JPT - Novembro/2016 by Capítulo Estudantil SPE UFPel

N OV E M B E R 2 0 1 6 â&#x20AC;¢ VO LU M E 6 8 , N U M B E R 1 1

JOURNAL OF PETROLEUM TECHNOLOGY

10/12/16 10:20 AM

Nov16_JPT_Cover.indd 1

GeoTesting GEOLOGY-BASED WELL TEST DESIGN AND INTERPRETATION SERVICES

Integrate geology and geophysics. Advance reservoir understanding. GeoTesting geology-based well test design and interpretation services maximize the value of well tests by integrating geological and geophysical models with dynamic well test dataâ&#x20AC;&#x201D;helping you improve production forecasting and unlock the full potential of your reservoir. Operating in the Norwegian Barents Sea, OMV used GeoTesting services to successfully characterize a geologically complex reservoir. Optimized well test design and calibration using dynamic well test data provided certainty in the reservoir model and confirmed reservoir connectivity. Find out more at

CONTENTS Volume 68 • Number 11

14 GUEST EDITORIAL • INCENTIVIZING ENERGY AND CLIMATE INNOVATION The offering of a suite of incentives in a global competition seeks to inspire scientists, technologists, and innovators to tackle seemingly intractable challenges. With a prize of USD 20 million, the NRG COSIA Carbon XPRIZE competition aims to bring out innovative technologies that can transform CO2 from a liability to an asset.

20 TECHNOLOGY UPDATE • FIT-FOR-PURPOSE SANDSCREENS ADDRESS COST-BENEFIT BALANCE A standalone screen has been developed for sand control in extended reach, multilateral, and long horizontal wells as a costeffective alternative to premium screens designed for mechanical loads beyond those usually seen in these wells.

28 RAPID WELLSITE WATER TESTING The treatment and recycling of produced water by US shale producers has pushed the development of new testing technologies and methods. The goal of some rapid-testing systems is to give producers a more reliable way to detect harmful bacteria while others seek to monitor water chemistry as an enhanced quality control measure.

32 CONFERENCE REVIEW • 2016 SPE ANNUAL TECHNICAL CONFERENCE AND EXHIBITION SPE’s first ATCE in the Middle East held in Dubai was attended by 7,500 industry professionals from 94 countries. Coverage of the keynote presentations and summaries of technical and panel sessions are featured.

38 ANNUAL SURVEY SHOWS DECLINING INDUSTRY SALARIES This year’s SPE Salary Survey of industry professionals reveals lower average total compensation than in previous years, while indicating a base pay increase from 2015 that is smaller than reported in the previous 2 years’ surveys.

42 STANDARDIZATION MAY HOLD KEY TO FUTURE OF MAJOR OFFSHORE PROJECTS Major offshore project costs have soared out of control, with low oil prices increasing the pressure on developers. In response, the industry is eyeing project standardization. A joint industry project under the International Association of Oil and Gas Producers is leading the way.

An Official Publication of the Society of Petroleum Engineers.

Adam Garland, chief scientist at Water Lens, holds a test tray that can be used with a portable system to test water quality from the oil field. It is one of several new methods offering quick, low-cost tests of water used for fracturing and injection. Source: Water Lens.

DEPARTMENTS 6 8 10 12 16 22 84 85 86 87 88

Performance Indices Regional Update President’s Column Comments Technology Applications E&P Notes SPE News SPE Events People Professional Services Advertisers’ Index

TECHNOLOGY FOCUS 45 DRILLING AND COMPLETION FLUIDS Badrul Mohamed Jan, SPE, Researcher and Academic Lecturer, Department of Chemical Engineering, University of Malaya

46 Method for Monitoring Mud Contamination in Wireline-FormationTester Sampling

48 Development of Novel Drilling-Fluid Nanoparticles for Enhanced Drilling Operations

52 Optimal Nanosilica Concentration in Synthetic-Based Mud for HP/HT Wells

56 Positron-Emission Tomography Offers New Insight Into Wormhole Formation

59 HORIZONTAL AND COMPLEX-TRAJECTORY WELLS Stéphane Menand, SPE, President, DrillScan US

60 A New Approach for Optimization of Long-Horizontal-Well Performance 62 Use of Microseismic Monitoring To Compare Completion Designs 65 Friction-Load Redistribution for Extended-Reach- and HorizontalWell Completions

67 GAS PRODUCTION TECHNOLOGY Scott J. Wilson, SPE, Senior Vice President, Ryder Scott

68 Plume Modeling Establishes Efficacy, Safety of Gas Extraction From Lake Kivu, Rwanda

70 A Deepwater Gasfield-Development Strategy for Trinidad and Tobago 72 Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project

75 OFFSHORE PRODUCTION AND FLOW ASSURANCE Sally A. Thomas, SPE, Retired, Principal Engineer, ConocoPhillips

76 Direct Electrical Heating of a Flexible Pipe 80 Flow-Assurance Methods Enabled by Medium-Voltage Heating Technology

82 Thermoplastic-Composite-Pipe Flowline Helps Reduce Project and Life-Cycle Costs

The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt.

Solutions for the Life Cycle of Your Well Drilling

Completions Production

Remedial Stimulation

Abandonment

TAM has solutions: For almost half a century, TAM has provided solutions for the countless challenges operators encounter during the life cycle of a well. TAM’s proven EPIC® solutions for drilling use our swellable packer, Casing Annulus Packer, and Port Collar for cement integrity during primary and secondary cementing operations. The versatile TAMPlug effectively isolates lost circulation zones. Unique completions products include the PosiFrac HALO™ frac seat and PosiFrac Toe Sleeve™. TAM’s extensive suite of swellable packers is available in multiple elastomer compounds to fit the specific application.

Excellence at the Wellsite®

We provide the exclusive TAM-J Multi-Set Inflatable Packer and the PosiFrac® Straddle System tools for selective production testing, acid stimulation, and sand fracturing placement. Our Single-Set Inflatable Packers can be used as production packers, bridge plugs, and scab liners. If P&A operations are needed, our Single-Set, Cement Retainer, TIP, TAMPlug, and TAM-J packers present reliable solutions. Whether companies are planning, drilling, completing, producing, remediating, or abandoning wells, TAM solutions are effective, efficient, and flexible.

www.tamintl.com

WELL INTERVENTION

TAM-195_SolutionsLifeCycle_rv3_0210.indd 1

PosiFrac HALO™ is a HydraWell, Inc. technology licensed exclusively to TAM International.

DRILLING & COMPLETIONS

UNCONVENTIONAL RESOURCES

RESERVOIR OPTIMIZATION

2/10/16 3:20 PM

Mohawk Energy SPE BOARD OF DIRECTORS OFFICERS

SOUTH AMERICA AND CARIBBEAN

2017 President Janeen Judah, Chevron

SOUTH, CENTRAL, AND EAST EUROPE

Recovering your Wellbore

Anelise Quintao Lara, Petrobras

Matthias Meister, Baker Hughes

2016 President Nathan Meehan, Baker Hughes

SOUTH ASIA AND THE PACIFIC

2018 President Darcy Spady, Broadview Energy

SOUTHWESTERN NORTH AMERICA

Vice President Finance Roland Moreau, ExxonMobil Annuitant

WESTERN NORTH AMERICA

MetalPatch™ restores integrity in a single trip solution.

Salis Aprilian, PT Badak NGL

Libby Einhorn, Concho Oil & Gas

REGIONAL DIRECTORS AFRICA Adeyemi Akinlawon, Adeb Konsult

Andrei Popa, Chevron

TECHNICAL DIRECTORS DRILLING Jeff Moss, ExxonMobil

CANADIAN Cam Matthews, C-FER Technologies

EASTERN NORTH AMERICA

HEALTH, SAFETY, SECURITY, ENVIRONMENT, AND SOCIAL RESPONSIBILITY Trey Shaffer, ERM

Joe Frantz, Range Resources

GULF COAST NORTH AMERICA J. Roger Hite, Inwood Solutions

MID-CONTINENT NORTH AMERICA Chris Jenkins, Independent Energy Standards

MANAGEMENT AND INFORMATION J.C. Cunha

MetalPatch seals off the problem area with minimal loss of inner diameter, providing maximum production and wellbore access. MetalPatch applications include: • Perforation shut off • Connection / Collar leaks • Parted casing • Casing corrosion • Leaking or failed sliding sleeve • Lateral re-completion

COMPLETIONS Jennifer Miskimins, Colorado School of Mines

MIDDLE EAST

PRODUCTION AND FACILITIES

Khalid Zainalabedin, Saudi Aramco

Hisham Saadawi, Ringstone Petroleum Consultants

NORTH SEA

RESERVOIR DESCRIPTION AND DYNAMICS

Karl Ludvig Heskestad, Det Norske Oljeselskap

Tom Blasingame, Texas A&M University

NORTHERN ASIA PACIFIC

DIRECTOR FOR ACADEMIA

Phongsthorn Thavisin, PTTEP

Parted Casing

Dan Hill, Texas A&M University Erin McEvers, Clearbrook Consulting

AT-LARGE DIRECTORS

RUSSIA AND THE CASPIAN

Khaled Al-Buraik, Saudi Aramco

Anton Ablaev, Schlumberger

Helena Wu, Santos Ltd.

JPT STAFF

The Journal of Petroleum Technology® magazine is a 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 Alex Asfar, Senior Manager Publishing Services Pam Boschee, Senior Manager Magazines Chris Carpenter, Technology Editor Trent Jacobs, Senior Technology Writer Anjana Sankara Narayanan, Editorial Manager Joel Parshall, Features Editor Stephen Rassenfoss, Emerging Technology Senior Editor Stephen Whitfield, Staff Writer Adam Wilson, Special Publications Editor Craig Moritz, Assistant Director Americas Sales & Exhibits Mary Jane Touchstone, Print Publishing Manager David Grant, Electronic Publishing Manager Laurie Sailsbury, Composition Specialist Supervisor Dennis Scharnberg, Proofreader

ThruPatch Packer Available Q4, 2016

ROCKY MOUNTAIN NORTH AMERICA

EDITORIAL POLICY: SPE encourages open and objective discussion of technical and professional subjects pertinent to the interests of the Society in its publications. Society publications shall contain no judgmental remarks or opinions as to the technical competence, personal character, or motivations of any individual, company, or group. Any material which, in the publisher’s opinion, does not meet the standards for objectivity, pertinence, and professional tone will be returned to the contributor with a request for revision before publication. SPE accepts advertising (print and electronic) for goods and services that, in the publisher’s judgment, address the technical or professional interests of its readers. SPE reserves the right to refuse to publish any advertising it considers to be unacceptable. COPYRIGHT AND USE: SPE grants permission to make up to five copies of any article in this journal for personal use. This permission is in addition to copying rights granted by law as fair use or library use. For copying beyond that or the above permission: (1) libraries and other users dealing with the Copyright Clearance Center (CCC) must pay a base fee of USD 5 per article plus USD 0.50 per page to CCC, 29 Congress St., Salem, Mass. 01970, USA (ISSN0149-2136) or (2) otherwise, contact SPE Librarian at SPE Americas Office in Richardson, Texas, USA, or e-mail service@spe.org to obtain permission to make more than five copies or for any other special use of copyrighted material in this journal. The above permission notwithstanding, SPE does not waive its right as copyright holder under the US Copyright Act. Canada Publications Agreement #40612608.

Re-Frac Zone

Depleted Zone

www.mohawkenergy.com

Mohawk Energy expanding the limits

PERFORMANCE INDICES WORLD CRUDE OIL PRODUCTION+‡ THOUSAND BOPD

HENRY HUB GULF COAST NATURAL GAS SPOT PRICE‡ 6

O PEC

MAR

APR

MAY

JUN

Algeria

1320

1300

Angola

1845

1840

1865

1870

Ecuador

552

555

556

550

Indonesia

847

851

856

860

3700

4000

4100

4120

Nigeria Qatar Saudi Arabia1 UAE Venezuela TOTAL

330 1980

1537

10040

10240

10340

10490

2595

2670

2820

2400

2300

2280

34051

34563

34584

35112

SEP

JUL

JUN

AUG

285 1850

MAY

330 2100

APR

320 2120

1 MAR

4405 2570

FEB

4355 2550

2016 JAN

4475 2320

DEC

4225 2550

NOV

Iraq Kuwait1 Libya

USD/million Btu

OCT

Iran

WORLD CRUDE OIL PRICES (USD/bbl)‡

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

Brent

32.18

38.21

41.58

46.74

48.25

44.95

45.84

46.57

WTI

30.32

37.55

40.75

46.71

48.76

44.65

44.72

45.18

THOUSAND BOPD NON-OPEC

MAR

APR

MAY

JUN

Canada

3767

3429

2811

3112

China

4091

4036

3973

4034

Egypt

491

494

493

490

Mexico

2249

2210

2207

2213

Norway

1632

1666

1607

1479

10522

10450

10440

10453

986

1003

993

921

Russia UK

REGION

MAR

APR

MAY

JUN

JUL

AUG

SEP

478

437

408

417

449

481

509

129

141

218

203

188

178

186

187

189

397

384

391

389

390

379

386

9174

8946

8894

8701

Other2

12633

12293

12572

12757

TOTAL

45545

44527

43990

44160

Total World

79596

79090

78574

79272

USA

WORLD ROTARY RIG COUNT†

Canada Latin America Europe Middle East Africa Asia Pacific

183

179

190

182

186

194

190

1551

1424

1405

1407

1481

1547

1584

INDICES KEY +

Figures do not include natural gas plant liquids.

Includes approximately one-half of Neutral Zone production.

From the October issue of JPT, the “Other” line item also includes Argentina, Australia, Azerbaijan, Brazil, Colombia, Denmark, Equatorial Guinea, Gabon, India, Kazakhstan, Malaysia, Oman, Sudan, Syria, Vietnam, and Yemen. Monthly production from these countries was listed individually in previous JPT issues. Ongoing work on the US Energy Information Administration (EIA) website is disrupting the regular updating of these countries’ production numbers. Additional annual and monthly international crude oil production statistics are available at: http://www.eia.gov/beta/international/.

Quarter

Supply includes crude oil, lease condensates, natural gas plant liquids, biofuels, other liquids, and refinery processing gains.

† Source: Baker Hughes. ‡ Source: EIA. Numbers revised by EIA are given in italics.

TOTAL

WORLD OIL SUPPLY AND DEMAND3‡ MILLION BOPD

2016 4th

1st

2nd

3rd

SUPPLY

96.54

95.53

96.38

DEMAND

94.23

94.17

95.28

95.93

JPT • NOVEMBER 2016

WellWatcher Flux MULTIZONAL RESERVOIR MONITORING SYSTEM

Event detected

A single wellhead penetration along with inductive couplers enable multidropping of PT gauges into the lower completion, and arrays of digital temperature sensors provide the highest-resolution measurements in the industry.

Maximize reservoir drainage while reducing uncertainty and minimizing operating costs. Early detection is critical to understanding complex reservoir behaviors and reducing risk and remedial costs. By acquiring continuous, real-time data across the entire sandface, the WellWatcher Flux* multizonal reservoir monitoring system enables operators to recognize events immediately and take action before problems occur. In addition, the system tracks flow profiles, identifies underperforming zones, and pinpoints hotspotsâ&#x20AC;&#x201D;all without impeding flow. Data is analyzed at surface to enable operators to manage well strategies, fine-tune performance, and optimize production. Find out more at

REGIONAL UPDATE AFRICA Z Shell’s new natural gas discoveries in Egypt are estimated in initial quantities at about 500 Bcf with more reserves possible, said Aidan Murphy, chairman and managing director of Shell Egypt. The discoveries, in a concession area of north Alam El-Shawish in the country’s western desert, could yield 10% to 15% of the total production of Badr el-Din Petroleum Company, the 50/50 joint venture of Shell and Egyptian General Petroleum Corporation that is expected to manage the operations. Z Eni reported that the Laarich East-1 oil well in Tunisia has a delivery capacity of approximately 2,000 B/D. Spudded in June, the well discovered hydrocarbons in Silurian and Ordovician sandstones while reaching a final depth of 13,487 ft. The well has now been connected to production. The company continues to drill Tunisian exploration prospects that have been identified on 3D seismic surveys. Eni owns a 50% stake in the Makhrouga-Laarich-Debbech license, where the Laarich East-1 well is located. State company Enterprise Tunisienne d’Activités Pétrolières holds the remaining stake.

ASIA Z China National Offshore Operating Company (CNOOC) began producing oil from separate fields in the South China Sea. At the Enping 18-1 field in the Pearl River Mouth Basin, current production of 2,010 B/D is expected to reach 11,800 B/D within the year. The field, which is part of a four-field regional joint development, lies in 295 ft of water and produces from facilities at the Enping 24-2 field. The company also has started production at the Weizhou 6-9/6-10 comprehensive adjustment project in the Beibu Gulf. Situated in 115 ft of water, the project is producing about 850 B/D and is expected to reach peak output of 3,800 B/D in 2018. CNOOC holds 100% operating interests in Enping 18-1 and Weizhou. Z Gazprom discovered a gas deposit during exploration at the Kirinskoye field in the Sea of Okhotsk near Sakhalin Island, Russia. Reserve estimates for the discovery have not been disclosed. The field is considered crucial for the company’s plans to boost liquefied natural gas (LNG) production at its Sakhalin-2 plant on the island. The plant

produces 10 million tonnes of LNG per year and is slated to add another 5 million tonnes of capacity. Z Ophir Energy initiated gas production at the Kerendan field in Indonesia. The company is transporting 3 MMscf/D to 5 MMscf/D to customer PLN, a state-owned electricity distributor, and will boost output to 20 MMscf/D when a new transmission line is completed later this year. Ophir is the operator with a 70% interest in the field, with the remaining interest held by PT Saka Bangkanai Kalimantan. Z KrisEnergy spudded the Bangora-6 development well in the Block 9 production sharing contract approximately 31 miles east of Dhaka, Bangladesh. Drilled from the Golpanagar site in the block’s northern section, the well is targeted to reach total depth at 12,421 ft measured depth or 10,016 ft total vertical depth. The Bangora field produced an average of 106 MMcf/D of gas and 291 B/D of condensate from four wells in 2015. The company is the operator and holds a 30% working interest in the block, with the remaining interests held by Niko Resources (60%) and Bangladesh Petroleum Exploration and Production Company (10%). Z Mubadala Petroleum’s MNA-17 well in the Manora development in the northern Gulf of Thailand has found 57 ft of oil pay in four reservoirs. Drilled to a 6,509-ft total vertical depth subsea, the well is being suspended before completion as a multizone producer that will use an electrical submersible pump during a hydraulic workover program. Production is expected to begin in November. The company is the operator and holds a 60% interest in the development, with Tap Oil (30%) and Northern Gulf Petroleum (10%) holding the remaining interests.

AUSTRALIA/OCEANIA Z Quadrant Energy’s Roc-2 well has found a hydrocarbon-bearing reservoir on the WA-437-P exploration permit in the North West Shelf of Australia. The discovery was confirmed by logging-while-drilling results obtained before the well reached its total measured depth of 17,356 ft. Extensive logging and testing were under way following the completion of drilling. The company is the operator and holds an 80% interest in

the permit, with the remaining stake held by Carnarvon Petroleum.

EUROPE Z Engie has made a discovery in the Cara prospect offshore Norway that could hold between 25 million BOE and 75 million BOE. The discovery well in License 636 encountered a gas column of 167 ft and an oil column of 196 ft. The company acquired extensive data from wireline logs, three successful core runs, and a successful production test. Possible linkage of the discovery to the nearby Gjøa field’s infrastructure are under evaluation. Engie is the operator with a 30% interest in the license. Idemitsu (30%), Tullow (20%), and Wellesley Petroleum (20%) are the other participants.

MIDDLE EAST Z Tethys Oil said that its share of production from Blocks 3 and 4 onshore the Sultanate of Oman increased to 387,174 bbl of oil, or 12,489 B/D, in August. The figures are gross amounts before subtraction of the government’s share and represent an increase from comparable figures of 368,628 bbl, or 11,891 B/D, in July.

NORTH AMERICA Z Shell began producing from the Stones project in the US Gulf of Mexico (GOM), which in 9,500 ft of water is the world’s deepest offshore oil and gas development. Initial production flows from two subsea wells that are tied back to a floating production, storage, and offloading (FPSO) vessel. Peak production slated for late 2017 is an estimated 50,000 BOE/D, which will flow from eight subsea wells and be assisted by a seafloor multiphase pumping system. The FPSO is only the second to be installed in the US GOM. Shell has a 100% interest in Stones.

SOUTH AMERICA Z Gazprom Chief Executive Officer Alexey Miller said that gas production at Bolivia’s Incahuasi field would double to 13 million m3/d by mid-2019. The company has a 20% interest in the gas and condensate field, which is operated by Total (50%). Tecpetrol (20%) and YPFB (10%) are the other partners. JPT

JPT • NOVEMBER 2016

Mud means more... from spud to production

Others may have you believe that mud is a commodity. In reality it’s the lifeblood of your well. That’s why we’ve invested in the things that make drilling and completion fluids a key driver of efficient well construction and optimized production: Quality products, designed for the toughest well challenges Great service, designed to meet your current business needs Flawless execution, designed to the highest safety and performance standards Mud means more. More performance. More production. More value. Visit BakerHughes.com/MudMeansMore for more information. © 2016 Baker Hughes Incorporated. All Rights Reserved. 45213 08/2016

RISK AND REWARD

Big Data and the Next Big Thing Janeen Judah, 2017 SPE President

SPE presidents are asked a lot of questions, and I suppose that’s true of anyone who stands in front of an audience as an authority figure. I have learned to expect many of the same questions, no matter the audience: What will the price of oil do? When will the industry turn around? How is the industry managing post-Big Crew Change? What are you going to do to “fix” the situation of women in the industry? What is your view on climate change? But my favorite question is: What’s the Next Big Thing? As I travel around as SPE President, I see a lot of new and different technologies, operators, and ideas. But my view on the Next Big Thing has been consistent for the last few years: I believe that we are not only entering the era of universal big data, but also the era of more intelligent software to help us make better decisions. The software will help us be better engineers by preserving knowledge and improving decision making. I believe the Next Big Thing will be infinite big data and intelligent machines to interpret it. Cheaper and more robust sensors will allow us to collect data not only on expensive deepwater completions and big compressors, but also on every isolated onshore well. Cheaper computing power, universal communications, and learning algorithms will allow engineers to use and interpret those large amounts of data to manage assets more efficiently. I believe operators and service providers will be able to reduce risk by using the full value of knowledge and experience to optimize asset management. I learned to be an engineer in the analog world of the late 1970s and early 1980s. Ours was a world of hand-drawn maps and handwritten columns of figures on green engineering paper. Programmable handheld calculators replaced the slide rule. Data capture was infrequent, monthly at best, and analysis was slow and tedious. Enter the PC. I vividly remember first getting a PC at work in 1985

At the 1964 New York World’s Fair. (I’m on the left.)

after I made the pitch to our district engineer to purchase an IBM PC Model XT for our six-person team. Before then, only special programs could be run on the mainframe at the faraway research center. Our group managed several Permian Basin waterfloods, and we had been doing very tedious calculations by hand. When I was pitching to the district engineer, his first question to me was “how many engineers will this PC replace?” What he didn’t see was that computational power would help the same number of engineers create better analysis and help drive better decisions. Since those ancient days of more than 30 years ago, better, faster, cheaper computing power is everywhere. We haven’t replaced engineers with PCs, but we have created new opportunities for better technical and economic evaluations. Enter the Internet. When I left ARCO in June 1994, engineers did not have email or Internet access. Three years later, I was emailing work across the Atlantic every day so that teams in Houston and London could collaborate. Now, especially for those of us in global companies, our workflows are completely dependent on instant global communications. But I believe we are only beginning to take advantage of the full potential of the globally connected computing world. The Internet, or Cloud, of Things is coming for all of us. Another question I’m often asked when I speak is: How will we manage the Big Crew Change? What will the industry do when all these people retire? How are we retaining the knowledge of all those experienced practitioners? I believe that many of my peers who are retiring or have retired as part of the Big Crew Change will continue to consult or work part-time on their own terms. But I think the greatest value will be for these experienced practitioners to help teach not just the next generation of human staff, but also the next generation of intelligent software. Their knowledge can be preserved forever in software that has learned how to duplicate, and eventually improve, their decisions. In his book, The Inevitable, Kevin Kelly refers to this artificial intelligence as “cognification”—not making a computer think like a human, but inserting a degree of “smartness” into its analysis. We already see the beginning of learning software with Google’s search algorithms and Apple’s Siri’s knowledge of everything. Intelligent software that brings efficiencies to humans is everywhere. Modern commercial aircraft are flown mostly by software. Routine radiology interpretation is being done more often by software, with physicians checking the work. Selfdriving cars learn your habits and are improving rapidly. There is no reason not to expect that the oil industry can use artificial

To contact the SPE President, email president@spe.org.

JPT • NOVEMBER 2016

intelligence and learning software to preserve and replace the human experience that is leaving the industry. At an SPE meeting not long ago, I overheard a familiar voice at a nearby table. It belonged to a Permian Basin fracturing expert who designed fractures for me in Midland, Texas, in 1981. He has forgotten more about hydraulic fracturing in the Permian Basin than most will ever know, and he is still designing fractures and mentoring younger technical staff. He is a perfect example of deep technical knowledge that could be preserved through learning software. Could you ever replace what he knows? Not completely, but software can help preserve it. Better sensors and intelligent software can help engineers manage complex operational systems. Our more complex production systems are too difficult for an individual to understand all the interactions. In the 1980s, a driller manually worked the brake, watching the gauges and pits. Today, the iron roughneck is a robot that has replaced rig hands while the rig operator works the controls from the safety of a booth. In a 1980s fracturing job, the company engineer (me) sat in the control van with the service company engineer monitoring pressures and rates as we manually adjusted the pumps. Today, fracturing controls are computerized and can be watched from the office. Innovation isn’t always a completely new invention. It is often the merger of two old techniques with a new idea. A great example is hydraulic fracturing+horizontal drilling=the shale revolution. Cheap, robust sensors+cheap computing power+learning software=truly real-time asset optimization. And the more that learning software is used, the more it learns and the better it gets, just like Siri. But software won’t replace human judgment; rather it will help us make better decisions with better access to data and better analysis of the data. For example, software can be used to improve subsurface interpretation by sifting through big data, assisting the human interpreter. To learn more, check out this article in the September JPT, “Better, Less Tedious Fault Interpretation” (http://www.spe.org/jpt/article/11770-ep-notes-29/). I like to think of big data plus cognification in a Star Trek way—like Captain Kirk and Mr. Spock. Spock was all logic and data, while Kirk was all emotion. Working together, the two could solve most any problem. Access to our own personal Spock of infinite logic and knowledge will certainly improve decision making. Software cannot replace the innovation that relationships and personal interaction brings—those “aha” moments at a meeting or in casual conversation with a colleague. Big data will make us better engineers, but relationships—through SPE—spur innovation. As a child, I visited the 1964 New York World’s Fair. IBM displayed the wonders of modern mainframe computing, and the Bell System’s exhibit included the picture phone and modem, both futuristic innovations in an era of rotary dialing. We could not have imagined the innovations of 2016. In 1986, we could not imagine the computer revolution, the Internet, and apps. Similarly, the revolutionizing inventions of 2046 are beyond our imagination. In my view, big data and learning software are the Next Big Thing, and they will revolutionize upstream, midstream, and downstream operations. JPT

JPT • NOVEMBER 2016

COMMENTS

EDITORIAL COMMITTEE Bernt Aadnøy, University of Stavanger Syed Ali—Chairperson, Consultant Tayfun Babadagli, University of Alberta

Facing the Future John Donnelly, JPT Editor

William Bailey, Schlumberger Mike Berry, Mike Berry Consulting Maria Capello, Kuwait Oil Company Frank Chang, Saudi Aramco Simon Chipperfield, Santos

Many of the top-level executives attending the SPE Annual Technical Conference and Exhibition (ATCE) in Dubai see the oil and gas industry rising from a market that has bottomed out and is on the rebound. Saudi Aramco Chief Executive Officer (CEO) Amin H. Nasser said the industry is in “recovery mode” and gradually reaching a supply/demand balance. Likewise, Schlumberger CEO Paal Kibsgaard said the market had reached bottom and was rising and requires more spending to insure against a global supply shortage in a couple of years. Although the previous decade had seemed like a golden age for oil with rising demand in Asia and new sources of supply from North America, the industry proved again that it is a cyclical business, with busts often following booms. Some believe that cyclicality, despite the pain, is a good thing. Jim Krane, the Wallace S. Wilson Fellow in Energy Studies at Rice University’s Baker Institute for Public Policy, says price cycles are inevitable in the oil and gas business and that has helped the industry remain competitive. “Price swings make companies disciplined and resilient,” Krane wrote last month in a Forbes online blog. “At the same time, they help fossil fuels retain their edge against competing technology. At one time or another, oil and gas have dispatched competitors such as whale oil, candles, steam engines, electric vehicles (in the 1900s), and solar panels. King coal is the latest victim. Nuclear power may be next.” When oil prices are too high, it encourages the development and use of alternative forms of energy, whether traditional ones such as coal, or new forms such as wind and renewable power. The current downturn has caused hydraulic fracturing techniques to become more efficient and service companies to lower their costs, says Krane, at the same time that oil and gas have become cheaper and more attractive to consumers. Although use of alternative forms of energy is growing, supported by governments concerned with climate change, most executives in the industry seem confident that fossil fuels will be the dominant energy source for years to come. But with government backing, which often comes with subsidies, the oil and gas industry has entered an era of competition with other energy sources whether prices are high or not. Topics at ATCE have always been a good barometer of the state of the industry, whether it was the arrival of new environmental regulations in the 1970s to the wave of mergers and acquisitions in the late 1990s. And executives at ATCE this year acknowledged the many challenges currently facing the industry. With panel session topics such as “E&P 2.0: Shaping the Future,” “Transforming the Industry to be Fit at 50,” “Boosting Efficiency in E&P,” and “Collaboration 2.0: Reinventing the E&P Industry,” executives discussed what the industry will need to do going forward to be successful. Both international and national oil companies said they were bent on improving operations, efficiency, and innovation while controlling costs. They are betting that the industry will remain resilient in spite of the inevitable sharp price swings and competition from other energy sources. JPT

Alex Crabtree, Hess Corporation Gunnar DeBruijn, Schlumberger Mark Egan, Retired Mark Elkins, Retired Alexandre Emerick, Petrobras Research Center Niall Fleming, Statoil Ted Frankiewicz, SPEC Services Stephen Goodyear, Shell Omer M. Gurpinar, Schlumberger A.G. Guzman-Garcia, Retired Greg Horton, Retired John Hudson, Shell Morten Iversen, Karachaganak Petroleum Leonard Kalfayan, Hess Corporation Thomas Knode, Statoil Sunil Kokal, Saudi Aramco Marc Kuck, Eni US Operating Jesse C. Lee, Schlumberger Douglas Lehr, Baker Hughes Silviu Livescu, Baker Hughes Shouxiang (Mark) Ma, Saudi Aramco John Macpherson, Baker Hughes Graham Mensa-Wilmot, Chevron Stéphane Menand, DrillScan Badrul H. Mohamed Jan, University of Malaya Zillur Rahim, Saudi Aramco Eric Ringle, FMC Technologies Martin Rylance, BP GWO Completions Engineering Robello Samuel, Halliburton Otto L. Santos, Petrobras Luigi A. Saputelli, Frontender Corporation Sally A. Thomas, Retired Win Thornton, BP plc Xiuli Wang, Baker Hughes Mike Weatherl, Well Integrity, LLC Rodney Wetzel, Chevron ETC Scott Wilson, Ryder Scott Company Jonathan Wylde, Clariant Oil Services Robert Ziegler, Weatherford

To contact JPT’s editor, email jdonnelly@spe.org. 12

JPT • NOVEMBER 2016

www.interwell.com

GUEST EDITORIAL

Incentivizing Energy and Climate Innovation Marcius Extavour and Paul Bunje, XPRIZE

In a quiet industrial park in suburban Toronto, there is a machine that eats carbon dioxide (CO2) and spits out fuel. This place, typically associated with its strip malls, ethnic and cultural diversity, and peaceful middle class life, might also soon be known as a hotbed of energy innovation. The project’s code name is “Pond.” A world away, at a world-class research institute in Bangalore, India, engineers have developed a completely different technology to convert CO2 into industrial chemicals. They are motivated by the desire to begin tackling rising global CO2 emissions. Their project code name is “Breathe.” Aside from a healthy obsession with carbon, what these two efforts have in

common might surprise you. Rather than collaborating on an international science project or with a company’s industrial research and development, both are competing to win a global competition to transform CO2 from a liability into an asset and, in so doing, create a paradigm shift in the energy space. Both are competitors in the NRG COSIA Carbon XPRIZE. And the competition is just getting started. The XPRIZE Foundation relies on the growing power of exponential technologies and revolutionary science to catalyze radical breakthroughs. This means developments in science and technology such as robotics, artificial intelligence, nanotechnology, big data, and other dis-

