everything from preventing seal leakage and extending

hydraulic cylinder life to lowering dynamic friction and

controlling hydraulic motor position.

Component designers must contend with extreme

wear conditions and harsh chemicals. In addition, they

must meet tight tolerances and factor in signifi cant

vibration and high pressures. Many variables

can aff ect sealing capabilities,

and their impact can vary greatly depending on

the sealing application. Manufacturers and users

are often challenged to balance resources properly

when addressing what could be substantial sealing

issues. Issues with the sealing system can aff ect

performance signifi cantly and may lead to decisions

in the validation process that produce erroneous or

misleading results or consume excessive resources.

So, what are the right methods to properly address

the validation of sealing systems?

Validate Sealing Systems for Optimized PerformanceInvestment at the start of a project can lead to improved safety, reliability and savings.

BY LARRY CASTLEMANTRELLEBORG SEALING SOLUTIONS

Image 1. Seals play an important role in overall equipment functionality, and validating seals is part of a successful system. (Images courtesy of Trelleborg Sealing Solutions)


27

Seal System Verifi cation

Verifi cation and validation of a system design process are

independent procedures that are used to ensure that a

system meets the intended specifi cations, requirements

and objectives. � ey provide assurances that reliability

and performance will be maintained over the life of the

process. Equipment manufacturers want to minimize the

cost of validation without jeopardizing any requirements.

� e validation process delivers a comprehensive

understanding of the risks or liability associated with the

process and gives insight into many of the infl uences on

the system’s performance.

Systems validation requires considerable planning.

Any mistakes in planning can lead to falsely validating

systems. � e product could then have to be redeveloped,

or it could be launched with poorly understood behavior.

For instance, seal leakage can aff ect cylinder or actuator

life, which can be a vital part of operations, controlling

valves in every area, and managing the fl ows of water, gas

or chemicals. Another example is sealing system friction,

which can aff ect position control. Since sealing system

performance and process performance are directly linked,

the validation of sealing system performance plays a

crucial role in process validation procedures.

Process Validation

More than a series of tests, validation is a process. It

begins with identifying areas of concern, continues

with testing, and is completed with an analysis and

verifi cation of results. However, during design validation

or development, market forces and conditions do not

always allow for all the possible paths to be considered.

� e balance of risk, such as risk of failure mode or system

functionality loss and associated liability, is crucial to

the decision-making process. In scenarios where time

and cost associated with validation are limited, it is

prudent to take into account the right seal functionality

considerations in the equipment.

Image 2. An engineer completes a compression test to ensure performance.


28 BEARINGS, COUPLINGS & SEALS

Process Workfl ow

� e process fl ow during a validation exercise

incorporates all signifi cant factors for consideration.

Even though the amount of crucial elements to consider

for a sealing system may seem overwhelming, many

of these factors provide a practical approach and fl ow.

Incorporating these important factors can reduce

common mistakes and duplicate common successes.

For starters, eff ective communication between the

sealing supplier and the end user as well as subsequent

thoughtful and planned action is benefi cial. While this

approach requires more eff ort up front, the reward is a

signifi cantly reduced chance of a negative outcome later.

Taking the critical elements of seals and bearings

into account before the testing phase of the validation

process will optimize the return on investment. � e end

result is better overall performance of the process.

Eff ective Use of Validation Flow

Knowledge of the elements of the sealing system, such

as seals, bearings and wipers, is critical to success.

Engineers should fi rst determine how to validate each

component, then determine the criteria for success or

failure. Finally, they should create a list of activities and

criteria to meet these standards.

A Learning Process

To avoid a faulty product launch or a redevelopment,

clear communication between the end user and supplier

is critical. � e results often save labor, machine time

and development costs.

Creative Sealing Solutions

Through Innovative

Engineering.

PPC Ultraseal

780/789 Dual Cartridge Seal

PPC 1200S Split Single Seal

PPC P3-FDual Cartridge Mechanical Seal

www.ppcmechanicalseals.com

Made in USACir

cle

13

6 o

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fo.c

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.

Larry Castleman is the technical

director of product development at

Trelleborg Sealing Solutions. For more

information, visit tss.trelleborg.com.

Taking the critical elements of

seals and bearings into account

before the testing phase of the

validation process will optimize

the return on investment.


29



30 BEARINGS, COUPLINGS & SEALSSPECIAL SECTION

M echanical seals consist of a rotating element

and a stationary element, each with a

lapped, precision-smooth mating face (see

Figure 1). Seal performance is determined

primarily by the condition of the faces and the pressure

applied to them. Other key factors are vibration, heat and

pumpage characteristics. Depending on the application

and user’s needs, diff erent seal types may be appropriate.

For many larger centrifugal pumps, users have the

option of installing either component or cartridge

mechanical seals. Understanding the advantages and

limitations of each can help determine the best solution

for a particular application.

Component Mechanical Seals

Standard mechanical seals are typically component

seals. When users order a replacement, they typically

receive a box containing seal faces, holding brackets,

O-rings, boots and other parts that require the skills of

an experienced pump technician to install and adjust

properly (see Image 1).

Incorrect installation and adjustment are common

causes of component seal failure. For example, if the seal

faces are not properly seated on the shaft or in the seal

housing, they will be misaligned. Sliding O-rings and

elastomers over shaft shoulders, keyways or sharp edges

of the seal housing can also cause damage to these parts

and result in incorrect seal tension.

� e seal housing often provides limited access, so

successful adjustments require precision and accuracy.

While an experienced pump technician can successfully

install and adjust any component seal, this process

provides opportunity for error.

Cartridge Mechanical Seals

Cartridge mechanical seals and component seals use

similar components, but the stationary components

of cartridge seals are preassembled in a housing, and

the rotating components are preassembled on a shaft-

mounted sleeve that is sealed with an O-ring. � e

cartridge seal housing typically replaces the gland cover

plate and seals to the pump housing with a gasket, an

O-ring or other elastomer. Since cartridge mechanical seal

components are preassembled onto the sleeve and into the

cartridge housing, errors in parts installation are unlikely.

Component or Cartridge: How to Choose the Right Seal The balance between cost and ease of installation should be the major deciding factor.

BY EUGENE VOGELEASA

Liquid Pumpage Vaporized Liquid

Rotating Shaft

Rotating Seal Face Stationary Seal Face

Figure 1. Common mechanical seal (Images and graphics courtesy of EASA)


31

� e amount of spring tension applied to the seal

faces is an important factor that aff ects successful seal

installation. On component seals, technicians can set

this tension manually by adjusting the length of the

installed seal spring. With cartridge mechanical seals,

the spring tension is preset. To ensure the proper tension,

a retaining device holds the rotating and stationary

elements in alignment until after the seal is mounted.

While the details of whether a cartridge mechanical

seal can be fi tted to an application are complex, one

Image 1. Component (left) and cartridge (right) mechanical seals




criterion is whether the seal installs from the wet side

or dry side of the seal chamber. Pumps with a seal that

installs from the wet side, behind the impeller, are

generally not candidates for cartridge mechanical seals.

In addition, submersible pumps, which are usually

fi tted with dual component seals, cannot be converted to

cartridge mechanical seals because the seals install from

the wet side of the pump.

Component vs. Cartridge

For end users deciding between a component and

cartridge seal, the primary considerations are cost and

ease of installation. If a competent pump technician

services the pump during overhaul under good working

conditions, ease of installation may seem like a minor

issue. However, the concern will be for subsequent seal

replacement during an emergency outage.

Cartridge mechanical seals may cost two to three times

component seals, so unless otherwise stated, competitive

repair bids are typically for component seals. Despite

the higher initial investment, however, a cartridge seal

can be a more cost-eff ective, long-term solution, given

the expectation that pump maintenance may require

in-service seal replacement. Potential savings accrue

from lower labor costs and

less production downtime

when subsequent seal

replacement is needed.

Projected savings

also include the

elimination of seal

failures resulting from

improper installation of

component seals.

Dual Seals

Dual seals are eff ective

solutions for many pumping environments and

applications that are tough on seals, including high

temperatures, high pressures and foul pumpage laden

with abrasives. Dual seals have a chamber between the

seals into which barrier fl uid can be pumped to provide

cooling, lubrication and protection from abrasives in

the pumpage. While redesigning a single-seal pump to

accept dual component seals would be challenging, the

precision components of a cartridge mechanical seal can

be designed as a dual seal that can easily fi t in the same

space as a single component seal (see Image 2).

Image 2. A cartridge dual mechanical seal

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33

Impeller Adjustment

Some pumps, particularly those with semi-open

impellers, require periodic adjustment of the impeller

face clearance. Users can make this adjustment by moving

the pump shaft axially, which can change the tension on

the seal. On a component seal, resetting the seal tension

requires signifi cant disassembly of the pump. Most

cartridge mechanical seals have retaining devices that

can be reinstalled to align the stationary and rotating

elements. � is makes it easy to reset the seal tension after

the impeller face clearance has been adjusted.

Split Cartridge Mechanical Seals

Replacing a mechanical pump seal, component or

cartridge usually requires pump disassembly. One way

to avoid this is to use a split seal. � e faces and other

circumferential components are split in half so they can

be installed without disassembling the pump. Since each

circumferential component must be properly fi tted and

joined together, installation of split component seals can

be problematic and requires a high degree of technical

ability. If any mistakes are made, the seal won’t work.

Recent developments in seal technology have led to

the production of split cartridge mechanical seals, which

greatly simplify the installation of split seals. Whether

a split cartridge mechanical seal is the best option

depends on ease of installation versus cost. � e additional

cost may be justifi ed if, historically, the application

has required in-service seal replacement and if pump

disassembly is diffi cult.

Making the Right Choice

If users are aiming to fi nd the most cost-eff ective, long-

term solution to pump maintenance and they anticipate

in-service seal replacement, a cartridge mechanical seal

will likely be a good choice. Incorporating a cartridge

mechanical seal also allows the conversion from a

packing seal to a mechanical seal. When low initial cost

is important, component seals—and a well-trained pump

technician—are the best option.

Eugene Vogel is a pump and vibration

specialist at the Electrical Apparatus

Service Association, Inc. (EASA) based in

St. Louis, Missouri. Vogel may be reached

at 314-993-2220. For more information,

visit easa.com.

T F S E A L S U S A . C O M

We Deliver!

[email protected]

Phone: 1.713.568.5547

Fax: 1.713.758.0388

10620 Stebbins Cir, Suite E

Houston, TX 77043

Serving Manufacturers and Distributors Over 30 Years!




E very industry has its own terminology. For

example, depending on the frame of reference,

the acronym “API” can mean American Petroleum

Institute, active pharmaceutical ingredient or

application programming interfaces. To know what is

meant, one needs to know the context. In the case of

industrial sealing products, the context is often a catalog

published by the manufacturer, which to the uninitiated,

may raise as many questions as it answers. Yet, accurately

deciphering the information is vital to making informed

decisions in the selection of the optimal seal for a

particular application (see Table 1).

When considering gasket information, note that the

service temperature, pressure and pressure X temperature

(P X T) values of the intended application do not exceed

the published ratings of the product.

Temperature limits are sometimes expressed in what

appears to be a dual rating—maximum and continuous

maximum. Maximum temperature is the temperature the

material could survive for an extremely short duration.

� e continuous maximum temperature is the working or

allowable temperature a product can withstand for the

duration of its service life. Analogous to these limits is

the published tensile strength of a structural material,

where the maximum temperature would be expressed as

ultimate or yield stress, and the continuous maximum

temperature would correlate to maximum allowable

stress. � is stress is typically the ultimate stress divided

by a safety factor.

Chemical compatibility of the material with the

media is another important consideration. Gasket

manufacturers publish tables ranking acceptability with

hundreds of common media.

Users should also consult the sealability numbers and

consider the nature of the media being sealed. Lower

values indicate the ability to seal more tightly than higher

How to Interpret Published Sealing DataGasket information and the tests used to generate it can help users make the best possible equipment selections.

BY JIM DRAGOGARLOCK SEALING TECHNOLOGIES, LLC

Image 1. A technician tests a gasket for leak tightness using DIN-3535 method and equipment. (Images and graphics courtesy of Garlock Sealing Technologies, LLC)


35

ones. When comparing gasket materials, the unit of

measure should be noted. Sealability data is expressed in

milliliters per hour (ml/hr), milliliters per minute (ml/

min) or cubic centimeters per minute (cc/min).

If the application thermally cycles, consider gasket

materials with the lowest creep values, indicating they

will not become as thin under compressive load as

materials with higher values. � e more a gasket creeps,

the more load will be lost from the fl ange bolts. � is

loosening can result in shorter service life, leaks or blow-

out. Note that thinner gaskets tend to creep less than

thicker ones.

In the case of non-metallic, worn or damaged fl anges,

materials with higher compressibility should be

chosen. � e higher the compressibility of a gasket, the

more conformable it will be to the fl ange surface. � e

manufacturer should always be consulted with regard to

the choice of product and selection logic.

Gasket Sheet Properties, Test Methods

& Signifi cance

� e following information describes in more detail the

types of tests conducted and the meaning of the results.

P X T – Pressure X Temperature Value

Test equipment includes a fl anged joint, heat source

and pressure source. In this destructive test, the gasket

is taken to a point of failure. � e pressure and

temperature at failure are noted, the product of which

is the ultimate level to which a safety factor is applied

for the published value.

ASTM F37B & DIN 3535-4

ASTM F37B “Standard Test Methods for Sealability

of Gasket Materials” and DIN 3535-4 “Seals in gas

supply; seals of It-Plates for gas valves, gas appliances

and gas pipelines” gauge how well the material seals.

Table 1. Typical catalog information for gaskets

Seal Composition Filled Restructured Polytetrafl uoroethylene (PTFE)

Compressed Aramid Fiber

Compressed Inorganic Fiber

TemperatureMinimumMaximumContinuous maximum

-450 F (-268 C)

---500 F (260 C)

-100 F (-75 C) 700 F (370 C)400 F (205 C)

-100 F (-75 C)800 F (425 C)

550 F (290 C)

Pressure 1,200 pounds per square inch (psi) (83 bar)

1,000 psi (70 bar) 1,200 psi (83 bar)

P x TMaximum for 1/32 inch, 1/16 inch (0.8 millimeters, 1.6 millimeters)

For 1/8 inch (3.2 millimeters)

350,000 pounds per square inch gauge (psig) x F (12,000 bar x C)

250,000 psig x F(8,600 bar x C)

350,000 psig x F (12,000 bar x C)

250,000 psig x F (8,600 bar x C)

400,000 psig x F (14,000 bar x C)

275,000 psig x F(9,600 bar x C)

Sealability – American Society for Testing and Materials (ASTM) F37BNitrogenASTM Fuel A

---0.22 ml/hr

0.2 ml/hr0.6 ml/hr

0.2 ml/hr1.0 ml/hr

Gas permeability – Deutsches Institut fur Normung (DIN) 3535 Part 4

<0.015 cc/min 0.05 cc/min 0.05 cc/min

Creep relaxation – ASTM F38 18% 21% 15%

Compressibility – ASTM F36 7-12% 7-17% 7-17%

Recovery – ASTM F36 >10% 50% >50%

Tensile strength – ASTM D1708 2,000 psi(14 Newtons per square millimeter

(N/mm2))

2,250 psi(15 N/mm2)

1,500 psi(10 N/mm2)



F37 and DIN 3535-4 give seal tightness at standardized

pressures and ambient temperatures. Custom tests can

introduce elevated temperatures and thermal cycling. F37

covers both gas and liquid at relatively low pressures and

compressive loads on the gasket. DIN 353-4 compressive

loads on the gasket are at levels that might be found in

a Class 150 raised-face fl ange. Gas is at a pressure of

580 psig.

ASTM F38 & DIN 52913

ASTM F38 “Standard Test Methods for Creep Relaxation

of Gasket Material” and DIN 52913 “Testing of static

gaskets for fl ange connections - Compression creep testing

of gaskets made from sheets” indicate joint longevity.

Standard temperature, compressive load and duration

rank the ability of a material to maintain its thickness,

which indicates how well a fl anged joint will maintain its

tightness. � e F38 tests are conducted at 100 C (212 F)

for 22 hours and DIN 52913 at 300 C (572 F) for 16 or

100 hours.

ASTM F36

� e “Standard Test Methods for Compressibility and

Recovery of Gasket Material” are ambient temperature

tests that indicate the ability of a material to compress

and conform under load. � e recovery portion of the test

reveals the material’s resilience. � e test results have little

meaning after a material has been exposed to elevated

temperatures. � e greater the compressibility, the more apt

the material is to conform to fl ange surface irregularities.

ASTM F152

� e “Standard Test Methods for Tension Testing of

Nonmetallic Gasket Materials” look at material strength.

Gaskets are cut into standard tensile test “dog bone”

coupons. � e results indicate that the material has been

manufactured properly and is strong enough to be cut

and handled.

Conclusion

Understanding published gasket information and the

tests used to generate it provide confi dence in the process

of selecting application-appropriate materials. � ese

selections, in turn, can be confi rmed by the manufacturer’s

applications engineers resulting in well-informed choices.

800.675.9930 www.nskamericas.com/aip

YOUR

BEARINGS

COULD BE

DOING

MUCH MORE

FOR YOU.NSK ASSET IMPROVEMENT PROGRAM (AIP)AIP provides real solutions to real challenges. It combines your knowledge of your business’ working environment, processes and problems, with the engineering expertise and innovation of NSK. By working with you at every stage of our AIP Value Cycle, we find the potential savings available and ensure they are achieved. Our solutions are quantifiable and measurable in terms of lowered costs, increased efficiencies and reduced downtime which results in increased profitability for your facility.

Your challenge. Our expertise. Increased profitability.

Cir

cle

13

5 o

n c

ard

or

vis

it p

sfre

ein

fo.c

om

.

Jim Drago is principal applications engineer

at Garlock Sealing Technologies, LLC. He has a

B.S. in mechanical engineering from Clarkson

University. He may be reached at

[email protected] or 800-448-6688.


37




B earings are precision components that require

clean lubrication in adequate amounts to ensure

a long, trouble-free life. Even small amounts of

contamination or slightly elevated temperatures

can lead to bearing failure.

A study of equipment reliability conducted at a major

refi nery concluded that 40 percent of rotating equipment

failures (pumps, mixers, etc.) were attributable to

bearing failure. It further estimated that 48 percent of

bearing failures were due to particle contamination and

4 percent were due to corrosion (caused by liquid in the

oil). In fact, bearing oil contamination accounts for 52

percent of bearing problems and 21 percent of rotating

equipment failures.1 If water, dust or other process fl uids

enter a bearing, it is headed for trouble. Modern labyrinth

bearing protection seals can help prevent these issues.

