July August 2013

July/August 2013

Pumping and Related Technology for Oil & Gas

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FROM THE EDITOR

E

ven with declining natural gas prices, production continues in the Marcellus Shale. Pennsylvania and West Virginia now produce 7 billion cubic feet of gas per day, which is 25 percent of the nationwide production and nearly double 2011’s rate. In 2012, the Marcellus Shale was the most productive gas field in the nation. The play that ushered in the shale gas boom is still the dominant production field today. Hydraulic fracturing has been used for decades and is safe when conducted correctly. However, environmental concerns continue to be at the forefront of production in the Marcellus region. Doug Walser’s Report from the Field on page 32 discusses the need for and steps to take for responsible production in the area. In addition to responsible production, the reuse of drilling mud is common practice among operators. A pump technology that helps improve the removal of solids from drilling mud is detailed on page 10. In hydraulic fracturing, the need to decrease the timeframe required to complete a well is an industry issue. The first part of a two-part series on page 14 examines a new but well-tested technique that decreases completion time. Subsea equipment must survive extreme cold and heat. For these

conditions, specialized insulation must be used to protect pipelines and other architecture. One such insulation is detailed on page 24. As in all operations in the oilfield, pumps in production must be specialized for individual applications. API 682 seals used in many areas of the oil patch and in refineries are discussed on page 36. Look for this issue at the Oil Sands Trade Show & Conference in Fort McMurray, Alberta, and read the article on oil sands production on page 40. Also, look for the Upstream Pumping Solutions team at SPE ATCE. We hope to see you there! Best Regards,

Lori Ditoro Editor Editor’s Note: In “Horizontal Multistage Pumping System for Natural Gas Liquids,” in the May/ June 2013 issue, the phrase “bearings made of metal-impregnated graphite” should have read “bearings made of GRAPHALLOY®.” We apologize for any confusion or inconvenience this may have caused.

Editorial Advisory Board Cleon Dunham, President, Oilfield Automation Consulting, & President, Artificial Lift R&D Council David Jones, Business Development Manager, Siemens Industry Inc. Chad Joost, Sales Manager, Well Stimulation Products, Stewart & Stevenson Daniel Lakovic, Progressing Cavity Pump Technical Expert, seepex, Inc.

Publisher Walter B. Evans, Jr. VP of Sales George Lake [email protected] • 205-345-0477 VP of Editorial Michelle Segrest [email protected] • 205-314-8279 Creative Director Terri Jackson [email protected]

EDITORIAL Editor Lori K. Ditoro [email protected] • 205-314-8269 Associate Editor Amanda Perry [email protected] • 205-314-8274 Contributing Editor Doug Walser CREATIVE SERVICES Creative Director Terri Jackson Senior Art Director Greg Ragsdale Art Director Jaime DeArman PRODUCTION Print Advertising Traffic Lisa Freeman [email protected] • 205-212-9402 Web Advertising Traffic Ashley Morris [email protected] • 205-561-2600 CIRCULATION Jeff Heine [email protected] • 630-739-0900 ADVERTISING Associate Publisher Vince Marino [email protected] • 205-310-2491 Addison Perkins [email protected] • 205-561-2603 Derrell Moody [email protected] • 205-345-0784 Mary-Kathryn Baker [email protected] • 205-345-6036 Mark Goins [email protected] • 205-345-6414 from the publishers of

Santosh Mathilakath, Vice President - Mono Group, National Oilwell Varco Gord Rasmuson, Sales Manager, Oil Lift Technology Bill Tipton, Division Vice President - Business Development, Weir Oil & Gas Doug Walser, Technology Manager, Pinnacle, a Halliburton Business Line Shaun White, Mud Pump Designer, White Star Pump Company

P.O. Box 530067, Birmingham, AL 35253

Editorial, Circulation and Production Offices 1900 28th Avenue South, Suite 110 Birmingham, AL 35209, Phone: 205-212-9402

Advertising Sales Offices 2126 McFarland Blvd. East, Suite A Tuscaloosa, AL 35404, Phone: 205-345-0477

UPSTREAM PUMPING SOLUTIONS (ISSN# 2159-3035) is published bimonthly by Cahaba Media Group, 1900 28th Avenue So., Suite 110, Birmingham, AL 35209. Standard A postage paid at Birmingham, AL, and additional mailing offices. Subscriptions: Free of charge to qualified industrial pump users. Publisher reserves the right to determine qualifications. 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 (205) 212-9402 inside or outside the U.S. POSTMASTER: Send changes of address and form 3579 to Upstream Pumping Solutions, Subscription Dept., 440 Quadrangle Drive, Suite E, Bolingbrook, IL 60440. ©2013 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 submission, 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 4 • Number 4

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Upstream Pumping Solutions • July/August 2013

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July/August 2013

July/August 2013

TABLE OF CONTENTS

Pumping and Related Technology for Oil & Gas

Volume 4 • Number 4

A field engineer prepares a packer to complete a horizontal well in the Marcellus Shale. Image courtesy of Baker Hughes Incorporated

DEPARTMENTS Drilling 10 Rotary Lobe Pumps & Decanter Centrifuge Increase Solids Removal By Bill Blodgett, LobePro Rotary Pumps Operators can experience ease of use, cost savings and improved efficiency.

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SPECIAL

Well Completion

s e c t i o n Subsea Equipment

14 Remedial Efforts for Fracture Treatment in Horizontal Laterals

24 Pipeline Protection During Deepwater Production By Alexander Lane, The Dow Chemical Company Wet insulation systems for subsea flow assurance provide reliable performance in extreme environments.

By Robert Reyes, Halliburton A design stimulation program using a diversion frac for proppant distribution can effectively stimulate troubled wells.

20 Fluid End Life By Gary Pendleton and Rob McPheron, AXON Energy Products Fluid end developments and modular design prolong fluid end life while maintaining higher pressures.

27 Low-Vibration Compressor Motors By Sumit Singhal, Siemens Motor Structural Design

Production

COVER The Marcellus Shale SERIES

36 The Revised API 682 Mechanical Seal Standard By Thomas Böhm and Markus Fries, EagleBurgmann The 4th Edition includes details on the revised product coding system, the seal system selection process and seal supply systems.

31 Still a Production Giant By Lori K. Ditoro With nearly doubled rates in 2012, the Marcellus Shale continues its dominance in U.S. natural gas production.

32 A New Focus on Responsible Development By Doug Walser, Pinnacle, a Halliburton Service Line A revolution concentrating on responsibility is taking place in North American unconventional oil and gas extraction—particularly in the Marcellus Shale.

40 Testing Center Helps UltraTemperature ESP Systems Improve Operations By Lawrence Burleigh, Baker Hughes Because of the harsh nature of SAGD operations, specialized artificial lift systems are required.

IN EACH ISSUE

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Upstream Pumping Solutions • July/August 2013

2 6 42 43 45 48

From the Editor Industry News Trade Show Coverage

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Oilfield Resources Classified Ads & Index of Advertisers Upstream Oil & Gas Market

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INDUSTRY NEWS

NEW HIRES, PROMOTIONS & RECOGNITIONS MARK J. SULLIVAN, Pump Systems Matter PARSIPPANY, N.J. ( July 9, 2013) The Hydraulic Institute appointed Mark J. Sullivan as its new director of education and training. Sullivan will lead all strategic development, marketing and Pump Systems Matter educational programs. Pump Systems Matter is a 501(c)3 education/training organization affiliated with the Hydraulic Institute, www.pumpsystemsmatter. org. The Hydraulic Institute is North America’s largest pump association, www.pumps.org. BEN VAN BEURDEN, Royal Dutch Shell THE HAGUE, The Netherlands ( July 9, 2013) – The Board of Royal Dutch Shell plc announced that Ben van Beurden will succeed Peter Voser as CEO. Voser will leave Shell at the end of March 2014. Royal Dutch Shell is a global group of energy and petrochemicals companies. www.shell.com MICHAEL BROWN, Chet Morrison Contractors HOUMA, La. ( July 1, 2013) – Chet Morrison Contractors hired industry veteran Michael Brown as general manager of Michael Marine Construction. Brown Brown has 35 years of experience in the commercial diving industry. Chet Morrison Contractors provides construction, maintenance and abandonment services to the oil and gas industry. www.chetmorrison.com

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TOM GEISSLER & DAVID SMITH, SOR Inc. LENEXA, Kan. ( June 28, 2013) SOR Inc. announced the new Western regional sales manager, Tom Geissler. Geissler has worked across a broad spectrum of industries including oil and gas, chemical, water and wastewater, bio-tech and pharmaceutical. David Smith was named Gulf Coast regional sales manager. With more than 30 years’ experience in sales and service in the oil and gas industry, Smith will manage strategic accounts. SOR Inc. provides level, pressure, temperature and flow instrumentation. www.sorinc.com NICOLÁS M. DEPETRIS CHAUVIN, WEC LONDON ( June 11, 2013) – The World Energy Council (WEC) appointed Dr. Nicolás M. Depetris Chauvin as its regional manager for the Latin America and Caribbean (LAC) region. Depetris Chauvin will support the WEC in strengthening its network in this region. WEC is the principal impartial network of leaders and practitioners promoting an affordable, stable and environmentally sensitive energy system for the greatest benefit of all. www.worldenergy.org

GUNTER CONNERT, Colfax Fluid Handling RADOLFZELL, Germany ( June 6, 2013) – Colfax Fluid Handling announced Gunter Connert as direct sales manager at Colfax Fluid Handling. Connert is responsible for serving the Power & Industry business segment in Germany, Benelux, Great Britain and Finland. Colfax Fluid Handling, a business of Colfax Corporation, is a provider in critical fluid-handling and transfer solutions. www.colfaxcorp.com JEFF SHELLEBARGER, Chevron SAN RAMON, Calif. ( June 5, 2013) – Chevron Corporation named Jeff Shellebarger president of Chevron North America Exploration and Production Company. Shellebarger succeeds Gary Luquette, who will retire after 35 years. He will be responsible for overseeing Chevron’s exploration and production activities. Chevron is an integrated energy company. www.chevron.com NICHOLAS DALE & GERRY MILLER, Claxton Engineering Services Ltd. GREAT YARMOUTH, U.K. ( June 5, 2013) – Claxton Engineering

MERGERS & ACQUISITIONS ACTEON completes acquisition of J2 Engineering Services Ltd. GE completes acquisition of Lufkin Industries

July 11, 2013 July 1, 2013

ACCELERATED COMPANIES acquires DynaFlo Artificial Lift Systems and Five Star Equipment

June 27, 2013

ROSNEFT and ExxonMobil advance strategic cooperation

June 21, 2013

Upstream Pumping Solutions • July/August 2013

Services Ltd., an Acteon company, named Nicholas Dale business development manager for Southeast Asia. Based Nicholas in Singapore, he will Dale focus on increasing the company’s penetration into the area’s market. Claxton also appointed Gerry Miller as vice president of sales, marketing and comGerry Miller mercial. Miller’s base will be at Claxton’s headquarters in Great Yarmouth, U.K. Claxton, an Acteon company, supplies engineering and services, www.claxtonengineering.com. Acteon companies provide mooring, foundation, riser, conductor, flowline and marine electronics products and services, www.acteon.com.