Marcius Extavour is director of technical operations, NRG COSIA Carbon XPRIZE, Energy and Environment Group, XPRIZE. Over the past 15 years, he has applied a background in experimental physics and engineering to complex problems in industry, government, and academia. He has worked with the US Senate Committee on Energy and Natural Resources, where he held the OSA/SPIE/AAAS Congressional Science and Technology Policy Fellowship, the Canadian electric utility Ontario Power Generation, and more recently the faculty of applied science and engineering at the University of Toronto, where he served as director of Government and Industry Partnerships. He earned a BASc degree in engineering science, and MSc and PhD degrees in quantum optics and atomic physics, all from the University of Toronto. Paul Bunje is the principal and senior scientist, Energy and Environment group, XPRIZE, where he attempts to bridge the gap between science and society to incentivize solutions to challenges facing our world, including climate change, energy, and the ocean. This work includes leading the Wendy Schmidt Ocean Health XPRIZE and the NRG COSIA Carbon XPRIZE. He has served as the founding executive director of the University of California at Los Angeles Center for Climate Change Solutions and as the managing director of the Los Angeles Regional Collaborative for Climate Action and Sustainability. He is also cofounder of Conservation X Labs, an organization that brings innovation to global conservation threats. He earned a BS degree in biology from the University of Southern California and a PhD from the University of California at Berkeley in evolutionary biology and genetics.

ruptive forces have the potential to show exponential impact on grand challenges such as sustainable energy and climate change. By offering a suite of incentives in a prize competition, XPRIZE seeks to inspire the world’s scientists, technologists, and innovators to tackle seemingly intractable challenges. Transforming our energy systems may be the 21st century’s greatest challenge. Articulating a grand challenge does not solve any problems, but a clear and deep articulation of the problem demands an understanding of the complexity and nuance involved in the problem itself and in a vision for defining characteristics of a solution. In our approach to energy innovation, XPRIZE recognizes that the technological, sociopolitical, and economic changes occurring globally present innovators with a rare opportunity to apply truly groundbreaking research to challenges of worldwide importance. We operate at the intersection of audacious and achievable. The Carbon XPRIZE is a USD 20 million global competition to incentivize technologies that convert CO2 emissions into valuable products. The winning teams will convert the largest quantity of CO2 from actual flue gas from coal or natural gas power plants into one or more products with the highest net value. The 10 teams that survive the first two elimination rounds (proposal evaluation was in summer of 2016, and lab-scale demonstration from late 2016 through 2017) will use two brand new test centers adjacent to operating power plants in western Canada and the US state of Wyoming to demonstrate their solutions at industrial scale. The competition is built to showcase new ways to transform CO2 instead

JPT • NOVEMBER 2016

of allowing it to escape into the atmosphere. But the real story here is not the technical challenge, but the teams that invest so much of their passion, creativity, and resources to compete. There are 47 entries in the competition from 38 teams. Seven countries from North America, Europe, and Asia are represented. Each entry brings a different approach to the CO2 conversion problem. Some, like Pond Technologies in Canada, accelerate the natural process of photosynthesis to transform CO2 into biodiesel and solid biofuel. Others, like Breathe in India, use a photochemical pathway to transform CO2 into methanol. Others still, like C2CNF out of George Washington University in the US, use an electrolysis process to produce carbon fiber from a CO2 feedstock. Individually, each team is a powerful innovation engine driven by the goal of applying breakthrough chemistries and catalysts to the challenge of CO2 conver-

sion by developing and commercializing industrial solutions. Taken together, this group of XPRIZE competitors is a powerful signal, both inside the clean technology and materials communities and in the broader energy and climate landscape, that innovation can and will have an important role to play in shaping and driving 21st century energy transitions. These teams and their networks of partners and supporters prove that good things are happening in energy innovation, and that it is not too late or too expensive to pursue radical new approaches, and that creative and dedicated teams of individuals can make an impact. As platform technologies, carbon capture, utilization, and storage have the potential to become major players in climate change mitigation, especially if they can demonstrate a meaningful reduction in existing and growing CO2 emissions from electricity generation. However, the

concept of CO2 as a material feedstock, and carbon capture and storage generally, are not without challenges. These approaches have been criticized as too expensive and too risky, and conventional wisdom has been that CO2 as a feedstock can never compete on a cost and energyintensity basis with fossil hydrocarbon feedstocks. New approaches to carbon capture and storage may alter the energetics, economics, and the broader narrative to the point where CO2 conversion could be poised for a radical leap forward. The Carbon XPRIZE is an invitation to take that leap. But outside of this XPRIZE, the promise of low-carbon energy solutions is a call to action to all scientists, engineers, entrepreneurs, and creative minds to demonstrate and inspire a path to a better energy future. We have the tools, we have scientific knowledge and capacity, we have the big thinkers, and anyone can now be a part of the solution. JPT

k-Drill® : your reliable source for every demand with top-grade KCl. Specifically designed for the challenging demands of the drilling industry k-Drill is a high performance product range of best quality potassium chloride. It is primarily used to prepare brines for drill-in, completion and work over fluids. k-Drill products combine German quality with reliable global service. No thrill, just drill. Whenever you need us, we are there.

K+ S KALI GmbH · Bertha-von-Suttner-Str. 7 · 34131 Kassel · Germany · industry@k-plus-s.com · www.kali-gmbh.com A K+ S Group Company

TECHNOLOGY APPLICATIONS Chris Carpenter, JPT Technology Editor

Screen-Handling System The Weatherford removable collar screen-handling system uses a minimum length of blank tubular to handle, connect, and run lower-completion screens. The design results in less tubular contact than conventional handling equipment, which means that more of the tubular can be dedicated to hydrocarbon production. The system includes an application-specific collar, a sliding collar table, and a hydraulically operated automated side-door elevator. A large, 14.3-in. maximum pass-through diameter enables the system to be used with completion assemblies. The system works with the company’s integrated safety-interlock system, which prevents casing and tubing strings from being accidentally dropped. A shock-absorbing system in the sliding collar table minimizes shock load on the tubular string as the string weight is transferred from the elevator to the table. The system is field-proven to handle and connect deepwater lower completion strings without marking string sections. The technology is intended for deepwater deployment but has the potential to improve the quality and efficiency of rig operations in a variety of fields.

into the wellbore, improves wellbore stability, and reduces the risk of hole collapse and differentially stuck pipe. The MPD system addresses the land segment by using a passive rotating control device (RCD) installed above the blowout preventer that diverts the flow through a setpoint MPD choke manifold (Fig. 1). The choke manifold contains a pressurecontrol choke, a pressure-relief valve, and a bypass line. The system comes with flowlines and valves to offer a complete tie-in to the rig’s circulation system. ◗ For additional information, visit

www.nov.com.

Anticorrosion Tool Corrosion Inhibitor System’s (CIS) Silver Hawg anticorrosion tool alters the chemical-reaction equations for scale formation, metal corrosion, and paraffin (wax) deposition. Comprising nine dis-

similar metals, the tool, which requires no handling of toxic chemicals or chemical waste, acts as a catalyst enabling a change in the electrostatic potential within the reaction equations (Fig. 2). This change in electrostatic potential produces a polarization effect at the electron level. This polarization effect on the molecules in petroleum-fluid solutions prevents scale formation, corrosion of metal, and paraffin wax deposition. For use in the petroleum industry, two patented tools have been developed for fluid treating. To keep subsurface piping clean, the company developed a downhole unit to be installed in the flow string of a wellbore. For all other fluid treating, a surface unit can be used. RTC Technologies is the North American distributor for the Silver Hawg. ◗ For additional information, visit

www.rtc-tech.com/silver-hawg/.

◗ For additional information, visit

www.weatherford.com.

Managed-Pressure-Drilling System National Oilwell Varco (NOV) has introduced the scalable MPowerD managedpressure-drilling (MPD) system, which allows clients to combine MPD components into customizable, fit-for-purpose packages that provide safe, efficient drilling in closed-loop applications for land, shelf, and deepwater segments. NOV’s integrated MPD solution allows drillers to manage wellbore pressure during drilling and connections; enables early detection of kicks and losses; and reduces risk, time, and cost for operations in both conventional and unconventional plays. Wellbore-pressure management mitigates undesired influx of gas and or water

Fig. 1—National Oilwell Varco’s MPowerD managed-pressure-drilling system.

Fig. 2—The Silver Hawg anticorrosion tool.

JPT • NOVEMBER 2016

BroadShear OFF-CENTER TOOL JOINT SHEAR RAMS

Successful shear test of an off-center tool joint pin and box, unshearable using conventional technologies.

Distinguished by shear ability. BroadShear rams now make it possible to shear any part of the drillstring above the BHA, including tool joint hardbanding and off-center tubularsâ&#x20AC;&#x201D;components long considered unshearable. Designed to stringent Bureau of Safety and Environmental Enforcement (BSEE) regulations, BroadShear rams bring enhanced security and dependability to marine drilling, so you can maximize safety in offshore operations.

Watch the BroadShear rams in action at

cameron.slb.com/BroadShear BroadShear is a mark of Schlumberger. ÂŠ 2016 Schlumberger. 16-DRL-177836

Fig. 3—Archer Oiltools’ Barricade is part of its Stronghold line of permanent-barrier systems.

Fig. 4—Thermanite high-temperature sealing material from Rubberatkins.

Barrier System Archer Oiltools introduced its Stronghold line of products, a series of perforating, washing, and cementing systems for a permanent annular barrier. The systems consist of the Barricade system, which perforates, washes, and cements the annulus (Fig. 3); the Defender, a barrier-test system that enables operators to perforate and test annular barriers; and the Rampart, a new cupless system that perforates, cleans, and cements the annulus. The systems eliminate the need for cutting, milling, and pulling tubulars out of the well, ensuring protection and long-term safety for the environment. ◗ For additional information, visit

www.archerwell.com.

Fig. 5—The Kymera XTreme hybrid drill bit from Baker Hughes.

cyclic steam stimulation. Steam injection has posed challenges to elastomeric seals over the years, with conventional seals failing early in the steam-injection cycle, resulting in unsatisfactory oil recovery. Steam injected in conventional slotted liner wells disperses unevenly, with effective heating near the heel but poor heating at the toe of the well. The Thermanite cups and packing elements ensure heat distribution and minimal temperature loss across the full length of the pipe, with zero loss of steam from the injector and producer wells (Fig. 4). Thermanite provides a sealing solution for harsh conditions in which temperatures can reach 600°F and provides resistance to sour gas and crude oil. ◗ For additional information, visit

www.rubberatkins.com.

High-Temperature Sealing Material

Hybrid Drill Bit

Rubberatkins’ Thermanite sealing material was developed for high-temperature applications and has proven effective in the containment of superheated steam in enhanced oil recovery operations such as steam-assisted gravity drainage and

Baker Hughes introduced its line of Kymera XTreme hybrid drill bits, designed to help oil and gas operators lower their well construction costs through faster and more-durable drilling performance. The bits—which com-

bine the strengths of polycrystallinediamond-compact and tricone-bit technology—offer the consistent performance of previous generations of hybrid bits while improving penetration rates and run life (Fig. 5). The drill bits are available in a variety of designs, each capable of addressing specific challenges in numerous applications, formation types, and hole sizes. The cutting structures incorporate enhanced shapes and carbide grades. The designs provide added tool-face control, enabling the drilling of longer distances at higher buildup rates than previously possible, while maintaining a high-quality borehole throughout extended runs. Blade and roller-cone designs can be optimized based on the operator’s application to deliver a variety of benefits that include long section-to-section runs and durability during transitions between formations. The bits also offer high steerability and control in difficult environments, including carbonates and interbedded formations. JPT ◗ For additional information, visit

www.bakerhughes.com.

JPT • NOVEMBER 2016

JPT Magazine - November | 8.125” x 10.875” | FINAL

peloton.com/cloud

An overhaul for Land Software was desperately needed. So we did it. We designed our new land data management system from the ground up and ended in the Cloud. Because our design is based on real user experiences, LandView™ captures and visualizes your land information like no other before. LandView™ is a web-based management solution in the MasterView® suite of products.

1660-24681_JPT_Magazine_Nov_VCR_8_125x10_875_FINAL.indd 1

2016-08-29 1:25 PM

TECHNOLOGY UPDATE

Fit-For-Purpose Sand Screens Address Cost-Benefit Balance Duncan Harper and Annabel Green, SPE, Tendeka

The pursuit of hydrocarbon reserves and increased oil production means that operators continue to look to prolific high-permeability, clastic reservoirs that can be found in basins around the world. The use of high-deviation and horizontal well trajectories in these fields increases the amount of reservoir contacted by the wellbore, which improves productivity but increases the challenges of sand control. Practical sand-control options for these wells include gravel packs, standalone screens, and slotted liners. The lower flux rates in extended-reach wells, and the high cost of gravel packing mean that operators are increasingly turning to standalone screens as the solution. However, the choice of screen will depend on the particular application to ensure that the well completion can retain the sand, avoid plugging and erosion, and maintain mechanical integrity. Subsea deployments, exits through milled windows, and long horizontal wells with swelling shales or unstable boreholes require a more robust and mechanically stronger solution. Other, less challenging wells may not require this level of mechanical performance yet still may need a sturdier sandcontrol solution than the use of standard screens. Weighing costs and benefits has become increasingly important in the current economically challenging environment. Operators cannot afford to use over-engineered solutions and demand a more focused option to fit their needs. Specifically, there is an increasing need for screens that are engineered to reduce cost and maintain performance but are stronger than a traditional screen.

Sand-Control Screens An effective sand screen is designed to allow the larger formation particles to bridge across the openings to offer maximum fluid flow area and reduce plugging. Smaller formation particles are then retained behind the larger “bridged” particles. Premium screens incorporate layers of metal mesh or weave to handle a larger range of particle sizes while increasing the fluid flow area and providing greater mechanical strength and erosion resistance. The selection of screen is highly dependent on the size and distribution of the formation solids produced. Screens can suffer from fines plugging and destabilization of the particle bridges. In the worst case, an uneven distribution of the flow into the screen can create flow “hot spots” that cause erosive “burn-through” from the high velocities of fluids entering the wellbore. This can lead to sand-control failure and the excessive production of sand through the well. Horizontal wells provide significantly greater reservoir contact compared with vertical wells and thus can produce more oil and gas with a lower drawdown pressure along the wellbore. This reduces sand production and flux through the completion, which allows standalone screens to control solids across a wider range of sands. In 2010, Tendeka commercialized the FloMax Ultra premium-mesh sand screen. Developed in response to the industry’s need for an ultrarugged screen that was suited to the rigors of long horizontal, multilateral, or subsea well operations, the screen meets the International Safety Organization (ISO) standard 17824 and is used in

some of the world’s harshest environments. More than 700,000 ft of the screens have been installed worldwide with no sand failures or production impairment recorded. However, the company estimated that up to 85% of wells that need sand control do not experience the mechanical loads that require this type of screen. Thus, Tendeka has recently developed a technologically updated screen to meet the sand-control needs of this large group of wells in a cost-effective manner, which is especially suited to current market conditions. The FloMax Elite screen (Figs. 1a, 1b, and 1c) is designed to offer an alternative premium-range screen that replicates many of the characteristics of the original design. The FloMax Elite product is a strong screen that achieves the same level of sand-control performance in the wells for which it is designed as the original screen does in the wells that require its capabilities. The new screen meets the ISO qualification standards. It uses the same five layers as the original screen, with reduced material content, and maintains the solid inner and outer jackets. The inner and outer shroud of the new screen are constructed of 1-mm-thick stainless steel, as opposed to the 1.5-mm steel used in the original screen. As with the original product, the shrouds are formed when the preperforated and punched stainless steel is shaped and welded in a unique spiral fashion. The inner and outer jackets have opposite spiral orientations to provide significant additional strength. In the same way as the original screen, construction of the new product uses the swaging method that

JPT • NOVEMBER 2016

(b)

(a)

(c)

Fig. 1—The FloMax Elite sand-control screen is shown (a) undergoing an outer shroud pull test and in close-up views of (b) the outer shroud and (c) the mesh layers. Source: Tendeka.

mechanically fuses all the layers without welding. This provides lateral support, which gives additional strength to the screen. Retaining the same construction technique across both designs has technical benefits and increases flexibility and consistency at the manufacturing facility, which ensures cost efficiency and finished-product quality.

Testing Qualification testing of the new screens takes place at the company’s manufacturing plant in Shanghai across a range of sizes. By keeping the same construction techniques, many of the mechanical strength ratings are maintained, such as the 100,000-lbm load rating of the raised end rings. Collapse and burst testing are repeated to quantify the effect of the reduced material volume used in the layered construction. Collapse Pressure. To test the collapse pressure, the 4½-in. sample screen was installed in the test fixture. The system was primed, and the outside of the screen was plugged with a calcium carbonate pill. After confirming the test fixture integrity and the accuracy of the pressure transducers, a stop-and-hold procedure was followed to obtain the maxi-

JPT • NOVEMBER 2016

mum collapse pressure rating. No loss of sand control, as defined by ISO 17824, was reported. The maximum collapse pressure achieved was limited by the setup to 5,000 psi. Burst Pressure. To test the burst pressure, the sample screen was reversed and reinstalled into the flow test fixture. Fluid from the previously used fluid-loss control pill was used in this test. After confirming test fixture integrity and the accuracy of the pressure transducers, the pump rate was increased to obtain the maximum burst pressure rating, which was 1,614 psi. As a result of these tests, the 4½-in. sand-control screen was found to have passed the minimum requirements for ISO 17824 grade V1.

We give you the superpowers you’ve always dreamed of. Introducing the world’s first X-Ray technology for oil wells. VISURAY’s revolutionary VR90 ® not only finds downhole blockages faster, it lets you see 2D and 3D reconstructions of the obstruction. We’ll illuminate the problem, you’ll eliminate the problem. Better yet, you’ll eliminate downtime and increase profitability.

Conclusion Sand control will challenge operators for as long as wells are drilled. Yet as big a challenge today is cost reduction across the industry. It is widely recognized that innovation must play a key role in securing future hydrocarbon production. The development of this new screen illustrates that innovation is not just about new technology but about finding ways to deliver the same performance with existing technology at a lower cost to the operator. JPT

VISURAY

ION X-RAY VIS

E&P NOTES

After Years of Development, Nanoparticle Drilling Fluid Ready Trent Jacobs, JPT Senior Technology Writer

The challenge for nanotechnology-based drilling fluids is that in order to gain acceptance, they cannot simply match the industry’s conventional chemistries—they must outperform them. Calgary-based nFluids believes it is among the first to answer that call. The 4-year-old firm is now in the early stages of commercializing its nanoparticle additive that it says is compatible with all types of drilling fluids. Based on results from nine pilot wells and an independent study by the University of Missouri, the company reports that its nano-additive has achieved up to a 60% increase in wellbore strength, a 90% reduction in fluid losses, and a 50% reduction in friction during drilling— with the latter translating to a faster rate of penetration. Jeffrey Forsyth, the chief executive officer of nFluids, said that since the company formed, it reduced its original manufacturing cost by about half while driving big improvements in the technology’s effectiveness. He explained that when iron and carbon constituents are broken down into

nano form “all their properties change and it’s almost as if you’re looking at a completely different material—but more importantly, most of those properties are greatly enhanced.” Those properties are what enable the nanoparticles to form a thin, yet durable, filter cake around the inside of the wellbore. This action takes place within minutes of introducing the nanoparticles into the drilling fluid base. As the particles move into the small pores and fractures of the exposed rock, the effective permeability is reduced, making it less likely that drilling fluids will bleed into the formation and weaken the wellbore. With less formation damage, it also becomes less likely that wellbore walls will collapse in on a drillstring, a common problem known as stuck pipe. And when the proper balance of fluids and well pressure is not effectively managed, even worse issues can arise such as a blowout. For producers tapping into the most unforgiving formations (think of shale or deepwater), the value proposition being offered is pretty simple: spend a little

more cash on advanced fluid technologies and a lot less time remediating the issues mentioned above. “If you look at drilling fluids—if everything goes according to plan—it is probably the smallest cost in many ways,” insisted Forsyth. “But if you lose a couple of days on a job where you’re drilling 3500 m, that’s going to amount to a lot more money than your fluid losses.” He added that the company can redesign the shape, size, and function of its nanoparticles to address a number of different drilling conditions. This flexibility has enabled the company to concentrate its additive solution so that it represents only half-a-percent of the total weight of a well’s entire drilling fluid system. In a promising sign for the company’s commercial prospects, it has signed a joint-development agreement with one of the majors (name not yet disclosed). It is also exploring a broad spectrum of other applications for its technology, including conformance control in enhanced oil recovery; water cut reduction in steam-assisted gravity drainage wells; perforation diversion for refracturing shale wells; and as a magnetic reservoir tracer.

For Further Reading

An illustration shows how nanoparticles plug fractures in a wellbore, adding integrity and reducing mud losses during drilling. Source: nFluids.

SPE 170589 Experimental Investigation on Wellbore Strengthening in Shales by Means of Nanoparticle-Based Drilling Fluids by O. Contreras, University of Calgary, and G. Hareland, Oklahoma State University et al. SPE 170263 Wellbore Strengthening in Sandstones by Means of NanoparticleBased Drilling Fluids by O. Contreras, University of Calgary, and G. Hareland, Oklahoma State University et al.

JPT • NOVEMBER 2016

CAMShale FRACTURING FLUID DELIVERY AND FLOWBACK SERVICE

Monoline* flanged-connection fracturing fluid delivery technology reduces installation time by more than 60%, Eagle Ford Shale.

More stages. Less cost. Integrated reliability. The CAMShale* fracturing fluid delivery and flowback service provides seamless delivery of hydraulic fracturing fluid from the pumping service providerâ&#x20AC;&#x2122;s missile trailer to the wellbore, integrating the entire high-pressure surface completion system through flowback and well testing. An operator in the Eagle Ford Shale reduced hydraulic fracturing costs by approximately USD 2.7 million per month and achieved 100% valve reliability with this integrated service, which uses only Cameron equipment, maintenance programs, work procedures, and a multiskilled crew. Find out more at

Anticipation, Uncertainty High for Upcoming Mexico Auctions Stephen Whitfield, Staff Writer The opening of Mexico’s oil and gas sector was a landmark moment in the industry, but despite the potential upside, the uncertainty and risk surrounding unfamiliar offshore territory in a volatile price market kept many potential investors at bay. Today, more than a year after the first auction of shallow-water blocks, operators have a better idea of what to expect from Mexican authorities, but there are still questions left to be answered with more public bids on the horizon, an expert said. In a presentation held by the SPE Gulf Coast Section’s International Study Group, Loren Long discussed Talos Energy’s decision to bid on Mexican shallowwater leases, its experiences operating in the country, and his outlook on upcoming auctions. Long is the managing director for Talos’ Mexican operations. Talos, in a consortium with Mexican company Sierra Oil and Gas and British company Premier Oil, won two contracts during the first phase of the initial round of auctions, held on 15 July

2015. The two blocks are located in the shallow waters off the coasts of Mexico’s Tabasco and Veracruz states. Under the terms of its production sharing contract (PSC) with the National Hydrocarbons Commission (CNH), Mexico’s upstream regulator, Talos gained a 45% participation interest in the two blocks. The consortium’s winning bid offered to pay the Mexican government 55.99% operating profit from its first block and 68.99% from the second block, slightly edging out bids from Statoil and Petronas. Long said there were several elements factoring into Talos’ decision to submit a bid. First, the financial barrier to entry was low: CNH required only USD 143 million in upfront cash guarantees, which Talos was able to satisfy with a performance bond that did not reduce its borrowing capacity under its revolving credit facility. Second, the company figured the uncertain commercial and regulatory framework surrounding the first auction would prove too risky for many nation-

al and multinational oil companies to participate, thus limiting the number of major competitors it would have to face. Third, the blocks CNH offered in Round 1 were geologically analogous to Talos’ other operations in the Gulf of Mexico, primarily in that they are saltdominated provinces that respond well to seismic data. Long said Mexico offered an opportunity for the company to apply its downhole geophysical and geological knowledge to take advantage of potentially sizable reserves. “There is an incredible amount of potential downhole,” Long said. “This is part of our thinking and approach to Mexico. We didn’t believe that one operator could find all the oil in that country. Pemex has stayed in an area that they know and like, and they have done quite well in that area, but they haven’t found everything. At least, that’s what we’re hoping.” Next March, the Mexican government will begin a round of auctions for shallow-water blocks. But before that,

The blocks designated for the Round 2 auctions in March will feature 10 shallow-water exploration blocks and five exploration and production blocks off the coasts of the Mexican states of Veracruz, Tabasco, and Campeche. Source: CNH.

JPT • NOVEMBER 2016

on 5 December, it will hold a public bid on 10 deepwater blocks located in the Perdido Fold Belt and the Salinas Basin. In addition, a separate bid will be held for the selection of a partner for Pemex (Petróleos Mexicanos), the Mexican state-owned petroleum company, to pursue exploration and production (E&P) activities in the Trion field. These auctions are considered to be the final phase of Round 1, while the March auctions are the first phase of Round 2. Trion is located 200 km offshore the Mexican state of Tamaulipas, near the country’s maritime border with the US. It has approximately 480 million bbl of proved, potential, and possible oil and gas reserves, and the auction marks the first farmout for a Pemex field. Long said he was initially excited by the Trion announcement because of the previous difficulties in getting Pemex to embrace a farmout. However, the terms of the joint operating agreement have left him slightly discouraged. Pemex will retain a participating interest of up to 45%, and the designated operator will maintain an interest between 30% and 45%. The winning bidder must carry Pemex’s participating interest until joint account investments attributable to the carried interest reach USD 464 million. While they are not interested in Trion, Long said smaller operators were looking at the farmout as a sign of what to expect from Pemex in future deals. “We were hoping that [the Trion farmout] would be a template for all of these dozens of fields in the Bay of Campeche that have not been developed. We were hoping that would be a template, but that has not turned out to be the case. It has been discouraging what we are seeing so

far. If that’s the template, it’s going to be a real struggle,” Long said. The bids for the first auction of Round 2 are due by 22 March. This auction will include 10 shallow-water exploration blocks and five E&P blocks off the coasts of Veracruz, Tabasco, and Campeche. Long said there is a possibility that Pemex adds additional deepwater fields to the auction, but that will depend on the results of the Trion farmout. Long said CNH and Sener, the Mexican energy ministry, have been responsive to industry feedback in setting the terms for bidding, particularly in lowering the financial barriers to entry. Companies looking to bid must meet one of two criteria: ◗ They have operated at least three projects between 2011 and 2015, and have capital of USD 600 million (down from USD 1 billion in Round 1). ◗ They have at least USD 1 billion of total capital investments in exploration and/or extraction projects (down from USD 10 billion in Round 1). The contracts for Round 2 will be PSCs. The stages of the PSC will include an exploration period of 4 years, an evaluation period of 2 years following a discovery, and a development period of 22 to 32 years, with extensions possible based on the continuity of production. Long said some of the provisions of the PSCs are administratively burdensome. For example, operators are expected to submit an exploration plan within 120 days after signing the contract, a time frame that Long said was unreasonable; a longer deadline would allow operators adequate time to look for potential drilling opportunities in a given block. Local content requirements for the Round 2 contracts will range between

15% and 35%, depending on the stage of the contract. With no specific labor requirements, Long said operators may be able to reach the local content threshold by purchasing goods like casing and fuel from Mexican companies. “A lot of people really amped this issue up and we’re not seeing the urgency there. A lot of people are like, ‘Oh, you have to fabricate your platforms offshore in Mexico,’ and ‘Oh, you have to use Mexican rigs,’ and we’re doing the math and thinking, no, you don’t really have to do that,” he said. The deepwater contracts will likely be a hybrid of a PSC and a license. Long said these contracts lack the cost recovery provisions commonly found in a PSC, but still require various administrative tasks like reporting their costs to the government. That may be reason enough for some companies to pass on submitting a bid. Discussions between operators and the government on the nature of the contracts are ongoing, however, and deepwater bidding will still draw considerable interest from operators because of the financial potential of the offered blocks. The deepwater contracts have drawn significant attention from large operators because of the amount of proven reserves. Chevron, ExxonMobil, Total, BP, and Statoil are among the companies registered for the auction. However, Long said the shallow-water blocks from Round 2 may be equally advantageous. “Our theory is that, for areas around there, you’ll see some very exciting opportunities,” he said. “That’s great news for the industry. Now, how quickly can those opportunities be exploited? I don’t know. That’ll remain to be seen, but I think it’ll at least be steady.”

Energy Research Funding the Next Generation Stephen Rassenfoss, JPT Emerging Technology Senior Editor When Tom Williams was hired as president of RPSEA, one of the first things he did was change the title of the technology development organization’s September conference. At the end of The Best of RPSEA 10 Years of Research, he added, “and Beyond.”

The decision was made shortly before the September gathering because he said the original made it sound “like a funeral. You are saying this is it.” That was a worry because the organization had failed to find funding to replace the dwindling cash flow

from a US Department of Energy (DOE) program that the US Congress had killed before it was scheduled to expire. At the meeting Williams emphasized, “It is not it. We are a viable organization that will keep going.”

JPT • NOVEMBER 2016

Since he replaced James Pappas, who retired, Williams has been on the hunt for new sources of support for an organization whose mission is to be “a lowcost manager and facilitator of research and development.” The business plan, based on advice from the consulting firm HBW Resources, streamlines the organization by merging multiple programs into two areas, onshore and offshore, and shortening its name from the Research Partnership to Secure Energy for America to just RPSEA (pronounced “Rep-Sea”). One of its selling points is its strong connections with exploration and production companies, which offer experts, test sites, and support for projects. “You cannot do research without an operator involved because it will never get applied,” Williams said. The organization is trying to find a positive in the brutal business environment. “At a time when money is tight” RPSEA can use its credibility and con-

nections with academia, industry, and government to create cost-effective R&D partnerships, said Jack Belcher, the executive vice president of HBW Resources, who is also currently RPSEA’s business development manager. It will need multiple sources of support from government and private sources. Williams has made progress in this while building the Environmentally Friendly Drilling Systems program, which has been working on ways to shrink the impact of unconventional drilling. Both organizations regularly put together research projects with government funding, often touching on issues related to regulation, such as safety and health, and that work is expected to grow. Williams said RPSEA has identified additional funding sources and has bid on funding for work with industry associations, the US Environmental Protection Agency, and the US Bureau of Ocean Energy Management.

RPSEA is reviewing the approximately 150 projects done in the past for DOE, looking for those where small amounts of added funding could allow promising ideas to move toward commercialization or field testing, he said. And it is building a database of the reports and stories written about past projects in publications such as this one, making them easily searchable for the first time. The new leader there is working overtime to build bridges and reestablish the flow of cash the organization needs to keep its staff working, with a goal of getting bigger. Soon after the meeting, Williams was off to the Groundwater Protection Council (GPC), which was looking to meet environmental regulators in oil and gas states. He also wanted to identify questions that RPSEA can help answer with the GPC’s support. “You can’t be afraid to ask for some things,” he said. JPT

Survival of the Simplest

A new species of toe valve

>> OmniFrac Pro Toe

For decades, engineers have had to trust the future of their wells to the lesser of two evils: exceptionally expensive TCP or unreliable first generation toe valves. Superior Completion Services has advanced toe valve technology with the new OmniFrac Pro Toe™, a mechanically simple design that simply works.

superiorenergy.com/completionservices

™

In Search of Cheap, Fast Ways To Detect Water Troubles Stephen Rassenfoss, JPT Emerging Technology Senior Editor

reating produced water to control bacteria is like weeding a garden. It addresses the problem that is not going away. Regular field testing shows water quality is highly variable. The biological and chemical makeup of a tank of produced water is complex and can quickly change as water from other sources is added and microbes rapidly multiply. “In the Permian Basin, I went out to wells that have been recently fractured and within 2 months they are already soured. It was back-traced to poor water quality. That happens more often than you think it does,” said David Burnett, a research scientist at the Texas A&M Engineering Experiment Station (TEES). One of the TEES projects is seeking practical, cheap, reliable, and quick testing options for microbes and chemicals, and seeing if those tests also work in the hands of a worker in the field. The goal is to convince operators that they need to test often and can rely on those results to manage their operations because performing a test that costs USD 10 or less could save USD 500,000 on a workover. TEES’ interest coincides with a spate of new options on the market for bio-

logical and chemical monitoring of oilfield water. One that met TEES’ criteria when tested is made by Retego Labs. The Internetlinked screening equipment has been provided to oilfield service companies to vet their screening methodology for chemical, mineral, and microbial content. The test usually takes less than 3 minutes, and requires adding a 3-ml sample to a test vial that contains the chemicals needed for a portable unit to measure a specific target. No pretreatment of the sample is required, and the cost is less than USD 5 per parameter tested.

