Gulfpub_wo_201808.pdf

AUGUST 2018 / DEFINING CONVENTIONAL, SHALE AND OFFSHORE TECHNOLOGY FOR OIL AND GAS / WorldOil.com

PERMIAN BASIN TECHNOLOGY Technical advances propel the leading U.S. region forward

SHALETECH PRACTICES

Filling the gaps in understanding shale well performance

DRILL PIPE

4th-generation connection enhances land drilling

REGIONAL REPORT: WEST AFRICA

Working toward becoming a global oil and gas supplier

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© 2018 National Oilwell Varco | All Rights Reserved

CONTENTS AUGUST 2018 / VOL. 239 NO. 8

9

78

43 SPECIAL FOCUS:

PERMIAN BASIN TECHNOLOGY 29

DRILL PIPE

COLUMNS

65

7

Permian basin leads the pack T. Harris

37

43

Perforating system improves stimulation results in unconventional completions

G. Plessis / A. Muradov D. Morgan / S. Forrester J. Dugas / B. White

A. Dyess

HSE - WELL CAPPING

New frac-pack additive is step change in sulfide scale control for Permian long horizontals

69

PERMIAN BASIS: ANALYSIS Permian oil production requires additional pipeline infrastructure

DIGITAL TRANSFORMATION/ OFFSHORE PRACTICES 73

53

Enhanced understanding improves “child well” performance G. Lindsay / G. Miller / T. Xu / D. Shan / J. Baihly

59

Copper alloy coupling reduces rod failures, boosts well efficiency C. Curran / D. Nielsen / W. Nielsen / R. Cash

Maintaining asset integrity during hurricane season

First oil Consent given to fracing first onshore, horizontal well in the UK

13

Energy issues A mixed bag

15

What’s new in exploration A.I. is just that, artificial— don’t make it a deity

17

Drilling advances Sensing doubts

19

What’s new in production Into the weeds

21

Executive viewpoint Using A.I. to enhance daily operations

23

Innovative thinkers Philippe Herve: Guiding the point of sail for AI in oil and gas

94

The last barrel Entrepreneurial spirit

D. Renzi

Energy Web Atlas / World Oil Staff

SHALETECH REPORT / PRACTICES & ADVANCES

Precise prediction of hydrocarbon burn efficiency is now possible A. Cuthbert

C. Okocha

48

Fourth-generation drill pipe connection enhances land drilling, reduces pipe maintenance

REGIONAL REPORT: WEST AFRICA

NEWS AND RESOURCES 9

World of oil and gas

78

Intending to be a global supplier, the region endures output disruptions

25

Industry at a glance

88

People in the industry

E. Querubin

89

Companies in the news

90

New products and services

91

Advertisers’ index

92

Marketplace / Advertising sales offices

93

Meetings and events

DEEPWATER/SUBSEA 83

Operators and service firms collaborate through groundbreaking subsea technology D. Lawson

ABOUT THE COVER

In January 2018, a PropStream last mile proppant logistics service truck secures frac sand from the Hi-Crush Pecos transload facility. The sand is for delivery to a wellsite in the southern Delaware basin of the Permian region of West Texas. Photo: Hi-Crush.

World Oil® / AUGUST 2018 3

Industrial Rubber Circulating Equipment Industrial Rubber, Inc.’s Swages are light and easy to handle, yet robust enough to withstand high pressure circulating. The 1502 union sub is easy to replace should the need arise. Swages are available in any size or style of casing thread – just let us know what you need! Features of the IRI Swage Include: •Dished Top Design Reduces Weight by up to 33% •1502 Union Easy to Maintain or Replace •ACME Threaded Connections – No Pipe Threads •One-piece Design allows for High-Pressure Use •Available for any size casing, with any style threads

Mailing Address: PO Box 2608 Houston, TX 77252-2608, USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 WorldOil.com

PUBLISHER Andy McDowell EDITORIAL

Editor Kurt Abraham Technical Editor Craig Fleming Associate Editor Emily Querubin News Editor Michele Cowart Contributing Editors Dr. A. F. Alhajji, Middle East Dr. Roger Bezdek, Washington Ron Bitto, Offshore David Blackmon, Reg. Affairs Robert Curran, Canada Bill Head, Exploration Don Francis, Production Raj Kanwar, South Asia Saeid Mokhatab, LNG

Dr. Jeffrey M. Moore, Asia-Pacific Mauro Nogarin, Latin America Dr. Øystein Noreng, North Sea Mark Patton, Water Management Dr. William J. Pike, Energy Issues Jim Redden, Drilling Dr. Jacques Sapir, FSU Mike Slaton, At Large Russell Wright, At Large

MAGAZINE PRODUCTION / +1 (713) 525-4633 Vice President—Production Sheryl Stone Manager—Advertising Production Cheryl Willis Assistant Manager—Advertising Production Krista Norman Manager—Editorial Production Angela Dietrich Assistant Manager—Editorial Production Lindsey Craun Artist/Illustrator David Weeks Graphic Designer Andreina Keller

ADVERTISING SALES

See Advertising sales offices

CIRCULATION / +1 (713) 520-4498 / [email protected] Director—Circulation Suzanne McGehee

EDITORIAL ADVISORY BOARD

Industrial Rubber, Inc.’s Circulating Heads complement the Industrial Rubber line of Cementing Heads. IRI Circulating Heads and Cementing Heads utilize a common Quick Connect sub that allows quick change out from Circulating Head to Cementing Head. This makes for a convenient circulating tool when used either in conjunction with an IRI Cementing Head or as a standalone unit. Features of the IRI Circulating Head Include: •Quick Coupling Union allows fast, easy connection to Casing String •Plugs can be dropped through the Circulating Head assembly by simple removal of the Circulating Head Cap. •Available for any size casing, with any style threads

Chairman—Dr. William J. Pike, Principal Scientist, KeyLogic, Inc., and Contractor to the National Energy Technology Laboratory, U.S. Department of Energy Ben Bloys, Manager, Los Alamos Technology Alliance, Chevron Dr. DeAnn Craig, Consultant Dan Domeracki, Vice President, Government and Industry Relations, Schlumberger, and Chairman, Petroleum Equipment and Services Association Deepak M. Gala, SME, Well Control Engineering and Relief Well Planning, Shell John Gellert, CEO, SEACOR Marine Holdings, and Chairman, National Ocean Industries Association Alexander G. Kemp, Professor of Petroleum Economics, and Director, Aberdeen Centre for Research in Energy Economics and Finance, University of Aberdeen Trent Latshaw, President, Latshaw Drilling Co. LLC, and member, IADC Executive Committee Keith Lynch, Wells Operations Advisor—Unconventional Assets, ConocoPhillips Dr. D. Nathan Meehan, Vice President, BHGE, and Managing Director, Gaffney-Cline & Associates Douglas C. Nester, Consultant David A. Pursell, Senior Vice President, Planning and Energy Fundamentals, Apache Corporation Art J. Schroeder, Jr., CEO, Energy Valley, Inc. Svein Tollefsen, Manager, Reservoir Technology, Equinor ASA Doug Valleau, President, Strategia Innovation and Technology Advisers, LLC Robert E. (Bob) Warren, President, Baclenna, Inc.

World Oil is indexed by Business Periodicals Index, Engineering Index Inc., and Environmental Periodicals Bibliography. Microfilm copies are available through University Microfilms International, Ann Arbor, Mich. The full text of World Oil is also available in electronic versions of the Business Periodicals Index. World Oil (ISSN 0043-8790), est. in 1916 as The Oil Weekly, is published monthly by Gulf Energy Information, 2 Greenway Plaza, Suite 1020, Houston, TX 77046. Periodicals postage paid at Houston, Texas, and at additional mailing offices. World Oil and The Oil Weekly are registered trademarks of Gulf Energy Information. Subscriptions: World Oil is available on a complimentary Request Subscription basis to persons actively engaged in the exploration/drilling/producing phase of the oil and gas industry who are in a position to recommend, specify or approve the purchase or use of equipment or services used in their operations. (When requesting subscription, state title, company name and nature of business as initial qualifications.) Persons who do not recommend, specify or approve the purchase or use of equipment or services (or persons in a related field of service or industry) can order subscriptions at the following rates: one year $399, two years $679, three years $897. AIRMAIL DELIVERY: Outside North America additional, $175/year. Single copies: $35 each, prepaid. PAYMENT MUST ACCOMPANY ORDER (make checks payable to World Oil). Postmaster: Send address changes to World Oil, PO Box 2608, Houston, TX 77252-2608. Subscription services/address changes: World Oil, Circulation Dept., PO Box 2608, Houston, TX 77252-2608. Phone: +1 (713) 520-4468. E-mail: [email protected]. Article reprints: World Oil, Cheryl Willis, Gulf Energy Information, Advertising Production Manager. 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Phone: 713-525-4633. Fax: 713-525-4615. Email: [email protected]. Copyright © 2018 by Gulf Publishing Company LLC. All rights reserved.

Oklahoma City, OK Toll-Free: 1-800-457-4851 • Fax: (405) 703-7049 www.iri-oiltool.com 4 AUGUST 2018 / WorldOil.com

President/CEO John Royall CFO Alan Millis Vice President Andy McDowell Vice President, Finance and Operations Pamela Harvey Vice President, Production Sheryl Stone Publication Agreement Number 40034765

Printed in USA

Other Gulf Energy Information titles include: Petroleum Economist©, Gas Processing™, Hydrocarbon Processing®, Pipeline & Gas Journal and Underground Construction.

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FIRST OIL KURT ABRAHAM, EDITOR

Consent given to fracing first onshore, horizontal well in the UK Ever so quietly, a significant milestone for the UK’s E&P industry has been reached. We refer to the UK Department for Business, Energy & Industrial Safety (BEIS) giving consent to shale gas developer Cuadrilla Resources, to become the first operator in Britain to frac an onshore, horizontal exploration well. Hydraulic fracturing consent was introduced into the government’s processes in 2015. The BEIS gave its approval on July 24 for Cuadrilla to frac the first shale gas well at its Preston New Road site in Lancashire, in northwestern England. “I have carefully considered Cuadrilla’s application, and I am content that hydraulic fracturing consent should be granted in this instance,” said Energy and Clean Growth Minister Claire Perry in a statement. The company is now preparing to apply for consent to frac its second well at that site. Cuadrilla was thrilled. “We are very pleased to be the first operator in the UK to have been awarded final consent to hydraulically fracture the UK’s first onshore horizontal shale exploration well,” said Cuadrilla CEO Francis Egan. He noted that “it is also a win for Lancashire, which has already benefitted directly from over £10 million of investment, as a result of our exploration works…...” Cuadrilla completed the first well during April in the Lower Bowland shale at a 2,300-m depth, with an 800-m lateral. The second well was completed last month through the Upper Bowland, to about 2,100 m with a 750-m lateral. URTeC was red-hot. Congratulations to URTeC and its exhibition for a very successful event in Houston, while achieving greatly increased attendance. At the end of the second day, attendance was up to 5,528, almost double the 2017 number in Austin. In fact, attendance at technical sessions and panels was so strong, that many had standing room only, with people lining the walls and falling out the doorways. Show officials scurried to switch some sessions to rooms with more capacity.

But this is a good problem to have, and clear evidence of two things. One, the U.S. upstream industry, particularly the onshore shale sector, is definitely on the mend, and many personnel are hungry for more information and technology to work with. And two, the content of the sessions was high-quality, as has been the case every year for URTeC. The show will return to Denver in 2019. Now, we’ve seen everything, A longtime industry friend sent me an email last month with a link, saying, “you won’t believe this.” He was right. In the July 23 edition of The Daily Caller, was a story entitled, “Study links fracking to higher rates of sexually transmitted diseases (STDs).” Extremists have blamed fracing for a lot of things, but this was really in left field. It seems that researchers at the Yale Public School of Health, with obvious time on their hands, believed that increased fracing in Ohio might be generating higher rates of STDs. Indeed, Yale researchers now claim to have found that cases of two specific STDs increased about 20% in nine Ohio counties with high shale development. Lead study author Nicole Deziel contends that out-of-state workers are frequently brought in because of specialized skills (fracing, in this case). She says they are mostly single, straight men, who bring along “masculinized social norms,” as they work at well sites in rural areas. Accordingly, she contends that these men are having more casual sex with the locals, thus raising the STD rate. Various medical experts have serious problems with this study, pointing out that STD rates were rising in Ohio before fracing was introduced to the state. “It doesn’t have anything to do with the shale gas industry directly, but it does have to do with population growth,” said Dr. Charlotte Gaydos, an STD expert at Johns Hopkins University, in a statement quoted by the Columbus Dispatch. “It makes sense, anytime there’s an activity in the area, which increases the influx of the migration of a population, that it might be associated.”

IN THIS ISSUE

29

Permian basin technology: Advances propel the region forward. Articles in this section

describe technology geared specifically to the Permian. Accordingly, on page 29, a Packers Plus author describes how innovative completion technology is reducing break-even prices for operators. On page 37, an author from Hunting’s Titan Division explains how a perforating system improves stimulation results in unconventional completions. Also, on page 43, a Clariant Oil Services author details how a new frac-pack additive is improving sulfide scale control for long horizontals.

53

ShaleTech Practices: Filling the gaps in understanding well performance. As the U.S. shale boom nears 15 years, operators are shifting strategies to the next phase of development, infill drilling, which presents its own challenges. Accordingly, Schlumberger conducted a 10-basin study that compared child and parent well performance in unconventional plays. Several authors from the company explain how experts are working on technologies and best practices that mitigate the effects of depletion and inter-well communication on child well performance.

78

West Africa intends to be a global supplier, but the region endures output disruptions.

As described by Associate Editor Emily Querubin, the region’s two top producers, Nigeria and Angola, are struggling with militant disruptions and underperformance by their E&P sectors. Nevertheless, the region’s energy sector continues toward becoming a leading global oil and gas supplier. Nearly $194 billion will be spent on developing African oil and gas fields between 2018 and 2025.

ŝŝ[email protected] World Oil® / AUGUST 2018 7

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WORLD OF OIL AND GAS EMILY QUERUBIN, ASSOCIATE EDITOR

DISCOVERIES & DEVELOPMENTS /////////////////////////////////////////////////////////// Petro River discovers Arsaga field, its largest find to date After successfully drilling the Arsaga 25-2 exploration well, Petro River Oil Corp. announced the discovery of its largest oil field to date. The well, situated in Osage County, Okla., was the first of three exploration wells to be drilled under the company’s 2018 drilling program. It was spudded in early July, reaching a depth of approximately 2,750 ft. Preliminary results showed about 30 ft of productive Mississippian Chat formation, which led to an estimated ultimate recovery of about 50,655 boed. “The discovery in the Arsaga field has given the company continued confidence in our ability to effectively use 3D seismic imaging technology to discover overlooked prospects. The development of the Arsaga field, with approximately 2,000 prospective acres and up to 100 well locations, will be the focus of our activity for the next couple of years,” Petro River President Stephen Brunner said in a release.

Exxon increases resource estimate for Guyana’s Stabroek Block ExxonMobil Corp. increased its estimate of discovered recoverable resources for the Stabroek Block, offshore Guyana. Following completion of testing at the Liza-5 appraisal well; the Ranger discovery; incorporation of the eighth discovery, Longtail, into the Turbot area evaluation; and completion of the Pacora discovery evaluation; the company revised its resource estimate for the block, from 3.2 Bboe to 4 Bboe. The Liza-5 well tested the northern part of Liza field, and will support a third phase of development in Guyana, alongside the giant Payara field. Likewise, the Longtail well established the Turbot-Longtail area as a potential development hub for recovery of more than 500 MMboe. Drilling of additional prospects in the area reportedly could further increase that estimate. According to the company, discoveries within the 6.6-million-acre Stabroek Block have established the potential for up to five FPSOs, producing over 750,000 bopd by 2025. Exxon’s affiliate, Esso E&P Guyana Limited, is operator of the block, with a 45% interest. Its partners include Hess Guyana Exploration Ltd. (30%) and CNOOC Nexen Petroleum Guyana Limited (25%).

Eni reports its second discovery in Egypt’s Faghur basin After drilling its second well to explore the deep geological sequences of the Faghur basin, Eni reported another light oil discovery in the Western Desert’s South West Meleiha License, approximately 80 north of Siwa. SWM B1-X was drilled to a TD of about 14,839 ft, approximately 4 mi from the first find, and encountered nearly 115 ft, net, of light oil in the Paleozoic sandstones of the Dessouky formation, of Carboniferous age, and in the Alam El Bueib sandstones, of Cretaceous age. The company says that it plans to drill several other prospects nearby, in the hopes of uncovering more resources and opening up a new productive area for Eni. International Egyptian Oil Company (IEOC), a subsidiary of Eni, holds a 100% stake in the South West Meleiha License.

PRODUCTION ///////////////////////////////////////////////////////////////////////////// Production begins at Australia’s Ichthys LNG project

INPEX Corp. (operator, 62.245%)— alongside partners Total (30%), CPC Corp. (2.625%), Tokyo Gas (1.575%), Osaka Gas (1.2%), Kansai Electric Power (1.2%), JERA (0.735%) and Toho Gas (0.42%)— started production at its Ichthys LNG project, offshore Western Australia. Produced gas will be gathered at the Central Processing Facility, Ichthys Explorer (pictured), and separated. Liquids are then piped to the nearby Ichthys Venturer FPSO, while gases are transported via pipeline to an onshore gas liquefaction plant in Darwin, Northern Territory. The development will produce approximately 8.9 million tons of LNG and about 1.65 million tons of liquefied petroleum gas per year. Additionally, it will produce approximately 100,000 bbl of condensate per day at peak. Image: INPEX Corp.

DNO ramps up production at Peshkabir field, in Iraq After announcing an output increase last month, DNO ASA exceeded its 30,000-bopd target at Peshkabir field, in the Kurdistan region of Iraq. The company initially reported that it would boost the field’s production rate by two-thirds, to at least 25,000 bopd, following completion of its Peshkabir-4 well testing program. “The pickup in Peshkabir production puts new meaning to the fast in fast-track in development of this field by the DNO team,” Bijan Mossavar-Rahmani, DNO’s executive chairman, said in a release. “And we expect Peshkabir to continue to surprise to the upside.” By the end of July, the field reportedly was producing approximately 35,000 bopd. Two more wells, Peshkabir-6 and Peshkabir-7, are scheduled to start production testing in August. “Peshkabir has now leapfrogged into second place, after Tawke, among the Kurdistan fields operated by the international oil companies,” Rahmani said. “We are setting our sights on higher production and accelerating field development.”

Total starts production at Kaombo field, offshore Angola Total has announced the start of production at Kaombo field, Angola’s largest offshore development. The field, situated in Block 32, will produce via the Kaombo Norte and Kaombo Sul FPSOs. The Kaombo Norte FPSO went onstream in July and will produce an estimated 115,000 bopd. The Kaombo Sul FPSO is not scheduled to go online until next year. The FPSOs will develop the resources of Gengibre, Gindungo, Caril, Canela, Mostarda and Louro fields, which cover an area of 800 km2 in the south-central part of the block. Overall production from both FPSOs is anticipated to reach an estimated 230,000 bopd. “The Kaombo start-up is a great milestone for Total. Developing the estimated 650 MMbbl of reserves will contribute to [our] growing production and cash flow in Africa,” Arnaud Breuillac, Total’s president of E&P, said in a release. “Total is proud to build on its deep offshore expertise to operate the latest major project coming on stream in Angola, which will account for 15% of the country’s oil production.” Total is operator of Block 32, with a 30% participating interest. Its partners include Sonangol P&P (30%), Sonangol Sinopec International 32 Limited (20%), Esso Exploration & Production Angola (Overseas) Limited (15%) and Galp Energia Overseas Block 32 BV (5%). Image: ALP Maritime Services BV. World Oil® / AUGUST 2018 9

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WORLD OF OIL AND GAS EMILY QUERUBIN, ASSOCIATE EDITOR













 

BUSINESS ////////////////////////////////////////////////// 


An exclusive



Total acquires Engie’s LNG business for $1.5 billion

 




BP acquires U.S. onshore assets from BHP Billiton for $10.5 billion



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Total has acquired Engie’s upstream LNG assets, including participating interests in liquefaction plants, long-term LNG sales and purchase agreements, and an LNG tanker fleet, as well as access to regasification  capacities in Europe. Among the acquired assets is interest in the   project, in southCameron LNG   western  Louisiana, as well as 18  LNG  carriers and a global LNG  trading contracts portfolio of 28  million tons/yr. “This transaction makes Total the second-largest global LNG player among the majors, with worldwide market share of 10%, and the group will manage an overall LNG portfolio of around 40 million tons/yr by 2020. It also helps us to build a position in the U.S. LNG market, with the 16.6% stake in the Cameron LNG project,” said Total CEO Patrick Pouyanne.

 

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BP has agreed to buy BHP Billiton’s assets in the Permian, Eagle Ford and Haynesville basins, as BHP exits the U.S. shale sector. The $10.5-billion acquisition represents the oil  major’s biggest purchase in nearly two decades. Presently, the assets are producing 190,000 boed, 45% of which are liquid   hydrocarbons, and cover 470,000 acres across Texas and Louisiana. The acreage is said to hold 4.6 Bboe of discovered resources, overall. BP upstream Chief Executive Bernard Looney said, “We’ve just got access to some of the best acreage  in some of the best basins in the onshore U.S., and I think we have one of the best teams in the industry to work it.” Image: BP.  

Chesapeake Energy announces $2-billion divestiture of Ohio shale assets

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 Chesapeake Energy has agreed to sell its Utica shale assets in Ohio to Encino Acquisition Partners for $2 billion. It is CEO Doug Lawler’s biggest transaction in more than three years. According   to the company, nearly all proceeds from the transaction will be used to pay down debt. Additionally, however, the transaction will aid the company in its efforts to focus its business more on the production of crude oil. Lawler reportedly is aiming to boost the company’s oil production by 10%, primarily through output growth in Wyoming’s Powder River basin. According to a   company statement, output from the area is expected to more than double in the next year. “The  Utica was the best asset for us to divest of, and what we have remaining in our portfolio is five very strong assets for future growth,” Lawler said. 

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Aker BP acquires license portfolio from Total for $205 million ‚ƒ

 

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Aker BP has agreed to acquire interest in Total’s portfolio of 11 licenses on  the Norwegian    Continental Shelf (NCS). The   $205-million acquisition includes   four discoveries—Trell, Trine, Alve  Nord and Rind—with reported net recoverable resources of 83 MMboe. Because they are near Aker BP’s Alvheim field, Trell and Trine are expected to produce through the Alvheim FPSO   (pictured). Likewise, the Alve Nord discovery is situated just north of Aker BP’s Skarv field and, therefore, it can be produced through the Skarv FPSO, in the northern area of the Norwegian Sea. In addition to the four discoveries, the transaction also gives the company increased interest in exploration acreage near its Ula field, in the southern section of the Norwegian North Sea. Image: Aker BP.

 



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World Oil® / AUGUST 2018 11 

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ENERGY ISSUES DR. WILLIAM J. PIKE, EDITORIAL ADVISORY BOARD CHAIRMAN

A mixed bag Did you ever have one of those months when everything you read seemed to compound the other things you read? Well, it has been one of those months for me. And, a lot of what I have read seems to indicate that no one has a clear vision of what might be about to happen. On the other hand, as discussed below, well-reasoned plans can mitigate a good deal of the uncertainty. Take these comments from a recent issue of the Houston Chronicle, for example. “OPEC could bring back 1 million barrels a day, but any barrels brought back by Saudi, Russia, Kuwait might just offset barrels lost from Iranian sanctions,” said Noah Barrett, an energy research analyst at Janus Henderson Investors (http://digital.olivesoftware. com/Olive/ODN/HoustonChronicle/ Default.aspx). Due to bottlenecks in the Permian Basin, “U.S. production will continue to grow, but it probably won’t exceed expectations. It’s more likely it will disappoint to the downside.” And, said Ashley Petersen, lead oil analyst at Stratas Advisors in New York, “there’s just kind of an acknowledgment that there is still a lot of supply in Texas, so it’s not clear sailing for prices.” According to John Kilduff, a partner at New York-based hedge fund Again Capital, “the summer-time doldrums are here and there’s not a lot of direction for this market at the moment.” The market uncertainty is compounded by additional factors, such as Venezuela’s continuing oil collapse (You can call that a collapse of the whole country. A cup of coffee in Venezuela costs 2,000,000 Bolivars [yes, two million] at the time this was written) and actions such as Mexico’s announcement that they intend to increase production by 600,000 bopd in two years. The move in Mexico is an effort to reverse a decline in production of nearly 2 MMbopd since 2005, with an investment estimated at some $9.5 billion. Yeah, it’s a crazy world. It’s hard to figure out where to go. So, why not start with what you have. First, protect your assets. Then, build on them with a life extension plan.

At its core, a life extension (LE) plan is a management system that provides assurance that an aging asset can continue to operate safely beyond the original design limits. This may, or may not, include the necessity for repairs or upgrades to address fabric degradation and/or manage risks. A life extension plan summary was recently published by Endeavor Management, a company that designs and implements practical business strategies. The plan would, at a minimum, include a summary of present condition, a strategy to monitor pertinent aspects of the facility to continually verify fitness for service and compliance with regulations and, ideally, baseline contingency plans to mitigate credible risks. Challenges. The challenges of life extension, said Endeavor, fall into four categories—safety, codes, technical and business. All four must be addressed, for a feasible life-extension program to exist: • SAFETY is at the core of business culture and must be considered at the outset of a LE program. • CODES AND STANDARDS. It is not expected that the asset will fully comply with codes and standards in place at the time of the LE review. The expectation must be that the risks associated with not meeting the latest codes and standards are assessed, and identified risks managed. • TECHNICAL CHALLENGES. The more reliable and comprehensive that the data are, the better will be the assessment. Generally, the challenges can be broken down into the following seven categories: ◦ Uncertain condition of critical components and equipment ◦ Decaying corrosion protection systems ◦ Challenges complying with new regulations ◦ Weight management ◦ Lack of historical data ◦ Change of use and/or location ◦ Predicting/extrapolating corrosion and fatigue.

• BUSINESS IMPACTS. This would include both short and long-term impacts of the LE plan. Factors typically considered include: ◦ Plan development: There will be desktop studies and, if necessary, site surveys to develop the documents that confirm that LE is achievable. ◦ Upgrades and repairs: Some form of work on the facility is required to sustain or support the LE. Examples of this are renewing corrosion protection systems, strengthening or replacing corroded steel, or installing monitoring systems. ◦ Periodic surveys: Extent and frequency of periodic surveys may be changed, as dictated by regulators. ◦ Production interruptions: Items (2) and (3) above may require shutting in, or at least disrupting, production. The extent, timing, duration and frequency of this needs to be estimated. Implementation. At the end of original life, the decision would be made to consider extending the operational life and this is the trigger to start the stepwise approach to determining the viability of LE. If followed through to extend the operating life, the stages are like those for a new asset: assess, implement, operate and verify. This systematic approach allows an asset life to be extended incrementally, provisionally at five-year to 10-year intervals. There would be periodic reassessment and “course corrections” made as the asset matures, and additional performance data are gathered and assessed. These “course corrections” may be purely business- or regulation-driven, but can include aspects, such as changes in operations. For access to all three portions of this LE analysis, visit (https://www.endeavormgmt.com/blog/life-extension-offshorefloating-assets-part-1.)

