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Performance Indices

Regional Update

President’s Column

Comments

Technology Applications

SPE Events E&P Notes

People

Professional Services

Advertisers’ Index

Production platforms in Vietnam’s

Bach Ho (White Tiger) field, which

has been a mainstay of the country’s

oil production since the late 1980s.

Photo courtesy of Petrovietnam.

CONTENTS

GUEST EDITORIAL • HOW TO THRIVE IN A DOWNTURNThe industry is in one of its periodic downturns in which previous business

or career plans may no longer be viable. But there are still ways to go from

surviving to thriving in the current price environment.

TECHNOLOGY UPDATE

Gas-handling capability is one of the most complex and challenging issues

in artificial lift. When gas pockets enter the wellbore and cause system

interruptions, the effectiveness of an electrical submersible pump can be

undermined. A multiphase encapsulated production system mitigates gas

interference in the pump, stabilizes the production rate, and eliminates

downtime associated with pump cycling and gas-lock conditions.

ELECTROMAGNETIC IMAGING OFFERS FIRST LOOKAT THE PROPPED ROCK

Understanding how much rock is being stimulated and propped is

critical for unconventional producers. New imaging methods using

electromagnetic energy or acoustic microemitters could represent a

milestone in understanding what is left behind after fracturing.

INDUSTRIAL-SIZED CYBER ATTACKS THREATEN

THE UPSTREAM SECTOR

The oil and gas industry is experiencing a higher frequency of cyber

attacks than other industries, second only to the power and utilities sector.

As the sophistication of the attacks increases, the industry is working on

multiple fronts to address the vulnerabilities. But experts say it will beyears until adequate safeguards are in place.

VIETNAM STILL HOLDS MUCH E&P OPPORTUNITY

Vietnam holds substantial opportunities because of its resource potential,

expanding economy, surging internal energy demand, and the diverse

group of oil operators active in the country. Petrovietnam’s interest in

expanding partnerships with international players will help in bringing in

more investment and expertise to its fields.

MANAGEMENT • MANAGING PROJECT UNCERTAINTY:

THE DELPHI METHOD

Decision making in uncertain environments is key to the successful delivery

of oil and gas projects. Identifying, understanding, and clearly articulatingproject uncertainties so that appropriate management strategies can be

put in place is important for the successful outcome of the project.

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

Volume 68 • Number 3

DEPARTMENTS

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DRILLING & COMPLETIONS UNCONVENTIONAL RESOURCES RESERVOIR OPTIMIZATION

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Straddle System tools for selective production testing, acid stimulation, and sand

fracturing placement. Our Single-Set Inflatable Packers can be used as production

packers, bridge plugs, and scab liners. If P&A operations are needed, our Single-Set,

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The complete SPE technical papers featured in this issue are available

free to SPE members for two months at www.spe.org/jpt.

HYDRAULIC FRACTURINGZillur Rahim, SPE, Senior Petroleum Engineering Consultant,

Saudi Aramco

An Improved Model for Predicting Hydraulic-Fracture-Height Migration

Novel Proppant Surface Treatment for Enhanced Performance andImproved Cleanup

New Stimulation Method Significantly Improves Hydrocarbon Recovery

Rod-Shaped-Proppant Fracturing Boosts Production and Adds Reserves

PRODUCTION MONITORING/SURVEILLANCEMarc Kuck, SPE, Drilling and Completions Engineering Manager, Eni

New Improvements to Deepwater Subsea Measurement

Achieving Well-Performance Optimization Through Work-FlowAutomation

Distributed Acoustic Sensing for Downhole Production and InjectionProfiling

HEAVY OILTayfun Babadagli, SPE, Professor, University of Alberta

Chemical EOR for Heavy Oil The Canadian Experience

Solvent-Enhanced Steamdrive Experiences From the First Field Pilot

Pilot Tests of New Enhanced-Oil-Recovery Technologies for Heavy-OilReservoirs

SEISMIC APPLICATIONSMark Egan, SPE, Retired

Near-Surface Velocity Model To Enhance PSDM Seismic Imaging ofDukhan Field

Broadband Seismic Acquisition Implications for Interpretation andReservoir Models

High-Fidelity Microseismic-Data Acquisition in the Midland BasinWolfcamp Shale Play

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Volunteering looks good on you.In the new SPE League of Volunteers, giving back suits you well.

As a volunteer for SPE, you provide the energy that makes our Society work. Giving back

gives you the opportunity to enhance your leadership and collaborative skills, and expand your

professional profile as you showcase your knowledge and talents to the industry.

Engage. Support. Volunteer. Learn more and join us at www.spe.org/volunteer.

Share your story: #SPElov

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The Journal of Petroleum Technology magazine is a

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JPT STAFF

SPE BOARD OF DIRECTORS

OFFICERS

2016 President

Nathan Meehan, Baker Hughes

2015 President

Helge Hove Haldorsen, Statoil

2017 President

Janeen Judah, Chevron

Vice President Finance

Roland Moreau, ExxonMobil Annuitant

REGIONAL DIRECTORS

AFRICA

Adeyemi Akinlawon,

Adeb Konsult

CANADIAN

Darcy Spady, Broadview Energy Asset Management

EASTERN NORTH AMERICA

Bob Garland, Silver Creek Services

GULF COAST NORTH AMERICA

J. Roger Hite, Inwood Solutions

MID-CONTINENT NORTH AMERICA

Michael Tunstall, Halliburton

MIDDLE EAST

Khalid Zainalabedin, Saudi Aramco

NORTH SEA

Carlos Chalbaud, ENGIE

NORTHERN ASIA PACIFIC

Phongsthorn Thavisin, PTTEP

ROCKY MOUNTAIN NORTH AMERICA

Erin McEvers, Clearbrook Consulting

RUSSIA AND THE CASPIAN

Anton Ablaev, Schlumberger

SOUTH AMERICA AND CARIBBEAN

Anelise Quintao Lara, Petrobras

SOUTH ASIA

John Hoppe, Shell

SOUTH, CENTRAL, AND EAST EUROPE

Matthias Meister, Baker Hughes

SOUTHERN ASIA PACIFIC

Salis Aprilian, PT Badak NGL

SOUTHWESTERN NORTH AMERICA

Libby Einhorn, Concho Oil & Gas

WESTERN NORTH AMERICA

Andrei Popa, Chevron

TECHNICAL DIRECTORS

DRILLING AND COMPLETIONS

David Curry, Baker Hughes

HEALTH, SAFETY, SECURITY, ENVIRONMENT,

AND SOCIAL RESPONSIBILITY

Trey Shaffer, ERM

MANAGEMENT AND INFORMATION

J.C. Cunha

PRODUCTION AND OPERATIONS

Jennifer Miskimins, Barree & Associates

PROJECTS, FACILITIES, AND CONSTRUCTION

Howard Duhon, GATE, Inc.

RESERVOIR DESCRIPTION AND DYNAMICS

Tom Blasingame, Texas A&M University

DIRECTOR FOR ACADEMIA

Dan Hill, Texas A&M University

AT-LARGE DIRECTORS

Khaled Al-Buraik, Saudi Aramco

Liu Zhenwu, China National Petroleum Corporation

See Wells

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M I C R O S E I S M I C . C O M

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JPT • MARCH 2016

WORLD CRUDE OIL PRODUCTION+‡

THOUSAND BOPD

OPEC 2015 JUL AUG SEP OCT

Algeria

Angola

Ecuador

Iran

Iraq

Kuwait*

Libya

Nigeria

Qatar

Saudi Arabia*

UAE

Venezuela

TOTAL 33840 33769 33726 33625

THOUSAND BOPD

NON-OPEC 2015 JUL AUG SEP OCT

Argentina

Australia

Azerbaijan

Brazil

Canada

China

Colombia

Denmark

Egypt

Eq. Guinea

Gabon

India

Indonesia

Kazakhstan

Malaysia

Mexico

Norway

Oman

Russia

Sudan

Syria

UK

USA

Vietnam

Yemen

Other

Total 46685 46670

Total World 80525 80439

PERFORMANCE INDICES

HENRY HUB GULF COAST NATURAL GAS SPOT PRICE‡

WORLD ROTARY RIG COUNT†

REGION JUL AUG SEP OCT NOV DEC2016JAN

US

Canada

Latin America

Europe

Middle East

Africa

Asia Pacific

TOTAL

WORLD CRUDE OIL PRICES (USD/bbl)‡

WORLD OIL SUPPLY AND DEMAND‡

MILLION BOPD 2015

Quarter 1st 2nd 3rd 4th

SUPPLY 94.60 95.50 96.38 96.00

DEMAND 92.74 93.19 94.90 94.24

INDICES KEY

+ Figures do not include NGLs and oil from nonconventional sources.