Test Gap

The “stability of treated water during storage has not yet been explored due to the difficulty of obtaining timely and accurate microbial levels,” wrote Allana Robertson, a recent Texas A&M graduate, in a paper. She reported on the use of a variety of test methods showing that “treated produced water still exhibits an unstable nutrient-rich nature capable of supporting microbial growth.” “Without the addition of a biocide to establish a residual concentration, microbial biomass levels can be expect-

ed to regrow surprisingly fast after any removal treatment,” Robertson wrote. The high cost of biocides, and regulations on how much can be used, limit them as a long-term control option. And bacteria can multiply faster than traditional lab testing services can deliver results. “A lab could take 2 to 3 weeks to get results back and by then it is too little, too late,” Burnett said, adding, “It was a breakthrough when we found something that can work in hours rather than days.” Robertson’s paper and Burnett’s testing program are aimed at convincing industry that there is a need, and the tools are available, to accurately measure the quality of a costly resource. The results in the paper included tests using the Bactiquant water meter that TEES is evaluating as a better alternative to long-established approaches to microbe monitoring. Portable testing equipment makers are facing limited competition. Few commercial labs will test produced water, which is a complex brew capable of killing costly lab equipment. “Private environmental labs are generally set up to test industrial waste and

JPT • NOVEMBER 2016

municipal waste water. But when companies start bringing in water from fracturing and flowback, they are generally not set up” to handle it, said Keith McElroy, a consulting microbiologist and produced water treatment expert at TEES. There are no formal industry standards for the testing of oilfield water. It is up to operators to know what they are looking for. “They know how to do it. But they ask what you want to test and you are back on square one. The operator doesn’t know what he wants to test. What is critical?” said Burnett, whose projects include seeking an answer for that question.

TEES has found that some tests proven in other industries are a bad choice in an oil field. Some are physically impossible to do—for example, a test based on the observation of a change in color of a fluid is not going to work when the water is black, McElroy said. Other tests require skills not likely to be found on a drilling crew, such as ensuring that samples are collected in uncontaminated glassware, and that the samples collected are representative of the water to be tested. Burnett describes the challenge this way: “It is a 10-million-gallon job and they are pumping 80 bbl/min, and a guy with a test tube is trying to grab a sample.”

A researcher at Texas A&M Engineering Experiment Station (TEES) prepares samples of produced water for bacterial analysis using the Bactiquant test from Mycometer. Source: TEES.

New Field Testing Device for Water Competes With Laboratory Methods Trent Jacobs, JPT Senior Technology Writer

A portable water testing system uses new analytical methods and advanced software to generate reliable measurements in 10 minutes. Source: Water Lens.

nalyzing the properties of produced water is a difficult process because of the extreme levels of suspended and dissolved particulates contained in it, and a chemistry profile that is in constant flux. But the transition from using fresh water to recycling produced and flowback water for hydraulic fracturing in North America has driven the need to

JPT • NOVEMBER 2016

improve how oilfield water sources are analyzed. Industry research shows that water chemistry can affect production behavior, and compared with fresh water, produced and flowback fluids introduce many more chemical constituents to the equation. Houston-based Water Lens is one of the latest companies to jump into

the testing device market with a portable system it developed to generate rapid answers on water quality from the field—offering producers an alternative to sending samples to laboratories and waiting weeks for results. Keith Cole, the chief executive officer of Water Lens, said the new technology was designed to measure the key parameters shale producers need in order to properly condition produced and flowback water for reuse. The company is also emphasizing that continuous testing of water sources would represent a strong measure of quality control for completions fluids. “If you know what’s in the water, then you know what amount of chemicals you should be adding and can effectively blend it,” Cole explained. “So the more important chemistry is to your operations, the better of a fit we are.” Highlighting the practice of storing water in lined pits as an example, Cole said operators have a tendency to run tests on this water source once every few fracturing treatments. The assumption is that the water’s chemistry is reasonably static.

“In practice, that’s not true,” he said. “The pits have varying water qualities from the top, middle, and bottom to the front, middle, and back.” Pit conditions may also change during the pressure pumping operation as more water is added from different sources. Listing other reasons operators should test water more frequently, Cole said detecting a change in the levels of magnesium or calcium in produced water may mean that scale or corrosion treatment chemicals are ineffective. Variations in salinity during the flowback stage might indicate that an induced fracture extended beyond the target zone. And maybe that last fracturing stage didn’t get propped effectively because something in the water degraded the proppant-delivery chemicals. To use the Water Lens device, a field worker takes a water sample and injects it into a disposable test tray. The tray is then loaded onto a chemical reader and after 10 minutes, the results are in. The company went commercial with the device last year after about 4 years of researching and developing chemistry techniques and proprietary data analytics software. The company believes those efforts have produced a system that can outperform con-

ventional field testing kits and thirdparty labs. Cole said conventional instruments and methodology developed half-acentury ago were never designed or updated to handle the high salinity of produced water. In his opinion, the field testing sector “quit innovating.” Adam Garland, the chief scientist at Water Lens, explained that the technology he helped create delivers more accurate measurements because it was designed for high salinity and to account for the majority of known interferences—chemicals that make it difficult to measure another chemical properly— found in produced water. “You have to be able to deal with the interferences,” he said, adding that the device’s software runs a dozen different tests to “know what they are and how much is in the water” and then adjustments are made to correct the measurements. In addition to its promise of 10-minute test times, the company is also counting on its low price point to encourage companies to test their water more frequently. Each tray can be customized to test up to 20 inorganic parameters at a time, including pH, alkalinity, boron, calcium, magnesium, and total dissolved

solids. The test trays range in cost from USD 150 to 250, depending on the number of parameters being tested and the number of trays purchased. The testing hardware is lent to users at no cost. The company is seeking opportunities to expand the use of its testing device for drilling fluid monitoring, cement quality verification, and flowback analysis. Cole said by monitoring flowback fluids multiple times a day, operators may save money on crew costs by knowing they can switch to production mode earlier than their predetermined schedule calls for. Because the technology does not constitute a lab, it is not eligible to be labcertified but the company says that it nonetheless holds itself to the same standards as accredited labs. It also said that its current clients have not taken issue with this. Over the next 6 to 12 months, the company plans to add at least 10 more parameters to its testing system including BTEX (benzene, toluene, ethylbenzene, and xylenes) and hydrogen sulfide, Acidproducing bacteria and sulfate-reducing bacteria, two microbial properties that Water Lens said are not currently possible to quickly and accurately quantify in the field, will also be added.

TOC Analysis Gains Acceptance as a Standard for Organics Testing Stephen Whitfield, Staff Writer

he presence of excessive levels of organic components in produced water can lead to costly problems for operators ranging from clogged membranes in treatment facilities to environmental issues and compliance with government permits. Having adequate technologies and processes for measuring organics may be a solid economic strategy for operators. Johnny Robinson, an organics monitoring process sales manager at GE, spoke about the importance of analyzing and controlling the levels of total organic carbon (TOC) in waste water during a

short course on water management held by the Global Petroleum Research Institute at Texas A&M University. Robinson outlined three metrics for monitoring organics in water: biological oxygen demand (BOD), the quantity of oxygen used by microorganisms in the oxidation of organic matter; chemical oxygen demand (COD), the amount of oxygen required to oxidize soluble and particulate organic matter in water; and TOC, the amount of carbon found in an organic compound. BOD and COD are the more commonly used metrics. A BOD test measures the

change in dissolved oxygen concentration in a water sample over a given period of time at a specified temperature. It monitors organics through two stages of decomposition. The carbonaceous stage represents the portion of oxygen demand involved in the conversion of organic carbon to carbon dioxide (CO2). The nitrogenous stage represents a combined carbonaceous and nitrogenous demand, when nitrogen and ammonia are converted to nitrite. A COD test involves the oxidization of all organic compounds in a water sample to CO2 using a strong oxidizing

JPT • NOVEMBER 2016

agent under acidic conditions. Potassium dichromate is a commonly used agent because it can oxidize most organic compounds. However, other substances such as ceric sulfate, potassium iodate, and potassium dichromate, can also be used to help determine COD. Because the oxidizing agent may react with substances not stabilized by bacteria in the water sample, the results of a COD test may not necessarily correlate with a corresponding BOD test. For continuous monitoring and control of organics, Robinson suggested that operators should use TOC as their standard, primarily because a typical TOC test is a significantly shorter process than testing for BOD or COD. A TOC analyzer can provide readings every 10 minutes, making it much more useful for real-time continuous control. Robinson said GE has an analyzer that can deliver readings every 2 minutes. By comparison, an average COD test takes approximately 4 hours, and the 5 days typically needed to complete a BOD test only measures a portion of BOD in a water sample—20 days is the conventionally adequate time frame for complete biochemical oxidation. Robinson said that the acceptance of TOC as a standard for organic monitoring has been relatively late compared to BOD and COD. Because of this, oxygen demand monitoring will remain a necessity for obtaining various government permits. The permit application from the US Environmental Protection Agency’s National Pollutant Discharge Elimination System (NPDES) requires operators to submit BOD and COD analyses of their waste water. However, he said TOC analyses have become increasingly commonplace on permits. “When we talk about monitoring organics, TOC has been kind of a late player to this game,” Robinson said. “TOC has a very high correlation to the COD and BOD. Many of the NPDES permits have COD and BOD on the permits. We’re never going to get rid of those, but we do see TOC showing up on these permits, and that’s good. That’s the bottom line.” The monitoring process for TOC begins with the removal of total inorganic carbon from a water sample. The

JPT • NOVEMBER 2016

TOC is then oxidized until it becomes CO2, and an infrared detector measures the remaining carbon content by analyzing the change in conductance. Robinson said that operators looking to measure in-water organics and on-water organics must use two separate samples, as each type of sample requires a different gathering method.

“With in-water, you’re actually getting a sample from beneath the surface, and with the on-water method you’re actually measuring with a device that floats on the surface,” he said. “You’re taking the measuring points of two different locations, so you’re not going to be able to use one sample. You’re going to have to take two different samples,” he said. JPT

Basic Emulsifiers

WHY PAY FOR THIS,

WHEN ALL YOU NEED IS THIS?

The same goes for your emulsifier purchases. XPLORTM Basic emulsifiers offer an economic alternative by meeting rudimentary performance requirements combined with the quality you expect from the emulsifier experts, Georgia-Pacific Oilfield Chemicals.

• Meet the requirements, meet the budget. • Get the job done. Don’t pay for unnecessary features. • Available for both mineral oil and diesel solvents.

CONFERENCE REVIEW

SPE Annual Conference Confronts the Future SPE held its first Annual Technical Conference and Exhibition in the Middle East in September, as 7,500 industry professionals from 94 countries met to discuss topics under the theme of “E&P 2.0: Transforming and Shaping the Future.” The event took place at the Dubai World Trade Centre under the patronage of the Vice President and Prime Minister of the United Arab Emirates and Ruler of Dubai, His Highness Sheikh Mohammed bin Rashid Al Maktoum, and drew senior speakers from operators, service companies, and academia. The conference opened with addresses from the leading executives of two of the region’s oil giants. Amin H. Nasser, president and chief executive officer (CEO) of Saudi Aramco, delivered the conference opening keynote address, and the welcome keynote speech was given by Abdul Munim Saif Al Kindy, director of exploration development and production for Abu Dhabi National Oil Company (ADNOC). Both Nasser and Al Kindy struck similar themes about the need for both the industry and their respective state

oil companies to change strategy in light of the oil and gas sector’s current economic challenges. Despite growth in alternative energy sources, hydrocarbons will supply the world’s energy needs for years to come, said Nasser. He called the current oil industry in recovery mode but still weak. “Despite recent oil price volatility, the market is reaching balance,” but likely will remain volatile in the near term, he said. Firms with both upstream and downstream businesses will remain in better shape, he added. Nasser laid out Saudi Aramco’s fourpoint framework for the future, which has similar applications to the broader industry, he said. The plan focuses on resilience, innovation, managing talent, and collaboration. Noting that many smaller companies have filed for bankruptcy because they were overleveraged, he emphasized that a strong financial position, and diversity beyond just the upstream, will help companies survive in times such as these. It also allows for continued investment in technology and building capable human resources.

Saudi Aramco is “pushing the envelope” with additional emphasis on R&D, opening satellite research centers, pursuing venture capital, and putting renewed effort on increasing recovery factors. Despite tough times, “now is the time to reboot our approach to human resources,” he said, including establishing a professional development center, strengthening ties at the university level, and bringing more women into key positions. Similarly, ADNOC is rethinking strategy to position itself better for the future. In the past 6 months, the state firm has adopted four pillars that will mark its priorities going forward, said Al Kindy. “We are going to become a smarter, more agile organization,” he said. He also emphasized the importance of developing staff, adding that the company is committed to developing the next generation of leaders judged on merit and will work to empower women, a neglected human resource in the industry. ADNOC will focus on four strategic areas, he said: enhancing the company’s performance, increasing profitability, optimizing efficiency, and investing in

JPT • NOVEMBER 2016

people. It wants to speed up time from discovery to first production and will invite partners to help it achieve this goal, and will increase R&D in upstream to develop new sources of production. Nathan Meehan, 2016 SPE President, closed the opening session by noting the visionary leadership in the UAE that has developed many world-class facilities over the past several decades. The oil and gas industry needs similar vision, and its younger leaders must “stand on the shoulders of giants” in able to “see further” and succeed in supplying the world’s energy, no matter the oil price.

Service Company Viewpoint A common theme running through the conference was how the current downturn is reshaping oil and gas industry operations. There is a growing consensus that while oil prices remain depressed, the supply glut is giving way to market balance. But if non-OPEC production continues to decline as it is, the new concern is that any equilibrium between supply and demand will be short-lived. Paal Kibsgaard, CEO of Schlumberger, said the industry has reached the bottom of the downturn cycle and must begin investing again in order to keep the pendulum from swinging too far the other way. “There is no way you can maintain medium- and long-term supply capacity with half the investment—it just doesn’t work,” he said, adding that oil markets

JPT • NOVEMBER 2016

are facing a supply crunch within 2 years if the industry does not increase spending quickly. Kibsgaard gave his remarks during a panel session on the future of E&P. As more money comes off the sidelines and into play, Kibsgaard emphasized that it needs to be spent more wisely than before. That will require service companies and operators to form tighter relationships when it comes to designing new technologies that will substantially lower finding and lifting costs. Kibsgaard said greater collaboration must also involve moving away from the practice of developing individual technology components and “toward developing complete technology systems, including all aspects of hardware and software.” As examples, he cited Schlumberger’s development of a new integrated land rig system and its recent acquisition of Cameron International, a deal aimed at marrying the two firms’ surface and subsurface capabilities. Also on the panel was Martin Craighead, CEO of Baker Hughes, who echoed the need for increased spending, which he said “will allow the industry to maximize growth opportunities and become more resilient in the downturns of the future.” He highlighted several technologies that will benefit from a new wave of investments, ones that he said also will define the future of his company. Those technologies include 3D print-

More than 7,500 industry professionals attended SPE’s flagship conference. From left, technical sessions covered all facets of the upstream industry; Abdul Munim Saif Al Kindy, director of exploration development and production for ADNOC, welcomes conference attendees; the SPE/UFRJ Student Chapter was the first South American team to win the PetroBowl; Ali Daneshy receives Honorary Membership at the annual banquet; 2016 President Nathan Meehan and conference dignitaries cut the ribbon opening the exhibit; and Amin H. Nasser, president and CEO of Saudi Aramco delivers the opening keynote address.

ing, material sciences, automation, and sensors. He said of the latter, “Advances in sensors and networking are embedding intelligence into every piece of hardware, creating a new metasystem that is changing the way tools, as well as materials, interact with each other.” Craighead also discussed the importance of investing in new mindsets. He said in an effort to capture some of the inspiration that has driven the rapid growth of the US software sector, the company opened a technology center in Palo Alto, California, USA—aka Silicon Valley. “You have a Baker Hughes office in Palo Alto and nobody knows what the heck that is, certainly none of the Google, Apple, or Yahoo people,” he said. “But it was about embedding our folks out there in that culture to experiment fast, learn fast, and fail fast.” That willingness to fail and move on, he noted, is what made the US shale revolution possible and is now what the rest of the oil and gas industry needs to embrace if it is to become a more sustainable business.

Greater Efficiency Across Operations During a session on the second day of the conference, both service providers and national oil companies debated what is required to increase efficiency in E&P operations. National oil company executives on the panel called for greater standard-

ization of materials and processes, increased automation, more effective use of data, and greater collaboration across the industry. The oil and gas industry needs efficiency solutions not just for the short term but for the next decade, said panel moderator Amran Marhubi, technical director for Petroleum Development Oman. “Lower prices are going

to be with us for quite some time,” he said. Despite the downturn, Saudi Aramco is not slowing its initiatives but is continually trying to increase efficiency, in rate of penetration, decreasing unit costs, limiting nonproductive time, and in other areas, said AbdulHameed AlRushaid, executive director, drilling and

New SPE President Promises To Lead and Engage Members Trent Jacobs, JPT Senior Technology Writer The final day of the SPE Annual Technology Conference and Exhibition in Dubai marked the beginning of the leadership term for 2017 SPE President Janeen Judah of Chevron. Judah assumed the organization’s top position during the annual President’s Luncheon on the last day of the conference. During her association with SPE, she has served on the Board of Directors as vice president of finance and has also chaired both the SPE Gulf Coast and Permian Basin sections. In her inaugural address, Judah acknowledged the struggles facing the industry but struck a hopeful tone, insisting that the industry will adapt to the reality of lower oil prices. “Today’s crude prices will force innovations in technology and business models, changing again how oil and gas is produced and developed,” she said. “Ultimately, we see an oil and gas industry that will be stronger, leaner, and built to last.” Like many of the companies that its members work for, SPE is navigating through challenging financial conditions, she said, and her primary goal will be to make sure any changes have minimal impact on member services. “While we modernize some of our member offerings, we will stay true to the core reason I believe people get involved in SPE: the personal relationships that we offer,” she said. “Meeting other engineers in person is the way to build business connections, and I think that is a big role that SPE plays for our members.” Judah said she will spend the next year working to promote the development of engineers in developing countries. Governments of many oil-producing nations have called on international operating and service companies to help cultivate local talent, and Judah emphasized that SPE will continue to be part of that effort under her leadership. And as the first woman SPE president in more than a decade, Judah promised to be accessible and visible to women working in the industry. “I realized many years ago that I am an example for young women engineers—whether I choose to be or not,” she related. “So you might as well step into the role, step into these shoes, and be proud.”

2016 SPE President Nathan Meehan hands incoming 2017 SPE President Janeen Judah the organization’s ceremonial gavel. In addition to traveling to local SPE sections around the globe, Judah said she will be actively engaging with members on social media. She plans to continue posting regular blog updates on LinkedIn and will be holding interactive discussions on both Facebook and Twitter. Handing Judah the ceremonial gavel was outgoing 2016 SPE President Nathan Meehan, a senior executive advisor at Baker Hughes. In his remarks as the outgoing leader, Meehan highlighted how increased access to fossil fuel energy has helped lift millions of people out of poverty. But he also stressed that SPE members must be cognizant of the world’s growing concerns over the environment and climate change. “Regardless of your beliefs about the role of anthropomorphic greenhouse gases in climate change, we must not ignore our role. We have to be part of the solution and not just be perceived as the problem,” he said.

JPT • NOVEMBER 2016

Schlumberger CEO Paal Kibsgaard said the industry must start spending more to maintain supply capacity.

workover, Saudi Aramco. “We are at a historical level in our E&P activities,” he said, adding that the company has introduced “more stringent” key performance indicators to wring more value out of its operations. ADNOC is also paying more attention to how it can improve costs and operations, said Mohamed Al Mutawa, manager of production and facilities engineering for the company. It now examines each cost factor in several categories— including rigs, drilling, workover, logging, and fluids—in every project, looking for potential savings. During a question-and-answer session, some in the audience asked whether operators were “squeezing” service companies and drilling contractors to improve their bottom line in the short term. “Operators are also sharing the pain” caused by lower oil prices, said Al-Rushaid of Saudi Aramco. But he acknowledged that the industry needs positive working relationships among operators, contractors, and the service sector. “Some drilling

contractors have gone out of business and this is not healthy for the industry,” he said. There is a distinct danger when the industry equates value just to unit cost, said Jim Friedheim, marketing and technology manager with M-I SWACO and a Schlumberger scientific advisor. Increasing value is not just about decreasing costs, it is about becoming more efficient and improving overall returns. “Rais-

ing efficiency raises value,” he said, adding that sometimes increasing efficiency requires spending money. If the industry puts a larger economic burden on the service sector during this downturn, “we will be killing the golden goose, killing the future,” he said, because it inevitably will slow technology innovation. Friedheim and Mette Munkholm, director of logging-while-drilling with

ENVENTURE. PUNCHING THROUGH. When you’re pushing the limits of exploration and development, you need extreme technology. Enventure’s proven ESET® solid expandable liner technology is engineered for toughness and reliability to help you reach Total Depth while minimizing NPT. Here’s how: s Rotate across ledges and through tortuous wellbores s Rotate and reciprocate to improve cementation of expanded liner Add more punch to your process with ESET® technology from Enventure. To find out more, visit us at: www.EnventureGT.com/ESET

Additional Conference Highlights Unconventional Push in Saudi Arabia

First Saudi CO2 EOR Project

Saudi Aramco has begun moving toward the production phase of its ambitious plan to develop its enormous unconventional gas resources. Khalid Al-Abdulqader, general manager unconventional resources for Saudi Aramco, said it is currently letting contracts for development drilling in North Arabia. That is one of three areas where Saudi Arabia is focusing on developing gas from reservoirs where fracturing is required to produce gas to replace oil now burned for power generation. Commercial-scale production of gas from the three areas could come as early as 2021, he said during the session. After the session, he clarified that while that is a reasonable estimate, it is too soon to be making commitments. The unconventional potential is enormous, with a resource 10 times the volume of the conventional oil and gas in the ground there.

Saudi Aramco’s first test of using carbon dioxide (CO2) injection to extend the life of a field resulted in a fourfold increase in oil production in the first year. “The response has been very positive,” said Sunil Kokal, a principal consultant for Saudi Aramco on enhanced oil recovery (EOR), who presented a paper on the project (SPE 181729) at the conference. As a result, the water cut dropped significantly from about 98% water produced to 90%. The jump in production came by using a type of EOR that often takes years to show its full benefit. In this case, the injections only lasted for about half a year because of shutdowns for maintenance. Kokal cautioned that it is too early to judge the results of the pilot project, pointing out that “the next year will be critical.”

Dubai Fractures Offshore Well Driven by the need to boost oil reserves, Dubai Petroleum announced that it completed its first multistage, hydraulically fractured, and propped horizontal well from an offshore platform in April. The government-owned oil company, which primarily operates offshore wells, reports that because the project targeted an unconventional formation, known as the Shilaif, with completion techniques used almost exclusively onshore, it may be the first of its kind for the offshore sector. “We believe this will be part of the future for Dubai as an oil-producing country,” said Frederic Chemin, a general manger with Dubai Petroleum, adding, “because of the size of the reserves we will be working very hard on this.” The company has not disclosed production rates but said the well was successfully propped and is flowing oil with only a 3% water cut. The Shilaif formation is estimated to hold 22 billion barrels of recoverable oil.

Baker Hughes, said the current environment has forced their companies to cut some research and to focus primarily on potential high-impact technologies. “There is no doubt that when you have less revenue, it affects what you can do,” Munkholm said.

Roles of Humans and Machines A session promising radical new ideas for “Innovation Beyond Limits” provoked questions about whether there is a limit to the degree that digital intelligence can supplant human decision making.

Human Factors Key in Megaprojects On a panel discussing megaprojects, Faud Al-Azman, the general manager of area projects for Saudi Aramco, said that addressing human-related problems is the key to making these multibillion-dollar developments economic. He said that 65% of megaprojects miss their original performance goals, and that the root cause is almost always the decisions made by employees, corporate management, or government regulators. Al-Azman explained how this pushed Saudi Aramco to adopt new management strategies for the development of its latest refinery and power generation megaproject—the Jazan Complex. The project involves more than 1,110 contractors and supply vendors, along with 70,000 construction workers. To avoid costly mistakes, the company is using an automated management database to track the progress of all its contractors and holds regular mini-conferences to scrutinize agendas. To ensure the project moves in the right direction, “we must strive to continue to learn as individuals, teams, and as organizations,” Al-Azman said. “Projects by their nature are very dynamic and they will not stand still— why should we?”

The panel began with presentations that predictably played up how analytics and big data will shape the future of the energy industry. Machines were celebrated for their ability to create value from the exploding volume of data in this wired world by speakers who warned workers of the jolt of change to come. “The next wave of big data and analytics will lead to the next wave, which is artificial intelligence, and that will lead to machine-to-machine learning,” said Alisa Choong, executive vice president

of competitive and technical IT at Shell. “For every science we have, there will be an element of computing and algorithms in there. Data science will be like reading grammar, and coding like reading and writing a foreign language.” Jobs titles will change and “people will need to be reskilled” for jobs such as coordinating and maintaining robots, she suggested. Panelists described how machines are becoming increasingly able to “learn” and automate processes, which raised questions about what humans would

JPT • NOVEMBER 2016

be doing. “We want to maintain the experience of people by putting it into machines that can learn from it and make it better,” said Mahmoud Kassem, executive vice president, surface, at GE Oil and Gas. The comment cards from the audience, many of whom identified themselves as previously working for a company in the oil industry, pushed back at those comments, prompting the moderator, Khaled Nouh, founder and managing partner of Eternal Consultants, to ask about the downside of a world in which machines talking to machines will play such a large role. “My wife, who is an economist, said we will destroy the economy of the world because we will have machines doing everything,” said Nouh. He asked the panelists to discuss “what are the humans doing here?” “In every industry revolution, you see more jobs created than job losses, but the jobs of the future many not exist today,” Choong said, adding that a new generation of workers who grew up with digital

technologies will have different expectations about the role of computers in the workforce. “If we do not inject new technology, we will become an unattractive industry to work in,” Kassem said, adding that E&P “will always have the human factor.” While analytics are required for decision makers to make use of masses of data—Choong calls it “augmented intelligence”—there will remain uncertainty and unknowns, which is something that humans are uniquely equipped to handle. “Our industry has utilized big data since the beginning,” said Roberto Dall’Omo, senior vice president of upstream R&D for Eni. The volume of data gathered and processed for seismic imaging has long made the industry a leader in supercomputing, “but in the end a human decides what is the best structure.” Innovation is another area that humans can do, but computers cannot. At the current low oil prices, it is essential for E&P companies for survival. But in that line of work, a traditional degree

in petroleum engineering is no guarantee of success. “During the last growth spurt in the industry from 2010 to 2014, two-thirds of the people hired [in Halliburton R&D] were from companies outside oil and gas,” said Greg Powers, vice president of technology at Halliburton. “Our patenting went up nearly 400%. The people who say you cannot hire people unless they are from oil and gas, I would tell you they are completely wrong.” And with the industry struggling to adapt to continued low oil prices, top people remain an essential commodity. “The longer oil prices stay this low, the greater the challenge to sustain production, putting a priority on human capital investments to ensure people with new skills are there when needed,” said Waleed Al-Mulhim manager of Saudi Aramco’s EXPEC Advanced Research Center. JPT JPT Editors John Donnelly, Stephen Rassenfoss, and Trent Jacobs contributed to this report.

HIPPS

SALARY SURVEY

Annual Survey Shows Declining Industry Salaries Petroleum industry professionals reported an average calculated total compensation of USD 185,001 in 2016 (Table 1 and Fig. 1), less than reported in previous years, according to the latest annual SPE Salary Survey. Total compensation in previous years was USD 206,020 in 2015, USD 214,328 in 2014, and USD 203,557 in 2013. Although the reported compensation in 2016 is less than in 2015, 35.9% of this year’s respondents indicated that their base pay increased from 2015 to 2016. However, this is a smaller figure than the previous 2 years’ percentage increases in base pay (58.5% saw an increase in 2015 and 82.2% saw an increase in 2014 from the previous year). Calculated mean base pay reported in 2016 declined (USD 143,006) from previous years, while other compensation (including bonuses) has been declining

since 2013. In 2016, members reported an average of USD 41,995 in other compensation. Again, this was a decrease from previous years (USD 52,931 in 2015 and USD 57,889 in 2014). The number of professionals receiving a car allowance also continued to decline, and was 24.6% in 2016. Respondents to the survey had an average industry experience of 18 years. The number of professionals who reported an education level higher than a bachelor’s degree was 43.8% in 2016.

Job Categories and Total Compensation The global mean for total compensation declined for every job category from 2015 to 2016 (Table 2). The most marked declines are from the top-tier professionals from the Africa; Oceania, Australia,

and New Zealand; and South, Central, and Eastern Europe regions. The professional and technician categories maintained the highest stability overall. For these two categories, nearly half of the regions were able to maintain or increase their level of compensation from 2015. Those who saw a decrease in salary experienced less of a decline in their compensation overall than the top tier of professionals.

Change in Base Pay by Region Overall, 13.8% of respondents reported a decline in their base pay in 2016, and 35.9% of respondents reported an increase (Table 3), a clear change from 2015 survey results (6.6% of respondents saw a decline; 58.5% of respondents saw an increase). Although the percentages stayed consistent for decrease in base pay across

Table 1—Summary of Results by Work Region (compensation expressed in USD)

Total

Africa

Oceania, Australia, and New Zealand

143,006 127,000

170,507 152,256

107,829 77,761

147,681 123,598

120,290 100,725

128,637 108,903

130,093 111,947

104,070 60,000

87,993 68,531

94,640 61,556

86,807 49,360

Other compensation Mean 41,995 Median 16,000

54,561 25,000

42,691 9,253

22,982 11,515

41,999 14,129

34,408 13,421

29,046 14,022

28,985 2,911

20,341 4,553

18,336 4,194

24,489 3,832

Total compensation Mean 185,001 Median 150,000

225,068 186,000

150,520 100,311

170,663 142,022

162,289 116,171

163,045 136,945

159,138 128,880

133,054 64,791

108,333 80,000

112,976 67,943

111,296 58,213

Base pay Mean Median

Middle East

Northern and Central Asia

South America, Caribbean, and Mexico

South, Central, and Eastern Southeast Europe Asia

Average base pay increase (%)

8.1

5.4

8.2

5.1

5.0

5.4

6.1

27.5

6.7

6.8

% With car allowance

24.6

19.3

58.0

12.2

16.8

43.0

34.4

26.4

19.2

23.6

41.2

Average age

18.1

19.6

15.2

16.8

16.7

16.9

18.4

15.5

14.9

15.3

14.8

Education beyond 43.8 bachelor’s degree (%)

33.8

53.8

48.9

29.1

56.7

69.6

71.2

53.5

84.7

34.1

% Citizens of work region

88.1

72.0

73.4

88.4

24.5

70.8

73.6

84.2

66.7

67.0

Average years of experience

Canada

Nor th Sea and North At lantic

79.1

JPT • NOVEMBER 2016

p opl po d The power of our resources means nothing without the energy of our people. Their focus and expertise make our energy more dependable, more sustainable, and more useful. We are looking for experienced petroleum engineers and geoscientists to join our team. Apply now.

www.aramco.jobs/jpt

Average Base Pay

54,561

Average Other Compensation

41,995

22,982

150,000

41,999

South, Central, and Eastern Europe

Southeast Asia

87,993

North Sea and North Atlantic

104,070

Middle East

120,290

Oceania, Canada Australia, and New Zealand

Northern South and America, Central Caribbean, Asia and Mexico

Fig. 1—Professionals in the US reported the highest base pay and other compensation.

