JUNE 2016 • VOLUME 68, NUMBER 6 JOURNAL OF PETROLEUM TECHNOLOGY Flow Control Technology Leadership

High-pressure large-bore BOPs in the Gulf of Mexico

Drilling Technology Sets the Standard

The only large-bore BOPs rated 20,000 psi and 25,000 psi in the fi eld today were designed, manufactured and installed by Cameron in the Gulf of Mexico. In addition, Cameron has the largest installed base of BOPs in the world. Today, Cameron o ers fully automated drilling technologies for onshore and o shore operations – all backed by full life cycle support, from conceptual design to installation and commissioning. Now, as part of Schlumberger, we look forward to extending our leadership in fl ow control technology.

Find out more at cameron.slb.com

All referenced trademarks are owned by or licensed to Schlumberger. © 2016 Schlumberger. All rights reserved. CAM-1007 CONTENTS Volume 68 • Number 6

14 GUEST EDITORIAL • ISN’T IT TIME FOR OUR OWN SPIELBERGIAN “IDEA SUMMIT”? Industry’s finest minds are expected to come together for an idea summit during the upcoming SPE Intelligent Energy International Conference and Exhibition in Aberdeen. At the bottom of the downturn, innovation, will, and collective imagination will help the industry get ready for the upturn.

28 EOR-FOR-SHALE IDEAS TO BOOST OUTPUT GAIN TRACTION The low recovery rates observed in most shale reservoirs has prompted a number of research projects to develop new enhanced oil recovery methods. But so far, there have been few success stories and a lot of work remains before the technology has wide applications.

32 NORWAY FACES UP TO HARSH CONDITIONS A row of pump jacks working in the The need to economically invest in offshore exploration and Bakken Shale, North Dakota, where production has inspired a wide range of innovations in Norway producers and university researchers to drastically reduce costs, which can lead to changes in offshore are developing new enhanced oil recovery methods to squeeze operations around the world. more oil and value out of existing horizontal wells. Photo courtesy of 40 RE-EMERGENT IRAN BRINGS LARGE POTENTIAL Ole Jørgen Bratland/Statoil ASA. With Iran re-entering the global oil market, a feature article looks at the state of Iran’s oil industry, the condition of its fields, its use of technology, and its present and future production potential.

44 OTC ASIA SESSIONS DISCUSS REGION’S ROLE DEPARTMENTS IN PRICE DOWNTURN, RECOVERY Representatives from various national oil companies, multinational  Performance Indices operators, service companies, and fabricators discuss the roles  Regional Update individual countries in the Asia Pacific region will play in the global  President’s Column oil market and the overall development of the region.  Comments  Technology Applications 47 MANAGEMENT • ENERGIZING WORLDWIDE OIL  Technology Update AND GAS DEEPWATER DEVELOPMENTS  E&P Notes What oil price is required to keep deepwater viable over the  People long term? A panel discussion at the 2016 Offshore Technology  SPE News Conference in Houston focused on the factors that influence  SPE Events deepwater developments, the scenario for the future, and the opportunities available within the industry. ‚ Professional Services  Advertisers’ Index

An Official Publication of the Society of Petroleum Engineers. Printed in US. Copyright 2016, Society of Petroleum Engineers.

TECHNOLOGY FOCUS

 COILED TUBING APPLICATIONS Alex Crabtree, SPE, Senior Adviser, Hess  Core Drilling Using Coiled Tubing From a Riserless Light-Well-Intervention Vessel  Focus on Ancillary Equipment and Fatigue in Coiled-Tubing Deepwater Commissioning  Optimization of Single-Trip Milling Using Large-Diameter Coiled Tubing

 MATRIX STIMULATION Lee Morgenthaler, SPE, Senior Staff Production Chemist, Shell  Sandstone-Acidizing System Eliminates Need for Preflush and Post-Flush MAKING Stages

 CO†-Energized-Acid Treatment Reduces Freshwater Use‡ Boosts Well Performance EVERY  No-Damage Stimulation By Use of Residual-Free Diverting Fluids TRIP  WELLBORE TUBULARS Pat York, SPE, Global Director, Weatherford  Steerable-Drilling-Liner Technology in Unstable Shale COUNT.  New Deepwater‡ High-Pressure GOM Tubular Maximizes Capability‡ Reduces Cost  Stuck-Pipe Prediction With Automated Real-Time Modeling and Data Analysis ZeroTime™ is a game-changing logging-while-working solution  EOR OPERATIONS that eliminates stand-alone Stephen Goodyear, SPE, EOR Deployment Lead, Shell diagnostic surveys by adding intelligence to routine trips  Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore ™ Environment in hole. ZeroTime enables operators to plan their next  Case StudyŽ Steam-Injection Step-Rate Tests Run in the Orcutt Oil Field move in total confidence with zero-added rig time.  Polymer Injection in Deepwater Field Offshore Angola  Colloidal-Dispersion Gel in a Heterogeneous Reservoir in Argentina - Minimise risk

- Maximise e
ciency

- Minimise costs

www.zerotime.info The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt. Introducing a new controlled optimization process for multistage completions ĮĞůĚͲůĞǀĞůƉƌŽŐƌĂŵďĂƐĞĚŽŶĐŽŶƐŝƐƚĞŶƚĨƌĂĐƉůĂĐĞŵĞŶƚ ĂŶĚŵĞĂƐƵƌĞĚĚŽǁŶŚŽůĞƉƌĞƐƐƵƌĞƐĂŶĚƚĞŵƉĞƌĂƚƵƌĞƐ

ŽŶƚƌŽůůŝŶŐŬĞLJǀĂƌŝĂďůĞƐĞŶĂďůĞƐƚƌƵĞŽƉƟŵŝnjĂƟŽŶ zŽƵĐĂŶ͛ƚƚƌƵůLJŽƉƟŵŝnjĞƉůƵŐͲĂŶĚͲƉĞƌĨĐŽŵƉůĞƟŽŶƐ͕ďĞĐĂƵƐĞĨƌĂĐ ƐƉĂĐŝŶŐĂŶĚƉƌŽƉƉĞĚǀŽůƵŵĞĂƌĞƵŶĐŽŶƚƌŽůůĞĚǀĂƌŝĂďůĞƐ͘dŚĞƐĂŵĞŝƐ ƚƌƵĞĨŽƌŽƉĞŶŚŽůĞƉĂĐŬĞƌͬďĂůůƐůĞĞǀĞĐŽŵƉůĞƟŽŶƐ͘ǀĞŶǁŚĞŶĂĐŽŵͲ ƉůĞƟŽŶŝƐĞĐŽŶŽŵŝĐĂůůLJĂĐĐĞƉƚĂďůĞ͕ƚŚĞƌĞŝƐŶŽŵĞƚŚŽĚŝĐĂůǁĂLJƚŽ ŝŵƉƌŽǀĞƚŚĞĚĞƐŝŐŶĨƌŽŵǁĞůůƚŽǁĞůů͕ďĞĐĂƵƐĞƚŚĞŶƵŵďĞƌŽĨĨƌĂĐƐ͕ ĨƌĂĐƐƉĂĐŝŶŐ͕ĂŶĚĨƌĂĐƐŝnjĞĂƌĞŶŽƚĐŽŶƚƌŽůůĂďůĞŽƌƌĞƉĞĂƚĂďůĞ͘ tŝƚŚƚŚĞDƵůƟƐƚĂŐĞhŶůŝŵŝƚĞĚΠƉŝŶƉŽŝŶƚĨƌĂĐƐLJƐƚĞŵ͕LJŽƵŬŶŽǁ WƌĞĚŝĐƚĂďůĞ͕ǀĞƌŝĮĂďůĞ͕ĂŶĚƌĞƉĞĂƚĂďůĞĨƌĂĐƐƉĂĐŝŶŐĂŶĚƉƌŽƉƉĞĚ ǁŚĞƌĞĨƌĂĐƐŝŶŝƟĂƚĞĂŶĚĞdžĂĐƚůLJŚŽǁŵƵĐŚƉƌŽƉƉĂŶƚLJŽƵƉƵƚŝŶĞĂĐŚ ǀŽůƵŵĞĞůŝŵŝŶĂƚĞŬĞLJƵŶŬŶŽǁŶƐƚŽĨĂĐŝůŝƚĂƚĞĨŽƌŵĂƟŽŶͲƐƉĞĐŝĮĐ͕ ŽŶĞ͘EŽŵĂƩĞƌǁŚĂƚĞůƐĞLJŽƵǀĂƌLJͶĨƌĂĐƐƉĂĐŝŶŐ͕ĨƌĂĐĚŝŵĞŶƐŝŽŶƐ͕ ǁĞůůͲƚŽͲǁĞůůŽƉƟŵŝnjĂƟŽŶĂĐƌŽƐƐĞŶƟƌĞĮĞůĚƐ͘ ƉƌŽƉƉĂŶƚƚLJƉĞ͕ĨƌĂĐŇƵŝĚ͕ŝŶũĞĐƟŽŶƌĂƚĞƐ͕ƉƌŽƉƉĂŶƚĐŽŶĐĞŶƚƌĂƟŽŶͶ ĨƌĂĐƉůĂĐĞŵĞŶƚƌĞŵĂŝŶƐƉƌĞĚŝĐƚĂďůĞĂŶĚƌĞƉĞĂƚĂďůĞ͕ƐŽLJŽƵĐĂŶ ĞǀĂůƵĂƚĞƚŚĞĞīĞĐƚƐŽĨƚŚĞĐŚĂŶŐĞƐLJŽƵŵĂŬĞ͘ Recorded downhole data describes every frac ƚĞǀĞƌLJƐƚĂŐĞ͕ŽƵƌƐƚĂŶĚĂƌĚDƵůƟƐƚĂŐĞhŶůŝŵŝƚĞĚĨƌĂĐͲŝƐŽůĂƟŽŶ ĂƐƐĞŵďůLJƌĞĐŽƌĚƐĂĐƚƵĂůƉƌĞƐƐƵƌĞƐĂŶĚƚĞŵƉĞƌĂƚƵƌĞƐĂƚƚŚĞĨƌĂĐnjŽŶĞ ĂŶĚŝŶƚŚĞǁĞůůďŽƌĞďĞůŽǁ;ƐĞĞĐŚĂƌƚĂƚƌŝŐŚƚͿ͘dŚĞĚĂƚĂƌĞǀĞĂůƐďŽƚŚ ƚŚĞƉƌĞƐĞŶĐĞĂŶĚƚLJƉĞŽĨĂŶLJŝŶƚĞƌnjŽŶĞĐŽŵŵƵŶŝĐĂƟŽŶ;ŶĂƚƵƌĂů ĨƌĂĐƚƵƌĞƐ͕ĐĞŵĞŶƚĨĂŝůƵƌĞ͕ůŽŶŐŝƚƵĚŝŶĂůĨƌĂĐͿ͕ƐŽLJŽƵĐĂŶĞƐƚĂďůŝƐŚ ŵŝŶŝŵƵŵĨƌĂĐƐƉĂĐŝŶŐŝŶĂŐŝǀĞŶĨŽƌŵĂƟŽŶ͘dŚĞĚĂƚĂĂůƐŽŝĚĞŶƟĮĞƐ ƚŚĞƉƌĞƐĞŶĐĞĂŶĚƐŽƵƌĐĞŽĨŶĞĂƌͲǁĞůůďŽƌĞƌĞƐƚƌŝĐƟŽŶƐ͕ĂƐǁĞůůĂƐ ƉƌŽƉƉĂŶƚďƌŝĚŐŝŶŐ͕ŝĨŝƚŽĐĐƵƌƐ͘^ƚĂŐĞͲďLJͲƐƚĂŐĞĚĞƚĂŝůƐŐŝǀĞLJŽƵŝŶƐŝŐŚƚƐ LJŽƵĚŽŶ͛ƚŐĞƚǁŝƚŚŽƚŚĞƌŵƵůƟƐƚĂŐĞĐŽŵƉůĞƟŽŶŵĞƚŚŽĚƐ͕ƵŶůĞƐƐLJŽƵ ƉĂLJĨŽƌƐĞƉĂƌĂƚĞĂŶĚĐŽƐƚůLJŵŽŶŝƚŽƌŝŶŐƐLJƐƚĞŵƐ͘ dŚĞĐŽŵďŝŶĂƟŽŶŽĨĐŽŶƐŝƐƚĞŶƚĨƌĂĐƉůĂĐĞŵĞŶƚĂŶĚĚŽǁŶŚŽůĞĚĂƚĂ ŝƐLJŽƵƌďĞƐƚĂŶĚĨĂƐƚĞƐƚƌŽƵƚĞƚŽƚƌƵůLJŽƉƟŵŝnjĞĚĐŽŵƉůĞƟŽŶƐĂŶĚ dŚĞƐĞĐŚĂƌƚƐƐŚŽǁƉƌĞƐƐƵƌĞĂŶĚƚĞŵƉĞƌĂƚƵƌĞĂďŽǀĞĂŶĚďĞůŽǁƚŚĞ ĮĞůĚͲĚĞǀĞůŽƉŵĞŶƚƐƚƌĂƚĞŐŝĞƐ͘>ĞĂƌŶŵŽƌĞĂƚŶĐƐŵƵůƟƐƚĂŐĞ͘ĐŽŵ͘ ŝƐŽůĂƟŽŶĂƐƐĞŵďůLJĨŽƌƚĞŶƐƚĂŐĞƐ͘dŚĞĚĂƚĂƌĞǀĞĂůƐĂŶĚĚĞƐĐƌŝďĞƐ ĂŶLJŝŶƚĞƌƐƚĂŐĞĐŽŵŵƵŶŝĐĂƟŽŶĂŶĚŝŵƉŽƌƚĂŶƚĨƌĂĐĂŶĚĨŽƌŵĂƟŽŶ ĐŚĂƌĂĐƚĞƌŝƐƟĐƐ͘

dŚĞDƵůƟƐƚĂŐĞhŶůŝŵŝƚĞĚĨƌĂĐͲŝƐŽůĂƟŽŶƐLJƐƚĞŵŝƐƚŚĞǁŽƌůĚ͛ƐůĞĂĚŝŶŐĐŽŝůĞĚͲƚƵďŝŶŐĨƌĂĐƚĞĐŚŶŽůŽŐLJ͕ǁŝƚŚŵŽƌĞƚŚĂŶϭϮဓ͕ϬϬϬƐƚĂŐĞƐĐŽŵƉůĞƚĞĚ͘

Learn from every frac.TM

ŶĐƐŵƵůƟƐƚĂŐĞ͘ĐŽŵ

©2015, NCS Multistage, LLC. All rights reserved. Multistage Unlimited and “Learn from every frac.” are trademarks of NCS Multistage, LLC. SPE BOARD OF DIRECTORS

OFFICERS SOUTH AMERICA AND CARIBBEAN Anelise Quintao Lara, Petrobras 2016 President SOUTH ASIA Nathan Meehan, Baker Hughes John Hoppe, Shell

2015 President SOUTH, CENTRAL, AND EAST EUROPE Helge Hove Haldorsen, Statoil Matthias Meister, Baker Hughes

2017 President SOUTHERN ASIA PACIFIC Janeen Judah, Chevron Salis Aprilian, PT Badak NGL

Vice President Finance SOUTHWESTERN NORTH AMERICA Roland Moreau, ExxonMobil Annuitant Libby Einhorn, Concho Oil & Gas WESTERN NORTH AMERICA REGIONAL DIRECTORS Andrei Popa, Chevron

AFRICA TECHNICAL DIRECTORS Adeyemi Akinlawon, Adeb Konsult DRILLING AND COMPLETIONS David Curry, Baker Hughes CANADIAN Darcy Spady, Broadview Energy HEALTH, SAFETY, SECURITY, ENVIRONMENT, AND SOCIAL RESPONSIBILITY EASTERN NORTH AMERICA Trey Shaffer, ERM Bob Garland, Silver Creek Services MANAGEMENT AND INFORMATION GULF COAST NORTH AMERICA J.C. Cunha J. Roger Hite, Inwood Solutions PRODUCTION AND OPERATIONS MID-CONTINENT NORTH AMERICA Jennifer Miskimins, Barree & Associates TIRED OF Michael Tunstall PROJECTS, FACILITIES, AND CONSTRUCTION MIDDLE EAST Howard Duhon, GATE, Inc. Khalid Zainalabedin, Saudi Aramco RESERVOIR DESCRIPTION AND DYNAMICS NORTH SEA Tom Blasingame, Texas A&M University Carlos Chalbaud, ENGIE

NORTHERN ASIA PACIFIC DIRECTOR FOR ACADEMIA Phongsthorn Thavisin, PTTEP Dan Hill, Texas A&M University ROCKY MOUNTAIN NORTH AMERICA Erin McEvers, Clearbrook Consulting AT-LARGE DIRECTORS RUSSIA AND THE CASPIAN Khaled Al-Buraik, Saudi Aramco RUN TIMES Anton Ablaev, Schlumberger Liu Zhenwu, China National Petroleum Corporation ON ARTIFICIAL LIFT?

The Journal of Petroleum Technology magazine is a JPT STAFF registered trademark of SPE.

Glenda Smith, Publisher SPE PUBLICATIONS: SPE is not responsible for any statement made or opinions expressed in its publications. John Donnelly, Editor EDITORIAL POLICY: SPE encourages open and objective • Reduce Lease Operating Alex Asfar, Senior Manager Publishing Services discussion of technical and professional subjects per- tinent to the interests of the Society in its publications. Pam Boschee, Senior Manager Magazines Society publications shall contain no judgmental remarks Expenses or opinions as to the technical competence, personal Chris Carpenter, Technology Editor character, or motivations of any individual, company, or group. Any material which, in the publisher’s opinion, Trent Jacobs, Senior Technology Writer does not meet the standards for objectivity, pertinence, Anjana Sankara Narayanan, Editorial Manager and professional tone will be returned to the contribu- • Mazimize drawdown, tor with a request for revision before publication. SPE Joel Parshall, Features Editor accepts advertising (print and electronic) for goods and services that, in the publisher’s judgment, address the pump through gas lock Stephen Rassenfoss, Emerging Technology Senior Editor technical or professional interests of its readers. SPE reserves the right to refuse to publish any advertising it Stephen Whitfield, Staff Writer considers to be unacceptable. Adam Wilson, Special Publications Editor COPYRIGHT AND USE: SPE grants permission to make • Avoid solids, sands on Craig Moritz, Assistant Director Americas Sales & Exhibits up to five copies of any article in this journal for personal use. This permission is in addition to copying rights grant- Mary Jane Touchstone, Print Publishing Manager ed by law as fair use or library use. For copying beyond shutdown that or the above permission: (1) libraries and other users David Grant, Electronic Publishing Manager dealing with the Copyright Clearance Center (CCC) must pay a base fee of USD 5 per article plus USD 0.50 per Laurie Sailsbury, Composition Specialist Supervisor page to CCC, 29 Congress St., Salem, Mass. 01970, USA Dennis Scharnberg, Proofreader (ISSN0149-2136) or (2) otherwise, contact SPE Librarian • Eliminate flush-bys and at SPE Americas Office in Richardson, Texas, USA, or e-mail [email protected] to obtain permission to make more than five copies or for any other special use of stuck pumps copyrighted material in this journal. The above permis- sion notwithstanding, SPE does not waive its right as copyright holder under the US Copyright Act. Canada Publications Agreement #40612608. PTSPROTECTS.COM PERFORMANCE INDICES

WORLD CRUDE OIL PRODUCTION+‡ HENRY HUB GULF COAST NATURAL GAS SPOT PRICE‡

THOUSAND BOPD  OPEC 2015 JUL AUG SEP OCT  Algeria     USD°million Btu Angola        Ecuador      Iran     Iraq      Kuwait*     Libya      JUL SEP     FEB JAN JUN DEC APR

Nigeria OCT AUG MAY 2016 NOV MAR Qatar     Saudi Arabia*       UAE     WORLD CRUDE OIL PRICES (USD/bbl)‡ Venezuela    

TOTAL 2016 33840 33769 33726 33625 SEP OCT NOV DEC JAN FEB MAR APR

Brent           THOUSAND BOPD WTI           NON-OPEC 2015 JUL AUG SEP OCT Argentina     Australia     WORLD ROTARY RIG COUNT† Azerbaijan    

Brazil     2016 REGION OCT NOV DEC JAN FEB MAR APR Canada       US         China      Canada        Colombia     Latin America         Denmark     Europe        Egypt      Middle East         Eq. Guinea     Africa        Gabon         Asia Pacific         India     TOTAL Indonesia     ¡£¢œ ¡£›¤ Ÿ¨œ¨ Ÿ¢¨Ÿ Ÿ¤œŸ Ÿ©©Ÿ Ÿ›¡› Kazakhstan     Malaysia      WORLD OIL SUPPLY AND DEMAND®‡ Mexico      Norway     MILLION BOPD 2015 2016 Oman     Quarter 2nd 3rd 4th 1st Russia        SUPPLY 95.42 96.45 96.53 95.47     Sudan DEMAND 93.32 94.97 94.08 94.15 Syria     UK      USA     INDICES KEY Vietnam     + Figures do not include NGLs and oil from nonconventional sources. Yemen     * Includes approximately one-half of Neutral Zone production. Latest available data on www.eia.gov. Other        Includes crude oil, lease condensates, natural gas plant liquids, other hydrocarbons for refinery feedstocks, Total 46685 46670 ›œžŸ¡ ›œ››œ refinery gains, alcohol, and liquids produced from nonconventional sources. Source: Baker Hughes. Total World 80525 80439 ¢££ž¢ ¢££¤Ÿ † ‡ Source: US Department of Energy/Energy Information Administration.

66 JPT • JUNE 2016 Salik LOCAL-SAND-ENABLED FLOW-CHANNEL FRACTURING SERVICE

Reduce fracturing costs by replacing more than 50% of proppant with local sand. Salik local-sand-enabled flow-channel fracturing service provides unprecedented cost reduction by using local sand as an inexpensive alternative to conventional proppant. Because it requires less imported proppant, the service also decreases transportation expenses—all while maximizing production and fracture conductivity.

Find out more at slb.com/salik

*Mark of Schlumberger. Copyright © 2016 Schlumberger. All rights reserved. 16-ST-121508

Salik full page for JPT April, May, June 2016 16-ST-121508 AD.indd 1 3/7/16 9:35 AM REGIONAL UPDATE

AFRICA were achieved from the new well. Mari, the of 4,400 B/D from Cretaceous fractured operator, has a 60% interest in the well. carbonate reservoirs. The Shewashan-1 Z Petroceltic International said that the MOL holds the remaining interest. well is being recompleted as a deviated first of up to 24 new development wells producing well. GPK is operator with an planned in Algeria’s Ain Tsila gas and Z China National Offshore Oil Company 80% interest in the wells. condensate field was successful. The AT-10 (CNOOC) has started production from the well, situated about 2 miles from the AT-1 Panyu 11-5 oil field in the Pearl River Mouth NORTH AMERICA field discovery well, reached a total depth Basin. Three horizontal wells have been of 6,578 ft. Wireline logs indicated that drilled in the field, which also makes use Z ExxonMobil has started production at the expected initial offtake rate would be of existing facilities in the Panyu 5-1 field. its Point Thomson project, the first project comparable to the AT-1 and AT-8 wells, One well is on production in the new field it has operated on Alaska’s North Slope. both of which test-flowed at more than with an output of about 3,270 B/D. Panyu Initial central pad production of about 30 MMcf/D. Petroceltic is the operator 11-5 is expected to reach peak production 5,000 B/D of natural gas condensate with a 38.25% interest in the production- of 3,900 B/D later this year. CNOOC holds and 100 MMscf/D of recycled gas will sharing contract that covers the Ain Tsila a 100% interest in the field. rise over a few months to peak levels output. The remaining interests are held by of up to 10,000 B/D of condensate and Sonatrach (43.375%) and Enel (18.375%). AUSTRALIA/OCEANIA 200 MMscf/D of recycled gas. The recycled gas is reinjected for future recovery. The Z Sonangol reported that it has found Z New Zealand Oil & Gas (NZOG) reported Point Thomson reservoir contains an reserves in the Kwanza Basin of Angola a further upgrade in developed reserves estimated 8 Tcf of gas and associated that could total 2.2 billion BOE, including in the Kupe gas and light oil field offshore condensate, which represents 25% of the reserves in a block jointly owned with Taranaki, New Zealand, following analysis North Slope’s known gas. ExxonMobil holds BP. Block 24, operated by BP, holds an by the field’s joint venture partners. a 62% interest in the project, with BP (32%), estimated 280 million bbl of condensate The upgrade from 5.22 million BOE to ConocoPhillips (4.9%), and other parties and 8 Tcf of gas, totaling 1.7 billion BOE, 6.02 million BOE is in addition to a 34.7% holding the remainder (1.1%). Sonangol said in a statement seen by increase announced in October. Based on Reuters. Sonangol also said that Block 20, detailed reservoir simulation uncertainty Z Otto Energy has provided updated which it operates, is commercially viable modeling, the company is reporting a new information on the SM-71 # 1 discovery and contains an estimated 139 million bbl 15.29% increase in proved and probable well on South Marsh Island Block 71 in the of condensate and 2.5 Tcf of gas, totaling developed reserves. NZOG has a 15% US Gulf of Mexico. Using the initial results of 570 million BOE. interest in the field, which is operated by quad-combo porosity logging, the company Origin Energy (50%). Other participants are has made these preliminary estimates of Z Lekoil said that the Otakikpo-002 well Genesis Energy (31%) and Mitsui (4%). net true vertical thickness (TVT) oil pay in Nigeria’s Otakikpo Marginal Field has counts for the well: I3 Sand, 17 ft TVT flowed oil from two upper zones during EUROPE pay; J Sand, 24 ft TVT pay; and D5 Sand, production tests. Peak flow rates of 91 ft TVT pay. The well will be deepened by 6,404 B/D and 5,684 B/D were achieved Z Providence Resources said that the Druid 600 ft to the original permitted measured in the two zones, with both test volumes and Drombeg prospects in the southern depth of 7,452 ft to extend the evaluation of flowing through a 36/64-in. choke. Lekoil Porcupine Basin, offshore Ireland, could targeted sands. By bearing certain project holds a 40% interest in the field with hold total cumulative in-place unrisked costs, Otto will earn a 50% interest in the operator Green Energy International prospective resources of 5 billion bbl of well through a farm-in agreement with holding a 60% share. oil. The company, which carried out the operator Byron Energy, which will retain prospective resource research in a joint a 50% share. ASIA industry project with Schlumberger, revealed that both prospects could be SOUTH AMERICA Z Mari Petroleum has made a third evaluated with a single vertical exploration significant discovery in Pakistan’s Karak well, costing an estimated USD 85 million. Z Statoil and partners Repsol Sinopec Block. The Halini-Deep-1 discovery follows Brasil and Petrobras have struck oil in successes at the Halini-X-1 well in 2011 and MIDDLE EAST the deepwater Campos Basin offshore the Kalabagh-1A well last year. The Halini- Brazil. The appraisal well encountered a Deep well was drilled to a depth of 19,357 ft. Z Gas Plus Khalakan (GPK) announced 175-m hydrocarbon column and produced Drillstem test results showed production that the Shewashan-2 development well approximately 16 MMscf/D of gas and from the Samana Suk reservoir, which will contribute to the 10,000-B/D year- 4,000 B/D of oil, Statoil said. Repsol lies beneath the Lumshiwal, Hangu, and end production target for Phase 1 of the Sinopec Brasil, a joint venture of Repsol and Lockhart reservoirs to which the previous Shewashan oil field in Iraq’s Kurdistan Sinopec, is the current operator. Statoil will wells are connected. In a completion Region. The well was drilled to a 9,081-ft take over as operator in the third quarter, integrity test, flow rates of 1,425 B/D of depth at a cost of USD 19.5 million. During raising its 35% stake in the project to 70%. oil and 1.18 MMscf/D (197 BOE/D) of gas tests, the well flowed at a maximum rate Petrobras holds a 30% stake. JPT

8 JPT • JUNE 2016 Stormy weather, seasoned team: It’s time to make optimal decisions about your reservoirs

More than ever, it is time to make the right decisions: develop production in the short term, increase reserves, improve economics, updates Field Development Plans, implement adequate IOR/EOR strategy, prepare for the rebound. Make sure your decision is supported by the best available expertise. Contact Beicip-Franlab.

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Quality: Why Is It So Important Now? Nathan Meehan, 2016 SPE President

Quality is a measurement of excellence In my March column, I wrote about social license to oper- that is often difficult to quantify. Pro- ate, deemed to exist when a project—or an industry—has on- viders of quality products and servic- going support and trust from the community. Gaining that es command premium prices. Brand support and trust requires that we not only meet, but exceed, names we associate with quality inspire society’s perceived basic requirements for safety, environ- positive thoughts. They are names mental stewardship, and social responsibility. We must deliver we trust to deliver what we expect of the affordable energy that society expects of us, and we must them—safely, reliably, and with flaw- deliver it reliably, safely, and with flawless performance. Qual- less performance. ity is not a luxury; it is essential. Quality is a perceptual, conditional, and somewhat subjec- tive attribute that is understood differently by different peo- The Role of Standards ple. In business, engineering, and manufacturing, quality is The value of standards to quality has been apparent at least fitness for purpose. It has a pragmatic interpretation as the since the Industrial Revolution. Sir Joseph Whitworth, a Vic- superiority of something. That something may be a product or torian mechanical engineer, campaigned for conformity and service. It may also be a process, personnel, management, or consistency in nuts and bolts in 1841. This made manufac- an entire enterprise—a brand. turing safer, more efficient, and more economical in his While our industry strives to strengthen quality and reli- native Britain and eventually, internationally. We in the oil ability standards worldwide, the general public has a very neg- and gas industry have applied similar logic to develop stan- ative perception of the industry’s performance. They do not dards that have imparted benefits in areas ranging from think “quality” when they consider our performance or con- the manufacture of tubular goods, fittings and flanges, to tributions to society. cost, performance, and reliability; global trade and interna- Why do so many people feel so negatively about the industry tional operations; health, safety, and environment (HSE); responsible for powering the modern world? It provides jobs sustainability; intellectual property; global trade; compe- and improves living standards. For more than 7 billion people tition and antitrust; knowledge sharing and transfer; the on our planet, every measure of quality of life, from gross do- needs of specific groups in society; and the development mestic product per capita and infant mortality, to education of indigenous capacity and technology transfer to develop- levels and access to clean water, is correlated to the consump- ing countries. tion of modern fuels, in particular oil and gas. There is no “If you control an industry’s standards, you control that doubt that it is a vital resource that has improved people’s lives industry lock, stock, and ledger,” wrote W. Edwards Dem- more than any other energy source. ing in his book, Out of the Crisis. The crisis in this case was A growing proportion of society now wants the lifestyle the economic struggle of the developed countries of North that oil and gas provide without our industry. Why? The America and Western Europe in the late 1970s and early short answer: trust. People do not trust oil companies. Per- 1980s to keep pace in the face of stiff competition from haps they are cynical about gasoline prices. They do not Japan’s ability to produce high-quality goods at competitive trust what they perceive as an environmental polluter and cost. Ironically, Japan’s economic rise following World War II source of greenhouse gases. They do not trust us to oper- was founded on the ideas taught by Deming, an Ameri- ate safely. The rise of vocal activist groups has exacerbat- can engineer, statistician, professor, author, and manage- ed the situation, but we are not without blame. There have ment consultant. been industry incidents that caused loss of lives and damage Japan became the second-largest economy in the world by to the environment. We did not always respond satisfactori- managing processes. Deming saw that the concepts of statis- ly. Modern telecommunications, especially the Internet and tical control of processes could be applied not only to manu- social media, spread bad news universally, instantaneously, facturing processes, but also to the processes by which enter- and continuously. prises are led and managed.

To contact the SPE President, email [email protected].

10 JPT • JUNE 2016 “Costs go down and productivity We must deliver the tem Requirements for the Petroleum, goes up as improvement of quality is Petrochemical, and Natural Gas In- accomplished by better management affordable energy that dustries, and industry tools such as of design, engineering, and testing, Six Sigma. While standards and pro- and by improvement of processes,” society expects of us, and cesses are important, it is ultimately he said. the culture of an organization that will After a series of lectures in Japan in we must deliver it reliably, deliver quality. 1950, a number of Japanese manufac- turers applied his techniques widely safely, and with flawless Moving Forward and experienced previously unheard- Quality has expanded from meet- of levels of quality and productivity. performance. Quality is not ing basic manufacturing standards to The improved quality and lower cost managing risk at all levels of an orga- created new international demand for a luxury; it is essential. nization and in all operating environ- Japanese products. ments. We have learned from past inci- Business terms and concepts, such dents that moving the industry toward as continuous improvement, quality control, and total qual- safer, more reliable operations requires that all aspects of ity management, came about through Deming’s teachings. quality programs be interrelated, interdependent, and consis- He warned that management’s failure to plan for the future tent. Standards such as API Q2, which support procedural con- would bring about loss of market, which brings about loss of trols, guidelines, risk mitigation, and other aspects of quality, jobs. He also counseled that management must be judged not will help our industry reduce risk and ensure safe, trouble- only by the quarterly dividend, but also by innovative plans free operations on the broadest scale possible. to stay in business, protect investment, ensure future divi- For individual companies, quality is a prerequisite for stay- dends, and provide more jobs through improved products ing in business, protecting return on investment, and provid- and services. ing more jobs. For our industry, it is a prerequisite for gaining Donald E. Purcell, a recognized expert in globalization, in- and retaining our social license to operate. JPT ternational standardization, and strategic standards educa- tion initiatives, compared global standards to DNA as the basic building blocks for all technology and economic sys- tems. They underpin expectations that platforms, systems, and equipment will be safe, reliable, and fit for purpose. If quality is the destination, standardization drives the im- proved performance, improved safety, improved reliability, and reduced costs needed to reach it. Leading standards bodies for the oil and gas industry include the American Petroleum Institute (API), Interna- tional Association of Oil & Gas Producers (IOGP), Inter- national Association of Drilling Contractors (IADC), and Bureau Veritas. Government agencies often promulgate regu- lations or voluntary programs that become de facto standards as well. To enhance quality, it is critical that throughout the enter- prise, employees at all levels embrace training and obtain all qualifications required to do their jobs properly, and we sup- Dig deeper without port these efforts with a broad, and expanding, range of train- ing programs. During periods of low prices, training is often leaving your desk. sacrificed. Inevitably, this risks quality in design, manufac- Too busy to be away from the o ce? Take yourself to greater turing, and implementation. In the same way Stop Work Or- depths right from your desktop with SPE Webinars and Online ders are implemented when conditions are unsafe, every- Education. Join our industry experts as they explore solutions one should be encouraged and empowered to take action and to real problems and discuss trending topics. speak up if they see something that does not comply with ap- View a list of available webinars at webevents.spe.org. propriate standards, processes, and procedures. It is vital to participate in quality standards such as API Q2, the specifica- tion developed in 2010 to ensure that service providers im- Connect, share with us on plement quality controls at the facility level, based on iden- @SPE_Events tifying, assessing, and managing risk. Similarly, quality can #SPEWEBINARS be improved by applying ISO/TS 29001:2007: Quality Sys-

JPT • JUNE 2016 11 COMMENTS EDITORIAL COMMITTEE Bernt Aadnøy, University of Stavanger Syed Ali—Chairperson, Schlumberger Tayfun Babadagli, University of Alberta William Bailey, Schlumberger The Toll on Future Supply Mike Berry, Mike Berry Consulting John Donnelly, JPT Editor Maria Capello, Kuwait Oil Company Simon Chipperfield, Santos Nicholas Clem, Baker Hughes Alex Crabtree, Hess Corporation Low oil prices have taken a huge toll on exploration and pro- Gunnar DeBruijn, Schlumberger duction (E&P) activity, and the decline could lead to production Mark Egan, WesternGeco shortfalls in the future. Mark Elkins, ConocoPhillips Discoveries of new reserves have now fallen to their lowest Alexandre Emerick, level in 60 years as projects are canceled or pushed back due Petrobras Research Center to low prices and company budget and staff cuts. Operators Niall Fleming, Statoil discovered 2.8 billion bbl of crude oil and liquids last year, the Ted Frankiewicz, SPEC Services lowest volume since 1954, according to a new report by consul- tancy IHS. Most of the reserves were found in deep water, which take years to bring on Stephen Goodyear, Shell to production. Omer M. Gurpinar, Schlumberger Two other recent reports were much-discussed during last month’s Offshore Tech- A.G. Guzman-Garcia, Retired nology Conference in Houston. Global deepwater spending continues to fall because Greg Horton, Consultant of the oil price crash, with the Americas and Africa the only bright spots, according to John Hudson, Shell a new study by Douglas-Westwood. A year ago, the consultancy saw 210 potential proj- Morten Iversen, Karachaganak Petroleum ects for installation in the next 5 years but now expects only 118 projects to be installed Leonard Kalfayan, Hess Corporation during 2016–2020. Tom Kelly, FMC Technologies E&P capital spending will be led by investments in the Americas and Africa, which Thomas Knode, Statoil combined will account for 87% of expenditures. The development of east Africa’s gas Sunil Kokal, Saudi Aramco basins and several US Gulf of Mexico plays will keep those centers as deepwater hubs. The Gulf of Mexico projects include Shell’s Appomattox field, its largest floating plat- Marc Kuck, Eni US Operating form offshore US; Anadarko’s subsea tiebacks at three fields; Chevron’s Jack/St. Malo Jesse C. Lee, Schlumberger floating production system; and BP’s Mad Dog phase 2 development. Silviu Livescu, Baker Hughes Wood Mackenzie is warning that the steep drop in production could lead to crit- Shouxiang (Mark) Ma, Saudi Aramco ical shortfalls in the future. It expects the industry to spend USD 40 billion/yr on John Macpherson, Baker Hughes exploration and appraisal from 2016 to 2018, less than half of what was spent during Casey McDonough, American Energy Partners 2012–2014, and that number could be lower depending on what oil prices do. The Stephane Menand, DrillScan consultancy sees a shift to smaller, near-field operations in the immediate future, Badrul H Mohamed Jan, University of Malaya with the industry eschewing high-dollar complex projects that potentially bring more Lee Morgenthaler, Retired lucrative output. Even many medium-term discoveries made before the price down- Michael L. Payne, BP plc fall are being delayed because of company budget cuts. Those factors contribute to Zillur Rahim, Saudi Aramco its prediction that continued poor exploration results could lead to a 4.5-million-B/D shortfall in the industry meeting demand by 2035, although a lot of variables could Martin Rylance, BP GWO Completions Engineering change in 19 years. Otto L. Santos, Petrobras Consultancies are not the only ones worried about coming supply shortfalls. Schlumberger Chief Executive Officer Paal Kibsgaard, speaking to investors about Luigi A. Saputelli, Hess Corporation the company’s first quarter earnings, said E&P investment likely will not meet future Sally A. Thomas, ConocoPhillips global energy demand unless something changes. “I think we will need significant Win Thornton, BP plc increases in E&P investment,” he was quoted as saying. “If you look at new invest- Xiuli Wang, Baker Hughes ments that are relatively short cycle, there are two sources of that. It is going to be the Mike Weatherl, Well Integrity, LLC conventional land international and it is going to be the unconventional land in North Rodney Wetzel, Chevron ETC America. …So I think the sources of additional production for 2017 are limited to these Scott Wilson, Ryder Scott Company items. Beyond that, I think we need a widespread, significant increase in E&P invest- Jonathan Wylde, Clariant Oil Services JPT ments to get supply back to where it can meet growing demand.” Pat York, Weatherford International

To contact JPT’s editor, email [email protected].

