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June 2014
Houston London Paris Stavanger Aberdeen Singapore Moscow Baku Perth Rio de Janeiro Lagos Luanda
World Trends and Technology for Offshore Oil and Gas Operations
For continuous news & analysis
www.offshore-mag.com
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Stimulation vessels update
t "OOVBM GMFFU TVSWFZ
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1406off_C1 1 6/3/14 2:18 PM
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34
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International Edition
Volume 74, Number 6
June 2014
C ON T E N T S
Offshore (ISSN 0030-0608) is published 12 times a year, monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices.
Copyright 2014 by PennWell. (Registered in U.S. Patent Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance
Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (978) 750-8400, Fax (978) 646-8600 to photocopy articles for a base fee of $1 per copy of the article plus 35¢ per page.
Payment should be sent directly to the CCC. Requests for bulk orders should be addressed to the Editor. Subscription prices: US $112.00 per year, Canada/Mexico $ 145.00 per year, All
other countries $184.00 per year (Airmail delivery: $257.00). Worldwide digital subscriptions: $112.00 per year. Single copy sales: US $11.00 per issue, Canada/Mexico $13.00 per issue, All
other countries $15.00 per issue (Airmail delivery: $24.00). Return Undeliverable Canadian Addresses to: P.O. Box 122, Niagara Falls, ON L2E 6S4. Back issues are available upon request.
POSTMASTER send form 3579 to Offshore, P.O. Box 3264, Northbrook, IL 60065-3264. To receive this magazine in digital format, go to www.offshoresubscribe.com.
Celebrating 60 Years of Trends, Tools, and Technology
GULF OF MEXICO
Drilling in Gulf of Mexico remains robust ............................... 34
Gulf of Mexico drilling activity remains robust and has continued to
show a remarkable comeback from the events of 2010, but the market
has seen a decline in activity in recent months as operators scale back
their commitments due to rising costs, and with past spending commit-
ments coming due.
Offine wells reduce value in US deepwater Gulf ................... 40
Wood Mackenzie recently studied the number of days of production per
month for more than 1,200 wells in deepwater Gulf of Mexico between
2007 and 2013. Production wells are thought of as fowing more or less
consistently. However, these wells can be shut-in for numerous reasons in-
cluding inclement weather, equipment failure, and on-going maintenance
drilling programs like workovers, side tracks, and recompletions. Based
on the study, producing oil and gas wells in deepwater GoM were online
on average only 79% of the time – less than 10 months in any given year.
60 YEARS OF OFFSHORE
From the archives: Plans set for the TLP debut ..................... 44
Selected from the March 1980 issue of Of fshore, the article describes
the Conoco-led consortium’s plans to develop the Hutton feld in the
North Sea with the industry’s frst tension leg platform, a “technologi-
cal breakthrough in deepwater exploration.”
GEOLOGY & GEOPHYSICS
Quantitative interpretation emerges
as major geoscience tool ........................................................ 46
The rise of deepwater exploration, together with the onshore shale boom,
has altered many industry geoscience workfows. For interpreters, this
has meant the widespread adoption of a series of advanced workfows
that are commonly defned as Quantitative Interpretation (QI). These
techniques take the interpreter beyond delineating reservoir geometry,
picking horizons and faults, and defning stratigraphy. The focus of QI is
to understand the internals of the reservoir rather than its architecture.
DRILLING & COMPLETION
MPD overcomes narrow drilling
window to reach stranded assets ........................................... 48
The long-producing US Gulf of Mexico shelf is being revitalized with
new technologies, allowing operators to access untapped reserves in
mature or depleted felds that would otherwise be unattainable. Among
the methods opening new opportunities in mature felds is managed
pressure drilling, which can overcome some of the limits of conven-
tional technology to drill through a tight operating window, manage
the changing annular pressure profle, reduce the likelihood of a well
control event, and manage wellbore stability to mitigate stuck pipe.
1406off_2 2 6/3/14 2:14 PM
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Find out more at
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56
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66
International Edition
Volume 74, Number 6
June 2014
C ON T E N T S
4 Of fshore June 2014 t www.offshore-mag.com
Celebrating 60 Years of Trends, Tools, and Technology
PRODUCTION OPERATIONS
Abandoned but not forgotten:
managing wells near end of life ............................................. 52
Many producing offshore oil and gas felds include a mixture of operat-
ing, suspended, and abandoned wells. One continuing challenge for
the operators is to distinguish between those wells that have been
suspended (i.e. for workovers) or abandoned safely, and those that are
not correctly treated. Well integrity management systems combine well
operating and production data within a framework for decision-making,
management processes, and organizational structure.
High-accuracy simulator trains
offshore oil platform operators ............................................... 56
LUKOIL has deployed an offshore training simulator (OTS) at its corpo-
rate training center near Astrakhan, Russia, that enables its employees
to become familiar with the same type of equipment and systems they
will use in the feld. The OTS features a modern control system from
Emerson Process Management and modeling software from Kongsberg
Oil and Gas Technologies, and was developed with the same Emerson
developers who had developed the confguration for LUKOIL’s North
Caspian Sea platform, located in the Yuri Korchagin oil feld.
PIPELINES & FLOWLINES
Study examines causes of slugging in subsea fowline ........ 60
One of Shell’s subsea tiebacks in the deepwater GoM has experienced
various fow assurance issues related to the produced fuids, and un-
expected unstable oscillating fow (slugging) has also been observed.
The commercial transient multi-phase fow simulation tool OLGA was
used to predict the slugging tendency. Several mechanisms that could
provide reasonable explanation for the observed unstable fow were
proposed and investigated.

STIMULATION VESSELS
Stim vessel feet features latest technologies ....................... 66
The global feet of stimulation vessels available to the industry is the
largest in its history. And, the technologies onboard are certainly the
most advanced to date. Deepwater stimulation vessels may be the
technology superstars, but offshore intervention, while perhaps not
as glamorous as big-league pressure pumping operations, also has an
essential role to play and a similar set of diffcult challenges.
2014 World survey of stimulation vessels .............................. 72
Get the latest detailed and comprehensive listing of the capabilities and
features of the worldwide stimulation vessel feet.
1406off_4 4 6/3/14 2:14 PM
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D E P A R T M E N T S
6 Of fshore June 2014 t www.offshore-mag.com
International Edition
Volume 74, Number 6
June 2014
EQUIPMENT & ENGINEERING
Industry unveils new products and technologies at OTC 2014 ................................ 74
The 2014 Offshore Technology Conference in Houston gave more than 108,300 attendees the
opportunity to learn about new products, services, and technologies and interact with industry
colleagues and professionals from around the world. This year’s event featured nine panel ses-
sions, 29 executive keynote presentations at luncheons and breakfasts, and 308 technical papers.
The sold-out exhibition covered 680,025 sq ft (63,176 sq m) and featured 2,568 companies
representing 43 countries.
Online .................................................... 8
Comment ............................................. 10
Data ..................................................... 12
Global E&P .......................................... 14
Offshore Europe .................................. 18
Gulf of Mexico ..................................... 20
Subsea Systems ................................. 22
Vessels, Rigs, & Surface Systems ...... 24
Drilling & Production ........................ 26
Geosciences ........................................ 28
Offshore Automation Solutions .......... 30
Regulatory Perspectives ..................... 32
Business Briefs ................................... 82
Advertisers’ Index ............................... 87
Beyond the Horizon ............................ 88
COVER: The global feet of stimulation
vessels available to the industry today
is the largest it has been in history, and
the technologies onboard are the most
advanced to date. StimWell Services
Ltd.’s Island Patriot is representative of
the vessel technology at work in offshore
well stimulation today. It holds the DNV
Well Stimulation Vessel Class notation
that adds tanks, a pumping and piping
arrangement, as well as equipment and
instrumentation related to the storage
and handling of well stimulation fuids, in
addition to the main class requirements.
The vessel also complies with statutory
regulations set by the International Mari-
time Organisation and the International
Management Code. See Page 72 for the
2014 Stimulation Vessel Survey results.
(Photo courtesy StimWell Services)
1406off_6 6 6/3/14 2:14 PM
© 2014 Baker Hughes Incorporated. All Rights Reserved. 40713 04/2014
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PennWell
1455 West Loop South, Suite 400, Houston, TX 77027 U.S.A.
Tel: (01j 713 621-9720 º Fax: (01j 713 963-6296
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8 Of fshore June 2O14 ª www.offshore-mag.com
Available at
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1406off_8 8 6/3/14 2:14 PM
1406off_9 9 6/3/14 2:14 PM
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10 Of fshore June 2014 t www.offshore-mag.com
To respond to articles in Of fshore, or to of fer articles for publication,
contact the editor by email ([email protected]).
COMMENT
%BWJE 1BHBOJF t )PVTUPO
Technology delivers unconventional results
The buzz in the US continues to be centered on tight oil and shale formations onshore…
and for good reason. Growth in crude oil production from those resources, spurred by
technology and effciency gains (among a host of other reasons), increased from 12% of
total US production in 2008 to 35% in 2012. Moreover, estimated growth from unconven-
tionals onshore could propel the US as a net exporter of crude oil and petroleum products
by 2040, according to one scenario in the US EIA Annual Energy Outlook 2014. A more
conservative scenario, the Reference case, estimates that total US crude oil production
will reach 9.6 MMb/d in 2019 – some 3.1 MMb/d more than in 2012 and near the historic
high in 1970. Over the same period (2012-2019), tight oil production is estimated to grow
by 2.5 MMb/d, to 4.8 MMb/d or 50% of the US total.
EIA estimates that production from Lower 48 offshore will vary between 1.4 and 2.0
MMb/d through 2040. Most of the production growth from US offshore areas is from a
number of deepwater Gulf of Mexico projects that are scheduled to come onstream by
the end of 2015.
The point here is to illustrate the impact that technology advances are having on
US onshore resource development, and to raise the following: Could technology ad-
vances deliver similar results offshore? In other words, are there any “unconventional”
approaches under development for offshore that could deliver a step-change in produc-
tion growth?
Advances in HP/HT equipment and services and improvements in subsalt imaging
could offer signifcant upside in the production curve. But, the one approach that is con-
sidered as having the greatest potential to add meaningful growth to the global reserves
base is EOR application to conventional offshore oil resources.
Recently formed alliances are proof of this emerging trend. Baker Hughes and Aker
Solutions are teaming to develop technology for production solutions that will boost
output, increase recovery rates, and reduce costs for subsea felds. This follows the
formation of OneSubsea – a Cameron and Schlumberger joint venture – also tasked with
improving recovery subsea.
A number of major operators are allocating resources for EOR R&D as well. BP, for
example, is developing LoSal, or low salinity, which is injection water treated to reduce
the total dissolved solids from seawater’s typical 35,000 ppm down to a few thousand
parts per million. The process also targets a reduction in the total divalent ion concen-
tration to a point below that of the connate reservoir water. These two steps combine to
help release the formation oil from the reservoir rock surfaces.
BP says its LoSal EOR technology has the potential to improve the outcome of water-
fooding by 5 to 10%.
Another approach is microbial EOR (MEOR). Offshore contributing editor Dick Ghis-
elin shares an interesting case study in his column on its application on the Statoil-
operated Norne feld in the Norwegian Sea. The process aims to stimulate the growth
of indigenous or injected bacteria, which can help to improve oil recovery by mobilizing
residual oil trapped in the pore space. As a result, recovery at Norne is approaching 55%.
Meanwhile, DNV GL has launched a joint industry project to develop a wind-powered
subsea water injection system. The concept is being promoted as an alternative for pro-
duction sites where reservoir characteristics and system design allow for raw seawater
injection, and there are long distances from the host platform to the satellite injection
well.
This is just a small sample of recent developments in EOR for offshore application. If
the technology is widely accepted, the results could be, well, unconventional.
1406off_10 10 6/3/14 2:14 PM
© 2014 Aker Solutions and Baker Hughes. All rights reserved. 40086 05/2014
Implementation of the alliance is subject to obtaining any required antitrust or other regulatory approvals.
Subsea
Production
Alliance
The Subsea Production Alliance is designing integrated in-well and seabed production solutions
as well as cost-effective intervention capabilities that will change the paradigm for subsea recovery
from new deepwater developments and mature felds. lnnovative solutions built on the bedrock
of industry-leading completion, production, and intervention products and services from
Aker Solutions and Baker Hughes.
Join the alliance to boost output, increase recovery, and reduce lifting costs at your subsea felds.
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1406off_11 11 6/3/14 2:14 PM
Worldwide offshore rig count & utilization rate
March 2012 – April 2014
950
850
750
650
550
450
350
100
90
80
70
60
50
40
N
o
.

o
f

r
i
g
s
F
l
e
e
t

u
t
i
l
i
z
a
t
i
o
n

r
a
t
e

%
M
a
r
c
h

1
2
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u
n
e

1
2
S
e
p
t

1
2
D
e
c

1
2
M
a
r
c
h

1
3
J
u
n
e

1
3
S
e
p
t

1
3
D
e
c

1
3
M
a
r
c
h

1
4
Contracted fleet utilization Total fleet Contracted Working
S
o
u
r
c
e
:

I
H
S
Capex (%) by water depth in the Gulf of Mexico 2009-2018
100
90
80
70
60
50
40
30
20
10
0
0-99
1,000-1,499 >1,499
100-499 500-999
2009
Source: Infield Systems
2010 2011 2012 2013 2014 2015 2016 2017 2018
O
p
e
r
a
t
o
r

c
a
p
e
x

s
h
a
r
e

(
%
)
Worldwide day rates
Year/Month Minimum Average Maximum
Drillship
2013 May $50,000 $460,000 $678,000
2013 June $50,000 $465,023 $678,000
2013 July $151,000 $466,627 $678,000
2013 Aug $151,000 $465,388 $678,000
2013 Sept $151,000 $459,435 $678,000
2013 Oct $151,000 $464,037 $678,000
2013 Nov $151,000 $470,960 $678,000
2013 Dec $151,000 $475,953 $678,000
2014 Jan $151,000 $478,831 $678,000
2014 Feb $151,000 $485,418 $678,000
2014 Mar $151,000 $491,167 $678,000
2014 Apr $151,000 $497,626 $678,000
Jackup
2013 May $30,000 $122,307 $361,000
2013 June $30,000 $122,908 $361,000
2013 July $30,000 $123,764 $361,000
2013 Aug $30,000 $125,274 $361,000
2013 Sept $30,000 $126,255 $361,000
2013 Oct $30,000 $127,951 $361,000
2013 Nov $30,000 $127,414 $361,000
2013 Dec $30,000 $129,406 $361,000
2014 Jan $30,000 $131,037 $361,000
2014 Feb $30,000 $130,352 $361,000
2014 Mar $30,000 $131,153 $361,000
2014 Apr $30,000 $132,535 $361,000
Semi
2013 May $145,000 $381,495 $656,662
2013 June $145,000 $380,282 $656,662
2013 July $145,000 $384,545 $656,662
2013 Aug $145,000 $386,443 $656,662
2013 Sept $145,000 $386,663 $656,662
2013 Oct $145,000 $382,210 $656,662
2013 Nov $145,000 $395,349 $656,662
2013 Dec $145,000 $394,334 $656,662
2014 Jan $145,000 $394,185 $656,662
2014 Feb $145,000 $392,792 $656,662
2014 Mar $145,000 $386,555 $656,662
2014 Apr $145,000 $387,444 $656,662
Source: Rigzone.com