24,489 86,807

Africa

18,336 94,640

United States of America

130,093

Total

128,637

29,046

20,341

147,681

50,000

34,408

28,985

107,829

100,000

170,507

42,691 143,006

Income (USD)

200,000

Table 2—Total Compensation by Job Category and Work Region (USD)

Africa

Oceania, Australia, and New Zealand

Executive/ Top Management

395,952

133,335

259,219

364,121

240,838

202,941

451,877

188,527

183,241

108,080

Manager/Director

274,083

249,516

234,274

180,396

190,798

202,065

265,270

190,075

189,454

185,174

Supervisor/ Superintendent/Lead

227,012

167,563

156,925

137,514

162,106

163,867

62,151

120,477

147,807

128,689

Professional/Individual Contributor

181,915

94,258

140,227

132,763

157,045

142,957

68,197

77,927

64,538

69,705

Technician/Specialist/ Support Staff

130,050

43,178

107,908

95,316

108,493

92,095

69,431

102,301

32,747

83,569

the regions from 2015 to 2016, there were a few considerable differences from 2015 for some of the regions for increase in base pay. The US, Canada, and Middle East regions had fewer respondents who saw an increase in their base pay in 2016, with the US down 28.4%, Canada down 27.6%, and the Middle East region down 25.8% from last year. Increase in average base pay by region remained consistent from 2015 to 2016. While all other regions’ salary increases hovered around 5–8% (4–9% in 2015), the South America, Caribbean, and Mexico region had a 27.5% average base pay increase (25.2% in 2015). Decrease in average base pay by region remained consistent from 2015 to 2016, with a few exceptions. Oceania, Australia, and New Zealand dropped from −21.3% in 2015 to −31.9% in 2016. The North Sea and North Atlantic region (−18.7% in 2015) saw the largest percentage decline in average base pay in 2016 to −30.3%.

Canada

Middle East

Nor th Sea and North At lantic

Northern and Central Asia

South America, Caribbean, and Mexico

South, Central, and Eastern Southeast Europe Asia

Table 3—Changes in Base Pay by Region (%)

Base Region

Increase in Base Pay

No Change in Base Pay

Decrease in Base Pay

32.2

54.6

13.2

Africa

57.3

31.7

11.0

Oceania, Australia, and New Zealand

37.4

50.4

12.2

Canada

24.2

52.0

23.7

Middle East

36.5

45.9

17.6

North Sea and North Atlantic

37.4

47.9

14.7

Northern and Central Asia

30.2

50.9

18.9

South America, Caribbean, and Mexico

54.1

36.5

9.5

South, Central, and Eastern Europe

27.8

63.9

8.3

Southeast Asia

48.6

42.5

8.9

How To Learn More This report represents a sample of current compensation in the industry. A detailed summary report containing charts and descriptive statistics of

trends and more information on the jobs, geographies, and employer types are available through the SPE Bookstore at www.spe.org/store. JPT

JPT • NOVEMBER 2016

JPT Magazine - November - Griffin | 8.125” x 10.875” | FINALREV

peloton.com/griffin

It’s no myth. Finally, you can get production software even PAs will love.

REV1660-24627_JPT_Magazine_Nov_Griffin_8_125x10_875_FINALREV.indd 1

2016-09-20 4:04 PM

Standardization May Hold Key to Future of Major Offshore Projects Joel Parshall, JPT Features Editor

educing the complexity and controlling the cost of major offshore projects are together one of the biggest challenges facing the oil and gas industry. The collapse of oil prices has only accentuated the issue, which was already evident when prices were still at USD 100/bbl. To combat the problem, operators are looking at ways to standardize and simplify projects globally as a means of expediting design, construction, installation, and startup; reducing costs throughout the process; and creating safer, more predictable, reliable facility operations.

The scale and complexity of many deepwater projects have driven costs out of control, despite the cyclical pullback of the past 2 years that has reduced the number of active projects and caused equipment and service providers to cut prices. An analysis of 400 major projects executed in the last 5 to 10 years, cited by Jim Nyquist of Emerson Process Management in a presentation at the IHS CERAWeek conference in Houston, showed a 65% failure rate based on cost overruns of at least 25% or schedule overruns of at least 50%.

Current focus SPAR

In order of complexity

Project

Future focus for industry

Power generation module

Systems (modules) Turbine generator package Packages (subsystems)

Equipment and bulk materials

Low-voltage switchgear

The global project standardization initiative facilitated by the International Association of Oil & Gas Producers (IOGP) is focusing on equipment and bulk materials (component) standardization in Joint Industry Project 33 (JIP33). In addition to low-voltage switchgear, JIP33 is working on standardization of ball valves, subsea wellheads, and piping and valve material through developing standardized procurement specifications for all of these components. IOGP sees future standardization efforts progressing to areas of increasing complexity in offshore projects. Image courtesy of the World Economic Forum.

Focus on Capital Efficiency Many of the projects analyzed were launched before the breadth of the shale revolution was apparent. In a future offshore market recovery, in contrast to prior upturns, potential major projects will likely be evaluated against highly competitive shale development plays in the quest for investment funding. The focus on capital efficiency will be even greater, which is why increasing standardization across global projects is likely to become an essential competitive strategy for major offshore operators irrespective of market conditions. Probably the broadest initiative so far to push for global standardization in upstream development activity is Joint Industry Project 33 (JIP33), facilitated by the International Association of Oil & Gas Producers (IOGP) and supported by the World Economic Forum (WEF), whose “Capital Project Complexity” workstream is being used throughout the project. The workstream’s core focus is on improving industrywide noncompetitive collaboration aimed at the standardization and reuse of procurement specifications that build on industry and international standards. In doing so, the oil and gas industry could decrease project costs and improve schedules. Moreover, the industry would likely capture a number of additional benefits, including improved engineering efficiency, enhanced equipment reliability and quality, and increased safety. JIP33, which was launched in November last year, includes 17 companies that represent a cross-section of the global upstream industry: BP, Chevron, Engie, Eni, ExxonMobil, Maersk, OMV, Pemex, PTTEP, Repsol, Saudi Aramco, Shell, Sonangol, Statoil, Total, Wintershall, and Woodside.

JPT • NOVEMBER 2016

Operators Overspending “Operators across the world are spending much more than needed on developing capital projects,” said Gordon Ballard, IOGP executive director. “Following an IOGP benchmarking exercise in 2014, we realized that despite decades of API, ISO, and industry standards work creating thousands of standards across the industry, operating companies still tend to develop and hold onto large volumes of their own specifications. “These bespoke designs supplement the industry and international standards and create further engineering cost and schedule implications for operators and contractors.” Company specifications of this type are often referred to as preferential engineering and sometimes more pejoratively as gold-plating.

Industry Erodes Value “The industry has been eroding value by creating bespoke components in each of our projects and in doing so has missed the opportunity to leverage industry-level standardization,” said Ian Cummins, head of upstream engineering at BP and chair of the JIP33 steering committee. “Standardization is a huge benefit. Everyone is clear about that. Other industries reflect standardization—the aviation industry, the automobile industry, and shipping. And we’ve progressed it within the oil and gas industry, but one might argue not to the same level.” JIP33 is focusing on the standardization of equipment and bulk materials (components), which represent the building blocks common to major projects. To prove the concept, the JIP is developing standardized equipment specifications for the procurement of several components: ball valves, subsea Christmas trees, low-voltage switchgear, and piping and valve materials, which were recently added to the project scope. This effort will be completed by year-end and will incorporate supplier feedback. A draft document on the industry culture change needed for successful standardization was discussed at a June WEF workshop and has been finalized.

JPT • NOVEMBER 2016

The objective is to show that these specifications can be standardized across the industry at the component level to give impetus to standardizing them for the vast array of components used in oil and gas projects. With success at this level, standardization could expand to packages (subsystems), modules (systems), and eventually projects themselves.

Looking at Procurement Procurement specifications represent the document package that an operator sends to a vendor to obtain a potential bid. If those specifications for a component are standardized, for example, the components delivered will be standardized. To focus on standardizing procurement specifications is to attack the problem of bespoke designs and preferential engineering at its source, as Cummins explains about BP’s efforts over the past several years to increase project standardization internally. “In BP, we were spending millions of dollars per major project recreating procurement specifications based on interpretation of our design standards,” he said. “We saw different projects ordering the same equipment—at the same time from the same supplier—with different procurement specifications. And it was not just those specifications, we asked for different documentation and different inspection and test requirements.”

Avoid Reinventing the Wheel “This was literally destroying value from the outset,” Cummins continued, “spending money reinventing the wheel. And this affects your ability to consistently engineer reliable facilities that start up and stay up.” To address the lack of consistency, BP has developed a suite of standardized procurement specifications that now number more than 300 and continues to grow as additional specifications are written. The specifications, with supporting quality and documentation requirements, are based on company and industry design standards and are used across projects companywide, supplemented only by specific project data.

As internally standardized specifications have been developed, the company has benefited by seeking direct feedback from its suppliers. “In a downturn, we traditionally turn to our suppliers and request cost reductions, and we must continue to challenge these costs,” Cummins said. “However, we can also jointly challenge costs by challenging our requirements, where we have gone beyond good practice and, in the supplier’s view, required things that do not add to the safety, integrity, or performance of the equipment. Using this insight, we can remove inefficiency in our project execution, and with this approach we are good for all seasons.” Standardization of procurement specifications, Cummins noted, holds benefits at a number of levels. ◗ Procurement cycles become shorter, with improved, more predictable schedules. For example, BP has reduced its typical bid evaluation period for major rotating equipment from more than a year to less than 6 months. ◗ Direct savings amounting to millions of dollars per project result from using the same specifications rather than rewriting them. ◗ Significant, often greater savings result from eliminating unnecessary costs related to preferential engineering. ◗ Removing unnecessary requirements, inconsistencies, and features reflecting preferential engineering leads to fewer fabrication defects and reduced risk. ◗ Engineering teams can focus on optimizing design rather than rewriting procurement specifications. ◗ A consistent language emerges on technical requirements, which engineering teams can use globally across the portfolio of projects. ◗ A common global learning platform takes hold so that lessons captured can be fed into future projects by updating the specifications. The ultimate success of JIP33 will depend on whether the procurement specifications it develops are put to

use by companies and the push toward standardization continues. Ballard is hopeful. “With support from our members’ own senior managements, and the value of the input provided by the WEF, we are optimistic that this effort will succeed,” he said. “The economic benefit will probably become evident several years down the road, as we actually see equipment delivered more costeffectively. But the prize is very big and worth waiting for.”

Overcoming Cultural Barrier The biggest barrier to moving toward standardization may be cultural. “It’s not so much the technical side of it. That’s pretty straightforward,” Cummins said. “I think that all operators have got to, from the top down, embed a culture of standardization and collaboration, which is actually quite challenging because trying to align technical experts can sometimes be difficult. And that’s not a criticism. They’ve got many years of experience and learnings. It’s pulling that team together into a room and having that discussion to get that standard going forward. “What we don’t want, though, and we’ve got to be careful,” he continued, “is that when we standardize a procurement specification, we just include the minimum requirements that all the operators agree on. That way, the operators individually are likely to take it and add their own requirements, and the supplier will again see different specifications coming in. So the process is about agreeing on the whole specification.” In the end, operators want the same thing, projects that are managed safely, start up on schedule, and stay up. And operators need to ensure that future projects that can meet those objectives are economically viable. Standardization holds the potential to achieve large cost savings, improve schedules, and reduce risk. If embraced, standardization will bring a cultural change in which standards will form a global framework to shape and drive all projects and collaboration across companies. “We are an innovative industry,” Cummins said. “Why not be innovative and standardize?” JPT

JPT • NOVEMBER 2016

TECHNOLOGY FOCUS

Drilling and Completion Fluids Badrul Mohamed Jan, SPE, Researcher and Academic Lecturer, Department of Chemical Engineering, University of Malaya This year marked the third year after completing my tenure as the deputy director of the University of Malaya Center of Innovation and Commercialization (UMCIC). UMCIC is the technology transfer office at the University of Malaya (UM), which is responsible for protecting UM’s inventions through intellectualproperty registration such as patents, copyrights, and trade secrets. Despite that, this year remained a busy and challenging year for most academics and researchers, specifically in Malaysia. Unstable oil price has a great effect on Malaysia, where the economy largely relies on the petroleum industry, reducing the research-funding assistance from the government. In fact, research funding has been slashed, and the university is expected to generate its own income. Apparently, it is time for the university to restrategize its research endeavors. Many of us were surprised by the collapse of crude-oil prices in 2014. Even though oil price currently seems stable at almost USD 50/bbl, it is still volatile. Maria Gallucci highlighted in her business column in International Business Times magazine the fact that scientists at Louisiana State University (LSU) were working on the Tuscaloo Marine Shale when oil was approximately USD 100/bbl. The Tuscaloo Marine Shale is a large rock formation in the middle of the state believed to hold billions of barrels of

crude. Many oil and gas companies were keen to embark on the research study, which mainly focused on the shale’s geological nature and potential drilling prospects. However, today tells a different tale. According to David Dismukes, executive director of LSU’s Center for Energy Studies in Baton Rouge, the interest has dissipated before eventually vanishing. The outlook in getting new projects in the private sector is slim to none. There is a similar outlook in other parts of the US, where research funding is severely battered by the low oil price. It is part of the long-term and broader initiative to slash costs. In most academic settings, innovation and exploration activities are shrinking if not halted. As they say, we not only need to work hard, but also, and most importantly, we need to work smart, especially during this trying time. With shrinking budgets and limited resources, partnerships and collaboration are considered the best options. It is no secret that universities and industry have a special platform to work hand-in-hand. Successful partnership between universities and industry can be realized only through innovation, knowledge, and technological findings. In Malaysia, for example, for the past 3 years, the government has initiated a specific program called Incubator Industry-University, or I2U. Under the I2U program, special funding was allocat-

Badrul Mohamed Jan, SPE, is a researcher and academic lecturer attached to the Department of Chemical Engineering, University of Malaya (UM), Malaysia. He holds BS, MS, and PhD degrees in petroleum engineering from the New Mexico Institute of Mining and Technology. Jan’s research areas and interests include the development of superlightweight completion fluids for underbalanced perforation and ultralow-interfacial-tension microemulsion for enhanced oil recovery. He is the recipient of the 2016 SPE Distinguished Achievement Award for Petroleum Engineering Faculty for the Northern Asia Pacific Region. Jan is a member of the JPT Editorial Committee and can be reached at badrules@um.edu.my.

JPT • NOVEMBER 2016

ed to two research universities to build an incubator that provides special spaces with sufficient supports for researchers to develop their prototype before entering the real market. UM has been selected as one of the pioneers of the program. Some of the incubator spaces are also reserved for real industry players to create real industry working environments within the incubator. A specific space is also reserved for service incubators, which refers to space meant for industry to provide its upstream oil-and-gas-specific services, such as pressure/volume/temperature fluid testing, core-test analysis, and material-testing studies. Such an arrangement would bring industry and the university closer than ever before, and both parties will benefit. Industry, specifically the small/medium industry and the small/medium enterprise with a very limited budget, will have the opportunity to access much specialized and state-of-the-art equipment available at the university. In short, it is an ideal route for a win/win collaboration. JPT

Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18539 Nanographene Application Improving Drilling-Fluids Performance by Norasazly Mohd Taha, Scomi KMC, et al. OTC 26165 Novelties in Nonemulsifiers for Completion Brines: Adapting Chemicals to Brazilian Oilfield Challenges by O.C.C. Poltronieri, Oxiteno, et al. SPE/IADC 180565 A Novel Environmentally Friendly Lubricant for Water-Based Drilling Fluids as a New Application for Biodiesel by Wai Li, China University of Petroleum, et al. SPE/IADC 180686 An Innovative Model-Assisted Drilling-Fluid Optimization Using Iterative Solids/Filtration Invasion Simulation To Maximize Well Productivity by Muhammad Ihsan Aljabbar, Bandung Institute of Technology, et al.

Method for Monitoring Mud Contamination in Wireline-Formation-Tester Sampling

he wireline formation tester (WFT) is a well-developed technology used to collect representative downhole fluid samples. Collecting low-contamination downhole samples in wells drilled with miscible oil-based mud (OBM) is challenging because the process must balance the need to acquire a sample with the desired level of contamination while using the minimum rig time. The authors introduce a simple but effective method for monitoring WFT sampling when targeting the low levels of contamination needed for asphaltene-onset-pressure analysis.

Introduction Flow-assurance problems caused by asphaltene deposition are common reasons for lost and deferred production in Gulf of Mexico Miocene reservoirs. Highquality samples are needed to measure the asphaltene-onset pressure and manage related flow-assurance problems. The asphaltene-onset pressure varies with the level of OBM contamination. The rise of asphaltene-related flow-assurance issues encourages operators to acquire high-quality downhole samples with the lowest possible OBM contamination. To reduce OBM contamination, operators have to pump out fluid from the formation to the borehole before filling the samples at the desired OBMcontamination level. There is not a standard procedure to determine a sample’s contamination level during the pumpout. Engineers sometimes rely on empirical evidence and previous experience to determine contamination levels. This

study introduces a practical method to estimate the contamination level from real-time fluid-analyzer data. A discussion of methods used to predict contamination is provided in the complete paper.

Conventional and Focused Probes The most-common probes used for downhole sampling in the oil industry are conventional and focused probes. Conventional probes have a single inlet to take formation fluid; the inlet is surrounded by a sealing material to isolate formation fluids from the wellbore mud column. Focused probes are available from several service companies. These probes can use a hydraulic ring inlet (guard) surrounding the probe inlet (sample) to create a barrier between the probe and the borehole fluid. The guard and sample are connected to separate hydraulic systems that allow controlling the pump rates to maintain the pressure in the guard at or slightly below the pressure in the sample. By doing this, most of the fluid drawn into the sample will be uncontaminated fluid. After the cleanout pumping, fluid from the sample inlet will be used to fill the tanks. A comparison of conventional and focused WFT probes when fluid sampling in the presence of oil-based filtrate invasion showed that focused probes can achieve lower contamination levels than conventional probes can, at a similar pump-out time. Results also showed that a focused probe provides improvements in cleanout time compared with a conventional probe for all variations of formation permeability anisotropy,

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175116, “Effective Method for Monitoring Oil-Based-Mud Contamination in Wireline-Formation-Tester Sampling,” by W. Pineda, BP; F. Gozalpour, formerly BP; and Mehdi Hagshenas, BP, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

sample-to-guard flow-rate ratio, and mud-invasion rate.

Contamination-PredictionMethod Development The method presented is developed in WFT sampling with a focused probe using gas/oil ratio (GOR) to monitor the cleanout process. However, method development is independent of probe geometry and may be applicable to standard probes. When using the focused probe, it is common to commingle the fluid from the guard and the sample line in the early times of pumping. Then, they are split into two separate lines with fluid analyzers that provide two separate GOR curves: the guard GOR and the sample GOR. These GORs are measured by the downhole near-infrared spectroscopy tool and are not necessarily calibrated to correspond to surface volumetric GORs. Numerical simulations show that, when sampling oil in the presence of water-based mud, the sample quality vs. time exhibits an approximately linear behavior when plotted vs. logarithm of time. In the presence of OBM, the behavior is not linear anymore but could be approximated by three different lines: one for the early time, one for the middle time, and one for the late time. This provides a hint that, after a particular time, sample quality improvement could be approximated by a line when using an exponential transformation to represent the pump-out time. The prediction method uses an exponential-type function to extrapolate GOR to infinity; once GOR at infinite time is found, current GOR is presented as a percentage of that value. This function is described in detail in the complete paper.

Application and Discussion The method presented in this paper was used to collect oil samples from deepwater Miocene turbidite formations.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 46

JPT • NOVEMBER 2016

11 OBM contamination from laboratory (%)

10 9

Real-time guard GOR deviation from GOR∞ (%)

Real-time sample GOR deviation from GOR∞ (%)

Guard GOR and Sample GOR Deviations From GOR∞ (%)

OBM Contamination From Laboratory (wt%STO)

0 1

Sample Station Fig. 1—Comparison of real-time OBM contamination prediction and laboratory OBM contamination (green triangles). Focused probes were used for all stations; guard (blue diamonds) and sample (red squares) contaminations based on their approximation to GOR-at-infinite-time prediction are shown. The distances between the red squares and the green triangles represent the difference between field OBM contamination prediction using the proposed method and laboratory results for each station. STO=stock-tank oil.

Because of borehole conditions, it was not always possible to collect the samples close to an upper shale boundary. Well B was temporarily suspended, and sampling was carried out after resuming operations. As a result, Samples 3 and 4 were collected long after the well was drilled. The basis for calculating contamination at any given time or estimating the remaining time to achieve a desired contamination level is provided in the complete paper. Results of real-time predictions for all sampling stations are compared with contamination from the laboratory analysis in Fig. 1. The laboratory contamination values are calculated from a subtraction method. Note that the difference between the predicted and the laboratory-measured contamination is always less than 1.8%. In fact, 78% of the time, the difference between sample realtime prediction and the laboratory contamination was less than or equal to 1%. Focused probes were used for all stations. Vendors generally stopped making realtime contamination predictions at 5%. Station 6 had the highest contamination level (3.2% from laboratory results). To investigate the root cause of high contamination in this sampling station, the authors reviewed the flow rates of sample and guard during the last hour

JPT • NOVEMBER 2016

of pumping before filling the bottles. Their results suggested that a guard-tosample flow-rate ratio of 1.5:3 will increase the chances of collecting a very low contamination sample. In one application, because of the abnormal behavior, a confident contamination prediction was not possible until 4 hours. The decision was made to fill the tanks when field prediction for the sample showed 1.8% deviation from infinite-time GOR after pumping out for 5.5 hours. Although the main objective is to provide guidance for contamination levels before filling the sample tanks, the technique can be used any time after sample and guard flows split to estimate the pump-out time required to achieve a desired contamination level. The longer the time of pump out, the more linear the GOR function becomes and the more accurate the predictions for contamination level and final pump-out time are.

pling conditions. High confidence in real-time contamination prediction with a focused-probe design can be achieved by use of the proposed method. JPT

Conclusions The GOR at infinite time is a good method to predict OBM sample contamination. The method can be applied to any probe type because it is not dependent on probe geometry or a pre-established curve-fitting formula; it is a fitting carried out in real time on the basis of sam-

Development of Novel Drilling-Fluid Nanoparticles for Enhanced Drilling Operations

his work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles. The examined nanoparticles have the potential to significantly improve the characteristics of the filter cakes at both low-pressure/low-temperature (LP/LT) and high-pressure/high-temperature (HP/HT) conditions. They also have the ability to maintain optimal rheological properties so that many drilling problems can be mitigated efficiently.

Introduction Drilling-fluid loss is considered the major source of capital expenditure during drilling operations. Nanoparticles have proved to be more effective in reducing the filtrate losses than conventional fluid-loss reducers. Because they exhibit different adsorption and transportation behavior in different porous media, nanoparticles have been used successfully as stabilizers in emulsions and foams, as rheology modifiers, and as fluid-loss additives in surfactant/polymer or water-based drilling fluids. Addition of Fe2O3 and SiO2 nanoparticles can improve or at least maintain fluid properties even at high temperatures. This work aims to find the optimal concentration of such nanoparticles.

Experimental Procedure Materials and Sample Preparation. Bentonite was supplied in powder form;

the water/bentonite suspension gives a mixture with a pH range of 8 to 10. The Fe2O3 nanoparticles were purchased in powder form with a spherical shape and an average diameter of less than 50 nm with a purity greater than 97%. Nanosilica was purchased in powder form with a spherical shape and an average diameter of 12 nm with a purity greater than 99.5%. Deionized water with pH range 6.8 to 7.2 was used along with the bentonite to prepare the base fluid. All the prepared samples had pH in the range of 7.9 to 8.3. The preparation of the samples was carried out following American Petroleum Institute (API) standards. The base fluid (BF) was formulated with a bentonite concentration of 7.0 wt% in 600 cm3 of deionized water. Different concentrations of Fe2O3 and SiO2 nanoparticles were used (0.5, 1.5, and 2.5 wt%). First, bentonite was added to deionized water and mixed for 20 minutes. The desired concentration of nanoparticles was added slowly to minimize the agglomeration, and mixing continued for 20 more minutes. The samples were then sealed in plastic containers and left for 16 hours at room temperature for the bentonite to hydrate.

repetitive, provided that samples are prepared per API procedures. The readings were taken from high to low speeds, while rotation lasted for 60 seconds at each rotational speed, with readings recorded every 10 seconds, thus giving eight measurements for each rotational speed. The rheological-parameter estimation was performed according to the HerschelBulkley rheological model, a good choice for many water/bentonite suspensions as well as for many drilling fluids. Understanding the yield-stress phenomenon is a cumbersome procedure that depends not only on the measuring technique but also on the model used to assess the data. Statistical modeling has been performed successfully toward an enhanced multivariate rheological model, which enables shear stress and viscosity prediction for the produced nanoparticle-based drilling fluids over a wide spectrum of realistic process conditions. Measurements were performed at different temperatures. To achieve the desired temperature, a water bath was used, allowing the water to circulate around the measuring cup and keeping the temperature fairly constant.

Rheological Measurements. Viscometric data were obtained at eight fixed speeds. The yield stress is estimated from the rheograms obtained with a rotational viscometer after extrapolating the shearstress/shear-rate curves to zero shear rate and fitting an appropriate rheological model. This procedure proved robust and

Fluid-Loss Measurements. The filtration characteristics of the drilling fluids were obtained following API procedures. Data were collected using a standard LP/LT filter press with a regulated air-pressurization system and standard 3.5-in.-diameter filter paper. Operating pressure of 100 psi at atmospheric temperature was used. The volume of the filtrate was recorded once per minute in a graduated cylinder. Filter-cake thicknesses were immediately measured at the end of the filtration period with a digital caliper for several repetitions, to provide a larger number of measurements to improve accuracy. For scanning-electron-microscope (SEM) analysis, the filter cakes were

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18381, “Development and Testing of Novel Drilling Fluids Using Fe2O3 and SiO2 Nanoparticles for Enhanced-Drilling Operations,” by Zisis Vryzas, Texas A&M University at Qatar; Omar Mahmoud and Hisham A. Nasr-El-Din, Texas A&M University; and Vassilios C. Kelessidis, Texas A&M University at Qatar, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 48

JPT • NOVEMBER 2016

FracGeo The Future of Shale Management, Today

Are your completions effectively optimizing the SRV and ROI to be competitive in today's price environment? How effective is your frac stage and well spacing?

Can you predict and validate your SRV?

Where does your proppant go?

Added value and solutions with FracGeo 3G workflows & software

Read more about our Fracture Geomechanical Simulator at www.fracgeo.com

(a)

(b)

Fig. 1—SEM images of the filter cakes after the HP/HT filtration test (300 psi and 250°F): (a) BF; (b) BF+0.5 wt% Fe2O3 nanoparticles (200X magnification).

dried in the oven at 250°F for 3 hours before measurement.

Results and Discussion Rheology. Rheological data were analyzed with the Herschel-Bulkley rheological equation. Rheograms for the 7.0 wt% bentonite aqueous suspensions with different concentrations of Fe2O3 nanoparticles at room temperature showed that their addition increases the shear stress at all shear rates when compared with the BF by raising the rheogram. The yield stress at 78°F increases with the increased addition of Fe2O3 nanoparticles and almost quadruples from 3.41 Pa in the BF to 13.04 Pa at the maximum tested concentration of Fe2O3 nanoparticles (2.5 wt%). Variation of yield stress with temperature for the samples containing Fe2O3 nanoparticles in the 7.0 wt% bentonite suspensions revealed that the main effect of temperature is on yield stress, which also increases with increasing concentration of nanoparticles. This increase becomes larger at higher temperatures. On the other hand, samples containing nanosilica exhibited a complex pattern regarding yield-stress variations. All yield-stress values obtained at different temperatures showed a decrease for all the concentrations used compared with the BF. Fluid-Loss Measurements. The filtration characteristics of drilling fluids are heavily dependent on the amount and physical state of the colloidal materials present in the drilling-fluid system. If there are adequate colloidal materials in the mud, then the fluid loss can be reduced. Addition of Fe2O3 nanoparticles causes reduction of fluid loss for all samples. In contrast, samples containing SiO2 nanoparticles exhibited a significant increase in the filtration volume.

Addition of 0.5 wt% Fe2O3 results in an improvement in the filtrate volume by 42.5%, compared with that of the BF. An increase in the filter-cake thickness by 17.3% and a decrease in the weight of the filter cake formed by 11.1% are also observed. In contrast, at HP/HT static conditions, addition of 0.5 wt% silica nanopowder adversely affected the filtration characteristics with an increase in the filtration volume by 13.0% compared with the BF. SEM. Homogeneous and well-textured mudcakes reveal another positive characteristic of the novel nanoparticlebased drilling fluids. The well-dispersed mudcakes that are created from these nanoparticle-based fluids demonstrate their high potential for decreasing drilling and production problems. Fig. 1 shows the SEM images produced from the HP/HT test from samples containing Fe2O3 nanoparticles. The SEM images show that the filter cake of the 0.5 wt% Fe2O3 nanoparticles has a smoother surface compared with that formed with the BF. Another noticeable point is that fewer agglomerates have been formed, which indicates a good microstructure between the bentonite and Fe2O3 nanoparticles. Smoother surfaces of the produced filter cakes have been noticed also upon the addition of SiO2 nanopowder. Zeta-Potential Measurements. Zetapotential measurements of water/bentonite suspensions with different concentration of nanoparticles showed that the Fe2O3 nanoparticles are stable in colloidal suspensions with positive charge. When adding these nanoparticles to bentonite suspensions, the net repulsive and attractive forces were in a ratio such that the clay platelets aligned in a configuration that reduced the penetrable surface area of the

filter-cake formation. On the other hand, samples containing SiO2 nanopowder were unstable under different temperatures with negative charges. These characteristics of SiO2 nanopowder adversely affect the clay-platelet configuration and thus reduce the efficiency of the filter cake. Computed-Tomography (CT) -Scan Measurements. CT-scan images have been taken through the cake diameter from one side to the other after the filtration test for samples containing Fe2O3 nanoparticles. The CT images showed that the filter cake contains two layers. The top layer (close to the drilling fluid) has a darker color and a lower CT number (CTN). However, the bottom layer (close to the rock surface) has a lighter color and a higher CTN. It was also noticed that for the 2.5 wt% nanoparticle filter cake, a third layer of different color and higher CTN appears below the bottom layer. The average CTN of the bottom layer increased with heightened Fe2O3 nanoparticle concentration. This confirms that the bottom layer is the main filter-cake layer in which the nanoparticles fit between the clay platelets and build the mudcake microstructure. The average CTN of the bottom layer decreased, and a new layer (third layer) appeared below the bottom layer, which has a high CTN. These results explain the increase in the filtrate volume with the increase of nanoparticle concentration. The increase in the Fe2O3 concentration leads to a decrease in filter-cake quality, where the nanoparticles do not fit between the bentonite plates and tend to agglomerate. At 2.5 wt%, the agglomerated nanoparticles settled down and formed the third layer in the filter cake. Inductively Coupled Plasma (ICP) Mass Spectrometry. The filtrate generated from the filtration of the samples containing different nanoparticle concentrations was analyzed with the ICP process. These measurements confirmed that 0.5 wt% of Fe2O3 nanoparticles is the optimal concentration. At HP/HT conditions, the Fe2O3 nanoparticles (at low concentrations) enhance the dissociation of Na+. This results in the formation of lowporosity, low-permeability filter cake. At higher concentrations, the nanoparticles agglomerate and adversely affect the clayplatelet microstructure. JPT

JPT • NOVEMBER 2016

Proppant-delivered production assurance technologies

A breakthrough in production assurance performance The longest lasting production assurance treatment by far The unique GUARDâ&#x201E;˘ family of proppant-delivered production assurance technologies provides a highly cost-effective way to assure long-term production and maximize recovery. A single treatment can be designed to address multiple production issues and last the life of the well, due to our proprietary controlled chemical release technology. As a result, well maintenance requirements and LOE are significantly reduced. By utilizing ceramic proppant as the chemical-delivery mechanism, the treatment safeguards the entire production system without impairing fracture conductivity. Make the break from expensive and short-lived treatments. carboceramics.com/guard

Optimal Nanosilica Concentration in Synthetic-Based Mud for HP/HT Wells

t certain conditions, the good performance of synthetic-based mud (SBM) will degrade, particularly because of the effect of chemical instability under high temperature. The study of nanoparticles in smart fluids in drilling operations has been gaining attention worldwide. This study intends to describe the improvement in performance of SBM with silicon dioxide (SiO2) nanopowder (nanosilica) at different concentrations.

Introduction Recently, research into the use of nanotechnology to design smart fluids containing nanoparticles has been conducted. This enhanced formulation with nanoparticles is intended to become a system optimizer, particularly with an aim toward enhancing filtration performance and providing better rheological behavior. The use of nanoparticles as a system optimizer corresponds with the fact that nanoparticles have better thermal stability [good for high-pressure/ high-temperature (HP/HT) conditions], are able to serve as bridging agents in fluid-loss systems to control lost circulation, and form Pickering emulsions for stabilizer systems. Although this research began almost a decade ago, there is no consensus about what percentage of nanoparticles must be added to a system to achieve optimal performance of the drilling fluid in reducing the drilling-fluid cost in total. Therefore, this study intends to investigate the role of nanosilica in improving SBM rheological properties and to iden-

tify the optimal concentration of nanosilica in SBM formulations.