* Includes approximately one-half of Neutral Zone production.

Latest available data on www.eia.gov.

Includes crude oil, lease condensates, natural gas plant liquids, other hydrocarbons for refinery feedstocks,

refinery gains, alcohol, and liquids produced from nonconventional sources.

† Source: Baker Hughes.

‡ Source: US Department of Energy/Energy Information Administration.

2 0 1 5

F E B

M A R

A P R

M A Y

J U N

J U L

A U G

S E P

O C T

N O V

D E C

2 0 1 6

J A N

USDmillion Btu

JUN JUL AUG SEP OCT NOV DEC2016JAN

Brent

WTI

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REGIONAL UPDATE

JPT • MARCH 2016

AFRICA

Eni started production from the West

Hub development project’s Mpungi field

in Block 15/06 offshore Angola. The

startup follows the project’s first oil from

the Sangos field in November 2014 and

the Cinguvu field last April. Mpungi will

ramp up West Hub oil production to

100,000 B/D in the first quarter from a

previous level of 60,000 B/D. The project

also includes the future development

of the Mpungi North, Ochigufu, and

Vandumbu fields. Eni is the block

operator with a 36.84% stake. Sonangol

(36.84%) and SSI Fifteen (26.32%) hold

the other stakes.

Bowleven said that its extended flow test

program at the Moambe and Zingana wellson the Bomono Permit onshore Cameroon

is complete. The company said that the

results to date continue to support its plans

for an initial supply of between 5 MMscf/D

and 6 MMscf/D of natural gas for power

generation, under a development program

established with partners Actis and Eneo.

The initial program focuses on production

from the shallower gas-prone sands on

the permit. Bowleven has a 100% equity

interest in the permit.

ASIA Sinopec struck high yields of oil and

natural gas in a test well offshore Beibu

Bay in southwestern China. The Wei-4

well, 68 miles southwest of the city of

Beihai, identified oil-bearing layers almost

328 ft thick. The well tested a first layer

at rates of more than 9,200 B/D of oil

and 2.53 MMcf/D of gas and a second

layer at more than 8,600 B/D of oil and

2.68 MMcf/D of gas. The offshore discovery,

in which Sinopec has a 100% interest, is

rare for the company, which mainly drills

onshore prospects.

OGDCL found natural gas at Thal East

Well No. 01 in Block 2769-15 in the Sukkur

District of Sindh Province in Pakistan.

Drilled to a 14,659-ft depth, the well

found hydrocarbons in the Basal Sand of

the Lower Goru formation and produced

23.5 MMscf/D of gas through a 36 /64-in.

choke at wellhead flowing pressure of

3,280 psig. OGDCL has a 100% interest in

the block.

Rosneft’s RN-Uvatneftegaz subsidiary

began commercial oil production at the

Zapadno-Epasskoye field, which is part

of the Uvat project in the Ust-Tegussky

license area of Russia’s Tyumen Region.

Hydraulic fracturing treatments at two of

the field’s seven wells have enabled the

production of more than 2,950 B/D of oil.

The field continues to produce a combined

16.6 Mcf/D of natural gas. Recoverable oil

reserves at the field amount to more than

121 million bbl, the company said.

Roxi Petroleum reported that Well

143 in the BNG Contract Area of western

Kazakhstan is “flowing strongly” after

encountering oil shows late last year.Average daily flow rates were 520 BOPD

with a 3-mm choke, 675 BOPD with a 5-mm

choke, and 815 BOPD with a 7-mm choke.

The improved flow rates have resulted from

the perforation of five additional intervals.

The well, which lies in the Pre-Caspian Basin,

was drilled to a 9,022-ft total depth. Roxi

has a 58.41% interest in the contract area,

which is about 25 miles southeast of Tengiz.

AUSTRALIA/OCEANIA

Buru Energy found oil at the UnganiFar West 1 well in production license L21

in Western Australia. An oil sample taken

at a 5,118-ft depth from the top of the

Anderson formation, and pressure data

interpretation, indicate that the well holds a

potential oil column of at least 45 ft and net

pay of about 16 ft. Buru, the operator, and

Diamond Resources (Fitzroy), a subsidiary

of Mitsubishi, each hold a 50% equity

interest in the well.

EUROPE

Total said on 21 January that first gas

production from Britain’s Laggan-Tormore

gas condensate fields off the Shetland

Islands in the North Sea was expected to

flow in the coming weeks. Peak production

of 494 MMcf/D is expected. Production had

been slated to start more than a year ago

but encountered delays. Total, the operator,

has a 60% stake in the project. Dong E&P

and SSE E&P each hold 20% stakes.

MIDDLE EAST

Gas Plus Khalakan (GPK) reported

that it had produced 65,000 bbl of oil

over 180 days from the Shewashan-1

discovery well in Iraq’s Kurdistan Region

before increased water production caused

it to be shut in. The discovery on the

Khalakan Block tested at a maximum rate

of 2,850 B/D of light oil in 2014. The well

will either be worked over, sidetracked, or

converted to water disposal if necessary,

the company said. GPK has spudded

the Shewashan-2 development well and

plans to drill a third development well

immediately afterward. GPK is the operator

of the Khalakan production sharing contract

with an 80% interest.

NORTH AMERICA

Anadarko produced first oil at the

Heidelberg field in Green Canyon Block

859 in the US Gulf of Mexico. The sister

spar project to Lucius, the Heidelberg

spar can produce 80,000 B/D of oil and

80 MMcf/D of natural gas and operate in

5,300 ft of water. Lucius, which started up

last year, and Heidelberg were constructed

with a “design one, build two” strategy

that streamlined and economized several

processes and enabled Heidelberg to come

on line 6 months sooner than otherwise.Operator Anadarko has a 31.5% interest.

Other participants are Cobalt International

Energy (9.375%), Eni (12.5%), ExxonMobil

(9.375%), Freeport-McMoran (12.5%),

Marubeni (12.75%), and Statoil (12%).

SOUTH AMERICA

Premier Oil recently redrilled its

Isobel Deep well (No. 14/20-2) in the

North Falkland Basin and confirmed the

oil discovery made at the well last May.

New hydrocarbons were also found, the

company reported. Situated on license

PL004A, the redrilled well reached its

9,890-ft target depth and found oil-bearing

zones in several sandstone reservoirs

between 8,400 ft and 9,385 ft. The lower

depth is the base of the Isobel Deep sand.

Operator Premier has a 36% interest in the

license, with the remaining interest held

by Rockhopper Exploration (24%) and

Falkland Oil and Gas (40%). JPT

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IMPROVING PEOPLE’S LIVES

0 JPT • MARCH 2016

“You don’t get your social license by going

to a government ministry and making an

application for one, or simply paying a

fee. … It requires far more than money to

truly become part of the communities in

which you operate.”

Pierre Lassonde, President of

Newmont Mining Corp., 2003

There is widespread acceptance that extraction industries—

including oil and gas—improve people’s lives and enable theeconomic growth of countries. However, at the project level,

this acceptance is neither automatic nor unconditional.

The concept of a social license to operate (SLO) has been ap-

plied to extraction industries and has been defined as “a commu-

nity’s perceptions of the acceptability of a company and its local

operations” by Thomson and Boutilier (2011). Community can

be very broadly defined to include stakeholders and interested

parties well outside the immediate areas of operations, or “any

group or individual who can affect or is affected by the achieve-

ment of the organization’s objectives” (Mitchell et al. 1997).