12 JPT • JUNE 2016

GUEST EDITORIAL

Isn’t It Time for Our Own Spielbergian “Idea Summit”?

Walt Aldred, Research Director and Scientific Adviser for Drilling, Schlumberger, and Executive Committee Co-chair for the 2016 SPE Intelligent Energy International Conference & Exhibition

Three years before the 2002 release of big data analytics, and intelligent and of expertise, drilling: I believe one way his science fiction film Minority Report, autonomous systems to create our own out of the current downturn to a stron- director Steven Spielberg brought future. This will enable us both to sur- ger future is to embrace digital innova- together an ad hoc think tank to help vive our current challenges and to thrive tion and new levels of automation. I’m him realistically imagine how the future in the years to come. not alone. might look in 50 years. More than a Consider the difference between Last fall, a survey conducted at the dozen visionaries and futurists came invention and innovation. Invention International Association of Drilling together for the 3-day event, an “idea develops new ideas and concepts; inno- Contractors Advanced Rig Technology summit,” which proved surprisingly vation combines existing elements and Conference indicated that many of its prescient. Several intelligent technolo- applies them in new ways. Today we members believe now may be the best gies envisioned in the film have since need innovation to take advantage of the time to adopt new technology. Forty been developed—including biomet- technological inventions that we already percent said a down market encourages ric iris scanners, robotic insects, crime have, and we need inventions to sus- automation. Another 38.5% agreed, as prediction software, multitouch inter- tain the future. Of course, we also need long as automated processes are prop- faces (you probably have one in your to leverage human potential, processes, erly deployed to meet specific opera- pocket or purse), and autonomous or and organizational ingenuity. tor requirements. Only 17% felt a down self-driving cars. To shape this future vision, we will market discourages automation, large- At almost 2 years into the oil indus- bring together the industry’s bright- ly because companies cannot afford try downturn, I believe now is the ideal est scientists, engineers, and visionar- new investments. time, a pivotal moment, to come togeth- ies, as well as executives and decision This would not be the first time the er for our own “idea summit” and begin makers who can implement new corpo- drilling industry has innovated in a to realistically imagine the future so that rate strategies and business models that downturn to profit in the upturn. Dur- we can respond to the “upturn” in the will catalyze technological and organi- ing a previous downturn—the oil price oil and gas industry when it arrives, as zational changes. collapse of 1998—one major contrac- it inevitably will as we have witnessed in This conference is organized to enable tor developed next-generation, semi- the past cycles. The seventh SPE Intelli- us to engage in candid conversation, ask automated land drilling rigs. Even gent Energy International Conference & one another hard questions, dream out charging a premium coming out of the Exhibition will meet for 3 days this Sep- loud, and open ourselves to fresh pos- downturn, these high-tech rigs low- tember in Aberdeen to consider how we sibilities. Take, for example, the appli- ered the drilling cost per foot by nearly can take emerging digital technologies, cation of digital technology in my area “two-thirds.” They consistently drilled record wells. A second effect, revealed by a Schlumberger study several years later, found that downhole tool reli- Walt Aldred is the research director and scientific adviser for ability improved almost “threefold” on drilling at Schlumberger Gould Research, working on novel these rigs. drilling methods and automation of the drilling system. In 1980, he While it took tremendous courage to joined Schlumberger, working offshore in the North Sea and West innovate in such an economic environ- Africa as a mud logger, monitoring real-time drilling operations and evaluating the pore pressure and geology. Since then, he has ment, ultimately it paid off, not just for worked on the development of real-time drilling monitoring and one service provider, but for the indus- evaluation of new drilling systems, including the early development try as a whole. of geosteering. Aldred is a founding member of the SPE Drilling Systems Automation Technical Section and is executive committee cochair for the 2016 SPE Intelligent New Autonomous Systems Energy International Conference & Exhibition. He holds degrees from Durham Surprisingly, the energy industry is clos- University, UK, with joint honors in chemistry and geology. er than many realize to implementing

14 JPT • JUNE 2016 fully or nearly autonomous systems. Where we go from here depends on This will be possible not because of our collective imagination and will. But some gigantic breakthrough in technol- we are well-positioned to put the pieces ogy, but rather by adding new levels together now, and take automation to of overlying intelligence to automated new levels. The intelligent way to imple- We give components that already exist. ment intelligent technology will be to Consider self-driving cars. While sev- match the degree of autonomy with the you the eral companies have been developing complexity of the operation, whether futuristic self-driving cars for more than in drilling, completions, or production. superpowers a decade, the rest of us have been adopt- The transition will unfold carefully in ing automated systems such as intel- stages, enabling us to learn as we go. It ligent cruise control and self-parking will be an evolution through innovation, you’ve without much ado for years. Autono- not a revolution. But the impact could mous cars and other self-guiding robots prove revolutionary. always incorporate an additional technology To advance to the next level of intelli- called SLAM (simultaneous localization gent energy, however, we will need more dreamed of. and mapping). SLAM systems locate the than technology. We will need new busi- vehicle relative to other objects and map ness models, new organizational struc- Introducing the world’s the optimal route to a specified destina- tures, and new ways of working as well. first X-Ray technology tion, within constraints, altering course We need models that encourage rather based on dynamic, real-time informa- than discourage collaboration, innova- for oil wells. tion. For autonomous cars and trucks, tion, integration, and automation. This VISURAY’s revolutionary VR  ® the payoff will come in fewer accidents is why they, too, are on the agenda for not only finds downhole blockages and fatalities, more efficient traffic flow, the 2016 SPE Intelligent Energy Interna- faster, it lets you see D and D optimal fuel usage, lower insurance pre- tional Conference. reconstructions of the obstruction. miums, and other benefits to individuals We’ll illuminate the problem, you’ll and society. What To Expect The challenge for the self-driving car The conference will begin with industry eliminate the problem. Better yet, lies in achieving sufficient intelligence thought leaders’ and analysts’ view of you’ll eliminate downtime and to navigate chaotic environments char- the current state of energy markets, the increase profitability. acterized by large degrees of uncertain- economic outlook for oil and gas, and ty. Sound familiar? the role of intelligent energy in short- Contact us for a The analogy with a complex drill- and long-term investment decisions. demonstration ing operation is obvious. Fortunately, Sixteen technical sessions with more visuray.com we started down the road to drilling than 75 papers, case studies, and les- automation years ago. Iron roughnecks sons learned will explore a wide range have automated dangerous pipe-han- of topics, including data communica- dling operations. Semi-intelligent auto- tions, real-time production optimiza- drillers have replaced manual control tion, production surveillance, drilling of weight on bit and rate of penetration optimization, advanced well technol- (ROP). Automated optimization algo- ogy, big data analytics, design of intel- rithms have boosted ROP an average of ligent energy programs, processing 32% over autodrillers. Today, intelligent monitoring and automated analysis, geosteering tools and rotary steerable cybersecurity, the role of people and systems represent our industry’s ver- organizations, robotics and the human- sion of SLAM. machine interface, smart operations, One day soon, like a self-driving car, and lessons from other industries. we may simply tell our autonomous Join the industry’s finest minds as we drilling system where we want to go in come together in our own Spielbergian the subsurface and, following our own idea summit, as we realistically imagine VISURAY “rules of the road,” it will take us there the future of oil and gas together. At the X-RAY VISION by the fastest, safest, and most cost- bottom of the downturn, let’s innovate effective route. to get ready for the upturn. JPT

JPT • JUNE 2016 TECHNOLOGY APPLICATIONS

Chris Carpenter, JPT Technology Editor

Hardfacing Rods angles. The cutting structure produces Invasion Tester Cutting & Wear’s SupaCutt range of hard- short cuttings that are circulated out of Testing of drilling fluids has numer- facing rods are used to hardface mills for the hole easily. The fragments are regu- ous important facets, and increasing- cutting steel and other materials down- lar in size, which ensures that laying an ly significant property measurements hole. They are made up of crushed tung- effective cutting structure is quicker and are fluid loss and, by extension, the sten carbide in a brazing alloy. When easier. The rods are slim to allow indi- bridging capacity of the fluid being test- deposited on a mill, the brazing alloy vidual pieces to be melted off for precise ed. Low fluid loss and minimal loss of is melted, bonding the tungsten car- construction of the cutting structure. whole fluid are integral parts of modern bide fragments to the tool. This forms Q For additional information, visit drilling- fluid design and have become a coarse cutting structure able to cut www.cwuk.com. vital performance criteria. Consider- through obstructions downhole. The ing the current industry-specified test- industry standard crushing process gen- Predictive-Analytics Software ing to characterize the performance of erates poorly shaped fragments that can Baker Hughes introduced its FieldPulse both fluid loss and bridging capability be flaky in character and from which model-based, predictive analytics soft- in a drilling fluid but given the risk in the better-shaped fragments are then ware, which enables operators to proac- working with compressed gas in cer- selected to be used in the manufacture tively optimize production across entire tain locations, Vertechs has developed of the rods. However, Cutting & Wear’s fields by giving them clear understand- a unique test device called the High- latest addition to the product line, Supa- ing of an asset’s performance in real time. Pressure Invasion Tester (HPIT). The Cutt Xtreme, uses a new fragmentation To provide this understanding, the Field- HPIT depends on generating a mechani- process that breaks steel-cutting grades Pulse software can seamlessly integrate cal force to a confined test body that of tungsten carbide into uniform frag- and interpret large volumes of produc- applies pressure up to 1,100 psi to the ments; these fragments present an excel- tion data, well models, and well-test data fluid sample. The results are visible in lent shape for cutting applications down- from multiple sources; then, automating the inspection tube, and the equipment hole (Fig. 1). They have strong, sharp common petroleum-engineering calcula- is portable (Fig. 2). The test medium is corners and, when laid, form a multi- tions, it helps identify and rank under- tude of cutting faces, the majority devel- performing wells. Key performance indi- oping neutral to negative rake-cutting cators such as rate decline and model deviations are monitored constantly, and warnings and alerts are generated to accelerate well selection and provide actionable data to help operators make decisions relating to well remediation when and where it is needed. Because the FieldPulse software uses data from existing production and completion data bases, operators can choose to avoid investing in new sensors, gauges, or data- bases. The software also has its own built- in nodal engine, which allows real-time integration between field data and well models without the need for additional well-modeling software. The FieldPulse software can be used in operations cen- ters, in modern collaboration rooms, on tablet devices, on touch-enabled laptops, and on conventional laptops and desk- tops. It works with minimal configura- Fig. 1—Cutting & Wear’s SupaCutt tion and is easily deployed, so value can Xtreme uses a new fragmentation process that breaks steel-cutting be realized within hours. grades of tungsten carbide into Q For additional information, visit uniform fragments. www.bakerhughes.com. Fig. 2—The HPIT from Vertechs.

16 JPT • JUNE 2016 ResFlow CV CHECK-VALVE ICD

The check valve is a drop-in replacement for a standard ResFlow* ICD nozzle.

New ICD design eliminates need for washpipe during sand control installations, saving operator 2 days and USD 2 million per well. The redesigned ResFlow CV* check-valve ICD enabled an operator to run ICDs for five extended-reach wells without using washpipe while still ensuring circulation to the toe of the completion during run-in. The lightweight assembly string provided easy installation of the ICDs in the highly deviated wells and facilitated displacement of all oil-base fluids. As a result, the operator eliminated washpipe rental and associated costs, experienced zero NPT, and saved 2 days and USD 2 million per well.

Find out more at slb.com/ResFlow

*Mark of Schlumberger. Copyright © 2016 Schlumberger. 16-CO-145466

ResFlow CV full page for JPT June 16-CO-145466 AD.indd 1 5/9/16 4:17 PM sized sand or rock, and could be fitted with a core block if desired. The HPIT requires no compressed gases and no electrical outlet, can be delivered to any location, and poses minimal risk to the user. HPIT can be used to test untreat- ed drilling fluids and assess the effect of adding loss-prevention products when troubleshooting downhole problems. Q For additional information, visit www.vertechs.com.

Hydraulic-Instrumentation Product Line NOV has announced the commer- Fig. 3—Weatherford’s OneSync cial release of two additions to the drilling-software platform uses three MD Totco hydraulic-instrumentation integrated software suites to reduce product family. The hydraulic-piston- complexity. separator pressure transmitter and the pressure debooster provide customers tions—that enable users to transition with a flanged mounting option on a across all phases of the well seamlessly, proved instrumentation system. These it reduces complexity and cost (Fig. 3). Fig. 4—The ROVINS NANO inertial navigation system from iXBlue offers new products, available in various sizes The software platform can be combined increased accuracy and reduced cost. and configurations, add to the flexi- with many other Weatherford drill- bility of installation options to meet ing technologies and services. When for remotely-operated-vehicle (ROV) a broader range of applications. The paired with the Microflux control sys- navigation. Based on iXBlue’s fiber-optic 1:1 piston-separator pressure transmit- tem and the company’s comprehensive gyroscope technology, ROVINS NANO ter separates process fluid and gauge managed-pressure-drilling (MPD) ser- has been designed for ROV pilots per- fluid while eliminating the lag signal vices, the software provides addition- forming maintenance and construction to the gauge. Available in standard al benefits including improved MPD operations. It offers the optimal stabil- and H2S configurations, the transmit- planning, rig-crew preparedness, real- ity and accuracy of the inertial position, ter’s simple design allows for easy field time decision making, and operational generating true north, roll, pitch, and overhaul and seal replacement. High control. The dynamic simulation soft- rotation rate (Fig. 4). ROVINS NANO is fluid capacity compensates for hose ware allows users to run hypothetical able to directly transmit the ROV’s posi- expansion associated with extend- scenarios in the field for MPD opera- tion with extreme accuracy thanks to ed high-pressure runs. The 4:1 pres- tions. A modified version of the same its integrated algorithm capable of col- sure debooster reduces high pressures software has been integrated into lecting acoustic data. This is now possi- by 25% for manageable measurement Maersk Training drilling simulators to ble regardless of the depth at which it is at the gauge, with standard capacities provide MPD training for offshore drill- located. Where the Doppler velocity log of 10,000, 15,000, and 20,000 psi. ing operations. Modular software pack- (DVL) has limitations, especially when Reduced output pressures allow for lon- ages can be selected from the oper- operating in middle water, ROVINS ger hose lengths and enable the opera- ations suite to address operational NANO is now there to guarantee opti- tor to maintain distance from the high- needs. When combined with the Micro- mal navigation safety. iXBlue thus pro- pressure process. flux control system, the automation- vides more flexibility to its customers: Q For additional information, visit and-control package enhances previ- by avoiding the use of DVL, operators www.nov.com. ous detection and operational-control reduce their operational and associated capabilities. The integrated solution has calibration costs. Besides its high level Comprehensive been deployed successfully during MPD of performance, ROVINS NANO’s com- Drilling-Software Platform operations in Canada, Brazil, and the pactness, lightness, and open architec- The OneSync software platform from North Sea. ture with all third-party sensors make it Weatherford is a comprehensive solu- Q For additional information, visit easy to integrate. At a reasonable price tion for well planning, training, sim- www.weatherford.com. point, the product offers better return ulation, and operational control that on investment and lower total cost enhances efficiency and connectivity. Inertial Navigation System of ownership. JPT With three integrated software suites— iXBlue has introduced ROVINS NANO, Q For additional information, visit well planning, simulation, and opera- an inertial navigation system designed www.ixblue.com.

18 JPT • JUNE 2016 WE DELIVER WHAT OTHERS CAN’T.

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Biocide Treatment Program Reduces P r e m a t u r e C o i l e d T u b i n g F a i l u r e s

Lemuel Edillon, SPE, STEP Energy Services, Matthew Henderson, SPE, Fusion Technologies, and Stan Leong, OSP

Premature coiled tubing (CT) failures age, corrosion, and excessive diametri- The strings failed in the range of 18% have occurred in the United States, in cal growth. Premature failure results not to 49% fatigue—well below their pre- areas such as the Eagle Ford and Haynes- only in operational delays and the associ- dicted 80% fatigue life. Preliminary ville formations, and the Permian Basin. ated costs, but critical safety risks for on- analysis of the failure points revealed In Canada, these failures once were not site personnel. pinholes and internal corrosion in the considered as prevalent. However, a pre- For these reasons, a study was under- base material and at the bias weld. The sentation at the 2015 SPE/ICoTA confer- taken to determine the root cause of the filler material used in bias welds has dif- ence in The Woodlands, Texas, changed CT string failures in the Montney. The ferent mechanical properties than the that perception. A paper presented there results showed that microbial influenced base pipe material, making it weaker and detailed how a major Canadian CT ser- corrosion (MIC) was a contributing fac- more fatigue-prone. vice provider experienced a series of CT tor. This led the CT service provider to To determine the failure mechanism, string failures while performing bridge instigate laboratory and field studies to CT strings from four of the seven units plug millout operations in the Montney create a biocide treatment program. The were further analyzed by the manufac- formation in northeastern British Colum- program has successfully mitigated fur- turers. In all four cases, internal corro- bia (Edillon et al., 2015). ther CT string failures in the Montney sion pitting was observed. Comprehen- With each trip in or out of the wellbore, and has now been applied to CT pro- sive analysis on one string, including CT strings incur fatigue that can be esti- grams in the Eagle Ford formation. scanning electron microscopy, energy- mated using simulation software based dispersive X-ray spectroscopy, and metal- on the CT outside diameter (OD), mate- CT String Analysis lography, was performed by the manufac- rial grade, and operating conditions. CT Seven failures of 60.3-mm (2.375-in.) CT turer and the University of Calgary. The strings can fail for a variety of reasons, strings supplied by multiple manufactur- analysis revealed that failure occurred including external mechanical dam- ers were experienced over 2½ months. at the bias weld and indicated micro- corrosion pitting and transverse crack- ing in the weld filler material (Fig. 1). The corrosion morphology (rounded shape with light green corrosion debris) and the presence of sulfur in the corrosion prod- uct provided indirect evidence of MIC.

CT Fluid Analysis CT fluid samples were analyzed for over- all microbial population, using the OSP LifeCheck ATP Test Kit, which quanti- fies ATP (adenosine triphosphate), the energy molecule of the cell. Bacterial counts (in microbial equivalent [ME]) can then be calculated from the ATP level (pg mass), in relation to a stan- dard, through ATP’s interaction with fire- fly luciferase enzyme, which produces light and enables detection with a lumi- Fig. 1—(a) An image of coiled tubing string failure showing transverse cracking nometer. The analysis indicated extreme- and pitting corrosion near the bias weld. (b) An image of bias weld material ly high concentrations of bacteria in the showing evidence of microbial influenced corrosion. source water (>106/ml).

20 JPT • JUNE 2016 7. 0 7 6.0 6.5 6 5.0 5.5 Control 5 54 ppm 4.0 107 ppm 4.5 214 ppm 4 321 ppm Log (ME/ml) Log (ME/ml) 3.5 3.0 428 ppm 3 2.0 2.5 2 1. 0 0246810 12 14 16 No 12344.5 17.5 24 Treatment Hours (a) Days (b) Fig. 2—(a) Results from a laboratory bacteria kill study with various concentrations of 2K7 biocide. (b) Results from a field study treatment of surface tank coiled tubing fluid with 2K7 biocide.

The presence of both sulfate-reducing at reducing bacterial levels, the glutaral- surface rebounded. Therefore, it was bacteria (SRB) and acid-producing bac- dehyde and THPS effects were short-lived concluded that the observed increase in teria was indicated in the fluid and on the with levels rebounding after 1 day. The surface bacteria was caused by the pop- solid metal using LifeCheck SRB and PRD 2K7 and DBNPA biocides were further ulation rebounding while sitting in the (phenol red dextrose) kits, respectively. evaluated over a range of ppm values. surface tanks. These bacterial metabolic subtypes are Even at the highest concentration tested, The rebound effect resulted from the known to be related to MIC. the DBNPA showed bacterial population CT fluid for the mill-out operations being MIC is caused by the formation of bio- recovery at 2 weeks, and with lower con- reused for each successive pad well. As films that result in localized corrosion in centrations, rebounding occurred in less flowback water was introduced into the form of very small pits, which lead to than 1 week. the surface tanks, so were the additives cracks and eventual pipe failure. The base The 2K7 biocide was effective at (polymers, surfactants) from stimulation fluid used for CT operations is often pro- 100 ppm for 8 days and when used at operations that, along with dissolved duced water recycled multiple times from >200 ppm reduced bacterial levels for formation nutrients (sulfates, nitrates, stimulation operations. This fluid pro- 2 weeks (Fig. 2). 2K7 biocide works by phosphates) and increased tempera- vides an ideal environment for bacterial disrupting the activity of bacterial mem- tures, provided an ideal environment for growth because it contains hydrocarbon brane proteins, causing cellular collapse. bacterial regrowth. and energy sources (polymers and sur- Unlike other biocides, which can react factants), is in the temperature range of with friction reducers and negate the Biocide Treatment Program 15°C–35°C (60°F–95°F), and is stagnant effect of both, 2K7 is nonionic and does The ability to identify the source of bac- when stored in tanks. not react with other fluid additives. terial population rebound in real time, using the LifeCheck ATP Test Kit, enabled Laboratory Biocide Studies Field Biocide Studies implementation of lower, maintenance Because the CT string and fluid analysis Field studies were performed to confirm treatments of the surface water with 2K7 indicated MIC as the root cause, laborato- the laboratory results and establish the biocide (one WSP per 40 m3–100 m3 ry and field studies were used to evaluate treatment program, as well as the bac- of fluid every 12–24 hr). In addition, available biocides to create an optimized terial contribution from source fluid vs. prestorage purging of the CT unit with treatment program. Multiple field-water wellbore flowback. Field studies conduct- nitrogen, 2K7 biocide, and corrosion samples were subjected to biocide kill ed on three separate well pads showed inhibitors has been implemented as the and loading studies to determine efficacy that one 2K7 Water Soluble Pak (WSP) per standard operating procedure by the CT and optimal concentrations. 10 m3 (63 bbl) of surface water effective- service company. JPT Four biocides were evaluated: glutar- ly reduced bacterial levels from >106/ml aldehyde, 2,2-dibromo-3-nitrilopropion- to <104/ml, with agitation of the fluid Reference amide (DBNPA), tetrakis(hydroxymethyl) reducing the reaction time. This fluid Edillon, L., McLeod, R., and Henderson, phosphonium sulfate (THPS), and OSP was then used for CT bridge plug milling M.A., et al. 2015. Application of a Biocide 2K7 biocide. Because each compound has operations and bacteria levels were mon- Water Treatment Program to Prevent a different mode of action, biocides were itored at various fluid locations in the Coiled Tubing Corrosion: A Case Study. tested at the same concentration. Once closed loop throughout the operations. Presented at the SPE/ICoTA Coiled Tubing comparative efficacy was evaluated, the Evaluation of wellbore flowback indi- and Well Intervention Conference & optimal treatment level was determined. cated consistently lower bacterial con- Exhibition, The Woodlands, Texas, USA, The laboratory analysis showed that centrations than the injected surface 24–25 March. SPE 173675-MS. http:// while all biocides were initially effective water. Despite this, bacteria levels at the dx.doi.org/10.2118/173675-MS.

JPT • JUNE 2016 21 E&P NOTES

Online Digital Rock Portal Launches Trent Jacobs, JPT Senior Technology Writer

Since the 1990s, X-ray computed is a way to share them so that there lege London, and Australian Nation- tomography (CT) has become increas- is more verification and more confi- al University. In addition, one project ingly popular for its ability to yield big dence built into” the analytical process, from Petrobras, the Brazilian national insights from tiny rock samples. But she added. oil and gas company, has been added to the volume of data produced from CT As the samples being analyzed by the portal. scanners is anything but tiny, and that a micro CT scanner get smaller, the Prodanović is also trying to market makes sharing and storing the files energy and storage required to image the portal as a way for companies to pre- a challenge. them grows larger. For example, rock serve their rock data, something she sees In an effort to address this issue and samples as small as 8 cubic millimeters as an advantageous feature during these foster collaboration in an area where may generate files of sizes between tumultuous times. there is currently very little, research- 700 MB and 30 GB. Such files are far too “The person who has been in charge of ers at the University of Texas at Austin large to send over most email servers, imaging may move on to a different posi- (UT) created a new web-based appli- and storage requirements can quick- tion, change companies, or they may get cation called Digital Rocks Portal. In ly balloon for companies carrying out laid off as is happening right now, and exchange for making their CT images of extensive exploratory analysis. there’s a high potential of a lot of infor- rocks available to outside researchers, Alternatively, companies can now use mation being lost,” she said. the website will offer exploration com- the digital rock portal and store all their But the free data management plat- panies free and unlimited data storage. data at UT’s advanced computer pro- form is just one of the incentives. The Maša Prodanović, the director of the cessing center, along with multiple back- broader scope of the portal involves Digital Rocks Portal and an assistant pro- up servers. Companies who want to use building an online community of geo- fessor at UT’s petroleum and geosys- the portal but keep their data private can science, engineering, and student re- tems engineering department, said this do so for 2 years, after which they must searchers that will work together to arrangement will improve the industry’s either allow the data to enter the public advance the budding discipline of digital understanding of rock microstructures domain, remove the data, or pay a fee to rock physics and generate new ways to and the accuracy of microscopic hydro- keep using the website. enhance productivity. carbon flow models—valuable informa- As it awaits industry participation, “This is not intended as a teaching tion that can be extrapolated to the res- UT has started to upload its repository tool,” said Mary Pettengill, the curator ervoir scale. of CT rock data and researchers from of Digital Rocks Portal, “but rather as a “These are large data sets that other institutions have signed on too, research tool with which existing data- require large computations, and this including Virginia Tech, Imperial Col- sets can continue to be useful to those studying porous materials, whether the researchers are academics or in commer- cial labs.” Another future aim of the portal is to help standardize both the data for- mat and the modeling algorithms used most often in the industry for rock anal- ysis by making them built-in features that can be applied with the click of a mouse; no downloading of software will be necessary. When coupled with computer modeling, 3D scans of small rock samples can be used to model how oil and gas might flow at much larger scales. A Each file will also contain metadata to new website is seeking to make the underlying data public to advance this identify the rocks and provide other con- emerging scientific discipline. Images courtesy of DigitalRocksPortal.org. textual information, something not rou-

22 JPT • JUNE 2016 Is your company developing a brilliant new technology? Brilliance can Showcase it to the industry at ATCE in Dubai on the change life exhibit fl oor theater. as we know it. Demonstrate your commitment to the groundbreaking technologies your company is developing for the E&P industry. Be an ENGenious presenter or sponsor at the Annual Technical Conference and Exhibition (ATCE) in Dubai, 26–28 September 2016.

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Albert Einstein tinely done today but necessary for col- to a OnePetro library for rock images that Science Foundation, a government agen- laboration. This aspect of the portal will may also include citations and links to cy that sponsors engineering research involve creating what is known as a “digi- research papers written about a particu- through grants, but UT is hoping that it tal object identifier” for each sample to lar sample. can establish a more sustainable business make its various properties searchable. The project has received funding model to keep the website up and run- The end product will be something akin through next year from the US National ning for the long term.

New Nanodevice Designed To Simplify Produced Water Treatment Stephen Whitfield, Staff Writer

In a presentation, “Put an END to Desali- cell reactions to create electric potential. unit. Capdevielle estimated that the com- nation Challenges,” presented by the SPE The battery serves as an electrical load pany would combine several devices into Gulf Coast Section’s Research and Devel- that completes the circuit by converting a singular unit approximately 3×3×2 ft opment Study Group, Bill Capdevielle the electric potential into power. Cap- in size. This unit could treat approxi- presented a new technology aimed at devielle said the load would be powerful mately 4,300 gal/D of produced water. A treating produced water at the wellsite to enough to monitor the desalination pro- pilot test will comprise five units. near-drinking-water quality. cess but not enough to run a pump. Magna Imperio Systems is currently The technology, electrochemical Once the circuit is completed, nega- in the midst of a funding round for the nanodiffusion (END), is designed to tive ions are drawn to the anode, and technology that should close sometime purify salt and brackish water supply the positive ions pass through the mem- this year. The company opened an office sources. Conceived by a high school stu- brane to coagulate around the mem- in Houston in March and is looking for dent in northern California, it was fur- brane, leaving a salty discharge. Void summer interns from Rice University ther developed while the inventor, Grant of negative and positive ions, the dis- and the University of Houston. Capdevi- Page, was a midshipman at the US Naval charge water is fresh. Capdevielle said elle said he has already approved the Academy in Annapolis. In 2014, he was the positive ions can be removed from seventh-generation design of the tech- awarded the Department of Energy the containment stream periodically. A nology. Three patents are published Award for Renewable and Sustainable water-softening process may work in and approved, and at least five more are Energy at the academy. Capdevielle is an this regard. being prepared. oil and gas consultant and an adviser for “Periodically, you have to either take The company is currently looking Magna Imperio Systems, a startup nano- out the cathode, let it dry, scrape it, clean for feedwater with which it can run a technology company created by Page it, put it back in, and your product is dry 3-month field trial. It will take water to further develop and commercialize salt. Or, we think there’s a way we can upstream from a reverse osmosis unit or the technology. shock [the salt] off electrically. We can a pretreating unit. The water should be END is a device comprising an elec- divert that fresh water into the saltwater of a high enough quality to run in a stan- trical battery and a three-chamber fuel disposal, shock it off, and you can go dard reverse osmosis unit, which means cell contained within a 5×5 in. square. back to fresh water,” he said. it must not contain any organics or sol- It contains an anode, cathode, and a The device has an energy footprint of ids larger than 5 microns in diameter. semipermeable membrane that contains 0.35 kW-hr/m3, which Capdevielle said Capdevielle said finding feedwater has proprietary nanotechnology and sepa- was well below the average footprint of been a challenge. “We need some water,” rates an incoming water stream. A con- a conventional reverse osmosis unit. He he said. “We’ve been asking for water for tainment loop circulates low-molarity estimated that the unit operates from about 9 months now, but no one wants to water. Salt water enters from the anode, 90% to 95% efficiency, compared to the give us water because they don’t want us and the molarity difference enhances 30% to 45% efficiency of a conventional to know what’s in it.”

A New EOR Concept From Shell To Enhance Waterflooding Trent Jacobs, JPT Senior Technology Writer

The key component of a new enhanced But after years of research, the com- “DME is a wonderful thing,” said Chris oil recovery (EOR) concept developed by pany believes dimethyl ether (DME) may Parsons, a principal reservoir engineer Shell is a petrochemical more commonly also boost recovery rates by up to 25% in at Shell Global Solutions, who described used in wart removers and as an aerosol reservoirs where waterflooding is no lon- the compound as “clean, efficient, por- propellant in hairsprays. ger effectively sweeping out residual oil. table, and safe.” However, due to low

24 JPT • JUNE 2016 Pore Scale Pore

This sequence shows how in a waterflooding application, a chemical known as dimethyl ether will move into residual oil droplets and cause them to swell up, which mobilizes the oil into the production stream. Graphic courtesy of Shell. oil prices, the company has temporarily wide potential application across the gies work, which use chemicals to lower shelved its plans to put DME to the test globe,” he added. the interfacial tension of the residual oil in the field. Part of what makes DME an intrigu- and the rock that it clings to. DME is produced primarily through ing EOR technology is that it is soluble Parsons stressed that for DME to be the process of dehydrating methanol but in both water and oil—with a preference an economic option it must be recovered it can also be produced from syngas. for the latter. Shell’s plan is to add DME from the producing wells. This process And because it is easily liquefied, DME to the waterflooding stream to reach a will require a series of strippers, com- is being considered as an alternative fuel concentration of about 16%, the upper pressors, and absorbers that may enable source for domestic heating and fleet limit of its dissolvability. up to 90% of the DME to be recycled. vehicles in Europe. “And then very interesting things start Shell began its research into DME for Speaking at the recent SPE Improved to happen when it’s in contact with oil,” EOR in 2007 and was prepared to launch Oil Recovery Conference in Tulsa, Par- explained Parsons. “It essentially jumps a number of pilot programs before oil sons highlighted the fact that DME phase from the water to the oil.” prices crashed. Parsons said for the is nonreactive, meaning it will not Once it mixes with the residual oil, he pilots to move forward, oil prices must degrade inside the reservoir or adhere said that the DME causes the oil phase reach “reasonable levels,” but did not to the rock matrix, and that it is equal- to swell, which forces the droplets out of provide a specific price point. ly effective in both sandstone and the tiny pore throats. The chemical also One advantage Shell has in terms carbonate reservoirs. lowers the viscosity. These two changes of cost and supply chain is that the “We’re quite confident we can deploy make it much easier for trapped oil to company produces DME at its Rhine- DME in any number of reservoirs, at become mobilized by a waterflood. land Refinery in Germany, one of the most conditions that we are likely to This is a significantly different process largest DME manufacturing sites in encounter, and that gives DME a very compared with how most EOR technolo- the world.