ŝŝ[email protected] / Bill Pike has 50 years’ experience in the upstream oil and gas industry, and serves as chairman of the World Oil Editorial Advisory Board. World Oil® / AUGUST 2018 13

WHAT’S NEW IN EXPLORATION WILLIAM (BILL) HEAD, CONTRIBUTING EDITOR

A.I. is just that, artificial— don’t make it a deity Also known as cognitive computing, ar- holes in a row. No longer does Exxon or project pioneered an AI effort, using gitificial intelligence (AI) is often spoken of others assign new hires to the field, then a gabytes in a predictive neurologic soluas the nirvana of processing mass detailed year in processing, then to interpretation. tion scheme to derive dynamic engineerinformation, in a faster, better, cheaper way. So, are we morphing a new E-child from ing data [fluid flow parameters] from 3D True. But exploration is not done in a room AI software? seismic. This was an attempt to develop a All is not despair. ConocoPhillips reservoir production tool for EOR, to find full of random actors. AI cannot replace deductive reasoning, the true power of an uses widespread, but people-driven AI. economically attractive clone prospects, explorationist—being able to jump to a I see other companies swinging back to and to evaluate M&A possibilities, Fig. 1. reasonable, low-risk, complex conclusion including math geophysicists, along with Marathon and partners provided licensed geologists, petrophysicists, and reservoir 3D data and well control over the GOM without all the needed data. Neuro-logic definitions include ev- fluids engineers, as a team, training AI Lobster field. Lobster is a classic dipping erything from Siri, autos and airplanes, to computing cycles. turbidite reservoir that has complex layers SEG’s June Leading Edge discusses ma- of deposition. Maybe we could have choJapanese toilets. SPE declares [April 2018] that 94% of execs will use AI for production chine learning with petrophysics results. sen a simpler field to model. control and decisions. Neuro is never bet- It’s useful, but hardly the scale of exploraA second illustration looks at AI simulater than the equations and assumptions in tion seismic resolution. One UT-RPSEA tion problems, Fig. 2. Author Sanjay Srinithe coded program or required vasan comments, “the model data input. Neuro computing Fig. 1. One UT-RPSEA project pioneered an AI effort that tried of the Lobster data, on the left, should only be a reference to to develop a reservoir production tool for EOR. Source: Sanjay is generated using a traditional Lesli Wood and UT-Austin, RPSEA Project 08121-2701machine-learning that is closely Srinivasan, two-point statistics-based algo03, 2011. supervised, not to a self-aware rithm (SISIM) and the curvirobot with “rights.” AI might linearity of channels is not prereplace what you do, but it can served in the model.” Therefore, never replace you. Perhaps. the common algorithm was imWe were seduced in the proved after multiple iterations, 1990s, morphing geologists per the model on the right. Both as 3D conceptualizers into beused the same data set as input. coming companies’ workstaTraining algorithms matters. tion “geophysicists.” The value The UT project spent years of geophysical-geos was lost attempting to train an AI proon management, eliminating gram from multiple formats advantages that math-based of 3D, well logs, and pressure/ geophysicists provided to intertime/production data. Each pretation. Interpreters were reinvestigator assumed the input quired to work late nights, genfrom others was perfect, theirs erating push-button, brightly with limitations. The truth? All colored maps. Math geos were had limitations. The one probsent to run field crews on the Fig. 2. Two representative permeability models (top layer) for lem that we could not overfront end of exploration or pro- cluster 9 of Lobe 10. Source: Personal communication in draft, H. come was the lack of enough cessing special projects at the Zhou, S. Srinivasan, L. Li and K. Lee, 2015. dynamic data to calibrate the tail end. geology or reservoir paramInterpreters lost undereters. All machine learning prostanding of the limits of data grams rely on someone knowing and methods. Poorly humanthe correct or near correct answer reasoned dry holes almost as input. Do you see a problem killed rank exploration by with that? 2001. A V.P. friend got “retired,” after his under-five-year Gulf of ŝŝ[email protected] / William (Bill) Head is Mexico (GOM) team drilled a technologist with over 40 years of experience in domestic and international exploration. six, $50-million, look-a-like dry World Oil® / AUGUST 2018 15

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DRILLING ADVANCES JIM REDDEN, CONTRIBUTING EDITOR

Sensing doubts Slapping all manner of sensors on a rig without considering the quality of subsequent data is to drilling automation what a switch to low-tar cigarettes and light beer is to a healthier lifestyle. Both cases represent self-defeating exercises with potentially ruinous outcomes. “The drilling industry right now is moving to more automation of data analytics. There’s a lot of data available, and the industry is going to be making more and more decisions based on that data,” Maria Araujo, R&D manager for the Southwest Research Institute (SwRI) of San Antonio, Texas, told the IADC Drilling Engineering Committee (DEC) quarterly Technology Forum on June 13 in Houston. “But, the key question is, is that data accurate?” In the latest effort to answer that question, the SwRI is spearheading the JIP, “Independent Verification and Validation (IV&V) of Sensors and Systems in Drilling.” As program manager, Araujo was on hand to update the first phase of the JIP, which the nonprofit institute introduced during a similar DEC forum on March 21. The primary objective of the JIP is developing a unified standard for the thirdparty verification and validation of critical sensors and systems used in the drilling operation. The aim is to verify that the sensor or system meets intended requirements and provides in-situ validation that it operates properly in the targeted environment. “The prize that will come out of the JIP will be a recommended practice that industry participants can utilize,” Araujo said. “Insitu is the key word here. A lot of sensors and systems go through some level of validation, but we’re focusing on in-situ verification and validation during the drilling operation. The performance in-situ during drilling may vary, because the environment and operating conditions may impact the quality and performance of those sensors.” JIP rationale. The JIP was conceived to address growing industry concerns that critical decisions, based on faulty sensor data, can lead to costly inefficiencies, at best, or catastrophic events, at worst.

The JIP sprung out of the DEC-affiliated Drilling Systems Automation (DSAS) Roadmap cross-industry initiative, where Southwest Research Institute has served as an original member of the more than fiveyear-old steering committee. While operators have individually conducted verification and validation activities, Araujo said the JIP hopes to resolve the industry’s lack of a consistent set of defined requirements to confirm the performance of critical sensors and associated systems. “We’re not going to re-invent the wheel. There’s a lot of standards out there that cover several aspects of sensor validation and data validation, so we’re going to leverage, not re-invent, those,” she said. “The idea is to add to whatever is out there for sensor validation.” “What’s happening today is that a lot of people are doing this individually, or in silos if you will, so there’s a lot of repetition from different operators and so forth. The idea is to come up with something everyone can agree on, and everyone can benefit from.” Araujo said the JIP will exploit SwRI’s extensive experience in employing the IV&V approach in commercial aviation, transportation, and other high-risk and data-driven sectors, with the objective of reducing the well-documented risks from inferior drilling data. Along with hiccups in the communications channel transferring data from the point of acquisition to the end-user, Araujo said a number of drilling sensors have been shown to be sorely inadequate. In some cases, they are either irregularly calibrated or improperly maintained, or else measuring properties in the wrong location, thereby invalidating the purported values. In other instances, sensors have been shown to be inadequately designed for the intended function. “Our goal is to develop a methodology and procedures to verify and validate those sensors while they are in operation, to make sure their performance is acceptable,” she said. “If we’re going to make either automation or analytical de-

cisions, we have to make sure that data is accurate and validated.” As part of the JIP’s first phase, which is seeking industry participants, an evolving steering committee of subject matter experts will guide the identification and prioritization of critical drilling sensors and systems. A key deliverable is development of a proof of concept, in which a standardized IV&V methodology will be employed on a drilling application. The JIP mandate stipulates that “the results from the program will be the publication of an agreed industry methodology, which can be implemented by any recognized and competent independent organization including, but not limited to, SwRI.” “Big issue.” In an earlier joint effort, the then-newly formed Operators Group for Data Quality in November 2016 began wrangling with less-than-reliable rig surface sensor data, just as sinking oil prices magnified the relationship of realtime data analytics to improved efficiencies and lower costs. The group has since teamed up with contractors, service companies and OEMs “to accelerate the adoption of standardized key measurement specifications, data storage, transmission, transformation and integration.” “We agree this (inadequate sensor data) is a big issue, and there’s a big effort around that,” Joey Husband, V.P. of global operations for Nabors Drilling Technology, said at the March DEC forum. As part of a presentation on “Creating Uptime with a Disruptive Drilling Contractor Business Model,” Husband said it’s imperative that sensors collecting critical data be accurate, calibrated and fit-for-purpose, to effectively address the vagaries of a drilling operation. “We have a lot of smart people writing codes for equipment, but the codes assume the rig is perfectly wired, perfectly grounded with the exact equipment, where it’s supposed to be,” he said.

ŝŝ[email protected] / Jim Redden, a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry. World Oil® / AUGUST 2018 17

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WHAT’S NEW IN PRODUCTION DON FRANCIS, CONTRIBUTING EDITOR

Into the weeds Driving operational performance in oil and gas is a pretty big topic, and it’s also the subject of a white paper from consulting company EY. At 16 pages, the paper is necessarily a high-level overview, with subtopics like “Industry objectives” and “Top business issues” that most anyone in the industry could predict. Still, high-level overviews such as EY’s effort have value. But, the devil is in the details, as they say. A screed on the importance of operational performance is not forthcoming. Instead, it may be more interesting to get into the weeds, as they also say, and take a look at an arcane but useful process that could help you earn your operational performance driver’s license. A paper, “Production availability analysis for oil and gas facilities: Concepts and procedure” (Brissaud, et. al., DNV France) scrutinizes the topic, beginning with a core concept: The expediency of oil and gas exploitation depends on the availability of processing facilities. “Availability” is standardized as the ability of an item to be in a state to perform a required function, under given conditions, at a given instant of time, or over a time interval, assuming that the required external resources are provided. It is based on time, and a single state (the up state) of an item. Since oil and gas facilities can be in multiple states (i.e., operate at different production levels), ranging continuously from nil to full production, an up state can be assumed when the actual production is equal to, or greater than, a reference level (e.g. a contracted or a design rate). However, because this availability does not differentiate states where production is slightly or greatly below the reference level, even if the impact on resulting production can be important, it is too restrictive for evaluations of production systems. Other availability (or “regularity”) measures have then been proposed, notably those discussed by T. Aven, 1987. One measure accepted by the ISO 20815 international standard is production avail-

ability—the ratio of production to planned production, or any other reference level, over a period of time. (The latter is volume-based instead of state-based; besides, the resulting measure is not a probability.) Production availability analysis takes part in the production assurance of oil and gas projects. [Activities are implemented] to achieve and maintain a performance that is at its optimum, in terms of the overall economy and, at the same time, consistent with applicable framework conditions. It is especially suitable for projects with medium-to-high technical risk, and during the first life-cycle phases (feasibility, conceptual design, and engineering). The production availability analyses are then used to: • Predict production performance, and verify compliance with objectives and requirements (specified in the production assurance program (PAP); • Identify operational conditions, subsystems and equipment items that are critical, and find measures for performance improvement; • Compare alternatives, and enable selection/optimization of equipment items, configurations, maintenance actions, and operations, with economic considerations (under project, technical, operational, health, safety, environmental and regulatory constraints). Production performance analyses should be consistent, and assumptions and reliability data should be traceable (ISO 20815). To fulfill this guidance, a procedure for production availability analysis has to be followed. The authors present a four-step procedure based on their “…experience in reliability, availability and maintainability (RAM) analyses for oil and gas facilities, and meets the recommendations of the general framework given by the ISO 20815.” Space prevents reporting the extensive details of this procedure. But the authors

set the stage by noting that in the current phase of the project…decisions regarding system design have already been made, and thus the purpose of production availability analysis is not the same. During the feasibility phase, the objective can be to optimize asset development plans by analyzing several alternatives. During the conceptual design, optimization is usually reduced to two or three alternative field-layout configurations. Finally, during the engineering phase, only a few alternative solutions are still possible, and the production availability analysis is used to verify compliance with requirements, for sparing recommendations and spare parts optimization. Production performance measure also depends on the project phase and relating objectives. To model more exhaustively the performance of a production system, (volume-based) production availability…is usually preferred [to] (state-based) availability. A “reference level” of production has, therefore, to be defined. To this end, the design rate (maximum input feed rate that can be treated) is often used in early project phases, as it is usually time-independent, convenient for any part or sub-part of the production chain (independently of other systems), and does not require sales contract or well-production rates to be defined. In more advanced phases of a project, the planned production volume, assuming no downtime, can be preferred, taking the constraints of sales contract (e.g., through the contracted rate) and well-production potentials (e.g., through the actual input feed rate) into account once available. To avoid time-dependent constraints in the system description and modeling, it is more convenient to reason in terms of design rate during the study basis and model development, and to translate in terms of other reference levels only during the production availability analyses.

ŝŝ[email protected] / For more than 30 years, Don Francis has observed the global oil and gas industry as a writer, editor and consultant to companies marketing upstream technologies. World Oil® / AUGUST 2018 19

EXECUTIVE VIEWPOINT BARRY ZHANG, CO-FOUNDER AND CEO, QUANTICO ENERGY SOLUTIONS

Using A.I. to enhance daily operations The modern smartphone is, for all intents and purposes, an inseparable part of our lives now. As of March 2017, Android commanded a larger market share of the global operating systems than did Windows. Hard to believe? Perhaps your child received his/her first smartphone before a laptop? There are several drivers behind smartphones, and consumer technology in general, permeating into our lives. I will focus on two that relate specifically to the proliferation of artificial intelligence (AI) in consumer technology: decision intelligence and virality. Decision intelligence. Google Maps provides a well-understood example of consumer intelligence. When you pull up directions in this service, it doesn’t just give you directions to your destination, the app gives you three alternative routes, each with a corresponding estimate of drive time. Roughly 90% of the time, one takes the fastest route, but 10% of the time, one may decide to take a different route. Google acknowledges that it doesn’t know whether the situation is a leisurely weekend drive or someone late for a meeting. So, it hands over the final decision to the consumer, but it has armed people with the decision intelligence, to make the right decision, with a few finger strokes. AI is also providing novel ways of delivering business intelligence to the oil and gas industry. For example, a standard part of developing shale plays is examining public and private data sets, to see where nearby wells have been drilled, what direction the laterals were oriented, and how much proppant went into the frac job. This workflow may be called traditional data analytics for Business Intelligence 1.0; however, the latest AI tools deliver important enhancements and lower cycle times. They can generate production predictions on an individual well basis, with a customized decline curve based on the well location (latitude, longitude and true vertical depth), and the

types and volumes of proppant and fluids utilized, aka Business Intelligence 2.0. A reservoir or frac engineer no longer needs to spend hours-to-days looking for trends in Spotfire and guessing whether a certain dot that doesn’t fit a trend line is simply an outlier or an important insight that can save the company millions. Business Intelligence 2.0 tools deliver more accurate results, and in a fraction of the time. Like Google Maps, Business Intelligence 2.0 tools can deliver results within a few clicks, leaving an oil company to run design and cost sensitivities to find the right scenarios that match its drilling and production objectives. Virality. There is a popular notion that going viral is a phenomenon that is hard to predict and when it happens, we don’t really know why. However, technology companies spend hundreds of millions of dollars on mastering the tools behind virality. How well it is embedded into the product delivery and user experience can mean the difference between becoming Facebook or the start-up you never heard of. Good examples of AI and virality include when LinkedIn sends an email about who is looking at your profile or when Facebook recommends friends with whom you should connect. Both venues foster connectivity between users and repeat visits to their platform, and both drive user growth. In oil and gas, most C-suites work hard to promote communications and collaboration across business units. Two months ago, I was in a meeting with a major operator, where the completion engineer stated that the formation was geologically benign, so the frac design can be uniform. Then the drilling engineer stated that the well tortuosity might cause undulations out of zone. It is one thing to recognize the problem, but how can AI promote a virtuous cycle (or a viral loop) of information sharing and insight creation among and across teams? The implications of virality, due to Business Intelligence 2.0 being utilized for pro-

duction modeling, are significant. Using a common platform, business development professionals can work with GGRE and completions in one simple, intuitive web interface. In an acreage valuation exercise, assumptions about formation properties and frac design can be cross-referenced, to generate powerful predictions of decline curves that are customized for a myriad of subsurface scenarios. Once the acreage is acquired, the development teams can utilize those A&D models to get a head start on where to drill the wells and find suppliers for the specific type of proppant to use for optimal production. As wells start to be delivered, the production teams can identify explicit sources of variance between that initial business development exercise and actual well performance. But modern-day digital initiatives are able to make the AI operational, so data-driven insights from one team can be captured digitally and subsequently leveraged by other teams, months to years afterward. If you are a large public company, chances are that Wall Street is asking about your data strategy. If you are a private E&P, chances are that your private equity sponsors are asking the same— even the limited partners of private equity groups are increasingly asking these questions. The winners in this digital race are working hard in our industry to embed lessons learned from everyday consumer applications, be it consumer intelligence tools, or virality, or other forms of technology tradecraft. Oil companies that proactively foster such AI technologies, to fill in the cracks of daily operations, will separate themselves from their competitors and deliver more alpha for shareholders.

ŝŝBARRY ZHANG is Co-Founder and Chief Executive Officer of

Quantico Energy Solutions, an artificial intelligence company focused on drilling and geoscience solutions for the oil and gas industry. Shell, Statoil and Nabors Industries are major investors in Quantico. Mr. Zhang is a leading expert on artificial intelligence for oil and gas. He has been sought out for his AI expertise by major, national news publications. World Oil® / AUGUST 2018 21

AMERICAN ASSOCIATION OF DRILLING ENGINEERS

2019 NATIONAL TECHNICAL CONFERENCE AND EXHIBITION

Elevating Data FOR MILE HIGH PERFORMANCE

09 -10 April 2019 | Hilton Denver City Center | Denver, Colorado

CALL FOR PAPERS Those interested in submitting a non-commercial technical paper and making a presentation are invited to submit a maximum 250 word abstract at www.aade.org

Abstracts due by September 30, 2018 Authors will be notified of acceptance by October 31, 2018 Papers due by February 15, 2019 Presentations due by March 15, 2019

SUGGESTED TOPICS: • • • • • • • • • • • • •

Bit Design Case Studies Cementing / Zone Isolation Circulation Loss Completions Data and Analytics Deepwater and Subsea Directional Drilling Downhole Tools Downhole Technologies Drilling Automation Drilling Fluids Drilling Management

• • • • • • • • • • • • •

Drilling Optimization Dual Gradient Drilling Factory Style Drilling Field Development Fluids Formation Evaluation Geoscience HSE HTHP Innovative Technologies MPD / UBD New Methodologies Performance Drilling

• • • • • • • • • • •

Rig Technology Risk Management Real-Time Operating Remote Data Monitoring Software and Modeling Special Techniques Tubulars / Expandables Wellbore Stability Well Construction Well Control Well Planning

The American Association of Drilling Engineers will host the National Technical Conference covering subjects considered to be improvements and innovations in drilling operations. This conference will be of interest to major and independent operators, service companies, drilling contractors, equipment and materials manufacturers.

AADE

For more information visit: www.aade.org

AMERICAN ASSOCIATION of DRILLING ENGINEERS

CONFERENCE CHAIR Frank Seidel [email protected] CONFERENCE CO-CHAIRS Erin Britton [email protected] Stephen Flowers [email protected] CONFERENCE COORDINATOR Carolyn Berry [email protected] PROGRAM COORDINATOR Mary Dimataris [email protected]

AADE

AMERICAN ASSOCIATION of DRILLING ENGINEERS

A of

INNOVATIVE THINKERS EMILY QUERUBIN, ASSOCIATE EDITOR

Philippe Herve   

Guiding the point of sail for AI in oil and gas

Although his father was an oil man, Philippe Herve never expected to find himself in the oil and gas business. Herve was born in Port Harcourt, Nigeria, but his family relocated to France, a few years later. His father’s career as a field engineer for Schlumberger required frequent travel, exposing Herve to a variety of new places with diverse cultural backgrounds, from Kuwait to Burma. While studying civil engineering at the Institut national des Sciences appliquées de Rennes (National Institute of Applied Sciences in Rennes, France), Herve joined a sailing club. Sailing competitively not only solidified Herve’s love for travel, but also established an affinity for innovation. “When sailing, you have to pay attention to the details,” he explained. “It is all about the speed of the boat, and how you can make things work faster.” Herve says he primarily sailed on a 470, a monohull planing dinghy that is typically handled by a two-person crew. While training to go to the summer Olympics, and competing against the world’s top sailing teams, Herve worked on mast and sail designs that would give him the advantage in a race. Ultimately, Herve never made it to the Olympics, but won several national titles and championships. He often jokes that while he did not get to go to the Olympics, due to

a political boycott of the games, he took the time to relax and won his gold medal when he met his wife. His 22-year career with Schlumberger combined many of the things he was most passionate about—science and engineering, world travel, and innovation. He started as a field engineer for the company’s wireline group, but over time, held a variety of roles within the lead operation, research, engineering and manufacturing groups. However, it wasn’t until Herve worked at Schlumberger’s Doll Research Center in Ridgefield, Conn., that he found his true passion. While working to develop and patent new solutions related to corrosion prediction and detection, he was struck by the seemingly endless possibilities of artificial intelligence (AI). Today, Herve serves as V.P. of oil and gas at SparkCognition, a cognitive analytics company with a platform designed specifically for the protection, monitoring and optimization of oil and gas operations. “AI allows companies to detect failure on an asset before it occurs,” Herve said. “These predictive capabilities allow companies to increase uptime and maximize their overall operations.” As the former CEO of a cybersecurity company, Herve also has been working to attract the oil and gas industry’s atten-

tion to the importance of data protection. “Our industry is behind others in terms of cybersecurity. For some reason, oil and gas seems to be resisting these technologies, when it should be adopting them,” he explained. “I am still baffled as to why our industry is not more concerned or actively adding modern protections when the Department of Energy is warning the industry that oil and gas is a strong target to cyber villains.” Through his network and knowledge of the oil and gas industry, Herve has facilitated the development of SparkCognition’s patented data-driven AI solutions. This includes solutions for predictive maintenance, cybersecurity and automated model building. To keep rigs up and running, and safe from cyber attacks, the company is implementing cuttingedge AI solutions that can significantly reduce downtime for oil and gas operations. Through the use of data and machine learning techniques, it provides operators with the ability to predict potential asset failures before they occur. Ultimately, with these different offerings, Herve hopes to apply that same drive for innovation he has always had to revolutionize the oil and gas industry. This passes muster for the entire company, as its website mission statement reads, “AI is not just evolution, it’s revolution.” World Oil®/AUGUST 201823

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INDUSTRY AT A GLANCE [email protected]

Crude benchmarks posted four straight weekly declines in July, despite an unexpected halt of Saudi shipments after an attack on two of its oil tankers in the Red Sea. Futures contracts also lost ground after financial advisors warned that escalating trade tensions, between the U.S. and China, were threatening global growth. After a request by President Trump, Saudi Arabia increased its daily production 4.6%, to 10.49 MMbopd in June, while the U.S. and Russia posted output gains of 1%, each. The U.S. rig count averaged 1,050 in July, six less than were active in June. DUCs in the Permian basin increased 164 in June, as logistical issues continue to strand capital in that region. International drilling increased 5.3% to 1,096 rigs in June, due mainly to a large gain in Canadian land-based activity. U.S. OIL PRODUCTION1

Thousand barrels per day

DAILY AVERAGE FOR MONTH JUNE 20182 21 440 21 505 478 5 22 118 7 1,604 19 67 75 6 665 1,215 68 570 4,416 118 30 235 33 10,738 10,298

STATE Alabama Alaska Arkansas California Colorado Florida Illinois Kansas Kentucky Louisiana4 Michigan Mississippi Montana Nebraska New Mexico North Dakota Ohio Oklahoma Texas4 Utah West Virginia Wyoming Others5 TOTAL U.S. LOWER 48

JUNE 20173 18 463 14 490 324 5 23 100 7 1,440 15 51 56 7 443 1,017 50 442 3,777 93 25 202 28 9,089 8,626

% DIFF. 16.7 –5.0 50.0 3.1 47.5 0.0 –4.3 18.0 0.0 11.4 26.7 31.4 33.9 –14.3 50.1 19.5 36.0 29.0 16.9 26.9 20.0 16.3 17.9 18.1 19.4

MAY 20182 21 495 21 500 475 5 24 120 7 1,620 19 62 73 6 665 1,145 70 566 4,329 115 30 233 33 10,634 10,139

1 Includes lease condensate. 2 Preliminary estimate, API. 3 DOE estimate. 4 Includes federal OCS production. 5 Includes Arizona, Indiana, Missouri, Nevada, New York, Pennsylvania, South Dakota, Tennessee and Virginia.

U.S. GAS PRICES ($/MCF) & PRODUCTION (BCFD) 100

7 6

80 60 40

Monthly price (Henry Hub) 12-month price avg. Production

20 0

M A M J J A S O N D J F M A M J J A S O N D J F M A M J J 2016 2017 2018

Production equals U.S. marketed production, wet gas. Source: EIA.

SELECTED WORLD OIL PRICES ($/BBL) 80 70 60 50

W. Texas Inter. Brent Blend Dubai Fateh

Source: DOE

40 30 20

J A S O N D J F M A M J J A S O N D J F M A M J J 2016 2017 2018

WORLD OIL & NGL PRODUCTION MAY 2018

AVG. 2017

AVG. 2016 10.42

OPEC–CRUDE OIL Saudi Arabia

10.46

10.03

9.96

Iran

3.79

3.82

3.80

3.55

Iraq

4.55

4.47

4.47

4.42

United Arab Emirates

2.90

2.87

2.93

3.05

Kuwait

2.72

2.71

2.71

2.88

Neutral Zone

0.00

0.00

0.00

0.00

Qatar

0.62

0.61

0.61

0.65

Angola

1.45

1.51

1.64

1.71

Nigeria

1.46

1.47

1.53

1.47

Libya

0.71

0.97

0.83

0.39

Algeria

1.05

1.04

1.05

1.11

Equatorial Guinea

0.13

0.13

0.13

0.14

Ecuador

0.53

0.53

0.53

0.55

Venezuela

1.30

1.36

1.97

2.24

Gabon

0.20

0.17

0.20

0.23

6.93 38.80

6.93 38.62

6.86 39.21

6.78 39.59 12.53

NGLs & condensate1 TOTAL OPEC OECD2 U.S.

14.99

14.87

13.22

Mexico

2.12

2.11

2.23

2.47

Canada

4.67

5.01

4.83

4.47

United Kingdom

1.02

1.03

1.01

1.03

Norway

1.73

1.62

1.97

1.99

0.50

0.50

0.51

0.49

0.31

0.31

0.31

0.34

0.07 25.42

0.07 25.53

0.07 24.18

0.08 23.42

11.45

11.35

11.36

11.34

3.11

3.13

3.00

2.90

China

3.82

3.82

3.87

3.98

Malaysia

0.69

0.69

0.69

0.71

India

0.85

0.85

0.86

0.85

Indonesia

0.82

0.82

0.85

0.88

Asia-others

0.97

1.00

1.06

1.15

Europe

0.13

0.13

0.13

0.14

Europe-others Australia Pacific-others TOTAL OECD NON–OECD Russia FSU-others

Brazil

2.82

2.73

2.74

2.61

Argentina

0.58

0.58

0.58

0.61

Colombia

0.86

0.87

0.86

0.88

Latin America-others

0.37

0.37

0.37

0.38

Oman

0.98

0.98

0.98

1.01

Syria

0.02

0.02

0.02

0.03

Yemen

0.04

0.04

0.03

0.02

Egypt

0.64

0.64

0.64

0.67

1.38 29.52

1.31 29.34

1.24 29.28

1.20 29.34

5

Africa/Middle East-others TOTAL NON–OECD

4

PROCESSING GAINS3

3

TOTAL SUPPLY

2 1 0

Million barrels per day

JUNE 2018

2.32

2.32

2.29

2.27

96.06

95.81

94.96

94.61

Source: International Energy Agency. Note: Totals and subtotals may not add, due to rounding. 1 Includes condensates reported by OPEC countries, oil from non-conventional sources, e.g. Venezuelan Orimulsion (but not Orinoco extra-heavy oil) and non-oil inputs to Saudi Arabian MTBE. 2 Comprises crude oil, condensates, NGLs and oil from non-conventional sources. 3 Net of volumetric gains and losses in refining (excludes net gain/loss in China and non-OECD Europe) and marine transportation losses.

WORKOVER RIG COUNT REGION ACTIVE Texas Gulf Coast 178 ArkLaTex 56 Eastern U.S. 37 South Louisiana 18 Mid-Continent 135 West Texas / Permian 475 Rocky Mountains 263 West Coast / Alaska 159 TOTAL U.S.   1,321

JUNE 2018 AVAIL. IDLE STACKED 47 64 65 20 45 72 52 25 12 2 10 2 32 87 100 20 181 163 50 142 57 37 137 88 260 691 559

TOTAL 354 193 126 32 354 839 512 421 2,831

% UTIL. 50% 29% 29% 56% 38% 57% 51% 38% 46%

Active - crewed and worked every day during the month. Available - has crew ready to work. Idle - capable of being put to work in 48 hr and does not require spending in excess of $50,000. Stacked - cannot work without investment in excess of $50,000.

YR. AGO ACTIVE 159 58 54 19 144 409 217 175 1,219 Source: AESC

World Oil® / AUGUST 2018 25

INDUSTRY AT A GLANCE [email protected]

INTERNATIONAL ROTARY RIG COUNT JUNE 2018 LAND OFFSHORE 134 3 48 30 2 0 1 2 0 0 0 14 6 0 6 1 19 0 1 6 13 15 350 42 39 13 24 3 60 0 54 0 53 0 23 0 92 16 0 0 5 10 76 18 50 0 0 4 9 0 0 1 8 5 9 8 154 26 72 0 5 8 24 0 7 0 12 14 24 2 10 2 136 79 19 4 0 26 85 31 30 3 0 8 0 0 1 4 0 2 1 1 898 198

REGION & COUNTRY CANADA* EUROPE Germany Italy Netherlands Norway Poland Romania Turkey United Kingdom Others MIDDLE EAST** Abu Dhabi Egypt Iraq Kuwait Oman Pakistan Saudi Arabia Syria Others AFRICA** Algeria Angola Kenya Libya Nigeria Others LATIN AMERICA Argentina Brazil Colombia Ecuador Mexico Venezuela Others ASIA-PACIFIC Australia China, offshore India Indonesia Malaysia New Zealand Thailand Vietnam Others TOTAL

Monthly average

MAY 2018 LAND OFFSHORE 80 3 52 28 3 0 1 1 2 1 0 13 6 0 6 1 19 0 0 5 14 7 353 48 39 13 21 4 60 0 54 0 54 0 24 0 97 19 0 0 4 0 77 17 50 0 0 4 9 0 0 1 9 5 9 7 150 24 67 0 5 9 24 0 6 0 12 11 25 3 11 1 137 81 18 4 1 26 84 30 32 3 0 6 0 0 1 6 0 3 1 3 842 199

**No data available for Iran and Sudan/South Sudan.

JUNE 2017 LAND OFFSHORE 148 2 59 32 3 0 4 0 0 2 0 15 10 0 5 0 21 0 1 8 15 7 355 42 36 13 23 4 51 0 56 0 54 0 25 0 103 16 0 0 7 9 72 14 57 0 0 2 8 0 0 1 4 4 3 7 158 34 60 0 4 13 20 0 7 0 8 16 47 2 24 3 119 75 12 0 0 20 80 30 21 1 0 6 0 0 3 10 0 4 3 4 911 199

Source: Baker Hughes, a GE company.

INTERNATIONAL OFFSHORE RIGS U.S. GULF OF MEXICO JULY 2018 JULY 2017 Total rigs in fleet Marketed Supply Marketed Contracted Rig utilization, %

NORTHWEST EUROPE JULY 2018 JULY 2017

WORLDWIDE JULY 2018 JULY 2017

78

95

91

108

769

825

45

52

74

81

647

669

36

33

64

63

489

483

80.0

63.5

86.5

77.8

75.6

72.2

Source: IHS Petrodata Weekly Rig Count.*

U.S. DRILLED BUT UNCOMPLETED WELLS REGION

JUNE 2018

Anadarko

908

895

13

Appalachia

748

753

–5

Bakken Eagle Ford

MAY 2018

CHANGE

769

750

19

1,537

1,495

42

Haynesville

182

180

2

Niobrara

431

473

–42

Permian

3,368

3,204

164

BASIN TOTALS

7,943

7,750

193

Source: EIA. Note: Totals may not add, due to rounding.