Dust Contamination

Dust in the production environment is a major problem

for bearings. Heavy dust is made of particles as small as

50 microns that can become airborne.

Because they fall at about 200 millimeters per

second, these particles are unlikely to move beyond the

production area. Heavy dust is readily seen as a cloud with

the naked eye.

Light dust, which is smaller than 50 microns in size,

may stay in the air for more than 30 minutes. � is type

of dust can travel well beyond the manufacturing site,

although it is commonly seen as a fi ne coating when it

settles on machinery, bearing housings and other surfaces.

Why Bearings FailModern labyrinth bearing protection seals can protect precision elements from contamination.

BY CHRIS REHMANNAESSEAL

Figure 1. While the shaft is rotating, a micro-gap opens, allowing the thermal expansion in the bearing housing. While the shaft is not rotating, the micro-gap is closed, forming a perfect vapor seal (Images and graphics courtesy of AESSEAL)

Image 1. Three months after running, the air purge still keeps dust away from the stator to rotor interface.

Outboard Air Purge

Inboard Air Purge


39

Both types of dust are a concern because even light

dust will fi nd its way into a bearing. Although the

housing off ers some protection, ingress still happens.

One signifi cant factor in bearing oil contamination is the

breathing process that occurs with all rotating equipment.

When equipment rotates, the bearing housing heats up,

and the oil and air mixture inside expands and is forced

through the seal. � e problem arises when equipment

cools, because the oil and air mixture also cools and

contracts, sucking air laden with dust from the external

atmosphere through seals back into the housing. Over

time, dust builds up inside the bearing and eventually leads

to oil contamination, abrasion to components and bearing

failure. Bearing seals must facilitate this breathing cycle to

extend bearing life, while preventing dust contamination.

Some modern labyrinth seals with an air purge

design are suitable for use in extreme environments and

applications where contamination may completely cover

the seal or equipment (see Image 1). � ese use a positive

air purge to enhance the performance of the labyrinth

in combination with mechanical seal pressure balancing

technology to maximize the performance of the seal and

minimize air consumption.

Figure 2. When equipment rotates, the bearing housing heats up, and the oil and air mixture inside heats up forcing air through the seal. As equipment cools the oil and air mixture contracts, it sucks air from the atmosphere.

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Humidity & Moisture Contamination

Moisture can enter bearing housings through old-style

labyrinth seals or lip seals as airborne water vapor or as

a stream of water from hose-down operations. It can also

enter through other ways, such as the breather vent or

from the widely used non-pressure balanced constant

level lubricators or abraded oil ring material.

Water vapor present in the atmosphere is also a cause of

many contamination problems. Even though the air in a

production plant may appear to be dry, moisture is always

present. Warm air can hold more water vapor, so the hot air

around machinery will have a higher relative humidity.

� e pathway for water vapor entering the bearing starts

when the bearing house begins to breathe. As the machine

cools, this warm, moisture-laden air (along with airborne

dust) is sucked back into the housing. As the equipment

continues to cool and reaches dew point, minute water

droplets form inside the bearing. � is moisture builds up,

causing corrosion and eventually failure.

Moisture and humidity alone contribute to damage

within mechanical components, however when

coupled with noxious elements from the air around the

production process, it can create an even more corrosive

combination for bearings.

To reduce the risk of humidity and moisture

contamination, the bearing housing would need to be kept

above dew point to prevent condensation from forming.

However, since this is not practical, the best way to reduce

the risk is use of modern labyrinth bearing protection.

When the shaft stops rotating, the bearing protection

creates a perfect vapor seal against both moisture and

dust. � ese labyrinth designs also protect against other

sources of moisture contamination such as powerful

waterjets. Some labyrinth seals can operate in completely

fl ooded or submerged environments, providing the

bearing with complete protection.

Overheating is another common cause of bearing

failure. To prevent overheating, users should get the

bearing running at optimum temperature, which requires

adequate, but not excessive, lubrication. Discoloration of

the rings, balls and cages, ranging from shades of blue to

brown, is a sure sign of bearing overheating. Unless the

bearing is made of special alloys, temperatures in excess

of 200 C (292 F) can anneal the ring and ball materials,

resulting in loss of hardness and, in extreme cases,

deformation of the bearing elements. � e most common

cause of overheating is excessive speed, inadequate heat

dissipation/insuffi cient cooling and lubricant failure.

Overheating is a major problem, because even slightly

elevated temperatures can cause oil or grease to degrade

or bleed, reducing effi ciency of the lubricant. Under even

higher temperatures, oxidation causes loss of lubricating

elements and the formation of carbon, which may clog

the bearing. � e most eff ective way to extend the life

of the lubricant and ensure that it remains in optimum

condition is to use a modern labyrinth bearing protector.

� ese devices have been proven to protect against

contamination ingress and lubricant egress.

Lubrication Issues

Improper lubrication accounts for about one-third of

all bearing failures. Poor lubricant viscosity, prolonged

service or infrequent changes, excessive temperature,

using the wrong type of lubrication or over-lubrication

are common problems. External contamination is another

major cause of compromised performance of the lubricant.

Creating optimum lubrication conditions is a

balancing act between over-lubrication and under-

lubrication. Both create a problem as do contamination

or the use of a lubricant not suited to the equipment.

Consistency, viscosity, oxidation resistance and anti-

wear characteristics all play a role in the selection of

a lubricant. Usually, the application will dictate the

amount, type and frequency of lubrication needed.

Figure 3. While the shaft is rotating, a micro-gap opens, allowing the thermal expansion in the bearing housing. While the shaft is not rotating, the micro-gap is closed, forming a perfect vapor seal.


41

Extending Bearing Life

Manufacturers have developed more advanced labyrinth

bearing protection seals that can off er protection against

all types of contamination. For example, one seal that

is non-contacting in operation to avoid shaft wear

incorporates patented dynamic lift technology to protect

against the breathing issues that contribute to 52 percent

of all bearing failures centered around contamination.

� is dynamic lift technology uses the centrifugal force

of rotating equipment to open a temporary micro-gap,

allowing expansion of the oil and air mixture in the

bearing housing, which allows the equipment to breathe.

When the equipment stops rotating, the micro-gap

immediately closes, forming a perfect seal. � is prevents

dust and moisture from being sucked back into the housing

and therefore prevents contamination (see Figure 3).

Rated to IP66 of the ingress protection code, this seal

can reduce water contamination of the bearing oil from

as high as 83 percent to just 0.0003 percent compared to

lip-seals, even when exposed to high-pressure water jets.

� e range is Atmosphères Explosives (ATEX) certifi ed for

use in explosive environments. Special designs make it

suitable for a wide range of applications.

It is also designed with a thinner cross-section and

seal length than competing devices, which means that it

can be retrofi tted on more equipment without having to

carry out modifi cations. Furthermore, the design enables

it to be positioned diff erently on the shaft than lip seals,

which means that damaged shafts can be retrofi tted

without costly replacement.

Conclusion

When all of the issues that cause bearing failure are

addressed, bearings should have a long, trouble-free

life. Taking steps to address these problems before they

happen can result in signifi cant cost savings. Bearings

are precision elements and require an ongoing supply of

clean lubricant in the appropriate amount to ensure long

equipment life and low maintenance. Modern labyrinth

bearing protectors have been shown to prevent the entry

of contaminants, as well as the loss of lubricant.

References:

1. Bloch, Heinz; “Pump Users Handbook: Life Extension” 2011

Chris Rehmann is business development manager for

AESSEAL in Knoxville, Tennessee. Prior to joining

AESSEAL in 2002, he earned his engineering

degree from Notre Dame and worked for 15

years in various management positions with an

oilfi eld engineering services company. For more

information, visit labtecta.com.

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A fter 30 years of research, an engineering

team in Japan has developed a hybrid-type

submersible bearing that prevents burnouts

during vertical pump dry-starts, exploits the

elasticity of the synthetic rubber to level the pressure

during typical operation, and ensures stable bearing

behavior by conferring vibration control while supporting

the rotating shafts.

Using polytetrafl uoroethylene (PTFE) strips as slide

members and synthetic soft rubber for cushioning

between the slide elements and metal shell (or the base

plates), the hybrid bearing can be used for dry-start

operation of vertical pumps without applying lubricating

water from the outside prior to pump operation.

Advantages of Adopting a Dry-Start Bearing

A wet-start vertical pump system requires that water

be injected from outside the pump into shaft protection

tubes at the top of the column pipes before operation. In

most cases, the water is pumped up automatically after

a fi xed time to avoid wasting the feed water pump power

or the water from the tap, which is usually called self-

feed water. A dry-start pump does not require lubrication

and is less prone to environmental damage from crevice

corrosion in joint parts where seawater remains. Because

the stainless steel shafts are exposed directly to the pump

main fl ow, pitting corrosion—prone to occur in low-fl ow-

velocity or stagnant regions—is reduced.

Structure of Hybrid Bearings

� ree molds have been developed to produce three types

of bearings, each suitable for a diff erent range and scale

of application. � ese include full-molded, segmental and

barrel type bearings.

Bearings are basically composed of four layers: PTFE

strips as slide elements, synthetic rubber for cushioning,

base plates as the backing-plates and a metal shell that

serves as the holder. � e full-molded bearing is used

almost exclusively for vertical pumps, making a simple,

three-layered structure as shown in Figure 1.

Friction Coeffi cients

Creating submersible bearings with materials that

have low friction coeffi cients has been a top priority

for submersible bearing manufacturers. Figure 2 shows

friction coeffi cients in tap water of diff erent bearing

materials (PTFE, polyether ether ketone [PEEK] and

polyurethane in hybrid structure with rubber) used in

dry-start vertical pumps and rubber bearings used in wet-

start pumps. Friction coeffi cients were obtained using

identically structured bearings to match test conditions.

� e graph plots one of the outcomes obtained by

changing the bearing loads from 0.25 to 1.0 mega-Pascals

Hybrid Bearings Enhance Performance of Dry-Start Vertical PumpsThis equipment exploits the elasticity of synthetic rubber and ensures stable bearing behavior.

BY FUMITAKA KIKKAWA & YOSHIMASA KACHU, MIKASA CORP.

& HIROSHI SATOH, ORIDEA INC.

Figure 1. PTFE/rubber hybrid bearings for pumps (Images and graphics courtesy of the authors)


43

(MPa) at four stages. Results show that all bearing

materials have excellent friction coeffi cients.

Eff ects of Synthetic Rubber

Friction coeffi cients obtained using the two test bearings

during wear resistance testing indicate that the test

bearing with the persistently soft rubber layer (72 Shore A

hardness) has a lower friction coeffi cient than the bearing

with the rubber layer turned into ebonite (80 Shore D

hardness). � is suggests that the rubber layer may prevent

sharp rises in the local pressure on the bearing conferred

by the shaft defl ection. � e rubber seems to keep pressure

low overall and limit the solid contact friction areas.

� e free surfaces of the rubber made by or among the

PTFE strips may improve the elastic eff ect compared with

the bearings without free surfaces facing the shaft, as with

a the bearing with a monolithic ring-like structure of metal

and resin.1 � e balance between the number of grooves and

the size of the area in which the water fi lm formed to lower

the friction coeffi cients is important. If the number of

grooves is increased to enhance the elasticity of the rubber,

the size of the water fi lm area will decrease and invite the

larger friction coeffi cients and vice versa.

Because the pump shafts of the vertical pumps are

suspended on the center of the column pipes, the bearing

load by the shaft weight is comparatively small, which is

typical with vertical pumps. � is reduces the importance

of self-alignment, but another problem may emerge.

Adhesive & Abrasive Wear Resistance

Wear resistance related to adhesive wear and the abrasive

wear of the slide members is an important factor for

submerged bearings from the viewpoint of tribology.

Figure 3 shows the results of an adhesive wear test on

two pieces of same-sized bearings. One was the PTFE

and rubber hybrid bearing, while the other contained

abundant sulfur and was vulcanized to harden the rubber

into ebonite with the hardness of 80 Shore D.

Figure 3 plots the coordinating friction data

according to the wear amount after confi rming the

friction coeffi cients through a series of tests performed

concurrently for the pure wear test and the measurement

of the friction coeffi cients. � e wear amount of the PTFE/

ebonite hybrid bearing is displayed as a ratio, while the

wear amount of the PTFE/rubber hybrid is assumed to

be 1.0. � e graph indicates that the wear of the original

bearing with the soft rubber layer is about one-half

of the wear amount of the bearing with a rubber layer

transformed into ebonite.

Absorptivity of Shaft Vibration

In addition to the eff ect on friction coeffi cients, the

rubber layer also aff ects shaft vibration control. A

viscoelastic material like rubber suppresses the self-

excited or sub-synchronous vibration that is caused by

the strong nonlinearity of the bearing characteristics

Figure 2. Friction coeffi cients in tap water

Figure 3. Test results of PTFE/rubber hybrid bearing Figure 4. Vibration amplitude when using three types of bearings



and tends to appear when loads are small, as in the case

of the shafts of vertical pumps.

Figure 4 (page 43) shows the peak-to-peak amplitude

measured on a bearing spider fi xed on the middle part

between the column pipes of the test pump in operation.

� e inside radiating spokes holding the bearing in the

shaft center were replaced with rods extruded from the

load cells to measure the bearing load. � is pump was

6 meters long under the fl oor. A 200-millimeter bored

vertical pseudo-pump with three bearings (upper, middle

and lower) was fi xed in the bearing spiders. � e impeller

of this pseudo-pump was replaced by a rotating disk with

the same rotating inertia to cease its pumping action.

� e amplitude curves shown in Figure 4 compare

the three kinds of bearings (PTFE/

rubber hybrid, nitrile rubber [NBR] and

cylindrical silicon carbide [SiC] bearing).

Rotation speed was continuously altered

throughout the test, and the loads on each

bearing, as well as the vibration amplitude,

were traced.

Only the cylindrical SiC bearings

generated a self-excited vibration

accompanied by the hysteresis

phenomena. � e PTFE/rubber hybrid

bearings ran quietly through the full

range of rotational speeds. Once excessive

vibration is generated with the use of

SiC bearings, an abnormal noise occurs,

and the loads on both upper and middle

bearings can increase by as much as

tenfold.2 � ese phenomena were often

observed in real pumps in factory tests and

in the fi eld.

Based on these fi ndings, the rubber

layer improves the damping performance

of the pump system and weakens the

nonlinearity of the bearing spring

constant because of the viscoelastic nature

of the rubber. � e actions diff er markedly

from the actions of the monolithically

structured metal/resin without rubber

lining eff ects. Once a vibration like sub-

synchronous resonance is generated, pump

parts such as the shaft might fracture.

Even if the consequences are not severe,

the abnormally raised bearing loads will

result in extreme wear of the bearings.2

Acceptability of Dry Runs

Figure 5 shows the threshold of the

possible dry-start continuing time

relative to the bearing pressure in an

experimental run at a progressively higher

shaft speed. � e plot shows a nearly

inverse relationship between the dry-run

continuing time and bearing pressure. As

expected, the bearing pressure remains

low on the vertical pumps as long as their

assemblies and alignments stay normal.

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45

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� e dry run can presumably be extended to a few minutes.

Under the ordinary usage requirements for vertical

pumps, the period of in-the-air operations using the dry-

start bearings at the point of pump startup is 10 seconds

or less. � erefore, Figure 5 shows that almost all of the

vertical pumps are capable of dry start.3

Acceptability of a Lack of Lubrication Water

A lack of lubrication water arises when some force or

phenomenon intercepts the fl ow of replacement water to

or from the bearing surroundings.

Assuming a cutoff of the passage of lubricating water

to and from the bearing, the test bearing was sealed in

Figure 5. Dry-run continuing time at different bearing pressure and shaft speeds

Figure 6. Temperature change when preventing feed water exchange to the bearings

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47

an experiment using the oil seals at both ends after

immersion in water. � e bearing temperature was

measured in the vicinity of the bearing surface.

Figure 6 shows the temperature change of the test

bearings during the experiment. Points A, B and C in

the fi gure are temperature measurement points. Point

B is at the middle of the longitudinal location of the

bearings, and points A and C are at the two ends. When

the infl ow and outfl ow of lubrication water is blocked,

the rubber bearings are at high risk of seizure. For

hybrid bearings, the risk exists only when the bearing

surfaces get wet.4

References

1. Satoh H., Okada K., Furukawa S., 1994a, ‘Infl uence of Grooves of

Compound-Structured Submerged Bearings for Vertical Pumps,’

Transactions of the Japan Society of Mechanical Engineers, Vol.60,

No.571, pp.1033-1038.

2. Satoh H., Takeda H., 1989, ‘Dry-Start Bearings for Vertical Pumps,’

Proceedings of 6th International Pump Users Symposium, pp. 75-82.

3. Kikkawa F., Ogawa R., Satoh H., 2010b, ‘PTFE submersible dry-start

bearings,’ World Pumps, No.531, pp.31-34.

4. Kikkawa F., Ogawa R., Satoh H., 2010a, ‘PTFE submersible dry-start

bearings,’ World Pumps, No.530, pp. 30-33.

Satoh H., Takeda H., Kikkawa F., 1988, ‘Dry-Start Bearings for

Vertical Pumps,’ Journal of Turbomachinery Society of Japan,

Vol.16, No.7, pp. 382-390.

Satoh H., Sugiya T., Okada K., Yamada S. 1994b, ‘Infl uence of

Submerged Bearings for Vertical Pumps on Vibration Characteristics,’

Transactions of the Japan Society of Mechanical Engineers, Vol.60,

No.578, pp.3233-3237.

Dr. Fumitaka Kikkawa is a director of Mikasa Corp.

and oversees the industrial products division.

Dr. Kikkawa earned a Ph.D. in engineering from

Nagasaki University with a focus on submersible

bearings for pumps and ships. He may be reached

at [email protected].

Yoshimasa Kachu is a graduate of the chemical

engineering program at Fukuoka University. He is

one of the chief engineers in the industrial products

division at Mikasa Corp. He may be reached at

[email protected].

Dr. Hiroshi Satoh has been engaged for the last

seven years as a consultant in mechanical

engineering at several companies, including

Mikasa. He received a Ph.D. in engineering from

Yamanashi University. He may be reached at

[email protected].

Represented by Global Pump Marketing

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48

A coupling transmits power from a driver to a

driven piece of equipment. � e driver can be

anything from an electric motor to a steam

turbine, and the driven equipment can be

a gearbox, fan or pump. While the coupling is often

viewed as the weak link in the pump assembly, replacing

a coupling element is still much easier than replacing a

sheared shaft.