Self-Adjusting PDC Bit Under Development Trent Jacobs, JPT Senior Technology Writer

Baker Hughes is developing a drill bit partners to see how the technology will pipe and is not actively controlled by capable of auto-adjusting its depth-of-cut work in the real world. the driller. (DOC) feature to handle dynamic drill- The crux of the system involves three “That’s the strength of this concept— ing conditions. In what may be a first- “hydromechanical feedback” mecha- because introducing electronics increas- of-its-kind technology, it is designed to nisms that are installed inside the PDC es the cost and also affects the reliabil- enhance polycrystalline diamond com- bit blades. Each mechanism has a piston- ity,” said Jayesh Jain, a research engineer pact (PDC) bits, and the company expects cylinder filled with hydraulic fluid that at Baker Hughes who helped design the it will generate value by delaying bit dam- is contained in a removable cartridge. new bit. age and increasing overall rate of pene- At the business end are egg-shaped Known for enhancing drilling stabil- tration (ROP). diamond elements called “ovoids” that ity and efficiency, DOC control is consid- In addition to the above benefits, Baker provide the DOC ability. ered to be a technology breakthrough in Hughes also believes the self-adjusting As the bit’s response to the forma- its own right. However, traditional DOC PDC bit will advance automated drilling tion changes, the mechanisms act like controllers are fixed in place and usu- efforts and enable harder-to-drill well shock absorbers to ensure the optimal ally tailored to a specific rock hardness, sections to be drilled in a single run vs. weight on bit (WOB)—the force applied which may require the bit to be replaced the two or three they may require today. from the surface to drive the bit into the as drilling moves deeper. The company has tested the bit in rock—is being used. The system does To figure out how and when the con- research wells and is now looking for not use electronic sensors or wired drill- trollers on its new bit should move, Baker

JPT • JUNE 2016 25 Explaining why such During testing, the self-adjust- adaptability is important, ing bit was able to achieve a ROP of Jain said, “Rapid changes in 90 ft/hr without stick/slip occurring, the contact forces with the whereas the fixed-bit encountered a formation over a few sec- stick/slip event when the ROP reached onds indicate unintended 34 ft/hr. changes in depth-of-cut that The tests, details of which were pre- are typically encountered sented in an SPE paper at the 2016 IADC/ during harmful events, such SPE Drilling Conference and Exhibi- as drilling vibrations. So this tion, demonstrate one of the key selling Contained in three identical cartridges, new mechanism senses these points for Baker Hughes: self-adjusting hydromechanical devices installed inside the bit changes, and essentially bit technology is capable of achieving may help drillers move through long and diverse absorbs part of the load.” a higher ROP by allowing drillers to use well sections. Image courtesy of Baker Hughes. Among those harmful more WOB. events the technology is To avoid causing damage, drillers often Hughes turned to computer modeling seeking to mitigate most is stick/slip, use conservative parameters when apply- and historical drilling data. As drilling which happens when the bit becomes ing WOB. Jain said the self-adjusting bit initiates, or restarts after a drillpipe con- momentarily stuck but the drillstring technology is more immune to problems nection, the mechanisms fully extend the continues to twist above it. It is a prob- caused by the improper WOB and there- DOC controllers to help stabilize the bit lem encountered both onshore and off- fore allows drillers to “push the limit” as it starts turning. shore and aside from the damage it may and reach target depths faster. Over a few minutes, the DOC control- cause to the bit, stick/slip can gener- lers gradually retract to allow for smooth ate vibrations along the drillstring that For Further Reading drilling. And when the bit suddenly may cause expensive bottomhole assem- SPE 178815 A Step Change in Drill Bit encounters stiffer rock sections, the DOC blies to fail and lead to additional losses Technology with Self-Adjusting PDC Bits controllers extend again to compensate. from downtime. by Jayesh Jain, Baker Hughes et al.

Wireline Method Offers Faster, Cheaper Plugging for Deepwater Wells Stephen Rassenfoss, JPT Emerging Technology Senior Editor

Five depleted natural gas wells in water said received bids up to USD 60 million cements those spaces, leaving the thick 7,000 ft have been plugged and aban- per well. steel casing as part of the barrier. doned using tools delivered by wireline, Deepwater decommissioning is a To do so, Wild Well inserts a tool into slashing the time and cost of the work in young field; most wells have not yet the wells that perforates surrounding the Gulf of Mexico. reached the age where production has casing, runs fluid to clean out the annu- The work was done by Wild Well Con- stopped and plugging is required. The lar area to be plugged, then runs a resin trol, part of Superior Energy Services, industry is seeking methods that can followed by cement to seal a space that which developed the method along cost-effectively plug wells in deep waters, exceeded the dimension required by with Oceaneering to access and cement in which the cost of fixing a leaking plug the Bureau of Safety and Environmental hard-to-reach spaces around complex is punishingly expensive. Enforcement, the US offshore regulator. offshore wells. The starting point for these jobs is The first two wells took longer than “We are taking riserless technolo- straightforward, remove production tub- expected as Wild Well and Oceaneering gy to its absolute limits,” said Martial ing and set a cement plug low in the well worked out the kinks in the multicom- Burguieres, vice president of marine well to temporarily abandon it. Completing ponent system. But the next three easily services for Wild Well. “We have come up the job is more complicated. Permanent beat its predicted times, which were with the cheapest and most efficient way plugging requires sealing all the possible lower than industry averages, according to put a fully, government-sanctioned leak pathways. In complicated deepwater to the company’s presentation. plug in well.” well designs, there can be as many as four The method was created as a way to By rethinking the process, which has layers of casing, with hard-to-reach open plug and abandon offshore wells with- often required a floating rig and riser to spaces in between that must be cement- out the high cost of deepwater rigs and pull the casing before plugging the well- ed shut. risers. But the first job showed how the bore, Wild Well has been able to plug and Removing the layers of steel addresses economics of the business have changed abandon wells for about USD 10 million the requirement, but it is costly. Instead since oil prices and offshore drilling rates each for Marubeni Oil and Gas, which he the Wild Well system accesses and have sunk.

26 JPT • JUNE 2016 With floating rigs rates now compa- rable to the cost of the multiservice ves- The tool is one of several components sels that the method was designed to developed to plug complex wells use, Burguieres said that at the request without a riser: of their client, they used a floating rig, • The Well Intervention Control System built by Oceaneering, which provides a more stable platform. which is a “flightless” remotely Wild Well has four wells left on the operated vehicle lowered to the nine-well contract. The work ahead work site. becomes increasingly difficult. Over the • The 7 Series device is used to first five wells, only one annular had to be control pressures during work plugged. Ahead are wells with two annu- and safely insert equipment into lars, and one with three. a well. Based on land testing, he said Wild • The Concentric Circulating Well can perforate three casing walls in System is used to send fluid sequence—even if the pipe is out of line, down to the well through a pipe creating uneven spaces. inside the larger drilling pipe used to land the 7 Series and fluid The faster-than-expected plugging circulation equipment. hastens the day when Wild Well will need • The DeepRange tool is a to find some work. One possibility is an multifunction wireline tool used to oil company with a couple of wells to perforate, circulate, and cement. plug holding a long-term contract on an underused deepwater drilling rig. The long, yellow and blue cylinder Burguieres would like to use a riser to in the picture is Wild Well Control’s deliver the DeepRange tool to demon- DeepRange tool, which was used strate its performance in that environ- to plug five deepwater wells in the Gulf of Mexico. Photo courtesy of ment, in hopes of broadening the possi- Wild Well Control. ble uses of the tool. JPT Permanent Patches: NO RIG REQUIRED.

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JPT_coiled-tubing_half-page.indd 1 5/10/16 6:15 PM EOR SHALE EOR-For-Shale Ideas to Boost Output Gain Traction Trent Jacobs, JPT Senior Technology Writer

Small CO2-capturing and reprocessing facilities might be one of the keys to ensuring decades of production from vast shale plays including the Permian Basin, Eagle Ford Shale, and Bakken Shale. Image courtesy of the US National Energy Technology Laboratory.

ow oil prices may not be the big- they may cost, what the most pressing injection-based EOR technology for tight gest threat to the long-term sus- challenges are, or exactly when an EOR oil in the US. The company said the L tainability of the North American operation should begin. development may have long-term pro- shale business. “Our understanding is really small,” duction benefits and is competitive with Some are more concerned about the low said Todd Hoffman, an assistant profes- drilling new wells. recovery rates of horizontal shale wells, sor of petroleum engineering at Montana But other than making it clear that the estimated to be about 7% on average— Tech University. “We’re coming from the process has been successful and uses dry far short of the 40% achieved through conventional world where ‘this’ is how we gas produced in the same field, EOG is primary and secondary (waterflooding) did EOR and we may just have to throw all withholding key operational details such production in conventional reservoirs. that out.” as whether it involves the huff-and-puff Refracturing has been touted as the Hoffman is one of several researchers technique or continuous injections. next big thing to improve ultimate recov- trying to figure out how EOR method- A number of other innovative shale ery, but such operations remain relative- ologies can be adapted or reinvented for producers including Statoil, Nexen Ener- ly expensive and may only temporarily the oil-rich shale fields of North Dakota, gy, Continental Resources, and Mara- reset production to initial rates once or Texas, and Canada. thon Oil have also either funded research twice in a well’s life. One of the most popular ideas being or are known to be running pilots, but To see long-term results and a dou- studied is a huff-and-puff approach that have not made their results public. bling or tripling of current recovery uses a single horizontal well to alternate As most shale producers remain rates, a number of experts say enhanced between producing oil and injecting nat- silent about their EOR efforts, there are oil recovery (EOR) technologies must be ural gas or CO2 to re-pressurize the reser- a growing number of technical papers developed to work in tight shale reser- voir and displace oil. being published by university petroleum voirs. And due to persistently low natural Another idea is to apply continuous departments and reservoir engineering gas prices, current efforts appear to be injections into one well and use an offset consultants. They are using computer exclusively focused on oil and condensate well as the producer. Others are looking models and corefloods to test their theo- producing wells. into flooding the wells with surfactants ries and have produced promising num- It is early days for this area of EOR and possibly acid to stimulate production. bers that suggest there may be several research. There is no consensus on which In May, EOG Resources laid claim to practical ways to implement EOR strate- approaches will work best, how much the first economic demonstration of an gies for shale.

28 JPT • JUNE 2016 “I think the biggest challenge is the low permeability, the very small pore throats that we have in the shale,” said Rober- to Aguilera, a professor of tight oil and unconventional gas at the University of Calgary. “If we are able to somehow man- age those very small pores, then I think we will be in good shape.” His research, funded partly by Nexen, proposes that those pore throats can be accessed by injecting otherwise stranded gas into the condensate and oil-rich lay- ers of shale. Computer models show that under Many of the enhanced oil recovery ideas for shale reservoirs call for producing favorable conditions in plays like the wells to be turned into gas-injector wells, either permanently or on a cycle Eagle Ford Shale of Texas, this may yield using the huff-and-puff approach. Photo courtesy of the US National Energy another 10% to 20% of incremental oil Technology Laboratory. over a 20-year period. Aguilera com- pared it to pouring a bottle of cheap But the potential is so big that we have He then listed several reasons why wine down a well and getting champagne to keep trying.” EOG believes its EOR strategy will not in return. be a “blanket application” across the “I am looking at hundreds of injection EOG Does EOR Eagle Ford, or in any other shale play for wells and hundreds of production wells,” The apparent breakthrough from EOG that matter. that would be suitable EOR candidates may be a turning point in the discussion For starters, an existing infrastructure in the Eagle Ford, he said. “It would be over whether EOR-for-shale is workable. in the area and abundant natural gas pro- a magnificent thing to do and I think the The company said that while the rate-of- duction have helped keep capital costs to potential is outstanding.” return is comparable to drilling a new around USD 1 million per well, a figure horizontal well, for every dollar spent, EOG hopes to drive down as it learns and Success Is Hard To Find its EOR program delivers twice the net becomes more efficient. For all the optimism coming out of present value. Helms also noted that geology is criti- academia, there are plenty of reasons Speaking on a quarterly conference cal to success and that results may not be to be skeptical, not the least of which is call, EOG executives said the process adds as beneficial where the producing forma- the fact that laboratory and modeling new reserves—as opposed to accelerated tion is too far down-dip or up-dip. results have historically done a poor job production—for about USD 6 per incre- “We have long discussed the compe- of matching up with the complex hetero- mental bbl and will deliver returns above tent barriers that encase the Eagle Ford geneity of shale reservoirs that makes 30% at USD 40 oil prices. The company’s and provide vertical containment for predicting flow behavior difficult. models show that recovery rates may be completions,” he said. “This unique fea- When Hoffman searched for examples improved by 30% to 70% and produc- ture also plays a significant role in keep- of EOR projects in the Bakken Shale, a tion responses in each well tend to begin ing the injection in contact with the tar- play with tens of thousands of horizon- within 3 months of the treatment. geted reservoir. The injected gas is thus tal wells drilled, he found only seven The announcement follows 3 years able to become miscible with the oil in wells that had been converted into injec- of research and four “very successful” the reservoir and subsequently drive tor wells. Public data from the wells show pilot programs that involved 15 wells. incremental oil recovery.” that none were successful at increas- The next step for the company will be to ing recovery, mostly due to exceedingly launch a fifth pilot later this year involv- Cash Crunch Slowing Progress quick breakthroughs from injectors to ing 32 wells. Aside from the EOG example, those the producers. “The results from lab experiments pressing forward on other EOR-for-shale For someone who has spent nearly indicated that the process was technical- projects are having to deal with the fact a decade believing EOR applications ly feasible, but the economics and opera- that like these rocks, money has also for shale could be proven through good tional execution were going to be chal- become tighter than ever. engineering, the lack of positive results lenged without some creative problem During the boom cycle, many opera- from such a prolific oil-producing region solving,” said Lloyd Helms, the executive tors were too busy to spend time and was a reality check. vice president of exploration and produc- cash on understanding which aspects “I am not as likely to say it’s going to tion at EOG. “Our EOR team has not only of shale production might have helped work, or that we just have to figure how solved the problem, but demonstrated advanced EOR research. And since the it’s going to work,” he said. “I’ve pulled returns that are competitive with our slowdown began in 2014, most com- back from that. It may not work, ever. premium drilling program.” panies are finding it difficult to expend

JPT • JUNE 2016 29 capital on anything that does not offer an Houston that is developing new prod- Early Breakthrough Issues immediate payoff. ucts for shale EOR, also believes CO2 is Hoffman said of the EOR testing done Earlier this year, Apache Corporation the best gas to use in shale reservoirs but so far in the Bakken the biggest problem called off plans to launch an EOR pilot warns of its pitfalls. observed was the speed at which water or project in the Permian Basin. The 3-year, “For a well that has been depleted, it gas was breaking through the formation. USD-6-million joint project was also part- could have produced 200,000 or 300,000 In some cases, the breakthroughs from ly funded by the US National Energy Tech- barrels of oil,” he said. “That’s a big void.” injectors to producers occurred in a mat- nology Laboratory and led by researchers He explained that the amount of CO2 ter of a few days. from Texas Tech University (TTU). required for an initial injection cycle This indicates that the fluids and gases The plan was to take a set of producing in such wells might cost USD 1 million, were hitting the ultralow-permeability wells and add compressors to make them which is why operators should initially rock matrix like a brick wall and then injector wells for huff-and-puff opera- focus on using cheap natural gas or natu- finding a fracture to move through. With tions. Researchers were hoping to learn ral gas liquids. the fractures acting as highways for fluid how to optimize the volume of injected In areas like the Bakken or Eagle Ford, and gas, the conformance needed to gas, the rate, and duration, and then how he said producers could alleviate bottle- sweep residual oil out the system simply long to produce oil before starting the necks by using produced gas for EOR, does not exist. injection cycle over again. leaving spare capacity for more oil to be Hoffman said the Bakken results were The simulation work suggested that produced. But as shale fields begin to discouraging, but he noted that some of the injection/production cycles could be build an EOR infrastructure and the con- the companies may have just been trying between 3 months and 6 months. On cept is proven with natural gas, Yinghui to see whether high volumes of gas and a multiwell pad those cycles could be said companies should switch to CO2 to water could be sent at low pressures back alternated so oil is always pumped out by improve the recovery factor. into the tight formations, which turned at least one or two wells while the others One way to do that would be to build out not to be an issue. are injecting gas back into the formation. localized power plants that burn gas and But at least two of the EOR pilots were transmit electricity to a field’s pumps and disrupted by “frac hits” from offset well Natural Gas Or CO2? compressor stations. Yinghui said the completions located hundreds of feet James Sheng is an associate professor in CO2 generated during this process could away, which also supports the theory that the petroleum engineering department be captured and piped to the individual within tight formations, fracture net- at TTU and the principal investigator on well locations. works are often extensive and must some- the Apache pilot. He said although nat- “Right now the major concern for natu- how be sealed to achieve conformance. ural gas was selected for injection, the ral gas is that it doesn’t have anywhere to Hoffman said people are looking at research shows that the optimal gas for go, but if there are several power plants in using different emulsions or calcite- EOR is CO2 because it becomes miscible the region, each plant could serve maybe producing bacteria that could be sent with oil at lower pressures and drives 1,000 wells and that’s good enough,” to downhole to plug up the fractures. recovery rates higher. support the economics of an EOR proj- There may be other options not yet And while in many areas CO2 is scarce, ect, he said. considered, including drilling a well the Permian Basin is home to one of the Yinghui added that with CO2-EOR, he along the toe-section of a set of pro- world’s largest CO2 supply infrastructures expects producers in the Bakken would ducing wells, leaving it unfractured, and that was set up long before the shale rev- lower their breakeven costs from about then using injections to drive EOR pro- olution began to support conventional USD 38–45 to the low USD 20s. duction in the fractured wells. Or maybe, EOR. As the number one oil producing He noted that many companies still operators could starting drilling wells in onshore area in the US, Sheng sees a big view EOR as too expensive to apply for a different orientation so fractures run opportunity for unconventional opera- shale. But despite the costs involved with along the well instead of perpendicular, tors in the Permian. establishing the necessary support facili- which could make some EOR techniques “It’s the perfect solution,” he said. ties, Yinghui said operators should still more effective. “You have existing pipelines and the consider investing in the technology so “I don’t know what the solution is,” he CO2 is there.” they can produce more oil with less capi- said. “But I think that is an area we need He also acknowledged the rosy recov- tal than would be consumed by expand- to focus on because if something is going ery projections derived through core- ing current developments. to work, we have to block off these high- flooding and simulations, which high- “As a matter of fact, EOR does cost a permeability pathways.” lights the need for more field testing. lot of money—in the conventional res- “In the laboratory,” he said, “we could ervoirs—but not so in the unconven- Zipper Fracs get 50% or 60% of the oil recovered, tional reservoirs,” he said. “If this works, Perhaps inter-well communication via a but in the field that is probably going to where you used to have to drill three or fracture network can be beneficial. And if be 15% to 20%.” four wells, you may only need to drill one so, then operators may want to start think- Yinghui Li, cofounder of InPetro Tech- well,” to have the same level of productiv- ing about EOR very early in their devel- nologies, a reservoir modeling firm in ity and bookable reserves. opment plans. This is the premise of a

30 JPT • JUNE 2016 new feasibility study done by Oluwanifemi ENHANCED OIL RECOVERY PILOTS IN THE BAKKEN SHALE Akinluyi, a graduate student in the petro- leum engineering department of the Year State Fluid/Gas Used EOR Type

University of Tulsa. 2008 North Dakota CO2 Huff-and-puff She presented the details of her work 2009 Montana CO2 Huff-and-puff in a paper at the recent SPE Improved Oil Recovery Conference. In the paper, Akin- 2012 North Dakota Water Huff-and-puff luyi describes how recycled-gas injec- 2012–2013 North Dakota Water Flood tions may be more effective when applied 2014 North Dakota CO2 Vertical well injection to “zipper frac” wells. Many shale pro- ducers have adopted the zipper-frac drill- 2014 Montana Water Flood ing and completion method because it 2014 North Dakota Natural Gas Flood allows them to work on multiple wells Source: Todd Hoffman at the same time and complete them one after the other in a configuration that so instead of attracting oil they attract overly expensive. She added that flood- resembles a zipper. water. As a consequence, the surfactants ing the well with water of an improper In a zipper frac, many of the fractures imbibe into the rock and displace the oil, composition would likely cause the clays will overlap or come into close proxim- which allows more to be produced. inside the shale to swell up and lead to ity with each other and Akinluyi thinks With funding from the US Department formation damage. this presents an opportunity to use one of Energy, ConocoPhillips, Noble Energy, One of the biggest challenges the UND of the offset wells to inject gas. “The zip- and Statoil, researchers at the University researchers discovered with surfactant per fracture gives you that structure to be of North Dakota (UND) have been pur- flooding in the Bakken is that the for- able to provide enough pressure support suing this area with coreflood tests and mation water is high in salinity and the for your producer,” she explained. believe it is an affordable option even in temperatures are very high, which both She said as the reservoir is depleted the current low-price era. affect surfactant performance. through production, computer models Dongmei Wang, an assistant profes- After testing a number of chemicals, show that the drainage volumes around sor of geological engineering at UND, they were able to identify a formula that fractures from adjacent wells begin to coauthored an SPE paper that described may withstand the harsh conditions of expand toward each other. “And if we let how the middle layer of the Bakken might the Bakken, and are looking to see if it time pass by, as you inject and produce respond favorably to surfactants. will work in other formations such as the on the other side, you will see even more The middle Bakken was chosen because Niobrara Shale which also has a relative- communication,” she added. it has more siltstone, limestone, and dolo- ly low porosity. UND plans to expand the According to her research, the win- mite components than the upper and research project to study if CO2 can be dow to begin this type of EOR may range lower benches of the formation, which used as a surfactant carrier to increase the from 1 to 5 years if the fractures are tend to be more of a pure shale and there- contacted area inside the reservoir. JPT close enough and should be done before fore tougher to penetrate with surfactants. significant depletion has taken place in “In the upper and lower shale, the For Further Reading order to take advantage of the forma- permeability is nano-darcy—very low,” SPE 180270 Improved Oil Recovery Pilot tion’s remaining pressure. Wang said. “But in the middle Bakken, Projects in the Bakken Formation, Akinluyi said her models also showed we think it is [higher] compared with the by Todd Hoffman and John Evans, that certain zipper-frac and well-spacing other formations.” Montana Tech University. designs will work better than others Wang said the injection/production SPE 177278 Improving Recovery of Liquids with regards to EOR. The variation that cycles might be only 1–2 weeks and could From Shales Through Gas Recycling and appears to work best is the “modified be done for a few years before reaching Dry Gas Injection by Alfonso Fragoso, zipper frac” which develops overlapping the point of diminishing returns. How- Yi Wang, Guicheng Jing, and Roberto Aguilera, University of Calgary. fractures from adjacent wells. She said ever, she noted that “we need to be patient SPE 179577 EOR Potential for Lean operators using these techniques should to see the oil recovery increases” as it Gas Reinjection in Zipper Fracs in Liquid- consider running models like hers if they could take 6 months to a year before any Rich Basins, by Oluwanifemi Akinluyi and have future EOR plans. production improvements are observed. Randy Hazlett, University of Tulsa. She said that adding a weak acid to the SPE 179541 Optimizing Water Chemistry to Surfactant Flooding mix might also eat away at parts of the Improve Oil Recovery From the Middle While most seem to be looking at gas formation and increase the surfactant’s Bakken Formation, by Dongmei Wang, injections, there is also significant inter- contact area without causing too much University of North Dakota, et al. est being paid to surfactant treatments formation damage. SPE 179667 Surfactant Huff-n-Puff using the huff-and-puff approach. The A surface system will be needed to mix Application Potentials for Unconventional goal is to use the surfactants to alter the surfactant with water and send it Reservoirs by Patrick Shuler, Zayne Lu, the wettability of the reservoir rocks downhole, but Wang said it should not be and Qisheng Ma, ChemEOR, et al.

JPT • JUNE 2016 31 Norway Faces Up to Harsh Conditions Stephen Rassenfoss, JPT Emerging Technology Senior Editor

The drilling floor on the Odfjell Drilling’s Deepsea Atlantic, which began work on a Johan Sverdrup 1 development well on 1 March. Photo courtesy of Statoil.

ffshore Norway is an unlikely working on high-tech tools to raise Eldar Sætre, the chief executive offi- spot for optimism. The conti- millions of fish, those working in the cer (CEO) of Statoil, pointed out that Onental shelf is home to a mature oil business are not talking about a the national oil company has lowered its basin, with harsh sea conditions, a repu- career change. average break-even cost for new proj- tation for high costs, and an exploration “Oil [/bbl] is selling for the same prices ects from USD 70/bbl to USD 40/bbl, and frontier well north of the Arctic Circle. as 4.5 kilo salmon. We could all start emphasized that the bulk of the improve- Last year’s version of low oil prices, farming salmon, but I do not think so,” ment was in savings that will remain after when benchmark crudes traded for said Arve Iverson, ROV operations man- supplier discounts are gone. around USD 50/bbl, led to news stories ager for Oceaneering, at the recent Sub- The themes of standardization, sim- in Norway pointing out that the shares sea Valley Conference in Oslo. plifying requirements, and working of the 10 largest local oil-industry- The show put on by the organization together were common ones when hear- related companies, excluding Statoil, created to increase the visibility of the ing from oil industry experts. were worth less than the 10 biggest engineering-driven oil industry in south- The test of whether the Norwe- aquaculture companies. east Norway, also amounted to a rally gian industry can deliver on its goal While raising salmon is expected to in support of the future of oil offshore of profitably producing oil in a era grow into a big business, with big oil Norway, and the global markets these of low prices, is the Johan Sverdrup industry suppliers such as Kongsberg com panies serve. field, a multibillion-barrel find which

32 JPT • JUNE 2016 is moving forward in the midst of “This may set up large bending reserves through exploration, with dis- the slump, showcasing innovations moments in the pipe, which are perma- coveries including the Johan Sverdrup backed by the Norwegian government nent,” Fjelldal said. “Significant long- discovery and an aggressive Barents Sea and Statoil. term stress can cause hydrogen-induced exploration program. “Sverdrup is one of the biggest indus- stress cracking.” “There are huge structures” in the trial projects in Norwegian history and The new connector, called the SeAlign blocks offered in the 23rd round, said one of the biggest in our time,” said Tord adjustable connector, does not require Kristin Færøvik, managing director for Lien, Norway’s minister of petroleum subsea construction work to stop. Lundin Norway. A Lundin map shows and energy. He pointed out that giant “If it comes in at 3°, it remains at 3°. 8.8 billion BOE yet to be discovered in finds are not likely to be the norm in the You do not have a bending moment,” said the lightly explored sea. It has discov- future when lower-cost development Bjørn Pettersen, technical manager for ered two oil-producing fields in the Bar- methods will be needed to bring small SubseaDesign and one of its founders. ents Sea—Alta and Gohta—where a total finds into production, and to extend SubseaDesign investors include Statoil, of five oil fields and two gas fields has their productive years. which has ordered 72 of the new connec- been found. “It is fundamental to reduce costs tors for installing pipelines needed for Lundin is studying how to develop to maintain subsea (completions) as a the subsea development of the massive its discoveries in the Barents Sea and development solution, and to maintain Johan Sverdrup field. Færøvik said “we see development Norway’s position as an energy exporter going forward.” in the decades ahead,” he said. Northern Frontier The leases offered in the 23rd round An acid test for how far they can take sub- are even farther north than the discov- Subsea Engineering sea development is in progress: The Nor- eries made above the top of Norway. In the exhibit hall nearby were com- wegian government’s 23rd license round She said warmer currents make condi- panies working on that problem with has offered large blocks in the Barents tions comparable to waters elsewhere on innovations ranging from an all-robotic Sea, well north of the Arctic Circle. the Norwegian Continental Shelf (NCS), drilling floor to a system for sharply “We have been told that [production] which are harsh, but something they reducing the paperwork that magnifies from Barents Sea is too expen ° sive and have learned to live with. the cost and conflicts associated with leave it there. But guess what, it can be A bigger problem would be discover- project management. done,” Sætre said. ing gas rather than oil in blocks offered While Stavanger is the best known oil Statoil’s competitors for blocks include in the current round, because get- town in Norway, there is a large clus- Lundin Norway, the independent Norwe- ting the gas to users would likely cost ter of offshore engineering, design, gian company, whose aggressive explo- more than it would fetch on a glutted and software-driven companies in and ration program has allowed it to quickly global market. around Oslo, which promotes the area as grow to become a large independent. It Færøvik said one of the positives for the Subsea Valley. said it has discovered 685 million BOE of development now is the cost of finding The companies range from diversi- fied technology giants such as Kongs- berg to innovative manufacturers, such as SubseaDesign, a 26-person company whose future in these hard times depends on the ability of its engineers to design and manufacture clever solutions for difficult problems. “It is new technology that brings us forward and keeps us alive in the mar- ket,” said Hans Fjelldal, sales manager for SubseaDesign. An example of that is a connect- er it designed to be self-aligning, which swivels up to 3° to accommodate an incoming pipe that is off line, while still providing a lasting seal. The conventional option is to stop, and force the pipe back in line with the con- An adjustable connector created by SubseaDesign is tested to see if it can nector. The delay adds to the cost, and accommodate a pipe that is 3° out of alignment and still seal. This SeAlign the lasting stress on the pipe can cause connector will be used by Statoil to develop the Johan Sverdrup field. Photo future trouble. courtesy of SubseaDesign.

JPT • JUNE 2016 33 and developing offshore fields “is the lowest it has been for a long time in the Subsea Price War Demands NCS,” and it will likely remain that way for a while based on the long-term nature Cost-Saving Innovations of this slowdown. nyone selling something new for Change is coming in many forms: Staying Alive Aoffshore exploration and produc- steel, sensors, software, and standards. For financially strong operators such tion has to be able to answer a simple Suppliers are working on things rang- as Statoil and Lundin, reducing costs is question from customers, “How can we ing from shrinking the size and cost of about making it possible to go forward save some money?” subsea pumps, removing hundreds of with exploration and development work. That blunt assessment was offered tons of equipment from platforms, to But for many others in the industry, the by Sören Themann, vice president sub- pipe connectors that can easily adjust to big challenge is surviving the downturn. sea monitoring for Kongsberg Mari- accommodate pipes coming in off line, “Oil service companies have bright- time, in a presentation to a group of oil avoiding the time and wear associated er times ahead but they have to sur- and gas writers visiting the Norwegian with bending them into line. vive 2016,” said Audun Martinsen, vice subsea supplier. Closer at hand are offerings based president analysis for Rystad Ener- The point was made again and again on data and processes, such as a proj- gy. The Oslo-based energy informa- on a tour of offshore-oil businesses in ect to reverse the rising tide of paper- tion and consulting firm predicts 2017 the Subsea Valley, the Oslo-area clus- work making projects much more will be another year of contraction in ter of engineering-driven subsea service expensive, and rethinking old proj- contracts awarded. and supply companies whose customers ect plans with an eye toward sharp He said, “2018 would be a turning need to drastically reduce the costs to budget reductions. point for the offshore market with sharp a level where they can again profitably Statoil is “radically reshaping our increases in 2019 and 2020.” While add offshore production. portfolio of nonsanctioned projects,” to rising oil prices will help revive demand What is required is “not small move costs down enough for them to go and help the rates to begin to recover, changes—radical changes,” said Eldar forward, Sætre said. It is one of many there will be still be an oversupply of Sætre, CEO for Statoil. He said the Nor- trying to revive projects that were put drilling rigs. wegian national oil company is “tak- on hold because they would not profit- Floating units ordered when oil prices ing down costs faster and with much ably produce hydrocarbons in a market were high will lessen the benefit of the more impact than we planned for and we where the price band for oil is centered 28 floating rigs retired last year and 5 could foresee.” at USD 50/bbl. expected to drop out this year, accord- ing to Rystad. As a result, the number of floating rigs working will rise from a low of 57% to 68%, if Rystad’s optimistic forecast holds true. The company described an econom- ic environment which will be getting less difficult, but one where success will require a different approach to managing exploration and production. “We have come from an environment where the important thing was to get barrels into action as soon as possible. Speed, not cost—that was the mental- ity in companies,” Sætre said, adding that now the focus is on cost, on keep- ing operations as lean as possible and as profitable as possible. And in that environment, it will not be possible to profitably produce some once-promising-looking hydro- carbon deposits. “There are places that will never come The K-Lander, built by Kongsberg for remote monitoring of methane leaks, near a methane hydrate test site. It was designed to create a simple platform back,” said Jarand Rystad, managing that can be scaled up to allow multiple devices to cover a wide area and partner at Rystad Energy. communicate. Photo courtesy of Kongsberg.

34 JPT • JUNE 2016 Installation Riser and Flowlines Well unit cost* (USD million) Oil Price (USD/bbl) 14% 12% 40 120 SPS 35 Other 100 5% 9% 30 80 25 20 60 15 40 Topside 10 30% 20 Facility 30% 5 (FPSO/ Platform) 0 0 Drilling and Completion

Cost Distribution * Subsea production system cost only Offshore Development (Typical Greenfield) Source: Internal FMC Technologies estimates

When oil prices plunged in 2015, the cost of subsea completions dropped slightly in comparison. The Forsys joint venture formed by FMC and Technip aims to reduce cost of installation, risers, flowlines, and subsea production systems (SPS). Images courtesy of Forsys.