26AUGUST 2018/WorldOil.com

INTERNATIONAL ROTARY DRILLING RIGS

U.S. ROTARY DRILLING RIGS

1,400

1,400

1,250

1,100

1,100

800

950

500

800 J J A S O N D J F M A M J J A S O N D J F M A M J 2016 2017 2018

200 J J A S O N D J F M A M J J A S O N D J F M A M J J 2016 2017 2018

Source: Baker Hughes, a GE company.

U.S. ROTARY RIG COUNT

Monthly average

JUNE 2018 1 1 0 0 9 8 1 1 15 15 0 33 0 0 0 58 36 3 2 17 0 3 0 0 2 92 0 55 22 140 38 0 0 534 1 0 47 30 13 13 4 25 3 46 320 18 4 10 8 17 26 1 19 1,056

JULY 2017 3 3 0 0 6 6 0 1 12 12 0 37 0 0 1 70 43 3 2 22 0 3 1 0 0 59 0 53 27 134 34 0 0 464 0 0 45 35 14 18 3 17 5 35 263 19 3 9 9 13 25 2 22 953

% DIFF. JULY ‘18 JULY ‘17 –66.7 –66.7 0 0 0.0 0.0 0 0.0 25.0 25.0 0 –13.5 0 0 –100.0 –20.0 –23.3 33.3 100.0 –27.3 0 0.0 –100.0 0 … 71.2 0 7.5 –18.5 3.7 11.8 0 0 13.1 ... 0 0.0 –11.4 7.1 –27.8 33.3 41.2 –60.0 37.1 19.4 –15.8 33.3 11.1 –33.3 30.8 12.0 0.0 –13.6 10.2

STATE & AREA ALABAMA-TOTAL Land Inland water Offshore ALASKA-TOTAL Land Offshore ARKANSAS CALIFORNIA-TOTAL Land Offshore COLORADO FLORIDA KANSAS KENTUCKY LOUISIANA-TOTAL North - Land South - Inl. water South - Land Offshore MICHIGAN MISSISSIPPI MONTANA NEBRASKA NEVADA NEW MEXICO NEW YORK NORTH DAKOTA OHIO OKLAHOMA PENNSYLVANIA SOUTH DAKOTA TENNESSEE TEXAS-TOTAL Offshore Inland water District 1 District 2 District 3 District 4 District 5 District 6 District 7B District 7C District 8 District 8A District 9 District 10 UTAH W. VIRGINIA WYOMING OTHERS U.S. OFFSHORE TOTAL U.S. GRAND TOTAL

JULY 2018 1 1 0 0 6 6 1 1 15 15 0 32 0 0 0 56 33 4 4 16 0 3 0 0 2 101 0 57 22 139 38 0 0 525 2 0 45 31 15 13 4 24 2 48 314 16 4 10 6 17 28 2 19 1,050

Source: Baker Hughes, a GE company.

Note: State monthly averages may not add up to U.S. total, due to rounding.

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SPECIAL FOCUS: PERMIAN BASIN TECHNOLOGY

Permian basin leads the pack

Innovative completion technology helps reduce break-even prices to keep operators afloat in the Permian basin

ŝŝTRAVIS HARRIS, Packers Plus Energy Services A sudden market downturn can make a promising field development uneconomic, with many examples from the last few years. In an effort to gird themselves against volatility, operators have strived more aggressively to lower operating costs, as it is now a necessity to decrease sensitivity to unstable market conditions. Some operators in the Permian basin have done this successfully by taking the lead in adopting innovations in drilling and completion technology. For completion technology, recent innovations have combined operational improvements with more effective treatments to improve production. The goal behind these completion technology advances is to reduce breakeven prices and strengthen the industry against market unpredictability, while taking advantage of the worldclass resource that is the Permian basin.

Key advancements in completion technologies have enabled Permian basin operators to accelerate acreage development.

LONG-TERM GROWTH PROJECTIONS

According to short-term forecasts from the U.S. Energy Information Administration (EIA), production growth from North America will essentially account for almost all of the expected growth in global oil supply in 2018 and 2019 among non-OPEC producers, Fig. 1.1 Yet, with minimal estimated production growth in Canada, and declining production in Mexico for 2018, the U.S. is forecast to account for nearly 90% of incremental North American liquids supply growth, Table 1. All key U.S. regions are forecast to increase oil and natural gas production in 2018, with the most significant increases in the Permian Basin for oil, Fig. 2.2 According to IHS Markit, capital expenditures in the Permian basin will represent almost a third of total spending in major onshore plays of the U.S. by 2021, Fig. 3.3 Total completed wells in the Permian basin are also estimated to make up over a third of total onshore U.S. plays by 2020.4 As such, based on current trends, the Permian basin is poised to be the main source of liquids supply growth for the global oil market. TECHNOLOGICAL ADVANCEMENT FOR HIGHER EFFICIENCY

The Permian basin showcases the potential for U.S. unconventional performance, where operators have managed to lower costs, year by year, while achieving higher production. This phenomenon is not restricted to the Permian basin; since 2011, break-even prices have decreased in all key regions, Fig. 4.5 World Oil® / AUGUST 2018 29

PERMIAN BASIN TECHNOLOGY

ing costs. As the unconventional industry gathered momentum, the demand for efficiency sparked trends and innovations such as: • Bullhead stimulation to zonally isolated multi-stage stimulation systems • Continuously pumped sliding sleeve systems • Extended lateral drilling. These changes have been moving steadily toward more operationally efficient systems while improving the effectiveness of treating the entire lateral.

More recently, from 2016 to 2017, estimated break-even prices in the Permian basin have dropped further, Fig. 5. Various subplays show a decrease ranging from 4% to 9%.4 This economic efficiency can be attributed to many factors, including discounted service rates, streamlined logistics, optimized operational efficiency, and most importantly, changes in technology. Technological advancement is the underlying factor that has, and continues to, facilitate better production while lowerTable 1. North American crude oil supply, MMbpd. Country U.S. Canada Mexico

2017 15.6 5.0 2.3

2018 17.6 5.3 2.2

2019 19.1 5.5 2.2

OUR EXPERIENCE IN THE PERMIAN

Packers Plus has been completing wells successfully in the Permian basin since 2009, working with operators to access unconventional reservoirs. Over the years, operators have gradually increased stage count and lateral length, as well as boosted rates and proppant volumes, both ultimately leading to improved production. These operators have access to a full range of proven completion solutions applicable to the Permian basin, including sliding sleeves for both open-hole and cemented liner systems, liner hangers, hydraulic toe sleeves and stage tools. Furthermore, a new full-bore latch system is set to provide benefits that overcome challenges of current completion methods.

Fig. 1. Estimated short-term North American crude oil and liquid fuels production growth. By 2019, U.S. oil production is expected to grow more than 4 MMbpd, Canada is estimated to grow close to 1 MMbpd. Mexican output is expected to decline slightly. Chart: Adapted from EIA.

Crude oil and liquid fuel production growth, MMbpd

5.0 2019 2018 2017

4.0 3.0 2.0 1.0

Open-hole completions. StackFRAC HD is a sliding sleeve system that virtually eliminates non-productive time, compared to traditional plug-and-perf. Once the system is installed and the packers are set, the stimulation can be done from start to finish in one continuous pumping operation. The first stage is activated, using a hydraulic sleeve, which does not require an intervention such as coiled tubing to access the toe. For all other stages, sleeves are opened using actuation balls, which also isolate each stage from lower zones. The ball for each subsequent stage is pumped in the flush of the previous stage, reducing overall completion time and fluid volumes. Degradable balls can further improve efficiency by eliminating the need for mill-out, which saves significant time and equipment costs. Unexpected problems, such as getting stuck, can spiral into major time and cost expenditures. When problems occur, mill-outs can take hours or sometimes days longer than planned.

0.0 -1.0 United States

Canada

Mexico

Fig. 2. Oil and gas production forecast for key U.S. regions, 2017 actuals and 2018 predictions. Source: EIA.

Oil production, Mbpd

5,000

June 2018 June 2017

4,000 3,000 2,000 1,000 0 Anadarko Appalachia

Bakken

Eagle Ford Haynesville

Niobrara

Permian

Fig. 3. Estimated annual capital expenditure and well count in major U.S. onshore plays. Source: EIA.

12,000 Bakken Eagle Ford Permian basin

60

U.S. onshore annual well count by play

Estimated annual capital expenditure per day

80

40

20

0

Bakken Eagle Ford Permian basin

10,000 8,000 6,000 4,000 2,000 0

2011

2012

2013

2014

2015

30 AUGUST 2018 / WorldOil.com

2016

2017

2018

2019

2020

2021

2016

2017

2018

2019

2020

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PERMIAN BASIN TECHNOLOGY

For these reasons, continuous pumping and sliding sleeve completions are arguably the most efficient of all styles. Case study. An operator developing nearly 3 million acres in

the Permian basin wanted to access these reservoirs while keeping costs low. The operator uses both open-hole sliding sleeve systems and plug-and-perf. Comparing production among an area of 40+ horizontal wells completed by this operator, targeting the Yeso reservoir, 10 wells that were completed using sliding sleeve systems show a 30% higher average production after 24 months, Fig. 6. Using StackFRAC HD, the operator has been able to gain significantly higher production while reducing or effectively eliminating non-productive time, and lower operational risk by eliminating well intervention and mill-out.

Cemented liner completions. Combining a cemented liner

with the operational efficiency of a sleeve system, QuickPORT IV sleeves can be run as part of the liner for a limited entry treatment. Individually isolated entry points are treated together in a single stage, and each nozzle is reinforced with tungsten carbide to prevent entry point erosion. One ball opens all sleeves in a stage, and like StackFRAC HD, incrementally larger balls open subsequent sleeves while providing zonal isolation. From the toe to the heel, the stimulation is done in one continuous pumping operation. By removing wireline and coiled tubing operations, and using degradable balls to avoid mill-outs, overall completion time and fluid volumes are more efficient using the limited-entry sliding sleeve than plug-and-perf.

100 90 80 70 60 50 40 30 20 10 0

98 85 81 73 66 39 38 34 33 29

Permian Midland Permian Delaware Eagle Ford Niobrara Bakken 2013

2014

2015

Estimated break even price, US$

50 45 40

52 47 44 42 42 39

Wolfcamp Midland Wolfcamp Delaware Bone Spring

32 AUGUST 2018 / WorldOil.com

200

2017

StackFRAC Other

29% higher

160

44 42 42 41 39 31

2016

Fig. 6. In an area where the operator completed over 40 wells targeting the Yeso reservoir, 10 wells that were completed using sliding sleeve systems produced almost 30% more, on average, after two years.

180

Bakken Eagle Ford Austin Chalk

35 0

A reliable liner hanger. The basic expectation of a liner hanger is that it should anchor the completion system and maintain pressure integrity throughout the life of the well. Furthermore, a liner hanger also should function reliably to lower operational risk, saving time and money. To do these things, a liner hanger must have capabilities in these areas: • Pressure rating • Hanging and rotational capability • Built-in mitigation and contingency.

2016

Fig. 5. Estimated break-even prices dropped from 2016 to 2017. Source: IHS Markit.

55

Permian had been having problems with wireline and coiled tubing. These issues included plug pre-setting, perforating, and applying sufficient weight on bit for mill-outs, particularly in wells with an MD greater than 20,000 ft. To resolve this issue, the operator began running the first four or five stages of its extended-reach laterals with clusters of limited-entry sleeves. This successfully eliminated unnecessary costs associated with operations at extreme depths, while maintaining the limited-entry stimulation design, and eliminating entry point erosion. After the toe stages, the operator continued with plug-and-perf for the rest of the stimulation. This hybrid design became standard for wells exceeding 20,000 ft, MD. More recently, the operator completed a particularly long well targeting the Wolfcamp formation. The well had a 23,300ft MD, including a long, 12,200-ft lateral section. To cover the deepest 3,900 ft of the lateral, 80 sleeves were grouped into the first 20 stages before, as usual, plug-and-perf was planned for the rest of the completion. This hybrid completion technique proved effective in the significantly longer well, and the first 20 stages were completed in just 70 hr of pumping time. Considering the longer-thanaverage MD, the strategy successfully reduced operational risk, non-productive time, and potential cost over-runs. The success of the 80-sleeve completion proves the effectiveness of the limited entry system in its ability to perform as a high-density, highstage count completion solution, Fig. 7.

Average cumulative production, Mbpd

Estimated break even price

Fig. 4. Average break-even prices fell during the 2013-to-2016 period in all key shale plays. For Permian Midland, the break-even has fallen from $98/bbl to $39; in the Permian Delaware, it dropped from $81 to $33. Source: Rystad Energy.

Case study. Another operator using plug-and-perf in the

140 120 100 80 60 40 20 0

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5

10

Months

15

20

25

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PERMIAN BASIN TECHNOLOGY

For pressure rating, a liner hanger should be rated above the system that it is paired with, to ensure that it will not be the weak link during hydraulic pressure spikes. The PrimeSET system is fully gas-tight (V0 qualified) up to 15,000 psi, making it appropriate for a wide variety of applications, Fig. 8. As extended laterals become more commonplace, rotational ability can be a limiting factor. During installation, the Drill Down Running Tool (DDRT) allows the operator to push, pull, and rotate with over 20,000 ft-lb of torque. This can be valuable when working in longer wells, which typically have more doglegs and deviations. Finally, risk mitigation is an important consideration for liner hangers, particularly the issue of a premature setting while pushing and rotating the system to depth. Since an accidental pre-set can cost millions to recover from, the PrimeSET DDRT is designed with a balanced piston releasing system that makes it unaffected by pressure spikes, and avoids premature release. The secondary mechanical release option, using left-hand rotation, is also designed as a contingency. Over 30 of these liner hangers have been used to install comFig. 7. The 80 sleeves used in a hybrid, extended-lateral completion successfully lowered operational risk and non-productive time.

pletion systems in the Permian basin without issue, with more than 100 systems deployed over North America. The Future: Full-bore sleeve completions. The comple-

tions industry is on the brink of proving a new technology that improves upon existing completion systems and provides features that operators have long desired. The benefits of this new technology include: • Full-bore during stimulation with no inside diameter restrictions • No stage limitations • Degradable isolation components to avoid mill-out • Operationally efficient, with minimized non-productive time. The Latch-and-Perf system allows operators to increase reservoir coverage with high-stage count capability, pump high rates throughout stimulation with a full bore, avoid mill-out time and costs, and improve operation efficiency using latches that have fast pump-down rates. This system was installed recently and run successfully in the Permian basin. During this trial, five stages were placed at the heel of the well. For each stage, an isolation latch was pumped downhole on wireline and latched into the locating sub. The casing was perforated, and the stage was treated. All five latches were pumped down successfully and latched into the profile, and treated without incident. A pump-down version of this system that operates without wireline and is pumped continuously is also in field trials. This system will help operators lower break-even prices further by reducing NPT and eliminating the need for interventions and mill-out, while maximizing reservoir contact in long laterals.

CONCLUSION

Fig. 8. This liner hanger is fully gas-tight, can handle over 20,000 ft-lb of torque, and is designed specifically to avoid premature setting.

If industry trends and economic projections follow through as predicted, the Permian basin is set to be the main source of liquids supply growth for the global oil market. Lowering break-even prices will lower sensitivity to market volatility. Many operators in the Permian basin have successfully done this by taking the lead in adopting innovations in drilling and completion technology. Key advancements in completion technologies have allowed operators in the Permian basin to accelerate acreage development. Improved efficiency has led to an ongoing reduction in breakeven prices, which in turn has enabled operators to be more profitable and less sensitive to oil price fluctuations. The next generation of completion technology is just getting ready to build further on this success. REFERENCES 1. U.S. Energy Information Administration, Short-Term Energy Outlook, May 2018. 2. U.S. Energy Information Administration, Drilling Productivity Report for key tight oil and shale gas regions, May 2018. 3. IHS Markit; The Permian Basin: A magnet for risk capital; Jan 2017. 4. IHS Markit; Outlook for U.S. Oil and Gas Production 2018-2020; April 2018. 5. Rystad Energy, NASWellCube.

TRAVIS HARRIS has held a variety of operational and management roles over his 30-year career in the oil and gas industry. Working as a technical services manager and an operations manager at large service companies, he was responsible for all daily operations in a large district. His focus at Packers Plus is to develop and implement the company’s strategy for its innovative cemented systems that improve efficiency, and save time and cost for operators. 34 AUGUST 2018 / WorldOil.com

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SPECIAL FOCUS: PERMIAN BASIN TECHNOLOGY

Perforating system improves stimulation results in unconventional completions

Efficiently completing horizontal wells in tight formations is key to a project’s economic success. In the Permian basin, laterals are typically stimulated in zoned stages, using plug-n-perf techniques and hydraulic fracturing. When planning a perforation design, it is important to optimize several key factors to ensure results match expectations.

ŝŝADAM DYESS, Hunting, Titan Division Perforating tight formations in horizontal wells presents a dilemma common to unconventional shale plays. Traditionally, operators must choose between running centralizers in the perforating gun string, or letting the string lay naturally on the casing’s inner wall. In centralized perforation strings, the charges utilized are positioned at a constant distance from the target casing’s inner wall. The space between the outer wall of the perforating gun containing the shaped charges and the inner wall of casing is the “fluid gap.” The gap’s influence on charge perforA perforating system and innovative shaped charges provide consistent entry holes, small exit holes and optimal penetration that improves stimulation performance.

mance can be predicted and quantified during the stimulation design program. The additional length and diameter of centralizers makes access to highly deviated horizontal wells difficult, if not impossible. Running a perforating string without centralizers improves access but delivers entry holes (EH)—the hole resulting from a shaped charge jet entering the casing—that can vary by as much as 50% between holes on the high side of the casing, compared to those on the low side, Fig. 1. Decentralized perforation strings must work with an asymmetrical fluid gap, which results in widely varying charge performance, including depth-of-penetration and EH size. Engineers select charges to provide adequate depth-of-penetration, small exit hole and consistent entry hole to improve stimulation. Conventional shaped charges are generally selected based on their various performance characteristics; however, they are not designed to account for fluid gap variances. Neither deep penetrating (DP), super-deep penetrating (SDP), or good hole (GH) shaped charges, can provide consistent EH diameter in decentralized applications. Inconsistent EH sizes make it difficult for stimulation designers to accurately calculate flow area, resulting in variations of proppant distribution and poor stimulation results. Non-uniform EH diameters can result in erosion and slotting of smaller perforations during the stimulation process, leading to under-utilization of the entire perforation set. This can cause slow ramp-up to intended treating pressures, therefore World Oil® / AUGUST 2018 37

PERMIAN BASIN TECHNOLOGY

extending pumping time, increasing the volume of frac fluids needed and reducing well stimulation efficiency. The perforating gun system also directly affects the operational productivity due to its tendency toward human error during the gun loading, arming and assembly processes. A reliable and “dummy-proof” perforating system is required to minimize nonproductive time for the stimulation operation. Pairing the ideal shaped charges with the right perforating gun system is imperative for efficient well stimulation and maximum productivity. SHAPED CHARGE SOLUTION

To solve the issues surrounding inconsistent entry holes, Hunting’s Titan Division developed the EQUAfrac. With EQUAfrac shaped charges designed specifically to reduce variations in EH diameter, the H-1 optimizes stimulation performance and well production rates in decentralized horizontal well completions. EQUAfrac technology can provide EH sizes, with less than 7% variation in diameter, regardless of string position, Fig. 2. Depending on the perforating gun size and the type of casing, Fig. 1. Shooting across various fluid gaps, using conventional shaped charges in decentralized perforating guns, can result in smaller casing entry holes across the larger fluid gaps, compared to a larger entry hole on the low side of the casing. The hole size variation can be as high as 50% and have adverse effects on the stimulation plan.

Small casing hole

Large fluid clearance

Large fluid clearance

Perforating assembly

Perforations

Large casing hole

Fig. 2. The uniform hole charges account for variances in the fluid gap in horizontal wells resulting in consistent entry hole diameters. The charge allows for 360° even distribution of frac fluids for improved stimulation.

38 AUGUST 2018 / WorldOil.com

the system can, in some cases, deliver EH size variance below 3%. This is accomplished via a proprietary shaped charge liner, creating a focused jet more quickly and over a longer gap. The innovative shaped charge technology can produce consistent entry holes, regardless of the distance from the outer wall of the perforating gun to the inner wall of the casing. Meaningful stimulation improvements result from consistent EH diameters, including reaching the treatment rate faster at a lower pressure. The frac pumping profile, which consists of the treatment rate, hydraulic horsepower and fluid volume required to reach formation breakdown, is similarly improved. The time, horsepower and volume needed to fracture the formation is decreased, because uniform EH size delivers equal proppant distribution in every hole, 360° around the wellbore. The increased area open to flow leads to consistent pump rates at lower pressures across the stage, Fig. 3. Faster treatments at lower pressures mean less horsepower and fluids, saving time and money during the fracturing process. Field trials. To analyze the shaped charge’s performance in a real-world environment, multiple field tests have been performed. The results were then compared to performance delivered by conventional shaped charges in decentralized applications. In one stimulation case study evaluating pumping profiles after perforating, the 23g EQUAfrac charge outperformed a comparable 23g conventional charge. The conventional charge resulted in breakdown pressure averaging 7,500 psi to 8,300 psi, and treating pressure averaged 8,900 psi. The treating rate averaged around 91 bbl/min. but was inconsistent. Conversely, the EQUAfrac charge improved break-down pressure, averaging between 7,000 psi and 7,800 psi, or 500 psi less than the conventional charge. The treating pressure using the consistent hole charges averaged around 8,400 psi, which was 6% lower than that of the conventional charges. The treating rate increased 10%, to 100 bbl/min. Treatment rates were reached faster, at a more consistent rate, when running EQUAfrac, allowing perforations to take higher sand concentrations at a lower pressure. Other field trials also demonstrated improved stimulation results that the consistent hole charges provide.

DEPTH OF PENETRATION

While entry hole consistency is a primary factor in frac design, perforating beyond the drilling-invaded zone is essential for efficient stimulation. The drilling-invaded zone is the rock formation surrounding the outer diameter of the wellbore that was damaged by the concentric pressure of the drilling process. This near-wellbore area has reduced permeability, due to the pulverized material that it contains. The industry consensus for ensuring depth of penetration— essentially the length of the perforation tunnel—is to extend past the drilling-invaded zone. Shaped charges that cannot penetrate past the invaded zone can hinder stimulation performance, with further negative impact to future production rates. Perforation penetration is critical to stimulation performance, because the depth of perforation directly affects how the fracture initiates fractures or cracks. Deeper perforations are, on average, easier to initiate and propagate. Deep, consistently formed perforations extending into the virgin formation can significantly reduce breakdown pressure and improve fracture initiation.

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Fig. 3. Consistent hole sizes resulting from EQUAfrac charges provide more area open to flow for the frac fluids, reducing breakdown pressures and time required for treatments during stimulation.

Hole size

0.60

Area open to flow

0.30

0.55

0.25

0.50 0.20 Area open to flow, in.

Hole size, in.

0.45 0.40 0.35

0.15

0.10 0.30 0.05 0.25 0.20

0.00 0° 0.2 in.

60° 0.5 in.

120° 1.1 in.

180° 1.5 in.

Phase, ° Fluid clearance, in.

240° 1.1 in.

300° 0.5 in.

Fig. 4. The company’s consistent hole charge provides two times the penetration, and significantly lower exit holes, compared to another consistent hole charge.

14

12

0.50 Penetration EnHole ExHole

0.45

0.30 0.25

6

Ex/En hole, in.

Total penetration, in.

0.35

8

0.20 0.15

4

0.10 2 0.05 0

0.00 Titan

Other shaped charge

A secondary reason for a longer, tapered perforation is that longer perforations are less influenced by the crushed zone surrounding a perforation tunnel than are short perforations. The perforation crushed zone is the region immediately around the perforation tunnel that acts as a barrier to further fracture extension, due to reduced permeability after the perforation event. 40 AUGUST 2018 / WorldOil.com

60° 0.5 in.

120° 1.1 in.

180° 1.5 in.

Phase, ° Fluid clearance, in.

240° 1.1 in.

300° 0.5 in.

The perforation jet causes micro-fracturing to the surrounding formation, destroying larger pores and replacing them with smaller ones. Studies have shown that the perforation damage is significantly higher near the perforation entry, compared to the area around the perforation tip further away (SPE paper 51051MS, Halleck). APPLICATION CHALLENGES

0.40 10

0° 0.2 in.

Since their introduction to the market in 2014, the EQUAfrac charges have completed hundreds of wells, providing a superior hole charge technology for improved frac efficiencies. While consistent EH is imperative for stimulation results that meet or exceed the design requirements, there are other charge performance metrics. The exit hole size, as well as the jet’s depth of penetration, are similarly important. In some cases, a shaped charge manufacturer is forced to sacrifice depth-of-penetration to achieve consistent and adequate EH size. It is also difficult to devise a consistent and large EH while keeping the exit hole small. The exit hole is the resulting diameter on the perforating gun, formed as the perforating jet leaves the gun. Ideally, the exit hole is as small as possible, so that debris inside of the perforating gun does not follow the jet and plug up the entry hole, rendering the EH effectively useless during stimulation. The company’s consistent hole-shaped charge solves all three challenges by providing consistent EH size, small exit holes and penetration well beyond the invaded zone. The shaped charges can achieve minimum penetration lengths 2½ times the interior diameter of the wellbore, extending past the low permeability damaged zone caused by hoop stress concentrations. The charges also maintain a beneficial ratio of entry hole size to exit hole size, which minimizes blockages due to debris.

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PERMIAN BASIN TECHNOLOGY

Fig. 5. The H-1 perforating system and EQUAfrac shaped charges provide consistent entry holes, small exit holes and optimal penetration that improve stimulation performance.

sure was 6% lower. The operator also noted that the new charge took less time to reach treating rate and allowed higher sand concentrations at lower pressures. These results demonstrated that the EQUAfrac charge consistently improved stimulation while decreasing costs. PERFORATING SYSTEM

Fig. 6. The perforating system has no wires, eliminating tandem sub maintenance. The system reduces gun-loading times by 80% and seal connections by 67%, decreasing the possibility of gun failures.

API stressed rock testing. API RP 19B Section 2 testing requires shooting into stressed rock targets to more closely mimic downhole perforation performance in shale formations. In multiple head-to-head tests, the Titan charge averaged roughly 10½-in. of penetration in Section 2 rock tests, above the needed penetration to extend past the invaded zone, into virgin formation, Fig. 4. EQUAfrac’s resulting exit hole is significantly lower than the entry hole, as well as the exit hole, compared to the other tested charge. This ideal exit hole to entry hole ratio reduces the likelihood of debris plugging the perforation. In comparison, a non-company consistent EH charge averaged penetration of less than 4½-in., below the needed penetration to surpass the invaded zone. The other charge also delivered larger exit holes nearly equal to the entry hole, which can attribute to debris filling perforations. In addition to Section 2 rock tests, an actual well stimulation case study was completed by alternating stages running EQUAfrac and the equivalent other-type consistent hole charge. Analysis of the resulting pumping profiles showed the other-type charge resulted in break-down pressure at an average of 8,400 psi to 9,500 psi, and treating pressure averaged 8,700 psi. The EQUAfrac charge resulted in break-down pressure averaging around 6,800 psi to 8,200 psi, and treating pressure averaged around 8,100 psi to 8,200 psi. Therefore, the consistent hole charge showed to break down the formation at pressures 13% lower than the other type charge, and the resulting treating pres42 AUGUST 2018 / WorldOil.com

To optimize delivery of the consistent hole-shaped charge, the company developed the H-1 perforating gun system, Fig. 5. This system is used in traditional, selective fire, and plugand-perf operations to improve operational efficiencies and to reduce associated costs. The system is designed for safe and efficient gun loading, arming and assembly, compared to conventional perforating guns. The system loads four times faster than most perforating guns in the field today. To make perforation gun loading even simpler, the company created H-Lok shaped charge technology. These charges simply twist and lock into place. The H-1 also prevents waste by utilizing predetermined detonating cord lengths that remove the need for measuring and trimming. The biggest time-saver is the elimination of the shooting wire, Fig. 6. While other systems feature “pre-wired” guns, the company’s design eliminates wires entirely, so there is zero risk of associated wiring errors. In addition to gun loading, the field arming operation is also much faster and easier, using the new perforating system. It is intuitive and user-friendly because it eliminates wires by using the RF-Safe ControlFire cartridge. The new cartridge allows the user to arm the gun by inserting the cartridge into the pin end of the gun. The cartridge utilizes proven and reliable ControlFire technology, which has a 99.99% success rate with nearly two million runs. The new perforating system also improves the total length of assembly (footprint) by reducing parts and connections. The tool string footprint is shortened because the box by pin design eliminates tandem subs between perforating guns. The system also improves performance in the wellbore by reducing potential seal failures, because there are no port plugs that can fail. Overall, the system reduces hardware connections by two thirds. These advances create a perforating system that is easier to handle and has reduced opportunities for human error. CONCLUSION

When completing horizontal shale wells using stage frac techniques, it is imperative to utilize reliable perforating guns and shaped charges that will consistently provide uniform perforations that extend into the virgin formation. Utilizing the provider’s line of shaped charges and the H-1 perforating system will optimize stimulation performance, reduce costs and improve operational efficiency when compared to other perforating systems and shaped charges. ADAM DYESS is the director of engineering for the Titan Division at Hunting Energy Services, based in Houston, Texas. Mr. Dyess has extensive knowledge in unconventional well completions, working in both the service and manufacturing sectors of the oilfield industry for 11 years. He began his career as a wireline field engineer in the Permian basin and is now focused on advancing technology and developing new products for well completions. He holds a bachelor’s degree in biomedical engineering from Vanderbilt University, Nashville, Tenn.