IN THE FIELD Weir Minerals Canada Opens New Facility MISSISSAUGA, Ontario ( July 24, 2013) – Weir Minerals Canada announced that its Fort McMurray service and distribution operation has been relocated to a new facility

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VISTAVU Among Canada’s Fastest-Growing Companies CALGARY, Canada ( June 3, 2013) VistaVu made its first appearance on the definitive listing of Canada’s Fastest-Growing Companies. It was ranked 385 in the 2013 PROFIT 500 list. VistaVu Solutions is an ERP software solution provider. www. vistavusolutions.com MIKE SUMRULD, Baker Hughes HOUSTON (May 28, 2013) Baker Hughes Incorporated named Mike Sumruld as vice president and treasurer. Baker Hughes supplies oilfield services, products, technology and systems to the oil and natural gas industry. www.bakerhughes.com

in the MacKenzie Industrial Park. This 19,000-square-foot facility will support customers in the Athabasca Oil Sands. Weir Minerals delivers end-to-end solutions for mining, dewatering, transportation, milling, processing and waste management activities. www.weir.co.uk

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INDUSTRY NEWS SCHLUMBERGER Opens Reservoir Laboratory in China CHENGDU, China ( July 3, 2013) Schlumberger announced the official opening of the Schlumberger Reservoir Laboratory in Chengdu, China. The company also contributed five scholarships to the American Association of Petroleum Geologists’ (AAPG) Outstanding Student Chapter Awards. Schlumberger is a supplier of technology, integrated project management and information solutions. www.slb.com GE Measurement & Control Unveils New Customer Application Center MOSCOW ( June 26, 2013) – GE announced the grand opening of its new Customer Application Center in Moscow. The company also

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announced the grand opening of its Customer Solutions Center at GE Measurement & Control’s Inspection Technologies site in Lewistown, Pa. GE Measurement & Control provides advanced, sensor-based measurement; non-destructive testing and inspection; flow and process control; turbine, generator, and plant controls; and condition monitoring. www.ge-mcs.com HOLT CAT Breaks Ground for New Facilities EDINBURG, Texas ( June 25, 2013) HOLT CAT held groundbreaking ceremonies for its facilities in Edinburg, Texas, and Little Elm, Texas. HOLT CAT sells, rents and services Caterpillar machines, engines, generator sets and trucks. www. holtcat.com

EVENTS Eastern Oil & Gas Conference Aug. 27 – 28 Monroeville, Pa. www.pioga.org Oil Sands Conference Sept. 9 – 11 Fort McMurray, Canada www.oilsandstradeshow.com NEVA Sept. 24 – 27 St. Petersburg, Russia +44 1449 741801 www.transtecneva.com SPE ATCE Sept. 30 – Oct. 2 Ernest N. Morial Convention Center New Orleans, La. 800-456-6863 www.spe.org/atce/2013

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DRILLING

A drilling rig in the Marcellus Shale, image courtesy of Baker Hughes Inc.

Rotary Lobe Pumps & Decanter Centrifuge Increase Solids Removal By Bill Blodgett, LobePro Rotary Pumps Operators can experience ease of use, cost savings and improved efficiency.

D

ilute drilling fluid required to return the drilling fluid to within the original specification is a major drilling expense. Typically, 20 or more barrels of dilute drilling fluid are required to offset one barrel of drilled solids that is not removed from the drilling fluid. As a result, many operators now use a decanter centrifuge, in addition to the standard shaker and desander, to improve their solids removal efficiency (SRE). The improvement in SRE comes from a decanter centrifuge’s ability to remove drilled solids that are

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too small for a shaker, desander and desilter to separate. This article discusses how a centrifuge fed by a rotary lobe pump can improve solids removal. It also details an example of a savings calculation from a dilute drilling fluid calculator that shows the possible savings from using a decanter centrifuge with a rotary lobe pump.

Feeding with a Rotary Lobe Pump A centrifuge can help remove solids that are too small to be eliminated by the standard shakers, desanders and

Upstream Pumping Solutions • July/August 2013

desilters. The D50 cut-point for the shaker, desilter and desander combination is typically 70 microns. The D50 cut-point for a decanter centrifuge is typically 6 microns. A D50 cut-point of 6 microns means that the centrifuge will remove 50 percent of the 6 micron solids in the drilling fluid. To obtain the maximum benefit, decanter centrifuges should be fed by a low-shear, positive displacement pump. The solids removal is improved with a rotary lobe pump because a centrifugal pump’s shearing action results in a higher percentage of drilled

solids that are less than 6 microns and, therefore, unable to be removed by the centrifuge. The flow from a rotary lobe pump is not affected as much as a centrifugal pump by changes in viscosity, pressure and specific gravity. Therefore, a rotary lobe pump can be much more readily managed to feed enough drilling fluid to take full advantage of the centrifuge’s capacity without overfeeding it. Drilling rig personnel are generally occupied with other tasks and cannot constantly adjust a centrifugal pump or change impellers as required. As a result, many more barrels of drilling fluid will typically be processed by the centrifuge when fed by a rotary lobe pump. This is also important because it is generally accepted that drilling solids not removed on the first pass will never be removed and will have to be controlled by dilution.

Rotary Lobe Pump Improvements Measured Table 1 shows a substantial reduction in dilution drilling fluid required for a 7,000-foot hole that results from the addition of a decanter centrifuge to other solids separation equipment. In this example, the savings in dilution drilling fluid preparation and disposal net of the centrifuge rental expense is $70,548 for the one 10-day job. The example in Table 1 is taken from Chapter 13 of the Drilling Fluids Processing Handbook published by ASME Shale Shaker Committee. The drilling fluid in this example was separated using a shaker, desilter and desander in combination, which removed 60 percent of the drilled solids. Then a centrifuge removed ⅓ of the 40 percent of drilled solids that remained. The improvement in SRE resulted from the decanter centrifuge’s ability to remove particles between 6

Table 1. Dilute drilling fluid calculator

to 70 microns that were not removed by the other solids separation equipment. In the example, a well bore of 13.5 inches in diameter that is 7,000 feet deep will result in 1,237 barrels of drilled solids. The shaker, desilter and desander combination leaves 495 barrels (40 percent of 1,237) of drilled solids in the drilling fluid. Using Section 4 in Table 1, 32.1 barrels of dilute drilling fluid are required for each barrel of drilled solids to restore the drilling mud to specification. This equals 15,868 barrels of dilute drilling fluid (495 x 32.1) with a total cost of $238,025 ($15 x 15,868) for dilute drilling fluid if a decanter centrifuge is not used. By using a decanter centrifuge fed by a rotary lobe pump to remove ⅓ of the 495 barrels of drilled solids remaining in the drilling fluid after processing by the shaker, desander and desilter combination, the cost of dilute drilling fluid can be reduced by $78,548 ($238,025 x ⅓). Some drilled solids, primarily those less than 6 microns, remain after centrifuge treatment. Unfortunately, the solids that contribute most to poor hole conditions are colloids and ultra-fine solids under 6 microns. As a result, many experienced operators have switched to low-shear, positive displacement pumps to feed the decanter centrifuge in an effort to minimize colloids and ultra-fine drilled solids. The dilute drilling fluid calculator, which was used to obtain the numbers in Table 1, helps determine the reduction in dilution drilling fluid required if the centrifuge is fed with a low-shear rotary lobe pump versus a centrifugal pump. (Email the author for a copy of the calculator.) Using a centrifugal pump instead will reduce the percentage of drilled www.upstreampumping.com

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DRILLING solids removed from 33 percent to 25 percent. This reduces the savings from using a decanter centrifuge by $19,042 on just one 10-day job. Additional benefits of a rotary lobe pump are: • Eliminating the annual overhaul cost for the centrifuge that can

result from overfeeding of the centrifuge by a centrifugal pump, typically about $12,000 per year • Avoiding priming problems at the drill site—a nuisance for operators—because rotary lobe pumps are self-priming and have strong vacuums

Case Study In 2009, a pumping solution company was selected by a manufacturer of decanter centrifuges as a partner. Most operators using low-shear, positive displacement pumps selected progressive cavity pumps (PCPs). The decanter centrifuge manufacturer’s management knew that several key operators were unhappy with the PCPs because of field failures caused by dry running for as little as 30 seconds, the time and difficulty to replace parts in the field, and the cost of repair parts. After extensive testing by its engineering staff, one of these users selected the decanter centrifuge manufacturer’s package featuring the rotary lobe pumps to feed their centrifuges and have replaced many of their PCPs with the pump solution company’s low-shear, positive displacement pump. These rotary lobe pumps are well-suited for their drilling mud tasks because they can run dry, provide low shear, have a strong vacuum and are self-priming. An additional bonus to these pumps is the ability to perform pump maintenance in-place quickly and easily. One person can handle the maintenance on the company’s average size pump in half the time of a comparable PCP.

Bill Blodgett is president of LobePro Rotary Pumps. He holds degrees in economics and finance from the University of Pennsylvania and the University of Chicago. H He can bbe reached at [email protected].

2570 Beverly Dr. #128, Aurora, IL 60502 T 630.236.3500

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Upstream Pumping Solutions • July/August 2013

LobePro Rotary Pumps provides engineered pumping solutions in applications such as drilling mud, oil refining, corrosives and waste oil. To learn more about LobePro Rotary Pumps, please visit www.lobepro.com.

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WELL COMPLETION

Remedial Efforts for Fracture Treatment in Horizontal Laterals By Robert Reyes, Halliburton A design stimulation program using a diversion frac for proppant distribution can effectively stimulate troubled wells. First of Two Parts

A

s oil and gas well fracture stimulation has progressed, multiple novel technologies have been developed to keep pace. With the onset of horizontal lateral drilling and completion work, this trend has been magnified even more. It has been reported that 500 to 1,000 trillion cubic feet of recoverable gas reserves have been added by North American shale plays alone. In 19 geographical basins, an estimated 35,000

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horizontal wells have been drilled and completed using multistage fracturing techniques. Proved reserves of U.S. oil and natural gas in 2010 rose by the highest amounts ever recorded since the U.S. Energy Information Administration (EIA) began publishing proved reserves estimates in 1977. An important factor for both oil and gas was the expanding application of horizontal drilling and hydraulic fracturing in

Upstream Pumping Solutions • July/August 2013

resource shales and other tight (very low permeability) formations. The same technologies that first spurred substantial gains in natural gas proved reserves have more recently expanded into similar oil producing formations. Helping drive proved reserves increases in 2010 were higher prices used to assess economic viability relative to the prices used for the 2009 reporting year, particularly for oil.1

Stimulation Evolution Fracture stimulation methods have evolved significantly from the high rate—100 to more than 180 barrels per minute—true limited entry design that used perforation techniques in an attempt to fracture treat from the heel to toe with a one-time pumpin stage. Many of these applications treated as much as a mile of lateral in one or two hours in a single operation. On most of these jobs, when a post-frac survey was performed, a large percentage of the lateral would show little or no stimulation, with the toe section most often untreated. This led well operators to seek better completion plans, and new completion and stimulation tools were designed to implement such changes. The first major change was to subdivide the wellbore and use the same limited entry perforating technique on shorter sections, with the industry designing new staging plug designs that allowed them to be pumped down the lateral to the desired position and wireline set. Soon, this type of plug would also drag down a multishot perf gun in the same operation, and by about 2002 or 2003, the perf and plug process was in use. New completion designs emerged that required lower injection rates, typically 50 to 90 barrels per minute, depending on the number of dividing stages that were selected or the number of perforated intervals per stage. For this reason, staged fracturing completions began to be the dominant method as resource shale completions became more common. This perf and plug method reduced horsepower costs while providing each fractured compartment a better chance to be effectively treated. The savings in horsepower was initially a trade off with the amount of increased time spent performing the

stage frac treatment, but going back to non-staged completions was not considered a viable economic option. With decreased total completion time becoming a critical issue for improving economics further, pumping service companies began to address how the stage fracture treatment could be as efficient as the compartmental lower rate plug and perf method, yet significantly reduce the time required for stimulation. The next major solution was sliding sleeves activated by ball drop mechanics. This approach increased the hardware costs of completion, but offered the economic benefits of reduced stimulation times. By installing the lateral sliding sleeves with a baffle (increasing in opening size as the position approached the heel) each stage would end by dropping a specifically sized ball from the surface to land on the baffle and slide the sleeve into an open position. With this technology, instead of shutting down to pump a plug and perforate, the time between stages was reduced significantly. Operators were again able to fracture an entire wellbore lateral (10 to 20 stages) in one day, possibly even allowing for flowback. However, just as plug and perf operations often encounter malfunctions that add costs, so might the ball activated sliding sleeve completion. They may be caused by human error of action or judgment, mechanical failure, or by unforeseen quirks of nature. With respect to the premature sticking of plugs or failed perf guns, recovering from these failures is usually possible, with added time and costs for the recovery operations, but seldom with very much loss of producing zones. However, when a failure occurs with a ball activated sliding sleeve assembly in place, the degree of problem may be as small as losing a

single pay interval to an issue—such as 10 or more completion stages with sliding sleeves in the lateral and being unable to open any of the sliding sleeve ports. Such a case could possibly be solved by milling out all the ball seats and then attempting to revert back to the application of plug and perf technique, requiring possibly a week or longer to recover the wellbore and to pump a perf and plug stimulation. This two-part series discusses a novel technique detailing a west Texas case history in which a service company was asked to recover a well in which all the sliding sleeve completion tools were in failure mode. It was decided to open all the zones and use a new product to effectively treat all stages in one pumping treatment. This technique is called diversion frac for proppant distribution.