GLOBAL DATA
12 Of fshore June 2014 t www.offshore-mag.com
This month, Infield Systems examines the dramatic
change in market share of capex by water depth in the
Gulf of Mexico over the last five years. Capex by water
depth of more than 1,499 m (4,917 ft) has changed
from 32% in 2009 to 58% in 2014. This is expected to
increase to 64% in 2018. Capex in deepwater (500-1,499
m) has decreased from 41% in 2009 to 29% in 2014
and is expected to further decrease to 24% by 2018. This
does not tell the whole tale with capex in the 1,000-1,499
m bracket remaining steady at a forecast period average
of 19% while capex between 500-999 m decreases to
3%. Shallow water (0-499 m) is expected to stabilize
over the forecast after falling from 22% in 2009 to 8% in
2014, but it is expected to rise to 11% by 2018.
Essentially, the Gulf of Mexico area is comprised of
two distinct basins. Shallow water (less than 500 m)
development in places such as East and West Cameron
and Vermillion has been going on for decades. Future
development is expected to mainly focus on small discoveries operating for a few years developed mainly
from fixed platforms or subsea tiebacks. Deepwater capex is expected to be focussed on subsea tieback
type developments.
In waters deeper than 1,499 m, the Gulf of Mexico is still a developing region. Over the period of
analysis, 80 fields are expected to attract capex in ultra-deepwater Gulf of Mexico with 63 expected to see
capex in the forecast period. This includes the Stones FPSO, to be the deepest installed platform globally
at a water depth of 2,896 m (9,499 ft) and only the second FPSO type development in the Gulf of Mexico.
Floating platforms with large numbers of subsea tiebacks – the “hub and spoke” system, are expected to
continue to remain popular as the Lower Tertiary of the Gulf of Mexico becomes increasingly developed.
− Kieran O’Brien, Energy Researcher, Infield Systems Ltd.
1406off_12 12 6/3/14 2:14 PM
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North America
Statoil and Husky Energy will resume
exploration and appraisal drilling this fall in
the deepwater Flemish Pass basin off New-
foundland & Labrador, using the semisub-
mersible West Hercules. The partners have
three potentially large oil discoveries in the
area, the most recent being last summer’s
Bay du Nord, 500 km (310 mi) northeast of
St John’s.
Brazil
Petrobras has completed its fnal manda-
tory exploratory well under its presalt Santos
basin Rights Transfer Agreement. Entorno
de Iara 3, drilled in 2,224 m (7,296 ft) of wa-
ter, 241 km (150 mi) offshore Rio de Janeiro
state, confrmed good-quality oil in carbonate
reservoirs below the presalt layer. Results
suggest 5 Bboe of reserves within the En-
torno de Iara block.
In the frontier Barreirinhas basin off north-
east Brazil, Thailand’s PTTEP has agreed to
farm into 25% of four blocks assigned last
year to BG Group. Assuming approval from
ANP, the partners will commission a 3D seis-
mic survey over the blocks under the initial
assessment phase.
West Africa
Total has discovered light oil in an abrupt
margin deepwater play offshore Côte d’Ivoire.
The semisub Eirik Raude drilled Saphir-1XB,
the frst well on block CI-154, in 2,300 m (7,546
ft) of water. It encountered a 350-m (1,148-ft)
series of thick sands containing a 40-m (131-
ft) hydrocarbon column with 34° API oil. Total
and partner Canadian Natural Resources plan
to evaluate a possible extension to the north-
east.
Côte d’Ivoire’s government has agreed to
extend African Petroleum’s production-shar-
ing contracts for deep offshore blocks CI-
509 and CI-513. These will give the Austra-
lian independent more time to pursue a rig
and to bring in partners for the frst-phase
commitment wells.
ttt
Noble Energy has completed a long-term
drillstem test on the Diega oil feld in block 1
offshore Equatorial Guinea. The well fowed
at constrained rates of up to 7,300 b/d, and re-
sults suggest recoverable volumes above 30
MMbbl. According to partner PA Resources,
Noble should submit a development plan be-
fore year-end. The partners will also re-eval-
uate the Carla South discovery in the same
block following a planned 3D seismic survey.
ttt
Total and its partners have launched the
$16-billion Kaombo development in Angolan
block 32, one of West Africa’s most extensive
deepwater projects to date. The offshore
complex will receive production from the
Canela, Caril, Gengibre, Hindungo, Louro,
and Mostarda felds in water depths ranging
from 1,400-1,900 m (4,593-6,233 ft). They are
spread out over an 800-sq km (309-sq mi)
area in the central and southeastern part of
the block, 260 km (161 mi) from Luanda.
Production will head to two converted
turret-moored FPSOs which Saipem will
supply and later operate and maintain. They
will enter service in 2017, and will each pro-
vide oil handling capacity of up to 115,000
b/d, water injection and gas compression of
respectively 200,000 b/d and 100 MMcf/d,
and storage for up to 1.7 MMbbl of oil.
Aker Solutions will provide the subsea pro-
duction system comprising 65 vertical subsea
wellsets, 20 manifolds, workover/tie-in and
control systems. The Technip/Hereema con-
sortium will supply and install 120 km (75 mi)
of umbilicals; 300 km (186 mi) of rigid pipe-
in-pipe production and single-pipe injection
lines; and 18 rigid single top tension risers,
associated 40-m (131-ft) tall buoyancy tanks
and jumpers. They expect to complete the in-
stallations during the frst half of 2018.
ttt
Genel Energy and White Rose have agreed
to pay China Sonangol and Statoil up to $281
million in total to farm into blocks 38 and 39 in
Angola’s offshore Kwanza basin. Water depths
in this frontier region, which has yielded nu-
merous successes for Cobalt International,
range from 1,500-2,500 m (4,921-8,202 ft). Genel
says the geology on both blocks is analogous
to Brazil’s Campos and Santos basins. The drill-
ship Stena Carron may have started drilling the
Dilolo prospect for Statoil in block 39.
Off Namibia to the south, Murphy Oil
has agreed to farm in as operator of explora-
tion blocks 2613A and 2613B. The company
and partners OMV, Cowan, and NAMCOR
planned to acquire 3D seismic. In offshore
2913B, on the maritime boundary with
South Africa, London-based Impact Oil and
Gas is confrmed as the new operator. The
acreage is thought to contain oil-prospective
sands within anticlinal traps west of the Or-
ange River delta.
Mediterranean Sea
Enagas has commissioned French con-
tractor Diestwell to overhaul the drilling
rig on the Gaviota platform, 8 km (4.97 mi)
offshore Spain’s northeast coast. Since 1994
the former gas production facility has sup-
ported gas storage in a subsurface reser-
voir. Dietswell will prepare the refurbished
rig for a workover program this summer.
Total’s Kaombo development offshore Angola. (Image courtesy Total)
1406off_14 14 6/3/14 2:14 PM
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Lebanon’s Ministry of Energy and Water has extended the dead-
line for bid submissions for the country’s frst offshore licensing
round until Aug. 14, 2014. This follows delays in decrees related to
delineation of the blocks and the model E&P agreement. Five off-
shore blocks are currently on offer, but more could be added.
ttt
Noble Energy and its partners will seek to expand the deepwater
Tamar feld gas production and export facilities. This follows a letter
of intent to sell up to 2.5 tcf over 15 years to Union Fenosa’s natural
gas liquefaction facilities in Egypt, subject to regulatory approvals.
Delek Group says its subsidiary companies in partnership with
Noble have applied to export gas from Israel’s deepwater Leviathan
feld through a new pipeline to Cyprus. They aim to supply up to
0.95 bcm/yr between early 2016 and the end of 2022, with options
to extend deliveries till end-2025. However, a development schedule
for Leviathan and agreements with Cyprus’ government would both
need to be in place by Aug. 21.
Black Sea
Allseas’ new construction vessel Pieter Schelte will install the sec-
ond string of the South Stream gas pipeline through deepwaters in
the Black Sea. The vessel, equipped with six welding and coating
stations, will start work on the 900-km (559-mi) pipelay campaign
in summer 2015. Saipem will connect the offshore pipeline to the
landfall sections using the above-water tie-ins.
Caspian Sea
RWE Dea and SOCAR will jointly evaluate prospectivity south of
the Absheron peninsula in the Azeri sector. The 850-sq km (328-
sq mi) study area, between Hamamdag and Karadagm, is in water
depths ranging from 0-30 m (0-98 ft).
In the same sector, BP has contracted the Saipem/Bos Shef/
Star Gulf consortium to transport and install new platform jackets,
topsides, subsea structures, and subsea production systems for the
Shah Deniz Stage 2 project. Additionally, the consortium will install
more than 360 km (223 mi) of subsea pipelines and upgrade the
Israfl Huseinov laybarge for the program.
Middle East
Qatar Petroleum (QP) is to commit more than $11 billion to rede-
velop the Bul Hanine offshore oil feld 120 km (75 mi) east of Qatar.
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(Image courtesy
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www.offshore-mag.com t June 2014 Of fshore 17
phase, will double the feld’s current produc-
tion capacity and extend its productive life.
QP plans to drill new wells from exist-
ing/modifed wellhead platforms and from
14 new wellhead platforms, with associated
production and injection fowlines. The new
offshore central complex will comprise pro-
duction, compression, utility and living quar-
ter platforms with topside weights ranging
from 4,000-14,000 metric tons (4,409-15,432
tons). Produced oil will be sent to Halul Is-
land for export, while 90 MMcf/d of sour
gas will head through a new 150-km (93-mi)
subsea pipeline to a gas treatment facility in
Mesaieed. Lean sweet gas will be imported
to the new complex for compression/injec-
tion.
East Africa
Anadarko says recent appraisal drilling
on the Orca feld has increased gas reserves
in Mozambique’s Offshore Area 1 to 50-75
tcf-plus. The company continues to progress
the planned Mozambique LNG project hav-
ing added incremental non-binding LNG
take-off agreements.
India
ONGC plans further development of its
Vasai East feld in the Arabian Sea offshore
western India. The company will drill infll
wells from the VSEB and VSEC wellhead
platforms into the feld’s northern and
southern fanks. It will also modify facilities
at the BPA/BCPA-2 process platform. The
project, due to be complete by the end of
2018, should add 1.83 million metric tons
(2.01 million tons) of incremental oil and
1,971 bcm of gas production by 2030.
Southeast Asia
CNOOC has delivered frst oil from the
Kenli 3-2 oil felds project in the southern
Bohai Sea. The company developed the
Kenli 3-2, Bozhong 34-6/7, southern part of
Bozhong 29-4, and the Bozhong 35-2 oil felds
in water depths averaging 20 m (65.6 ft).
The offshore facilities, designed to produce
35,000 b/d, include seven platforms. Oil is
exported to a processing terminal onshore.
ttt
Shell has a new gas discovery in block
SK318 off Malaysia. The Rosmari-1 well,
drilled 135 km (84 mi) offshore, intersected
a gas column of more than 450 m (1,476 ft).
Shell and partners Petronas plan to drill for
more gas in the area.
Petronas has signed a small feld risk
service contract with a consortium headed
by EnQuest for development of the Tanjong
Bram feld offshore Lutong, Sarawak. The
approved development plan involves drilling
wells and installing platforms and pipelines
which will be linked to existing infrastruc-
ture. First oil is slated for 2015, with an esti-
mated project cost of $100 million.
Elsewhere off Malaysia, Australian com-
pany ROC Oil has farmed into 50% of a Petro-
nas-operated PSC covering the shallow-water
producing felds D21, D35, and J4. Combined
production is currently 10,000 b/d of oil and
17 MMcf/d of gas. The partners will look to
raise output through redevelopment and en-
hanced oil recovery measures.
ttt
Premier Oil has discovered oil and gas
in the Kuda Laut structure in the Tuna PSC
offshore Indonesia. The Kuda-Laut-1 well
encountered 183 ft (56 m) of net oil-bearing
reservoir and 327 ft (99.7 m) of net gas-
bearing reservoir. The company planned a
side track into the Singa Laut prospect in the
adjacent fault block.
Australasia
Origin Energy has contracted Seadrill’s
West Telesto to drill two new wells during the
next Australian summer on the Yolla gas
feld in the Bass Strait. The wells form part
of the BassGas joint venture’s Yolla mid-life
enhancement project Stage 2, designed to
maintain production from the feld.
ttt
New Zealand’s Energy and Resources Min-
ister Simon Bridges has revealed details of
the country’s third annual block offer for pe-
troleum exploration permits. Block Offer 2014
covers total acreage of 405,000 sq km (156,371
sq mi). Offshore release areas include the
Canterbury, Great South, New Caledonia,
Pegasus-East Coast, Reinga-Northland, and
Taranaki basins. Bids are due by Sept. 25, with
permits due to be issued between December
and March 2015. •
1406off_17 17 6/3/14 2:14 PM
OFFSHORE EUROPE
+FSFNZ #FDLNBO t -POEPO
18 0G GTIPSF June 2014 t www.offshore-mag.com
Basement well pushes drilling boundaries
Appraisal drilling resumed last month on Hurricane Energy’s
basement Lancaster oil discovery west of Shetland. The semisub-
mersible Transocean Sedco 712 is drilling the well which will be fow
tested. SPD is managing the program which could last 75 days.
According to Hurricane CEO Dr. Robert Trice, this is the frst
time a 1-km (0.6-mi) horizontal well section has been attempted in
the UK’s fractured basement. The well path for the horizontal seg-
ment will cross at least nine faults identifed from 3D seismic, com-
pared with two seismic scale fault penetrations for the previous well
on the feld which tested 2,500 b/d of oil.
If the current well meets expectations it will be suspended for a
future tieback to a host production facility. A success, Trice added,
“will also have a signifcant impact on how the industry values other
fractured basement opportunities in the UK…The government-spon-
sored Pilot study describes fractured basement reservoirs as the most
extensive underexplored play remaining on the UK continental shelf.”
Off the Faroe Islands the semisub West Hercules has re-entered
the Brugdan II exploration well in license 006, which had been sus-
pended since November 2012 when bad weather called a halt to op-
erations. Brugdan is a large four-way dip closure at Tertiary level
that was frst drilled in 2006, although that well had to be abandoned
prior to reaching the sandstone target due to mechanical issues. The
waters around the Faroes are among the toughest for operations
throughout northern Europe, due to the severe metocean condi-
tions and the extensive layers of basalt in the subsurface. But the
area is also viewed as highly prospective.
Ormen Lange compression studies suspended
Norske Shell and its partners have opted to postpone offshore
compression for the deepwater Ormen Lange gas feld in the Nor-
wegian Sea. This had been one of two concepts under review since
2008 to extend the life of the feld, which currently produces through
an extensive network of subsea facilities tied back to the shore. The
other option was compression from a new TLP.
Committee chairman Odin Estensen said that following an up-
dated analysis of the reservoir the licensees concluded that neither
concept was proftable. The latest fndings indicated that offshore
compression is not even time-critical for recovery from the feld, he
added. “More knowledge will be accessible from both the reservoir
and technology in the coming years and will form the basis for evalu-
ating new compression options.”
Grethe Moen, chief executive of state-owned Petoro, a partner in
the project, said that the proposed forward plan did not represent
a suffciently strong commitment, and that her organization would
continue to push for compression in the longer term.
Petoro is also a partner in Statoil’s planned Johan Castberg multi-
feld development in the Barents Sea. The operator recently com-
pleted a fve-well campaign to prove more oil in the area. After a
series of disappointments, the fnal well delivered apparently com-
mercial hydrocarbons from the Drivis structure, 15 km (9.3 mi)
from the original Skrugard discovery well in 345 m (1,132 ft) of wa-
ter. Recoverable oil volumes could be in the 42-54 MMbbl range.
Statoil favors a semisubmersible platform-based solution for Johan
Castberg, exporting oil to northern Norway for storage. However,
Moen said Petoro would continue to push for equal focus on the alter-
native option of a smaller foating production unit with offshore loading.
Call to cut costs of Norway wells
Aside from Drivis, exploration drilling has paid off farther south
with Wintershall fnding gas and condensate with two wells in the
lower Cretaceous Solberg prospect in the Norwegian Sea, close to
last year’s Rodriguez discovery. VNG’s drillstem test on its Pil fnd in
the same sector, southwest of the Njord complex, suggests recover-
able resources of up to 170 MMboe. And Statoil’s recent Valemon
North discovery at the Jurassic level could hold up to 75 MMboe
of gas/condensate and oil. The main Valemon feld is due to come
onstream later this year via a fxed platform.
However, half of the Norwegian felds under consideration for
development are smaller than 27 MMboe, according to Moen. “De-
veloping these discoveries presents major proftability challenges,”
she said, with production well drilling accounting for around half
the cost of a development. Norwegian operators need to get a grip
on capacity, measured by wells per year, she added, and on drilling
costs infated by creeping ineffciencies.
In the past, she claimed, the industry managed to execute stan-
dard drilling tasks twice as quickly as it does now. However, she
suggested that “through simplifcation, technology which increases
cost effectiveness, and a cultural shift away from seeking fault-free
operation to pursuing effciency, we can achieve radical effciency
gains compared with the present position.”
Platforms converge on North Sea
This has been a busy period for loadouts of structures for new
North Sea projects. Over the past two months Aker has shipped out
jackets for the Edvard Grieg and Eldfsk projects from its west coast
Norway yards; Nexen’s Golden Eagle Area production, utilities
and quarters deck left Lamprell’s yard in Sharjah, UAE. Heerema
Fabrication Group skidded the 8,500-ton launch jacket for DONG
Energy’s Danish sector Hejre feld platform onto a barge from the
quayside in Vlissingen, the Netherlands, and this was due to be fol-
lowed by the 900-ton pre-drilling wellhead deck.
In the UK, Heerema’s Hartlepool yard dispatched the 1,640-met-
ric ton (1,808-ton) topsides for GDF SUEZ’s Cygnus gas feld, with
the 1,146-metric ton (1,263-ton) jacket, built by Burntisland Fabrica-
tors, sailing out of eastern Scotland. Both fabricators are building
the remaining three platforms for this development.
One of the next major construction programs will be for Xcite Energy
Resources’ phased heavy oil Bentley project in the UK northern North
Sea. The company is working with AMEC and Ove Arup & Partners to
optimize the design of Arup’s self-installing steel ACE production plat-
form. This would allow the facility to be built and integrated at a wide
range of yards, and wet-towed directly to the Bentley feld for installa-
tion with minimal offshore support. Teekay Shipping is set to provide
a bridge-linked, cylindrical Sevan foating storage and offoading unit.
Xcite has also entered a collaboration agreement with Statoil and
Shell to examine potential synergies with Statoil’s much larger Bres-
say heavy oilfeld development. A team from the three companies
will examine potential use of common infrastructure, assets and op-
erational solutions for the two projects. •
Sail away of the Cygnus Alpha topsides from Heerema Hartlepool.
(Courtesy Heerema Fabrication Group)
1406off_18 18 6/3/14 2:14 PM
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BP ends active shoreline
cleanup operations
BP says that the US Coast Guard has end-
ed patrols and operations on the fnal three
shoreline miles in Louisiana, bringing to a
close the extensive four-year active cleanup
of the Gulf Coast following the Deepwater
Horizon accident. These operations ended
in Florida, Alabama, and Mississippi in June
2013.
BP says that the large-scale cleanup ef-
fort, combined with early restoration proj-
ects and natural recovery processes, is help-
ing the Gulf return to its baseline condition,
which is the condition it would be in if the ac-
cident had not occurred. The company has
spent more than $14 billion and more than
70 million personnel hours on response and
cleanup activities, say company offcials.
Although active cleanup has ended, the
entire area of response is subject to the
National Response Center (NRC) process.
Coast Guard personnel are pre-positioned to
investigate any further reports of oil-based
material.
From the beginning, BP says it has worked
under the Coast Guard’s direction and in co-
operation with state agencies and local gov-
ernments to limit the accident’s impact on the
environment, and remove oil from the water
and shoreline. Aerial reconnaissance fights
were fown across approximately 14,000
miles of shoreline. Nearly 4,400 miles were
ground-surveyed, with teams identifying
1,104 miles that experienced some level of
oiling and 778 miles that required some mea-
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McDermott signs agreement
for Gulfport spoolbase
McDermott says that one of its subsidiar-
ies has signed a lease agreement with the
Mississippi Development Authority and the
Mississippi State Port Authority for the ex-
clusive right to operate a spoolbase and ma-
rine operations base in the Port of Gulfport.
McDermott expects the facility, designed to
serve projects from the GoM, will be avail-
able in early 2016.
The new facility in Gulfport, located on
the Mississippi coastline, will be used to fab-
ricate steel pipe stalklines through advanced
welding processes for use in offshore reeled
pipelay operations. The new 50-acre facil-
ity will feature a state-of-the-art fabrication
building and stalk racks, as well as a dedi-
cated dock for vessel berthing to accommo-
date reeling pipe onto McDermott’s feet of
specialized vessels for transport and instal-
lation offshore.
Fugro expands survey feet
Fugro is expanding its survey feet in the
GoM to include a new AUV, Echo Surveyor
VII, and a new vessel, R/V Fugro Americas.
“Both of these impending launches indi-
cate our strong capabilities and commitment
to our clients in the GoM and international-
ly,” said Melissa Jeansonne, vice president,
Fugro GeoServices, Inc. “Both the Fugro
Americas and Echo Surveyor VII will join the
current feet later in the year. We already
operate three AUVs in the GoM – one Hu-
gin (Echo Surveyor II), and two Bluefn (Echo
Mapper); and our new multi-purpose Fugro
Americas vessel enables us to have three
vessels capable of operating AUVs in the
Americas.”
The company says that AUVs are becoming
the preferred choice of instrument platform
for deep sea and remote surveys. In addition
to providing improved multibeam swath cover-
age, the Echo Surveyor VII will support the ac-
quisition of sidescan sonar, sub-bottom profler
and CTD profler data, and will carry various
environmental sensors to meet a wide range of
offshore survey demands.
The Fugro Americas is a state-of-the-art
multi-purpose vessel well suited for high
resolution geophysical surveys and seafoor
mapping. “We are extremely proud of the
Fugro Americas and look forward to her ar-
rival in service,” said Jim Grady, Asset Man-
ager, Fugro GeoServices, Inc. “At 193 ft she
is bigger and faster than our current vessels
in the GoM, has more berths as part of our
purpose-built design, and is both quiet and
fuel effcient. SOLAS classed, she is capable
of undertaking seismic, conventional, AUV
and geotechnical surveys thus providing the
advantage of just one mobilization that can
meet every client’s needs.”
EMAS gets LOA
for Gunfint project
EMAS reports that it has received a letter
of agreement (LOA) from Noble Energy for
the Gunfint project in the GoM.
Under the terms of the agreement, EMAS’s
subsea services division EMAS AMC has
been nominated to perform the offshore in-
stallation of pipelines, umbilicals, and ancil-
lary equipment for the Gunfint project in the
Mississippi Canyon area of the US GoM, in
water depths in excess of 2,000 m (6,561 ft).
The pipelines will be installed with EMAS
AMC’s fagship vessel the Lewek Constella-
tion while the EMAS marine base in Ingle-
side, Texas, will be used to perform the pipe
stalking and fabrication of various subsea
structures. Project preparation activities have
already commenced and offshore works are
scheduled to be carried out during 2015.
W&T Offshore acquires
Woodside assets
W&T Offshore, Inc. says that its wholly
owned subsidiary, W & T Energy VI, LLC,
has completed the acquisition of exploration
and production properties in the deepwater
GoM from Woodside Energy (USA) Inc.
The transaction includes a 20% non-operated
working interest in the producing Neptune
feld (Atwater Valley blocks 574, 575, and
618 along with an interest in the associated
tension leg platform). In addition, Energy VI
is acquiring all of Woodside’s interest in 24
deepwater exploration blocks.
The purchase price is $51 million (sub-
ject to customary post-effective date adjust-
ments) and the assumption of any related as-
set retirement obligations. The acquisition
was funded from available cash on hand and
the revolving credit facility.
Total net proved reserves acquired are
1.9 MMboe (100% classifed as proved devel-
oped) with a PV-10 of $53 million and prob-
able net reserves of 1.1 MMboe. During
January 2014, average daily net production
from the Neptune feld was approximately
1,660 boe (net of royalties), of which 87%
was oil. •
Rig utilization update
Total mobile rig utilization in the GoM decreased in the first full week of May, ac-
cording to RigData’s weekly report of offshore drilling plans, well permits, and rig
locations dated May 5, 2014.
Current fleet utilization is 64.8%, with 70 of 108 rigs under contract or committed
for work. Utilization of the marketed rig fleet, which excludes cold stacked and other
rigs that are here but not marketed in the US Gulf, decreased to 84.3% from the past
week, with 70 of 83 units under contract.
Utilization of the jackup fleet remained unchanged at 58.2% over the previous
week, with 32 of 55 units under contract. Marketed rig utilization remained at 84.2%,
with 32 of 38 units under contract.
Floating rig utilization decreased over the previous week to 71.7%, with 38 of 53
units under contract. Marketed utilization decreased to 84.4%, with 38 of 45 units
under contract or committed for work.
Total platform rig fleet utilization increased from the previous week to 68.3%, with
28 of 41 units under contract. Marketed utilization increased to 84.8%, with 28 of 33
units under contract or committed for work.
For more information about the status of drilling activities in the GoM, please see
our Gulf of Mexico mid-year report starting on page 34.
1406off_20 20 6/3/14 2:15 PM
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SUBSEA SYSTEMS
(FOF ,MJFXFS t )PVTUPO
22 0G GTIPSF June 2014 t www.offshore-mag.com
New lift/deployment ROV in development
A new type of lift and deployment ROV dubbed Shuttle Sub by
Deep Blue Engineering UK Ltd. is being introduced.
The buoyant-controlled Shuttle Sub can foat, dive, surface, and
maintain neutral buoyancy with a 100-metric ton (110-ton) payload,
says Deep Blue.
“The Shuttle Sub is essentially an ROV in its own right, but it com-
bines this with a transport function,” said David Webster, managing di-
rector of Deep Blue Engineering. And it offers an alternative to cranes
for installing generating equipment, cables, exploration, or recovery
work and does not require an additional ROV to serve as a monitor.
Deep Blue Engineering says it will submit the frst Shuttle Sub to
rigorous testing over the coming months.
Plans are to make the Shuttle Sub, which will be available in two siz-
es, have a payload capacity of 50 metric tons as well as the 100-metric
ton version. The vehicle weighs slightly less than its payload capacity,
and uses a “cartridge-based” carrying system similar to the container
method used in the shipping industry.
A crane mounted on the support vessel lifts the empty Shuttle Sub
into the water, then lowers the payload cartridge into the Shuttle Sub.
Different cartridges are designed for different applications. For ex-
ample, cartridge variants currently include a reel for laying cable, a
drum for deploying long steel tube fying leads, and lifting equipment
for salvage operations.
Future plans include the intervention and capping capability, and
a cartridge with a subsea drilling capability.
The current design can be deployed in water depths to 1,500 m
(4,920 ft). Deep Blue plans to develop a Shuttle Sub capable of work-
ing at 3,000 m (9,840 ft), followed by greater depths in the future. •
Baker Hughes Inc. and Aker Solutions ASA have agreed to
form an alliance to develop technology for subsea production
solutions.
The non-incorporated alliance will combine Aker Solu-
tions’ subsea production and processing systems with Baker
Hughes’ well completions and artificial-lift technology to deliver
integrated in-well and subsea production solutions.
The alliance also will focus on advancing the industry’s
well-intervention capabilities to further optimize efficiency and
reduce risks in subsea developments.
The structure of the alliance allows each company to offer
any products and services to design the best solution for cus-
tomers’ production challenges.
“Deepwater subsea fields have so far been characterized by
low recovery rates, and new discoveries in deeper and more
hostile environments are making these fields even more costly
to develop,” said Martin Craighead, Baker Hughes’ chairman and
CEO. “The single-digit recovery rates currently being achieved
at many of these fields don’t support a sustainable business
model. By joining forces, Baker Hughes and Aker Solutions will
identify and integrate the most effective combinations of in-well
and subsea technologies, enabling greater production rates—ef-
ficiently and economically—from subsea fields.”
“Our joint commitment will strengthen the business of each
company and help our customers unlock the vast values that
come from subsea production,” said Oyvind Eriksen, Aker
Solutions’ executive chairman. “Subsea factory development
is a key focus for Aker Solutions and the partnership with
Baker Hughes will provide critical capabilities that will help
us develop technologies to create a fully-functioning subsea
production system which will improve recovery rates and lower
costs for oil producers.”
(Above) Meridian Ocean Services has added two Saab Seaeye Lynx ROVs
to its Falcon fleet to undertake a wider range of deeper inspection tasks at
short notice. The company has created a suite of rapidly deployable ROV
packages comprising Saab Seaeye Lynx and Falcons set in small-footprint
containerized systems ready for speedy deployment from a 150-ft vessel.
Meridian says the Lynx, with its TMS and enhanced operating features, will
expand the company’s range of inspection roles in deeper platform work,
around buoys, artificial reefs, and for cleaning and diver support.
Baker Hughes, Aker Solutions form subsea production alliance
1406off_22 22 6/3/14 2:15 PM
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1406off_23 23 6/3/14 2:15 PM
VESSELS, RI GS, & SURFACE SYSTEMS
24 Of fshore June 2014 t www.offshore-mag.com
#SVDF #FBVCPVFG t )PVTUPO
Ceona delivers Polar Onyx
and Normand Pacifc
Ceona says it has completed fnal outftting
of the Polar Onyx and the Normand Pacifc to
begin client projects offshore Brazil and in the
Gulf of Mexico, respectively. The successful
delivery of the two fexlay and subsea construc-
tion vessels marks the conclusion of the frst
phase of Ceona’s feet development program.
The company says that the Polar Onyx is
designed for operations in harsh conditions
and deepwaters (Ulstein X-bow), and is built
to the highest standard in dynamic position-
ing, DP-3 (Operations +) with a 250-ton AHC
offshore crane. Final outftting has taken place
in Schiedam, the Netherlands, where Huisman
has installed a 275-ton vertical lay system (VLS)
and a deck-mounted carousel with capacity for
2,000 tons of fexible products. Two permanent
work-class ROVs delivered by Ceona’s partner
ROVOP, which can operate in 3,000 m (9,842 ft)
water depth, were also mobilized in Schiedam.
Following her on-schedule completion, the
Polar Onyx has sailed for Brazil (Vitoria) where
she will mobilize and enter service as a pipelay
support vessel (PLSV) for Petrobras. Ceona
will manage the PLSV, the vessel’s maiden
contract, in partnership with Odebrecht Oil &
Gas (OOG). The Polar Onyx is under charter
to Ceona from GC Rieber Shipping for a fxed
period of fve years, with options for up to fve
additional years.
Meanwhile, the Normand Pacifc has been
fnalized in Galveston, Texas, with the installa-
tion of a new high-specifcation 75-ton VLS, a
reel drive system of 400-ton reels and two work-
class ROVOP ROVs. It has sailed to Freeport to
mobilize for its frst contract as part of the Ceo-
na feet, working on the Clipper Contingency
Umbilical Installation Project for Bennu Oil and
Gas in the Gulf of Mexico. The vessel will work
on installation of a dynamic umbilical and elec-
trical quad cables in water depths of over 900
m (2,952 ft). The Normand Pacifc is chartered
from Solstad Offshore for one year, starting in
April 2014, with an option of extension.
Ceona says that with work under way in
both Brazil and the Gulf of Mexico, it will con-
tinue to build its subsea capabilities with the
ongoing construction of the Ceona Amazon, its
multipurpose pipelay and construction vessel.
The Ceona Amazon is on track for delivery in
early 2015.
Boskalis initiates study into
ultra large Dockwise vessel
Royal Boskalis Westminster N.V. (Boskalis)
announced at the recent Offshore Technology
Conference in Houston that it has started a
study into a new ultra large V-class Heavy Ma-
rine Transport Vessel (HTV).
The Dockwise Vanguard, which came into
service in early 2013, is already the world’s
largest V-class HTV with a carrying capacity
of 117,000 metric tons and a deck space of
270 m x 70 m (885 ft x 229 ft).
The study addresses both the market op-
portunities and the technical requirements
for the new vessel. Boskalis says it will en-
gage with clients to understand how this ves-
sel can accommodate the expected growth in
the FPSO and FLNG markets in addition to
the ocean-going transport of outsized heavy
marine structures.
Compared to the Dockwise Vanguard, the
new vessel will be larger in terms of length,
breadth and carrying capacity, but will also
have a bowless design and asymmetric ac-
commodation.
Boskalis says that the addition of another
V-class vessel to its current feet of semisub-
mersible HTVs will enable the company to
further expand its leading market position in
the offshore energy industry.
Ensco orders two
ENSCO 140 Series jackups
Ensco plc says it has ordered two high-spec-
ifcation jackups, ENSCO 140 and ENSCO 141,
to fulfll customer demand for the company’s
differentiated rig technology and contract
drilling services in the Middle East. Both rigs,
which will incorporate Ensco’s patented Canti-
Leverage Advantage technology, are signif-
cantly enhanced versions of the LeTourneau
Super 116E jackup design.
The new jackups will include design specif-
cations necessary to fully comply with the vast
majority of regulatory and customer require-
ments in the Middle East, the primary target
market for ENSCO 140 and ENSCO 141. The
rigs are scheduled for delivery in mid-2016
from Lamprell’s newest shipyard located in
the United Arab Emirates. Ensco says that the
rigs are also suitable for most of the markets
around the world outside of the Middle East.
The two jackups will be constructed under
a fxed-price contract. Including commission-
ing, systems integration testing and project
management, the total construction cost is es-
timated to be $430 million, or $215 million per
rig. The contract with Lamprell includes op-
tions for two additional rigs of similar design.
The company says that ENSCO 140 and
ENSCO 141 will offer enhanced crane capac-
ity and liquid mud storage; and that living
quarters with 140 beds will translate into
signifcant logistical effciencies and cost sav-
ings for customers.
Other key features of the rig design include
a dual-drilling fuid system, a 1.5 million-pound
derrick, TDS-8 top drive and a 15k BOP. The
rigs will initially be outftted to work in wa-
ter depths up to 340 ft (103 m) and may be
upgraded to operate in up to 400 ft (122 m)
of water. They will be capable of drilling to a
maximum total depth of 30,000 ft (9,144 m).
With this new order, Ensco says it now has
eight newbuild rigs under construction: fve
premium jackups and three ultra-deepwater
drillships. Since the beginning of 2010, Ensco
has taken delivery of 12 high-performance
rigs, including two ENSCO 120 Series ultra-
premium harsh environment jackups, fve
Samsung DP-3 ultra-deepwater drillships and
fve ENSCO 8500 Series ultra-deepwater semi-
submersibles. During this same period, Ensco
has divested 13 less capable rigs as part of its
continuous high-grading strategy. Proceeds
from these sales have been used to fund new-
build orders. •
(Left) The Polar Onyx has sailed for Brazil (Vitoria) where she will mobilize and enter service as a pipelay support vessel (PLSV) for Petrobras.
(Right) The Normand Pacific has sailed to Freeport, Texas, to work on the Clipper Contingency Umbilical Installation Project for Bennu Oil and Gas
in the Gulf of Mexico. (Photos courtesy Ceona)
1406off_24 24 6/3/14 2:15 PM
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1406off_25 25 6/3/14 2:15 PM
DRI LLI NG & PRODUCTI ON
%JDL (IJTFMJO t )PVTUPO
26 0G GTIPSF June 2014 t www.offshore-mag.com
This month’s column is all about produc-
tion. While drilling is of critical importance,
no operator makes any money until the well
produces. As has been noted many times be-
fore, it is a shame that many producers are
content to leave as much as 65% of crude oil
in the ground. It is a shame because there is
a proven solution.
About a year ago, I did research on en-
hanced oil recovery (EOR), the technique
that purports to make a signifcant improve-
ment in recovery factor—going after that
65% of residual oil. One question I asked the
producers I interviewed had to do with the
relative percentage of techniques employed
to coax more crude out of the ground. The
favored technique, by a long shot, was ther-
mal, at almost 90%, followed by chemical at
9%. Lastly was biological, almost a nonentity.
It is a shame that my research was con-
fned to North America. If I had looked
overseas, I would have found a much more
encouraging picture. The successful use of
biological EOR has been experienced for the
past 20 years by a leading national oil compa-
ny, and several scientifc institutes abroad.
Spectacular results have been recorded by
Statoil at its Norne feld in the Norwegian
North Sea. Following 25 years of research
and development (R&D) and deployment,
the recovery factor at Norne is approaching
55%. More than 30 MMbbl of additional pro-
duced oil has been attributed to the applied
microbial EOR (AMEOR) program there.
In Russia, the Winogradsky Institute of
Biotechnology has done decades of work
with the objective of harnessing the power of
microbes to improve production. Biotopics in
Argentina has had 20 years of experience in
the area. And the Energy Resource Institute
(TERI) in India is a derivative of the huge
TATA Corp. All are energized by the aspect
of recovering a signifcant fraction of crude
oil left behind by initial production methods.
A North American company has beneft-
ed from all this R&D by mining the above
sources for the most successful techniques
and applying them to felds it has purchased.
Glori Energy of Houston is a relative new-
comer, but behaves like a seasoned veteran
benefting from 20 years of learning to avoid
false starts.
The potential of AMEOR is huge, espe-
cially in this era of high crude oil prices. The
good news is that offshore appears to be the
biggest opportunity, because volumes are
very high and initial recovery factors are
low. In addition, many offshore felds are
developed using a single centrally-located
production facility to tap gathering lines.
This layout typically favors EOR techniques,
no matter which type is used. But the rela-
tively small footprint of AMEOR production
equipment poses an additional advantage for
facilities where deck space is at a premium.
Challenges
There is a major difference between
AMEOR and thermal or chemical EOR—
timing. The best time to deploy AMEOR
is from the outset. Why wait until the feld
experiences problems such as loss of pres-
sure, or severe water encroachment? The
application of microbes can enhance produc-
tion from the moment they are introduced.
As a result, experience shows that the best
time to deploy AMEOR is at the frst detec-
tion of water in the fow stream. The treat-
ment can slow the increase in water cut and
ultimately enable more oil production. If an
operator has produced 20% of the oil from
the reservoir, 80% is still in place. If the pro-
ducer can reduce the amount of water be-
ing produced, the fngering of water that is
breaking through into production will stop
and more oil will be produced. Glori Energy
has experienced greatly-improved recovery
factors on the felds it has treated.
In a water-wet reservoir, which most are,
there is irreducible water that will never pro-
duce. It is held to the sand grains by surface
tension. The greater the surface area of the
sand grains, the more irreducible water will
adhere. The trick is to shut off the mobile
water by boosting the relative permeability
to oil. You do not have to shut off all the wa-
ter, just the mobile portion.
Timing is everything. Many operators
wait too long to decide about using mi-
crobes. As a result, the challenges can be
insurmountable. Many prefer to “trial” the
technique on felds that are old and tired,
justifying their decision under the philoso-
phy of “do no harm,” rather than investigat-
ing the real potential. Too little, too late, and
the challenges of performing a well-confg-
ured and appropriate test can be signifcant.
Results are sometimes diffcult to quantify
because there is limited or low quality non-
granular baseline data.
Additionally, many engineers believe that
bacteria are bad, that they contribute to corro-
sion or souring. Experience at Norne shows
that souring is not an issue and the potential
to corrode downhole tubulars can be elimi-
nated by anti-corrosion coatings or the use
of stainless metals. Actually the chemicals in-
jected suppress souring. As far as corrosion
is concerned, the only element involved is
oxygen. In actual practice, only the injection
zone is affected, the rest of the well tubulars
are unaffected. None of the producing wells
have been monitored producing any of the
bacteria. It is consumed close to the injector.
While inhibition steps cost money, the im-
provement in production completely justifes
the techniques from a fnancial perspective.
Glori Energy is a Clean-Tech 100 company,
so there is no downside risk. The process
does not increase souring potential.
Addressing the technique from the f-
nancial point of view, leads to another issue.
Some operators who have trialed AMEOR
have chosen very low quality project oppor-
tunities—those deemed of lowest risk. Even
though experience shows that risks are insig-
nifcant, they are reluctant to commit a well
making 1,000 b/d or more, even though a sig-
nifcant production uplift could be attained. If
stripper wells are offered, even if production
is doubled, they are still stripper wells.
How does it work?
There is no need to inject “cultured”
bacteria into the wells. In fact, most bacte-
ria that is grown under surface conditions
cannot withstand bottomhole temperatures.
Glori Energy takes advantage of bacteria
that is already in the reservoir, so it fully ac-
climatized to the environment. The bacteria
are activated by injection of nutrients and a
few parts per million of oxygen. Within six
months a change of productivity should be
observed. Over longer periods production
rate increases up to 30% have been experi-
enced along with a decrease in decline rate.
The project is easily controlled. To stop it,
stop feeding the bacteria called a “soft kill,”
or oxygenate the water by adding about 4
ppm O
2
. The idea that double-digit improve-
ments in recovery factor are attainable from
reservoirs that have already been discov-
ered and developed should attract operators
everywhere, but especially in North Ameri-
ca offshore. •
Applied microbial EOR offers potential, opportunity for operators
Timing is everything. Many operators wait
too long to decide about using microbes.
1406off_26 26 6/3/14 2:15 PM
1406off_27 27 6/3/14 2:15 PM
GEOSCI ENCES
(FOF ,MJFXFS t )PVTUPO
28 0G GTIPSF June 2014 t www.offshore-mag.com
PEMEX awards seismic survey contract
ION Geophysical Corp.’s GX Technology group has won a multi-
year contract with Petroleos Mexicanos (PEMEX), the national oil
company of Mexico, to provide a range of seismic data processing
for multiple offshore and onshore surveys over the next three years.
The work will be done at GXT’s Villahermosa, Mexico, and Houston
offces, and through its Houston high performance computing center.
GXT will apply proprietary imaging technologies to process the
data that will include deepwaters of the Gulf of Mexico in complex
subsalt areas. The scope of services includes GXT’s WiBand broad-
band processing, velocity model building, and pre-stack depth mi-
gration (PreSDM) using both beam migration and high frequency
reverse time migration (RTM) techniques.
“PEMEX will continue to invest heavily in hydrocarbon explora-
tion and development in the years ahead,” said Jose Antonio Escal-
era, sub-director of Exploration at PEMEX. “Much of this investment
will be directed at E&P projects in which the targets are located
in complex geologic regimes, including in fractured carbonate and
deepwater subsalt reservoirs.”
This comes as Mexico moves to open its energy sector for outside
investments. The moves include plans to release previously conf-
dential seismic data.
PEMEX will release its seismic data after the completion of follow-
up legislation and rule-making as soon as April 20. Shortly thereaf-
ter, he said, the data will become public.
New permits for seismic assessment are expected following im-
plementation of the April legislation, moving toward a frst round of
open bidding around June of next year.
Husky-CNOOC contract
Indonesian seismic work
Nordic Maritime, in collaboration with ELNUSA, has contracted
a 3D seismic data acquisition and processing job offshore Indonesia
for Husky-CNOOC Madura Ltd.
Nordic Maritime’s seismic vessel S/V Nordic Bahari, which re-
cently completed a 2,500-line km (1,553-mi) 2D marine seismic data
acquisition and processing project on data from East Malaysia’s Sar-
awak T3 block, for Pexco Sarawak N.V., will start the acquisition of
approximately 420 sq km (162 sq mi) by the end of May with sup-
port from chase vessel M/V Viking Vanguard.
The project is expected to be completed by July.
PGS to expand offshore eastern Canada data
PGS is expanding its multi-client library offshore eastern Canada
with an added 30,000 km (18,641 mi) of 2D seismic data in the Lab-
rador Sea and Newfoundland Flemish Pass.
The M/V Sanco Spirit, using the PGS GeoStreamer multi-sensor
technology, will start seismic and gravity data acquisition in the Lab-
rador Sea and northeast Newfoundland-Flemish Pass areas. The data
should be relevant to areas of interest (AOIs) that Canada’s New-
foundland and Labrador Offshore Petroleum Board (C-NLOPB) is
expected to announce soon following last December’s new land ten-
ure system.This new data will complement PGS’ existing 47,600 km
(29,577 mi) of 2D regional data acquired from 2011 to 2013.
The survey is in cooperation with TGS which will perform the
data processing. Final data is expected to be available to clients in
3Q 2015.
Also this July the M/V Atlantic Explorer is scheduled to start ac-
quisition of seismic and gravity data in the Tail of the Bank area of
Southeast Grand Banks. The Southeast Grand Banks 2D covers an
initial 15,000 km (9,321 mi), where it is expected the C-NLOPB will
announce future AOIs. Once again processing of the GeoStreamer
data will be performed by TGS and fnal data will be available to
clients in 3Q 2015.
3D seismic survey completed
offshore Namibia
Pancontinental Oil & Gas NL has completed a 3D seismic survey
of its prospective offshore acreage in license area EL 0037 offshore
Namibia.
The 3D acquisition, over approximately 3,000 sq km (1,158 sq mi)
covers a number of leads noted on existing 2D seismic data. A second
2D acquisition phase will cover approximately 1,000 km (621 mi).
EL 0037 covers 17,295 sq km (6,678 sq mi) in the Walvis basin.
The 3D survey was managed by the EL0037 Joint Venture operator
Tullow Oil, using the seismic acquisition vessel Polarcus Asima.
Moroccan survey done for Chariot
Chariot Oil & Gas Ltd. has completed a 1,700-sq km (656-sq mi)
3D seismic survey across its areas of interest offshore Morocco.
The survey, encompassing ~1,075 sq km (415 sq mi) in Rabat Deep,
~250 sq km (96 sq mi) in Loukos Offshore, and ~375 sq km (145 sq
mi) in Mohammedia Reconnaissance, is intended to enable the com-
pany to mature drillable prospects in the Mio-Pliocene and Jurassic
plays identifed within this region on reprocessed legacy 2D data.
Following processing, Chariot will interpret this new data which
is expected to be completed by the end of 2014.
Survey off Iran anticipates embargo lift
Global Geo Services has made available its Persian Carpet 2000
multi-client 2D seismic survey over 106,000 km (65,865 mi) of the
Iranian part of the Persian Gulf and the Oman Sea.
CEO Bjorn Ursin-Holm said: “With the ongoing international ne-
gotiations to lift the US/EU embargo on Iran, there is a big push to
open up Iran for new foreign investments to international oil com-
panies. The PC-2000 seismic survey covers the entire offshore area
offshore Iran and preliminary interpretation of the data shows geo-
logical risks will be minimal, reserves are huge, and there is signif-
cant potential for the international community.”
PC-2000 provides a dense grid of 2x2-km seismic lines. Numerous
undrilled structures and stratigraphic prospects have been found
from preliminary interpretation of the data, the company said. •
Lease areas held offshore Namibia.
1406off_28 28 6/3/14 2:15 PM
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1406off_29 29 6/3/14 2:15 PM
OFFSHORE AUTOMATI ON SOLUTI ONS
30 Of fshore June 2014 t www.offshore-mag.com
Ian Verhappen
Industrial Automation Networks Inc.
This author and industry observer had
the opportunity to attend OTC (Offshore
Technology Conference) 2014 in Houston in
early May, and therefore had an opportunity
to wander through the exhibition foor to see
how automation is being deployed and used
offshore – above and below the waves. It was
good to see how technology, and in particular
automation technology, is helping to make
the offshore environment safer, more reli-
able, and cost effective than ever before.
The frst general impression of the event,
other than its sheer size, is the large number
of international exhibitors, particularly from
Asia. However, most of these companies are
hardware manufacturers (i.e. valves, drilling
tools, fabricators, etc.) rather than automa-
tion equipment suppliers. The country pa-
vilions, however, did have some interesting
items in them, though in some cases it was
hard to get access to all the smaller booths
under the umbrella (or indeed fnd them) –
often because the numbering they used was
different than the rest of the hall.
My observations can be categorized into
the following broad categories: subsea, com-
munications, asset management, and sensors;
so let’s take a look at each of these individually.
Subsea
Due to the remote and harsh conditions
subsea, equipment for this environment must
be at a minimum semi-autonomous (able to
continue operating without continuous sur-
face communications), which implicitly leads
to some level of automation. The most obvi-
ous automated subsea equipment are the
production pads themselves, though I saw
little of that equipment other than perhaps
the chokes and valves. However, what I did
see – that may not be considered typical ex-
amples of automation – were the submersible
vehicles. By their nature, these vehicles re-
quire a high level of automation for steering,
maintaining orientation (gyroscopes), ma-
nipulation of the various motors, robot arms,
etc., that allow them to perform the tasks for
which they are designed under the guidance
of a remote operator. In the event of lost sur-
face communications for extended periods of
time, these devices also have to be able to au-
tonomously continue or abort their mission
without jeopardizing the submersible.
As might be expected, a number of exhibi-
tors demonstrated how products developed
for the onshore market had been adapted for
use offshore, whether that was development
of specifc applications (software and opera-
tor assistants), marine certifcation, or reduc-
tion of weight to provide the same capability
using less power or space. A number of the
larger exhibitors in this category showed
how their equipment could be used in harsh
environments above or below the surface.
Communications
The most visible communications com-
ponents on display were the wide range of
subsea cables, or perhaps more accurately
umbilical cords, that connect the ocean foor
with the surface. These cables are engineer-
ing marvels that combine a wide range of
communications media in close proximity to
each other, while being able to withstand the
rigours of the subsea environment. The de-
signs also keep them electrically (EMI/RFI,
etc.) isolated so that the message on the
cables do not degrade during transmission.
There were also a number of advances in
topsides communications. The exhibition hall
featured a number of rugged and seaworthy
wireless products which offer a means of
connecting previously uneconomic devices/
alarms, or simply eliminating the weight as-
sociated with cabling infrastructure.
Asset management
Keeping track of things, and more impor-
tantly individuals in real time – with minimal
intervention by the individual or asset – is
becoming an important component of HSE
programs. Knowing where everyone is can
save precious time in the event of an abnor-
mal situation, and can also be used to pro-
vide alerts in the event that someone does
not move enough. This was the innovation
that sparked my interest in OTC – being
able to identify a potential “man down” re-
motely.
Installing a wireless backbone network
also makes it possible to provide remote
support for feld personnel, enabling them
to access the maintenance network while
“on the foor.” For example, these technolo-
gies enable workers to view data manuals off
the server remotely, or check on stores/in-
ventory from the equipment itself. This can
be a particularly useful tool for checking on
the availability of replacement parts prior to
disassembling equipment, thereby improv-
ing productivity and overall equipment reli-
ability.
Sensors
Using the wireless infrastructure now
fnding its way offshore, a couple of exhibi-
tors were showing how passive sensors can
measure strain and temperature readings,
and communicate them to a central gateway
for retransmission to the central control-
lers. Because passive sensors have a limited
range, the gateways must be located within
a few meters of the sensor proper, and from
there connect to the larger network trans-
mitting the signal back to the control cen-
ter. So, to some extent, the development
of these sensor networks depends on the
broader wireless network developments and
adoption rates.
Though diffcult to fnd the “automation”
offerings at OTC, they certainly were evident
– in some cases as part of a large multi-nation-
al space; in others within the far more cozy
country pavilions; and then also in separate
stands. Like always, just as interesting as the
displays and products are the opportunities
to network with peers and through them
learn not only about the products but also
how they are being applied or (just as much
fun) how they might be applied with a little
ingenuity or imagination. After all, the origi-
nal product is the result of someone’s ingenu-
ity, so it only seems fair that as engineers and
technical people we take that next step to de-
termine the problems that these devices can
solve. Keep that thought in mind next time
you attend a trade show, conference, or ex-
hibition because that is how you will add and
receive real value from the event. •
The Author
Ian Verhappen, P.Eng. is an ISA Fellow, ISA Certifed
Automation Professional (CAP), Automation Hall of
Fame member and a recognized authority on process
analyzer sample systems, Foundation Fieldbus and
industrial communications technologies. Verhappen
provides consulting services in the areas of feld level
industrial communications, process analytics, and
hydrocarbon facility automation. Feedback is always
welcome via e-mail at [email protected].
Reviewing automation offerings at OTC
This was the innovation that sparked my interest −
being able to identify a potential ‘man down’ remotely.
1406off_30 30 6/3/14 2:15 PM
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1406off_31 31 6/3/14 2:15 PM
REGULATORY PERSPECTI VES
32 Of fshore June 2014 t www.offshore-mag.com
Boyd Carano
Alan J. Alexander
Raul Garcia
Vinson & Elkins LLP
Mexico is the ninth largest producer of oil in the world and its proved
reserves of 11.4 Bbbl are the 18th largest in the world. Approximate-
ly 75% of Mexico’s production is found offshore in the shallow-water
Cantarell, Ku-Maloob-Zaap, Abkatún-Pol Chuc, and Litoral of Tabasco
felds. However, as production from the Cantarell feld has declined
from a peak 2.1 MMb/d in 2004 to 400,000 b/d at the end of 2012, Mex-
ico’s overall production has likewise fallen from a peak of 3.4 MMb/d
in 2004 to 2.5 MMb/d in 2012. In recent years, Mexico’s state-owned
oil company, Petróleos Mexicanos (PEMEX), has had some success
exploring in deepwater in the Gulf of Mexico, but still lacks the neces-
sary capability and capital to operate and produce in such deepwaters.
National ownership of all hydrocarbons was established in Mex-
ico’s post-revolutionary Constitution of 1917. In 1938, the Mexican
oil and gas industry was nationalized and PEMEX was established
as the sole operator in the country. PEMEX’s declining production
is due at least in part to its legal inability to work with private partici-
pants to gain access to the technical capability, experience, and capi-
tal that it lacks in order to produce its more challenging resources,
such as deepwater deposits.
Legal reform of the industry to allow for private investment in oil
and gas resources took the frst step toward coming to fruition in
December 2013 with the approval of changes to Mexico’s Constitu-
tion. The constitutional reforms preserve state ownership of hydro-
carbons in place, but allow for private ownership after extraction.
The reforms provided for four types of contracting regimes: service
contracts, proft-sharing contracts, production sharing-contracts,
and licenses; however, the terms of these agreements have not yet
been made available. It also became clear from the constitutional
reforms that private parties would not be required to partner with
PEMEX in order to participate in Mexican oil and gas plays.
Nonetheless, before felds would be bid to private parties, PEMEX,
through a process known as “Round Zero,” will be allowed to retain
felds, if it can show that it possesses the technical, operational, and
fnancial capabilities to develop them. In March, PEMEX sent to the
Ministry of Energy (SENER) the list of felds it would like to retain.
Although the list has not been made public, SENER disclosed that
PEMEX seeks to retain 83% of its proven and probable oil reserves
and 31% of its prospective resources, which would include deepwater
felds. PEMEX’s experience resides in operating in shallow water and
with tertiary recovery operations, so it is likely that it will be allowed
to retain the Cantarell, Ku-Maloob-Zaap, Abkatún-Pol Chuc, and Lito-
ral of Tabasco felds, among others, and seek additional technical
experience in more challenging offshore felds, such as extra heavy
felds in shallow water and deepwater felds in the Gulf of Mexico.
SENER has until September to issue its fnal ruling on the list of felds
that PEMEX seeks to retain.
Much of the detail with respect to the implementation of the consti-
tutional reforms was left to secondary legislation. The proposed sec-
ondary legislation would only allow PEMEX independent authority to
enter into service contracts, and not joint ventures, for felds awarded to
it through the Round Zero process (Assignment Areas). Instead, if PE-
MEX desires to explore or develop an Assignment Area through a joint
venture, it would frst be required to request the CNH to “migrate” such
Assignment Area. The CNH would then conduct a public bid process to
determine PEMEX’s joint venture partner pursuant to an exploration and
production contract. With respect to all other areas that CNH tenders for
bid pursuant to exploration and production contracts, interested parties
are free to enter into joint ventures with PEMEX or anyone else to bid
and, if the bid is awarded, explore and develop such areas.
The proposed secondary legislation also would include a 25% na-
tional content requirement for exploration and production contracts
that would be gradually implemented starting in 2015 with such
implementation continuing through 2025.
Another proposal included in the secondary legislation would re-
quire PEMEX to have a minimum 20% stake in any exploration and
production contract that encompasses cross-border felds, including
those located offshore. International oil companies will be required
to partner with PEMEX for these future cross-border felds, though
it is not required that PEMEX be the operator of such felds.
The proposed secondary legislation also would allow SENER to re-
quire the participation of PEMEX in exploration and production con-
tracts where there are opportunities for technology transfer to help
develop the capacities of PEMEX. In these cases, PEMEX would have
a maximum participation of up to 30%.
As with any legislative process, the secondary legislation as ul-
timately adopted by the Mexican government is likely to differ in
some respects from the proposals recently put forth. Regardless of
the fnal form of the secondary legislation, other issues for private
parties to consider between now and mid-2015 when the frst bid
rounds are anticipated to take place include:
* Sulñcient amounts and/or adequate quality ol providers to meet
the new local content rules
* Compliance with the terms ol the USMexico Transboundary Hydro-
carbon Agreement for operations on reservoirs that straddle the mari-
time boundary ol the US and Mexico, including entering into unitiza-
tion agreements and unit operating agreements under the agreement
* Lnvironmental law considerations, the importance ol which are
highlighted by Mexico’s proposed new environmental protection
agency, independent of the Ministry of Environment and Natural
Resources, called the National Agency for Industrial Security and
Environmental Protection in the Hydrocarbon Sector
* The degree ol availability ol gathering, storage, pipeline, and oth-
er midstream infrastructure in the areas that are offered for bid
* Anticorruption considerations, including compliance with the
£C!A and the UK Bribery Act, as well as Mexico`s own new
anti-bribery statute
* Labor and employment considerations, including the availabil-
ity of qualifed workers and possible interactions with the Petro-
leum Workers Union ol Mexico
* Transaction structuring to take advantage ol bilateral investment
treaties and tax treaties between Mexico and other jurisdictions.
If the secondary legislation that is ultimately adopted is substan-
tially similar to what has so far been proposed, Mexico could see
signifcant growth in offshore activity in the coming years. •
The authors
Boyd Carano is a partner at Vinson & Elkins LLP. Based in Palo Alto,
California, he is a member of the global law frm’s Energy Industry
Group and worldwide Project Finance and Development Practice Group.
Alan J. Alexander is an associate at Vinson & Elkins. Based in Hous-
ton, he focuses on transactions and projects in the energy industry,
including mergers and acquisitions, project fnancings, joint ventures,
and deals involving private equity.
Raul Garcia is an associate at Vinson & Elkins. Based in Houston, his
principal areas of practice are mergers and acquisitions and energy
transactions and projects.
Deepwater opportunities beckon offshore Mexico
1406off_32 32 6/3/14 2:15 PM
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CapCom_OSRMel_1406 1 4/3/14 5:22 PM
34 Of fshore June 2O14 ª www.offshore-mag.com

GULF OF MEXI CO
Drilling in Gulf of Mexico
remains robust
Numbers down recently
but still up since 2010
G
ulf of Mexico drilling activity remains
robust and has continued to show
a remarkable comeback from the
events of 2010, but the market has
seen a decline in activity in recent
months as operators scale back their com-
mitments due to growing costs, and with
past spending commitments coming due.
According to Baker Hughes rig count data,
the number of rigs working in the Gulf dipped
to a low of 12 in July 2010, three months be-
fore the federal moratorium on drilling was
lifted. By September 2013, there were 63 rigs
working in the GoM, the majority targeting
oil in the deep waters of the outer continen-
tal shelf. The count has since backed off that
high, though it matches levels seen before
April 2010. According to the Baker Hughes
rig count data, there were 58 rotary rigs oper-
ating in the Gulf of Mexico as of May 9.
According to IHS Petrodata, total con-
tracted backlog for the US GoM has fallen
from approximately 2,186 months per rig in
early December 2013 to about 2,043 months
per rig as of early May 2014. However, the
number of drillships in the region has in-
creased by seven units over the same pe-
riod, stretching out the number of rigs by
which the total is divided.
“The combination of the fast-growing foat-
er supply with the relatively few foating rig
contracts signed over the past several months
means the foater segment has suffered more
of a decline in contracted backlog months
than the much-larger jackup segment,” says
Cinnamon Odell, rig analyst at IHS Petrodata.
For the foating rig segment, contracted rig
backlog stands at about 1,921 months of work
as of early May. This is a decline from 2,017
months of work on rig contractors’ books in
early December 2013. At present, about 86%
of remaining 2014 days are booked for drill-
ships and around 61% for semis. For 2015,
85% of drillship days are locked up, as are 41%
of semi days, says Odell.
Looking at the jackup segment, only 30%
of remaining 2014 days in the US Gulf are al-
ready contracted. Odell notes that 21 of the
region’s 58 jackups are cold stacked, mean-
ing they are not being actively marketed for
work. In December 2013, jackups had a total
of 169 months of upcoming work secured.
“Now that fgure has dropped to about 123
months of future work,” Odell observed.
“Less than 1% of available days in 2015 are
booked, leaving essentially the entire year
still open for any operator looking to drill in
jackup territory next year.”
The reasons for the decline in drilling activ-
ity vary among operators, but are most often
tied to rising costs or limited budgets. Some
operators have been reducing their spending
due to high costs; others cite the fact that past
spending commitments are now coming due.
“We’ve seen some gaps between programs
for jackups as well as foaters,” Odell notes.
“And for the frst time in many years, not
counting the post-Macondo moratorium pe-
riod, US GoM foaters are idle and looking for
work both here and abroad.” Odell notes that
in May, Transocean confrmed that its GSF
Development Driller II has mobilized out of the
US Gulf for work in the Black Sea. That rig
had been working in the GoM fully utilized
since it arrived for its maiden job in 2005.
Odell also notes that operators are taking
advantage of the fact that foater rates are
coming down, “so those that are looking for
rigs for upcoming programs are hesitant to
sign on the dotted line while prices continue
to drop. They are waiting to see how things
play out before they commit.” So while some
operators are committed to spending less
this year than in past years, demand still ex-
Bruce Beaubouef
Managing Editor
The Sevan Louisiana ultradeepwater rig mo-
bilized on her own power from Singapore to
Curacao with a tug assist for fuel economies.
The rig recently left Curaçao for an upcoming
job in the Gulf of Mexico. (Courtesy Sevan
Drilling ASA)
1406off_34 34 6/3/14 2:15 PM
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GULF OF MEXI CO
ists. “It’s just a matter of negotiating the best
deal on the part of the rig contractor and the
operator,” Odell observes.
Despite this recent decline, industry ana-
lysts believe that as long as oil prices stay in
the $80 to $90/bbl range, drilling in the Gulf
will remain active. Major oil companies like
ExxonMobil, Chevron, and BP are spend-
ing billions of dollars developing deepwater
felds that are projected to almost double the
fow of oil over the next decade.
The latest sale of federal oil and gas leas-
es in March drew more than $870 million
in high bids, including $41.6 million from
BP. The British oil company was permitted
to bid on leases for the frst time since the
Macondo spill, after reaching an agreement
with the Environmental Protection Agency
in March.
To be sure, safety regulations and permit-
ting requirements have escalated since 2010,
and that has slowed drilling activity. Since
Macondo, the federal government has insti-
tuted stricter requirements on safety equip-
ment like blowout preventers, and on the
readiness of spill response teams.
Regulators are also forcing companies to
take a more systemic approach to drilling
safety. Instead of following a set of rules, com-
panies are being required to develop drilling
plans that prove they have taken appropriate
steps to avoid blowouts. And those plans must
be signed off on by a third-party consultant.
At least partly as a result, drilling costs in
the GoM have increased dramatically over
the last fve years. The regulations set in
place since Macondo require more expensive
equipment, and have extended drilling peri-
ods on some deepwater wells to nine months,
roughly 30% longer than before. Despite all
this, increased demand in the Gulf and other
offshore areas has driven up the rates on the
advanced drilling rigs needed for deepwater
jobs to more than $500,000 a day.
In recent weeks, a number of operators and
contractors have updated their exploration and
development efforts in the Gulf, or announced
the start of new drilling campaigns.
In April, Stone Energy Corp. reported suc-
cess on the deepwater Cardona South well in
Mississippi Canyon block 29. The company
said that the Cardona South well (MC 29 #5)
encountered more than 275 ft (84 m) of net oil
pay in three separate sections of the well.
The Cardona South well extends the pro-
ductive zone of the Mississippi Canyon 29
TB-9 well to the adjacent fault block to the
south and sets up a potential second and
Maersk Drilling says that the Maersk Valiant has begun its voyage to the Gulf of Mexico, where it will
commence a two-year contract with ConocoPhillips and Marathon Oil Corp. (Courtesy Maersk Drilling)
1406off_36 36 6/3/14 2:15 PM
1406off_37 37 6/3/14 2:15 PM
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GULF OF MEXI CO
US Gulf of Mexico current backlog as a percentage of available supply
Rig type Total current backlog 2014 2015
Drillship 1,554.83 85.85 85.05
Jackup 122.58 30.41 0.72
Semisubmersible 365.76 60.68 41.31
‘Available’ excludes non-marketed rigs and units that are not immediately ready to go to work, for example because they are in
the yard. ‘Current Backlog’ is defined as future contract commitments, as of May 2, 2014, expressed in rig months.
Source: IHS Petrodata
third well in the fault block. Plans are to fow
the Cardona South well (and the previously
announced Cardona discovery) to the Stone
owned and operated Pompano platform,
with frst production expected in early 2015.
Production casing has been set and ce-
mented in the Cardona South well and the
subsea tree equipment will soon be put in
place. The rig will then move back to the
original Cardona well (MC 29 #4 well) to be-
gin completion operations before returning
to complete the Cardona South well. Sepa-
rately, the original Cardona well was previ-
ously estimated to have approximately 84 ft
(26 m) of net oil pay. After further evalua-
tion, the estimated net oil pay for this well is
now approximately 96 ft (29 m).
Also in April, Maersk Drilling reported
that its Maersk Valiant drillship had begun its
voyage from Singapore to the Gulf, where
it will commence a two-year contract with
ConocoPhillips and Marathon Oil Corp. The
estimated contract value with ConocoPhil-
lips and Marathon for Maersk Valiant is $694
million including mobilization, but exclud-
ing cost escalation.
In May, Statoil announced that it had start-
ed drilling Martin, a high-impact prospect in
the Gulf, on April 20. The company says that
it considers Martin one of the top prospects
in its global portfolio; and that, since acquir-
ing the prospect in 2012, it has been able to
advance it in 20 months, considerably faster
than the normal maturation time.
Exxon Mobil is pursuing what is believed
to be one of the largest deposits in the deep-
water area, the Julia feld. At a depth of more
than 30,000 ft (9,144 m), Exxon is spending
$4 billion, with production set to begin in
2016.
BP continues to focus on its deepwater
felds in the Gulf, with a company-record 10
rigs operating there now. Offcials say that
the company will spend $10 billion over the
next fve years in the deepwater Gulf, which
amounts to about 10% of its worldwide explo-
ration and production budget.
Likewise, Chevron has its Jack/St. Malo
and Big Foot felds coming online this year
and next. They are projected to eventually pro-
duce almost 170,000 b/d of oil — on par with
daily oil production in Wyoming last year.
Analysts are projecting oil prices will drop
close to $80 by the end of 2015 as large quan-
tities of crude come online. That could put
a dent in the domestic hydraulic fracturing
boom, in which operators must constantly
drill new wells to keep up with rapid declines
in productivity.
But the same impact is not expected in
the Gulf of Mexico. With billions of dollars
invested and steadier productivity from deep
Gulf wells, the oil companies have committed
themselves for the long term. •
1406off_38 38 6/3/14 2:16 PM
Refinery-wide modelling
using your own standards
REFINING
Facility models that
understand field plans
PRODUCTION
[email protected] www.kbcat.com blog.kbcat.com
EMEA: +44 1932 242424 ASIA: +65 6735 5488 AMER: +1 281 293 8200
KBC Advanced Technologies plc
1406off_39 39 6/3/14 2:16 PM
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GULF OF MEXI CO
Offline wells reduce value
in US deepwater Gulf
Short production halts have long-term ef fect
W
ood Mackenzie recently studied the
number of days of production per
month for more than 1,200 wells in
deepwater Gulf of Mexico (GoM)
between 2007 and 2013. Production
wells are thought of as fowing more or less
consistently. However, these wells can be shut-
in for numerous reasons, including inclement
weather, equipment failure, and on-going main-
tenance drilling programs like workovers, side
tracks, and recompletions.
Based on the study, producing oil and
gas wells in deepwater GoM were online on
average only 79% of the time – less than 10
months in any given year. While it is intuitive
that a loss of production leads to lower reve-
nue in the near-term, there is also a long-term
impact as oil and gas production is deferred.
Reducing uptime decreases oil and gas felds’
net present value (NPV) and internal rate of
return (IRR). For a larger feld in deepwater
GoM, less than a 10% change in producing
days each year leads to as much as a 15%
change in NPV. For Wood Mackenzie’s base
case model Lower Tertiary feld with a valu-
ation of $822 million, this is the equivalent of
$100 million in unrealized returns.
So while the average well in the region
has been producing the equivalent of 24 days
per month, there is substantial underlying
variation from well to well and year to year.
The standard deviation was approximately
10%, or roughly three days. However, there
are occasional periods when the majority
of wells are not producing simultaneously.
For example, after Hurricane Ike a major-
ity of the felds were shut-in for months due
to damage to production facilities and in-
frastructure. During this time, the average
number of days per month on production
dropped below 20% in September 2008 and
did not exceed 60% until January of the fol-
lowing year. Hurricane Katrina had a similar
effect on production three years earlier.
Despite there being only one major hurri-
cane between 2007 and 2013, Ike was severe
enough to shut-in the majority of deepwater
wells for almost four months. If Ike is exclud-
ed, the six-year average increases from 79%
to 81%. This does not refect the variation in
shut-in duration from well to well. Operators
Nimi Henderson
Thomas Shattuck
Wood Mackenzie
1406off_40 40 6/3/14 2:16 PM
850 km 900 km
913 km
950 km 1000 km 1050 km 1100 km 1150 km 1200 km 1250 km 1300 km 1350 km 1400 km
US | Mexico
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| YucatanSPAN
Mississippi Fan Sigsbee Scarp K2
1450 km 1500 km 1550 km 1600 km
see next page
GULF OF MEXI CO
with suffcient contingency plans for pipeline
and facility damage as well as logistical limita-
tions can bring their wells online faster than
the average. For example, oil exported via
Shell’s Auger pipeline system was re-routed
through a temporarily reversed section of the
Poseidon pipeline following Ike. Fields with-
out that fexibility could be shut-in for infra-
structure repairs after future hurricanes.
While weather related shut-ins are inevita-
ble, there are other times where wells or en-
tire felds go offine. Whether due to mainte-
nance, workovers or equipment failure, these
also impact the feld’s economics. Subsea tie-
backs have an increased risk of being shut-in
because of problems or maintenance at the
host facility. Although these shut-ins are also
unavoidable to some degree, operators can
Average number of days on production per month, 2007-2013. Source: Wood Mackenzie.
1406off_41 41 6/3/14 2:16 PM
Explore the Entire Gulf of Mexico.
1600 km 1650 km 1700 km 1750 km 1800 km 1850 km 1900 km 1950 km 2000 km 2050 km 2100 km 2150 km 2200 km 2250 km 2300 km 2350 km
Belize Fan Yucatan Peninsula Extension Yucatan Scarp
see previous page