SPECIAL FOCUS: PERMIAN BASIN TECHNOLOGY

New frac-pack additive is step change in sulfide scale control for Permian long horizontals

A new sulfide scale control, frac-pack additive solved a Permian basin operator’s severe production impairment during startup, and initial frac-fluid return, in 50-stage, hydraulically stimulated, 15,000-ft horizontal Spraberry formation wells.

ŝŝDR. CYRIL OKOCHA, Clariant Oil Services The Permian basin, a sedimentary basin in West Texas and southeastern New Mexico, is one of the most prolific oil and gas basins in the United States, with total production over 14.9 Bbbl since 1993. The play spans approximately 250 mi wide and 300 mi long, and encompasses several sub-basins, including the Delaware and Midland basins. The geology of these basins is unique, as single wells can often source oil and gas production from multiple layers of formation rock across different geological zones. In this article, we are concerned with the Spraberry formation, which along with the Wolfcamp formation are regarded as the most productive oilField application of the chemical has resulted in significant costsavings through elimination of well entry requirements, posthydraulic fracturing treatment. Photo: Clariant Oil Services.

bearing zones in the U.S., and have been dubbed “Texarabia” by various press. The Permian basin comprises four major plays, including the Wolfcamp and Bone Spring horizontal plays in the Delaware basin, and the horizontal Wolfcamp and vertical Spraberry plays in the Midland basin. They routinely are drilled together, to access the stacked formations, Fig. 1. HYDRAULIC FRACTURING/ FLOWBACK FLUID MANAGEMENT

Hydraulic fracturing is an extraction technique used to facilitate enhanced oil and gas production from hydrocarbonbearing formations. The process entails injecting hydraulic fracturing fluid downhole into an oil or gas well. The injection pressure used is sufficiently high to cause splitting/cracking of near-wellbore formation rock in the target, hydrocarbon-bearing formation, allowing release of stored hydrocarbon potential back to the wellbore via the artificially created fractures. Frac fluids used in these treatments routinely include solid proppant materials, such as graded sand, which pack into the newly formed fractures, and function to maintain fluid and gas transmission pathways from reservoir to wellbore, once the hydraulic pressure is released. Fracing has contributed significantly to increased U.S. oil and gas production, by more than 50% of oil output and nearly 70% of gas production in 2015. This is projected to position the U.S. as the world production leader by 2021 (EIA 2015- https:// www.eia.gov/todayinenergy/detail.php?id=25372). Hydraulic World Oil® / AUGUST 2018 43

PERMIAN BASIN TECHNOLOGY

fracturing is regarded by most as the key enabling technology for economic production of unconventional resources, such as shales and tight sands. This article addresses scale-related production challenges encountered during the initial 30-to-60-day hydraulic fracture treatment flowback phase in Spraberry long horizontal wells. During the initial post-shut-in flowback phase, the returning fracture treatment fluids dominate well-produced water ion composition (identified via chemical signatures of the fracturing cocktail components). The frac treatment progressively cycles out of the well with time, and eventually the well-produced water ion composition reverts to that of the reservoir waters. In general, water processing/disposal costs during flowback treatment have been estimated to be between $1.00 to $8.00 per bbl of water (IHS 2016), and Permian operators typically include the first 30 to 60 days of flowback disposal into their capital costs per well. These costs can range from $0.3 MM to $1.2 MM, making up 5% to 19% of a well’s total cost (IHS 2014). Fig. 1. The Midland basin, showing the Spraberry trend with the location (star) of the subject wells. Map: Shale Experts.

THE SCALE CHALLENGE: BLOCKAGES AND DEPOSITION

Typically, during flowback, approximately 30% to 75% of the fluid injected is returned in the first three weeks. It is, incidentally, a very interesting research area on chemical additives that enhance the return rates of these injected fluids, which can be achieved using surfactant chemistry or better polymer and breaker combinations. The return profile of slick water fracturing versus gel fracturing can be explained by this phenomenon in the Permian and many other plays in the U.S. The very nature of fracing operations, with high pressures and large volumes of water, usually causes substances, such as released metals or dissolved salts from the formation, to be brought up with the flowback water, including trapped gases. Flowback water often contains high concentrations of total dissolved solids (TDS), heavy metals, suspended solids, sand and dissolved radioactive substances released from the formation (Zhang, 2014). Hydraulic fracturing chemical additives make up less than 3% of the total frac fluids and are typically included to reduce well blockages, primarily from dissolved rock formation (calcium, magnesium, manganese and strontium). They also are used to limit heavy metal contamination (such as iron, chromium, copper, molybdenum, niobium, vanadium, and zinc) and formation fluid imbibition, as a result of leaching and mobilization of reactive surfaces exposed to the frac fluid. Chemical additives include scale inhibitors, corrosion inhibitors, iron control agent, pH and clay control agent, along with other additives, this typically guarantees a successful hydraulic fracturing job. World Oil previously published an article ( July 2009, “Considerations for development of Marcellus shale gas”) that nicely shows the distribution of chemicals used for typical shale gas gel fractures, summarized in Fig. 2. In some hydraulically fractured wells, scale deposition is not effectively controlled by the conventional scale inhibitor, either as a result of heavy metal and/or sulfide poisoning, leading to severe scale deposition in the recently opened fractures and wellbore. Flowback duration and production are immediately impacted by these depositions, and well re-entries with an associated well cleaning plan are required to reinstate production. In this article, the challenges that a Permian operator faces during completion of several 50-stage, hydraulically fractured

Fig. 2. Typical chemical make-up of a Marcellus hydraulic fracturing fluid.8 Chart: World Oil.

Proppant 3.5750% Water 95.9719%

44 AUGUST 2018 / WorldOil.com

Gelling agent 0.0575% Scale inhibitor 0.0822% KCI 0.0844% Acid 0.1186% Crosslinker 0.0008% Surfactant 0.0016% Friction reducer 0.0395% Biocide 0.0065% pH adjuster 0.0093% Corrosion inhibitor 0.0105% Breaker 0.0237% Iron control 0.0540%

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PERMIAN BASIN TECHNOLOGY

Fig. 3. Laboratory testing of the novel sulfide scale control technology for performance and compatibility. Photo: Clariant Oil Services.

ommended at an applied dose rate of 1 gallon per thousand (GPT) in the pad and 0.4 GPT for the remainder of the 50 stages. Compatibility tests and subsurface performance tests were carried out prior to the field application, showing excellent compatibility with the frac fluids and a favorable adsorption–desorption (isotherm), and therefore an assumed field squeeze performance, Fig. 3. DEPLOYMENT RESULTS

wells are highlighted. It was discovered that these failures were attributed to iron sulfide (FexSy) and zinc sulfide (ZnS) scale deposition during flowback. Further, this article introduces the industry’s first, innovative solution to control these types of exotic scale effectively during fracturing and flowback. The operator tried different mitigation options, including increasing concentration and changing out the standard scale inhibitor, among many, all of which were unsuccessful in preventing well failures. As the cost accumulated in well re-entries and associated mitigation options, a request was sent to Clariant Oil Services to provide an effective, lasting solution. The development of the chemistry has been covered adequately in previous publications (Savin, et al. 2014; Wylde, et al. 2015). Readers are encouraged to check further into the unique characteristics exhibited by this patented chemistry for dispersing and inhibiting sulfide scales, in comparison to traditional scale inhibitor products’ inhibition mechanisms.

The sulfide scale inhibitor additive used in the hydraulic fracturing treatment resulted in control of all sulfide scale issues downhole in the target wells. Well scaling health was determined via zero fouling, combined with monitoring of well-produced waters, which showed steady and consistent dissolved iron and zinc concentrations. There was no increase in H2S evolution during flowback. It was not possible to determine the residual scale inhibitor concentration, due to the presence of high levels of interfering chemical species in the flowback fluid. The primary culprit is believed to be the generic drag reducer chemical additive employed throughout the treatment. ESP run-times increased from a few weeks to several months of continuous operation, with motor temperature indicators and across-pump differential pressure transducers indicating low or no scale development. In addition, several ESP units were recovered for inspection topsides, where no new significant sulfide scale deposition was identified within any unit. For wells equipped with pressure transducers downhole, it was deduced that wellbore tubing was free from any new, significant solids deposition. The laboratory tests showed, and it was corroborated in the field, that the new sulfide scale inhibitor technology reduced the iron and zinc scale deposition rate to 99.9% (compared to the previous untreated water), and met the KPIs set for performance. The technology proved to be an excellent sulfide inhibitor, acid and non-acid, frac pad-compatible, squeezable, and temperature-and-high-shear-stable.

FIELD SOLUTION AND DEPLOYMENT

CONCLUSION

For the field case history presented here, both the capital expenses per well and the number of well re-entries for scale mitigation increased. Several remediation chemistries were eventually trialed, which provided only temporary relief from the continuous sulfide scaling experienced in the wellbore and across ESPs (electrical submersible pumps). The operator requested a solution—to control iron and zinc sulfide—to be delivered during the hydraulic fracturing operation. Key performance indicators (KPIs) were developed between the operator and the service company, to align on pass/fail criteria in the laboratory and field. These KPIs included the following: • Exceptional performance to inhibit iron and zinc sulfide • Compatible with frac fluid (pad–acid and non-acid pads) • Suitable adsorption and desorption characteristics (squeezable) • Temperature and high-pressure (shear) stability • Zero increase in H2S evolution during flowback. The chemistry used, as described above, was proven in the detailed testing protocols to be a viable sulfide inhibitor for this hydraulic fracturing application. The use rate was rec46 AUGUST 2018 / WorldOil.com

The new-generation sulfide scale control additive dosed into the frac treatment package was very effective at controlling various types of sulfide scales during the post-frac treatment production phase. As a direct consequence of deploying the additive, the Permian basin operator gained the following: • Economic benefit, with respect to continued production and reduced downtime/deferred oil cost • Economic benefit via savings made on well re-entry frequency and remedial cleanup actions • Reduced concerns of H2S evolution during flowback and provided environmental and cost-savings benefits. DR. CYRIL OKOCHA is a scale specialist for the global innovation team within the business line, Oil Services, at Clariant. Dr. Okocha has a background in geochemistry from University of Newcastle upon Tyne and earned his PhD in petroleum engineering from Heriot-Watt University, both in the U.K . He conducted his postdoctoral fellowship research in collaboration with Clariant at Heriot-Watt University to develop the now-patented sulfide scale inhibitor. Dr. Okocha is the author and co-author of several SPE conference papers and three patents/patent applications. WEB EXCLUSIVE: Visit WorldOil.com to view the references for this article.

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TechTalk

Permian oil production requires additional pipeline infrastructure Further expansion of oil output in the Permian basin is dependent on a number of pipelines being built or expanded. Here is a rundown of the status of various pipeline projects in the region.

ENERGY WEB ATLAS and WORLD OIL STAFF With regard to the short-term future of the Permian basin, through the rest of this year and into early 2019, it is now the consensus of the World Oil staff that activity will level off during second-half 2018. Indeed, it is possible that anywhere from a 10% to 20% drop in drilling and development work could occur in the second half. The reason is simple—there just won’t be enough pipeline capacity to handle the extra production that a full activity rate would generate. Accordingly, building additional pipeline capacity in the Permian is job number one. Already, counting all the projects confirmed on the books, Permian pipeline capacity could eventually total 7.0 MMbopd. There also is eventual potential for up to 9.0 MMbopd of Permian pipeline capacity, if all goes well. But first the pipelines on the books have to be built. It appears that a first wave of a half-dozen pipeline projects will go online during 2019, followed by a second wave of four or more projects in 2020. In the meantime, Permian pipeline capacity will be constrained through at

least mid-2019, exacerbated by growth in the region’s oil production rate, anticipated to hit 4.0 MMbpd by the beginning of next year. So, for the next 12 months, Permian operators will have to rely on storage capacity and alternative transportation methods to make up the difference. Yet, given the shortage of trucks and truck drivers, the trucking of oil, particularly over long distances, is not expected to be a factor. This leaves rail as the only reasonable alternative. There are indications that rail capacity out of the region could be expanded to 300,000 to 400,000 bopd. In addition, some local sand mine terminals could be converted to alleviate rail congestion and boost capacity on the tracks further. So, given the serious capacity situation, not to mention the possibility that flaring of associated gas output may have to rise to 700 MMcfd to 800 MMcfd, the pipeline infrastructure must be expanded quickly. Accordingly, we feel it is important to feature the following status report on Permian pipeline projecs from the Energy Web Atlas, a division of our parent company, Gulf Energy Information.

PERMIAN BASIN PRODUCTION

The EIA’s Annual Energy Outlook for 2018 forecasts that oil production in the Permian basin will experience the largest growth of all U.S. shale plays, increasing 60% from an average 2.5 MMbpd in 2018 to 4 MMbpd by 2030, Fig. 1. However,

Lower 48 onshore crude oil production by region, MMbpd

Fig. 1. An overview of past, present and predicted oil production in the Permian basin and other regions, 2000–2050. Source: U.S. Energy Information Administration.

5

History

Projections

4

Southwest

3

Dakotas/Rocky Mountains

2

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1 0 2000

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East 2010

2017 2020

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48 AUGUST 2018 / WorldOil.com

2040

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recent production in the shale play has far surpassed the predicted 2.5 MMbopd for 2018. According to the EIA’s Drilling Productivity Report, oil production reached 3.333 MMbpd in July, a 56,000bpd increase over June. The Baker Hughes North American Rig Count reported that there were 476 operating rigs targeting oil in July, compared to 374 operating a year earlier. Based on that report, the rig count in the Permian basin accounts for 55% of all operating rigs targeting oil in the U.S. According to Genscape, the Permian basin had 3.175 MMbopd of total takeaway capacity in March 2018, with outgoing pipeline capacity at 2.725 MMbpd. Given that production has surpassed pipeline takeaway capacity in the past few months, existing pipelines are falling short. This leaves the region relying heavily on new infrastructure development to keep afloat.

SATISFYING DEMAND: CURRENT AND PLANNED PIPELINES Existing pipelines. According to the Energy Web Atlas, two pipelines have gone online recently in the Permian basin to help alleviate the current strain on takeaway capacity in the play, Fig. 2. In the first project, Enterprise Products Partners LP completed the Midland-to-Sealy Pipeline that runs 416 mi from Midland, Texas, to Sealy, Texas It provides 450,000 bpd of takeaway capacity from the Permian basin to U.S. Gulf Coast markets. In the second project, Medallion Pipeline Company LLC has completed the Delaware Express Pipeline that runs 95 mi from Ward County, Texas, to Crane, Texas, and has a capacity of 200,000 bpd. This pipeline provides Delaware basin customers with access to the Permian basin long-haul takeaway pipelines, local refineries and downstream markets. In addition, some existing Permian basin pipelines are undergoing expansions: • Magellan Midstream Partners LP and Plains All American Pipeline LP own the BridgeTex Pipeline that runs 400 mi from the Permian basin to U.S. Gulf Coast markets. SPONSORED CONTENT

PERMIAN BASIN: ANALYSIS

The pipeline has a current capacity of 400,000 bopd and will be expanded to 440,000 bopd. • Energy Transfer Partners LP and ExxonMobil own the Permian Express 1 and Permian Express 2 pipelines that transport Permian basin crude to both the Nederland and Longview markets in Texas. The system includes 700 mi of pipeline with a joint capacity of 350,000 bopd. It will be expanded 300,000 bopd upon completion of the Permian Express 3 Pipeline. • Plains All American Pipeline LP owns the Cactus Pipeline that runs 310 mi from McCamey, Texas, to Gardendale, Texas, and transports Permian basin crude to the Eagle Ford JV Pipeline serving U.S. Gulf Coast markets. The pipeline has a current capacity of 390,000 bopd, and the system will be expanded to 965,000 bopd.

Fig. 2. Existing oil pipelines in the Permian basin. Source: Energy Web Atlas.

Fig. 3. Permian basin oil pipelines, planned and under construction. Source: Energy Web Atlas.

Planned pipelines. According to the Energy Web Atlas, several midstream companies are planning new pipeline infrastructure and expansions to develop additional infrastructure, to meet takeaway demand in the Permian basin, Fig. 3. Some major planned pipeline projects include: • Phillips 66 and Andeavor have proposed the Gray Oak Pipeline (Fig. 4) that will run 600 mi from Reeves County, Texas, to Crane County, Texas. The pipeline will provide producers and other shippers the opportunity to secure crude oil transportation from West Texas to the destination markets of Corpus Christi, Freeport, and Houston, Texas. The pipeline will have an initial capacity of 800,000 bopd and a maximum capacity of 1.0 MMbopd. The pipeline is scheduled for completion in fourthquarter 2019. On July 30, 2018, the partners announced that the line will cost $2 billion to build. • Phillips 66 has proposed the Reeves-Odessa Origination Project (Rodeo Pipeline) that will run 130 mi from Reeves County, Texas, to terminals in the Odessa-Midland area. The pipeline will have an initial capacity of 130,000 bopd and a maximum capacity of 430,000 bopd. The pipeline is scheduled to start construction in thirdquarter 2018. • Enterprise Products Partners LP plans to convert one of its natural SPONSORED CONTENT

gas liquids (NGLs) pipelines that runs from the Permian basin to the Texas Gulf Coast to crude oil service. This conversion will provide the company with a total crude oil takeaway capacity of over 650,000 bpd from the Permian basin to a crude oil hub in Houston, Texas. Enterprise will convert one of its three existing NGL pipelines that stretch from the Permian basin to the Texas Gulf Coast, which includes the Seminole Blue, Seminole Red and Chaparral pipelines. The conversion is scheduled for completion in first-quarter 2020. • Magellan Midstream Partners LP has proposed the Crane to Three Rivers Pipeline that will run 375 mi from Crane, Texas, to Three Rivers, Texas. The pipeline will have an initial capacity of 350,000 bopd and a maximum capacity of 600,000 bopd. Shippers will

have the option to deliver crude oil and condensate from the Three Rivers area to the Houston area via a new 200-mi pipeline, or to the Corpus Christi area via a new 70-mi pipeline. The project, initially scheduled for completion in fourth-quarter 2019, is currently delayed. • Magellan Midstream Partners LP and Plains All American Pipeline LP have launched an open season to expand the existing BridgeTex Pipeline through enhancements of existing pumps and related equipment in Bryan, Texas. The expansion will add 40,000 bopd of capacity, bringing total pipeline capacity to 440,000 bopd. The expansion in scheduled for completion in second-quarter 2019. • Energy Transfer Partners LP (ETP) and ExxonMobil have proposed the Permian Express 3 Pipeline Expansion that will utilize existing World Oil® / AUGUST 2018 49

TechTalk

Fig. 4. The planned Gray Oak Pipeline in the Permian basin. Source: Energy Web Atlas.

Fig. 5. Epic Oil Pipeline is under construction in the Permian basin. Source: Energy Web Atlas.

Crane, Texas. The pipeline will offer direct service from the Delaware Basin to the existing Longhorn Pipeline, which provides crude oil and condensate transportation service to the Houston and Texas City refining complex and marine export facilities. The pipeline will have an initial capacity of 250,000 bopd and a maximum capacity of 600,000 bopd. The pipeline is scheduled for completion in second-quarter 2019. • Plains All American Pipeline LP is developing the Cactus II Pipeline that will run 515 mi and connect to the existing 310-mi Cactus Pipeline System. The pipeline will run from Orla, Texas, to Corpus Christi, Texas, and will have a capacity of 575,000 bopd. The expansion is scheduled for completion in fourth-quarter 2019.

Potential obstacles. While many pipe-

pipelines from the Midland and Delaware basins to Nederland, Texas. The expansion will provide producers with new crude oil takeaway capacity to multiple markets, including the 26-MMbbl ETP Terminal in Nederland. Phase I of the project went online in fourth-quarter 2017 and has a capacity of 100,000 bopd. Once all phases are complete, the expansion will add 300,000 bopd of capacity to the existing network.

Pipelines

under

construction.

According to the Energy Web Atlas, several midstream operators have started construction already on new pipeline infrastructure and expansions in the Permian basin, with many of them expected to go online in 2019. Some major pipeline projects in development include: • Epic Pipeline Co. LLC is developing the EPIC Crude Pipeline (Fig. 5) that will run 700 mi from Orla, Texas, to Corpus Christi, Texas. The pipeline will provide takeaway 50 AUGUST 2018 / WorldOil.com

capacity from the Permian and Eagle Ford basins to both refining and export markets in, and around, Corpus Christi, Texas. It will run parallel with the previously announced EPIC NGL Pipeline. That line will have an initial capacity of 590,000 bopd and is scheduled for completion in second-quarter 2019. As of late July 2018, Epic had successfully completed its first open season for the project. • Andeavor is developing the Conan Crude Oil Gathering Pipeline System that will run 130 mi from Lea County, N.M., to a proposed terminal in Loving County, Texas. There, the gathering system will interconnect with long-haul pipeline carriers. The pipeline will have an initial capacity of 250,000 bopd and a maximum capacity of 500,000 bopd. The gathering system was scheduled for completion in mid-2018. • Magellan Midstream Partners LP is developing the Wink Pipeline that will run 60 mi from Wink, Texas, to

line projects are on the horizon in the Permian basin, some have experienced delays, due to lack of shipper support that could prevent the pipelines from ever breaking ground. Magellan Midstream Partners LP announced that they are putting the proposed 375-mi Crane-to-Three Rivers Pipeline on hold, after an unsuccessful open season failed to gain shipper commitments. The pipeline could provide a potential 600,000 bopd of takeaway capacity in the region, but the company stated that it won’t proceed with the project until it receives satisfactory interest from potential customers. In May, Buckeye Partners LP unexpectedly cancelled an open season for the proposed 513-mi South Texas Gateway Pipeline. The line would run from Wink, Texas, to Corpus Christi, Texas, and deliver over 600,000 bpd of crude oil and condensate from the region to U.S. Gulf Coast markets. The company has yet to release a reason for the project’s sudden suspension and has, instead, announced plans to focus on the proposed South Texas Gateway Terminal in Corpus Christi. While no plans have been made public that either the Crane-to-Three Rivers Pipeline or South Texas Gateway Pipeline are cancelled, the prospect of these shelved projects being built doesn’t seem promising. Editor’s note: The Energy Web Atlas is a product of Gulf Energy Information, the parent company of World Oil. SPONSORED CONTENT

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SHALETECH REPORT / PRACTICES & ADVANCES

Enhanced understanding improves “child well” performance In U.S. shale fields, operators are attempting to improve infill well performance. In the Eagle Ford, child wells now account for about 75% of new completions. Infill drilling is ramping up in the Permian, which hosts half of all U.S. drilling.

Fig. 1. Outlines of 10 unconventional plays selected for the parent/child well interaction study. CANADA

Bakken

WA

MN SD

ID

OR

WY

NV

UT

Woodford

Wolfcamp and Bone Springs

TAO XU, DAN SHAN and JASON BAIHLY, Schlumberger

The transition to infill development in the shale fields has been challenging, and production rates are highly variable and unpredictable. This is due to depletion effects of the parent well that can cause fracture hits and interwell communication among child and parent wells (SPE 174902). In reservoirs with significant depletion caused by parent wells, predicting performance of new infill wells can be difficult. Although operators expect infill wells to perform comparably to, or better than, existing parent wells, the reality is that infill wells often produce below established offset parent well decline curves. This scenario adversely impacts future reserve estimates and, ultimately, field economics. BASIN STUDIES

To increase the understanding of the output relationship between parent and child wells, the service provider studied 3,000 fracture hits across five major unconventional plays, Table 1. The analysis was performed to better understand parent well challenges in each individual field (SPE 180200). The study determined that fracture interference had different effects in different basins, in terms of severity and whether the interference was positive or negative to parents. In most

NM

Barnett

OK

TX

VT

MI NY

IA KS

CO

CA

ME

WI NE

Niobrara

AR

 GARRETT LINDSAY, GRANT MILLER,

ND

MT

IN

IL

OH

MO TN

MS

Haynesville

AL

INFILL PERFORMANCE

Historically, there has been little research on basin-wide trends for infill well performance, on average, compared with their corresponding parent wells. To better understand child well performance issues, the service company conducted a comprehensive study in 2017 (SPE

NJ DC MD

Gulf of Maine

DE

NC SC GA

LA

NORTH ATLANTIC OCEAN

FL

Gulf of Mexico

Table 1. Fracture hit breakdown across five major unconventional plays. Bakken Eagle Ford Haynesville Positive hit - Long term 17% 9% 20% Positive hit - Short term 33% 14% 38% Positive hit total 50% 24% 58% No change 35% 36% 24% Negative hit total 15% 41% 19% Negative hit - Short term 7% 13% 5% Negative hit - Long term 6% 17% 5% Shut-in post offset hit 2% 10% 9% Instances included 649 1,210 366 Original No. of instances 827 1,561 449 Instances with invalid data 178 351 83

cases, fracture hits on existing parent wells resulted in a positive or no change of trend in the production of the parent well. However, in the Woodford and Niobrara, fracture hits on existing parent wells resulted in a negative or no change trend in the parent well. The Eagle Ford was split, with an approximate 50/50 chance that a fracture hit will be positive or negative to parent well production.

WV VA

Eagle Ford M E X I CO

PA

KY

Fayetteville AR

Marcellus

NH MA CT RI

Woodford 2% 2% 4% 32% 64% 20% 41% 3% 259 283 24

Niobrara 0% 6% 6% 38% 56% 19% 31% 6% 32 49 17

189875) across 10 major U.S. unconventional plays, including Bakken/Three Forks, Barnett, Bone Springs, Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Wolfcamp and Woodford, Fig. 1. The study used public data from IHS Enerdeq, reported through late 2016, to design a spatial, statistical approach with key production indicators, to evaluate the difference in production performance between the original parent well and new child wells. While the study was not intended to present a specific protocol for accurately predicting infill well production, it does use a logical workflow that provides scientific-based inferences on production performance of infill wells versus pre-existing parent wells. The conclusions present alternative strategies and World Oil®/AUGUST 201853

SHALETECH REPORT / PRACTICES & ADVANCES Fig. 2. The study suggests longer laterals and larger frac volumes are required in offsets to achieve production rates similar to parent wells.

100 B12 volume

90

B12 volume/lbm/ft

80

Iterations, %

70 60 50 40 30 20 10 0 Child

Parent Wells Bakken

Child

Parent Wells Barnett

Child

Parent Wells Bone Springs

technologies that may increase the potential of underperforming infill wells. The study examines the effects of reservoir depletion and fracture behavior on infill production. These factors have become increasingly important, as operators push the envelope of unconventional development to maximize return on investment. Fluctuating commodity prices and service costs, and the economics of single-well versus pad drilling, must be considered when calibrating expectations. Statistical moving-window workflow. To consistently evaluate infill/par-

ent well production, a statistical movingwindow workflow was implemented to study thousands of wells in a relatively short time-span. The approach analyzes each well, compared to all surrounding wells, within a specified three-dimensional radius to enable evaluation in three directions. Distances between wells were measured from the midpoints of laterals, as identified from public deviation survey data. This method takes into account different landing zones for the laterals, especially in plays with thick or stacked pay intervals, such as the Permian’s Bone Springs and Wolfcamp. Each moving-window iteration included a preexisting parent well and new child well(s) within a specified radius. Parent wells were defined as having a minimum of two years of production history with at least one child well that produced a minimum of one year. These cutoffs were implemented to allow adequate time to 54 AUGUST 2018 / WorldOil.com

Child

Parent Wells Eagle Ford

Child

Parent Wells Fayetteville

Child

Parent Wells Haynesville

Child

Parent Wells Marcellus

observe depletion effects. A 1,000-ft radius was studied primarily for each moving window, followed by 1,000-1,500-ft, 1,500-2,000-ft and 2,000-2,500-ft radii, to investigate changing effects with distance. For wells with thick or stacked pay, a 100-ft limit was assumed in the depth direction, even though vertical communication may be shorter or longer, depending on fracture height, vertical permeability or fracture conductivity. A best, consecutive 12-month volume (B12) was calculated for every well as a comparative tool for each iteration. For dry gas basins, a B12 gas volume was calculated, and for oil basins, a B12 oil volume was determined. A B12 boe volume was calculated for basins with significant gas and oil production. The parent well B12 volumes were compared to the average B12 volumes of the child well(s) in each iteration, and then compared at different distances. To adjust for other possible drivers, production was normalized by total proppant pumped and lateral length for each iteration, as these were accessible through public sources. Only producing wells with reported lateral lengths and total proppant volumes were included in the data set, to ensure an accurate comparison when looking at raw versus normalized volumes. The study assumed that the geology and reservoir properties in each moving window were the same. Also, because the information is not available in public sources, the study did not consider all completion components, such as open-

Child

Parent Wells Niobrara

Child

Parent Wells Wolfcamp

Child

Parent Wells Woodford

hole versus cased-hole, number of stages, perforation cluster spacing and fluid type, differences in flowback, production practices or artificial lift techniques. Additionally, production indicators used as the comparative tool in the analysis were not intended to, and should not be used to, directly correlate with differences in expected reserve volumes. Trends across basins. Despite reservoir heterogeneity and variations in the number of iterations, ranging from 31 for the Bone Springs to 1,661 for the Eagle Ford, the study identified key trends across each specific basin, Fig. 2. The depletion effects from parent wells and intercommunication between child wells can result in lower-than-expected production from child wells. A first glance at a basic B12 production comparison indicates there is an approximately 50% chance that a child well will outperform a parent well. However, adjusting production for available completion information suggests that larger proppant volumes and longer laterals in child wells may be necessary to achieve similar production rates to the parent wells, which can have negative economic implications for operators. Using 1,000 ft as the radius of investigation, parent well B12 production slightly outperforms child well(s) in seven plays (Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Wolfcamp and Woodford), while in the Bakken and Barnett formations, there is roughly an equal chance that the parent

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SHALETECH REPORT / PRACTICES & ADVANCES form the offset. However, when normalizing B12 production lateral length and proppant volume, parent wells outperform child wells 70% to 80% of the time. These trends strengthen the implication that operators have been successful at increasing the potential of infill wells by pumping larger treatment sizes; however, it may increase the risk of detrimental fracture hits on parent wells while increasing the costs associated with child well completions.