Diversion Frac for Proppant Distribution The diversion frac method is engineered to improve the efficiency of completion techniques. As a result, production increases should be observed. The procedure involves providing all reservoir access points an opportunity to receive fracture stimulation treatment. The access points include the perforations, completion sliding sleeve tools, hydraulic sleeves, hydrojetted holes, and open hole, which are the fracture initiation points. With the staged dropping of a biodegradable material, which exists in a range of mesh sizes, a previously treated zone is bridged and diverted, sending the trailing fracture treatment stage into the next access point, which should be the next untreated zone that is least resistant to taking fluid. Time is saved when the drop is made, and the previously treated zone is diverted, redirecting the treatment www.upstreampumping.com

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WELL COMPLETION fluid that follows to “break down” the next zone. This process occurs in the same timeframe in which crews operating the old plug and perforate method would be shutting down to get ready for wireline runs to set a plug and perforate the next zone, which could take two hours per stage on an average well.

Background: Plug and Perforate Method The plug and perforate completion technique has been the primary process for stage frac completions for most of the past decade. The well completion type most commonly applied has been be a cemented liner or casing or, less often, an openhole liner using casing external packers to partition the annulus into zones and includes pumping down plugs and perforating guns in horizontal applications. The application consists of gaining entry to the formation by perforating the farthest interval or the toe section and then breaking down the formation and pumping the first fracture treatment into this zone. After a large flush stage to wash residual proppant from the wellbore and then shutting down, isolation is achieved from the just-treated zone by placing a pumpdown mechanical plug above it. Then the process repeats as the next zone to be treated is perforated (typically two to seven perf clusters). The gun is retrieved and then the interval is broken down and fracture stimulated. This procedure continues until the last planned zone is treated and flushed. In North America, the plug and perforate process is being used in about 85 percent of today’s horizontal well completions.2 Efficiencies can be improved by combining multiple perforating runs (i.e., multiple stages) into one and a significant amount of time can be saved by using diversion

16

frac for proppant distribution in between these sub-stages. With an hour or two as a baseline to perform wireline runs, running three sub-stages in one run saves two to four hours per treatment.

Applications of Diversion Frac for Proppant Distribution The service operator’s special biodegradable diverting agents provide temporary temperature- or time-based fluid-loss control (temporary perf sealing) in the near-wellbore region (NWB) of the perforations and the fracture of new zones accepting fluid after the diverter arrives. Diverting agents of this type have been used to divert in perforation tunnels, nearfield fractures, slotted liners and open hole zones to redirect the fracturing

treatment fluid to non-treated zones (zones that accepted little or no fluid before diverter placement). Treatment fluids used include frac gel, acid, scale treatment and wellcontrol treatments. The treatment can be placed in aqueous fluid between applications or bullheaded before an application, such as with split casing in which one is attempting to divert away from a trouble zone. Volumes required depend on the geometry of where diversion is desired. Reservoir or treating pressure will not affect biodegradable diverters. The advantages of biodegradable diversion material include: • Treatment time is reduced. • Treatment fluid is distributed more efficiently. • The need to drill out plugs is eliminated.

Figure 1. Material A (1 pound per gallon) degradation testing at 160 F

Upstream Pumping Solutions • July/August 2013

Figure 2. Material B degradation at 100 F

diversion treatment, casing and cement sheath integrity, bottomhole temperature, and bottomhole pressure available as flow-back energy.3 Particle bridging is achieved with a product that is multi-sized, biodegradable and temporary. Two specific size distributions are: • Material A particle size distribution: 20 to 25 percent is in the 4- to 10-mesh size range and 40 to 50 percent is in the 20- to 40mesh size range. The remainder is smaller. • Material B particle size distribution: 8 to 10 percent is larger than 8 mesh, 40 to 50 percent is in the 20- to 40-mesh range, and 30 to 45 percent is smaller than 40 mesh.

• The material is compatible with many fracturing fluids. • The material degrades over time. Care must be taken to isolate the pumps that are engaged with the material because special valve seats are required for proper pumping.2

Diverter Delivery and Diversion Using a method to alter flow distribution is called diversion. Its purpose is to divert the flow of fluid from one portion of an interval to another. The diversion method best suited for a particular situation depends on many factors, including but not limited to the type of well completion, perforation density, the type of fluid that is produced or injected after the Name

Measured Depth (feet)

The action of the smaller particles Outer Diameter (inches)

Inner Diameter (inches)

Linear Weight (ppf)

Grade

Production Casing

0 to 8,610

7

6.276

26

P-110

Open Hole

7,651 to 9,718

—

6.125

—

—

Production Liner

7,651 to 12,353

4.5

4.000

11.6

P-110

Table 1. Tubulars Interval Name/ Depth (feet)

No. of Perfs

TVD (feet)

Stg 1 perforation interval: 12,213 to 12,214

12

8,083

Stg 2 perforation interval: 11,900 to 11,901

12

8,081

Stg 3 perforation interval: 11,546 to 11,547

12

8,078

Stg 4 perforation interval: 11,145 to 11,146

12

8,084

Stg 5 perforation interval: 10,703 to 10,704

12

8,099

Stg 6 perforation interval: 10,253 to 10,254

12

8,114

Stg 7 perforation interval: 9,989 to 9,990

12

8,119

Stg 8 perforation interval: 9,633 to 9,634

12

8,125

Stg 9 perforation interval: 9,366 to 9,367

12

8,130

Stg 10 perforation interval: 8,967 to 8,968

12

8,136

Stg 11 perforation interval: 8,655 to 8,656

12

8,144

Stg 12 perforation interval: 8,344 to 8,345

12

8,146

Case History A

Table 2. Perforations Treatment/Depth (ft.)

Pore Press. (psig) BHST (F) Frac. Grad. (psi/ft.)

Devonian: 8,344 to 12,214 3,092

127

Table 3. Lithology

will “nest” in the pore throats of the coarse-sized particles and create a seal to fluid flow. A characteristic of particle bridging is that it is independent of the size or geometry of the perforation or void space. The “variable” mesh will accumulate and divert fluid flow. At the designed temperature, the material will soften, helping achieve a seal that is more restrictive to flow, which creates back-pressure against any fluid that attempts to flow into a diverted channel. This allows higher pressure in the wellbore that may be needed to initiate flow in a new zone. Once the material is pumped into the perforation or fracture, it will later degrade based on temperature and/ or time. The Material A form of this agent is effective in wells with a bottomhole static temperature (BHST) of 160 to 320 F (see Figure 1). For wells with lower BHSTs, Material B is effective in temperatures as low as 140 F and up to 450 F (see Figure 2). For cooler wells, because the degradation occurs over time, depending on the pumping time, it can be acceptable to use diversion frac for proppant distribution, but laboratory testing must confirm the candidate well. Case History A (discussed later in this article) was such a well, with BHST of only 127 F. Degradation of these materials is based on the dissolution of the materials in water or other brine solutions. For typical well flowback, 100 percent dissolution is not required. Field experience has indicated that as little as 20 percent degradation would result in non-restrictive flowback and clean up times would not be impacted.

0.75

The case history discussed in this section describes a horizontal west Texas well in Ward County. The well was cased with 7-inch, 26-pound-per-foot www.upstreampumping.com

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WELL COMPLETION (ppf ) casing to 8,610 feet, then a 4.5inch liner 11.6 ppf is hung at 7,651 to 12,353 feet. True vertical depth (TVD) was 8,144 feet. Drilled in the Devonian formation, perforations were at 12,213; 11,900; 11,546; 11,145; 10,703; 10,253; 9,989; 9,633; 9,366; 8,967; 8,655; and 8,344 feet shot with 12 shots per foot. Pore pressure was 3,092 psi with 127 F BHST. A previous service company ran sliding sleeves as part of the liner, and the sleeves would not open, causing a job failure. The ball-seat baffles had to be drilled out to allow perforating. Using the diversion frac for proppant distribution material, it was decided to perforate the above depths and have the horizontal lateral 100 percent open in all zones planned to frac. The fracture treatment design would incorporate diversion to place the proppant treatment into all zones in one large pump-in stage. Tables 1 through 3 present the details for the tubulars, perforations and lithology of the Ward County well. Design The team decided to pump a guarbased crosslinked fluid (prepared from 15 centipoise [cp] base gel) carrying 1, 2, 3 and 4 pounds mass per gallon (lbm/gal) brown 20/40-mesh sand in five separate stages. After each flush, the plan was to drop 240 lbm of 100-mesh sand with 240 lbm of the diversion frac for proppant distribution material such that it equates to 2 lbm/gal concentration for the diverter combinations based on the volume in which they were mixed. Because five proppant frac stages were planned, diversion material was dropped after Stages 1 through 4. After Stage 5, only a flush was to be used. Actual The fracture treatment used the

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following volumes (Note: All crosslinked gel was prepared using the 15cp linear gel): • 74,848 gallons of linear 15-cp fluid used for flushes and to place diverting material downhole • 75,663 gallons of crosslinked gel used in pad stages • 209,464 gallons of crosslinked gel used to carry 319,848 lbm of 20/40-mesh brown sand at 1, 2, 3 and 4-lbm/gal concentrations • 5,964 gallons of crosslinked gel to carry the diverters at a 2-lbm/gal concentration Figures 3 through 6 illustrate the diversion effects. Stage 1 (not shown) pumped 47,833 lbm of proppant,

and Stage 2 was commenced (Figure 3). Stage 2 first dropped a diverter at 11:23 minute on the surface, and it arrived at the calculated bottom interval at 11:43 minute, which corresponds to a 200-psi increase in pressure between these two times as the diverter approached an uphole, open perforation. The operations proceeded to frac, as designed. A total of 123,203 lbm of proppant was pumped during Stage 2. In front of Stage 3 was the second diverter drop (Figure 4). The diverter was dropped at 13:46 on the surface, and at 14:11 it reached the calculated bottom interval, with a 400-psi increase in pressure at 13:56. Operations proceeded to frac Stage 3.

Figure 3. Pumping of diverter following Stage 1 and the pumping of Stage 2

Figure 4. Diverter after Stage 2 and the pumping of Stage 3

Upstream Pumping Solutions • July/August 2013

Sand-laden fluid was pumped (not as designed, due to high pressures) at 0.5 and 1 lbm/gal. A total of 32,891 lbm of proppant was pumped. Prior to Stage 4 was the third diverter drop (Figure 5). The diverter was dropped at 15:54 on the surface, and at 16:18, it reached the calculated bottom interval, with a 300-psi increase in pressure at 16:16. Operations proceeded to frac Stage 4. Sand-laden fluid was pumped (not as designed because of pressure rise) from 0.5, 1, 2 and 3 lbm/gal. The operator did not attempt to pump the 4-lbm/gal concentration. A total of 115,921 lbm of proppant was pumped during Stage 4. Preceding Stage 5 was the fourth diverter drop (Figure 6). The diverter

was dropped at 17:45 on the surface and reached the calculated bottom interval at 18:17, with elevated pressures. Pumping sand-laden fluid was not attempted because of maximum pressure, and the job proceeded to the flush stage. Conclusions This work discusses a case history from a horizontal west Texas well in Ward County involving diversion frac for proppant distribution. The project was initiated with a troubled horizontal wellbore, which was an economic burden. Having not been stimulated, any treatment seemed costly, because completion tools that had previously failed had to be altered before the

operator believed a fracture treatment could be attempted. A pumping service company engineered a remedial design stimulation program involving the preperforating of 12 zones and using a diversion frac for proppant distribution, which was pumped with excellent results. Both the service company and the operator were satisfied with the results, but production numbers have not yet been released at the request of the well operator. The 4,000-foot lateral and 144 perforations encompassing many stages of shale pay were effectively stage fracture treated in approximately 10 hours. This pump-in included 319,848 lbm of 20/40-mesh brown proppant and 365,939 gallons of fracturing fluid with additives and breakers set to create a significant stimulated reservoir volume, providing the well a very good chance for economic production. Part Two (September/October 2013) will include two other case histories using the diversion frac method.