SLO is deemed to exist when a project has ongoing approval

of the community. For any project to have SLO, it is necessaryto earn and maintain the support—and ultimately trust—of

the community. We have seen ample evidence, including in our

own industry, that failure to do this can lead to conflict, de-

lays, added costs, or even prohibition of projects. Because it is

rooted in beliefs and perceptions, SLO is intangible. Beliefs and

perceptions are subject to change with new information; SLO

is nonpermanent. This presents challenges for companies who

want to know the status of their SLO and what they need to do

to maintain or improve it.

Thomson and Boutilier developed a framework to measure

beliefs, perceptions, and opinions that impact social license in

the mining industry and published quantitative assessments of

their framework. Fig. 1 represents their model and serves as a

useful starting point for a discussion of SLO in the upstream oil

and gas industry.

Measuring Social LicenseAccording to the Thomson and Boutilier framework, SLO exists

in a four-level hierarchy, with withholding or withdrawal at

the lowest level, followed by acceptance, approval, and co-

ownership, or psychological identification. To advance in the

hierarchy, the project must meet criteria of legitimacy, credibil-

ity, and trust.

At the lowest level, SLO does not exist, and projects cannot

proceed; the community perceives them as illegitimate. To be

considered legitimate, an extraction operation must contribute

to the well-being of the community, respect existing traditionsand lifestyles, and be conducted in a manner the community

considers fair. If the extraction project is not considered legiti-

mate, the community either withholds or withdraws access—

including legal license—to essential resources. Drilling permits

fall under this category, as do restrictions prohibiting hydraulic

fracturing imposed by a government. The social license to op-

erate also can be withheld or withdrawn by removing essential

financing, workforce availability, markets, etc. Examples of so-

cial licenses that have been withheld in our industry are the de-

velopment of the Marcellus Shale in New York and development

of unconventional resources in France. The driver for these li-

censes failing to rise to the level of acceptance is not primarilythe complaints of local residents who could be directly affected

by activity, but a larger concern at state or national levels aris-

ing from fears about hydraulic fracturing.

The next-higher level of social license is acceptance. This is

the most common level in the SLO hierarchy. It may be granted

grudgingly or reluctantly by parts of the community. Impor-

tantly, this level is just one level above the social license being

withdrawn. While acceptance implies tolerance, there may

be lingering or recurring issues, the presence of outside non-

governmental organizations, and watchful monitoring.

Social License To OperateNathan Meehan, 2016 SPE President

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

Fig. 1—Measuring social license to operate. Source:

Thomson and Boutilier, 2011.

TrustBoundary

CredibilityBoundary

LegitimacyBoundary

Approval

Acceptance

Withheld/Withdrawn

Psychological

Identification

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11JPT • MARCH 2016

While legitimacy and credibility lead to acceptance of a proj-

ect, it is important for operators to be perceived as credible by

the community at-large to rise to the level of approval. This level

of license requires that operators and their contractors commu-

nicate openly and honestly with the community, deliver on the

actions they promise, and provide benefits to the community.

The hallmarks of the approval level are support for the project

and participating companies, perception of the companies asgood neighbors, and pride in collaborative achievements.

The highest level of social license—psychological identifi-

cation, or co-ownership—can only occur when a high level of

trust is present throughout the community. Building that level

of trust requires consistency in communications and execution.

Once it is established, project participants and the community

engage in real dialogue. A substantial portion of the community

and other stakeholders incorporate the project into their collec-

tive identity. The community often becomes an advocate or de-

fender of the project since its members consider themselves to

be co-owners and emotionally vested in its future. This level of

social license should be industry’s objective.

Gaining Social LicenseBecause SLO is intangible and dynamic, conflicting ideas among

stakeholders can impact the level of license that is granted.

Community members may have very low levels of trust for oper-

ators in general, yet be much more willing to believe individual

employees whom they know and trust. Similarly, each commu-

nity has specific issues and interests that form the basis for rela-

tionship building between it and the project operator. As a pre-

requisite for SLO, the operator should map and understand the

social structure, issues, and vision of the various individuals,

groups, and organizations that form the community.Confidence in the status of a social license requires measur-

ing it periodically and using the results to modify practice to

improve the quality of the relationship between the project and

the community. Uwiera-Gartner (2013) discussed some of the

issues associated with communicating how hydraulic fracturing

operations can be used in a way that protects the environment.

Some early industry communication efforts emphasized point-

ing out flaws in public perception and media accounts instead of

addressing a variety of public concerns. Uwiera-Gartner dem-

onstrated that open and honest communication is essential to

maintaining the social license.

Olawoyin et al. (2012) quantitatively illustrated the increas-ing number of potential violations of best practices that could

result in environmental impacts associated with increased drill-

ing activity. They emphasized the importance for operators to

implement mitigation practices and focus on flawless execu-

tion. An industry reputation can suffer enormous damage when

environmental damage or personnel injuries or fatalities occur.

Beliefs, opinions, and perceptions—and social license to op-

erate—are subject to change as new information is acquired.

It is important for the Society of Petroleum Engineers (SPE)

members to be familiar with the many facets of the industry

so they can communicate factual information. SPE’s website

energy4me.org is an excellent source of such information.

Understanding the communities where we wish to work,

conveying factual information, communicating honestly and

openly, and acting in ways that build credibility and trust will

help our industry and the companies that comprise it strength-

en and maintain the quality of relationships to earn and main-

tain the highest level of social license—and the benefits that

accompany it. JPT

ReferencesLassonde, P. 2003. What Shade of Green Are You? Presentation to

the Melbourne Mining Club. https://www.ausimm.com.au/content/

docs/minclub130803.pdf .

Thomson, I. and Boutilier, R.G. 2011. Social license to operate. In

SME Mining Engineering Handbook, ed. Darling, P., 1779–1796.

Colorado, US: Society for Mining, Metallurgy and Exploration.

Mitchell, R.K., Agle, B.R. and Wood, D.J. 1997. Toward a Theory of

Stakeholder Identification and Salience: Defining the Principle of

Who and What Really Counts, The Acad Mgmt Rev, 22(4): 853–886.

Uwiera-Gartner, M. 2013. Groundwater Considerations of Shale

Gas Developments Using Hydraulic Fracturing: Examples,Additional Study, and Social Responsibility. Presented at the

SPE Unconventional Resources Conference, Calgary, Canada,

5–7 November. SPE 167233. http://dx.doi.org/10.2118/167233-MS.

Olawoyin, R., Wang, J.Y., and Oyewole, S.A. 2012. Environmental

Safety Assessment of Drilling Operations in the Marcellus-Shale

Gas Development. SPE Drill & Compl 18(2): 212–220. SPE 163095.

http://dx.doi.org/10.2118/163095-PA.

Sub-Ez the

www.subez.com.au

A simple cost-effective

solution to the commontask of installing subsinto BHA assemblies onthe rig floor or pipe deck.

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COMMENTS

JPT • MARCH 20162

Long vs. Short TermJohn Donnelly, JPT Editor

ExxonMobil’s latest long-term energy outlook paints a gener-

ally robust picture for oil and natural gas despite the steep fall

in hydrocarbon prices and cuts in capital spending. The out-

look predicts that the oil and gas share of the energy market

will grow and that renewable energy sources will remain only a

small share of the total picture.

Oil will continue to be the world’s largest energy source, with

demand for oil and other liquids growing by 20% from 2014 to

2040, according to ExxonMobil’s The Outlook for Energy: A View to 2040. Coal, which

is currently the globe’s second-largest fuel, will decline from providing 25% to 20%

of total energy demand as industry uses more fuels with lower CO2 emissions. Naturalgas use will increase as it replaces coal as second in consumption.

The outlook belies shorter-term predictions for the oil and gas market, which con-

tinue to forecast a tough year ahead. IHS CERA believes North American independents

will need further capital spending cuts to align spending with cash flow. An analysis

of 44 North American E&P companies shows that those firms need to cut spending by

another USD 24 billion, or 30%, to maintain a healthy fiscal balance. E&P companies

cut their 2016 spending budgets sharply from the previous year, but the price of oil has

fallen sharply since the fourth quarter of 2015.