GULF OF MEXI CO
design maintenance and workover programs
to minimize downtime and to increase a pro-
ducing asset’s value.
Eliminating downtime
To illustrate how changes in days of pro-
duction per month affect the value of differ-
ent types of felds in GoM, compare two mod-
el felds under varied risking conditions. One
is a multi-well, Lower Tertiary feld, similar
to BP’s Kaskida (KC 292) or Chevron’s Jack
(WR 759). The other is a single-well, Middle
Miocene subsea tieback, similar to those in
Noble Energy’s Rio Grande complex.
The Lower Tertiary model assumes a
standalone facility with 12 producing wells
and three water injectors with recoverable
reserves of 300 MMboe. The Middle Mio-
cene model assumes a single-well tied back
to a nearby facility with total recoverable re-
serves of 22 MMboe. The base case assumes
10 months of production per year during the
entire life of the feld, whereas the low and
high cases assume nine and 11 months, re-
spectively. Assume the same recoverable re-
serves for the low, base, and high cases.
As oil and gas production is deferred into
the future, the NPV and IRR for each feld is
reduced in real terms. For a base case model
Lower Tertiary feld, the NPV is $822 million
Modeling assumptions: The models used for the generic Lower Tertiary and
Middle Miocene fields evaluate a development project sanction forward.
The Lower Tertiary model assumes sanction in 2018 with first production in 2023
and the field developed via a standalone, wet-tree facility with third-party built oil and
gas export lines transporting hydrocarbons to shore. The field was assigned recover-
able reserves of 300 MMboe.
The Middle Miocene model assumes sanction in 2016 with first oil in 2018 and the
field developed as a single-well subsea tieback to nearby infrastructure. The field was
assumed to have recoverable reserves of 22 MMboe.
The low, base, and high cases were generated by varying the number of months
a year a field was producing, from nine to 11 months. The field life varied between
cases; however, all wells were permanently shut-in after oil production dropped
below 300 b/d.
Economic assumptions: Wood Mackenzie’s discount rate is 10% nominal. The
discount date is Jan. 1, 2014, and the inflation rate is 1.9% in 2014 and 2% from 2015
onward.
Wood Mackenzie’s Brent oil price assumption (nominal terms) is $103.25/bbl in
2014, $100/bbl in 2015, $98.73/bbl in 2016, $98/bbl in 2017, and $97.42/bbl in 2018,
inflated at 2% per annum thereafter. This equates to a long-term Brent price assump-
tion of $90.00/bbl (real, 2014 terms) from 2018 onward.
Crude from the model Middle Miocene field is assumed to trade at parity with LLS
crude at (nominal terms): $98.73/bbl in 2014, $96.38/bbl in 2015, $95.29/bbl in 2016,
$94.30/bbl in 2017, $93.72/bbl in 2018, inflated at 2.00% per annum thereafter.
Crude from the model Lower Tertiary field is assumed to trade at parity with Mars
crude at (nominal terms): $97.75/bbl in 2014, $95.86/bbl in 2015, $95.42/bbl in 2016,
$95.67/bbl in 2017, $90.94/bbl in 2018, inflated at 2% per annum thereafter.
Wood Mackenzie’s Henry Hub gas price assumption (nominal terms) is $4.31/Mcf
in 2014, $4.20/Mcf in 2015, $4.72/Mcf in 2016, $4.73/Mcf in 2017, and $4.74/Mcf in 2018,
inflated at 2% per annum thereafter. This equates to a long-term Henry Hub price as-
sumption of $4.38/Mcf (real, 2014 terms) from 2018 onward.
1406off_42 42 6/3/14 2:16 PM
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AREAS OF EXPERTISE
Unconventional Reservoirs
Challenging Environments
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Basin Exploration
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GULF OF MEXI CO
and IRR is 16.5%. An additional month of pro-
duction each year increases the NPV by $100
million and IRR by 1%. These effects also in-
crease with feld size. In the case of the larg-
est Lower Tertiary feld modeled, Tiber at
566 MMboe, producing for 11 months a year
increases the valuation by over $300 million.
For a model Middle Miocene, single-well
subsea tieback, the base case NPV is $284
million and IRR is 60.4%. An additional month
of production each year increases the project
valuation by $15 million and increases IRR
over 3%. For a multi-well tieback, the change
is proportional. A three-well tieback can see
an increase NPV more than $50 million.
In the low case, production in earlier years is
reduced and feld life is extended, decreasing
near-term revenue and increasing total operat-
ing costs. For the model Lower Tertiary feld,
producing the equivalent of nine months a
year reduces NPV by 15% or $125 million. For
the Middle Miocene feld, NPV drops by 6%
or $17 million. In both cases, the downside of
losing a month of production a year outweighs
the increased value from producing an extra
month. To mitigate these risks, operators may
choose to shorten feld life and recover less
reserves. However, this still likely reduces the
overall valuation of the feld.
Although three days a month seems like
a small number, over the period of a larger
feld’s life, this can defer production by years.
In cases like Hurricane Ike, shutting-in pro-
duction is unavoidable, but the effects can
be mitigated by developing adequate contin-
gency plans to bring production on sooner.
Beyond that, optimizing maintenance, work-
overs and side tracks to limit non-productive
time can improve a feld’s economics and
increase earlier cash fows. Furthermore,
operators should review redundancy and
reliability of production equipment to limit
time-consuming maintenance and preserve
value in the long term. •
(Left) Model Lower Tertiary field economics. (Right) Model Middle Miocene field economics.
1406off_43 43 6/3/14 2:16 PM
Offshore milestones, 1979-1983
1979 25th anniversary issue of Offshore magazine
1980 Water drilling depth records, 4,876 ft
1981 Deepest subsea completion, 820 ft
1982 Underwater manifold marks North Sea first
1983 Exxon installs first guyed tower
44 Of fshore June 2O14 ª www.offshore-mag.com

60 YEARS OF OFFSHORE
1406off_44 44 6/3/14 2:16 PM
1406off_45 45 6/3/14 2:16 PM
46 Of fshore June 2O14 ª www.offshore-mag.com

GEOLOGY & GEOPHYSI CS
Quantitative interpretation
emerges as major geoscience tool
Advanced workfow delves deeper into reservoir internals
T
he rise of deepwater exploration, together
with the onshore shale boom, has altered
many industry geoscience workfows.
Organizations are racing to understand
how to economically produce these costly
modern reservoirs. For interpreters, this has
meant the widespread adoption of a series of
advanced workfows that are commonly defned
as Quantitative Interpretation (QI). Broadly
speaking, these techniques take the interpreter
beyond delineating reservoir geometry, picking
horizons and faults, and defning stratigraphy.
The focus of QI is to understand the internals of
the reservoir rather than its architecture.
In the quantitative interpretation workfow,
the interpreter attempts to characterize the
rock type, fuid composition, and fow charac-
teristics of the reservoir. A range of techniques
can be employed, from amplitude variation
with offset (AVO) analysis and inversion, to
facies classifcation, pore pressure prediction,
4D (time-lapse) seismic analysis, and geome-
chanical analysis.
AVO is the leading seismic amplitude analy-
sis technology for direct hydrocarbon detection.
The workfow requires expertise in many disci-
plines, as well as the integration of seismic, petro-
physical, interpretation, and other forms of data.
Inversion uses well log properties and
seismic data to convert the acoustic refec-
tions at layer interfaces into rock properties.
Facies analysis, whether electrofacies us-
ing well log data or seismic facies analysis,
identifes similar groupings of data, allowing
interpreters to identify subtle features.
Understanding pore pressure is impor-
tant in deep prospects. Pore pressure pre-
dictions can be made based on seismic ve-
locities and calibrated to well information.
Seismic velocities can be better defned with
a 3D model that includes the major struc-
tures and major stratigraphic elements.
Time-lapse (4D) seismic analysis can
qualify the predictability and repeatability of
4D data prior to running an adapted reservoir
characterization workfow at the reservoir
level, to confdently analyze and understand
the impact of production and injection, and
interpret changes in reservoir conditions.
Geomechanical analysis helps understand
the distribution of stress within the reser-
voir and can be critical to reducing drilling
risk and superior reservoir management.
The end results of this analysis include a
more precise defnition of lithology, porosity,
estimation of oil and gas in place, brittleness,
fracture orientation, and intensity. These re-
sults allow operators to make better drilling
decisions by identifying the most productive
parts of the reservoir.
One driver behind the enhanced interest
in quantitative interpretation is the advance-
ment in higher resolution imaging made
possible by broadband acquisition and pro-
cessing. Full azimuth and broad frequency
range acquisitions allow operators to see
fner features more clearly. New processing
techniques like 5D regularization have re-
duced acquisition limitations at the surface,
deghosting and other noise suppression al-
gorithms have improved signal quality, and
advanced migration algorithms such as re-
verse time migration or the proprietary Para-
digm full-azimuth angle domain migration
(GeoDepth EarthStudy 360), are able to bet-
ter image complex geology such as near salt
fanks. All of these changes mean interpret-
ers can delve much deeper into their data.
However, generalist interpreters still face
challenges in incorporating QI analysis into
their workfows. Chief among these is the
ever present diffculty of data management.
Quantitative analysis requires both the in-
tegration of well log data with the seismic
– both pre- and post-stack – and then share
this information with well planning and drill-
ing applications. Ideally, it should be pos-
sible to update these quantitative geologi-
cal models with data received in real time
during drilling, and match model data with
actual fndings. However, most organiza-
tions lack integrated software and processes
to make this a reality. Often, different parts
of the quantitative analysis workfow are
conducted in disparate, disconnected tools.
This concern has been voiced to Paradigm
by customers as the top challenge – how to
take advanced workfows and make them
available to every user in a single integrated
solution. Paradigm believes its forthcoming
Epic software is an approach that can help
solve this market need.
Despite these challenges, the industry
continues to forge ahead, adopting advanced
QI workfows in order to reduce the risk on
their billion-dollar feld development proj-
ects. Experienced interpreters have seen nu-
merous fads come and go, but if the recent
years of increasing interest and usage are
any indication, quantitative interpretation is
here to stay. •
Indy Chakrabarti
Paradigm
Advanced interactive QSI workflow in Paradigm 3D Canvas.
1406off_46 46 6/3/14 2:16 PM
Offshore projects are more complex and demanding than ever. The future is farther out and deeper
below, and the challenges that go with it are forcing engineers to work smarter, safer, and more
productively. Bentley’s comprehensive offshore solutions, supported by the integration of industry
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THERE'S
A LOT RIDING
ON THIS
WHEN CONDITIONS
ARE AT THEIR WORST,
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MAXIMUM LOAD
DECK LOAD
CELLAR DECK
R.L 123 M
SIG. WAVE
HEIGHT: 12.5 M
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PLATFORM POSITION
LATITUDE: 56°
10’ 24.2677”
LONGITUDE: 01°
08’ 55.1789”
1406off_47 47 6/3/14 2:16 PM
48 Of fshore June 2O14 ª www.offshore-mag.com

DRI LLI NG & COMPLETI ON
MPD overcomes narrow drilling
window to reach stranded assets
T
he long-producing US Gulf of Mexico
shelf is being revitalized with new
technologies, allowing operators to
access untapped reserves in mature
or depleted felds that would other-
wise be unattainable.
Among the methods opening new oppor-
tunities in mature felds is managed pres-
sure drilling (MPD). In several cases MPD
has succeeded in the Gulf of Mexico (GoM)
shelf in mature felds depleted by more
than 50 years of production. Hydrocarbon
production changes geological properties
which cause a reduction in formation pres-
sures and, subsequently, a narrow available
drilling window subject to wellbore instabil-
ity. Using conventional methods, such condi-
tions can render a well un-drillable or lead
to dangerous and costly well events such as
kicks, losses, and wellbore collapse.
MPD can overcome some of the limits of
conventional technology to drill through a
tight operating window, manage the chang-
ing annular pressure profle, reduce the like-
lihood of a well control event, and manage
wellbore stability to mitigate stuck pipe.
Case history
In one GoM shelf well, an MPD system
enabled a major operator to successfully
tap previously unattainable assets in a feld
brought online in the mid-1960s. Although
reservoir pressure had declined in the tar-
get sand as well as some shallower sands,
recent well pressure profle tests indicated
that pockets of untapped hydrocarbons with-
in the formation could enable production for
many more years.
The well is in South Timbalier, in less
than 200 ft (61 m) water depth, southwest
of Grand Isle, Louisiana. A variety of prob-
lems in drilling an offset well—reduced frac-
ture gradient, differential sticking, and lost
returns—showed it would be diffcult if not
impossible to drill this well conventionally.
The target sand’s proximity to salt added to
the complications and uncertainties.
MPD in a mature feld
The operator determined the best ap-
proach to produce from these stranded as-
sets would be to drill a side track from the
main wellbore, originally drilled in the year
2000. Pre-drill pressure models indicated the
margin between wellbore stability gradient
and fracture gradient was too tight to drill
conventionally, as depletion in the reservoir
had reduced the expected fracture gradient.
That led the operator and Weatherford to
deploy the Microfux MPD control system.
The system is designed to enhance safety
and reduce environmental risk and cost
when drilling through challenging forma-
tions, including mature and depleted felds.
The technology facilitates drilling through
multiple abnormal pressure profles using
mud weights closer to pore pressure. It helps
ensure constant bottomhole pressure (CBHP)
is maintained during connections and trips,
and allows for dynamic formation integrity
tests (FIT) at any depth while drilling. If swab-
bing is a concern, the MPD control system
also can manage surface backpressure to
maintain CBHP when tripping out of the hole.
In MPD, a rotating control device (RCD)
is required to close the loop. For safety, the
closed-to-the-atmosphere system diverts all
of the fuid returns away from the wellbore
and through the MPD manifold, while simul-
taneously providing surface back pressure
on the well. A closed-loop system allows the
fexibility to manipulate annular pressure as
the well dictates and enables drilling in en-
vironmentally sensitive and hazardous areas
by minimizing the potential for fuid spills.
Microfux has an auto-control feature that
restores mass balance and provides faster
response times to minimize fuid infuxes.
The ability to quickly adapt to changing well
conditions is critical when drilling with nar-
row margins. Drilling effciency is enhanced
through dynamic mud weight manage-
ment and more accurate pore and fracture
pressure determination. Economically, the
technology enables operators to make cost-
effective drilling decisions based on actual
surface and well data, rather than predic-
tive models, and also differentiates between
kicks/losses and less-critical wellbore is-
sues. It reduces non-productive time by miti-
gating a variety of drilling hazards, improves
rate of penetration (ROP) which minimizes
tripping and unnecessary well shut-ins.
Following pre-job planning that included a
geological analysis of the target and drilling
of offset wells, the operator set a whipstock
and deployed the MPD control system from
a jackup rig to drill an initial 6½-in. side track
from the existing 7-in. liner. Drilling abrupt-
ly halted due to an unpredicted fault that
caused the well to deviate from the planned
trajectory.
Lessons learned
Although the initial side track cost time,
the operator and crew used lessons learned
when drilling a second side track. By deploy-
ing the MPD control system in the frst side
track, the operator was able to respond to well
events in real-time and to use the information
to plan a second side track with fewer hole
stability issues. Instead of geological models,
the second well was planned using real-time
data gathered from the initial side track.
Neal Richard
Weatherford
MPD piping and instrumentation design illustrates the MPD flow loop.
(All images courtesy Weatherford)
1406off_48 48 6/3/14 2:16 PM
CONFERENCE & EXHIBITION
26 - 28 JANUARY 2015
QATAR NATIONAL
CONVENTION CENTRE
DOHA, QATAR
OPTIMIZING
PERFORMANCE
Supporting Publications:
Owned and
produced by:
Presented by:
Held under the Patronage of H.E. Dr Mohd Bin Saleh
Al-Sada, Minister of Energy & Industry, State of Qatar
Organised by: Hosted by:
INVITATION TO EXHIBIT
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provides the ideal location from which to collaborate, conduct business and
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Jane Bailey
Europe, Middle East & Africa
T: +44 (0) 1992 656 651
M: +44 7983 388 367
F: +44 (0) 1992 656 700
E: [email protected]
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The Americas
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Australia, New Zealand,
South East Asia
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M: +61 437 700 093
E: [email protected]
1406off_49 49 6/3/14 2:16 PM
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www.cat.com www.caterpillar.com

DRI LLI NG & COMPLETI ON
The Microfux capability was enabled by
key components, including the RCD, installed
on the well to contain and divert annular fuids
while drilling. For data recovery, the device
routes fuid through the control manifold,
which has a Coriolis mass fow meter to cap-
ture in real time data such as mass fow and
volume fow rates, fuid density, and tempera-
ture of the returning annular fuids.
The data is routed to the intelligent control
unit (ICU), an independent SCADA control
system that measures and analyzes physical
properties, reacting to well control events,
and distinguishing between ballooning/
breathing and more serious fuid infuxes or
losses. The ICU sends data to the operator
and redundant interfaces and, when in auto-
mated mode, controls the drilling chokes to
regulate backpressure.
The real-time data from the initial side
track revealed that while depletion in the res-
ervoir had reduced the fracture gradient and
narrowed the drilling margin, the more seri-
ous challenge was hole instability. The data
also showed that the mud weight required to
control the shales would need to be higher
than the offset wells had indicated.
A common condition in many mature
GoM shelf felds is that the lower pressure
limit of the wellbore is the stability gradient.
In a typical well the lower limit is known
as the pore pressure and the upper limit is
known as the fracture gradient. Drilling
fuid density typically is selected to remain
within these two limits. If the pumped drill-
ing fuid is too light, the well may begin to
fow hydrocarbons from the open formation
resulting in an infux. If the pumped drilling
fuid is too heavy, it eventually breaks down
the formation, resulting in fuid loss.
In this particular well, however, the stabil-
ity gradient was the lower limit. When the
stability gradient is higher than the pore
pressure, if the bottomhole pressure drops
too low, the wellbore is subject to instability
and risk of collapse.
Hole instability is exacerbated by cyclical
stress from making pipe connections in con-
ventional drilling. Normal drilling consists of
drillstring rotation and pumping fuid up the
annulus creates an added pressure transmitted
downhole. This is defned as equivalent circu-
lating density (ECD). When drilling stops to
make connections, a loss of bottomhole ECD
is observed and the wellbore is relaxed. The
continuous shifting of bottomhole pressure can
cause wellbore fatigue, especially in unstable
shale or ballooning formations. Using the
CBHP variant of MPD, surface backpressure is
applied during connections to compensate for
any ECD lost and to prevent the wellbore from
relaxing, thus retaining an intact wellbore.
A successful side track
The second side track kicked off within
the existing 6½-in. open-hole section and
successfully reached total depth in the target
sand. MPD maintained the wellbore pressure
profle within the wellbore stability limit and
the sand fracture gradient of the depleted
sands. Static fuid density remained higher
than pore pressure during the operation. The
MPD control system also addressed the spe-
cifc drilling challenges of the well, including
hole instability.
Three times during drilling, the MPD con-
trol system increased equivalent mud weight
to remediate packoffs due to shale instability.
The system also was used to place and dis-
place heavy mud during tripping. Due to the
higher-than-expected wellbore stability gradi-
ent, a key objective of the MPD system was
to modify the bottomhole equivalent circulat-
ing density (BH ECD) as necessary during
drilling. The system maintained 12.8 ppg BH
ECD equivalent while drilling at the start of
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the well, and increased the equivalent mud
weight to 13.7 ppg at total depth.
MPD benefts
The MPD system enabled the operator to
successfully reach the target depth, while miti-
gating wellbore stability hazards and quickly
identifying small downhole losses and pack-
offs. Such losses and packoffs were mitigated
by increasing bottomhole pressure, eliminat-
ing the time needed to increase mud weight.
There was no serious infux, loss, or ballooning.
The system also manipulated bottomhole pres-
sure when zones with higher-than-expected
wellbore stability gradients were encountered.
Upon reaching total depth, a dynamic FIT was
performed to 14 ppg without any losses.
The system’s ability to control the annular
pressure profle of the well resulted in a safe
and effcient operation that enabled the opera-
tor to restart production in the mature, seem-
ingly depleted formation. Automatic kick and
loss detection helped control risks while drill-
ing through rapidly changing pressures.
The success can be quantifed by the months
of planning and preparation involved. Both the
operator and the drilling contractor underwent
extensive MPD training prior to project kickoff.
The rig team reviewed MPD procedures and
practiced MPD connections before drilling out
of the casing shoe. The learning curve for the
drill crew built quickly and, as their confdence
in MPD knowledge and process familiarity in-
creased, the time required to execute various
MPD tasks decreased on the second side track.
Moreover, the success of the operation has
created opportunities for application of the
MPD in similar mature or depleted wells. The
operator is currently using the MPD system
elsewhere in the GoM. •
To perform MPD, a rotating control device (RCD)
is required to close the loop. The rendering rep-
resents the MPD equipment used to success-
fully execute the GoM project.
1406off_51 51 6/3/14 2:16 PM
52 Of fshore June 2O14 ª www.offshore-mag.com

PRODUCTI ON OPERATI ONS
Abandoned but not forgotten:
managing wells near end of life
Best practice calls for monitoring to continue
M
any producing offshore oil and
gas felds include a mixture
of operating, suspended, and
abandoned wells. One continu-
ing challenge for the operators
is to distinguish between those wells that
have been suspended (i.e. for workovers) or
abandoned safely, and those that are not cor-
rectly treated.
Suspended wells can encounter a variety
of problems, and wells that have been per-
manently plugged and abandoned (P&A’d)
can start to leak. There are numerous possi-
ble causes. Over time thermal and pressure
cycling can generate micro annuli or cracks
in the cement seal or other formations above
the reservoir, while leak paths can develop
from the inside of the wellbore outwards,
or in the plugs themselves if they have not
been positioned or tested properly.
Nevertheless, provided there is some
structure left at the surface, there is scope
for monitoring the condition of an aban-
doned well – even if it means using a single
pressure gauge to ensure a reading of nil
above a plug or wellhead. Best practice is to
continue to monitor abandoned wells for a
number of years, using a well integrity man-
agement system.
Well integrity management systems com-
bine well operating and production data
within a framework for decision-making,
management processes and organizational
structure. They also enable operators to
maintain a full history of their wells. Analy-
sis of historical data not only provides criti-
cal intelligence for managing abandoned
wells safely, but helps operators get more
from their assets.
Levels of suspension
There are many reasons why a produc-
ing well might be shut-in. Often shut-ins are
necessary to perform routine maintenance
of surface facilities, equipment or pipelines,
rather than the well itself. The operator
might also be experiencing lower than ex-
pected rates of recovery.
Meanwhile, integrity issues can arise
from sources such as scaling, corrosion,
failed well barrier equipment, or sustained
annulus pressure. The latter is the number
one killer of wells and can lead to an exter-
nal leak or, at worst, a blowout. Even if no
leakage occurs, when pressure within the
well rises above its safe operating envelope,
the resultant failure of well barrier equip-
ment can be too risky or costly to repair and
therefore the well must be abandoned.
If a well is being shut-in to discontinue
fow for a short period, this is achieved by
simply closing the surface safety valve (typi-
cally, the upper master valve). If the well has
Dr. Liane Smith
Wood Group Intetech
Overview of well types and states for different reservoirs with integrity status color coded. (Image courtesy Wood Group Intetech)
Category of wells Total
Well number
# wells
outside limits PER_PZ8 PER_PZ9 PER_PZ13 PER_PZ10 PER_PZ7 PER_PZ5 PER_PZ6 PER_PZ1 PER_PZ11
Abandoned 7
Awaiting abandonment 0
Permanently abandoned 7 PER161 PER321 PER081,
PER086
PER001,
PER006
PER241
Unknown 0
Condensate producer 18
CRI 0
In operation 3 PER171 PER091,
PER096
In operation - and CRI 0
In operation - awaiting suspension 3 PER191 PER111,
PER116
In operation - needs workover/intervention 3 PER 181 PER101,
PER106
In operation - scheduled for workover/intervention 0
Pending flowline hook-up after workover 3 PER141,
PER146
PER221
Temporarily shut-in 3 PER201 PER121,
PER126
Workover/intervention in progress 3 PER211 PER131,
PER136
1406off_52 52 6/3/14 2:16 PM
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1406off_53 53 6/3/14 2:16 PM
54 Of fshore June 2O14 ª www.offshore-mag.com

PRODUCTI ON OPERATI ONS
to remain suspended for a long period of
time, a heavy liquid such as brine is pumped
in to prevent fuid fow. This can then be re-
moved later to re-start fow.
Should permanent abandonment be re-
quired, the well is plugged by setting me-
chanical or cement plugs in the wellbore at
specifc intervals to prevent fuid fow. The
P&A process normally requires a workover
rig and pumping of cement into the well to
restore the natural integrity of the formation
penetrated.
Properly plugged wells can save the op-
erator substantial sums through avoidance of
lost production. If a well is not properly aban-
doned, it may provide pathways for brines,
hydrocarbons, or other fuids to migrate to
surface, leading to the technically demanding
and costly task of re-entering the abandoned
well to plug a leak.
Operating guidelines
In regions such as the North Sea and
Asia/Pacifc, the growing number of aging
assets has meant operators must adopt more
robust approaches to managing well aban-
donment. Britain’s Department for Energy
and Climate Change (DECC) estimates that
as of 2012, there were 740 suspended wells
on the UK continental shelf with around
5,000 wells to be decommissioned.
Oil and Gas UK has guidelines to steer
operators on the considerations that need
to be taken when suspending operations in
a well for a limited time, re-entering a well
safely, and abandoning a well. The guide-
lines provide minimum criteria for ensur-
ing full and adequate isolation of formation
fuids both within the wellbore and from
surface or seabed. The Well Suspension and
Abandonment workgroup of the associa-
tion’s Well Life Cycle Practices Forum has
also produced guidelines on qualifcation of
materials for the suspension and abandon-
ment of wells.
In the US, regulatory standards require
specifc provisions for plugging and docu-
menting oil and natural gas wells before
they are abandoned. P&A regulations vary
to some degree among states, but all pre-
scribe the depth intervals that must be ce-
mented, as well as the materials allowable in
plugging practices.
Despite a consensus that the processes
and regulation relating to abandonment need
to be vastly improved, wells continue to be
plugged at the lowest possible cost and in
accordance with the minimum requirements
mandated by regulators. This is because
P&A work is capital-intensive and provides
no return on investment for operators.
In the US and Europe, the OSPAR Conven-
tion – the current legal instrument guiding
international cooperation on the protection of
the marine environment – mandates that an
abandoned well remains the responsibility of
the owner. According to a report issued last
year by the UK’s Royal Academy of Engineer-
ing on decommissioning in the North Sea,
should ownership of an asset be transferred
during the feld’s lifespan, liability transfers
to the new owner in most cases. However,
there are cases where it remains with the
seller. For example, should a new owner de-
fault, liability reverts to the original license
holder. As such, the report notes that there
is a generally accepted understanding within
the industry that, “if you put it there, you take
it away.” Operators must therefore take the
utmost care to protect the environment at all
stages of the P&A process to avoid potential
remediation or litigation costs should issues
with an abandoned well arise at a later date.
It is worth noting that recent high pro-
fle incidents in the Gulf of Mexico and the
North Sea occurred during operations relat-
ed to well abandonment. These events serve
to highlight the importance of adopting an
asset management strategy that ensures the
continuous integrity of wells from design
and construction, to operation, and fnally
abandonment.
Getting ahead of the curve
Scaling, corrosion, and failed well barrier
equipment are all common issues that call for
vigilance to minimize the risk of leakage. The
fact is that thermodynamics always catches
up with you: When there is a piece of unpro-
tected steel in the ground it will corrode. Any
new engineering system will have some fail-
ures due to human error or material defects.
There will also be a steady rate of failures that
can be corrected routinely by maintenance
and repair, before corrosion or fatigue dam-
age eventually sets in.
However, many oil and gas operators fnd
that the level of well “infant mortality” is
far too high – wells that come into service
and quickly develop various integrity is-
sues. Equipment leak testing and annulus
pressure monitoring also identify a high
frequency of failures with the associated
maintenance demands that this brings. As
a consequence, many wells are terminated
prematurely before the end of their cost-
effective life. Tools that allow well integrity
to be controlled at every step tackle all these
problems and result in wells achieving their
design objectives. An advanced well integ-
rity system enables operators to consolidate
all of their well data and manage the full life-
cycle of their wells.
Using web-based well integrity manage-
ment software with smart functionality
make it possible to acquire information from
multiple sources – including third-party da-
tabases and legacy systems – and to display
it in a single management dashboard. This
provides an instant view of current well in-
tegrity status as well as historical key per-
formance indicators (KPIs) at a well, feld,
or enterprise level.
Operators receive email warnings of wells
where conditions indicate that well barriers
are failing and there is a risk of a leak. The
software also performs added-value analysis
of the data collected to identify developing
problems. This allows operators to track
wells that are at risk of failing and to take
preventative action to keep them safely in
production. In addition, they can ensure a
safe and effective P&A or well suspension at
the frst attempt because the well condition
is known in detail.
If a well is suspended properly, and the op-
erator has a full history of the materials used,
equipment installed, and the damage the
well may have sustained over its life, it may
also be possible to recover or re-design the
well. Thanks to advances in drilling and well
design, temporarily abandoned wells could
prove to be extremely valuable assets. Cru-
cially, using historical well integrity data to
improve front-end processes and equipment
selected based on past performance and les-
sons learned can drive down operating costs,
optimize maintenance, reduce workovers,
and increase proftability of well operations in
the long term. •
Editor’s note: Intetech, which was recently acquired
by Wood Group, is now known as Wood Group In-
tetech, part of Wood Group Kenny.
Thanks to advances in drilling and well design,
temporarily abandoned wells could prove to be
extremely valuable assets moving forward.
1406off_54 54 6/3/14 2:16 PM
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1406off_55 55 6/3/14 2:16 PM
56 Of fshore June 2O14 ª www.offshore-mag.com

PRODUCTI ON OPERATI ONS
High-accuracy simulator trains
offshore oil platform operators
OTS replicates platform equipment and systems
L
UKOIL has deployed an offshore train-
ing simulator (OTS) at its corporate
training center near Astrakhan, Russia,
that enables its employees to become
familiar with exactly the same type of
equipment and systems they will use in the
feld.
The OTS features a modern control sys-
tem from Emerson Process Management and
modeling software from Kongsberg, and was
developed with the same Emerson developers
who confgured LUKOIL’s North Caspian Sea
platform in the Yuri Korchagin oil feld. The
following reviews the development of that
training center and explains how it operates.
Production facilities
In 1995, LUKOIL began to investigate a
previously unexplored area in the northern
Caspian Sea. Exploratory drilling began in
1999, and the frst production platform began
operating in April 2010, with fve more felds
to be developed by 2017. The company real-
ized the need for trained operators to work
safely and consistently, so they embarked
on a program to develop a center to provide
operators with the most up-to-date and com-
plete training possible.
The platform is located about 70 km (43.5
mi) offshore in the Yuri Korchagin oil feld,
and while the water is not very deep – 11
to 13 m (36 to 43 ft) – the operating condi-
tions can be severe, with low temperatures,
ice felds, and strong winds. The complex
consists of two platforms: the production
platform, LSP-1, and the habitation platform,
LSP-2, which accommodates up to 105 em-
ployees and is connected to the production
platform by an elevated walkway. There can
be as many as fve shifts on the platform at
one time.
Oil produced by the platform is transported
58 km (36 mi) to a foating storage unit via a 300-
mm (12-in.) subsea pipeline. The main produc-
tion facility is powered by extracted gas, backed
up by diesel motors when necessary.
The platform uses a modern distributed
control system (DCS) from Emerson Pro-
cess Management: a DeltaV distributed con-
trol system, DeltaV SIS (safety instrumented
system), AMS Suite plant asset management
software, and the controls for the platform’s
fre and gas systems. The total I/O comes to
about 14,000 points.
Need for training
Training is vital for proper and safe opera-
tion. At one time, LUKOIL conducted opera-
tions training onboard the platform, but it
quickly became apparent that this was not
a safety arrangement. The company started
planning an onshore training facility, and in
2011 opened a corporate training center in
the suburbs of the nearby city of Astrakhan.
Initially aimed at training in frefghting and
other emergency procedures, the center has
grown into a multi-purpose training facility
for safety training (fre and gas, sea rescue,
and frst aid training) as well as instrumen-
tation and offshore operations training, fo-
cusing on skills development for operations
and engineering staff. Operators are trained
in safe and effcient process operation; pro-
cess knowledge development; knowledge
of process control systems; and startup,
shutdown, and abnormal situation handling
skills. The center has a capacity of 2,500
trainees per year.
The safety training is realistic, and even
includes a mockup of a helicopter that can
be flled with people and then dropped into
a water tank so that trainees can learn to es-
cape a crash at sea. It also provides realistic
fre training, with instruction in the use of
fre extinguishers and the various fre-fght-
ing systems on the platform.
A similar level of realism is necessary for op-
erator and supervisor training to prevent pro-
cess upsets, lost production, spills (the entire
production operation operates under a strict
no-discharge rule), and danger to personnel.
This means that the simulated control system
on which the training is done must exactly du-
plicate the control system on the platform.
Ilya Vasilyevych Fotin
LUKOIL

Viacheslav Kulikov
Emerson Process Management
LUKOIL’s North Caspian Sea platform is located about 70 km (43 mi) offshore in the Yuri Korchagin
oil field. (Images courtesy Emerson Process Management)
1406off_56 56 6/3/14 2:16 PM
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PRODUCTI ON OPERATI ONS
OTS architecture
and functions
Key to achieving that realism is the op-
erator training simulator (OTS), which is
designed to replicate exactly the platform’s
equipment, and was developed with the
same Emerson developers who had devel-
oped the confguration for the production
platform. The idea was to train operators on
exactly the same equipment that they would
be using in the feld, and the OTS uses the
same hardware as the platform’s DCS and
SIS, and runs the same software. It is set up
to match the as-installed system, not a “func-
tional equivalent” built from preliminary
designs, and uses simulation software that
duplicates the confguration exactly as on
site: the DCS confguration is an exact copy
of the one on the platform, the SIS confgu-
ration and emergency shutdown algorithms
are exact copies, and the fre and gas alarm
confguration is an exact copy. The OTS al-
lows trainees to perform control, start-up,
and shutdown procedures for major plat-
form systems, and all scenarios and training
courses are customized and confgurable.
Hardware for the OTS includes fve PC
workstations that are connected to the con-
trol system emulator that executes the actual
control system’s DCS/SIS algorithms, using
simulated values as the inputs. The PCs can
be switched to operate as supervisor work-
stations, central control room (CCR) opera-
tor workstations, or feld operator worksta-
tions. They connect via a local area network
to the instructor workspace, which includes
three DeltaV application workstations, a K-
Spice model workstation and a DeltaV Pro-
fessionalPlus workstation. Operator screens
are exact copies of the operator screens on
Hardware for the OTS includes five PC workstations connected to the control system emulator,
three DeltaV application workstations, a K-Spice model workstation, and a DeltaV ProfessionalPlus
workstation.
1406off_57 57 6/3/14 2:16 PM
58 Of fshore June 2O14 ª www.offshore-mag.com

