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JUNE 2015
COILED TUBING APPLICATIONSMATRIX STIMULATIONWELLBORE TUBULARS
EOR OPERATIONS
Drilling AutomationIndustry Adapts to Low PricesWellbore Survey ManagementGood Reservoir Stewardship
FEATURES
JOURNAL OF PETROLEUM TECHNOLOGY www.spe.org/jpt
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June15_JPT_Cover.indd 1 5/13/15 9:13 AM
Start producing fullbore. Dissolvable plug and perf.The In nity* fullbore interventionless stimulation systemthe next step in plug-and-perf operationsuses degradable
frac balls and degradable ball seats that leave absolutely nothing in the well that would impede production.
Fullbore ow helps ensure that production reaches its full potential. Completely eliminating milling interventions and
all wellbore restrictions now makes multistage stimulation many times more ef cient and cost-ef ective.
Find out more at
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InfinityDISSOLVABLE
PLUG AND PERF SYSTEM
Before
After
The Infinity sytem is engineered to dissolve completely.
6 Performance Indices
10 Regional Update
12 Company News
14 Presidents Column
20 Comments
24 Technology Applications
32 Technology Update
42 Young Technology Showcase
46 E&P Notes
123 SPE News
124 People
125 Professional Services
127 Advertisers Index
128 SPE Events
Cover: Curved mirrors focus the suns light energy to create steam for use
in an enhanced oil recovery project
in Oman. The solar EOR pilot is the
first of its kind in the Middle East.
A synopsis of paper SPE 169745
examines the performance, results,
and learnings from the project
on page 111. Photo courtesy of
GlassPointSolar.
18 STRENGTHENING THE BRAND IDENTITY OF SPES EVENTS The Society seeks to deliver a consistent experience for attendees and
exhibitors with the definitions of six event formats.
22 GUEST EDITORIAL KEEPING RESERVOIR STEWARDSHIP ON COURSE As conventional reservoir evaluation comes under threat in a low oil price
environment, one hopes that operators will resist the temptation to cut
back on essential data acquisition.
50 AUTOMATED DRILLING TECHNOLOGIES SHOWING PROMISE Automated drilling systems under development are increasingly being
used as a way to lower costs, but their uptake may be slowed down
during a period of low oil prices.
58 PROFITS POSSIBLE AT LOW OIL PRICES BUT TOUGH CHANGES REQUIRED At the IHS CERAWeek conference, speakers said the transition will put
pressure on unconventional oil producers to reduce costs and bring in
new ways of operation.
66 BETTER SURVEY MANAGEMENT MAKES WELLS SAFER AND MORE PRODUCTIVEDo you know where your wellbore is? The SPE Wellbore Positioning
Technical Section aims to make drilling safer, optimize production, and
maximize reserves recovery.
70 MINING DAILY DRILLERS REPORTS FOR TELLING PATTERNS BP is pushing the envelope with a system that searches written logs to
extract useful patterns and insightful information that could help avert
trouble or improve drilling operations.
72 Q&A AHMAD AL-KHOWAITER, CTO, SAUDI ARAMCO The chief technology officer says the company believes that being
competitive in technology is essential to the future of the oil and gas
industry.
74 SPE PUBLISHES TECHNICAL REPORT ON WORST-CASE DISCHARGES Recording the consensus from a SPE-sponsored summit, the report
focuses on the calculation of discharges rather than well design or
intervention for primary use in the US Gulf of Mexico.
76 OFFSHORE EUROPE TO ADDRESS TALENT SHORTAGE AND PEOPLE-RELATED CHALLENGES To be held in Aberdeen under the theme of How to Inspire the Next
Generation, the biennial conference will feature papers on people-related
topics for the first time.
An Official Publication of the Society of Petroleum Engineers.Printed in US. Copyright 2015, Society of Petroleum Engineers.
Volume 67 Number 6
HOW DO YOU ENSURE THEINTEGRITY OF YOUR MOSTCHALLENGING WELLS?
Archer CfexDELIVERING A NEW ERA IN WELL INTEGRITY
Built to perform secure cementing
operations in any situation, Cflex
uses advanced technology to
improve the annulus seal. Its
been specifically engineered
to meet the highest possible
integrity standard, while providing
the custom-built flexibility to
accommodate any flow rates you
may face. And its gas-tight seal has
earned VO qualification through its
rigorous testing equivalent to the
ISO 14998 (formerly ISO 14310) and
API 11D1 standards. Combined with
a slim design and revolutionary
large flow area ports that boost
operational eficiency and
performance. Cflex is ultimately
able to deliver a multistage
cementing solution to safely fit
any drilling situation.
archerwell.com/qa
Cflex
Cflex Dart Catcher
Cflex m
ultifunction operating tool
controls Cflex selectively and precisely.
TECHNOLOGY
The complete SPE technical papers featured in this issue are available
free to SPE members for two months at www.spe.org/jpt.
78 Coiled Tubing Applications
Alex Crabtree, SPE, Senior Adviser, Hess Corporation
79 Development of Improved High-Strength Coiled Tubing
82 Microbial-Influenced-Corrosion-Related Coiled-Tubing Failures andEquipment Damage
86 Coiled-Tubing-Deployed Shutoffs in Alaska With a Polymer Gel andMicrofine Cement
90 Matrix Stimulation
Lee Morgenthaler, SPE, Senior Staff Production Chemist, Shell
91 Visualization of Acid Treatments With 3D Nuclear-Magnetic-Resonance Imaging
94 Monitoring Acid-Stimulation Treatments With Slickline Distributed-Temperature Sensing
97 Use of Weak-Acid and Nonacid Alternatives in Acidizing HorizontalWells
100 Wellbore Tubulars
Pat York, SPE, Global Director, Weatherford
101 Detection of Kicks With Networked Drillstring and Along-String Pressure Evaluation
104 Development of Drillpipe-Riser-Intervention Systems Offshore West Africa
107 Reducing Tubing Failures in the Tambaredjo Field, Suriname
110 EOR Operations
Stephen Goodyear, SPE, EOR Deployment Lead, Shell
111 Pilot Steam Generator Uses Solar Energy Successfully for EOR Operations in Oman
114 Pilot to Full-Field Polymer Application in One of Indias Largest Onshore Fields
117 Magnus Water-Alternating-Gas-Pattern Optimization Through DataIntegration
120 Field Pilots Show Effectiveness of Foams in Low-Porosity Naturally Fractured Reservoir
Find out more at
slb.com/OptiDrill
REAL-TIME DRILLING
INTELLIGENCE SERVICE
OptiDrill
Know what is happening downhole. Drill with confidence.
Drilling & Formation Evaluation | Well Construction | Completion & Stimulation | Production
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CEMENT & CASING INTEGRITY EVALUATION
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SPE PUBLICATIONS: SPE is not responsible for any
statement made or opinions expressed in its publications.
EDITORIAL POLICY: SPE encourages open and objective
discussion of technical and professional subjects per-
tinent to the interests of the Society in its publications.
Society publications shall contain no judgmental remarks
or opinions as to the technical competence, personal
character, or motivations of any individual, company, or
group. Any material which, in the publishers opinion,
does not meet the standards for objectivity, pertinence,
and professional tone will be returned to the contribu-
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accepts advertising (print and electronic) for goods and
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technical or professional interests of its readers. SPE
reserves the right to refuse to publish any advertising it
considers to be unacceptable.
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that or the above permission: (1) libraries and other users
dealing with the Copyright Clearance Center (CCC) must
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at SPE Americas Office in Richardson, Texas, USA, or
e-mail [email protected] to obtain permission to make
more than five copies or for any other special use of
copyrighted material in this journal. The above permis-
sion notwithstanding, SPE does not waive its right as
copyright holder under the US Copyright Act.
Canada Publications Agreement #40612608.
Glenda Smith, Publisher
John Donnelly, Editor
Alex Asfar, Senior Manager Publishing Services
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JPT STAFF
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Drilling & Formation Evaluation ____
Well Construction ____
Completion & Stimulation ____
Production
2015 Weatherford. All rights reserved.
ITS ALL IN THE WAY
WEREWIRED.
From comprehensive formation
evaluation to full casing analysis,
our wireline services help you manage
every aspect of your operations
in both openhole and cased-hole wells.