Consultancy Wood Mackenzie predicts “another volatile, uncertain, complex, and

ambiguous year” with only the most robust or strategically important projects going

forward. It projects that exploration spending will be only half of its 2014 peak. The

lack of new investment and aging, high-cost fields in some regions will be a challengefor operators, but there are some bright spots for potential investment, especially off-

shore Mexico and Iran.

Wood Mackenzie offered several predictions and milestones to watch for during the

rest of the year.

“Meaningful” increases in production from Iran are not likely as the country

offers new contract terms for upstream projects. Crude exports should increase

to about 400,000 B/D as shut-in wells are brought back on stream. Saudi Arabia

will maintain current production levels so as not to lose market share to Iran.

Declines in spending will hit Africa hard. Output will stagnate in Angola and

Nigeria due to its aging fields, high production costs, and lack of investment.

North Sea activity also will decline because of lower spending. Rationalization

is likely as well as merger and acquisition interest. But production in Russia willmaintain current levels of 10.7 million B/D despite the drop in oil prices.

In North America, the inventory of drilled but uncompleted wells is at an all-time

high. Wood Mackenzie predicts that the draw down on these wells will remain

flat compared with 2015 through the first part of this year but will increase

significantly in the second half. US Gulf of Mexico deepwater production will

reach a new high with an additional 250,000 BOE/D coming on line. This reflects

projects that have been in development for years.

Mexico’s deepwater bidding round of 10 blocks primarily in the Perdido fold belt

will be successful. The acreage prospectivity and favorable contract terms will

contribute to its most successful bid round to date. JPT

EDITORIAL COMMITTEE

Bernt Aadnøy, University of Stavanger

Syed Ali—Chairperson, Schlumberger

Tayfun Babadagli, University of Alberta

William Bailey, Schlumberger

Ian G. Ball, Intecsea (UK) Ltd

Mike Berry, Mike Berry Consulting

Maria Capello, Kuwait Oil Company

Simon Chipperfield, Santos

Nicholas Clem, Baker Hughes

Alex Crabtree, Hess Corporation

Gunnar DeBruijn, Schlumberger

Alexandre Emerick,

Petrobras Research Center

Niall Fleming, Statoil

Ted Frankiewicz, SPEC Services

Emmanuel Garland, Total

Stephen Goodyear, Shell

Reid Grigg, New Mexico Petroleum Recovery

Research Center

Omer M. Gurpinar, Schlumberger

A.G. Guzman-Garcia, ExxonMobil (retired)

Greg Horton, Consultant

John Hudson, Shell

Morten Iversen, BG Group

Leonard Kalfayan, Hess Corporation

Tom Kelly, FMC Technologies

Gerd Kleemeyer, Shell Global Solutions

International BV

Thomas Knode, Statoil

Marc Kuck, Eni US Operating

Jesse C. Lee, Schlumberger

Silviu Livescu, Baker Hughes

Shouxiang (Mark) Ma, Saudi Aramco

John Macpherson, Baker Hughes

Casey McDonough, Chesapeake Energy

Stephane Menand, DrillScan

Badrul H Mohamed Jan, University of Malaya

Lee Morgenthaler, Shell

Michael L. Payne, BP plc

Zillur Rahim, Saudi Aramco

Jon Ruszka, Baker Hughes

Martin Rylance, GWO CompletionsEngineering

Otto L. Santos, Petrobras

Luigi A. Saputelli, Hess Corporation

Sally A. Thomas, ConocoPhillips

Win Thornton, BP plc

Xiuli Wang, Minerva Engineering

Mike Weatherl, Well Integrity, LLC

Rodney Wetzel, Chevron ETC

Scott Wilson, Ryder Scott Company

Jonathan Wylde, Clariant Oil Services

Pat York, Weatherford International

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

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Wellbarrier IIlustration Tool

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Delivering high quality well barrier illustrations

Use our software solution to document the robustness of the

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The industry is in one of its periodic

downturns. Jobs are uncertain or scarce.

Profitability is challenged. Bankruptcy

looms. Projects are being canceled. Deals

are dropped or delayed. It seems there

is bad news everywhere. So how do we

survive in this environment? And, more

importantly, how do we go from surviv-ing to thriving?

The leadership of the SPE Gulf Coast

Section (GCS) has launched a new initia-

tive called “Members in Transition” with

the aim of providing support, advice, and

best practices for thriving in a downturn.

The key principles are the following:

1. Be innovative. Plan A is often not

available these days. We have to look for

alternatives. As an individual, whether

you are a prospective graduate with anambition to work for a major producer or

a service provider, or have just lost your

job, consider all alternatives.

In addition to your first choices,

also look for jobs in marketing,

finance, regulation, midstream,

or downstream. Your expertise is

in the petroleum industry, as well

as in petroleum engineering. Your

skills are much broader than you

might think. Extend your education by taking

advanced courses or by earning

a new degree. This will be time

well spent preparing for the

future. Explore the educational

opportunities available from your

SPE section.

Start your own business. This

could create a rewarding new

career path. In partnership with

the Houston Technology Center,

the SPE GCS is establishing anIdeas Launch Pad program to

match members’ ideas with angel

investors. Entrepreneurs will need

realistic financial projections

and need to be able to tell the

business story in a convincing way

to potential investors. Employers

value entrepreneurial skills. These

business skills will serve you well

if you eventually decide to move to

a corporate role. Creating a greatbusiness story (Fisher 2014) for

investors will help you develop

skills that are useful for moving

projects forward when you are

hired by a company in the future.

As a company, your previous busi-

ness plan may no longer be viable in

the current price environment. Take a

clean sheet of paper, throw out all past

preferences and prejudices, and start

afresh. Develop a new plan that works in

today’s environment.Now is the time to explore new

technologies and new processes that

improve performance. In the January

issue of JPT (Rassenfoss 2016), the SPE

technical directors talked about inno-

vations needed for “Doing Better in

Bad Times.”

2. Be curious. To come up with new ways

of doing things, you need new ideas.

To get new ideas you need imagination.

This is a good time to look for ideas fromother industries.

3. Cut costs. When prices are low, it is

important to cut costs, whether you are

an individual or a company. Now is the

time to be diligent, even ruthless, with

cutting costs. In the end, you will be more

secure and better prepared when good

times return.

Lean Six Sigma techniques can be

applied to streamline workflows. Work

roles may need to be expanded or con-

GUEST EDITORIAL

How To Thrive in a Downturn

J. Roger Hite, Consultant, Inwood Solutions, and C. Susan Howes, Consultant

J. Roger Hite is a petroleum engineering consultant with Inwood

Solutions in Houston and part owner of a production company

with property in Louisiana. He has published a number of papers

and articles, primarily on various aspects of enhanced oil recovery

management. Hite is an SPE Distinguished Member and a recipient

of the International Management and Information Award. He is

currently Regional Director for the Gulf Coast North America

Region. He holds a BS degree in chemical engineering fromTulane University and a PhD in chemical engineering from Princeton University.

C. Susan Howes is a reservoir management consultant in Houston.

She was formerly a reservoir management consultant at Chevron,

with a prior role as learning and organizational development

manager at Anadarko. She has coauthored several papers and

articles on the topics of uncertainty management, risk

management, and talent management for SPE conferences and

publications. Howes is chair of the SPE Soft Skills Committee,

previously served as Regional Director for the Gulf Coast North

America Region, is a recipient of the SPE Distinguished Service Award, and is an SPE

Distinguished Member. She holds a BS degree in petroleum engineering from the

University of Texas.

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solidated. There may be opportuni-

ties to develop collaborative relation-

ships between and among companies.

Explore every avenue to cut costs and

improve performance.

4. Work hard. This is a bad time to be sit-

ting around waiting for something goodto happen. If you are employed, com-

mit yourself to being a valued employee.

Think like an owner—this keeps you

aligned with your employer and helps

you add value. Being the best performer

is a good thing.

Look for resources to find help. Many

SPE sections offer Distinguished Lec-

turer talks, monthly technical meetings,

short courses, and soft skills workshops

to upgrade your competencies. Addition-

al opportunities are offered by SPE atregional and international conferences.