PRODUCTI ON OPERATI ONS
the platform, and all complexes and systems are available to the
central control room operators. Operator screen access level for
the technology, power and utility complexes is privilege dependent.
Field operator screens emulate the actions of feld operator such as
opening manual valves and feld equipment operation.
The OTS hardware and software are divided into three main
parts: control system emulation, a process model and simulator, and
facilities for the organization of training, evaluation, and courseware.
Control system model
The control system emulation, as mentioned, is an exact copy of the
control system confguration for the platform’s DCS, the emergen-
cy shutdown system and the fre and gas detection systems. It also
provides emulations for local control systems, including compressor
startup and anti-surge controls, power generation, and glycol block.
Process model and simulator
The process model, which runs on its own server, calculates pro-
cess parameters with high accuracy, taking DCS/SIS outputs from
the control system emulator as inputs. It has two parts: A high-f-
delity technology complex model handles oil and gas production,
separation and transport, while a medium-fdelity power and utility
complex model handles power generation and distribution, auxil-
iary systems and life support, where high accuracy is not required.
Technology complex model
The high-fdelity technology complex process model uses K-Spice,
from Kongsberg Oil and Gas Technologies. The K-Spice model for
the technology complex includes models for 26 production wells plus
gas lift, three gas injection wells, and three water injection wells. It
also models oil separation, preparation and transport system, the gas
compression and injection, fuel gas system, the water treatment sys-
tem, the TEG (triethylene glycol) system, as well as auxiliaries: chem-
ical injection, fares, drainage, etc. It can be modifed and expanded as
necessary. Integration with the DCS and SIS system is via a standard
OPC server and a custom K-Spice/DeltaV interface. More than 6,000
parameters are interfaced between K-Spice and DeltaV.
Power and utility model
The medium-fdelity power and utility process model uses the
SEEDS (Standard Entities for the Engineering of Dynamic Simula-
tors) platform, a medium-fdelity native dynamic simulation that pro-
vides a realistic and effective simulation environment within a single
integrated database. It includes the models for the power generation
system (gas turbine generator and emergency generator); the power
distribution system; the diesel fuel and oil system for power objects;
the waste heat recovery systems; the life support systems within the
production platform; the fre extinguishing systems; and the auxil-
iary process systems, including water supply, cooling/heating agent,
drainage, etc. The SEEDS model also interfaces to the K-Spice model.
Instructor station
The instructor workstation provides an HMI for the instructor
and handles instructor functions and operator evaluation. It runs
Neptune Instructor, a monitoring and assessment system from
Kongsberg Maritime, which is used to set up scenarios and evaluate
the actions from the operators and their responses to the circum-
stances and scenarios given by the instructors.
Project execution and schedule
The project was implemented in three stages. Stage 1, which ran
from November through December 2011, was devoted to input data
collection and project design. Project data was collected and ana-
lyzed in detail, and missing data identifed. The initial design was
then developed and sent for approval.
Stage 2, which covered the technology and power complex, ran
from January to September 2012. It included the development of
the Technology Complex model in K-Spice, the development of the
Power Complex model in SEEDS, the transfer of copies of the DCS/
SIS confguration and operator screens to OTS and feld operator
screens, system integration, and the model acceptance test.
Stage 3, which ran from October to December 2012, covered the
utility complex and training organization. It included development of
the utility complex model in SEEDS, development of scenarios and
training courseware and trial operation and site acceptance.
Organization of training
A typical training class consists of an instructor at the instructor
workstation to load training scenarios and conduct the session, while
at the fve operator workstations might be a shift lead, a senior opera-
tor, a production operator, a power operator and a feld operator. The
training instructor can choose among 29 customized shift training
Integration of the complex process model into the LUKOIL facilities.
The high-fidelity technology complex process model uses K-Spice, from
Kongsberg Oil and Gas Technologies. The K-Spice model for the technology
complex includes models for 26 production wells plus gas lift, three gas
injection wells and three water injection wells, and other platform systems.
1406off_58 58 6/3/14 2:16 PM
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PRODUCTI ON OPERATI ONS
scenarios ranging from alarm reaction training to full-scale platform
startup, and can confgure and modify scenarios and introduce events
and malfunctions as needed. Trainees are provided with scenario-
based courseware to study, and their performance is automatically
evaluated in the Neptune Instructor system.
Key success factors
A number of factors contributed to the success of the project. All
needed input data was available from both LUKOIL and Emerson,
and starting to collect that data early in the project allowed time
for data analysis and mining. Similarly, starting early on the task
of integration tests resulted in seamless integration. The engineers
involved were well experienced; both the project manager and the
DCS/SIS engineer participated in the Korchagin DCS project and
know the system well. The Emerson and Kongsberg offces collabo-
rated extensively. And the LUKOIL instructor and chief engineers
provided their full support and expertise.
Results and future plans
The training system was successfully delivered to the LUKOIL
Corporate Training Center on time, on budget, and in full scope.
LUKOIL operating and engineering staff are now trained in a real-
istic environment onshore before going offshore. The system has
proven to be a high-fdelity solution for both staff training and engi-
neering studies, with scenario-based courseware and evaluation for
various training levels – from beginners to experienced operators.
Operators and engineers gain increased knowledge, and on-site op-
erational safety is improved.
The OTS has made possible an expansion of LUKOIL Corporate
Training Center offerings with offshore oil production training. The
system will support the company’s operations at the Yuri Korchagin
feld throughout the platform lifecycle, and the training facility will
support operations at new oil felds as they are developed in 2015
through 2017. •
The authors
Ilya Fotin is the Chief Metrologist, Chief of Automation and Metrology department
of LUKOIL-Nizhnevolzhskneft, LUKOIL Oil Co., Russia, with 25 years of experience
in the oil and gas industry. He began his career as a control instrumentation techni-
cian at oil production facilities in Perm region. His further career included the posi-
tions of chief technician, the head of laboratory and the head of automation, IT and
communications department in LUKOIL-Perm branch of LUKOIL Oil Co. In 2004
he moved to LUKOIL-Nizhnevolzhskneft (North Caspian Region) where LUKOIL
began development of its of fshore oil production facilities. He participated in devel-
opment of the Yuri Korchagin oil feld and was responsible for the development, com-
missioning, and operation of the instrumentation, automation, control, and safety
systems at the of fshore oil production platform and FSO. His current responsibilities
include supervision of the operation of instrumentation and automation as well as
participation in the development of further of fshore facilities at the oil felds in the
North Caspian Region. He can be reached at [email protected].
Viacheslav Kulikov is senior consultant and group leader of Strategic Services CIS,
Emerson Process Management with six years of experience in industry and fve years
in academia. He has a Ph.D. from RWTH Aachen University, Germany. Following
the graduation he started his career at Emerson Process Management as advanced
process control engineer. Starting from 2011 he became a lead engineer for
advanced process control and operator training simulator projects. In 2013, he was
promoted to senior consultant position and became responsible for development of
Strategic Services CIS group of experts in advanced solutions in process automation.
He can be reached at [email protected].
1406off_59 59 6/3/14 2:16 PM
60 Of fshore June 2O14 ª www.offshore-mag.com

PI PELI NES & FLOWLI NES
Study examines causes
of slugging in subsea flowline
O
ne Shell subsea tieback in the deep-
water GoM has experienced nu-
merous production issues such as
wax, asphaltenes, scale, emulsions,
and sand production. In addition to
various fow assurance issues related to the
produced fuids, unexpected unstable oscil-
lating fow has also been observed after well
stimulation jobs, which nevertheless boost-
ed the wells production signifcantly.
The observed unstable fow (slugging)
was characterized by high pressure fuctua-
tions and signifcant water cut variations at
topsides, which leads to platform trips and
occasional shutdowns.
In turn, the gas surge due to slugging is
problematic to production because it can lead
to topsides trips and production constraints
due to limited gas compression capability of
the platform. It was noted that a signifcant
increase in liquid production rate did not
reduce the slugging tendency. Filter sample
analysis from the topsides free water knock-
out identifed a highly viscous emulsion/
sludge coming from the subsea system. The
emulsion/sludge may be generated by sub-
sea choking or well fuid incompatibility. The
combination with other fow assurance issues
experienced during production has made the
slugging behavior diffcult to distinguish and
to suggest mitigation options.
To better understand this phenomenon and
optimize the production, it is critical to under-
stand the slugging patterns and to identify
the root cause of the unstable fow. The com-
mercial transient multiphase fow simulation
tool OLGA was used to predict the slugging
tendency. Several mechanisms that could pro-
vide reasonable explanation for the observed
unstable fow were proposed and investigated.
In particular, the mechanisms of riser-induced
severe slugging, terrain-induced slugging,
and growing slugs were studied. Other pos-
sible explanations of the slugging related to
fowline topography, organic solid deposition
and emulsion/sludge were also investigated.
Comparisons between the simulation results
and the available feld data allowed for valida-
tion of various slugging mechanisms, iden-
tifying the most probable root cause of the
observed slugging, and recommending miti-
gation strategies.
Field description
The subsea tieback consists of four subsea
wells: namely A1, A2, A3, and A4 at a water
depth around 4,000 ft. The subsea feld is tied
back to the host platform through an 8 x 12-
in. pipe-in-pipe fowline. The fowline is about
18 miles long, with mostly uphill topography
from the subsea manifold up to the riser base.
The produced oil API gravity is 27-28°. The
produced fuid GOR (gas-to-oil ratio) is 800-
900 scf/stb (standard cubic feet per stock
tank barrel) and the associated water cut
varies from 0% to 70% for each well. Note that
A1, A2, and A3 wells produced a signifcant
amount of water.
Flow assurance issues
As noted, the feld has experienced nu-
merous fow assurance issues such as wax
deposition in the riser at low fow rates, as-
phaltene solids collected during well inter-
L. Wang
L. A. Dykhno
G. J. Zabaras
Z. Huo
Shell Global Solutions (US) Inc.
C. R. Holloway
N. B. Dee
W. Nisbet Jr.
Shell Exploration & Production Co.
Filter samples analysis: (left) filter samples taken during restart; (right) emulsions sample.
Field production history and fow conditions at the riser outlet in chronological order.
Case Liquid rate Water cut
Manifold
pressure
Manifold
temperature
Wells in
production Flow condition Slug size Slug frequency
bbl/day % psig F – – bbl hr-1
1 11,000 36 2,530 127 A1, A2, A3 Hydrodynamic slugging 2-3 15-20
2 12,500 25 2,520 125 A1, A2, A3, A4 Unstable flow 10-15 3-4
3 18,000 31 2,700 130 A1, A2, A3, A4 Unstable flow 10-15 1-2
4 16,000 34 1,600 135 A1, A2, A3 Unstable flow 10-15 3-4
5 12,000 30 1,870 128 A1, A2 Hydrodynamic slugging 2-3 15-20
6 10,000 60-70 2,630 130 A2, A3 Hydrodynamic slugging with
topsides choking
2-3* 15-20*
* The slug size and slugging frequency were estimated after the topsides choking was applied.
1406off_60 60 6/3/14 2:17 PM
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62 Of fshore June 2O14 ª www.offshore-mag.com

PI PELI NES & FLOWLI NES
ventions, and scale appearance once the scale inhibition was turned
off. Some other feld observations include the inability to reach the
target blowdown pressure and solids production during restart indi-
cate that solid deposition or even plug may exist near the riser base.
The plug was speculated to be either wax or asphaltenes. Finally yet
importantly, simulation with clean pipes shows about 30% less pres-
sure drop compared against the feld data.
After a planned shutdown, operations discovered that the pres-
sure communication between the manifold and topsides was limited
in the fowline. A large number of liquid and flter samples were tak-
en at different times during system restart. The liquid samples were
later found to be emulsions with different water cuts. Such emul-
sions have the viscosity up to 1000 cP at low shear conditions (i.e.
shear rate about 1 sec
-1
). The flter samples were initially thought
to be asphaltenes deposits. However, asphaltenes analysis (IP 143)
showed that the “solid” only had ~9% asphaltenes content, compa-
rable to the oil samples. Further study by microscope showed that
those “solids” are also emulsions with signifcantly higher viscosity
– as high as 1.5x10
6
cP at low shear rates.
Field observation
In addition to aforementioned fow assurance issues, unexpected
unstable fow was observed after well stimulation jobs. The observed
unstable fow (slugging) was characterized by very high pressure
fuctuations and signifcant water cut variations at topsides, which
leads to platform trips and occasional shutdowns. The feld produc-
tion history and fow conditions at the riser outlet are summarized
in chronological order in the table. The A1 well stimulation job was
performed between Case 1 and Case 2. The A2 well stimulation job
was performed between Case 2 and Case 3. The unstable fow was
observed right after the well stimulation jobs. The slugging frequency
and slug sizes were estimated based on the feld data.
Hydrodynamic slug fow was observed for cases 1, 5, and 6, where
the pressure, temperature, liquid rate, and water cut fuctuations are
very small (less than 5% from the average). The slugging frequency
for hydrodynamic slugs is about one slug per 3-5 minutes and the slug
size is about 2-3 bbls per slug. On the other hand, unstable fow (ob-
served for cases 2, 3, and 4) was characterized by high pressure fuc-
tuation at upstream of the boarding choke, signifcant temperature
drop due to gas expansion in the riser and large fuctuations in liquid
rate and water cut. The observed slugging frequency is about one
slug per 15-20 minutes and the slug size is about 10-15 bbls per slug.
Analysis approach
OLGA (version 5.3.2.2) was used to investigate the slugging ten-
dency and validate possible slugging mechanisms of the system.
The slug-tracking option was activated with the default delay con-
stant of 150. The intent of using OLGA transient simulations was to
capture the slugging tendency for each mechanism proposed. The
explanations for the observations are mainly based on simulations
and comparisons against the feld data. Past experience indicates
that slugging predictions made through the use of a multi-phase fow
1406off_62 62 6/3/14 2:17 PM
1406off_63 63 6/3/14 2:17 PM
64 Of fshore June 2O14 ª www.offshore-mag.com

PI PELI NES & FLOWLI NES
simulator (such as OLGA) are at the limit of
the current understanding and modeling ca-
pability. However, this validated multi-phase
fow tool can properly capture the slugging
tendency and the sensitivities to various op-
erating conditions.
A fow regime map was frst developed us-
ing OLGA to identify the slugging boundaries
of the system at the riser outlet. The fow map
is presented as a function of total liquid rate and
water cut (assuming a constant GOR of 900 scf/
stb) for easier comparisons against the feld
data. Then the developed fow map was used
to validate various mechanisms proposed to
explain the slugging patterns observed in this
feld. Other possible mechanisms were also
validated through OLGA transient simulations,
such as severe slugging due to downward sec-
tion upstream of the riser base, possible slug-
ging due to choking effect by organic solid
deposition, and emulsion/sludge-induced slug-
ging by highly viscous emulsion/sludge in the
subsea system.
Flow regime map
Three distinctive fow regimes were iden-
tifed in the fow regime map developed
through OLGA: the unstable oscillating fow,
hydrodynamic slug fow, and stable fow. The
unstable oscillating fow is observed at low
liquid rates and high water cuts. At low fow
rates, the liquid falls back in the riser and the
pressure drop of the system is dominated by
the hydrostatic pressure loss. Signifcant pres-
sure fuctuations are observed but the oscilla-
tion frequency is much lower than hydrody-
namic slugging. The hydrodynamic slugging
fow regime is encountered at moderate fow
rates and at all water cuts. The stable fow re-
gime is encountered at high fow rates.
The six production cases retrieved from
the feld data were superimposed on the fow
regime map. The operating conditions for all
of the cases except case 6 fall into hydrody-
namic slug fow regime. However, only cases
1 and 5 agree well with the feld observa-
tion. Cases 2, 3, and 4, exhibit much worse
slugging behaviors that cannot be explained
with the fow map. Therefore, a few possible
mechanisms /hypothesis for the slugging oc-
currence observed in cases 2, 3, and 4 were
proposed.
Severe slugging. The necessary conditions for
the severe slugging to occur include 1. A down-
ward fowline section at riser base with stratifed
or annular fow; 2. Unstable fow in the riser, and
3. Liquid blockage at the riser base. For cases 2-4,
those conditions are not fully satisfed and the ob-
served unstable fow does not fall into one of the
severe slugging types. For example, the fowline
topography does not have downward section
at the riser base and hydrodynamic slug fow is
predicted. In addition, unstable fow is unlikely to
exist in the riser due to moderate fow rates (even
up to 18,000 b/d). Field data also show that there
was no production starvation as seen for most
severe slugging cases. Also, slug sizes are about
10-15 bbls/slug (less than 10% of the total riser vol-
ume), which are much smaller compared to the
slug sizes during severe slugging.
Terrain-induced slugging. This is similar to the
severe slugging in that liquid accumulates at low
dips in the fowline instead of the riser base, as
seen in the severe slugging. The liquid builds
up at the low spots in the fowline and eventually
gets swept out as slugs. The terrain slugs tend to
occur at relatively low fow rates. The terrain-in-
duced slugging is unlikely because the fowline
shows no signifcant low spots and the fow rates
are moderate.
Growing slugs. These can occur when the
liquid/gas interface for stratifed fow is still
stable with respect to small disturbances. The
initiated slugs will be stable if the liquid holdup
for the stratifed fow regime is larger than the
liquid holdup for the hydrodynamic slug fow
regime. The growing slugs occur in the transi-
tion zone of stratifed fow and hydrodynamic
slug fow. Cases 2-4 have moderate fow rates
and hydrodynamic slugging is predicted in the
fowline at the riser base. Therefore, the slug-
ging pattern observed in the feld is unlikely
due to the mechanism of the growing slugs.
Low dip at the riser base. Low dips may be
generated along the fowline due to unequal
settling in the mud more than 10 after the fow-
line was installed. In this case, a low spot just
upstream of the riser base was assumed, which
may lead to terrain/severe type of slugging
as observed in the feld. However, the OLGA
simulation results did suggest that the low dip
could introduce the terrain/severe slugging
at topsides, mainly due to the high production
rate of over 16,000 b/d. The predicted pressure,
temperature, and water cut variations do not
agree with the feld observation either. In addi-
tion, the predicted manifold pressure is about
20% lower than the feld data. With all the dis-
agreements presented above, the hypothesis of
low dip induced slugging is not valid to explain
the slugging behavior observed in the feld.
Choking effect. The feld has experienced
various solid depositions, including but not
limited to wax and asphaltenes. Other feld
observations such as the inability to reach the
target blowdown pressure, solid production
during restart, and limited pressure communi-
cation between the manifold and topsides also
support the hypothesis that solid deposition
or even plug may exist in the fowline/riser
system. The deposition/plug restricts the fow
like a choke. Choked fow (slugging) could be
developed due to this choking effect. The solid
deposition was modeled in OLGA as a choke
with a 1-in. opening. The size of the restriction
was determined in order to match the ampli-
tude of the boarding pressure fuctuations
observed. The choking effect was also inves-
tigated with sensitivity to the plug locations.
An OLGA simulation showed signifcantly
smaller water cut and liquid rate fuctuations.
The predicted manifold pressure is about 20%
higher than the feld observation. Therefore,
it is unlikely that the hypothesis of obstruction
in the riser or in the fowline leads to the slug-
ging patterns observed.
Emulsion/sludge-induced slugging. The fac-
tors that supported the existence of the heavy
emulsion/sludge in the system include:
t i4PMJEw TBNQMFT DPMMFDUFE GSPN UIF GSFF
water knockout during system restart
showed high viscosity emulsions as per
fler sample analysis
t 3FDFOU XFMM TUJNVMBUJPO KPCT NBZ IBWF
introduced emulsifed agents
t 3FEVDJOH UIF UPUBM SBUF CZ TIVUUJOH JO "
well helped reduce/eliminate slugging
t 5IFSF JT B LOPXO TBOE JTTVF GSPN "
prior to A1 failure, which could inten-
sify the emulsion in the system
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PI PELI NES & FLOWLI NES
* Simulation with clean pipe predicted a
8Oº less pressure compared against the
ñeld data
* A blowdown exercise indicated that pack-
ing more gas prior to blowdown makes
blowdown more ellective.
The emulsion/sludge may be generated
by subsea choking or incompatibility ol the
üuids lrom dillerent wells. The hypothesis
ol emulsion/sludgeinduced slugging is that
the subsea system generated emulsion/
sludge exists as the lourth phase in addition
to the oil/water/gas threephase mixture.
The residence time is too short lor the vis-
cous emulsion/sludge to dissipate in the
üowline and riser. The emulsion or sludge
was periodically generated in the subsea
system and the ¨immiscible" emulsion/
sludge üowed with the oil/water/gas mix-
ture, creating slugs similar to the slugging
patterns caused by the pigging operations.
To validate the hypothesis through tran-
sient simulations, the emulsion/sludge was
modeled as a series ol pigs with smaller
diameter than the pipe !D. The pigs were
launched lrom the manilold with a lrequency
ol one pig per hour to match the slugging
lrequency observed in the ñeld. The energy
calculation was turned oll to stabilize the
OLCA simulations (therelore no temperature
comparison). The simulation predictions lor
liquid rate, water cut, and pressure üuctua-
tions at the riser outlet show good qualitative
agreement with the ñeld data. The predicted
manilold pressure and slug size (152O bar-
rels per slug) also showed good agreement
with ñeld data. The mechanism ol emulsion/
sludgeinduced slugging seemed to reason-
ably explain the slugging behavior.
The origin ol the emulsion/sludge may
be due to subsea choking and/or incompat-
ibility ol the produced üuids lrom dillerent
wells. !n addition, the recent well stimulation
|obs may have introduced emulsiñed agents.
Other solids, such as wax, sand, scale and
asphaltenes that have been experienced in
the subsea system also tend to intensily and
complicate the emulsion/sludge issue.
Findings
Comparisons between the simulation re-
sults and the ñeld data show that the proposed
emulsion/sludgeinduced slugging mecha-
nism can reasonably explain the observed
slugging behavior. The emulsion/sludge may
be generated periodically in the system, which
can develop the observed slugging patterns.
The ¨immiscible" emulsion/sludge üows with
the oil/water/gas mixture and creates slugs
similar to some pigging devices.
Mitigation strategy
The lollowing slugging prevention and miti-
gation strategies were proposed with an em-
phasis on reducing the amount ol emulsion/
sludge in the system.
With regard to emulsion/sludge preven-
tion and mitigation:
* Actively monitor the wells` production.
!roduce the wells with less emulsions
ñrst and gradually produce the wells
that may have emulsion issues.
* !n|ect demulsiñer chemical upstream ol
the separator to improve separation.
Topsides choking should be used with care
because it will only be ellective when üow in-
stability is lowüow driven ÷ lor example, when
üow rates are lower than 1O,OOO b/d with high
water cuts ol GO7Oº. !l slugging was observed
at high üow rates where hydrodynamic slug-
ging is expected, topsides choking may not be
ellective and it may even worsen the slugging
issue due to signiñcant pressure buildup be-
hind the liquid slugs. •
Acknowledgment
Based on a paper presented at the Deep Of fshore Tech-
nology International Conference & Exhibition, held at
the Woodlands Waterway Marriot Hotel & Convention
Center, Oct. 22-24, 2013.
1406off_65 65 6/3/14 2:17 PM
66 Of fshore June 2O14 ª www.offshore-mag.com

STI MULATI ON VESSELS
Stim vessel fleet features
latest technologies
Advances provide more ef fciency, production
A
s Offshore magazine’s World Survey of Stimulation Vessels
made clear, the global feet of vessels available to the indus-
try for this critical process is the largest in its history. And,
the technologies onboard are certainly the most advanced to
date. Deepwater stimulation vessels may be the technology
superstars, but offshore intervention, while perhaps not as glamor-
ous as big-league pressure pumping operations, also has an essen-
tial role to play and a similar set of diffcult challenges.
Modular stimulation packages
Augmenting the feet of today’s highly capable, conventional stimula-
tion vessels are supply boats that serve “ad hoc” as stimulation vessels
when the situation demands it. This is made possible by the introduc-
tion of modularity, which gives new capability to the existing conven-
tional supply vessel feet. This approach has proven effective in help-
ing operators meet technical, logistical, and operational challenges in
remote offshore locations. These modular designs are said to offer the
same level of operational quality as a dedicated stimulation vessel.
Schlumberger says its FlexSTIM Pronto system can be rigged
up or rigged down in just seven days, while reducing health, safety,
and environmental exposure. The design offers process control of
all equipment by remote control systems from the control cabin, and
the stimulation package can be placed on an offshore supply vessel.
The lightweight equipment package was designed for offshore use
and installation on the back deck of a conventional supply vessel or
a platform supply vessel.
The Baker Hughes StimFORCE modular stimulation system is
an operationally fexible pumping package composed of skid-based
pumping equipment, which can be shipped to a location and reas-
sembled on a platform supply vessel, barge, or offshore rig. A grid
framework secures the pumping equipment to the vessel or barge,
to ensure safety. The system is DNV 2.7-1 certifed and CE marked.
The equipment, which meets ISO dimensional standards, is secured
using twist-lock connections.
An operator working offshore West Africa had a delay that forced
the cancellation of a reserved stimulation vessel, which moved on
to another project. The system was deployed to the well site instead
and enabled the pumping of 38 well treatments on 27 wells, saving
the operator $9 million in idle rig time.
Modularity versus specialization
While modularity has its advantages, the highest level of offshore
stimulation capability is gained from vessels designed for the re-
quirements of a specifc operating area.
Engineered for North Sea conditions, Baker Hughes recently
launched the Blue Orca stimulation vessel. It houses fve pump
units, each capable of delivering 2,750 hydraulic hp. The two fuid-
end sizes can be reconfgured for fexibility. The vessel can carry
2.5 million lbm (1,134 metric tons) of sand or equivalent proppant,
which allows multiple fracturing treatments without returning to
port to resupply.
New systems permit blending of high-quality fracturing fuids and
eliminate the need for oil-based slurried polymer concentrates. A
three-mode acid-blending system enables mixing a range of organic
or inorganic acid systems. Eight lined tanks hold a total of 180,000
gal of organic and inorganic acids and solvents.
Built for dedicated use by Saudi Aramco, Halliburton’s newest
stimulation vessel, the Stim Star Arabian Gulf, is designed to meet
the stimulation requirements of Arabian Gulf wells. It is working for
the Manifa feld stimulation campaign.
Don Francis
Special Correspondent
(Above) The FlexSTIM Pronto modular design allows equipment instal-
lation in seven days on a standard Bourbon GPA 670 vessel. (Image
courtesy Schlumberger) (Below) The Blue Orca is engineered for North
Sea conditions and can perform a series of well stimulations and sand
control operations without the need to return to port and resupply. (Photo
courtesy Baker Hughes)
1406off_66 66 6/3/14 2:17 PM
1406off_67 67 6/3/14 2:17 PM
68 Of fshore June 2O14 ª www.offshore-mag.com

STI MULATI ON VESSELS
The vessel meets or exceeds SOLAS, IMO, IEC, and MARPOL
regulations. Although developed primarily for acidizing treatments
on both producing and injection wells in the Manifa feld, the vessel
can handle all phases of production stimulation, including fractur-
ing, sand control, and conformance solutions for the Middle East
offshore market.
The Stim Star Arabian Gulf is 234 ft (71.32 m) long, 56 ft (17.07 m)
wide, and 18 ft (5.49 m) deep. It can provide up to 14,000 hydraulic
hp for stimulation treatments. The vessel has acid-on-the-fy (AOF)
capability and the ability to reconfgure using the company’s vessel
modular solution system. The AOF system provides real-time con-
trol of the acid blend.
DP intervention
Intervention, stimulation’s close relative in the family of tools
for increasing (or restoring) production, has also seen new devel-
opments to address the unique problems of offshore intervention
operations.
Halliburton has performed a coiled tubing (CT) and catenary
workover operation in the South China Sea from a dynamically posi-
tioned (DP) vessel. This is believed to be a frst in the region.
In rough seas, regular work vessels have to separate from plat-
forms, halting operations to pick up anchors to avoid dragging into
undersea pipelines. During the monsoon season, workover opera-
tions virtually cease, compromising production. In quickly chang-
ing conditions, anchored vessels may not have the time needed to
disconnect and pull up anchors.
Halliburton partnered with the owner of a DP vessel in Brunei
to outft it with coiled tubing and catenary equipment. The vessel
remains in position when seas are high. There is also no need to
transfer the CT reel, power pack, and control console to the plat-
form, saving rig-up and rig-down time.
The use of the DP vessel enables Halliburton to quickly disconnect
from the platform in the event of approaching weather. Because the
CT reel was on the DP vessel and catenary disconnects were used,
crews can quickly separate from the platform.
Riserless well intervention
FMC Technologies’s riserless light well intervention (RLWI) sys-
tem is intended for all types of wireline jobs using braided wire or
slick line. It enables operations of tool strings with variable length
and requires no circulation of well fuids to the intervention vessel.
The system can operate on all subsea tree confgurations for
production and injection wells. It has provisions for well kill and is
designed to be as effcient as rig-based operations. It is currently
available in 7
1
⁄16-in., 10,000 psi confguration and includes upper and
lower lubricator packages, together with a well control package and
adapters to suit most subsea tree types.
A proprietary lubricator system is used to insert downhole tool
packages into the wellbore under full pressure, without taking hy-
drocarbons back to the vessel or to the environment. The technol-
ogy enables integrated operations and increases safety by reducing
personnel exposure.
Light well intervention vessels
Statoil uses light well intervention (LWI) vessels to increase re-
covery from subsea felds, and says these vessels reduce costs.
The company operates approximately 500 subsea wells on the
Norwegian continental shelf (NCS), where the liquid recovery fac-
tor of subsea felds is lower than for fxed installations. Maintenance
of damaged wells and reopening of shut-in wells are important to
increase the production rate and recoverable volumes.
According to Statoil, to maintain current production levels on the
NCS toward 2020, it is vital to secure an effcient rig feet adapted
to the assignments. Sustainable cost competitiveness, drilling eff-
ciency, and suffcient rig capacity are key factors. The company says
that compared to conventional drilling units, LWI vessels reduce the
cost of well interventions by approximately 60%. Reduced well inter-
vention costs also help increase the number of interventions.
The company has carried out riserless light well intervention
operations since 2000. These vessels are faster to redeploy than a
moored semisubmersible. Statoil has three LWI vessels from Island
Offshore in operations on the NCS. From 2015, two vessels from
Island Offshore will be on contract for the company.
The light well intervention vessels are connected to a well with
the aid of a subsea lubricator lowered to the seabed. They can per-
form logging and workovers, but they do not drill. During light well
intervention services, downhole equipment is remotely operated via
wireline from the surface and—unlike rigs—without a riser.
The “category A” units are designed for mid-water operations
(70-450 m or 230-1,476 ft water depth), and can operate year-round
across the entire NCS. The units are designed based on the compa-
ny’s functional specifcation and include the vessel, subsea wireline
stack system, wireline, and ROVs.
The category A design for light well interventions offers advantages,
the company says. It is cost-effective, uses dedicated equipment and
The Stim Star Arabian Gulf has acid-on-the-fly capability and can be
reconfigured using the company’s vessel modular solution system. (Photo
courtesy Halliburton)
The riserless light well intervention system can perform operations on
all subsea tree configurations for production and injection wells. (Photo
courtesy FMC Technologies)
1406off_68 68 6/3/14 2:17 PM
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1406off_69 69 6/3/14 2:17 PM
70 Of fshore June 2O14 ª www.offshore-mag.com

STI MULATI ON VESSELS
The light well intervention vessel Island
Wellserver has been working full-time since
2009 for Statoil. (Photo courtesy Island
Offshore)
tools, and provides permanent access to
work and maintenance areas. There is
no anchor handling, and a single service
contractor is responsible for the com-
plete operation.
The units are designed for effcient
and safe handling of equipment. Skid-
ding systems enable safe material han-
dling of equipment and modules in rough weather conditions.
Under category A contracts, each contractor is responsible for
wireline services and ROV services as an integrated part of the
category A service. Statoil will award the contract on behalf of the
participating licenses. The Island Frontier and Island Wellserver con-
tracts are for fve years, with two two-year options. The licenses
participating in the cooperation are: Åsgard, Norne, Gullfaks, Os-
eberg, Heidrun, Snøhvit, Tyrihans, Tordis/Vigdis, Snorre, Statf-
jord, and Sleipner.
Chemicals
Deepwater vessels are the most visible part of stimulation opera-
tions, but other, behind-the-scene components such as chemicals
and proppants are also essential to success.
Problems such as inorganic and organic deposition, corrosion,
and reservoir souring can occur after stimulation. During a well’s
stimulation phase, the Baker Hughes StimPlus fow assurance ser-
vice pumps slow-release, solid fow-assurance chemicals into the
reservoir as part of fracture, gravel pack, or other stimulation treat-
ments, to protect against production fow problems. For deepwater
and ultra-deepwater wells, a solid substrate ensures reliable applica-
tion in high-pressure environments.
The service includes a variety of feld-proven, chemically com-
patible additives to protect against bacteria-induced corrosion and
reservoir souring. They are also intended to ensure constant pro-
duction fow and prevent deposition in the formation and wellbore
after the treatment.
For deepwater wells, the company’s high-strength scale inhibitor
particles can serve as a conventional, medium-strength proppant
while providing long-term inhibition. These particles can be used in
closure pressures greater than 8,000 psi.
Enzyme technology
Based on bioengineering, a novel technology from EOR Solu-
tions uses an enzyme with the property to attach to hydrocarbons
and subsequently release them as droplets, which can then be re-
covered. This mechanism causes the removal of plugs made from
deposits of heavy hydrocarbons near the wellbore, leading to in-
creased fuid fow.
In water-wetted systems, the enzyme changes the surface to be-
come enzyme-water wetted. The enzyme also reduces the surface
tension between oil and the aqueous phase. These effects cause the
release of oil trapped in pores.
The ultimate use of the technology is in fooding systems where
the whole reservoir is fooded with a diluted enzyme solution. This
causes a reduction in residual oil saturation following actual en-
hanced oil recovery.
The enzyme is said to be nontoxic, nonpathogenic, and biodegrad-
able. It is resistant to temperatures and chemicals typically present in
reservoirs.
Because the well stimulation process using the enzyme technol-
ogy is simple—it requires only a setup
of mixing tanks and pressure pumps—
it is applicable to both onshore and
offshore wells. The enzyme does not
interact with water salinity, and dilu-
tion with seawater and preparation for
offshore well stimulation can be done
on the rig or platform.
The enzyme technology is mostly
used for permanent changes to forma-
tion wetting conditions near the well-
bore. Accordingly, wells that have been
in operation for a long time or have con-
ditions in the formation or oil properties that are causing deposition
of asphaltenes, resins, or other heavy hydrocarbons near the wellbore
are good candidates for stimulation by this technology. The use of the
enzyme technology to release these deposits and create an enzyme-
water permanent surface of the rock near the wellbore increases in-
fow of fuids to the well and increases oil production.
The releasing mechanism is done in a catalytic manner; the en-
zyme does not react with or form stable compounds with hydrocar-
bons. The properties of the enzyme and components in the enzyme
treatment solution changes oil-wetted solid surfaces to enzyme-wa-
ter wetted.
Enzymes are organic catalysts and the enzymatic function of the
product is because the enzymes seek and release the oil but are not
consumed in the releasing mechanism.
The enzyme is specifc to hydrocarbons, but not specifc to the
molecular size of the hydrocarbon. After the release of hydrocar-
bons, the enzyme remains in the water phase in the reservoir and is
available to release oil from new oil-wetted surfaces.
Because the enzymes do not interact with acids, they can be used
in combination with, for example, acid treatment of carbonate-based
rocks, giving synergetic effects of enhancing fow conditions and
releasing oil from the rock surfaces.
The enzyme fuid has not shown to interact with other oilfeld
chemicals such as scale inhibitors and biocides, so it can be used in
combination with such chemicals. Stabilizers have also been added
to the enzyme solution to make them resistant to high temperatures
present in most oil reservoirs.
Proppants
A request from a major operator in the Gulf of Mexico led to the
development of an ultra-conductive, ultra-high strength proppant
technology to maximize and sustain hydrocarbon fow rates at 20,000
psi closure stresses for the life of the well. The signifcantly higher
rates of hydrocarbon fow created by an ultra-conductive proppant
enable operators to achieve a greater return on investment.
At 20,000 psi, Carbo Ceramics’ Kryptosphere proppant has ap-
proximately twice the baseline conductivity of bauxite-based high-
strength proppants (as measured by ISO 13503-5). As the reservoir
depletes and closure stresses increase, the proppant retains its in-
tegrity to provide the long-term conductivity of each fracture, which
increases ultimate recovery.
The proppant’s sustained conductivity has been demonstrated dur-
ing cyclic loading tests. After cycling closure stress between 20,000 psi
and 12,000 psi fve times, the difference in conductivity increased to
almost four times that of comparable bauxite proppants. API Acid Solu-
bility tests demonstrate that the proppant’s acid resistant is more than
10 times greater than conventional high-strength bauxite proppants.
A beta factor one-ffth of conventional high-strength bauxite after
cycling at 20,000 psi minimizes the impact of non-Darcy fow, reduc-
ing the multi-phase pressure drop through the fracture and deliver-
ing a more uniform fow profle. •
1406off_70 70 6/3/14 2:17 PM
®
The Deepwater Operations Conference and Exhibition will continue the tradition of excellence in addressing
operational challenges involved in developing deepwater resources. We will return to the Moody Gardens Hotel
and Convention Center on November 4 – 6, 2014 in Galveston, Texas.
Challenges in deepwater production are complex and command our attention to develop solutions that are
economical and long-term. The Deepwater Operations Conference and Exhibition provides a unique experience
for attendees and exhibitors to share, learn and connect in a forum dedicated to addressing these challenges.
OWNED & PRODUCED BY: PRESENTED BY: SUPPORTED BY:
DIAMOND SPONSOR
OPENING NIGHT RECEPTION & TITLE GOLF:
PLATINUM SPONSOR
BADGE HOLDERS:
HOSTED BY:
GOLD SPONSOR
WEDNESDAY & THURSDAY LUNCH SPONSOR:
BRONZE SPONSOR
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SILVER SPONSOR
COFFEE BREAKS:
NOVEMBER 4 – 6, 2014
MOODY GARDENS HOTEL & CONVENTION CENTER, GALVESTON, TX
www.deepwateroperati ons.com
CONFERENCE & EXHIBITION
EXPLORING THE
OPERATIONAL
DEPTHS
1406off_71 71 6/3/14 2:17 PM
72 Of fshore June 2OO7 ª www.offshore-mag.com

PRODUCTI ON

STI MULATI ON VESSELS
2014 World survey of stimulation vessels
Region of operation Statistics Above deck Below deck Tankage
72 Of fshore June 2014
ª
www.offshore-mag.com
1
2
5 3 7
6 4 8
Notes:
1) 2 off Drexel 3 in. line
2) 4,500 gal of LFC
3) 4 in./ 3 in./ 2.75 in.
4) DGPS/Satloc
5) Two-bow thrusters

1-bow fixed 1,200 hp
1-bow dropdown 1,200 hp
2-stern thrusters 600 hp

6) 1,000 hp tunnel and
1,200 hp dropdown
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Baker Hughes Tony Martin; 3rd Flr. Bldg. 5 Chiswick Park, 566 Chiswick High Road, London W4 5YF, UK; Telephone: +44 (0)203 009 9098; email: [email protected]