Explore the full breadth of our wireline
services at weatherford.com/wireline
WIRELINE SERVICES
ACOUSTICS GEOMECHANICS PULSED
360-IMAGING POROSITY AND LITHOLGY
GEOLOGY RESISTIVITY NUCLEAR
MAGNETIC RESONANCE TESTING AND PVT
SAMPLING SIDEWALL CORING RESER
EVALUATION WIRELINE GEOLOGY
MECHANICAL INTERVENTION PLUGBACK
SERVICES PERFORATING PIPE RECOVER
GEOLOGY PRODUCTION LOGGING
PULSED NEUTRON SEISMIC PROPELLANT
STIMULATION MICROSEISMIC SEISMIC
PROFILE GEOPHYSICS GEOMECHANICS
PIPE RECOVERY PULSED NEUTRON
66 JPT JUNE 2015
PERFORMANCE INDICES
WORLD CRUDE OIL PRODUCTION+
THOUSAND BOPD
OPEC 2014 JUL AUG SEP OCT NOV DEC
Algeria 1420 1420 1420 1420 1420 1420
Angola 1740 1813 1823 1848 1813 1733
Ecuador 558 558 551 557 563 561
Iran 3230 3230 3230 3230 3230 3230
Iraq 3195 3225 3515 3465 3425 3775
Kuwait* 2650 2650 2650 2575 2500 2500
Libya 435 530 785 950 615 500
Nigeria 2470 2520 2470 2320 2440 2440
Qatar 1553 1553 1513 1513 1503 1503
Saudi Arabia* 9840 9740 9640 9740 9640 9640
UAE 2820 2820 2820 2820 2820 2820
Venezuela 2500 2500 2500 2500 2500 2500
TOTAL 32411 32559 32917 32938 32469 32622
THOUSAND BOPD
NON-OPEC 2014 JUL AUG SEP OCT NOV DEC
Argentina 525 529 540 539 534 534
Australia 353 355 362 346 360 354
Azerbaijan 870 912 822 842 792 842
Brazil 2267 2326 2358 2393 2358 2497
Canada 3629 3547 3595 3717 3704 3678
China 4084 4118 4175 4224 4290 4315
Colombia 971 1002 996 1004 1004 1009
Denmark 159 173 165 175 190 182
Egypt 477 474 471 468 465 462
Eq. Guinea 248 248 248 248 248 248
Gabon 240 240 240 240 240 240
India 757 728 757 774 782 773
Indonesia 800 787 786 772 786 778
Kazakhstan 1641 1646 1559 1578 1716 1778
Malaysia 560 562 577 613 670 671
Mexico 2427 2455 2430 2402 2391 2290
Norway 1605 1556 1519 1625 1610 1624
Oman 957 953 958 938 921 932
Russia 10003 10056 10079 10176 10173 10197
Sudan 258 257 257 257 257 257
Syria 23 23 22 21 21 21
UK 705 467 747 790 798 842
USA 8716 8757 8923 9060 9039 9226
Vietnam 288 304 285 283 282 291
Yemen 129 128 126 125 125 113
Other 2521 2473 2523 2449 2510 2524
Total 45213 45076 45520 46059 46266 46678
Total World 77624 77635 78437 78997 78735 79300
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Contact us today for more information.
JPT JUNE 2015
PERFORMANCE INDICES
HENRY HUB GULF COAST NATURAL GAS SPOT PRICE*
WORLD ROTARY RIG COUNT
REGION2014 OCT NOV DEC
2015 JAN FEB MAR APR
US 1925 1925 1882 1683 1348 1110 976
Canada 424 421 375 368 363 196 90
Latin America 393 375 369 351 355 351 325
Europe 148 149 148 128 133 135 119
Middle East 390 403 403 415 415 407 410
Africa 125 142 138 132 132 125 120
Asia Pacific 252 255 255 232 240 233 228
TOTAL 3657 3670 3570 3309 2986 2557 2268
WORLD CRUDE OIL PRICES (USD/bbl)
109.54 102.18 111.80 105.79 106.77 103.59 101.61 96.54
2014 MAY JUN JUL AUG
97.09 93.21 87.43 84.40 79.44 75.79 62.34 59.29
SEP OCT NOV DEC
47.76 47.22 58.10 50.58 55.89 47.82 59.52 54.45
2015 JAN FEB MAR APR
Brent WTI
WORLD OIL SUPPLY AND DEMAND1
MILLION BOPD 2014 2015
Quarter 2nd 3rd 4th 1st
SUPPLY 92.42 93.53 94.62 94.00
DEMAND 91.40 92.86 92.84 92.38
INDICES KEY + Figures do not include NGLs and oil from nonconventional sources. * Includes approximately one-half of Neutral Zone production.
1 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. * The US Dept. of Energy/Energy Information Administration discontinued its reporting of US Natural Gas Wellhead
Prices, replacing them with Henry Hub Gulf Coast Natural Gas Spot Prices.
Source: US Dept. of Energy/Energy Information Admin.
6
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JAN
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USD/Mil. BTUs
200
0
400
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800
1000
1200
1/1
1/8
1/15
1/22
1/29
2/5
2/12
2/19
2/26
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3/11
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4/22
4/29
5/6
5/13
5/20
5/27
6/3
6/10
6/17
6/24
7/1
7/8
Bbls. CBT Oil Production Daily Total 2012
CnF Foamer Pumped
More oil,
less Cost
For more information contact
[email protected] call
832-308-Cesi (2374)
CnF Foam Conformance Modifer
the feld in the above graph was under a Co2 food and the project was not meeting expectations. After injecting Cesis CnF
foam conformance modifer, an incremental increase of approximately 14,000 barrels of oil was produced at a total cost of less than $0.60 per barrel this production increase has persisted for more than 6 months!
The patented Anti Stick-slip Tool (AST)
responds to torque spikes or stick-slip
action from polycrystalline diamond cutters
(PDC) by releasing the load, reducing the
depth of cut (DOC) and re-applying load as
needed. This results in a steady torsional load,
reduced vibration and low risk to bottom
hole components. The parameter window is
simultaneously expanded to allow for signifcant
increases in the rate of penetration.
Learn how AST works and how to implement at:
tomax.no
Contact us:
Aberdeen: +44 1224 561313
Houston: +1 713 557-7542
Stavanger: +47 51 95 11 70
Rio de Janeiro: +21 3497-5083
A North Sea operator
experienced great vibration
challenges in a 16 hole
when ECD limitations
required the addition of
a 17 underreamer. By
implementing AST at the
same time, the vibration
issue was solved and the
achieved savings resulted
in the solution being
nominated for Best Process
Improvement of that year.
STRINGERS ENLARGEMENT ROUGH SEAS PERFORMANCE INTERVENTION
The AST is being used in an increasing number of applications:
SAVINGS THROUGH
CHALLENGING FEET
2100
1900
1500
1100
1300
1700
900
700Depth TVD (m)
Time (days)10 20 30 40 50 60
Sections using 16 x 17 underreamer, AST and rotary steerable system
Sections drilled using plain 16 bit and rotary steerable system
Time (hours)
REGIONAL UPDATE
10 JPT JUNE 2015
AFRICA
Vaalco Energy started oil production
from the Etame 12-H development well
offshore Gabon. The well was drilled
to ameasured depth of approximately
3450 m and was targeting the recently
discovered lower lobe of the Gamba
reservoir. It was brought on line at a rate
of 2,000BOPD with no indication of
hydrogen sulfide. Vaalco (28.07%) is the
operator with partners Addax Petroleum
(31.63%), Sasol(27.75%), Tullow Oil (7.5%),
Sojitz (2.98%), and PetroEnergy(2.34%).
ASIA
KrisEnergy started drilling the
Rossukon-2 exploration well on Block
G6/48 in the Gulf of Thailand, using
the Key Gibraltar jackup rig. The well
will reacha total depth at 5,462 ft and
will testEarly Miocene stacked fluvial
sandstones on a broad structural high.
The well will also appraise the Rossukon-1
reservoir, which produced 850 BOPD
during tests. KrisEnergy (30%) is
the operator with partners Northern
Gulf Petroleum (40%) and Mubadala
Petroleum (30%).
AUSTRALIA
AWE expanded its oil production in the
Tui area offshore New Zealand by bringing
the Pateke-4H development well on line in
PMP 38158. The tieback project involved
the installation of 1312 m of flexible
flowline, a gas lift umbilical, integrated
controls, and ancillary equipment at water
depths of approximately 124 m. The initial
flow rate was 34,000 BOPD. AWE (57.5%)
is the operator with partners New Zealand
Oil and Gas (27.5%) and Pan Pacific
Petroleum(15%).