A rethinking is needed globally be- ability to work with owners and sup- ander Risøy, the managing director of cause costs had gotten so out of hand pliers and ensure all that is ordered Nebb, an engineering and manufactur- that on some projects “even if you give it works together adds efficiencies. And ing firm developing subsea power sys- [hardware] away for free, the project will this arrangement reduces the number of tems for variable speed electric motors not fly,” said Henning Gruehagen, front- interfaces and paperwork. that are smaller than those on the mar- end manager and head of Forsys Norway, But it requires a level of trust from ket now. during a presentation at the venture’s operators who have long divided the Its goal is to build subsea equipment Oslo area office. Forsys is selling the idea work among multiple competing firms, that turns a steady electric current from that given a chance to conceive, design, not wanting to cede too much pricing an electric line into a precisely adjustable and manage a project from the start, it power to any one firm. flow, and “you don’t need anything top- can reduce the total cost by 20%–40%. side and you now achieve true subsea fac- With hundreds of offshore projects Pump Power tories,” he said. delayed indefinitely, there are more man- While using pumps to add production There are huge fields now served by agers motivated to try change. onshore is common, they have been lit- pumps whose power needs are rated in “We are extremely busy these tle used in deepwater fields, due to con- the megawatts (MW)—enough to power days,” Gruehagen said “We are talk- cerns about the cost and lack of equip- thousands of homes—but finding the ing to many companies with delayed or ment available. hardware to profitably boost produc- canceled projects.” A couple makers in Norway have ideas tion from lower-producing older wells or Early last year operators squeezed about how to drastically cut the size and smaller satellite fields where the power costs by winning discounts from suppli- expense of supplying the varying power needed is measured in kilowatts (kW) is ers. Further reductions that will linger needs of subsea pumps. a problem. “Subsea variable speed drives when prices recover will require substan- “Subsea boosting is one of the simplest until now have been practically not avail- tial changes on many fronts. tools you have in your toolbox,” said able,” he said. “You can see how it is radically dif- Alexander Fuglesang, chairman and CEO Nebb’s initial offering is a 45-kW vari- ferent,” Gruehagen said describing a of Fuglesangs Subsea. “People forgot able power supply unit, and it is working design offering, “less equipment cost, subsea can be cheaper than topsides.” on one with an output of up to 5 kW. It is less installation cost, and less integra- A big reason operators are not think- also seeking support for a larger unit with tion cost.” ing that way is because of the large-sized an output in the range of 350–1500 kW, The Technip-FMC Technologies joint equipment found on the decks of pro- which could be combined with similar venture is based in London with offices duction platforms that provide variable units for a greater output. in major oil-producing regions including levels of electric power or the hydrau- While adding production with pumps one near Oslo. lic force needed to control the speed of is the current goal, long-term they see Savings are in the details. There are pumps or other motors. these units driving all sorts of motors. simplified designs significantly reduc- What is on the market now was Statoil’s goal is to make Norway a center ing the large equipment required. The described as “big dumb things” by Alex- for development of the subsea factory—

JPT • JUNE 2016 35 moving the equipment for functions such “You have to keep in mind there are no as gas compression and water separation people involved here. If you take people to the seabed, which will require a range out of the loop, you get rid of the aspect of variable power supplies. of people on the drill floor, you can do Fuglesangs’ approach to changing things fast,” he added. speeds takes the steady output of an elec- The full system is expected to save tric motor and uses a torque converter 30–40 days/year. He predicted the to alter the output as needed by a pump. USD-10-million cost of the company’s “The approach is the same as [the one] robotic team could be paid back in a year. cars use for automatic transmissions,” Those estimates are based on simu- said Ole Petter Storholt, sales engineer lations predicting the three machines for Voith Turbo, which supplies the criti- working together can steadily perform cal part allowing a low-speed motor to at a level comparable to a good human drive a high-speed pump. The power crew. The next step for the company is is transferred using magnetic coupling showing these devices can do as well with across a barrier that separates the motor actual pipe on a rig floor, beginning on a compartment from the oil and water Norwegian test rig, known as the Ullrigg. flowing from the well. The three robots in the system include The design eliminates the need for two familiar-looking units—a pipe han- seals, which would be required for a dler and a mechanical roughneck. These direct power connection, which Fugel- The design of Nebb’s 4-kW variable two resemble machines others have speed drive is based on a unit built sang said is the most common cause for for land use, then modified for subsea made to handle and assemble pipe. The pump failures. use. The hard part is managing the difference is these are electric-powered, Nebb, which has a lot of experience heat created by these electronic which allows smaller adjustments in with variable speed drives used for indus- components sealed within a water- the power and position, allowing them try, started with a variable speed electric tight case. Photo courtesy of Nebb. to be “flexible and strong and precise,” drive built for land, which it extensive- Raunholt said. ly modified to stand up to subsea use, Until now that has been a drawback The one that stands out is the drill where heat and vibration are issues. for drill floor mechanization, which floor robot, which looks like a stout, The advantage with land units is there has made things safer but slower off- headless worker. And like its human are tens of thousands of them, Risøy shore Norway. Lars Raunholt, founder counterpart, it is designed to do the wid- said. “They are well-proven. Not like and vice president of business develop- est range of jobs. Videos show it mov- subsea units for which there are small ment for Robotic Drilling said he is confi- ing up and back on its track picking up numbers with no information on the life- dent his drill floor team can speed things short sections of pipe—which in practice time failure rate.” up considerably, connecting a section of could be the subs holding logging tools in The trick is cooling a sealed unit with pipe—tripping from slips to slips—in the a bottomhole assembly. It is capable a variable frequency drive unit inside 48 seconds, compared to crews working of lifting up to 1500 kg with one claw- that is likely to fail when the tempera- offshore Norway requiring an average of like appendage that can grip and spin ture exceeds 40°C. “We must get rid of 90–120 seconds. two pipes together. When it needs to do a lot of heat. It is like an oven inside,” While drill floors now rely on machines another task, it can change tools in sec- he said. to help workers move and connect pipe, onds, Raunholt said. Nebb describes it as a passive cool- the work has been slowed by control The well plan is built into the mem- ing system. But when asked for details, systems that require step-by-step pro- ory of the robot control system. When Asmud Risøy, the company founder and cesses with constant stops, to check each a change of plan is required, it can be chief financial officer, answers simply, “It step. Work is further slowed because done by a crewmember by telling them is one of our secrets.” those machines are running alongside what to do using a command from humans, which adds safety concerns, the menu describing what needs to be Robot Drillers he said. done rather than defining how to do it Robotic Drilling Systems has created a “What we are trying to do is create step by step. team of three robots designed to replace a seamless system where the machines The drill floor robot is already on the humans on the drilling floor, and early work together and we do not have to stop Ullrigg where they hope to move all three testing shows they work well together. to check if it is in the right place” Raunholt of the rig robots by next year, with a goal Now comes the even harder part, said. “Sensors are constantly updating a of offshore use by mid-2018. proving the three smart machines can spatial awareness program controlling While the initial goal is to prove they work together as efficiently as a skilled their motions. It is a more seamless way are an efficient, reliable replacement, team of humans. than it was traditionally done.” Raunholt sees them doing more in the

36 JPT • JUNE 2016 future. The possibilities can range from using precise torque readings while connecting pipes to identify damaged threads, to handling radioactive sources. In the future, Raunholt sees an automat- ed drilling floor wired into a downhole drilling automation program to coordi- nate the work like a smoothly operating assembly line. “Its potential is not known yet,” he said. “It has done 3 out of the 100 things it can do.”

Paperwork Reduction On the list of excesses that led to the surge in offshore development costs dur- ing years when the industry was booming was a growing flood of paperwork. There was “a massive explosion of paper,” with a fourfold increase in the number of documents reviewed for a typ- The three Robotic Systems devices are shown in the testing center at the ical offshore project between 2012 and company’s facility in Stavanger. Photo courtesy of Robotic Drilling Systems. 2015, said Bente Helen Leinum, senior principal consultant subsea system oper- which has created several joint industry and risers at DNV Oil and Gas, add- ations for DNV GL. projects seeking ways to reduce subsea ing that back then there were a “lot of In an effort to eliminate that glut, the costs, is working to recruit more interna- new people in oil and gas … less experi- vessel ratings and standards-setting tional support to address what it says has enced people.” organization is working with 20 oper- been as an industrywide problem with A report is expected in June setting ators and service companies working excess documentation. out the documentation requirements offshore Norway to create a system to “The trend shows a lack of trust for a range of subsea projects, covering reduce the paperwork and reviews asso- between partners,” said Anders Husby, how they would be tracked and reviewed. ciated with subsea projects. DNV GL, head of department for well, subsea Generating multiple generations of doc- uments increases the risk of errors get- ting into the paperwork, which will not be caught by overworked reviewers. And there is the cost of the excess. “A lot less engineering hours [required for documentation and review] is defi- nitely the biggest benefit,” Leinum said. If companies followed the recommenda- tions, they could reduce the number of engineering hours required for reviews by 42%. The multiyear project concluded that some of the biggest expected savings can come from reusing documents covering similar details in past projects. It esti- mated that this could reduce the number of new documents by 75% or more. A study of three contractors from among its member companies showed a wide range in the number of documents reviewed, ranging from 47% to 65%. The Drill Floor Robot is the most flexible of the three robots, moving back The DNV report concluded that “with and forth on its track as it handles subs, which can be used to put together less reviewed documents, the more valu- bottomhole assemblies. Photo courtesy of Robotic Drilling Systems. able the review process will be.”

JPT • JUNE 2016 37 Oceaneering’s Stavanger “Mission Support Center” controls a remotely operated vehicle offshore Norway during a test in February. The operator in the foreground is controlling a tool that is cleaning marine growth off a subsea structure.

Really Remotely Controlled Underwater Vehicles

he operators for remotely operated experts to been called in on short notice Pulling these operations off requires T vehicles (ROV) will be getting more to work onshore rather than having to a degree of automation to help bridge remote in the future as land-based con- fly offshore. the lag time, known as latency, caused trol begins to become a reality. The savings would come in the form by the time needed for the signal to trav- Oceaneering has built an onshore of fewer helicopter trips, less time lost el up to a satellite and back to land- control center in Stavanger which will in transit, and fewer people to support based control center. Even with advanced be used to help control maintenance offshore, as well as reducing the safe- video and data compression, sending a work offshore this spring, said Arve ty risks and emissions associated with command takes about one-half a sec- Iversen, ROV operations manager for those flights. ond, but the large amount of information Oceaneering, during a presentation at Recently 13 passengers and crew died to transmit a high-definition view of the the recent Subsea Valley Conference in in the crash of a helicopter flying from a resulting action takes about 2 seconds, Oslo, Norway. platform offshore Norway to an island off Iversen said. The support center in Stavanger har- Bergen, an accident that investigators say “Latency is a challenge for navigator— bor allows full control of ROVs using sat- appears to be due to a mechanical failure a 2-second delay is quite a challenge,” ellite connections and a semiautomatic related to the main rotor. Iversen said. control system that gives operators the The first onshore-controlled repair job The company is using what it has ability to deliver commands—such as for Statoil will entail helping to control an learned from space operations to help stab a tool into a port—without having ROV that will be replacing anodes used for bridge these gaps. The systems that pre- to guide its every move in real time. corrosion control on an offshore jackup cisely control an ROV’s movements using “Now you can have them at the support rig. Last year, Oceaneering demonstrated constantly updated 3D grid of the area center and there is a huge saving oppor- that a land-based controller in the Gulf where it is working, was jointly devel- tunity there,” Iversen said. of Mexico could pilot a work-class ROV oped by Oceaneering ROV and Oceaneer- On complex jobs, the system, which using a satellite link. Earlier this year off- ing Space Systems, he said. has been named the Remote Piloting shore Norway, a controller in Oceaneer- Over time Oceaneering will be work- and Automated Control Technology, is ing’s Mission Support Center in Stavanger ing to make the system more capable aimed at reducing the number of people used a multipurpose tool to clean marine and reliable, employ faster communi- who will need to be offshore, and allows growth off a subsea structure. cation links, reduce the risk of break-

38 JPT • JUNE 2016 downs with redundant links, recognize During a presentation at the confer- In order to reduce those costs, Idiap and address the communication prob- ence, one skeptical questioner pointed Research is working to create “more lems among widely separated teams, and out that any savings from land-based cost- and time-efficient ROV opera- keep up with the ever-changing cyber control would look small if a job was tions, where manned support is to a threats by hackers. botched due to problems associated with large extent delocalized onshore … at a While a video from the service com- distant control. Iversen responded that land-based ROV control center,” it said pany showed a person onshore control- the offshore control room will still be on its website. ling ROV work offshore, where the con- manned when work is in progress, but When another large ROV maker, FMC trol chair in an ROV-handling vessel was an onshore station could step in during Technologies, was asked about dis- empty, that is not a good representation shifts when little is going on. tant control, it said it has included “the of how this will be normally used in the Another questioner from an oil and framework for distance independent near term. gas company saw it as a positive for those control and monitoring in its ROVs for a While a land-based controller can pro- observing work for operators, because number of years.” vide time for a worker offshore to take a they will be able to monitor and interact “We are very encouraged to see a break during a slow period, Oceaneering with the ROV control crews at multiple major user like Oceaneering beginning is hoping to reduce the number of people locations without having to take a heli- to explore this area as well. It is at this required at the job site by linking in peo- copter trip. time a very interesting story, however ple onshore, or on other offshore com- Others developing ROV technology an incomplete one,” said Tyler Schilling, mand centers. are working on combining robotics and president at FMC Technologies Schil- “We will be using this today as a sup- distant control capabilities to reduce ling Robotics. “The value proposition port function,” he said. In a complex job, crews offshore. One such project by the is still not clear. Ultimately for these as many as six people may be required for Idiap Research Institute in Switzerland types of techniques to demonstrate ROV control covering several shifts. Some is focused on reducing offshore crews, value they need to lower the cost of of those are needed for only a few hours, which often require three professionals operating the ROV, improve the produc- but must remain offshore long afterward per shift, with enough workers on hand tivity of the system the ROV supports, waiting for a helicopter to take them back. for round-the-clock staffing. or both.” JPT

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JPT • JUNE 2016 39 Brings Large Potential Joel Parshall, JPT Features Editor

he re-emergence of Iran as a full player in the global oil restrictions on Iran’s central bank, Iranian imports, and the Tand gas market is a major development and would be so country’s access to international shipping insurance. under any market conditions. In the current environ- ment, the collapse of oil prices accentuates concern over mar- Dramatic Impact ket stability, the prospects for price recovery, and the implica- As the sanctions took hold, Iran’s production of crude oil and tions of both issues for the global financial system. While the noncrude liquids fell from 4.4 million B/D in 2011 to an aver- concerns are justified, the most important global dimensions age of 3.6 million B/D over the next 3 years. Crude oil pro- of Iran’s return to the market have to do with the country’s duction, which excludes noncrude liquids, fell from a pre- long-term oil and gas potential. vious 3.7 million B/D to an average of 2.8 million B/D under The recently implemented Joint Comprehensive Plan of the sanctions. Crude oil exports were cut in half, falling from Action (JCPOA)* lifts nuclear-related sanctions against Iran 2.2 million B/D to 1.1 million B/D. Many oil fields and wells to restore the country’s access to world oil and gas mar- had to be shut in. Development projects were halted or seri- kets and its freedom to seek international investment in ously delayed, and the financial consequences of the restric- its industry. tions that stemmed from the sanctions cascaded through the Imposed in December 2011 and the first half of 2012 in con- Iranian economy. nection with Iranian nuclear activity, the sanctions placed The effects on Iran’s natural gas industry were not as great, as the country has been a limited gas exporter. Some proj- ect development activities were slowed or stalled by the sanctions. However, the National Iranian Oil Company (NIOC) Apart from the JCPOA, United States sanctions related to brought five new phases of the offshore South Pars gas field global terrorism and human rights issues remain in effect on stream over the past 2 years without help from foreign on Iran. International companies and banks are likely to companies. South Pars in the Persian Gulf is the world’s larg- be cautious about entering the Iranian market. However, est gas field, and the new phases are expected to increase notwithstanding some reticence among potential investors, domestic gas supplies by about 40%. Falakshahi said, “We expect Iran to reach its presanctions On the oil side, Iran could realistically add 500,000 B/D levels of production by the second half of 2017.” of production to global markets this year, according Iran has made conflicting statements about the desirabil- to Homayoun Falakshahi, Middle East and North Africa ity of achieving a near-term production freeze among OPEC upstream research analyst at Wood Mackenzie. and non-OPEC oil producers as a first step toward stabi- lizing the global market. However, the country chose not No Bottlenecks to participate with other producers in the mid-April meet- “There are no major bottlenecks to ramp up production at ing in Doha to negotiate a freeze agreement, and Iran’s the Iranian oil fields, so the pace at which production will absence was cited by Saudi Arabia as a reason for refus- increase really depends on how quickly crude oil sales will ing to move toward a freeze. Iran has repeatedly stated pick up,” Falakshahi said. that it will not freeze its production at a level below its pre- sanctions output.

*Agreed to by China, France, Germany, Russia, the United Kingdom, the United States, the European Union, and Iran.

A view of the Tehran skyline topped by the Milad Tower, the world's sixth tallest telecommunications tower. A processing unit at Asalouyeh Seaport on the Persian Gulf handles production from Iran’s South Pars gas project, the world’s largest gas field. Photo courtesy of Reuters.

A Conservative Outlook and 2019, with rig and crew services major international service companies. In a conservative outlook for Iranian pro- being the major driver. In onshore opera- With these companies free to resume duction and drilling activity, research- tions, spending on coiled tubing services Iranian activity, DW anticipates that the er Katy Smith of Douglas-Westwood is expected to show the strongest growth, market for LWD and MWD services will (DW) forecasts that Iranian oil pro- while in offshore operations, expendi- become more competitive. duction will increase to approximately tures on directional drilling services, 4.2 million B/D by 2021, of which slightly drilling fluids, and drill bits are forecast Iran Petroleum Contract more than 3 million B/D will come from to increase significantly. Iran is revising its contracting approach onshore fields. Gas production is expect- The sanctions had a substantial effect from a buyback system to a service- ed to reach almost 6 million BOE/D by on Iran’s access to logging-while-drilling agreement model called the Iran Petro- 2021, of which almost 4 million BOE/D (LWD) and measurement-while-drilling leum Contract (IPC), with features of a will come from offshore sources. Fur- (MWD) services, for which the support- production-sharing contract and incentive ther development of the South Pars field ing technology depended strongly on the for using the most advanced technologies. will make a major contribution to the increase in offshore gas production. Onshore DW expects the number of Iranian offshore oil and gas development wells, 10 Offshore excluding appraisal and exploration wells, to increase at a 6% compound 8 annual growth rate (CAGR) between 2015 6 and 2021. Over the next 4 years, DW forecasts the 4 number of active drilling rigs to increase from 73 to 91 onshore and to more than Production (million BOE/D) 2 double to 30 rigs offshore. In the services sector, DW expects 0 onshore and offshore spending on 2005 2007 2009 2011 2013 2015 2017 2019 2021 Iranian projects to grow at CAGRs of Total Iranian Hydrocarbons Production 2005–2021 10% and 8%, respectively, between 2015 Source: Douglas-Westwood’s Iran Oil & Gas Market Forecast 2015–2019.

42 JPT • JUNE 2016 For exploration, the IPC will enable is the world’s third largest producer with ing partner at NAFT Energy, in an online discoveries to move automatically to a 2015 marketed output of 16.8 Bcf/D article for www.spe.org in December. the development phase, instead of hav- and a gross output of 24.3 Bcf/D, which “One cannot afford to show up right at ing companies renegotiate terms from includes flared and vented volumes and the opening, purchase the bid packages, scratch as required under the buy- the substantial amount of gas that is bid, and hope for the best. back contracts. “If exploration is not reinjected into reservoirs to maintain oil “Understanding the business culture, successful, companies may be offered production. On a net basis, Iran uses along with learning and appreciating acreage nearby to continue exploring,” all of its produced gas internally, with local values, could be a good starting Falakshahi said. exported quantities offset by imports point. Companies need to know NIOC The NIOC has listed 49 oil and gas driven by logistical needs. and learn their concerns, objectives, developments for securing possible for- Eventually, Iran could play a much and goals. Planning and developing an eign investment. The short-term focus is larger role in the global gas market. engagement strategy is vital.” on 29 projects, with a priority on fields With sufficient international investment, shared with neighboring countries. Much the country could be able to boost pro- Political, Economic Risks of the potential lies in gas projects, par- duction by about 12.5 Bcf/D after 2025, Despite the removal of nuclear-related ticularly a handful of offshore develop- Falakshahi said. Most of the increase sanctions, significant political and eco- ments such as North Pars and Kish. would be marketed gas, although a por- nomic risks remain for foreign com- The projects typically have low pre- tion might be used for reinjection. How- panies planning to enter the Iranian tax development costs, some as low as ever, a currently glutted market, with upstream business. Among them are the USD 5 to USD 15 per bbl of oil, according new Australian and US liquefied natural continuing US sanctions regarding ter- to Falakshahi. However, some projects gas exports adding to supply, constrains rorism and human rights concerns and are technically challenging and will be Iran’s near-term ability to increase pro- the possibility that the multinational costlier to develop, such as the deepwater duction for export purposes. nuclear sanctions will be reinstated if Sardar-e-Jangal field in the Caspian Sea Iran violates the terms of the JCPOA. and the Golshan and Ferdowsi heavy oil Foreign Investment is Key Iranian tensions with Saudi Arabia fields in the Persian Gulf. In both oil and gas, the key to Iran’s and Israel pose some risk. Higher costs resurgence and expansion is how much of capital and insurance, Iran’s double- Ambitious Plans foreign investment it can secure. “The digit inflation, and the country’s dual Iranian plans for the upstream sector are capital investment needs are huge, exchange-rate regimen could also dis- ambitious. Through the IPC structure, the more than USD 200 billion worth in the courage investors. country is hoping to attract USD 180 bil- next 15 years for all oil and gas fields,” Nonetheless, the economics of Iranian lion in international investment to boost Falakshahi said. “The NIOC also needs to projects could make them attractive. crude oil production by 1 million B/D bring in the latest technologies to make The capital intensity of onshore green- through the projects included in its 2016 the most of its older fields. The recovery field projects developed in Iran between licensing round and ultimately raise pro- rates in Iran’s oil fields are much lower 1995 and 2005 ranged from roughly duction to 5.7 million B/D by 2020 . than elsewhere in the region because of USD 10,000 to USD 15,000 per flow- That may be overly optimistic. Accord- the lack of technology. ing bbl and translates, when adjusted ing to Falakshahi, if Iran is successful “The NIOC has a good knowledge for inflation, to about one-third the level in attracting the needed foreign invest- of its fields but typically lacks skills in found in recent North American uncon- ment, crude oil production in a best case improved oil recovery and enhanced ventional field developments, according could grow to 4.5 million B/D to 5 mil- oil recovery and in dealing with very to Nejad. “Iran’s low-cost barrels may lion B/D by 2025. Under ideal circum- sour gas. The challenges are as big as offer relief to the current low-price envi- stances, production could be sustained the potential.” ronment for those who dare the above- at that level for about a decade. With the Much will depend on the details of surface risks of the country,” he said. addition of condensate output, produc- the IPC implementation and Iran’s will- And finally, the resource potential of tion possibly could reach 6 million B/D. ingness to improve transparency. With- Iran may be more than what most peo- In a worst case, with little new for- out the latter step, “a lot of internation- ple have considered. “As strange as it eign investment coming in, any produc- al oil companies will just turn away,” might seem, the majority of the country tion increases from new developments, Falakshahi said. remains vastly unexplored,” Falakshahi such as Azadegan and Yadaravan along As companies approach the 2016 said. “The Zagros fold belt, which gath- the Iraq border, will be offset by declines licensing round (which will likely involve ers more than 95% of Iran’s oil and gas from other large fields. Crude oil output a tendering process), they must recog- fields, is a mature region. But other parts, would then stagnate at about 3.8 mil- nize how it differs from “bidding for such Iran’s share of the Caspian Sea, are lion B/D, Falakshahi said. a license in the Norwegian Continental almost frontier regions. The potential In natural gas, Iran has the world’s sec- Shelf or [the] Gulf of Mexico,” said Syd could be very big. Shale exploration is ond largest reserves behind Russia and Nejad, chief executive officer and manag- also in a very early process.” JPT

JPT • JUNE 2016 43 Datuk N. Rajendran, deputy chief executive officer at the Malaysian Investment Development Authority, talks about what Malaysia needs to do to prepare for an industry turnaround at a session dedicated to the country at OTC Asia.

OTC Asia Sessions Discuss Region’s Role in Price Downturn, Recovery

Stephen Whitfield, Staff Writer

s the oil and gas industry weath- While the Chinese market is still in rich gas area, and hopefully some of our ers a transitional phase brought a nascent developmental stage, Zhang successful projects will push shale.” Aon by a drop in oil prices, bur- Xiaofeng said the CNPC is optimistic China’s focus on shale gas has been geoning markets in Southeast Asia about its progress in developing specif- driven in large part by its inability to stand poised to establish themselves ic types of reservoirs. Zhang, a project develop its coalbed methane (CBM) as legitimate players in the future. manager at CNPC, cited volcanic reser- resources. The country’s total resource Attendees of the recent Offshore Tech- voirs as a particular source of optimism. of CBM is approximately 36.8 Tcm, but nology Conference Asia in Kuala Lum- China has one of the largest collections the coal depositional structure in China pur saw the myriad ways in which the of proven volcanic reserves in the world; is too complex for the existing techno- region’s potential could make it into an 900 billion m3 of the country’s 3 tril- logical infrastructure to exploit. Over- industry stronghold. lion m3 (Tcm) total proven reserves is in coming this complexity will be critical In a series of sessions devoted to volcanic reservoirs. for the country in the near future. Zhang individual countries in the Asia Pacif- However, Zhang said there are some said there is, at present, no large-scale ic region, representatives from national technical difficulties CNPC faces in commercial production of CBM in China. oil companies, multinational operators, actualizing these resources. He said Xiangyu Wang, a professor of con- and service companies presented their the company must improve its reser- struction management at Curtin Uni- thoughts on the roles they will play in the voir prediction techniques, as well as its versity and the moderator of the ses- overall development of the region and crack detection. sion, said renewables should play a larger the global oil market. Zhang was equally optimistic about role in China’s energy policy, even as shale gas prospects in China, but opera- the country continues to develop its oil China tional costs must continue to decline in and gas economy. Coal made up 65.7% Panel speakers at the China country ses- order for the country to increase devel- of China’s total energy consumption in sion described a country flush with natu- opment of the resource. CNPC estimated 2013, compared with 18.9% for oil and ral resources but unable to exploit them that in 2015, the cost of drilling a horizon- 5.5% for gas. to the fullest extent. Led by its national tal well in shale formations in the Sichuan Wang said China has relatively abun- oil company, the China National Petro- Basin ranged between USD 11.3 million dant wind energy resources because of leum Corporation (CNPC), the coun- and USD 12.9 million per well, represent- its monsoon climate and its long coast- try is eager to acquire the tools needed ing a 23% cost reduction from 2013. line. He identified the southeastern coast to increase production from its oil and “Of course, shale gas is an important and the provinces of Shandong, Jiansu, gas reserves. resource for China,” Zhang said. “It is a Zhejiang, Fujian, Guandong, Guangxi,

44 JPT • JUNE 2016 and Hainan as areas with great potential said that operators’ cost-cutting efforts Datuk Rajendran, deputy chief execu- to develop offshore wind power. focused primarily on concept design tive officer at the Malaysian Investment However, Wang did not identify exactly optimization and selection, but not in Development Authority and modera- which strategies the Chinese government the fabrication of platforms. Despite that tor of the session, said Malaysian com- was prepared to enact to help extract focus, Woo-Seung Sim, research director panies must consolidate into “formida- more renewables. at HHI, and Joongnan Lee, senior manag- ble and competitive” entities capable of “I think, probably, [China] will rely er at SHI, agreed that South Korea bears handling the eventual turnaround in oil on more renewable energies,” he said. some responsibility in assisting opera- prices. Rajendran also said that an over- “I think the Chinese government will be tors to lower their expenditures. ly competitive market may have nega- quite ambitious in going to the coasts to Lee mentioned SHI’s Research Insti- tive consequences on local industry in get these resources.” tute as an entity devoted to increasing the future. Zhang said the Chinese government cost efficiency for projects. Founded in Adif Zulkifli, senior vice president of has always encouraged and actively 2014, the institute spearheads initiatives corporate strategy at Petronas, echoed sought foreign investment to help fur- that help add value to offshore projects similar sentiments. Prior to the down- ther development in the country’s oil and and plant technologies, while also devel- turn, he said the country saw an influx of gas infrastructure. Hao Yunxing, director oping specialized functions to enhance companies with little history in oil and of the Qingdao WELL Ocean Science and their technological competitiveness. gas operations enter the market. This led Technology Association, said his orga- Sim said there are two additional ways to an increase in inefficient operations, nization has visited more than 30 coun- fabricators can help beyond research which then resulted in what he called an tries in the past 3 years to encourage and development. One way is through “uncontrollable” escalation in produc- investment. It also co-hosted the Interna- increased collaboration with engineering tion costs. At present, he said approxi- tional Ocean Technology Conference and companies to develop cost-effective top- mately 3,600 service providers were reg- Exposition last year in Qingdao with the side designs. Another is through a great- istered with Petronas. goal of exchanging ideas between Chi- er push for standardized designs and Zulkifli said the market forces pres- nese agencies, service companies, and construction processes, which he said ent in the current oil price downturn will the global academic community. could help shorten construction sched- lead to a necessary shake-up in the Malay- “China’s engineering, technology, and ules and save money. sian sector, where only experienced com- equipment areas are developing a little Sim said shortened construction panies willing to adapt to changing cir- bit late, but now we are cooperating with schedules should not affect the quality cumstances in the long term will be active. other countries and we will work togeth- of the facilities being built at the fabrica- “The oil and gas services and equip- er, so we can potentially have a very big tion yards. ment players need to be more competi- market in China. If we cooperate with “I think we can keep to a [shorter] tive, more efficient, and self-sustaining, advanced technology companies, we will schedule and maintain value for all proj- and offer varied services. Let’s not forget, achieve a lot. We are building a platform ects. It is the first thing I think HHI can too, to step back and rethink technol- for the international technology com- do for the industry. As you know, nor- ogy, where we can drive down costs fur- munity and scientific communication in mally offshore project budgets have kept ther and improve efficiency, innovation, order to build international confidence increasing, so I think if we can plan now as well as oil and gas industry coopera- and expand together,” Hao said through and push for standards, I think costs can tion,” he said. an interpreter. be reduced as part of the whole project,” Zulkifli highlighted Petronas’ work he said. with the Cost Reduction Alliance 2.0 in South Korea Lee said standardized processes could helping reduce inefficiencies and lower The South Korea country session help in the long term, but fabricators costs in the Malaysian market. Launched touched on the country’s expansive fab- would have to reconcile the short-term last year, the program is a collabora- rication facilities, and the role its three spend required to conform their assem- tion between Petronas, contractors, major fabricators—Samsung Heavy bly equipment to a common specifica- and service companies seeking to opti- Industries (SHI), Hyundai Heavy Indus- tion, as well as the effort needed to opti- mize costs, improve efficiencies, and tries (HHI), and Daewoo Shipbuilding mize production and automation. increase productivity in the Malaysian and Marine Engineering—will play in upstream business. helping the industry weather the oil Malaysia To achieve these goals, Petronas estab- price downturn. Panelists at the Malaysia country session lished the following initiatives for other Cost reduction for offshore projects described the host country as one on the companies to follow: was at the forefront of discussion for the verge of leading the Asia Pacific region, Q Greater emphasis on low-cost panel speakers. Yonghwan Kim, chair of with multinational operators and service drilling the department of naval architecture and companies making necessary infrastruc- Q Reduction of surplus material ocean engineering at Seoul National Uni- tural improvements to handle an increas- through improved planning and versity and moderator of the session, ing project workload. inventory management

JPT • JUNE 2016 45 SPE Bookstore Q Renegotiation of contracts for “If you want to enhance the efficiency exploration and production (E&P) of our tools, the turnaround, and look activities at reducing our Capex, we cannot accept Q Joint sourcing of services and a situation where our operators need materials to have a backup tool,” Razouqi said. Q The development of a standardized “We want to be in a position where we design for platform types, systems, can showcase our ability to do things equipment, and components right the first time so no one will have Q Common planning and scheduling to have a backup tool that you have of logistics to pay for.” Q The consolidation and Like Schlumberger, FMC Technologies centralization of warehouses has also committed to Malaysia as a cen- Q Operating expenses and capital tral player for its activities in the Asia expenditure (Capex) benchmarking Pacific region. Douglas Bruce Moody, Q Late-field optimization general manager and senior vice pres- As of March, Petronas has saved ident of subsea systems at FMC, said MYR 2.4 billion under the program. the company has ramped up its infra- Zulkifli said the company expects to save structure in the country over the past 10 MYR 4.9 billion in 2016. years. The company’s headquarters in Maen Razouqi, vice president and gen- Kuala Lumpur houses its engineering and eral manager at Schlumberger Malaysia, deepwater project teams, and it opened

NEW! Print and Digital Versions Available said efficiency must become a primary two plants in Johor Bahru to expand its focus for Malaysian companies moving manufacturing capabilities. Acid Stimulation forward. He said operators and service Moody said FMC is committed to companies are too willing to accept high developing a strong Malaysian work- Syed A. Ali, Leonard Kalfayan, rates of nonproductive time (NPT) on force, primarily by increasing its annu- and Carl Montgomery upstream E&P projects, and that willing- al spend with Malaysian suppliers and Stimulation of oil, gas, and injection wells ness could lead to unnecessary financial training local staff. He said that approxi- with acid is almost as old as the petroleum losses. These companies need to place mately 10% of FMC’s staff in Malaysia is engineering industry itself. But, the science and a greater emphasis on eliminating NPT. contracted from outside of the country, technology of acidizing has undergone striking “Is it easy to eliminate NPT? No. But and that the company hopes to lower that changes in recent years. Acid Stimulation, ensures a comprehensive and up-to-the-minute I think what we want to do, jointly with percentage in the coming years. presentation of the development of acidizing operators and with our partners, is to “This is a very important part of what technology. This book delivers an authoritative find out elements to reduce that because we do globally, getting good local sup- presentation of the key areas of Acid Stimulation, that’s what’s going to bring the efficiency, pliers and developing an ecosystem,” providing an important resource for anyone and the costs down,” Razouqi said. Moody said. “We localize everywhere who designs, analyzes, and/or improves acidizing treatments. He said Schlumberger’s average NPT we go. The majority of our work staff rate in Malaysian operations over the is Malaysian. Through our core values, Contents past few years is between 8% and 9%. we’ve developed these people to be ready Formation Damage The company’s goal is to reduce that fig- for the oil and gas industry.” Acidizing Chemistry ure to less than 1% by 2020. Last year, One of FMC’s goals in the region is to Carbonate Acidizing it spent approximately MYR 50 million publish standard specifications of equip- Sandstone Acidizing Acid Placement & Diversion on its Malaysian infrastructure and an ment components for operators to use Treatment Evaluation & Real-Time Diagnosis additional MYR 200 million on contracts throughout the region. Moody said stan- Acid Fracturing with third-party suppliers. dardization will help improve efficien- Additives for Acidizing Fluids: In addition, Schlumberger established cy in its operations, as it will not have Their Functions, Interactions, & Limitations the Wireline Center for Reliability and to design customized equipment for Acid Corrosion & Its Control Economics of Matrix Stimulation Efficiency in Port Klang to maintain log- every project. Acidizing Safety & Quality & the Environment ging tools and prepare them for distribu- “If you take the standard, not only is tion to its operations in Malaysia, Thai- your cost much lower, but your lead time Preview sample pages from this new book and land, and Vietnam. The center is another is much lower and, most significantly for order your own copy by visiting our bookstore example of consolidation in the region: the subsea industry, the deviation from at www.spe.org/go/books. By placing its sourcing decisions to a cen- your delivery time is much more concise. tral location, Razouqi said Schlumberger We can be much more predictable as an has seen greater efficiency in operations industry, and cut down the nonproduc- and a reduction in Capex. tive time,” Moody said. JPT

JPT • JUNE 2016 MANAGEMENT

Energizing Worldwide Oil and Gas Deepwater Developments

Martijn Dekker, Shell Oil; Mike McEvilly, Hess Corporation; Mike Beattie, Anadarko; Bruce Laws, Maersk Oil Houston; Deanna Goodwin, Technip; and Sandeep Khurana, Granherne-KBR

The precipitous drop in oil prices is put- explored scenarios on how deepwater US Gulf of Mexico (GOM) to USD 75/bbl ting higher-cost plays such as deepwater breakeven prices can be brought down in West Africa, 2-3 times the costs in the under the microscope. Key questions significantly. previous decade. This was due primarily include: How will the industry energize to three factors: increased geologic com- deepwater developments to close the The Past and Present plexity (for example, the Paleogene in gap between cost and current commod- In the run-up to the oil price drop in late the GOM, and the pre-salt in Brazil and ity prices? What oil price is required to 2014, deepwater had spectacular invest- Angola), increased government take and keep deepwater viable over the long term? ment and production growth. However, local content requirements, and project These topics will undoubtedly be at the even then there were signs of increasing- cost escalations beyond supplier mar- top of the mind for oil company execu- ly challenging project economics. Glob- gin/commodity costs (such as increased tives over the months to come, and were al deepwater investment increased from design complexity.) the focus of a panel discussion at the USD 16 billion in 2003 to more than In today’s “lower-for-longer” price Offshore Technology Conference (OTC) USD 70 billion in 2013 with production environment, deepwater greenfield proj- conference titled “Energizing Worldwide more than doubling in that time period to ect economics are challenged, yielding Oil and Gas Developments.” Also partici- almost 6 million B/D, or 7% of the world’s dramatic cuts in investment. As of early pating was Kassia Yanosek of McKinsey total oil supply. However, toward the end 2016, approximately 35 billion BOE or & Company, which provided break-even of this period, there were buildups in approximately 6 million BOEPD of deep- cost analyses and historical data on deep- costs and cycle times. In the USD 100/bbl water reserves and production, respec- water developments. price environment of 2012–2013, deep- tively, has been deferred. The good By reflecting on the past and looking water breakeven costs for green field news is that in today’s price environ- at the current situation, the panelists projects ranged from USD 70/bbl in the ment, project costs have been reduced across the board, primarily driven by supply chain margin compression. In Other liquids and NGLs Sanctioned Slow Recovery 2030 Production, million B/D Not sanctioned Producing regions with competitive supply chains,

Mature field Potential such as the GOM, breakeven costs for decline offshore growth greenfield developments have decreased

Global demand 17 106 20% on average to USD 50–60/bbl and outlook range 2030 ultradeepwater rig day rates have fallen 95 –34 +11% 40% from the first quarter of 2014 to the 8 2 1177 first quarter of 2016.