Based on the Connor Bordelon
StimFORCE I

ª 257 52 4,400 12 8,400 6,550 None None 3,500 350,000 N/A 2,500 400,000 10,400 8,000 20 Yes 2 x 45
StimFORCE II
††
ª 261 60 10,200 12 12000 Flex 6,550 1,100 4000 Flex 3,500 350,000 Column K N/A 5,000 1,000,000 7,500 8,000 20 Yes 2 x 45
StimFORCE III Platform Supply Vessel (PSV) 4,750 6,550 1,100 None 350,000 N/A PSV PSV PSV PSV 20 Yes 2 X 45
1 WSV Blue Dolphin ª 300 60 7,200 10 13,000 8,850 None None 7,500 750,000 2,000,000 11,800 7,915 25 Yes 3 x 60
WSV Blue Orca ª 317 60 12,570 12.3 180,000 16,400 None None 14,450 1,100,000 None 53,676 10,156 1,400,000 10,156 10,156 80 Yes 2 x 60
WSV Blue Tarpon ª 300 60 7,200 10 3,600 8,850 400 None 7,500 750,000 2,000,000 10,200 7,915 80 Yes 3 x 60
2 M/V BJ Blue Shark ª 260 56 5,400 10 70,000 32,800 None None 4,250 425,000 None 58,000 2,600 1,025,000 2,600 5,100 10 Yes 2 x 50
3 M/V BJ Blue Angel ª 275 60 9,600 12 60,000 29,000 None None 5,000 500,000 None 57,000 4,000 1,650,000 4,000 6,900 10 Yes 2 x 50
M/V BJ Blue Marlin ª 280 56 7,200 13.5 60,000 29,000 None None 5,900 590,000 None 120,000 4,800 1,100,000 4,800 8,900 10 Yes 2 x 50
4 M/V Vestfonn ª 270 60 6,480 12 180,000 3,150 N/A 22,000 N/A N/A 180,000 6,650 N/A 1,200,000 10,875 7,143 60 Note 2
Halliburton Rami Yassine, 3000 North Sam Houston Pkwy East, Houston, TX 77032; Telephone: (281) 871-6160; email: [email protected]
5 Stim Star Arabian Gulf ª 234 56 4,000 11.5 100,000 12,800 None N/A N/A N/A N/A 9,000 6,000 c u ft 9,000 5,800 50 Yes
Halliburton 301 ª 210 42 2,450 11 152,000 4,400 None 12,000 N/A N/A N/A 1,570 N/A N/A 2,625 N/A Yes
HOS Beaufort 200 56 4,200 12 14,800 10,980 None 21,600 N/A 150,000 N/A None 200,000 3 988 5,085 N/A N/A
HOS Hawke ª 200 56 4,200 12 67,288** 15,000 None 64,800 N/A N/A 54,228 None N/A 2,200 5,085 N/A N/A
6 HOS Saylor ª 243 54 7,845 12 31,000 16,720 1,628 32,400 11,087 N/A 50,000 1,628 N/A 1,628 1,770 N/A N/A
Falcon Tide ª 258 49 3,000 9 187,500 16,780 None N/A N/A N/A 62,500 2,450 N/A 2,450 2,588 N/A N/A
7 Skandi Fjord 288 61 7,200 14 180,000 12,000 1,048 N/A N/A 1,730,000 136,000 19,760 2,650 cu ft 23,810 7,140 100 Yes
8 Stim Star Angola ª 241 54 6,570 14 25,000 21,300 100 N/A N/A 450,000 N/A 8,051 9005 cu ft 8,051 5,661 + Watermaker 75 Yes
Stim Star ª 274 56 3,420 14.2 60,000** 12,100 600 N/A N/A 501,000 N/A 4,850 8,075 cu ft 4,850 4850 + Watermaker 75 Yes
Stim Star II ª 240 56 3,420 14.2 ***** 8,000 None ***** N/A 668,000 N/A 6,040 8,075 cu ft 5,465 10,486 75 Yes
9 Stim Star III ª 260 56 5,400 14.2 ***** 10,000 None ***** N/A 835,000 N/A 10,230 10,500 cu ft 8,870 6,740 75 Yes
Stim Star Borneo ª 200 66 2,000 7 8,400 7,437 None 1,100 N/A 350,000 N/A 4,000 N/A 4,000 5,100 10 Yes
Schlumberger Torsten Braun, Vechta, GER; phone: +49 4441 9530; email: [email protected] General Information: http://www.slb.com/services/stimulation/execution/offshore_vessels.aspx
10 Big Orange 18 ª 243 59 5,000 12 180,000 15,000 None 24,000 1,150 1,200,000 N/A N/A 5,500 15,400 5,500 5,500 60 Yes
DeepSTIM Norway I ª 305 66 9,300 14 90,000 15,000 970 40,000 N/A N/A 188,000 N/A 13,000 N/A 13,000 13,000 100 Yes
DeepSTIM Norway II ª 305 66 9,300 14 90,000 15,000 970 40,000 N/A N/A 188,000 N/A 13,000 N/A 13,000 13,000 100 Yes
11 Big Orange 25 ª 217 44 3,600 10 20,000 11,000 380 N/A N/A N/A 67,000 N/A 2,000 N/A 2,000 2,000 8 No
12 DeepSTIM I ª 260 56 3,420 12 8,400 8,000 870 N/A 2,000 200,000 N/A N/A 4,800 12,200 4,800 4,800 15 Yes
13 DeepSTIM II ª 270 56 3,420 12 8,400 8,000 860 N/A 2,000 200,000 N/A N/A 6,600 14,700 6,600 6,600 15 Yes
DeepSTIM PRONTO ª 240 54 5,500 12 32,000 8,000 N/A N/A 2,400 240,000 N/A N/A 6,800 9,000 6,800 6,800 No Yes
14 DeepSTIM Mexico ª 240 54 5,500 12 40,000 15,000 N/A 60,000 N/A N/A N/A 50,000 6,280 9,000 6,280 6,280 No No
DeepSTIM Brasil I ª 311 60 6,700 13 120,000 9,000 440 N/A 5,600 560,000 N/A 65,000 8,760 1,300,000 8,760 8,760 15 Yes 2 x 40
DeepSTIM Brasil II ª 311 60 6,700 13 120,000 9,000 440 N/A 5,600 560,000 N/A 65,000 8,760 1,300,000 8,760 8,760 15 Yes 2 x 40
StimWell Services Mike Harries; Beacon Innovation Centre, Beacon Park, Gorleston, Great Yarmouth; Telephone +44 (0) 1493 448021; Email [email protected]; General information: http://stimwellservices.com
15 Island Patriot ª 283 63 10,340 12 220,000 8,960 None 16,000 N/A 1,770,000 0 27,000 27,000 740,000 7,720 10,240 Yes Yes
Superior Energy Services Lester Haddox Jr. ; Lafayette, Louisiana ; Telephone ; (337) 837-6047; Email: [email protected]
16 Inspiration ª 270 56 3,420 10 6,500 12,000 880 10,000 1,000,000 8,374 1,000,000 6,600 11,600 20 Yes 2 x 50
1406off_72 72 6/3/14 2:17 PM
www.offshore-mag.com ª June 2OO7 Of fshore 78
STI MULATI ON VESSELS
General notes:
Mixing equipment Navigational equipment Safety equipment Pumping equipment
Total operating
pump capability
(frac pumps)
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www.offshore-mag.com ª June 2O14 Of fshore 78
9
10
13 11 15
14 12 16
** Acid storage below deck
*** Navigational thrusters are of Azimuthal type
N/A Not applicable
**** Hp expandable to 11,000 hhp
!! Hp expandable to 16,500 hhp
! Hp expandable to 10,400 hhp
Worldwide offshore marine
vessels capable of self-propulsion
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t 1VNQ i.BY 3BUFw JODMVEFT BMM QVNQT BWBJMBCMF
t 1VNQ i.BY 1SFTTVSFw JT IJHIUFTU SBUJOH PG BMM
pumps on rigs
t #MBOL DFMMT JOEJDBUF iEBUB OPU QSPWJEFEw
t 1VNQ UZQFT DPNNPO UP BMM WFTTFMT JO
survey are quintiplex and triplex posi-
tive displacement pumps with Coflexip
high-pressure line(s)

††
Based on the William C Hightower
2 x 45 27O 2O 1G,2OO 82 Yes G,8OO Yes BF·2 ABS certilied Yes Yes Yes Yes 8, 4 2 x 8OO 15,OOO 5 8,8OO 82 15,OOO 1,OO8
2 x 45 858 2O 1G,OOO 45 Yes 2,8OO Yes BF·2 ABS certilied Yes Yes Yes Yes 8, 4 2 x 8OO 15,OOO 6 1O,8OO GO 15,OOO 1,8OO
2 X 45 888 2O 1G,OOO 45 Yes FSv FSv FSv Yes Yes Yes Yes 8, 4 2 x 85O 15,OOO 6 1O,GOO GO 15,OOO FSv
8 x GO 2OO 5O 82,OOO 8O Yes 4,55O Yes BF·2 ABS certilied Yes Yes Yes Yes 8, 4 85O 2O,OOO O 28,OOO 8O 2O,OOO 8,8GO
2 x GO 4x5O 8O 25OOO 5O Yes G7O4 Yes MT BF·2 ABS certilied Yes Yes Yes Yes 4 4OO 15OOO 7 152OO 8O 15,OO 88GO
8 x GO 55O 2O 82,OOO 8O Yes 4,55O Yes BF·2 ABS certilied Yes Yes Yes Yes 4 2 x 4OO 15,OOO 11 24,7OO 8O 15,OOO 8,8GO
2 x 5O 4x5O 5O 82,OOO 5O Yes 5,OOO Yes BF·2 ABS certilied Yes Yes Yes Yes 4 5OO 15,OOO 7 1O,8OO 5O 15,OOO 2,52O
2 x 5O 4x5O 5O 82,OOO 5O Yes O,4GO Yes BF·2 Bhv certilied Yes Yes Yes Yes 8, 4 5OO 15,OOO O 18,8OO 5O 15,OOO 2,52O
2 x 5O 4x5O 5O 82,OOO 5O Yes G,GOO Yes BF·2 ABS certilied Yes Yes Yes Yes 8, 4 5OO 15,OOO 8 12,8OO 5O 15,OOO 2,52O
GO 288 GO 22,OOO GO Yes 8,2OO Yes Simrad SBF21/BF2 hote 1 Yes Yes Yes hote 8 GOO 15,OOO 8 18,4OO GO 15,OOO 2,78O
7O 5O 5O N/A N/A N/A 2x75O/85O Yes Beier Radio ívCS 2OO2 BFS·2 Yes Yes Yes Yes 8 2OO 15,OOO 5 5,OOO 45 15,OOO 2x 2,1OO
7O N/A 7O N/A N/A No G5O No N/A Yes Yes Yes Yes 8 82O 1O,OOO 8 4,8OO 7O 11,2OO 2,1OO
25 5O 15 18 No 1,2OO Yes Simrad SBFO1, BFS·1 Yes Yes Yes Yes 8 2OO 15,OOO 6 7,2OO 85 15,OOO 2 ea 115O
85 N/A 85 N/A 85 Yes 1,2OO Yes Simrad SBFO1, BFS·1 Yes Yes Yes Yes 8 4OO 15,OOO 4 G,75O 85 15,OOO 2,O4O
4O 5O 4O N/A 4O Yes 77O/77O Yes BFS·1 Yes Yes Yes Yes 8 4OO 15,OOO 4 G,75O 4O 15,OOO 8 ea 25OO
85 N/A 85 N/A 85 N/A 1,8OO Yes hautronics ATS11 4O2, XBFS·1 Yes Yes Yes Yes 4 4OO 15,OOO 7 11,5OO 85 18,5OO 2,O4O
GO 48 GO 2O,OOO GO Yes 8,8OO Yes Kongsberg 7O8, BF·AA Yes Yes Yes Yes 2x4 4OO 15,OOO 6 1O,4OO 1OO 15,OOO 5,O4O
7O 5O 4O 2O,OOO GO Yes 2 x 8OO/2 x 8OO Yes Simrad/Konesberg BFS·2 / Radius Yes Yes Yes Yes 8,4 4OO 15,OOO 6 8,25O 75 15,OOO 5 ea 2,5OO
5O 4GO 8O 2O,OOO 5O Yes 1,2OO/1,OOO Yes Simrad/Kongsberg SBF21, BFS·2 / Radius Yes Yes Yes Yes 8, 4 4OO 15,OOO 6 1O,8OO 75 15,OOO 7 ea 2,5OO
5O N/A N/A 2O,OOO 5O Yes 1,OOO/4OO Yes Bridgemate íí, BFS·2 Yes Yes Yes Yes 8, 4 4OO 15,OOO 6 17,5OO G4 15,OOO 7 ea 2,5OO
75 N/A N/A 2O,OOO GO Yes 2·1,OOO/1·1,2OO Yes Simrad/Konesberg SBF21, BFS·2 Yes Yes Yes Yes 8, 4 4OO 15,OOO 8 21,5OO G4 15,OOO 7 ea 8,1OO
8O 1OO 15 2O,OOO 8O Yes 1,OOO No L·8 Joy Stick Control Yes Yes Yes Yes 8 85O 15,OOO 8 8,25O 25 15,OOO 8 ea 1,2GO
12O 2OO GO 24,OOO GO Yes 7,1OO Yes Kongsberg K·Fos/BF2 Yes Yes Yes Yes 8 & 4 2 x 85O 15,OOO O 12,GOO 7O 12,5OO G,72O
8O 1OO 8O N/A 8O No 1O,2OO Yes Marine Technology/Bridge Mate BF2 Yes Yes Yes Yes 4 2 x 87O 15,OOO 1O 2O,OOO 8O 15,OOO 14,OOO
8O 1OO 8O N/A 8O No 1O,2OO Yes Marine Technology/Bridge Mate BF2 Yes Yes Yes Yes 4 2 x 87O 15,OOO 1O 2O,OOO 8O 15,OOO 14,OOO
8O 15O 8O N/A 7O No 75O Yes Kongsberg · BF Yes Yes Yes Yes 4 2 x 8OO 15,OOO 5 1O,OOO 8O 1O,OOO 2,1OO
7O 15O 8O 18,OOO 5O Yes 1,55O Yes Kongsberg/Simrad · BF2 Yes Yes Yes Yes 8 2 x 8OO 15,OOO 8 1G,85O 5O 15,OOO 2,1OO
7O 15O 8O 18,OOO 5O Yes 2,2OO Yes Kongsberg/Simrad · BF2 Yes Yes Yes Yes 8 2 x 8OO 15,OOO 8 21,45O 5O 15,OOO 2,1OO
4O 1OO 8O 12,OOO 4O Yes 2,5OO Yes Kongsberg/BF2 Yes Yes Yes Yes 8 1 x 8OO 15,OOO 5 8,25O 4O 1O,OOO 1,G8O
4O 4OO 4O O,OOO 85 Yes 2,OOO Yes Kongsberg/BF2 Yes Yes Yes Yes 8 1 x 85O 15,OOO 4 G,5OO 4O 15,OOO 1,G8O
2 x 4O 2OO GO 2 x 15,OOO 5O Yes 4OGO Yes Marine Technology/Bridge Mate BF2 Yes Yes Yes Yes 8 & 4 2 x 45O 15,OOO 8 18,5OO GO 15,OOO 8,4OO
2 x 4O 2OO GO 2 x 15,OOO 5O Yes 4OGO Yes Marine Technology/Bridge Mate BF2 Yes Yes Yes Yes 8 & 4 2 x 45O 15,OOO 8 18,5OO GO 15,OOO 8,4OO
vices.com
GO 7,72O GO 2O,OOO GO Yes 5,8OO Yes BF 2 Bhv Certilied Yes Yes Yes Yes 2 x 4 2 x 4OO 15,OOO 6 12,OOO GO 15,OOO 5,O4O
2 x 5O 18O 15 2 x 18,OOO GO Yes 1,2OO/1,OOO``` Yes BF·2 ABS certilied Yes Yes Yes Yes 2 x 8 2 x 85O 15,OOO 7 12,5OO```` GO 15,OOO 2,1OO
1,008
1,890
3,360
3360
3,360
2,520
2,520
2,520
2,730
4,200
2,100
2300
2,940
7,500
2,940
5,040
12,500
17,500
17,500
21,700
3,780
6,720
14,000
14,000
2,100
2,100
2,100
1,680
1,680
8,400
8,400
5,040
2,100
1406off_73 73 6/3/14 2:17 PM

EQUI PMENT & ENGI NEERI NG
74 Of fshore June 2014 t www.offshore-mag.com
T
he 2014 Offshore Technology Confer-
ence gave more than 108,300 attendees
the opportunity to learn about new
products, services, and technologies
and interact with industry colleagues
and professionals from around the world at
the recent edition in Houston.
This year’s event featured nine panel ses-
sions, 29 executive keynote presentations at
luncheons and breakfasts, and 308 techni-
cal papers. The sold-out exhibition covered
680,025 sq ft (63,176 sq m) and featured 2,568
companies representing 43 countries.
Drilling technologies
A number of new products and technolo-
gies were featured for the offshore drilling
market.
Cameron unveiled the EVO 300 Bonnet,
which addresses drillers’ need to shear stron-
ger, thicker tubulars and seal the wellbore.
Building on the company’s EVO BOP technol-
ogy, the new bonnet provides 54% greater ram
closing force versus earlier bonnets.
Caterpillar Oil & Gas introduced a new
platform to the Cat C175-16 offshore generator
set. The existing model is available with 1,833
ekW @ 60 Hz (1,200 rpm) of rated power.
The new Cat C175-16 offshore generator set
offers 2,300 ekW @ 50 Hz (1,500 rpm) of rated
power.
The MCS type-approved, 50 Hz C175 offers
25° tilt capability, an integral feature for solu-
tions providing emergency power on semisub-
mersible rigs. Driven by two ADEM A4 engine
control modules, the IMO Tier II compliant
engine features full redundancy and provides
engine protection, and low emissions.
Baker Hughes announced the commercial
release of its Cytadel ZX electronically actu-
ated casing packer, a gas-tight packer with an
electronic trigger mechanism used to provide
wellbore integrity and to reduce risk of sus-
tained casing pressure-related (SCP-related)
blowouts.
The Cytadel ZX packer forms a V0-rated
secondary mechanical pressure barrier
above the primary cement job. The barrier
eliminates gas migration and protects against
dangerous SCP, even when downhole condi-
tions compromise the sealing integrity of the
casing cement.
The new system comprises three funda-
mental components. The downhole packer
is built on a solid-body mandrel, eliminating
ports and O-rings, and the potential for gas
migration through the mandrel. The founda-
tion of the packer is the zero-extrusion ZX seal
element. Finally, a unique modular electronic
trigger mechanism, deployed and activated in
one trip, eliminates the need for pressure or
pipe manipulation to set the packer, improving
rig site effciency and reducing risk.
The packer is run as part of a long-string
completion and is positioned to isolate the
casing-to-casing annulus. After the cementing
operation, the packer is remotely actuated
from the surface when a unique signal acti-
vates the onboard electronics module. Once
set, the packer provides an ISO 14310 V0-rated
annular seal, creating a permanent gas-tight
barrier and eliminating the need for costly
pressure bleed-off operations.
With drilling and production from high-
pressure reservoirs at or more than 20,000 psi
(138 MPa) becoming more likely in the near
future, GE Oil & Gas unveiled a BOP program
destined to meet the requirements.
Because the demands of drilling 20,000
psi wells at 12,500 ft (3,810 m) differ greatly
from those for 15,000 psi wells, the company
is working on components to meet the higher
pressures. Key features include:
t 6QHSBEFE SBN BOE BOOVMBS #01T
t 4FB0/:9 #01 $POUSPM 4ZTUFN EFTJHOFE
to maximize uptime
t 4FB-ZUJDT #01 "EWJTPS TPGUXBSF UP HJWF
real-time information.
“GE’s new BOP system will enable
operators to explore deepwater basins that
are currently inaccessible with conventional
15-ksi BOP systems,” said Andrew Way,
president and CEO of GE’s Drilling & Surface
business—GE Oil & Gas. “Our new BOP
system utilizes all of GE’s latest ‘Predictivity’
communications software solutions to allow
for real-time remote monitoring of equipment
status and performance, thus offering new
degrees of reliability and performance.”
Subsea
/FX UFDIOPMPHJFT BOE QSPEVDUT XFSF BMTP
on display for the subsea market.
4DIJMMJOH 3PCPUJDT VOWFJMFE UIF 6)% ***
ROV. The technology meets API 53 standards
for BOP intervention with RAM closure in
less than 45 seconds. The company says the
system increases ROV pilot effciency through
intuitive ROV control interface, automated
navigation, and positioning systems.
Cameron introduced the Cognition Stack
Instrumentation Infrastructure Package.
The Cognition package offers a new way to
monitor subsea BOP stack functions from the
surface while the stack is deployed subsea.
The company says the package provides a
network of new sensors, communication paths
to transmit sensor data to the surface, and
Industry unveils new products
and technologies at OTC 2014
Conference attendance and exhibition set records
Jessica Tippee
Assistant Editor
The new
platform
offers a
2,300 ekW
power rating
for offshore
drilling and
production
applications.
The GE Oil & Gas software uses predictive
analytics based on actual component perfor-
mance data to monitor BOP performance.
1406off_74 74 6/3/14 2:17 PM
1406off_75 75 6/3/14 2:17 PM
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Di scover more about the
Nyla-Heroes by vi si ti ng:

EQUI PMENT & ENGI NEERI NG
the analytics, alerts and alarms to
turn the data into insights about the
condition of the subsea BOP.
Milton Roy launched the Prim-
eroyal X, an API 675 compliant
metering pump. The company says
the new pump is designed to give
operators greater power and more
accurate control to improve fow and
deliver consistent product quality.
Logistics, safety, and training
This year’s event also featured new offshore logistics and safety equip-
ment and training initiatives.
Under their jointly owned Hi-Con Training program, Raytheon Profes-
sional Services LLC and Petrofac Training Services launched the new
Tropical Helicopter Underwater Escape Training (THUET) course.
Approved by OPITO, this new training for high-consequence oil and
gas exploration scenarios will be offered at NASA’s Neutral Buoyancy
Lab (NBL), and has been accepted by Shell UA and other Gulf of Mexico
operators to satisfy their warm-water HUET requirement. It has also
been reviewed and endorsed by the P&T Wells organization.
The THUET course intends to help workers traveling to and from
offshore oil and gas installations and vessels by helicopter stay calm
in an emergency. It also teaches delegates to escape a
helicopter following an unexpected water landing
by providing specifc training in pre-fight and in-
fight requirements.
Hi-Con Training’s THUET course is taught by
training professionals at the NBL at the Johnson
Space Center in Houston. The 6.2 million-gallon,
40-ft deep (12-m deep) pool, once used exclu-
sively to train astronauts, allows for an extremely
realistic learning experience, and a Modular Egress
Training Simulator allows participants to experience
the feeling of escaping from a helicopter fully submerged in water.
“As part of our focus on service and excellence, Hi-Con Training is
constantly reviewed, upgraded, and expanded, ensuring that it is current
and of the highest quality,” said Tracy Cox, director of performance
consulting at Raytheon Professional Services. “The OPITO-approved
Tropical HUET is a safety and survival game changer and an important
initiative for oil and gas workers in the Gulf of Mexico.”
Wild Well announced a joint agreement with Check-6 to develop the
next generation of well control training for the oil and gas industry. The
partnership will result in a new standard of training by providing access
to the most advanced computer-based training and learning techniques
available.
The training partnership will focus on advancing well control training
courses using methods designed for adult learning while incorporating
new teaching and learning techniques in lecture, computer-based train-
ing, and hands-on simulation exercises.
Cobham Life Support introduced its new Survivor+ personal
overboard survival system. The Survivor+, a new class of “wearable”
personal fotation device, incorporates both a SOLAS approved infatable
life jacket and a personal life raft into a single system worn as a compact
vest for maximum readiness and survivability. The company says the
new maritime safety system is designed to improve chances of survival
The Primeroyal X pump represents
the first new product Milton Roy has
developed as a brand of Accudyne
Industries.
1406off_76 76 6/3/14 2:17 PM
Greater Columbus Convention Center
Columbus, Ohio
August 18-20, 2015
Brought to you by the most formidable brands in the
energy business, POWER-GEN and the Oil & Gas Journal.
Introducing POWER-GEN Natural Gas, an annual exhibition targeting gas-fired generation
and the many issues surrounding the technology, operation, construction, and maintenance
of gas-fired power.
Preliminary Conference Tracks to Include:
Power:
• Large Frame Gas Turbines
• Operations & Maintenance
• Siting & Construction
• Small Gas Turbine Applications
(aeroderivative gas turbines)
Oil & Gas:
• Operator presentations on the midstream/
pipeline infrastructure development in
Marcellus & Utica
Look for more information coming soon!
www.power-gennaturalgas.com
PRESENTED BY: OWNED & PRODUCED BY:
Coming
1406off_77 77 6/3/14 2:17 PM
Presentations that travel so you don’t have to.
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Create your interactive environment today. For upcoming sponsorship opportunities contact: David Davis | 713.963.6206 | [email protected]
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EQUI PMENT & ENGI NEERI NG
in Man Overboard and
vessel evacuation.
Orga Offshore un-
veiled its next-genera-
tion offshore platform
marking and warning
system. The user-
friendly touchscreen na-
vaids central control panel
(NCCP) sits at the heart of
the new digital system. Its modular design
allows easy set up and maintenance while the
touchscreen user interface enables full system
interaction to control and monitor all the com-
pany’s aids to navigation equipment.
The control panel can also be extended
to integrate the company’s new circle and H
helideck touchdown, positioning and marking
lighting system as well as its latest aviation ob-
struction light system. Available for certifed
IECex and ATEX (Zone 1) and non-certifed
use, the NCCP has full alarm, history, and
remote status monitoring capabilities.
Spotlight award winners
Service and supply companies, contrac-
tors, and vendors introduced many products
and technologies, but 12 new, innovative, and
proven technologies each received a Spotlight
on New Technology Award.
Baker Hughes was recognized for the
LaunchPRO wireless top drive cement head,
which launches balls, plugs, or darts wire-
lessly during cementing of heavy subsea long
strings and long, heavy liners. Its remote
wireless operation reduces HSE risk by reduc-
ing manual intervention and rig time, while
optimizing reliability.
The system’s operation is powered by rig
air through a single pneumatic hose that can
be tethered to the cementing line to reduce
the risk of damage during cementing opera-
tions. A wireless pressure transducer pro-
vides real-time data to the cementing operator
to allow for adjustments during operations.
FMC Technologies Schilling Robotics
won for the ISOL-8 Pump. The isolated pump
enables secondary intervention for BOPs in
compliance with API Standard 53. The pump
is tightly integrated with FMC’s UHD III ROV,
and meets the 45 second requirement for clos-
ing BOP shear rams.
It consists of independent pistons syn-
chronized with software control. Flexible
confguration allows optimization for a variety
of demands and can simultaneously provide
up to 50 gpm at 5,000 psi. The company says
this system is depth insensitive and can save
operators up to $4 million per rig.
FMC Technologies received the award for
the offshore footless loading arm (OLAF). The
technology was developed for LNG transfer
between an FLNG vessel and a conventional
LNG carrier, in side-by-side moored arrange-
ment in offshore conditions.
The OLAF design is able to accommodate
the large elevation difference between an
FLNG deck, where it is installed, and an LNG
carrier piping connection at lower level, without
overloads. The company says the system
covers 100% of side-by-side operability in harsh
environmental conditions, thanks to its concept,
its targeting system for connection assistance,
and constant position monitoring system, SIL3,
to manage the emergency disconnection.
GE Oil & Gas received two spotlight awards.
The ISOL-8 Pump is tightly integrated with
FMC Technologies’ UHD III ROV.
1406off_78 78 6/3/14 2:17 PM
The frst was for the Zenith GFI ground fault
immune ESP monitoring system. The system
offers a solution that cannot be disturbed by
ground faults, enabling operators to maintain
well surveillance for production optimization
and pump protection, despite fault conditions.
The company’s second award was for the
SeaLytics, a software solution that enables
drilling contractors to monitor performance
and plan maintenance of BOPs using predic-
tive analytics based on actual component per-
formance data. The software can improve BOP
system uptime, reduce unnecessary mainte-
nance, and lead to better cost forecasting.
Geoservices, a Schlumberger company, was
recognized for the fuid loss and gain detec-
tion service (FLAG). The service provides
accurate fuids monitoring and precise coriolis
fow metering with any drilling fuid on any
rig, and in operating conditions including drill-
ing, tripping, circulating, and cementing.
Halliburton Drill Bits and Services won for
the TDReam tool. Challenged to design a tool
to increase effciency, Halliburton developed
a solution that has the added benefts of opti-
mized steerability and fuid fow, and reduced
tool length based on the proven reliability of
the NBR reamer technology.
SBM Offshore was recognized for the very
high pressure fuid swivel. This new technol-
FLAG features an essential early warning
system that is highly sensitive to fluctua-
tions but intelligent enough to help prevent
false alarms.
The TDReam tool is designed to reduce rat-
hole length and reach target depth in one run.
1406off_79 79 6/3/14 2:18 PM
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EQUI PMENT & ENGI NEERI NG
ogy increases the operating
range of high-pressure
swivels by using a
patented technique to
cascade the pressure
drop over multiple
seals. The 12-in. pro-
totype toroidal swivel
has been fully qualifed
to 830 barg (12,000 psig),
including long-term endurance
test runs, and has the potential to operate at
more than 1,000 barg (14,500 psig).
The company says this swivel is specifcally
aimed at gas or water injection from FPSOs
into ultra-high pressure reservoirs, such as the
Lower Tertiary felds of the US Gulf of Mexico.
Schlumberger received the award for
the Seismic Guided Drilling service, which
predicts formation pressures hundreds
of meters ahead of the bit while drilling.
The service uses both surface seismic and
logging-while-drilling (LWD) data to provide
a 3D look-ahead velocity model with reduced
uncertainty. The company says this model
leads to better geological and geomechanical
description enabling proactive drilling deci-
sions, particularly in deepwater exploration.
Velocities ahead of the bit are re-calculated
from seismic refections by using LWD veloci-
ties behind the bit as a constraint. Compared
with pre-drill predictions, this provides much
more accurate results, which can be used in
velocity-to-pressure transforms to give more
reliable formation pressures.
Weatherford was recognized for the Casing-
Link EM antenna system. The technology was
developed to address the signal attenuation
encountered while drilling in deeper depths
with an EM telemetry system. This method
employs an insulated wire that is externally at-
tached to a standard casing string; a borehole
receiver typically located downhole and con-
nected to the casing; and a surface transceiver.
The borehole receiver picks up the EM
signal at the casing connection terminal and
transmits it via the external signal wire to the
surface transceiver, which decodes the EM sig-
nal. The wire exits the casing near the surface
and passes through a wellhead modifed to ac-
cept the cable pass through. There is negligible
signal attenuation within the transmission wire,
which increases telemetry depth.
West Production Technology AS won the
award for SwarfPak, a technology for P&A
and slot recovery with reduced rig time and
reduced environmental footprint. The company
says the most revolutionary characteristic of the
technology is that all the swarf particles will be
deposited and left downhole, avoiding the use
of surface swarf handling equipment. Another
beneft is that the milling speed is increased.
WesternGeco was recognized for the
IsoMetrix marine isometric seismic tech-
nology, which enables the frst truly 3D
measurement of seismic wavefelds using
towed streamers. A new streamer design that
includes measurement of the vertical and
crossline gradient of the seismic wavefeld en-
ables unaliased reconstruction of the pressure
wavefeld between the streamers.
The company says the resulting fne
isometric sampling in both crossline and inline
directions provides the most accurate images
of the subsurface ever recorded, making
the data suitable for many interpretation and
reservoir modeling applications in exploration
and reservoir development.
OTC returns to Houston at NRG Park May
4-7, 2015. •
The IsoMetrix technology delivers high-fideli-
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1406off_80 80 6/3/14 2:18 PM
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1406off_81 81 6/3/14 2:18 PM