Figure 5. Diverter after Stage 3 and the pumping of Stage 4

Figure 6. The diverter after Stage 4 did not allow pumping of Stage 5

References 1. EIA U.S. Energy Information Administration, August 2012. 2. Halliburton. 2012. AccessFrac PD. Technology Bulletin SMA-1-000-X, 8/23/2012. 3. Reyes, R., Glasbergen, G., Yeager, V., and Parrish, J. 2011. DTS Sensing: An Emerging Technology Offers Fluid Placement for Acid. Paper SPE 145055 presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, 30 October – 2 November.

Robert Reyes is on the Technology Team for Halliburton Energy Services in the Permian Basin and has 18 years of experience in the oil and gas industry. www.upstreampumping.com

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WELL COMPLETION

Fluid End Life By Gary Pendleton and Rob McPheron, AXON Energy Products Fluid end developments and modular design prolong fluid end life while maintaining higher pressures.

A

s the hydraulic fracturing industry has grown and developed in recent years, greater demands are placed on hydraulic fracturing (frac) and well service pump equipment. Specifically, because of the necessity of well service capabilities at increasing depths, these pumps face higher pressures and greater power requirements.

Short Life in Harsh Conditions As one of the main consumables of the pump, the fluid end is greatly affected by these rising demands. Depending on the power rating of the pump, the fluid end must survive harsh operating environmental conditions while performing at increasingly high pressures and high flow rates. For example, operating pressures up to 15,000 psi and speeds of up to 300 strokes per minute are not uncommon. The life of the fluid end

Configurable quintuplex pump with modular fluid end assembly

is also greatly affected by the pumped proppant, which can cause erosion of the pump’s internal surfaces and valves. Ultimately, this reduces the pressure and flow rate capacity of the pump. Pumps are generally configured

as triplex (three pressure plungers) or quintuplex (five pressure plungers) units. During the operational cycle (one complete revolution of the pump crank), each pressure plunger is incorporated into operation. In particular, the triplex and quintuplex pumps operate at 120-degree and 72-degree intervals, respectively. For instance, the corresponding oscillating pressure cycles within a quintuplex fluid end range from a negative pressure (suction) to discharge (up to 15,000 psi), occurring every fifth of a second for a pump operating at 300 strokes per minute. The eventual result of these demanding conditions is fatigue cracking.

Searching for Solutions Examples of varied fluid end replacement types

20

Upstream Pumping Solutions • July/August 2013

During the last decade, the industry has developed and refined its fluid

Depending on the power rating of the pump, the fluid end must survive harsh operating environmental conditions while performing at increasingly high pressures and high flow rates. ends to provide operators with solutions to prolong fluid end life while maintaining high pressures. For example, tougher carbon steels and/or stainless steels have been developed to provide increased durability of the internal surfaces to reduce the erosive effects and resist fatigue cracking. These properties must be balanced with the increased difficulty of machining tougher steels and the chemical effects of the proppants used. Techniques have been specifically developed to reduce fatigue effects, including autofrettage and shot peening. Autofrettage is a metal processing technique that exposes the fluid end to massive pressure, causing its internal portions to yield. Shot peening is achieved by accelerating spherical media against the fluid end’s surface to form small dents. Both methods provide localized, compressed surfaces within the internal

structure of the fluid end. For cracking to occur, the compressive stresses must be overcome before a tensile stress can be developed. Once in the tensile region and subject to material and geometric properties of the fluid end, cracking may begin. Additional benefits can be achieved with modular fluid ends if the pressure containment can be isolated from imposing stresses to adjacent fluid end cylinders. Because of its design, stress transfer typically occurs between cylinders in monoblock assemblies. In contrast, single fluid ends (in a triplex or quintuplex model) provide a natural break in the

stress transfer, reducing the flexing stress amplitude within the fluid end. This improves pressure cycles and reduces cylinder stress during operation, thereby diminishing the potential for fatigue stress. All fluid ends could ultimately fail because of fatigue cracking or a reaction to chemicals, erosion or a combination of these. When operating at high pressures, fluid ends are prone to finite lifespans. Using modular fluid end assemblies instead of a monoblock design results in easier maintenance and reduced downtime. In particular, the modular design allows for reduced maintenance cost and time required for service. Inventory options are also more viable with the modular design, further decreasing downtime. For example, it is more viable to have single fluid end assemblies in

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21

WELL COMPLETION

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Modular fluid end assembly compared with monoblock fluid end assembly

22

inventory—ready for replacement in the frac pump when needed— rather than enduring downtime as the monoblock assembly is manufactured. Moreover, converting from monoblock to modular does not require special tools, training or parts. Regardless of the design, fluid end life can be extended with a maintenance program that includes: • Inspecting fluid end internals for damaged or worn parts after each job • Washing fluid ends to remove any stagnant sediment • Inspecting stay rods and tie bars for proper torque compressions • Maintaining accurate data for the total rate pumped Rather than mitigating pump issues as they occur, a thorough maintenance schedule is ideal to ensure the longest fluid end life possible.

Upstream Pumping Solutions • July/August 2013

Gary Pendleton is the chief technology officer at AXON Energy Products. He has been involved in product development in an i andd has h extensive range of industries a track record of leading-edge technology development and innovation. He holds an engineering degree from the University of Sunderland and patent registrations in a variety of industries. Rob McPheron is the account manager for AXON Well Intervention Products with an expertise in well service pumps and equipment. After attending Middl Middle Tennessee State University and running his own business for seven years, he joined AXON in 2009. He is a member of SPE, AESC and ICoTA. He can be reached at robmcpheron@ axonep.com or 832-655-9437.

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One Company. . .Unlimited Solutions circle 105 on card or go to upsfreeinfo.com

SSPECIAL P EC I A L s e c t i o n

SPECIAL s e c t i o n

Performance of the system on line pipe during reeling and installation was tested via bend testing.

Pipeline Protection During Deepwater Production By Alexander Lane, The Dow Chemical Company Wet insulation systems for subsea flow assurance provide reliable performance in extreme environments.

A

s global energy demand continues to rise, operators are pursuing new frontiers in oil and gas exploration. Following several years of steady gains, deepwater has emerged as a leader in unconventional oil and gas production. According to an Information Handling Services report, deepwater reserves accounted

24

for more than 75 percent of new discoveries last year, exceeding onshore and shallow water discoveries in number and size. Deepwater reservoirs are typically located on the outer edge of continental shelves and may be found within the frigid confines of the Arctic Circle. Both situations pose special challenges to nearly every aspect of

Upstream Pumping Solutions • July/August 2013

oil and gas exploration and production, including the installation and operation of pipeline flow assurance systems. In subsea oil and gas production, flow assurance insulation technologies used to prevent hydrate and wax formation typically rely on external coatings, known as wet insulation,

SUBSEA EQUIPMENT that provide thermal protection and corrosion control from the wellhead to the delivery point. Polypropylene and polyurethanes have long been preferred materials for flow assurance insulation, primarily because they satisfy performance needs in a repeatable, cost-effective manner. In deepwater environments, flow assurance becomes more challenging because oil flowing from the reservoirs is often much hotter than oil from shallow water or onshore wells. At the other temperature extreme, subsea Arctic wells face flow assurance challenges because of extremely cold ambient temperatures, which can restrict the flexibility of insulation material and complicate pipe reeling and installation. In both cases, these conditions stretch or exceed the thermal and mechanical capabilities of current wet insulation offerings for subsea flow assurance.

Flow Assurance Solution

in-service temperatures as high as 160 C (320 F). Testing also demonstrates the system’s ability to retain flexibility and toughness in temperatures as low as -40 C (-40 F). The insulation system features a hybrid polyether thermoset insulation coating for thermal protection and a fusion-bonded epoxy (FBE) underlay for corrosion resistance. The special FBE anti-corrosion coating is based on a specific epoxy resin technology and is used for line pipe and field applications. The insulation system maintains a consistent, low K-factor across components and delivers thermal and corrosion protection using a single technology that works from the wellhead to the delivery point. This feature helps improve reliability at any foreseeable subsea depth by reducing the potential risks associated with bonding dissimilar and potentially incompatible materials used on line pipe, subsea architecture and field joints.

To bridge the performance gap, a Testing System Performance chemical company initiated a multiyear research project to develop a Several tests were conducted in lab pipeline flow assurance insulation soand small-scale to ensure the insulalution that would reliably perform at tion system’s viability for component higher service temperatures and lower coating, pipeline installation and longinstallation temperatures. Joining term service performance prior to forces with insulation system applicacommercial-scale testing. In ring shear tors worldwide, this initiative resulted testing, a coated pipe without a joint in the development of a subsea flow was cut, and a section was evaluated assurance wet insulation system. for system adhesion by quantifying The subsea flow assurance wet insulation system is based on a special insulation material that offers uniform performance from the wellhead to the delivery point with a wide installation and operating temperature range. Ongoing test data demonstrate that the system has the ability to withThe flexural fatigue test demonstrated the stand pressures found at water depths flexibility of the system and its resilience to vibrations that may be experienced of at least 4,000 meters and mainduring production. tain stable thermal conductivity at

the force required to separate the duallayer system from the pipe. During flexural fatigue testing, system flexibility was tested by cycling a coated pipe with a coated joint 100,000 times to imitate the vibration that may be experienced during production. In thermal shock testing, a coated pipe with a coated joint was subjected to sudden changes in temperature, cycling between 4 C (39.2 F) and 160 C (320 F) to simulate sub-zero installation temperatures and hot oil flowing through a cold pipe. These extreme temperature fluctuations tested joint adhesion and the overall mechanical integrity of the system. In all cases, third-party testing confirmed that the mechanical properties demonstrated by the system in lab and small-scale testing were fully reproducible at full commercial scale.

Optimizing the Application Process In addition to extensive performance testing, commercial-scale coating trials were conducted to establish simple, repeatable commercial application processes. Across all three application areas, the coating trials indicated that the application processes for the components of the insulation system were complete and that the system can be applied at full-scale.

Insulation for Line Pipe Insulation for line pipe was successfully applied by a member of the global qualified coater network at a new pipe-coating facility near the Gulf of Mexico. The chemical company collaborated with this coater on the full-scale qualification of the special line pipe insulation and worked to optimize the insulation application capability of the plant. While full-scale pipe trials continued, a bending/straightening trial www.upstreampumping.com

25

SPECIAL s e c t i o n of jointed pipe coated with special line pipe and field joints insulation materials was conducted in 2012 to test the performance of the insulation system on line pipe during reeling and installation. The pipe was subjected to five bending and straightening cycles on a 7.5-meter radius bending former and a 30-meter radius straightening former, respectively, at 8.7 C (47.6 F) ambient test conditions. The pipe passed with no audible or visual signs of disbondment or cracking. The pipe was subsequently exposed to simulated service test conditions and posttesting as well, without any issues. After large-scale testing, specimens from the pipe were machined to confirm property retention.

Insulation for Field Joints The coater for the special field joints

insulation had advanced equipment installed at its new research and development facilities to support the new technology offering. This coating application specialist demonstrated a simple and robust field joint coating process for special field joint insulation at full production scale on 8-inch line pipe coated with the special line pipe insulation. The robust, reproducible process resulted in highquality field joints with a competitive 15-minute cycle time, high mobility and a compact equipment footprint.