For the purposes of this article, the driver will be an

alternating current (AC) electric motor, and elastomeric

couplings will be the focus. Typically, these couplings

consist of three to six components, excluding fastener

hardware. � ey have two hubs with bores to match the

drive shaft and driver shaft and an elastomeric element

between them. Some couplings, especially spacer types,

have more components. A spacer coupling assembly, for

example, can have two shaft hubs, two fl anges and one

elastomeric element. � e assembly bolts together in such

a way that the two fl anges and element drop out of the

center section.

Based on the calculation for horsepower (HP) indicated

in Equation 1, the proper sizing of couplings is highly

dependent on HP, torque and shaft speed. In addition to

these variables, other elements such as service factor and

misalignment capabilities can aff ect coupling operation

and application. For this reason, many users rely only on

the manufacturer’s methods for proper sizing. Reading a

few coupling manuals will indicate that a vast selection of

couplings can meet a user’s power criteria. Still, selecting

the best coupling for the job depends on the environment

and the operators just as much as the mathematics

behind the sizing. When selecting a coupling for a pump

application, end users should consider the following factors.

HP = T(n)

63025 Equation 1

Where

HP = horsepower

T = torque (inch-pounds)

n = shaft speed

Service Factor

Service factor is an application- and coupling-dependent

multiplier that should be factored into sizing data. It is a

buff er between the torque capacity used to size a coupling

and what happens in the real world.

For example, if a pump requires 500 inch-pounds (in-lb)

of torque and the coupling manual recommends a 1.2

service factor, the coupling would be sized for 600 in-lb

(500 in-lb x 1.2 = 600 in-lb). � is is to help compensate for

application details such as shock loads, type of driver and

The Basics of Coupling Selection Users should consider these important factors when choosing the best equipment for their applications.

BY ROBERT BRAMERFISCHER PROCESS INDUSTRIES

Image 1. Spacer couplings are engineered to have a drop-out center section to allow for easy removal of the pump rotating assembly without having to unbolt the motor. (Images and graphics courtesy of Fischer Process Industries)

BEARINGS, COUPLINGS & SEALSSPECIAL SECTION


49

type of driven equipment. Each type of equipment has its own

load characteristics and can generally be found in the sizing

section of a coupling manual; if not, consult the manufacturer.

Always use the service factor recommended for the particular

coupling to be used, and resist the urge to oversize the

coupling. � e coupling is meant to be the weak link.

Fail Safe

A fail-safe coupling will transmit power even after the

element fails, because part of both hubs operates in the

same plane. A jaw coupling is an example of a fail-safe

coupling. Alternatively, couplings that are not fail-safe

are also available. When the element fails, these couplings

will no longer transmit power, because no part of the hubs

operates in the same plane.

Load Characteristics

Users should always know the load characteristics for

their pumps. Are uniform or non-uniform loads expected?

Is this a variable-torque (centrifugal pump) or constant-

torque (positive displacement) application?

Starting torque is particularly important. Progressing

cavity pump applications are a prime example of an

application where starting torque is much greater than

the running torque. � is possibility must be taken into

consideration during coupling sizing. � e number of starts

and stops per hour also plays a role in selection.

Back Pull-Out Design

When specifying a coupling for a pump that uses a

back pull-out design, a spacer coupling is an ideal choice.

Spacer couplings are prominent in the pump industry

and are available in a wide variety of designs. � ey are

Image 2. Radially split elements can typically be replaced with less effort and without the need to unbolt fl anges from hubs.




engineered to have a drop-out center section to allow

for easy removal of the pump rotating assembly without

having to unbolt the motor (see Image 1, page 48).

� e distance between shaft ends (DBSE) must

be large enough to allow the rotating assembly to

be removed without having to unbolt the motor. A

coupling with a DBSE that is too small can lead to a

fl awed buildup and require the maintenance personnel

working on the pump to move the motor in order

to remove the rotating assembly, which defeats the

purpose of a back pull-out design.

With the exception of American Petroleum Institute

(API) applications, which are beyond the scope of this

article, using an elastomeric coupling with a radially

split element is a solid choice for a general-purpose

spacer coupling. Radially split elements can typically

be replaced with less eff ort and without the need to

unbolt fl anges from hubs (see Image 2, page 49).

5 COMMON COUPLING MISTAKES

1. Failing to check maximum bore capacity: Sometimes

the shaft size of the driver or the driven piece of

equipment exceeds the maximum bore capacity of the

coupling hub. In this case, the shaft sizes dictate the

coupling size. Avoid coupling bores that use shallow

keyways because these hubs use different size keys. As

Murphy’s law would have it, the key you will need during

a breakdown will not be included in the box.

2. Using the one-size-fi ts-all approach: The coupling is the

weak link, so size it accordingly. Making all the couplings

the same size may seem like a good idea, but it is not. An

oversized or undersized coupling will lead to destroyed

pumps and failed couplings.

3. Ignoring multiple duty points: Size the coupling for

the highest torque duty point, but pay attention to

the service factor of the duty with the lower torque

requirement. Keep in mind the torque limit of the shaft.

Consult a coupling manual for help with these types

of applications.

4. Ignoring heat and chemical compatibility: Make

sure the coupling elastomer is compatible with the

environment where it will be used. In other words, is what

you’re pumping compatible with the elastomer? A seal

failure can expose the element to the pumped fl uid. Is

the temperature limit of the element acceptable for the

environment where it will be used?

5. Overlooking space restrictions: Make sure your

coupling can fi t where you want to put it. A high-torque

application, gearbox to pump for example, often requires

a coupling with a large outside diameter. Consider using

an element with a higher torque rating, or look into

different designs that have a higher-torque density.

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around the world. Contact KSB, your one source

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KSB, Inc. . Mid-Atlantic . Phone: (804) 565-8203

[email protected] . www.ksbusa.com

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[email protected] . www.standardalloys.com

Our technology. Your success. Pumps Valves Service

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51

In addition, the entire coupling assembly often has

fewer components. � e fewer components, the less

users have to keep track of.

Misalignment

Shaft misalignment includes parallel off set,

angular off set and a mixture of the two (see Figure

1). Coupling manufactures often talk about the

misalignment their coupling can tolerate. Just

because the coupling can handle the misalignment

does not mean that the pump can. For example,

a popular model elastomeric coupling used in the

pump industry can handle more than 0.060 inches of

parallel off set. However, the installation, operation

and maintenance (IOM) manual for the pump to

which the coupling is being mounted indicates that

the manufacturer only recommends 0.005 inches

of parallel off set. � e coupling can tolerate more

than 12 times the parallel off set that the pump is

recommended to handle. Improper alignment will lead

to bearing and seal issues down the road. Taking the

necessary time to align their pump assemblies before

putting them into service will help save plants money

in the long run.

Robert Bramer is a mechanical engineer with

Fischer Process Industries. He may be reached at


Figure 1. Shaft misalignment includes parallel offset, angular offset and a mixture of the two.

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A dvanced thermoplastic materials off er

several advantages over aluminum and other

metals for turbo-compressor labyrinth seals.

Polymer seals eliminate the risk of metal tooth

deformation and mating shaft damage during shaft

rubs. � is enables end users to tighten initial clearances

and reduce clearance loss over time. Overall compressor

effi ciency improves greatly over the life of the seals.

� is article provides mechanical property data from

two diff erent sets of seals. � e integrity of the seals after

11 and 15 years in service was compared with new, off -

the-shelf seals of the same material.

� e fi rst set of seals, including fi ve diff erent seals

for evaluation, was installed in 1996 and remained in

service for 11 years in a natural gas compressor. Visually,

the seals were in good condition, with the exception of

damage suff ered during the removal process. � ey each

exhibited damage ranging from a few gouges to being

completely broken.

Upon removal, the in-service seals showed little signs

of wear and the teeth were well-defi ned and in good

condition. � e seals did incur some damage during the

removal process: Some had just a few gouges, and others

were completely broken.

Polymer Seals Perform Reliably After Years of UseTwo sets of seals, in service for 11 and 15 years, still meet baseline standards.

BY JIM HEBELQUADRANT

Image 1. The fi rst set of seals were removed from a natural gas compressor after 11 years in service. (Images and graphics courtesy of Quadrant)

Image 2. The second seal was removed from a different compressor, which had been in service for 15 years.


53

Another seal was evaluated from

a diff erent compressor, which had

been in service for 15 years. � is

seal also showed some gouges from

removal and handling during the

compressor’s rebuild.

Evaluating the Seals

To evaluate the integrity of the

seals, the mechanical properties of

the returned seals were compared

with those of standard seals.

Only one seal—from the initial

set, B-case, 2nd wheel—was large

enough to allow full-sized tensile

test bars to be machined.

Tensile properties are the

fi ngerprint of a material’s

integrity. Full-sized tensile

bars are needed to yield a full

complement of tensile properties,

including strength, modulus and

elongation values.

In addition, other mechanical

properties were evaluated,

including compressive strength

Table 1. The two sets of seals used in the evaluation and their descriptions

Summary of received seals

Seal Set 1 - 1 Years in Service Seal Set 2 - 15 Years in Service

B-Case (2) C-Case C-Case C-Case C-Case 8th Stage

2nd Wheel 5th Wheel 4th Wheel 5th Wheel(possibly)

7th Wheel 2nd Wheel

TCE PartNumber

C-029-126-002 D-029-164-005 D-029-100-029 D-029-100-029

D-029-100-029

D-029-126-002

Nova SerialNumber

120201187 120201103 Not identifi ed 120201090 Not identifi ed

120201187

Marking onPart

Not identifi ed 14388 K201C #5

lower

14387 K201C #4

lower

14386 K201C 14389 K201C #7

Not identifi ed

Size 15.242" OD x 12.6"

ID x 2.226”

18.057" OD x 16.4" IDx 1.180”

11.623" OD x 10.0"

ID x 1.562”

11.623" OD x 10.0"

ID x 1.562”

11.623" OD x 10.0"

ID x 1.562”

15.242” OD x 12.6” ID x 2.226”

Seal Confi g 2-segment shaftseal

2-segment impeller

seal

2-segment shaftseal

2-segment shaftseal

2-segment shaftseal

2-segment shaftseal

Material Torlon 4540 Torlon 4540 Torlon 4540 Torlon 4540 Torlon 4540 Torlon 4540

Temp Exposure

47 to 60 C 49 to 64 C 44 to 57 C 49 to 64 C 61 to 77 C 31 to 45 C

Time in Service

11 yr 11 yr 11 yr 11 yr 11 yr 15 yr


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54 SPECIAL SECTION BEARINGS, COUPLINGS & SEALS

Table 2. The results of the mechanical property testing for both the 11-year-old and 15-year-old polymer labyrinth seals

Summary of received seals

Seal Set 1 11 Years in Service

Seal Set 2 15 Years in Service

Test Method

Duratron T4540Baseline (1)

B-Case(2) C-Case C-Case C-Case C-Case 8th Stage

RecentProduction

2nd Wheel

5th Wheel

4th Wheel

5th Wheel

7th Wheel

2nd Wheel

Specifi c gravity ASTMD792

1.47 1.47 NA NA NA NA 1.47

Tensile strength, psi

ASTMD638

10,516 9,416 NA NA NA NA 10,323

Elongation at yield, %

ASTMD638

3.40 2.23 NA NA NA NA 3.34

Elongation at break, %

ASTMD638

3.40 2.23 NA NA NA NA 3.34

Tensile modulus, psi

ASTMD638

608,843 634,536 NA NA NA NA NA

Flex strength, psi

ASTMD790

11,864 13,217 NA NA NA NA 9,160

Flex modulus, psi

ASTMD790

546,492 608,581 NA NA NA NA 687,283

Compressive strength, psi

ASTMD695

23,606 21,140 21,475 21,136 20,345 21,860 22,132

Compressive modulus,psi

ASTMD695

346,670 433,450 437,000 450,000 454,160 456,440 376,060

DSC Tg, oC ASTMD3418

281 280 NA NA NA NA 272

Moisture content at time of testing, %

ASTMD570

Dry 0.47 NA NA NA NA 0.58

(1) Quadrant production sample data based on averages between 18” x 11” x 6” and 12” x 3.5” x 6” tubular bars

(2) B-Case, 2nd wheel was the only component large enough to allow for a full-sized machined tensile bar, which allowed for tensile strength, elongation and modulus data. As a result, only compressive data was generated on the other samples.

The property values of both the 11-year-old and 15-year-old

compressor seals revealed consistent performance compared

with standard data for the product.


55

and modulus. For the initial set of seals,

only compressive test samples could

be machined and tested because of the

limited sample size of the other, smaller

cross-section seals.

� e single, 15-year seal underwent a

full complement of testing, except for

tensile modulus testing. Without

enough material to yield a full-sized

tensile bar, the modulus value could not

be determined.

� e property values from the

in-service seals were then compared to

a baseline set of data. To determine the

baseline values, compression-molded

tubular bars were used to replicate

the same production process as the

returned, older samples. Two tubes were

pulled from production, test plaques

were machined and tested, and the

results were documented.

Results

� e property values of both the 11-year-

old and 15-year-old compressor seals

revealed consistent performance

compared with standard data for

the product.

For the 11-year-old seals, the tensile

strength and elongation properties of

the B-case sample were a little lower

than baseline, but the tensile modulus

was higher. � e lower properties

were due to slight embrittlement

during service.

� e fl exural and compressive

properties were higher than current

production, which can also be attributed

to embrittlement. � e glass-transition

temperature (Tg) of the 11-year-old

material remained steady at 280 degrees

C, at which no major degradation of

the polymeric structure occurred. � e

compressive strength and modulus

values were also tightly packed and

within a 7 percent spread, showing good

data integrity among the returned seals.

For the 15-year-old seal, both tensile

and compressive data matched closely to

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James Hebel is application development and technical

service manager at Quadrant EPP, where he has been for

14 years. He holds a B.S. in mechanical engineering from

Virginia Polytechnic Institute and State University and

an M.S. in mechanical engineering from

The Catholic University of America. His

prior work experience includes the U.S.

Department of Defense and U.S. Gypsum

Company. He may be reached at james.


Image 3. For seals from the B-case sample, tensile strength was lower than baseline, but tensile modulus was higher.

baseline values, including the tensile elongation. Flexural

strength was less than baseline, while fl exural modulus

was above baseline. However, the data was within

acceptable variation considering the age of the polymer.

After 11 and 15 years of service in a natural gas

compressor, the integrity of seals appears to be similar to

current production.

Overall compressor effi ciency

improves greatly over the

life of the seals.

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O ne of the largest electric power generation

companies in the U.S. conducted an upgrade

project of their water pumps at their nuclear

plant facility. � e pump original equipment

manufacturer (OEM) was contracted to produce a series

of vertical circulating water pumps. � e vertical pump

model is designed to pump high volumes of seawater

and has an external fl ush provided to each of the four

composite bearing locations. � e bearings are composed

of a proprietary thermoplastic material, which is designed

specifi cally for use as bushings, bearings and wear rings

in pumps handling abrasive media up to 250 F (120

C). Its properties make it a more reliable material than

traditional rubber, ceramic or bronze.

� e Challenge

� e nuclear plant engineering team requested that the

pump manufacturer add a low-fl ow/fl ush alarm to the

upgraded pumps. � e alarm would trigger when the

fl ush drops below 5 gallons per minute (GPM) of fl ow to

the bearings. � e bearings in the pump must survive 15

minutes of low-fl ow/fl ush conditions to give the operators

adequate time to respond.

Although the pump OEM was confi dent the bearings

would survive for 15 minutes under low-fl ow/fl ush

conditions, suffi cient data was not available to confi rm

the composite bearings’ performance.

Composite Bearings Resist Wear in Circulating Water PumpsA thermoplastic composition in abrasive applications helped bearings meet end user specifi cations.

BY GREG GEDNEYGREENE, TWEED & CO.

Image 1. A bearing made of the proprietary thermoplastic material and a stainless steel shaft (Images and graphics courtesy of Greene, Tweed & Co.)

Figure 1. The test matrix shows the results of using the testing rig.


59

� e Solution

A test program was developed to confi rm the bearing’s

ability to survive in the end user’s condition. � e

program’s objective was to verify that the running

clearance would remain within an acceptable limit (less

than two times the original clearance) after a 15-minute

dry run, using the same operating conditions as the

vertical pump.

� e Results

Four bearings were tested on a horizontal testing rig.

Multiple tests were run on the four bearings, each for a

specifi ed amount of time (15, 30 and 60 minutes). � e

bearings demonstrated outstanding wear resistance

throughout the test program, shown by the minimal

change in measured internal diameters (ID) in Table 1.

� e results show a greater than 4x safety factor. � e

bearings showed no problems when tested for up to 60

minutes. � e pump manufacturer integrated the alarm,

and the power generation company specifi ed bearings

made from the proprietary thermoplastic material for all

circulating water pumps supplied to their nuclear facility.

Before Test Test 1 (15 min) Test 2 (30 min) Test 3 (60 min)

Test Results: 5 psi load Inner Diameter Inner Diameter Inner Diameter Inner Diameter

Bearing 1 2.705” (68.72 mm) 2.706” (68.73 mm) 2.705” (68.72 mm) 2.706” (68.73 mm)


Test Results: 10 psi load



Table 1. The inner diameter of the bearings measured in inches (”) and millimeters (mm) before and after testing

Greg Gedney is the equipment segment

manager at Greene, Tweed & Co. He may be

reached at [email protected] or 281-765-

4550. Visit gtweed.com for more information.

Designed to handle the tough demands of higher head conditions found in many low pressure sewage applications. Utilizing the same reliable patented cutter system at 414,000 cuts per minute, these new units incorporate 2 impeller stages for e�cient pumping of sewage slurries up to 200 feet. With only 16 full-load amps, these units are not only the solution to many demanding applications, but also replace other grinder units failing to meet requirements.

franklinengineered.com

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60


T he rising cost of electrical power has caused

many industrial plants to shift their focus to

energy consumption. Plants often run pumping

equipment continuously, and much research has

pointed to opportunities for cost savings by optimizing

pumping equipment.

When evaluating the potential for energy savings, end

users cannot consider a pump in isolation. � e suitability

of the pump for the system within which it operates

is vital. Even the best designed and most effi cient

equipment off ers power-saving potential if it is run off

its best effi ciency point (BEP) in a system for which it

is ill-applied.

Many plants have been in operation for more than 40

years, and their operating philosophies have changed

over time. Plant improvements have enabled higher

throughput, often increasing production by as much as

125-150 percent. Unfortunately, little is done to improve

or increase the performance of the support-service

pumping equipment, such as cooling water pumps.