BUSI NESS BRI EFS
82 Of fshore June 2014 t www.offshore-mag.com
People
Repsol has appointed Josu Jon Imaz San
Miguel as CEO.
CGG has appointed Rémi Dorval as chair-
man of the board of directors. He succeeds
Robert Brunck.
Stuart Bradie has joined KBR as president
and CEO.
Rowan Companies plc
has elected Dr. Thomas
P. Burke as CEO. H.E.
Lentz has retired as the
chairman of the board of
directors. The company
has appointed W. Matt
Ralls as the executive
chairman of the board
and Sir Graham Hearne
as the new lead director
of the board.
Chris Finlayson has resigned as chief
executive and as an executive director of the
board of BG Group for personal reasons.
Until a permanent replacement is appointed,
Andrew Gould, the company’s non-executive
chairman, will take over as interim executive
chairman.
Nexen Energy ULC, a wholly owned subsid-
iary of CNOOC Ltd., has appointed Fang Zhi
as CEO. He succeeds Kevin Reinhart.
The National Ocean Industries Association
board of directors has elected John T. Rynd
as chairman and Cindy B. Taylor as vice
chair for the 2014-2015 term.
Charles D. Davidson, chairman and CEO
of Noble Energy, plans to retire and leave the
board of directors on May 1, 2015.
Decom North Sea has appointed Nigel
Jenkins as chief executive.
Michael Cowie has joined Ecosse Subsea
Systems as technical director.
EnerMech has appointed Stuart Cowie
as Process, Pipeline, and Umbilicals general
manager for Norway.
ADIL has promoted Lo Van Wachem to
general manager of projects and develop-
ments. The company has appointed Raffaele
Chiandet as deputy general manager at its
London offce, and Mike Fuery has been
appointed general manager of opportunity
management.
AMEC has appointed Jeff Reilly as group
president of Strategy and Business Develop-
ment.
Noble Corp. has appointed Steven A. Manz
as senior vice president and CFO of Paragon
Offshore Ltd.
Gary P. Luquette has been elected non-
executive chairman of McDermott’s board of
directors.
Valvitalia SpA has appointed Umberto
Quadrino as chairman of the board of direc-
tors.
Naval Sondhi has joined FoundOcean to
lead the SMR design services division.
Larry Scott has joined NEOS GeoSolutions
as vice president of global sales.
For the 2014-2015 term the Petroleum
Equipment Suppliers Association has elected
Paul Coppinger as chairman, Gary Halver-
son as vice chairman, Johan Pfeiffer as frst
vice president, and Dave Warren as treasurer.
Exova has appointed Stuart Bond as global
business development manager, corrosion.
Trendsetter Engineering has promoted
Ron Downing to president.
InterMoor has appointed Lesley Max-
well as group human
resources manager, Dun-
can Cuthill as general
manager of InterMoor
Marine Services Ltd., and
Nick Knight as business
development manager
of InterMoor Marine
Services Ltd.
SPP Pumps has ap-
pointed Ian Burrows
as business development manager for major
projects.
Sterling Seismic Services Ltd. has ap-
pointed Chuck Diggins as vice president and
center manager in Houston.
IHC Merwede America Corp. has appointed
Thomas Agnevall as vice president business
development.
Niko Resources Ltd. has elected Stewart
Gossen to the board of directors.
Dron & Dickson has appointed Lenny Col-
lins as HSEQ manager and Bruce McHattie
as UK wholesales operations manager.
Ram Srivastav has joined Geotrace Tech-
nologies Inc. as chief metrics offcer.
BHP Billiton has appointed Malcolm
Brinded as an independent non-executive
director and a member of the Sustainability
Committee.
HS Ocean Group has appointed Peter Bre-
slin as managing director of its shipbuilding
and repair subsidiary McTays.
Diamond Petroleum
Ventures LLC has ap-
pointed Em Roosevelt as
technical sales represen-
tative.
Cairn has appointed
James Smith as fnance
director and joined the
board as an executive
director.
National Oilwell Varco
has appointed Marcela E. Donadio to the
board of directors.
Wireline Engineering has hired Douglas
Gordon as division sales manager for Asia/
Pacifc; Paul Higginson as division sales
manager for Europe, Africa, and Americas;
and Alex Ozzard-Low as global business
development manager.
Garry Kennie has
been appointed president
of Houlder Americas Inc.
NCS Survey has ap-
pointed Simon Gold-
sworthy as business
development manager in
its Aberdeen offce.
Applied Seismology
Consultants Ltd. has
appointed Lee Clarke
as general manager and
director.
Michael Ketley has
joined Theon Ltd. as en-
gineering manager, and
Jason Frost has joined
the company as business
manager – studies.
Circulation Solutions
has appointed Jerry
Beeson as vice president
of sales.
Enteq Upstream PLC
has appointed CS Fan as
China and Southeast Asia
sales manager.
Bernard André has
joined Aminex as an
exploration advisor.
Knight Oil Tools has
appointed Chris Rosson
as senior vice president of
global resources. Nicho-
las Knight has been
named vice president of
operations, Knight Oil
Tools U.S.A.
David Gair has re-
signed from the board of
directors of Noreco.
Wellsite Rental Ser-
vices has appointed Rex
Ferrier as vice president
- Texas operations, and
Blair Faucheaux as
controller.
The Petroleum
Network Education
Conference’s Philip C.
Crouse Cornerstone
Award recognizes
signifcant accomplish-
ments in upstream
E&P petroleum data
management. This year
the Cornerstone Award
honors Rusty Foreman
and Jerry Hubbard.
Foreman, global head
E&P Data Management,
BP in Houston, has led
the effort to professionalize the feld of Data
Burke
Cuthill
Kennie
Rosson
Ferrier
Goldsworthy
Knight
Faucheaux
Roosevelt
1406off_82 82 6/3/14 2:18 PM
BUSI NESS BRI EFS
www.offshore-mag.com t June 2014 Of fshore 83
Management within BP and in the broader
upstream E&P data community. Hubbard is
president and CEO of Energistics of Houston,
the upstream industry’s open data exchange
standards consortium. He was recognized
for his contributions to building an inclusive
global user community, facilitating a collab-
orative standards development environment,
and developing strategic industry alliances.
The recognition was presented at the closing
awards lunch of the 18th PNEC International
Conference on Petroleum Data Integration,
Information and Data Management held May
20-22, 2014, in Houston, under the production
and auspices of PennWell Corp.
Company News
Aker Solutions will split into two compa-
nies to speed up a streamlining process that
will reduce costs and better position all parts
of the group to meet the customer needs. The
Subsea, Umbilicals, Engineering and Mainte-
nance, Modifcations and Operations areas will
form a new company under the Aker Solutions
name. The other units, including Drilling
Technologies, Aker Oilfeld Services and
Process Systems, will be developed indepen-
dently as part of a new oil-services investment
company, named Akastor.
Reef Subsea is reorganizing to create
three independent companies: Reef Subsea,
X-Subsea, and Technocean Subsea. The
companies will have separate management
and independent strategies. Reef Subsea, to be
headquartered in Thornaby, northeast Eng-
land, will continue to focus on the laying and
burial services of subsea cables to all energy
industries. X-Subsea, which will replace the
Reef Subsea Dredging and Excavation brand,
is headquartered in Houston. With operations
in UK, Norway, Singapore, and the Middle
East, the company will continue to focus on
precision dredging and excavation. Tech-
nocean Subsea, headquartered in Bergen, will
replace the Reef Subsea Integrated Projects
brand to focus on subsea inspection, mainte-
nance, and repair and construction, and build
on its success and growth in the North Sea
and West Africa.
InterMoor, an Acteon company, has added
to its stock of mooring equipment in Asia/
Pacifc and opened a new offce at the Loyang
Offshore Supply Base in Singapore.
Gulf International Services has agreed to
acquire Japan Drilling Co.’s 30% sharehold-
ing in Gulf Drilling International.
DNV GL has acquired Marine Cybernet-
ics, which provides third-party testing of
computer control systems.
Deep Sea Mooring is backing the launch
of Deep Sea Installation, a new, specialist
business dedicated to subsea installation solu-
tions. The company will initially focus on the
FPSO segment.
Genesis Oil and Gas Consultants Ltd.
has fnalized the lease for offce space in
Covington, Louisiana, and will soon begin sup-
plying engineering services to clients in the
greater New Orleans area.
GAC Russia is upgrading its facilities at
the port of Novorossiysk to support offshore
E&P in the Black Sea. The company has
signed contracts with one company to provide
supply base support, including a dedicated
berth, open and closed storage areas, a site
for liquid mud plant and dry bulk plant, and
offces.
Tenaris has invested $39 million in the
construction of its research and development
center in the UFRJ Technological Park in Rio
de Janeiro.
Swift Worldwide Resources has launched
a joint venture called SOMINU with the
Eastern Nzema Stool community in western
Ghana. SOMINU, which means “help to lift,”
will provide job opportunities for more than
2,000 personnel to support the upcoming
construction of a deepwater port facility in the
Atuabo region of Ghana. The partnership will
focus on maximizing employment and skills
development of the local Atuabo population.
All profts from the project will be reinvested
in training and community-improvement
programs focused on education, healthcare,
and sports.
Unique Maritime Group is teaming with
OEG Offshore to offer the rental and sale of
offshore equipment in the Middle East. OEG
Unique, based in the UAE and Qatar, will
offer OEG’s full range of certifed cargo carry-
ing units and A60 modules.
Ferguson Group has formed a new
partnership in Vietnam with local company
New World Logistics JSC, operating out of
bases in Vung Tau, Ho Chi Minh, Nha Trang,
Haiphong, and Hanoi.
The National Ocean Industries Associa-
tion has named Noble Corp. as the recipient
of NOIA’s 2014 Safety-in-Seas (SIS) Safety
Practice Award, and Danos as the recipient of
its 2014 SIS Culture of Safety Award.
London Offshore Consultants has regis-
tered LOC Seoul and opened the company’s
frst offce in South Korea.
AVEVA has opened its second R&D center
in Hyderabad, India.
WorleyParsons has signed a general
agreement with ASD Global for the use of
OptiPlant, Pipe Router, and Pipe Support
Optimizer for all its projects worldwide.
EnerMech has acquired Louisiana-based
Diversifed Oil Field Service Inc. and Cape
Town, South Africa-based Control Valve
Technology.
RISC has acquired ISIS Petroleum
Consultants.
The Norwegian Geotechnical Institute
has announced plans to establish a wholly
owned subsidiary offce in Perth, Australia,
during 2014.
Classifcation society ClassNK has estab-
lished a new survey offce in Belem, Brazil.
Trelleborg’s marine systems operation has
opened a new sales and business development
offce in Houston.
Scottish energy consultancy Tymor Marine
has opened its frst overseas facility in the US.
The frm’s US operations will trade as Tymor
Marine US Inc. from offces in Kaplan,
Louisiana.
Weatherford International Ltd., Sino-
pec Oilfeld Service Corp., and Shengli
Highland Petroleum Equipment Co. Ltd.
have entered into a joint venture agreement
to form a new equity joint venture company
in China. The joint venture will combine the
complementary strengths of each of its parent
companies to provide products and services
within a collaborative framework helping to
tap into the vast unconventional resource base
in mainland China.
Exova METECH has acquired the special-
ist calibration business of Raufoss Offshore
in Norway. The move will see the transfer of
technology assets and personnel to Exova
METECH, with operations remaining in the
company’s current facility in Raufoss Indus-
trial Park, north of Oslo.
McDermott International Inc. has
signed a lease agreement with the Mississippi
Development Authority and the Mississippi
State Port Authority for the exclusive right to
operate a spoolbase and marine operations
base in the Port of Gulfport. The new 50-acre
facility will feature a fabrication building and
stalk racks as well as a dedicated dock for ves-
sel berthing. The company expects the facility
will be available in early 2016.
Oilennium Ltd. has doubled the size of its
global headquarters in Norfolk, UK, and has
moved its US offce into larger premises in
Houston.
ROMAR International has appointed
STEP Oiltools as its agent in the Caspian
region.
Core Grouting Services is a new addition
to Acteon’s company portfolio. Core provides
grouting for foundations on oil and gas plat-
forms and offshore wind farms.
Sandvik AB has completed the acquisition
of Varel International Energy Services.
Bredero Shaw has implemented its
Complete Coating Assurance model, the frst
and only offshore pipeline coating model that
ensures successful performance throughout
the project. The model includes six elements:
engineering services, pipe and joint coating
design, coating system validation, logistics
management, pipe coating application, and
feld joint coating. The company says its prime
purpose is to reduce project risk, schedule
risk, and performance risk.
1406off_83 83 6/3/14 2:18 PM
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1406off_84 84 6/3/14 2:18 PM
MANAGING
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For Exhibiting and Sponsorship
Opportunities please contact:
Europe, Middle East & Asia
Tony B. Moyo
T: +44 (0) 1992 656 658
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Africa
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T: +234 802 223 2864
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The Americas
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Presented by: Owned & Produced by: Supporting Publication: Follow Offshore Events on:
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1406off_85 85 6/3/14 2:18 PM
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Subsea Tieback Forum & Exhibition
March 3-5, 2015 | New Orleans Ernest N. Morial Convention Center | New Orleans, LA
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Owned & Produced by: Presented by: Supported by: Hosted by:
1406off_86 86 6/3/14 2:18 PM
PENNWELL PETROLEUM GROUP
1455 West Loop South, Suite 400, Houston, TX 77027
FhühL +1 718 6Z1 97Z0 º FkX +1 718 968 6ZZ8
David Davis (Worldwide Sales Manager)
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[email protected]
Grace Jordan (Classified Sales) [email protected]
GREATER HOUSTON AREA, TX
David Davis [email protected]
64" t $"/"%"
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8"4)*/(50/ t 03&(0/ t $"-*'03/*"
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ITALY
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SALES OFFICES
A
Aero Tec Laboratories, Inc.
.................. 84
atlinc.com
Aker Solutions
...................................... 11
www.akersolutions.com
B
Baker Hughes
....................................7, 31
www.bakerhughes.com
Bauer Compressors
............................... 5
www.bauercomp.com
Bentley Systems
................................... 47
www.bentley.com
Bluebeam Software, Inc.
........................ 9
www.bluebeam.com
Bredero Shaw
........................................ 27
brederoshaw.com
C
Cameron
................................................ 13
www.c-a-m.com
City of Busan ........................................ 75
english.busan.go.kr
CJWinter ................................................ 79
cjwinter.com
Crowley Maritime Corp. ........................ 51
www.crowley.com
D
Deep Down, Inc. .................................... 10
www.deepdowninc.com
Delmar Systems, Inc. ............................ 36
www.delmarus.com
Delta Rigging & Tools ........................... 23
www.deltarigging.com
Dril-Quip ............................................... C3
www.dril-quip.com
F
FMC Technologies
............................... C4
www.fmctechnologies.com
G
Gardner Denver, Inc.
............................. 21
pumpingperfected.com
H
Halliburton
.............................................35
www.halliburton.com
Harris CapRock
.....................................33
www.harriscaprock.com
Hoover Materials Handling
Group
..................................................... 17
www.hooversolutions.com
Hornbeck Offshore Services
................ 45
www.hornbeckoffshore.com
I
Integris Rentals
..................................... 61
integris-rentals.com
ION Geophysical Corp.
....................40-43
iongeo.com/GulfSPAN
IPLOCA
.................................................. 59
www.iploca.com
K
KBC Advanced Technologies
..............39
www.kbcat.com
Kobelco / Kobe Steel, Ltd.
....................29
www.kobelcocompressors.com
Korean Air
..............................................15
www.koreanair.com
L
Louisiana Machinery ............................ 50
www.LouisianaCat.com
M
M&D Industries ..................................... 63
drilllab.com
Midis Energy Services, Ltd. ................. 16
www.midisenergyservices.com
N
Newpark Drilling Fluids. ....................... 37
www.newparkdf.com
NOV Fiber Glass Systems. ................... 25
www.fgspipe.com
Nylacast ................................................. 76
www.nylacast.com
O
OneSubsea ........................................... C2
www.onesubsea.com
Orion Instruments ................................ 69
www.orioninstruments.com
P
PennWell
Deep Offshore Technology
Conference & Exhibition .................33
www.deepoffshoretechnology.com
Deepwater Operations
Conference & Exhibition .................71
www.deepwateroperations.com
MAPSearch .......................................16
www.mapsearch.com
Offshore Group ..........................78, 80
www.offshore-mag.com
Offshore Middle East
Conference & Exhibition .................49
www.offshoremiddleeast.com
Offshore West Africa
Conference & Exhibition .................85
www.offshorewestafrica.com
POWER-GEN Natural Gas
Conference & Exhibition ................. 77
www.power-gennaturalgas.com
Subsea Tieback Conference &
Conference & Exhibition .................86
www.subseatiebackforum.com
Topsides, Platforms & Hulls
Conference & Exhibition .................81
www.topsidesevent.com
R
REPSOL ................................................. 57
www.repsol.com
S
Schlumberger .........................................3
www.slb.com
Stim Well Services ................................67
www.stimwellservices.com
T
TD Williamson ....................................... 55
tdwilliamson.com
TIW Corporation ..................................... 6
www.tiwtools.com
Tomax AS............................................... 19
www.tomax.no
U
UOP, A Honeywell Company ................53
www.uop.com
V
Variable Bore Rams, Inc. ...................... 38
www.vbri.com
W
Wood Group Mustang ............................ 1
www.mustangeng.com
The index of page numbers is provided as
a service. The publisher does not assume
any liability for error or omission.
"%7&35*4&34 */%&9
1406off_87 87 6/3/14 2:18 PM
This page refects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. Offshore
Magazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to David Paganie at [email protected].
88 Of fshore June 2014 t www.offshore-mag.com
BEYOND THE HORI ZON
Consider this. With a world population of about 7 billion people,
our total energy consumption today is more than 500 quadrillion
Btu—every barrel of oil produced meets the energy needs of 30
people for a day. By 2040, our energy needs are projected to rise
to more than 820 quadrillion Btu. Even accounting for renewable,
nuclear energy, and coal, hydrocarbon liquids and natural gas will
still account for half of the energy produced.
It is no surprise that increased need for energy has necessitated
the trend toward looking for new energy sources in new basins.
Emerging developments, like Stones in the Gulf of Mexico, are tak-
ing the industry forward into more than 2,000-m (6,500-ft) water
depths, termed the “ultra-deepwater.”
What were the elements leading to current successes in the deep-
water? How can industry continue these advances, implementing the
results and building safe and successful operations which will also be
applicable in the ultra-deepwater? Ultra-deepwater basins present dif-
ferent metocean environments, high-pressure/high-temperature res-
ervoirs, and deep formations. As these ultra-deepwater basins may be
located farther from currently established infrastructure, the industry
continues to focus on technologies, approaches to work, and strategies
that can be adapted to the expansion into these ultra-deepwater basins.
As industry continues its work to access newly discovered sourc-
es of hydrocarbons, success can be measured in many ways. For the
moment let’s focus on three:
t 4BGFUZ BOE FOWJSPONFOUBM SFTQPOTJCJMJUJFT
t 5FDIOPMPHJDBM JOOPWBUJPO
t %FWFMPQJOH OFX UBMFOU
Safety does not begin offshore. It starts in the offce during the
design process. Improvements in safety start by progressing what
are currently accepted as sound, normal industry practices.
Continuous innovations in design not only keep all facilities operat-
ing safely; they also lead to improvements and even safer conditions.
All potential risks must be constantly evaluated, and the technical
community must continue improvements aimed at eliminating poten-
tial safety hazards.
The industry has applied, and should continue to apply, that same
approach to managing potential environmental risks. What are the
potential hazards and how should control barriers be designed to re-
duce or prevent a potential event? For example, the design of a pas-
sive hull with no exterior penetrations and no cross-fooding piping
limits the possibility of water ingress and progressive fooding that
could lead to stability problems. Advances in technology, once de-
veloped, should be adopted into practice. Our experience regularly
shows that by thinking through the potential risks and exposures,
design solutions can be developed that prevent bad outcomes, and
in the end are far more affordable to build and operate.
Engineering and design innovations are a key component of suc-
cess in ultra-deepwater environments. The industry has developed
and is deploying engineering solutions and technology to address
the high pressures and high temperatures which can be encountered
at deeper depths, which in turn may increase the load on risers and
mooring systems. Design engineers must continue to innovate in
ultra-deepwater environments in ways that are not only increasingly
safe and affordable but also offer the opportunity for standardization
for engineering excellence in a constant, sustainable way.
The myriad of factors that are in play in the ultra-deepwater
means that there are an equal variety of options and solutions to
address the technological aspects of ultra-deepwater. For example,
high pressures at deepwater depths could be a subsea solution, a
topside solution, or a wells solution—or all three in combination.
Interdisciplinary collaboration will increase the potential for the de-
velopment of additional creative solutions.
Leveraging and training talent is essential to sustaining successful
operations on all frontiers. Many of us, having been in the industry for
25 to 40 years, enjoy the mentoring and development process, and in
due course look forward to the succeeding generations of offshore en-
gineers and scientists. While we may initially seek the most experience
for deepwater assignments, we also must leverage the experience of
current staff along with fostering the talents of our bright but less expe-
rienced colleagues. That can translate into very basic strategies – like
taking a new hire or less experienced associate along with you to a con-
ference, or sitting down and reviewing someone’s work. Giving time,
guidance, support and coaching – especially at the most junior levels
– will help these staff members and, ultimately, our projects succeed.
We also have to ask ourselves if we are continually alert to provid-
ing opportunities for hands-on experience for company staff and for
suppliers and contractors. Offshore work provides some different
logistical challenges in workforce training. Offshore operators must
not only continually invest in training their technical personnel, con-
sistent with best practices and resources available, but also assist
in accommodating supplier and contractor training programs for
newly hired or less experienced employees, including having them
participate on major projects. It is important to involve the entire
supply chain in designing and building systems in a responsible
way—from the beginning and throughout the process.
Robert W. Patterson
EVP Project and Engineering Services
Shell Global Solutions
Building on success to new depths
1406off_88 88 6/3/14 2:18 PM
Systems validation testing confirms it.
Contact a DRIL-QUIP representative for more information
on our subsea wellhead system validation testing program.
To ensure the reliability of our subsea wellhead systems, DRIL-QUIP has
built a horizontal test machine and integrated control system designed
to create the load conditions of harsh deepwater environments.
DRIL-QUIP’S new horizontal test machine provides full-scale testing for our wellhead
system confgurations. Combined tension/compression, bending, pressure and
casing end-loads can be simultaneously applied to simulate actual feld conditions.
This comprehensive, fully automated testing program is another example of
how we set the standard for total systems reliability.
Our systems can
handle the stress.
1406off_C3 3 6/3/14 2:18 PM
www.fmctechnologies.com
Copyright © FMC Technologies, Inc. All Rights Reserved.
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JUNE 2014 ENERGYBOARDROOM.COM 3
advertisement
BRAZIL
PT 2
S
cientists exploring the New Hebrides trench in the Pacific Ocean
recently gained further understanding of the inhabitants of the
deepwater environment by sending an ROV (remotely operated ve-
hicle) the 7,000m distance to the sea floor. The creatures that encoun-
tered were similar to animals adapted to other deepwater trenches, but
at the same time appeared in different numbers and in different forms:
they were subtly adapted to this local environment. A certain type of eel
was particularly abundant because the area is especially nutrient poor;
this type of eel is able to cope with infrequent meals, scavenged from
the sea floor. Unlike the animals of the New Hebrides trench, Brazilian
operators do not currently face a lack of commercial sustenance, but
there is still the need to ensure one’s company is best suited to dealing
with the local business environment.
THIS SPONSORED SUPPLEMENT WAS
PRODUCED BY FOCUS REPORTS.
Publisher: Ines Nandin
Project Director: Chiraz Bensemmane
Editorial Coordinator: Fraser Wallace
For exclusive interviews and more info,
plus log onto energyboardroom.com or
write to [email protected]
ADVANCING EVOLUTION
1406off_focusreportDIG_3 3 6/3/14 4:48 PM
4 ENERGYBOARDROOM.COM JUNE 2014
Speeding up integration of new ideas and con-
cepts into the Brazilian oil and gas industry is one
way that policy makers are expediting the industry
reshuffle that will allow best use of hydrocarbon re-
sources across the country. There is an imperative
to gain the skills that Brazilian industry can use to
ease access to resources. Lowering costs and in-
creasing capabilities must be married with the Bra-
zilian government’s desire to increase the capabili-
ties of local industries through use of local content
regulation (LCR).
This dual ambition creates both opportunity and
market turbulence, which can help or hinder com-
panies operating in Brazil to varying degrees.
Almir Barbassa, the CFO for Petrobras, details
the wealth flowing from equipment already in-
stalled: “The first FPSO at the Lula field is produc-
ing more than 100,000 bpd with four wells. The
production rate per well averages 25,000 bpd, al-
though the platform itself was built to receive six
producing wells. Two of them are idle because there is no room on
the FPSO due to the amazing productivity of the other wells.”
Barbassa also gives an idea of the success Petrobras has already
had from the pre-salt fields: “The success rate of the wells we drilled
in the pre-salt stands at 85 percent. We have a fleet of 40 new genera-
tion rigs able to drill in waters up to 2000m depth and a total of 69
floating rigs working for Petrobras.”
The CFO of Brazil’s national giant goes on to describe the current
opportunities that Brazil’s biggest operator, with 76 percent market
share, is taking advantage of: “Today we are working to develop the
existing fields. Petrobras is installing more than 30 oil rigs between
2013 and 2018. Most of the capex needed to build this equipment
has already been deployed – not only the USD 42 billion for the trans-
fer of rights, but the development of 20 FPSOs, each costing USD
1.5-1.8 billion. If we include the cost of adding wells to the FPSOs,
each module requires USD 5-6 billion before starting production. We
are paying for future production today.”
Barbassa estimates output of 4.2 million bpd, plus 1 million bpd in
gas equivalent by 2020.
The break-even figure for pre-salt production is USD 40-45 per
barrel of Brent crude, and with the price of oil currently over USD 100
per barrel, pre-salt fields have the capacity to be very lucrative for
Brazil and the oil and gas sector. Local and international companies
are eager to engage with this opportunity too.
Milton Costa, executive secretary of the Brazilian Petroleum Gas
and Biofuels Institute (IBP) also predicts much pre-salt activity. He
thinks that the first priority, however, must be reducing drilling costs:
“Drilling operations need to be further optimized. This is work in
progress. The pioneer wells in pre-salt cost up to USD 200-300 mil-
lion, but in Lula, Petrobras is now drilling for some USD 70-80 million,
less than three months from the start of operations.”
Brazil has been very lucky, as the pre-salt discoveries came just
after the techniques for deepwater extraction had been fully devel-
oped and learned in the Campos Basin.
Costa predicts significant challenges, though not insurmountable
ones: “Petrobras has a huge financial challenge in the next three to four
years. They have to put the last systems in the Cam-
pos Basin in production and add pre-salt projects.
When production goes up, they will start to generate
a lot of cash flow, and in four years will be in a very
good position to face all the other investments.”
PRESALT PULL
There is an increasing diversity and abundance of
businesses in the Brazilian oil and gas sector. As
Brazil’s industrial capabilities and capacities grow,
so more business niches appear. Understandably,
many companies have arrived to work accessing
the pre-salt resources, an opportunity on a scale
previously unfathomed. However, native efforts to
extract these resources cannot be forgotten either,
for of course Brazilians are eager to take their stake
of this prize.
Queiroz Galvao, an industrial conglomerate
originating in the state of Pernambuco, is an ex-
ample of a thriving Brazilian consortium. This enter-
prise is now consolidating its position with a swelling presence in the
Brazilian oil and gas sector.
“The company developed over the years to be one of the largest
groups in Brazil,” explains Antonio Augusto de Queiroz Galvao, chair-
man of Queiroz Galvao Oil and Gas. “At the moment, the business is
a diversified enterprise. Oil and gas is certainly one of our growth
drivers [and] in particular has grown significantly since 1980 through
the foundation of a then small onshore drilling company, Queiroz Gal-
vao Oil and Gas (QGOG).” Today, the company also operates off-
shore, and assets include 12 floating drilling units, eight operating,
and four under construction. “One, the Brava Star, will be completed
this year in Korea,” Galvao reveals. “It is a top-range and well
equipped unit built by Samsung.’
Queiroz Galvao also constructs vessels. Galvao details that this in-
cludes “FPSOs, as our business has a 37.5 percent stake in the South
Atlantic Shipyard. On this site, oil tankers and drilling rigs are being
fabricated.”
This diversification has also seen the group form and float Queiroz
Galvao Exploration and Production (QGEP) on the Sao Paulo stock
exchange. This company is the operator on block BS-4, in Atlanta
Field, at a depth of 1,500m.
Galvao is unequivocal about why Queiroz Galvao is present in Bra-
zil’s oil and gas sector: “The resources in the pre-salt fields are sub-
stantial, and production will increase rapidly; oil and gas resources
will undoubtedly be central to Brazil’s future success.”
GAS, AN OPPORTUNITY WITH SPARK
Pre-salt oil is one of a number of hydrocarbon sources that are attract-
ing companies from abroad to Brazil. Around 12 percent of activity in
Brazil’s oil and gas sector is onshore, attracting international compa-
nies and enabling the emergence of local players.
Geogas, a company providing compression and treatment of natu-
ral gas services is one local competitor.
Last year in Maranhão, Valerus Geogas, completed 12 miles of gas
pipelines feeding a gas treatment unit over 90,000m2 in area supply-
ing an electric power station, a milestone project for the company.
Milton Costa Filho,
executive secretary,
IBP
Amir Barbassa,
CFO, Petrobras
Antônio Augusto
de Queiroz Galvao,
chairman, Queiroz
Galvao Oil & Gas
Denis Palluat de
Besset, General
Manager, Total
Exploration and
Production Brazil
1406off_focusreportDIG_4 4 6/3/14 4:48 PM
1406off_focusreportDIG_5 5 6/3/14 4:48 PM
6 ENERGYBOARDROOM.COM JUNE 2014
KEY CONSIDERATIONS IN BRAZIL
THREE BUSINESSMEN GIVE THEIR THOUGHTS ON CONSIDERATIONS OF IMPORT
IN THE BRAZILIAN MARKET.
1. PETROBRAS’ FAVOR IS WORTH WONDERS
Luiz Braga; VP- Geomarket Director Latin America, CGG:
“CGG have been working in Brazil for a long time, and the approval of
Petrobras over that period has been a great tool in validating CGG’s
technology to the market.” He continues: “Petrobras are technology
leaders offshore; when they state that a technology is a useful one,
other operators listen. This has been of great use to CGG.”
Petrobras are the key player in Brazil (and are the seventh biggest
energy company in the world) with a 76 percent market share. They
dominate the market, and other participants in the Brazilian market
must learn to deal with them.
2. THINK LIKE A BRAZILIAN
Ian Wilkinson; Socio-Director, Petrolink:
“Brazil is not an easy market for overseas companies to enter; un-
derstanding the divergence between Brazil and Europe is essential
to succeed. The catch-all phrase of ‘cultural differences’ is key to
business strategy and prominent amongst all the issues which must
be considered by any business seeking to enter the Brazilian market.”
3. ATTACK RISKS FROM ALL SIDES
Nilo Chagas de Azambuja Filho; Chief Technical Exploration Officer, HRT:
- by diversifying:
“Acquiring assets already producing is a costly but low-risk strategy,
particularly when compared to straight up exploration. The latter,
however, is far cheaper. Both exploration and production are important.
The Polvo field [HRT recently acquired a 60 percent stake] is part of
HRT’s diversification strategy and will allow HRT to move from being
a non-operating company to a fully-fledged operator.”
- by gaining partners:
“Having a partner is it allows more aggressive drilling of wells in the field, by reducing risk
and sharing further investment. This is towards the aim of increasing production.”
PRODUCTION OF OIL (BRAZIL)
Source: Petrobras
181
653
Onshore
Mil bpd
1980 1990 2000 2012 2017E 2020E
Shallow water
Deepwater
Ultra deepwater
bpd = Barrels of oil per day E = Estimated
1,271
1,980
2,750
4,200
“The key for growing our client list is turnkey solutions
– complete from start to finish,” says Paulo Lopes, di-
rector of Valerus Geogas Consortium.
Valerus Geogas has attempted to finesse its pro-
duction and operational procedures. Lopes empha-
sizes efficiency: “Prefabrication is a specialty of Va-
lerus Geogas [meaning] one can attend to several
stages in the production process simultaneously, rath-
er than proceeding in a lumbering, slow manner.” Va-
lerus Geogas also seeks to develop local fabrication
facilities, typically sourcing more standardized equip-
ment in this manner. Only the core equipment then
requires transport, cutting down on the cost and time
taken up by logistics. “The company is capable of de-
livering a project in a third of the time that might be
expected from traditional approaches.”
Exterran is another commercial unit focused on Brazil’s gas re-
sources. Fernando Costa, country manager, highlights his company’s
value proposition: “Exterran highlights its technical expertise to the
wider market by providing services aimed at satisfying [clients’]
requirements.”
Costa describes how his company deals with Brazil’s large size
and the location of gas reserves: “We also ensure our services en-
gage with opportunities such as electricity production near locations
where gas is being extracted from the ground.” At the moment,
Brazil’s limited pipeline network means transmitting and selling elec-
tric power generated through gas combustion is key to creating a
market for gas, extracted far from pipeline networks.
Costa highlights that the Brazilian gas compression business is
immature, and many opportunities have yet to emerge as demand
grows: “the main units are the engines, compressors and coolers
and it is not possible to obtain these readily in Brazil. Demand at the
DEVON -
Desenvolvimento
do Campo de
Polvo Plataforma
de PolvoPolvo Oil
Field- credit HRT
Nilo Chagas de
Azambuja Filho,
CEO, HRT Oil and
Gas
Dr.Ian Wilkinson,
socio-diretor,
Petrolink
Luiz Braga,
Vice President
& Geomarket
Director Latin
America, CGG
Brazil
1406off_focusreportDIG_6 6 6/3/14 4:48 PM
JUNE 2014 ENERGYBOARDROOM.COM 7
moment does not encourage traditional global producers to take up
manufacturing these units locally and for this reason, we must keep
importing this equipment.”
He displays confidence that the market will pro-
vide this demand: “Sao Paulo is a good example as
it has greatly expanded its gas network and so the
path to developing gas has a precedent. The po-
tential for this market is huge because Brazil’s gas
resources are growing.”
Lopes cites one reason for this growth: ‘“On-
shore concessions are being granted which is in-
creasing the pace of operations across the
country.”
HUNGRY HUNTERS
Following the first block auctions in five years, and the issuing of con-
cessions, opportunities have also increased for companies searching
for Brazil’s hydrocarbon resources, both onshore and offshore.
An innovative, native company with a unique product, Oil Finder
provides remote software solutions allowing clients to locate seafloor
sources of oil from satellite imaging of seeps (natural or otherwise) on
the surface. In a ‘competitive test run’ held in cooperation with Petro-
bras, areas indicated by Oil Finder to have oil resources had a 65
percent chance of having traces of petroleum chemicals in the sea-
bed compared to 25 percent in areas which oil finder did not indicate
a ‘find’ was likely.
Manlio Mano, executive director of Oil Finder,
summarizes: “Oil Finders’ technological advantage
will allow companies to speed up locating oil,
meaning production will happen faster.”
More traditional survey companies are capital-
izing on opportunities arising following the 11th
and 12th rounds of auctions for concessions in the
Brazilian market too.
CGG, an integrated geoscience company pro-
viding leading geological, geophysical and reser-
voir capabilities is headed in Brazil by Luiz Braga, VP- Geomarket Di-
rector Latin America. He states: “Two of the main reasons for CGG’s
success following 2013’s bidding rounds were the company’s technol-
ogy and strategy for advancing the process of delivering results to
clients.”
Braga illustrates CGG’s applicability offshore: “In offshore, CGG is
pioneering new technologies as well, clearly with Brazil’s significant
focus on this area for new development, companies such as CGG
must pay attention to this sector. Ensuring operators are able to fully
understand their wells as production is ongoing will need a degree of
emphasis, and CGG seeks to address this requirement.” CGG has
reduced its own risk by proactively securing a contract backlog
through 2014 and new auctions are expected in 2015.
Risk avoidance not only drives CGG’s strategies, but also that of
the wider surveying industry and multi-client survey in Brazil has be-
come the norm as the operator transfers risk to the surveying party.
TRUNK ROUTES
Operators demand countless services, from surveying, to delivery of
parts and equipment required to sustain consistent operation - down-
time is lost revenue. Renata Pereira, executive di-
rector at BRASCO, a logistical onshore and off-
shore support company states: “[BRASCO] is
positioning itself to pick up the greatest market
share from the 11th round of auctions. It is a man-
ner of business drive, and having the proper com-
petencies to deal with customer demands as they
arise.”
Pereira states the logistics industry is central to
the growth of Brazil’s community of businesses:
“Efficient transport over longer distances needs to
become the norm.” She concludes that truly coor-
dinated supply chains, from site of production to
point of use are vital for Brazil’s ambition.
Calixto Deberaldini, country manager of GTM
do Brazil, a leader in Latin America in the distribu-
tion of chemical inputs, raw materials, and provider
of logistics services, sees opportunity in supplying
the Brazilian market: “Handling and importation
costs in Brazil are higher, freight rates are pushed up by poor road
infrastructure.” While many would view this as a disadvantage, De-
beraldini highlights that GTM uses experience and technical capabili-
ties to ameliorate these further costs.
GTM is a recent entrant to Brazil, and Deberaldini articulates the
company’s strategy to seize market share: “GTM has so far intro-
Paulo Lopes,
director,
Valerus Geogas
Consortium
Manlio Mano,
executive director,
Oil Finder
Calixto Deberaldini,
country manager,
GTM do Brasil
Renata Pereira,
executive director,
BRASCO Logistics
Offshore
1406off_focusreportDIG_7 7 6/3/14 4:48 PM
8 ENERGYBOARDROOM.COM JUNE 2014
duced a limited number, between five and ten products to Brazil to
ensure that these gain a solid reputation and a respectable market
share within the E&P sector. These products are used in drilling, ce-
menting and well stimulation operations.” He predicts future success
for GTM: “GTM expects to shift 50,000 tons of material in Brazil by
2015. The focus on international transport and high volume capacities
means GTM is able to be highly competitive across its diverse prod-
uct portfolio.”
GTM achieves this focus on high volume transit through its sister
company, Panachem, based in Houston which aims to connect GTM
to suppliers across the world, ensuring that GTM has access to the
lowest prices in the market for transport. This a core strategy for GTM
which allows the company to mitigate the high cost caused by the
poor quality of infrastructure and actual size of Brazil.
NAVIGATING THE REGULATORY FRAMEWORK
Logistical supply is far from the only hurdle encoun-
tered in Brazil. All participants in the market are af-
fected heavily by government efforts to regulate
development. Petrobras, for example, is the sole
operator of pre-salt projects, even though this re-
stricts Petrobras from deploying assets elsewhere.
LCR is a common complaint of companies entering
Brazil from abroad, but local players can find it a
hindrance too- Daniel del Rio, country manager at
Westshore do Brazil, a shipbroker, highlights Brazil-
ian regulation, whilst aiding businesses at home, also has a cost: “the
protection provided by these rules to Brazilian operators simply re-
moves the imperative on ship owners and shipyards to reduce costs.
In this way, Brazilian regulation fails Brazilian industry; Brazil should
have the ambition to be internationally
competitive.”
Not everyone is unhappy however. Patricia
Coelho, President of Asgaard Navegacao, an off-
shore services company, explains: “my vision of an
internationally operating Brazilian shipping com-
pany will be achieved under the umbrella of what I
describe as ‘The Brazilian Jones’ Act’ (Brazilian law
9,432), which protects Brazilian flagged vessels.”
This law means contracting companies must give
precedence to locally established companies.
Coelho’s business benefits from current policies in
place in Brazil, but this is not the case for every
participant in the Brazilian oil and gas sector.
Clearly, many local suppliers of goods and ser-
vices are in a better position, shielded in part from
the forces of international competition.
Håkon Ward, former general manager of Kongs-
berg Oil and Gas Technologies Brazil (KOGT) (now
Vice President for Engineering Services; Software
& Services), a company providing technology,
products and services for surveillance, integration,
and analysis of drilling and production operations,
highlights the need for international companies to “get close” to the
Brazilian market to deal with local regulation. “Over recent years
competition has increased, and regulation and tax systems have be-
come more challenging. For these reasons the importance of having
a local presence in Brazil remains clear; any company needs to be in
close proximity to the market and its clients in Brazil, KOGT being no
exception.”
Håkon Ward,
former general
manager of
Kongsberg Oil &
Gas Technologies
Brazil, now VP
Engineering Service
Software & Services
Norway
Patricia Coelho,
president
of Asgaard
Navegacao
Daniel Del Rio,
country manager,
Westshore do Brasil
PETROBRAS’ NOTABLE MILESTONES ADVANCING PRODUCTION NOVEMBER 2013 TO MAY 2014:
The FPSO-type platform P-63 came
online in November 2013. The vessel
is capable of processing 140,000 bar-
rels of oil and 1 million cubic meters
of gas per day and is the first produc-
tion system at Papa-Terra (Campos
Basin)
A second FPSO-type platform, P-58
started operations in March 2014.
Located around 85 km offshore in Es-
pírito Santo, in water as deep as 1400
meters the platform can process
c180,000 barrels of oil and 6 million
cubic meters of natural gas daily from
both pre-salt and post-salt reservoirs.
Well 7-SPH-04-SPS was activated on
April 3 2014 in the Sapinhoá field in
water depth of 2,120 meters. This well
has potential to produce 26,000 bar-
rels of oil each day and is connected
to the FPSO Cidade de São Paulo, 
Most recently activated was the asset
7-LL-22D-RJS which started operating
at Lula, on May 9, now contributing
31,000 b/d. This asset is connected to
the FPSO Cidade de Paraty by means
of a buoyancy supported riser (BSR)
- a piece of equipment Petrobras has
cited as instrumental in this success
PRODUCTION PUSHES SKYWARDS FOR PETROBRAS
L
ike a rhinoceros, enraged by a swarm of stinging bees trampling a road
to safety through farm fences and hedges Petrobras has started to
smash through records- potentially confounding the critics who stated that
Petrobras could not produce quickly enough to cope with the company’s
notable debts.
The company has now reached production levels of 470,000 b/d in the
presalt layer of the Santos and Campos basins offshore Brazil. This is a new
daily production record according to the company and represents Petro-
bras’ assets beginning to return value to their owner.
The achievement represented the combined with production from 24
wells. Most recently activated was the asset 7-LL-22D-RJS which started
operating at Lula, on May 9, now contributing 31,000 b/d. This asset is con-
nected to the FPSO Cidade de Paraty by means of a buoyancy supported
riser (BSR) - a piece of equipment Petrobras has cited as instrumental in this
success and has delivered superlative production volumes from this well as
well as wells attached to the FPSO Cidade de Sao Paulo in Sapinhoa field.
At this end of this year, 15 new wells are predicted to begin production,
four in the Campos Basin and 11 in the Santos Basin.
Two further wells will be linked to Cidade de Sao Paulo, five to the Ci-
dade de Paraty, one to the P-48 platform and three to the P-58 platform. All
these platforms are already producing assets for Petrobras. Close at hand
however, the FPSOs Cidade de Ilhabela (recently arrived from China) and
Cidade de Mangalore ought to start operations in the second half of 2014.
These FPSOs will have two wells connected to them respectively- adding
even further to Petrobras’ significant and growing productive capacity.
1406off_focusreportDIG_8 8 6/3/14 4:48 PM
JUNE 2014 ENERGYBOARDROOM.COM 9
One company that realized this early on was
Technip. Adriano Novitsky, CEO for the Brazilian
subsea division states: “The company has been
growing since starting in Vitoria 25 years ago. With
the pre-salt resource emerging, Technip realized
the opportunity and moved to construct a new fa-
cility in Acu. Our company decided five years ago
to increase R&D capabilities in Brazil. The company
has a technology center based at Vitoria, and an-
other here in Rio de Janeiro. In Vitoria, a lab under-
takes dynamic and static tests to evaluate the reac-
tion of the pipe to conditions that might be found
offshore.”
Technip’s SVP for Latin America, Jose Jorge Arau-
jo emphasizes the result of this early move for the
business is that ”the company has continuously been
working on one large project of this sort after another
since 2003, when work was undertaken on the P-52,
Brazil’s first locally built semi-submersible.”
Another company less delighted with the local content require-
ment regulation (LCR) is Repsol-Sinopec. José Maria Moreno, CEO,
states: “LCR is our greatest concern because it actively prevents the
procurement of FPSOs from abroad, which would allow production to
progress more swiftly.”
Despite this perceived obstacle, Moreno is clear why Repsol-Sino-
pec is in Brazil: “In 2005, however, pre-salt resourc-
es were discovered and this changed how compa-
nies, including Repsol, viewed Brazil entirely. The
pre-salt contain over 500 billion barrels of oil.”
“There are technical challenges to reaching
these larger, highly valuable resources, however
the industry has now managed to reduce costs and
this resource is commercially highly attractive.”
Repsol-Sinopec has various operations in Brazil,
including the Pao de Acucar field discovered in block- BM-C-33 in the
Campos Basin. There, Repsol-Sinopec is the operator with a 35 per-
cent share alongside Statoil and Petrobras. Of a number of deposits,
Pao de Acucar is the company’s most important, featuring a band of
oil 500m deep.
A company in Brazil that finds itself in the middle of this dance
between regulation and partnership is Sete Brasil Participações. João
Carlos Ferraz, CEO of Sete Brazil, states that the company’s “order
book will boost Brazilian shipyards and consists of 29 ultra-deepwater
automated design type rigs, capable of operating in the most difficult
of conditions.”
Sete’s order book is enormous, and offers Brazil a clear path to an
enhanced industrial sector. “These rigs will also utilize 55 – 65 percent
local content, and BNDES will advance 80 percent of the finance,” Ferraz
adds. “Given that our company will fuel whole sections of the economy,
it was always entirely likely that BNDES would support our efforts in this
Adiano Novitsky,
CEO Subsea
Division, Technip
Brazil
Jose Jorge Araujo,
SVP America
Latina, Technip
Brazil
José Maria Moreno,
CEO, Repsol-
Sinopec
cgg.com/brazil
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PASSION FOR
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Exceeding expectations for 50 years.
1406off_focusreportDIG_9 9 6/3/14 4:55 PM
10 ENERGYBOARDROOM.COM JUNE 2014
manner. Local content and producing here in Brazil
[was] the reason Sete Brazil was created. Without lo-
cal content rules, there would be no need for Sete
Brazil to exist.”
Petrobras and Sete Brazil are central to the growth
of Brazilian local industries; they give them shelter
and sustenance in the form of contracts. As the IOCs
add their muscle to the Brazilian oil and gas sector,
further development and cooperation will become
possible. It is clear that the industries associated with
oil and gas in Brazil will do very well in the long run, and LCR certainly
adds to local demand, bolstering local suppliers. It is also clear that inter-
national companies can still add significant strength to local efforts and
many of the technologies and techniques that international players can
bring to Brazil are core to bringing down costs associated with extrac-
tion, key to Petrobras’ dream of producing 4.2 million barrels of oil per
day in 2020.
TEAM WORK MAKES THE DREAM WORK
Brazilian policy makers are certainly aware that new ideas can expedite
access to the value of Brazil’s pre-salt resources, as well as ensure maxi-
mum value is taken from existing fields, onshore and offshore. For this
reason, companies operating in Brazil are obliged to invest a portion of
their revenue in research and development. Alongside indigenous re-
search bodies, such as the Centro de Pesquisas Leopoldo Américo Mi-
guez de Mello (CENPES), incoming experience is again assisting to
push Brazil’s ambition forward. Kjetil Solbrække, President at SINTEF, a
research institution originating in Norway, explains his institute’s par-
ticular strength: “SINTEF has a very proficient group of staff working
here in Brazil on flow assurance [which] is one of the technological areas
that has brought Norwegian abilities in extracting oil forward a great
deal. It allows more oil to be directed to the same number of process-
ing plants. This offers huge financial savings on oil extraction in the
presalt resources.”
Nelson Leite, President of FMC Technologies, a technology solu-
tions provider, indicates foreign entities offer more than technology:
“IOCs offer further investment as well as novel experience: the par-
ticipation of more IOCs in the Brazilian market would be of great
benefit in realizing the country’s ambitions for production. The in-
volvement of IOCs together with Petrobras on the Libra field is an
excellent development because all these players will bring their own
experiences to the table; new technologies can and will assist them
in achieving their aims.”
João Ferraz of Sete Brazil agrees with the idea that foreign compa-
nies working alongside their Brazilian counterparts is beneficial: “Sete
Brazil is an equity investment company, and does not desire to become
a drilling company.” The presalt domain is a huge resource: “Petrobras
will require a huge amount of everything in a very short period of time.
Service providers operating in Brazil will have to initiate a very fast track
increase in capacity, and without stimulation to grow or assistance, they
Joao Carlos de
Medeiros Ferraz,
diretor president,
Sete do Brasil
lnLernuLlonul offshore murlne servlce comµuny bused ln 8ruzll
focused ln µrovldlng servlces Lo mu|or oll 8 gus comµunles und
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conLuLoQusguurd.com.br
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1406off_focusreportDIG_10 10 6/3/14 4:48 PM
JUNE 2014 ENERGYBOARDROOM.COM 11
would likely fall behind Petrobras’ demands for
equipment and services.
“Sete Brazil comes not to replace existing play-
ers, but to support them, offer its strong balance
sheet and assets to help service companies who
could not keep pace with Petrobras’ requirements.
A joint venture business model is advantageous to
both parties and offers a route to rapidly providing
the capacity to extract Brazil’s oil and gas
resources.”
Denis Palluat de Besset, managing director of To-
tal E&P Brazil, extolls the opportunities he sees from
connecting with other players. Speaking of the Libra
consortium, he remarks: “a deepwater champion
has been created. The level of experience and abili-
ty within this consortium is astounding and further-
more, the power the Chinese bring to the consor-
tium too, means that Libra will generate significant
kudos for all involved parties.”
Felipe Lopes, general manager at Sotreq, a Caterpillar dealer, at-
tests to advantages cooperation and collaboration has for equipment
companies. Having access to Caterpillar’s international brand gives
Sotreq recognition, whilst Sotreq’s local knowledge and high quality
repair system for Caterpillar products as part of an international chain
reinforces that brand. “Not long ago, [Caterpillar] opened a factory in
Brazil to build small generator sets, and we used this as a precedent to
argue that large engines such as the 3500 units- Sotreq’s cash cow in
the offshore market- should also be produced here,” he explains.
Lopes highlights the value of other commercial links too: “Sotreq
remains principally a Caterpillar dealer, however, for some contracts, it
is important to have the ability to add some extra capacities to the
finished offering.” For this reason, Sotreq also works alongside Vulkan
do Brasil, the Brazilian affiliate of the Germany-based mechanical trans-
mission technology company.
EXPANSIVE AMBITION
International companies are eager to become involved in extracting
Brazil’s hydrocarbon resources and equally, Brazilian oil and gas com-
panies now are beginning to look at openings beyond the ‘safe port’
created by the Brazilian regulatory system. They might not have the
protection offered by LCR, as it directs more volume to Brazilian busi-
nesses, but the opportunities out with the country are clearly worth a
degree of risk
These opportunities extend beyond solely extracting hydrocarbons.
Marcelino Jose L. Nascimento, chairman of Bravante, a company oper-
ating in the Platform Supply Vessel (PSV) shipbuilding and bunker sup-
ply business (currently restructuring) sourced a number of its PSVs out-
side Brazil, in the United States. “Bravante decided to source part of its
fleet in the USA because the shipbuilding industry there is reputable
and respected, and vitally to our business also has some very attractive
financing packages,” he says. “We received one of the lowest interest
rates on our fiscal package - a 23 year bond at 3.6 percent interest each
year. This was a very good opportunity.”
Companies looking to wider horizons include both small players and
some of Brazil’s commercial champions: Queiroz Galvao Oil and Gas
for example has a letter of intent to drill in Paraguay and will be moving
a drilling unit there in the near future. Galvao,
QGOG’s chairman says: “We want to make our com-
pany international however, and expand where we
can. Growing the company means that we must be
a player in more than one country.”
Small companies too, wish to expand. Oil Find-
er’s Manlio Mano states: “alongside University Col-
lege of Los Angeles (UCLA), Oil Finder looked at
moving further afield, into international markets.
Currently, Oil Finder has a unique offering which is
particularly valuable at the pre-bid stage. There are
around ten auctions globally each year and this
gives our business great scope to market its product
through multi-client bids.”
Brazilian companies show an eagerness to over-
come additional costs of production and to reach
the international market. “CAPEX in Brazil is ex-
tremely high, and because everything is tailor made
for Petrobras this means that an internationally com-
petitive vessel must be highly developed, offering premium services,”
states Asgaard’s Patricia Coelho. “Petrobras is highly demanding, and
Asgaard has responded to this by equipping its fleet with Rolls Royce
engines for example. This means that our vessels are equipped to de-
liver services to any company, in any location.”
The future of the Brazilian oil and gas sector looks bright; and
through increased local demand, likely to invigorate the country’s wid-
er manufacturing base too. Policy makers looking to the future how-
ever, still need to tailor regulation to enable Brazilian businesses to
thrive in any oil environment.
Gold Star Platform in
Niteroi getting ready for
PreSal works in Gold
Star area - Queiroz
Galvao Oil & Gas
Marcelino Jose
L. Nascimento,
chairman, Bravante
Felipe Lopes,
general manager,
Sotreq
Nelson Leite,
President, Subsea
Systems FMC
Technologies
Kjetil Solbrække,
President, SINTEF
1406off_focusreportDIG_11 11 6/3/14 4:48 PM
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Securing Energy,
Fueling Growth
Enhancing India’s
hydrocarbon footprint
Supplement to:
1405CP_CairnIndia_C1 1 4/16/14 3:16 PM
1405CP_CairnIndia_C2 2 4/16/14 3:16 PM
Contents
2 Building a world-class E&P company
in India —in the words of the CEO
4 The path to success
8 Building energy security
12 Mangala: From sand to oil
14 Black gold flows across the desert
16 Pioneering initiatives in
technology application
18 Enhanced oil recovery (EOR) in Rajasthan
20 Alkaline-surfactant-polymer
(ASP) flooding
22 Recognized excellence in HSE
24 An oil company that also
explored for water
26 The Barmer Basin development
29 Delving deeper in Rajasthan
30 Exploring beyond India’s borders
32 Growing through the drill bit
34 An attractive proposition for the
world’s community of vendors
VP, Custom Publishing
Roy Markum
[email protected]
Editor in Chief
Denise Allen Zwicker
[email protected]
Co-Editors
Vendor Management Team,
Cairn India
COMMISSIONED BY:
Cairn India Limited
3rd & 4th Floors,
Vipul Plaza, Sun City
Sector 54, Gurgaon
122 002, India
PennWell Corporate
Headquarters
1421 S. Sheridan Rd.,
Tulsa, OK 74112
Copy Editor
Ron Bitto
[email protected]
Art Director
Meg Fuschetti
Production Manager
Shirley Gamboa
Circulation Manager
Tommie Grigg
1405CP_CairnIndia_1 1 4/16/14 3:24 PM
2 CAIRN INDIA LIMITED
Building a world-class E&P company in India
—in the words of the CEO
When we entered India in 1994 our goal was to create a
world-class operation. The majors had looked at Asia
in general, but they left India out. On the other hand,
we believed that India had a lot to offer in oil and gas.
We began with a single field producing ap-
proximately 3,000 barrels per day. Today, a
couple of decades later, we are producing
close to 220,000 barrels per day—almost
30 percent of India’s domestic crude oil
production. When we reach our goal of
300,000 barrels per day, our contribution
to India’s energy security will be even more
significant.
It’s been a fascinating journey thus far, and
there’s so much still ahead of us.
Cairn has built its success on
a steadfast commitment
to learning. We do, we
learn, we adapt and
we produce outstanding results. Here are
just three examples:
◆ Our first offshore field, Ravva, was essen-
tially a redevelopment project. Everyone
else assumed that it would produce no
more than 100 million barrels of oil. But,
under Cairn’s care, it already has pro-
duced more than 250 million barrels—
and at one of the lowest operating costs
in the world.
◆ At Cambay, on the west coast of India,
we found and developed a greenfield
project in just 28 months. It’s the fast-
est discovery-to-delivery project
ever achieved in India.
◆ Our record-breaking success
at Rajasthan was due to per-
severance and patience. We drilled 13
dry wells before the 14th revealed a bil-
lion-barrel oil field worth US$100 billion
at today’s prices. The discovery aside,
putting it into production required us to
bring a great deal of innovative technol-
ogy to India. For example, in just two
years, we built the world’s longest con-
tinuously heated pipeline, a first for any
oil independent, and it has not been re-
peated since.
We couldn’t have achieved these mile-
stones without our suppliers, who brought
us the technology we needed. The role of
the entire vendor and supplier community
has been enormous for Cairn. They are our
partners.
Now we have reached a certain level of
success and laid a solid foundation for
an even more exciting future. We have
world-class assets in our portfolio. We
have built a world-class talent pool. We
have the funds to deploy—US$3 billion
over the next three years—to begin the
next phase of Cairn India’s growth. We
are looking for the execution partners to
achieve our very ambitious goal of creat-
ing energy security for India.
In this next phase of growth we are scouting
worldwide for the technology that will con-
tinue to improve our recovery factor.
Our business objective is to be able to op-
erate our fields within a wide crude oil
price range. The route to that objective is
greater productivity. We are focused on
discovery and recovery technology and
cost efficiency.
P. Elango, CEO
Cairn India Ltd.
1405CP_CairnIndia_2 2 4/16/14 3:24 PM
Typically, the big fields—the elephants—
come first. Then come the smaller finds.
We see opportunity in tight reservoirs and
small pools and we need the latest tech-
nology to unlock this potential.
We will be drilling at least 450 wells by fis-
cal year 2016, including 100 exploration
and appraisal wells, onshore and offshore.
And we’re developing facilities to bring this
new oil and gas into production quickly. For
that, we need cross-sector technology: part-
ners who have achieved these goals time
and again around the world.
Approximately 78 percent of India’s basins
are still under explored. Cairn is engaged in
constant dialogue with the government to
open these opportunities, including shale gas.
The policy environment in India has improved
significantly in recent years—and even in the
past few months. The government of India
has defined a clear vision to achieve energy
self-sufficiency by 2030, so the opportunity
for us is very large.
Cairn wants to lead the way in building re-
lationships with the best providers of tech-
nology—both service and equipment. As
we demonstrate greater efficiency through
technology, our partners will find multiple
opportunities—not only with Cairn, but also
with all the companies in India.
We are ready to deploy the best technol-
ogy the world can offer. We have the re-
source base. We have the money to invest.
We have people who understand the tech-
nology. Now we just need solution provid-
ers to help us achieve our vision.
PRODUCING ASSETS
Rajasthan (RJ-ON-90/1)
◆ Key fields in Rajasthan: Mangala, Bhagyam and Aishwariya.
◆ Development Area (DA) 1 comprises the Mangala, Aishwariya,
Saraswati and Raageshwari oil and gas fields, and produces ap-
proximately 161,000 boepd; DA 2 comprises the Bhagyam field and
produces approximately 25,000 boepd.
◆ Block current production: approximately 186,000 boepd.
◆ Raageshwari: commenced production in March 2012.
◆ Saraswati: began production in May 2011.
◆ Bhagyam: started production in January 2012.