Woodside Burrups Pyxis-1 exploration
well in offshore production license
WA-34-L intersected approximately
18.5 m of net gas pay within its Jurassic
sandstone target in Western Australia. The
well reached a total depth of 3347 m and
lies 15 km north of Woodsides producing
Pluto gas field. Wireline logging confirmed
the discovery through gas samples, which
were brought to the surface, along with
the detection of a gas pressure gradient.
Woodside (90%) is the operator with
partners Kansai Electric Power Australia
(5%) and Tokyo Gas Pluto (5%).
Santos made a wet gas discovery in
Cooper basin in Queensland, Australia.
The Emery-1 exploration well was drilled
to a total depth of 3262 m and intersected
gas in the Patchawarra formation, which
contained stacked reservoirs. The well has
been cased and suspended as a future gas
producer. Santos (60%) is the operator
with partner Drillsearch (40%).
EUROPE
Maersk Oil started oil and gas
production from its unmanned Tyra
Southeast-B platform, which sits 220 km
off Denmarks west coast in the North
Sea. Maersk plans to drill a total of 8 to 12
horizontal wells in the area over the next
2 years. The development is expected
to deliver approximately 50millionBOE
in resources, 20 million bbl of oil and
170Bcf of gas. The field is operated by
the Danish Underground Consortium,
which is madeup of Maersk (31.2%),
Shell (36.8%),Nordsfonden (20%),
andChevron (12%).
MIDDLE EAST
Qatargas sold its first cargo of liquefied
natural gas (LNG) to Pakistan State Oil.
The transaction is the first LNG agreement
between Qatar and Pakistan and the
first LNG import deal for any entity in
Pakistan. The delivery commissioned the
Excelerate Exquiste, which will be used as
a floating storage and regasification unit
when it is moored at Port Qasim, as part
of the Elengy terminal, Pakistans first LNG
importfacility.
NORTH AMERICA
ExxonMobil started production
fromthe Hadrian South gas field,
whichislocated 230 miles south of
Louisiana in theUS Gulf of Mexico. The
field sits at a water depth of 7,650ft,
making it the companys deepest
subseatieback. Hadrian South is
expectedto reach a peakproduction of
300 MMcf/Dof naturalgas and 3,000B/D
of liquids. ExxonMobil (46.7%) is the
operator with partners Eni (30%) and
Petrobras (23.3%).
SOUTH AMERICA
Premier Oil discovered a net 81 ft of
oil-bearing reservoir and a net 55 ft of
gas-bearing reservoir at its Zebedee well,
offshore the Falkland Islands (Malvinas).
The well penetrated multiple targets in
the Cretaceous F2 and F3 formations,
with pay concentrated primarily in the
Hector and Zebedee sands. Premier (36%)
is the operator with partners Falkland
Oil and Gas (40%), and Rockhopper
Exploration(24%).
Karoon Gas Australias Echidna-1 well
has intersected an oil-bearing section
of Paleocene sands in Block S-M-1102 of
the Santos basin, offshore Brazil. Mud
logs showed elevated gas readings and
oil florescence in the sandstones. Future
wireline logging will reveal the volume of
gross and net oil and gas pay. Additional
intervals of interest have been identified
in the Maastrichtian section and will be
evaluated during the wireline program.
Karoon (65%) is the operator with partner
Pacific Rubiales Energy (35%).
LGO Energy has spudded GY-672, the
first of seven wells that it plans to drill at
the Goudron field in Trinidad. The well will
be drilled to 3,505 ft measured depth and
is targeting a C-sand reservoir interval,
approximately 420 ft to the east of the
surface location. In total, the program
will involve the perforation of 275 ft of
C-sand reservoirs and 955 ft of Goudron
sandstone reservoirs. LGO is the operator
and holds 100% interest in the field.
Petrobras discovered oil in Amazon
basins Block AM-T-84. The discovery was
made while drilling well 1-BRSA-1293-AM,
which reached a total depth of 2040m.
Preliminary tests have confirmed the
presence of light, 47 API gravity oil in
arenaceous reservoirs, extending from
1350m to 1900 m deep. Petrobras (60%)
is the operator of the concession with
partner Petrogal Brasil (40%).
Petrobras discovered an onshore oil
accumulation in the Esprito Santo basin,
120 km from Vitria, Brazil. The reservoirs
are located at a depth of 711 m and the
well was drilled to a total depth of 1312 m.
Petrobras is the operator and holds 100%
interest in Block ES-T-495. JPT
Seismic_on_Demand-JPT.pdf 2 5/11/15 12:58 PM
COMPANY NEWS
12 JPT JUNE 2015
MERGERS AND ACQUISITIONS
Royal Dutch Shell has offered to acquire BG Group for approximately
USD70 billion in a deal made up of
common shares and cash. The transaction
will significantly expand Shells liquefied
natural gas (LNG) business and is
expected to close next year.
Sanchez Energy closed a deal with a subsidiary of Sanchez Production
Partners to sell wellbore and associated
interests in producing oil and gas
wells worth USD 83 million in cash and
approximately 1 million common shares,
valued at USD 2 million. The assets
are located in different parts of Texas,
including Sanchezs nonoperated Palmetto
field in the Eagle Ford Shale, and supply
2% of Sanchezs net production.
Penn West Petroleum has entered into a USD 321 million agreement with
Freehold Royalties to sell an 8.5% gross
overriding royalty in its working interests
in the Viking oil play in the Dodsland area
of Saskatchewan, Canada. The deal also
includes existing royalties and mineral
title lands in Alberta, Saskatchewan,
andManitoba.
Bonterra Energy has acquired Cardiumformation-focused assets in the
Pembina area of Alberta, Canada, from
an unnamed oil and gas producer for
USD 138million. With this transaction,
the company has added approximately
1,800 BOEPD of low-decline, conventional
oil and gas liquids to its production. The
property contains 9.9million BOE of
proved reserves.
Petrobras has sold its assets in Argentinas Austral basin to Compaia
General de Combustibles for
USD101million. The property includes
26onshore exploration concessions
withanaverage production of
15,000BOEPD, and the infrastructure
required fordistribution, treatment, and
storage. This is the first asset that Petrobras
has sold in its 20152016 divestment plan,
which will see the company sell a total of
USD 13.7 billion inassets.
Pemex signed an agreement worth USD 1 billion with private equity firm
First Reserve to jointly invest in energy
infrastructure in Mexico. The first
investment is the Los Ramones pipeline
system, which is under construction and
will consist of 744 km of natural gas
pipelines. Commercial operations for
the system are expected to begin in the
middle of next year.
Gulfport Energy entered into an agreement to acquire Paloma Partners
III for USD 300 million. Paloma holds
approximately 24,000 net nonproducing
acres in a core area of the dry gas
window of the Utica shale in Belmont and
Jefferson counties in Ohio. The transaction
is expected to close in the third quarter of
the year.
Resolute Energy has signed an agreement with an unnamed buyer to sell
noncore assets in the Midland basin for
approximately USD 42 million. The assets
consist of operated and nonoperated
properties in Howard County in Texas,
and proceeds from the sale will be used to
reduce the companys debt.
COMPANY MOVES
Peak Well Systems has completed the construction of its new gas pressure
testing facility in Aberdeen. The facility
will enable the company to conduct
in-house ISO 1431 validation testing of
its product lines up to the highest V0
grade. The facility is equipped to conduct
testing at temperatures of up to 392F
and pressures of up to 15,000 psi for
prolonged periods of time in simulated
gaswells.
Tam International, which provides inflatable and swellable packers for the oil
and gas industry, has opened a new office
in Stavanger. The office will be run by
Colin Graham, Norway country manager.
CONTRACTS
Hercules Offshore has signed a 5-year contract with a subsidiary of Eni for the
use of its Hercules 260 jackup rig offshore
West Africa. The day rate will range from
a minimum of USD 75,000 per day when
Brent crude falls below USD 86/bbl to a
maximum of USD 125,000 per day when
Brent crude exceeds USD 125/bbl. The
contract began in April.
Fugro was awarded a 5-year contract worth USD 100 million by Total Congo
E&P. It will provide remotely operated
vehicle (ROV) services and remote
subseatooling for the Moho Nord field,
which lies 75 km off the Republic of the
Congo. Four ROV systems and blowout
preventer tooling will be installed on
three mobile drilling units and one field
supportvessel.
Harkand has secured a USD 5 million contract from Swiber Offshore Mexico
toperform saturation diving services
for an offshore pipeline project. It also
entered a joint venture with Mexican
service firm, Arena Servicios de Mexico.
