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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
Solutions for the Life Cycleof Your Well
WELL INTERVENTION
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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
TECHNOLOGY FOCUSWe giveyou thesuperpowersyou’vealwaysdreamed of.Introducing the world’sfirst X-Ray technologyfor oil wells.VISURAY’s revolutionary VR
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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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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
BETTER with
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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 president@spe.org.
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 y@spe.org.
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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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4 JPT • MARCH 2016
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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6 JPT • MARCH 2016
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.
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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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19JPT • MARCH 2016
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.
For additional information, visit
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.
For additional information, visit
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.
For additional information, visit
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
For additional information, visit
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
0 JPT • MARCH 2016
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
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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
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2 JPT • MARCH 2016
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.
8/18/2019 JPT march 2016
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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
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Casing XRVTTS Drilling Solution’s
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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 • info@ttsdrilling.com
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
6 JPT • MARCH 2016
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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27JPT • MARCH 2016
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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8 JPT • MARCH 2016
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
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