◆ Over the next three years Cairn plans to spend US$3 billion.
Ravva (PKGM-1), Andhra Pradesh
◆ Block current production: approximately 28,000 boepd.
◆ Produced more than double the initial estimates of crude oil and
natural gas.
◆ Example of how technology can play a central role in accessing
new reserves.
◆ Toward the end of 2013, commenced drilling of “high value, high risk”
exploration prospect in High Pressure High Temperature (HPHT)
environment.
Cambay (CB/OS-2), Gujarat
◆ Block current production: approximately 10,300 boepd.
◆ Example of optimal asset use.
◆ Tolling and processing of Oil & Natural Gas Corp. Ltd.’s North
Tapti gas.
◆ Application of advanced geophysical tools transformed the block
from a predominantly gas field to an oil field.
◆ Advanced reservoir modeling studies resulted in incremental re-
coverable volumes from the reservoir zones.
◆ Infill drilling campaign commenced in fiscal year 2013.
1405CP_CairnIndia_3 3 4/16/14 3:24 PM
4 CAIRN INDIA LIMITED
The path to success
As Cairn approaches its 20th birthday, we take this
opportunity to look back with a bit of nostalgia at its early days.
Operating oil and gas companies en-
tered the Indian exploration and produc-
tion arena in the early 1950s. By the be-
ginning of the 1990s, a few thousand wells
had been drilled by oil majors in Asia, but
India did not figure prominently in that
total. However, efforts by India’s National
Oil Companies (NOCs) —Oil and Natural
Gas Corporation Limited (ONGC) and Oil
India Limited (OIL) —resulted in some im-
portant discoveries. ONGC discovered the
Bombay High Offshore field during the ear-
ly 1970s, which continues to be the largest
oil field in India today.
When India opened up its economy to at-
tract foreign investments in the early
1990s, the oil and gas industry also start-
ed looking up. The Ravva oil field discov-
ered by ONGC in 1987, was offered for
re-development to Command Petroleum,
a small Australian independent, and the
Production Sharing Contract (PSC) was
signed in 1994. Cairn Energy Plc, an in-
dependent Scottish oil and gas explora-
tion and production company, headquar-
tered in Edinburgh, took over Command
Petroleum. Cairn successfully redevel-
oped the Ravva field to produce 50,000
bopd, and had its first deepwater gas
find in the Krishna-Godavari basin (KG-
DW1) off southern India. The compa-
ny followed up with gas discoveries in the
Cambay basin in north-west India in early
2000. Following Cairn’s success, Reliance
Industries Limited, another private player in
India, announced a mega-discovery also in
deepwater in the Krishna-Godavari basin.
In 2004, Cairn discovered Mangala, the
largest onshore discovery of hydrocarbons
in India in two decades. These discoveries
in a short span of time attracted a number
of large and small foreign oil companies.
Today the Government of India conducts
road shows promoting its New Exploration
Licensing Policy (NELP) offering a num-
ber of its oil and gas fields for develop-
ment by both Indian and foreign operating
oil and gas companies. Over the last two
decades, the government has progressive-
ly made investment in the Indian hydrocar-
bon industry more attractive, leading to en-
hanced presence of global players. British
Petroleum and British Gas currently part-
ner with Reliance in its upstream opera-
tions. The goal is to secure energy for India
and make it less dependent on crude im-
ports for its rapidly growing economy. The
Indian Government recently started allow-
ing exploration in developed fields, there-
by paving the way for early monetization of
discoveries.
At Cairn, Ravva
changes everything
The Ravva field was the game changer.
Situated off the east coast of India, Ravva
is the cash cow that attracted Cairn
(Command Petroleum) to India in 1994.
Ravva means “diamond” in Sanskrit and
Telugu and identifies the shape of this
amazingly productive field.
In 1994, the JV comprising Command
Petroleum, later acquired by Cairn Energy
Plc, Videocon Petroleum, ONGC, and Ravva
Oil (Singapore) was formed to develop the
Ravva field.
RAVVA FACTS
◆ Block current produc-
tion: approximately 28,000
boepd.
◆ Cumulative production is
more than double its initial
estimates.
◆ Example of how technol-
ogy can play a central
role in accessing new re-
serves.
◆ Ravva’s field-direct op-
erating cost is one of
the lowest among Cairn
India’s peers.
1405CP_CairnIndia_4 4 4/16/14 3:24 PM
CAIRN INDIA LIMITED
◆ Cairn Energy PLC acquired controlling stake in Command
Petroleum Ltd. in 1996.
◆ The acquisition was completed and name changed from
Command Petroleum to Cairn Energy India Pty. Ltd. in 1997.
◆ Cairn successfully concluded an initial public offering of its
Indian business in January 2007. It held the majority shares
in Cairn India Ltd.
◆ August 2010 saw the announcement of a sharehold-
er-level transaction between Cairn Energy and Vedanta
Resources PLC.
◆ The Vedanta Group acquired a controlling interest in Cairn
India in December 2011.
1405CP_CairnIndia_5 5 4/16/14 3:24 PM
Cairn India timeline
6 CAIRN INDIA LIMITED
The initial production sharing contract
(PSC—called a production-sharing agree-
ment in other countries) estimated that the
field would produce 100 million barrels
of oil. Cairn, through efficient reservoir
management and use of technology, has
produced more than 250 million barrels
to date. The PSC committed to 35,000
bopd, but the joint venture maintained pro-
duction at 50,000 bopd for almost 9 years.
With a continuing focus on technology, the
joint venture has kept Ravva’s costs among
the lowest in the world.
Cairn is currently drilling a technically chal-
lenging, high-pressure, high-temperature
well that is more than 4 kilometers deep
and targets late Oligocene prospects. Cairn
is expecting positive results soon.
Gulf of Cambay
Cairn’s second foray in India was in the
turbulent waters of the Gulf of Cambay,
on India’s west coast, at CB/OS-2 block.
Just 28 months passed from the dis-
covery of the Lakshmi field in 2000 and
the production of first gas. In the next 16
months the nearby Gauri field was also
brought online.
The joint venture, led by Cairn, initiated
new studies of the reservoir and discov-
ered an oil leg. Using advanced geophys-
ical tools, they successfully converted the
predominantly gas field into a profitable
oil producer, setting a field record of more
than 10,500 bopd in 2009.
The joint-venture partners own an 82-acre
onshore processing facility at Suvali in the
district of Surat, Gujarat, long known as
India’s chemical hub. The plant is certified
to ISO 14001 and OHSAS 18001 stan-
dards and has the capacity to process 150
mmscfd of natural gas and 10,000 bopd
of crude oil.
CAMBAY FACTS
◆ Block current production:
approximately 10,300 boepd.
◆ Cairn transformed the
block from a predominantly
gas field to an oil field.
◆ Cairn’s technology-driven
approach has almost dou-
bled production.
1998
Ravva
satellite gas
discoveries.
2000
Cambay
discoveries—
Lakshmi, Gauri,
Ambe.
JANUARY
2004
Mangala
(Rajasthan,
India) discovery,
considered to
be the largest
onshore oil
discovery in India
in more than two
decades.
JANUARY
2007
Cairn India
Limited listed
on the Bombay
Stock Exchange
and the National
Stock Exchange
of India.
JUNE
2008
Cairn awarded
an exploration
license from
the Sri Lanka
government.
AUGUST
2009
Commenced
production
from the
Mangala field
in Rajasthan,
India.
1405CP_CairnIndia_6 6 4/16/14 3:24 PM
CAIRN INDIA LIMITED 7
JUNE
2010
World’s longest
(approximately
600 km)
continuously
heated and
insulated pipeline
operational.
OCTOBER
2011
Discovery in
Sri Lanka; first
in 30 years.
Established
a working
petroleum
system in frontier
Mannar Basin.
APRIL
2012
Made one of the
largest onshore
oil discoveries in
the KG Basin.
JUNE
2012
Ravva field
produced more
than 249 million
barrels of crude
and sold 309
billion cubic feet
of gas—more
than double the
initial estimates.
AUGUST
2012
Signed a farm-
in agreement
with PetroSA
to explore in the
Orange basin, on
the west coast of
South Africa.
DECEMBER
2013
Rajasthan
Block exceeds
200 mmboe
of cumulative
production.
1405CP_CairnIndia_7 7 4/16/14 3:24 PM
8 CAIRN INDIA LIMITED
Building energy security
Energy is a fundamental requirement for economic
development. Therefore, energy security is even more
important in the developing world than it is in developed
countries.
India, one of the fastest-growing large
economies, needs energy supplies to fuel
its growth. As of early 2014, the republic
imports approximately 80 percent of its oil
needs. Without new and substantial do-
mestic discoveries, imports are projected
to increase to 90 percent by 2030. This
represents a significant transfer of wealth
from India to the oil exporting nations.
“India is spending approximately $140
billion annually importing oil,” said Sunil
Bohra, Cairn’s Deputy CFO. “It has been
one of the biggest factors contributing to
current account deficit. The Government of
India, cognizant of the matter, has initiated
several steps to promote oil and gas pro-
duction, including regulatory changes.”
Regulatory changes
spur development
“Regulatory changes, such as the roll out of
policy enabling oil exploration in Develop-
ment Areas in February 2013 and transpar-
ent gas pricing policy which will be effec-
tive from April 2014, are likely to encourage
more investments in hydrocarbon explora-
tion and development, including develop-
ing assets that were uneconomical earlier,”
Bohra continued.
“With access to adequate funds, Cairn is
well positioned to finance the next phase
of exploration and development through in-
ternal accruals. With planned spend of over
US$3 billion by fiscal year 2016, along with
probable capital expenditure required for
developing our new discoveries, we look
forward to encouraging partnership with
our existing and prospective suppliers.”
Cairn’s Senior Manager of Corporate
Communi cations Chirag Shah said, “We
have been engaging more effectively with
the Government of India through industry
associations in India. Industry associations
like the Association of Oil & Gas Operators,
the Confederation of Indian Industries
and the Federation of Indian Chambers of
Commerce and Industry engage in focused
consultations with the Indian government.”
Cairn made the largest onshore discov-
ery in the world in 2004 at the world-class
“Cairn is well positioned to be the customer of choice
for oil field service companies who want to enter
India. With its proven track record, large capital expenditure
plans and willingness to adopt new technology, Cairn offers
exciting opportunities.” — T.K. Venkatesan, Director of
Procurement and Supply Chain Management
1405CP_CairnIndia_8 8 4/16/14 3:24 PM
Rajasthan - RJ-ON-90/1
Ravva - PKGM-1
PR-OSN-2004/1
KG-ONN-2003/1
KG-OSN-2009/3
MB-DWN-2009/1
Sri Lanka SL-2007-01-001
Cambay Basin - CB/OS-2
I N D I A
South Africa Block-1
S O U T H
A F R I C A
46.55%
28.28%
3.4%
3.21%
2.45%
2.24%
1.96%
ONGC
RIL
BHP Billiton
HOEC
Cairn
Santos
OIL
80.58%
7.49%
5.72%
4.08%
0.59%
0.29%
0.27%
ONGC
OIL
Cairn
BG-RIL-ONGC
RIL
SELAN
FOCUS
58%
9%
~30%
~3%
ONGC
OIL
Cairn
Other private
players
44%
22%
22%
12%
Exploration initiated
Moderate to
well explored
Poorly explored
Unexplored
Source: Hydrocarbon Exploration and Production Activities,
India 2011-12 & 2012-13, Directorate General of Hydrocarbons
*MoPNG petroleum production statistics,
December 2013
India’s
exploration status
Distribution of
petroleum exploration
license areas under
operation in India
Distribution of
mining lease areas
under operation
in India
India crude oil
production pie*
Portfolio of assets
11.91% Others 0.98% Others
CAIRN INDIA LIMITED 9
Mangala field in Rajasthan, with commer-
cial production beginning in August 2009.
‘Creating more Cairns’
“We firmly believe that Cairn India’s success
has laid the foundation for more ‘Cairns’ to
come into India. There’s a huge potential
here and we need more E&P players,” said
Dr. Sunil Bharati, Chief Technology Officer.
Suniti Bhat, Head of the Rajasthan Asset,
concurred: “The pie we offer at Cairn is
very large; there’s a big pile of work to
come. We’re fully funded, with board align-
ment, policies in place, full ownership of
India’s largest basin, and the top people.
Now we need vendors and partners who
can bring us the technological edge rather
than the cheapest solution.”
1405CP_CairnIndia_9 9 4/16/14 3:24 PM
1405CP_CairnIndia_10 10 4/16/14 3:24 PM
CONTRIBUTION TO
THE GOVERNMENT
◆ Total contribution for fiscal
year 2013 was US$3.6 billion.
Contributed approximately
US$2.3 billion in Royalty, Cess,
Direct taxes & Value Added
Taxes (VAT) and US$1.3 billion
as Profit Petroleum to the Indian
government.
◆ Approximate 800 percent net in-
crease in the contribution during
the last four years.
◆ Approximately 75 percent
of the government's Profit
Petroleum revenue comes from
Cairn-operated assets.
FY
Gross contribution
(USD, Billions)
2013 2012 2011 2010
1
2
3
1405CP_CairnIndia_11 11 4/16/14 3:24 PM
Dr. Sunil Bharati,
Chief Technology Officer
12 CAIRN INDIA LIMITED
Mangala: From sand to oil
For centuries the enormous, inhospi-
table Thar Desert of northwestern India
has been home mostly to shepherds
and farmers. Rajasthan, the largest
state in the Republic of India, includes
this famous desert—also known as the
Great Indian Desert—as well as one
of the world’s oldest mountain ranges,
the Aravalli Range. Archaeological ru-
ins here, dating from the ancient Indus
Valley civilization, are the oldest in the
Indian subcontinent.
Initial exploration by Shell
In the early 1990s, this arid, thinly popu-
lated landscape attracted the attention of
Royal Dutch Shell. In a production sharing
contract with the Indian national oil compa-
ny, Oil & Natural Gas Corp. Ltd., Shell ex-
plored the area, conducting seismic stud-
ies and drilling a well in 1998.
Cairn farmed into the block and took over
the operatorship after obtaining 100 per-
cent of the license. After analyzing the
initial logs, Cairn had a deep faith in the
basin’s geology and reservoirs so they per-
sisted with drilling exploration wells and
eventually made a landmark discovery.
It took tenacity, but the effort paid off—big
time. After drilling 13 wells, the 14th well in-
tersected a total oil column of 320 meters.
Cairn had discovered a major reser-
voir, and named the field “Mangala” for
the Hindi word that means “auspicious.”
Mangala was the largest onshore discov-
ery in the world in 2004.
The world-class Mangala field
“Mangala was a company maker,” said
Apurba Saha, Cairn’s Head of Mature
Assets. Mangala was the largest on-
shore hydrocarbon discovery in India in
more than 20 years. This find was fol-
lowed by Bhagyam and Aishwariya.
Over the years, Cairn India’s Rajasthan
block has seen a total of 28 hydrocarbon
discoveries.
1405CP_CairnIndia_12 12 4/16/14 3:24 PM
BUILDING A COMMUNITY INFRASTRUCTURE
When Cairn first entered the
Barmer district in the state of
Rajasthan, there were only two
hotels with a total of 18–20 rooms,
and neither had a restaurant. If
Cairn was going to erect a pro-
cessing terminal, one of the first
tasks at hand was to find suitable
food and shelter for thousands of
workers.
Initially, Cairn staff and con-
tractors had to take turns sleep-
ing in the available beds and ate
the same breakfast every day for
many months. Cairn had to make
a tent shed to cover the terrace
and transform it into a makeshift
kitchen for cooking breakfasts
and packing the workers’ lunches.
Today, the same business entity
is a 320-room hotel with a bar and
two restaurants, a banquet hall for
the local community and a bunker
yard that can house 120 more peo-
ple. Cairn’s presence transformed
the local infrastructure, and the
hotel is just one example.
Another is cell phones. “When we
arrived, there wasn’t a single shop
to sell and repair mobile phones.
Now there are 20, and they are not
dependent on Cairn.
“A whole new set of businesses
has mushroomed in the area, im-
proving its economy dramatical-
ly,” Dr. Bharati said with some
pride. “There are two bakeries,
even though the local people
don’t eat bakery bread. There are
taxis, buses, services of all sorts,
and hospitality businesses. And
the petroleum Cairn is produc-
ing there is contributing US$1 bil-
lion per annum to the state gov-
ernment.”
1405CP_CairnIndia_13 13 4/16/14 3:24 PM
14 CAIRN INDIA LIMITED
Black gold flows across the desert
Cairn’s discovery of the world-class Mangala field in 2004
was a “company maker,” in the words of Apurba Saha.
Output from the Rajasthan fields con-
tribute significantly to India’s total do-
mestic crude oil production. Today, it
accounts for close to 25 percent of the
country’s domestic crude production.
The Rajasthan block has already pro-
duced more than 200 million barrels of
hydrocarbons.
But it was never an easy task. The quality of
the oil was challenging; it had a high pour
point. At ambient temperature it was like a
black candle—an oil that did not flow.
Getting the waxy crude out of the ground
was challenge enough, requiring the use of
hot-water injection from the outset. Cairn
also faced the challenge of how to get the
waxy crude to market. The nearest refin-
eries were hundreds of miles away—and
Cairn had no infrastructure.
For the first few months, Cairn delivered
the oil by tanker to the nearest refineries.
However, this was not sustainable once
production increased dramatically.
Cairn looked at all the options, includ-
ing rail and tankers, and finally decided to
build the longest continuously heated pipe-
line in the world using SEHMS technology.
No, Cairn was not in the transportation
business. But someone had to do it. Cairn
was simply more aggressive in identifying
what would work at an optimum cost and
at choosing the right vendors.
The majority of the 391-mile (630-kilo-
meter), 24-inch pipeline was completed
in just 18 months, passing through two
states, more than 270 villages and 700
crossings—after negotiations with 45,000
landowners.
The immense project addressed three ma-
jor challenges:
◆ How to keep the crude continuously
heated.
◆ How to minimize disruptions to agri-
culture, commerce and the environ-
ment along its 391-mile (630-kilome-
ter) route.
◆ How to design the shortest possible, yet
still strategic route to buyers.
Skin Effect Heat Management System (SEHMS) technology is traditionally used
for short, above-ground applications. Many innovations were required to apply
this technology to an underground, cross-country pipeline system. The crude-oil
pipeline is insulated with 90-millimeter polyurethane foam to arrest the heat loss
from the pipeline to the surrounding soil. It is further enclosed with a 5-millimeter
high-density polyethylene jacket for protection and to make it watertight. Thirty-six
above-ground heating stations with maximum 1 megawatt power-generating units
are installed at approximately 12-mile intervals along the pipeline route. In addition,
two intermediary terminals are installed along the pipeline route. The primary ener-
gy source is gas from Cairn’s Raageshwari field in Rajasthan.
1405CP_CairnIndia_14 14 4/16/14 3:24 PM
CAIRN INDIA LIMITED 15
Making the sluggish oil flow
The crude had to be heated from 109°F
to 149°F (the wax appearance tem-
perature). Engineers considered sever-
al methods, and, in 2007, devised the fi-
nal concept. The 24-inch crude pipeline is
paralleled by an 8-inch natural gas pipeline
that feeds gas to create electricity at 36
above-ground installations. These 1-mega-
watt heating stations were constructed
approximately every 12 miles (20 kilome-
ters) along the pipeline’s length.
The Skin Effect Heat Management System
keeps the crude heated and moving
through the length of the pipeline for deliv-
ery at the Gujarat coast and on to the con-
tracted buyers.
Minimizing disruptions
The pipeline route was selected to min-
imize disturbance to the environment,
human habitations, forests and aquat-
ic bodies—and to avoid sanctuaries, ar-
chaeological monuments and other sensi-
tive locations. The route also avoids mining
areas, rugged and intricate terrain, built-up
areas, places of worship, and slopes.
Environmental- and social-impact studies
assessed and addressed the needs of the
communities affected by the project, and
outlined a comprehensive and sustainable
plan of engagement with each of them.
Once construction of the pipeline was
complete, the land was restored and re-
turned to its owners—primarily farmers
and shepherds.
CAIRN’S PROVEN TRACK RECORD
Exploration
◆ More than 40 discoveries to date:
– Success rate of 50 percent or better.
– Responsible for four of eight significant discover-
ies in India since 2000.
– Discovered Mangala: the largest onshore discov-
ery worldwide in 2004.
– Made the first-ever discovery in Sri Lanka in 2011.
◆ Opened four new frontier basins:
– Onshore Barmer.
– Deepwater Krishna Godavari.
– Offshore Cambay.
– Deepwater Sri Lanka.
◆ Diverse operating environments:
– Onshore.
– Transitional.
– Offshore deep water.
◆ Established gross proved and probable reserves
and resources of more than 1 billion barrels of oil
equivalent as per SPE assessment.
Production
◆ The Rajasthan block has seen gross development
capital expenditures of more than US$4 billion.
◆ Fast-track development:
– Rajasthan: discovery to production in five
years, field direct opex of approximately $3/bbl.
– Cambay: Lakshmi field achieved discovery to pro-
duction in 28 months; Gauri field brought online in
the following 16 months.
– Ravva redevelopment: tenfold production ramp-
up—from 3,000 to 35,000 bopd in 26 months.
◆ Low-cost operator, ranking in the top quartile
among global peers.
PIPELINE
STATISTICS
◆ Engaged more than 6,000
workers.
◆ Completed 22 million man-
hours with no lost-time in-
juries.
◆ More than 700 crossings of
various types, including 34
major rivers, 38 canals and
numerous highways, rail-
ways, etc.
1405CP_CairnIndia_15 15 4/16/14 3:24 PM
16 CAIRN INDIA LIMITED
Pioneering initiatives in technology application
◆ Cairn built the world’s longest continu-
ously heated and insulated pipeline.
◆ Cairn plans to deploy enhanced oil re-
covery in the early stages of field life.
◆ Cairn first in India to apply micro-seismic
hydrofrac monitoring technology.
Drilling services
◆ Largest offshore horizontal well in India.
◆ First in India to drill with casing tech-
nology offshore—and set the record for
deepest 20-inch casing drilling.
◆ First to deploy rotary-steerable assem-
blies for extended-reach drilling (ERD)
in the Indian offshore—and drilled the
first ERD well in shallow, unconsolidat-
ed formations.
◆ First in India to execute rotary-steerable
assemblies onshore.
◆ First in India to use synthetic-based
mud in a land project.
◆ Introduced lightweight cement slur-
ries and jetting of surface conductors in
deep water.
◆ Application of well-pad-based drilling—
up to 20 wells per pad.
◆ Deployment of custom-built, highly mo-
bile rigs.
Well services
◆ First in Southeast Asia to use coiled-
tubing catenary.
◆ First in India to use E-line-based tractor
operations for conveyance in high-an-
gle, extended-reach offshore wells.
◆ First in India offshore to retrofit sand
screens through tubing on inflatable
plugs—without using a rig.
“Technology drives our work because it drives down
the cost of ownership. Many of the firsts in oil and gas
technology were brought to India by Cairn.”—Suniti Bhat,
Director Rajasthan Asset
◆ Thin sands in Cambay
◆ Tight reservoir
◆ Opportunity to increase
recovery
◆ High-pour-point crude
(Challenge was to keep the
crude at or above 65°C)
◆ Opportunity to improve
efficiency in rig moves/
footprint
◆ Pipeline capacity constraints
◆ Spectral decomposition
◆ Fracking and horizontal wells
◆ EOR
◆ Heated pipeline
◆ Highly-mobile rigs
◆ Multi-well pad drilling
◆ Optimal equipment design
◆ Drag reducing agent
Challenges/Opportunities Technology Solutions
Successful Application of Technology to Overcome Challenges
Exploring & exploiting
challenging reservoirs
Flow assurance
Reduce drilling
impact and cost
Infrastructure capacity
1405CP_CairnIndia_16 16 4/16/14 3:24 PM
CAIRN INDIA LIMITED 17
◆ First in India to straddle stimulation
technology through a tele-coil for pro-
duction and injection wells.
◆ First to use straddle-packer technology
to stimulate a 2,800-meter horizontal
well in a single intervention.
◆ First in India to use mechanical straddle
packers to achieve conformance in EOR
wells and initiate polymer injection.
◆ First Indian coiled-tubing operation from
an offshore platform without the use of
a dedicated vessel.
Well completion
◆ First in India to conduct under-balanced
perforation using tubing-conveyed per-
forating (TCP) guns.
◆ First in the world to install an expand-
able sand screen.
◆ First in India to use a new wellhead de-
sign for hot-water circulation and artifi-
cial lift.
◆ First in India to deploy inflow-con-
trol devices in deviated and extended-
reach wells.
◆ First in India to use a sand-control
screen with integral Sliding Sleeve
Design (SSD).
◆ First in India to use state-of-the-art pro-
gressive-cavity pumps with capacities
as high as 4,000 bopd.
◆ First in India to use state-of-the-art,
high-rate, electric submersible pumps
on a large scale.
◆ First in India to install high-rate jet
pumps in circulation.
◆ First in India to use SSDs for artificial lift.
1405CP_CairnIndia_17 17 4/16/14 3:25 PM
18 CAIRN INDIA LIMITED
Enhanced oil recovery (EOR) in Rajasthan
Intensive program is among the world’s largest.
The Rajasthan block is producing approxi-
mately 186,000 boepd—a production rate
that Cairn has been maintaining with infill
drilling and water injection. To support pro-
duction in the long term and enhance re-
covery, Cairn adopted field-wide enhanced
oil recovery (EOR). The polymer EOR flood
for Mangala field will commence in Q4 of
fiscal year 2015.
Cairn’s experts believe the EOR potential
from the Mangala, Bhagyam and Aishwariya
fields in Rajasthan is an additional 12 to 14
percent. This is due to better sweep and dis-
placement efficiency, abetted by plateau ex-
tensions and enhancements that will mo-
bilize more oil. Cairn India has initiated the
Mangala Polymer Flood, one of the largest
EOR programs in the world, to increase ulti-
mate recovery and support production.
Calling on the experts
With input and advice from global ex-
perts, Cairn has designed its EOR program,
which will use polymer flooding to push the
oil out of the ground.
Owing to the viscosity of the oil, EOR is the
key for Cairn. EOR increases recovery from
current levels and helps ensure sustained
production. Each percentage increment
in production translates to more money
from the operation. Cairn engineers have
worked closely with global experts in EOR,
as well as with major oil field service com-
panies and universities around the globe.
“We have been waterflooding Mangala since
the beginning of production; we have pilot-
ed polymer flooding; and now we are imple-
menting polymer flooding at full scale,” said
Brennan S. Punnapully, General Manager
of EOR Development. “Ours is the second
largest polymer flood in the world—second
only to the Chinese. And theirs is in multiple
fields; ours is the largest single field.”
Upon completion, the Mangala EOR project
will hold the record for the largest ever in a
single field.
One of the world’s
largest EOR projects
“EOR is a good example of our initiatives to
look for outsourcing partners who can bring
broader competencies into our system,” said
P. Elango, CEO. “We retain our own core geo-
technical skills at Cairn. But we want to part-
ner with people whose core expertise is dif-
ferent from ours—in EOR, for example.
“We are embarking on one of the world’s
largest EOR projects, buying huge amounts
of chemicals,” Elango continued. “We need
more than one major supplier just to meet
our requirements.”
The EOR project not only calls for assem-
bling humungous quantities of polymers,
but also throws several challenges in its
handling and movement. Cairn is actively
exploring various models of operation and
maintenance of the central polymer facility
including outsourcing. Cairn believes that
there is an opportunity for alliances to be
developed in the longer term as EOR ex-
tends from Mangala to other fields.
1405CP_CairnIndia_18 18 4/16/14 3:25 PM
CHANGING MINDSETS
Cairn's accomplishments are even
more impressive in light of living con-
ditions in the Thar Desert, which
overlies the rich Rajasthan basin.
“Here, we faced not only the techni-
cal challenge of getting the oil out of
the ground, but also the challenge
of mobilizing 12,000 people in one
of the most backward districts of
India,” Hari Kumar, Director HSEQ &
Security commented.
In the agrarian economy of the Thar
Desert, available workers wear large
turbans and go barefoot. They resist-
ed Cairn’s requirement of wearing
hard hats and safety shoes.
This was a shock for Cairn, but the
safety issue had to be addressed. So
Cairn engaged local NGOs (non-gov-
ernmental organizations), teachers
and schoolchildren to present skits to
change the safety mind set. To reach
out to unlettered and semi-liter-
ate audiences, Cairn used visuals to
stress the importance of hard hats,
safety shoes and gloves. Cairn orga-
nized puppet shows, songs and danc-
es by children, entertainment and
snacks to get the message across.
“We couldn’t get thousands of peo-
ple into a classroom, so we presented
road shows of about half an hour in
each of 220 villages in the Rajasthan
area and along our pipeline, reach-
ing 800 to 1,000 people each day. We
changed the subjects monthly—from
road safety to electrical safety to per-
sonal protective equipment. We were
able to increase safety compliance
from 20 percent to fully 100 percent
in just one year. And the road shows
continue today.”
To promote pipeline safety, Cairn
gave subscriber-identity module
(SIM) cards to the 10,000 farmers
through whose fields the pipeline
passed. The farmers, almost all of
whom carry cell phones, were happy
to receive the cards, which provide
market information for their crops.
“We loaded an emergency number
on each phone and asked the farm-
ers to report in case of an emergen-
cy.” said Kumar.
To construct the Rajasthan facilities,
Cairn trained 65,000 people in two
years. Today, most of them have gone
back to farming, although some have
become entrepreneurs in the new
economy that Cairn has created. And
all of them can now work at construc-
tion jobs on short notice. Today, 3,000
people continue to work at Cairn’s lo-
cal facilities.
1405CP_CairnIndia_19 19 4/16/14 3:25 PM
Saline water
abstraction
Export
oil storage
Gas recovery system
T
h
u
m
b
li
S
a
lin
e
A
q
u
if
e
r
B
a
r
m
e
r
H
ill
F
a
t
e
h
g
a
r
h
Oil
Fuel gas
distribution system
Export
pipeline
Water
injector
Heat
Vertical
well
Horizontal
well
Separator + heat
Initial
Original oil
Sand grain
After waterfood
Oil saturation display at pore level
Reduction in trapped oil
After ASP food
Remaining oil
Water
20 CAIRN INDIA LIMITED
Alkaline-surfactant-polymer (ASP) flooding
Cairn’s reservoir team believes that al-
kaline-surfactant-polymer (ASP) flood-
ing can further increase recovery from
the Mangala field, and Cairn is present-
ly piloting an ASP flooding program. If
it’s successful, Cairn will implement it
across the entire field. The ASP phase of
the enhanced oil recovery (EOR) involves
the use of alkali, surfactant and polymer.
The alkali and surfactants alter the sur-
face tension of the oil making it more mo-
bile and enhancing recovery. ASP flooding
is a relatively new technology, which of-
fers the potential for higher recovery than
polymer flooding. ASP flooding requires a
large volume of chemicals, which makes
logistics and operations very challenging.
Alkaline-Surfactant-Polymer (ASP) Flood Improved displacement efficiency.
1405CP_CairnIndia_20 20 4/16/14 3:25 PM
GIVING BACK
How best to give back to society is
the classic question faced by explo-
ration and production companies
worldwide. Whatever the answer,
it always includes an acknowledge-
ment by the oil companies that they
accept certain responsibilities to
the affected community and to the
nation.
Cairn’s perspective is that it doesn’t
just operate in a community; it fuels
the amazing within it. Cairn’s social
contributions are many and varied.
Through its inclusive growth ap-
proach, Cairn India has been able to
benefit approximately 500,000 com-
munity members through various
community-development initiatives.
These are just a few highlights:
Education
◆ Close to 100 rural libraries are be-
ing set up, educating more than
20,000 students across Rajasthan
and Gujarat.
◆ Cairn India, through different ed-
ucational initiatives, has worked
with 160 government schools and
assisted some 50,000 students.
Healthcare
◆ A mobile hospital that offers free
healthcare to 7,500 people every
month (serving more than 1 mil-
lion people to date).
Woman empowerment
◆ More than 10,000 Rajasthan com-
munity members, of which 80
percent are women, have suc-
cessfully engaged in a dairy-de-
velopment initiative that has
yielded average daily milk produc-
tion of more than 1,300 gallons
and, to date, has generated more
than US$1 million for local com-
munities.
Economic development
◆ An enterprise center that has
trained 8,000 people in language
and technical skills so they can
operate their own sustainable
businesses.
Nature
◆ Cairn rerouted the world’s lon-
gest heated pipeline so as not
to disturb India’s first marine
sanctuary.
Cairn’s five-year goals in Rajasthan,
its largest operating area, are:
Health
◆ Access to quality primary and
secondary care by the entire pop-
ulation of 2.6 million.
◆ Availability of safe drinking water
to all.
◆ 40 percent improvement in overall
health indicators.
Livelihood/income
enhancement
◆ Improved productivity of local
workforce through training and
local employment (more than
7,000 people gainfully employed).
◆ Enhanced incomes, through pro-
ductivity improvement (farming
and livestock), for one-fifth of the
75,000 households in the area.
◆ Increased green cover and water
conservation area wide.
Education
◆ Increased student enrollment, es-
pecially of girls (30 percent).
◆ Improved student retention
through grade 12 (70 percent).
◆ Improved academic perfor-
mance, especially in Science,
Mathematics and English (20 per-
cent annual improvement).
Infrastructure
◆ Complement government pro-
grams to create community
assets.
◆ Partner with government to ad-
dress local infrastructure devel-
opment.
1405CP_CairnIndia_21 21 4/16/14 3:25 PM
Hari Kumar,
Director–HSEQ & Security
22 CAIRN INDIA LIMITED
Recognized excellence in HSE
How did an independent exploration and production company
in India become one of the top five global E&P companies
in HSE (health, safety and environmental) performance?
One day at a time. Not to mention attention
from P. Elango who said, “Safety is No. 1
for Cairn India. We expect our partners to
adopt our high standards, and we will like-
wise adopt theirs.”
As a result, Cairn India has achieved an
impressive safety record, especially in a
developing country:
◆ The company’s largest operation, in the
Rajasthan block and beyond (including
an approximately 391-mile {630-kilo-
meter} pipeline), accrued 28.2 million
hours in fiscal year 2013 without a lost-
time injury.
◆ Its Rajasthan facilities and well up-
time stood at 97.7 percent during fis-
cal 2013 and figured in the top decile
among its global peers.
◆ Its major operations, at Rajasthan,
Cambay and Ravva, meet ISO 14001:
2004 standards.
◆ Cambay and Ravva also meet OHSAS
18001: 2007.
◆ Cairn India won the 2012 Platinum
Award for Safety Excellence for its Ravva
operations from the Federation of Indian
Chambers of Commerce and Industry.
“Our vision on HSEQ is pretty clear: No
Harm to People or the Environment. With
an ever expanding footprint in our areas of
operation, it is increasingly important that
we understand the risks we are exposed to
and proactively eliminate or mitigate them
to levels as low as reasonably practicable.
What this means is that we build and nur-
ture a robust safety culture in which ev-
eryone demonstrates care for self and be
a protector of others,” said Hari Kumar.
“We set off on this journey to improve our
HSE performance by establishing transpar-
ent systems and adopting good industry
standards. Our young leaders across as-
sets and in corporate teams have imple-
mented very innovative concepts to raise
the awareness of our work force and that
of our partners, be it vendors, contractors
or other service providers. As one of the
fastest growing energy companies in the
world, we also face the challenge of cre-
ating value for the stakeholders and energy
for the countries in which we operate. This
calls for maximizing our operating assets
availability by ensuring asset integrity and
process safety. Hence our current focus
is on these critical areas and on minimiz-
ing the Green House Gas (GHG) emissions.
Everyone of us at Cairn is proud of our
achievements in HSE and I firmly believe
we are on the right track. But being an oil
and gas company, we can not drop our
guard and we move carefully in our journey
one step at a time,” concludes Hari.
◆ Cairn’s Raageshwari Oil Mine was the Runners-up at the pres-
tigious National Safety Award (Mines) for the year 2010 for the
Lowest Injury Frequency Rate per lakh Man Shifts in Oil Mines
Category
◆ The Offshore Ravva Field selected Winners of Oil Industry Safety
Awards for the Year 2010-11 under offshore production platforms
category
◆ Cairn won the prestigious ‘Oil Industry Safety Directorate (OISD)’
Safety Award for the Year 2011-12 under ‘Cross Country - Crude Oil
Pipeline’ category
◆ Cairn won sixteen awards at the 26th Mines Safety Week 2012 in
Rajasthan
1405CP_CairnIndia_22 22 4/16/14 3:25 PM
ECONOMIC,
ENVIRONMENTAL
AND SOCIAL
SUSTAINABILITY
“We are building an organization that will
lead the path of growth through safe and
sustainable practices and will emerge as
an inspiration for individuals and organi-
zations,” wrote P. Elango in Cairn India’s
first sustainability report in 2012-13.
The report, available under the sustain-
ability section on the Cairn India website,
describes the company’s policies, goals
and initiatives in economic, environmen-
tal and social sustainability.
1405CP_CairnIndia_23 23 4/16/14 3:25 PM
24 CAIRN INDIA LIMITED
An oil company that also
explored for water
“To run a good oil and gas company, you
need top expertise in water,” said P. Elango.
And where would you need it more than in
a remote desert?
Rajasthan is a part of the world where
water is valued above any other resource.
Here, women and girls spend the bulk of
their day walking to local water wells and
carrying home water for their households
and livestock. Cairn was determined not
to take a drop from the community. And
yet Cairn needed lots of water for its
operations.
So once oil was discovered the immedi-
ate priority was to find water. During ini-
tial construction of Cairn facilities, Cairn
used the least quantity of water that it
could, buying it from the local villagers.
And then Cairn had to drill to meet its wa-
ter requirement.
Brennan S. Punnapully said, “In our en-
deavor to find water for our operations,
we also mapped freshwater availability in
the Rajasthan block and surrounding ar-
eas, which helps the entire community.
“Cairn conducted extensive tests to en-
sure that the withdrawal quantity would
not effect the freshwater supplies.” he
noted. “Extensive tests were done to
prove the aquifer size and to demonstrate
that at Cairn’s forecasted withdrawal rate,
the aquifer depletion will neither impact
the freshwater sources nor deplete the
aquifer significantly.”
The aquifer water is saline and needs to
be treated prior to use. The water is heated
and circulated throughout the surface fa-
cilities and is used as injection water.
“By 2015, the Mangala processing plant
will be processing more than 800,000
barrels of water per day. In fact, the wa-
ter-processing plant will be a major com-
ponent in the overall Mangala processing
plant.” said Punnapully. “It is a great op-
portunity for water treatment professionals
and suppliers who can support our chal-
lenging water treatment needs.
“And, as our use of water increases, so
does our need for chemicals. This is an in-
teresting opportunity for the water treat-
ment chemical suppliers, who can provide
antiscalants, corrosion inhibitors, clarifies,
demulsifiers etc.”
“In Rajasthan, we will eventually reach 1.2 million barrels
of total fluids, which means a huge increase in water
treatment. That’s Cairn’s water challenge, and we’re looking for help
with it.”—Brennan S. Punnapully, General Manager of EOR
Development
1405CP_CairnIndia_24 24 4/16/14 3:25 PM
SAFE DRINKING WATER
FOR LOCAL VILLAGES
Among the social responsibilities that Cairn India has undertaken in
Rajasthan is a commitment to supplying safe drinking water to peo-
ple who have never been able to count on it.
“With a vision of providing accessible safe drinking water for all, we
have begun a unique, community-based project. The local water-
works supplies the raw water, Cairn supplies equipment and village
water committees distribute the water. Currently, this project pro-
vides clean drinking water to more than 10,000 villagers, and we plan
to scale it up in the near future,” said Nilesh Jain, Head of Corporate
Social Responsibility.
1405CP_CairnIndia_25 25 4/16/14 3:25 PM
26 CAIRN INDIA LIMITED
The Barmer Basin development
A major hydrocarbon province.
With the Mangala discovery in 2004, Cairn
established the Barmer basin of Rajasthan
as a major new hydrocarbon province.
The Rajasthan block consists of more than
20 separate oil and gas fields. The majority
of the reserves are found in the Mangala,
Bhagyam and Aishwariya fields—with
gross ultimate oil recovery of more than
1 billion barrels.
The giant Barmer basin currently accounts
for almost 25 percent of India’s domestic
crude production—and promises to pow-
er India’s burgeoning oil industry until at
least 2030.
Massive potential
“The potential is huge—and it’s happening
now. At the end of 2013, we had six land
rigs in Rajasthan. By April 2014, we’ll have
12. By 2016, we’ll have 20 plus,” said T.K.
Venkatesan, Director of Procurement and
Supply Chain Management.
Cairn is targeting 530 mmboe of gross re-
coverable risked prospective resources
from Rajasthan. Cairn plans to drill half of
its gross prospective risked resource base
by the end of fiscal year 2014. By fiscal
year 2016, Cairn will drill 100 exploration
and appraisal wells in Rajasthan—and
more than 350 development wells.
“It’s a quantum change for Cairn—and we
need solution providers,” Venkatesan as-
serted. “We’ll be spending US$3 billion by
fiscal year 2016—for rigs, fracturing, drill-
ing, enhanced oil recovery and more. We
want to work with the best-in-class service
providers from around the world.”
BARMER BASIN
PROJECT TIMELINE
1997/1998 Cairn enters pro-
duction-sharing contract.
2004 Well #14: Mangala
dis covery.
2009 Mangala first oil.
2010 Approximately 370
miles (600 kilometers) of
the 391-mile (630-kilome-
ter) pipeline complete and
operational.
2011 Producing 125 kbopd
2012 Bhagyam first oil.
2013 Aishwariya first oil.
2016 Plans to complete
100 exploration and apprais-
al wells and 350 development
wells.
1405CP_CairnIndia_26 26 4/16/14 3:25 PM
N-P
KAAMESHWARI WEST-6 GAS
KAAMESHWARI WEST-3 GAS
KAAMESHWARI WEST-2 OIL
RAAGESHWARI - S-1
N-I
MANGALA
N-E
BHAGYAM
N-I-NORTH
SHAKTI
SHAKTINE
NC WEST OIL & GAS
BHAGYAM SOUTH
MANGALA BARMER HILL
AISHWARIYA
VANDANA
VIJAYA
GS-V
SARASWATI CREST
SARASWATI
KAAMESHWARI
RAAGESHWARI OIL
SHAHEED TUKARAM OMBALE
RAAGESHWARI DEEP GAS
GUDA
V2Y CHANNEL
AISHWARIYA BARMER HILL
5 0 10 20
OIL FIELD
GAS FIELD
Oil Discovery
Gas Discovery
Oil Shows
Oil Discovery & Gas Shows
Kilometers
Discoveries in
Rajasthan Block RJ-ON-90/1
DEVELOPMENT AREA 2
Awarded November 2006
DEVELOPMENT AREA 3
Awarded December 2008
DEVELOPMENT AREA 1
Awarded October 2004
CAIRN INDIA LIMITED 27
Director of Operations and Development
Rich Paces added, “There’s tremendous
additional upside potential in Rajasthan—
there’s a huge amount of oil and gas in
place. We’re focused on exploring, de-
veloping and producing these hydrocar-
bons—and increasing the volumes that we
produce. The rewards from optimizing res-
ervoir management and making the most
of infill drilling, waterflooding and polymer
floods are huge. If we increase recovery by
just 1 percent of our approximately 4 bil-
lion boe of HIIP (hydrocarbons initially in
place) in our existing Rajasthan discover-
ies, that’s 40 million boe.
“Not bad. The gas potential of the Barmer
basin is also exciting. As our exploration
program further evaluates the deeper
gas-prone stratigraphic horizons, I’m con-
fident that all stakeholders will see tre-
mendous value associated with develop-
ing a new, domestic source of gas.”
1405CP_CairnIndia_27 27 4/16/14 3:25 PM
28 CAIRN INDIA LIMITED
BARMER HILL FORMATION
The Barmer Hill formation extends across a large area in Barmer basin, and the majority of wells penetrating
this formation have found oil and gas. These are low-permeability, tight reservoirs requiring fracture stimula-
tion and horizontal well completion.
Cairn’s infrastructure is already in place for quick monetization of this resource base. Data analogs indicate
recovery factors of 7 percent to 20 percent. Cairn is on a fast track to prepare development plans for discover-
ies in the area.
1405CP_CairnIndia_28 28 4/16/14 3:25 PM
CAIRN INDIA LIMITED 29
Delving deeper in Rajasthan
Cairn plans to target approximately 100 prospects.
Cairn India has committed US$750 mil-
lion to the pursuit of high-value explora-
tion opportunities in the prolific Rajasthan
province, source of the bulk of its produc-
tion to date. The success of these wells
will write the next growth story for Cairn.
The fi el ds now bei ng expl ored i n
Rajasthan are far smaller than our exist-
ing fields. To successfully monetize them,
we have to look at totally different meth-
ods—fit-for-purpose solutions and ear-
ly-production systems like those we see
used in Texas.
An ambitious,
two-pronged strategy
This target-rich environment includes
approximately 100 prospects represent-
ing 20 play types in a basin with 3.1 bil-
lion barrels of oil equivalent in place.
Cairn estimates the prospective re-
sources at 530 million boe (gross risked
recoverable).
Cairn is using a two-pronged strategy to
address proven-play extensions, as well as
unproven plays. In proven plays, it will first
drill prospects with the largest risked vol-
umes. Then it will revise and reprioritize the
remaining prospects based on its explora-
tion results. In unproven plays, it will de-
risk the play, drilling the lowest-risk pros-
pect first, then revise and reprioritize the
tested play based on drilling results.
Exploration program
To date, Cairn has drilled more than 100
exploration wells. So far:
◆ More than 50 percent of the wells drilled
have found hydrocarbons.
◆ On track to drill out 50 percent of
gross prospective resources in fiscal
year 2014.
◆ In addition, Cairn is acquiring approx-
imately 734 square miles of additional
3-D seismic data to assist in extending
proven plays and de-risking prospects.
“These marginal fields are a predominant part of our
work for the next couple of years. Our explorationists and
geologists tell us there’s a lot to be found over multiple smaller
fields. But our engineers and reservoir guys have to think differently
about them. Making a success of this will require access to
international engineers and others with specialized experience.
It’s a great opportunity for vendors to come and work with us —
not just providing services, but providing solutions.”
—Sivakumar Pothepalli, Asset Manager - Producing
Assets, RJ Operations
1405CP_CairnIndia_29 29 4/16/14 3:25 PM
S.V. Nair, Director of
Strategy and Integration
30 CAIRN INDIA LIMITED
Exploring beyond India’s borders
Sri Lanka, South Africa and onward…
Cairn made its first international foray in
2008—to Sri Lanka, just outside India’s
border, where no well had been drilled
in 30 years. Cairn made two discoveries.
“We’re now working to commercialize what
we have found and then do more,” said
Sharad Goenka, Asset Manager, Cambay.
Sri Lanka was a challenging deepwater
block. Cairn made the bold move of drilling
through the basalt because it was expect-
ing a sedimentary sequence. Cairn drilled
700 meters through the basalt and found
hydrocarbons.
Cairn had a positive experience with the
authorities in Sri Lanka. Thanks to Cairn’s
geoscientists, out of three wells as part
of Phase 1, Cairn made two discoveries.
Cairn is still studying the data in the block,
but the 66 percent success rate up to now
is quite pleasing.
South Africa’s Orange basin
“In 2012 we ventured to the Orange basin
in South Africa,” Bharati said. “We com-
pleted a 3-D seismic survey within a few
months after taking it.” The acquisition of
approximately 1,864 miles of 2-D seismic
data will commence in the fourth quarter of
fiscal year 2014 and will facilitate explora-
tion evaluation in areas not covered by the
2013 3-D seismic survey.
Rich Paces noted, “With regulatory support
from PetroSA, we had a seismic vessel on
site in less than a month after we finalized
the Block 1 farm-in agreement.”
Sharad Goenka said “Now we’re sitting
with US$3 billion on our balance sheet,
and we keep generating more. We’re well
placed to participate in mergers and acqui-
sitions and business development.
“That’s what led us to South Africa, where
we’re ‘wetting our toes’ on the internation-
al frontier. The taxes are attractive there,
and there are lots of areas that need more
exploration.
“We’ve grown in an emerging market like
India, so we’re well placed to manage the
risks in the non-OECD countries in the area.
For now, we’re basically focused on sub-
Saharan Africa and Southeast Asia, which
are manageably close by—in a similar time
zone. And our parent company, Vedanta, has
a footprint in these places as well. We want to
walk first before we run.”
BEST-IN-CLASS VENDORS ARE
CRUCIAL TO OUR GROWTH
Cairn is slowly but surely expanding its activities beyond India. This in-
creases the need for us to find new vendors, contractors, service and
technology providers. “We need best-in-class service providers who
can work with us to deliver our business goals” said S.V. Nair, Director
of Strategy and Integration. “Once we have a contract with a vendor, we
see them as partners, since their performance will determine our suc-
cess. Thereafter, we spend time and energy in building and strength-
ening these relationships. We are a growing company with huge aspi-
rations. To spur that growth, we know that building relationships with
vendors across the globe is inevitable.”
1405CP_CairnIndia_30 30 4/16/14 3:25 PM
CAIRN INDIA LIMITED 31
Drill ship Chikyu during Sri Lanka operations
1405CP_CairnIndia_31 31 4/16/14 3:25 PM
“If we get our requested extensions beyond 2020, there
will be no one better placed than Cairn to look at areas
beyond Rajasthan. We’re the best-positioned to monetize that and
reduce the import burden on India.”—Clifford Lang, Head
of Drilling.
32 CAIRN INDIA LIMITED
Growing through the drill bit
“Before Cairn India’s initial public offer-
ing (IPO) in 2007, the company was worth
half a billion U.S. dollars,” commented
Sharad Goenka. “After the IPO, Cairn was
worth US$6 billion—12 times as much!
That growth was driven by our success at
Rajasthan—and made the markets more
confident in us.”
India is sort of frontierish, with lots of areas
that need more exploration. It is a geogra-
phy that Cairn is well established in and
knows intimately.
Major capital investments
The program is ambitious indeed. After
opening four frontier basins with more than
40 discoveries, Cairn India has proven it-
self and has earned the capital to move
ahead with:
◆ US$1.2 billion to sustain MBA produc-
tion via EOR technology and infill drill-
ing program.
◆ US$450 million to develop additional
producing fields in the Barmer Hill for-
mation and satellite fields of Rajasthan.
◆ US$750 million to pursue high-value ex-
ploration opportunities in Rajasthan.
◆ US$600 million to exploit its diverse
portfolio across India, in Sri Lanka,
South Africa and beyond.
Cairn is on track for a fiscal year 2014
exit production target of more than 225
kboepd. It is focusing its development on
low-permeability reservoirs within Barmer
Hill. (See “The Barmer Basin development,”
page 26.)
Already, Cairn is undertaking an aggressive
exploration and appraisal program to drill
out 50 percent of gross risked prospective
resources by FY 14 in Rajasthan, commer-
cialize the KG-ONN onshore discovery and
drill a high-risk, high-return exploration well
in hitherto uncharted area of its Ravva block.
‘A quantum change
in the company’
“We have had significant growth of 15
to 20 percent a year for the last 15-plus
years,” said B. Ananthakrishnan, Director
of Subsurface. “A lot of the resources are
yet to be discovered or, if discovered, have
yet to be commercialized.
“Our business shows that it will be a huge
step up in number of wells, rigs, facilities,
and contracts. It’s a quantum change in the
company and an opportunity for the exter-
nal world, especially vendors,” he continued.
“As part of the business plan, we have
mapped out the activities required for the
next three years: the number of exploration
wells, the number of development wells,
1405CP_CairnIndia_32 32 4/16/14 3:25 PM
CAIRN INDIA LIMITED 33
the facilities, the land, the capacities, the
rigs. Everything has been defined,” he said.
We have detailed execution and procure-
ment plans that will interest the world’s
vendors. Unlike many other independents,
we can confidently say that we can fund
both ongoing and future exploration.
Marginal Field Development
Any E&P company would be happy to
have a field like Mangala alone, but
now Cairn is moving into many small-
er fields—a basket of 15 to 20 satel-
lite fields that were discovered by Cairn
years ago.
Cairn explorationists and geologists be-
lieve that there is a lot of oil and gas to
be found in these multiple smaller fields.
Development of marginal fields will re-
quire access to international engineers
and vendors who can provide not just ser-
vices, but solutions. Cairn is looking at
specific technologies: enhanced oil recov-
ery, tight-reservoir technology and modu-
larization of facilities for smaller fields. By
2016-17, Cairn could be operating in ex-
cess of twenty rigs.
AN INVESTMENT IN THE
KRISHNA GODAVARI BASIN
Call us optimists.
Just as we did with the massive Mangala discovery in 2004, Cairn
explorationists believed in the potential of the Krishna Godavari
(KG) basin.
“In this case, multiple wells had been drilled in the area earlier and
had been unsuccessful. Cairn took this onshore, greenfield block and
had a different opinion of the potential.” said Nicholas J.P. Whiteley,
Asset Manager for India Exploration.
“We collected new data to understand the deeper reservoir and be-
gan an exploration program of five wells. The fifth well found deep
oil—the Nagayalanka discovery—in 2010. The second exploration well
drilled in phase II also resulted in a light-oil discovery—the largest in
the onshore part of the KG basin.
“Once again, Cairn has been the trailblazer, going deeper, being bold-
er,” Whiteley said.
The block contains 481 mmboe of gross proved and probable hydro-
carbons in place.
“It’s a deep, tight reservoir with high temperatures. It needs special
handling, and it needs fracking. It would have been viewed as non-
commercial years ago, but Cairn used its knowledge of fracking in
Rajasthan to work on these reservoirs and get something out of them.
“Cairn has built a new production center for it—and the additional op-
portunities its explorationists envision in the block and in and around
the field,” Whiteley added.
1405CP_CairnIndia_33 33 4/16/14 3:25 PM
“Cairn India is the fastest growing E&P company in the world, according to Platts
Top 250 Global Energy Company Rankings for 2013 (and 2012). The company has seen
strong revenues and profits driven by lowest quartile operating costs. And company planners
have set objectives for a 12 to 15 percent annualized growth rate. It’s an aggressive plan that
requires reliable technology partners and enhanced supplier engagements across the
business.”—Sudhir Mathur, Chief Financial Officer.
34 CAIRN INDIA LIMITED
An attractive proposition for
the world’s community of vendors
Procurement and supply chain have their
roots in the days of barter trading, and they
continue to evolve as businesses around
the world strive to find the optimal pro-
curement solution with respect to speed,
price and technology. In the ever-chang-
ing world of commodities and technology
breakthroughs, upsteam oil and gas com-
panies must constantly reevaluate their
purchasing strategies to gain the benefits
of a robust Procurement and Supply Chain
Management (PSCM) effort.
It is not an exaggeration to say that PSCM
itself has moved far beyond a strictly tacti-
cal approach. While the main objective of
acquiring a product or service at the lowest
possible cost has not changed much, the
approach, scale and surrounding ecosys-
tem have evolved. Cairn understands that
the primary objective of supply chain man-
agement is the efficient integration of sup-
pliers, factories, warehouses and stores so
that merchandise is produced in the right
quantities and distributed to the right loca-
tions at the right time, all while minimiz-
ing total system cost and satisfying service
requirements.
At Cairn the PSCM team drives efforts to
ensure that value is fully realized in all pro-
curement transactions. Over the last de-
cade, we have scaled up from spending a
few million dollars with a handful of suppli-
ers, to spending more than US$1.7 billion
with close to 5000 active suppliers.
Cairn’s rapidly increasing value and volume
of spending has called for a much more
structured engagement with vendors cover-
ing the life cycle of vendor management. At
Cairn, the PSCM function has initiated steps
to move from a transactional approach to a
strategic approach to meeting its procure-
ment needs. A Vendor Management Team
(VMT) has been set up to manage the sup-
pliers, commodities, services and eventual
outsourcing and to identify, register and on-
board vendors.
“As much as we look for vendors to part-
ner with us in our journey, we also look
for optimal solutions,” said Vasu Devan,
General Manager – Vendor Management.
“PSCM is an important cog in the Cairn
growth machine.
“In 2011 we began hosting annual sup-
plier conferences to reach a wider ven-
dor community,” Devan noted. “The third
edition of the annual supplier confer-
ence was held during March 2014 and
was attended by over four hundred ven-
dor organizations from across the world.
And now we’re planning to add region-
al conferences including more in North
America.Cairn has held road shows and
1405CP_CairnIndia_34 34 4/16/14 3:25 PM
Vasu Devan, General
Manager – Vendor
Management
CAIRN INDIA LIMITED 35
conferences for different supplier cat-
egories in the Middle East, Sri Lanka,
North America and India. Our goal is to
increase our vendor base by continuous-
ly engaging with vendors and developing
trusting partnerships to enhance value
for both parties.”
Strategic sourcing and
Supplier relationships
PSCM is identifying commodities and
locking in vendor contracts on a long-
term basis. “These are commodities that
are critical to the operation and account
for high spending in value and volume,”
Devan said. “Cairn is looking to outsource
the activities that are not core to the busi-
ness of exploration and production.
“We’ll be looking at partners for these
businesses, and we have a process for
registering and onboarding vendors,”
Devan continued.
The VMT within PSCM connects the busi-
ness of Cairn to the wide world of oil field
WHAT ATTRACTS PEOPLE TO CAIRN?
‘We’re poised for a turbocharge.’
Cairn’s success at developing the Rajasthan field in a short time, at
extracting very viscous oil and transporting it in the world’s longest
continuously heated pipeline, and at leading EOR deployment for
maximum recovery is attracting ‘the best and the brightest’ to its op-
erations throughout India and beyond.
“Our entrepreneurial culture is extremely attractive to people—
whether they’re Indian nationals who want to come ‘home’ or one of
a dozen other nationalities represented at Cairn,”said Sanjay Singh,
Director of Human Resources and Administration.
“We are poised for a turbocharge, and we are ready to develop the
leaders for tomorrow,” he continued. “We have a new but fairly robust
talent-management process, and we believe in giving people a bigger
experience.
“If you have the aptitude and the right attitude, you will grow here,”
Singh continued. “We love people who can integrate things cross-
functionally—deep specialists as well as integrators. These are the
hotshots for us.”
1405CP_CairnIndia_35 35 4/16/14 3:25 PM
36 CAIRN INDIA LIMITED
services and vendors with its rigorous stra-
tegic sourcing and supplier landscaping
initiatives.
Cairn has also embarked on an en-
hanced engagement program with sup-
pliers drawing the plans for a strategic
association as opposed to a tactical and
transactional business relationship with
the suppliers. Just as we listen to our
shareholders as a part of investor rela-
tions, today Cairn also listens to its sup-
pliers through PSCM and the VMT, offer-
ing a single point of contact for vendors to
communicate with Cairn.
Moving towards global
best practices
Cairn, along with other operating E&P
companies in India, works closely with
the government on policy formulation and
determining ways to increase India’s en-
ergy security.” Cairn closely consults the
state oil company, its Joint Venture part-
ner in all its assets in India, to bring global
best practices to improve procurement ef-
ficiencies,” Devan said.
While least cost procurement is common
in many parts of the world under produc-
tion sharing regimes, Cairn is making ef-
forts to embrace global best practices.
Going forward Cairn is increasingly mov-
ing to evaluating solutions on total cost of
ownership with emphasis on quality. HSEQ
and financial standing continue to be key
criteria for evaluation.
Cairn is held in very high regard by its
stakeholders primarily due to its contribu-
tion to India’s energy security in the last
two decades, its track record in safety, and
its commitment to corporate social respon-
sibility. While Cairn continues to work with
major oil field service companies, it also
encourages the smaller players and new
entrants to partner with it.
1405CP_CairnIndia_36 36 4/16/14 3:25 PM
CAIRN INDIA – FUTURE OUTLOOK
On track to meet the fiscal year exit guidance of over 225,000 boepd
◆ Robust operational performance across all producing assets, supported by infill drilling
◆ Focused on developing and enhancing production from discovered and new fields
◆ Target to enhance ultimate recovery and support production through implementation of Polymer Flood
EOR Program
◆ Encouraged by Raageshwari Deepfield, preparation of revised field development plan for additional gas
related infrastructure spend
Target to book additional reserves and resources by FY14
◆ Accelerated exploration and appraisal activity supported by increased rig count across assets
◆ On track to drill out 50% of gross risked prospective resources in RJ by FY14
◆ To evaluate blocks in NELP–X, building on the Company’s exploration portfolio in India
Continue to deliver accelerated value to stakeholders
CAIRN INDIA LIMITED C37
1405CP_CairnIndia_C3 3 4/16/14 3:23 PM
Cairn India Limited
3rd & 4th Floors, Vipul Plaza, Sun City
Sector 54, Gurgaon 122 002, India
+91 124 459 3000
Follow us:
Twitter - @Cairn_India
LinkedIn - company/cairn-india-ltd
YouTube - cairnindialtd
SlideShare - cairnindia
Contact Cairn PSCM team:
[email protected]
To register as a vendor log on to
www.cairnindia.com/supplier
www.cairnindia.com
About Cairn India
Cairn India is the largest independent oil and gas
exploration and production company in India.
Together with its JV partners, Cairn India operates
approximately one third of India’s domestic crude
oil production. The Company has a world-class re-
source base, with interest in seven blocks in India
and one each in Sri Lanka and South Africa. For
more information, please visit www.cairnindia.com.
About Vedanta Resources plc
Vedanta Resources plc (“Vedanta”) is a London list-
ed, diversified global natural resources major. The
group produces aluminium, copper, zinc, lead, sil-
ver, iron ore, oil & gas and commercial energy.
Vedanta has operations in India, Zambia, Namibia,
South Africa, Ireland, Liberia, Australia and Sri
Lanka. With an empowered talent pool global-
ly, Vedanta places strong emphasis on partnering
with all its stakeholders based on the core values
of entrepreneurship, excellence, trust, inclusive-
ness and growth. For more information, please visit
www.vedantaresources.com.
1405CP_CairnIndia_C4 4 4/16/14 3:23 PM
ORGANIZATIONAL INSIGHTS
Military Friendly Energy
Industry Employers
For t he i ndus t r y ’ s c ar eer - mi nded pr of e s s i onal s SPRING 2014
A suppl ement t o PennWel l publ i c at i ons | www. PennEner g yJ OBS. c om
Bridging the Gap:
Women in Energy
Energy to Serve: Veterans
find new direction in
the energy industry
Attracting and Retaining
Women in Oil and
Gas Engineering
TRAINING INSIGHTS:
1404PEJEW_C1 1 4/21/14 2:20 PM
1404PEJEW_C2 2 4/21/14 2:20 PM
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2 EDITOR’S LETTER
Women and Veterans in Energy
Hilton Price, PennWell
3 Bridging the Gap: Women in Energy
Dorothy Davis Ballard, PennWell
6 Attracting and Retaining Women in
Oil and Gas Engineering
By Neil Tregarthen, NES Global Talent
8 Women in Energy Spotlight: Christi Gell
10 Women in Energy Q&A: Sarah Cridland
12 TRAINING INSIGHTS
Energy to Serve: Veterans find new
direction in the energy industry
Hilton Price, PennWell
16 ORGANIZATIONAL INSIGHTS
Military Friendly Energy Industry Employers
PennEnergy.com
18 INDUSTRY INSIGHTS
Employee Innovations Address Environmental
Concerns of CO2 Storage and Carbon Ash
Dan Patel & Gerry Klemm, Southern Company
w w w . P e n n E n e r g y J O B S . c o m
SPRING 2014
A PENNWELL PUBLI CATI ON
Dorothy Davis Ballard, Content Director
[email protected]
Hilton Price, Editor
[email protected]
Cindy Chamberlin, Art Director
[email protected]
Daniel Greene, Production Manager
[email protected]
Tommie Grigg,
Audience Development Manager
[email protected]