Individuals create more value by dis-

covering their strengths (Buckingham

and Clifton 2001) rather than trying to

address their weaknesses. Personality

profiles help users to categorize their

strengths, and then put their strengths to

work at three levels: for their own devel-

opment, for their success as a manager,

and for the success of their organization.

5. Keep your enthusiasm. Many of ushave been through downturns in the

business before. We know we can get

through them, just as we have done in

the past. A good spirit helps—doom and

gloom do not.

Remember, life does not move in

straight lines. There are good times and

bad times, sunshine and rain, whether

you are in this industry or any other. We

all have to manage our lives prudently in

the down times, confident that the good

times will return. In the meantime, avail yourself of SPE resources and talk with

others in SPE.

Career transition experts tell us that

face-to-face engagement with profes-

sionals in our industry is the best way to

work through a transition, rather than

spending all our time at our computers.

Engagement in a professional society

such as SPE will improve your outlook on

the future, particularly if you take advan-

tage of the resources and networking

that SPE provides.

SPE ResourcesSPE cares about each and every mem-

ber and is doing everything it can to

help. SPE Chief Executive Officer and

Executive Vice President Mark Rubin

(2015) listed SPE initiatives in an earlier

JPT article:

SPE e-Mentoring Program(www.spe.org/ementoring ).

Finding the right mentor can make

a world of difference, particularly

for young professionals.

SPE Job Board (www.spe.org/

industry/jobs). In partnership

with Oilpro, SPE has developed

a comprehensive jobs search

engine to help members find

the latest opportunities in their

field.

SPE Web Events (webevents.spe.org ). SPE web events include live

webinars and on-demand online

training courses and videos.

SPE Competency Management

Tool (www.spe.org/training/

cmt). The SPE Competency

Management Tool is a free

online member benefit that

allows you to assess your current

professional capabilities against

one of 41 key exploration and

production job competencymodels.

SPE Insurance (www.speinsurance.

com). The SPE Insurance Program

is a unique group insurance

program designed to meet the

specific needs of petroleum

engineering professionals. The

SPE plans offered can continue

to protect you even if you change

jobs or no longer have a corporate

insurance program.

Network To Build RelationshipsIf you are unemployed or want a change,

develop your networking skills. Jeffrey

Gitomer (2006) wrote in his book “All

things being equal, people want to do

business with their friends.” If you are

planning to start a business, your first

clients will likely be colleagues who

know you and trust you to get the job

done. Consider four connection ques-

tions to “unlock the answer to growth

and success:”

Who do you know?

How well are you connected?

Do you know how to make a

connection?

Who knows you?

The skills that you develop during

your job search, i.e., networking, find-

ing leads, making phone calls, and get-ting meetings, translate well to becoming

a successful rainmaker for your business

(Fox 2006). The most important of the

various job search techniques is network-

ing—“just plain talking to people” will

always help in a job search. Use network-

ing to tap into the “hidden” job market,

those jobs that are not posted online.

The majority of the job market falls into

the hidden category. There is less com-

petition in applying for hidden jobs than

when applying for “open” posted posi-tions online.

The best ways to thrive in a downturn

include being innovative, cutting costs,

working hard, keeping your enthusiasm,

and networking to build relationships.

Increasing your engagement in SPE will

provide you with numerous opportuni-

ties to accomplish these objectives.JPT

ReferencesBuckingham, M. and Clifton, D. 2001.

Now, Discover Your Strengths. New York:The Free Press.

Fisher, B. 2014. The Six Secrets of

Raising Capital: An Insider’s Guide

for Entrepreneurs. San Francisco:

Berrett-Koehler.

Fox, J.J. 2006. Secrets of Great Rainmakers:

The Keys to Success and Wealth. New

York: Hyperion.

Gitomer, J. 2006. Jeffrey Gitomer’s

Little Black Book of Connections:

6.5 Assets for Networking Your

Way to Rich Relationships. Austin,Texas: Bard Press.

Pierson, O. 2006. The Unwritten

Rules of the Highly Effective Job

Search: The Proven Program Used

by the World’s Leading Career

Services Company. New York:

McGraw-Hill.

Rassenfoss, S. 2016. Doing Better in Bad

Times, J Pet Technol, 68(1): 38–41.

Rubin, M. 2015. SPE Provides Support

During Industry Downturn, J Pet Technol,

67(5):22.

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The power of our resources means nothing without the energy of our people. Their focus and expertise makeour energy more dependable, more sustainable, and more useful.

We are looking for experienced oil and gas professionals in Upstream, Downstream, Human Resources,Treasury, and Safety and Loss Prevention.

Apply now.

www.aramco.jobs/jpt

Oil and Gas Professionals

urrg

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oppor i

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TECHNOLOGY APPLICATIONS

JPT • MARCH 20168

Mechanized Stabbing GuideThe new Weatherford mechanized stab-

bing guide remotely guides tubulars tofacilitate hands-free stab-in. The guide

incorporates four axes of motion that

are run by remote control in an auto-

matic sequence, which removes the need

for a rig hand to enter the red zone at

the rotary table. It can be installed on

platform, jackup, and semisubmersible

rigs in any environment (Fig. 1). Bolt-

ed directly onto a flush-mounted spider,

the guide moves from horizontal to ver-

tical while the spider base remains sta-

tionary. The mechanized guide aligns tothe pipe and adjusts to accommodate

different pipe thicknesses and thread-

ed-box heights. Operational flexibility is

further increased by the guide’s compat-

ibility with a wide range of casing and

coupling sizes. The tool also includes

polyurethane clamping elements that

eliminate metal-to-metal contact dur-

ing stabbing, to protect sealing surfaces.

When used in conjunction with Weath-

erford’s OverDrive casing-running and

drilling system, the mechanized stabbingguide enables the entire casing-running

process to be executed without manual

handling. The full system removes per-

sonnel from high-risk zones on the rig

floor, thereby enhancing safety.

For additional information, visit

www.weatherford.com.

Pipeline ConnectorSpirax Sarco introduced the PC3000

and PC4000 pipeline-connector range.

This range has been developed to satisfythe needs of modern process industries,

significantly simplifying installation

and reducing maintenance time. Tradi-

tional steam-trapping assemblies often

require the plant to be shut down for new

traps to be installed, taking significant

time and reducing production output.

The PC3000 and PC4000 pipeline con-

nectors, with single or double isolation,

allow steam traps to be installed with-

out need for process shutdown (Fig. 2).

These pipeline connectors are ideal for

Chris Carpenter, JPT Technology Editor

Fig. 1—Weatherford’s mechanized stabbing guide enables automated stab-in of

tubulars, which removes personnel from high-risk zones on the rig floor.

Fig. 2—The PC3000 and PC4000 pipeline-connector range from Spirax Sarco

is designed to allow steam-trap installation with minimal process interruption.

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the oil and specialty-chemical industries

and are suitable for manifold applica-tions where steam traps are used on trac-

ing and main-line drainage. Some of the

range’s features and benefits include an

American Society of Mechanical Engi-

neers 600-rated forged body suitable for

use on lines up to 800°F, a fully shroud-

ed piston-valve stem that reduces the

potential of corrosion, and a standard fit-

ted strainer that protects the steam trap

from debris entrained in the condensate.

A universal steam-trap connection allows

the safe fitting of the complete rangeof steam traps without interruption to

existing processes.


www.spiraxsarco.com.

Water-Shutoff ChemicalPQ Corporation introduced the EcoDrill

S45, an environmentally friendly chemi-

cal treatment for water control and pro-

file modification. EcoDrill S45 uses new

technology that enhances traditional

benefits associated with sodium silicatechemistry. EcoDrill S45 is an alkaline,

low-viscosity, aqueous solution consist-

ing of nanosized presilica-sols. The silica

species are converted into a highly dura-

ble silica gel with the addition of a set-

ting agent. The choice and concentration

of setting agent allow for flexible gela-

tion times ranging from seconds to days

within the reservoir. These silica species

in solution are produced with a lower

charge density that allows for more-

controlled gelation times while using sig-

nificantly less setting agent (Fig. 3). Once

set, the silica gel shows much greater

dimensional stability. EcoDrill S45 can be

formulated to suit a wide range of water-control and carbon dioxide problems. It

effectively treats near-wellbore challeng-

es such as fractures, or it can be placed

deeper in the reservoir to combat high

water/oil ratios, fingering, coning, and

early breakthrough during waterflood-

ing. Excellent safety and environmen-

tal characteristics provide the option for

use across freshwater zones. Operational

temperatures range from 10 to 250°C.


www.pqcorp.com/pc.