As system fl ow demands increase, the duty point of the

pumps is forced to shift far to the right of the BEP, well

outside the acceptable operating range (AOR). � is causes

effi ciency and pump reliability to decrease dramatically.

Casting tolerances, surface fi nishes, and impeller/

volute or impeller/diff user geometry have all dramatically

improved during the last 40 years. But because

many pumps were installed when the plants were

commissioned, the existing pumps were manufactured

using techniques that would be considered obsolete today.

� e result is higher energy costs and reduced reliability

and availability, which often cause production delays.

� e Starting Point

Pumps react to changing system conditions. System

demand (or system resistance) determines the fl ow and

pressure at which a pump will operate. As system fl ow

demand increases, the fl ow throughput of a pump also

increases, causing it to operate further on the right-hand

part of the performance curve.

� e system demand is graphically represented by

plotting the system resistance curve as a function of fl ow.

� is curve enables the end user to quickly determine

system fl ow for a given pump since the pressure and

fl ow are determined by the intersection of the pump

performance curve (red) with the system head curve

(green). A process design engineer would ideally select a

pump with an operating point that would have coincided

Optimize High-Energy Pumps With Improved Impeller DesignAs new design and manufacturing technologies are developed, end users can aff ordably upgrade their systems and verify better performance.

BY BOB JENNINGS & DR. GARY DYSONHYDRO, INC.

PUMP SYSTEM OPTIMIZATION

61


with the BEP. � is could yield a pump

effi ciency of 80 percent, as shown in Figure 1.

However, many support pumping systems

have exceeded their original design and have

much higher fl ows to support the higher plant

production. � is is particularly common in

cooling water applications, condenser water

pumps, descale pumps or any application

where water usage is proportional to

production.

While the original design may have

called for two-pump operation, present-day

requirements may require 2 1/2 pumps online,

with two pumps being insuffi cient and three pumps too

many. As fl ows increase, the result is usually that system

requirements have exceeded the AOR of the pumps (see

Figure 2, page 62).

Original Duty Point

� e original system design for one processing plant’s

service water pumps was to have three pumps operating

in parallel with an installed spare as a standby. � e total

system requirement was 105,000 U.S. gallons per minute

(GPM) (23,864 cubic meters per hour) at a pressure of 190

feet (57.9 meters) total dynamic head (TDH). Each pump

was rated for 35,000 GPM (7,955 cubic meters per hour)

at 190 feet (57.9 meters) TDH.

As production increased, more service water was

required, causing the existing pumps to operate

further out to the right of the performance curve. � is

caused the net positive suction head required (NPSHR)

to exceed the NPSH available (NPSHA), leading to severe

cavitation issues. To reduce cavitation problems, the

plant ran four pumps in parallel and throttled each

pump to keep the individual pump fl ows low enough

to prevent cavitation.

Image 1. Much research has pointed to opportunities for cost savings by optimizing pumping equipment. (Images and graphics courtesy of Hydro, Inc.)

Figure 1. Pump and system curve interaction

62 PUMP SYSTEM OPTIMIZATIONCOVER S E R I E S


Over time, the design of the impellers also drifted

away from optimal because no testing or verifi cation of

the performance took place. Cavitation and insuffi cient

service water continued until the pumping station

could not keep up with plant demand. As Figure 3 (page

63) shows, fi eld pump assessments and subsequent

individual performance tests conducted on the

poorly replicated impellers showed that the pump

performance had been dramatically compromised.

New Impeller Design

� e technological advances made in recent years

with reverse engineering, laser digitizing equipment,

computation fl uid dynamics (CFD) software and the

ability to print 3-D foundry molds from computer-

aided design/computer-aided modeling (CAD/CAM)

software has revolutionized the aftermarket industry.

Solutions that were cost-prohibitive fi ve years ago

are now within the realm of fi nancial feasibility. � e

solution helped manufacturers and end users solve

their energy optimization diffi culties in three ways:

1. Capture system resistance data and operating

conditions. � e plant’s pumps operated at diff erent

fl ow conditions. Understanding how these fl ow

requirements matched the system’s resistance enabled

an optimized design fl ow to be derived that would


Figure 2. Pump Performance curve interaction based on different system requirements

Acceptable Operating Range

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63


ensure that head was not generated by the pump to

be dissipated over a control valve, so the number of

pumps running was optimized for the demand.

2. Capture the geometry of the existing impeller

using advanced laser-scanning equipment and

build a CFD model of this impeller. � is

allows design scenarios to be evaluated

to get the optimized design for the newly

established fl ow conditions.

3. Use additive manufacturing in the

form of 3-D foundry sand printers

and casting simulation software

to drastically reduce lead-time and

overhead normally associated with

pattern/core box sand casting processes.

� e 3-D printing process directly from

the design data ensures that the integrity

of the design is completely captured. � e

high accuracy of sand printing means that

vane-to-vane symmetry and vane shape is

identical. Sand printing also off ers improved

casting surface fi nish. � ese manufacturing measures

alone can lead to a 3 percent effi ciency increase.

Tables 1-3 show the before and after energy usage,

based on the projected energy audits (see page 64).

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Figure 3. Pump performance test data illustrating performance degradation

64 PUMP SYSTEM OPTIMIZATION

Table 2. Newly designed system

Measurement Per Pump Per System

GPM 48,333* 144,999*

TDH 160 160

Effi ciency 0.89 0.89

Brake horsepower 2,194 6,582

kW 1,637 4,911

Hours per year 8,400 8,400

kW rate $0.07 $0.07

Total energy cost per year $962,556.00 $2,887,668.00

* Note: Three redesigned pumps online

Table 3. Total projected energy savings for the system

Energy Costs - Original (Present) $ 4,431,168.00

Energy Costs - New Impeller Design $ 2,887,668.00

Impeller Design and Manufacturing Costs for 4 impellers

$ 390,000.00*

Total Savings $ 1,153,500.00

* Number excludes the regular repair cost(s) normally incurred for this equipment.

Table 1. Original system

Measurement Per Pump Per System

GPM 40,000* 160,000*

TDH 185 185

Effi ciency 0.74 0.74

Brake horsepower 2,525 10,101

kilowatts (kW) 1,884 7,536

Hours per year 8,400 8,400

kW rate $0.07 $0.07

Total energy cost per year $1,107,792.00 $4,431,168.00

* Note: Four pumps online throttle to prevent cavitation


In addition to energy savings, improved reliability and availability

translates to extended mean time between repairs, signifi cantly reducing

maintenance costs.

Conclusion

Signifi cant energy savings opportunities exist in every manufacturing

facility worldwide, particularly with pumping systems that:

• use pumps driven by 200 horsepower and above

• are primarily providing cooling water

• include demands proportional to the plant throughput

• are used for batch operations

• have inherent delays or production slowdown

• currently use dump valves or bypass lines

• feature fl uctuating system loadingCir

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65


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Dr. Gary Dyson is managing director with

Hydro Global Engineering Services. He has

a Ph.D. from Cranfi eld University and 30

years of experience in the pump

industry in senior positions

with many manufacturers.

His expertise includes pump

hydraulic performance,

design and reliability

improvement.

Bob Jennings has worked in sales, repair

and troubleshooting pumping systems for

HydroAire since 1976 and has more than

15 years of experience dedicated

to submersible pump

development and applications

in the municipal industry.

Jennings is the lead training

instructor for Hydro, Inc.

In the past, pump upgrades or rerates

tended to lie strictly with the OEM

because they were the only party with

access to cost-eff ective cast parts.

However, with the technology revolution

that is taking place in the aftermarket,

upper tier service centers with on-staff

hydraulic engineering support can often

provide cost-eff ective, newly designed

impellers or volutes with solutions

specifi cally designed for the application.

With reverse engineering, laser

digitizing equipment, CFD software and

rapid prototyping coupled with the ability

to print 3-D foundry molds directly from

CAD/CAM software, the end user is no

longer required to limp along with an

obsolete pumping system. Solutions are

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67


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EXPERTS

U nderstanding net positive suction head (NPSH)

and cavitation is essential for plant managers,

pump manufacturers and operators. Proper

NPSH calculations are vital for preventing

cavitation and ensuring proper pump functionality.

� e following 10 facts about NPSH can help end users

improve system operation and effi ciency.

1. Analyzing NPSH margins can help

reduce cavitation.

Cavitation is defi ned as the partial evaporation of a liquid

in a system. Vapor forms when the static pressure in a

liquid’s fl ow drops below the vapor pressure of that liquid.

A two-phase fl ow occurs when a vapor bubble appears and

fl uid evaporates. When these bubbles enter a region where

static pressure exceeds vapor pressure, they will implode,

causing cavitation. � ese bubbles can cause cavities that

impair the head and effi ciency of the pump, creating

excessive noise and vibration. Cavitation erosion can be

detrimental to the pump’s head and effi ciency. Damage to

ancillary components, such as bearings and seals, from

higher vibration is also likely. � e region of the lowest

pressure generally occurs around the leading edge of the

vane, and this is where cavitation will most likely occur.

10 Things You Need to Know about NPSHBecause cavitation is unavoidable in pump operations, understanding how to reduce it using NPSH calculations is necessary to maintain pump functionality and health.

BY SIMON BRADSHAWITT GOULDS PUMPS

Figure 1. Cavitation visualization

(Images and graphics courtesy of ITT Goulds Pumps)Figure 2. Analyzing NPSH margins can

help reduce cavitation.



Although cavitation cannot be completely

suppressed in a pump, measuring the required

NPSH (NPSHR) and analyzing NPSH margins

are key to reducing cavitation and keeping the

pump running smoothly.

2. NPSH has two main components.

NPSH distinguishes between the pressure

available to give to the pump (NPSHA) and

the pressure required by the pump (NPSHR)

to limit the reduction of pump head to an

acceptable level.

3. NPSHA requires an in-depth calculation.

NPSHA is caused by atmospheric pressure, tank elevation

or pressure inside a tank. � is measurement must be

calculated by the user. At sea level, the atmospheric

pressure provided is 14.77 pounds per square inch

(psi), or 1 bar, which fl uctuates depending on elevation.

Additionally, the fl uid vapor pressure will vary with

temperature. With this calculation, the manufacturer

must convert pressure to feet or meters and consider the

fl uid temperature and elevation surrounding the pump.

4. Critical tests determine NPSHR.

NPSHR is the minimum amount of pressure required at

the pump impeller to limit the reduction in pump head

to an acceptable level. Instead of using a calculation as

with NPSHA, the manufacturer will run tests to validate

the critical quantity of NPSHR. To do this, the fl ow is kept

constant, and the NPSHA is reduced. As NPSH

A is lowered,

cavitation inside the pump will increase until it begins to

block fl uid fl ow through the pump. � ese tests must be

repeated until every fl ow point has been recorded. NPSHR

is commonly called NPSH3, because a three percent head

drop criteria is often used during a NPSHR test.


Image 1. Calculating NPSHA

69


5. � ere are other forms of NPSH.

Many diff erent forms of and acronyms for NPSH exist.

Similar to NPSH3, NPSH

1 or NPSH

0 results when the pump

head is only reduced by 1 or 0 percent, respectively. NPSHi,

where the “i” stands for inception, is where cavitation

fi rst occurs.

NPSH40K

is the NPSH at which the impeller will have a

40,000-hour life. NPSH40K

usually can be determined only

by the pump supplier, as in-depth knowledge of the impeller

geometry and material is necessary. NPSH40K

typically is

used for boiler feed pumps, large critical pumps and for plant

owner/operators who want confi dence that the impeller will

not fail between major overhauls.

6. � ree methods can be used to

determine NPSH40K

.

Pump suppliers can determine NPSH40K

using three methods. � e fi rst method

involves building a full-size or a scale-

factor test rig of the impeller and recording

subsequent damage after a test run. � is

process can be costly and time-consuming.

Another is Vlamming, an empirical

method used for stainless steel impellers

in water. Using certain parameters

associated with the impeller within the

equation, suppliers determine a value.

Gülich is the third method and is based on

the size of the cavitation bubble, which is

usually determined by computational fl uid

dynamics (CFD) and impeller material.

7. Proper material selection can

reduce NPSH margin.

� e new Hydraulic Institute (HI) Standard

9.6.1, released in 2012, provides guidelines

and recommendations for NPSH margins,

how much NPSHA is needed for a given

pump service and what features are needed

in a pump based on the NPSHA.

Proper material selection in a pump

can reduce NPSH margin requirements

and, as a result, life cycle cost. During the

process of selecting materials, end users

should consider materials less susceptible

to cavitation damage, which could impact

overall system cost.

8. All pumps have cavitation

regardless of NPSH.

Frequently, pump users infer that as

long as NPSHA is above the NPSH

R, no

cavitation will occur. � is is a common

misconception. For example, in order to

completely suppress cavitation in a pump

where the NPSH3 occurs at 19 feet, the

NPSH1 occurs at 25 feet, the NPSH

0 occurs

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at 63 feet and the NPSHi at 107 feet, the NPSH

A must be

about 5.5 times the NPSHR. Few, if any, pumps operate with

this margin, revealing that all pumps have cavitation. � e

only question is whether it is damaging cavitation.

9. Specifi c materials can help prevent cavitation.

Because cavitation is present in every

pump, users must fi nd the right materials

to minimize damage. � e leading material

chosen for cavitation resistance is

Martensitic stainless steel, also known

as CA6NM, chrome steel or 13-4. More

resistant materials are available, but they

are less common and more expensive,

making Martensitic stainless steel an ideal

option in freshwater applications.

10. � e thermodynamic eff ect can

aff ect NPSH.

If a fl uid has a high vapor pressure or

temperature, more energy must be

exchanged across the vapor-fl uid boundary

and the vapor bubble. � is is known as the

thermodynamic eff ect, or the hydrocarbon

correction factor. Cavitation bubbles

become smaller, and NPSHR is reduced.

If in doubt, consider the critical point

of a fl uid. As you get closer to water’s

critical point—374 C or 705 F—the

thermodynamic eff ect becomes more

pronounced. At this critical point, only

a single phase is present, either a low-

density liquid or a high-density gas, and

because there is no liquid-gas mixture,

cavitation cannot occur. Guidance on this

method can be found in H.I. Standard 1.3.

Conclusion

Cavitation is unavoidable in pump

operations. Understanding how to reduce

it using NPSH calculations is necessary to

maintain pump functionality and health.

Although methods and materials are

available to reduce the eff ects of cavitation,

the truth is that cavitation will always be

present. Proper management of cavitation

to prevent damage is the end goal.


Simon Bradshaw is director of API product

development & technology for ITT Goulds

Pumps. Bradshaw has more than 20 years of

engineering experience in the pump industry.

Read more online at

pumpsandsystems.com/npsh.

71


E ngineered composites can be designed and used

to improve performance and effi ciency as well as

reduce maintenance and repair costs. Composite

upgrades prevent expensive products from

deteriorating, extend the life and reliability of existing

equipment, and increase pump effi ciency.

� ey can even prevent pump leaks that can

result in costly cleanups and fi nes from

regulatory agencies. In most cases, reduced

downtime resulting from introducing

structural composite pump upgrades is one

of the most important benefi ts.

� e impeller is the heart of any

centrifugal pump. Like a human heart,

a pump impeller is the most critical

pump component, constantly stressed by

hydrodynamic forces, fatigue, corrosion,

erosion abrasion, chemical attack

and cavitation. � e overall effi ciency of a

centrifugal pump is in direct correlation to

the effi ciency of the impeller. To maximize

effi ciency, the impeller’s hydraulic design

must correspond to the design of the pump

casing and to the operating conditions of

the pump in service.

Any centrifugal pump can be made

energy-effi cient by upgrading the impeller

and rings to an optimized and engineered

composite, such as one company’s

structural graphite epoxy composite. � is company off ers

impeller and ring upgrades for any centrifugal pump,

which provide higher effi ciencies and increased longevity.

� ey can also design the impeller so that the operating

point becomes the best effi ciency point (BEP).

Engineered Composites Off er Opportunities for Upgrading EquipmentThese pumps prevent equipment from corroding, provide lower costs and increase effi ciency.

BY JOHN A. KOZELSIMS PUMP VALVE COMPANY, INC.

Image 1. Structural composite upgrades can extend pump life, improve performance and increase effi ciency. (Images and graphics courtesy of SIMS Pump Valve Company, Inc.)



When companies are trying to save money, it may

seem diffi cult to justify the upgrades, but the payback

for pump upgrades is extremely quick—usually less

than one year return on investment. In most cases,

the incremental costs of upgrades are minimal when

compared with the loss in

downtime, energy and expensive

repairs. Plant outages, ship

overhauls, building new vessels,

constructing new manufacturing

plants, plant expansions and new

system installations are good

opportunities to upgrade existing

pumps to composite internals

and specify pumps with upgraded

effi ciency and reliability features.

As equipment starts to age,

pumps lose performance and

effi ciency. � ey also require

additional maintenance, repairs,

expenses and downtime. Often,

the aging or corroding equipment

cannot keep up with plant

demand. Before equipment gets to

this point, pumps can be upgraded

to structural composite to extend

the life of the pump, return the

pump to the proper performance

and increase effi ciency.

Pump Optimization

Too often, a pump is purchased

for a specifi c performance but

when put into service, it operates

at a point completely diff erent

from the original design point,

or BEP, because of the system

requirements. � e pump operating

away from the BEP also causes

problems such as excessive noise

and vibration, shaft oscillation,

cavitation, and premature wear

and failure of the mechanical

seals, bearings, rings, sleeves

and impellers.

In extreme cases, the pump

shaft will break right behind the

impeller from the excessive radial

forces that occur when a pump is

operated away from the original

design point.

Operating a pump away from the BEP has a detrimental

eff ect on pump effi ciency. � e larger the pump, the more

energy is wasted. Operating any pump away from the

BEP wastes a tremendous amount of money, because an

estimated 85 percent of the total cost of owning a pump

73



is the operational cost (maintenance cost plus the cost of energy).

Fortunately, these problems can be easily resolved by installing

engineered structural composite impellers and rings, which

have been re-engineered for the system’s requirements.

� e reliability and longevity of the complete pump is also

substantially improved.

Image 2 shows two severely deteriorated impellers in a two-

stage horizontally split-case cooling pump in a power plant. � ey

were underperforming and were terribly ineffi cient. A 75-kilowatt

(kW) motor operating in this condition could easily lose 50

percent of the original effi ciency.