Harkand Arena will complete a wide-
ranging scope of work, including the
installation of risers and expansion spools
at the Ayatsil field, in the waters of the
Campeche Sound.
Two Bumi Armada subsidiary companies secured USD 300 million
worth of contracts from ElectroGas for
the conversion, supply, operation, and
maintenance of a floating storage unit
(FSU) in Malta. The unit will be used in
the establishment of an LNG receiving
terminal in Delimara. The contract has
a duration of 18 years and 2 months,
and operations are expected to begin
nextyear.
Amec Foster Wheeler has been awarded a contract by BP worth more
than USD 73 million. The company will
provide operations, maintenance, and
project support for the Forties Pipeline
System and the Central Area Transmission
System terminal in Teesside, United
Kingdom. The FPS connects oil and gas
fields in the North Sea to onshore facilities
in the UK. The contract will create 90 jobs
and two apprenticeships. It will run until
January 2020 and will be managed from
the companys Aberdeenoffices.JPT
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ENERGY 360
14 JPT JUNE 2015
Questions posed by 2015 SPE President
Helge Hove Haldorsen
Answers provided by Rune Mode
Ramberg, Chief Engineer Subsea
Technology & Operations, Statoil
Steve Thurston, Chevrons vice president of deepwater exploration and projects com-
pares developing US Gulf of Mexico oil fields like Jack and St. Malo in 7,000 ft to the
1969 moon landing: Except we are going to the moon every day! It really is impres-
sive to see how offshore and subsea technology have evolved over the years. Of the
worlds current oil demand of approximately 93 million BOPD, some 27 million BOPD
or 30% comes from offshore fields and the offshore contribution is expected to con-
tinue to grow according to Douglas-Westwood World Drilling & Production Market
Forecast 2005-2021.
The Norwegian Continental Shelf (NCS) is among the front-runners in subsea
technology developments and applications. It is like a giant subsea and offshore 2.0
laboratory for the rest of the offshore world.
According to Statoil, it has more than 500 subsea wells and is the worlds largest operator in water depths greater than 100 m.
The Troll-Oseberg Gas Injection subsea template installed in 1991 supplies gas subsea from Troll to Oseberg, 48 km away, making a gravity drainage
recoverymechanism on Oseberg possible, resulting in a very high oil
recoveryfactor.
Through more than 150 multibranched subsea wells (two to six branches per well), individual Troll oil province development wells can connect with nearly
45,000 ft of productive reservoir.
Subsea water separation and subsea reinjection units have been successfully used on the Troll oil and Tordis field developments. At the Tyrihans 10%
additional recovery is achieved with injection of raw seawater from pumps on
the seafloor.
Snhvit and Ormen Lange are all-subsea offshore gas developments and sendunprocessed wellstreams to shore 90 and 75 miles from
shore,respectively.
Efficient subsea gas compression is the next challenge that the industry must face
to continue subsea development. When an offshore gas field is developed 100% by a
subsea development and the pressure falls because of production, compression will
be needed at some point to maintain the production rate. But, there is no platform to
Invited Perspective:
Another Worlds First From The
NCS: Subsea Gas Compression
Is Here Helge Hove Haldorsen, 2015 SPE President
SPE BOARD OF DIRECTORS
OFFICERS
2015 President
Helge Hove Haldorsen, Statoil
2014 President
Jeff Spath, Schlumberger
2016 President
Nathan Meehan, Baker Hughes
Vice President Finance
Janeen Judah, Chevron
REGIONAL DIRECTORS
AFRICA
Anthony Ogunkoya,
TBFF Upstream Oil and Gas Consulting
CANADIAN
Darcy Spady, Sanjel
EASTERN NORTH AMERICA
Bob Garland, Tetra Technologies
GULF COAST NORTH AMERICA
Bryant Mueller, Halliburton
MID-CONTINENT NORTH AMERICA
Michael Tunstall, Halliburton
MIDDLE EAST
Fareed Abdulla, Abu Dhabi Co. Onshore Oil Opn
NORTH SEA
Carlos Chalbaud, GDF Suez E&P UK
NORTHERN ASIA PACIFIC
Ron Morris, Roc Oil (Bohai)/Roc Oil (China)
ROCKY MOUNTAIN NORTH AMERICA
Mike Eberhard, Anadarko Petroleum
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 Pertamina
SOUTHWESTERN NORTH AMERICA
Libby Einhorn, Concho Oil & Gas
WESTERN NORTH AMERICA
Tom Walsh, Petrotechnical Resources of Alaska
TECHNICAL DIRECTORS
DRILLING AND COMPLETIONS
David Curry, Baker Hughes
HEALTH, SAFETY, SECURITY, ENVIRONMENT,
AND SOCIAL RESPONSIBILITY
Trey Shaffer, Environmental Resources Management
MANAGEMENT AND INFORMATION
J.C. Cunha, Chevron
PRODUCTION AND OPERATIONS
Shauna Noonan, ConocoPhillips
PROJECTS, FACILITIES, AND CONSTRUCTION
Howard Duhon, Gibson Applied Tech PF&C
RESERVOIR DESCRIPTION AND DYNAMICS
Olivier Houz, KAPPA Engineering
DIRECTOR FOR ACADEMIA
Dan Hill, Texas A&M
AT-LARGE DIRECTORS
Khaled Al-Buraik, Saudi Aramco
Liu Zhenwu, China National Petroleum Corporation
To contact the SPE President, email [email protected].
15JPT JUNE 2015
put it onunless you build one. What about installing subsea compression and skipping the platform altogether? Is this even possible? I posed questions to Statoils chief engineer in subsea technology, Rune Mode Ramberg, regarding the latest subsea compression developments on the NCS.
Why is subsea compression a good idea?
Subsea compression is one of the most important contribu-tors to recovering additional oil and gas reserves, and provides future opportunities for improved recovery from a number of fields. Compression on the seabed also provides greater effect than a conventional topside compressor. The closer the com-pressor is to the well, the more effective it is, making extrac-tion more energy-efficient. In addition, the platform avoids the extra weight and space required by a topside compression module, which makes it more cost-effective as we cut capital and operating costs. A compressor sited on the seabed can be operated remotely from a land-based facility, also cutting sup-port costs. In addition, a study for sgard subsea compression shows that the carbon footprint of a subsea compressor is half that of a platform compressor because a subsea compressor is unmanned and improves personnel safety.
Why have so many subsea technologies come out of
Norway and the NCS?
Statoil is not afraid to try new things if it makes good business sense. We have a long-term perspective when we put efforts and resources into breaking technology barriers. Testing and quali-fying new solutions are vital to the success of our technological developments. In Norway, we have a long and strong tradition for qualifying new technology at near field conditions before a new project is making its final concept selection decision. A purpose-built test facility for subsea gas compressor technol-
ogy at Statoils large test center, K-lab, has been instrumental in order to qualify the new subsea compression technology.
Tell us how we got to where we are today?
Statoils subsea story began when we first put a subsea well in production on Gullfaks, 22 December 1986. Since then, we have developed subsea technology systematically and have taken courageous technology steps in good collaboration with our partners and the supplier industry. Collaboration is key as we are better together. Subsea technology has made all our field developments in greater than 200-m water depth pos-sible, among these: sgard, Norne, Snhvit, Tyrihans, Kris-tin, Troll oil province, and Aasta Hansteen starting up in 2017. Future resources are farther from shore, in deeper and colder waters. Innovative subsea technology is key to developing these resources commercially. The idea of subsea compression began 30 years agonow it is soon to be realized.
On which fields will it be installed and what is the value
creation potential?
Statoil is currently developing two subsea compression proj-ects together with its partners: subsea dry gas compression on sgard and subsea wet gas compression on Gullfaks, both vital technology innovations to increase oil recovery.
At the 15-year-old sgard field on the NCS, we installed two 11.5-MW compressors expected to extend the life of the field by up to 20 years, increasing the recovery rates by about a third, and adding approximately 282 million BOE in reserves. That is the size of a new medium-sized field. This spring, we are install-ing the compressor trains consisting of 22 modules on the sea-bed at approximately 300-m water depth.
We are also working on a smaller pair of compressors (5MW each) to be installed at the same time in a field close to
Statoil is developing a subsea wet gas compression project on the Gullfaks in the North Sea.
ENERGY 360
16 JPT JUNE 2015
the giant Gullfaks field, increasing recovery from the Gullfaks South Brent reservoir by 22 million BOE. The recovery rate can be increased from 62% to 74% on Gullfaks C using this solu-tion combined with conventional low-pressure production in a later phase. This is very good for a subsea field. Realizing subsea compression is an important milestone to reach in our ambi-tious technology development strategy. With it, we will be able to realize the subsea factory.