Experimental Approach The first part of this study focuses on the performance of nanosilica in the base-mud system, where the testing temperature is 275°F, to understand its behavior at normal drilling temperatures. The second part of this study focuses on evaluating the performance of enhanced SBM formulations with nanosilica at the onset of HP/HT conditions (350°F). The concentration of nanosilica became the modifying parameter in the analysis, and it varies from 20 to 60% of the commercial-fluid-loss-controladditive weight [0.16 to 1.05% of total mud weight (MW)]. Overall, the study focuses on mud properties such as MW, plastic viscosity (PV), yield point (YP), gel strength, electrical stability, and HP/HT fluid-loss volume. A process flow chart, as well as a discussion of testing equipment, is provided in the complete paper. Nanosilica Characterization. The characterization of nanosilica used in this study was performed with scanningelectron-microscopy imaging and elemental dispersive spectroscopy for elemental identification. It is very important to examine the size and purity of the nanoparticles to ensure that the study parameter is correct as predefined in the objectives. Drilling-Mud Formulation. In this project, the samples were tested at 275°F as the base temperature and at 350°F as

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176036, “Optimal Nanosilica Concentration in Synthetic-Based Muds for High-Pressure/High-Temperature Wells,” by Norazwan Wahid and Muhammad Aslam Md. Yusof, Petronas, and Nor Hazimastura Hanafi, Scomi Oiltools, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed.

the high temperature. Enhanced mud formulations with different concentrations of nanosilica also were used for comparison studies on both systems. The formulations of drilling mud used for 275°F and 450°F differ because additives are applicable only at certain temperature limits. This ensures that the mud is capable of withstanding the respective temperature without its performance being affected. The variation in nanosilica concentrations with respect to the commercial fluid-loss-control additive was the main experimental modifying parameter. The amount of nanosilica used with respect to the commercial-fluid-loss-control additive varies from 20 to 60%.

Mud-Data Analysis The experimental data were measured before hot rolling (BHR) and after hot rolling (AHR) for the mud rheological properties; the HP/HT filtration test was performed only AHR. The mud samples were left aging for 16 hours at dynamic conditions. Rheology-Performance Comparisons. The rheology performance of the mud systems can be discussed in terms of PV, YP, and 10-second/-minute gel strength. PV is the first component of resistance to flow in Bingham plastic fluid. It shows the mechanical friction between the solid phases, between the liquid phases, and between solid and liquid phases. Equations used to calculate PV and YP are provided in the complete paper. YP is the second component of resistance to flow in Bingham plastic fluid. It reflects the electrochemical or attractive forces in mud under flowing conditions. This is the result of negative and positive charges located on or near the particle surfaces. Gel strength indicates the strength of the attractive force (gelation) in a drilling

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 52

JPT • NOVEMBER 2016

CRE ATING TOMORROW’S SOLUTIONS

SILICONE SOLUTIONS FROM TOP TO BOT TOM.

www.wacker.com/oil-gas

Silicones for foam control were just the beginning. Add to that WACKER’s expanded offerings of innovative silicone applications and the result is enhanced physical performance for gas and oil producers, reduced downtime, and improved flow and delivery of other process efficiencies. What’s more, our technical expertise, customized solutions, speed to market and localized support give you just what you need – from the top of your list to your bottom line. • • • • • •

Demulsification Defoaming Well bore stabilization Sand consolidation Proppant enhancement Cementing

Wacker Chemical Corporation, 3301 Sutton Road, Adrian, MI 49221 TEL: 888 922 5374, www.wacker.com/oil-gas, info.usa@wacker.com

WACK1650_Oil_8.125x10.875_0493A.indd 1

10/10/16 9:23 AM

WACK-0493A

Gel Strength (lbf/100 ft2)

20 15 10

17 16

13 13

12 11

18 13

5 0

10-Second Gel Strength, lbf/100 ft2 Base-Case BHR 60% Nanosilica BHR 40% Nanosilica AHR

10-Minute Gel Strength, lbf/100 ft2

20% Nanosilica BHR Base-Case AHR 60% Nanosilica AHR

40% Nanosilica BHR 20% Nanosilica AHR

Gel Strength (lbf/100 ft2)

Fig. 1—Gel-strength comparison for 12-lbm/gal, 275°F mud.

40 30 20 10 0

16 14 14 12 11

22 21 12

10-Second Gel Strength, lbf/100 ft2 Base-Case BHR 60% Nanosilica BHR 40% Nanosilica AHR

20% Nanosilica BHR Base-Case AHR 60% Nanosilica AHR

10-Minute Gel Strength, lbf/100 ft2 40% Nanosilica BHR 20% Nanosilica AHR

Fig. 2—Gel-strength comparison for 13.5-lbm/gal, 350°F mud.

fluid under static conditions. Excessive gelation is caused by high solid concentration, leading to flocculation. The performance analysis was conducted between BHR and AHR to study the respective properties. The rheological properties BHR and AHR in rolling condition show the same trend, which increases when the rotation becomes faster. The muds become more viscous AHR because of the temperature effect on the chemicals and additives, especially nanosilica. The highest rheology is seen in the base mud with no nanosilica. In both the base mud and the nanosilica mud, the rheological properties AHR are increased. This is caused by the effect of temperature on the chemicals in the mud that flocculate after being exposed to high temperatures. As a consequence, the mud becomes thicker and more viscous, thus increasing the capacity for carrying cuttings to the surface. By comparison, nanosilica muds are less viscous. This is because when nanosilica is present, it tends to deflocculate and modifies the properties of mud to

!"#$%&'()*+,&,*-(".",%"/%0( Department of Petroleum and Geosystems Engineering The University of Texas at Austin

The University of Texas at Austin’s Department of Petroleum and Geosystems Engineering (UT PGE) seeks outstanding applicants to fill a faculty position at the rank of assistant professor. Exceptional candidates will also be considered for other faculty ranks. The successful candidate is expected to supervise graduate students, teach undergraduate and graduate courses, develop sponsored research programs, collaborate with other faculty, and be involved in service to the university and the engineering profession. A PhD in petroleum engineering or a related discipline is required. Applications are encouraged from candidates specializing in any area within petroleum engineering. UT PGE has strong programs in drilling and completions, reservoir engineering, reservoir characterization, enhanced oil recovery, formation evaluation, geomechanics, unconventional resources, and production engineering. Faculty also work in the innovative areas of geologic carbon storage, methane hydrates, geothermal energy, and applications of engineered nano-particles to subsurface processes. We look for candidates who can bring new ideas and skills to our research program as well as collaborate with existing personnel. Applications from women and minorities are encouraged. UT PGE is a world leader in petroleum engineering research, education, training and outreach, dedicated to maintaining oil and gas as an affordable, sustainable and reliable source of energy into the future. The department’s undergraduate and graduate petroleum engineering programs are both ranked #1 in the country (according to the latest US News and World Report rankings). UT PGE’s 20 faculty, 200 graduate students and 400 undergraduates work and study using state of the art equipment and expanding laboratory and instructional space. Interdisciplinary work is promoted and rewarded in collaboration with the 6 other departments of the Cockrell School of Engineering as well as with the top-ranked Jackson School of Geosciences and other disciplines. The University of Texas at Austin is one the world’s leading research universities. Apply online at www.pge.utexas.edu. Interested persons will be asked to submit a detailed curriculum vitae including academic and professional experience, statements describing their philosophy and goals with regard to both teaching and research, and a list of peer-reviewed publications and other technical papers. Applicants should also provide the names, addresses and telephone numbers of at least five references. Dr. Jon E. Olson, PHD, P.E. Chairman and Frank W. Jessen Professor The Lois K. and Richard D. Folger Leadership Chair Department of Petroleum and Geosystems Engineering The University of Texas at Austin Email: Stickney @austin.utexas.edu

The University of Texas is an Equal Opportunity/ Affirmative Action Employer. Security sensitive position; background check conducted on applicant selected. Please visit www.pge.utexas.edu for more information about the Department of Petroleum and Geosystems Engineering.

JPT • NOVEMBER 2016

have lower rheology but maintain a high gel-strength value. Gel strength for nanosilica mud is much higher than for the base mud even though it is less viscous and has a lower YP and PV than the base mud. When examining the PV and YP performance of both mud systems BHR and AHR (PV indicates the resistance of the fluid to flow, while YP is used to evaluate the mud’s ability to transport cuttings in the annulus to the surface), PV and YP tend to increase after 16 hours of exposure to the desired temperature (275 and 350°F) to simulate the bottomhole condition. The increase in these parameters might be caused by mud flocculation. However, the trend of an increasing nanosilica concentration shows a decrease in PV and YP values when compared with the base mud AHR. This can be understood by noting that the nanosilica is dispersed properly in the mud, thus making the mud less viscous when compared with the base mud. 10-Second/-Minute Gel-Strength Comparison. Figs. 1 and 2 show gel-strength comparisons for both mud systems. They depict the shear stress measured at low shear rate after the mud was left in a static condition for a certain period of time, normally measured at 10-second and 10-minute intervals. The enhanced mud for both systems showed comparatively higher gel-strength values for 10-minute measurements when compared with those of the base mud. This is a good indicator for better suspension of drill cuttings at static conditions when drilling operations are halted, but too-high gel strength may require greater force to break the gel. Both YP and gel strength show the ability of the fluid to remove drill cuttings to the surface and to suspend cuttings while drilling operations are halted. However, the major difference in terms of hydraulics is that once the pipe is rotated and the fluid is moving, the gelling will not be observed, yet the YP will not disappear. Therefore, addition of nanosilica helps improve the fluid PV, YP, and gel strength for better drilling-fluid performance. HP/HT Fluid-Loss Performance. Nanosilica is intended in this study to be used as a fluid-loss-control additive in order to compare its performance with that of the commercially used fluid-loss agent, which is asphaltene-based gilsonite. Increasing nanosilica concentration in the formulation helps reduce the amount of filtrate produced. However, an optimum range of combinations should be studied for better formulation in order to achieve lower filtrate volume. At 40% concentration of nanosilica to gilsonite, the filtrate volume was decreased by 41.67% for a 275°F mud system and by 28.57% for a 350°F mud system, when compared with the base case. The mudcakes formed at the end of the filtration test were thinner when compared with those of the base mud. Variation in concentration does not significantly affect mudcake formation in this study. Lower filtrate will reduce the problem of formation damage, and thinner mudcake helps reduce the tendency of pipe to stick. Therefore, a 2:3 ratio of nanosilica to gilsonite could be the optimal combination for lower filtrate volumes. It can be concluded that nanosilica is a good additive for reducing fluid-loss problems, particularly in hightemperature systems. JPT

Host

STRATEGIES FOR THE NEW ENERGY LANDSCAPE

TOP 5 REASONS TO VISIT DO BUSINESS ADIPEC represents a global opportunity for you to connect with over 2,000+ exhibiting companies within the complete Oil and Gas supply chain. Discover new technologies and solutions that optimise costs and drive efficiencies.

NETWORK Meet with existing clients to protect your market share and network with new clients to drive new business growth and opportunities – ADIPEC attracts an audience of over 95,000 visitors from 120 countries.

EXCHANGE KNOWLEDGE Learn from world class industry experts through the 106 technical conference sessions, industry panel sessions, ministerial sessions, global business leaders sessions and from over 850 speakers making ADIPEC the largest Oil and Gas conference knowledge platform in the world today.

GENERATE QUALIFIED LEADS Gain access to the people that matter, who shape the energy industry and influence the decision making process. Target key professionals with purchasing power looking for innovations and technical solutions in your sector.

OPTIMISE YOUR TRAVEL BUDGETS Meet the industry’s leading companies under one roof across four days of highlevel networking and business opportunities. Four days at ADIPEC could equal a year’s worth of travelling around the world, meeting with clients and prospects.

WHAT TO EXPECT DURING THE 4 DAYS OF ADIPEC?

2,000+

8,500+

Attendees

Exhibiting Companies

Delegates

International Country Pavilions Exhibiting

National Oil Companies

International Oil Companies

REGISTRATION NOW OPEN

www.adipec.com/visreg ONE GLOBAL INDUSTRY. ONE CITY. ONE MEETING PLACE. Supported By

Official Airline

JPT • NOVEMBER 2016

95,000+

Official Travel Agent

Host City

Official Hotel

Official Media Partner

Knowledge Partner

Conference Organiser

ADIPEC Organised By

Positron-Emission Tomography Offers New Insight Into Wormhole Formation

olymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. Polymer-gel behavior is often studied in corefloods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chase floods. The work presented in this paper uses complementary positron-emission-tomography (PET)/computed-tomography (CT) imaging to quantify the behavior and blocking capacity of gel during chase waterflooding.

work, the authors study the extrusion of formed polymer gel through fractures, and its resistance to pressure during subsequent waterfloods. PET imaging is based on the decay of positron-emitting radionuclides. In this work, PET was used to visualize flow of radioactive water through a gelfilled fracture, to augment global measurements, and to increase the understanding of filter-cake formation during formed-gel placement and wormhole formation during chase floods. A discussion of the experimental setup, including limestone- and sandstone-core-plug preparation, polymer-gel placement, the chase-flood procedure, and the PET-imaging process, is provided in the complete paper.

Introduction Channeling of injected fluids through a highly permeable fracture network, and the following early fluid breakthrough, may be mitigated by placing a highly viscous polymer gel in the fracture. With polymer gel in place, higher differential pressures may be achieved during chase floods, which can contribute to increased sweep efficiency in the porous matrix adjacent to the fracture network. A polymer gel is formed when a gelant solution is exposed to elevated temperature for a given time, known as the gelation time. Previous work has investigated how the gel state during placement (gel or gelant) influenced the gel behavior during chase floods. The complete paper provides a detailed discussion of previous models for fluid leakoff. In this

Results and Discussion Polymer-Gel Placement. The rate of water leakoff during gel propagation through open fractures has been shown to be independent of core material and largely independent of the gelinjection rate. When using short fractures, screenout of gel could occur at high gel-flow rates. In this study, lower constant-injection rates of 200 mL/h (for the limestone core) and 6 mL/h (for the sandstone core) were used. The limestone core was mounted in the PET scanner during gel injection, and volumetric measurements for leakoff calculation were not performed. The leakoff rate measured during gel injection into the sandstone core was lower than that expected from the leakoff models.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180051, “New Insight Into Wormhole Formation in Polymer Gel During Water Chase Floods Using Positron-Emission Tomography,” by B. Brattekås, University of Stavanger; M. Steinsbø, A. Graue, M.A. Fernø, and H. Espedal, University of Bergen; and R.S. Seright, New Mexico Petroleum Recovery Research Center, prepared for the 2016 SPE Bergen One-Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed.

Water Chase Floods. Calculations Made on the Basis of Global Measurements. Waterflooding was performed to measure the gel blocking capacity and analyze the development of wormholes through the gel-filled fractures. Rupture pressures (the pressure at which the gel in the fracture breaks and allows fluids to flow through it) were 4.5 and 4.4 kPa/cm for the sandstone and limestone core, respectively, and corresponded well with previously reported rupture-pressure data after formed-gel placement in fractures. When the gel ruptures, water may again flow through the fracture by following the rupture path. In the sandstone core, eight increasing and decreasing rate cycles were performed, whereas two cycles were performed in the limestone core. The pressure gradients measured during water injection at the specific rate steps are shown in Fig. 1 as functions of the effective brine velocity through the fracture. The measurements were taken for each rate step when the pressure response across the gel-filled fracture had stabilized at a close-to-constant value. Fig. 1 shows the initial rupture pressure and the following pressure response during the first two increasing/decreasingrate cycles in both core plugs. The rupture pressures are denoted by a red dot (limestone) and a black triangle (sandstone). The gel behavior during water chase flooding was similar in the two core plugs: after gel rupture, water could pass through the fracture and the pressure gradient across the fracture decreased for the lowest water-flow rate. When the flow rate was increased to 60 mL/h, the measured pressure gradient across the fracture continued to decrease. Increasing the flow rate further yielded an increase in the measured pressure gradient up to the initial post-rupture level. When the flow rate was stepwise decreased to 6 mL/h,

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 56

JPT • NOVEMBER 2016

Prupture

Prupture, limestone

Prupture, sandstone

Increased rate, limestone

Increased rate, sandstone

1st cycle

Decreased rate, limestone

Decreased rate, sandstone

2nd cycle

Pressure Gradient, kPa/cm

3rd cycle

4th cycle 5th cycle

0.1

0.1 1

100

1000

Effective Velocity Through Fracture, cm/h

10 000

100

1000

Effective Velocity Through Fracture, cm/h

Fig. 1—Measured pressure gradients as functions of the effective velocity of brine through the fractures. Left: the limestone core (red curves) and the sandstone core (black curves) during the first two increasing- and decreasing-rate cycles. The dotted lines represent decreasing-rate cycles, and the solid lines represent cycles in which the injection rate increases. Right: the first five increasing/decreasing-rate cycles, out of eight in total, for the sandstone core.

significantly lower pressure gradients were measured for each specific rate. This was expected behavior, attributed to erosion of gel in the wormholes during water injection. With the water-flow rate back at the initial level (6 mL/h), two different waterflood schedules were performed in the core plugs: in the limestone core, lowrate waterflooding was continued for 13 hours, while six additional decreasing/ increasing injection-rate cycles were performed in the sandstone core. Fig. 1 shows the first five increasing/ decreasing-rate cycles in the sandstone core, out of eight cycles in total. The pressure gradients for each specific rate continued to decrease during the third cycle (increasing rate) with respect to the first two cycles. From the third cycle, however, the pressure gradients remained on the same level within each flow rate, suggesting a stable system with minor gel erosion. The elasticity of the gel enabled it to maintain a stable and high pressure resistance after rupture and significant water throughput, because wormholes are allowed to collapse and reopen during waterflooding, depending on the water-flow rate. Wormhole widths for the two cores could be calculated from the measured differential-pressure and rate data. The wormhole width increased with in-

JPT • NOVEMBER 2016

creasing injection rates. Wormhole development was similar in the gel-filled fractures of the two core plugs. The calculated wormhole widths for the limestone core corresponded well with those

of the sandstone core, considering a lower degree of gel erosion. In-Situ Investigations of Wormhole Development With PET. PET imaging was used to investigate water flow

STAR-CCM+: Discover better designs, faster. Explore designs digitally to innovate while reducing cost and overdesign.

siemens.com/mdx

Don’t let your SPE member benefits run dry. Membership in the Society of Petroleum Engineers is a continuous well of career-enhancing opportunities for E&P professionals. Whether you want to enhance your knowledge, expand your network, or develop your leadership skills, it pays to remain engaged with SPE. Stay connected to all that SPE has to offer: Publications and Journals Events and Training Courses Local Section Activities Volunteer Opportunities Online Communities and Resources

Keep your SPE member benefits producing for you. Renew today at www.spe.org/go/17Renew.

through a gel-filled fracture in situ. To closely investigate the water-flow pattern during the increasing- and decreasingrate cycles, six images were constructed from the PET data—one for each rate step. Wormholes and wormhole development with flow rate were clearly seen on the PET images. The wormhole formed during initial waterflooding at 6 mL/h mostly consists of a single flow conduit, although large-scale variations in the size of the rupture path were observed within the fracture volume. Eleven percent of the fracture volume emitted a radioactive signal and thus contained wormhole(s). The rest of the fracture was filled with concentrated gel that did not exhibit a signal detectable by PET. When the rate was increased to 60 mL/h, the wormhole branched out and filled larger portions of the fracture. New rupture paths were formed through the concentrated gel filter cake compared with the first rate step, and fluid flow was observed through several wormholes spanning between the inlet and the outlet. Twenty-two percent of the fracture volume conducted water flow at 60 mL/h, efficiently doubling the wormhole volume since gel rupture. The part of the fracture volume conducting flow of radioactive water increased further (27%) when the injection rate was increased to 300 mL/h, although at a much lower scale. New wormhole flow paths were not created during this rate step. A reduction in the rate to 60 mL/h did not cause a corresponding reduction in the measured wormhole volume, and the wormhole remained in the same shape and location as in the preceding rate step. Reducing the flow rate to 6 mL/h reduced the wormhole volume to 24% of the fracture volume without changing the wormhole morphology. In-situ imaging supported the existence of a nonuniform gel filter cake in the fracture, and the authors observed that (for the first two waterflood cycles) ◗ The wormholes are in the same location from the initial breach to late waterflooding. ◗ The wormholes are, for the most part, in the same shape for the duration of waterflooding, although new rupture paths were added to the original rupture path when

the flow rate was increased above the original level. ◗ The wormholes are eroded wider when higher and higher rates are used. ◗ The wormholes do not collapse when the rate is lowered. ◗ Extended waterflooding substantially erodes gel along the fracture-width direction but does not form new wormhole pathways. Wormhole Development: In-Situ Measurements Compared With Global Calculations. The authors converted the total measured wormhole volume in the fracture to average wormhole widths with simple calculations of geometry. It was assumed that the wormhole had a rectangular shape, such that one side was fixed at the fracture aperture and the other side was the wormhole width (not fixed). In-situ imaging by use of PET showed large variations in the wormhole width, from very narrow in some sections of the fracture to spanning almost half the fracture height in other sections. The uncertainty contained in an average value for the wormhole width is therefore large; however, it was necessary to use these values to compare in-situ imaging with calculations from global measurements. Measured average wormhole widths were more than 30 times higher than the calculated values for each specific rate and do not account for the high pressure gradients achieved during postrupture waterflooding. This indicates that the average wormhole width is not a good measure for the actual conductivity of the fracture and is not the controlling factor for flow. In-situ imaging by use of PET revealed the existence of several wormholes seemingly randomly distributed within the fracture volume and with significant variations in width. In-situ imaging by use of PET relied on the presence and decay of radioactive water in the core only and could be performed during dynamic floods for several different flow rates and timesteps. PET is able to capture and quantify quick changes in polymer-gel networks during chase waterfloods without damaging the core or gel. Visual inspection of fracture surfaces, however, requires the core to be broken apart, and the core cannot be used further. JPT

JPT • NOVEMBER 2016

TECHNOLOGY FOCUS

Horizontal and Complex-Trajectory Wells Stéphane Menand, SPE, President, DrillScan US

Following the downturn, the number of horizontal wells drilled this year has fallen dramatically compared with previous historic levels. In these difficult times, attention to cost reduction through relentless optimization of all segments, from drilling to completions, has never been so important. Horizontal-well costs have decreased significantly over the last few years thanks to many lessons learned. In unconventional plays, multiple solutions have been implemented and tested in well construction, casing design, hole size, bottomhole assemblies (BHAs), directional systems, drillpipe, oscillation techniques, drill bits, well trajectory, and pad drilling, with the main goals being greater efficiency and reduction of costs. On the drilling side, operators have been able to find the optimal drilling system to drill the curve and the lateral with the same BHA in just a few days. Have we reached a plateau? Not yet. Can we optimize more? Yes, absolutely. In unconventional wells, the trend is now to increase the horizontal length to 15,000 ft and, further, to increase the recoverability per foot of lateral. There is probably a technical and economic limit to this, but the

Have we reached a plateau? Not yet. Can we optimize more? Yes, absolutely. industry has kept pushing these limits further. The role of digital technologies is increasing, and this enables oilfield performance improvements. Indeed, drilling data easily acquired now with electronic drilling recorders have revolutionized the possibility of visualization, monitoring, and analysis in real time. The attention recently has been on trying to use computer modeling to guide the directional-drilling process. Guidance systems in two or three dimensions are now helping the directional driller in real time to find the best possible well path to reduce tortuosity and maximize rate of penetration and possibly production. Data coming from the drilling job are now reused by completion teams to optimize the position of the hydraulicfracturing stages to maximize production. The main idea consists of calculating the mechanical specific energy at the bit (derived from operating parameters) to estimate unconfined compressive strength of the rock, which is a valuable

Stéphane Menand, SPE, is the president of DrillScan US, based in Houston. Previously, he held a research position at Mines ParisTech university. Menand holds a PhD degree in drilling engineering from Mines ParisTech. He has 18 years of experience in the oil and gas industry, mainly as a research-and-development project manager in drilling engineering, more specifically in directional drilling, drillstring mechanics (torque, drag, and buckling), drilling dynamics, and drill-bit performance. Menand has authored SPE papers and other technical papers and holds several patents. He serves on the JPT Editorial Committee and is an associate editor for SPE Drilling & Completions. Menand can be reached at stephane.menand@drillscan.com.

JPT • NOVEMBER 2016

mechanical rock property for reservoir evaluation, eventually to map zones with high potential for fracturing. Thanks to the analysis of previously drilled and completed wells (microseismic fracture mapping, reservoir modeling, and production analysis), the industry is moving toward optimal lateral and vertical spacing between two horizontal wells to get the greatest recovery of hydrocarbons in place. On the completion side, the same data accumulated over the last few years have enabled operators to compare fairly the two typical completion systems used in unconventional plays (fracturing sleeve with activated ball or plug-and-perforate techniques) to better evaluate them and select one method over another. These examples illustrate just a few of the numerous advances made in horizontal and complex-trajectory wells and demonstrate that, despite this historic downturn, the oil and gas industry has kept innovating and optimizing to bring more-efficient solutions to the table. JPT

Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 180652 Improving Directional Survey Accuracy Through Real-Time Operating Centers by Shawn DeVerse, Surcon, et al. SPE/IADC 178885 Multilaterals in the Mississippi Lime by Robert Meize, SandRidge Energy, et al. SPE/IADC 178875 Team Approach to Horizontal-Drilling Optimization in the Marcellus Delivers Record-Setting Performance by Denise Azuaga Livingston, Baker Hughes, et al.

A New Approach for Optimization of Long-Horizontal-Well Performance

nitially, it was believed that a horizontal well should be drilled with as much length as possible. However, field experience and flowmeter surveys in long horizontal drainholes revealed that the frictional pressure loss in the wellbore is an important factor hindering the full use of the entire length of the horizontal well. This paper presents a new approach to maximize the use of the full length of long horizontal drainholes.

Introduction Horizontal-well drilling allowed the drilling of different well architectures and made it possible to offset well costs and productivity limitations. Intuitively, drilling longer wells will maximize exposure to the producing formation and yield higher flow capacity. Paradoxically, however, some wells were drilled longer than the optimal horizontalsection length and the extra length did not yield additional flow. Therefore, it is important to determine the optimal horizontal-section length that would achieve flow contribution along the whole section. Experience has revealed that long horizontal wells suffer from frictional pressure losses. This fact is exacerbated in the presence of highly productive formations; these would require low pressure drawdowns that may well be similar to the frictional pressure losses, which would therefore hinder wellbore flow ingress. Thus, some horizontal wells are equipped with downhole flow-choke systems to optimize well productivity.

Finite-Conductivity Horizontal Wells Horizontal wells are initially deemed to be infinite-conductivity wellbores; this thesis was made on the basis of the fact that the magnitude of the pressure drop in the wellbore is negligible. Practically speaking, however, production data proved otherwise; frictional pressure losses in horizontal wellbores hinder flow influx to different degrees along the horizontal section. This issue is of great importance under conditions in which the magnitude of the pressure drop in the wellbore is small when compared with the magnitude of the pressure drop in the reservoir. Therefore, given the fact that horizontal wells are often proposed and justified on the premise that high production rates can be obtained by small reservoir pressure drops, and the fact that flow developed at reasonably high production rates should cause increased wellbore pressure losses, the use of the infinite-conductivity assumption for horizontal wells may not be valid. The inflow performance of a long horizontal drainhole is more strongly influenced by the pressure profile in the wellbore. For that purpose, flow characterization and evaluation of the effect of pressure losses in such wells were given significant attention. Field data supported the idea that high-productivity wells suffer more from the effect of wellbore hydraulics. In addition, data proved that even in relatively short wells, frictional pressure losses can impair productivity, especially in wells drilled in highly productive formations.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18372, “A New Approach for Optimization of Long-Horizontal-Well Performances,” by Abdullah Al Qahtani, Hasan Al Hashim, and Hasan Al Yousef, King Fahd University of Petroleum and Minerals, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission.

Wellbore Flow and Hydraulics Intensive analytical and experimental studies have been conducted to investigate the different aspects of horizontalwellbore flow behavior. Some analytical wellbore models for single-phase flow have been developed, demonstrating that the incorporation of horizontal-wellbore hydraulics into the horizontal-well model is a challenging issue.

Physical Model For a U-shaped well in a reservoir with an anisotropic but homogeneous layer of uniform thickness, an isothermal and single-phase flow of fluid with constant compressibility and viscosity is considered. The reservoir in this solution is assumed to be an infinite-acting, flat-slab reservoir that is homogeneous and anisotropic, having uniform thickness and having two impermeable layers at the top and bottom of the formation. The well is a U-shaped finite-conductivity wellbore with flexible production ratios from both wings. For a long horizontal well with a high flow rate and a small wellbore diameter, the pressure drop along the wellbore can be significant and will affect well performance. For better understanding of horizontal-well behavior, a good estimate of the pressure drop within the horizontal portion of the well is needed. The semianalytical model in this study was developed for a finite-conductivity Ushaped horizontal well, and it includes the frictional pressure drop in the horizontal drainhole.

Coupling Solution for Different Flow Directions The semianalytical solution of the Ushaped wells is based on the development of an analytical formulation for the fluid flow in both directions, with a split point taking place at any point along the horizontal section. The position of that point

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 60

JPT • NOVEMBER 2016

25,000

2,000 1,990

20,000

1,980 1,970 Flow Profile

15,000

1,960

Pressure Profile

1,950

10,000

1,940 1,930

5,000

1,920

1,900 4,000

Pressure Profile (psi)

Cumulative Flow (B/D)

is determined by the well/reservoir flow characteristics and dictated by the ratio of the flow from both ends. The solution is based on the mathematical formulation of flow in the two directions of the well—namely, the left and right wings. The solution couples the wellbore flow with the transient response of the reservoir. Equations related to this solution are provided in the complete paper.

1,910

U-Shaped-Horizontal-Well Flow Model In the U-shaped horizontal well producing from both sides, a point of split of flow will take place along the horizontal section that will depend on the flow rates and well/reservoir interaction. For this to happen, a continuity of wellbore and sandface pressure has to take place. This means that, at the point of split, one would expect to have flow in opposite directions on both sides. The mathematical formulations were used to construct the solution matrix considering the point of flow split, which in turn is found by iterative solution to satisfy the conditions of continuity of pressure in the wellbore and in the reservoir at the point of flow split. The matrix is solved using Newton’s method, to find the wellbore pressures at the two ends and the flow-flux profile along the horizontal well.

Performance Optimization The proposed optimization scheme is obtained by mitigating the frictional pressure losses by splitting the flow of the wellbore to produce the long horizontal well from both ends (heel and toe) to maximize the production from the entire drilled well length, produce lowproductivity portions or damaged portions of the horizontal section, and ensure better reservoir sweep. The developed rigorous semianalytical model, which includes wellbore hydraulics and variable skin, was used to study the performance of the proposed U-shaped horizontal well. The model was used to optimize production performance of long horizontal wells by simulating the flow in the wellbore, and the subsequent pressure perturbation in the wellbore.

Maximizing Flow Capacity A wellbore-flow simulation of horizontalwell performance to demonstrate the

JPT • NOVEMBER 2016

500

1,000

1,500

2,000

2,500

3,000

3,500

Distance From Heel (ft)

Fig. 1—Flow and pressure profiles of the U-shaped horizontal well.

merit of the U-shaped well design was performed for a 4,000-ft horizontal well and for two well-productivity index (PI) values of 1,000 and 2,000 STB/D/psi (well data are provided in the complete paper). The wellbore-flow simulations in such wells have shown that these wells will be more restricted by the outflow performance (i.e., wellbore hydraulics). Results of a comparison of the flow profiles for a conventional horizontal well considering the two PI values show that the high-PI well will suffer from the effect of the frictional pressure losses in the wellbore and that some portion of the section will yield no contribution. Furthermore, other comparisons of the flow profiles indicated that the wellbore pressure reaches a constant value faster in the high-PI case. When the frictional pressure losses for both scenarios are calculated, those in the 2,000-STB/D/psi case are closer to what is expected for the same pressure drawdown of 10.32 psi at the toe of the well. Using the same well data and applying the U-shaped wellbore, flow analysis indicated less flow restriction from the effect of friction because flow travel will be split in half, reducing the frictional losses by half. Fig. 1 shows the simulation of the U-shaped well with flow production from both sides using the PI of 2,000 STB/D/psi. Analysis indicated that each wing can produce almost as the full-length conventional well. In addition, the pressure profiles in both wings are shown, and it can be seen from the figure that the pressure drawdown at the midpoint of the U-shaped horizontal well is 15 psi.