If the original effi ciency was 80 percent and now the pump is

operating at 40 percent effi ciency, there would be an approximate

loss of $31,104 per year at $0.12 per kilowatt (kW) hour (see

Equation 1).

30 kW loss x 8,640 hours x $0.12/kW hour = $31.104

Equation 1

Even if the pump was operating only 10 percent away from

the BEP, the approximate loss would be $7,776 per year, plus

additional maintenance expenses (see Equation 2).

Image 2. Two severely deteriorated impellers in a two-

stage horizontally split-case cooling pump




7.5 kW loss x 8,640 hours x $0.12 kW hour = $7,776.00

Equation 2

� e composite pump in Image 4 was re-engineered

into a two-stage structural composite pump with single-

suction impellers (see page 76). It is approximately 11

percent more effi cient than the original metallic pump

(before corroding), and this new composite pump will

never corrode. All wetted parts are manufactured

with structural composite, and the bearing frames are

machined from type 316 stainless steel.

Improved Effi ciency

In 2015, tremendous eff ort has been put forth to reduce

energy consumption. � e Department of Energy (DOE)

and the Hydraulic Institute have been working together

to reduce the energy consumption of pumps, motors and

pump systems. Engineered composites can contribute to

this eff ort. By re-engineering the pump/impeller design,

they can signifi cantly reduce energy consumption—in

some cases by 20 percent.

Equipment Longevity

In addition to improved effi ciency, engineered composite

impellers off er many advantages over traditional products

cast from metal. � ey do not corrode, are lightweight,

can run with tighter clearances, are designed for high

effi ciency, and are not subject to casting defects or

Image 3. Damage from corrosion, erosion and cavitation can quickly destroy metallic pumps and pump parts.

75



imperfections. Many of these impellers and

casing rings have been used successfully

since 1955 in the Marine, Navy, wastewater,

industrial and chemical markets. Structural

composite impellers have often outlasted

and outperformed products manufactured

from bronze, stainless steel, duplex steel,

monel and even titanium.

Reduced Wear

� e new alternative composite solutions

for impellers and rings are ideal for new,

repair or retrofi t applications. Engineered

impellers and rings are lightweight and do

not corrode.

Wear of other pump parts—including

the pump casing—is greatly reduced

because of the engineered impeller’s

balance, light weight, self-lubrication,

sealing, and resistance to corrosion, erosion

and cavitation. � is means far less expense

for replacement of parts and downtime.

Reducing or eliminating corrosion, erosion

and cavitation can increase effi ciency and

reduce costs substantially.

Maximized Performance

Because of new technologies, structural

composite impellers are computer-

engineered and precision-machined. � e

impeller vane geometry can be engineered

using computational fl uid dynamics (CFD)

techniques and programmed to maximize

effi ciency and performance. Problems

such as recirculation, radial thrust and

cavitation can be minimized or eliminated

by using structural composite impellers

instead of the traditional

metallic ones. Impeller vane shapes can

easily be modifi ed to provide the best

vane shape for specifi c applications and

performance requests.

Corrosion, erosion, cavitation, rotor

imbalance and leakage between the wear

rings, casing rings and interstage bushings

are major contributors to the loss of

pump effi ciency. Damage from corrosion,

erosion and cavitation quickly destroys

the metallic pump parts. Because of the

self-lubricating characteristics of many

Image 4. This composite pump was re-engineered into a two-stage structural composite pump with single-suction impellers. It is approximately 11 percent more effi cient than the original metallic pump (before corroding).




engineered composites and because

composites do not wear or corrode,

the performance curve will actually

increase over a period of time. A 1,000-

hour performance test was completed

on a U.S. Navy Standard Fire Pump

manufactured from titanium with

one company’s engineered structural

composite impeller and casing rings.

� e result showed a 2.5 percent

increase in the head-capacity (H-Q) at

the end of the test.

One of the many advantages of using

composite pumps is that the casing

volute geometries and the impeller

geometries can be designed and

engineered specifi cally for the required

operating point in the plant or vessel.

With premium effi ciency engineered

structural composite pumps, strength

can be added and removed based

on need.

Premium effi ciency composite

pumps are designed and engineered to

keep their overall sizes at a minimum

so that they can easily fi t into confi ned

spaces. � ese types of pumps are

also engineered to minimize piping

modifi cations while maintaining or

exceeding pump performance. � ese

engineered composite equipment

upgrades help pump users increase

the effi ciency and longevity of their

pumping systems.

John A. Kozel is president and CEO of SIMS Pump Valve Company, Inc.

He may be reached at 201-792-0600 or at

[email protected]. For more information, visit simsite.com.

Image 5. This vertical in-line structural graphite composite pump replaced the type 316 stainless steel pumps onboard the Navy Military Sea Lift Command Vessel.

Because of the self-lubricating characteristics

of many engineered composites and because

composites do not wear or corrode, the

performance curve will actually increase over a

period of time.

77



W hy should electrical inspections be an

integral part of a pump maintenance

routine? � e answer is simple: Performing

electrical inspections on pumps and their

systems helps locate faults before they become failures.

� is allows the maintenance technician to order parts or

replacement pumps and schedule system maintenance in

advance to avoid costly downtime and emergency repairs.

Electrical inspections can provide a great deal of

information about the overall condition of the pumping

system. � is is especially true for submersible pumps in

which the motor and the pump are packaged as a single

unit. Most of these pumps are equipped with internal

sensors for winding temperature, bearing temperature

and the presence of moisture. During the last fi ve years,

vibration sensors have become standard equipment in

larger pumps. � e information these sensors provide

can mean the diff erence between a simple rebuild or

stator rewind and rotor replacement. Regular electrical

inspections can help reduce each pump’s total cost of

ownership (TCO).

Offl ine Testing

During a motor inspection, several tests are performed

on the stator windings. A multimeter can be used to test

the resistance of the coils and compare them to each

other. For single-phase motors, the resistance readings

can be compared to an ohms chart provided by the

manufacturer. In three-phase motors the resistance

(ohms) on each phase should be within 2 percent. Shorts

to ground can only be found with a multimeter if there

is a direct short. Other conditions, such as moisture,

dirt or carbonization, may not be detectable. When

electrical arcing occurs between the windings and

ground or between coils, the insulation of the windings

becomes carbonized, basically turning the material into

a semiconductor. A semiconductor acts like an insulator

until a barrier potential voltage is reached. � en, it shorts

and behaves like a conductor.

In the case of carbonized winding insulation, a

multimeter cannot detect the ground fault because the

test voltage of the meter (9-10 volts [V] direct current

[DC]) is too low to reach the barrier potential of the

carbonized insulation. In the past, a hipot test was

used to fi nd ground shorts. During a hipot test, a high

voltage potential (2,000 V) is placed across the windings,

and leakage through the insulation is measured to

determine the condition of the insulation (see Image 2,

page 80). Unfortunately, these testers can damage the

windings over time. If moisture or dirt is present, the

Electrical Inspections Reduce Cost of Ownership Offl ine and online testing can improve reliability and reduce downtime.

BY JAMES JETTE KSB PUMPS INC.

Image 1. A Megger test in action

(Images courtesy of KSB)



hipot may cause an arc to

fl ash, instantly ruining

the windings. Hipot tests

are used at factories to

determine the dielectric

breakdown voltage of new

windings. A hipot test is

also required for explosion-

proof certifi cation.

In 2015, a Megger (a

registered trademark of

the Megger Corporation)

is used to test for shorts to

ground. Megger tests work

by sending a low-amperage

(0.001 amps) pulse of DC

voltage between the coil

leads and the stator ground

at two times the motor’s

operating voltage (250-

1,000 V).

� e Megger displays the

results in megaohms (see Image 1). Readings from the

Megger can determine whether there is a direct short

to ground or an insulation fault in the windings, such

as moisture or dirt. In the case of moisture or dirt, the

stator can be washed, dried and re-dipped in varnish to

save the owner from an expensive rewind.

For coil-to-coil and turn-to-turn shorts, multimeters

and Meggers can only detect a major short. For minor

shorts, a coil and winding tester is needed. When

a small turn-to-turn fault occurs, there is typically only

a tiny change to the DC resistance. With larger motors

this change can be too small to detect with an

ordinary multimeter.

To fi nd the short, the end user must look at the

diff erence between the alternating current (AC)

resistance (inductance) and the DC resistance. While

the DC resistance may change slightly because of a

minor short, the AC resistance will vary greatly with

frequency. Minor shorts can be easily detected by

comparing the three windings while testing a range of

frequencies. Two types of coil and winding testers are

available. Both types input a low voltage AC signal and

read the output. A surge tester—the most common

style of coil tester—has a screen that displays the

waveform as the tester steps through the frequencies.

Other types calculate the diff erential internally and

display the results on a screen.

79




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Online Testing

� e most exciting new development in the world of pump

electrical maintenance is the development of online

testing. � is new breed of instruments can be attached

to a pumping system to monitor the pump and motor

while they are running. � e temperature, vibration, fl ow,

pressure, power and electrical waveforms can be analyzed

using online testing.

On the motor side, users can detect problems with

incoming power, bearings, stator shorts, and dirty or

wet windings. On the pump side, the intake pressure,

discharge pressure, fl uid temperature, fl ow rate, bearing

condition and vibration can be measured.

Another feature of online testing—known as data

logging—is the ability to collect measurements over a

period of time. � e majority of pump system problems

happen when an operator is not present—the “ghost”

failures that occur in the late hours of the night. Data

logging can monitor multiple channels of information

for long periods of time to capture these events as they

happen. Examining data logger records collected over

extended periods can also reveal trends that point to

gradual deterioration of pump or motor conditions before

they become critical.

A data logger can also show the operating parameters

of the pump system and help end users evaluate the exact

duty point and duty cycles of the system. Comparing

this information with the

manufacturer’s pump curves,

end users can determine with

high accuracy where the pump is

operating on the curve, measure

the system curve and determine

where the motor is running on the

power curve.

� is information shows the

eff ects of pump wear, pipe

restrictions and suction issues.

� is information can also be used

to accurately calculate the pump

system effi ciency, which allows the

engineer to off er solutions that

can improve effi ciency, reduce wear

and decrease downtime.

James Jette is a senior service sales

expert at KSB Canada. Jette has a degree in

electronics and computer science from the

New England Technical Institute.

His credentials include a Red

Seal certifi cate as an industrial

millwright from Toronto-based

Humber College.

Image 2. Hipot testing performed on a submersible pump stator



The Power of Knowledge Engineering

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The annual Turbomachinery & Pump Symposia (TPS 2015) feature a

technical program and international exhibition, complete with full-

size equipment and hundreds of companies. he Turbomachinery

Symposium is the only meeting organized by users for users. he members of

the Advisory Committee are recognized leaders in the rotating equipment and

power generation community. he event promotes professional development,

technology transfer, peer networking and information exchange.

he symposia cover topics including maintenance, troubleshooting,

operation and purchase of pumps. More than 6,000 rotating equipment and

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which represents industries such as oil and gas, chemical and petrochemical, power, manufacturing, mining

and metals, and water.

With 17 short courses and 88 technical sessions, professionals have the opportunity to grow their

knowledge of pumps and turbomachinery. he technical sessions include lectures, tutorials, discussion groups

and case studies. Executives, managers, engineers, sales directors and technicians are represented. More than

300 companies take part in the exhibition. For more information, visit tps.tamu.edu.

44TH Turbomachinery & 31ST Pump SymposiaSept. 14-17, 2014George R. Brown Convention CenterHouston, Texas

Exhibition Hours

Tuesday, Sept. 14 Noon – 2 p.m.

Tuesday, Sept. 14 2:30 p.m. – 7 p.m.

Wednesday, Sept. 15 Noon – 2 p.m.

Wednesday, Sept. 15 2:30 p.m. – 6:30 p.m.

Thursday, Sept. 16 9:30 a.m. – Noon

Visit us at Booth 1318


83

STAY COMPETITIVE

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88th Annual Water Environment Federation Technical Exhibition and Conference

September 26 – 30, 2015 McCormick Place, Chicago, Illinois USA

Register Today!www.WEFTEC.org

ONE WORLD.ONE WATER.ONE EVENT.



84 BUSINESS OF THE BUSINESS

The agriculture industry has

historically been a slow

adapter of new technology.

With more than 7 billion people

currently on the planet, the

need for precision farming has

caused a rapid evolution in the

industry. Precision agriculture

is thought by many to be the

biggest technological change in

agriculture since the introduction

of hydraulics in the 1940s.

Food Security

One of the key challenges the

world faces today is population

growth, particularly in developing

countries. According to a recently

released report from the United

Nations, the world’s 7.2 billion

people will increase to 8.1 billion

by 2025 and 9.6 billion by 2050.

Most of that growth will occur

in developing regions, which are

projected to increase from

5.9 billion in 2013 to 8.2 billion

in 2050. � e current food

production rate, however, falls

signi� cantly short of meeting this

increased need.

� is de� cit is pushing farmers

to adopt better technologies that

will meet the increasing demand

and to optimize resources with

minimum waste. Adoption of

precision agriculture, particularly

in developing regions, can play

a signi� cant role in feeding the

burgeoning global population.

A few key challenges will

contribute to food insecurity in the

21st century:

• Growing urbanization,

which will lead to decreases

in green space resulting

from the extension of cities

and movement of rural

communities to urban areas

• Declining agricultural

productivity resulting from

lack of healthy soil, water and

habitat

• Increasing water scarcity, which

will be the key challenge for

crop cultivation

Precision Agriculture

Built on location-based

technologies such as global

positioning systems (GPS) and

geographic information systems

(GIS), precision agriculture has

transformed the way farming is

conducted. It enables farmers to

monitor � eets remotely, conduct

soil analysis, monitor yield or

create customized maps to target

each area of a � eld uniquely. It

ensures better crop yield and

output e� ciency, enabling high

pro� tability with optimum use of

available resources.

Emerging countries are

expected to invest heavily in

precision agriculture. In developed

countries, investment is expected

to be in the more highly e� cient

precision farming systems

and procedures.

As food production needs

increase, precision agriculture

will be one of the key technologies

farmers rely on to increase

productivity by maximizing the

use of available land.

Implementation of precision

agriculture technology can lower

costs for seed, fertilizer, fuel and

labor and increase a � eld’s yield.

Often, payback periods can be

one to � ve years depending on the

technologies used.

Established agriculture and

technology companies and a

host of startups are providing

innovative products and services

that are focused on helping

farmers improve operational

e� ciency. Precision agriculture is

considered to be a huge advantage

for geospatial companies. Many

smaller companies will be bought

as they gain momentum and

provide unique products and

services. Trimble’s extensive

Connected Farm o� erings,

for example, include precision

agriculture products and services

that could drive the increased

e� ciency and yield needed to

develop the industry.

Precision Agriculture & Remote Monitoring Modernize Pump Systems

As food production needs increase, this technology allows end users to conserve

water and increase effi ciency.

By Arun Prasath

Frost & Sullivan


85

Remote Monitoring

New technologies will enable

multiple innovative applications

that change the way we live,

communicate and conduct

business. In 2015, the number of

connected devices is around 8.5

billion, and the installed base of

connected devices and machines

is expected to grow to 50 billion

units by 2020.

Remote monitoring is crucial

and intensive in agriculture.

In farming, water levels, soil

conditions and temperature

require continuous examination.

On the plant side, yield

monitoring and weed monitoring

are closely related key metrics.

Conserving water is a vital part

of farming. Water monitoring

and management are critical to

ensure this resource is allocated

e� ectively and used e� ciently.

Farmers spend approximately

one-third of their time traveling

to inaccessible or distant places to

ensure pumps are working well.

� e demand for pump monitoring

has increased as farmers look

to reduce costs. Some farming

operations, however, expend a

signi� cant amount of time and

labor to monitor the operation

of the irrigation pumps on their

farms. With the adoption of

Internet of � ings (IoT), end users

can monitor and control pump

systems from their smartphones

or tablets.

A pump monitoring system

is composed of a sensor and

a transmitter. � e sensor is

positioned in the water � ow of

the discharge from the irrigation

pump and senses whether or not

water is present. In this system,

each pump being monitored

is given a descriptive name or

number that is indicated in

the message so the producer

knows exactly which pump is

not operating. Once the pump

is operating again, the system

sends a signal indicating the water

� ow has been reestablished. It is

also possible to use the monitor

system to turn o� power units

remotely from a computer through

a website.

Several companies o� er wireless

technology for agriculture

professionals. Net Irrigate,

a manufacturer of wireless

irrigation monitoring technology

for the agriculture industry,

designed PumpProxy, which allows

farmers to remotely monitor and

shut down irrigation pumps by

website or mobile app and receive

text, voice or email noti� cations

about issues including thermal

overloads or power failures.

Conclusion

� e modern agriculture

industry provides a wide range

of opportunities for remote

monitoring and control. Water

conservation is a major challenge

for farmers, and because of

new regulations in water usage,

farmers are looking for better

ways to use available resources.

� e growing awareness—coupled

with technology savvy farmers—

will increase the rate of growth of

precision agriculture at automated

farm processes.

Arun Prasath is an industrial

automation and process control

industry analyst for Frost &

Sullivan, North America and India.

Prasath has an MBA in marketing

and operations from BIM, Trichy,

India, and a bachelor’s

degree in mechanical

engineering

from AAMEC,

Tanjore, India.

Adapt:

Conservation

agriculture

Utilize: Better water

management systems

Improve: Agricultural productivity

Develop: Sustainable agricultural practices

g

Food Security

Figure 1. Tackling food insecurity (Courtesy of Frost & Sullivan)


86 EFFICIENCY MATTERS

Pumps make industrial

manufacturing possible.

Every day, thousands of

industries around the world rely

on various pumping technologies

to move raw materials and end

products through the production

process. Whether handling lube

oils, paints and coatings, or

working in applications from

heat transfer to chemical

processing, pumps must reliably,

e� ciently and safely transfer an

array of � uids, all of which have

unique—and often challenging—

handling characteristics.

If a pump is the weak link in

the production process, the entire

operation will be compromised,

with the downtime required for

repair or replacement eating away

at production quotas and the

bottom line.

Industrial manufacturers can

choose from a wide range of pump

options when out� tting their

facilities. A number of factors

also go into choosing pumping

technology. Operational reliability

and the ability to meet speci� c

� uid-handling requirements

are among the most important.

With manufacturing operations

governed by operating budgets and

expenses, equipment acquisition

costs and subsequent maintenance

are also primary concerns.