Hydrogen-SpecificProcess Analyzer

The HY-OPTIMA 2700 Series hydrogen-

specific process analyzer from H2scan

uses a solid-state, nonconsumable sen-

sor. H2scan’s proprietary thin-film tech-

nology provides a direct hydrogen mea-

surement that is not cross sensitive to

virtually every other gas. The analyzer

is ideal for use anywhere hydrogen is

produced or consumed, such as refin-ery, natural-gas, petrochemical, and

industrial-gas applications, where real-

time measurements can enhance process-

plant efficiencies, improve diagnostics,

and reduce maintenance requirements

(Fig. 4). The analyzer is easy to install

and use, providing analog and serial out-

puts for accurate, real-time hydrogen

measurement in multicomponent or even

varying process streams.


www.h2scan.com.

Fiber-OpticData-Management ServiceCombining fiber-optic distributed-

temperature-sensing (DTS) data withother surface and downhole informa-

tion can provide the insight oil and gas

operators need to enhance production

and make more-informed operation-

al decisions. But current practices to

manage this information are complex,

costly, and time-consuming, making it

difficult to extract the full value of the

data. The Baker Hughes AMBIT fiber-

optic data-management service helps

operators simplify data integration and

improve productivity and performance.The secure, cloud-based AMBIT service

is designed to reduce the workload and

cost of data management compared with

traditional services that require costly

and complicated systems, programs, and

licenses. Deployed through a software-

as-a-service model, the AMBIT service

enables users to access their data in real

time through a web interface, to make

more-efficient and -effective operational

decisions. The management of large vol-

umes of data is simplified by incorporat-ing production mark-up-language DTS

standards, enabling easy integration with

applications and devices across multiple

vendors. This allows transmission of data

in a common format, enabling users to

share the data quickly and easily with the

capability of tracking metadata and sav-

ing multiple versions of processed data

without compromising any raw data in

the process. JPT


www.bakerhughes.com.

Fig. 3—10% active solution of PQ

Corporation’s EcoDrill S45 without

setting agent (left) vs. 10% active

solution of EcoDrill S45 with setting

agent and set for 4 hours at room

temperature (right).

Fig. 4—Two units of the HY-OPTIMA 2700 Series hydrogen-specific process

analyzer from H2scan.

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TECHNOLOGY UPDATE


Electrical submersible pump (ESP) sys-

tems are critical to achieving the max-

imum production rates and reservoir

pressure drawdown that improve ulti-

mate recovery. But when gas pockets

enter the wellbore and cause system

interruptions, the effectiveness of a tra-

ditional ESP can be undermined.Gas-handling capability is one of the

most complex and challenging issues in

artificial lift. Production in unconven-

tional wells varies significantly, depend-

ing on the evolution of the reservoir. In

a typical scenario, the well begins pro-

ducing with high liquid rates and some

gas. Over a period of a few months, oil

production rates fall and gas produc-

tion rises.

While many wells can produce with

small quantities of gas, the presence oflarge gas volumes precludes the use of

conventional pumping equipment. The

gas-handling challenges are exacerbated

by the long horizontals and multiphase

flow of oil and gas that are common in

unconventional oil plays.

Most horizontal wells are not perfect-

ly horizontal. The wells’ lateral portions

have undulations that cause the accumu-

lation of water in the low spots and gas

in the high spots. During the produc-

tion phase in unconventional plays,higher levels of natural

gas are usually

released from the pay zone as reser-

voir pressure depletes. This gas typi-

cally enters the horizontal wellbore and

accumulates in the high side of the lat-

eral, creating large gas slugs that cause

low-flow or no-flow conditions in an ESP

system as they move up the wellbore.

The resulting cycling and gas-lock condi-tions affect system reliability, which can

interrupt production and limit ultimate

reserves recovery.

In challenging downhole conditions,

operators often choose to install an ESP

system below the perforations. This sce-

nario is particularly useful in wells with

high gas content in the fluid stream and

in highly productive wells, where oper-

ators want to maximize the pressure

drawdown to release additional reserves

from the reservoir. Placing the ESP belowthe perforations separates the gas from

the fluid, eliminating issues associated

with gas entering the ESP.

However, reliability becomes a con-

cern because fluid does not flow past

the motor at the appropriate veloci-

ty to ensure motor cooling. To over-

come this issue, the ESP motor

can be encased in a

shroud,

but using a shroud can limit the size of

the ESP system and, therefore, produc-

tion rates.

Encapsulated SystemTo mitigate these problems, Baker

Hughes developed the Cenesis Phase

multiphase production system (Fig. 1)that encapsulates the entire ESP in a

shroud to separate gas naturally from the

production stream before it can enter the

pump. The multiphase encapsulated pro-

duction system includes the FlexPumpER

extended-range pump, which enables

production over a wide flow range and

eliminates costly system changeouts as

production declines. Wide vane openings

in the pumps’ mixed-flow pump stage

designs help mitigate the impact of natu-

ral gas on the system.The shroud provides a reservoir of

fluid that allows the lighter natural gas to

rise up the annulus while the heavier

liquids enter the shroud

to be produced

Fig. 1—The Cenesis Phase multiphase production

system overcomes multiphase flow challenges in

unconventional wells by encapsulating the entire electrical

submersible pump (ESP) system in a shroud to separate

gas naturally from the production stream before it can enter the

pump. Graphics courtesy of Baker Hughes.

Encapsulated ESP Handles Multiphase Flows

To Extend Run Life and Boost Oil Recovery

Jonathan Nichols and Nathan Holland, Baker Hughes

8/18/2019 JPT march 2016

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JPT • MARCH 2016

through the ESP system. It also enables the ESP system to con-

tinue operating when gas slugs displace fluid in the wellbore to

create low-flow or no-flow conditions.

Mitigating gas interference in the pump stabilizes produc-

tion rates, im-proves efficiency, and eliminates reliability issues

and downtime associated with pump cycling and gas-lock con-

ditions. The shrouded system design is also beneficial during

the installation, protecting the ESP components as they passthrough the deviated sections of a horizontal wellbore.

Recirculation Extends ReliabilityThe system design features a patented, integrated recirculation

system that extends ESP longevity and reliability by ensuring

adequate motor cooling. The recirculation system continuous-

ly redirects fluid flow past the motor to prevent overheating.

Thus, it provides mechanical protection for the motor lead

extension during installation in deviated or horizontal well-

bores and from downhole pressure changes.

Additionally, the recirculation system can be used to deliver a

chemical treatment to the area directly below the ESP motor totreat the entire ESP in wells where there are scale or corrosion

concerns. The chemical treatment is pumped through the recir-

culation pump, which mixes the chemicals with well fluid before

they come in contact with the ESP system metallurgy. This pre-

mixing minimizes any impact on the equipment.

In wells with sand production issues, sand management

devices can be incorporated to keep sand from entering the ESP

or falling back into it during a shutdown.

Case Study: KansasDeploying the multiphase encapsulated production system

recently helped an operator in Kansas increase productionby 346% compared with a gas lift system, and improved ESP

system run life by 440% vs. a traditional ESP design (Fig. 2).

The operator had completed a well using 7-in. casing, and dur-

ing the first year of production installed two separate standard

ESP systems and a gas lift system in an attempt to maximize

production. However, each system produced disappoint-

ing results.

Gas lift was unable to draw down the bottomhole pressure,

which limited production. The standard ESPs experienced fre-

quent shutdowns and high motor temperatures, resulting in

deferred production and reliability problems.