Complex Geometry Insulation for Subsea Architecture Another important step in the ongoing qualification of the insulation system as an end-to-end subsea flow assurance solution was the successful coating of subsea architecture with a

complex geometry. Since the introduction of the insulation for subsea architecture with a complex geometry, a member of the global qualified coater network has refined its coating application process to verify its ability to custom coat complex subsea architecture and successfully applied the special complex geometry insulation to an experimental piece of subsea architecture designed with intentionally complex geometry. In preparation for the complex geometry trial, the chemical company conducted extensive finite element analysis modeling and worked closely with the coater to design a rigorous test piece that would exceed the level of complexity typically found in subsea architecture. Modeling results informed the final shape of the mold design and some of the internal coating processes. After prototype testing and scale-up, the coating demonstration was successfully conducted and replicated with multiple pours and witnessed by members of a joint oil and gas industry group.

Conclusion The chemical company continues to pursue a high level of flow assurance qualification for the wet insulation system to decrease risk, especially in extreme environments. The new technology has been indicated for use in subsea insulation applications.

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26

Upstream Pumping Solutions • July/August 2013

Alexander Lane is the global business leader for the Transmission segment of Dow Oil, Gas & Mining, a market-facing business of The Dow Chemical Company. Hi His responsibilities for the segment include strategic marketing, business development, business model innovation and profitability.

SUBSEA EQUIPMENT

Low-Vibration Compressor Motors By Sumit Singhal, Siemens Motor Structural Design Last of Three Parts

E

lectric motors for high-speed, turbo compressors used in the oil and gas industry are limited by three factors: centrifugal forces, thermal considerations and rotordynamic (shaft vibration) behavior. Part One discussed the many offshore, subsea and onshore applications for electric motors. It also covered the causes of vibration. Part Two included the requirements of rotor and bearing design to limit vibration. Part Three discusses the structural motor design necessary to minimize vibration in compressor trains.

Interaction Between Rotating/Non-Rotating Structures Electric motors are a special class of rotating machinery in which there is strong interaction between the rotating shaft and non-rotating structures—such as the stators and the frame—because of the presence of electromagnetic forces in the air gap. These act on both the rotor and stator. To have low vibration levels, the motor should be free of combined rotor-structural resonance points in the operating speed range. Rotating rotor and non-rotating structures are coupled through oil film forces at the bearing locations and also by electromagnetic forces in the rotor-stator air gap. Electromagnetic

forces generated in the air gap rotate at the line frequency and twice the line frequency. Forces at twice the line frequency can cause ovalization of the stator and frame, which is manifested as vibration and noise. These 2-times deformations can possibly be transmitted through the base frame to the pedestal bearings. This results in axial bearing housing velocities that can exceed the specified limit. These vibrations are related to second-order resonance amplification in the stator structure. To assess the vibration behavior and minimize the risk for vibration problems in the field, rotor dynamic calculations in critical drive trains should be performed—including the non-rotating structures. Figure 1a shows the pure rotor bending modes that are decoupled from non-rotating structures. Figure 1b shows rotor

Figure 1a. Pure rotor bending mode shape

bending because of a large movement of the stator. This vibration mode does not exist if full modeling of the non-rotating structures is excluded from the calculation. Normally, the resonance points of a rotor can be easily identified. This is more complicated for the nonrotating parts because sheet metal construction has many modes, and filtering out the critical ones is not easy. The modal mass is one indication for relevant modes. Only modes with sufficiently high modal mass must be considered for structural vibration purposes. To identify the most critical modes, a forced vibration response calculation is usually required. The most sensitive factor for these types of calculations is the assumption of modal damping factors for the individual modes. Comparison of calculation and measured response values leads to modal damping factors of between 1 to 3 percent, depending on the participation of bolted connections or other damping elements in the mode shapes. In most cases, a visual estimation of mode shapes (how many joint connections are involved in that mode) will lead to normal damping values. For detailed structural calculations, a sufficiently accurate knowledge of the foundation

Figure 1b. Rotor bending caused by large movement of non-rotating structure (stator) www.upstreampumping.com

27

SPECIAL s e c t i o n is necessary, which is discussed in the next section.

Foundation High-speed drive trains for turbocompressors are mounted on either concrete or steel foundations. The vibration behavior of the drive train system on a concrete foundation is much different than one on a steel foundation. A concrete foundation has high stiffness, and if designed correctly, does not have much influence on the vibration behavior of the shaft and bearing housings. The stiffness of a steel foundation is much lower than that of a concrete foundation. Therefore, it has a significant influence on the vibration behavior of the drive train system. This means that mass stiffness and damping of the foundation table should be included in the rotordynamic calculations to better predict the field vibration behavior. A steel foundation that is much softer than the drive train structure is not uncommon. At the design stage, stiffness parameters of foundations are based on finite element models. Quality and modeling methods influence the derivation of foundation parameters that are used in rotordynamic models. The stiffness of the motors is normally not considered when designing the foundation. The mass and mass moment of inertia of the motor, for example, are usually modeled using single mass points. The connection of the mass points can be realized using rigid beams to the foot point of the motors. Ideally, the stiffness of turbomachinery foundations should be higher than the stiffness of the machinery oil film and bearing housing stiffness. For large turbomachinery trains, this cannot be accomplished in every case because of arrangement and cost/space restrictions. When the

28

foundation parameters are included in the rotordynamic model, this significantly affects the predicted vibration behavior. For soft foundation designs, rotordynamic behavior and vibration amplitudes predicted based on static foundation stiffness are very different than if the modal mass and the stiffness of the foundation is considered when making the analysis. The differences in the vibration amplitude calculations arise because the system eigenvalues (natural frequency) may be different for these methods. If the system eigenvalue is close to the operating speed range, then this will increase the vibration amplitudes. Realistic predictions can be made by finite element models of

the complete system, including the foundation and machine structure. A complete system analysis requires a large amount of computing power and expert engineering resources. Figures 2a and 2b show examples of these evaluations. In accordance with DIN 4024, two foundation options are available—rigid and flexible. Rigid foundations mean the first eigenvalues are higher than the operational speed. In most cases, only flexible foundations can be incorporated, which means that the first or several eigenvalues are within the operational speed range. In this case, the stiffness of the foundation may influence the rotor dynamic calculation. To avoid vibration caused

Figure 2a. Pure rotor bending mode, concrete foundation

Figure 2b. Foundation bending mode influencing shaft preparation at the drive end of the motor

Upstream Pumping Solutions • July/August 2013

SUBSEA EQUIPMENT by the foundation, the first eigenmodes of the foundation should be, at a minimum, 20 percent lower or 25 percent higher than the operational speed. The higher mode should have a separation margin of more than 10 percent. The second design criteria used for foundations are effective in maintaining the vibration amplitudes at the machinery bearing housing and/or casing in accordance with DIN ISO 10816. For motor design vibration acceptance criteria, velocity measures in accordance with DIN ISO 108163 should not exceed 4.5 millimeters per second for rigid foundations and

7.1 millimeters per second for flexible foundations. These values are for Zone B/C or during operation. For the response analysis, an imbalance quality of G 6.3 and a structural damping of 2 percent in accordance with DIN 4024 should be assumed.10

Conclusion Special considerations must be applied when designing high-speed electric motor drives to meet low vibration requirements. Special design features, optimization of the rotor, correct selection and optimization of fluid bearings and magnetic bearings are required to comply with

Figure 3. Drive train on a steel foundation

Figure 4. Motor on a steel foundation with three-point support on an offshore oil platform

rotordynamic and vibration limits. The interaction between rotating parts and non-rotating structures must be considered to identify the effects of the system coupling on rotordynamic and shaft vibration. In addition to the motor design, external influences involving the foundation design can lead to high drive train vibration levels. To avoid vibration problems in the field, a complete system analysis, including the drive train and foundation, may be required. Series References 1. H. Kuemmlee, P. Wearon, F. Kleiner, “Large Electrical Drives—Setting Trends for Oil & Gas Applications,” in IEEE PCIC Conference Record, 2008, PCIC2008-30. 2. S. Singhal, H. Walter, T. Tyer, “Concept, Design and Testing of 16,000 HP 9,500 rpm Induction Motor with Oil film Bearings for Pipeline Applications in North America,” IEEE PCIC Conference Record, 2013. 3. API Std. 684: Tutorial on the API Standard Paragraphs Covering Rotor Dynamics and Balancing. 4. S. Singhal, R. Mistry, “Oil Whirl Rotordynamic Instability Phenomenon— Diagnosis and Cure in Large Induction Motors,” in IEEE PCIC Conference Record, 2009. 5. A. Kimball, “Vibration Prevention in Engineering,” New York, John Wiley & Sons, Inc., 1932. 6. D. Hartog, “Mechanical Vibration,” New York, McGraw-Hill, 1934. 7. API 546 – Brushless Synchronous Machines – 500 KVA and Larger. 8. API 617 – Centrifugal Compressors for Petroleum, Chemical and Gas Service Industry. 9. ISO 14839: Mechanical Vibration – Vibration of Rotating Machinery Equipped with Active Magnetic Bearings, 1st Edition, 2004, ISO 10. DIN 4024 – Machine foundations

Sumit Singhal is with Siemens Drive Technologies Division, Large Drives Applications. He can be reached at [email protected]. www.upstreampumping.com

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The Marcellus Shale presents unique challenges to operators developing these assets. Image courtesy of Baker Hughes

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Upstream Pumping Solutions • July/August 2013

THE MARCELLUS SHALE

Still a Production Giant By Lori K. Ditoro With nearly doubled rates in 2012, the Marcellus Shale continues its dominance in U.S. natural gas production.

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n 2012, the Marcellus Shale was the most productive gas field in the nation. The play that ushered in the shale gas boom is still the dominant production gas field today. Pennsylvania and West Virginia now produce 7 billion cubic feet of gas per day, which is 25 percent of the nationwide production and nearly double 2011’s rate.1 After declining because of the natural gas surplus, prices are beginning to creep up. President Obama’s recent support of natural gas exports and upcoming pipeline projects to help move the vast quantities being produced are helping the rebound in prices. Because of this, natural gas production rates are increasing again as well.2 While those in the industry understand that hydraulic fracturing has been used for decades and is safe when conducted correctly, environmental concerns continue to be at the forefront of production in the area. Doug Walser’s Report from the Field on page 32 discusses the need for and steps to take for responsible production in the area. This report includes the important concern of water use and treatment. Many well service companies have embraced the challenge of preventing water contamination. They have developed systems to treat and reuse produced water to prevent

the depletion of precious freshwater sources (more critical in the arid climates of Texas and North Dakota) and avoid produced water disposal. Technological developments will continue to improve production and facilitate all aspects of the drilling, completion and production process. During hydraulic fracturing, sand, water and chemicals are sent under extremely high pressure into the shale play. New proppants, called Penn Prop, are beads from recycled glass and other waste items that are used instead of sand. This new proppant could increase Marcellus shale production by 50 percent.2 The economic benefits of the upstream oil and gas industry’s operations in the Marcellus Shale are great. However, the need for infrastructure for transportation and downstream refining of the produced hydrocarbons will prove to be economic drivers as well. In March 2012, Shell Oil Company selected a site about 30 miles north of Pittsburgh for a petrochemical plant to convert natural gas liquids into plastics and antifreeze, but the final decision to move forward is still several years away. The need to transport the produced gas to areas on the East Coast for processing means that pipeline infrastructure must be added and aging infrastructure must be repaired, updated or replaced. Experts predict

that more than 50,000 miles of new pipeline will be laid as a result of Marcellus Shale drilling.3 With surplus natural gas supplies, the U.S. is seeing an increase in its use. Most new-construction power generation facilities are natural-gasfired, and many municipalities are turning to natural-gas-powered vehicles for their fleets. Since natural gas is a cleaner burning fuel than coal, fewer emissions mean a cleaner environment. In Pennsylvania specifically—in the center of the Marcellus—a housing shortage is also leading to new construction and adaptation of the hotel industry to accommodate the continued influx of workers to the area—an additional economic benefit for the region.2 References 1. Begos, Kevin, “Marcellus natural gas production expanded in 2012,” Businessweek, Dec. 26, 2012. 2. Carter, Jon, “How to Make Money by Investing in Marcellus Shale,” www.energyandcapital.com, July 19, 2013. 3. Youker, Darrin, “Marcellus Shale Drilling Driving Expansion in Pipelines,” Country Focus, www.pfb.com, January 2012.