Two of the biggest drivers behind poor child well performance are the depletion effects of the parent well and the interwell communication between offsets, as they compete for the same resources. One would expect that the child wells further from the parent well would be better performers; however, this was difficult to conclude from the evaluation, because it was masked by the effect of the interwell communication between child wells.

PERMIAN BASIN

With increased infill drilling in the Permian basin, operators will soon be encountering the above outlined issues. One of the examples is the Bone Springs, which flagged 31 parent/child well sets. Here, the situation is unique, in that child wells perform better than parent wells 65% of the time on a non-normalized basis at 1,000-ft radius. Normalized proppant volumes reflect the same trends as in other plays, meaning that a given proppant concentration doesn’t deliver as much oil in the child well as it did in the parent well. However, because proppant loading increased, likely leading to improved child well performance, child well production on a non-normalized basis is on par with, or better than, that of the parent wells across the data set. At first glance, the distances between parent and child wells doesn’t appear to be as significant in the Permian as in the other basins. However, this may be because there are fewer iterations, and therefore less data for evaluating parent versus child wells, or because the average well spacing between child wells is larger than in the other basins. It is important to note that the completion design has improved continuously in the Bone Springs since 2012, so each generation of wells—regardless of child or parent—performs better than the previous generation. The Bone Springs is fairly new compared to other basins; therefore, the depletion effects aren’t as severe, and major child development hasn’t begun. Well performance numbers are flipped at 1,000-ft spacing in the Wolfcamp play, which has 82 parent/child sets. Parent wells perform better than the child wells 66% of the time when non-normalized, and nearly 80% of the time when production is normalized with proppant volumes and lateral length. Time, an indicator of depletion, appears to play an important role, because after more than 24 months between child well and parent well drilling, there is a significant drop in child well production versus parent well production. As in the Bone Springs, proppant volume increases over time in the Wolfcamp likely account for production improvements observed in the parent wells. IMPROVING THE ODDS

Engineering experts are working on technologies and best practices that mitigate the effects of depletion and interwell communication on child well 56 AUGUST 2018 / WorldOil.com

PRACTICES & ADVANCES / SHALETECH REPORT ing outward from there also could reduce the potential negative impact caused by parent well depletion on non-adjacent child wells. • Optimizing completion designs by modeling the depletion effects can be a viable predictive tool for infill drilling, and proppant volumes and

well spacing can be adjusted accordingly to maximize the return on capital deployed, as operators don’t want to over- or undercapitalize an area. • Additionally, the use of near-wellbore and far-field chemical diversion techniques can help increase

Fig. 3. Fracture geometry service increases child well production, up to 53%.

160,000 140,000 120,000 Cumulative oil, bbl

performance. They also are improving reservoir models to better account for the real impact of infill wells to fully understand critical timing, spacing, and job sizes, to solve these dynamic challenges related to field development planning in unconventional basins. The following strategies are suggested to improve infill development campaigns: • From a purely technical standpoint, drilling and completing all wells in a given area at the same time would be ideal, but is economically and operationally unrealistic, given production requirements for holding leases in U.S. unconventional plays. However, completing wells next to each other on lease boundaries to equalize the drainage patterns could minimize the depletion effect when infill wells are completed. It is also important to recognize that timing of the infill drill will impact the child well performance, so job designs and even well spacing will need to change, as time to infill drilling changes. Completing the well closest to the parent well and then work-

C

100,000 80,000

B

53% Up to 53% improvement over local cumulative oil type curve

60,000 40,000 20,000 0

0

1

2

3

4

5

6 7 Production, months

8

9

10

11

12

PLUG-AND-PLAY SIMPLICITY IN THE FIELD. RELIABLE CONNECTIONS DOWNHOLE. PERFORATING

SYSTEM

RETHINK YOUR PERF OPERATIONS. CJENERGY.COM/GAMECHANGER World Oil® / AUGUST 2018 57

SHALETECH REPORT / PRACTICES & ADVANCES child well production while limiting interwell communication. In the Eagle Ford, the Broadband Shield* fracture-geometry control service has been successful in encouraging fracture propagation in new undrained rock of child wells, while reducing negative fracture hits on the parent wells. Figure 3 shows a 15%-to-50% increase in child well production when using BroadBand Shield service versus the average of the other child wells in the area (URTeC 2670497). • In some cases, refracturing the parent well before completing the offset child wells can boost production in both the parent and child wells. • Enhanced oil recovery (EOR) also may increase production in both the parent and child wells. EOR applications using natural gas injection have delivered positive production results in the Eagle Ford for EOG; nevertheless, the technique needs further testing in the unconventional sector.

*Mark of Schlumberger GARRETT LINDSAY is a senior production engineer for Schlumberger. His 11 years of experience have been focused on unconventional plays across North American and international basins. His experience includes production/completion evaluations, integrated reservoir studies, refracturing, and candidate selection. Mr. Lindsay has a BS degree in petroleum engineering from Texas A&M University. GRANT MILLER is a production engineer with five years of experience in North American and international plays. His focus has been on unconventional and tight reservoir production analysis, with emphasis on completion optimization and production enhancement in existing wells. Mr. Miller holds a BS degree in petroleum engineering from the University of Texas at Austin. TAO XU is a production stimulation engineer with Schlumberger. His five years of experience have been in technical and sales roles, focused mainly on North American unconventional hydraulic fracture modeling, completion and production optimization, and operations. Mr. Xu

has a BS degree in petroleum engineering from China University of Petroleum and a MS degree in petroleum engineering from the Colorado School of Mines. DAN SHAN is a principal reservoir engineer with Schlumberger. She has 17 years of industry experience, primarily in reservoir simulation and production analysis for conventional and unconventional resources. She holds a BS degree in chemical engineering from Tsinghua University, China, and an MS degree in petroleum engineering from the University of Texas at Austin. Mrs. Shan is a registered Professional Engineer in the State of Texas. JASON BAIHLY is a commercial and risk assessment manager for Schlumberger. In this role, he develops alternative business models to help operators perform projects, with minimal impact on their capital budgets for new, drilled-but-uncompleted (DUC), and refracturing applications. Mr. Baihly has more than 15 years of experience focused in tight rock plays, including sands, carbonates and shales. He has also worked to deliver pressure pumping services, completions, consulting services, asset management and integration. Mr. Baihly has a BS degree in civil engineering from the South Dakota School of Mines and Technology and an MSc degree in petroleum engineering management from Heriot Watt University in Edinburgh, Scotland.

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58AUGUST 2018/WorldOil.com

SHALETECH REPORT / PRACTICES & ADVANCES

Copper alloy coupling reduces rod failures, boosts well efficiency An advanced sucker rod coupling is optimizing virtually every aspect of rod lift efficiency, and increasing productivity in unconventional plays.

Fig. 1. The copper alloy couplings reduce overall friction on sucker rod strings.

ŝŝCAROLYN CURRAN, DIANE NIELSEN, WILLIAM NIELSEN and RICHARD CASH, Materion Corp., USA

The deviation and side loading in deep, unconventional wells presents unique challenges for sucker rod pumping, when rods flex during the downstroke of the pumping unit and sucker rod couplings wear into the inner wall of the production tubing. For example, a well pumping at 6 strokes/ min. will cycle 8,640 times per day and any given point on the sucker rod string can travel up to 23 miles/day. With so much potential contact between the sucker rod string and production tubing, there is ample opportunity to reduce frictional drag and system loading. Tubing leaks and coupling failures have historically accounted for nearly half of the failures in rod pump wells, with the root cause of these leaks frequently identified as coupling on tubing wear. COPPER ALLOY COUPLING

A standard spray metal coupling is abrasive to steel production tubing because of its hard-nickel coating. While standard “T” couplings are not coated, nor as hard as spray metal couplings, tubing wear occurs by a steel-on-steel galling mechanism. The T couplings also are more susceptible to corrosion. To alleviate these effects and associated tubing wear, Materion developed a new low-friction, high-strength copper alloy. The ToughMet coupling is made of highly durable spinodal bronze composed of copper, nickel and tin, Fig. 1. The specialized metallurgical composition is naturally anti-galling to steel production tubing. It features high-impact strength, offers improved corrosion resistance and can reduce overall friction on sucker rod strings. Reducing workover frequency. The new sucker rod couplings were successfully qualified initially in deviated wells with higher-than-average rates of failure. Hess Corp., one of the largest producers in the Bakken, more than tripled its mean time between failures after introducing the couplings to deviated sections of their wells. The company went on to include the couplings in its standard production practice. Permian basin. Discovery Natural Resources LLC operates more than 1,000 wells in the Permian basin. In some of their extremely deviated wells, rod-on-tubing wear was causing fail-

ures every 60 to 90 days. After introducing the copper alloy couplings, the company reported one well running for more than 385 days without failure. Clearly, both operators were able to significantly reduce workovers and effectively improve production efficiencies by utilizing a sucker rod coupling that actively mitigates coupling-on-tubing wear. ADDITIONAL EFFICIENCY GAINS

In addition to reducing workover costs in deviated wells, there is a wide range of unanticipated benefits of using the new couplings. Identifying improvements in well performance, in addition to reduced tubing failures, was of interest to eight separate operators. Between these different companies, 11 wells are running entire sucker rod strings of ToughMet couplings to investigate and quantify benefits observed by reducing frictional drag in the well. After analyzing their data, the following observations and predictions were made on wells modified to run entire sucker rod strings of the new couplings, where no other design alterations are made: • 88% of wells experienced an increase in oil production. • 93% of wells experienced increased downhole stroke. Downhole stroke is usually much shorter than the stroke length measured at the surface, because rods stretch, contract and deflect. Lowering frictional drag on the sucker rod string allows it to travel more smoothly and with more velocity, translating into greater downhole stroke. Capturing more pump stroke improves compression and allows the well to operate at maximum capacity. • 87% of wells experienced decreased fluid level above the pump. Decreasing the fluid level is desirable and indicates efficient sucker rod pumping. World Oil® / AUGUST 2018 59

SHALETECH REPORT / PRACTICES & ADVANCES Fig. 2. Probability chart showing population percentiles for determining the coupling’s potential impact on production rates. It’s 88% probable that a well will have improved oil production with a mean increase of 37%.

99 Mean St Dev N AD P-value

80 70 60 50 40 30 20

0.3732 0.3221 10 0.207 0.816

75 50 25

-50

0 50 Change in oil production,%

5

90.3 %

59 %

15.7 % 0% -100

37.3 %

12.35

10 5 1

95

15.6 %

Well popuation,%

95 90

100

150

Fig. 3. Probability chart showing population percentiles to predict the coupling’s potential impact on gearbox loading. It’s 98% probable that a well will experience gearbox load reduction with a mean decrease of 16%.

99 Mean St Dev N AD P-value

Well popuation,%

95 90 80 70 60 50 40 30 20

-0.1606 0.08154 15 0.202 0.850

97.5 95

75 50 25

10 5 -100

-40

-30 -20 -10 Change to gear box loading,%

-3 % -0 %

-11 %

-16 %

-22 %

-29 %

1

5 0

10

• 81% of wells experienced improved pump fillage. Operation is more efficient if the pump is filled with fluid, which lowers electrical power usage. • 98% of wells experienced gearbox load reduction. Loading on the gearbox is related directly to power requirements necessary to operate a well on rod pump. The gearbox drives the polished rod and provides the torque to rotate the counterweights. • 95% of wells experienced peak polished rod load reduction. The polished rod holds the entire weight of the sucker rod string below, the weight of the fluid and the added inertial effects as the unit reciprocates. Frictional drag on the sucker rod string increases the load on the polished rod. • 93% of wells experienced improved system efficiency. Higher system efficiency indicates the well is using less power for more fluid production, and the costs of operation are directly related to this metric. The data support the hypothesis that the new copper alloy couplings not only reduce tubing wear, but also minimize frictional drag on the sucker rod string. When the sucker rod string can travel more smoothly, wells are able to capture lost downhole stroke and return more efficient fluid production. 60 AUGUST 2018 / WorldOil.com

The couplings also may extend the life of surface equipment and sucker rods, as indicated by smoother pump cards and reduced loads on the gearbox and polished rod. Minimizing frictional drag will likely improve a well’s operating efficiency and deliver associated power savings. The following case studies detail observations made to improvements in overall efficiency when running entire sucker rod strings of copper alloy couplings. Case study 1. A Permian basin operator (B), installed 126 couplings in Well 1 during August 2017. Through April 2018, the well experienced overall improved oil production and downhole stroke, while pump fillage stayed static before, and after, coupling installation. Oil production increased an average 35 bpd to 145 bpd, compared to 110 bpd with spray metal couplings. Likewise, downhole stroke length increased by an average of 49 in. to 175 in., compared to 126 in. with spray metal couplings. Loads on the surface equipment also reduced significantly. Gearbox loading was designed to run at 76.5% of its suggested maximum load and averaged 74.6% with the spray metal couplings. After the new couplings were installed, the average gearbox load averaged 63%, which was 12% lower than the spray metal average or 14% below the designed target. Average peak polished rod load decreased by over 8,500 lb, a 27% improvement. This well continues to run the couplings, but failed after 8.3 months in May 2018, due to a rod part. After 2,560,320 cycles, the couplings showed minimal wear, and the serial numbers on the faces were still visible. All of the couplings were reinstalled. Case study 2. A Permian operator (B) installed an entire sucker rod string, consisting of 186 couplings, into horizontal Well 2 during August 2017. This well ran on rod pump, with both spray metal and T couplings, prior to installing the new-style copper alloy couplings. Historically, it had failed every 6 to 10 months, due to a tubing leak or rod failure. During workover, the same 1¾-in. pump was rebuilt and reinstalled and fiberglass rods, tubing rotators and rod rotators and guides were maintained. About 50% of the L80 production tubing was also replaced during the workover. The pump was set in the curve at 6,656 ft and side loads average 240 lb. The designed stroke length was 130 in., and the well is running at seven strokes per min. on a variable speed drive. After the new couplings were installed, this well has been running for more than a year without incident. Well efficiency improvements. During the first six months of operating with the new couplings, oil production averaged 130.5 bpd, compared to 110 bpd prior. When Well 2 was running with spray metal and T couplings, the downhole stroke length was 132 in. versus a 130 in. design. After the new full string of couplings was installed, the well’s downhole stroke recorded between 150 in. and 155 in., gaining an additional 18 in. to 23 in. Pump fillage ran between 92% and 99.9%, compared to 90% before. Likewise, loads on the well’s gearbox, as a percentage of its designed max load, changed from 84% down to 59%64%, suggesting possible decreased power usage and potential extended gearbox life. Lastly, the peak polished rod load averaged more than 3,000 lb below the historical average. In April 2018, the operator indicated that the well’s fluid levels were rising because of fracing nearby, therefore data

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SHALETECH REPORT / PRACTICES & ADVANCES obtained during this time period have not been used to evaluate the performance of the well. Case study 3. In January 2018, a different West Texas operator (C), installed an entire sucker rod string consisting of 456 copper alloy couplings in an 11,411-ft Permian vertical Well 3. This is a lower-producing well that previously ran spray metal and T couplings. Historically, its failure frequency was an average 119 days, due to various failure modes. Upon workover, the same 1¼-in. pump was reinstalled, and no tubing rotators, rod rotators, or rod guides were implemented to maintain the same well design. Well efficiency improvements. After a month of run time, reduced friction and loading data were observed alongside increased production, effective net stroke length and pump fillage. The operator noted the following comparisons between the well’s prior performance with spray metal and T couplings and the current performance with ToughMet couplings: • Oil production increased from 19 bpd to 22 bpd (16%). • Gearbox loading declined from 87% to 77%. • Pump stroke improved from 70 in. to 77 in. (10%). • Pump fillage increased from 80% to 100%. • Pump friction lessened from 987 lb to 776 lb (21% decrease). • Pump volume efficiency increased from 55% to 64%. • Structural unit loading was 2% lower with copper alloy couplings. • Maximum rod loading was 4% lower with copper alloy couplings. After two months of run time, the variable frequency drive was removed and replaced with a pump off controller, because the well started to fight gas interference. Now, the well shuts down and idles whenever pump fillage falls below 60%, to allow the wellbore to fill. After three months of run time, the operator reported that oil production averaged 19 bpd, which is equal to the historical production rate. However, because the well is now operating just 14.6 hr/day, compared to 24 hr/day with the previous design, fluid production cannot be validly compared. Despite this, other benefits were measured: Fig. 4. Probability plot with population percentiles to deduce the coupling’s potential impact on average system efficiency. It’s 93% probable that a well will experience improved system efficiency with a mean increase of 37%.

99

Well popuation,%

95 90 80 70 60 50 40 30 20

Mean St Dev N AD P-value

0.3660 0.2524 11 0.455 0.216

95

75 50 25

10 5 -50

78 %

54 %

37 %

0% 20 %

-5 %

1

7.5 5 0 50 100 Change to average system efficiency, %

62 AUGUST 2018 / WorldOil.com

150

• Downhole stroke improved even further to 80-85 in. from 70 in. Similar wells in the field were only capturing a 70-75 in. pump stroke. • Pump fillage was 100% when the well was not affected by gas interference. • Pump volume efficiency improved to 76%, compared to 55% before. • Structural unit loading decreased to 85%, compared to 90% before. • Gearbox loading increased slightly to 81% but was still below pre-copper alloy averages. • Maximum rod loading decreased to 97%, compared to 114% before. In April 2018, Well 3 failed due to a broken rod likely caused by paraffin build up. During workover, the couplings showed no wear and were reinstalled. Performance updates will be gathered and averaged over a longer period, as the well continues to run. Case study 4. In February 2018, another Permian operator (D) installed 286 copper alloy couplings in a 9,200-ft horizontal well. Prior to new coupling installation, Well 4 was operating at 6 SPM on a variable speed drive with spray metal couplings, fiberglass and steel rods and L80 production tubing. This well did not use rod rotators or rod guides. The operator noted that this well fights gas interference and experiences rod buckling in the bottom section of the sucker rod string. To help alleviate gas interference issues, Well 4 is designed to shut off when pump fillage falls below 70%. Historically, the daily well run time recorded between 2045%, pump fillage was 81-85% and oil production was 26 bpd. Gas averaged 35 Mscf per day and water averaged 25 bpd. Upon workover, 17 spray metal couplings could not be broken out. However, no other design changes were made to the well, when the new-style couplings were implemented. Well efficiency improvements. After 2½ months of operation, the operator was surprised to see daily run time double to 6080% for Well 4. The run time/day increased with the copper alloy couplings, because typical pump fillage was 99.5% and thus remained above the 70% trigger point for shutting the well off more often. The operator suggests that the low-friction couplings have helped to alleviate the buckling in the bottom section of the rod string, allowing for improved compression in the pump, better plunger movement, greater pump fillage and a faster recovery rate. The oil production rate increased 15% to 30 bpd. Gas and water averaged 49 Mcfd and 23 bpd, respectively. The operator noted that Well 4 had not produced 30 bpd since October 2017. Case study summary. The early results from these field trials show that changing out standard couplings to copper alloy couplings has a positive impact on well performance. The statistics suggest that the new couplings have increased or accelerated the oil production rate 21% on average in these wells. The statistics also confirm the hypothesis that the copper alloy couplings allow wells to capture extradownhole stroke length, increase pump fillage, decrease fluid levels, minimize gearbox wear and alleviate loads on the sucker rod string. Three probability charts express the likelihood that a well will experience improved performance metrics when installing the new copper alloy couplings, Figs. 2, 3 and 4. This

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SHALETECH REPORT / INNOVATIONS AND TECHNIQUES summary of field data enables operators to graphically visualize the effects of reducing friction in their wells and the probability that they will capture the documented benefits of the new couplings. Although this study reports on the initial findings of field trials that targeted well optimization by using the new couplings, statistical analysis based on a normal distribution model suggests that 93% of wells will experience improved system efficiencies. The probabilities of increasing revenue, while simultaneously reducing cash OPEX and CAPEX, eclipse the minor marginal cost of adopting this technology. CONCLUSION

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To date, 28 operators have installed ToughMet couplings in more than 900 wells in multiple shale fields, including the Bakken and Permian basin. The case studies demonstrate that, in addition to reducing failure rates and avoiding costly workovers, the couplings have a measurable effect on a well’s performance. Each well is operating more efficiently with improved sucker rod string movement, greater downhole stroke, increased pump fillage and accelerated fluid production. In addition, simply switching coupling materials has resulted in decreased loads on the gearbox and polished rod, which suggests that surface equipment life can also be extended. Performance step-change. Switching sucker rod couplings from standard T or spray metal to the copper alloy couplings achieved the following (on average): • Oil production increased 21%. • Downhole stroke increased 23%. • Pump fillage increased 9%. • Peak polished rod load decreased 16%. • Decreased alternating stress on the polished rod by 16%. • Gearbox loading decreased 16%. • Fluid level above the pump reduced 28%. • System efficiency increased 37%. ACKNOWLEDGEMENT The authors want to thank the operators who are participating in this project. From a business perspective, having operator derived field data from which to draw risk-adjusted financial expectations is essential. CAROLYN CURRAN is a sales engineer for Materion Performance Alloys, responsible for North Dakota and Montana territories. Ms. Curran joined the company in 2016 as a customer technical service engineer. She holds a BS degree in materials engineering from Brown University, Rhode Island. DIANE NIELSEN is the global oil and gas market manager for Materion Performance Alloys. Mrs. Nielsen joined the company in 1990 as a field sales engineer responsible for Texas, Oklahoma, Louisiana and Kansas. Mrs. Nielsen holds a BS degree in metallurgy and materials engineering from Lehigh University, Pennsylvania. WILLIAM NIELSEN is vice president/general manager for Materion Performance Alloys. Mr. Nielsen’s career in the materials industry spans more than 45 years, during which time he has invented, developed and commercialized new materials for use on aircraft, oilfield and mining equipment. Mr. Nielsen holds a BS degree in metallurgical engineering from Case Western Reserve University, Cleveland, Ohio. He also attended the Weatherhead School of Management at the same university. RICHARD CASH is a field sales engineer for Materion Performance Alloys. He joined the company in 2015 and is responsible for oil and gas application development in Texas, Okla., La. and Kansas. Mr. Cash’s experience in the materials industry began in 2005. He holds a BA degree in marketing from Sam Houston State University, Texas.

64 AUGUST 2018 / WorldOil.com

DRILL PIPE

Fourth-generation drill pipe connection enhances land drilling, reduces pipe maintenance A two-year R&D drilling program addresses a new onshore paradigm, enhances performance and improves economics.

Fig. 1. The new Delta connection, with more threads engaged at stab, and less rotation to engage shoulders, results in reduced thread damage through the service life of the connection.

ŝŝGUILLAUME PLESSIS, ANDREI MURADOV, DAN MORGAN, and

STEPHEN FORRESTER, NOV; JEREMY DUGAS and BRENNAN WHITE, Quail Tools

Double-shouldered drill pipe connections developed over the past several decades have seen performance primarily as the driver of growth and change. Each generation saw successive improvements in torque capacity, and streamlining the connections’ profiles addressed the challenges of hole cleaning and hydraulics. More recently, additional development yielded enhancements to fatigue resistance and running speed. These improvements were intended to enable connection use in deviated and extended-reach offshore wells, which had previously been difficult—or impossible—to drill with earlier generations of API rotary-shouldered connections. Since these were enabling technologies, cost was of little concern during this timeframe; the advances in design so dramatically increased performance that their higher cost of maintenance could be justified. As these premium connections began to be deployed onshore, however, maintenance costs became an issue. Factory drilling applications—where drilling and completing wells in extremely short timeframes is critical—demanded a drill pipe connection that was both high-performing and cost-effective, particularly with regard to total cost of ownership over the life of the connection. Intensive use of the existing connection technologies proved that there was room for improvement, especially if the intent was to transition the new connection to land drilling. In response to this issue, National Oilwell Varco (NOV) engaged in a two-year R&D program to develop a high-performance, lower-cost product. The resultant fourth-generation drill pipe connection, Delta, is now in use by various companies across North America, including Quail Tools, which was first to bring Delta to the market. CONNECTION DESIGN AND TESTING

The Delta connection (Fig. 1) had several major design considerations, which took into account the strengths and drawbacks of past generations of connections. User feedback revealed that the torque of second-generation connections (XT) was sufficient for the new connection and that, in some cases, it even exceeded the capacity of existing iron roughnecks and top drives. Tool joint dimensions remained largely the same, as they were acceptable from a fishability and hydraulics standpoint.

Two versions of the new connection—standard and streamlined—were developed to address the varying needs of land drilling. The major focus was on making the new connection more rugged, easier to use and less expensive to maintain. The following were critical components for this goal: • Deeper stabbing and faster make-up for ease of use on the rig floor • The use of relaxed inspection criteria from a dimensional standpoint and a new tolerance for pitting in the less-loaded thread roots sections • More available room for refacing, as this repair is the least invasive and can be performed with portable refacers • Increased bearing surface during spinning, to reduce inuse connection damage and rate of recut. Finite element analysis (FEA) was performed to optimize design parameters and verify stress distribution in the Delta connection. Modeling of extreme manufacturing tolerance conditions determined the connection’s stress distribution, and axial interferences at the shoulders were imposed to simulate torsional make-up. Minimum and maximum make-up torque, as well as external tensile loads, were also simulated. The FEA simulations revealed that the dimensions and tolerance selected for the new connection could adequately handle stress states without exceeding material capabilities. In addition, the FEA results indicated that wider field inspection tolerances could be adopted to reduce repair frequency without compromising the connection’s performance. Two-dimensional axisymmetric models of corresponding connections approximated the number of threads in contact World Oil® / AUGUST 2018 65

DRILL PIPE

between the pin and box at stab. Having more threads engaged than previous connections meant that Delta provided a more even stress distribution, a reduction in stab damage, and elimination of the stabbing guide as a rig floor necessity. The connection’s newly optimized geometry increased total available reface material 50%, permitting additional refaces to take place before a recut was needed, and reduced material loss by up to 30% for face-and-chase repair operations, allowing for more recuts. Laboratory testing validated the design and performance of the Delta connection after the computer simulations were complete. Make and break testing, performed 100 times, allowed NOV to determine the connection’s galling resistance, while torque-to-yield testing validated the connection’s calculated torsional strength. Over the course of testing, the connection was examined every 10 make-and-break cycles to observe the location and severity of damage, and to determine if dimensions remained within field inspection tolerances. No damage was encountered on the shoulders or threads and the dimensions were well within tolerances after the testing. In addition, the number of turns from stab to make-up was reduced to only 6.7 turns on average—far ahead of the 13 turns required by second-generation, double-shouldered connections—and torque-to-yield results correlated closely with the connection’s calculated torsional strength. Fatigue testing was performed in a harmonic resonant test machine to compare the Delta connection’s performance versus the second-generation connection under the same bending moment. The new conFig. 2. Torque analysis of the string revealed that a premium connection was needed to deliver proper torque to the drill bit in more challenging wells.

Fig. 3. The result of backreaming in 9⅝-in., 47-ppf casing. The available torque is increased significantly beyond the limits of the NC50 connection when using the Delta connection.

0 2,000

Measured depth, ft

4,000 6,000

Backreaming (Delta 544) Torque limit (Delta 544) Backreaming (NC-50) Torque limit (NC-50)

8,000 10,000 12,000 14,000 16,000

TD-18,394 ft

18,000 15,000

20,000

25,000

30,000 35,000 Torque, ft-lb

66 AUGUST 2018 / WorldOil.com

40,000

45,000

50,000

nection design still outperformed the baseline connection by 243%, under the same bending moment. This enhanced fatigue resistance meant that the threader could forego the process of cold rolling the thread roots with no loss of performance. CONNECTION FIELD TRIALS

Before deploying the new connection in a commercial application, field testing was undertaken to validate that the connection performed as intended. A prototype string of 5-in. drill pipe with streamlined tool joints was produced, and 60 joints of pipe with the new Delta connection (6⅝-in. OD × 3½-in. ID) were sent to be run at NOV’s test rig in Navasota, Texas. The 375-ton, 1,500-hp rig was equipped with NOVOS—a drilling process automation platform—as well as an ST-100 iron roughneck and TDS-11SH top drive. In addition, the stand transfer vehicle arm-racking system was used to handle stands of pipe. A section of drill pipe measuring 1,900 ft was inserted at the bottom of the string that was run on the test rig in this application. A two-phase test program was implemented over the following three months. The first phase was used to qualify other tools, as the pipe was run in the bottom of the string while the rig drilled test wells; the second phase focused on make-andbreak cycles. At the end of testing, the connections were to be inspected to determine how well they withstood field service. Three directional test wells, each with a dogleg severity high enough to expose the prototype drill pipe, were drilled for the program. The drill pipe was subjected to strenuous use during the testing period, with continual making and breaking of connections and manipulation in and out of the well. The Delta connection was tested, using the highest strength tool joints commercially available, and the connection was exposed to the highest make-up pre-load, applying the extended maximum make-up torque (corrected by a friction factor of 1.15) of 79,000 ft/lb. For comparison, an API NC50 connection for the size and grade of pipe used has a maximum makeup torque of 38,000 ft/lb. Rig personnel were instructed not to take extra care when running the connection, and to avoid using a stabbing guide. The desire was not to expressly mimic real drilling conditions, but rather to put the connection through the most adverse conditions possible. A comparative spinning test also was run, using the same iron roughneck, to evaluate make-up speed of the new connection versus the second-generation connection. The second-generation connection required more rotations to shoulder and took 8 sec to make up; the Delta connection made up in 4 sec. When the field trials were completed, the used drillstring components were re-inspected. After cleaning the connections to ensure proper visibility of the threads, make-up shoulders, and seal surfaces, a visual inspection was carried out. The field procedure called for extremely stringent inspection of the primary and secondary make-up shoulders (seal faces and internal torque stop, respectively), as well as thread surfaces (flanks, crests and roots) and thread profile. Though there was some handling-related impact damage and minor scoring/galling, these issues were typical of rotary-shouldered connections and not of concern. A dimensional inspection followed the visual inspection. Ultimately, both visual and dimensional integrity were maintained. Despite running the connections under intentionally harsh operating conditions and exposing the pipe to an unprecedented amount of make-up torque, there was virtually no damage to the connec-

DRILL PIPE

POST-TRIAL DEPLOYMENTS

The new connection has been used already in several fields across the U.S. for varying operator-defined reasons, with each connection size offering its own particular utility. Torque analysis (Fig. 2) revealed that a premium connection was necessary on longer laterals to deliver more torque to the drill bit. The general benefit of having a higher make-up torque with a slimmer profile has been to allow operators to exceed their prior limitations. A prime example is the use of 5½-in., 21.90-pounds per foot (ppf) Delta 544 where 5-in., 19.50-ppf NC50 was used previously. While the connections have the same tool joint OD—and therefore the same fishability—the Delta 544 connection, streamlined for a 5½-in. tube, provides a 64% increase in available torque. Figure 3 shows the result of backreaming in 9⅝-in., 47-ppf casing. Pipe with the Delta connection can be used in the same wellbore, while providing a drastic increase in available torque— the available torque-at-bit for the Delta 544 case is 20,000 ft/lbf, while it is only 5,000 ft/lbf for the NC50 case. This type of analysis has been done routinely in WellPlan by Quail Tool’s technical services division, since the release of the Delta connection. Operators are realizing that they can achieve more available drilling torque without compromising fishability. This is particularly useful for companies that are using rotary steerable systems, or even those rotating while drilling with a motor. Long laterals, now standard in North American unconventional shale

wells, require high torque to rotate the string. Rotating often can be required to reduce the severity of buckling, even if the hole is not being drilled directly by the rotation of the string; that is, there is always a benefit of having higher torque and therefore the option to rotate the string, even if that was not the original plan. The same can be said for the use of 4½-in., 16.60ppf Delta 425 over 4-in., 14-ppf NC40. The standard tool joint OD is the same, but the Delta connection offers a much higher make-up torque. Additional benefits of increasing the tube size include an improvement in string pressure loss and buckling resistance, Fig. 4. The lower pressure loss in the string means more pressure reaches the formation during a fracture, while Fig. 4. String pressure loss, using the Delta connection vs. the NC50 connection. The dramatic reduction in pressure loss means that more pressure reaches the formation during a fracture.