When the frictional pressure for the Ushaped well for the PI of 1,000 STB/D/psi is calculated, it is seen that the frictional-pressure loss is less, which makes the pressure drawdown at the middle approximately 15 psi, yielding high flow into the wellbore.

Conclusions A semianalytical solution was developed to predict the performance of a Ushaped horizontal well and its pressuretransient responses at both ends. The U-shaped-flow setup could optimize the flow efficiency of the system by mitigating/alleviating flow hindrances. On the basis of the results of this study, the following conclusions can be derived: ◗ The proposed U-shaped horizontalwell design alleviates flow restrictions imposed by wellbore hydraulics in horizontal drainholes, allowing more contribution from the whole length of the wellbore. ◗ A split of flow occurs along the horizontal section. The position of this split is a function of the rate ratio of the production from both ends, skin damage, and frictional pressure loss. ◗ Results indicated an appreciable merit in drilling the U-shaped horizontal well and producing from both ends, which will reduce the frictional-loss effect, thus maximizing well performance. ◗ The U-shaped horizontal well enables flexibility in producing from both ends at any desired rate ratio, allowing active control of portions of production and direction of flow within the wellbore. JPT

Use of Microseismic Monitoring To Compare Completion Designs

his study compares the performance of openhole-packer completion systems with that of cemented-liner completion systems in the northern Montney gas resource play. The authors’ data demonstrate that the benefits of openhole completions include an increase in initial production (30-day average) (IP30) rates, an increase in expected ultimate raw gas recovery per well, and a decrease in stimulation-period costs, all on an unadjusted basis. When adjusted for total proppant placed or total fluid pumped on average per completion, the relative benefit of openhole systems ranges from 6 to 31%, depending on the test metric selected.

Introduction Recovery optimization from the Montney presents a unique development challenge because of the play’s extensive thickness and corresponding multilayer extraction potential. In the Blair/Town Block study area, it has been observed that openhole completions consistently outperform cemented-liner completions when considering standard metrics of production and cost. Completion-liner systems for horizontal wells are designed to isolate hydraulic-fracture treatments to minimize stimulation pumping interference between successive stages. At present, two basic liner designs enjoy widespread use: 1. Openhole multistage (OHMS) liners, wherein annular isolation is provided by external packers.

2. Cemented-liner perforate-and-plug (CLPP) systems, wherein cement provides mechanical isolation along the liner annulus. These two liner designs are discussed in further detail in the complete paper. This paper investigates the superior performance of openhole stimulations by use of microseismic monitoring to evaluate comparative stimulation response during one openhole and one cementedliner completion. Microseismic assessments of stimulation patterns typically involve qualitative inspection of event-cloud maps. While useful for visualizing stimulated reservoir volumes (SRVs), these assessments typically do not offer practical insights into actual rock failure. In this study, a new method of microseismic analysis is applied to conduct a more-rigorous appraisal of rock failure on the basis of an in-depth assessment of individual-event focal mechanisms. Geologic Setting and Study Area. The study area for this paper is situated within the British Columbia northern Montney region. The Montney formation is generally interpreted as a series of stacked turbidite fans deposited in a quiet, deepwater setting. It consists of a very-fine-grained and low-permeability dolomitic siltstone. Porosities range from 1 to 9%, with an average of 4 to 5%. Initial reservoir pressures within the study area vary from 26 to 35 MPa. The principal reservoir-quality factors include occurrence of carbonate cements plus variably-altered organic carbon, both of which tend to constrain po-

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174955, “Comparing Openhole-Packer Systems With Cemented-Liner Completions in the Northern Montney Gas Resource Play: Results From Microseismic Monitoring and Production,” by James Reimer, Matthew Ng, and Bryan Dusterhoft, Painted Pony Petroleum; Brad Birkelo, Spectraseis; and Barry Hildek, Packers Plus Energy Services, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

rosity preservation at the millimeter scale. On a regional basis, this study area is characterized by a northwest-to-southeasttrending structural grain imparted by various ages and styles of fault and fracture development. Drill depths to the Montney target range from 1900- to 2300-m true vertical depth in the Blair/Town area. Drilling and Stimulation Program. The Blair/Town horizontal development program commenced in 2010 with CLPP completions. In 2012, the application of OHMS systems in the Montney was tested on the basis of successful experience with this technology in the Bakken tight oil play of Saskatchewan. To date, a total of 56 horizontal Montney completions have been opened. This study incorporates 19 CLPP wells and 11 single-lateral OHMS wells. Only those wells with a stable and sufficient production history were selected for inclusion in this study. These 30 wells are distributed over 11 surface drilling pads. Study wells were drilled in monobore style, with a 200-mm main hole and a 156-mm horizontal section. An aqueous drilling fluid was used to the kickoff point, and invert mud was used thereafter to final total depth. Wells were cased with a tapered string, using 140-mm casing to the heel and 114-mm casing (CLPP) or 114-mm packer liners (OHMS) along the horizontal section. All completions were conducted using a generic slickwater fluid system. The generalized treatment procedure involved pumping 10 m3 of acid spearhead, followed by 90 to 150 m3 of pad volume and 500 to 700 m3 of slurry. As a guiding objective, proppant placement of approximately 1 t per lateral meter was targeted.

Production and Cost Comparison Fig. 1 presents the average production curves by completion technology for the first 6 producing months, with time normalized to producing day raw-wellhead-

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 62

JPT • NOVEMBER 2016

WE DELIVER WHAT OTHERS CAN’T. C&J CONTINUES TO PRODUCE new technologies to improve efficiencies, increase production and reduce costs.

Re-ConSM Frac-less Re-Stimulation for EFFICIENT, INCREASED PRODUCTION

Lateral ScienceSM Process PRECISELY ENGINEERED COMPLETIONS

USBS Directional Motor THE INDUSTRY’S SHORTEST bit-to-bend drilling motor

To learn more, contact your C&J representative. Or contact us at inquiries@cjenergy.com.

EXCELLENCE DELIVERED. CJENERGY.COM

Raw-Wellhead-Gas Rate, MMcf/D

OHMS (11 Wells) Average IP30 Rate=6.5 MMcf/D First 6 Months Cumulative=1.01 Bcf Type-Curve EUR=10 Bcf

CLPP (19 Wells) Average IP30 Rate=5.2 MMcf/D First 6 Months Cumulative=0.69 Bcf Type-Curve EUR=7.0 Bcf

1 1

Production Month Fig. 1—Monthly average production for wells in this study; time normalized to producing days.

gas volumes. The graphs clearly illustrate that OHMS completions have outperformed CLPP systems. On an adjusted basis, a modest improvement to IP30 rates was noted; however, a significant uplift (ranging from 21 to 26%) occurred for the OHMS systems on the basis of 6-month cumulative recovery and forecast estimated ultimate recovery (EUR). The comparison of the cost benefits of OHMS and CLPP completions focused on expenditures incurred during actual stimulation (pumping) days. The authors believe that this approach offers the optimum comparator because other (highly) variable cost factors such as location setup, flow testing, and plug-and-port drillouts are excluded from the calculations. The results clearly demonstrate an important realized cost and time benefit for the OHMS wells in this study. On average, the OHMS completions saved 2.8 stimulation days (36% time reduction) and USD 390,000 in aggregate stimulation costs (13% cost reduction). Similarly, an average per stage cost savings of 14% on a normalized equivalent-stage-count basis was realized.

Microseismic Program Acquisition Program. The surface-array system was selected to obtain optimal x–y positioning accuracy within an acceptable cost structure and because the focal-mechanism method introduced herein requires a wide-aperture data set to calculate a coherent solution. The equipment setup consisted of 189 geophone stations laid out on a 13×17 grid at 360-m orthogonal spacing. This yielded a survey size of approximately 4.5×6.5 km,

representing a recording aperture equal to the depth of the Montney reservoir. The survey used three-component sensors with a 250-Hz sampling rate. Array geometry was similar for both pads. The events data sets used in this study are based on a minimum signal/noise ratio of 5:1, recorded during hydraulicfracture-pumping times. The authors believe that pumping-time events offer the clearest sample to appraise stimulation efficacy. Nonpumping events are unlikely to represent actual stimulation because they are commonly distal, or positioned above or below the geologic formation of interest. Visual inspection of the data sets confirmed these assumptions. Event Magnitude and Position. A total of 1,646 microseismic events were detected during pumping time between the two well completions monitored in this study. The event-magnitude histogram (Fig. 6 in the complete paper) immediately suggests that the total energy delivery provided by the OHMS stimulation was superior to that of the CLPP stimulation, on the basis of the relative number of events. Additionally, the OHMS stimulation is characterized by a lower median magnitude value, which may be indicative of differences relating to stimulationenergy dispersion. While event maps are useful for visualizing the overall shape and distribution of SRVs, they provide little quantifiable information concerning actual rock response or failure mechanisms. It was apparent that a different analytical approach would be required to evaluate the relative efficacy of the OHMS and CLPP stimulations. Event Focal Mechanisms. Microseismicevent focal mechanisms provide an additional tool to evaluate rock response during hydraulic fracturing. The focalmechanism method is based on the premise that energy is radiated in a nonuniform fashion when rocks rupture, and the resulting pattern of radiation provides valuable information concerning the type of rock failure. The focal mechanisms are used to determine the unique failure geometry for each event. Individual-fault-plane solutions are generated by examining the directional energy pattern. The two potential fault-

plane orientations are calculated, and the final solution includes azimuths and apparent dips of each plane. Although there is an inherent ambiguity as to which is the real failure plane, typically the steeper-dipping one is selected as the principal plane because the occurrence of very-low-angle failure in deep formations is expected to be low and most stimulation geometries are expected to possess steep dips. The inclination data are typically presented as a “beachball”-style diagram, which provides a visual indication of the failure geometry. Failure-Plane Crossplots. A crossplot of the inclination (dip) of the principal plane vs. the auxiliary plane offers a graphical method to assess the failure geometry of an event population. Fig. 7 of the complete paper illustrates the crossplot developed for this purpose. Appendices C through E of the complete paper present failure-plane crossplots for the microseismic data acquired in this study. In addition to the failure crossplots, the authors prepared histograms of event magnitudes, segmented by the same distance intervals. This provides a visual method to examine the stimulationenergy intensity correlative with the failure plots. It is noted that the histogram patterns are different for each completion style.

Conclusions Production data lead the authors to conclude that OHMS systems provide enhanced well performance relative to CLPP systems in the study area. In addition, the realized time and cost advantages for OHMS completions are similar to benefits reported by other operators for the British Columbia Montney play. As a result, this operator has switched to the exclusive use of OHMS systems on all Montney horizontal wells. It is concluded that liner design alone represents an important driver of failure geometry and stimulation efficacy. It is inferred that superior hydraulic stimulations occur when energy delivery to the formation is optimized with respect to propagation complexity and total intensity. An open liner annulus appears to be a critical mechanical element required to achieve these conditions, particularly for the specific stage and cluster spacing used in the study wells. JPT

JPT • NOVEMBER 2016

Friction-Load Redistribution for ExtendedReach- and Horizontal-Well Completions

n horizontal and extended-reach wells in which long completions are run into highly deviated or lateral zones, large compression loads arise because of running friction. These loads remain locked in the string when the packer or cement sets. Dissipation of friction caused by string vibrations and movements redistributes these friction loads between the wellhead and the packer or the top of the cement. A numerical approach is presented to calculate the redistributed friction load so that an accurate initial tubing load is implemented in the tubularstress analysis.

Introduction The long lateral wells in modern shale developments provide new motivation to better understand and model the effect of friction in casing and tubing design. The multiple-barrier approach and modern design techniques compare favorably with previous generations of well construction. Even so, the root-cause failure analysis of individual subsurface components such as tubing, connections, or packers is difficult. The multizone-fracturestimulation techniques common to shale developments combine the multiple challenges of long lateral zones with associated friction-induced compression loads and cyclic thermal loading from successive stimulation, flowback, and production. An important motivation for understanding the effect of redistribution of locked-in friction loads is

the increasing application of onetrip multistage completions and intelligent-well-system completions in unconventional-reservoir field developments. In extended-reach wells, as the long laterals grow longer and more-expensive equipment is run out farther into the reservoir-contact area, design requirements will become increasingly challenging. It can be argued that these considerations are not as important for cemented completions or where the production casing is the effective operational conduit. However, even for productioncasing fracture stimulations or even production, loads below the top of the cement cannot necessarily be disregarded. Also, the planned top-of-cement depth may not be realized. Hence, much more of the casing may be uncemented than in the original plan.

Completion Design With Friction The fact that there has not been a formulation presented to provide guidance in the redistribution of locked-in friction loads is probably attributable to the commonly held viewpoint that friction may be ignored for conservative design analysis of life service loads. However, various situations exist in which the “no-friction” approach may be nonconservative. These include the following: ◗ Scenario A: Running friction that may be locked into the system by packer or cement setting; thus, the initial load state may be significantly different from that

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IADC/SPE 178905, “Friction-Load Redistribution for Robust and Cost-Efficient Design of Extended-Reach- and Horizontal-Well Completions,” by A.R. McSpadden, SPE, and R. Trevisan, SPE, Altus Well Experts, prepared for the 2016 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March.

of hanging weight without friction as is often assumed. ◗ Scenario B: Tensile load during overpull events that may be seriously underestimated in the presence of friction in a deviated wellbore, especially with shallow doglegs. ◗ Scenario C: Extreme localized tensile or compressive loads may develop over production-service life as changes in operating pressure and temperature act to reorient friction-contact loads between the tubular and the wellbore; the key point is not only the magnitude of changes, but the sequence over time in which they occur that can generate new and unexpected load conditions. Scenario C is the most difficult of these and currently defies any widely accepted tractable solution. The essential ingredient is the ability to track the history of changing friction orientation all along the string as it undergoes nonuniformly distributed temperature and pressure changes. Current tubular-stress-analysis software has limited capability to model friction history in which a true sequence of well operations can be specified. Another observation is important to fully round out the discussion of friction-based design challenges for extended-reach- and horizontal-well completions. Inasmuch as the immediate effect of running friction is to lock compression into the completion string, the most obvious concern is the existence of high compression loads toward the bottom of the well, particularly at a production packer placed just above the heel of the reservoir lateral. Clearly, compression loads tend to dominate downhole. Thus, tubing, connection, and packer ratings under large

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • NOVEMBER 2016

compression may be the limiting design component. However, single-trip multistage and intelligent-well completions in deep wells are also subject to tension limitations near the surface because of cumulative tubular weight. As a result, thicker-walled pipe, which is more expensive, may be required near the surface, where tension limitations of tubulars and connections may become the limiting component. Hence, robust and cost-efficient completion design involves a balance of downhole compression loads and near-surface tension loads. A key theoretical insight critical to understanding the nature of any friction-load redistribution is to remember that the tubular completion forms an elastic continuum from surface to the downhole fixed end. If any incremental friction load along the length of the tubular is released or otherwise dissipates, the incremental string load released must be shared between the surface and a downhole fixed point, on the basis of the relative stiffness of the intervening system elastic members. The net result of this collective system redistribution may not be intuitive. The net result is some additional tension at surface as well as additional compression below. A simplified physical example to illustrate this concept is provided in the complete paper.

Proposed-Model Description The model proposed in this work is intended to deal practically and conservatively with the design challenge of running friction loads that are subsequently redistributed. The accumulated compression caused by frictional resistance experienced during running is locked into the string when the packer system or cement is set. Subsequent dissipation of friction caused by subsurface perturbations cannot be easily predicted or modeled; however, it is nonetheless realistic and likely. If frictional forces are later dissipated by vibration effects and string disturbance during well life, then the locked-in compressive load will be redistributed along the string. The magnitude of the locked-in load transferred to the string top vs. that force slacked off on the packer below is criti-

cal for a correct estimation of the total stress acting on the string. The resultant force redistribution can be used to adjust the initial conditions for tubingstress analysis and can lead to moreaccurate stress calculation. A numerical model based on the equivalent stiffness of a series of springs has been developed for the frictionredistribution problem. The solution is based on a simple 1D finite-element model in which incremental frictional loads are decomposed and redistributed on the basis of relative stiffness of the string uphole and downhole of each local node. The string is divided into discrete elements, each of which constitutes a node in a series-of-springs system. The incremental friction loads during running are estimated for each node from a standard torque-and-drag analysis. The formulation of this model is described in detail in the complete paper. Obviously, the accuracy of the numerical method is dependent on the number of the elements into which the string is subdivided. The model described fits well into a tubular-stress-analysis work flow. A torque-and-drag-analysis tool is initially run to determine the effective force profiles while running in hole (RIH). From that, and from the redistributionmodel result, an updated stress-analysis model is used for the verification of the tubular string. This process may be summarized as follows: 1. Run torque-and-drag analysis to obtain the effective-force profiles for the RIH scenario with and without friction. If buckling occurs during installation, the torque-anddrag analysis provides the local helical buckling loads. 2. Enter the differential effectiveforce results from Step 1 into the redistribution model to obtain the redistributed frictional-load value at surface and at packer or the top of the cement. 3. In the tubular-stress module, adjust the tubing initial conditions by applying the load from Step 2 as a slackoff input parameter. 4. Run the tubular-stress module without friction effects to simulate

total dissipation and resultant friction-load redistribution. A case study illustrative of the model calculation technique and work flow is provided in the complete paper.

Conclusions A numerical model and work flow have been developed to calculate the redistribution of axial forces on completion strings that are run and set in the wellbore in the presence of friction. In the event that friction dissipates, the initial locked-in friction load has been accounted for and redistributed along the string on the basis of an elasticcontinuum model. The model output yields the appropriate slack-off force input, which can be applied to standard tubular-stress design software in a tubular-stress analysis. This provides a realistic assessment of both realistic tension loads near surface and compression loads near the packer or the top of the cement. Even if friction effects are not completely dissipated, the results from the foregoing analysis technique provide worst-case tension at the surface and worst-case compression at the packer or the top of the cement. In practice, it is likely that there will be only partial dissipation of friction and redistribution of locked-in friction force caused by string vibrations and movements. In the case of total removal of friction from the system after the packer is set, the thermal strain generated during a production event would be distributed uniformly along the entire string. However, this is not the case if some friction localized above the packer remains in the system after the packer or cement sets. The numerical solution presented in this work provides for the estimation of the amount of frictional load being transferred to the string top and bottom after the packer or cement sets. It is important to note that the proposed solutions are based on the assumption of total dissipation of friction in life service. However, it should not be assumed that this represents the worst-case scenario for the stress in the completion at an arbitrary point along the string. JPT

JPT • NOVEMBER 2016

TECHNOLOGY FOCUS

Gas Production Technology Scott J. Wilson, SPE, Senior Vice President, Ryder Scott

What do you do when the power goes out? That situation might evoke the tranquility of putting down your smartphone and looking out the window for a few moments of quiet reflection. Or it might bring the anxiety of wondering if your indoor plumbing will freeze when the power fails on a cold, dark night. But what if it brought the panic of being in the middle of a difficult childbirth operation in a remote hospital that has access only to unreliable electricity generated by intermittent sources? That is the painful reality outlined in The Moral Case for Fossil Fuels, a new book written by Alex Epstein. With a background in philosophy, Epstein wonders why we all seem to accept that the world is “addicted” to our “bad” product while that same product provides us with a standard of living only available to royalty a century ago. With an unbiased perspective, he notes that increased fossil fuel use correlates strongly with increased standard of living, wealth, life expectancy, and food availability and decreased deaths from severe weather events. Why are we so negative about

Why are we so negative about something that has done so much good for so many people? something that has done so much good for so many people? Anthropogenic-global-warming activists argue that returning the climate to prehuman conditions is their ultimate goal, even if decreasing human wellbeing is required. They conveniently forget that the climate was changing before humans arrived, the climate will continue to change after we are gone, and that we have never been successful in attempts to “unchange” the climate. They endorse naïve energy alternatives at impractical prices or that are only found in science fiction. To their credit, science fiction does eventually come to pass sometimes; but, do we power hospital equipment with wishful thinking until then? The US Energy Information Administration predicts that, from 2012 to 2020, subsidized intermittent wind and solar energy will nearly double from 3.9 to

Scott J. Wilson, SPE, is a senior vice president in the Denver office of Ryder Scott. He specializes in well-performance prediction and optimization, reserves appraisals, simulation studies, custom software development, and training. Wilson holds a BS degree in petroleum engineering from the Colorado School of Mines and an MBA degree from the University of Colorado. He holds three patents and is a registered professional engineer in Alaska, Colorado, Texas, and Wyoming. Wilson serves on the JPT Editorial Committee and can be reached at scott.wilson@ryderscott.com.

JPT • NOVEMBER 2016

6.5% of total world energy consumption. Meanwhile, natural gas provides reliable heating, cooling, and electricity at freemarket prices for billions of people. Each year, gas-fired power plants allow millions of additional people to gain their first access to dependable electricity for lighting, smoke-free cooking, and, yes, 21st-century health care. On the basis of long-term fuel-use trends, we can expect that, within a couple of centuries, the sun may provide the same large-scale, low-cost, and reliable power now provided by natural gas. Until then, I will take that rare opportunity when my office loses power to remember to be grateful for the standard of living that fossil fuels have provided for me and billions of other lucky people around the globe. JPT

Recommended additional reading at OnePetro: www.onepetro.org. SPE 174852 Liquid Loading of Highly Deviated Gas Wells, From 60 to 88° by Y. Alsaadi, University of Tulsa, et al. SPE 177567 Integrated Methodology for Production and Facilities Analysis To Optimize Barnett Shale Gas Production— A Case Study by A.A. Moniem Ahmed, Schlumberger, et al. SPE 179537 Experimental Study on Revaporization Mechanism of Huff ’n’ Puff Gas Injection To Enhance Condensate Recovery in Shale Gas/Condensate Reservoirs by Xingbang Meng, Texas Tech University, et al. SPE 180247 Infill-Drilling Opportunity in Fruitland Coal, San Juan Basin, Colorado by Prannay Parihar, Chevron, et al.

Plume Modeling Establishes Efficacy, Safety of Gas Extraction From Lake Kivu, Rwanda

ake Kivu is unique among East African Rift lakes with high concentrations of dissolved carbon dioxide (CO2) in that it also contains methane (CH4). The dissolved gases constitute a hazard because a vertical disruption of the water could cause gasladen water to be displaced to shallower depths with lower pressures, allowing the gas to bubble out of solution and triggering a gas eruption. A floating gasextraction facility has been constructed to extract gas-laden water, separate the methane and some of the CO2, and reinject the degassed water, thus increasing the safety of the lake and simultaneously providing CH4.

Introduction Lake Kivu sits along the border between the Democratic Republic of the Congo (DRC) and Rwanda, in the Great Rift Valley region of Africa. The lake is approximately 89 km long, oriented in a north/ south direction, and 48 km wide. The lake is at 1460 m above sea level and has a maximum depth of approximately 485 m in its northern basin. Lake Kivu has an unusual thermal structure. At depths below approximately 80 m, the water temperature increases with depth. However, the water also contains large quantities of dissolved CO2 and salt, with concentrations that increase with depth. The densityincreasing effects of CO2 and salt maintain the lake stratification despite the inverted temperature profile. The density structure of the lake is a series of relatively homogeneous mixed

zones separated by density-gradient layers. The major mixed zones, beginning at the surface, are referred to as the Biozone, Intermediate Zone, Potential Resource Zone, Upper Resource Zone, and Lower Resource Zone. The Main Density Gradient separates the Potential Resource Zone from the Upper Resource Zone. The Secondary Density Gradient separates the Upper and Lower Resource Zones. The gases in Lake Kivu are kept in solution by the hydrostatic pressure at depth. If a disruption to the lake (because of a landslide or volcanic activity) caused gas-laden water to be brought to shallower depths where the hydrostatic pressure was below the saturation pressure (the pressure necessary to keep all the gases in solution), gas bubbles would form in the water. The gas bubbles would form a buoyant plume that would carry even more gas-laden water to shallower depths and release even more gases. This could eventually result in a large-scale release of gases at the surface of the lake. Such an event, called a limnic eruption, occurred in 1986 at Lake Nyos in Cameroon, resulting in a large-scale release of CO2 and widespread asphyxiation of nearby villagers and livestock. Because of this threat, the governments of Rwanda and DRC are working to ensure that any activity involving Lake Kivu does not disrupt the stratification of the lake. Lake Kivu is unique among similar East African Rift lakes in that it also contains high concentrations of CH4, a potential resource. The highest concentrations of CH4 in Lake Kivu are at the lowest depths, in the Upper Resource Zone and the

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27247, “Plume Modeling in Lake Kivu, Rwanda, for a Gas-Extraction Facility,” by Timothy L. Morse, Nicolas F. Ponchaut, and Gary N. Bigham, Exponent, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Lower Resource Zone. A gas-extraction facility has been constructed to extract methane from Lake Kivu, providing an energy source and simultaneously reducing the gas concentration in the lake, thereby increasing the lake’s safety. The facility, contained on a floating barge, will extract gas-laden water from the Lower Resource Zone (at a depth of 350–360 m) through four extraction risers. The facility will then separate the dissolved gases (CH4, CO2, and some hydrogen sulfide) from the water, and reinject the degassed water into the lake through four discharge risers. A diagram of the facility is shown in Fig. 1.

Hydrodynamic Simulations Two of the key questions regarding the effects of the degassed water that is discharged back into the lake were ◗ Will the degassed water recirculate back into the intake risers and prevent effective gas extraction? ◗ Will the degassed-water plume upset the lake stratification and lead to a gas release? To answer these questions, the authors conducted several simulations of the degassed-water plume. These simulations were performed with a commercial computational-fluid-dynamics software package. The Reynolds-averaged NavierStokes model was used, along with a turbulence model. The density of the plume, both at the point of discharge and as it evolves and dilutes in the lake water, is the most important parameter dictating plume behavior. The density depends primarily on four variables: water temperature, salinity, concentration of CH4, and concentration of CO2. Higher temperature decreases density, while higher salinity increases density. The gas concentrations have a complicated effect on density. If the gas concentration is small enough such that the local hydrostatic pressure is sufficient

The complete paper is available for purchase at OnePetro: www.onepetro.org. 68

JPT • NOVEMBER 2016

Wash tower

Fig. 1—Diagram of the gas-extraction barge.

Separator (×4)

Discharge riser (×4)

Intake riser (×4)

to hold the gases in solution, then the dissolved gases have a relatively modest (but still important) effect on the density. The presence of dissolved CO2 increases the density, while the presence of dissolved CH4 actually decreases the density. However, if the gas concentration is high enough that the gases cannot be kept in solution by the hydrostatic pressure, bubbles will form in the water, dramatically decreasing the local density. Both effects—dissolved gases and gases in bubble form—must be accounted for to calculate the plume density correctly.

an increase in density such that the degassed water is denser than even the deepest water in the lake. This is the reason for the concern regarding recirculation from the discharge point to the intake risers. Regardless of the discharge depth, the plume will sink initially. Because the intake risers are positioned near the bottom of the lake (where the CH4 concentration is the highest), there was a concern that the sinking degassed water would be drawn back into the intake risers, rendering the gas-extraction process ineffective.

Simulated Plume Behavior Discharge Scenarios Examined For the extraction scenario examined in the complete paper, the raw water was extracted from a depth of 355 m and the degassed water was reinjected at 280 m. The four discharge risers terminated with a diffuser that directed the discharge flow horizontally. The discharge flow rate (per each of the four discharge risers) was 2.3 m3/s. The gas-separation process removes most of the CH4, some of the CO2, and none of the salt. The temperature also decreases slightly. The removal of CH4 results in

JPT • NOVEMBER 2016

The degassed water mixes and dilutes considerably as it exits the discharge riser. After this initial mixing, the plume is still heavier than the surrounding lake water and sinks to a maximum depth of 327 m. The plume then rises slightly and stratifies at a depth of approximately 313 m, within the Secondary Density Gradient. The plume sinks beyond its final stratification depth because of the excess momentum imparted during the initial sinking phase. The plume sinks through the Upper Resource Zone (between depths of 270

and 310 m). There is no way for the plume to reach neutral buoyancy within this constant-density mixed zone. The plume is initially denser than the surrounding water (in fact denser than any water in the lake). As it mixes with the ambient water in the Upper Resource Zone, it dilutes and the density decreases, but it can never decrease below the density of the ambient water. The plume, therefore, sinks. The plume ceases to sink once it encounters the denser water within the Secondary Density Gradient below the Upper Resource Zone. The Secondary Density Gradient thus acts as a barrier, preventing the plume from sinking farther into the Lower Resource Zone where it could potentially encounter the intake risers. Streamlines of the discharge plume confirm that the degassed water does not enter the intake risers and, thus, that recirculation does not occur. One of the concerns associated with the discharge plume is that it could cause a local uplift effect on the density gradients above it. The models show that degassed-water discharge does not have an uplift effect on the density gradients above the discharge depth. The Main Density Gradient at approximately 260 m is unchanged by the discharge of the degassed water.

Conclusions The results of the simulation answer the two key questions regarding the degassed-water plume. The degassedwater plume does not enter the intake risers but rather stratifies above the intake risers. And the dynamics of the degassed-water plume does not cause uplift of the water column, and, thus, the gas-extraction process that was modeled does not present a risk of lake overturn. The simulation results also show that the degassed water stratifies within a density gradient. This is because, if the degassed water is discharged outside of a density gradient (where there is almost zero change in density with depth) and is denser than the surrounding water, there is nothing to stop the plume from sinking until it reaches a density gradient, regardless of how much mixing occurs. By adjusting the discharge depth, the degassed-water plume could be made to stratify within any density gradient of choice. JPT

A Deepwater Gasfield-Development Strategy for Trinidad and Tobago

rinidad and Tobago is the top natural-gas producer in the Caribbean, with average daily production in 2014 of 4.069 Bscf/D. With vibrant upstream, midstream, and downstream sectors, Trinidad and Tobago makes maximum use of the natural-gas value chain. Further maximization through growth in the downstream sector requires an adequate supply of natural gas in addition to the shallow-water gas fields offshore, which are currently the main supply. Because of the thriving gas sector, a large amount of infrastructure already exists that may aid with any further development.

Annual Averages for Natural-Gas Production and Usage 4.8 4.6 4.4 4.2 4

Production, Bcf/D 3.8

Use, Bcf/D

3.6

Average production over 5 years=4.2 Bcf/D

3.4

Average use over 5 years=3.9 Bcf/D

3.2 3 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Year

Introduction The Trinidad and Tobago Gas Development Model has shaped the growth of its natural-gas economy over the years, and, in 2014, the energy sector accounted for 45% of the country’s gross domestic product. Average production over the past 5 years was an estimated 4.2 Bcf/D, while average use for the same period was 3.9 Bcf/D, with liquefied natural gas (LNG) accounting for more than 50% of this consumption (Fig. 1). With the onset of proposed additional projects in the downstream sector, additional gas use in the near future is inevitable. Although this additional capacity can emanate from the existing provedreserves base, another source of gas could be currently unexploited deepwater basins. In the past 5 years, nine productionsharing contracts for exploration in Trinidad and Tobago’s deepwater areas were

Usage values used for average

Production values used for average

Fig. 1—Annual averages for natural gas production and use.

signed. If gas is discovered, first gas can be on line within 5 to 10 years of discovery. If this occurs, additional quantities of natural gas would be available for domestic, Caribbean, and Latin American markets. While deepwater gas developments have economic challenges, existing infrastructure in Trinidad and Tobago can aid development. Because domestic, Latin American, and Caribbean markets are the main targets of this evaluation, relatively small recoverable-resource sizes of 3.0, 4.0, and 5.0 Tcf were assumed for a drygasfield-development scenario. A lowprice scenario of less than or equal to USD 4/Mscf and a production range of

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177102, “A Deepwater Gasfield-Development Strategy for Trinidad and Tobago,” by Ayasha Nickie, Trinidad and Tobago Ministry of Energy and Energy Affairs, prepared for the 2015 SPE Latin American and Caribbean Petroleum Engineering Conference, Quito, Ecuador, 18–20 November. The paper has not been peer reviewed.

500 to 750 MMscf/D are used to calculate the feasibility of each scenario. Associated capital and operational expenditure; net present value (NPV) discounted at 6, 8, and 10% nominal to January 2015; government and operator share percentages; and internal rates of return (IRRs) at the discounted values are also highlighted. The NPVs and IRRs are used as the primary economic parameters for analysis of the project.