Lori K. Ditoro is editor of Upstream Pumping Solutions.

www.upstreampumping.com

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A New Focus on Responsible Development

REPORT FROM THE FIELD

By Doug Walser, Pinnacle, a Halliburton Service Line A revolution concentrating on responsibility is taking place in North American unconventional oil and gas extraction—particularly in the Marcellus Shale.

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not-so-quiet revolution is underway in North American unconventional oil and gas extraction, centered in the Appalachian Basin and, more specifically, the Marcellus Shale. The upheaval is not violent, but it is transformational. While not purely technical, it involves continuous technical improvement. It is not only political, but politics are an integral driver of the process. It is not just a fiscal issue, but microeconomics are the motivation for the hundreds of thousands of decisions made by individuals, families, advocacy groups and the corporations that ultimately spend capital to attempt to achieve a return on their investments.

been stimulated. Opposition to development activities initially started public debate. Advocacy groups from all walks of life used questionable tactics, taking advantage of general unawareness of the business and technical specifics. As the years have passed and the (once muddy) issues have been clarified, a number of realities are being recognized by the general public and industry participants: • Industry activities must be performed responsibly—from an environmental, health and safety perspective. These three areas of focus must be taken seriously. • D&C activities should be directed and performed by locally sourced human resources whenever pos-

The Marcellus Shale has been targeted by developers since the mid-1800s. Changes in drilling and completion practices are evolving almost daily. The Marcellus Shale has been targeted by developers since the mid1800s. However, during the last eight to 10 years, incremental improvements in drilling and completion (D&C) practices have increased the level of activity to such a degree that public awareness of the industry has

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sible, so that the flow of cash generally remains regionalized to the greatest extent that is reasonable. • The concerns of local residents must be seriously considered and addressed. • Environmental practices that are often considered unnecessary or extreme in other regions of the world are entirely appropriate for

Upstream Pumping Solutions • July/August 2013

this area. These include a major focus on surface and groundwater protection, significant footprint reduction per unit of hydrocarbon produced, optimized use of fresh water, and careful attention to minimizing existing infrastructure disruptions. These realities have always been well understood by many industry participants. The difference today is that corporations, groups and individuals are recognizing that they must be applied across the board if continued regional participation is desired. Fortunately, lifting and transportation costs are on the low end of what is generally observed in North America, so even with extended low gas commodity pricing, some companies have declared positive margins associated with continued Marcellus activity.

Footprint Reduction Footprint reduction per unit of hydrocarbon produced has become important in the drive to minimize localized impact in sensitive areas. The process of horizontal drilling and multi-well pads has, by its nature, reduced the surface footprint. While four to six wellheads per pad location have been used for a while as starting

THE MARCELLUS SHALE

points for parallel horizontal development wells, more operators are moving to or considering eight wellheads per surface location, and some operators have experimented with 10 to 12 per location. Different factors restrict an immediate and complete industry move to the higher concentrations. First, industry experience with tight parallel wellbore spacing (the downhole laterals 400 to 800 feet apart from each other from a map view perspective) has demonstrated that the acceleration of reserve recovery is best enabled when the time period between completions is short, on the order of hours or days, as opposed to months or years. The implication, then, is that one drilling rig on one pad drilling eight

The process of horizontal drilling and multiwell pads has, by its nature, reduced the surface footprint. wells sequentially will normally force hydraulic stimulation and completion activity to wait for multiple months until the drilling of all eight (or more) wells is finished. Obviously, production from those same eight wells is delayed by that same process. Therefore, cash flow and the cost of capital become non-negligible issues of concern. Some unique methods for enabling simultaneous drilling rigs on the same pad have been considered, but so far, that scenario has not been actively embraced by the industry as a whole.

Second, including eight or more wellbores per pad necessitates construction of incremental surface infrastructure to handle extremely high production rates for relatively short periods of time. This infrastructure (pipelines, compression, separating and stripping facilities) is customized to the particular hydrocarbon and water stream that is expected to be produced, as opposed to what is actually produced. Therefore, designing these facilities involves considering factors associated with over- or underestimating the magnitude and

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Fresh Water Use Reduction Operators and service companies alike recognize that conservation and protection of surface and subsurface sources of drinking water are critical to continued sustainability of the energy industry in the region. As operators continue to transition from acreage delineation to full-scale field development in a manufacturing mode environment, responsible recycling of fracturing fluid makeup water is rapidly becoming the rule rather than the “experiment.”

sourced in or adjacent to the target reservoir. This water often has elevated chloride content, suspended solids and dissolved minerals that must be dealt with prior to reuse. • Water from other industrial, residential or natural sources that does not meet “fresh water” standards—Custom analysis and treating is required. The technologies related to recycling, preparing and treating water for use in hydraulic fracturing operations have improved dramatically in the last three to five years. In addition to specialized chemical diagnostic and treatment tools, mobile electro-

In addition to specialized chemical diagnostic and treatment tools, mobile electrocoagulation units are used in anodic processes to coagulate solids and either drop them out or float them to the surface for mechanical removal. Three sources of water can generally be considered for pre-completion treatment and subsequent injection during hydraulic fracturing activities: • Load water from previous fracturing operations—This is “used” fracturing water that has flowed back to surface processing facilities and has mixed with pre-existing reservoir waters and some amount of solids and minerals from the reservoir of interest. • Produced waters from existing wells—Many older wellbores that have long since ceased the production of load water will produce small quantities of water directly

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coagulation units are used in anodic processes to coagulate solids and either drop them out or float them to the surface for mechanical removal. Historically, fracturing fluids used in unconventional shale plays such as the Marcellus have been based on fresh water with small amounts of additives that assist in functionalities—such as friction reduction, lowering of surface tension and scale prevention. During the last few years, not only are these additives shifting toward “greener” compositions, but determining exactly how much, what and where it is being pumped is becoming easier. Operators that actively

Upstream Pumping Solutions • July/August 2013

embrace these technologies gain respect from local groups, individuals and regulatory entities and play a vital role in improving the industry’s environmental footprint and reducing the overall use of surface and fresh groundwater.

Conclusion A revolution is occurring in the way business is being conducted in the Appalachian Basin. Employers are looking to local labor pools and local schools to staff the ramp-up in activity. States are finding ways to effectively legislate, administrate and regulate activity to balance economic viability with environmental responsibility. Local residents and groups are educating themselves on the specifics of the issues that impact them and their economy. As development activity in the Marcellus continues to mature, this region is and will continue to be a living example of how commonsense responsibility can be applied across North America and eventually to all unconventional plays worldwide.

Doug Walser has extensive (31 years) Permian Basin, Mid-Continent, Appalachia, Rockies and South Texas experience with Dowell Schlumberger; The Western Company of North America; BJ Services; and Pinnacle, a Halliburton business line. He has specialized in the calibration of threedimensional fracture modeling via a number of methods. Recently, he has specialized in the examination and comparison of the various emerging resource plays in North America, and more specifically, plays with liquid hydrocarbons. He has written 14 papers and holds three patents in his areas of interest. He can be reached at [email protected].

PRODUCTION

When sealing aggressive and abrasive crude oil in pipelines, reliability and extended service intervals are required. Challenging conditions place high demands on the design limits of sealing and supply systems, which can handle frequent stops/starts and occasional pressure reversals or reverse pump rotation.

The Revised API 682 Mechanical Seal Standard By Thomas Böhm and Markus Fries, EagleBurgmann The 4th Edition includes details on the revised product coding system, the seal system selection process and seal supply systems.

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fter nearly six years of intensive work, the American Petroleum Institute (API) 682 mechanical seal standard is soon to be adopted. Since its introduction in 1994, API 682 has become “the” standard that sets the global tone for the procurement and operation of seal and supply systems for centrifugal pumps in the oil and gas sector as well as in the petrochemical industry. API 682 is a “living” standard that directly incorporates diverse practical experience in its regular updates. Founded in 1919 and located in Washington, D.C., the API includes close to 500 companies from the oil

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and gas sector and the petrochemical industry. Since 1924, it has focused on technical standards. To this day, API has adopted roughly 500 standards that address diverse processes and components in detail—which ultimately ensure a maximum of operating and process reliability. API standards, which are clearly defined and in part attached to approval tests, do not only take effect in the U.S. In many cases, they have developed into worldwide industrial standards. API is often considered a synonym for safety and reliability. Individual standards—including API 682 regulations for mechanical

Upstream Pumping Solutions • July/August 2013

seals and seal supply systems—have become so popular that they have even been referenced in outside industry applications. The authors of the new edition point out that this was never the intention and clarify the actual purpose of the API 682 standards. The standards are for seal systems in pumps—not in agitators or compressors—and for oil and gas and petro chemistry—not for water supply or the food sector.

API 682 History Initial information about mechanical seals was originally provided in the API 610 pump standard. During

the 1990s, API 682 developed into a separate, more comprehensive standard for mechanical seals and supply systems. The API 682 standard is continually maintained and updated by end users and manufacturers. Another quality of API 682 is that it does not typically permit only a single technical solution. In addition to proven and tested standard solutions (defaults), the regulations also deliberately list alternatives (options) and even allow customized solutions (engineered solutions). This diversity is demonstrated more clearly in this edition than in previous ones. The composition of the 25-member task force is representative of the practical way in which API approaches the topic of seals. Since 2006, the task force has been updating the 3rd Edition of API 682 that took effect in 2004 and is still valid. In addition to leading seal system manufacturers, the American-European expert

panel—which intentionally counted on non-API member collaboration— also included renowned planning companies and representatives from some of the largest mineral oil groups, who are users of the seal solutions.

Checked and Tested Safety While the currently valid API 682 edition included about 200 pages, the 4th Edition is 260 pages. The revised edition is organized into a body of text with 11 chapters and detailed annexes with a significantly expanded scope. For example, Annex I provides detailed information on more than 20 pages for API-conform seal qualification tests. Default seals and options must be tested using five different media and clearly defined operating conditions representative of typical API applications. Together with the described seal designs, this yields a high number of

The Principle Innovations of API 682 4th Edition at a Glance Mechanical Seals • Adaptation of pressure limits: 20 bar (gauge) for Category 1, 40 bar (gauge) for Categories 2 and 3 • Detailed notes to engineered seals • Combination of seal types in Arrangements 2 and 3 • Definition of vapor pressure margin • Overview table of internal gap dimensions • Selection of SiC face material independent of category • Optional bellows material Alloy 718 for metal bellows seals, Type B • Additional requirement for set screws for torque transmission • New details regarding the selection and operation of pressurized double seal systems • Reduced minimum gap at the internal pumping device Seal Supply Systems • Transmitters instead of switches • Alternative arrangement selection method on the basis of Risk & Hazard codes • New API Plans (03, 55, 65A, 65B, 66A, 66B, 99) • Hydrostatic level detection for Plans 52, 53A • Temperature measurement of gas bubble for Plan 53B • 28-day refilling interval for barrier pressure systems • Minimum pipe wall thicknesses of 2.5 millimeters for welded joints • Temperature limits for instrumentation

possible test variations. In the process, the expended time per test and seal type can take up to 200 hours. The result for typical industry seal designs is documented in a test certificate and a detailed report. Customer-specific qualification tests can be agreed upon for engineered seals. Essentially, checked and tested product safety is the core of the standard. The objective of API 682 is continuous operation of at least three years (25,000 operating hours subject to the legally stipulated emission values, or for maximum “screening value” of 1,000 parts per million by volume, EPA Method 21), increased operational reliability and simplified maintenance. The standards defined by API apply exclusively to cartridge systems with a shaft diameter of 20 to 110 millimeters and a defined range of operating conditions.

Coding System The 4th Edition also includes the revised product coding system (Annex D). The proven classification parameters “Category,” “Arrangement” and “Type” will be continued. They are listed first in the revised code and provide information about the setup and field of use of the respective API seal. The seal arrangement includes: • Arrangement 1—single seals are differentiated • Arrangements 2 and 3—double seals with and without pressurization Details regarding the supply system—specified as “Plan”—are in the old and new code. The addition of precise information regarding material selection and shaft diameter is new. This gives more meaning to the code and guarantees a clear specification of the mechanical seal and its operation—from selection to www.upstreampumping.com

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PRODUCTION documentation. Industry experts agreed that the expanded coding system will prove itself in practice and endure permanently.