1,400 1,200

String pressure loss (NC-50) String pressure loss (Delta 544)

1,000 Pressure loss, psi

tion. Results indicated such high durability, that new, broader acceptance criteria for the Delta connection were developed.

800 600 400 200 0 100

120

140

160

180 200 220 Pump rate, gpm

240

260

280

300

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DRILL PIPE

increased buckling resistance translates to more weight-on-bit while sliding before causing helical buckling. CONCLUSION

With laterals continuing to increase in length, and challenging wells demanding more robust equipment, a step change in connection technology was necessary. The Delta connection was developed to meet or exceed the performance of earlier connections, while still reducing total cost of ownership. Extensive connection design validation and testing provided valuable insight into performance differentiators, while connection field trials proved the viability of Delta for broader commercial implementation. The Delta connection is performing in fields across the U.S. with an overall recut rate of 3.6% over a sampling base of over 40,000 connection inspections. Field use repeatedly confirms the benefits of using the new connection, as shown in the modeling performed by Quail Tools. In addition to the performance benefits of using the higher strength connection and tube in the same wellbore, Delta helps operators to realize significant reductions in the cost of pipe maintenance, due to fewer connections needing recuts—and a lower price for recuts when required. GUILLAUME PLESSIS joined NOV with the legacy Grant Prideco team in 2008. A graduate of Arts et Métiers Paris-Tech, he has dedicated almost 20 years to drilling tubulars, first as a product engineer and later in various marketing and product management roles. Mr. Plessis has published numerous papers and is active in the industry’s technical committees.

ANDREI MURADOV has worked at NOV for 24 years, most recently as V.P. of engineering for Grant Prideco. He holds a BS degree with honors in petroleum engineering from Gubkin University of Oil and Gas, and he completed the NOV Ventures program at McCombs School of Business. DAN MORGAN uses his more than 36 years of increasing responsibility at NOV—through quality, metrology, engineering—in his current role as director, field service / claims, to serve the company’s global customers at every level. With training in metallurgy, quality, management, leadership, steel processing, and well drilling, Dan is passionate about safely providing quality products and ensuring customer satisfaction. STEPHEN FORRESTER has worked at NOV as a marketing/technical communications writer since 2014. He researches and executes strategic marketing communication and technical writing opportunities to support the company’s businesses. He holds BA and MA degrees in English from the University of Houston. JEREMY DUGAS serves as the technical services manager for Quail Tools. He joined the team in 1996 as a drill pipe inspector and has since held a variety of key positions. In 2009, he managed and led the newly formed Quail Tools deepwater division, where he worked extensively with heavy-duty landing strings and handling equipment. BRENNAN WHITE has worked at Quail Tools as the engineering manager, since 2016, and was a mechanical engineer for the company prior. Mr. White holds a BS degree in mechanical engineering and an MS degree in engineering and technology management. In addition, he is a PhD student at the University of Alabama, studying aerospace engineering and mechanics.

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68 AUGUST 2018 / WorldOil.com

HSE – WELL CAPPING

Precise prediction of hydrocarbon burn efficiency is now possible From the early days of dynamite to advanced well control systems, significant advances have been made in fire suppression and blow out prevention in the oil and gas industry.

Fig. 1. Myron Kinley is known as a trailblazer in the fire suppression industry. He developed many patents and designs for the tools and techniques of oil firefighting.

ŝŝANDY CUTHBERT, Boots and Coots In the early 1900s, gushers were romanticized as symbols of prosperity. In retrospect, blowouts were recognized for their detrimental impact on personnel, assets and the environment, not to mention the loss of marketable resources. In response, well control technologies have evolved significantly over the last few decades, and Boots & Coots has been on the leading edge of those advancements. EARLY TECHNIQUES

Early in the industry, well fires could be extinguished using TNT, which depleted the available oxygen and effectively extinguished the conflagration, Fig. 1. Nowadays, the well is left to burn-off toxic elements, or voluntary ignition is used if the well has not caught fire spontaneously —the use of explosives is now confined to the annals of history. Burn efficiency modeling has matured significantly to determine just how critical it is to burn uncontrolled hydrocarbon emissions. Extensive industry leading research, involving Boots & Coots (Methodology to Predict Hydrocarbon Burn Efficiency of Blowout Flow in a Hostile Environment, SPE paper 062517), now enables precise quantitative prediction of how much is burned, and the quantity of asphaltenes that remain, assisting in determining suitable spill mitigation response. With safety uppermost in the projects undertaken by the company, the work in Iraq after operation Desert Storm saw the introduction of the Athey Wagon as a less

risky means of addressing the wellhead, either by cradling a venturi tube (Instrumented Venturi Tube, Boots & Coots, Patent application #2016-IPM-100655 U1 PCT) to vent the fire away from the immediate vicinity of the wellhead, or by supporting a new wellhead installation. With advances in wellhead operations came the addition of the jet cutter, that could cut through an existing wellhead more safely to prepare it remotely, rather than risk personnel near the blowing well. The cutter (Fig. 2), using a sand and water mixture, has been used by the company in the closer confines of platform fires, where limited space precludes the use of larger tools. The “Oxylance” has also become standard issue in recent years, to make more accurate cuts of the wellhead to prepare for re-heading. RECENT ADVANCES

Focusing on prevention rather than cure, we supply the special services of gate valve drilling technology, hot tapping or a cryogenic freeze service, espe-

Fig. 2. The sand-line cutter uses a sand and water mixture to suppress platform fires, where limited space precludes the use of larger tools.

cially in cases where a well on production encounters problems. Gate valve drilling has progressed to the subsea environment, where we have IP to provide an ROV-driven system for deeper waters, where the environment precludes the use of divers (Deepwater Diverless Hot Tap Unit, Boots & Coots published invention disclosure #2017-IPM paper-101102). Development of software algorithms has led to improvements in well-kill dyWorld Oil® / AUGUST 2018 69

HSE – WELL CAPPING

namics design, such as OLGA ABC and greater accuracy in kick tolerance using DrillBench. Likewise, updates in COMPASS software have allowed the Fig. 3. The RapidCap AFCS 02 subsea capping system uses advanced computation, fluid-dynamic software to accurately model plume force velocities.

firm to stay current with well planning techniques, and personnel have become power users of this industry-standard software, but that hasn’t stopped us from investigating more functional proprietary software designs of our own. Hand-inhand with well kill, is well integrity, which is a preventative approach to well control, and has benefitted from using landmark software, such as StressCheck and WellCAT for casing design. Multiple well control scenarios can now be run in a relatively short timeframe, to determine the best ways to prevent well control incidents, especially in deepwater environments. The difficulty facing more mature wells is determining integrity. Older tubulars in a well must be de-rated, based on longevity and environment. Gas dispersion and radiant heat modeling have become an aspect in the field of incident command and control – knowing how to set-up an incident site and work with local emergency response organizations to potentially move families that might otherwise be downwind of a burning rig, for example. Multi-well pad drilling with 20-ft to 40-ft, center-tocenter well spacing, makes collaborative pre-planning well control essential. Risk mitigation is necessary as a pre-emptive tool, and we have been a proponent of risk evaluation as a progressive evolu-

Fig. 4. The RapidCap AFCS 47 demonstrates landing capabilities in underwater scenarios and is currently undergoing research.

70 AUGUST 2018 / WorldOil.com

tion in applying in-house expertise. The industry has emerged more proactively than it has been in years. The use of carefully constructed well control contingency plans is now regarded as an industry staple in the creation of the overall emergency response plan. The magnetic guidance system (MGT), a tool for magnetic ranging applications, measures vertical and horizontal well separation between a relief well and a target well, within a precision of a few centimeters, for hydraulic interception during the well kill process. The MGT was developed in 1993 as a joint effort between Sperry Drilling and Vector Magnetics of Ithaca, N.Y. In 1999, further development work with rotating magnets was undertaken as another method of determining the proximity between a current well and a target well. Thus, the rotating magnet ranging service (RMRS) was born. The RMRS proximity surveys range from 5m to 15m behind the bit, combined with upgrades for shallow intersection and faster processing (2017). The addition of gyro measurements (2017) represent additional technological developments in relief-well drilling. ELECTROMAGNETIC TELEMETRY

Since 2002, electromagnetic telemetry has seen the largest overall improvement in relief well ranging efficiency, minimizing the time impact and improving overall drilling efficiency (Electromagnetic Ranging Source Suitable for Use in a Drill String, Boots & Coots, U.S. Patent No. 9,534,488 B2). The need for a passive ranging tool that uses acoustic energy has been identified, particularly for real-time surveying. With a range to open hole, there is no ferromagnetic signal, or through salt domes, which otherwise absorb and scatter conventional magnetic ranging signals (Passive Ranging Using LWD Acoustic Velocity Measurements, Boots & Coots, Patent application #PCT/US2015/04940). Similarly, a means to range to a thermal signal, generated by the influx through the formation, is another area of investigation, when there is no steel present to provide a signal (Passive Ranging to a Target Well Using a Fiber Optic Ranging Assembly, Boots & Coots, Patent application #PCT/US2015/56484). We embarked on a subsea source control solution in 2016, and operate an in-

HSE – WELL CAPPING

novative capping stack, employing gate valve technology, a departure from more traditional, unwieldy ram-based systems (Method and System for Rapid Deployment of a Capping Stack, Boots & Coots, U.S. Patent No. 9,222,494 B2). The lighter design of the modular system can be deployed more rapidly to any global incident (Rapid Response Well Control Assembly, Boots & Coots, Patent filing 2016-IPM-100655 U1 PCT), compared to the logistically complex requirements that cumbersome, conventional capping stacks demand. The company is pushing further technological design change improvements (Ball Valve Design Capping Stack, Boots & Coots, Patent application #2017-IPM-101101 U1 PCT). ENTER THE RAPIDCAP

Simulation software is taking the steadfast methods of subsea source control future-forward. Having branchedout into the subsea arena with the introduction of the RapidCap subsea capping system (Fig. 3), Boots & Coots is fast becoming industry leaders in capping stack deployment. Further technological features using ball-valve apparatus have already been submitted as a patent application. Sophisticated computational, fluid-dynamic software can accurately model plume force velocities and determine the veracity of landing a capping stack under any given condition. Multibody interactions between the dynamic positioning deployment vessel, the heave compensated crane deploying the capping stack, the spring force produced by the deployment cable and the 6° of freedom of the capping stack, require massive computing power to produce a suitably high-resolution model accurately, and coupled with dynamic plume force analysis is adaptive rocket science. Additional groundbreaking research into the landing capabilities in both deepwater and shallow-water scenarios, a first in the industry, is being conducted solely at our discretion, Fig. 4. Further investigation into slick propagation and migration from an oil spill, using smoothed particle hydrodynamics, is also being investigated. Predictive programs have existed for some time, but none have the accuracy or fidelity that is now being produced by a partner firm for slick dispersion analysis. Alongside traditional well control methodology, our proficiency uses man-

aged pressure drilling to precisely manage wellbore annular hydraulic pressure. Looking ahead, several field-proven, downhole data measurement technologies are being adapted to improve barrier integrity verification in subsea wells. Also included are wired casing for realtime monitoring of annular pressure/ temperature during casing, cementing and production operations, wireless real-time annular pressure/temperature monitoring and fiber optic sensor measurement across producing formations (Casing/Tubing Annular Pressure/Fluid Expansion Control, Boots & Coots, U.S. Patent No. 9,835,009 B2). IN SUMMARY

Well control has come a long way in the past 40 years. Our firm has grown into a technologically shrewd company that envisions improvements in data telemetry and “smart well” systems, new kick detection techniques and statistical algorithms. Those algorithms develop data trends and significant deviations from the expected measurement values, using sensitive, near-bit and pres-

sure-while-drilling measurements from logging-while-drilling, to maximize the amount of time available to initiate well control and recovery procedures. We have embraced a proactive prevention ethos rather than concentrating on reactive response. But to aid in both facets, it has been imperative to move forward with the times, developing new techniques and innovation. ANDY CUTHBERT, global engineering and technology manager, is a post-graduate of the University of London, Mr. Cuthbert has 34 years of industry experience, and has been involved in projects of ever-increasing complexity. These include the introduction and coordination of new technology and pioneering innovations, such as multilateral completion technology, rotary steerable systems and a gamechanging air-mobile subsea capping stack system. Mr. Cuthbert holds eight patents with more than 10 still pending. He has authored or co-authored almost 30 technical papers for the SPE, IADC, ASME, OTC and the PMI on directional drilling, multilateral technology, contingency well control measures, and various aspects of project management, presenting to the oil and gas community worldwide.

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DIGITAL TRANSFORMATION/OFFSHORE PRACTICES

Maintaining asset integrity during hurricane season Use of simulation twins can protect floating assets during hurricane season.

Fig. 1. Digital twin models can be a handy tool for urgent operational situations, like hurricanes. Photo: Stress Engineering.

ŝŝDAVID F. RENZI, PE, Stress Engineering Services (Editor’s note: We can think of no better time to feature this article than in the August issue, as the North American hurricane season builds to its peak in first-half September. This month also marks the one-year anniversary of vicious Hurricane Harvey, which plowed its way through the Gulf of Mexico and set all-time rainfall records in Houston and Southeast Texas.) Over the past few years, the oil and gas industry has been rapidly embracing the benefits of a digital transformation. One aspect of the transformation is the emergence of digital twin models, which provide a virtual representation of physical systems that mirror the information embedded therein. Most digital twin models for offshore floating facilities are focused on maintaining operational and inspection data. These digital twins can be linked through the life cycle of the system and allow for an unprecedented collection of asset information that reflects real-time conditions. As a subset of assorted digital twins, “simulation twins” add an additional layer of capability, by providing integrated physics-based analytical models and predicted responses, Fig. 1.

Fig. 2. Simulation twin cycle.

BENEFITS OF SIMULATION TWIN MODELS

Simulation twins are built on a foundation of physics-based analytical models, capable of accurately evaluating the response of a system. These physics-based models are ideal for situations where system response data are limited in terms of availability or accuracy. This scenario literally describes the reality of most floating systems. Data analytics solutions incorporating techniques, such as machine learning and artificial intelligence, can be extremely powerful, but are also inherently limited by the availability and quality of data. A highly capable simulation twin can be developed by using the foundation of physics-based models with an additional layer of data analytics to recognize the full potential of both techniques. A perfect example of this challenge for a floating system is the difficulty in determining measured riser response. A typical riser has little-to-no instrumentation unless a particular area of concern is identified that warrants an expensive instrumentation campaign. This instrumentation, when installed, still provides coverage for only a relatively small region over the entire length of the riser. Although the measured response of the riser, itself, is typically correlated to the measured motion of the floating host facility, the correlation is only partial, and the quality of the measured motion data is often lacking. It is obvious that

data analytic solutions applied to only these available, measured data will inherently be limited. A powerful solution is to use a physics-based model to generate the responses of the entire system, based on the most reliable and accurate available data. Data analytic algorithms can then be applied to not only measured data, but also the augmented data provided by the physics-based model. In essence, a continuous cycle is developed, where the physics-based model and data analytics solutions are tied together, to provide an extremely accurate assessment of the system, as demonstrated in Fig. 2. World Oil® / AUGUST 2018 73

DIGITAL TRANSFORMATION/OFFSHORE PRACTICES

Obviously, a properly developed simulation twin model must accurately predict the system responses and must properly clean the measured data utilized by the model. A comparison of tendon tensions, predicted by a properly developed simulation twin and measured by a tendon monitoring system for a TLP during two hurricane events, is provided in Fig. 3. Without a proven ability to adequately clean the measured data and predict a system’s response, the benefits of a simulation twin are greatly reduced, if not eliminated completely, Fig. 4. The accuracy and breadth of the simulation twin can be improved and optimized continually after the initial implementation. This improvement and optimization process can take the form of data analytics solutions, such as machine learning, a better understanding of the physics and assumptions utilized by the analytical engine, or expanding the simulation twin to evaluate other system components or phenomena. For a floating system simulation twin model, the areas of concern are the floating host motions, mooring/tendon systems, riser systems, umbilicals and hull/topsides structure with appurtenances. An initial implementation may focus on a particular area of concern and may not cover the entirety of these components or systems; however, the additional items can be incorporated as the system is expanded over time. Another aspect of the system that can be improved and optimized continually is the analytical engines and assumptions used in these engines. Every analytical model uses some level of assumptions for the practical purposes of efficiency or lack of known information. As information becomes available through the implementation of the simulation twin, these models and assumptions can be evaluated. The knowledge gained from this Fig. 3. Comparison of measured and predicted tendon response during hurricane events.

Fig. 4. Example of raw data (left) vs cleaned data (right).

74 AUGUST 2018 / WorldOil.com

process can be captured and applied to the design and evaluation of other floating systems and components. Finally, the enabling technology of a simulation twin is full automation of both the system assessment and the identification of useful insight. If labor effort is required to perform these activities, the cost-benefit of implementing the simulation twin model may be unrealized. This automation applies to all aspects of implementation: data cleaning, physics-based model assessments, data analytics, and the final presentation to the end-user of the insight generated. The useful presentation of insight is especially important. There has been a vast amount of data collected throughout the industry over the past decades. Almost all of these data have remained unused, due primarily to a lack of the necessary technology to efficiently gather insight from the disparate data located in a myriad of different storage systems. Accessing this insight requires technology developed by a combination of subject matter experts, data analytics experts and information technology experts. This combination is needed to identify which information is truly valuable as actionable insight, and present this information to the end-users in a format that allows ease-of-use and provides sufficient information to determine the actions needed. HURRICANE SEASON ASSET INTEGRITY MANAGEMENT

Simulation twins can provide system information, not only for real-time conditions, but also past and future conditions. These capabilities can be leveraged for many benefits, one of which is protecting the asset integrity of floating systems during hurricane events. The three primary facets that a simulation twin utilizes for hurricane event integrity management are: • Hurricane season planning activities • Real-time response during hurricane events • Post event inspections and activities. These facets all take advantage of the ability of a simulation twin to provide complete system responses, using relatively little available measured data. Even if measured data from the floating system are unavailable for a hurricane event—whether due to lack of instrumentation or lack of power to the instrumentation system during hurricane evacuation—the simulation twin can rely on other sources of data. Forecast and hindcast data available from publicly available sources and private meteorological services can provide site-specific environmental data that can be utilized by the physics-based models. This ad-

DIGITAL TRANSFORMATION/OFFSHORE PRACTICES

ditional layer of robustness ensures that the operator can rely on the actionable insight being generated, regardless of the level of instrumentation or data availability. Hurricane season planning activities. Most operators rely on information generated during the design phase of a floating facility, to determine operational guidelines documented in the marine operations manual. The design phase typically considers a range of conditions meant to represent the lower and upper bounds of the facility configuration. For example, a minimum riser and maximum riser condition may be evaluated. Or a minimum topsides vertical center of gravity (VCG) and maximum topsides VCG may be evaluated. The operational guidance is then developed, based on the worst-case response of all these various conditions. However, the as-is condition of a facility is almost never wellrepresented by the extreme bounding conditions. A simulation twin represents the best-known condition of the facility and can be used to determine the system response to expected environmental and operational loads. This capability can be leveraged in two manners to provide operational guidance during hurricane season: • Evaluation of response, due to extreme event conditions, based on pre-determined metocean criteria (e.g., a 100-yr hurricane, as defined in API RP 2MET) • Predicted response, due to named storms (e.g., using forecasted conditions of a hurricane moving into and through the Gulf of Mexico).

The operator can use the response of the as-is system to hurricane events, to optimize asset integrity management and operational plans. The response, due to pre-determined metocean criteria, can guide long-term plans, while the response for particular events will guide short-term plans. The primary benefits are derived from: • Determining the ideal evacuation condition of the facility, to minimize strength and fatigue loading of components • Understanding the strength and fatigue utilization of the floating system and components during hurricane events. Evacuation procedures typically consist of activities, such as adjusting mooring line or tendon tensions; re-positioning the floating system; adjusting top-tensioned riser tensions; securing a drilling rig (mechanical lockdown); and re-ballasting or offloading equipment to maintain desired weight and VCG conditions. These procedures can be optimized, based on expected environmental conditions and as-is facility conditions, allowing only those activities that are necessary to maintain asset integrity to be performed. Determining which components and locations are critical, in terms of strength and fatigue utilization, is a long-term asset integrity management activity. The system response during hurricane events forms a portion of this activity. Understanding the actual utilization of components, during hurricane events experienced by the system, allows for more accurate estimations of long-term behavior. This understanding then informs

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World Oil® / AUGUST 2018 75

DIGITAL TRANSFORMATION/OFFSHORE PRACTICES

the development of risk-based inspection plans and conditionbased maintenance programs. Fig. 5. A simulation twin can be of real help when floating systems in the Gulf of Mexico have to be evacuated in advance of named storms, as was the case with Hurricane Harvey during August 2017. Image: NeoSight/OceansMap.

Real-time response during hurricane events. Floating systems in the Gulf of Mexico are evacuated in anticipation of named storm events, Fig. 5. Many floating systems can provide at least limited real-time instrumentation data to onshore facilities during these evacuation situations. These limited data often provide information for vessel motions, mooring line tensions and environmental data. The simulation twin can utilize the measured data to determine the response of the floating system and all of its components (not only where instrumentation is installed). The simulation twin also can act as a “virtual sensor” to provide data where physical sensors either provide unreliable data or are completely unavailable. For example, mooring line load cell tension data often have issues regarding quality and continuity. The “virtual sensors” provided by the simulation twin provide consistent, high-quality data along the entirety of the mooring line, and not just at the location of the physical sensor. The simulation twin can incorporate data available outside of the instrumentation system. For example, environmental data from meteorological forecasts or other weather models can supplement the measured instrumentation data. The integrity of the floating system and its component can be inferred by comparing predicted and measured responses. Automated alarms can be established for discrepancies between predicted and measured responses, alerting personnel to issues that need to be examined with additional scrutiny. For example, if the measured pitch and roll response of a semisubmersible

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DIGITAL TRANSFORMATION/OFFSHORE PRACTICES

is significantly different than the predicted response for the measured environmental loading, this is an indication that the as-is condition does not match the condition prescribed in the evacuation procedures. Personnel can be alerted to examine the issue further and take appropriate action. These pre-emptive alerts are in contrast to the typical methods that are based on key performance indicators (KPIs), which examine each data channel individually, in relation to a pre-set threshold rather than in a holistic view of the entire system response. This methodology cannot capture the anomalous response until after these limits have been reached, and the possibility of taking corrective actions is improbable. Post-event inspections and activities. The third benefit of

simulation twins for hurricane events is to expedite post-event inspections and activities. The simulation twin provides a real-time assessment of the response experienced by the floating system during the passage of the hurricane. This response encompasses the entirety of the floating system, including the mooring/tendon systems, riser systems, umbilicals, and hull/topsides structure. Response of critical structural locations, such as deck-tocolumn connections, or events such as a mooring line breakage, can be identified. This provides the operator with a “punch list” of anomalies detected during the event, and identifies the components with the highest strength and/or fatigue utilization. This allows the operator to prioritize inspection and post-event activities. This information will be available, even before the facility is re-manned.

CONCLUSION

The digital transformation occurring in the oil and gas industry provides exciting new capabilities to improve safety and efficiency. An important piece of the transformation is simulation twins utilizing physics-based models. One specific benefit of these simulation twins is to provide a significant enhancement of floating systems asset integrity management during hurricane season. This benefit is realized through the ability of the simulation twin to evaluate forecasted, real-time and previously measured conditions. The operator of a facility can efficiently determine the ideal evacuation conditions for a floating system, identify anomalous responses during the event, and provide an immediate post-event assessment of the floating system. Previously, these activities were either not performed or preformed on a limited basis, due to the labor effort required. The automation of these activities greatly reduces, or even eliminates, the labor effort required to provide such extensive information. In conjunction with the ability to provide automated alerts of anomalous behavior, the operator can focus its hurricane season efforts, guided by a clear and complete picture of its assets’ integrity. DAVID RENZI is a principal at Stress Engineering Services, where he specializes in floating systems asset integrity management, performance analysis of floating production systems, and analysis and design of marine riser and mooring systems. He holds a BS degree in mechanical engineering from Texas A&M University, and is a professional engineer, licensed in the state of Texas.

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World Oil® / AUGUST 2018 77

REGIONAL REPORT

WEST AFRICA

Intending to be a global supplier, the region endures output disruptions

ŝŝEMILY QUERUBIN, Associate Editor Despite ongoing conflict throughout West Africa, the region’s energy sector continues to make progress toward becoming a leading global oil and gas supplier. According to GlobalData, nearly $194 billion will be spent on African oil and gas fields between 2018 and 2025. NIGERIA

Despite its position as the “Giant of Africa,” in terms of population and economy, Nigeria has struggled for years to resist the threat from militant groups. Because Nigeria is Africa’s top oil producer, militants see oilfield installations as a prime target. In 2016, continual assaults resulted in the lowest output that the country had seen in over three decades. Last July, suspected Boko Haram militants ambushed a group of geological surveyors in Borno state, in northeastern Nigeria. The attack resulted in the death of numerous Nigerian soldiers—who were acting as security escorts for the exploration team—as well as the kidnapping of several staff members from the University of Maiduguri’s geology department. Militants are progressively getting bolder in their attacks, as the July 2017 strike took place in what was considered a low-risk area.

The attacks are impeding the country’s efforts to expand exploration outside the Niger River Delta, in the hope of finding new crude reserves. The geologists had been working for Nigerian National Petroleum Corp. (NNPC) at the time, surveying parts of the Lake Chad basin, which is said to be a key area of operation for Boko Haram. It reportedly was the first attempt to uncover new reserves since exploration ceased in 2014, due to the wave of violence. Since the election of President Muhammadu Buhari in 2015, Nigeria’s economy has been shrinking, due largely to the decline in oil production. In the southern Niger River Delta, where most of the country’s oil is produced, continued output disruptions have deprived the government of more than $7 billion in revenue. Last December, the federal government agreed to take $1 billion from an account designated for oil revenue savings to support the country’s war against Boko Haram’s Islamist insurgency. According to the Nigerian government, the expenditure leaves $1.32 billion in the excess crude account, which is where oil income above projected estimates is saved. For now, however, there is no end in sight for the Nigerian oil

Left: Among others, Total operates the Moho Nord project, which it says is the largest oil project ever undertaken in the Republic of the Congo. Image: Total. Center: Eni’s Kalimba discovery well, offshore Angola, was drilled by the West Gemini drillship earlier this year. The discovery is estimated to contain between 230 MMbbl and 300 MMbbl of light oil in place. Image: Seadrill. Right: In Cameroon, Victoria Oil & Gas is making significant E&P progress, particularly at Logbaba field, in the Douala basin. Image: Victoria Oil & Gas.