Observations On the basis of subsea development and applying an economic analysis for Trinidad and Tobago’s deepwater gas fiscal regime, results were calculated for price scenarios of USD 3/Mscf, USD 3.50/Mscf, and USD 4/Mscf. NPVs discounted at 6, 8, and 10% nominal to January 2015 are also applied to each case. The results indicate that total cost, which includes capital, operational, and abandonment costs, falls between USD 5 billion and USD 8 billion; this equates to

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 70

JPT • NOVEMBER 2016

USDÂ 8.78â&#x20AC;&#x201C;11.19/BOE. Additionally, the results indicate that, for a price scenario of USD 3/Mscf for a 3-Tcf case, discounted at the three rates, government NPV is always negative. For the 4-Tcf case at a similar price, government NPV is also negative when discounted at 8 and 10%, but, for the 5-Tcf case, it becomes negative only at a discount rate of 10%. However, if we consider an IRR of 20% and greater for the operator with a positive government NPV greater than USDÂ 100 million as economical, then the following scenarios depict a favorable result for both parties: â&#x2014;&#x2014; 3-Tcf case discounted at 6% with aÂ price of USD 3.50/Mscf and USD 4/Mscf â&#x2014;&#x2014; 4-Tcf case discounted at 6% with aÂ price of USD 4/Mscf â&#x2014;&#x2014; 5-Tcf case discounted at 6% with aÂ price of USD 4/Mscf On the basis of these favorable outcomes, government share percentage lies between 19 and 35% and, for the operator, NPV ranges between USD 1.2 billion and USD 2.3 billion.

affect the economic outcome positively for all parties and increase government share percentage; however, this was not proved through this evaluation.

OIL

Way Forward

ruo7 1ŕŚ&#x17E;om bm1u;-v;7 0

Both operators and government have a profound interest in the economic success of any project. Identifying factors with the largest effect on the economics is important, but finding ways and solutions to reduce their effect is imperative. Additionally, detailed market evaluation and business planning also are important to commercialize deepwater natural gas. Wellhead prices sold to LNG are approximately USD 3/Mscf to USD 4/Mscf, while those sold to the domestic market are much lower. On the basis of this evaluation, economic returns can be generated by tapping into the existing LNG market. LNG exports to existing Latin American and Caribbean destinations, therefore, can increase, but the domestic market would have to pay more for natural gas from deepwater basins.

50% with FloSure

Ĺ&#x2013;" Ĺ&#x160;Ć?ŃśĆ?Ć?Ć&#x2019;Ć&#x2022;Ĺ&#x160; "

SAND CONTROL

INFLOW CONTROL

Conclusion Discussion While many factors contribute to the economic success of a project, an IRR of 20% and greater was used as a benchmark. Investor IRR in frontier deepwater gas development for Trinidad and Tobago ranges between 20 and 25%. This range, when applied to this evaluation, results in the 3-Tcf case at USD 3.50/Mscf and USD 4/Mscf and the 4-Tcf and 5-Tcf cases at USD 4/Mscf, all discounted at 6%, being the favorable choices. In the past 5 years, three deepwater bid rounds were held, and, for the proposals submitted, government share percent for the similar production tier of production in excess of 500 to 750Â MMscf/D with gas price of less than or equal to USD 4/Mscf ranged from 17 to 60%. For this evaluation, government share ranged from 19 to 35% for the favorable choices. Although the development size, discount factor applied, and method of economic analysis may vary for each company, a lower share percentage (as compared with the typical 50â&#x20AC;&#x201C;65% for shallow marine areas) may be needed for government at this price scenario for deepwater gas development. A gas price greater than USD 4/Mscf may

Although technical and economic challenges are inherent to deepwater natural-gas development, a development strategy of a subsea tieback to a semisubmersible with a gas-export pipeline to shore and tapping into the existing LNG market at gas prices greater than USD 3.50/Mscf can yield an economically feasible project. Similarly, tying into and leveraging existing infrastructure would help project economics, and Latin American and Caribbean markets can be served with this supply. Initial investment will be high, between USDÂ 5 billion and USDÂ 8Â billion, and, for economic returns to both operator and government, the following scenarios are applicable: â&#x2014;&#x2014; 3-Tcf case discounted at 6% with aÂ price of USD 3.50/Mscf and USDÂ 4/Mscf â&#x2014;&#x2014; 4-Tcf case discounted at 6% with aÂ price of USD 4/Mscf â&#x2014;&#x2014; 5-Tcf case discounted at 6% with aÂ price of USD 4/Mscf On the basis of these favorable outcomes, government share percent ranges from 19 to 35% and, for the operator, an NPV of USD 1.2 billion to USD 2.3 billion can be achieved. JPT

|;m7;h- 1ol

RESULTS ACROSS YOUR RESERVOIR JPT â&#x20AC;˘ NOVEMBER 2016

Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project

he offshore Wheatstone project in Western Australia uses subsea big-bore gas wells as the preferred method of producing the field. Each of the highly productive wells represents a source of gas that, if accidently allowed to flow unhindered, could present an uncommonly difficult well-control challenge. This paper details the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occur during the execution of the subsea big-bore gas wells and that, if a blowout were to occur, the response to such an event would be sufficient and robust.

Introduction The Wheatstone high-rate gas-well design, with its 9⅝-in. production conduit, represents the company’s initial attempt at implementing such a well. Because the design team’s combined engineering and execution experience included neither big-bore wells nor reservoirs of Wheatstone’s productive magnitude, well-control expectations were limited to anticipating needing only a single relief well in the event of a blowout. However, upon receipt of dynamic-kill simulations performed by consulting experts in that field, a new reality became obvious. That is, the combination of a large wellbore connected to the multidarcy Wheatstone gas reservoir has the potential to produce at more than 1 Bscf/D if flow is unconstrained; in some scenarios, this could require the use of up to four relief wells simultaneous-

ly injecting 15-lbm/gal drilling fluid to regain control. Analyses suggest that it is improbable that a dynamic kill at Wheatstone can be performed successfully using only a single relief well, given the large diameter of the production wellbore. Therefore, the well-control risk of drilling a Wheatstone well was mitigated not by limiting its productive capacity (i.e., reducing the well diameter) but by (1) optimizing casing-setting depths to minimize the number of required relief wells, (2) designing the well to be completely pressure competent, even if it were totally filled with gas, and (3) formulating a blowout-response plan that is reflective of the complexities of executing a two-well dynamic kill on any of the nine foundation wells drilled at Wheatstone.

Well-Control Implications The results of various relief-well analyses made it immediately clear that a one-relief-well scenario did not exist for most well/reservoir combinations. The only well configuration that could be controlled confidently using only one relief well was that of a fully completed well. It was concluded that this well configuration was controllable with a single relief well because it requires only 53 bbl/min of 15-lbm/gal fluid to complete the kill operation. The maximum possible kill rate for a single subsea well was assumed to lie in the 60- to 100-bbl/min range. This range, rather than one more narrowly defined, was assumed because no examples exist in the literature of an actual dynamic kill

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174890, “Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project,” by Eric R. Upchurch, SPE, Sam Falkner, Andrew House, SPE, Chinh Nguyen, SPE, and Ken Russell, Chevron Australia, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

performed with both a subsea relief well and a weighted fluid. Additionally, all kills are assumed to be performed with a 15-lbm/gal fluid because it (1) represents a fluid density high enough to minimize the required injection rate of a relief well, (2) is a fluid density low enough to be confidently mixed and maintained on-site, and (3) contains a low enough concentration of solids that the risk of erosion to subsea-blowout-preventer components is reduced. Penetrating the gas reservoir below a shallow-set 13⅝-in. casing could require three or four relief wells to control a blowout. However, penetrating the gas reservoir below a deep-set 9⅝-in. liner reduces the number of required relief wells to no more than two. The difference between these two outcomes is completely driven by the depth at which the relief wells can intercept the well that is blowing out. That intersection cannot be deeper than the deepest metal pipe in the target well, that being the metal that relief-well ranging tools will try to detect. Considering that at least two subsea relief wells are required to respond to a Wheatstone blowout and that such a response has been implemented only once in the oil industry, it is valid to ask why a more-direct approach to controlling a well is not being considered, such as a capping stack. Capping stacks are not deployable at Wheatstone because of the shallow water depth (220-m maximum). At this depth, the gas plume from a blowout would emerge close enough to the vessel deploying the capping stack, and at a high enough concentration, to pose a fire hazard.

Reservoir-Entry Strategy Implications for Production-Hole Drilling. Having committed to an execution plan that never requires more than two relief wells, a method for ful-

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 72

JPT • NOVEMBER 2016

You canâ&#x20AC;&#x2122;t afford to use the wrong additive.

Saving money using products not suitable to your application costs you a lot more in the long run. Our chemical expertise and decades of experience serving the oilfield industry ensures youâ&#x20AC;&#x2122;ll get the right specialty additive for your application for the right price. Our technical expertise is just an email or call away. chemicals@ingevity.com 1 800 458 4034

Ingevity_JPT_April 2016.indd 1

3/7/16 2:01 PM

9⅝

r ine .L -in

ing as .C -in

9⅝

as .C

-in

9⅝

2800-m TVD

7-in . Li ne

ell W et rg Ta

(N 7-in on . L ma ine gn r eti c)

Direct Intersection

ole

H -in.

6⅛

Oriented Perforations

3050-m TVD

Gas-Pay-Zone Top

Fig. 1—An example of a two-relief-well intercept scenario for Wheatstone.

filling that expectation had to be established. In essence, all well objectives, from both a completions perspective and a well-control perspective, can be met if the shoe of the 9⅝-in. liner is placed reasonably close to the top of the gas reservoir without prematurely penetrating it. If the correct risk balance is struck, the ultimate outcome will be a liner shoe that is placed close enough to the gas reservoir such that exposure of the overburden shale is minimized during completion operations while, simultaneously, the chance of the 12¼-in. hole prematurely penetrating the gas reservoir remains near zero. Implications for Pilot-Hole Drilling. Relative to the production-hole drilling, the relief-well-minimization solution for drilling pilot holes is less sophisticated from a technical perspective but more involved operationally. Where the production-hole solution is a technological application with little schedule-related (i.e., rig time) cost, the cost of the pilot-hole solution is completely related to schedule and, in turn, is much greater. In a pilot hole, the 12¼-in. section is drilled to approximately 30 m vertically above the gas reservoir. Once drilled, the 12¼-in. hole is isolated with

a full string of 9⅝-in. casing. The casing/openhole annulus is only partially filled with cement. This allows the 9⅝-in. casing to be cut 150 m below the 13⅝-in. shoe and then pulled out of the well. This leaves a 150-m openhole window that is then filled with cement to allow sidetracking the well to the optimal producing location. This method was used in all four pilot holes drilled at Wheatstone.

Relief-Well Planning With the deployment of well-control mitigations, the process for planning relief wells becomes somewhat simpler. Rather than having to plan for possible relief-well intersections at both a shallow- and a deep-set casing shoe (because it is possible to have a blowout with either exposed), now all planning can proceed with the simplifying assumption that relief wells need to intersect the target well only near the top of the gas reservoir. Because all relief wells are targeted at the top of the gas reservoir [3050-m true vertical depth (TVD)], rather than at a shallower target such as the 13⅝-in. shoe (2100-m TVD), none of the trajectories necessary to intersect the development wells are considered to be extreme. All relief-well trajectories are planned to

allow the locating and tracking of the target well. Up to this point, the casing design of the relief well would look like that of a pilot hole, except that the 9⅝-in.-casing shoe would be set slightly shallower at approximately 2800-m TVD. The 9⅝-in. casing is set at this point to ensure a pressure-competent wellbore just in case the target well is prematurely intersected as drilling proceeds deeper. Once this casing string is cemented in place, two possible options are available for forming the hydraulic connection with the target well. One option is to drill an 8½-in. hole directly adjacent and parallel to the target well and install a 7-in. liner. The final hydraulic connection between the relief well and the target well is then established by perforating into the target well from the 7-in. liner using oriented tubing-conveyed perforating (TCP) guns (Fig. 1). A second option is to drill the 8½-in. hole such that it converges toward the target well at an incidence angle of 3–5°. Drilling of this hole is halted approximately 30 m short of the expected intersection with the target well. At this point, the 7-in. liner is installed. Afterward, a 6⅛-in. hole is drilled to intersect the target well and form the hydraulic connection (Fig. 1). If the oriented-perforating technique is used in only one of the two relief wells, a successful well kill might occur as follows: Pursue drilling both relief wells simultaneously, with the intent of having the 9⅝-in. casing string cemented in both in a similar time frame. Next, install the 7-in. liners in both wells (Fig. 1). Next, install TCP guns in the oriented-perforations relief well and stand by until the direct-intersection relief well establishes communication with the target well. Once the direct intersection is accomplished, the other relief well can then be perforated to form its own hydraulic connection. Executing a dual-relief-well plan that has a high chance of success in connecting both relief wells nearly simultaneously to the target well is the key to avoiding a prolonged and continuous fluid-injection operation on a single well. JPT

JPT • NOVEMBER 2016

TECHNOLOGY FOCUS

Offshore Production and Flow Assurance Sally A. Thomas, SPE, Retired, Principal Engineer, ConocoPhillips

Subsea tieback of a new field to an existing offshore production facility is one option to minimize development costs. Alternative flowline or equipment specification is another option in addressing development costs. The three papers here discuss slightly different approaches to subsea flowlines and to offshore heating systems. All three have progressed to at least a full-scale demonstration stage, if not to actual field installation. Although carbon-steel flowlines have been the primary choice for most subsea flowlines, increasingly corrosive reservoir fluids lead to other material choices. In addition to corrosion-resistant-alloy cladding or pipe, thermoplastic composite pipe (TCP) is recognized as an alternative. As a result of a large jointindustry project, DNV recently issued a recommended practice for specification, design, and qualification of TCP. The use of a TCP recommended practice is expected to reduce project-specific implementation costs but maintain a consistent qualification approach. OTC 26512 discusses TCP properties, applications, installation, and operation.

Offshore opportunities continue to drive new technology applications and approaches. Hydrate and wax flow-assurance risks are typically mitigated by continuous chemical injection, heat, insulation, pigging, or a combination of strategies. Heat conservation (insulation) may be effective in short- to moderate-length flowlines but is insufficient in longer flowlines; active heating is needed there. Direct electric heating is proposed for flexible pipe. OTC 26939 describes using the carcass and tensile armor of flexible pipe to pass electric current so that only one end of the pipe is required to have electrical connections. The qualification testing on a 12-in.-diameter, 125-m-long flexible pipe is discussed, including low-voltage and highvoltage scenarios. Offshore-facility electric heating elements and power cables typically are low-voltage systems. Medium-voltage

Sally A. Thomas, SPE, recently retired as a principal engineer in production technology at ConocoPhillips. She holds BS and MChE degrees from Oklahoma State University in chemical engineering. Although mostly stationed in the US, Thomas has had international assignments in the UAE, the UK, and Venezuela. She has served in SPE local-section offices; on regionalmeetings organizing committees; as a technical-paper reviewer; as chairperson of the SPE Books Committee; and as a member of the SPE Projects, Facilities, and Construction Advisory Committee and the JPT Editorial Committee.

JPT • NOVEMBER 2016

(up to 7,200 V) systems are suggested alternatives for facilities with megawatt-level electric heating requirements. Advances in metal-sheathed electric process heating and power controls suggest that significant savings are possible in footprint, efficiency, and reliability compared with conventional lowvoltage systems. OTC 26389 discusses the case study used to select a mediumvoltage, 2.6-MW heating system for a Gulf of Mexico location. Although the higher-voltage equipment capital cost is higher than the low-voltage equipment cost, installation, operating, and maintenance costs are less. Offshore opportunities continue to drive new technology applications and approaches. The three papers highlighted here focus on minimizing costs while providing safe, reliable operations. I hope you find them interesting. They reminded me to keep my mind open to new options. JPT

Recommended additional reading at OnePetro: www.onepetro.org. OTC 26832 Application of Flexible Composite Pipe as a Cost-Effective Alternative to Carbon Steel—Design Experience by Syafiah Adam, Brunei Shell Petroleum, et al. OTC 24022 Buoyant Tower: Construction Challenges and Lessons Learned by Clyde Crochet, HortonGMC, et al. OTC 27176 Use of Advanced Composites in Offshore Pipeline Design by Naveen Ravirala, Wood Group Kenny, et al.

Direct Electrical Heating of a Flexible Pipe

his paper describes a new direct electrical heating method in flexible-pipe systems. The method effectively expands the operational envelope of flexible unbonded pipes by offering prevention and removal of hydrate plugs and mitigation of wax precipitation by distributed heating along the entire pipe length. The directelectrical-heating solution is effectively operated as a coaxial cable, where electrical current is passed through the carcass and returned through the tensile-armor (TA) layers.

resembles a standard, coaxial-cable geometry, where the polymeric pressure sheath serves as the dielectric insulator. Although the directheating solution can be used as a standalone system, there are significant advantages to combining it with a fiberoptic thermal-monitoring system. Together, these two technologies yield a complete heating system that allows for monitoring and control.

The Concept of Direct-Heated Flexible Pipes

Full-Scale Experimental Setup

The general structure of the flexible unbonded pipe is shown in Fig. 1. The inside of the pipe consists of a stainless, wound carcass surrounded by a polymeric pressure sheath defining the fluid barrier. On top of the liner is pressure armoring made from interlocked C-shaped profiles. TA is made from two layers of helically wound steel profiles wound in opposite directions. Thermalinsulation tape may be present on top of the TA. The pipe is protected by a polymeric outer sheath. The idea behind the new flexiblepipe-heating concept is to pass electrical current directly through the existing carcass structure and return the current through the TA wires. This configuration makes it possible to feed the power into the pipe with the electrical feeds being connected only to the one end of the pipe, which is normally mounted topside. This electrical configuration

In addition to small-scale, midscale, and semifull-scale development tests, a full-scale qualification test was conducted that included a 125-m-long flexible pipe with a 12-in.-diameter bore. The test pipe was fitted with optical fibers to establish a method for distributedtemperature measurements. For reasons of redundancy, two identical helically wound multimode optical fibers were used. The purpose of the fiberoptic system is to measure the temperature of the pipe annulus. From knowledge of the annulus temperature, the bore temperature can be deduced. The pipe was transferred into a tank that was built for the purpose of imitating ocean thermal conditions. The tank was filled with seawater from the local harbor, and the water was circulated by a pump placed in the tank. The temperature in the tank was approximately 4°C. After a heat-up se-

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26936, “Direct Electrical Heating of a Flexible Pipe,” by T. Holst, T. Larsen, A. Straarup, K. Glejbol, and K.S. Olsen, National Oilwell Varco Denmark, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Fig. 1—A schematic of a flexible-pipe cross section showing the main layers in the general structure.

quence, the pipe cooled because of heat transfer to the water in the tank, hence raising the water temperature. The tank water was replaced a couple of times during cool down, typically once the water temperature reached 10–12°C. In order to measure the temperature of the bore fluid, a probe was inserted into one end of the pipe. During all tests, the entire pipe was filled with canola oil, which was chosen for environmental reasons and because its specific heat capacity is close to what could be expected in an oil field. The pipe could also be pressurized to typical operating pressure. The canola oil was not circulated, imitating a shut-down situation. The annulus condition of the pipe was dry. The pipe was heated from a standalone power system consisting of up to five paralleled three-phase diesel generators, each with a nominal power output of 500 kV-A. Only two of the generator’s three phases were used because the heated pipe is a single-phase system. A thyristor regulation unit was used to adjust the power applied to the pipe. The actual pipe length of 125 m limits the input voltage to approximately 100 V for a heating-power level of

The complete paper is available for purchase at OnePetro: www.onepetro.org. 76

JPT • NOVEMBER 2016

KBC Adv_ SPE Journal of Petro Tech_ Oct2016.pdf 1 9/7/2016 8:34:07 AM

World-class technology and consulting services for designing, operating and managing hydrocarbon production and processing facilities.

A Yokogawa Company

Production System Optimisation Flow Assurance Production Network Design Fluids and Oil Property Analysis Reliability & Maintenance Energy Efficiency Organisational Effectiveness

CMY

Our Engineering Software Suite

KBC will be at ADIPEC in Abu Dhabi, 7-10 November. Visit us at Booth 8412.

KBC Advanced Technologies answers@kbcat.com • www.kbcat.com • blog.kbcat.com AMER: +1 281 293 8200 APAC: +65 6735 5488 EMEIA: +44 1932 242424

SPE Hydraulic Fracturing Technology Conference 24–26 January 2017 The Woodlands, Texas, USA The Woodlands Waterway Marriott Hotel and Convention Center

Register now and explore effective solutions in hydraulic fracturing. • 50 paper presentations • 20 Knowledge Sharing ePosters • 90+ exhibiting companies • Six training courses • 1,000+ attendees www.spe.org/go/attend17HFTC

350 W/m. This setup is referred to as the low-voltage power configuration. In most scenarios, the pipe will be much longer; hence, the applied voltage will have to be much higher. In order to simulate a long pipe, an additional load bank was connected in series with the test pipe instead of the jumper cable. In this situation, a step-up transformer is inserted between the thyristor regulating unit and the test pipe. Because available load banks in the megawatt range are built for typical mains voltages, it was necessary for test purposes to include a step-down transformer after the test pipe and before the load bank, to simulate the load on a very long pipe. This is referred to as the high-voltage power configuration. In this power configuration, realistic voltages and currents could be applied to the test pipe simultaneously.

High-Voltage Power Configuration The high-voltage test was intended to make this full-scale test as realistic as possible by including a load bank simulating the main length of the pipe. If the power dissipated in the pipe is kept the same, there is no thermal difference between the low-voltage and the high-voltage tests. Therefore, the heatup and cool-down temperature profiles were very similar. The bore pressure was raised to 35 bar by hydraulic pumps and kept within ±5 bar of this value during the heat-up and cooldown cycles. The resistive load bank was used to mimic a longer piece of pipe by adding a resistor in series with the test pipe. Several heating tests were performed during which high voltage and high current were applied simultaneously to the test pipe.

Low-Voltage Power Configuration

Conclusions

The pipe was heated until the temperature measured by the fiber-optic monitoring system reached 60°C. Once at 60°C, the temperature was maintained by fiber-optic feed of temperature to the thyristor control system. After this hold period, the power was switched off and the pipe was allowed to cool down passively. The full heat-up/hold/cool-down cycle was then repeated. The bore-fluid temperature was approximately 10°C higher than the average fiber-optic temperature measurements. This temperature difference originates from the thermal gradient over the polymeric pressure sheath. The carcass, where the heat is generated, is placed on one side of the pressure sheath, and the temperature fiber is placed on the other side of the pressure sheath. Bore-fluid temperature measurements show that the bore temperature could be increased by more than 30°C within 12 hours. From the temperature profiles, temperature variations along the length of the pipe during heat up were estimated to be within ±5°C. This was without the canola oil being circulated. If the oil is circulated, one would expect the temperature variations largely to level out because the oil will transport heat along the pipe length.

It has been demonstrated repeatedly that it is possible to heat 125 m of 12-in. flexible pipe by passing current directly through the pipe carcass and returning it through the TA wires. Power cables were connected to the pipe at two modified end fittings. An experimental highvoltage setup was constructed and operated on-site, simulating the realistic power load situation of a 4-km-long flexible flowline. The following highlights can be emphasized: ◗ Power levels up to 350 W/m could be applied directly to the bore. ◗ Carcass currents and voltages up to 400 A and 2.5 kV, respectively, were applied simultaneously to the pipe. ◗ Bore-fluid heating up to 70°C was achieved. ◗ The obtained test results showed that the system was able to increase the bore temperature by more than 30°C over 12 hours. ◗ Temperature variations along the length of the test pipe were measured to be within ±5°C. ◗ Power regulation and control of heating temperature was demonstrated on the basis of input data from the integrated fiber-optic monitoring system. JPT

JPT • NOVEMBER 2016

An element of safety

Visualize barriers to strengthen risk management Wellbarrier IIlustration Tool is a specialized software to prepare well barrier illustrations. It helps you to make educated decisions throughout the lifecycle of the well. Be prepared â&#x20AC;&#x201C; make sure your wells are safeguarded.

Wellbarrier Illustration Tool â&#x20AC;&#x201C; used in 35 countries around the world.

www.wellbarrier.com

Flow-Assurance Methods Enabled by Medium-Voltage Heating Technology

edium-voltage electric heating systems offer reduced installation cost and increasing efficiency for multimegawatt oil and gas heating applications compared with low-voltage systems. For offshore applications, the systems offer the added benefit of both space and weight reductions. The technology is based on the same principles as low-voltage electrical-resistance heating that has been used in industry for the past century, but reapplied for mediumvoltage use.

Description and Application of Equipment and Processes

Introduction

Insulating Materials. One of the more important factors in the manufacture of medium-voltage heating elements involves the compound used inside the element to provide the right combination of thermal conductivity, electrical resistivity, and dielectric strength. Various oxides have been tested under high loads and environmental conditions to produce the optimal heat-transfer and electrical properties for use as mediumvoltage elements. For medium-voltage elements, a blend of highly pure magnesium oxide is extruded and fired to produce ideal compaction characteristics in a configuration that provides very high dielectric-breakdown voltages.

Most industries use low-voltage systems, typically less than 1,000 V, for electric heating applications. These were practical for most applications through the 20th century. Now, however, many applications in heavy industries such as oil and gas, petrochemical, and chemical demand much higher power output. These applications require multimegawatt electric heating systems. At low voltages, such requirements lead to challenges with power distribution, process design, and costs. A viable solution involves leveraging medium-voltage power. A safe and reliable technical design for metal-sheathed electric heating and power controls exists for heating systems operating at medium voltages. These medium-voltage electric heating systems allow the oil and gas industry to capture all the advantages of electric process heat while minimizing the disadvantages of lowvoltage, high-amperage designs.

A medium-voltage electric heating element is capable of very large power output that can operate on voltages up to 7,200 V. Modified dielectric material formulations are capable of ultrahigh insulation resistance and enable the element to reach values in excess of 25,000 V during safety testing. These two properties deliver the performance and reliability necessary for industrial applications, even at temperatures up to 540°C.

terminations automatically eliminates moisture intrusion. Failure Modes. Traditional modes of failure for low-voltage heating elements (e.g., stitching and phase-to-ground shorts) are more of a concern as voltage increases. An improved failure mode on medium-voltage elements occurs in the nonheated region, contributing to very safe dielectric properties over the element temperature ranges. Because of the high dielectric strength of the insulation material, the element’s resistance coil will typically melt, causing an open circuit or phase-to-phase failure before a phase-to-ground trip can develop. Processing and Element Compaction. Fill rates, vibration, and compaction techniques are critical for producing the best sealing and dielectric capabilities. The fill materials are assembled into the heating element in a temperaturecontrolled condition, avoiding many of the moisture-related issues appearing with low-voltage elements during fabrication.

Terminations. Dielectric breakdown and moisture intrusion at terminations present a common issue in electric heating. This is exacerbated when higher voltages are applied. As a beneficial side effect, the inherent dielectric strength required for medium-voltage

Pressure Boundary. Elements are able to interface effectively with a flange/ tubesheet using either tubing compression fittings to facilitate element replacement or a traditional welded connection. Either method of attachment can withstand up to 240 barg. In addition, the compression fittings allow for the replaceability of individual heating elements.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26389, “Flow-Assurance and Hydrate-Prevention Methods Enabled by Medium-Voltage Electric Heating Technology,” by C. Molnar and M. Riley, Chromalox, prepared for the 2016 Offshore Technology Conference Asia, Kuala Lumpur, 22–25 March. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Dielectric Breakdown. The mediumvoltage heating elements exhibit high dielectric withstand voltages across a wide temperature range, with dielectric resistance decreasing only slightly over the element’s normal operating range as temperature increases.

The complete paper is available for purchase at OnePetro: www.onepetro.org. 80

JPT • NOVEMBER 2016

Contact Resistance and Thermal Cycling. One of the more common causes of low-voltage-element failures involves loose or compromised terminations and electrical connections. For mediumvoltage elements, verification that the electrical connections are secure and insulated is performed on every connection to prevent excessive heat buildup and the potential for arc-related flash/ blast incidents. Thermal Endurance. Medium-voltage heating elements operating in a laboratory environment continuously over a year, heating both air and water, performed as designed, even under extreme cycling conditions. Test data show that medium-voltage-heating-element life expectancies are similar to those of low-voltage heating elements under the same set of operational conditions.

Presentation of Data and Results Installation Savings. Medium-voltage technology permits operation of process heat equipment directly from an existing distribution system up to 7,200 V, potentially eliminating the installation of dedicated step-down transformers for low-voltage duty. When operating multimegawatt systems, this cost avoidance has been shown to be approximately USD 25,000 or more per megawatt installed. Additionally, using medium-voltage heating elements instead of low-voltage elements for electric process heating reduces the amperage draw for the same heat output. This allows the end user to reduce both the wire diameter and number of wires necessary for installation when compared with a low-voltage source. Even considering the higher cost of medium-voltage wire compared with low-voltage wire, at higher voltages, the material savings on wire alone can equal USD 1.50 per amper per foot of run. A multimegawatt system operating at 4,160 V installed several hundred feet from the main distribution bus can save the end user close to USD 200,000. Finally, the higher voltage reduces the labor cost necessary for installation. Using fewer wires of smaller diameter reduces the time and effort for installation.

JPT • NOVEMBER 2016

Operating Savings. Operating at medium voltages increases the efficiency of power distribution and consumption. Electric process heat and control solutions have much higher efficiencies than fuel-fired systems, especially at reduced duty cycles. However, they are not 100% energy efficient. Energy losses occur in the form of heat generation. A typical low-voltage system will operate at approximately 96% efficiency, with 4% energy loss coming from heat generated by current transmission across wire, busing, connections, and instrumentation. However, the lower amperage associated with medium-voltage technology minimizes power loss. Electric power transmission lines operating at hundreds of thousands of volts exhibit the same benefit—high transmission efficiency and reduced line loss. For example, a purely resistive load multimegawatt electric heating solution operating at 4,160 V will run at almost 99% power efficiency. That 3% improvement in efficiency vs. low voltage translates into operating-cost savings for the life of the system. Maintenance Savings. One key advantage of electric process heat in general is the low cost of maintenance. With no moving parts and a robust design, electric process heaters will often operate for decades with minimal maintenance relative to fuel-fired equipment. Life-Cycle Savings. The system is designed to incorporate individually replaceable medium-voltage elements to reduce both time and cost in repair situations. The end user can remove a failed element, and the controller will make the necessary compensations to allow the heater to continue in service. Alternatively, spare elements from on-site storage can be used rather than needing a full heating unit from a manufacturer. Should an emergency arise, the production downtime involved with replacing failed elements is greatly reduced. For a typical multimegawatt system, the cost savings associated with replaceable elements can reach USD 100,000 per incident. Downtime may drop to a matter of days, as opposed to many weeks for a sourced replacement bundle.

Weight Savings. Heat output is a function of Ohm’s law such that, for a given power (heat) output, the amperage and voltage are in a one-to-one inverse relationship. Thus, when amperage is cut by a factor of 8 to 10, the voltage must be increased by the same factor. For the electric heater itself, this has only a slight effect on size and weight of the equipment. However, for the electric control panel and switch gear, there is a significant reduction of volume and weight when using medium-voltage power vs. low voltage. It holds true that, for medium-voltage systems, the weight and volume space savings can be as high as 35%. In the case of oil and gas electric heating applications, especially on offshore platforms, this could mean between 5 and 15 tons of weight reduction and between 100 and 300 ft3 of volumetric space savings.

Offshore Applications Typical heating applications on offshore platforms and production facilities include glycol reboiling, oil and gas conditioning, knockout drum heating, molecular-sieve regeneration, seawater or potable water, and fuel-/ lube-oil maintenance. Medium-voltage heating technology is ideally suited for such high-capacity heating applications. However, there is the potential to install high-pressure medium-voltage heating elements for downhole and subsea heating applications. Medium-voltage heating technology has advantages over low-voltage heating solutions because of the minimal heat-generation energy losses that come from operating at thousands of volts over long distances. In addition, it has an advantage over heating-cable solutions because those cables are limited to minimal heat output per linear foot, requiring the entire well/pipe length to be heated. By using medium-voltage heating elements, high-powered heating systems can be integrated into a clamshell assembly capable of delivering large amounts of heat to much smaller underwater heating zones as a downhole and subsea tool. Further, a complete centralized hot-water/-oil subsea heating system can be used for the distribution and control of heat across a subsea field. JPT

Thermoplastic-Composite-Pipe Flowline Helps Reduce Project and Life-Cycle Costs

hermoplastic composite pipe (TCP) is a spoolable, fully bonded, thermoplastic pipe with glass or carbon-fiber reinforcements. The bonded composite pipe has a solid wall like steel pipe and is able to cope with corrosive environments without being affected. For its low weight and collapse resistance, TCP is most often associated with deep water. However, the combination of a solid wall, spoolability, and corrosion resistance makes TCP attractive for production-flowline applications in shallow water also.