More Precision During Selection The selection process of an API seal system is complicated. Several flow charts and tables on more than 10 pages are dedicated to this topic in the new edition. To provide more precision in the technical selection process when determining the arrangement, an alternative selection tool (Annex A.4) has been included in the 4th Edition for the first time. This method is based on the established “Risk & Hazard Code” and has been tested in practice. The starting point is the pumped medium. Its real hazard potential is accurately recorded and described by the “Hazard & Risk Code” in the “Material Safety Data Sheets.” Decisions can be made quickly and securely, for example, about whether a single seal (Arrangement 1) will suffice, or if a double seal with barrier pressure system is required.

Practical Experience The experience-based, “lived” standard of the API 682 edition is demonstrated by the two silicon carbide (SiC) variants, reaction-bonded silicon carbide and self-sintered silicon carbide, which are treated equally as default materials for sliding surfaces in chemical (Category 1) as well as in refinery/oil and gas applications (Category 2 or 3). Until now, sintered SiC was set for chemical applications because of its superior chemical stability, whereas the reaction-bonded variant established itself in the refinery sector. This restrictive allocation was canceled because of practical application examples (best practices) that were brought to the attention of the task force, which called for a course correction. Chapters 8 and 9, dealing with the hardware for the supply systems and instrumentation, were subjected to intense revision. They were completely reorganized so that the topic is now handled in three stages, which makes it more systematic. The first block introduces the supply systems in total. The piping and the components are addressed next.

Numerous operators use robust seals in their gas injection compressors. Pre-configured seal management systems are also used to safeguard optimal operation of the gas-lubricated sealing system.

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Upstream Pumping Solutions • July/August 2013

Statoil offshore oil platform

Seal Supply Systems Plan 53 with a pressurized barrier fluid belongs to the more complicated supply systems. In detail, three types are possible: • Plan 53A is the solution with the constructively least amount of effort. The pressure on the barrier medium is generated directly via gas pressurization—normally with nitrogen—in the tank. However, the application has limits, since higher barrier pressures could cause a dissolution of the nitrogen in the barrier medium. The consequence would be the risk of inadequate lubrication in the sealing gap of the mechanical seal. That is why Plans 53B and 53C are used for higher barrier pressure. • Plan 53B uses a clever solution, which makes it popular. Pressurization occurs via an elastomer bladder in the reservoir that separates the nitrogen from the barrier fluid. Pressure monitoring with consideration of the temperature in the bladder accumulator records the values and transfers them

to the control room. The fill level with consideration of any temperature impacts is calculated there, and the correct time for refilling the barrier fluid is determined. • Plan 53C works with a piston accumulator, which makes it among the more sophisticated seal supply systems. A new prescribed refilling interval of at least 28 days has also been included in the 4th Edition of API 682. The fluid reservoir must be large enough to supply the seal with barrier fluid for this entire period—without refilling. To obtain the most compact reservoirs, the seal manufacturers are required to find optimized system solutions with minimal leakage values for the barrier medium. Also, Plans 03, 55, 65A, 65B, 66A, 66B and 99 have been newly included in the regulations and, along with the already existing plans, are described in detail in Annex G.

Transmitters Replace Switches Regardless of pressures, temperature, flow rates or fill levels, the 4th Edition heralds a change to modern transmitters for the supply systems. Switches had previously been the default, but transmitters have now taken the position. Although they can be more expensive, they transmit continuously measured values. The control room is now aware of the actual system status at any time and can immediately sound the alarm if problems arise. The transition to transmitters as default is illustrative: the API specifications primarily concern operating and process reliability and only then consider economic viability. This universal application is also verified by the decision of the task force to only permit seamless pipes in the future for

“Piping” for the supply systems. The use of welded pipes, which would be less expensive, was considered unacceptable. The task force also addressed the topic of heat resistance of instrumentation used in supply systems pragmatically. In the past, frequent debates occurred regarding whether supply systems for high temperature applications—for example, a 400 C approved pump—have to be equipped with special instrumentation for high temperatures. Now the temperature specification for the instrumentation has been limited to 100 C. If instruments with higher temperature limits are required in the future, the customer has to inform the seal vendor accordingly.

A Clearer Structure The essential improvements, in addition to the technical supplements and updates, are the clear structures of the latest API regulation. The body of the text was tightened and structured appropriately, whereas technical details and background information were placed in the annexes. Some of the wording in individual chapters was revised to improve understanding. The improved user friendliness is shown in Annex E, which addresses structured communication and data exchange between suppliers and customers. Descriptions that previously encompassed many pages in API 682 are now bundled into two compact checklists in the 4th Edition. The first list systematically describes what must be considered for inquiries and quotations. It specifies the data that needs to be provided and the additional information and documents with which it must be combined. For example, seal systems that deviate from standardized API solutions must be shown separately. Annex E is completed by a

second checklist that shows in which order the documentation is necessary. Apart from the numerous technical updates and improved user friendliness, one detail is visually the most striking innovation of this edition: all mechanical seals are equipped with red plugs in the supply connections of the seal gland upon delivery. Until the unit is installed, these plastic closures prevent the ingress of dirt in the seal. During operation, the connections are either assigned to pipelines, or the plastic plugs are replaced with enclosed metal plugs. An additional benefit is that the 4th Edition API seals are quickly identified by the red plugs.

Thomas Böhm is head of standardization – Division Mechanical Seals – for EagleBurgmann and an API Task Force member. He can be reached at thomas.boehm@ b h @ de.eagleburgmann.com or +49 8171 231048. Markus Fries is product manager at EagleBurgmann GmbH & Co. KG, Wolfratshausen. He can be reached at markus. fries@ de.eagleburgmann.com com or +49 8171 231161. EagleBurgmann is a provider of industrial seal technology that is used in industries including oil and gas, refinery, power, chemical, energy, food, paper, water and mining. For more than 20 years, the company has provided its knowledge in further developing API specifications for the design of seal systems for the oil and gas and petrochemical sectors and is active in the API 682 Task Force. For more information, visit www.eagleburgmann.com.

www.upstreampumping.com

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PRODUCTION

Testing Center Helps Ultra-Temperature ESP Systems Improve Operations By Lawrence Burleigh, Baker Hughes Because of the harsh nature of SAGD operations, specialized artificial lift systems are required.

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ince conventional oil supplies decrease each year and global energy consumption continues to increase, alternative methods of heavy oil production have become increasingly important to satisfy market demand. Bitumen is too thick to flow on its own, so steam is injected to reduce the bitumen’s viscosity. The steam-assisted gravity drainage (SAGD) method of producing bitumen involves drilling two horizontal wells parallel to each other, with one well about 15 feet above the other (see Figure 1). Producers liquefy the bitumen by injecting steam into the upper well so that the hydrocarbon flows downward into the lower well. Artificial lift techniques, such as elevated-temperature electrical submersible pumping (ESP) systems, bring the steam-heated oil to the surface. An innovative thermal-recovery ESP system is helping SAGD operators efficiently produce in the Canadian oil sands (see Figure 2). With this ESP system, operators reliably produce more from their bitumen and heavy oil reserves.

Birth of the UltraTemperature System A provider of ESP systems decided to enter the SAGD market more than

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Figure 1. SAGD method of bitumen extraction

10 years ago. It conducted intensive tests with a vertical, high-temperature test loop at its testing center. SAGD projects require ESP systems that can withstand the extreme heat generated by steam injection. With the vertical test loop, the supplier’s engineers were able to expand their research and development (R&D) capabilities to run tests autonomously in controlled temperature cycles that were more consistent with the SAGD environment. In a conventional oil well, the temperature is consistently hot. However, in SAGD operations, the injected steam controls the temperature and pressure, altering the productivity index of the well. The test’s hot loop must mimic these conditions.

Upstream Pumping Solutions • July/August 2013

This testing led to an extremetemperature ESP system, rated to bottomhole temperatures up to 428 F (220 C). Introduced in 2004, this extreme-temperature ESP system gained acceptance as a reliable method of artificial lift in the oil sands. The ESP provider was the first in the oilfield services industry to offer two new system innovations: the plug-in pothead and pre-filled motor/ seal. The plug-in pothead and prefilled motor/seal reduce rig time and avoid exposing the motor internals to harsh operating conditions, extending run life. These systems reliably operate in the presence of abrasives, gas and steam with abrasion-resistant components. They were equipped with

variable speed drives using specially designed software to optimize system starts and maximize performance in the presence of viscous oil. Oil sands operators determined that higher steam temperatures often resulted in increased production from SAGD well pairs. By raising the fluid temperature, the steam chamber volume around the horizontal well pairs is increased, and the bitumen becomes more mobile. This enables the bitumen to flow more easily into the producing well’s ESP system. In anticipation of ever-increasing temperature requirements, the provider invested in the industry’s first horizontal high-temperature test loop rated to 572 F (300 C), which was designed specifically to rigorously stress ESP systems to record breaking temperatures, such as those found in SAGD applications.

The New System The R&D efforts at the testing facility in response to operators’ specific requirements continued. Engineers worked to enhance the extremetemperature system and build on the extreme-temperature system’s success in the field and an ultra-temperature system was developed. Introduced in 2010, this ESP system was the first reliable ESP system rated at 482 F (250 C) bottomhole temperature. It included many upgrades over previous ESP system designs that

enable operation at increasingly high temperatures. Electrical and insulation upgrades extended motor run life, high-temperature motor oils ensured dependability, and upgraded motor power cable connectors and electrical motor lead extensions prevented failures. Development of the ultra-temperature ESP system also required extensive materials testing to optimize elastomers, epoxies, oils and additives. The engineers evaluated seven different oils to develop a synthetic oil with a custom additive package to fill the motors and seals. SAGD operators push the high-temperature envelope, so the engineers knew that they wanted a lift system that not only improved production performance but also extended reliability. This goal was accomplished. Early in 2013, these ESP systems reached a significant milestone of 100 years of cumulative run life, with several dozen systems in operation. To achieve long ESP run life, SAGD operators require that pump systems be equipped with gauges that can monitor continuous operation at elevated temperatures. To address this, a provider developed 536 F (280 C) rated fiber-optic pressure and temperature gauges. These gauges measure the intake, motor and discharge points of the system to deliver continuous readings. Fiber-optic gauges are placed inside the pump system during manufacturing, facilitating efficient, reliable pump installation at the well site. The gauges operate reliably at the elevated temperatures to deliver accurate and direct measurements. The data is sent from the well to the surface via a fiber optic line.

The Future Figure 2. The injected steam and the ESP system that lifts the thinned bitumen to the surface

center, not only for elevated temperature applications but also for deepwater and unconventional shale oil applications. The research and technology center is part of an expansion to help operators achieve production objectives. This facility will also provide laboratory space for developing industry-leading technology that supports customers operating throughout the world, especially in the Gulf of Mexico, Brazil, Canada and the North Sea. This facility has resources for advancing the technology of ESP systems, with fully monitored test wells and flow loops for evaluating pump system performance while handling high viscosity fluids at ultra-temperatures.

Lawrence Burleigh has worked in the ESP industry since 1998— applying ESP systems in oilfields, water wells, geothermal wells and SAGD applications in the U U.S., S Indonesia, Europe and Canada. He received a Bachelor of Science degree in mechanical engineering from Case Western Reserve University in 1989 and a Master of Business Administration from the University of Tulsa in 1996. He is also a registered professional engineer in the state of Oklahoma. Burleigh can be reached at [email protected]. Baker Hughes supplies oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company has more than 58,000 employees who today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information, visit www.bakerhughes.com.