78 AUGUST 2018 / WorldOil.com

industry, as the threat of violence from several militant groups persists. In November, the Niger Delta Avengers issued another warning to the region: “Our operatives are intact and focused, ready to implement instructions,” the statement read. “We can assure you that every oil installation in our region will feel warmth of the wrath.” The group also issued reported threats to Total’s Egina oil field, which was scheduled for start-up this year. “The water depth poses a challenge for the development of Egina, which is one of the deepest offshore projects ever operated by Total,” said JeanMichel Guy, executive general manager of the project. The ultradeepwater field, situated more than 80 mi offshore, has a forecast production capacity of 200,000 bopd. The project expects to see 44 subsea wells drilled, in water depths between 4,593 ft and 5,577 ft. The wells will be connected, via umbilicals and risers, to an FPSO that is designed to hold 2.3 MMbbl of oil, Fig. 1. A JV, led by Nigeria LNG, made progress on its $12-billion LNG expansion program this year, which is expected to increase the country’s LNG capacity as much as 40%. The company, alongside Saipem, TechnipFMC and Chiyoda Corp., is working to take FID on the project by the end of the year. In early July, engineering and design contracts were signed for construction of a seventh facility on the nation’s Atlantic coast. The expansion plan is part of the country’s efforts to maintain market share and preserve its position as one of the world’s top LNG exporters, as it competes with increasing output from Qatar, Australia and the U.S. Nigerian oil producer Shoreline Group also anticipates progress in the Niger River Delta this year, as it seeks to boost output significantly. In January, the company announced a $530-million financing deal with Vitol Group that will allow a production increase of between 80,000 bopd and 100,000 bopd this

year. Shoreline reportedly was one of several Nigerian producers that bought fields in the Niger River Delta after international companies, including Shell, withdrew amid the ongoing violence. The company, which holds an estimated 1 Bbbl in reserves, had ceased all production for a year, following the February 2016 closure of the Forcados terminal. According to CEO Kola Karim, the company now plans to boost its gas output from 100 MMscfd to about 500 MMscfd. According to Bloomberg, however, the Federal Republic of Nigeria, overall, was expected to load just 1.8 MMbopd during July. While the output level is in line with the cap that was agreed on by OPEC, the country still faces the possibility of a production drop, due to the threat of militant attacks. “Security in the Niger Delta remains a major concern, with persisting incidents of criminality, kidnapping and vandalism, as well as onshore and offshore piracy,” said Igo Weli, general manager for external relations at Shell’s local unit. GHANA/IVORY COAST

The government of Ghana signed an agreement with ExxonMobil Corp. in January, granting the company exploration and production rights for the deepwater Cape Three Points Block. The 366,000-acre block, situated 57 mi off Ghana’s coast, is believed to have high resource potential. As operator, with 80% interest, ExxonMobil will carry out exploration activities in the block later this year, including acquisition and analysis of seismic data. At present, Ghana reportedly has 21 licensed blocks, 14 of which are in ultra-deepwater territory. Tullow Oil, Anadarko Petroleum, Kosmos Energy and CEF (SOC) are among the top operating companies in the region. Ghana’s E&P sector has taken off over the past five years, with eight new discoveries. World Oil® / AUGUST 2018 79

REGIONAL REPORT / WEST AFRICA Of late, Ghana and Côte d’Ivoire (also known as Ivory Coast) have dealt with numerous maritime border disputes related to regional offshore exploration blocks. In September, Kosmos Energy, which holds a 17% participating interest in Fig. 1. Despite challenges related to water depth and threats from Nigerian militants, Total’s Egina field is scheduled for start-up this year. The Egina FPSO is designed to hold as much as 2.3 MMbbl of oil. Image: Total.

Fig. 2. State firm Société Nationale des Hydrocarbures has launched a licensing round in Cameroon this year, opening eight blocks in the Rio del Rey and Douala/Kribi-Campo basins for exploration. Source: CGG.

80 AUGUST 2018 / WorldOil.com

the offshore Tano Block, announced that arbitration between the two countries has not affected production at the offshore TEN development. In addition, Kosmos operates one of Ghana’s latest deepwater projects, Mahogany-Teak-Akasa (MTA). The project is in the West Cape Three Points Block and is anticipated to come online this year. CAMEROON/EQUATORIAL GUINEA

In Cameroon, Victoria Oil & Gas has made significant progress at Logbaba field, in the Douala basin. Last November, the company reported that its La-108 well had successfully reached nearly 9,400 ft, MD, encountering 277 ft of net gas sand in the Upper and Lower Logbaba formations. This was significantly more than the La-107 net sands, and reportedly exceeded predrill estimates. The LA-108 concluded a two-well drilling campaign that had begun in November 2016. By the end of December, initial flow testing was complete. According to the company release, La-108 showed initial gas flowrates up to 15 MMscfd from the lower Logbaba sands, while La-107 tested at a rate of approximately 4 MMscfd. Following evaluation of seismic reprocessing results and completion of the development drilling campaign, the company revised the field’s reserve estimates in June. The field’s proved reserves were revised upward by 29 Bcf, to 69 Bcf. Additionally, its remaining 2P reserves were revised upward by 106 Bcf, to 309 Bcf. VOG Chairman Kevin Foo said, “The results of this reserves update are a major advance to our business in Cameroon. They provide a significant value upgrade to the Logbaba project, and confirm that the field reserves will meet the growing demand in the Douala market for the foreseeable future.” One of Cameroon’s biggest developments of late, however, is its $1.2-billion Hilli Episeyo LNG project, which started full commercial operation in early June 2018—just three months after first gas was confirmed. The project’s production vessel reportedly is only the second FLNG facility to go onstream worldwide. And, according to Golar LNG, it is the world’s first FLNG vessel to be developed as a conversion project from an LNG carrier. While the project is fairly small, with a production rate of approximately 2.4 million tons per year, it is an important milestone for Cameroon, making it a net gas exporter and the sixth African nation to supply LNG. “It’s good to see a new African exporter coming into the market,” Trevor Sikorski, head of natural gas and carbon research at Energy Aspects, told Bloomberg. “An obvious market is Europe, particularly when the markets can be a bit stressed.” Cameroon is said to be geographically well-positioned as a supplier to the European market, as cargo can be transported to Britain in just 11 days. A directive by state firm Société Nationale des Hydrocarbures’ (SNH), to promote Cameroon’s hydrocarbon resources, instigated the launch of a licensing round this year. The licensing round opened eight blocks—Bakassi, Bomana, Bolongo, Etinde, Kombe-Nsepe, Tilapia, Ntem and Elombo—in the resource-rich Rio del Rey basin and the highly prospective Douala/Kribi-Campo basin, Fig. 2. Just south of Cameroon, in Equatorial Guinea, Ophir Energy and its partners are still working to secure project financing for the Fortuna project in Block R, west of Bioko Island. There have been six commercial discoveries in the block, to date. According to Ophir, it holds 3.7 Tcf of gas resources,

WEST AFRICA / REGIONAL REPORT with an expected plateau production rate of 330 MMscfd for 30 years. The project will utilize an FLNG vessel, because the gas uncovered in Block R is particularly rich in methane, with no contaminants or heavy hydrocarbons; therefore, it requires minimal topside processing.

Fig. 3. Total’s deepwater Kaombo project, which is said to hold an estimated 660 MMbbl of reserves, will produce to the Kaombo Norte and Kaombo Sul FPSOs, offshore Angola. Image: Total.

GABON/CONGO

Last year, Shell divested its onshore oil and gas assets in Gabon, selling all its interests to Assala Energy for $628 million in November. Assala is now the second-largest oil producer in the Gabonese Republic, operating Rabi, Toucan/Robin, Koula/Damier, Gamba/Ivinga and Bende/M’Bassou/Totou fields. Additionally, the company holds interests in four non-operated fields—Atora, Avocette, Coucal and Tsiengui. Panoro Energy, another major operator in Gabon, made progress at Tortue field last April. The company reported successful completion of the field’s first development well, DTM2H, in the offshore Dussafu license. The well was drilled and completed as a horizontal production well in the Dentale D6 reservoir, encountering a long horizontal section of oil-saturated Dentale D6 sandstone. Additionally, the well encountered a gross 121-ft hydrocarbon column, with nearly 92 ft of net pay, in the shallower Gamba and upper Dentale reservoir section. Subsequently, Panoro drilled its second development well, DTM-3H. The results reportedly were in line with pre-drill expectations, encountering a long horizontal section of oilsaturated Gamba sandstone. Both development wells were suspended, pending the arrival and hook-up of the FPSO. The BW Adolo FPSO then set sail in Singapore, enroute to Tortue field, in early July. Due to arrive in August, the FPSO reportedly is on schedule to deliver first oil during the second half of the year. With substantial oil and gas reserves, the Republic of Congo (Brazzaville) became OPEC’s newest member in June. Hydrocarbons Minister Jean-Marc Thystère Tchicaya told Bloomberg shortly thereafter that the country plans to boost oil production by as much as 65% this year. The increase in output is largely attributed to the planned start-up of commercial production at Moho North and Banga Kayo, where an additional 140,000 bopd and 50,000 bopd will be produced, respectively. The country’s increased output aims to alleviate the economic effects of the recent downturn. Moreover, the Ministry of Hydrocarbons is promoting the Congo-Brazzaville License Round Phase 2. “The Republic of Congo will focus on building on the momentum of the License Round Phase 1 in 2016, which saw 30 international companies register to participate. The timetable for the License Round Phase 2 will see the opening of the call for tender in September 2018, followed by a major promotion campaign in Cape Town (South Africa) at Africa Oil Week in November 2018. The closing date for receipt of tender offers in Brazzaville will be June 30, 2019,” Minister Thystère Tchicaya explained in a release. In a further push to expand E&P, the Democratic Republic of Congo (DRC) reportedly is considering whether to open parts of its Virunga and Salonga National Parks to drillers. However, the parks contain protected areas of tropical rainforest that are home to mountain gorillas, which are classified as an endangered species. Consequently, it is said that the ministry is enlisting members from the presidency,

Fig. 4. In May, Total reported that FID had been taken on the Zinia 2 project, in Angola’s offshore Block 17. Source: Total.

parliament and the government, as well as civil society organizations, to determine whether or not the plan should press on. “The DRC is committed to not carrying out any oil exploration or production in protected areas,” explained Emmanuel Kayumba, chief of staff in Congo’s Oil Ministry. “Even if the commission comes to a conclusion that we can explore or produce oil, we will do it in respect of the laws and regulations in force, whether local or international.” ANGOLA

According to GlobalData, Angola will account for approximately 23.8% of Africa’s total capex spending between 2018 and 2025. As Africa’s second-largest producer, Angola’s oil production comprises approximately 50% of its gross domestic product and about 92% of its exports. The country presently produces about 1.55 MMbopd, which is down from last year’s average of 1.67 MMbopd. Last December, the nation’s crude production reached a six-month low, which reportedly was a direct cause of field maintenance. However, Angola reportedly is planning a production increase of about 250,000 bopd by 2020. Sonangol, the sole concessionaire for E&P in Angola, is said to be in talks with oil majors, including ExxonMobil and Equinor, concerning the potential boost. The company’s chairman of the board, Carlos Saturnino, said that Angola is becoming more attractive to international operators, due to World Oil® / AUGUST 2018 81

REGIONAL REPORT / WEST AFRICA more favorable investment terms and improved energy legislation. Accordingly, the country is expected to see an increased production level of no less than 1.63 MMbopd next year. Officials also have alluded to a possible oil and gas bidding round before 2019. The tender reportedly is for oil blocks in the Namibe basin, off Angola’s southern coast. “It’s about 10 offshore blocks, although there is nothing concrete at the moment,” Petroleum Minister Jose Maria Botelho de Vasconcelos told Bloomberg last August. The expected production increase is largely ascribed to the planned start-up of Total’s $16-billion Kaombo project. The ultra-deepwater development, situated in Block 32, holds an estimated 660 MMbbl of reserves, spread across six fields. The fields will be connected through 186 mi of subsea pipelines that will produce to two FPSO units, each with a treatment capacity of 115,000 bopd, Fig. 3. According to Total, the fields’ reserves span a diverse system of reservoirs that reach depths down to 6,397 ft. Once online, output is expected to peak at approximately 230,000 bopd, according to IEA. Earlier this year, Eni reported a ramp-up of production at Ochigufu field, in Angola’s deep offshore Block 15/06. The field is connected to the Sangos production system, which then connects to the N’Goma FPSO, in the block’s West Hub. According to the company, several more start-ups are planned for the block this year, including the UM8 reservoir in the East Hub and the Subsea Boosting System for Mpungi field. Additionally, Angola’s Vandumbu field, also in the West Hub, is expected to start production early next year. Eni said that the planned start-

ups will add an additional 30,000 bopd to the block’s overall production, exceeding 170,000 bopd in 2019. Eni reported more success in Block 15/06 during June 2018, announcing a new oil discovery in the Kalimba exploration prospect. The Kalimba-1 NFW well, about 31 mi southeast of the Armada Olombendo FPSO, was drilled by the West Gemini drillship in a water depth greater than 1,500 ft. The well proved a 75-ft net oil pay of high-quality oil in Upper Miocene sandstones, with excellent petrophysical properties. Eni said that data acquired from the wellsite indicated a production capacity in excess of 5,000 bopd. The discovery is estimated to contain between 230 MMbbl and 300 MMbbl of light oil in place, overall. According to Eni, the oil find is creating more exploration opportunities for the southern portion of Block 15/06 because, until now, it was deemed a predominantly gas-prone area. In May, Total reported progress in Angola’s Block 17, Fig. 4. FID was taken on the company’s Zinia 2 project, about 93 mi off Angola’s coast. The project is made up of nine wells that will be tied back to the Pazflor FPSO. The wells are in water depths ranging from 1,968 ft to 3,937 ft. According to the company, Zinia 2 is the first of several potential short-cycle developments on the block, intended to unlock its remaining resources through the connection of satellite reservoirs to the existing FPSOs. Total E&P President Arnaud Breuillac said in a statement, “Zinia 2 opens a new chapter in the history of Block 17. This project will allow [us] to extend the profitability of this prolific block, with over 2.6 Bbbl already produced.”

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DEEPWATER/SUBSEA

Operators and service firms collaborate through ground-breaking subsea technology A growing urgency and drive for innovation in the subsea sector has seen the development of some of the industry’s guiding, purposebuilt well intervention technologies.

Amortization) fell by £1.7 billion, on average, over the same period. In this sense, innovations in digital transformation and technology, among other activities, have been vital in helping supply chain companies sustain their businesses in what has been a more demanding climate.

Fig. 1. The XR Connector’s unique design ensures that no damage is done, even after repeated release, offering the ability to rapidly disconnect from the wellhead in an emergency situation.

GLOBAL TECHNOLOGY

ŝŝDRUMMOND LAWSON,

Subsea Technologies Ltd.

Collaboration is the driving force of the global oil and gas industry, as it faces mounting pressure to increase efficiencies, maximize production and streamline processes, both offshore and onshore. In turn, these moves hopefully will reduce costs and boost profits. However, a fresh mindset is essential, if the industry is to overcome some of the challenges that it faces. Accordingly, a recent shift in culture, which is centered on a more open-minded approach toward technological advances and innovations, is gaining noticeable traction. This is particularly true in the subsea sector. This tangible change in attitudes is the key to unlocking efficiencies throughout the entire global supply chain, as we work to maximize the remaining value from what is—certainly in terms of the UK Continental Shelf (UKCS)—an aging basin. According to a recent report by Oil & Gas UK, the Oil and Gas Technology Centre (OGTC)—which co-invested £37 million in a variety of projects—already has played a part in 72 technology solutions, demonstrating the sector’s desire to embrace innovation and prolong the life of the UKCS. The report stated that the UK oil and gas services sector has faced some of its toughest times in recent years, as revenues fell by more than £10 billion from 2014 to 2016. However, the study also highlighted that EBITDA (Earnings Before Interest, Taxation, Depreciation and

The investment in, and subsequent progression of, innovative technologies, particularly within the subsea sector, is critical to sustaining production into the next decade. We already know that technical advances have been a driving force behind the increase in total production and improved well placement in recent years, providing solutions to complex offshore challenges, which often require cutting-edge techniques. Many companies also have been prioritizing methods of maximizing ROI from existing wells and infrastructure, which could include well interventions and workovers, according to Oil & Gas UK. The industry’s attention also will soon turn to developing and pinpointing solutions to extract oil and gas from high-pressure regions, which are moving higher up boardroom agendas, as the oil price increases. The biggest start-up next year is expected to be the Culzean HPHT gas field in the central North Sea. This also has a global focus, as some of the world’s most challenging deepwater basins exist in international waters. Examples include the Gulf of Mexico’s ultradeepwater Paleogene, Egypt’s West Nile Delta, and offshore Azerbaijan, where reservoir pressures and temperatures exceed the industry’s current technical capacity. In 2012, BP announced the launch of “Project 20K,” an R&D program designed to create bespoke technologies that are able to drill, complete, produce and intervene in deepwater reservoirs that have pressures of 20,000 psi at the mud line. However, investment in deepwater technology has taken a back seat in recent years, as a result of the industry downturn.

Nonetheless, as the oil price strengthens, and with high pressure at the seabed in these locations, a critical item becomes subsea connectors that can operate safely and reliably at these elevated pressures. They are necessary—particularly at extreme depths—to maintain the highest productivity levels. Subsea Technologies Ltd. (STL) is designing and developing products that challenge the norm, customizing connectors specifically for deepwater developments, where the demand is expected to become more evident, as the market improves. As the oil price reaches a viable level, operators are exploring deepwater areas further, with specific areas of interest in the Gulf of Mexico. The key is to complement and enhance a range of innovations to fit customers’ requirements. Instead of selling solely from a “shopping list,” the company tailors its approach to offering products that are entirely client-led, and which can configure seamlessly into existing offshore systems. In this respect, the company is seeing a growing demand to develop technology for highly complex and critical World Oil® / AUGUST 2018 83

DEEPWATER/SUBSEA

applications, which has put pressure on the sector. Nevertheless, STL has succeeded in launching a number of industry firsts with quantifiable benefits. The introduction of the Xtreme Release (XR) Connector and the multi-functional Stackable Lightweight Intervention Connector (SLIC) are just two examples. COMING OF AGE

As one of the world’s first purposebuilt, well intervention technologies, the XR Connector has paved the way for further subsea technical advancements. Providing a safety-critical solution to the ingrained industry issue of maximum riser disconnect angle, it gives operators the confidence to disconnect a riser in an emergency, while offering improvements in efficiency, productivity and costs. The connector’s face-to-face technology differs fundamentally from all other subsea connectors, which offer a conventional male-into-female arrangement. In an emergency scenario, it allows operators to stay connected to a subsea well for longer periods of time in adverse weather, and it minimizes pre-emptive disconnects when bad weather strikes. It also reduces the risk of damage to subsea infrastructure, if the vessel has a position-keeping failure, while lowering the risk of damage to a vessel, failure of the riser pipe, and damage to the wellhead and/ or loss of well containment. Accordingly,

the connector guards against environmental, as well as reputational damage. The high-angle connector enables vessels to continue operating, while protecting personnel, assets and the environment, and defending against the consequences of dynamic positioning failure. It essentially solves the challenge of safely and reliably disconnecting a riser under a high-bending moment and without damage—which can occur in any water depth, as a result of a vessel drift or drive-off. The connector was designed and developed about a decade ago, and is believed to be the only connector that is able to disconnect a riser at 100% of its rated bending capacity. Its success has led to further variations in the connector family. FORWARD-THINKING APPROACH

The XR Connector was introduced to offshore operations following the first coiled tubing intervention using a rigid riser, which was deployed for an oil major in the North Sea. This was carried out from a mono-hull vessel and, although the downhole objectives of the project were achieved, an entirely bespoke system was ultimately required for this to become a regular operation. Following this realization, the support of STL was enlisted to deliver a purposebuilt, coiled tubing riser system to overcome many of the challenges previously

Fig. 2. Without the benefits of this technology, the resulting damage could cause a significant financial burden, as well as a reputational crisis for the operator—particularly if the damage results in a spill or a well control incident.

identified. As part of this, the company completed a Front-End Engineering Design (FEED) study to develop a detailed conceptual design. During the global analysis work on the riser, it was discovered that, to get the system operating safely in North Sea water depths, no existing connector would be able to ensure the release of the riser from the subsea christmas tree with absolute assurance that it would not get stuck. Thus, the XR Connector was the answer. STL proposed the technology and ultimately secured its first launch customer. The first XR Connector (a 10-ksi, 73/8-in. bore version) was delivered in 2009, following extensive qualification testing. The launch customer had designed their intervention system to operate as a hybrid riser/riserless configuration, which meant that, in the riserless configuration, the XR Connector remained in the stack, but its functionality was not required. Although the client successfully completed its first riserless intervention in 2009, it was months before the company deployed the coiled tubing riser system on a test well, to prove the operation of the system. This was the first time that the connector was disconnected subsea. Initially, it was just with vertical tension on the riser. It subsequently included a bending load, by intentionally moving the vessel off center from the test well, restricted to approximately 5° from the vertical. Since completing offshore trials on the test well, the customer has successfully completed a number of riser well intervention operations, with more contracted for the coming years. STL also built an XR Connector for a Houston-based operator, which has the potential to be deployed in the coming months. In a further example, the 10-ksi, 73/8in. version of the XR Connector was licensed in 2011 to a multi-national client, which standardized on this item in its completion/workover riser (CWOR) systems. At the request of the customer, the XR Connector was re-engineered to optimize the design and manufacture of the product and meet its precise requirements, building a prototype of the modified connector for re-qualification. DEEPWATER/SUBSEA SOLUTIONS

Along with the XR Connector, STL’s engineers have designed a number of other products that cope with the demanding requirements of both constant operation 84 AUGUST 2018 / WorldOil.com

DEEPWATER/SUBSEA

in harsh conditions and maximum operational uptime, allowing for minimum maintenance downtime. The XR Connector’s unique design ensures that no damage is done, even after repeated release, offering the ability to rapidly disconnect from the wellhead in an emergency situation, Fig. 1. It also allows the vessel’s crew enough time to respond to challenging scenarios, without the risk of getting stuck to the wellhead or damaging the connector or riser, if the crew does not react quickly enough. This is a risk presented by all other connectors on the market. Without the benefits of this technology (Fig. 2), the resulting damage could cause a significant financial burden, as well as a reputational crisis for the operator—particularly if the damage results in a spill or a well control incident. Nearly a decade after the connector’s launch, the company has responded to the more recent industry demands for high-performance products at lower price points by reworking the XR Connector design to achieve a new derivative—the HB Connector. By incorporating the key benefits of the XR Connector, the company is now

developing the HB Connector, which was designed following a customer request for a lower-cost version of the XR for use in deepwater applications. It will have almost all of the benefits offered by the XR, except that it is not recommended for use in water depths less than 300 m and will cost between 50% and 65% of the price of the XR, depending on the configuration selected by the client. STL already has secured a launch client, with a firm order for two HB Connectors to be qualified, manufactured and delivered before the end of 2018. Just like the XR Connector, the HB Connector allows the vessel’s crew enough time to respond to challenging scenarios, without the risk of getting stuck to the wellhead, ultimately improving productivity levels. The SLIC technology (Stackable Lightweight Intervention Connector) is a further product that makes up STL’s portfolio, and it features “plug-and-play” configurability. The SLIC is a latch-style connector for Riserless Subsea Well Intervention (RLWI), Fig. 3. It improves safety, offers increased reliability, ease of mainte-

nance and redundancy. Its design takes into account the complexities of the entire physical, operational and contractual environment in which it operates, which minimizes downtime, not only for the operator but the end user, and subsequently benefiting the entire industry. It is typically used at the top of a subsea lubricator assembly as the interface for subsea wireline pressure control heads and other riserless subsea intervention system components. However, it is, at times, used at the bottom of the lubricator, to enable rapid connection and disconnection of the lubricator from the well control package, either at surface or subsea. Operators have commented on the “rugged” and “robust” nature of the connector and its ease of use. One major operator, who has a SLIC at the bottom of its lubricator assembly, was able to deliver a highly successful project to a client that would not have been possible without it. In that instance, the wells required high-rate injection of stimulation fluid (much greater than would have been possible through other access routes) so, after

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DEEPWATER/SUBSEA

pulling the crown plugs out of the christmas tree, the lubricator was recovered, and a modified SLIC mandrel, with an adapter to two 3-in. hoses, was installed. Using the two large-bore hoses, a stimulation vessel was then able to connect and pump very high-rate stimulation fluids—resulting in productivity improvements of over 50% on the project. The SLIC essentially is a multi-functional access point, enabling a wide variety of tools to connect to it, creating a highly flexible and adaptable element of an intervention system. This adaptability and configuration benefits not only operators but the whole supply chain. The technology also provides the option to extend the lubricator of a riserless intervention system and, as a result, creates the ability to recover a dropped wireline toolstring using the same RLWI system. A CUSTOMIZED PORTFOLIO

In 2015, STL was approached by China’s BOMCo, regarding subsea hydraulic stab plate couplers. The profiles of the intended couplers were already machined into their equipment, but the couplers they had intended to use had become unavailable. Consequently, there was a need to develop couplers that would fit into the existing profiles to avoid scrapping the high-value machined components.

The company’s initial coupler development strategy had been to enter the subsea stab plate coupler market by developing elastomeric sealing couplers for temporary equipment, but the client required much more challenging metal-to-metal sealing couplers for permanent installation. STL developed five different coupler configurations and sizes, each with its own set of design complexities. They required extremely small components that would work under very high pressures, while minimizing the restriction of fluid flow, using several different exotic alloys for both corrosion resistance and strength. While major suppliers of hydraulic stab plate couplers produce permanently installed couplers, which use a metalto-metal seal when engaged, they use elastomeric or polymer seals to seal the poppet when they are disengaged. The company created a metal-to-metal sealing poppet, enabling the couplers to seal with metal seals, whether engaged or disengaged. This means the male coupler— typically left permanently subsea—has only metallic components that will not degrade over its lifespan. The company’s project ultimately allowed it to run a series of internal process improvement programs, focused on more efficient management of orders for small, standardized products. New stab

Fig. 3. The SLIC design takes into account the complexities of the entire physical, operational and contractual environment in which it operates, which minimizes downtime, not only for the operator but the end-user.

plate coupler variants are now in development, with orders having been secured from customers for elastomeric sealing variants. The first ¼-in., 10-ksi stab plate couplers have just been delivered to the customer, with 3/8-in., ½-in. and ¾-in. variations now in development. After significant effort, STL offers a growing hydraulic coupler portfolio in a lead time of 12 weeks or less. This allows clients to become increasingly responsive and supportive of their own customers’ needs, while reducing project delays. FUTURE INNOVATION

According to Oil & Gas UK, if a supply chain company can provide a solution that improves efficiency and reduces costs, it typically has been able to protect or grow market share. The timely progression and development of technology and innovation that is driving supply chain efficiency is essential to help and sustain production for the future, which ultimately has global implications for the offshore/subsea sector. The deployment of new technology has been beneficial to more recently drilled development wells, which have experienced increased efficiencies as a direct result. As an industry, we will need to be even bolder and braver in terms of how we introduce and incorporate the latest cutting-edge solutions into the subsea sector, and beyond, to recover the remaining oil reserves. This growing urgency and drive for innovation in the subsea sector has seen the development of some of the world’s first purpose-built, well intervention technologies. Acceptance of new technology in the subsea industry is always challenging, yet, with signs that the industry is beginning to recover, operators and service companies are taking a different approach to component selection. We are having conversations that are more open to technological advancements, providing invaluable performance benefits. DRUMMOND LAWSON is a graduate in manufacturing engineering & management from the University of Dundee. He subsequently became a charted engineer through the Institute of Mechanical Engineers. Throughout his career, Mr. Lawson has held positions with Expro Group, Schlumberger, Shell and Ramco. He created Lewis Ltd., which was sold to a Norwegian buyer in 2008. He then co-founded Subsea Technologies Ltd. (STL) in 2010, where he serves as CEO.

86 AUGUST 2018 / WorldOil.com

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FEBRUARY 2018 / DEFINING CONVENTIONAL, SHALE AND OFFSHORE TECHNOLOGY FOR OIL AND GAS / WorldOil.com

FEBRUARY 2018

2018 FORECAST

Led by the U.S., the global drilling recovery gains momentum

2018 FORECAST

DIRECTIONAL DRILLING

Turbodrills and matched bits achieve superior results in hard, abrasive HT formations

SHALETECH: MARCELLUS/UTICA

Record laterals help feed new pipelines, plants in northeastern U.S.

G & G TECHNOLOGY

Geo-engineered completion designs improve recovery in unconventional wells

GULF PUBLISHING COMPANY

PEOPLE IN THE INDUSTRY [email protected]

Mitch Ingram

James Callahan

Flavia Rezende

Neil Hathaway

Oliver Kassam

Anadarko Petroleum Corporation has named Mitch Ingram, formerly executive V.P., international and deepwater operations and project management, to the post of executive V.P., international, deepwater and exploration. Ingram has nearly 30 years of experience in the industry and joined Anadarko in 2015 as executive V.P., global LNG. Prior to joining the company, Ingram worked with BG Group as executive V.P., technical, and was a member of the company’s executive committee. The company also announced that Ernie Leyendecker, formerly executive V.P., exploration, is retiring after more than 30 years in the industry.

Danos has announced James Callahan as V.P., operations and Reed Peré as V.P., business development, sales and marketing. With nearly 30 years of industry experience, Callahan most recently served as V.P., project services. Formerly V.P., production, Peré has over 10 years of experience in the industry. In addition, Mike Guidry, who has been with the company for 25 years and serves as operations manager, will move to general manager of production. Kevin Biringer will become the Permian general manager of projects.

Flavia Rezende has been appointed offshore manager at Bureau Veritas, North America. As a naval architect and marine engineer, with more than 15 years of experience in the industry, Rezende previously held senior positions within the company, including manager for technical development. Chad Fuhrmann has been named operations manager for MAC, a Bureau Veritas company. As a marine engineer, Fuhrmann served with the U.S. Naval Reserve before moving into the private sector 10 years ago. Additionally, Neale Fraser has been appointed MAC’s operations manager, Europe. Fraser previously held roles at GL Noble Denton and Divex UK, and was part of the original senior team at MAC when it was founded in 2011.

Deep Casing Tools has appointed Neil Hathaway to Middle East regional manager. With 28 years of international experience in the industry, Hathaway has worked for oilfield service companies, including Weatherford, and spent a decade in field operations.

Airborne Oil & Gas has appointed Oliver Kassam to CEO. Most recently, Kassam served as president and managing director at SBM Offshore N.V., in Brazil. Additionally, he served eight years at Subsea 7. Kassam brings over 20 years of industry experience to the company, and will be based in IJmuiden, The Netherlands.