What were the key technical and other challenges to solve?
It is important to understand that the project is not only a subsea compressor project, although the compressor is the heart in the system. A comprehensive technology qualifica-tion program has been carried throughout the whole peri-od from 2007 to 2014. Testing and completion of the subsea modules took place during the last 2 years. Pipeline, pipeline end manifold, and spool installation were carried out during the 2013 season. Subsea structures and topside power mod-ule heavy lift installations were completed in 2013. Umbilical and module installation were started in 2014 and will be com-pleted later this year.We also had to build a new onshore base for storage and maintenance. To be able to install the modules on sgard, we have upgraded one of the existing offshore con-struction vessels,Technips North Sea Giant, with a new mod-ule handlingsystem.
Are there still residual risks?
The actual compressor for the first compressor train on sgard is currently being tested as it has been submerged in a big pool at Statoils test center at Krst, providing operating conditions that are similar to those awaiting the compressor at thesgard seabed. The requirements for equipment tobeplaced in 300 m of water, inaccessible to most, are strict.
The compressor train modules have been tested prior to installation to ensure that they are compatible and intercom-municate properly. We are also using very strict checklists andcontrol procedures for this project. For the Gullfaks subsea wet gas compression, testing has progressed through the final system integration tests. The results have been very positive.
Will we see subsea compression spread globally in a hurry,
like a subsea revolution?
Natural pressure in large gas fields will become too low over time to maintain a stable flow and a high production profile. To compensate for this decline, the operator needs to invest in a precompression system either on an existing platform, a new platform, or a subsea compression factory. For the sgard field, Statoil decided to install seabed compressors near the wellheads to increase the pressure. At the moment, we are working on several other business cases for subsea gas com-pression. It will take some time before we will see subsea com-pression spreading globally. But the combination of large gas fields and long tiebacks of subsea wells will create additional demands for subsea gas compression. So we should not be sur-
prised if the next wave of subsea gas compression is in Austra-lia or EastAfrica.
What is the next subsea frontier and are there still many
terra incognitas in subsea in your view?
At the moment, we are very concerned with the large cost increase the oil industry is facing. Statoil is promoting subsea industrialization and standardization for more cost-efficient field development through establishing visions and the steps to reach these through sharing technical specifications and participating in joint industry projects. This will create oppor-tunities if we are able to cooperate with the vendor industry to develop cost-efficient subsea solutions giving us high recovery rates. At the moment, development of large gas fields in deep water down to 3,000 m is a new subsea frontier. In a longer time frame, developing subsea facilities in the Arctic may well be the next frontier.
Explain this vision of a subsea factory?
A subsea factory is a process plant on the seabed making it possible to utilize remote-controlled transport of hydrocar-bons at any offshore facility. Statoil has gradually matured anddeveloped the idea of a subsea factory as the resources are farther from shore, in deeper waters, and in harsher areas. We believe compact separation facilities on the seabed will be a key to success in Arctic areas or deepwater areas like the Gulf of Mexico (US and Mexico) and Brazil. We have already taken the first technological steps. We have made the worlds first complete subsea solution for separation and injection of water and sand from the Tordis wellstream, and developed the first subsea facility for injection of raw seawater on Tyrihans. Proj-ects such as the oil-dominated multiphase transport on Tyri-hans and Snhvits gas condensate transport are at the fore-front in the development of multiphase transport over long distances. Thenext step is to realize subsea gas compression later this year.
With subsea compression, we now have all the main ele-ments. We can extract the oil and gas; we can separate oil, gas and water on the seafloor; inject the water back; and boost the oil and gas to a nearby facility.
Why has Statoil focused so much on subsea technologies?
The future of the oil and gas industry is out at sea. It is far-ther from land, at greater depths, and in colder, harsher envi-ronments. The subsea factory will be vital to realize busi-nessopportunities for Statoil in these areas. We have been in the forefront of subsea technology for 25 years. We have the experi-ence and the courage to take more brave steps subsea.
Conclusion
So there you have it. Another worlds subsea first has seen the light of day on the NCS. And there is no reason why the sub-sea story should end there. What does it take? Head, heart, guts,and collaboration! Think about it! JPT
2015 Baker Hughes Incorporated. All Rights Reserved. 42928 04/2015
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SPE BRAND
18 JPT JUNE 2015
The most powerful brands
are created and maintained by
deliveringdistinctive and consistent
experiences to the market.*
The way the Marriott Corp.** has brand-
ed its hotel chains is a great example.
Each chain is defined according to the
type of experience and amenities offered
to guests and this is consistent for each
one around the world.
After being approved by the many
SPE volunteers who serve on the inter-
national Board of Directors, SPE has
embarked to strengthen the brand of its
events by being consistent and clear with
their titles. The SPE volunteers wrote the
new naming convention policy based on
feedback from members that it should
be clear from the event title what the
technical content is and in which format
it will be delivered. You may see some
of your favorite events now advertised
with a slight change in name, but just
changing a word or two to provide clar-
ity will not change the event itself. Being
clear with the title will help to attract
the right attendees, authors, presenters,
andexhibitors.
A major effort with brand iden-
tity is ensuring that we are deliver-
ing a consistent experience for specif-
ic event formats. The following are six
event definitions that are the key to
strengthening the SPE brand identity.
Only the first three definitions are new:
conference, symposium, and training
course. The other three (forum, work-
shop, and summit) were approved by
the Board in 2007, but are included here
for clarity.
SPE Conference: An SPE conference
promotes the exchange of technical
knowledge primarily through technical
paper presentations, which are further
disseminated through publication in the
conference proceedings and later placed
on the OnePetro website. Conferences
typically feature an exhibition and are
managed by SPE staff.
SPE Symposium: An SPE symposium
may not be a fully papered program as
the technical program committee can
build the sessions from invited present-
ers and those selected through the call
for speakers process, if offered. SPE
manuscripts, if any, are disseminated
through OnePetro. In many cases, sym-
posia also feature an exhibition and are
either managed by SPE staff or by a sec-
tion that has hired SPE staff for some
services, such as call for papers.
SPE Training Course: An SPE training
course is one that has been reviewed and
approved for technical quality and rel-
evance by the Global Training Commit-
tee (GTC). A training course also may be
approved by a regional advisory com-
mittee or a regional conference plan-
ning committee when there is insuffi-
cient time for GTC review or there is no
intent to offer the course beyond a single
event. Continuing education units are
offered for completed courses.
SPE Forum: An SPE forum is an invita-
tion-only event that is developed and
approved by the Forum Series Coordi-
nation Committee to explore a specif-
ic and emerging industry challenge not
already addressed in existing SPE events.
A written summary may be prepared
and distributed to the participants after
the forum and with unanimous partici-
pant agreement at the discretion of the
program committee and SPE approval.
Forums do not offer a call for papers, pub-
lished presentations, sponsorships, or
exhibitions and are managed by SPEstaff.
SPE Workshop: An SPE workshop,
also referred to as an applied technol-
ogy workshop (ATW), features a techni-
cal program made up of presentations
on a highly focused topic solicited by
the program committee. Presentations
that have been authorized for release are
compiled and released to attendees after
the workshop. SPE staff work with sec-
tions and regional advisory committees
to provide the right number of work-
shops and relevant topics needed for
that particular geographical area.
SPE Summit: An SPE summit is a 1- to
3-day invitation-only event with specific,
predefined objectives that are managed
by SPE staff. It is a fast-track response
to emerging issues, problems, technol-
ogies, and strategies of broad signifi-
cance to the industry. Written records
of the discussions and conclusions are
published, with the intent of providing
a deliverable that benefits the indus-
try and has the potential to lead to fur-
therinitiatives. JPT
Strengthening the Brand Identity of SPEs
Meetings and Events
Shauna Noonan, ConocoPhillips, SPE Technical Director Production and Operations
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** http://www.marriott.com/marriott-
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15AD-GE-207-V1_PREG_Taurus_JPT_June.indd 1 07/05/15 11:00
COMMENTS
20 JPT JUNE 2015
A Pivotal Month
John Donnelly, JPT Editor
This month should offer key clues to the direction of the oil
market over the next several months. OPEC countries will meet
on 5 June in Vienna in a regular meeting to discuss their cur-
rent supply to the market and production quotas. And govern-
ment figures released this month should begin to get a better
handle on the decline in US production.
OPECs last meeting, in November, contributed to the
steep drop in oil prices when Saudi Arabia decided it would no
longer play the role of swing producer and would instead defend market share.