Each conventional ESP system produced for several monthsbut began to have gas interference when the pressure in the

wells declined, which led to an increased number of gas slug-

ging incidents. The increased gas volume in the wellbore caused

frequent gas locking of the ESP, which resulted in little to no

liquid flowing past the motor and through the pump. Fluid flow

is necessary to maintain an adequate operating temperature.

Gas-locking events ultimately led to short runs of 144 days and

102 days, respectively, for the two original ESPs. Following the

short runs, the operator tried gas lift. The gas lift system elimi-

nated shutdowns caused by gas interference. However, produc-

tion was extremely constrained, never exceeding 4 BOPD vs. an

average of 66 BOPD and 59 BOPD for the two ESP systems. The

8/18/2019 JPT march 2016

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limited oil production achievable with gas

lift made the well uneconomic.

After evaluating the performance of

the previous artificial lift methods, a

5½-in. multiphase encapsulated produc-

tion system for 7-in. casing was used

to decrease nonproductive time and

increase the reliability and run life of the

ESP system. The encapsulated system

eliminated temperature-related shut-

downs and maximized production and

run life. At case history publication time,

the system had run 790 days, compared

with 144 days for the the longest-run-

ning ESP that it replaced. JPT

2012 2013 2014 2015

Oil Gas Water Water + Oil Gas-to-Liquid Ratio Pump Intake Pressure

FreeFlowing

ESP144-Day Run

Gas Lift113-Day Run

ESP102-Day Run

Cenesis Phase780-Day Run

Fig. 2—Using a multiphase encapsulated production system, an operator in Kansas increased production by 346%,

compared with a gas lift system, and improved ESP run life by 440% vs. a traditional ESP.

SPE EVENTS

WORKSHOPS

8–9 March Kuala Lumpur—SPE Petroleum

Economics—Optimising Value Throughout

the Asset Life Cycle

9–10 March Harstad—SPE Norwegian

Arctic Subsurface and Drilling Challenges

13–16 March Penang—SPE Complex

Reservoir Fluid Characterisation—Impact

on Hydrocarbon Recovery and Production

14–15 March Aberdeen—Brownfields

Redevelopment—A Meeting of Minds to

Meet the Challenges

15–16 March Calgary—SPE Thermal

Completions and Workover Operations

21–22 March London—SPE Petroleum

Economics and Valuation

28–30 March Fort Worth—SPE/SEG

Injection Induced Seismicity—Engineering

Integration, Evaluation, and Mitigation

29–30 March San Antonio—SPE

Production Chemistry and Chemical

Systems

29–30 March Doha—SPE Reservoir

Characterisation

6–7 April Comodoro Rivadavia—SPE

Mature Field Management as the Key for

Production Optimization

CONFERENCES

21–23 March Muscat—SPE EOR

Conference at Oil and Gas West Asia

22–23 March Houston—SPE/ICoTA Coiled

Tubing and Well Intervention Conference

and Exhibition

22–25 March Kuala Lumpur—OTC Asia

9–13 April Tulsa—SPE Improved Oil

Recovery Conference

SYMPOSIUMS

8–9 March Abu Dhabi—SPE Women in

Leadership: Exceeding Expectations

9–10 March Amman—SPE Iraq—The

Petroleum Potentiality and Future of Energy

29–31 March Dubai—SPE Cyber Security

and Business Resilience for the Oil and Gas

Industry

30–31 March Mexico City—SPE Mexico

Health, Safety, Environment, and

Sustainability

5 April Calgary—SPE/CHOA Slugging It

Out Conference

FORUMS

22–25 May Kuala Lumpur—SPE: The Role

of Geomechanics in Conventional and

Unconventional Reservoir Performance

and Management

CALL FOR PAPERS

SPE Russian Petroleum Technology

Conference and Exhibition Moscow

Deadline: 18 March

SPE Liquids-Rich Basins Conference-

North America Midland

Deadline: 21 March

SPE International Heavy Oil Conference

and Exhibition Kuwait City

Deadline: 3 May

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

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MWV Specialty Chemicals is now Ingevity—

the global leader in emulsiiers.

New name. New Look. Same trust.

ingevity.com

A trusted partner in

challenging times.

8/18/2019 JPT march 2016

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The Casing XRV’s ability to break static friction allows operators to run casing

to TD without excessive force, thus protecting the string from unnecessary stress

and high friction. Minimizing casing stress during installation

safeguards the operator from costly remedial operations in the future.

In addition, the friction breaking technology increases run speed

which results in decreased rig time, providing immediate cost

savings for the operator.

Visit our website to watch the Casing XRV in action.

Save Rig Time

Improve Cement Bond

Eliminate High Torque Threads

Reduce Mud Costs

Reach TD In One Run

Casing XRVTTS Drilling Solution’s

The Missing Piece To Efficiently Completing Your Well.

Save Rig Costs.

Cost Saving Advantages:

8/18/2019 JPT march 2016

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The average casing run time, utilizing the Casing XRV, was 19 hours; saving the operator an

average of 18 hours, signifying a 48% decrease in rig time. This directly correlates to a 94%

increase in run speed when utilizing a Casing XRV; proving the friction breaking technology

of the Casing XRV is significantly reducing operators rig costs.

www.ttsdrilling.com • [email protected]

On an eight well pad comparison ...

94% Increase In Run Speed

48% Decrease In Rig Time

60

50

40

30

20

10

0Without Casing XRV

Casing Run Times (Hrs)

With Casing XRV

350

300

250

200

150

100

50

0

Without Casing XRV

Casing Run Speeds (ft/hr)

With Casing XRV

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E&P NOTES


A pilot project carried out by Hess Corp.

demonstrates just how quickly automat-

ed drilling technology is able to take a rig

from the bottom of the pack and push it

to the top.

In November 2014, the company

selected a rig from its Bakken Shale fleet

that had been in the bottom quartilein terms of performance for more than

2 years. But over the course of a 16-well

program, the rig became the second fast-

est Hess had working at the time. Year-to-

year comparisons showed the automated

rig had improved its drilling footage per

day by 24% compared with the fleet aver-

age of 17% over the same period.

Despite the apparent success of the

project, the industry downturn forced

the company to lay down the rig last year.

Details of the pilot were discussed at ameeting of the SPE Gulf Coast Section in

January in Houston. The technical paper

summarizing the results will be present-

ed at the IADC/SPE Drilling Conference

and Exhibition this month in Fort Worth,

Texas (SPE 178870).

The system, supplied by National Oil-

well Varco, used a downhole automation

system that controlled the auto-driller

system on the rig. Wired pipe delivered

high-speed data between these systems

and tools that measured key parame-ters, including downhole weight-on-bit,

torque, and vibration. Matthew Isbell,

a drilling optimization adviser at Hess,

noted that the wired pipe delivered so

much information that it was a challenge

to handle it all.

“The data fire hose overwhelmed us,

both in terms of analyzing the run as it

was happening as well as at the end of

each well and trying to figure out whatwe should modify on the system for the

next well.” He added that one of the goals

of any future automated pilot is to come

up with a way to better visualize the data

to make the process of understanding it

more efficient.

Keith Trichel, a drilling engineering

adviser at Hess, said the original plan for

the pilot was to simply turn the system on

and observe how it functioned without

asking the rig crew to take action on the

real-time data streaming out of the well.“But to our surprise, the rig crew and the

folks involved in the drilling process real-

ly quickly grasped what they were seeing

and started reacting to it,” he said.

With the ability to see what was taking

place downhole, the rig crew began using

the automated equipment as a learning

tool. This enabled them to use the data

to run on-the-fly experiments to achieve

performance improvements and see

problems sooner.

One key discovery the crew madewas that they could speed up the rota-

tion from the standard 45–50 rev/min to

90 rev/min. By speeding up the rotation,

the drillstring became more stable and

allowed the vertical section to be drilled

in one run vs. the usual two. Other Hess-

operated rigs in the area followed their

lead and made similar performance gains.

The pilot also showed that as certain

gains are made, unexpected problemsmay be introduced. The major issues

Hess faced involved increased wear on

the bits due to the rate of penetration

and the bottomhole assembly’s tendency

to “drop,” which occurs when bit force is

placed on the low side of the well while

drilling the curve.