Looking ahead, the ESP provider is expanding its artificial lift research www.upstreampumping.com

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TRADE SHOW ROUNDUP

Oil Sands Trade Show and Conference

SPE Annual Technical Conference and Exhibition

Sept. 10 – 11, 2013 Suncor Community Leisure Centre Fort McMurray, Alberta, Canada

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he Oil Sands Trade Show and Conference provides oil sands industry professionals with opportunities to learn about topics affecting the oil sands community. The Canadian oil sands have experienced rapid growth in past decade, which has resulted in more opportunities for commercial organizations across the supply chain. With the comparatively low cost of Canadian oil compared to the rest of North America, exploring topics such as the transport and infrastructure challenges is important for growth in the industry. For more information, visit oilsandstradeshow.com/2013/.

T

he Society of Petroleum Engineers’ Annual Technical Conference and Exhibition (SPE ATCE) has provided exploration and production industry professionals with an opportunity to network and gain technical knowledge for 89 years. SPE ATCE 2013 will include technical sessions— presented concurrently with an exhibition—that will concentrate on all phases of oil and gas exploration and production. For more information, visit www.spe.org/atce/2013/. Exhibition Hours

Exhibition Hours Tuesday, Sept. 10 Wednesday, Sept. 11

Sept. 30 – Oct. 2, 2013 Ernest N. Morial Convention Center New Orleans, La.

11 a.m. – 7 p.m. 10 a.m. – 4 p.m.

Monday, Sept. 30 Tuesday, Oct. 1 Wednesday, Oct. 2

9 a.m. – 6 p.m. 9 a.m. – 5:30 p.m. 9 a.m. – 2 p.m.

Exploring new opportunities for your business?

World Pumps This study analyzes the global pump industry. It presents historical demand data (2001, 2006, 2011) and forecasts for 2016 and 2021 by product, market, world region and major country. The study also evaluates company market share and profiles industry participants.

Study #: 2771 ...... Published: December 2012........Price: $6400

Oil & Gas Infrastructure This study analyzes the $8.9 billion US oil and gas infrastructure equipment industry. It presents historical demand data (2001, 2006, 2011) and forecasts for 2016 and 2021 by product, application and US region. The study also evaluates company market share and profiles industry players.

Study #: 2922 ......Published: November 2012 ........Price: $5100

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42

Upstream Pumping Solutions • July/August 2013

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OILFIELD RESOURCES

Honing Machine Ohio Tool Works launched its newest honing machine— the OTW Twin-Spindle 5000. The honing machine features specialized fixturing, tooling, abrasives and cutting fluids, making it a turn-key solution for high-volume pump barrel production and other oil and gas honing applications. Other advantages include twin parallel spindles for simultaneous production of two barrels and automated touchscreen PLC controls. Circle 200 on card or go to upsfreeinfo.com

Data Integration Software Northwest Analytics launched its enterprise manufacturing intelligence solution WA F id for oil and gas applications. NWA Focus EMI provides complete data source integration and real-time process analytics and visibility. Oil and gas operators can quickly view and share data-intensive production information from multiple assets over large geographical areas. The solution also features two accelerated modules which improve a user’s ability to accumulate and disseminate knowledge. Circle 201 on card or go to upsfreeinfo.com

Corrosion Protection Cortec Corporation’s VpCI 637 TOL provides internal corrosion protection for gas flow and gas transmission lines. The i water, corrosive i gasses and d product is effective against chloride contamination. It is a combination of vapor phase, neutralizing and film-forming corrosion inhibitors to combat corrosive attack from moisture and condensation, oxygen, carbon dioxide, hydrogen sulfide and other corrosive contaminants in natural gas. Circle 202 on card or go to upsfreeinfo.com

Cutter Chet Morrison Contractors developed an innovation in subsea cutting. The Subsea Hydraulic Abrasive Rotating Cutter (SHARC) was developed to make subsea plugging and abandonment work safer for dived for hand jetting and reducing ers by eliminating the need the time divers spend under water. SHARC also reduces overall job time by 60 percent. Unlike other methods, it does not require the use of explosives. Circle 203 on card or go to upsfreeinfo.com

Installation Tool American Power Tool Company introduced the SafetySwage SS-1 and SS-2, which are new compact portable power tools for installing single and two ferrule compression fittings. The tools allow workers to install a wide range of fittings in a fraction of the time required by hydraulic pre-setters. They also feature technology to ensure fast, accurate fitting installation in hard-to-reach locations. Circle 204 on card or go to upsfreeinfo.com

Protective Glove Ansell launched its newest protective winter glove. The ActivArmr 97-201 personal protective glove is designed to meet the challenges of Canada’s harsh winter climate, while offering optimum balance of protection and dexterity for the real-world extremes of oil and gas industry conditions. The reinforced Kevlar stitching supports a waterproof polyurethane barrier and the Thinsulate insulation keeps hands warm and dry. Circle 205 on card or go to upsfreeinfo.com

To have a product or service considered for Oilfield Resources, please send the information to Amanda Perry at [email protected]. www.upstreampumping.com

43

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HOST ASSOCIATION:

So

PRODUCED BY:

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The Largest Meeting Place for the World’s Shale Oil & Gas Industry

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Driving a Sustainable and Profitable Future for the World’s Shale Industry

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SILVER SPONSOR:

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For more information contact Robert Beckmann at at [email protected] or www.world-shale.com

CLASSIFIED ADS

Register for an informative webinar sponsored by

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“New Flux Drive SmartCoupling” Magnetic SmartCoupling saves energy on oversized systems by reducing pump speed. Torque transmission across an air gap also eliminates vibration, increasing bearing and seal life.

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INDEX OF ADVERTISERS Advertiser Name R.S. # Page AXON Energy Products .... 101 .... IBC Bal Seal Engineering Inc... 140 .......47 Baldor Electric Company...141 .......46 Basler Electric ................... 142 .......47 Burns Dewatering Services Inc. .................. 143 .......46 CENTA Corporation .......... 159 ...... 45 CENTA Corporation .......... 120 .......12 CheckPoint Pumps & Systems ..................... 131 .......42 CheckPoint Pumps & Systems ..................... 144 .......46 Dragon Products Ltd. ....... 102 .........5 EagleBurgmann ................ 145 .......47 FluxDrive Incorporated ......147 ...... 45 Franklin Electric ................ 148 ...... 45 The Freedonia Group........ 130 .......42 Garlock Sealing Technologies ................. 146 ...... 45 Gorman-Rupp Company .. 149 .......46 Gorman-Rupp Company .. 103 .........3 ITT Goulds Pumps ............ 150 ...... 45 JJ Tech .............................. 104 .......13

Advertiser Name R.S. # Page LobePro............................. 151 .......46 Meltric Corporation........... 152 .......47 National Oilwell Varco Mission ................ 105 .......23 Oil Sands Trade Show ...... 121 ...... 33 Penticton Foundry Ltd. ..... 126 .......21 Proco Products, Inc. ......... 127 .......26 Proco Products, Inc. ......... 153 .......47 PSG ................................... 122 .........8 Reliable Pumps ................. 125 .......22 Scalewatcher .................... 154 .......46 Scalewatcher .................... 123 .........7 Schlumberger ................... 106 ..... BC SERO Pump Systems, Inc.155 .......47 Siemens ............................ 156 .......46 Thompson Pump .............. 157 .......46 WEG Electric Corp. ........... 158 .......46 Weir Oil & Gas ................... 100 ..... IFC World Shale Oil & Gas ...... 108 ...... 44 Yaskawa America, Inc. ..... 109 .........9 * Index of Advertisers is furnished as a courtesy, and no responsibility is assumed for incorrect information.

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Shale Coverage Don’t miss

Lori Ditoro’s blog at

upstreampumping.com

Recently named one of the “Top 50 Oil and Gas People on Twitter” by Drillinginfo. Follow her on Twitter at

@LoriDitoro. www.upstreampumping.com

45

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©2013 Baldor Electric Company

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46

Upstream Pumping Solutions • July/August 2013

CLASSIFIED ADS

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MOTOR PLUGS

Metal Bellows

Turn up the heat with MBS682 for high-temperature performance. Available in single and dual cartridge seal arrangements, the MBS682 is API 682 compliant and has a complete resistance to temperatures up to 800°F. For more information on MBS682 metal bellows, visit getmetalbellows.com or call 800-303-7735.

QUICKLY CONNECT & DISCONNECT POWER OFF Button

www.EagleBurgmann.com www.EagleBurgmannNow.com

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Control and Protection

Safety Shutter (on receptacle)

for Engine/Motor Driven Pumps and Generators

Rated up to 200A, 60hp

 Connector + Switch in 1 device  Maximizes Arc Flash Protection  Minimizes PPE Requirements meltric.com 800.433.7642

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Engine Control

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47

UPSTREAM OIL & GAS MARKET

North American Proppant Market Update By The Freedonia Group, Inc. Demand to exceed 100 billion pounds by 2017.

N

orth American proppant demand has risen sharply during the past decade. While growth is expected to slow from the early years, double-digit annual gains are still expected, with overall demand reaching more than 100 billion pounds in 2017, valued at nearly $9.4 billion. Proppants are relatively simple products, but they have been critical to the expansion of oil and gas production in North America, setting off a chain of events that is revitalizing the region’s chemical processing and other manufacturing industries. Proppants have been used in oil and gas production for more than 60 years, but the advent of horizontal drilling technology coupled with multistage hydraulic fracturing created significant new opportunities for growth, starting around the mid2000s, especially as success in early applications such as the Barnett Shale in Texas translated to even more productive formations. These advances became more prominent at the same time that oil and gas prices skyrocketed, providing further growth im-

petus to drilling and completion activity. Continued high oil prices and a recovery in natural gas prices will sustain oilfield activity in the U.S. and Canada, with particularly good opportunities expected in several states including Texas, North Dakota and Pennsylvania. Opportunities are also expected in several developing plays in Western Canada, including the Montney and Horn River plays. However, nearly every area with significant unconventional reserves is expected to benefit from these trends. Raw sand will continue to account for the lion’s share of proppant demand. Although it generally cannot be used in wells with high closure pressures, raw sand performs suitably in most conditions. Because of their higher cost, ceramic proppants will be restricted to areas that require high performance products, especially as improved fracturing techniques have allowed raw sand to be used in applications previously thought to be beyond their performance range. However, these production areas include some of the larger centers of

North American Proppant Demand (billion pounds) % Annual Growth Item Proppant Demand By Country: United States Canada By Type: Sand Ceramic Other

2007 13,960 12,270 1,690 12,276 1,639 45

2012 59,100 53,260 5,840 53,550 5,272 278

2017 102,400 89,950 12,450 93,900 8,040 460

2007 – 2012 2012 – 2017 33.5 34.1 28.1 34.3 26.3 43.9

11.6 11.1 16.3 11.9 8.8 10.6

Source: The Freedonia Group, Inc.

48

Upstream Pumping Solutions • July/August 2013

upstream activity, such as the Eagle Ford Shale in Texas and the Bakken Shale in North Dakota, Montana and Canada, where sand and ceramics are often used together. Coated sand proppants are expected to increase their market presence because they offer cost advantages over ceramic proppants and performance advantages over raw sand. These different product types (and sizes) are often used in combinations that maximize well productivity. For example, coated proppants are often used to prevent the flowback of raw sand. Development of unconventional resources such as shale oil and gas has been the driving force behind growth in proppant demand during the past decade. While significant demand began with drilling in the Barnett Shale in Texas, more recent growth has been in liquids-rich formations such as the Bakken and Eagle Ford plays. Demand in these and similar formations is being driven by high oil prices, which is spurring drilling activity, as well as by the deep and highly challenging geology of these wells, which require greater amounts of proppant to complete because they generally involve more fracturing stages. The Freedonia Group is an international business research company, founded in 1985, that publishes more than 100 industry research studies annually. For more information, email [email protected], visit www.freedoniagroup.com, or contact Corinne Gangloff at [email protected] or 440-684-9600.

THE ALTERNATIVE

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TM

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Extreme-temperature environments require extremely reliable ESPs. Selecting the right ESP system, one that can effectively handle abrasive, high-temperature conditions, will extend the run life and enhance the production of your thermal recovery. Stemming from three generations of design and 80 years of high-temperature experience, the REDA HotlineSA3 ESP system provides field-proven reliability for hostile wells with bottomhole temperatures up to 250 degC [482 degF]. Find out more at slb.com/hotlineSA3

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