61 Scenario for the Future LTO growth Despite the current pullback, a poten- 61 tial long-term supply scenario indicates that offshore production could account LTO—Light tight oil for up to 50% of new supply require- ments in 2025 to make up for mature 2015 Decline in 2030 New New New oil New 2030 Total producing Production onshore shale/tight sands/ offshore Total asset decline curves and the decreasing global assets from extra global likelihood of oil sands as a competitive production existing fields heavy production source of supply. In a scenario where Source: McKinsey Energy Insights; Rystad Energy global 2030 demand reaches approxi- Fig. 1—Sources of future production. Despite potential scenarios for growth, mately 106 million B/D, new offshore activity reductions and questionable economics put into question the role that production may need to reach approxi- deep water will play. mately 17 million B/D to close the pro-

JPT • JUNE 2016 47 USD/BOE USD 70/bbl in 2030 Scenario form designs, and can be implemented

70 more broadly across the industry. Similar –20% –35% techniques can be applied to many other What is not included: areas of the supply chain. Dev. Drilling 26 50–60 ▪ Technology The supply chain efficiencies and com- –24% break- 40–50 throughs mon standard project design solutions are 19 –25% Facilities 5 –32% ▪ Changes to great opportunities when applied on an –23% 15 government Equipment 4 individual company level. However, inno- –32% take 7 3 –10% Subsea –26% 3 2 ▪ Efficiencies vations and deeper collaborations across 5 –18% 3 Opex 8 0% 4 from industry players are required to signifi- 8 –27% 6 industry-level collaboration cantly transform the deepwater project Government 21 –20% 0% cost structure. One example is to further take 17 17 reduce project complexity and capital costs through industry-level agreements 2014 costs Near-term realized costs Realistic potential costs that harmonize equipment specifications Source: McKinsey Energy Insights and standard development solutions. Fig. 2—The projected average Gulf of Mexico greenfield deepwater costs in At the field and basin levels, oper- 2030 have the potential to drop 35–40% from 2014 levels. ators can further improve cost struc- tures through commercial innovations. jected supply/demand gap as depicted Typical examples include the optimiza- This could take the form of the financ- in Fig. 1. This scenario assumes that oil tion of offshore logistics; standardizing ing of topside and subsea hubs through prices recover to USD 60–70/bbl in 2018, and simplifying specifications for scope, a third party; sharing services with other OPEC market share remains constant, material, and equipment at the opera- industry participants, such as through and unconventionals outside of North tor and contractor level; and strategic rig pools; and development phasing America grow at a slow pace. Growth in vendor relationships. The largest oppor- or increasing the reserve size with co- any of these other resource types would tunity for operators may be to rigor- developments and partnerships. Exam- potentially reduce the call for deepwater. ously drive down scope to a minimal ples of the latter are Anadarko’s Inde- For this deepwater supply growth to level to meet functional requirements pendence Hub project, BP and Chevron’s be achievable, it is essential to improve and regulations. coinvestment in western GOM proper- deepwater competitiveness not only in There is substantial potential for ties (Keathley Canyon), and LLOG’s Delta the USD 50–70/bbl world but also in a additional cost savings through com- House co-development project. scenario in which sub-USD 50/bbl prices mon design innovations at the project persist. McKinsey developed a “realistic level. The standardization of equipment, Supplier Alliances and New potential” (i.e., assuming current best- design, and installation will improve Contractor Offerings in-class practices) breakeven economics project economics through enhanced One of the most effective themes to case for an average project in the GOM, delivery schedules, reduction in engi- enhance project performance and reduce finding that cost reductions through best- neering, manufacturing and installation cost is early engagement with the engi- in-class practices across a range of levers costs, and reduction of risk in the project neering, procurement, construction, and could reduce costs to USD 40–50/bbl execution. These improvements can be installation (EPCI) contractor, paired (Fig. 2). Some of the themes of oppor- at the equipment level such as the gains with continuity and consistency of proj- tunities that are within industry control from using a standard subsea tree design ect management personnel, which pro- include supply chain efficiencies, com- or at the full platform design. For exam- vides the best opportunity for execution mon standard project design solutions, ple, Anadarko utilized a “design one, excellence. Gaps in project planning and innovations in field developments, and build two” philosophy for the Lucius and front-end engineering design typically supply chain alliances. Heidelberg projects in the GOM. The ben- result in costly change to the overall proj- efits for the project development cycle ect later. Supply Chain Efficiencies can come from a streamlined specifica- The key to success at the early engage- When oil prices were around USD 100/bbl, tion/tendering/evaluation process, lim- ment stage and throughout the execution the industry was already starting to ited delays due to unknown unknowns, process is trust built in the context of address capital efficiency by looking at and avoiding trouble time. a true operator/contractor partnership. opportunities to transform the supply The deepwater industry can make Building this trust often works best in a chain. With the drop in oil prices, this great strides in reducing development small, integrated team over a number of work has been accelerated. Key cost- costs through a strategy of standard- months and years, and requires commit- saving opportunities include demand ization. Standardization has been suc- ment to the relationship. The historical management of services, standardization cessfully demonstrated in subsea and contractual relationships, particularly in of equipment, and price management. topsides equipment as well as full plat- the GOM, have typically been tactical—

48 JPT • JUNE 2016 based on a work-package-by-work-pack- age basis with reimbursable or lump- DG0 DG1 DG2 DG3 sum contracts. In many cases, operator companies have not opened the door for early engagement with contractors until later in the process (e.g., Decision Gate 3 in Fig. 3). By this time, effective- ly 90% of the cost has been determined with savings opportunities potentially left unidentified.

Working together during the field Savings Potential development design process offers prov- en benefits for both the operator and the contractor. In recent years, con- tracting has in some cases evolved into frame agreements and project manage- Time After Start of Concept Definition ment contracts, targeting reduced cost DG—decision gate Source: Forsys Subsea (an FMC Technologies through increased collaboration. Frame and Technip company) agreements establish common protocols and standards—such as commercial base Fig. 3—The value of early contractor involvement includes the ability to rates and the contractual frame work— rationalize the overall field layout and to drive standards, project development, that operators can use on future projects and integration of technology. with a preapproved set of potential con- tractors. These contracting models cou- With competitive advantage in deep- ther enhanced by developing a tech- pled with advanced design approaches water originally based on mastering the nology tailored to that geology/geogra- can open the door to streamlining the technology related to water depth, deep- phy that drives down development costs design process while at the same time water has matured considerably since even further. reducing risk. the industry stepped into water depths of Optimizing costs through the supply New alliances and partnership mod- more than 1,000 ft in the 1980s. There- chain and development scope will only els under way in the industry have the fore it would be appropriate to reassess get companies so far in closing the gap potential to improve cost savings and what drives competitive advantage between today’s cost structure and what project performance even further. Stra- in deepwater. is required to re-energize deepwater tegic alliances between EPCI and equip- Admittedly, deepwater is still one of in today’s oil price environment. New ment companies, such as OneSubsea the most technology-intensive oil and strategies and approaches are required, (Schlumberger, Cameron, and Subsea 7) gas plays. However, for water depths of in addition to a minimum-level crude or the alliance between FMC Technolo- less than 7,000 ft, and pressure and tem- oil price. gies and Technip, have formed recently perature under 15,000 psi and 300°F, to better address operator challenges respectively, hardware technology is Summary and reduce costs with the aim to drive becoming more commoditized. Gaining A subset of ideas and concepts highlight- greater value in project delivery. For a competitive edge today may require a ed in this article are being tested and example, by rationalizing and simplify- focused strategy more related to world- implemented across the industry to some ing the overall field layout and integrat- class exploration success, efficiencies extent. However, more is required to ing subsea umbilicals, risers, flowlines, in deploying the deepwater technology, accelerate the competitiveness of deep- and subsea production and process- or optimization of the recovery from water in the global energy mix. In addi- ing systems, costs can be dramatically deepwater reservoirs. Such strategies tion to addressing value levers that are reduced by eliminating redundant sub- could entail a geography focus (e.g., within companies’ control, step changes sea hardware, optimizing and derisk- GOM), geology focus (e.g., Atlantic con- in technology innovation and improve- ing the offshore construction campaign, jugate margin pre-salt plays), life cycle ments in the fiscal and regulatory envi- integrating across all infrastructures, focus (e.g., explore and sell), or tech- ronment are necessary to achieve trans- and streamlining project teams. nology focus (e.g., technology-enabled formative economics. JPT improved productivity). New Strategies Combining these strategies may make Today’s price environment also provides them more impactful by building on This article builds on OTC 27317 prepared for presentation at the 2016 an opportunity for changes in how inter- each other. For example, a strategy com- Offshore Technology Conference in national oil companies and suppliers bining a focus on a particular geologic Houston. The full-length paper can be think about their deepwater strategies. play in one or two basins can be fur- found at www.onepetro.org.

JPT • JUNE 2016 49 TECHNOLOGY FOCUS

Coiled Tubing Applications Alex Crabtree, SPE, Senior Adviser, Hess

Another tough year has passed since the The next 12 months of steel materials for coiled-tubing well- last coiled-tubing feature in JPT. In spite intervention operations continues to of the difficult economic climate, the SPE/ could bring upturns and grow. This performance envelope is being ICoTA Coiled Tubing and Well Interven- downturns and greater or examined in terms of both the mechani- tion Conference and Exhibition moved lesser volatility. Whatever cal (e.g., abrasion and fatigue) and the to a new venue this year, the George R. environmental (e.g., sour-well environ- Brown Convention Center in Houston, may happen, the coiled- ments). For example, renewed studies because of the continued growth of the tubing industry’s record last are being conducted on the combina- exhibition in prior years. Attendance was tion of high-cycle elastic and low-cycle down by only a small percentage, which, year indicates that it will plastic fatigue, which currently has rel- I hope, is an encouraging sign. still be moving forward. evance to subsea work. Formerly, such As mentioned in last year’s feature, the studies were limited to the use of coiled coiled-tubing industry is adapting to the tubing as a pump string. Additionally, changing environment. Several papers at as a downline for pumping fluids from a established knowledge of solids trans- this year’s conference discussed various vessel to a subsea tree or pipeline. While port in high-angle wells, from both field aspects of subsea work performed with this is not new to the coiled-tubing indus- experience and laboratory work, is being coiled tubing. Two papers presented dif- try, tooling and vessel-based-equipment applied more widely to reduce costs ferent methods to use coiled tubing to improvements have been developed to through increased efficiency. This has enter or drill wellbores by using either an make operations safer and more ver- been a long implementation curve for the injector or a snubbing jack at the seabed satile. Also in this arena, new thermo- coiled-tubing industry. and a secondary coiled-tubing injector at plastic composite materials are being The next 12 months could bring the surface. In both methods, the coiled introduced to the market and may bring upturns and downturns and greater or tubing runs freely through the water— further enhancements. These types of lesser volatility. Whatever may happen, that is, the coiled tubing is not contained developments require considerable the coiled-tubing industry’s record last within a secondary riser pipe—and, investment on behalf of the companies year indicates that it will still be mov- hence, many in the industry are referring involved and tend to signal confidence in ing forward. JPT to this new technique as riserless coiled the longer-term return. tubing. Other subsea operations men- Meanwhile, investment in furthering tioned included the use of coiled tubing the understanding of the performance Recommended additional reading at OnePetro: www.onepetro.org. Alex Crabtree, SPE, is senior adviser for well interventions and SPE 179096 Localized Extreme Coiled- well integrity with the Hess Corporation E&P Technology depart- Tubing Wall Loss—Causes and Remediation ment. He has more than 33 years of experience in the upstream Practices by Steven Craig, Baker Hughes, oil and gas industry. Crabtree holds a BS degree in mechanical et al. engineering. He has worked in Southeast Asia, the Middle East, SPE 179083 Novel Abrasive Perforating Europe, North America, and South America, both onshore and With Acid-Soluble Material and offshore. Crabtree previously worked within the oilfield- Subsequent Hydrajet-Assisted Stimulation services-company sector, holding various engineering and man- Provide Outstanding Results in Carbonate agement posts in research and development, field operations, downhole-tool design, Gas Well by Alejandro Chacon, Halliburton, and technology implementation. He has authored several SPE papers and is a past et al. program-committee chairperson for various SPE conferences and SPE Applied SPE 168294 Coiled-Tubing-Material Technology Workshops. Crabtree was an SPE Distinguished Lecturer in 2001–02 and Selection for Velocity Strings in Sour Brine is a member of the JPT Editorial Committee. Service by I. Ward, Shell Canada, et al.

50 JPT • JUNE 2016 Core Drilling Using Coiled Tubing From a Riserless Light-Well-Intervention Vessel

oiled-tubing technology is deployed from a light-well-intervention was designed with walkways allow- Ccommonly used in well servicing vessel without the use of a riser. ing safe access to the injector heads to deliver effective solutions in the during maintenance. oil and gas industry. However, coiled Objectives The lower cursor frame was modified tubing is extremely versatile and The subsea road tunnel will be the world’s to support the surface coiled- tubing in- may be used to deliver cost-effective longest and deepest tunnel; its deepest jector, which enables the vertical forces solutions in many applications outside point is approximately 385 m beneath sea generated by the surface injector to of well intervention. This paper details level. It shortens the travel time between transfer to the passive heave compensa- the planning, design, and execution Stavanger and Norway’s second largest tor. Any lateral force generated by ves- of a project involving the core drilling city, Bergen. The project required the sel movement is transferred to the tower of three wellbores using coiled-tubing drilling of four pilot holes along the route guide rails. The tower also includes a directional drilling along the future before drilling the tunnel, to obtain core platform frame for safe access to the in- Rogfast tunnel route on the Norwegian samples and verify rock quality. jectors during maintenance periods in coast. The project obtained core The project required several new tech- the operation. samples to verify rock quality before nologies and techniques to enable the Guide wires connected to the subsea tunnel drilling. collection of the rock samples: guide base and subsea injector are used Q The world’s first coiled-tubing for guiding the injector during deploy- Introduction operation simultaneously and ment and retrieval. The Norwegian government is enhanc- independently controlling surface A tool-handling skid was designed and ing the connectivity of its road network and subsea injectors, deployed from built to enable the safe handling and de- by building a road connecting Stavanger a riserless light-well-intervention ployment of the long and heavy bottom- to Bergen. This route includes a 25-km vessel hole assembly. tunnel along the future Rogfast route on Q Deployment and application A 70-t passive heave compensator, the Norwegian coast. To make tunneling of a new subsea connector and built specifically for the project, with a operations more efficient, verification of guide base 5-m stroke length, is installed between rock quality ahead of tunnel construction Q Deployment of a 30-m, 5⅞-in.- the lower cursor frame and the main eliminates the requirement of drilling outer-diameter bottomhole winch hook in the intervention tower. pilot holes ahead of the main tunneling directional-drilling assembly This provides vertical heave compensa- machinery. Eliminating the pilot-hole re- Q Drilling and core sampling of a tion to the surface injector during the quirement optimizes the tunnel route and 248-m borehole, with a maximum operation. In addition, the compensator significantly reduces tunnel construc- deviation of 55° and the surface injector maintain a posi- tion time. Therefore, coiled tubing was tive tension in the coiled-tubing string deployed from a light-well- intervention Project-Specific Equipment during drilling. vessel and drilling and coring opera- During the planning stage, vessel mod- A funnel was mounted below the sur- tions were performed along the route, ifications were identified that includ- face injector to guide and limit bending enabling rock samples to be collected be- ed an intervention tower installed over of the coiled-tubing string during subsea- fore tunnel construction. This required the moonpool. injector deployment and retrieval. surface and subsea coiled-tubing injec- An injector parking stand supported A standard coiled-tubing reel was tors that could be controlled simultane- the subsea coiled-tubing injector dur- used to keep the coiled-tubing string be- ously and independently. The system is ing the surface rig-up phase. The frame tween the reel and the surface injector in tension. A subsea wiper, comprising a steel This article, written by Special Publications Editor Adam Wilson, contains highlights housing with rubber seals and brass of paper SPE 179086, “Successful Core-Drilling Project Using Coiled Tubing From a bushings, was also necessary to keep Riserless Light-Well-Intervention Vessel in a Norwegian Fjord,” by Susana Rojas, gravel and mud from drilling from enter- SPE, and Michael Taggart, SPE, Baker Hughes, and Per Buset, Island Offshore, ing the subsea injector. prepared for the 2016 SPE/ICoTA Coiled Tubing and Well Intervention Conference and A subsea connector was used to latch Exhibition, Houston, 22–23 March. The paper has not been peer reviewed. and unlatch the subsea injector to the

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

JPT • JUNE 2016 51 Passive Heave Compensator

Lower Frame Surface Coiled- Injector Tubing Reel Funnel

Main Deck Tool-Handling Skid

Subsea Injector Fig. 1—Equipment layout. Wiper Connector subsea guide base, which comprises a start. However, for the coring operation, Subsea steel frame with a 15-m lubricator sec- three bit styles were tried in the field and Guide Base tion. The main purposes of this guide a polycrystalline-diamond-compact bit Seabed base are to level the lubricator section was selected to complete the job. by using the four hydraulically operat- Fig. 2—Equipment stack up. ed legs and to give the subsea injector a Management stable foundation. of the Coiled-Tubing String coiled tubing remained within the elastic The project-specific equipment is Management of the coiled-tubing string region and, therefore, that no additional shown in Figs. 1 and 2. in all operations is very important to fatigue was created. avoid unexpected failures from the ef- Downhole Tooling fects of bending the material beyond Operational Summary Requirements the elastic limit. During conventional The project originally comprised the The drilling-tools package was supplied operations, coiled tubing travels from drilling and coring of four holes along to enable efficient and effective drilling the reel to the well by means of the the future subsea tunnel, enabling rock- operations, including gooseneck and the coiled-tubing injec- quality verification. However, the sam- Q A quick connector, used to make tor. When moving the string in and out ples recovered from the first three up and break out the bottomhole of the well, two bending events are as- wells provided sufficient data to ana- assembly sociated with the reel and four bend- lyze the formation and the project was Q A communication and power ing events are at the gooseneck. These concluded without completing all the tool, for the pulsing sequence bending events create low cycle fatigue planned boreholes. of the tool to recognize damage in the coiled tubing. The dam- The operation steps were downlinks (surface-to-downhole age can be calculated and compared 1. Drill an 8-m vertical section to communication) and for power with known limits. provide a rathole to enable a longer generation and pulser control Although the fatigue limits are well- bottomhole assembly to be run for Q Measurement-while-drilling understood, the nature of the operation the build sections. recording axial and lateral increases the risk of additional fatigue not 2. Drill a 10° build section, including vibration, directing the azimuth considered in the standard calculations. the directional drilling tool. and the inclination of the well path For this project, the vessel heave will 3. Drill a 13° to 14° build section with Q A positive-displacement motor create further bending of the coiled tub- a 29.2-m tool. enabling bit rotation ing that may be difficult to quantify. This 4. Drill and core three wells cored Q A real-time tool to optimize the damage can be eliminated by creating through the bedrock, intersecting drilling operation and minimize slack coiled tubing between the injector the path of the proposed assembly failures by analyzing and the reel. In addition, an operation- underwater tunnel. results from the processing and al control was implemented that would 5. Upon completion, cement recording of downhole mechanical minimize stationary periods to a fixed each borehole for a proper and vibrational data depth for no longer than 3 hours. abandonment. For an open-water Q A directional tool to follow the The project team considered that ad- job, every cement additive required directional well trajectory ditional fatigue in the coiled tubing ex- was environmentally friendly. Q A roller-cone bit with 5⅞-in. posed to open water would be minimized The project included 47 coring runs outer diameter if tension were maintained between the and the recovery of 120 m of core sam- During directional drilling, the prima- subsea and surface injectors. Testing fol- ples. The entire operation was performed ry roller-cone bit worked well from the lowing the operation confirmed that the with one drill bit and one coring bit. JPT

52 JPT • JUNE 2016 Day or night We keep your equipment up and running.

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© 2016 National Oilwell Varco | All rights reserved Focus on Ancillary Equipment and Fatigue in Coiled-Tubing Deepwater Commissioning

he installation of flowlines in Arch Tever-deeper and -more-remote areas requires specific technologies Coiled tubing for precommissioning. Coiled tubing Tensioner Lever wind can be a solution; however, offshore Tower Control Swivel flange precommissioning can require coiled cabin Power Stopper Coiled-tubing tubing to be deployed several times pack clamp reel Spare- for durations sometimes exceeding a To part month and requires larger diameters. Work/hang-off precommission container Therefore, a campaign was initiated platform spread to characterize the behavior of coiled tubing under combined plastic Flying-hose- Main frame Support vessel and elastic fatigue. In addition, an Bend stiffener deployment system innovative bend-stiffener design or radius controller was developed to control the stress Vessel side shell levels in the coiled tubing at the hang- off location. Fig. 1—Typical coiled-tubing precommissioning spread. Introduction Precommissioning is a critical part Coiled tubing offers the advantage of Ancillary Equipment of flowline installation and opera- having a higher diameter/weight ratio The typical scenario for offshore pre- tion. This process occurs at the end than flexible lines, allowing for large- commissioning with coiled tubing con- of the installation to validate the in- diameter tubing to be deployed from an sists of deploying a small-bore rigid line tegrity and performance of any system MSV while keeping loads transferred (i.e., the coiled tubing) to approach the before commissioning. to the vessel at an acceptable level. In location of the pipeline end termination When no direct access is available addition, coiled tubing has an exten- and pig launcher and receiver that will from a surface facility, precommission- sive track record onshore and most of be used. A flexible hose is then connect- ing is, most of the time, performed from the required components are available ed between the coiled tubing and the a multiservice vessel (MSV) using a off the shelf. However, onshore appli- pig launcher and receiver. The hose al- flexible line. However, as water depth cations of coiled tubing are essentially lows the system some flexibility to avoid and the diameter and length of the flow- static while offshore precommissioning transferring loads to the pig launcher line to be precommissioned increase, activities are dynamic. The coiled tub- and receiver from vessel movement and the submerged weight of the line be- ing hangs from the vessel and, there- environmental loading. comes an issue, requiring the installa- fore, is subject to loads from the waves, Topside equipment for coiled-tubing tion of buoyancy modules to limit the currents, and vessel motions. This offshore precommissioning is identical loads transferred to the vessel. To sim- means that the coiled tubing and the to that used for conventional coiled- plify offshore precommissioning ac- associated equipment should be de- tubing operations, with two excep- tivities, the company decided to use signed to withstand extreme loads and tions: The injector that usually snubs coiled tubing. elastic fatigue. the coiled tubing into the well serves as a tensioner, and a dedicated deploy- ment system is required for the flying This article, written by Special Publications Editor Adam Wilson, contains highlights hose. The flying hose is usually a noncol- of paper OTC 25665, “Adaptation of Coiled Tubing for Deep- and Ultradeepwater lapsible hose that can tolerate only very Commissioning: Focus on Fatigue and Ancillary Equipment,” by François Lirola limited tension loads but has a very low and François-Régis Pionetti, Saipem, prepared for the 2015 Offshore Technology minimum bend radius. This hose is usu- Conference, Houston, 4–7 May. The paper has not been peer reviewed. ally equipped with ancillary equipment and cannot be deployed directly con- Copyright 2015 Offshore Technology Conference. Reproduced by permission. nected to the coiled tubing. Overboard-

The complete paper is available for purchase at OnePetro: www.onepetro.org.

54 JPT • JUNE 2016 ing operations are required to set up use for onshore operations. Elastic fa- Once the damage has been generat- the system. An overview of the topside tigue of coiled tubing is far less docu- ed for all load cases from the time se- equipment is presented in Fig. 1. mented. Few data on the combination ries, statistical data can be derived from The exit of the tensioner is clearly the of plastic and elastic damage are avail- the results. critical location. That is where the ten- able, making the combination process sion loads are at their maximum. Just quite uncertain. Fatigue-Testing Program. The com- below the tensioner, the coiled tubing pany decided to conduct fatigue tests on has to support the weight of a signifi- Fatigue-Assessment Methodology. actual coiled tubing. The tests were car- cantly long line, typically 2000 m. This To address the various hurdles, a ried out on coiled tubing made of CT-80 is also where bending loads are at their fatigue-assessment methodology was grade material. In-house plastic-fatigue maximum. At the exit of the tension- developed to verify that the design life testing allowed for the assessment er, the coiled tubing can be considered of the system overmatches the foreseen of fatigue performance with a single as being clamped on an infinitely stiff duration of operations. The considered methodology, reducing bias. Samples structure, which means that bending model differs from standard fatigue as- repeatedly were deformed and straight- loads will be concentrated at that loca- sessments in that it aims to take into ac- ened plastically until a given plastic- tion. As is the case for riser applications, count the effect of plastic damage on the damage level was reached. The samples a mitigation device is clearly needed. As elastic fatigue behavior of the system. were then transferred to the elastic- highlighted in Fig. 1, a bend stiffener Please see the complete paper for a de- fatigue-testing bench and were cycled is required. scription of the model. until failure. This step allows for fit- The following guidelines were consid- ting the power law on the damage evo- ered in the design of the bend stiffener, Implementation of the Model. A spe- lution. In order to assess the sensitivity which could be tailored for each project: cific tool was created to apply the pro- of the model to alternating plastic- and Q The bend stiffener should be made posed model. The tool is based on the elastic-fatigue cycles, a final batch of of a single piece to be as simple as time series of the environmental data tests will be performed in which a fa- possible. Therefore, a connector in the area where precommissioning is tigue scenario will be repeated until allowing passage through the bend going to be performed. It computes the failure. The samples will be deformed stiffener is required. overall damage for each operation start- plastically once, then elastically loaded, Q A straightener is needed so that the ing date with a step of 3 hours over sev- then deformed plastically once again coiled tubing is straight enough to eral decades, corresponding to tens of and so on until the samples break. The pass through the bend stiffener. thousands of load cases. The tool ac- testing is currently ongoing and, at the Q The bend stiffener has to be large counts for any reeling and unreeling op- time of publication, all data were not enough to accommodate large erations for coiled-tubing deployment yet available. ovalization of the coiled tubing. and recovery required in precommis- Q Precautions should be taken to sioning and for each time the system has Elastic-Fatigue Testing. The first step prevent the coiled tubing from to be recovered because of wave height of the program consisted of performing being scratched during the exceeding the maximum allowed value. elastic-fatigue tests on actual coiled tub- insertion. The procedure begins with computing ing. A testing bench was purpose built the number of allowed plastic-fatigue for the tests. The bench was a conven- Fatigue cycles by use of a dedicated coiled- tional four-point bending bench with Once a suitable design has been tubing software. Then, preliminary particular attention paid to the clamp- achieved, the design life of the coiled elastic-fatigue calculations are made. ing system to limit the risk of break- tubing has to be assessed. The main The time series is transformed into a ing the pipes at those locations, which challenge lies in the combination of scatter diagram, and the elastic dam- would make the results irrelevant be- plastic and elastic fatigue. age is computed for each sea state with- cause it is practically impossible to as- Typical offshore precommissioning in the scatter diagram. This damage is sess the stress at the clamp locations. requires several deployments and re- normalized with regard to the num- The main reason for using the four- coveries of coiled tubing and lasts ap- ber of waves within the sea state, then point bending testing instead of reso- proximately 600 hours. Consequently, the number of applied cycles and the nant fatigue testing is that the same coiled tubing will be exposed to high number of allowed cycles within a sea bench will be used on plastically de- levels of stress and plastic fatigue dur- state are extracted. Plastic and elastic formed pipes. ing deployment and recovery and, be- fatigue are then combined. Consider- Samples were tested to failure, or tween each deployment, will have to ing the operational scenario, the dam- testing was stopped when reaching sustain a significant number of elastic age induced by both plastic and elastic the run-out that was set to 1.5 times fatigue cycles. fatigue is computed with the model for the target. Plastic fatigue of coiled tubing is well- each sea state met over the duration of Nine samples were tested. They all documented because of its extensive the required operations. overmatched the run-out. JPT

JPT • JUNE 2016 55 Optimization of Single-Trip Milling Using Large-Diameter Coiled Tubing

arger-diameter coiled tubing (CT) cased wells, leaving the velocity and vis- cause the viscosity is high and the RE is Lrecently has been used to perform cosity dependent on each operation. too low to transport sand and debris, gel millouts because of its improved set- When pumping any treatment fluid sweeps were limited during optimized down force and increased annular through CT, a fluid friction reducer (FR) single-trip millouts. velocities (AVs) for cleanout purposes. must be pumped continuously to re- Service companies and operators have duce friction pressure generated from Single-Trip Wells reduced the number of wiper trips pumping fluid through a restricted area. Table 1 compares the average time spent when using larger-diameter CT, to save The FR decreases the circulating pres- on conventional millouts compared with time and money. Milling efficiency sure, enabling higher pump rates to be single-trip millouts of the same depth using 2-in. CT can be dramatically achieved. A rheology-control unit uses and sleeve number. Single trips allowed improved by maintaining proper fluid electric variable-frequency-drive pumps time savings of 47%. The table also rheology throughout the operation. to add FR and other chemicals to the compares the average chemical usage. By doing so, 2-in. CT has been used to fluid and to provide the ability to change The optimized chemical-injection sys- perform single-trip millouts, reducing dosage on the fly. These pumps are ac- tem reduced FR use by 94%, and the operational time by 40%. curate down to thousandths of a gallon, correct fluid rheology reduced gel use enabling higher chemical usage in small- by 96%. Fluids er doses. The chemicals are injected di- Six wells ranging from 9,600 to The main objective of CT operations rectly into the flow, then inline mixers 13,300 ft were completed in a single trip in horizontal wells is to clean the lat- enable shearing of the chemical to attain each. Low viscosity and sufficient AV al- eral completely of any debris without consistent mixing. Direct injection and lowed high REs and superior cleaning of compromising the well’s integrity. The inline mixers eliminate the unnecessary each wellbore. first and most important component of waste and oversaturation of chemicals single-trip-millout operations is correct seen when using conventional mixing Multiple-Wiper-Trip Wells fluid rheology. This system comprises the tubs. This optimized fluid increases the Sometimes, operators were hesitant to AV, Reynolds number (RE), and fluid vis- longevity of the recirculated water while perform a particular millout in a sin- cosity. With correct use of chemicals and maintaining a high RE, in turn decreasing gle trip. In other cases, issues such as proper AVs, the fluid system allows sand the cost to the operator. bottomhole-assembly failures occurred, and debris to travel out of the wellbore. Another common practice of con- resulting in a trip to surface for the as- The RE determines the flow regime as ventional millouts was to send multiple sembly to be replaced. Even with mul- laminar, transitional, or turbulent. Tur- linear-gel sweeps throughout the lateral. tiple wiper trips, precise chemical injec- bulent flow is characterized by swirling The objective was to increase the viscos- tion and correct fluid rheology reduced of the water (i.e., presence of eddies), ity of the fluid to lift sand and debris out operational time by 18% and increased which agitates the settling bed, enabling of the well. However, it has been discov- chemical efficiency by 90%. Table 2 sand and debris to flow out of the lat- ered that the more-viscous-gel sweeps represents the average time and chemi- eral and, in turn, out of the well. RE can lead to laminar flow, which is not condu- cal amounts used on wells with similar be broken into three components: fluid cive to moving sand and debris in the lat- depths. The remaining 12 wells ranged in velocity, hydraulic diameter (flow area eral. The laminar fluid flows over debris, depth from 11,000 to 20,500 ft. between casing and coil), and kinematic enabling it to settle and stay in the lateral viscosity (funnel viscosity). In this case, section of the well. Gel sweeps have vis- Challenges the hydraulic diameter is predetermined cosities of 20 cp or greater, compromis- Although an optimized single-trip mill- by the 2-in. CT working in 7- to 4.5-in. ing the RE down to below 20,000. Be- out is ideal, every well is different and caution must be taken when performing any well-intervention operation. Some This article, written by Special Publications Editor Adam Wilson, contains highlights challenges can be foreseen and mitigated of paper SPE 179090, “Optimization of Single-Trip Milling Using 2-in. Coiled Tubing,” while others cannot. by Elizabeth Snyder, SPE, and Justin Noland, SPE, Sanjel, prepared for the 2016 The foreseeable problems should be SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, Houston, addressed before attempting an opti- 22–23 March. The paper has not been peer reviewed. mized single-trip millout. Flowback must

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56 JPT • JUNE 2016 Time (hours) FR (gal) Gel (gal)

Conventional 23.6 248.5 112 Single Trip 12.5 15.5 5 Percent Saved 47% 94% 96%

Table 1—Single-trip vs. conventional millouts.