The pilot had aimed to generate enough

time savings to break even on the cost of

the automated system but achieved this

on only six of the wells drilled while six

other wells missed the target by less thanUSD 100,000. The overruns on the other

four wells were chalked up to “trouble

time” in the curved sections and time lost

trying out different bottomhole assembly

units to address dropping issues.

The downturn had other unexpected

effects on the project. Isbell said the drill-

ing team had wanted to limit variables as

much as possible. But because of “indus-

try unrest” and turnover, the automated

rig had three different drilling superinten-

dents, four different drilling engineers,and six different company men come and

go over the course of the project.

Payoff Still Possible in Refracturing Conventional Wells

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

There has been a lot of talk about refrac-

turing recently, but the percentage of wells

fractured more than once is a small fraction

of the 35% rate from the 1950s to 1970s.

That statistic came from a recent

presentation by Anton Babani-

yazov, a staff production engineer for

ConocoPhillips, who used it to begin

a talk for the SPE Gulf Coast Section’s

Permian Basin Study Group about

a successful fracturing campaign in

west Texas.

Hess Pilots Automated Drilling Rig

in the BakkenTrent Jacobs, JPT Senior Technology Writer

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The wells were in conventional reser-

voirs in the Permian Basin, some dating

back to the mid-century years he referred

to as when far fewer wells were fractured

but a significant number were refrac-

tured, often multiple times. The point

was that there is money to be made on

the oil left behind in reservoir rock thatis of far higher quality than the uncon-

ventional rock layers, which have got-

ten far more attention and investment in

recent years.

“With the growing numbers of aging

wellbores, rework in the existing zones

such as refracturing helps to reduce tem-

porarily abandoned well counts, increase

production rates, and often reserves,”

he said, adding, “the ‘rework inventory’

remains high and economically attrac-

tive for Permian Basin operators.”A campaign in 2010 and 2012 cov-

ering more than 70 wells yielded an

80% success rate, which Babani-

yazov defined as a production gain that

allowed payback on the investment with-

in 6 months to a year. The cost varied

because the nature of the work ranges

from acidizing to refracturing or deep-

ening the well. While the latter options

cost more, they also offer higher poten-

tial gains.

The price collapse has put the pro-gram on hold at a time when spend-

ing has been slashed, and the outlook

is uncertain because prices for oil and

services are so hard to predict. “When

I was involved, it was USD 50/bbl and

now it is what, 29 a barrel?” he said

during a presentation in mid-Jan-

uary. “USD 30/bbl is not the same as

USD 50 bbl.”

ConocoPhillips’ campaign was start-

ed because it had a significant number

of wells dating back as far as the 1960s,when production had dwindled to the

level at which the company needed to

spend to increase the output or plug and

abandon the wells.

A way was lacking to identify which

of the wells would be candidates, and

rank which offered the greatest poten-

tial payoff. There was limited indus-

try experience to draw on. Industry

reports on refracturing tend to focus

on successes, with little data avail-

able about the ones that had failed andthe causes.

The answer to the question was com-

plicated. Based on the slides shown dur-

ing Babaniyazov’s presentation, screen-

ing required answering many questions.

At the top of the list: Are there sig-

nificant volumes of good quality res-

ervoir that have not been tapped. He

said a study showed wells in the Perm-

ian in which 30% of the reserves had

been bypassed.

The condition of the steel casingand cement around it is also critical. A

cement bond log estimating that 95% of

the cement is sound leaves enough room

for a channel that can divert fluid and

undercut the effectiveness of the fractur-

ing work.

The targets were a mix of new and

old. Some aimed at hitting newer res-

ervoir rock in higher-pressure zones,

others were designed to improve the

output from older reservoir sections in

which flow assurance was often a prob-lem. Refracturing could open produc-

tion pathways where there has been

“degradation of fracture conductivity

over time.”

The success of the program required

cooperation among a wide range of

exploration professionals, from geolo-

gists seeking out untapped rock to frac-

turing engineers considering the best

way to divert fluid so it reached the

targeted areas. Success also depend-

ed on training the field staff to gatherthe critical information, such as doing

mini-frac tests to measure localized

pressure levels, which are needed to

evaluate the local formation pressure

levels required to assess the potential

refracturing yield.

The system may still be of use in what

will be a period of extended low prices,

but that will have to be verified.

“You have time to go back to the draw-

ing board,” Babaniyazov said. Technical

and economic success will require usingthis analysis to determine the risks and

rewards of refracturing, ensure the well

is sound, and identify which diversion

techniques are the best options.

Drawdown Management Critical to Mitigating EUR Losses

in Shale Wells

Stephen Whitfield, Staff Writer

The increase in production from hydrau-lic fracturing operations in recent years

has had a dramatic effect on the oil and

gas industry. However, as shale plays

have taken up a larger percentage of the

overall market, annual decreases in esti-

mated ultimate recovery (EUR) values

for shale wells is now a major concern

for operators.

At a presentation hosted by the SPE

Gulf Coast Section, Ibrahim Abou-Sayed

discussed how the adoption of draw-

down management strategies have

helped mitigate and reduce these losses.Abou-Sayed, the founder and president

of i-Stimulation Solutions, also spoke

about the elements of drawdown man-

agement that have been found to have

the most significant impact on shale

well productivity.

In the presentation, titled “Shale Well

Drawdown Management and Surveil-

lance to Avoid EUR Loss and Impact on

Refracturing,” Abou-Sayed listed several

parameters that affect production man-

agement strategies. Among them were

the permeability of the formation andvarious types of pressures, such as the

initial reservoir pressure, the pressure

at the safety relief valve, and the closure

pressures on the hydraulic fracturing

proppant and unpropped fracture sur-

faces. Abou-Sayed said downhole flow

pressure, reservoir pressure, and choke

size are the parameters over which oper-

ators can exert the greatest control.

“When you are locating the reservoir

or reducing the downhole pressure, you

are putting more closure pressure on the

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proppant, and you are closing the non-

propped fracture,” he said. “You have to

take all of that into consideration, oth-

erwise you will see your productivity go

way down very quickly.”

Abou-Sayed discussed the Haynesville

Shale Development Program. Launched

by Exco Resources in March 2008, theprogram sought to increase production

in the Haynesville Shale reservoir locat-

ed in east Texas and northern Louisiana.

The Haynesville shale was deter-

mined to be soft and friable, potential-

ly supporting proppant embedment and

negatively impacting production. As a

result, the company implemented a con-

trolled drawdown strategy in the wells’

early lives. The methodology involved

the development of a maximum draw-

down limit based on well depth, reser-voir pressure, bottomhole flowing pres-

sure, and critical closure stress on the

proppant pack.

After initial testing on some of its ver-

tical wells, Exco applied a finalized draw-

down method to every vertical well and

an additional horizontal well, which was

produced with increasing choke sizes

to help maximize early water recovery

while maintaining the drawdown below

the maximum limit. Production from the

horizontal well was shown to be similar

to the vertical wells, but the horizontal

well’s pressure profile was significant-

ly higher and declined at a slower rate.

Exco concluded that this was because it

could maintain sufficient backpressure.

Abou-Sayed said it is important, but

not critical, to find an accurate bottom-

hole pressure when determining themaximum drawdown level.

“It’s not going to kill you immediately,”

he said. “What we have seen with many

companies is that they’ll have different

drawdown criteria from the first week to

the second week, and from the second

week to the third week.”

As shale formations are fractured

under local conditions, the maximum

drawdown level is not measured from the

initial reservoir pressure. Abou-Sayed

said operators should observe reservoirpressure at three times: at the time of

perforation, on the day the well is opened

up to fracture, and during the first stage

of production. Tighter formations often

create higher pressures.

Abou-Sayed said the drop in EUR val-

ues is in part due to low effective system

permeability and the design and imple-

mentation of ineffective completion

and stimulation strategies. In addition,

he said physical deformations some-

times cause excessive fracture conduc-

tivity loss. This leads to a lost connec-

tion between the well, the fracture, and

JPT march 2016

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