Marathon Oil Corporation said that Zach Dailey will assume the role of advisor to President and CEO Lee Tillman, following his previous role as V.P., investor relations. In turn, Guy Baber will assume the role of V.P., investor relations. Most recently, Baber was managing director, senior research analyst and co-head of energy research at Simmons & Company International, energy specialists of Piper Jaffray. Crescent Point Energy Corp has announced that Ryan Gritzfeldt, formerly V.P., marketing and innovation, has assumed the role of COO. Gritzfeldt is a professional engineer and has been with the company for 14 years. Neil Smith, COO, and Tamara MacDonald, senior V.P., corporate and business development, have stepped down as officers of the company.

Devon Energy Corp. said that shareholders have elected John Krenicki, Jr. to the board of directors. Krenicki expands the company’s board to 10 members — of whom eight are independent directors — and is a senior operating partner at the private-equity investment firm Clayton, Dubilier & Rice LLC. Hunter Oil Corp. has named Al H. Denson, P.E. as CEO, replacing Andrew Hromyk, who has assumed the role of executive chairman. Denson has over 40 years of industry experience, where he served in various engineering, operations and management roles. Northwoods Energy LLC has announced Nate Wells as CFO. He brings almost 20 years of experience to the company, and most recently served as chief accounting officer and controller at Jonah Energy LLC.

88 AUGUST 2018 / WorldOil.com

Heerema Marine Contractors (HMC) has brought in Koos-Jan van Brouwershaven as CEO and Wijnand Tutuarima as CFO. Van Brouwershaven joins from sister company Heerema Fabrication Group (HFG), where he has worked as CEO, since 2013. He will remain CEO of HFG, as well. Tutuarima joined the company in 2013. Prior to this appointment he was senior V.P., finance, at HMC and was a member of the management team. Jerry Starling has been appointed director of diving and ROV operations at Kreuz Subsea. He brings more than 25 years of industry experience to the business, and most recently held senior diving roles at DOF Subsea and DeepOcean. He will be based in Singapore.

Eaton has named Molly Murphy senior V.P., North American sales, and Jeff Krakowiak senior V.P., marketing and commercial operations. With more than 20 years of experience in the electrical industry, Murphy’s responsibilities will include sales for industrial, original equipment manufacturer and commercial. Krakowiak will lead the marketing communications, sales operations, and project management teams. Krakowiak has nearly three decades of experience in the industry. Dave Bucklew, the current senior V.P., North American sales, has elected to retire. Reactive Downhole Tools has named Jonathan Brian as a U.S.-based senior business development manager. Brian has over 15 years of experience in the industry, including technical sales roles for Isolation Technologies and TAM International. BCCK Holding Company has appointed Bob Swann as director of project management and controls. Swann has spent 27 years of his career in Texas. His roles included project and engineering management for Pond & Company and DCP Midstream LP, and also served as a director of marketing and V.P., finance for Solvay Interox, a Solvay America Company.

PJ Valves has announced Neil Kirkbride as a non-executive director. Kirkbride brings 37 years of industry experience to the company, having worked previously in similar roles at BEL Valves and Glenalmond Group. At BEL Valves, Kirkbride was managing director for more than 20 years. Deloitte has appointed Shaun Reynolds and Kent Mackenzie to partner, oil and gas specialist, in the Scotland region. Previously, Reynolds set up and led the transaction services team for the Aberdeen office. Mackenzie, formerly global head for Fintech for risk advisory, Edinburgh, will be leading international strategy for the sector. He joined the company in 2014. Global Maritime has named Eric Frank to oversee its U.S. operations. Frank, who will also be responsible for dynamic positioning services throughout the U.S., brings 27 years of industry experience to the company. Over the previous 11 years, Frank held a variety of leadership and engineering roles at Seadrill, including technical manager for special projects in the Western Hemisphere.

COMPANIES IN THE NEWS [email protected]

in-house lab utilizes friction flow loop, rotational viscometer, gas chormatography-mass spectrometry with pyrolysis, and X-ray diffraction to perform post-frac sequential flowback studies. These studies confirm the efficacy of the scale control and microbiocides used during stimulations and other analyses.

Danos has been awarded a contract by Shell Exploration and Production Company to provide coatings for Shell’s deepwater Appomattox platform in the Gulf of Mexico. The coatings project should last approximately six months. Previously, Danos fabricated three boarding valve skids and one service line skid out of its Amelia, La., facility for Appomattox, which required support from the company’s project management, fabrication, coatings and automation service lines. In the Gulf of Mexico, 80 mi off the coast of Louisiana, the Appomattox platform is one of Shell’s new deepwater investments in the Gulf and is set to begin production before the end of the decade. Photo: Shell.

Engineering consultancy Thornton Tomasetti has agreed to acquire technical consulting specialist MMI Engineering. Currently owned by international environmental consultancy, Geosyntec, the new company will be rebranded as MMI Thornton Tomasetti and will be in the UK and Australia. In the U.S., the business will operate under the Thornton Tomasetti name upon completion of the deal. The goal of the union is to offer clients a full suite of risk management and technical security services with an expanded European, Australasia and Far East presence. Integrated marine service company C-Innovation, LLC, an affiliate of Edison Chouest Offshore, will be responsible for flushing and preparing 60 mi of pipeline for decommissioning in the Bass Lite Flowline decommissioning project for Apache Corporation. Situated in the Mississippi Canyon area of the Gulf of Mexico, the project was expected to last approximately two weeks, and it required two vessels with coiled tubing units. The project was slated to be gaslifted using hot tap, while flushing operations were executed. Start-up Wellpro Group is expected to create new jobs

within its first year of trading, after announcing its move to premises in Aberdeen. The wellintervention company’s portfolio includes thru tubing, operational design, project management, and service rentals, focusing on the UK and European markets, with plans for global growth. The Aberdeenbased firm is housed in a 5,750 ft2 office/workshop space, and is in the process of a significant investment in new equipment. Shell Integrated Gas Thailand Pte Ltd and Thai Energy Company Ltd, have sold their 22.2222% interest in Bongkot field and adjoining acreage offshore Thailand to PTT Exploration & Production Public Company Limited (PTTEP) and PTTEP International Limited, a wholly-owned subsidiary of PTTEP, for a transaction value of $750 million. This sale, consisting of Shell’s stake in Blocks 15, 16 and 17, and Block G12/48, was announced in first-quarter 2018. PTTEP operates Bongkot and, with completion of this transaction, has increased its stake to 66.6667%. The remaining 33.3333% belong to Total. Chemstream has evolved from its beginnings in the coal industry to analyzing formation geology and frac water quality for oilfield applications. The

TechnipFMC has been awarded a contract by Total for the Zinia Phase 2 field development, offshore Angola, at a water depth between 800 and 1,000 m. The contract covers the engineering, procurement and construction of subsea equipment, including nine subsea tree units, as well as wellheads, subsea control systems, connection systems and associated equipment. This contract also covers support services for assembly, test, mobilization and installation. Element Materials Technology has opened a new laboratory in Singapore. The ISO 17025-accredited materials testing laboratory offers specialized metallurgical and fracture toughness testing for contractors and fabricators in the Asia Pacific region. The sour service corrosion testing facility includes multiple baths for ASTM G48 corrosion testing and the capacity to conduct coating testing, such as cathodic disbondment testing, at room temperature and elevated temperature, as well as indentation and impact testing. ConocoPhillips has entered into an agreement to sell a subsidiary to BP for an undisclosed price. The subsidiary will hold a 16.5% interest in the BP-operated Clair field, with ConocoPhillips retaining a 7.5% interest. Additionally, simultaneous agreements were reached to acquire BP’s 39.2% interest in the Greater Kuparuk Area in Alaska and BP’s 38% interest in the Kuparuk Transportation Company for an undisclosed price. The Greater Kuparuk Area acquisition is subject to co-owner pre-emption rights. ExxonMobil subsidiary Esso Exploration and Production Guyana Limited has awarded SBM Offshore contracts to perform FEED for a second FPSO at the Liza development in the Stabroek Block of Guyana. The firm operates the Stabroek Block with partners Hess Guyana

Exploration Ltd. and CNOOC Nexen Petroleum Guyana Limited. The FPSO is designed to produce 220,000 bopd, will have associated gas treatment capacity of 400 MMcfd, and water injection capacity of 250,000 bpd. The FPSO will be spread-moored in a water depth of about 1,600 m and will be able to store around 2 MMbbl of oil.

Oilfield technology firm, Airborne Oil & Gas, has commenced a qualification program for a thermoplastic composite pipe riser for a major operator in South America and Subsea 7 (a minority shareholder). The conditional process involves analysis of global riser behavior, as well as installation. The objective of this project, set to begin in secondquarter 2018, was to develop a material that would allow operators to use a free-hanging, catenary configuration, to be installed by pipe-lay vessels. Photo: Airborne. China National Offshore Oil Corporation has signed a production sharing contract with Roc Oil Company and Smart Oil Investment Ltd for Weizhou 10-3W oil field (18-km2 total area, 40-m water depth,) and Block 22/04 (80-km2 total area, 40-80-m water depth). The South China Sea areas are in the Beibu Gulf basin and are approximately 60 km from the southern coast of China and northwest of Hainan Island. Al Yasat Company for Petroleum Operations, a subsidiary of the Abu Dhabi National Oil Company (ADNOC) has awarded an engineering, procurement and construction contract, for full development of the offshore Bu Haseer field, to Abu Dhabi’s National Petroleum Construction Company. The agreement covers offshore facilities, which will see production capacity from Bu Haseer increase from today’s 8,000 bopd to 16,000 bopd in 2020. World Oil® / AUGUST 2018 89

NEW PRODUCTS AND SERVICES [email protected]

Heavy-duty, medium-pressure and variable pumps provide efficient and durable fuel transfer Plenty-brand screw and vane pumps from SPX Flow are engineered to pump heavy viscous fluids, and are ideal for forced lubrication of rotating machinery and fuel transfer processes. The TRIRO triple screw pumps offer quiet, pulse-and-vibration-free operation. With only three moving parts, installation is simplified, minimizing impact on other equipment. Also, the vane pumps offer gentle, low-shear pumping action, low rate of wear, lower running costs, and variable flow without the need for variable-speed drive systems. Additionally, the Twinro two-screw pumps provide heavy-duty fuel transfer in accordance with API specifications. Photo: SPX Flow. www.spxflow.com

Seismic acquisition system traverses marsh zones Sercel has launched a transition zone version of its 508XT seismic acquisition system, capable of mixing wireless nodes, autonomous sections and connecting links, either on land or in transition zones. Designed to deploy in marsh zones, the reinforced hardware has a breaking strength to 300 daN and can withstand the challenges of operating in shallow water, up to 25 m. With real-time monitoring capabilities, the plug-and-play system features local storage, autonomous model automatic rerouting, and utilizes fault-tolerant X-Tech architecture. Real-time monitoring capability allows quality control of the complete spread.

High-resolution images, models from subsurface optimize accuracy Emerson announces the release of the Paradigm 18 integrated software solution suite. This release includes advanced technologies that use reservoir intelligence and enhanced operational certainty, and support effective asset management. Artificial intelligence capabilities enable identification of geologic facies from seismic and wellbore data. This unifying platform encompasses user interface and data management, artificial intelligence capabilities, support for cloud hosting, and high-resolution processing, imaging, interpretation and modeling geoscience software, delivering more accurate subsurface models.

Customized cutter technology enhances PDC bit performance

Non-contact, loop-powered transmitter improves resolution

The Pulsar model R86 non-contact radar transmitter from Magnetrol has a 26-GHz radar signal with a smaller wavelength and antennas, and improved resolution. This results in a smaller-beam angle that allows for installation into process connections as small as 1½ in. (38 mm). Automated echo capture conveys real-time waveform and trend data, showing up to 20 events, including diagnostic and configuration data to pinpoint any issues. The instrument uses circular polarization, eliminating the need to rotate the antenna orientation during commissioning. This simplifies installation and delivers proper alignment in virtually every application. High-temperature antennas are designed for use in operating conditions up to 750°F (400°C). Photo: Magentrol. http://R86.magnetrol.com

Halliburton has unveiled its BaraOmni hybrid separation system that removes ultra-fine, low-gravity solids, resulting in optimal fluid systems. The compact technology eliminates the need for dilution and improves the ability to recover drilling fluids, so more wells can be drilled with less fluid volume. Additionally, mobile technology allows drilling fluids, contaminated solids and other hydrocarbon waste streams to be treated with a single system. It replaces traditional complex solids control and waste management equipment set-ups. As a result, the operator can minimize waste transportation, off-site treatment and storage to reduce environmental exposure and total cost of ownership.

Force cutters from Varel Oil & Gas Drill Bits are a set of unique cutter geometries, designed to optimize drilling performance by fine-tuning the bit’s interaction with the rock. Research into shaped cutter design has created four new figures to match cutting action to drilling conditions and objectives. The OVAL, TRIFORCE, SCOOP, and FANG cutters have raised ridges, concave faces, and other unique features. Each pattern provides a different cutting action to reduce torque, pre-fracture the rock, create a progressive back rake, and enable non-standard positioning on the bit. Utilizing bit design software, a virtual approximation of ROP, and other variables is determined, and adjustments are made for better performance. The firm reportedly has been testing in Permian, STACK and Canadian laterals with good success. Photo: Varel Oil & Gas.

www.halliburton.com

www.vareloilandgas.com

www.nanoterra.com

www.sercel.com

www.pdgm.com/paradigm18

Ultra-fine solids removal, cuttings treatment improve drilling fluid recovery

90 AUGUST 2018 / WorldOil.com

BioSurfactants break down oil/ water without changing hydrocarbon structure Nanotera Group has introduced plant-based cleaning agents to replace chemical and hazardous products. This biodegradable product can be applied in enhanced oil recovery, tank cleaning, equipment maintenance, oil herding, oil/water separation and rig maintenance. By weakening the polar attraction of oil to the surface, the surfactants break down organic contaminants, oil and water emulsions and remediate hydrocarbons without polluting the treated product.

ADVERTISERS IN THIS ISSUE

AF Global Corp .............................................................33 www.afglobalcorp.com/NRG

American Association of Drilling Engineers ........22 www.aade.org

Ariel Corporation .........................................................63 www.arielcorp.com/whoweare

Baker Hughes, A GE Company .................................16 www.bhge.com/better

C&J Energy Services ...................................................39 www.cjenergy.com

C&J Energy Services ................................................... 57 www.cjenergy.com/gamechanger

Cold Pad .........................................................................24 www.cold-pad.com

Covia Corportaion .......................................................64 www.coviacorp.com/wo

Deepwater Executive Summit..................................20 www.deepwaterexecsummit.com

GWDC...............................................................................14 www.gwdc.com.cn

Enventure Global Technology ..................................67 www.enventuregt.com/eseal

Gai-Tronics .....................................................................56 www.gai-tronics.com

Gardner Denver .............................................................61 www.redlinepacking.gardnerdenverpumps.com

Geodynamics .................................................................51 www.perf.com

GR Energy Services ......................................................41 www.grenergyservices.com

Gulf Energy Information ................................................. Classified Pages ........................................................92 Events—HPHT ........................................................... 72 Events—PE Mexico Energy Strategy Forum ....95 Events—Shaletech ..................................................52 Events—WGLC ..........................................................82 Events—WO Awards ...............................................85 Gulf Video Division ..................................................92 WO Circulation ...................................................28, 87 WO Permian Basin Map ...........................................11 WO Webcast-- DNOW.............................................91 WO Webcast-- Summer Frac Forum..................76 Halliburton .....................................................................96 www.halliburton.com/advancedcompletions

Halliburton .....................................................................36 www.halliburton.com/geometrix

Hardbanding Solutions By Postle Industries ........71 www.hardbandingsolutions.com

Hi Crush Proppants ....................................................... 6 www.hicrush.com/propstream

Hydrozonix....................................................................... 5 www.hydrozonix.com

Industrial Rubber ........................................................... 4 www.iri-oiltool.com

JFE Steel..........................................................................31 www.jfetc.com

K+S Kali GmbH .............................................................67 www.kali-gmbh.com

Magnetrol International ............................................... 8 www.magnetrol.com

Nissan Chemical America Corporation ..................18 www.nanoactiv.com

NOV.................................................................................... 2 www.nov.com/offshoreupgrades

Offshore Northern Seas Foundation ...................... 27 www.ons.no

Packers Plus ..................................................................58 www.packersplus.com

Shale Support ...............................................................47 www.shalesupport.com

Society Of Petroleum Engineers ............................. 77 www.go.atce.org/ATCEregister

Tetra Technologies Inc................................................45 www.tetratec.com

Tomax AS ........................................................................12 www.tomax.no

Varel International ....................................................... 10 www.vareloilandgas.com

Volant Products Inc. ....................................................35 www.volantproducts.ca

Weir Oil & Gas ............................................................... 75 www.edgeservice.weir

Yellowjacket Oil Services LLC ..................................55 www.yjosllc.com

This index and procedure for securing additional information are provided as a service to World Oil advertisers and a convenience to our readers. Gulf Energy Information is not responsible for omissions or errors.

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92 AUGUST 2018 / WorldOil.com

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MEETINGS AND EVENTS [email protected]

AUGUST AAPG, Latin America and Caribbean Region Energy Opportunities Conference, Aug. 22–24, Hilton Hotel and Convention Center, Cartagena, Colombia P: +1 (800) 364-2274 F: +1 (918) 560-2665 [email protected] www.aapg.org/events IADC/SPE, Asia Pacific Drilling Technology Conference and Exhibition, Aug. 27–29, Bangkok, Thailand (See box for contact information) SPE, Artificial Lift Conference and Exhibition - Americas, Aug. 28–30, The Woodlands Waterway Marriott and Convention Center, The Woodlands, Texas (See box for contact information)

Mexican Association of Petroleum Geologists (AMGP), Mexican Petroleum Congress, Sept. 26–29, Expo Mundo Imperial, Acapulco, Mexico P: + 52 (55) 5599 2860 Adolfo.alejandro.huidobro@ pemex.com www.congresomexicano delpetroleo.com

OCTOBER NOIA, 2018 Fall Meeting, Oct. 3–5, Hyatt Regency Hill Country Resort, San Antonio, Texas P: +1 (202) 347-6900 [email protected] www.noia.org

SEPTEMBER

IADC, Contracts & Risk Management Conference, Oct. 9–10, Norris Conference Center – CityCentre, Houston, Texas (See box for contact information)

dmg events, World Heavy Oil Congress & Exhibition, Sept. 3–5, Oman Convention & Exhibition Center, Muscat, Oman P: +971 (2) 697 0504 [email protected] www.worldheavyoilcongress.com

IPAA, Oil & Gas Investment Symposium Chicago, Oct. 10, Mid-America Club, Chicago, Ill. P: +1 (202) 857-4722 F: +1 (202) 293-0681 [email protected] www.ipaa.org

SPE, ENGenious Symposium & Exhibition for Upstream Innovation, Sept. 4–6, Aberdeen Exhibition & Conference Centre, Aberdeen, Scotland, UK (See box for contact information)

World Oil/Gulf Energy Information Events, World Oil Awards, Oct. 11, Houstonian Hotel Club and Spa, Houston, Texas (See box for contact information)

SPE, Liquids-Rich Basins Conference – North America, Sept. 5–6, The Petroleum Club, Midland, Texas (See box for contact information)

AAPG, Mid-Continent Section Field Conference, Oct. 12–14, Cornhusker Marriott Hotel, Lincoln, Neb. P: +1 (402) 472-9801 [email protected] www.aapg.org/events

IADC, Advanced Rig Technology Conference & Exhibition, Sept. 11–12, Hyatt Regency Austin, Austin, Texas (See box for contact information) dmg events, Gastech Exhibition & Conference, Sept. 17–20, Fira Gran Via, Barcelona, Spain P: +44 (0) 203 615 5914 [email protected] www.gastechevent.com SPE, Annual Technical Conference and Exhibition, Sept. 24–26, Kay Bailey Hutchison Convention Center, Dallas, Texas (See box for contact information) IADC, Drilling HSE&T Europe 2018 Conference & Exhibition, Sept. 25–26, Beurs van Berlage, Amsterdam, The Netherlands (See box for contact information)

SEG, International Exposition and 88th Annual Meeting, Oct. 14–19, Anaheim Convention Center, Anaheim, Calif. P: +1 (918) 497-5581 F: +1 (918) 497-5558 [email protected] www.seg.org/Annual-Meeting-2018 SPE, Russian Petroleum Technology Conference, Oct. 15–17, Holiday Inn Sokolniki Hotel, Moscow, Russia (See box for contact information) IADC, Critical Issues Latin America Conference & Exhibition, Oct. 16–17, Hyatt Regency Mexico City, Mexico City, Mexico (See box for contact information)

SPE, International Hydraulic Fracturing Technology Conference and Exhibition, Oct. 16–18, Muscat, Oman (See box for contact information) PBIOS, Permian Basin International Oil Show, Oct. 16–18, Ector County Coliseum, Odessa, Texas [email protected] www.pbioilshow.org IADC, International Well Control 2018 Conference & Exhibition, Oct. 23–24, Melia Milano Hotel, Milan, Italy (See box for contact information) SPE, Asia Pacific Oil & Gas Conference and Exhibition, Oct. 23–25, Royal International Convention Centre, Brisbane, Australia (See box for contact information) SPE, Annual Caspian Technical Conference & Exhibition, Oct. 24–26, Astana, Kazakhstan (See box for contact information) Gulf Energy Information Events, Women’s Global Leadership Conference in Energy (WGLC), Oct. 29–30, Royal Sonesta, Houston, Texas (See box for contact information) World Oil/Gulf Energy Information Events, HPHT Drilling, Completions and Production Conference, Oct. 30–31, Norris Conference Center – CityCentre, Houston, Texas (See box for contact information) dmg events, Gas Asia Summit Exhibition and Conference, Oct. 31–Nov. 1, Marina Bay Sands, Singapore P: +65 6422-1475 [email protected] www.gasasiasummit.com

NOVEMBER AAPG, 2018 International Conference & Exhibition, Nov. 4–7, Cape Town International Convention Centre, Cape Town, South Africa P: +1 (918) 560-9431 [email protected]/www.aapg.org OTC, Arctic Technology Conference, Nov. 5–7, Hilton Americas, Houston, Texas P: +1 (972) 952-9494 F: +1 (713) 779-4216 [email protected] www.otcnet.org/arctic

Argentine Oil and Gas Institute (IAPG), 10th Hydrocarbon Exploration and Development Congress, Nov. 5–9, Mendoza, Argentina P: +54 (11) 5277 4274 F: +54 (11) 5277-4263 [email protected] www.iapg.org.ar IADC, Annual General Meeting, Nov. 7–9, The Ritz-Carlton, New Orleans, La. (See box for contact information) dmg events, European Autumn Gas Conference (EAGC), Nov. 7–9, Andel’s by Vienna House Berlin, Berlin, Germany P: +44 (0) 203-615-2393 [email protected] www.theeagc.com IPAA, Annual Meeting, Nov. 11–13, The Ritz-Carlton, New Orleans, La. P: +1 (202) 857-4722 F: +1 (202) 293-0681 [email protected] www.ipaa.org dmg events, Abu Dhabi International Petroleum Exhibition and Conference, Nov. 12–15, Abu Dhabi National Exhibition Centre, Abu Dhabi, UAE P: +971 (0)2 444-4909 [email protected] SPE, Symposium: Decommissioning and Abandonment, Nov. 27–28, Kuala Lumpur, Malaysia (See box for contact information)

International Association of Drilling Contractors (IADC) P: +1 (713) 292-1945 F: +1 (713) 292-1946 [email protected] www.iadc.org/events Society of Petroleum Engineers (SPE) P: +1 (972) 952-9393 F: +1 (972) 952-9435 [email protected] www.spe.org/events/ calendar World Oil/Gulf Energy Information Events P: +1 (713) 529-4301 F: +1 (713) 520-4433 energyevents@ gulfenergyinfo.com www.worldoil.com/events World Oil® / AUGUST 2018 93

THE LAST BARREL CRAIG FLEMING, TECHNICAL EDITOR

Entrepreneurial spirit It started in 1859, with Edwin Drake in Titusville, Pa., and spread like wildfire to other parts of the U.S. An incredible entrepreneurial flame, fanned by winds from a democratic system, encouraged wildcatters to invest capital and sink wells in search of elusive hydrocarbon riches. In 1865, commercial oil production was discovered in Humboldt County, southern California, and in 1870, John D. Rockefeller formed Standard Oil of Ohio. In January 1901, Spindletop was discovered when Anthony Lucas drilled a well near Beaumont, Texas, that tapped an oil-charged formation that blew six tons of 4-in. drill pipe over the crown block, to the delight of the well’s owners (most likely). When these risk-takers were successful, they profited from their ideas and good fortune, without excessive interference from the government or regulatory bodies. That was yesterday, and the good-old-days are gone, right? Well, despite increased regulations and pressure from enviro-groups, the industrious spirt that defined the U.S. oil industry at the turn of the century is very much alive and flourishing. Rumpelstiltskin. The Permian basin contains billions of bbl of high-quality crude, but the surface is a barren wasteland filled with tons of worthless sand, right? Wrong! A perfect example of entrepreneurial fortitude is taking place on the windswept dunes of the West Texas plains. The money-multiplying effect of the Permian boom is fueling the emergence of mining operations that rival the original U.S. frac sand operations in northwestern Wisconsin. In the last 12-months, a multitude of mines have been built near Monahans, Texas (RR Dist. 8). The first one was constructed by Hi-Crush Partners in July 2017, and 10 more immediately followed. Another 10 are in the planning/construction stage (Bloomberg). The location of the Hi-Crush mine (et al.) enables proppant to be trucked to the well site rather than transported by rail. This significantly reduces costs and logistical complexities for E&P and service 94 AUGUST 2018 / WorldOil.com

companies. In addition to the company’s full-scale facility at Kermit, they operate transload facilities near Pecos, Odessa and Big Spring, and can service up to 95% of proppant consumption within a 75-mi radius. The Kermit facility has a capacity of 3 MMtons of sand/year. However, West Texas sand is not as well-rounded as its Wisconsin cousin, but it’s much cheaper. Shipping costs from Wisconsin come to around $90/ton. That’s triple the $25 that it costs to truck in the Texas sand. Too much sand! With 11 mines operating and another 10 planned, the risk of overproduction is a legitimate concern. Although officials at the local mining companies are not overly alarmed, industry analysts suggest over-expansion is a major risk, even if the frac sand market remains strong. “Although things look great today, we can’t assume this is going to last,” said Joseph Triepke, an analyst at Infill Thinking. “Look at all this capacity.” Boomtown (for now). Together, these new operations are expected to mine and ship about 22 MMtons of sand in 2018 to drillers in the Permian basin. This immense volume equals 25% of total U.S. supply. And industry experts say the figure could climb to over 50 million tons in roughly two years. At today’s price of $80/ton, these 11 mines should generate about $2 billion in 2018. Utah oil sands. Oil seeps and surface shows have attracted wildcatters and businessmen to areas that eventually were developed into prolific oil-producing regions. This familiar scenario is unfolding in the Uinta basin, 60 mi south of Vernal, where Petroteq Energy has developed an innovative process to extract commercial quantities of crude from the area’s oil-bearing sands. Although several companies have tried to squeeze crude from Utah’s vast oil sand deposits, none have had commercial success (Bloomberg). Petroteq’s extraction procedure was developed by Ukrainian chemist Vladimir Podlipskiy, the company’s chief technology officer. The process starts when small

chunks of oil-bearing sand, mined at the surface, are fed into a vertical centrifuge loaded with a proprietary blend of solvents. As the solids fall out of the mixture, the liquid is heated and the solvents evaporate while the oil is piped out. The chemical vapor is condensed and run back through the process. According to Petroteq President Jerry Bailey, “our extraction system uses no water and recovers/recycles 99% of our proprietary solvent.” This virtually eliminates environmental concerns about water requirements and large, toxic tailing ponds that are typical of other oil sands operations. Petroteq said it’s targeting a break-even cost of $30/bbl, much lower than oil sands production in Alberta, that breaks even at around $65-$75/bbl, according to IHS Markit. The Utah Geological Survey estimates that the state’s oil-sand deposits contain up to 13 Bbbl of oil. Petroteq CEO David Sealock said, “we have enough oil here to extract 10,000 bopd for over 25 years.” The company projects that it will produce its first 1,000 bbl in September. Under the radar? During the 19781981 drilling boom, fund-companies were promoting Austin Chalk prospects in South Texas. The chalk was a promoters’ best friend. After fracing, the tight formation would surge back with high volumes of crude, but production would cease before pay-out, leaving investors with a loss (but promoters with a gain). Horizontals were attempted in Texas during the past decade, but variable production again hampered chalk development. Never fear, EOG Resources to the rescue. EOG captured the industry’s attention when its Eagles Ranch 14H, in Avoyelles Parish, La., produced 80,000 bbl of oil in 110 days (Wood Mackenzie). “It’s the first modern completion in this portion of the Austin Chalk. Early results suggest it could be a breakthrough for Louisiana acreage.” Are you convinced? If not, you should be.

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MEXICO ENERGY STRATEGY FORUM LEGACY OF THE ENERGY REFORM – KEEPING THE MOMENTUM

3 October 2018, Mexico City Join industry leaders at the 3rd annual Mexico Energy Strategy Forum. Building on the success of our forums in 2016 and 2017, Petroleum Economist will once again facilitate top-down analysis and discussion around Mexico’s energy reforms. › Hear of new investment and exploration opportunities › Listen and debate with international speakers on the progress of the reforms › Network with high-profile decision makers

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Engineered Solutions for Smarter Completions IT’S ALL ABOUT THE RESERVOIR

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As the leader in Advanced Completions, we offer customized solutions for enhanced reservoir understanding and control to maximize your asset’s life cycle. These award-winning solutions include our FlexRite® multilateral systems to optimize reservoir contact, EquiFlow® autonomous ICDs to reduce unwanted fluids, and SmartWell® systems for proactive downhole reservoir management. Contact us to learn how Advanced Completions can provide in-depth reservoir insights and solutions to deliver the lowest cost per BOE.

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