Time (hours) FR (gal) Gel (gal)

Conventional 66 418 184 Optimized 54 60 6 Percent Saved 18% 86% 97%

Table 2—Optimized vs. conventional millouts. be set up to accommodate debris being nique with many variables. Not every returned more frequently throughout operator was convinced that optimized the job. There should be a 3-in. return single-trip millouts were possible, let iron and a redundant junk-/plug-catcher alone cost- and time-effective. As the system that can be cleaned to ensure subject of this paper, six wells were com- that debris is returning to surface and pleted with single trips using 2-in. CT, not plugging off return lines. Another saving 47% of the time required by con- problem that can occur during single- ventional millouts, which require multi- trip millouts results from an unplanned ple wiper trips. Fluid rheology is a major interruption in circulation through the component of single-trip optimization coil and up the annulus. Once pumping and must be monitored closely for a suc- stops, turbulent flow is lost and debris cessful operation. begins to settle along the bottom of the The rheology-control unit used dur- casing and around the coil. When the ing these millouts provided a methodical debris starts to settle, the fluid rheol- approach to control chemical usage and ogy is compromised; therefore, a wiper deliver more-efficient wellbore cleaning The Podium Is Yours. trip should be performed until circula- while saving time. The ability to moni- tion is established. One issue in perform- tor pumping fluids in real time and to Take the microphone and give ing a wiper trip when circulation is lost adjust accordingly allowed CT opera- the gift of knowledge is the potential for wellbore debris to tions to mill continuously without losing through SPE Speaker Source. begin to pile up as the coil is being pulled time on wiper trips. An acoustic mon- through it. In this circumstance, the coil itor provided qualitative flowback in- Knowledge is one of the most valuable operator needs to be cautious of the coil formation, a commonly neglected part resources in the world. It powers weight. Any abnormal increase in coil of any CT operation and the one that our minds so we can power the world. weight should result in the coil being has the most room for development to Invest in the future of E&P by registering stopped. Once circulation is established enhance further the results of current to the point of turbulent flow, a minimum 2-in. single-trip optimized millouts. If to become a speaker at SPE Section of two bottoms up should be pumped be- the monitor signal drops during the job, and Student Chapter events. fore moving the coil, to ensure that the flowback could be alerted before there is Learn more and create your speaker debris is being moved hydraulically out a major issue. profile today at of hole. One challenge encountered on Single trips are attractive and save the www.spe.org/volunteer/speaker-source. location was the conventional thought most time and money, but not every well process of using multiple gel sweeps to can be completed with a single trip. En- clean the well. Gel sweeps compromise gineering along with CT operators must the RE and allow debris to settle because still be vigilant about changing well con- of the transition from turbulent flow to ditions. It is sometimes necessary to per- laminar flow. form wiper trips because of changing well conditions. The optimized single-trip Conclusion 2-in.-CT millout saved time and increased The process of optimizing single-trip efficiency by optimizing fluid rheology millouts with 2-in. CT is a dynamic tech- and reducing chemical usage. JPT

JPT • JUNE 2016 TECHNOLOGY FOCUS

Matrix Stimulation Lee Morgenthaler, SPE, Senior Staff Production Chemist, Shell

It goes without saying that the oil and gas more-complex mineralogy, greater per- enable creation of distributed etched- industry faces unprecedented challeng- meability contrast, and higher tem- fracture and wormhole networks along es today. Low oil prices are driving con- peratures. New chemistries are being long interval and multilateral wells in tinued improvements in efficiency and deployed to control the aggressiveness of low-permeability and heterogeneous a search for technologies to deliver bar- stimulation fluids at high temperatures reservoirs. These technologies are being rels at the lowest possible cost. Health, and to minimize the effect of unwant- taken up across the globe and are deliv- safety, and environmental (HSE) impacts ed damaging precipitation reactions. ering optimized treatment designs and of chemicals used in drilling, completion, Sandstone matrix acidizing traditionally execution on a large scale. and production operations are under requires the use of a carefully designed Finally, there is an ongoing effort to increased scrutiny from regulatory and sequence of stages to manage the com- use state-of-the-art simulation technolo- community stakeholders. At the same plex reactions between hydrofluoric acid gies (e.g., computational fluid dynamics) time, more and more complex and tech- and siliceous minerals. New formula- to model complex coupled reaction and nically challenging reservoirs must be tions that can be applied at higher tem- flow processes and improve the under- developed to replace reserves. peratures and sometimes with a single standing of stimulation processes and Matrix stimulation is being used to stage have been developed and deployed interpretation of more-detailed data maintain production from existing wells in the field. In addition to increasing the now available (e.g., from distributed- and reservoirs and maximize produc- potential application range and effec- temperature sensing). tion from new wells at an attractive cost tiveness, these formulations reduce the Matrix stimulation remains a critical per incremental barrel. Close cooper- chemical footprint of sandstone stimula- technology for delivering barrels at min- ation between suppliers, service com- tion. Laboratory data indicate that they imum cost. It is finding application in panies, and operators is required to are very effective but must be tailored unconventional- as well as conventional- deliver systems-level life-cycle solutions carefully to the target reservoir. Contin- reservoir development. Chemical for- that leverage the HSE benefit to improve ued experiments, theoretical modeling, mulations and theoretical models con- effectiveness and operational efficiency. and field testing are needed to under- tinue to develop, sometimes incremen- Over nearly a century of application stand and achieve the full benefits of tally and sometimes in step changes, and study, acidizing technologies have deploying these new technologies. to broaden the scope of application, been matured for relatively pure carbon- In low-permeability carbonate res- improve effectiveness, reduce cost, and ates, clean sandstones (less than 10% ervoirs, acid stimulation is a low-cost reduce HSE impact. JPT carbonate), and temperatures below alternative to propped hydraulic fractur- approximately 100°C. Today, the indus- ing. New chemical and mechanical diver- try is developing reservoirs that have sion technologies are being deployed to Recommended additional reading at OnePetro: www.onepetro.org. SPE 173686 Optimization of Matrix Lee Morgenthaler, SPE, is senior staff production chemist at Acidizing With Fluids Diversion in Real Shell. He has been with Shell for 35 years, starting as a research Time Using Distributed-Temperature chemist at the Bellaire Research Center. Morgenthaler has had Sensing and Coiled Tubing by Eber Medina, assignments as a production engineer, research-and- Pinnacle, et al. development team leader, research manager, and production SPE 179001 Field Results and chemist on a wide variety of projects. These include technology Experimental Comparative Analysis of development in completion and stimulation fluids, flow assur- Sodium- and Nonsodium-Chelant-Based ance, waterflooding, and field support for completion and HF Acidizing Fluids for Sand-Control stimulation activities in sandstone and carbonate reservoirs. He is currently working Operations by Alyssa LaBlanc Smith, in Shell’s Upstream Americas Deepwater business, with roles in technology deploy- Halliburton, et al. ment and production-chemistry leadership. Morgenthaler holds a BS degree from SPE 179017 An Improved Wormhole- Tufts University and a PhD degree from the University of Florida, both in chemistry. Propagation Model With a Field Example He is a member of the JPT Editorial Committee. by Xuehao Tan, Schlumberger, et al.

58 JPT • JUNE 2016 Sandstone-Acidizing System Eliminates Need for Preflush and Post-Flush Stages

he goal of sandstone-matrix ica, while HCl helps keep reaction prod- Regular Sandstone Acid Tacidizing is to remove siliceous ucts soluble in spent acid. Coreflood Experiments 1 through 4 were particles that are blocking or bridging To overcome some of the potential conducted to investigate the effect of pore throats. This is accomplished by problems associated with sandstone using preflush and post-flush stages of injecting acid formulations containing acidizing, a one-step sandstone acid sys- HCl when using the regular sandstone hydrofluoric acid (HF) or its precursors tem was developed. The new acid sys- acid. In these experiments, Bandera because HF is the only common acid that tem will eliminate the need for preflush sandstone cores were used. The regular dissolves siliceous particles sufficiently. and post-flush HCl stages, reduce the sandstone acid system evaluated in this Standard treatments include preflush treatment complexity, reduce the HCl re- study contains 3 wt% HF. and post-flush stages of hydrochloric quirements, and reduce the overall treat- acid (HCl) to minimize the potential ment rig time. A coreflood study was con- Coreflood 1. After injecting 5 wt% for secondary precipitation. This paper ducted with different sandstone cores NH4Cl to measure the initial permeabil- presents experimental and field-case at 180°F. ity, 4 pore volumes (PV) of 10 wt% HCl studies with a sandstone-acidizing was injected as a preflush stage, followed treatment designed to retard the One-Step Sandstone Acid by 8 PV of regular sandstone acid, and, HF reaction rate and enable single- Because of the variation in mineralogi- finally, 4 PV of 10 wt% HCl as the post- stage treatment. cal composition of the formation being flush stage. While injecting the first 2 PV treated, an inherent risk is always in- of the preflush acid stage, the pressure Introduction volved in sandstone acidizing. In an ef- drop increased from 10 to 50 psi and The goal of sandstone-matrix acidizing is fort to mitigate any problems, the new then decreased to 24 psi while injecting to dissolve damage that blocks or bridg- system contains a higher ratio of HCl the remaining 2 PV of the stage. These es pore throats in the formation matrix, to HF than conventional sandstone acid results indicated that HCl injection in thus ideally restoring the original res- systems, which reduces the pH of the HF sandstone formation caused damage and ervoir permeability. HF is the only com- mixture to levels at which some unwanted stimulation at the same time. At tested mon, inexpensive mineral acid able to reaction products have higher solubility. conditions, the initial damaging mecha- dissolve siliceous minerals. Therefore, Four fluid formulations were select- nism of HCl dominated until 2 PV had any sandstone acid system contains HF ed for testing as one-step sandstone been injected; then stimulation and dam- in some form. Mud acid, which is com- acid systems. Selection was based on aging mechanisms were equal. After that, posed of HCl and HF, is used commonly HCl-/HF-concentration ratio as follows: the stimulation mechanism dominated. to remove the formation damage in sand- Q Acid A is equivalent to 15 wt% HCl However, the overall effect was damage; stone reservoirs. Three main steps are in- and 1.9 wt% HF. after 4 PV of HCl injection, the pressure volved in conventional sandstone-matrix Q Acid B is equivalent to 10 wt% HCl drop had increased from 10 to 24 psi. treatment: preflush, main acid stage, and and 2.3 wt% HF. After the preflush stage of HCl, 8 PV post-flush. In the main acid stage, mix- Q Acid C is equivalent to 5 wt% HCl of the main acid stage was injected. The tures of mud acid have been used exten- and 2.6 wt% HF. pressure drop decreased from 24 to 8 psi sively in the field. In mud acid, the role of Q Acid D is equivalent to 3 wt% HCl after injecting 5 PV of the regular sand- HF is to dissolve aluminosilicates and sil- and 2.8 wt% HF. stone acid. However, during the injection of the remaining 3 PV, the pressure drop This article, written by Special Publications Editor Adam Wilson, contains highlights slowly increased from 8 to 9 psi. This of paper IPTC 18571, “Retarded HF System To Deeply Stimulate Sandstone Formation may be evidence of precipitation during the injection of regular sandstone acid. and Eliminate the Need for Preflush and Post-Flush Acid Stages: Experimental and Overall, the regular sandstone acid stage Field Cases,” by Ahmed M. Gomaa, SPE, Sergey Stolyarov, and Jennifer Cutler, SPE, was able to remove the damage caused by Baker Hughes, prepared for the 2015 International Petroleum Technology Conference, the HCl and enhance the permeability of Doha, Qatar, 7–9 December. The paper has not been peer reviewed. the core. In the final post-flush acid stage of HCl, the pressure drop increased slow- Copyright 2015 International Petroleum Technology Conference. Reproduced by ly from 9 to 11 psi. Even after treating the permission. sandstone core with HF, the post-flush

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JPT • JUNE 2016 59 Injection-Fluid Sequence Permeability Experiment Base Fluid Preflush Main Treatment Post-Flush Base Fluid Enhancement (%) 5 wt% NH Cl 5 wt% NH Cl 1 4 10 wt% HCl regular sandstone acid 10 wt% HCl 4 28 5 wt% NH Cl 5 wt% NH Cl 2 4 – regular sandstone acid – 4 −67.5 5 wt% NH Cl 5 wt% NH Cl 3 4 10 wt% HCl regular sandstone acid – 4 32 5 wt% NH Cl regular sandstone acid 10 wt% HCl 5 wt% NH Cl 4 4 – 4 −53.30 Table 1—Summary of the core-test results for regular sandstone acid system.

Main Maximum Injected Permeability and 18 PV was required to achieve 54% Experiment Treatment Pressure Drop (psi) Volume (PV) Enhancement (%) permeability enhancement. 5 Acid A 154 12 113 All selected acid formulations can stim- 6 Acid B 120 15 104 ulate Bandera sandstone cores success- 7 Acid C 105 16 86 fully; however, each formulation shows 8 Acid D 7 5 18 54 a different pressure-drop performance Table 2—Summary of the core-test results for Acids A, B, C, and D. with different final permeability enhance- ment. Table 2 summarizes the results of stage will damage the core if the core to 2 mL/min, to determine the initial core Corefloods 5 through 8. Acid A gives the contains HCl-sensitive clay. permeability. Acid A was injected inside maximum observed pressure drop, fol- Core 5 at a rate of 2 mL/min. As expected, lowed by B, C and D, in that order. Also, Coreflood 2. For this test, the regular because of the high HCl concentration Acid A gives the highest permeability en- sandstone acid was evaluated without in- of Acid A, the pressure drop increased hancement with the lowest acid volume, jecting a preflush or post-flush stage of from nearly 12 psi to 154 psi within the followed by B, C, and D, in that order. HCl. Initially, 5 wt% NH4Cl was inject- first 2 PV of Acid A injection. After that, ed at a rate of 5 mL/min, then reduced to the pressure drop decreased rapidly for Regular vs. One-Step 2 mL/min, to determine the initial perme- the next 2 PV to 40 psi. The decrease in Sandstone Acid ability. The acid-injection rate was then the pressure drop slowed upon reaching Eight formation cores were obtained kept constant at 2 mL/min until the end 12 psi (initial pressure drop), after total from three wells on the US west coast of the experiment. As the regular sand- injection of 12 PV. At the end of the exper- and were used to highlight the perfor- stone acid entered the core, the pres- iment, 113% permeability enhancement mance difference between regular sand- sure drop increased continuously from was calculated. stone acid (with acid preflush and post- 10 to 40 psi. This is an indication of dam- flush) and one-step sandstone acid age inside the core, and, in fact, the final Coreflood 6. The 5 wt% NH4Cl solution (Acid C without acid preflush or post- measured permeability reflected a 67.5% was injected at 5 mL/min, then reduced flush). It is important to highlight that, in permeability reduction. It is most prob- to 2 mL/min, to determine the initial core each well, cores were drilled from near- ably a result of CaF2 and MgF2 precipi- permeability. Acid B was injected inside ly the same depth to ensure comparable tation because the Bandera cores con- Core 6 at a rate of 2 mL/min. The pres- formation mineralogy. tained 5 wt% dolomite. Secondary and sure drop increased from nearly 12 psi For three of the cores, regular sand- tertiary precipitation also likely came to 120 psi within the first 3 PV of Acid B stone acid required an acid volume of from clay minerals. injection. After that, the pressure drop 27.9 PV to enhance the permeability by Table 1 shows the summary of the decreased rapidly for the next 3 PV to 21.97% while Acid C at 28.2 PV achieved first four experiments to show the ef- 38 psi. The decrease in the pressure drop a permeability enhancement of 333.26%. fect of adding preflush and post-flush of slowed upon reaching 12 psi, after total Also, with a volume of 20 PV, Acid C HCl. The highest permeability enhance- injection of 15 PV. At the end of the exper- enhanced the permeability by 239.62%. ment was obtained when only a preflush iment, 104% permeability enhancement Similar observations were noticed in five stage of HCl was used, followed by the was calculated. other cores. It was clear that the one-step case where both preflush and post-flush sandstone acid system effectively stimu- stages were used. Corefloods 7 and 8. Acids C and D pro- lated the formation cores with a high- duced the same pressure-drop perfor- er permeability enhancement and lower One-Step Sandstone Acid mance as Acids A and B. The pressure acid volumes than the regular sandstone Four different fluid formulas (Acids A, drop while injecting Acid C initially in- acid. This can be explained as the one- B, C, and D) were selected to be tested as creased to 108 psi within the first 3 PV; step sandstone acid system being more one-step sandstone acid systems without after approximately 16 PV of Acid C in- retarded, allowing HF to penetrate the any preflush or post-flush stages of HCl. jection, 86% permeability enhance- formation deeply. In addition, the one- ment was calculated. For Acid D, the step sandstone acid system contains ad- Coreflood 5. The 5 wt% NH4Cl solution initial pressure drop increased to ditives that reduce or eliminate second- was injected at 5 mL/min, then reduced 75 psi while injecting the first 4 PV, ary and tertiary precipitation. JPT

60 JPT • JUNE 2016 CO2-Energized-Acid Treatment Reduces Freshwater Use, Boosts Well Performance

arbon dioxide (CO2) with 30% quantities sufficient to produce viscous Q It reduces or eliminates the need Cfoam quality (FQ) has been foam (emulsion) is one of the more sig- for swabbing. The load to recover introduced for the first time during nificant improvements in recent years. is significantly lower than a acid fracturing treatments in a tight, The addition of CO2 to acid accom- conventional-treatment volume. sour, high-pressure/high-temperature plishes the following: The balance of the treatment (the carbonate gas reservoir in Saudi Arabia Q It increases the viscosity of the CO2) will vaporize and aid in the to reduce consumption of fresh water, commingled fluid. recovery of undissolved fines, spent minimize reservoir damage, reduce Q It controls leakoff of acid. acid, and flush volumes. the flowback period, and eliminate the Q Most CO2 foamed-acid treatments Because CO2 at the surface is above the need for nitrogen lifting with coiled are performed at matrix rates. It can critical pressure (1,071 psi) but below tubing. The addition of liquid CO2 to easily be pumped at fracturing rates. the critical temperature (87.8°F), CO2 is hydrochloric acid (HCl) in quantities The fracture length is determined pumped into the wellbore as a liquid. It sufficient to produce emulsion allows by acid reaction rate, injection rate, remains a liquid until heated by the for- live acid to retard and penetrate much fracture width, and rate of fluid loss mation downhole. Conversion of CO2 to deeper than HCl alone. from the fracture to the formation. a gas downhole causes no disruption of Q It dramatically increases the the two-phase fluid because supercritical Introduction efficiency of HCl. Laboratory CO2 has a high density and no abrupt ex- Gases were introduced to the oil and gas testing with cores from the pansion of CO2 occurs. industry primarily as an aid to recover canyon reef formation indicates pumped stimulation fluids. This appli- an improvement in penetration of Reservoir Characteristics cation still accounts for the majority of live acid of almost ninefold over a The carbonate formation in Saudi Ara- use of nitrogen and CO2. Special applica- conventional acid system. bia consists of dolomite and limestone tions, such as foaming stimulation fluids, Q It cleanses the formation. Many sections that can have streaks of shale, have reduced consumption of the liquid formations are only partially anhydrite, or low-permeability sections phase significantly. soluble in HCl. The energy and across the gross pay. Formation hetero- Stimulation activities have been in- viscosity of the foamed acid aid geneity between wells is significant, and creasing dramatically in Saudi Arabia. in removal of these undissolved developed porosity sections in one well During each stage of fracturing stimu- fines from the formation. The CO2 may not exist in an offset well. The car- lation in Saudi Arabia, up to 3,000 bbl also strips hydrocarbon from the bonate formation is ideal for acid fractur- of groundwater is used. Up to 70% of rock, exposing it to dissolution by ing because of the heterogeneous nature that groundwater consumption can be the acid. It improves formation of the formation, which tends to support reduced through the CO2-foam fractur- permeability by the removal of created-fracture conductivity. ing treatment. The application of CO2 stimulation and connate fluids. also reduces the flowback period and Q It dissolves more rock. An Candidate Well (Well A) eliminates the need to perform coiled- 80%-quality foam (only 20% of the Well A was drilled as a vertical gas pro- tubing nitrogen lifting, which is a unique volume is acid) has been proved to ducer across both the upper and the requirement for tight and depleted reser- remove as much rock as when the lower carbonate reservoir. Intervals voirs. The addition of liquid CO2 to HCl in entire solution is acid. of 50 ft in the upper carbonate res- ervoir of Well A were perforated, and This article, written by Special Publications Editor Adam Wilson, contains highlights the prefracture gas rate was determined to be 1.6 MMscf/D at a flowing well- of paper SPE 172620, “Successful Implementation of CO -Energized-Acid Fracturing 2 head pressure (FWHP) of 773 psi. Well Treatment in Deep, Tight, and Sour Carbonate Gas Reservoir in Saudi Arabia That A was selected as the candidate for CO2- Reduced Freshwater Consumption and Enhanced Well Performance,” by Ataur R. energized-acid fracturing for the follow- Malik, SPE, Alaa A. Dashash, Saad M. Driweesh, SPE, and Yousef M. Noaman, ing reasons: SPE, Saudi Aramco, and Eduardo Soriano, SPE, and Alfredo Lopez, Halliburton, Q The tight reservoir means that prepared for the 2015 SPE Middle East Oil and Gas Show and Conference, Manama, fluid recovery after the stimulation Bahrain, 8–11 March. The paper has not been peer reviewed. treatment is a concern.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

JPT • JUNE 2016 61 Q A marginal net pay means ure to crosslink in high-pH gel systems. tion. The Well A cleanup period was re- commercial gas from a single For this reason, the fracturing fluid se- duced by at least 30% as a result of CO2 conventional vertical acid-fracture lected is a low-pH zirconate-based cross- application in the treatment fluids. treatment may not be feasible. linked gel that is compatible with CO2 Q It could expedite and maximize and can be used with up to 7% potassium Treatment Evaluation fluids recovery to maximize fracture chloride for maximum clay protection. The post-stimulation gas rate for the conductivity. It is designed for formations that may upper carbonate reservoir in Well A was be sensitive to clay damage or have low 5.2 MMscf/D at an FWHP of 1,862 psig, as Fracturing-Fluid Description bottomhole pressures. compared with the prefracture gas rate of Current practice during acid fracturing Intensive laboratory testing was per- 1.6 MMscf/D at an FWHP of 773 psig. CO2, in carbonate formations includes using formed before the acid-fracture treat- as either liquid or gas, is considered non- alternating crosslinked gel (pad), gelled ment in Well A, to confirm that fracturing damaging to the formation, particularly HCl (26 to 28%), emulsified acid (26 fluid will remain stable enough to devel- in gas wells. It is recommended to flow to 28%), and diverting pills. The pad op the fracture profile and create a vis- back the well within 6 to 9 hours after fluid used to create the fracture profile cous fingering effect during alternating the acid fracture treatment to take full and fingering effect is normally borate- stages, leaving irregular etched patterns advantage of the stored energy and bet- crosslinked guar gel. Typically, the acid along the fracture face for the required ter fluids recovery. Historically, the aver- volumes ranged from 700 to 1,000 gal effective conductivity. age acid-flowback period in Saudi Arabia per foot of net pay. is approximately 5 to 7 days from similar When CO2 is used to either ener- Stimulation Design reservoirs. For this particular case, the gize or foam the stimulation fluids, it Design. The design includes 26% vis- flowback time was reduced to 3 days. is injected in the liquid state to form an cosified acid as the main reactive treat- Reduction in groundwater consump- emulsion at temperatures greater than ment fluid, using an average volume of tion is considered a vast benefit. For Well 88°F. CO2 is not compatible with borate- 1,000 gal of foamed acid per foot of A, the water savings was approximately crosslinked guar gel because carbonic perforation. The low-pH zirconate-based 23,000 gal through the use of CO2 with acid formed by mixing CO2 with water crosslinked gel as the pad gel was opti- 30% FQ. A greater reduction in ground- can cause a premature break or a fail- mized for the presence of CO2 and foam- water consumption can be observed by ing agent. To minimize fluid leakoff to increasing the CO2 FQ to 60% during high-permeability zones and improve di- acid fracturing in the Saudi Arabian car- version effects, a diverter pill was includ- bonate reservoir. The consumption of ed in the stimulation design. water will fall even lower during proppant fracturing treatment in sandstone reser- Surface Equipment. The surface equip- voirs because the CO2 FQ can be raised as ment is the same as that for conventional high as 75% during proppant fracturing. fracturing treatments except additional equipment is required to pump the CO2 Conclusions in liquid phase. Liquid CO2 is injected There was 2.5-fold production increase into the treating fluids near the wellhead from the upper carbonate reservoir of through a separate high-pressure treat- Well A after the stimulation treatment. ing line. The two streams will meet at the The production from Well A is approxi- wellhead to be pumped according to the mately twofold higher when compared planned pump schedule. with one of the best offset performers. Also, a significantly higher dimension- Flowback less productivity index was observed in Well A was shut in for 9 hours after the Well A than in offset wells, after acid stimulation treatment to allow the acid fracturing with CO2-energized fractur- to react completely with the formation ing fluids. rock. Depending on lithology, bottom- The CO2 increases viscosity, controls hole static temperature, cool-down tem- leakoff of acid, and, therefore, increas- perature, and local experience, the post- es HCl efficiency. CO2 can be pumped at stimulation shut-in period may vary in both matrix and fracture rates. CO2 re- length. It is important to open the well moves emulsion/water blocks and im- with a small choke and bean up gradually. proves formation virgin permeabili- Rapid beanup may trap liquid in the res- ty. CO2 strips residual condensate from ervoir and slow the liquid-recovery rate. the reservoir rock. The chemical re- Initial flowback exhibits a high concen- quirement also is reduced during CO2- tration of CO2, which eventually reduces energized/foam stimulation, as a result of to the original reservoir CO2 concentra- the reduction in water volume. JPT

62 JPT • JUNE 2016 No-Damage Stimulation By Use of Residual-Free Diverting Fluids

orizontal wells and acid Hstimulation are essential technologies for the development of complex carbonate reservoirs. However, conducting effective stimulation in horizontal wells with long intervals is extremely difficult because traditional acid systems can flow only into the high-permeability formations, leaving the damaged formation untreated. This paper studied three residual- free fluid systems for acid treatments and fracturing in order to develop no-damage or reduced-damage and highly effective stimulation techniques for long-interval wells. (a) at room temperature (b) at reservoir temperature (c) at high temperature for 5–10 minutes for 1–2 hours

Introduction Fig. 1—Molecular structure and diverting mechanism of TCA. Horizontal wells are essential for the de- velopment of carbonate reservoirs in This paper analyzes three clean fluid creases in order to flow back easily and China. However, horizontal wells always systems for acid treatment and fractur- leave no damage in the formation. have long intervals, so they are extremely ing. The no-damage stimulation systems The molecular structure of the gelling difficult to stimulate. considered are a temperature-controlled agent of TCA can be a comb-type multi- The fluid systems used are a critical as- deep-diverting acid system (TCA), a pH- cation polymer. Fig. 1 shows the molec- pect of high-efficiency stimulation. Tra- controlled self-diverting acid system ular structure in which the end radicals ditional acid systems, which do not have (DCA), and a fracture-reorientation tech- on the backbone and branched chain de- diverting capabilities, can flow only into nology using degradable fiber (RDF). activated the molecule, preventing the the high-permeability formations, leav- molecular chain from growing. When the ing the damaged formation untreated. TCA temperature is greater than 80°C, the That is why long-interval wells with high Diverting Mechanism of TCA. The TCA polymer in the acid is reactivated and heterogeneity need to be treated by a di- system is similar to ordinary gelled acid continues to grow or connect with other verting acid system. during pumping. The gelling agent can polymer molecules. As a result, the mo- A new diverting acid system should dissolve in water in a short time, reduc- lecular weight and the viscosity of the have the following characteristics: The ing the frictional resistance of the system acid system grow rapidly with the assis- capability to reduce the acid/rock re- dramatically and making it easy to pre- tance of an activator, which can reduce action rate; a diverting performance to pare and pump. At formation tempera- the activation energy. The polymer de- achieve uniform stimulation in a carbon- ture, the system has a high viscosity to composes when it is heated to greater ate reservoir with high heterogeneity; ensure diverting and retarding perfor- than 130°C for 1–2 hours. Fig. 1 shows the and use of clean chemical additives to mance. After the acid fracturing treat- process of viscosity increasing and the eliminate or limit damage. ment, the viscosity of the spent acid de- polymer decomposing.

Viscosity of the TCA. The process of This article, written by Special Publications Editor Adam Wilson, contains highlights increasing viscosity of the TCA can be of paper SPE 177495, “No-Damage Stimulation Based on Residual-Free Diverting divided into two stages. First, the po- Fluid for Carbonate Reservoir,” by Y. Shi, X. Yang, F. Zhou, Y. Gao, S. Lian, X. Li, lymerization of the TCA gelling agent in and X. Han, Research Institute of Petroleum Exploration and Development, CNPC, acid is activated at a specific tempera- prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, ture with the help of a catalyzer. Second, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. the gelling-agent polymer decomposes

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

JPT • JUNE 2016 63 cores was designed to validate the di- verting capacity of DCA. When the ex- periment was conducted with DCA, all three cores were stimulated effective- ly because of the diverting capacity. As with the traditional acid, DCA will flow Ca2+ into the high-permeability core first 2+ Mg Oil and react with it. After the reaction be- tween DCA and high-permeability core, the viscosity of the system will increase rapidly and the high-permeability core Spherical micelles Huge-body micelles Spherical micelles will be blocked. Then, the acid will di- Fig. 2—Diverting mechanism of DCA. vert into the midpermeability and low- permeability cores. at high temperature through backbone ing this process, the pH value of the sys- breaking. The first stage can be complet- tem will increase and Ca2+ and Mg2+ will RDF ed in a short time because of the high be released into the fluid as H+ is con- Diverting Mechanism of RDF. Degrad- temperature and the existence of an acti- sumed. As a result, the molecules of VES able fiber is used as the diverting agent vator. The second stage is a slow process. will aggregate into large micelles (middle in RDF and is mixed into the acid or The viscosity of TCA is less than in Fig. 2). The micelles gel further to form fracturing fluid to generate the RDF sys- 30 mPa·s when the temperature is less a body structure. In this way, the viscos- tem. In an RDF treatment, a hydraulic than 50°C, resulting in low viscosity on ity of the system will increase dramatical- fracture will be generated first. Then, the surface that facilitates pumping. The ly, giving the system a diverting capacity. the RDF system will be injected into viscosity of the TCA begins to increase The VES micelles will break up automati- the formation as a diverting fluid. When when the temperature reaches 60°C cally when in contact with hydrocarbon, fiber enters the formation, it will tempo- and grows rapidly when the tempera- and the viscosity of the system can be rarily block the opened hydraulic frac- ture is greater than 80°C. The viscosity reduced to 3–5 mPa·s in an oil forma- ture, increasing the net pressure and re- can reach 220 mPa·s at approximately tion. Therefore, spent DCA can flow back orienting the hydraulic fracture until a 100–130°C. After 1–2 hours at 130°C, the easily and leave no damage. new fracture in a new direction is gener- backbones of the gelling agent in the sys- ated. After treatment, the fiber will de- tem begin to break, which reduces the Viscosity of the DCA. In fresh acid grade at formation temperature and the viscosity to less than 10 mPa·s. Conse- (when pH is low), the viscosity of the blockage will be removed. quently, the formation will not be dam- system is approximately 10 mPa·s, mak- Fracture-reorientation technology aged after treatment. ing pumping easy. During the reaction, using degradable fiber has the advantages the viscosity will increase as the pH of of reducing leakoff effectively; transport- DCA the DCA system changes. The viscosity of ing a high concentration of proppant; Diverting Mechanism of DCA. The di- DCA with a VES concentration of 5–6% and being degradable and, therefore, not verting agent of DCA is a kind of visco- can reach 1000 mPa·s when the pH value damaging to the formation. elastic surfactant (VES). At the begin- is approximately 0.35. ning, the VES exists as a single molecule Diverting Performance. A carbonate in fresh acid (left in Fig. 2). When DCA Diverting Capability of DCA. A core- core was cracked to generate an artifi- contacts rock, the reaction starts. Dur- flood experiment with three parallel cial fracture. Then, the RDF system was injected into the core with the artificial fracture to simulate the process of frac- ture reorientation. Fig. 3 shows the core before and after fiber injection. The fiber blocks the fracture well. During the ex- periment, the injection pressure was re- corded. The maximum blocking pres- sure can reach 30 MPa, so the degradable fiber has a strong diverting performance.

Degradation Performance. The degra- dation process of degradable fiber was also simulated. After being heated for approximately 400 minutes at 150°C, the fiber degrades with a degradation ratio Fig. 3—Core sample before (left) and after (right) fiber injection. of more than 99%. JPT

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Wellbore Tubulars Pat York, SPE, Global Director, Weatherford

Today’s economic situation within our These papers span the application of The extended-reading references industry has been harsh, harder than Q A 1000-m steerable drilling liner selected further explore various appli- any downturn I have witnessed during directionally drilled in through cations and evaluation techniques span- my 44 years in the industry. However, it an unstable shale in the Åsgard/ ning tubular-application areas from has provided the environment to influ- Midgard field in the Norwegian completion intervention to casing reme- ence positively the forging, application, North Sea after multiple attempts diation to drilling-challenge mitigation. field trialing, and acceptance of inno- to drill and case this same hole These include case-history references to vative technologies within our indus- section failed. assist readers in expanding the applica- try. Recent oil-industry technical pub- Q A subsea completion string that tions knowledge within their wellbore- lications are filled with a wide variety would provide efficient hydraulics tubulars toolbox. of applications of models, tools, and during fracturing operations while We all strive to deliver quality well techniques being developed and applied ensuring mechanical and pressure construction, production, interven- to the drilling, completion, interven- integrity. This high-pressure/high- tion, and abandonment to our industry. tion, and even wellbore-abandonment temperature system was developed During the evaluation of the writings arenas, allowing us to be more efficient to be the answer to extreme to be included within these few short by driving costly nonproductive time completion challenges within pages encapsulating the extensive base out of our operations. multiple deepwater Gulf of Mexico of information published that surrounds While the development of innovative projects within the Jack and St. Malo the application of wellbore tubulars, I technologies is critical, their correct and field reservoirs. was struck by the quality and diversity cost-effective application is even more Q A drilling software that delivers of information available. Therefore, the important. No matter how good, tech- operational surveillance in real time, reader is encouraged to search further nically impressive, or even innovative assisting in the avoidance of stuck within the industry’s technical-paper and a technology is, if its application is not pipe and with application within a article archives in the OnePetro online operationally practical as well as cost- variety of drilling environments. The library (www.onepetro.org) to explore efficient, then in the end it is just a proposed software was tested with additional aspects of wellbore tubulars cute widget. historical data sets from 36 stuck- and the tools and techniques that are The papers within this Wellbore pipe incidents in the Eagle Ford, currently available to responsibly apply Tubulars section focus on delivering Utica, Permian, and Gulf of Mexico. and critique their applicability. JPT efficiencies to us, converting nonpro- the paper contains discussion of case ductive time into new dollars for the histories in several shale horizontal bottom line. unconventional wells. Recommended additional reading at OnePetro: www.onepetro.org. Pat York, SPE, is global director with Well Engineering and SPE 175878 Steerable Drilling Liner Project Management for Weatherford. He has been in the oil and Matches the Industry’s Common Theme gas industry for 44 years. York has been involved in drilling- Regarding Cost-Optimization Approaches hazard management since 2005 and with solid-expandable and Minimizing Geomechanics-Related technology since its initial global implementation in 1998. Since Challenges—Technology Overview, by Wael 2004, he has collaborated with clients on complex drilling and Applications, and Limitations El Sherbeny, Baker Hughes, et al. completion projects. Throughout his career, York has served in several management, business-development, and operational SPE 168271 Tubing-Retrievable Surface- roles, as well as in executive management in the solid-expandable and drilling- Controlled Subsurface-Safety-Valve hazard-mitigation arenas. Before joining Weatherford, he was the vice president Floating-Flapper Remediation by B. Gary, Halliburton, et al. of commercialization for Enventure Global Technology. York has authored or co authored more than 30 technical papers and articles and several chapters in indus- SPE/IADC 178780 Solid-Expandable try technical books and textbooks. He holds a bachelor’s degree in electronic engi- Solution To Qualify Existing Nonsour- neering tech nology from Northwestern State University. York is a member of the JPT Service Production Casing by Jesus D. Editorial Committee. Contreras, ConocoPhillips, et al.