Although many took this as provocative, several executives speaking at the recent
IHS CERA conference in Houston noted that OPEC fears prolonged high oil prices
could lead to faster development of alternative energy, and the cartel is engaged
in a price discovery exercise to determine the sustainability of US shale produc-
ers. I think its going to be very useful to the industry to have a clear understand-
ing of the resilience of these resources, how robust the resources are, and how they
are able to withstand different price environments, said ExxonMobil Chief Execu-
tive Officer Rex Tillerson. Most of the executives at the conference agreed that the
current price downturn would last a while and that the current situation seemed
closer to the downturn that occurred in the mid-1980s, rather than more recent
price downturns.
The OPEC strategy is definitely having an impact on North American produc-
tion. The US Energy Information Administration last month lowered its 2015 and
2016 crude oil production growth forecasts. Its latest Short-Term Energy Outlook
predicts that US crude production this year will increase 530,000 B/D (revised down
from 550,000 B/D) and that 2016 growth will be 20,000 B/D (revised down from
80,000 B/D). US producers have cut spending, idled more than half of the countrys
drilling rigs, and eliminated thousands of jobs. The number of active rigs working in
the US had fallen for 23 weeks in a row as of mid-May.
US oil production averaged 9.3 million B/D in March but is expected to
begin declining in June. In contrast, Saudi Arabia has been increasing produc-
tion. It grew oil output to 10.31 million B/D in April, a slight increase from Marchs
total of 10.29 million B/D, the countrys highest oil production in three decades.
Saudi Arabia has increased output by 700,000 B/D since the fourth quarter
of 2014.
The price decline has had other repercussions. In a new industry survey by
Mercer, oil and gas industry employers have shifted from buying talent as their
core strategy to one of building talent instead. In a second survey, titled Inside
Employees Minds: What oil and Gas Employees Value, workers now rank job secu-
rity and base pay as their top concerns. Compared with previous oil industry surveys
and surveys in other industries, ranking job security over base pay is atypical. JPT
EDITORIAL COMMITTEESyed AliChairperson, Technical Advisor,
Schlumberger
Francisco J. Alhanati, Director, Exploration & Production, C-FER Technologies
William Bailey, Principal Reservoir Engineer, Schlumberger
Ian G. Ball, Technical Director, Intecsea (UK) Ltd
Luciane Bonet, Reservoir Engineering Manager, Petrobras America Inc.
Robert B. Carpenter, Sr. Advisor Cementing, Chevron ETC
Simon Chipperfield, Team Leader Central Gas Team/Gas Exploitation, Eastern Australia Development,
Santos
Nicholas J. Clem, Engineering Manager, BakerHughes
Alex Crabtree, Senior Advisor, Hess Corporation
Jose C. Cunha, Technical Training Leader, Chevron ETC
Alexandre Emerick, Reservoir Engineer, Petrobras Research Center
Niall Fleming, Leading Advisor Well Productivity & Stimulation, Statoil
Ted Frankiewicz, Engineering Advisor, SPEC Services
Emmanuel Garland, Special Advisor to the HSE Vice President, Total
Reid Grigg, Senior Engineer/Section Head, Gas Flooding Processes and Flow Heterogeneities, New
Mexico Petroleum Recovery Research Center
Omer M. Gurpinar, Technical Director, Enhanced Oil Recovery, Schlumberger
A.G. Guzman-Garcia, Engineer Advisor, ExxonMobil (retired)
Robert Harrison, Global Business Leader, Reserves & Asset Evaluation, Senergy
Delores J. Hinkle, Director, Corporate Reserves, Marathon Oil (retired)
John Hudson, Senior Production Engineer, Shell
Morten Iversen, Completion Team Leader, BG Group
Leonard Kalfayan, Global Production Engineering Advisor, Hess Corporation
Tom Kelly, Systems Engineering, FMC Technologies
Gerd Kleemeyer, Head Integrated Geophysical Services, Shell Global Solutions International BV
Jesse C. Lee, Chemistry Technology Manager, Schlumberger
Casey McDonough, Drilling Engineer, Chesapeake Energy
Cam Matthews, Director, New Technology Ventures, C-FER Technologies
Badrul H Mohamed Jan, Lecturer/Researcher, University of Malaya
Lee Morgenthaler, Staff Production Chemist, Shell
Alvaro F. Negrao, Senior Drilling Advisor, Woodside Energy (USA)
Shauna G. Noonan, Staff Production Engineer, ConocoPhillips
Karen E. Olson, Completion Expert, Southwestern Energy
Michael L. Payne, Senior Advisor, BP plc
Mauricio P. Rebelo, Technical Services Manager, Petrobras America
Jon Ruszka, Drilling Manager, Baker Hughes (Africa Region)
Martin Rylance, Senior Advisor, GWO Completions Engineering
Jacques B. Salies, Drilling Manager, Queiroz Galvo E&P
Otto L. Santos, Snior Consultor, Petrobras
Luigi A. Saputelli, Senior Production Modeling Advisor, Hess Corporation
Sally A. Thomas, Principal Engineer, Production Technology, ConocoPhillips
Win Thornton, Global Projects Organization, BP plc
Erik Vikane, Manager Petroleum Technology, Statoil
Xiuli Wang, Director, Minerva Engineering
Mike Weatherl, Deepwater Engineering Consultant, Well Integrity, LLC
Rodney Wetzel, Team Lead, SandFace Completions, Chevron ETC
Scott Wilson, Senior Vice President, Ryder Scott Company
Jonathan Wylde, Global Head Technology, Clariant Oil Services
Pat York, Global Director, Well Engineering & Project Management, Weatherford International
To contact JPTs editor, email [email protected].
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UNCONVENTIONALS
H039-15 JPT.indd 1 4/10/15 4:44 PM
22 JPT JUNE 2015
GUEST EDITORIAL
Bob Harrison, SPE,
is a consultant
petroleum engineer
who worked for
more than 20 years
with British Gas and
Enterprise Oil, and
currently advises
on international project delivery for LR
Senergy. Harrisons major interest is
rapid, accurate screening of oil and gas
assets. Harrison has edited textbooks on
formation evaluation and has published
more than 35 technical papers. He serves
on the SPE London Section Board and
is a Technical Editor for SPE Reservoir
Evaluation & Engineering. In 2014, he
received the SPE North Sea Region
Award for distinguished contribution to
petroleum engineering in Management
and Information. He holds a BS degree
in electrical engineering from the
University of Manchester, an MS degree
in petroleum engineering from Imperial
College, London, and an MBA degree
from Cranfield University.
The French term, dj vu, which means literally already seen, is the feeling that you
have previously experienced something you are currently experiencing. Two thirds of
adults claim to have sensed this phenomenon, but this figure rises to 100% when one
considers professionals in the oil and gas industry, which is undergoing yet another
boom-and-bust cycle.
Besides the real concern that the recently announced staff layoffs will only has-
ten the big crew change (as some golden oldies may decide to call it a day this time
around), one hopes that operators will maintain good stewardship of their wells and
fields and resist the temptation to cut back on essential data acquisition.
Reservoir stewardship, in which operators accept the responsibility to shepherd
and safeguard the assets of a company or a country, involves the periodic review of
asset performance to ensure productivity and recovery targets are met and main-
tained, and to guide future work plans. Continuous reservoir appraisal and surveil-
lance are essential to minimize production losses from downtime in wells, facilities,
and export systems. Unfortunately, it is evident that some operators (and govern-
ments) pay only lip service to good reservoir stewardship, especially when oil and gas
prices are low.
Sometime ago, I read a student thesis that looked at options for reducing costs in
the unconventional factory drilling process. It concluded that significant time and
money could be saved if formation evaluation services were eliminated from the well
program. The project sponsor was happy with the result and the student graduated,
but I was appalled that this suggestion could ever be taken seriously. Unconventional
reservoirs have complex pore systems, very low interparticle permeability, contain
free and adsorbed gas, and exhibit variable water salinity, all of which make their char-
acterization a major challenge for the geoscientist.
Therefore, more core data (not less) are needed to calibrate the responses of
logging suites, which also require enhanced measurement services as opposed to
standard tool strings. The taking of core permits subsequent rock typing to include
dynamic properties and fracturability and allows partitioning of the reservoir into
zones that reflect quartz content and producibility.