While all pumping technologies

can have positive points in

Image 1. In order to fashion a handling and transfer operation that optimizes reliability, effi ciency and safety, many chemical processors are making the decision to install internal gear pumps. (Images courtesy of PSG)

Internal Gear Pumps Handle Harsh Conditions

These pumps offer effi ciency and reliability in complex industrial operations.

By Chrishelle Rogers

Maag Industrial Pumps


87

industrial manufacturing

operations, positive displacement

internal gear pumps can o� er

precise and consistent transfer of

demanding � uids.

Chemical processing and

manufacturing is one of the most

complex industrial operations. � e

chemical manufacturing process

is so intricate that it is comprised

of several unit operations,

from cracking, distillation and

evaporation, to gas absorption,

scrubbing and solvent extraction.

Within that family of unit

operations, � uid transfer

touches every stage of the

manufacturing process and is vital

for overall process success. Often

oversimpli� ed as “transporting

� uid from one point to another,”

� uid transfer in chemical

manufacturing is much more.

Fluid transfer includes a

spectrum of applications, with

responsibilities all along the

chemical production chain. For

example, thin or viscous raw

materials can be transferred to

storage tanks or blending and

mixing tanks. Final formulations

can be transferred to holding

tanks, and � nished products can

be loaded into intermediate bulk

containers (IBCs) for delivery or

consumer packaging.

In many cases, chemical

manufacturing processes require

the use of dangerous substances,

such as strong acids, caustics,

solvents, resins and polymers.

Despite their inherent danger, these

are necessary for the manufacture

of thousands of consumer goods

or to facilitate other industrial

processes. � e challenge when using

dangerous chemicals is to construct,

handle and transfer them in a safe

and reliable way.

Fortunately for chemical

processors, positive displacement

Image 2. No acid, polymer, resin or caustic has the same handling characteristics, which makes pump versatility a primary concern for chemical processors. These internal gear pumps overcome many handling concerns by featuring a method of operation that can successfully and safely transfer fl uids of differing viscosities and chemical makeups.

For more information, please go to:

psgpumps.com/ps815mip

EnviroGear® and G Series Internal Gear Pumps o er you highly reliable and versatile pumping solutions for a wide range of applications, from thin to viscous � uids. With � eld-proven technology that’s safer, greener and interchangeable with competitive technologies, the G Series and EnviroGear line of pumps are the workhorses you’ve been looking for!

PSG 22069 Van Buren Street

Grand Terrace, CA 92313-5651P: +1 (909) 422-1731

psgdover.com

VersatilityReliabilityand

Improve

EnviroGear

• Lowest overall cost of ownership

• 50% reduction in maintenance costs

• Single fluid chamber design eliminates leaks

• Patented between-the-bearing support greatly improves reliability

G-Series

• Best-in-class delivery

• Interchangeable with competitive models

• Flexible design for easy installation

• Multiple seal options available

• Available in cast iron and stainless steel

Where

Innovatio

n Flows



88 EFFICIENCY MATTERS

internal gear pumps have continually

o� ered the reliability and cost-

e� ectiveness required for handling

raw materials and � nished products.

One manufacturer has created an

internal gear pump with a simple

design that includes only two

moving parts, a pair of coinciding

gears called the rotor and idler, for

precise and consistent transfer of

demanding � uids.

� is design creates a four-step

operating process:

1. � e rotor and idler gears

un-mesh at the suction port to

create an atmospheric vacuum

that draws � uid into the pump.

As the rotor turns, the � uid is

forced between the rotor teeth

and idler teeth.

2. Continual rotation of the rotor

forces the � uid through a

crescent-shaped area within the

wetted path. � e crescent-shaped

area divides the � uid and acts as

a barrier between the inlet and

discharge ports.

3. As the rotor continues rotation,

the � uid is forced past the crescent-

shaped area and moves toward the

discharge port.

4. As the rotor completes its

rotation, the rotor and idler teeth

engage, forcing the � uid through

the discharge port of the pump.

� is method allows the pumps

to operate equally well in either

direction, resulting in a positive,

non-pulsating � ow of the pumped

� uid. Other design features

include a rotatable pump casing

that allows for multiple inlet and

outlet port positions and single-

point end-clearance adjustment. It

also features an enlarged bearing

housing at the rear of the pump

that allows easy drive-end access

to the shaft seal.

Image 3. Internal gear pumps feature a unique design that features only two moving parts, a rotor and idler gear, which allows them to operate equally well in either direction and deliver positive, non-pulsating fl ow of the liquid being handled.

DISCOVER BETTER DESIGNS.

FASTER.FOR OPTIMAL PUMP PERFORMANCE

AUTOMATE YOUR DESIGN SPACE EXPLORATION WITH CFD

www.cd-adapco.com

[email protected]

VISIT US AT PUMP & TURBOMACHINERY SYMPOSIA AT BOOTH 1529/1531



89

Chemical processors must deal daily

with � uids that are di� cult to transfer.

� eir task is to create a handling and

transfer regimen that includes pumping

equipment compatible with many di� erent

types of dangerous chemicals while also

o� ering reliable operation and cost-

e� ectiveness with regard to maintenance,

repair and downtime.

Chrishelle Rogers is the global gear pump product manager for Maag

Industrial Pumps, Grand Terrace, California, and PSG, Oakbrook Terrace,

Illinois. Rogers can be reached at 909-222-1309 or chrishelle.rogers@

psgdover.com. For more information, visit psgdover.com.

Image 5. Fluid transfer touches every stage of the manufacturing process and is vital for overall process success.

Image 4. Internal gear pumps feature a unique design that have only two moving parts, a rotor and idler gear, which allows them to operate equally well in either direction and deliver positive, non-pulsating fl ow of the liquid being handled.



90 MAINTENANCE MINDERS

Every oil and gas facility

is comprised of critical

equipment and processes

that must operate reliably for

successful production. One

loose bolt or faulty thermostat

can result in equipment failure

and downtime. To prevent these

catastrophic events, many

facilities are turning to modern

software solutions that allow them

to remotely monitor equipment

conditions and detect faults before

they result in costly damage.

� e two examples below show

how early fault detection using

remote monitoring software can

save oil and gas facilities valuable

time and money.

Broken Valve Bolt

On March 13, a remote monitoring

software solution identi� ed a

sudden and sustained rise in the

number of impacts over time on a

reciprocating compressor.

Values for this sensor were

expected to stay near 0 for

sustained periods of time. � e

software provider’s reliability

center noti� ed the end user of this

issue during their scheduled

weekly call.

When the operators

investigated the issue, they found

that valve center bolts had broken

on three separate valves. Parts of

one of the bolts had fallen into the

cylinder head and were damaging

the piston.

� e debris from the broken

bolts could have caused a

catastrophic failure of this

compressor and could have

resulted in the compressor

requiring a complete overhaul.

Because the issue was detected

early, the user was able to replace

the piston and valves and return

the machine to service.

Faulty � ermostat &

Low Oil Level

In early July, this same software

solution detected a drop in lube

oil pressure on a reciprocating

compressor at another oil and gas

facility well before the pressure

reached the shutdown limit.

Given the operating conditions,

lube oil pressure values were

expected to operate between 55

and 60 pounds per square inch

gauge (PSIG) (4.8 and 5.2 bar). � e

software provider immediately

sent a noti� cation to the user

when the lube oil pressure

dropped to 48 PSIG (4.3 bar) and

discussed the issue on the next

weekly call. Actual values for lube

oil pressure continued to drop

as low as 33 PSIG (3.3 bar). � e

Oil & Gas Facilities Detect Costly Faults Early

A software solution alerted two end users of problems with their reciprocating

compressors, saving time and money.

By Cynthia Stone


91

shutdown limit for the asset was

at 30 PSIG (3.1 bar).

When the facility investigated

this issue, they discovered a

thermostat that was getting

stuck and causing the lube oil to

not be properly controlled. � e

user replaced the thermostat and

reported this maintenance action

on the next weekly call.

However, the software

provider’s reliability center

was not able to verify that the

facility’s maintenance action

was fully successful because

actual values had not returned

to expected values. A follow-up

maintenance action, performed

by the user, identi� ed a second

issue—the lube oil tank level

was low. � e user re� lled the lube

oil tank.

Loss of proper lube oil could

cause catastrophic damage to

the reciprocating compressor,

leading to a loss of production.

In this case, the facility received

several days of warning, which

allowed them to investigate

and correct the issue before any

damage occurred to the machine

or the drop in oil pressure reached

the low-pressure shutdown

limits. � e user was also able

to receive veri� cation that

both maintenance actions were

e� ective at correcting this issue

by seeing the actual values return

to expected values.

Cynthia Stone is a product

marketing manager for Industrial

Data Intelligence at GE. She has

nearly a decade of experience

working in predictive analytics

for power, oil and gas,

mining and aviation.

Stone may be

reached at cynthia.

[email protected].

The debris from the broken bolts could have caused a catastrophic

failure of this compressor and could have resulted in the

compressor requiring a complete overhaul.

Check out past Maintenance Minders

articles to read about the following topics:

• How monitoring software enables

scheduled mainteance

• How remote monitoring prevents valve

failure at combined-cycle power plants

• How turbine error identifi cation stops

costly power plant outage

• How system component malfunctions

lead to higher pump speeds with

stagnant fl ow rates

Next month’s Maintenance Minders will

discuss how remote monitoring software

detected a wiped bearing on a feedwater

pump as well as an operational issue

on a lube oil pump at combined-cycle

power plants.

READ MORE ONLINE AT

pumpsandsystems.com/mmgeip



92 MOTORS & DRIVES

Energy e� ciency has become

a major focus for the U.S.

government, municipalities,

power utilities and the industrial

sector, with much of the attention

falling on components such as

motors and pumps. For end users,

understanding the di� erence

between component e� ciency

and system e� ciency as applied to

motor-driven equipment is critical

for evaluating a total system and

making appropriate upgrades. � e

Energy Independence and Security

Act (EISA) is one standard that

users must understand and comply

with to successfully improve

system e� ciency.

E� ciency Standards as

De� ned by EISA

For each general-purpose

rating (Subtype 1) from 1 to

200 horsepower (HP) that was

previously covered by EPAct, the

law speci� es a nominal full-

load e� ciency level based on

National Electrical Manufacturers

Association (NEMA) premium

e� ciency as shown in NEMA MG

1, Table 12-12. All 230- or 460-volt

(and 575-volt for Canada) motors

currently under EPAct that were

manufactured after December 19,

2010, must meet or exceed this

e� ciency level.

General-purpose electric

motors (Subtype II) not previously

covered by EPAct will be required

to comply with energy e� ciencies

as de� ned by NEMA MG 1, Table

12-11. � e term general-purpose

electric motor (Subtype II) refers to

motors that incorporate the design

elements of a general-purpose

electric motor (Subtype I) that are

con� gured as one of the following:

• U-frame motor

• Design C motor

• Close-coupled pump motor

• Footless motor vertical solid

shaft normal thrust motor (as

in a horizontal con� guration)

• An 8-pole motor (900 rpm)

• A poly-phase motor with

voltage of not more than

600 volts (other than 230 or

460 volts)

Motors that are 201 to 500

HP that were not previously

covered by EPAct will be required

to comply with energy e� cient

e� ciencies as de� ned by NEMA

MG I, Table 12-11.

� is information and the Tables

referenced above are readily

available on the Department of

Energy (DOE) website.

So, what does the new EISA

Standard have to do with system

e� ciency? Many end users

believe that any system e� ciency

improvement is the result of

an increase in motor e� ciency;

however, that is not always the

case. For example, consider a

centrifugal pump system operating

at a � xed speed. � e system

requires variable � ow and is

controlled by a motor-operated

valve. One might believe that

replacing the standard-e� ciency

motor with the new EISA premium-

e� cient motor would lead to an

incremental gain in e� ciency and

a lower operating cost. � is seems

reasonable, but more factors must

be considered.

In order to meet the EISA

standard, motor original

equipment manufacturers (OEMs)

had to redesign their equipment

to achieve the increased e� ciency

as mandated by government

regulations. To understand what

is meant by “increased e� ciency,”

users must know the de� nition of

a premium-e� ciency motor and

what a� ects that e� ciency.

Motor Losses

Losses in a motor include stray

losses, rotors, stators, core losses

and fan design (windage).

To make a motor more e� cient,

a manufacturer must add more or

better material. � ese additions

and adjustments could include

more active material such as

copper in the winding, a longer

stator, rotor cores and improved

electrical steel (silicon steel is

used for the stator and rotor). A

Understanding System Effi ciency in Motor-Driven Rotating Equipment

Users should consider system changes to comply with the new EISA standard.

By William Livoti


93

low-loss fan design could also be

used to reduce friction and windage

losses. To reduce the stray load

losses, manufacturing processes

are assured through International

Organization for Standardization

(ISO) 9001 procedures.

Some advantages of energy

e� cient motors are:

• Maximum E� ciency – Energy-

e� cient motors operate at

maximum e� ciency even when

they are lightly loaded because of

better design.

• Longer Life – Energy-e� cient

motors dissipate less heat

compared with standard motors.

Use of energy-e� cient fans

keeps the motor at a lower

temperature, which increases

the life of the insulation and

windings as well as the overall

life of the motor.

• Lower Operating Cost – � e

total energy cost of energy-

e� cient motors during its

life cycle is much lower when

compared with conventional

motors.

• Other Bene� ts – Energy-

e� cient motors have better

tolerance to thermal and

electrical stresses, the ability to

operate at higher temperatures,

and the ability to withstand

abnormal operating conditions

such as low voltage, high voltage

or phase imbalance.

System E� ciency

Energy-e� cient motors can also

improve system e� ciency, but

end users must consider the

following factors:

• Motors meeting higher

e� ciencies tend to run faster

than their less e� cient

counterparts.

• Matching speeds to application

need (such as pump � ow) is

important to consider.

• Drives may be required, which

o� ers the opportunity to

increase system e� ciency in

applications with variable output

requirements. Variable frequency

drives (VFDs) require further

considerations for optimum

reliability and e� ciency.

• In some cases, mounting

dimensions for motor into

machinery may be slightly

di� erent.

Case Study

� e following case study graphically

illustrates the impact of a premium-

e� cient motor in a centrifugal

pumping application.

Figure 1 (page 92) provides four

separate scenarios for reducing

energy consumption in a cooling

tower pumping system. � e

portrayed system is a typical closed

loop con� guration where the

discharge is being throttled over a

range of operation. � e system in

this example operates 24/7, 365

days per year. At this particular

load point, that means it operates

70 percent of the time—or 6,250

hours per year.

Columns 1 and 2 in Figure 1

indicate the various components

factored into the system e� ciency

calculation. Column A is the

base condition where the system

operates 50 percent of the time.

� e component e� ciencies for the

VFD and gearbox are at 100 percent

because they were not used.

Under the base condition,

the total power required is

approximately 1,777 HP; almost

356 HP is being lost (wasted) across

a control valve. In addition, the

pump is operating back on the curve

at 65 percent e� ciency. Under

these conditions, the total system

e� ciency is 49 percent.

Column B provides the new

operating conditions with the

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94 MOTORS & DRIVES

addition of a VFD. � e head required

has been reduced to 150 feet because

the loss across the valve has been

eliminated by reducing the speed of

the pump to meet required system

demand. Motor e� ciency remains the

same, and a 2 percent loss has been

added as a result of heat generated

across the drive. Note the dramatic

improvement in the overall system

e� ciency (81 percent) and the

total operating cost reduction from

$414,306 to $187,360. � e total cost

savings is $226,946 per year.

Column C addresses the impact on

the system by improving the e� ciency

of the pump. Nothing else in the

system was changed.

� e minimal improvement of the

overall system e� ciency (53 percent)

results from increasing the pump

e� ciency by 5 percent. � e 50 feet

of head loss across the control valve

remains, so the total power required

is 1,650 HP. � is scenario does not

present huge savings based on the cost

of a new pump and installation and

potential piping changes. Factor in the

ongoing reliability issues, such as the

pump operating back on the curve, and

$29,593 would be di� cult to justify.

Column D identi� es potential

savings when motor e� ciency is

improved by 2 percent. Again, nothing

has changed in the system with the

exception of an additional 5 feet of

friction loss across the valve as a

result of the reduced slip in the

premium-e� cient motor (head

increases to the square of the

speed). In this case, the system

e� ciency remains the same at

49 percent. Note that the power

required for the additional friction

has increased to 330 HP. � e total

power required was reduced to

1,650.2 HP (a reduction of 127

HP) with a total savings of $518

per year.

References

1. EISA Standards Department of Energy

2. WEG Electric

William Livoti is the power

generation business development

manager for

WEG Electric

Corporation. Livoti

may be reached at

[email protected].

Figure 1. Four separate scenarios for reducing energy consumption in a cooling tower pumping system (Courtesy of WEG)



95

Compression packings have

su� ered from a reputation

of being an old-fashioned

technology unsuited to modern

industrial processes. In the case of

rotating equipment, they are largely

superseded by mechanical seals. In

particular, many believe packings are

ine� cient because of high frictional

losses. Much of this perception

is based on outdated products

and not on modern types that

use sophisticated synthetic yarns

combined with complex lubricants.

� is article describes the

development of a straightforward

test procedure for compression

packings used in rotary applications.

� e procedure was used to study the

frictional characteristics of several

packing types in comparison with

various mechanical seals using a

test rig speci� cally designed for

the purpose. � e results from the

friction testing on a number of

packing types and mechanical seals

will also be discussed. � ese results

call into question the theoretical

methods currently used to calculate

packing friction.

Test Procedure Development

As early as 2004, the European

Sealing Association (ESA) along

with its U.S. counterpart, the Fluid

Sealing Association (FSA), formed a

joint task force to develop a realistic,

performance-based test method for

compression packings used in rotary

applications. � e driving force for this

project was to enable manufacturers

to publish true comparative data on

packing performance and allow end

users to better di� erentiate between

products when making selections for

their applications.

� e speci� cation was developed

through a number of iterations. At

each stage, the validity, accuracy

and repeatability were tested using

“round-robin” tests. Each member

company tested the same product

from a single source, and the results

were compared. Any deviations

from consistency were discussed

and the speci� cation re� ned for the

next validation round. To maintain

impartiality, all of the test results

were submitted to an independent

body for analysis—French research

organization Centre Technique des

Industries Mécaniques (CETIM),

who also carried out their own tests

in each round. Figure 1 shows a

typical test setup.