66 JPT • JUNE 2016 Steerable-Drilling-Liner Technology in Unstable Shale

hallenging environments such as proximately 1000 m. The drilling op- proximately 300 m of BHA and drillpipe Cunstable clay formations represent eration was performed without any was left in the hole. high operational risk when running major problems; however, it was nec- After evaluation of further options, tubulars after drilling is completed. essary to change the drilling bottom- the aim was to drill the 8½-in. sec- Use of steerable-drilling-liner (SDL) hole assembly (BHA) because of a tool tion in one run and limit as much as systems combines drilling and casing of failure. There were also challenges to possible the application of mechanical the hole, thereby mitigating the risk of keep the oil-based-mud system stable or hydraulic loads to a formation that not being able to run the liner because enough to drill the section. When run- had already proved weak. Therefore, the of time-dependent formation collapse. ning in with the 7-in. liner, obstruction SDL system became an obvious choice. This case study presents the difficulties was met approximately 500 m out in encountered with conventional the open hole. It was decided to pull out SDL Technology approaches with a semisubmersible with the liner and plan for a wiper trip. The SDL is an integrated drilling system rig in the North Sea during 7-in.-liner- Problems were encountered already in that combines the advantages of rotary- running operations in an unstable clay the 9⅝-in.- casing shoe and rathole area steerable-drilling technology with the formation and details a subsequent during this wiper-trip operation. After liner-drilling concept. Main SDL bene- SDL operation. 650 m of working and attempting to get fits include reduced mechanical load on the wiper-trip string down, it was decid- the borehole wall and reduced hydraulic Introduction ed to pull out with the BHA and cement load on the borehole. Midgard, a subsea field, is part of the back the hole and prepare for a side- The system consists of a retrievable Åsgard Licence and is located in the track. A considerable amount of cut- and changeable inner string/pilot BHA North Sea. Midgard consists of three tings and 10% mechanical cavings were and an outer liner string. Inner and outer templates with four slots each. Produc- circulated out during this wiper trip. strings are connected by a running tool, tion from the field goes to the produc- An 8½-in. sidetrack was performed which transmits required torque, locat- tion platform Åsgard B. The primary immediately below the 9⅝-in.-casing ed at the top of the liner. The liner ro- objective of this well was to increase shoe. The section was drilled with sta- tates slowly at approximately 30 rev/min reserves, accelerate production, and ble drilling parameters, and the hole to overcome axial friction, while the add robustness. The secondary objec- was circulated clean at total depth (TD). reamer bit and pilot BHA/bit rotate with tive was to evaluate the potential of this Some tight spots and overpull were re- an additional 120 rev/min provided by a segment. The target in the reservoir ported while pulling out of the open modified positive-displacement motor. was approximately 4 km from the tem- hole. The 7-in. liner was then run in An overview of the system is shown in plate at a depth of 2500-m true vertical the hole, but this time the obstructions Fig. 1. System components and opera- depth (TVD), making this well almost an were met in the 9⅝-in.-casing-shoe tion are detailed in the complete paper. extended-reach well. This paper will area; after 150 m, it was not possible to In addition to the main components only focus on the 8½-in. section. get any further. The decision was made of the SDL system, it was necessary in to pull out of the hole. this operation to use a flow- diverter sub Conventional Drilling A new cleanout run was performed, enabling a 50:50 flow partition to pro- of the 8½-in. Section with an 8½-in. bit and a 9½-in. under- vide enough flow to power the down- The 8½-in. section was planned to be reamer. Major challenges were ex- hole tools and to provide enough hole drilled to approximately 20-m TVD perienced while reaming the hole. cleaning inside the 9⅝-in. casing. A above the reservoir for a length of ap- Eventually, the string parted and ap- ball-drop-operated flow bypass was also included above the flow diverter in order to circulate inside the 9⅝-in. casing at This article, written by JPT Technology Editor Chris Carpenter, contains highlights any time during the drilling operation. of paper SPE 178811, “World Record Using Steerable-Drilling-Liner Technology The new 8½-in. section was planned To Secure Previously Nondrillable Section in Unstable Shale,” by Vincent Bossis, as a sidetrack from the 9⅝-in. cas- Gaute Grindhaug, Morten Eidem, Jan Fjorden, and Jim Roger Ringstad, Statoil, ing. A 9⅝-in. whipstock had been in- prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, stalled. This SDL operation was also Texas, USA, 1–3 March. The paper has not been peer reviewed. one of the first to be planned through a

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JPT • JUNE 2016 67 Fig. 1— The SDL system, including main components: (1) running tool, (2) thruster, (3) motor, (4) RDS, (5) 8½-in. reamer bit, (6) 6-in. pilot BHA, (7) 7-in. liner, and (8) 5-in. drillpipe. The 5-in. drillpipe was used to surface. The running tool on top of the 7-in. liner will remain inside the 9⅝-in. casing during the entire drilling operation.

whipstock and casing window. The plan- down to 3790.6 m. Drilling out of the stock, and the assembly was careful- ning of an SDL operation is highly de- window with the SDL technology was ly tripped in to 3808 m—18 m outside tailed, and it was necessary to focus on perceived to entail high risk with regard the window, with the reamer bit 4 m some key points, many of which [such to damage to the cutting structure of the outside the window before starting cir- as well path, equivalent-circulating- reamer bit on the liner. Therefore, a sep- culation. Some pack-off tendencies density (ECD) -management strategies, arate drill-out run was performed with a were experienced when bringing up the drillstring and centralizer design, and motor BHA. No restrictions were seen pumps, and ECD readings up to 1.88 weather-imposed limitations] are de- sliding over the window, and a success- specific gravity (sg) were experienced. tailed in the complete paper. ful kickoff was performed. Drilling con- It was concluded that the pilot BHA had tinued down to 3875 m, giving an 85-m- become jammed into the fill and the Operations long rathole outside the window. cavings in the rathole when running in The first attempt to drill the section Circulation was initiated and the hole through the window without cir- with the SDL system was abandoned be- reamer drive sub (RDS) was activated culation. The SDL BHA was pulled back cause of junk in the hole. A new 9⅝-in. before running out over the whipstock. into the 9⅝-in. casing. Some overpull whipstock was set inside the 9⅝-in. Having activated the tools, circulation was seen tripping back into the cas- casing with the top of the whipstock at was turned off to prevent rotation of the ing, but no problems were seen when 3784.7 m and a 6-m-long window milled reamer bit while sliding over the whip- restarting circulation.

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68 JPT • JUNE 2016 The string was run back into the hole tings load increased. With a WOB of be- moderate amount of cuttings was seen until the pilot bit was 2 m outside the tween 5 and 8 Mt, the progress rate was during the first bottoms up, but only a window before circulation started. It kept at 30 m/h, with torque varying be- minor amount of cuttings thereafter. was necessary to continue reaming care- tween 17 and 19 kN·m. ECD continued Circulation after TD further proved fully down until the reamer bit entered to be stable at 1.80 sg, which was much that good hole cleaning had been the open hole. A downlink was then sent lower than the value predicted from the achieved during drilling, but addition- to activate the RDS again. Operations hydraulic simulations. al circulation was performed at 3768 m continued by washing slowly down, WOB was increased to 8–10 Mt, but with the circulation sub at the transition using 4 hours to clean out the 85-m-long the rate of penetration dropped to between the horizontal (70°) section and section from the kickoff run. No pack- ±20 m/h. This was in line with what had the vertical (40°) section above. Only a offs or severe ECD variations were seen, been experienced while drilling con- minor amount of cuttings was seen, and and the pilot bit was drilled into the ventionally. Drilling parameters, ECD, the BHA was pulled to surface. new formation. and hole-cleaning indicators were still With the section completed and The 6-in. pilot BHA was carefully smooth and steady. At 4420 m, progress lined, cementing was to be performed drilled into the new formation until the rates picked back up to 30 m/h and drill- with a cement stinger and a mechan- 8½-in. reamer bit engaged the bottom ing continued down to TD of the section ical plug, set inside the 7-in. liner. of the previously drilled 8½-in. hole. at 4901 m without further problems. However, the cement job was aborted At a bit depth of 3890 m, both the Having reached the TD of the sec- because the wellbore had eventually col- 6-in. pilot bit and the 8½-in. reamer tion, the bit was pulled a few meters off- lapsed outside the liner while tripping bit were bedded into virgin formation bottom and the annulus was circulated out with the SDL BHA (to make up the and drilling commenced with steady clean. A command was sent to the RDS cement assembly). parameters. A good progress rate was to disconnect, and a ball was dropped to The SDL system allowed the 8½-in. achieved with low weight on bit (WOB) disconnect the liner-running tool. Hav- section of this well to be drilled and and smooth torque of approximately ing released the 7-in. liner, the bit was cased at the same time when conven- 18 kN·m. Drilling ahead, no indication pulled inside the 7-in. liner and a second tional methods were not an option. of packoff was seen, and ECD increased ball was dropped to open the circulation More than 1000 m was drilled, setting a gradually from 1.76 to 1.80 sg as the cut- sub located above the top of the liner. A new record. JPT

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JPT • JUNE 2016 69 New Deepwater, High-Pressure GOM Tubular Maximizes Capability, Reduces Cost

2-year comprehensive effort to a total depth of 28,411 ft. The GOM well Q An absolute-external-working- Adesign, test, manufacture, and was located approximately 190 miles pressure rating of approximately deploy a new high-pressure completion southwest of New Orleans in Green Can- 24,500 psi to sustain elevated tubular (CT) for Chevron’s deepwater yon Block 640. Results from the ex- annulus pressures and not collapse Gulf of Mexico (GOM) operations is ploratory well indicated the presence of or leak presented. The completion application high- quality reservoir sand with a total Q The ability to withstand multiple expected harsh, aggressive loading net pay of more than 400 ft. Following makeup and breakout cycles while modes and high pressures to be the results of the exploratory well, two maintaining sealability at pressure encountered. The major challenge was to appraisal wells were drilled simultane- to enable multiple trips into the design, test, and manufacture a subsea- ously in Green Canyon Blocks 596 and well for cleanout, displacement, completion string that would provide 640. The appraisal program verified the perforation, and fracture efficient hydraulics during fracturing operator’s initial estimates of 400 to operations operations while ensuring mechanical 500 million bbl of ultimate recoverable Q A high-performance metal-to- and pressure integrity. oil reserves, one of the most signifi- metal seal that possessed integrity cant net-pay accumulations recorded in against fluid leak Introduction the GOM. The basis of the first-generation-CT In 2004, the first built-for-purpose Because of the extreme depth and connection was the first-generation CT incorporating a gas-tight, rotary- bottomhole pressure of the Tahiti res- metal-to-metal (MTM) connection. shouldered connection was developed ervoir, the completion and well test re- Finite-element analysis (FEA) of the and deployed in the GOM. Since that time, quired the design of new equipment to first-generation MTM connection re- rotary-shouldered connections have successfully perforate, frac pack, and vealed that the extended box counter- evolved (this evolution is described in de- flow test the Tahiti 1 discovery well, in- bore lacked stability under the immense tail in the complete paper). Present-day cluding the design and qualification of a external pressure and compressive connections offer improved perfor- perforating and frac-pack CT. loads anticipated at the bottom of the mance, increased torsional capacity, and The CT requirements included well. Sectional stresses in the box coun- improved hydraulics, and have created Q Fishable within the 9⅞-in. tieback, terbore significantly exceeded the ma- slimmer profiles. Additionally, running limiting the connection outer terial capabilities, and counterbore col- and handling characteristics have been diameter (OD) to 7 in. lapse was predicted. improved, providing faster makeup, re- Q An inner diameter (ID) of no less To provide additional rigidity and duced trip time, and decreased repair cost than 4¼ in. to provide the desired structural stability to the box counter- because of reduced connection damage. treating rate during fracturing bore of the first-generation CT connec- However, the need remained to incorpo- operations tion, the counterbore length was short- rate these technological advancements Q An absolute-internal-working- ened from 2¼ to ⅝ in. Adjusting the and benefits into a second-generation CT. pressure rating of approximately box counterbore length created an im- 29,000 psi to sustain internal balance of forces acting on the inter- CT Requirements pressure and not leak, nal and external shoulders. The initial In March 2002, the operator drilled potentially jeopardizing clearance, or gap, between the pin nose the Tahiti 1 well in 4,017 ft of water to the frac-pack results and the box internal shoulder when the connection is made up “hand-tight” This article, written by JPT Technology Editor Chris Carpenter, contains highlights and the makeup position when the ex- ternal shoulder and thread flanks are of paper SPE 173034, “New Deepwater, High-Pressure Completion Tubular for Gulf touching slightly had to be determined. of Mexico Maximizes Combined-Load Capability While Incorporating Proven Cost- The proper gap for the first-generation Saving Features,” by T. Anderson, C. Fontenot, and R. Davey, Chevron; J. Dugas and CT was determined through a series of B. White, Quail Tools; K.A. Hamilton, C-FER Technologies; and P.S. Beauchamp, FEA runs. L.C. Karlapalem, A. Muradov, and J. N. Brock, NOV Grant Prideco, prepared for the The new design was then analyzed 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper with FEA against the anticipated Tahiti has not been peer reviewed. loads. The connection showed that

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70 JPT • JUNE 2016 sectional stress values in the box coun- connection. On the basis of the FEA re- 3°/100 ft dogleg severity; and internal terbore still exceeded the 120,000-psi sults, the 7-in.-OD×4¼-in.-ID second- and external pressures up to 29,920 and tool-joint-material specified minimum generation-CT connection displayed 25,279 psi, respectively. The three load yield strength (SMYS). A decision was acceptable stress profiles for all the ser- points (5.1, 6.1, and 7.1) were used to made to incorporate 135,000-psi-SMYS vice load points. compensate for the axial tensile load as a tool-joint material for the connection. result of the capped-end pressure effect Rigorous physical testing verified the Connection Testing. Comprehen- created by the external geometry of the design, and the first-generation CT was sive full-scale physical testing of the samples when they were subjected to ex- deployed successfully on the Tahiti 1 second-generation-CT-connection de- ternal pressure. well and has become the standard high- sign was necessary to verify performance All of the load points where external performance CT for the operator and for the operating conditions expect- pressure was applied to the connection other deepwater-GOM operators. ed in high-pressure/high-temperature samples had internal pressure applied (HP/HT) offshore wells. The test- simultaneously. Applying both internal Development ing program consisted of two phases: and external pressure at the same time of Second-Generation CT (1) galling-resistance (make-and-break) was critical in the overall evaluation of The objective of the new deepwater, testing and (2) structural/sealabili- the second-generation-CT-connection high-pressure CT was to maintain or ty testing. The make-and-break test- performance. If only the net differen- improve the combined-load capability ing subjected the candidate connection tial pressure had been applied, only the of the first-generation CT while provid- samples to multiple makeup and break- sealability characteristics of the radi- ing the speed of makeup and proven cost out cycles to assess the galling resis- al MTM seal would have been evalu- savings of the third-generation double- tance of the connection. The structural/ ated. By applying internal and external shouldered connection (DSC). sealability testing subjected the same pressures simultaneously, the test pro- The first-generation CT benefits from connection samples to a range of com- gram not only determined the sealabil- the refinement and optimization of the bined loading conditions, including ity characteristics, but also further es- third-generation DSC design. The de- axial tension and compression loads, tablished whether the connection was sign requirements were met through the simultaneous internal and external capable of withstanding the combined combination of high-strength material, pressures, elevated temperature, and axial, radial, and hoop stresses repre- proven radial MTM seal technology, and bending loads. Preparations for both sentative of those in the eventual expect- the double-start thread that reduced the make-and-break testing and structural/ ed operating conditions for this connec- number of turns necessary to assemble sealability tests are provided in the com- tion design. the connection by 50%. Other design plete paper. Structural/Sealability-Test Results. parameters of the second-generation Connection Samples. Three second- The structural/sealability tests were per- CT, such as dual-radius thread form generation-CT-connection samples formed between 8 March and 20 April of that enhances connection fatigue per- were machined from 7½-in.-diameter 2013. The samples were tested individu- formance and optimized taper, pitch, 4130M bar-stock material that was ally, with Sample 3 being the first one and thread height, are identical to those quenched and tempered to achieve min- tested, followed by Sample 1 and then found on the third-generation DSC. The imum yield strength of 135,000 psi. Sample 2. Each sample was assembled verification of the second-generation Each of the three samples was machined with the test fixtures and external vessel CT design involved FEA and a rigorous to meet specific critical tolerance con- making up the test apparatus and then physical test program. figurations. An additional sample was installed in a load frame with an axial- Higher tool-joint yield strength al- machined from the same material for load capacity of 3,400 kips in both ten- lowed the optimization of the connec- each tolerance configuration (three sion and compression. tion’s taper and thread height to in- spare samples in total) in case one or Because the test apparatus was con- crease stabbing depth, which reduced more of the original samples were dam- structed in such a way that no leak path the number of turns from stab to aged at any point in the testing process. was possible from the interior to the makeup as compared with the first- Structural/Sealability-Test-Program exterior pressure chambers, a pres- generation CT. The deeper stab depth Load Points. The structural/sealability- sure change between the inner bore provides increased stability as the pin test-program load points were designed of the sample and the external ves- connection is first rotated, which re- to replicate various load combinations sel could be attributed only to leakage duces the chances of cross-threading. to which the connections could be sub- across the sample connection. As such, Additionally, deeper stab reduces the jected during installation and opera- connection-sample-sealability perfor- likelihood of creating pinch points, in- tion in offshore HP/HT applications. The mance was assessed by monitoring the creasing operator safety. load points for this program subject- pressure differential across the connec- A comprehensive FEA (detailed in the ed the connection samples to net axial tion. None of the three samples tested complete paper) was conducted to op- loads between 1,100 kips in tension and showed any signs of leakage across their timize the design and evaluate the per- 215 kips in compression; temperature connections under a net external or a formance of the second-generation-CT up to 220°F; bending loads to create a net internal pressure differential. JPT

JPT • JUNE 2016 71 Stuck-Pipe Prediction With Automated Real-Time Modeling and Data Analysis

real-time method is presented to drillstring, drilling fluid, and the indications of impending stuck pipe. A Apredict impending stuck pipe with wellbore itself moving-average smoothing technique sufficient warning to prevent it. The Q Fit within a logical progression was implemented to represent the entire new method uses automated analysis of that can indicate impending sample as a single value. real-time modeling coupled with real- stuck pipe Implementing depth-based analy- time-data analysis. It can be applied to Comparison of the commonly avail- sis is relatively straightforward when all well types for any well operation. able data sets with these criteria yield- the bit is on bottom and the hole is The new method combines two types of ed the following list, divided into being drilled. But depth-based analysis analysis: (1) deviation of real-time data three categories. is much more difficult when also con- from real-time model predictions by Q Inputs: parameters directly sidering off- bottom activities, such as use of hydraulics and torque-and-drag controlled by the driller at surface tripping and reaming, where the bit may software, and (2) trend analysis of real- o Flow rate in pass the same depth on multiple occa- time data. o Surface rotary speed sions and significantly different sensor o Surface weight on bit values may be recorded. This complex- Data Types and Frequency Q Outputs: measurements that ity required that the incoming time- The approach taken was to first study record the well’s response to indexed data be separated into depth- real-time data sets from wells in which the inputs indexed subgroups on the basis of the stuck-pipe incidents occurred and deter- o Pump pressure rig activity being performed. Alerts mine the root cause of each. The major- o Surface rotary torque would not be generated until the mov- ity of these wells were drilled between o Hookload ing averages for deviation from model 2009 and 2013 in the Eagle Ford shale. Q Others: parameters that provide and rate of change exceeded predefined Specific patterns in the data were then significant value but do not thresholds. The historical stuck-pipe- identified as potential leading indicators necessarily fit the input-vs.-output incident data set was used to determine of stuck pipe. relationship these thresholds. This was performed One of the first issues identified was o Equivalent circulating density by calculating the actual deviation from that the type, frequency, and quality of (ECD) plan and actual rate of change for the data available are not consistent from The various parameters in the wells previously described key parameters in well to well. To ensure that the alert- used in this analysis were primarily re- wells where stuck-pipe incidents were ing system was configured to work on corded at a frequency of one data point known to have occurred. If these values different well types with a high degree per 5 seconds (0.2 Hz). surpassed certain thresholds only when of functionality, the decision was made approaching the stuck-pipe incident, that it would be designed to monitor Methodology those thresholds should be the values a well and provide alerts even if only The first decision was that alerts would that are used to generate alerts. “critical” data streams are available. not be generated from single-point As expected, it was determined that These critical streams would meet the values. Instead, they would be based the magnitude of the thresholds varies following criteria: upon a representative sample of data from well to well. This means that there Q Available on most rigs capable of over a given time/depth interval. The is not always a single value beyond which capturing real-time data authors’ early work used the deviation a deviation from model/rate-of-change Q Be useful in determining from plan and rate-of-change behavior calculation should generate an alert. Fur- information about the over 25-ft depth intervals to search for thermore, some wells showed the stron- gest indicators of impending problems in deviation from model data, while rapid This article, written by JPT Technology Editor Chris Carpenter, contains highlights of rate of change was the strongest indica- paper SPE 178888, “Stuck-Pipe Prediction Using Automated Real-Time Modeling and tor in others, although neither type of in- Data Analysis,” by Kent Salminen, SPE, Curtis Cheatham, SPE, Mark Smith, SPE, dicator could be relied upon to be present and Khaydar Valiulin, SPE, Weatherford, prepared for the 2016 SPE/IADC Drilling in all incidents. Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not The authors’ solution was to com- been peer reviewed. bine these values into a single stuck-

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72 JPT • JUNE 2016 pipe-risk curve, which would be scaled Case History— served. The rig crew was able to pull the from 0–100%. Time-Based Alerting BHA through the obstruction, but, less Once the method was coded into the soft- than 60 ft later, another obstruction was Stuck-Pipe-Risk Calculation ware, a number of tests were run using encountered. The BHA became irretriev- In the absence of a downhole pressure recorded real-time data from wells in ably stuck during this second event. Both sensor used to measure ECD in real time, which stuck-pipe incidents were known the near-miss and the final sticking point the following parameters are combined to have occurred. The data were replayed were considered valid for testing. to calculate stuck-pipe risk: from a WITSML server to replicate the The stuck-pipe risk from 22:40 to 23:00 Q Torque deviation from model way that the software would receive the was less than 10%. This was the case for Q Hookload deviation from model data during an actual drilling operation. nearly the entirety of the lateral section Q Pump-pressure deviation from The goal was to determine whether the leading up to this point. The risk level model following criteria were met: reached a maximum of 54% while back- Q Torque rate of change Q The stuck-pipe-risk calculation reaming at 02:48, and the near-miss event Q Hookload rate of change should remain comparatively low occurred at 03:36. The warning time in Q Standpipe-pressure rate of change during normal operations when no this case was 48 minutes, which was con- For each of these calculated values, problems occurred. sidered sufficient time for the rig crew to there is a threshold below which the data Q Stuck-pipe risk should increase have been notified of the increasing risk. are considered to be within an accept- leading up to the known stuck-pipe The rig crew worked through the near- able range. A table with maximum allow- event. miss incident and were able to move the bit able values similar for each parameter Q The increase in stuck-pipe risk another 60 ft before the pipe became fully was created. should occur sufficiently earlier than stuck. Average stuck-pipe risk reached a Negative values indicate that calculat- the stuck-pipe event itself so that maximum value of 63% at 04:10, which ed deviations and rates of change should the rig crew could have conceivably was 27 minutes before the point at which be greater in magnitude to be consid- taken a mitigating action if they were the bit could no longer be moved. This ered normal. The risk of impending stuck alerted to the problem. was, once again, viewed as sufficient time pipe increases if the calculated trend falls The first test well was drilled in a US to warn the crew of the impending risk below the specified threshold. For posi- onshore shale play. After landing in the and allow them to take a mitigating ac- tive values, deviation and rate of change upper target zone, lost circulation was tion. It was also considered a positive that should remain less than the threshold to observed and the operator elected to pull the risk was higher for the actual sticking be considered normal. out of hole to run a contingency liner and event than for the near-miss. JPT As the stuck-pipe-risk calculation isolate the loss zone. On the trip out of system receives time-based wellsite- hole, the drilling bottomhole assembly information-transfer standard-markup- (BHA) became stuck in the vertical sec- One Stop for language (WITSML) data, an algorithm tion of the wellbore while backreaming Everything JPT automatically assigns a rig activity to near the intermediate-casing shoe. each row of incoming data. This allows The first point at which the average Get all your online JPT all rotary-drilling data, for instance, to stuck-pipe risk exceeded 50% occurred content in one place at be grouped together. This is important at 20:02 (11 minutes before the actual www.spe.org/jpt because of the way that model output stuck-pipe event). The average risk for Responsive Design curves are structured. These programs the preceding 24 hours of normal opera- yield predicted values for a specific pa- tions was approximately 12%. This test SPE members can access rameter vs. bit depth. The hole depth is was considered successful. the latest issue of JPT not a model input. This means that if the The next test well was also drilled in a from any of their devices. bit depth and rig activity for each incom- US onshore shale play. Drilling conditions Optimized for desktop, ing line of WITSML data are known, then were stable until the bit was approximate- tablet, and phone, JPT is all of those data can be correctly assigned ly 75 ft from total depth, at which point easy to read and browse to the corresponding predicted curve. the driller had difficulty achieving enough anytime you are online. The next step is to calculate the devia- weight on bit to drill ahead. Torque also tion and rate-of-change values for that became erratic. After reaching the planned particular point; this procedure is cov- total well depth, the rig crew began to ered in detail in the complete paper. backream out of the hole. The plan was to Offline Access During the development of the stuck- continue backreaming until the horizontal pipe-prevention method, a software section of the well was considered clean, Download PDF versions package was released that would serve as at which point the drilling BHA would be of 180+ issues dating a platform for real-time drilling engineer- pulled out of hole on elevators. Once the back to 1997 for reading ing and optimization. This software in- bit was approximately 100 ft off-bottom, online or when an cludes a number of features that required a near-miss incident occurred where sig- Internet connection is the method to be modified slightly. nificant overpulls (60–70 kips) were ob- not available.

JPT • JUNE 2016 73 TECHNOLOGY FOCUS

EOR Operations Stephen Goodyear, SPE, EOR Deployment Lead, Shell

A seminal event last year was the Cli- Even though conditions in and so something of a virtuous circle mate Change Conference in Paris, where might exist. The use of CO2 captured participating countries agreed to reduce the industry remain very for greenhouse-gas-management rea- their carbon output “as soon as possible” tough at present, EOR is sons can enable more-widespread gas- and to do their best to keep global warm- injection EOR. CO EOR can provide expected to be increasingly 2 ing “to well below 2°C.” History will be secure CO2 storage and additional rev- the judge of whether 2015 turns out to be important in the future, with enues, accelerating the implementation a turning point in the journey to reducing of carbon capture and ultimately the global warming. There is still a long way the possibility of significant building of a commercial CCS industry to go to turn good intention into substan- further uptake of gas- that can help realize the aspiration of net tive action if the world is to transition to injection EOR linked to the zero carbon emission fossil fuels. a low-carbon economy and ultimately to Even though conditions in the indus- one of net zero carbon emissions. This climate-change agenda. try remain very tough at present, EOR challenge is all the tougher given increas- is expected to be increasingly important ing demand for energy, with the Interna- in the future, with the possibility of sig- tional Energy Agency expecting growth key differentiator of gas injection, com- nificant further uptake of gas-injection by one-third between 2013 and 2040. pared with other EOR techniques target- EOR linked to the climate-change agen- In the US, there has been a gradu- ing light oils, is the ability to overcome da. As ever, SPE continues to have a key al shift in the balance of enhanced-oil- some of the variability in reservoir geolo- role in disseminating best practices and recovery (EOR) production between gy by recycling back-produced injectant. project learnings. JPT thermal and gas-injection projects. Since The deployment of gas-injection EOR 2006, production from gas injection has is limited by the availability of gas; where outstripped that from thermal, and it there is access to a gas market, the use of Recommended additional reading is continuing to grow. Worldwide, gas- hydrocarbon gas is generally not attrac- at OnePetro: www.onepetro.org. injection EOR is established as a suc- tive, and carbon dioxide (CO2) is not cessful, robust, commercial technology widely available at acceptable prices. SPE 169513 Case Study: Steam-Injection Step-Rate Test Run in the Shallow Low- deployed in a wide range of operating Carbon capture and storage (CCS) Permeability Diatomite Formation, Orcutt conditions from onshore to shallow off- is a mechanism that can facilitate the Oil Field, Careaga Lease, Santa Barbara shore and, more recently, deep water. A transition to a low-carbon economy, County, California by Ramon Elias, Santa Maria Energy, et al.

SPE 174700 On the Road to 60% Oil Stephen Goodyear, SPE, is EOR deployment lead for Shell’s Recovery by Implementing Miscible Upstream International region. He has 30 years of experience as a Hydrocarbon WAG in a North African Field reservoir engineer, principally working in EOR. Before joining Shell by I. Maffeis, Eni, et al. in 2002, Goodyear worked for an oil and gas consultancy and, SPE 177697 Use of an Integrated during his career, has performed a wide variety of roles, including Approach To Optimize a Congested roles in research and in field-development planning. He is a Shell Brownfield Facilities Development subject-matter expert for gas injection and has a particular inter- by C. Roberts, S2V Consulting, et al. est in next-generation CO2 EOR projects and carbon capture and storage. Goodyear holds an MMath degree from Cambridge University and a PhD SPE 174656 Nano Spherical Polymer JPT Pilot in a Mature 18 °API Sandstone degree in physics from the University of Edinburgh. He is a member of the Editorial Reservoir Waterflood in Alberta, Canada, Committee and can be reached at [email protected]. by Randy Irvine, Harvest Operations, et al.

74 JPT • JUNE 2016 Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore Environment

ydrocarbon-gas injection nificant amount of hydrogen sulfide. All was located in the waterflooded tran- Himproves microscopic- three reservoirs have common contact sition area of Reservoir B. Oil was pro- displacement efficiency and generally and similar oil properties, with a strong duced with the long string of producer acts as pressure maintenance; however, compositional gradient. Production from Well P-1. The long string of observer Well unfavorable mobility ratio can affect the field started in the late 1960s through Obs-1 was used to monitor the vertical the ultimate recovery negatively natural depletion, which indicated weak gas efficiency and pressure. Gas was in- because of viscous fingering and aquifer support. jected from the horizontal injector Well gravity override. This paper describes Before pilot implementation, labora- I-2, which is perforated at the lower part a gas-injection pilot that has been tory experiments were performed to de- of the reservoir and is approximately implemented in offshore Middle East termine the feasibility of hydrocarbon- 2,300 ft in length. The producer well is carbonate reservoirs (a second pilot gas injection. Pressure/volume/tem- located 2,360 ft away from the midpoint is described in the complete paper) perature experiments showed that the of the horizontal section of the injector, to assess injectivity, productivity, minimum miscibility pressure (MMP) while the observer is located 460 ft away macroscopic-sweep efficiency, flow is approximately 4,500 psia, which is from the injector. assurance, and operational efficiency higher than initial reservoir pressure, A tight zone is located 5 ft above the in a field that has a long water- but the crude oil has a strong swelling base of the reservoir, and there are two injection history. effect. Unsteady-state coreflood experi- high-permeability streaks in the middle ments performed with a 200-cm-long of the formation in the producer Well P-1. Introduction core showed a recovery of 70% for im- The average oil saturation in the pilot The carbonate field is part of the Lower miscible flood and a recovery of 92% for area is estimated to be approximately Cretaceous Lower Lekhwair formation. miscible flood. 0.30 units, through a different set of The field is divided into A, B, and C reser- Full-field compositional simulation logs. Pressure measurements showed a voirs, 20 to 35 ft thick individually. Each of gas injection incorporating a tuned 0.057-psi/ft pressure gradient toward the reservoir is vertically separated by non- equation of state indicated signifi- producer, owing to historical peripheral- pay tight intervals of similar thickness, cant incremental oil and reasonable water-injection field development. composed of argillaceous limestone, iso- pressure support. The average pressure measured in the lating each reservoir from the others. De- pilot area is approximately 4,900 psia, pending on the reservoir, oolitic shoal Pilot Description which is higher than the MMP of inject- facies can be more abundant. Near the In Reservoir B, tertiary injection was per- ed gas. flank area, the formation is water-wet, formed in the transition zone, close to Injection/Production Performance. and, as one moves toward the crestal the oil/water contact in an area that had The gas injection was initiated in March area, the formation becomes oil-wet. already experienced peripheral water in- 2002, with an average monthly injec- The reservoir fluid is undersaturat- jection. Injected gas was from the first- tion rate of 15 MMscf/D over the first ed at initial pressure of 4,200 psig at stage separator. 3 months, followed by a rate increase to datum depth and a temperature of 220°F. 25 MMscf/D, then a gradual reduction Oil gravity is 40 °API, and oil contains Pilot B: Description and Performance. to 10 MMscf/D after gas breakthrough. 1–2 mol% carbon dioxide and an insig- Pilot B was also a line-drive pilot, but 20 Bscf of gas was injected during this duration, corresponding to 1.49-pore- This article, written by JPT Technology Editor Chris Carpenter, contains highlights volume injection. of paper IPTC 18513, “A Case Study on Miscible and Immiscible Gas-Injection Pilots Because the pilot was located in a tran- sition zone that had already been water- in a Middle East Carbonate Reservoir in an Offshore Environment,” by Jitendra flooded, the producer showed oil produc- Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company, tion of 300–400 STB/D with 80% water prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, cut immediately after commencement of 7–9 December. The paper has not been peer reviewed. gas injection. After 1 year of injection, the well showed an increase in oil production Copyright 2015 International Petroleum Technology Conference. Reproduced by with decrease in water cut, indicating ar- permission. rival of the oil bank and the effectiveness

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JPT • JUNE 2016 75 Sg Sg Sg Sg Sg Sg 0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 0 0.2 0.4 0.6 0.8 True Vertical Depth Subsea Vertical True

August 2002 November 2002 August 2003 June 2004 July 2005 December 2005

Fig. 1—Gas saturation from simulation model at Obs-1. Sg=gas saturation.

of gas injection. However, gas/oil ratio values were found in the dense zone. The of three-phase fluid movement, and it (GOR) then increased rapidly, indicat- sampling performed at the top and bot- can be used to predict the areal and verti- ing gas breakthrough in July 2003, after tom of the formation observed 100% cal efficiency of this miscible pilot. only 1.5 years of injection. The produc- gas, indicating the presence of residual Areal and Vertical Sweep. Because er well was closed in April 2004 because oil saturation in the vicinity. of the lack of nearby wells around the of surface-facility constraints. Neverthe- Asphaltene deposition was not ob- pilot area, it was difficult to assess areal- less, the well was tested biannually to served in Pilot B producers. This may be sweep efficiency with high accuracy. Sim- monitor gas movement. attributed to low asphaltene content in ulations are in agreement with water-cut Monitoring Performance. The pres- the crude oil (0.1 wt%) as well as lower observations for Well P-1. Water cut de- sure survey of the producer and observer oil saturation owing to the fact that oil creases after start of gas injection in both confirmed that, during the whole peri- has already been swept by water in the simulations and pilot results. od of injection, there was good pressure zone around gas-injection Pilot B. The gas breakthrough occurs from the support in the pilot area and the pres- high-permeability streaks that are locat- sure always remained higher than the History Match of Pilot B. Model De- ed in the middle of the formation. The #/ 1 -
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76 JPT • JUNE 2016 lenges that affect recovery are gravity ry gas injection. WAG injection not only Q The vertical-sweep efficiency segregation and reservoir heterogeneity. produces extra oil but also reduces by half was affected by reservoir The Pilot B history-matched simu- the amount of gas required. The WAG- geology as Pilot B observed lation model was used to evaluate the injection gas-usage factor, the amount of early gas breakthrough benefit of water-alternating-gas (WAG) gas required to produce one unit of oil, is through high-permeability -injection implementation instead significantly lower than that for tertiary streaks. of tertiary gas injection in the Pilot B injection. Moreover, WAG injection can Q A good history match of area. A WAG-injection ratio of 1:1 and a be optimized further by reducing gas vol- both pilots has been obtained, 6-month cycle were used for the screen- ume (tapering) in later cycles. suggesting that miscible ing study. In this model, hysteresis and injection occurred in Pilot B. gas-trapping effects are not considered Conclusions Tertiary miscible injection of because laboratory experiments have Q A gas-injection pilot was conducted Pilot B recovered an additional not yet been performed to evaluate these in a Lower Cretaceous carbonate 16% of stock-tank oil in place parameters. The operational constraints formation. Improvement in compared with waterflooding. of Pilot B are used in the model—that pressure support and production Q Gas injection in WAG mode is is, a GOR limit of 15 Mscf/STB and water performance was observed in a possible solution to control cut of 95%. the pilot. mobility and improve recovery. When considering the performance Q Pilots have been carried out in the Simulations performed on comparison of tertiary Pilot B and WAG flank area, where the pressure the history-matched model injection, WAG injection recovers signifi- gradient, owing to peripheral water using a WAG-injection strategy cant additional oil with the same opera- injection, significantly affects the give higher oil recovery with tional constraints compared with tertia- gas movement and behavior. lower GOR. JPT