Conventional reservoir evaluation also comes under threat in a low oil price envi-
ronment. The major cost overruns in wells are invariably due to drilling failures, not
data acquisition. Yet on being told to cut costs, the usual reaction of well engineers is
to challenge the need for coring and logging in the formation evaluation program. We
are constantly faced with the dilemma of short-term benefit vs. long-term worth when
acquiring data. However, the latter tends to be more subjective and is therefore harder
to quantify in value of information terms, which leads to myopic operators gather-
ing only data required for the decisions in hand.
At the field level, daily accurate measurement of produced fluid volumes and
surface pressures and regular records of reservoir pressure are vital for sound res-
ervoir management. Without these data, history matching is impossible and uncali-
brated simulation models can lead to suboptimal investment decisions and poorer
resource estimates. Operators must regard adequate data acquisition as essential,
Keeping Reservoir Stewardship on Course
Bob Harrison, Technical Authority/Project Director, Reservoir Services, LR Senergy
23JPT JUNE 2015
rather than as an unnecessary overhead,
otherwise the stewardship of their assets
will beimpaired.
It seems incongruous that operators
would rather defer or even cancel the
acquisition of data from their producing
assets, and instead use assumptions, esti-
mates, and analogs (assuming the latter
are available and analogous) to populate
their reservoir models. These dynam-
ic models, which take many months to
build and run, can therefore never be
optimized, yet their outputs are used as
the basis for future reservoir manage-
ment decisions.
For example, some operators of off-
shore developments declare their pref-
erence for running bottomhole pressure
surveys and production logs in some
wells each year, rather than installing
permanent downhole gauges. My expe-
rience suggests that few of these sur-
veys are subsequently carried out, which
means that the actual reservoir pressure
and zonal flow contribution, essential
for validating any dynamic model, can go
unchecked year after year.
Production efficiency is a glob-
al problem, and one that is particularly
severe in the UK North Sea, where fields
exhibit average annual production loss-
es of almost 40%. Of course, operators
are wary of publishing such data, yet this
metric is at the heart of the asset stew-
ardship strategy in the UK governments
UKCS: Maximising Recovery Review: Final
Report by Ian Wood. This independent
study proposes that operators must be
held to account to ensure [] the proper
stewardship of their assets and infrastruc-
ture consistent with their obligations to
maximize economic recovery from the
fields under their licenses and with con-
sideration to adjacent resources.
A Production Efficiency Task Force
of North Sea operators, contractors, and
UK government officials was set up in
2014 to tackle this issue and hopes to
set a common basis of measurement of
production efficiency, with an underly-
ing choke model, this year. Success will
depend on the willingness of companies
to share best operational practices to
help increase economic recovery and to
allow benchmarking of comparable field
performance by regulators.
In the 1993 movie Groundhog Day,
Bill Murray, who is reliving the same day
over and over, asks a restaurant owner,
Do you ever have dj vu, Mrs. Lancast-
er? She replies, I dont think so, but I
could check with the kitchen. Experi-
enced professionals do not need to check
with the kitchen, but they do hope that the
industry has learned from past mistakes
made in the name of cost reduction.JPT
TECHNOLOGY APPLICATIONS
24 JPT JUNE 2015
Bore-Erosion Measurement and Inspection SystemLaserStream introduced its Bore- Erosion
Measurement and Inspection Sys-
tem (BEMIS) laser scanning technology
through an exclusive relationship with
Laser Techniques Company. The BEMIS
laser sensor rotates at high speed as it
is driven the length of a tubular, typi-
cally generating more than 2,500 data
points per revolution (Fig. 1). The result
is a high-resolution 3D map of the compo-
nent inner surface. The linear resolution
(the tightness of the helix) can be as fine
as .010 in. or as loose as 1 in., depending
on the application. These data provide
information about wall loss (erosion and
corrosion), mechanical wear (wireline
and coiled tubing), eccentricity, and exact
dimensions. Typically, measurements
are accurate to .002 in. or better. Until
recently, this technology has been pri-
marily used by organizations such as the
National Aeronautics and Space Adminis-
tration, the Department of Defense, and
nuclear power companies. LaserStream
can customize its equipment and soft-
ware applications to meet specific needs,
varying sizes, or different applications
(risers, tubing, and casing).
For additional information, visit www.laserstreamlp.com.
Formation-Pressure-Testing ServiceThe FTeX advanced formation-pressure-
testing service from Baker Hughes uses
downhole automation and real-time con-
trol of an intelligent packer-and-pump
configuration to deliver critical forma-
tion dataincluding pressure profiles,
fluid contacts, and mobility informa-
tionreliably, accurately, and efficiently
(Fig.2). The data offer an earlier and bet-
ter understanding of the reserves in place
so operators can quickly identify the pro-
duction potential of a well. Leveraging
adaptive software, the FTeX service auto-
mates the operation sequence downhole
to optimize tool controls and test parame-
ters with minimal input from surface per-
sonnel, thereby reducing data inconsis-
tencies and inaccuracies that often result
from manual testing. The service adapts
to the formation response encountered
during the initial drawdown to define the
optimal parameters for subsequent draw-
downs, in real time, leading to increased
data accuracy and efficiency. Running the
FTeX service with other wireline tech-
nologies reduces the number of logging
runs, saving rig time and cost. The ser-
vices combination of advanced technol-
ogy, efficient operations, and downhole
automation delivers some of the fast-
est, most-accurate measurements in the
industry. The FTeX service is the latest
development in Baker Hughes strategy
to improve well efficiency, optimize pro-
duction, and increase ultimate recovery.
For additional information, visit www.bakerhughes.com.
Versatile Cargo CarrierDeep Blue Engineerings Shuttle Sub is a
versatile cargo carrier based on the con-
cept of a large remotely operated vehicle
Chris Carpenter, JPT Technology Editor
Fig. 1BEMIS from LaserStream.
Fig. 2The Baker Hughes FTeX advanced formation-pressure-testing service
uses downhole automation and real-time control of an intelligent packer-
and-pump configuration to deliver critical formation data, offering a better
understanding of the reserves in place.
TECHNOLOGY APPLICATIONS
26 JPT JUNE 2015
(ROV) with payload capacity, deployed
from a support vessel at the surface
(Fig.3). It can be used to conduct a range
of installation, heavy-lift, and deployment
operations. Its versatility is a byprod-
uct of its modular payload cartridge sys-
tem, making it ideal for pipe installation,
cable deployment, salvage work, and sub-
sea intervention. Installation functions
are conducted by the Shuttle Sub with no
requirement for assistance from a smaller
work-class ROV. The largest Shuttle Sub
will be capable of transporting and laying
approximately 100 tons of pipe during
each trip from the support vessel. Each
pipe is extracted from the hopper by two
manipulators, which can be used to posi-
tion and align the pipe and then insert
it and make up a connection. The Shut-
tle Sub can further create new possibili-
ties for lift-and-deployment techniques
that are not available to marine opera-
tors because all of these operations are
currently achieved by use of lift lines
from a vessel at surface. Salvage oper-
ations will be made significantly safer,
using a fully engineered, controlled, and
robust buoyancy system in conjunction
with multiple lift lines from the Shuttle
Sub to the load.
For additional information, visit www.deepblueengineering.co.uk.
Ultrahigh-Temperature Measurement-While-Drilling ServiceSchlumberger introduced the TeleScope
ICE ultrahigh-temperature measurement-
while-drilling service. This new technol-
ogy enables standard drilling operations
in reservoirs with extreme temperatures.
The TeleScope ICE system helps custom-
ers eliminate runs, drill wells with pre-
cision, and mitigate operational risks to
make previously undrillable wells a pos-
sibility. The TeleScope ICE service trans-
mits survey and formation-evaluation
data at high speed, enabling real-time
well placement and risk mitigation in
harsh drilling conditions. It makes use
of integrated ceramic electronics (ICE)
and multichip modules that are specifi-
cally designed and ruggedized for hos-
tile downhole environments (Fig. 4). It is
part of a suite of ultrahigh- temperature
technologies that have been field tested
in the Gulf of Mexico, Malaysia, and the
Gulf of Thailand. In the Gulf of Thailand,
PTT Exploration and Production (PTTEP)
was operating in a reservoir with max-
imum temperature of 204C (399F).
PTTEP used the TeleScope ICE service
to obtain real-time downhole measure-
ments and drilled the well to total depth
in one run. The operator also eliminated
the need for a bottomhole-assembly trip
to protect electronics as well as a gyro
run to determine the location of the well,
which saved 12 rig hours and decreased
operational cost by USD300,000.
For additional information, visit www.slb.com/ultraht.