� e � rst drafts of the speci� cation

allowed test conditions that re� ected

those commonly encountered in

� eld applications but with water

as the test medium. � e following

parameters were to be measured and

recorded at speci� ed intervals during

each test run after the break-in

period and at the end of the test:

• Total leakage (milliliters)

• Leak rate (milliliters per hour)

• Gland temperature (degrees

Celsius)

• Number of gland adjustments

• Amount of each adjustment

(millimeters)

• Normalized power consumption

(watts per millimeter squared)

Energy Effi ciency of Compression Packings in Rotodynamic Pump ApplicationsBy Henri Azibert

FSA Technical Director

Figure 1. Typical test arrangement (Images and graphics courtesy of FSA)

SEALING SENSE


96 SEALING SENSE

Leakage from the static outer side

(gland) and the dynamic inner side

(shaft) was recorded separately.

For the � rst series of tests,

the packing selected was one of

known good performance and of

material and construction typically

used by all of the participating

manufacturers. A graphite/

expanded polytetra� uoroethylene

(ePTFE) cross-plaited packing was

selected, and test packings were

manufactured by one manufacturer

from the same batch of yarn to suit

each of the participants test rigs.

� e general trends from these

early tests provided composite

results for 12 tests at six test

facilities under the same conditions

of 6 bar pressure for 100 hours at

di� erent speeds. While consistency

within each individual laboratory

was satisfactory, the variation

between them was substantial.

� e speci� cation was, therefore,

re� ned to better control the test

conditions and procedures, and the

importance of the initial � tting of

the packing and the break-in period

was emphasized.

� ree leakage classes were

introduced to allow for di� ering

target leakage levels depending

on the criticality of the intended

application area of the packing.

• L1 = less than or equal to 5

milliliters per minute (ml/min)


ml/min


ml/min

Gradually, other packings were

tested and eventually a � nal

speci� cation was reached. Figure

2 shows results from testing a

graphite/ePTFE packing under the

� nal speci� cation conditions, with

good repeatability of results.

� e � nal speci� cation was

issued and is freely available to

download from the FSA website. � e

speci� cation was also put forward

to CEN Technical Committee TC

197 – ‘Pumps’ to be adopted as a

full European Standard. � is was

approved, and TC 197/WG 3 has

prepared a Final Draft EN 16752

Centrifugal pumps- Test procedure

for seal packings, which is currently

going through the standardization

approval process and should see

� nal publication in 2015.

Power Consumption

While the � nal test procedure

produced good correlation of

results in terms of packing leakage,

temperature and post-test packing

condition, the one performance

aspect that continued to cause

debate was frictional level and

power consumption. � roughout

the round-robin test program

the results reported for frictional

torque or absorbed power showed

signi� cant variability, partly

because of the di� erent methods

used to measure it.

� is uncertainty about packing

friction is concerning, because the

generally accepted wisdom is that

packings are ine� cient in terms

of power consumption. But little

research has been conducted on

the more sophisticated products

currently available that use

exfoliated graphite, ePTFE, aramid

and other synthetic yarns and

modern lubricant systems.

To obtain de� nitive information

on packing friction, the joint

ESA/FSA Technical Task Force

commissioned CETIM to carry

out a follow-up project. It consists

of the design and manufacture of

a dedicated test rig to carry out

testing in accordance with the

procedure, including highly accurate

systems to directly measure the

frictional force of the packing alone.

Test Rig

� e test rig is designed to test

both compression packings

and mechanical seals so direct

comparison can be made under

the same conditions (see Image

1, page 98). A torque meter is

used to record the mechanical

seal or packing friction on the

shaft. Measurements of torque,

temperature and leakage levels are

Figure 2. Results from round-robin 5


97



98 SEALING SENSE

recorded, and the instrumentation

permits continuous monitoring of

all parameters throughout the test.

Initial Testing

After initial trials to validate

the equipment functionality and

accuracy of the monitoring devices,

the � rst tests were carried out on

the same graphite/ePTFE packing

that had been widely used during

the earlier test program.

Testing was conducted at

di� erent rotational speeds and

pressures, with varying target

leak rates. For direct comparison,

a typical unitized, single-spring

elastomer bellows mechanical seal

was also tested under a range of

conditions. It is an unbalanced

mechanical seal with carbon

graphite versus chromium oxide

seal faces.

� e measured torque is plotted

for di� erent water pressures, in

the case of the packing with the

associated shaft leak. During these

tests, the gland leak rate was of the

same order of magnitude as that of

the shaft.

� ese results were unexpected. � e

� gures for packing were much lower

than predicted and were of the same

order of magnitude as, and generally

lower than, the mechanical seal.

Of course, a degree of leakage must

be tolerated when using packings,

and the lubrication a� orded by

the leaking � uid will reduce the

friction. But even when the leak

rate is extremely low, as in the case

at 6 bar and 1500 rpm, the friction

recorded was the same as that for the

mechanical seal at a lower pressure.

Rigorous checks were carried out

to ensure the accuracy of the results.

In particular, the measurement

range of the torque meter was

revised to ensure accuracy at these

much lower torque levels, and it

was veri� ed that the torque levels

measured for mechanical seals

were generally in line with the

manufacturer’s published data.

Further Tests

A further series of tests was carried

out on two other packing types and

four mechanical seal variants. � e

packings were a lubricated natural

ramie � ber, which would normally

be used where higher leakage would

be acceptable, and a synthetic

aramid yarn packing.

� e mechanical seals were one

unbalanced and two balanced

component seals and a cartridge

balanced seal. � ey were chosen

to represent a cross section of

commonly used designs. � ese

featured carbon graphite versus

silicon carbide seal faces. � is face

combination is typically chosen for

its low coe� cient of friction. � e

designs had di� erent balance ratios,

and two had a composite narrow

seal face and the other two had a

monolithic narrow seal face.

All tests in this sequence were

carried out at 6 bar pressure. � e

comparative results are shown in

Figure 3.

Some of the results for the

mechanical seals were unexpected.

� e unbalanced mechanical seal

showed lower torque than the

balanced O-ring pusher seal.

� e di� erence can most likely

be explained by the fact that the

face pro� les are di� erent for the

composite seal face of the balanced

seal than the monolithic design of

the unbalanced seal.

Typical thermal de� ections are

di� erent for these variations in

design. � e composite faces tend to

have a divergent pro� le with outside

contact, while the monolithic

face tends to have a convergent

pro� le with good � uid penetration

between the faces. � e pressure

drop between the seal faces is

di� erent, leading to higher e� ective

hydraulic closing forces for the

outside contact than for the inside

contact. Di� erent spring loads for

the designs, which are di� cult to

set accurately in component seals,

would also have a signi� cant impact

on contact pressure.

� is illustrates two major

points. First, speci� c designs have

speci� c characteristics, and broad

classi� cations are not su� cient to

evaluate the power consumption

of one type of design. Second, the

pressure drop between the sealing

interface is critical in determining

the actual power consumption

of the sealing device. � is should

be considered with packing and

mechanical seals.

� e packing friction compares

favorably with all of the mechanical

seal variants. � ese unexpected

results have led to a reconsideration

of the traditional methods for

calculating packing friction.

Image 1. Friction test rig


99

� eoretical Considerations

� e formula that has long been used

to calculate power consumption

from compression packing systems is

as follows:

P= Pp x RPM x D x µ x Ap x F

Where

P = Power (HP or kilowatts,

depending on units used)

Pp = sealed pressure

RPM = rotational speed

D = shaft diameter

µ = coe� cient of friction

between the packing and

the shaft

Ap = packing contact area

F = factor, depending on

units used

� is formula is similar to the

one used for mechanical seals,

which has been shown to give

a good approximation to power

consumption levels.

Recognized approximations in

the packing formula are that it

does not take account of lubricant

levels, actual packing compression,

type of liquid sealed, viscosity or

temperature. But it can provide a

� gure for the amount of energy

consumed by the packing. It tends

to give power consumption levels

that are approximately 10 times

that of a balanced mechanical seal

used under the same conditions.

Test results show that the

approximations in the formula

are not su� cient to explain the

deviations from the calculated

values.

� e di� erences in calculated

results from the test measurements

reported here vary by factors from

25 to 100 times.

While more work is planned, the

conventional wisdom contained

assumptions that are not veri� ed

through the experiments. � us, the

use of sealed pressure as the contact

pressure for the packing along its

entire axial length must be revised.

A pressure drop coe� cient of 0.2

gives much better correlation of

calculated to testing results.

� e coe� cient of friction must

also be re-evaluated when current

advanced synthetic � ber materials

are used.

For example, a coe� cient of

friction value of 0.03 for ePTFE/

Graphite packing is more in

agreement with testing results than

the traditional value of 0.17. Other

variables must also be considered,

such as shaft speed and size as well

as leakage levels because they have a

direct impact on power consumption.

Further Work

Some further test work is planned

on other packing types. � e major

thrust of this work is to develop

a mathematical model that will

provide an accurate tool for the

calculation of packing power

consumption. A revised formula

will be � nalized once testing is

completed.

� e unquestioned switch from

compression packing to mechanical

seals to save energy in sealing

systems must be reconsidered.

Users must take many factors into

account when using one technology

versus the other, including periodic

maintenance, the availability of

trained maintenance personnel

and permissible leakage levels.

But frictional energy saving is not

as important as conventionally

viewed. � e choice of which

technology to use must encompass

all aspects of performance based on

real results rather than perception.

Acknowledgements

� e author would like to express his

appreciation to all of the ESA and

FSA member companies involved

in this project, in particular the

members of the joint ESA/FSA

Packings Technical Task Force and

David Edwin-Scott of the European

Sealing Association (UK), and Didier

Fribourg of the Technical Center

for Mechanical Industries – CETIM

(France).

Next Month: How to Achieve

Zero Emissions with Mechanical

Seals

We invite your suggestions for article topics as

well as questions on sealing issues so we can

better respond to the needs of the industry.

Please direct your suggestions and questions to

sealingsensequestions@� uidsealing.com.

Figure 3. Tests at 6 bar


100 HI PUMP FAQS

What dynamic analysis

considerations are

recommended for the

petroleum market?

End users should evaluate

their need for dynamic analysis by

considering the level of proven

� eld experience available for

any given con� guration. � e

vendor and user should agree on

which types of analysis should be

performed at any level. Lateral,

torsional and structural analyses

are three identi� able and normally

separable deliverables.

In all cases, it is the user’s

prerogative to specify additional

tests, validations and/or analyses

to further mitigate risk.

Historically, dynamic analysis

trends have developed within

the various pump application

markets because of the types

and characteristics of equipment

typically used and as a result

of past experiences. In the oil

and gas industry, single-stage

overhung horizontal pumps and

between-bearings, one- and two-

stage pumps must be designed

to be classically rigid, which can

eliminate the need for lateral

dynamic analysis.

Multistage pumps identical to

pumps proven in-� eld are also

not subject to lateral analysis.

Vertically suspended pumps are

required to be designed with

established limits on bearing

spacing to ensure suitable lateral

rotodynamic performance.

Drive system con� guration and

power levels determine the need

for torsional dynamic analysis.

High-energy, high-speed,

critical-service and unspared

machines are subject to high

levels of customer intervention

and scrutiny, with the user having

varying de� nitions of these terms.

For more information on

dynamic analysis, refer to

ANSI/ HI 9.6.8: Rotodynamic

Pumps Guideline for Dynamics of

Pumping Machinery.

What piping installation

recommendations are

important to consider for

rotary pumps?

Because rotary pumps are

designed with close running

clearances, clean piping is a must.

Dirt, grit, weld bead or scale, later

� ushed from an unclean piping

system, will damage and may

seize the pump. Figure 3.4.3.11

illustrates pipe-to-pump

alignment considerations.

Piping should be installed on

supports independent of the

pump. Supports must be capable

of carrying the mass of the pipe,

insulation and the pumped � uid.

Supports may be hangers, which

carry the mass from above, or

stands, which carry the mass

from below.

Clamps or brackets may

be used to secure piping to existing

columns. Supports must allow free

movement of the piping caused by

thermal expansion or contraction.

Dynamic Analysis in the Petroleum Market & Piping Installation for Rotary Pumps By Hydraulic Institute

Figure 3.4.3.11. Pipe-to-pump alignment (Courtesy of Hydraulic Institute)


101

Supports should be installed at intervals that

uniformly and amply support the piping load,

precluding contact with piping and equipment.

Pipe strains or stresses transmitted to the pump

by improper piping support systems may cause

distortion, wear or binding of the rotary members

and excessive power requirements.

Piping systems that contain expansion joints must

be designed so the expansion joint is not exposed

to more motion than accounted for in its design.

Expansion joints or � exible connectors should not be

used to compensate for misaligned piping.

� readed joints should be coated with compounds

compatible with, but not soluble in, the pumped

liquid. End users working with Te� on-taped joints

should be careful to prevent shredded pieces of

Te� on from entering the piping system. Piping

should start at the pump and work toward the

source of supply and the point of discharge. Shuto�

valves and unions are recommended to facilitate

future inspection and repair. Reducers are preferred

to bushings when a change in pipe size is necessary.

Avoid unnecessary restrictions in the pipeline, such

as elbows, sharp bends, globe or angle valves, and

restricted-type plug valves.

Users should predetermine pipe size by taking

into account the required � ow rate; minimum

or maximum velocities; the � uid viscosity at the

lowest pumping temperature; the length of the

piping system, including valves, strainers and other

restrictions; and the elevation of the pump with

reference to supply and discharge points.

HI Pump FAQs® is produced by the Hydraulic Institute as a service to pump users, contractors, distributors, reps and OEMs. For more information, visit pumps.org.

Find more HI Pump FAQs online at

pumpsandsystems.com/

tags/hi-pump-faqs.



U N M AT C H A B L E E X P E R I E N C EI N F L O W C O N T RO L

T R A N S A C T I O N S

MEMBER FINRA, SIPC

Jordan, Knauff & Company is a knowledgeable and experienced provider of a comprehensive line of investment banking services to the pump, valve and

Our lines of business include: selling companies, raising debt and equity capital, and assistance

To learn more about Jordan, Knauff & Company, contact any member of our Flow Control

Managing Principal Senior Associate

102 PRACTICE & OPERATIONS

For more than 100 years,

Wisconsin sand has been

prized for industrial

applications—including metal

casting, construction and

consumer products such as

iPods. Now, the sand has found

new applications in hydraulic

fracturing, or fracking. During

fracking, pumps open up deep rock

formations using a high-pressure

mixture of solutions such as sand

and water. � e sand opens the

rock, releasing oil and gas deposits

for extraction.

White Wisconsin sand works

well in hydraulic fracturing

applications. � e large grains

and round shape better open

� ssures, allowing more successful

extraction of fossil fuels.

In 2015, energy companies will

use more than 2.6 million tons of

sand in exploration & production

(E&P) activities. Demand for sand

has increased more than 40 percent

since 2011.

Challenges

A remote Wisconsin sand mine

experienced pump deterioration

from the abrasive sand. Because

of the harsh Midwest winters,

the mine only operates from

April 1 to � anksgiving. During

operating season, the plant is

scheduled to run 24 hours per day

to maximize production.

Initially, the plant used vertical

turbines on the wet side of the

process, where the sand was

washed, scrubbed of impurities

and sized. � e wash removes

metals and small particles of silica.

Afterward, the sand moves to the

dry side, where it dehydrates in

speci� c storage areas based on its

composition. � e sand is inspected

and tested after drying. Rail cars

transport the sand to frac sites for

mixing and injection.

� e process water is recycled,

reducing the plant’s costs and water

needs. While the process removes

the large particles for sale, the

� ne particles remain suspended

in the recycled water. Over time,

this microscopic slurry attacks

the bronze-� tted vertical turbine.

Particle accumulation around

the seal leads to failures, and the

residue eventually reduces pump

� ow. � e grit forces openings in the

rubber bushings, allowing water

to escape. Eventually, the turbine

shuts down, ceasing all operations.

Because of constant operation,

the turbines failed frequently

as � ne particles accumulated

quickly. � e sand mine incurred

major expenses from repairs and

lost productivity.

Patented Solutions

A pump distributor working

with the plant operator o� ered a

centrifugal pump with a specialized

mechanical sealing system, slurry-

resistant construction material and

superior solids-handling capability.

Unlike the seals in the vertical

turbine, the pump’s mechanical

sealing system uses vanes cast

into the impeller to wash away

� ne particles behind the impeller.

Specially angled de� ector vanes

on the dished backplate create

a cyclonic action, which pulls in

the particles. � e mechanical seal

system provides greater reliability

without the need for � ush water or

additional gauging systems.

� e pump has 10-inch suction

and 8-inch discharge and features a

Centrifugal Pump Saves Sand Mine More than $1.5 Million

The mechanical seal system, among other features, reduced downtime at the Wisconsin plant.

By Chris Dunn, Crisp Industries,

& Bill Schlittler, Cornell Pump Company

Image 1. This remote Wisconsin sand mine experienced pump deterioration from the abrasive sand. (Images courtesy of Cornell Pump Company)


103

cast-iron impeller and volute. More

resilient than the bronze � ttings

on the turbine, the cast iron

helps the pump better withstand

the silica slurry. � e pumps also

include a 416 stainless shaft and

sleeve as well as deep groove

bearings rated for at least 50,000

hours. � e unit can handle heads

up to 360 feet, � ow rates up to

8,000 gallons per minute and solids

up to 3.38 inches in diameter.

Additional Features

� e pump also features a dry-

priming system with a vacuum

assist. If the pump loses prime,

the system engages the assisting

vacuum pump to draw sand into

the volute. When normal operation

resumes, the system disengages.

Unlike a venturi system, this

dry-priming method does not

materially a� ect e� ciency.

An oil reservoir can lubricate the

pump’s seal faces if it loses prime.

With the dry-priming vacuum,

the system protects the seal faces

from heat and cracking that could

occur without pumpage to lubricate

it. When the system reprimes,

the gland disengages. � e system

is self-contained and does not

spill over into the pump stream.

� e pump can run dry for hours

without damaging the seal faces.

� e new centrifugal pump was

more e� cient than the vertical

turbine—hitting the same design

and � ow speci� cations while

requiring less energy and saving

operation costs. � e motor for

the centrifugal pump is readily

available in nearby Milwaukee or

Minneapolis, while the motor for

the turbine required a signi� cantly

longer lead time to order.

Millions Saved

Since installation in March 2014,

the plant has run continuously.

With the previous turbines, the

plant would have experienced

at least 60 hours of downtime.

Processing more than 600 tons an

hour meant the plant would have

lost the opportunity to process

more than 36,000 additional tons

of sand in a year. With high-quality

hydraulic fracturing sand selling at

more than $50 a ton, the new

pump helped save more than a

$1.5 million dollars of downtime

losses in a year.

� e plant operator plans to

open several more locations in

2015, and because of the success

of this system, each facility will

be installed with 8- or 10-inch

versions of the new pump.