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+*'4( - Case Study: Steam-Injection Step-Rate Tests Run in the Orcutt Oil Field

he operator has initiated a cyclic- without loss of steam-injection contain- in the complete paper). The FPR can be Tsteam-stimulation (CSS) project ment. Steam injection was resumed when unique to the injection fluid that is used. in the Opal A diatomite of the Sisquoc it was determined to be safe to do so, and In general, an SRT consists of a series formation on the Careaga lease in matrix flow was re- established. To this of constant-rate injections with rates in- the Orcutt oil field in Santa Barbara end, two operational procedures exist for creasing from low to high in a step-wise County, California. The operator has analyzing data as part of the operator’s ef- fashion following a period of reservoir received entitlement to proceed with an forts to improve steam-injection practices stabilization. Each constant-rate step is expansion consisting of 110 additional further and to improve understanding of normally run over approximately equal new wells. This paper discusses steam- the mechanisms leading to oil produc- lengths of time. injection step-rate tests (SRTs) for tion. One is taken from common water- A discussion of SRT analysis by use of this asset. flood surveillance practices and graphi- Hall’s method is provided in the com- cally displays changes in flow resistance plete paper. Introduction during injection, aimed at indicating if The target zone contains high oil content formation parting or a loss of steam con- Analysis of Field Data ranging from 1,800 to 3,000 bbl/acre-ft finement is initiating. The other is analy- Two field-test examples are present- in massive intervals with 200- to 700-ft sis of the pressure falloff observed dur- ed that compare the utility of analyzing thickness at depths of 600 to 1,000 ft ing the soak period between injection and SRTs with the conventional method and and with a permeability of 5 to 15 md. The production, a period intended to allow Hall’s method. The tests were performed pilot currently consists of 19 cyclic-steam- pressures and temperatures to dissipate on Wells 1615 and 1715 in May of 2012 injection wells configured in a 4×5 matrix away from the vicinity of the well and into (results for Well 1615 are presented in spaced approximately 120 ft apart, pro- the producing zone. the complete paper). All steam-injection ducing from an average depth of 925 ft. rates are expressed in barrels of cold- A supervisory control and data- General SRT Approach water equivalent per day (BCWE/D). Posi- acquisition system is used to control and The objective of an SRT is to deter- tive rate values denote injection. monitor various aspects of field oper- mine the pressure at which resistance ations, especially the steam- injection- to flow within the rock matrix suddenly Well 1715 Results. An eight-step SRT was process protocols. Relatively low steam- decreases as the formation is subject- run on Well 1715 on 12 May 2012. The injection rates of 250 to 450 B/D cold- ed to increasingly higher fluid-injection total duration of the test was approxi- water equivalent are used with 70% rates. That point is said to be detect- mately 16.5 hours after the well had been constant- quality steam. Steam-injection able when the injection pressure exceeds shut in for approximately 1 hour. The per- pressures and rates have been monitored formation-parting pressure (FPP), which forations were from 934 to 974 ft (40 ft closely throughout the process since creates increased fluid conduction. This total). The productive interval is approxi- startup in October 2009. effect produces a reduction in the slope mately 250 ft thick. A total of 28 CSS cy- More than 1,000 steam-injection cy- of the pressure-vs.-flow-rate curve. The cles were performed on the well before cles have been completed as of this paper’s values of pressure and flow rate corre- the SRT was performed. The recorded writing. For all cycles, the onset of forma- sponding to the point where the two lines SRT data are presented in the complete tion parting has been detected less than intersect in the pressure-vs.-flow-rate paper; the generalized SRT plot is shown 0.5% of the time. In all detected events, curve are called the FPP and formation- in Fig. 1. Trendline 1a shows a slight- steam injection was adjusted or halted parting rate (FPR), respectively (see Fig. 1 ly different trend and slightly different y-intercepts compared with Trendline 2a (or 170 vs. 150 psi, respectively), and the This article, written by JPT Technology Editor Chris Carpenter, contains highlights of slopes are similar. As the test continues, a paper SPE 169513, “Case Study: Steam-Injection Step-Rate Tests Run in the Shallow small and constant separation is noticed Low-Permeability Diatomite Formation, Orcutt Oil Field, Careaga Lease, Santa between Trendlines 1a and 2a. Trendlines Barbara County, California,” by Ramon Elias and Ian Marquardt, Santa Maria 1b and 2b appear almost as overlays. Energy, and Mason Medizade, California Polytechnic State University, prepared for The intersection point of Trendlines the 2014 SPE Western North American and Rocky Mountain Joint Regional Meeting, 1a and 1b or 2a and 2b marks the pres- Denver, 16–18 April. The paper has not been peer reviewed. sure and rate at which parting occurs. As

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78 JPT • JUNE 2016 1,200 Slope 1b 1a/1b Intersect y=0.1676x+991.43 1b R²=0.9867 1,100 (316 BCWE/D, 1,044 psi)

1,000 2b Slope 2b 900 Slope 1a 1a y=0.1508x+996.65 ²= y=2.7665x+170.37 R 0.8525 ²= 800 R 0.9706 2a/2b Intersect 2a (322 BCWE/D, 1,045 psi) 700 Slope 2a y=2.7766x+150.21 600 R²=0.9473

500 Injection Pressure (psi) 400

300

200

100

0 0 100 200 300 400 500 Injection Rate (BCWE/D) Fig. 1—Well 1715 generalized SRT plot. shown in the figure, the intersection of of partial plugging. In comparison, the or equal to the overburden stress. The these trendlines occurs at nearly the same corresponding Hall-plot-slope trend- measured FPP can exceed the overburden point, or an FPP of 1,044 and 1,045 psi, line for Well 1615 is approximately zero. stress if positive skin is present during respectively. The corresponding FPRs are This could indicate that the observed the SRT. Skin effects have been detected 316 and 322 BCWE/D, respectively, for parting reactions in Well 1715 may have and observed. nearly constant 70% steam quality. As been caused by steam breaking through These results say that positive skin ef- seen in Wells 1615 and 1715, approximate- a plugged zone rather than parting of the fects warrant further analysis and re- ly the same intersections are obtained re- formation itself. Additionally, the fact view. Leakoff tests during drilling may gardless of the data sets used. that the Hall-plot slope did not recover to provide more insight. The latter must be In the corresponding Hall plot, pre- levels seen early in the test suggests that performed with great care; the operator’s sented in the complete paper, a continu- the formation itself may not have parted. experience at Orcutt has been that leakoff ous period of increasing flow resistance is tests will produce borehole weaknesses seen throughout from 0 to approximate- Overburden Stress. Openhole logging that cause troublesome loss of circula- ly 130 BCWE of cumulative steam injec- data from the operator’s Orcutt diatomite tion while drilling and cementing. tion. A brief period of stable flow occurs wells show that the overburden gradi- from approximately 130 to approximately ent with respect to depth is between 0.75 Conclusions 155 BCWE, followed by an abrupt drop in and 0.76 psi/ft. This is based on openhole Q The point at which formation the Hall-plot slope, indicating parting at density/porosity-log data and sidewall- parting occurs within the Opal A can approximately the start of Step 7. core grain-density measurements taken be seen by conducting an SRT using Formation parting that occurred at ap- from 15 wells located in close proxim- steam. However, because of several proximately 155 BCWE had an observed ity to the SRT wells. The corresponding potential factors, the corresponding parting pressure of 1,038 psi. This value overburden stress is equal to the prod- FPP is not necessarily correct. compares favorably with the values of uct of the overburden gradient (psi/ft) Q Flow constrictions, partial 1,044 and 1,045 psi computed from the and vertical depth (ft). The calculated plugging, and other factors can generalized SRT plot. overburden-stress values are 719 and mask the true FPP recorded during The Hall plot gives a much differ- 709 psi for Wells 1615 and 1715, respec- an SRT using steam. ent profile for this well than for Well tively. In comparison, the corresponding Q Effective real-time monitoring 1615. What can be characterized as par- FPPs measured from the SRT are approx- and analysis help provide a safe tial plugging can be seen over more of imately 1,050 and 1,040 psi, respectively, and effective steam-injection- the test before the formation parting oc- a difference of 331 psi for both. management program and improve curs. The trendline before the parting Barring tectonic or other complicat- understanding of CSS behavior in has an increasing slope, characteristic ing factors, the FPP should be less than the diatomite. JPT

JPT • JUNE 2016 79 Polymer Injection in Deepwater Field Offshore Angola

he polymer-injection project Tin the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects. Thorough, integrated geoscience and architectural studies led to the decision to initiate a polymer-injectivity test on a single well, followed by a continuous injection of polymer on one of the four subsea lines delivering water to the field. The complete paper describes the main results of the pilot phase. Fig. 1—Dalia field subsea development layout. Introduction A subsea development scheme with Dalia Reservoir Dalia Polymer Project water injection for full pressure mainte- The field is developed by water injection, Different options were considered to nance was chosen for the Dalia field to- using a floating production, storage, and demonstrate polymer efficiency in a gether with gas reinjection. Very early in offloading (FPSO) vessel with 28 devi- shorter time than 3 to 4 years after the the geoscience studies, oil viscosity was ated or horizontal subsea injector wells first pilot phase began, and thus move identified as the main limiting factor to and four injection flowlines (plus three ahead the sanction of the extension by water-injection recovery. Polymer injec- gas-reinjection wells active before An- 1 to 2 years. tion was positively screened as a poten- golan liquefied-natural-gas startup). A Eventually, it was proposed to drill an tial enhanced-oil-recovery method for single flowline generally injects into sev- infill sampler well close to a viscosified- the field. eral reservoirs as well as several systems. water injector in the pilot area, with an Extensive feasibility studies of poly- Maximum yearly average water injection additional production target in a deeper mer flooding were initiated in 2003, is 360,000 BWPD. Desulfated seawater horizon. The main objectives of this sam- 3 years before production start-up. A has been injected since startup to prevent pler well were twofold: (1) sample the vis- phased approach was chosen to as- any barium sulfate deposition, and all the cosified water in the top layer swept by sess and reduce the main uncertain- produced water is reinjected. viscosified water and (2) produce unde- ties of the project, consisting of the Production is achieved through four veloped bottom layers. construction of a powder-polymer production lines and 40 producers. solution-preparation skid, a single-well First oil was on 13 December 2006. The Full-Line Polymer Injection injectivity test, a longer injection period 240,000-B/D oil-production plateau was Full-line polymer injection officially through one of the injection lines (sup- reached after a few months, while, at the began on 8 February 2010, with injection plying three wells), and the drilling of a time of this writing, 8 years after startup, on the flowline that exclusively served sampler/producer well to assess in-situ the field is still producing at a reduced the Camelia reservoir at that period of viscosity, while continuing surface and plateau rate of 200,000 BOPD. A sche- time. Polymer injection was stopped in subsurface studies. matic of the layout is provided in Fig. 1. August 2012, after 7 million cumulative bbl of viscosified-water injection had been achieved. Polymer concentration This article, written by JPT Technology Editor Chris Carpenter, contains highlights was approximately 900 ppm, and a max- of paper SPE 174699, “Dalia/Camelia Polymer Injection in Deep Offshore Field, imum of 5 t/d of polymer was injected. Angola: Learnings and In-Situ Polymer-Sampling Results,” by D.C. Morel, E. Zaugg, Still, the skid operability was not ideal. S. Jouenne, J.A. Danquigny, and P.R. Cordelier, Total, prepared for the 2015 SPE The skid uptime was greater than 80%, Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not but at the expense of intensive efforts been peer reviewed. from the operational teams, and the

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80 JPT • JUNE 2016 maximum operating rate was 10% below This effort is described in detail in the Results specifications. Valuable learnings have complete paper. The origin of such degradation was inves- been acquired during this pilot phase. tigated, and additional laboratory tests Long-term injectivity has proved to be BHS. BHS was performed in mid-2012 were completed. There are three main excellent on the horizontal wells. to prevent any possibility of mechanical sources of potential degradation of the Injectivity on deviated wells was ex- degradation during the sampling. The polymer solutions: cellent when polymer solution was di- objective of the sampling was to measure Q Biodegradation. In the presence luted with desulfated water, but a sig- the actual in-situ properties of the poly- of bacteria, hydrolyzed nificant injectivity-index decrease was mer injected from the FPSO vessel after polyacrylamides (HPAMs) are observed abruptly in August 2010 on de- propagation in the reservoir and to con- stable. Compatibility of the viated Well DAL-713. Several attempts clude the Dalia polymer pilot (Phase 1). polymer with the injected biocide were made to restore the injectivity by The tool had been tested previous- was checked. injecting slugs of desulfated seawater, ly onshore and was adapted to polymer Q Chemical degradation. For but the initial injectivity index was never sampling. A special jet was used to limit various reasons, both types of recovered. Still, it remained stable after- the flow rate during the suction of the chemical degradation—oxidative ward until the end of the polymer injec- sample and to prevent the polymer from and thermal degradation—were tion. This injectivity-index decrease has mechanical degradation. Sampling was discarded as factors. been attributed to the poor quality of the simulated onshore by working with a Q Mechanical degradation. Because produced water used at that time to di- fluid at the same pressure as the reser- of the elongational component of lute the polymer solution. voir. As for the MDT operation, sampling the flow when passing through a and transfer bottles, along with trans- porous medium, HPAM chains are Polymer Sampler fer bench lines, were carefully flushed stretched in the flow direction. Drilling operations began in mid-2011. with ultrapure gas to prevent the samples At a high strain rate, breakage The sampler well was drilled near a from oxygen contamination. of multiple chains occurs, which viscosified-water injector (approximately One run of four bottles was performed results in a viscosity loss. For a 80 to 190 m), and was located behind the on both CX13A and CX13B zones with given flow geometry, strain rate polymer front, according to 4D-seismic coiled tubing from 16 to 19 July 2012. is correlated with the shear rate. monitoring. Two sidetracks had to be Out of eight samplers, only seven were For that reason, mechanical drilled because the completion could not recovered, because one sampler failed. degradation in a given geometry be run owing to clay instabilities. Four bottles were analyzed directly on can be predicted from shear-rate In summer of 2012, the sampler the Dalia FPSO vessel, while three were estimation. well was eventually completed in one not opened and were sent to France for The choke at the sea bottom was the zone (CX13A) for water- and polymer- further analysis. most-shearing equipment. Degradation sampling purposes and in another zone tests were performed on a 6-in. Dalia (CX8) for oil-production purposes, with Characterization of BHS Solutions. choke valve. Results indicated that deg- a 5½-in. standalone screen, including a The analyses performed on the Dalia radation is a function of the pressure mechanical sliding sleeve, to allow iso- FPSO vessel and in France revealed that drop through the choke. At greater than lation of the upper reservoir during the Q The polymer was present in each 5 bar, the polymer degradation is higher production of the bottom reservoirs. zone: CX13A, CX13B, and CX12. The than 50%. During polymer injection, it measured polymer concentration was thus necessary to work with chokes Polymer Sampling was in the same range as that of the fully opened to prevent the polymer A detailed study was undertaken in the injected solution (approximately from extensive degradation. (A meth- operator’s laboratories to check that rep- +790/−30 ppm active polymer). odology to assess mechanical degrada- resentative samples of the in-situ poly- Q The average salinity was 41 g/L, tion at the sandface is provided in the mer solutions could be taken with exist- close to the salinity of the injected complete paper.) ing sampling tools and that all analytical solution. On the basis of the Dalia field ex- issues might be solved to measure the key Q The average viscosity on all perience and the operator’s in-house properties of the solution. While bottom- samples was +1.4/−0.2 cp at expertise, mechanical degradation hole sampling (BHS) after the comple- 17 s–1, corresponding to an average at the near-wellbore region is consid- tion of the well was clearly identified as degradation of +75% /−6 %. ered to be the main source of poly- the preferred and most-representative Additional degradation was found mer degradation. This degradation is sampling procedure for these particular- on MDT samples. Mechanical degrada- caused by permeability impairment ly delicate operations, a first attempt was tion would have occurred at the probe (as observed on the DAL-753 samples) carried out to collect samples by means entrance during the MDT sampling be- that is a result of the poor quality of of a modified modular-dynamic-tester cause of the passage through a plugged the injected produced water. This re- (MDT) device (in reverse, low-shock con- probe. During the operation, inline vis- sult highlights the important role that figuration) in open hole just after the cosity measurements were revealed to near-wellbore damage can play in poly- drilling phase of the well (in mid-2011). be inefficient. mer degradation. JPT

JPT • JUNE 2016 81 Colloidal-Dispersion Gel in a Heterogeneous Reservoir in Argentina

1000 he Loma Alta Sur (LAS) field is Oil (m3/d) LAS-1, LAS-2, and LAS-10 converted to injectors Ta multilayer fluvial sandstone Water (m3/d) Injection reservoir in the Neuquén basin of 31 50 22 Argentina. Reservoir heterogeneities 18 58 and an adverse mobility ratio (30-cp oil) 66 led to an early water breakthrough soon 49 26

/d 10 53 after water injection started. Colloidal- 3 100 68 dispersion-gel (CDG) injection was m 27 67 7 Waterflood oil trend 46 69 considered a viable strategy to improve 2 62 oil recovery in the field. 1 CDG Phase II Incremental LAS-58 CDG Pilot Summary oil attributed to CDG Phase III CDG Phase II trend The CDG pilot was implemented in the 10 well conversions LAS-58 injector located on the north-

eastern side of the field. LAS-58 is an ir- Aug-94 Aug-95 Aug-96 Aug-97 Aug-98 Aug-99 Aug-00 Aug-01 Aug-02 Aug-03 Aug-04 Aug-05 Aug-06 Aug-07 Aug-08 Aug-09 Aug-10 Aug-11 Aug-12 Aug-13 Aug-14 Aug-15 regular pattern that began water injec- Fig. 1—Injection and production history of the LAS-58 pattern (10 wells) and tion in 2002, showing an early water map showing wells converted to water injectors. breakthrough. The operator estimates that after 3 years of water injection in the the pore volume of the LAS-58 pilot area. It is important to mention that, after LAS-58 pattern, cumulative secondary Phase I consisted of a small injection vol- CDG injection, several changes were im- oil recovery is only 5.48% of original oil ume intended to test CDG injectivity and plemented in the LAS-58 pilot area as a in place (OOIP). The LAS-58 pattern in- did not affect pilot oil-production re- strategy to optimize waterflood opera- cludes 10 producers: six first-line produc- sponse but definitively contributed to ad- tions (i.e., a workover in Well LAS-7 and ers with well spacing ranging from 138 to justing the polymer concentration used several producers converted into injec- 164 m and four second-line producers. in the pilot through Phases II and III of tors). Taking these changes into account, The first tracer-injection program was CDG injection. projected ultimate incremental oil in the implemented in March of 2003, 3 months The main observation after Phase LAS-58 pattern also included the con- after initial water injection in the LAS-58 II of CDG injection was a very distinc- version of three producers into injec- injector. The fastest tracer breakthrough tive change in the injection profile of tors (Wells LAS-1, LAS-2, and LAS-10) was observed in offset producer LAS-18 the LAS-58 injector. The water-injection (Fig. 1). Wells LAS-1 and LAS-10 were (50 days). However, the amount of trac- flow paths were diverted into the mid- converted in August 2011 and Well LAS-2 er recovered in LAS-18 and LAS-26 was dle (Mandrel 2) and bottom (Mandrel 1) in February 2014. Increases in oil and below 1.5% of the total injected. Pro- zones of the pay zone because of the re- water rates observed in December 2012 ducer LAS-49 showed the second-fastest duction in injectivity in the thief zones were possibly affected by the conversion breakthrough but with a cumulative trac- located at the top (Mandrel 3) of the of these three wells. er recovery of 4%. reservoir. In October 2007, the incre- To estimate performance of the LAS-58 Each of the CDG-injection phases was mental oil production for the 10 offset pattern, hyperbolic decline-curve meth- followed by water injection at similar in- producers was reported as 133,292 bbl, ods were used for each of the 10 offset jection rates. The total volume of CDG in- with a reduction in water production of producers. During the first 20 months jected (62 179 m3) represented 3.06% of 406,949 bbl. of the project (CDG Phase II followed by water injection), several wells showed a positive response. However, the largest oil This article, written by JPT Technology Editor Chris Carpenter, contains highlights response was observed during and after of paper SPE 174704, “CDG in a Heterogeneous Fluvial Reservoir in Argentina: Pilot CDG Phase III. A decrease in oil rates ob- and Field-Expansion Evaluation,” by D. Diaz and N. Saez, YPF; M. Cabrera, InLab; served in June 2014 was attributable to E. Manrique, Consultant; and J. Romero, M. Kazempour, and N. Aye, Tiorco, most of the offset producers being shut in; prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, currently, there is an ongoing evaluation 11–13 August. The paper has not been peer reviewed. to revitalize the LAS waterflood.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

82 JPT • JUNE 2016 Production Response Injection Response interpreted with care when comparing of Individual Wells and Post-Tracer Injection tracer results from both programs. Well-by-well analysis reveals that oil- Changes in water-injection profiles (ver- The second tracer program injected production response in the LAS-58 pilot tical tracer surveys) were determined be- yellow acid in Mandrel 3 (upper layer), area was not uniform. To provide an over- fore and after CDG injection. It is im- tritiated water in Mandrel 2, and am- view of well-production response, Wells portant to mention that the average net monium thyocianate in Mandrel 1. An LAS-18, LAS-49, LAS-50, and LAS-53 were pay of LAS-58 is approximately 38 m. injection profile after CDG Phase II was selected for a more-detailed analysis. Wellhead pressure during the injection obtained a few months before tracer in- Wells LAS-18 and LAS-49 reported profile before CDG injection started was jection began. As expected, the fastest tracer breakthrough at 50 and 112 days, 6 kg/cm2 at a rate of 158 m3/d. The injec- tracer arrival was observed in the upper respectively. Despite an early tracer re- tion profile after CDG Phase II was re- layers because of higher permeabilities sponse, neither well reported the pro- corded at 30 kg/cm2 at an injection rate and the flow distributions observed in duction of polymer during the injection of 162 m3/d. Mechanical problems in the the injection profile. Overall, the second of CDG. Well LAS-18 continued its oil de- LAS-58 injector limited running repre- tracer program confirms production per- cline during Phase II, and incremental oil sentative injection profiles. The injection formance of the CDG projects in LAS-58 was observed 14 months after Phase III of profile of February 2011 was obtained (additional details are provided in the CDG injection. The water/oil ratio (WOR) in the upper sands only because of sand complete paper). of LAS-18 remained reasonably stable accumulation in the middle and bottom After almost 10 years since CDG injec- at 10 until December of 2010. Produc- zones limiting the access of the tool. It tion began, it can be concluded that the tion response of Well LAS-18 suggests can be seen that the injection profile in LAS CDG pilot was technically and eco- that CDG injection reduced the existing the upper sand shows that the water in- nomically a success. However, on the transmissibility with the LAS-58 injec- take is similar to that observed before basis of the lessons learned during and tor. On the other hand, producer Well CDG injection began in July 2005. This after the injection of CDG in the field, LAS-49 showed an increase in oil rate injection profile was run at 105 m3/d with there is room to improve the perfor- after 2 months of CDG Phase II operation. a wellhead pressure of 45 kg/cm2. How- mance of this chemical enhanced-oil- However, in early 2008, WOR showed a ever, the upper sand (Mandrel 3) of the recovery method in LAS and, potential- sharp increase, requiring a well interven- LAS-58 injector has a thickness of 8 m, ly, other analog fields in the country. To tion. Despite the early tracer response at only 21% of the total net pay. It can be in- evaluate new options and potentially ex- Wells LAS-18 and LAS-49, both reported ferred that the transmissibility reduction pand CDG injection in this mature water- reasonable cumulative incremental oil generated by CDG injection (Phases II flood, detailed laboratory and numerical- (3000 to 4500 m3). In general, the first and III) was partially or totally removed simulation studies were initiated in the line of producers showed a higher oil- after more than 3 years of water injection final quarter of 2014 as part of an LAS- production response after CDG Phase III, since the end of CDG Phase III. In Au- waterflood revitalization. Preliminary re- especially Well LAS-22 (cumulative oil of gust 2011, another injection profile was sults of these ongoing studies are provid- approximately 7000 m3). obtained, but this time for the middle ed in the complete paper. Wells LAS-50 and LAS-53 showed and bottom pay zones (Mandrels 2 and similar oil-production response after 1). This survey still indicated a positive Conclusions CDG Phase II. Well LAS-50 started to variation of the injection profile. How- Q CDG injection was implemented increase oil production 5 months after ever, injectivity was reduced because of successfully in the LAS field. CDG Phase II ended. This well also shows water diversion into lower-permeability Incremental oil recovery was a clear change in WOR, demonstrating zones. This behavior was expected on the reported at 49 400 m3 (2.3% of the the benefits of CDG injection, especially basis of the better connectivity and areal OOIP). The largest oil response was after Phase III. Well LAS-53 is one of the development of the upper sand sequenc- observed a few months after the producers with the largest cumulative es (Mandrel 3) compared with the lower final phase of CDG injection. oil production during the period from layers (Mandrels 2 and 1). In 2013, addi- Q No polymer production or July 2005 to June 2014. This second-line tional injection profiles were attempted, significant operational problems offset producer started to mobilize oil but mechanical problems (i.e., casing- were reported during the CDG- during CDG Phase II. By July 2006, Well diameter reduction) limited the running injection phases. LAS-53 steadily produced between 10 of reliable tracer surveys. Q Laboratory studies indicate and 20 m3/d until the third quarter of In June 2006, a second tracer program that CDG injection can generate 2012, with a WOR of less than 10. It is be- was run after CDG Phase II. However, this higher viscosities than polymer lieved that oil-production response ob- tracer program was run with a different solutions at the same polymer served in this well after December 2011 strategy. During the first tracer program, concentration. CDG injection was influenced by the conversion to in- tritiated water was bullheaded simulta- showed the formation of aggregates jector of Well LAS-10. Therefore, oil pro- neously in all three zones (mandrels). in the range of 1 µm, suggesting duction recorded after this period was The second tracer program was run by intermolecular crosslinking not included in the actual recovery factor injecting tracers selectively in each of or a combination of intra- and of the LAS-58 CDG pilot. the mandrels. Therefore, results must be intermolecular crosslinking. JPT

JPT • JUNE 2016 83 PEOPLE

JOHN ALGEROY, SPE, has been appointed engineering. The College Edition recognizes undergraduate Europe and Africa region manager at engineering students for their active role in the student chap- AccessESP. He will be responsible for mar- ters of their engineering societies and engineering outreach keting, sales, and operations. Algeroy has both on and off campus. Academic excellence, leadership, 32 years of domestic and international oil- communication skills, and community service of the nomi- field experience and has served in opera- nees are also considered during selection. Formerly called the tional and managerial positions, primarily National Engineers Week Foundation, DiscoverE is an organi- in the completions sector. Most recently, he was a product line zation that promotes the engineering profession. manager for Schlumberger and was responsible for the devel- opment of a new electric intelligent completions system for ex- CHRISTOPHE RAIMBAULT, SPE, was appointed vice presi- tended-reach drilling and multilateral wells. Algeroy holds a BS dent, sales and marketing, at Rowan Companies. Before join- in petroleum engineering from Stavanger University. ing Rowan, he was director of business development and ac- count management at Transocean, after serving in several A. PAUL BACLAWSKI, SPE, JOHN H. marketing and operations positions for Transocean, Global- GRAHAM JR., SPE, JOHN F. TEMPLIN II, SantaFe, and Global Marine since 1997. He is a board member STEVE T. WHITAKER, and DEAN R. of the SPE Swiss Section. Raimbault holds a bachelor’s degree RICHMOND have formed a privately held, in general mechanics from Ecole Nationale Supérieure d’Arts startup upstream oil and gas acquisition et Métiers, Paris company titled Senex Energy Partners. Be- Baclawski fore forming the company, the founders of DAVE WALLIS, SPE, retired from OFS Senex worked together as senior analysts Portal as director for eastern hemisphere. in Devon Energy’s new ventures and acqui- As a part of OFS Portal’s support for open sitions and exploration teams. Baclawski is industry standards, Wallis was active in the appointed vice president and chief operat- Petroleum Industry Data Exchange (PIDX) ing officer for Senex. He is a certified petro- standards group from 2003 to 2014, serv- leum geologist and California-licensed pro- ing on PIDX’s executive committee and fessional geologist. Graham is appointed chairing the membership, marketing, and catalogue and clas- Graham vice president of engineering. He is a Texas- sification workgroup teams. His involvement with OFS Portal licensed professional engineer. The roles of began before the organization’s inception, with his role in the the others are as follows: Templin, president and chief execu- 12-person multicompany team tasked with creating the por- tive officer; Whitaker, vice president of exploration; and Rich- tal’s original vision and design. Wallis has authored several mond, vice president of geosciences. white papers on oil and gas e-commerce and contributed to various standards bodies and trade associations. He holds a TOBY DEEN, SPE, has been inducted into bachelor’s degree in geological science from the University of DiscoverE’s 2016 class of New Faces of En- London and master’s degree in sedimentology from Swansea gineering. He is an operations engineer at University, Wales. Devon Energy. National engineering soci- eties nominate professionals who are 30 years old or younger for the award, and Member Deaths Deen this year’s class of 12 includes young pro- fessionals from a cross-section of indus- Rex Alford, Houston, Texas, USA tries, including energy, technology, water John F. Armstrong, Houston, Texas, USA resources, medicine, aerospace, and the Hugh J. Ayres, Duncan, Oklahoma, USA environment. Among his other initiatives, Schley J. Babin, Houston, Texas, USA Deen started the SPE Oklahoma City Sec- John Bayiringisa, Entebbe, Uganda Arnold B. Booker, tion Future Trailblazers Mentoring Pro- Midland, Texas, USA David W. Harris, gram, which helps connect engineering Montgomery, Texas, USA Edwin G. Hays, Irving, Texas, USA Sahani students with local professional mentors. William B. Lamb, Wichita, Kansas, USA Deen holds a BS in petroleum engineer- Fletcher S. Lewis, Oklahoma City, Oklahoma, USA ing from the University of Oklahoma. HARSH SAHANI, SPE, James R. Line, Russell, Kansas, USA was inducted into DiscoverE’s 2016 class of New Faces of En- Forrest D. Musson, Lafayette, Louisiana, USA gineering College Edition. He is a student of the Graphic Era Edward J. Pittinger, Midland, Texas, USA University in India pursuing a bachelor’s degree in petroleum Robert D. Tibbs, Oklahoma City, Oklahoma, USA

84 JPT • JUNE 2016 SPE NEWS

Technical Report: Guidance for Decision Quality for Multicompany Upstream Projects

Regardless of the oil price, large joint venture upstream proj- ects have significantly underperformed on cost, schedule, and Decision Maker’s production. Smaller upstream projects have not fared much better.1 While there are a number of good books that go into Bill of Rights some detail on reasoning focused principally on project man- agement, poor decision quality played a very significant role in the underperformance. As a decision maker, you have the right to Therefore, a group of experienced subject matter experts • A decision frame that structures the (SMEs) from across the oil and gas industry worked collab- decision in the context most relevant to oratively to develop a joint technical report focused on good your needs decision quality. Additional industry input was obtained • Creative alternatives that allow you from a discussion session at the Society of Petroleum Engi- neers (SPE) Annual Technology and Exhibition Conference in to make a selection among viable and September 2015. distinct choices The resulting report “Guidance for Decision Quality for • Relevant and reliable information upon Multicompany Upstream Projects” (181246-TR) is available for which to base your decision, including free download at OnePetro.org and provides practical advice the uncertainty of the information on the application of decision quality principles, which apply • An understanding of the potential during all phases of a project’s life cycle, including exploration, development, and operational phases. consequences of each alternative based The group of SMEs focused on decision quality as defined by on your choice criteria the Society of Decision Professionals (SDP) in terms of a Deci- • A logical analysis that allows you to sion Maker’s Bill of Rights.2 The focus of this report is on gain- draw meaningful conclusions from the ing alignment as much as understanding differences among information to reach clarity of action the participants regarding the opportunity, alternatives, infor- • Effective facilitation to gain alignment mation, values, trade-offs, logical analysis, and commitment to action. and commitment to action Both SPE and SDP sponsored this effort requiring numerous meetings of the SMEs to reach agreement, and both societies believe this technical report to contain valuable information Upstream Projects,” featuring 2017 SPE President Janeen Judah that should be shared broadly with our communities. as guest speaker and Pat Burdett, lead author of the report, as Attend an SPE webinar on 22 June presenting the techni- the speaker. To view details and register, visit https://webevents. cal report, “Guidance for Decision Quality for Multicompany spe.org/products/decision-quality-in-multi-company-projects.

1Edward W. Merrow, founder and CEO of Independent Project Analysis Inc. 2Used with permission of SDP, a global, multi-industry organization dedicated to promoting quality decision standards and connecting decision makers, practitioners, and academics of decision sciences.

New Completions Technical Discipline Created SPE’s Board of Directors has created a if completions became a separate techni- increasing complexity of completions new Completions technical discipline, cal discipline. technologies and operations. In addi- concluding that the interests of SPE pro- Currently, completions engineering tion, the Production and Operations dis- fessional members from the drilling and has come to be regarded by the industry cipline definition includes some topics completions, and production and opera- as a separate discipline in its own right, that are now often thought of as falling tions communities would be best served distinct from drilling, because of the under the category of completions engi-

JPT • JUNE 2016 85 neering, which has resulted in ambiguity discipline, comprising more than 25% grams and member benefits. SPE soon about whether some activities should be of SPE professional members. will be contacting members to allow classified as Drilling and Completions or With the addition of Completions, them to update their member profiles Production and Operations. Drilling and SPE’s seventh technical discipline, and, if applicable, select a new preferred Completions is the largest SPE technical changes will be seen across SPE’s pro- technical discipline.

SPE Compendium Highlights Emerging Trends in Process Safety The first in what is expected to be a world at various flagship SPE events “This volume, in and of itself, represents series of compendia focused on cutting- and conferences. an impressive resource,” said Trey Shaffer, edge research and field experiences in The papers presented in the compen- SPE HSSE-SR technical director. “But it is health, safety, security, environment, dium were selected from thousands of the tip of the iceberg when it comes to what and social responsibility (HSSE-SR) is recently published SPE papers in the One- SPE has to offer exploration and produc- now available for free download from Petro online technical library and high- tion professionals working in HSSE-SR.” SPE. The goal behind this collection light emerging trends in process safety. is to offer readers a cross-section of The papers were selected by a volunteer The compendium is available online at technical papers presented around the editorial team. www.spe.org/disciplines/hse/promo.php.

SPE EVENTS

WORKSHOPS 14 June Q London—SPE London Annual 24–26 October Q Moscow—SPE Russian Conference: Adapting to a Challenging Oil Petroleum Technology Conference and 9 June Q Calgary—SPE Oilsands: Price Environment Exhibition Competitive Strategies for In-Situ Well Pad 1–3 August Q San Antonio—SPE/AAPG/ 25–27 October Q The Woodlands—SPE Development SEG Unconventional Resources Technology Artificial Lift Conference and Exhibition- 19–21 July Q Colorado Springs—SPE Conference North America Distributed Fiber-Optic Sensing for Wells, 2–4 August Q Lagos—SPE Nigeria Annual 25–27 October Q Perth—SPE Asia Pacific Reservoir, and Facilities Management International Conference and Exhibition Oil and Gas Conference and Exhibition 25–27 July Q Bangkok—SPE Artificial Lift 22–24 August Q Singapore—IADC/ Systems for Optimised Production SPE Asia Pacific Drilling Technology SYMPOSIUMS 15–16 August Q Kuala Lumpur—SPE Conference and Exhibition 13–15 September Q Canton—SPE Eastern Reserves, Resources, and Definition 24–26 August Q Beijing—SPE Asia Pacific Regional Meeting 20–21 September Q Calgary—SPE Caprock Hydraulic Fracturing Conference 29 November–1 December Q Banff—SPE Integrity for Thermal Applications 6–8 September Q Aberdeen—SPE Thermal Well Integrity and Design 9–12 October Q Muscat—EAGE/SPE Tar Intelligent Energy Conference Mats and Heavy Oil 14–15 September Q Galveston—SPE FORUMS 10–11 October Q Kuala Lumpur—SPE Deepwater Drilling and Completions Conference Reservoir Surveillance & Production 12–16 June Q San Antonio—SPE Processing Enhancement Through Cost-Effective 21–22 September Q Midland—SPE Liquids- Facilities of the Future Technology Integration and Operation Rich Basins Conference—North America 12–17 June Q San Antonio—SPE Key Efficiency 26–28 September Q Dubai—SPE Annual Factors for Success in Unconventional 11–12 October Q Doha—SPE Reservoir Technical Conference and Exhibition Reservoir Development Characterisation 18–20 October Q Accra—SPE African 23–26 October Q Abu Dhabi—EAGE/SPE Health, Safety, Security, Environment, CALL FOR PAPERS Integrated Geomechanics in E&P and Social Responsibility Conference and Exhibition CONFERENCES SPE International Conference on Oilfield 19–20 October Q Lima—SPE Latin America Chemistry Q Montgomery and Caribbean Heavy and Extra Heavy Oil Deadline 16 June 7–8 June Q Calgary—SPE Canada Heavy Oil Conference Technical Conference SPE Hydraulic Fracturing Technology 24–26 October Q St. John’s, Newfoundland Conference Q The Woodlands Q 13–15 June Port of Spain—SPE Trinidad and Labrador—Arctic Technology Deadline: 15 August and Tobago Section Energy Resources Conference Conference

Find complete listings of upcoming SPE workshops, conferences, symposiums, and forums at www.spe.org/events.

86 JPT • JUNE 2016 PROFESSIONAL SERVICES

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