Fig. 4The ultrahigh-temperature-rated electronics in the TeleScope ICE
service were fully functional after 2,000 hours of testing at temperatures
greater than 200C.
Fig. 3Deep Blue Engineerings versatile Shuttle Sub.
Find out more at CircSub.com
Stuck Pipe?Chase to the cut.
HyPR HoleSaverFast and simple | User operated | Inherently safe | Full strength subs | Benign dormancy
TopJet Mud Shear Sub Drift Catcher Pressure Test Sub
DRILLING COMPLETIONS WORKOVER P & A
HyPR HoleSaver DAV MX CircSub Self-Filling Float
The HyPR Hole Saver is a new method of hydraulic pipe recovery that
makes freeing stuck pipe quicker, easier and safer than ever before.
Just drop the dart and pump.
Churchill is the performance leader in dart activated solutions to downhole
challenges. For more than ten years we have been designing robust, simple tools
that send mechanical darts right where you need them. With no setup or
personnel required, and using no explosives, Churchills HyPR HoleSaver
gives you a low-cost contingency to solve downhole problems, rapidly.
Faster recovery means big savings.
Also available for Abandonments
Churchill final ad JPT3.indd 1 01/05/2015 10:35
TECHNOLOGY APPLICATIONS
28 JPT JUNE 2015
Asset-Management Mobile ApplicationRetriever Communications introduced
its new enterprise mobile application,
Barking for Assets, for field force in the
energy sector that is designed to increase
efficiency and reliability of critical asset
management. Barking for Assets is an
advanced field-application technology
that em powers field operations, in coor-
dination with engineering, in the deliv-
ery of asset care, offering an alternative
to approaches that focus exclusively on
centralized planning that often does not
reflect on-site realities. It is a mobile
app that integrates directly into multi-
ple enterprise systems, simultaneously
including enterprise-asset-management
systems and engineering-planning sys-
tems (Fig. 5). It supports employees
who handle the planning and field oper-
ations within a com pany to reduce unex-
pected downtime, and serves as a single
solution configurable to field and plant
processes. Retrievers mobile solutions
work in 3G, 4G, and WiFi environments,
as well as in limited and no-wireless-
coverage areas. Many leading asset-
management com panies are investing
in technology to support and automate
reliability-focused maintenance. Bark-
ing for Assets uses a multitier task tem-
plate, providing the flexibility, visibility,
control, and resource management nec-
essary to capture valuable data, improve
operational efficiency, and manage
assets safely and proactively in the field.
For additional information, visit www.retrieverbarking.com.
Drilling-Riser ElevatorWeatherfords drilling-riser elevator,
the DRE 500, safely and efficient-
ly runs flanged-connection drilling-
riser strings in harsh deepwater envi-
ronments. Compatible with 500- or
750-ton bails, the elevator is designed
for efficient rig up. Rated for drilling-
riser strings up to 500 tons, the eleva-
tor handles stress joints, riser joints
with buoyancy cans, and riser joints
with or without strakes and fairings.
The specially designed indexing dogs
ensure that the riser is gripped proper-
Fig. 5Screenshot from Retriever Communications Barking for Assets asset-
management mobile application.
Fig. 6Weatherfords DRE 500 drilling-riser elevator.
$115K
REDUCING COST PER BOE.
READ THE WHOLE STORY AT FMSA.COM/CURABLENPV.
CURABLE RESIN-COATED SAND
INCREASED NPV
WELL MAINTENANCE
PER STAGE BYREDUCING
TECHNOLOGY APPLICATIONS
30 JPT JUNE 2015
ly, allowing it to be raised and lowered
into the well (Fig. 6). The nonmark-
ing feature on the tool protects against
stress- concentration factors created by
standard dies, which extends the life of
the riser joint. Hydraulic operation of
the spider and elevator eliminates the
time needed to manually bolt standard
lifting gear, ultimately reducing over-
all run times. Used with Weatherfords
integrated safety-interlock system, the
elevator can be operated remotely to
eliminate manual riser-running tasks
and keep personnel out of hazardous
zones. The interlocking mechanics
also keep the elevator and spider from
opening in the event of hydraulic or
pneumaticfailure.
For additional information, visit www.weatherford.com/products-
services/well-construction/
tubular-running-services.
Permanent Downhole Cable
RSCC Wire & Cable introduced its new
PressureTEC cable to ensure a higher-
performing permanent- downhole-cable
(PDC) installation for oil and gas drill-
ing applications (Fig. 7). Drilling equip-
ment engineers are familiar with
tubing-encapsulated-cable products that
are traditionally made with a welded
metal tube over a solid filler to protect
the electrical conductor inside the cable.
In a metal-clad tube with a traditional
solid-core filler, quality testing is limited
to an eddy-current test to check for weld
defects. Though eddy-current testing is
capable of finding defects, this process
is not guaranteed to find all defects. The
PressureTEC cables design incorporates
a welded metal tube to protect the con-
ductor, but the tube is first filled with an
expandable foam material and then is fol-
lowed by a pressurized-gas test that can
detect a defect in the metal tube or weld.
When the tube passes 100% integrity, the
foam core is then expanded to surround
the conductor and also adhere to the
tube wall to create holding forces. RSCCs
new PressureTEC cables are available in
150 and 200C materials, depending on
operating-temperaturerequirements.
For additional information, visit www.r-scc.com.
Fig. 7The PressureTEC PDC from RSCC Wire & Cable.
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JPT JUNE 2015
Intelligent Tracer TechnologyResmans Intelligent Tracer technology accurately quanti-
fies zonal-inflow contribution and detects the location of
water breakthrough. Applications include quantification of
oil inflow contribution, water-breakthrough monitoring, and
inflow-assurance monitoring. The information obtained with
Resman Intelligent Tracer technology provides the equiva-
lent of a production log but without the risk and cost of well
intervention. No cables, connections, intervention, or major
changes to completion design are needed. The oil-targeted
Intelligent Tracers can achieve up to 5 years of life, while the
water-targeted Intelligent Tracers can have longer life spans
because they are dormant until activated by contact with
water. Resmans chemicals are used in extremely low concen-
trations (down to parts per trillion) and are compatible for
water discharge. No radiation is used. The Intelligent Tracer
technology can be formed into a variety of shapes to allow it to
be integrated into a wide range of completion designs (Fig.8).
The Intelligent Tracer systems are designed to remain dor-
mant until contacted by the target fluid. When contacted by
the target fluid, tracer molecules are released in very small
quantities. This release is independent of flow conditions and
happens at a laboratory-designed rate. Resman chemists have
developed more than 50 uniquely identifiable chemical signa-
tures for oil and another 50 forwater.JPT
For additional information, visit www.resman.no.
Fig. 8Resman systems can be easily integrated with
a variety of completion devices, including screens and
pupjoints.
TECHNOLOGY UPDATE
32 JPT JUNE 2015
The greatest challenge facing the oil
and gas industry, particularly in this
low-price environment, is to increase
recovery rates. Experts in multiple dis-
ciplines across the industry are focus-
ing on it because even a small improve-
ment in recovery factors can make a
majorimpact.
To meet this challenge, the indus-
try must do more than look to new, step-
change technologies; it must question
current practices. For example, the prac-
tice of delaying first production after
the multistage fracture stimulation of
wells is widely seen as a sound operat-
ing strategy. Additional shut-ins, wheth-
er intentional or unexpected, are a part
of everyday well operations. However, a
growing body of evidence shows a nega-
tive effect on wellbore connectivity with
the reservoir.
A recent study examined more than
360 wells in six North American shale
plays to determine the effect of produc-
tion delay and shut-ins (Crafton and Noe
2013). The analyses showed that delay-
ing production quickly damages wells,
thus affecting wellbore connectivity and
production. A similar result was found
for shut-ins, with a strong correlation
between the number of shut-ins and
incurred damage.
One of the mechanisms causing this
damage is the energy stored in the fluid/
fluid interfaces in the form of a capil-
lary pressure difference. Historically, the
pressure difference has been understood
to be relatively small, but in shale plays,
it can easily be of the same magnitude as
the original reservoir pressure.
The study also examined the poten-
tial benefit of using a persistent interfa-
cial tension management (pITM) nano-
fluid to mitigate these negative effects
and found that in cases of production
delay or shut-in, wells treated with pITM
nanofluid showed improved connec-
tivity and production compared with
untreated wells. Therefore, the reduc-
tion of interfacial tension has the effect
of reducing the amount of energy, or
pressure drop, needed to allow flow
tobegin.
The Study MethodologyTo determine the effect of production
delay and shut-ins, two metrics wer