Bill Schlittler, PE, is mining

market manager at Cornell Pump

Company—a Clackamas, Oregon,

manufacturer of centrifugal pumps.

Schlittler has more than 30 years

of experience as a mining engineer,

specializing in slurry

applications. He may

be reached at 503-653-

0330 or bschlittler@

cornellpump.com.

Chris Dunn is general manager of

the Pipe and Pump Division of Crisp

Industries. With more than 20 years

of experience, Dunn has serviced

many mining and fracking sites and

is active in applications

across North

America. He may be

reached at cdunn@

crispindustries.com or

940-683-4070.

Images 2 and 3. Because of harsh Midwest winters, the mine only operates from April to November, when the plant is scheduled to run 24 hours per day. The constant operation requires reliable equipment with superior solids-handling capability.



104 PRACTICE & OPERATIONS

While instrumentation

and monitoring

software are widely used

in manufacturing facilities around

the world, these tools alone will not

solve every production problem.

In addition to software and other

resources, the � eld workforce

plays a major role in the overall

e� ectiveness of a plant’s reliability

strategies.

� is is especially true in the

pump industry because pumps are

frequently located in remote or

di� cult-to-access locations. For this

reason, instrumentation and remote

monitoring software must be

combined with tools that empower

the � eld workforce to manage and

maintain systems reliably and

e� ciently. � is comprehensive

strategy can help � eld workers

increase their knowledge of system

processes and procedures, analyze

important equipment information,

and make well-informed decisions.

� e Importance of

Remote Monitoring

A comprehensive reliability strategy

is vital because two primary

elements make up nearly 80 percent

of the total cost of ownership (TCO)

of pumps: energy consumption

and maintenance activities (see

Figure 1). A variety of pumping

applications demonstrate that

remote monitoring of energy

consumption is critical to energy

optimization. In addition, remote

monitoring of the pumping

equipment can result in increased

uptime because of the ability to

prevent unexpected failures.

Because pumps represent more

than 50 percent of all energy

savings potential and consume

almost 25 percent of all motor

energy, energy savings is one

of the most clearly quanti� able

bene� ts of incorporating remote

monitoring into a facility’s

predictive maintenance strategy.

� e ability to monitor and adjust

system operation

to ensure

optimal energy

consumption is a

primary bene� t.

While data

collection through

remote monitoring

cannot improve

e� ciency on its

own, it is a critical

� rst step to closing

the loop around

process variables.

While remote

monitoring alone

cannot improve

e� ciency, as

part of a comprehensive reliability

strategy, it can help enhance

operational e� ciency in the long

run. For example, over time, pumps

may wear. � is degradation can

appear in the form of impeller wear,

pipe corrosion, reduced bearing

e� ciency and decreased system

e� ciencies, which may cause pumps

to operate well away from their

best e� ciency point (BEP). Remote

monitoring technology gathers data

that can indicate such changes in

operating conditions, allowing the

operator to adjust system speeds to

maintain BEP alignment. Figure 2

shows the impact of wear rings and

cavitation.

Figure 1. Typical pump life cycle cost profi le (Courtesy of Hydraulic Institute and Pump Systems Matter)

How Remote Monitoring Empowers Plant Employees

Modern monitoring software provides plants with the data they need to improve reliability while

empowering pump operators to make well-informed decisions.

First of Two Parts

By Jason Vick & Jack Creamer

Schneider Electric


105

Studies have shown that pump

maintenance accounts for 25

percent of a typical pump’s TCO.

All too often, end users discover

too late conditions that lead to

pump or motor breakdown or a

serious catastrophe that damages

equipment, cripples operations and

impacts employee safety.

Improving Predictive

Maintenance

Predictive maintenance can be

custom-designed for a user’s

speci� c system, built from regular

observation and recordkeeping

that can reveal trends and uncover

anomalies. When equipment is

commissioned, a facility may

create a pump health log to use as

a baseline for alarms and required

maintenance triggers during the

lifetime of the system. End users

can leverage this historical data

to take future actions to optimize

their operational e� ciency.

With minimal investment using

standard features built into a

variable frequency drive (VFD) or

other smart motor control system,

users can greatly expand reliability

and reduce operational costs. For

reference, users should remember

that pump equipment purchase

prices are estimated to account

for only 10 percent of the overall

lifetime expense of the system.

Monitoring Stranded Assets

Stranded assets, or assets that

are not instrumented or only

partially instrumented, are found

in industries such as re� ning,

upstream and midstream oil and

gas, petrochemical, metals and

mining, power generation and

distribution, water and wastewater,

pulp and paper, and discrete

manufacturing. In some cases,

stranded assets can make up as

much as 40 to 60 percent of a plant’s

total asset count. Because these

assets are not constantly monitored

electronically, � eld personnel must

monitor the equipment to ensure

that it remains safe and reliable.

In addition to stranded assets, a

host of regulations require that

personnel � ll out forms that ensure

compliance with such rules.

Many companies rely on

paper-based or experience-based

monitoring of stranded assets

and compliance activities. But

others have adopted advanced

mobile decision support software

applications that allow them to

collect, report and analyze non-

instrumented data.

Every option for remote

monitoring of stranded assets has

pros and cons. For every option,

however, users must decide how to

combine remote monitoring with

human interaction. For example,

when paper and experience are

relied on as the preferred methods

for monitoring stranded assets, � eld

workers often lack the situational

awareness to make well-informed

decisions. Di� erences in experience

level, miscommunication, training

de� ciencies or employee ownership

may result in poorly made decisions

that can lead to premature

equipment failures, unit shutdowns

or even worse—personal injury.

By contrast, when companies

adopt advanced mobile decision

support applications running on

mobile computers, they are able to

achieve the following:

• Positive asset/location

identi� cation

• Remote access to standard

procedures

• Heightened situational

awareness

• Advanced scheduling

• Visibility to non-instrumented

data

Positive asset and location

identi� cation are a key aspect

of remote monitoring. By using

mobile devices equipped with

barcode readers, radio frequency

identi� cation (RFID) readers, QBR

coding or global positioning systems

(GPS), mobile users can properly

identify an asset and access the

correct set of tasks they need to

complete for that asset. � e use of

positive asset identi� cation also

provides an audit trail if needed.

Jason Vick is the mobility

technical sales consultants

manager at Schneider Electric

where he is responsible for

providing mobile workforce

enablement technical

guidance and

best practices to

customers in many

vertical markets.

Jack Creamer is the segment

manager of the pumping equipment

sector for Schneider Electric—

Square D and an active member of

the Pumps & Systems

Editorial Advisory

Board. He may be

reached at jack.

creamer@schneider-

electric.com.

Figure 2. The impact of wear rings and cavitation (Courtesy of Schneider Electric)

106 PRODUCTS

To have a product considered for our Products page, please send the information to Amy Cash, [email protected].

Solids Measurement

Colonial Seal Company, a New Jersey-based specialty distributor of standard and custom sealing solutions, announces a range

of new design or replacement mechanical seals. � is includes elastomeric bellows seals, conical spring O-ring mounted seals, parallel spring diaphragms, balanced diaphragm seals, parallel spring O-ring mounted seals, wave spring type seals and water pump type seals. Circle 206 on card or visit psfreeinfo.com.

Mechanical Seals

Ashcroft Inc. announces the new G3 pressure transducer, which o� ers 316L stainless steel wetted material and absolute pressure measurement to ful� ll unique OEM sensor requirements. Available in ranges from 0/5 through 0/300 psi and vacuum, the application-friendly G3 is enhanced by a broad choice of pressure and electrical

connections and outputs. � is compact transducer is constructed to stand up to shock and vibration while providing stable pressure readings over an extended life. Circle 205 on card or visit psfreeinfo.com.

Compact Pressure Transducer

SPM Instrument, Sweden, announces the DuoTech, a multi-purpose accelerometer for vibration and shock pulse measurement. In the DuoTech accelerometer, two of the most widely used and

successful methods for monitoring mechanical condition come together: vibration and shock pulse measurement. � e combination of the patented HD enveloping and SPM HD measuring techniques provides maximum � exibility, enabling superior lubrication and bearing monitoring—covering the entire bearing deterioration process.Circle 204 on card or visit psfreeinfo.com.

Multi-Purpose Accelerometer

ClearView Filtration’s patented � lter assemblies allow visual inspection of the � uid being � ltered, the � lter element and the particles � ltered out of the � uid system. � is is done in seconds without draining, leaking or the loss of � uid and without unbolting or loosening any fasteners or � ttings—even when � ltering

non-transparent � uids. ClearView Filtration helps determine if particles are from normal use or engine or � uid system components excessively wearing. Circle 203 on card or visit psfreeinfo.com.

Oil & Fluid Filter Assemblies

Zoeller Pump Company announced the � rst 1/2 horsepower (HP) grinder pump, the Shark Model 800. � is unit targets the problematic residential 1/2 horsepower sewage ejector market, which is plagued by the infamous wipes. It uses the latest design in cutter and plate technology coupled with a powerful 3,500 rpm, oil-� lled

motor. � e success of the Model 800 prompted Zoeller Pump Company to develop the next generation of grinder pumps to cover a broader range of applications. � e 803-805-807 family of cast-iron, automatic and non-automatic grinder pumps are available in 1/2 HP (803), 3/4 HP (805), and 1 HP (807). Circle 202 on card or visit psfreeinfo.com.

Grinder Pump

SEEPEX introduces Smart Conveying Technology (SCT), the innovative technology for progressive cavity pumps.

In addition to the one-stage design for pressures up to 4 bar (60 psi), SCT is now available in a two-stage design for pressures up to 8 bar (120 psi). SCT is a customized solution that is e� cient, economical and environmentally friendly. SCT delivers enhanced pump performance with a longer component service life and easy maintenance, reducing maintenance time by up to 85 percent. Circle 201 on card or visit psfreeinfo.com.

Progressive Cavity Pumps


107

Advert isersFREE PRODUCT INFORMATION Visit www.psfreeinfo.com to request more information from these advertisers.

Advanced Engineered Pump, Inc. 111 169

Advanced Technical Staing Solutions, Inc. 111 168

AIGI Environmental Inc. 31 122

Amtech Drives 65 118

Automationdirect.com 19 101

Badger Meter Inc. 21 102

Bal Seal Engineering Inc. 108 170

Basetek, LLC. 108 192

BJM Pumps 55 152

Blue White Industries 9 119

Boerger LLC 56 123

CD-Adapco 88 153

Colfax Corporation 7 103

Conhagen, Inc. 71 124

Continental Pump Company 108 171

Cornell Pump Company 11 120

Crane Pumps & Systems 45 104

Dan Bolen & Associates, LLC. 111 172

Dickow Pump Company 89 125

DiscFlo 3 105

Dura Bar 5 106

Engineered Software Inc. 73 126

EnviroPump and Seal Inc. 82 163

FLSmidth 55 154

Franklin Electric 59 127

Frost & Sullivan 82 164

GE Intelligent Platforms 90-91 128

Gorman-Rupp Company 17 107

GPM, Inc. 47 129

Graphite Metallizing Corp. 39 130

Hoosier Pattern, Inc. 46 150

Hydraulic Institute 79 165

Hydro, Inc. IFC 100

Jordan, Knauf & Company 101 166

KSB, Inc. 50 151

KTR Corporation 53 155

Load Controls, Inc. 62 131

Load Controls, Inc. 108 174

LobePro 109 173

LUDECA, Inc. 63 132

Magnatex Pumps, Inc. 77 161

Master Bond Inc. 108 175

Meltric Corporation 108 176

Milton Roy 49 121

Nachi America, Inc. 32 133

National Pump Company 24 134

NETZSCH Group 109 177

NOC 109 178

NSK 36 135

Pemo Pumps 15 147

Pinnacle-Flo, Inc. 94 156

PPC Mechanical Seals 28 136

Pump and TurboMachinery Symposia 81 108

PSG, a Dover company 87 157

Pumpworks 610 75 137

R+W America L.P. 41 138

Raven Lining Systems 16 139

Ruthman Companies 37 109

Scenic Precise Element, Inc. 109 179

Schaeler Group USA Inc. 29 110

Schenck Trebel Corp. 66 149

Schneider Electric 57 116

SEPCO 44 140

SEPCO 110 180

Siemens Industry BC 111

Sims Pump Co. 109 188



SKF 80 158

Skinner Power Systems, LLC 12 141

St. Marys Foundry 109 181

Stein Seal 76 162

Stein Seal 107 190

Summit Industrial Products 70 142

Summit Pump, Inc. 110 182

Teikoku USA, Inc. 69 148

TF Seals 33 143

Titan Flow Control, Inc. 79 191

Titan Manufacturing, Inc. 64 159

Titan Manufacturing, Inc. 110 183

Trachte, USA 111 184

Tuf-Lok International 111 185

Tuthill Transfer Systems 51 144

Vaughan IBC 112

Vertilo Pump Company 110 186

Vesco 110 187

Waukesha Bearings 74 145

WEFTEC 83 113

WEG Electric Corp. 13 114

WEG Electric Corp. 93 160

Westerberg and Associates 101 167

WPI 111 189

Yaskawa America Inc 25 115

Zoeller Pump Company 23 146

he Index of Advertisers is furnished as a courtesy, and no responsibility is assumed for incorrect information.

Advertiser Name Page RS# Advertiser Name Page RS# Advertiser Name Page RS#





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109

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111

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112 PUMP MARKET ANALYSIS

By Jordan, Knauff & Company

Wall Street Pump & Valve Industry Watch

These materials were prepared for informational purposes from sources that are believed to be reliable but which could change without notice. Jordan, Knauff & Company and Pumps & Systems shall not in any way be liable for claims relating to these materials and makes no warranties, express or implied, or representations as to their accuracy or com-pleteness or for errors or omissions contained herein. This information is not intended to be construed as tax, legal or investment advice. These materials do not constitute an offer to buy or sell any financial security or participate in any investment offering or deployment of capital.

The Jordan, Knauf & Company (JKC) Valve Stock Index was down 21.5 percent

over the last 12 months, while the broader S&P 500 Index was up 4.5 percent. he JKC Pump Stock Index also decreased 22.4 percent for the same time period.1

he Institute for Supply Management’s Purchasing Managers’ Index (PMI) rose to 53.5 percent for the month of June compared with 52.8 percent in May. he Employment Index rose 3.8 percent to 55.5 percent for the month, while the New Orders Index grew to 56 percent from 55.8 percent in May. he overall PMI has averaged 52.6 percent through the irst half of the year, less than the average of 56.9 percent seen in the second half of 2014. he Production Index averaged 61.6 percent in the second half of last year while averaging only 54.8 percent during the irst quarter of this year.

he Bureau of Labor Statistics reported that nonfarm payroll employment rose by 223,000 in June, and the unemployment rate decreased to 5.3 percent. Job gains occurred in professional and business services, healthcare, retail trade, inancial activities, and transportation and warehousing. he manufacturing sector grew by 4,000 jobs, compared with

an increase of 64,000 in professional and business services. In the irst half of the year, manufacturing has added an average of just over 6,000 workers per month. Nonfarm employment increases averaged more than 250,000 per month for the past 16 months and surpassed 200,000 in 14 of the past 16 months.

he Census Bureau reported that total construction spending rose 0.8 percent in May while rising 5.9 percent during the irst ive months of the year. It is up 8.2 percent over 2014. New home sales activity was at its highest level in seven years in May. Private nonresidential construction increased 1.5 percent during the month and is up 12.7 percent year over year.

As of last year, only four countries were producing commercial volumes of either crude oil from tight formations or natural gas from shale formations according to the U.S. Energy Information Administration and Advanced Resources International Inc. Along with the U.S. and Canada, Argentina and China have recently begun production of this type. Other countries that have started to explore shale and tight oil but are still short of reaching

commercial production include Mexico, Poland, Algeria, Australia, Colombia and Russia.

On Wall Street, all indices were down for the month of June. he Dow Jones Industrial Average lost 2.2 percent, the S&P 500 Index was down 2.1 percent, and the NASDAQ Composite declined 1.6 percent. For the second quarter of the year, the Dow declined 0.2 percent and the S&P 500 lost 0.9 percent, while the NASDAQ gained 1.8 percent. Concerns about Greece’s bailout program and referendum on whether to accept terms demanded by its creditors afected investors. Despite a rise in consumer spending, upbeat housing data and encouraging retail sales, the Federal Reserve Bank indicated it will increase interest rates at a slower pace than it expected earlier this year.

Jordan, Knauf

& Company is an

investment bank

based in Chicago,

Illinois, that

provides merger and

acquisition advisory

services to the

pump, valve and

iltration industries.

Please visit

jordanknauf.com for

more information.

Jordan Knauf &

Company is a member

of FINRA.

Source: Capital IQ and JKC research. Local currency converted to USD using historical spot rates. he JKC Pump and Valve Stock Indices include a select list of publicly traded companies involved in the pump and valve industries weighted by market capitalization.

Figure 1. Stock indices from July 1, 2014, to June 30, 2015

Source: U.S. Energy Information Administration and Baker Hughes Inc. Source: Institute for Supply Management Manufacturing Report on Business® and U.S. Census Bureau

Reference

1. he S&P Return

igures are provided

by Capital IQ.

Figure 3. U.S. PMI and manufacturing shipmentsFigure 2. U.S. energy consumption and rig counts

Vaughan’s Rotamix System sets the standard for hydraulic mixing, providing the customer with

lower operating and maintenance costs, more efficient breakdown of solids and Vaughan’s

UNMATCHED RELIABILITY. It’s perfect for digesters, sludge storage tanks, equalization basins

and other process or suspension type mixing applications.

- Over 1000 installations worldwide

- Optimizes solids contact with its unique “dual rotational zone” mixing pattern

- 10 Year Nozzle warranty

See videos, drawings, and details at ChopperPumps.com or call 888.249.CHOP

















Oczkowo"qh"7.222"JR






The more flexible you are, the faster

you can move: that’s the thinking

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The newest addition to the SINAMICS

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combines superior reliability and

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ever before.

The SINAMICS GH150 drive is built to

accommodate a separate transformer,

allowing for a more versatile plant

layout and compatibility with any

primary voltage or number of pulses.

The control cabinet can be placed up

to 50 meters from the power section.

siemens.com/sinamics-perfect-harmony

The control cabinet can even be

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The SINAMICS GH150 comes with an

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SINAMICS PERFECT HARMONY is

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New flexibility. Higher reliability.Introducing the SINAMICS PERFECT HARMONY GH150 water-cooled drive.


Pumps & Systems - August 2015

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