TCP TCP uses a one-material design concept in which the internal liner, the composite layers, and the outer coating are all of the same polymer material (Fig. 1). The pipe is made with an in-situ-consolidation manufacturing process that melt-fuses all layers together to form a strong and stiff solid wall. This produces a pipe that is collapse resistant, spoolable, lightweight, and corrosion resistant. The orientation of the reinforcement fibers (the lay-up) can be varied for each layer, enabling an optimized design for each set of design requirements, such as internal and external pressure rating, tension capability, allowable bending radius, and fatigue performance. The flexibility and spoolability of the solid pipe are the result of the relatively high strain in the glass-fiber materials and, to a lesser extent, in carbon fibers, compared with steel. Flexibility comes at the expense of tension capacity and vice versa. Therefore, TCP that is designed for high ten-

sion (e.g., in dynamic riser applications) will have a larger minimum bend radius than TCP that is optimized for bending. In practice, bending strains of 1 to 3.5% are achieved. For example, a 7-in.-innerdiameter flowline is spooled on a 6-mbarrel-diameter storage drum and has a minimum bend radius in service of 5 m.

Applications Within the oil and gas industry, TCP is applied in the market segments of subsea flowlines, umbilicals, and risers; well intervention; and pipeline precommissioning. Well intervention includes operations such as acid stimulation, chemical injection, and plug and abandonment. The following products are applied in intervention and precommissioning: ◗ Downline—free-hanging pipe, deployed from surface vessel to the seabed to pump fluids down ◗ Jumper—the dynamic, flexible, and collapse-resistant pipe between static and dynamic subsea equipment (e.g., from downline to injection skid or tree) In subsea flowlines, umbilicals, and risers, typical TCP applications are ◗ Corrosion-free static flowlines and risers for hydrocarbon ◗ Jumper spools providing flexibility to cope with large deflection envelopes ◗ Flexible (dynamic) risers for deepwater production operations providing low-weight seabed-tosurface fluid conduits Pressure ratings are related to diameter. The maximum design pres-

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26512, “Reduce Project and Life-Cycle Cost With TCP Flowline,” by Bart Steuten and Martin van Onna, Airborne Oil and Gas, prepared for the 2016 Offshore Technology Conference Asia, Kuala Lumpur, 22–25 March. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

sure that is qualified and delivered is 10,000 psi at 2.5-in. internal diameter for high-collapse-resistant subsea jumper applications.

End Fittings TCP end fittings rely on a proven and simple clamping method. The extensively tested and proven clamping method avoids having to terminate individual reinforcement layers, can be applied at any point in a pipe, and can be assembled at any location in the world. The internal stem results in a minor reduction of the internal diameter. For typical flowline sizes, the internal diameter at the end fitting is 95% of the flowline internal diameter, ensuring that the TCP is fully piggable.

Materials and Corrosion The fully bonded composite wall of the TCP flowline is impervious to corrosion, including the most-aggressive and mostunpredictable types of corrosion such as microbacteria-induced corrosion caused by sulfur-reducing bacteria. Contrary to steel corrosion, which is often difficult to predict, the long-term effects such as polymer aging that slowly reduce the strength of composite flowlines are accurately characterized and implemented in design. In comparison with carbon-steelpipeline systems, significant operational benefits are obtained by designing out the possibility of flowline corrosion. ◗ Corrosion and biocide inhibition can be omitted. Equipment such as pumps, storage tanks, tubings, and umbilicals and logistical operations for the chemical supplies are not required. ◗ Wall-thickness measurement by intelligent pigging is not required. Instead, aging of the polymer materials can be monitored through coupon examination and comparison with design values.

The complete paper is available for purchase at OnePetro: www.onepetro.org. 82

JPT • NOVEMBER 2016

Coating Laminate (Tailored lay-up) Fig. 1â&#x20AC;&#x201D; Liner Thermoplastic-compositepipe concept (left) and laminate microscopy.

Installation The spoolability of TCP and the potential to manufacture long lengths allow for efficient and cost-effective reel-lay installation. This can be achieved with dedicated reel-lay vessels, cable-lay vessels, or multipurpose vessels outfitted with the required pipe-lay equipment. The equipment needed includes a turntable or reel with reel-drive system, tensioner, and overboarding chute to control the minimum bending radius duringÂ overboarding. If the pipe is to be buried, and if a suitable vessel is selected such as a dedicated flexibles-lay vessel with trencher, the pipe can be laid and buried simultaneously in a single pass. The flexible pipe allows installation from any subsea or topside tie-in point. In the case of topside tie-in, which is the case for platform-to-platform installation, the installation of the flowline from topside tie-in point to topside tie-in point can be achieved without subsea flange connections and without diver interventions.

Operational Aspects In service, the primary concerns are to keep up the flow and ensure integrity. TCP flowlines are fully piggable, allowing the flowlines to be regularly cleaned of sand, scale, and wax by means of suitable pigs (e.g., foam, soft-brush pigs). The regular pipeline-cleaning operations with TCP, therefore, are similar to those with steel flowlines. However, because of the smooth surface of the internal liner that remains smooth throughout the TCP service life (no corrosion), one can expect that scale and wax will be less likely to precipitate on the pipe wall. Consequently, one can expect a longer interval between required cleaning-pig runs. Caliper pigging can be used to inspect the pipe internal geometry in the case of

JPT â&#x20AC;˘ NOVEMBER 2016

irregularities. Local indentation of the pipe wall because of external impact can be detected internally because the solid wall means external denting always will result in internal denting. Optionally, on the platform topside, a short test piece, or coupon, can be placed in the flow path to monitor the aging of the pipe material. At predefined intervals during the design life, the test material can be retrieved and tested to compare the mechanical properties of the test materials with the design values.

Project Scope Comparison With Steel Flowline and Unbonded Flexibles In order to evaluate and assess the costeffectiveness of the TCP flowline, a comparison with other available solutions needs to be made. On the project level, the bulk of the pipeline cost usually is associated with installation. Especially for carbon-steel pipelines, the material cost is only a fraction of the total pipeline asinstalled cost. With flexible, spoolable pipe, material cost is higher and installation cost is lower. This is the case for both unbonded flexible pipe and TCP flowline. The higher material cost changes the distribution of cost more toward materials; however, because of high installationvessel costs (mobilization cost and day rate), the majority of the project cost remains with installation. Although carbon-steel-pipeline material costs are considerably lower compared with unbonded-flexible-pipe and TCP costs, the lay cost for steel pipe is high. Day-rate costs for reel-lay vessels are lower. Subsequently, for seabed intervention work, pipe burial, and tie-ins to the platform, separate vessels have to be mobilized. For the tie-in, costly diver intervention, metrology, and spool-piece fabrication after the metrology are needed.

For the unbonded flexible pipe or TCP, only one vessel mobilization is required for the installation. By using a flexible-lay vessel with trenching capacity, TCP can be laid and simultaneously buried by jet trencher, mechanical trencher, or plow. Bundling of the TCP with steel wire rope to achieve on-bottom stability is also conducted simultaneously with the pipe lay. The tie-in to the platform can be completed with the same vessel. This single-vessel and singlemobilization operation results in large cost savings and a reduction of project risk. In addition to installation and tie-in cost, because of the requirement for corrosion inhibition with carbon steel, additional platform and equipment costs are entailed for the carbon-steel-case alternative, including costs for inhibitor pumps and storage tanks. Installation costs of unbonded flexible pipe and TCP flowline can be expected to be very similar. The advantage on cost that TCP has over unbonded flexible pipe lies in lower pipe-manufacturing costs. Lower TCP manufacturing costs are the result of lower capital investment costs, simple pipe construction, and simple end-fitting design.

Operational Cost The main contributors to operational cost for carbon-steel pipelines are the corrosion-inhibition fluids and the logistical costs associated with this. Specifically in offshore environments, logistical costs are high because the fluids must be transported over sea by supply vessels. Further operational costs relate to inspection and monitoring costs and the cost of the loss of production during, for example, intelligent-pigging inspection of pipelines or inhibitor batch dosing. All of the costs related to corrosion can be avoided if noncorrosive TCP flowline is used instead of carbon steel. JPT

SPE NEWS

The Way Ahead Magazine Transitions to a Web Publication With the launch of the redesigned, device-friendly website, SPE young professionals’ magazine, The Way Ahead (TWA), is now an online-only publication and can be found at www.spe.org/twa. The old website, which held pdfs of articles from the print issues, has been updated to a webfriendly format and adapts to desktop, tablet, or mobile reading. Moving away from the individual issue model, the TWA website will feature new content regularly under its traditional departments and will also be grouped under broad topics such

as Business, Career, and Technology. Social media and email options are provided with each article for easy sharing, and a monthly email newsletter delivering the latest updates from the website will be sent to readers. Launched in 2005, TWA is produced by SPE young professional volunteers who make up the TWA Editorial Committee. They write the articles or solicit them from industry leaders on topics that are of interest to young professionals, such as career development, emerging technologies, mentoring, and university-to-industry transition.

SPE Recognizes Technical Editors Every year, SPE recognizes members who have made an exceptional effort to ensure the technical excellence of the Society’s peer-reviewed journals. For their contributions, the following individuals are recipients of the 2016 Outstanding Technical Editor Award.

SPE Drilling & Completion Glen Benge, Benge Consulting Peter Boul, Aramco Services Company Roman Bulgachev, BP John Cook, Schlumberger David Curry, Baker Hughes Mark Dykstra, Shell Jeremy Greenwood, Halliburton Xianping (Sean) Wu, Shell

SPE Economics & Management Nikita Chugunov, Schlumberger Amin Ettehadtavakkol, Texas Tech University Scott Meddaugh, Midwestern State University Babafemi Ogunyomi, Chevron Doug Reynolds, University of Alaska Fairbanks

SPE Journal Simeon Agada, Imperial College London Vladimir Alvarado, The University of Wyoming Baojun Bai, Missouri University of Science and Technology Steffen Berg, Shell Rodolfo Camacho Velazquez, Pemex

SPE Honors Peer Reviewers of Technical Papers SPE created the A Peer Apart program to recognize dedicated individuals who have been involved in the peer review of 100 or more papers. This year, six individuals join the elite group, bringing the total membership of A Peer Apart to 149 dedicated members. Hussein Hoteit, Chevron Vladimir Alvarado, University of Wyoming Faruk O. Alpak, Shell

Peilin Cao, Chevron Eric Delamaide, IFP Technologies Canada Yannong Dong, Statoil Noaman El-khatib, Consultant Reza Fassihi, BHP Billiton Bo Gao, ExxonMobil Guohua Gao, Shell Jiahang Han, Baker Hughes Jincong He, Chevron Hussein Hoteit, Chevron Katie Humphry, Dutch Petroleum (NAM) Minsuk Ji, Baker Hughes Saeid Khorsandi, Pennsylvania State University

Joyce Holtzclaw, E&B Natural Resources Management G. Paul Willhite, University of Kansas Harvey Yarranton, University of Calgary

Kenneth Kibodeaux, Shell Anthony Kovscek, Stanford University Byungtark Lee, Itasca Houston Olwijn Leeuwenburgh, TNO Hangyu Li, Shell Huazhou Li, University of Alberta Botao Lin, China University of Petroleum, Beijing Silviu Livescu, Baker Hughes Haishan Luo, The University of Texas at Austin Cesar Mantilla, Shell Kishore Mohanty, The University of Texas at Austin Hisham Nasr-El-Din, Texas A&M University

JPT • NOVEMBER 2016

Changhe Qiao, Pennsylvania State University Cindy Ross, Stanford University Josephina Schembre-McCabe, Chevron Peter Schutjens, Shell Qiang Sheng, BP Jianlei Sun, Texas A&M University Vahid Taghikhani, Sharif University of Technology Dongmei Wang, University of North Dakota Shugang Wang, Chevron Yixuan Wang, Stanford University Yushu Wang, Shell Global Solutions Christian Wolfsteiner, Chevron Terry Wong, Landmark Graphics Bicheng Yan, Texas A&M University Meng Yu, Shell Rustem Zaydullin, Stanford University

SPE Production & Operations Ghaithan Al-Muntasheri, Saudi Aramco Frank Chang, Saudi Aramco Luud Dorrestijn, Consultant

Wayne Frenier, Consultant Rashid Hasan, Texas A&M University David Knowles, Shell Lingling Li, AkzoNobel Jiajing Lin, New Mexico Mining Institute of Mining & Technology

SPE Reservoir Evaluation & Engineering Anil Ambastha, Chevron Nigeria Mariela Araujo Fresky, Shell Subhash Ayirala, Saudi Aramco Steffen Berg, Shell Garfield Bowen, Ridgeway Kite Software Bruce Carey, Peters & Company Mark Chan, Suncor Energy Yuguang Chen, Chevron Yildiray Cinar, Saudi Aramco Torsten Clemens, OMV Exploration & Production Albert Cui, CBM Solutions Eric Delamaide, IFP Technologies Canada Tim Duggan, Petroleum Development Oman

Bo Gao, ExxonMobil Choongyong Han, Chevron Byron Haynes, Shell Myung Hwang, PetroTel Shah Kabir, CS Kabir Consulting Gavin Longmuir, Consulting Petroleum Engineers Hassan Mahani, Shell Olu Okpani, Chevron Nigeria Ryosuke Okuno, The University of Texas at Austin Jyotsna Sharma, Chevron Vijay Shrivastava, Computer Modelling Group Diederik van Batenburg, Shell Johan van Dorp, Shell Thomas von Schroeter, BP

Oil and Gas Facilities Williams Chirinos, Inexertus Galen Dino, Consultant Ted Frankiewicz, Spec Services Terry Lou, ProSep Sudhakar Mahajanam, Pinnacle Advanced Reliability Technologies

SPE EVENTS WORKSHOPS 9–10 November ◗ The Woodlands—SPE Strategies for Identifying and Exploiting the Sweet Spot in Unconventional Reservoirs

25–26 January 2017 ◗ Abu Dhabi—SPE/ EAGE: Reservoir Life Cycle Management— Innovation and Sustainability in Dynamic Oil Price Environment

15–16 February 2017 ◗ Calgary—SPE Canada Heavy Oil Technical Conference 15–16 February 2017 ◗ Calgary—SPE Canada Unconventional Resources Conference

13–16 November ◗ Cairo—SPE Deep Wells Challenges in a Challenging Condition

6–7 February 2017 ◗ Muscat—SPE Advanced Field Development— Sustainability and Challenges

SYMPOSIUMS

16–17 November ◗ Abu Dhabi—AAPG/ EAGE/SEG/SPE Knowledge Management Challenges

6–7 February 2017 ◗ Abu Dhabi—SPE Global Integrated Series: Managing Well Integrity in a Low-Cost Oil Environment

29 November–1 December ◗ Banff— SPE Thermal Well Integrity and Design

21–23 November ◗ Dubai—SPE/AAPG/ EAGE Unconventional Plays: Achieving Efficiency and Effectiveness Through Integration

13–14 February 2017 ◗ Kuala Lumpur—SPE Mature Field Redevelopments—How to Stay Relevant For the Foreseeable Future

15–16 March 2017 ◗ Salvador—SPE Latin American and Caribbean Mature Fields

21–23 November ◗ Kuala Lumpur— SPE Flow Assurance—Survival During Industry Downturn 28–29 November ◗ Kuala Lumpur—SPE GIWS: Maximising Asset Value in a Low Oil Price Environment Through CostOptimised Well Integrity Activities 5–6 December ◗ Kuala Lumpur—SPE Challenges of CO2—Creating Value Through Innovativeness for Separation, Transportation, and Utilisation 12–14 December ◗ Houston—AIChE/SPE: Next Generation Deepwater Facilities

CONFERENCES

15–16 March 2017 ◗ Amman—SPE Iraq— The Petroleum Potentiality and Future of Energy

14–16 November ◗ Bangkok—International Petroleum Technology Conference

27–31 March 2017 ◗ Oklahoma City— SPE Oklahoma City Oil and Gas

30 November–1 December ◗ Manama— SPE Middle East Artificial Lift Conference and Exhibition

FORUM

5–7 December ◗ Nairobi City—SPE/AAPG Africa Energy and Technology Conference 6–8 December ◗ Mangaf—SPE International Heavy Oil Conference & Exhibition 24–26 January 2017 ◗ The Woodlands— SPE Hydraulic Fracturing Technology Conference and Exhibition

14–16 February 2017 ◗ Rotterdam—SPE Forum Series—Emerging Technologies

CALL FOR PAPERS SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition ◗ Bali Deadline: 9 December SPE Offshore Europe ◗ Aberdeen Deadline: 13 January 2017

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

JPT • NOVEMBER 2016

PEOPLE ROBIN FIELDER, SPE, was appointed vice

president, investor relations, at Anadarko, with JOHN COLGLAZIER serving in an advisory capacity as senior vice president until his retirement early next year. Fielder’s previous positions at the company include director, investor relations; general manager of East Texas and North Louisiana; and worldwide operations business advisor. She holds a BS degree in petroleum engineering from Texas A&M University, and is a registered professional engineer in the state of Texas. PETER SOROKA, SPE, was appointed ad-

vanced completions commercialization manager at Tendeka. He joins the company from OMV UK, where he was head of increased oil recovery/enhanced oil recovery technology. Soroka joined Tendeka’s newly formed enhanced production and client services group and will also be responsible for expanding the company’s client base. He has more than 35 years’ experience in technological development for oil and gas projects worldwide; incorporating subsea reservoirs and wells; and greenfield, brownfield, and satellite projects. EVE SPRUNT, SPE, was appointed Presi-

dent-Elect at the American Geosciences Institute. She was the 2006 SPE president. Sprunt has professional society and business management experience and was a founder of the Society of Core Analysts. She was recently the first vice president of the Society of Exploration Geophysicists (SEG), where she founded the SEG Women’s Network Committee. Now a consultant, Sprunt held advisory and management roles at Chevron until 2013, including business development manager for Chevron Energy Technology Company, university partnership and recruitment manager, and most recently advisor for geological research and development. Before joining Chevron, she worked at Mobil Oil Corporation for 21 years in upstream new business development and research and development of technologies. Sprunt holds 23 patents and has authored several technical papers and editorials for industry publications. She was a member of the SPE Board from 1991 to 1994 and an SPE Distinguished Lecturer during 1998–1999 and 2015–2016. Sprunt was recognized with SPE Honorary Membership in 2010 and Society of Women Engineers’ Achievement Award in 2013. She holds BS and MS degrees from Massachusetts Institute of Technology in earth and planetary sciences and a PhD from Stanford University in geophysics.

In Memoriam This section lists with regret SPE members who recently passed away. If you would like to report the passing of a family member who was an SPE member, please write to service@spe.org. Carroll B. Cox, Palo Alto, California, USA Roy B. Riggs Jr., Dallas, Texas, USA KEITH HAL COATS, SPE, died 13 September 2016. He was 81. He was an accomplished teacher and pioneer developer of reservoir simulation software. In 1992, Coats founded Coats Engineering and served as the president until 2005 and technical director until his death. There he developed the reservoir simulator, Sensor, beginning in 1992 and continued to work on it until his death. Before cofounding Intercomp Resource Development and Engineering in 1968, Coats was assistant professor of chemical engineering at the University of Michigan, research associate at Esso Production Research, and associate professor of petroleum engineering at the University of Texas. He was chairman of the board at Intercomp from 1968 to 1983 and technical director at Scientific Software-Intercomp from 1982 to 1992. He developed and published detailed descriptions of a number of increasingly complex black oil, compositional, and thermal reservoir simulation models. Coats authored more than 70 technical papers and contributed to the Petroleum Engineering Handbook. A Distinguished Member of SPE, he received the Lester C. Uren Award and Anthony F. Lucas Gold Medal. He was elected to the National Academy of Engineering in 1988. Coats held BS, MS, and PhD degrees in chemical engineering, and an MS degree in mathematics, all from the University of Michigan. MICHAEL LYLE PAYNE, SPE, died 9 September 2016. He was 56. Payne had more than 30 years of experience in the industry, including in drilling operations, computing, research, and consulting. He was recognized with the SPE Drilling Engineering Award in 2000. Payne was a segment engineering technical authority at BP and previously held positions at the company leading up to distinguished advisor. Before joining BP, Payne worked at ARCO for several years and on assignment to ARCO British worked on the the BP Wytch Farm ERD project. Payne held leadership positions at the American Petroleum Institute and made significant contributions to the development of industry standards. He authored several technical papers and was a member of the JPT Editorial Committee. An SPE Distinguished Lecturer, he was chairperson or cochairperson of several SPE Advanced Technology Workshops and member of SPE conference committees. Payne held BS and PhD degrees in mechanical engineering from Rice University, and a master’s degree in petroleum engineering from the University of Houston.

JPT • NOVEMBER 2016

PROFESSIONAL SERVICES

contact@AvasthiConsulting.com

FTI

™

www.AvasthiConsulting.com

AVASTHI & ASSOCIATES, INC. Worldwide Energy Consulting, Engineering, Training, Shale and EOR/IOR Project Operations Since 1990 Field Development Planning (FDP) of Onshore and Offshore (Shallow and Deep water) Oil, Gas, Gas-condensate, and Heavy Oil Fields, and Unconventional/ Shale Resources. Reservoir Characterization, Engineering and Simulation (Static and Dynamic Modeling), Economic Evaluation, IAM, EOR/IOR, CCUS, Geomechanics, and Fracturing/Stimulation

Head Office: 800 Rockmead Drive, Suite 212 Houston, Texas 77339, U.S.A. • Phone: +1-281-359-2674

PLATT SPARKS • • • • • • • • • • • •

Consulting Petroleum Engineers Reservoir Engineering Reservoir Simulation Reservoir Characterization Oil and Gas Reserves Evaluation Fair Market Value and Acquisition Valuation Enhanced Oil Recovery Economic Evaluation Oil and Gas Production Gas Storage Design and Screening Regulatory Filings and Database Acquisition Expert Petroleum Engineering Testimony

FTI Platt Sparks 925-A Capital of Texas Highway S. Austin, Texas 78746 U.S.A. (512) 327-6930

Changing Your Address? Let SPE know +1.972.952.9393

lenandersen.com Len Andersen

www.FTIConsulting.com www.PlattSparks.com expert@ftiplattsparks.com

800-428-4801

H.J. Gruy and Associates, Inc.

SPE Benefits

LONQUIST & CO. LLC Petroleum Engineers • Energy Advisors www.lonquist.com

Oil and Natural Gas Reserve Advisors

Discover the possibilities. http://www.spe.org/members/benefits

CG A

Reserve Determinations Geologic Studies Field Studies Petrophysical Analysis Reservoir Simulation Stochastic Evaluations

Market Valuations Expert Testimony Arbitration Commercial Models Risk Analysis Acquisition Screening

6575 West Loop South, Suite 550 Bellaire, Texas 77401 TEL: (713) 739-1000 FAX: (713) 739-6112 hougruy@hjgruy.com

• • • •

Reservoir Engineering Reserve Determinations Economic Evaluations Underground Storage Engineering • Salt Cavern Engineering • Supply Studies • Mining Engineering

• Merger & Acquisition Support • Mineral and Royalty Management • Regulatory Filings and Testimony • Facilities Engineering • Disposal Well Design • Graphical Information Systems

Austin — Houston — Wichita — Calgary

CAWLEY, GILLESPIE & ASSOCIATES, INC.

www.hjgruy.com

PETROLEUM CONSULTANTS SINCE 1960

Worldwide Petroleum Consulting

M.J. ENGLAND, P.E.

HOT Engineering

CONSULTING PETROLEUM ENGINEER

Fort Worth (817) 336-2461

Houston (713) 651-9944

Austin (512) 249-7000

www.cgaus.com – info@cgaus.com

COUTRET AND ASSOCIATES, INC. Petroleum Reservoir Engineers Property Evaluation, Reservoir Engineering Fluid Injection, Property Management 401 Edwards Street, Suite 810 Shreveport, LA 71101

Phone (318) 221-0482 Fax (318) 221-3202

www.coutret.com

FORREST A. GARB & ASSOCIATES, INC. International Petroleum Consultants Reservoir Engineering Economic Evaluation Geologic Studies Forensic Engineering

Expert Witness Reservoir Simulation Due Diligence Technical Staffing

5310 Harvest Hill Road, Suite 275 Dallas, Texas 75230-5805 Tel: 972-788-1110 Fax: 972-991-3160 Email: forgarb@forgarb.com Web pages: www.forgarb.com

Frank Givens, CPA Structured approach to Investment Decisions 662-404-3798 frank.givens@lpl.com LPL FINANCIAL Member FINRA/SIPC

JPT • NOVEMBER 2016

Exploration / Field Development / Training

Reserve Reports Fair Market Value

Estate Appraisals Expert Witness

215 Union Blvd., Suite 350 Lakewood, CO 80228-1840 Telephone: 303/298-0860 Facsimile: 303/298-0861

Integrated Reservoir Studies • Lead & Prospect Generation • Reservoir Characterisation • Field SERVING THE OIL AND GAS INDUSTRY FOR Development Planning • Enhanced Oil Recovery • OVER 60 YEARS Underground Gas Storage • Reserves Audits • Training & HR Development www.hoteng.com Parkstrasse 6, 8700 Leoben, Austria INTERNATIONAL OIL AND GAS CONSULTANTS Phone: +43 3842 430530 / Fax: +43 3842 430531 hot@hoteng.com, training@hoteng.com

MILLER AND LENTS, LTD.

Huddleston & Co., Inc. Domestic and International Petroleum & Geological Engineers 1221 McKinney, Suite 3700 Houston, TX 77010 Ph: (713) 209-1100 Fax: (713) 209-1104 e-mail: info@HuddlestonCo.com

International Reservoir Technologies, Inc. INTEGRATED RESERVOIR STUDIES Seismic Interpretation & Modeling Stratigraphy & Petrophysics Reservoir Simulation Enhanced Oil Recovery Studies Well Test Design & Analysis Well Completion Optimization 300 Union Blvd., Suite 400 Lakewood, CO 80228 PH: (303) 279-0877 Fax: (303) 279-0936 www.irt-inc.com IRT_Information@irt-inc.com

Specializing in All Phases of Reserves Evaluations, Including Petroleum Economics, Reservoir Engineering, Geology, and Petrophysics

Two Houston Center Phone: (713) 651-9455 909 Fannin St., Ste. 1300 Fax: (713) 654-9914 Houston, TX 77010 e-mail: mail@millerandlents.com Web pages: http://www.millerandlents.com

NITEC

LLC

International Petroleum Consultants Fractured Reservoir Characterization/Modeling Gas Storage • Unconventional • EOR • CO2 CCS Black Oil/Compositional/Thermal Reservoir Simulation Provider of LYNX®, MatchingPro®, PlanningPro® and ForecastingPro® Software Denver, Colorado 475 17th Street, Suite 1400 Ph. (303) 292-9595 www.NITECLLC.com

PERA

ROBERTO AGUILERA, Ph.D. SERVIPETROL LTD.

Curtis H. Whitson & Associates

International Petroleum Consultants Independent Oil and Gas Producers

Naturally Fractured Reservoirs Log Interpretation Well Test Analysis Design & Analysis of PVT Data Performance Forecasts Economics Gas Condensate Specialists Numerical Simulation Compositional Simulation Expertise Petroleum Short Courses Pipe-It Integrated-Model Optimization E-mail: aguilera@servipetrol.com 903-19th Avenue SW, Suite 502 Skonnertveien 7, 1st floor • 7053 Ranheim Norway Calgary, Canada T2P 3T7 Phone 47 7384 8080 / Fax 47 7384 8081 Phone: (403) 266-2535 Fax: (403) 264-8297 whitson@pera.no / www.pera.no http://www.servipetrol.com

EOS Fluid Characterization

PetroTel

SiteLark

Reservoir Modeling and Engineering Services Please Contact: www.sitelark.com

Telephone: 469-222-5436 E-mail: dbiswas@sitelark.com

PRA

JAMES E. SMITH & ASSOCIATES, INC.

Petrotechnical Resources of Alaska, LLC

Alaska’s Oil and Gas Consultants Geology, Geophysics, and Engineering www.Petroak.com 3601 C Street Suite 1424

(907) 272-1232 voice (907) 272-1344 fax Anchorage, AK 99503

Taking Petroleum Engineering Training to a New Level For dates & descriptions of courses held worldwide, please visit us at

www.TarekAhmedAssociates.com

WILLIAM M. COBB & ASSOCIATES, INC. — WORLDWIDE PETROLEUM CONSULTANTS — Waterflood & EOR Studies Geological & Petrophysical Analysis Reservoir Simulation Unconventional Resource Evaluation Reserves & Property Valuation Gas Storage & CO2 Sequestration Analysis Expert Witness • Technical Training

A Flotek Company

Worldwide Offices: Ph: +1-972-473-2767

Tarek Ahmed & Associates Ltd.

SPARTAN OPERATING CO., INC.

310 South Vine Avenue, Tyler, TX 75702 903-593-9660 • 903-593-5527 (FAX) • 800-587-9660

12770 Coit Road, Suite 907, Dallas, TX 75251 Phone (972) 385-0354 www.wmcobb.com FAX (972) 788-5165 office@wmcobb.com

ZAETRIC

Providing technical document development, business process support and printing/binding services to the oil & gas industry since 2000. • DOCUMENTATION — Drilling & Completion, Rig Operations, QA/HSE, Equipment, Reports, Instructions & Procedures • BUSINESS PROCESS — Technical Contracts, RFQs, Process Evaluation, Project & Vendor Management • PRINTING/BINDING — Turnkey, In-House, Customizable, Quick Turnaround

smithjames@jes-engineer.com • http://www.jes-engineer.com James E. Smith, P.E., Registered Professional Engineer

www.zaetric.com • The Woodlands, Texas 281-298-1878 • inquiries@zaetric.com

ADVERTISERS IN THIS ISSUE JPT ADVERTISING SALES ADIPEC 2016 Page 55

LEUTERT Page 47

Advanced Technology Valve SpA Page 37

Mohawk Energy Page 5

Baker Hughes Page 9

NCS Multistage, LLC Page 2

C&J Energy Services Page 63

Peloton LandView Page 19

Cameron, a Schlumberger company Pages 17, 23

Peloton, Inc. Page 41

Cansco Well Control Page 43

Production Tool Solution Page 3

CARBO Page 51

PV Fluid Products, Ltd. Page 11

CD-adapco Page 57

Rock Flow Dynamics Cover 3

Enventure Page 35

Saudi Aramco Page 39

FracGeo LLC Page 49

Schlumberger Cover 2, Page 7

Georgia-Pacific Chemicals Page 31

Superior Energy Services, Inc. Page 27

Hexion Page 25

TAM International Page 4

Ingevity formerly MWV Specialty Chemicals Page 73

Tendeka Page 71

Interwell Norway AS Page 13

The University of Texas at Austin, Dept. of Petroleum & Geosystems Engineering Page 54

K+S KALI Page 15 KAPPA Engineering Cover 4 KBC Advanced Technologies Plc Page 77

Visuray Page 21 Wacker Chemical Corporation Page 53 Wellbarrier AS Page 79

Dana Griffin Advertising Sales Manager (Americas, Asia Pacific, and South Asia) Tel: +1.713.457.6857 dgriffin@spe.org Jane Bailey Advertising Sales Manager (Europe, Middle East, Russia, and Africa) Tel: +44 (0) 1227.266.605 jbailey@spe.org Craig W. Moritz Assistant Director Americas Sales & Exhibits Tel: +1.713.457.6888 cmoritz@spe.org

ADDRESS CHANGE: Contact Customer Services at 1.972.952.9393 to notify of address change or make changes online at www.spe.org. Subscriptions are USD 15 per year (members). JPT JOURNAL OF PETROLEUM TECHNOLOGY (ISSN 0149-2136) is published monthly by the Society of Petroleum Engineers, 222 Palisades Creek Drive, Richardson, TX 75080 USA. Periodicals postage paid at Richardson, TX, and additional offices. POSTMASTER: Send address changes to JPT, P.O. Box 833836, Richardson, TX 75083-3836 USA.

JPT • NOVEMBER 2016

Your reservoirs

ARE AS OLD as the

DINOSAURS.

Your

SIMULATION TECHNOLOGY doesn’t have to be.

Reservoirs are ancient, but your simulation technology shouldn’t be. Today, tNavigator is the apex predator, with the ability to close the loop on model simulation cycles. With tNavigator, you can quickly create and convert geological models to HD models for a complete loop solution. So don’t settle for prehistoric software—switch to tNavigator.

www.trytnavigator.com

RFD-014_Dinosaur_tNavigator_Campaign_080816.indd 1

8/9/16 9:28 AM

KAPPA | Unconventional Resources

A new, real-physics constrained, efficient workflow for the management, analysis and forecasting of production data in unconventional plays. Coming soon in KAPPA Generation 5

In collaboration with DeGolyer and MacNaughton

Find out more: www.kappaeng.com/ur