PennWell Corporation
1421 South Sheridan Road
Tulsa, Oklahoma 74112
918 835 3161
PennWell.com
Recruitment Advertising Sales:
Courtney Noonkester
Sales Manager
918 831 9558
[email protected]
Adv er t i s er s’
I ndex Chevron .............................................................................................................. C2
Map search .................................................................................................. 13, 19
Pennenergy.com ................................................................................................ 15
Pennenergy Jobs Books ..................................................................................... 11
Pennenergy Jobs ......................................................................................5, C3, C4
1404PEJEW_1 1 4/21/14 2:19 PM
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Edi t or ’ s
Let t er
H
ELLO everyone and a big thank you to Dorothy Davis! Dorothy has handed the
reins of PennEnergy Workforce over to me, and I couldn’t be more excited. We
have a fantastic issue dedicated to a topic I’m very passionate about: Putting people to
work, specifically people who may be overlooked or marginalized.
For women, the fight for true equality is ongoing, and that is often very clear in the
“boys club” world of the energy industry. A new survey looks at the hard data on women
engineers. To see some of their findings, head to page 6.
We wanted to share some women’s individual experiences, too. To see an
autobiographical look at what the experience was like for one engineer, head to page
8, and for an in-depth
questionnaire with another
prominent woman in the
industry, head to page 10.
Our nation’s fighting
men and women are often
overlooked when they return
home from duty. However,
the industry is working to find
them a new career here at
home. For an overview of veteran’s experiences returning to work, head to page 12.
Many energy companies are showing great success in veteran hiring. For a look at
some of the companies that employ returning soldiers, head to page 16.
It’s an expansive energy industry and there’s room to employ so many, from so many
backgrounds and walks of life. I’m excited to share these stories with you.
Let’s get to work!
—Hilton Price
Starting Point
“It’s an expansive energy industr y and
there’s room to employ so many, from so
many backgrounds and walks of life.”
1404PEJEW_2 2 4/21/14 2:19 PM
Cover STORY
EnergyWorkforce
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Spring 2014 3
Bridging the Gap:
Women in Energy
By Dorothy Davis-Ballard
A
S baby boomers are gradually
exiting the workforce, energy
companies are continuing to
ramp up their efforts to recruit women
for roles that have traditionally been
held by men. As a growing number of
women are pursuing STEM (science,
technology, engineering and mathe-
matics) educations and careers, they are
emerging as a driving force in the suc-
cess of the energy industry. The energy
sectors are not only essential, but also
offer numerous opportunities to operate
and develop new and innovative tech-
nologies. Advancing the responsible
productivity of oil and gas, renewables
and efficiency is more important than
ever as global demand continues to
rise sharply and access to resources be-
comes increasingly complex.
Encouraging pursuit of STEM careers
In order to fill many of the positions at
oil and gas and renewable energy firms
and facilities, companies must look to
improving access to STEM education-
al programs and career opportunities
for women.
While women account for half of
the U.S. workforce overall, less than 25
percent of women are in STEM jobs,
according to the U.S. Department of
Commerce’s Economics & Statistics Ad-
ministration (ESA). Further, many of
the jobs in the energy industry demand
a background or degree in a STEM
field, which also opens women to high-
paying positions. Women with STEM
jobs are paid 33 percent more than wom-
en in non-STEM jobs, the ESA said.
As an example, the position of reser-
voir engineer, which ranked in the No.
10 spot in CNNMoney/PayScale’s list of
Best Jobs in America, usually requires a
degree or background in petroleum or
chemical engineering. Reservoir engi-
neers earn a median pay of $179,000,
with top earners getting paid $254,000
to hold a low stress job that boasts a high
level of personal satisfaction, according
to the survey.
“Because no two oil and gas fields
are the same, I’m constantly expanding
my knowledge of the industry, which
makes the job fulfilling and enriching,”
Kristen O’Connor, a reservoir engineer
with Marathon Oil in Houston, told
CNNMoney.
Industry works to include more women
Encouraging women to pursue STEM
educations and careers is an evolving
priority for many energy companies
that understand the need to diversify
their workforce to increase innovation
in the industry and competitiveness in
the global marketplace.Many in the in-
dustry are recognizing more needs to be
done to attract and retain women in the
energy sector and at the same time, fill a
large skills gap anticipated to be left by
the exiting workforce of baby boomers.
Leading companies such as ExxonMo-
bil are actively addressing the problem
of filling the gender gap through fund-
ing to organizations that are committed
to expanding the number of women in
STEM careers.
“Companies have to think of recruit-
ing in a different light now and have in-
novative or new recruitment strategies,”
said Carolyn Stewart, regional business
development manager in Houston for
recruitment firm NES Global Talent.
BP’s Global Diversity and Inclusion
Report shows more U.S. oil and gas pro-
fessionals were optimistic about hiring
and advancement for women in the oil
and gas industry with 75 percent express-
ing a positive outlook, which is 4 per-
cent higher than the 71 percent mea-
sured globally. More than 60 percent of
respondents believe more women will
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EnergyWorkforce
join the industry as either workers who
are newly entering the sector or workers
in the early stages of their career, accord-
ing to BP’s report.
“We want women to know that the oil
and gas industry has made tremendous
strides in recent years and that it offers op-
portunities not provided by other sectors,”
said Kirsty Bashforth, group head of or-
ganizational effectiveness at BP. “Wheth-
er working internationally or domestical-
ly, onshore or offshore, the possibilities
are endless.”
Women accounted for almost 32 per-
cent of new hires at BP, as the company
hopes to appeal to top talent in the indus-
try and grow diversity within the firm,
according to Bashforth. She said boost-
ing diversity and inclusion at BP helps
to increase its competitiveness, saying
these qualities are a ‘must have,’ not a
‘nice to have.’
Women have also grown represent a
large amount of the workforce in renew-
ables. The solar industry has women rep-
resenting 19 percent of the workforce in
2014, or 26,738 staff, according to data
from The Solar Foundation’s National
Solar Jobs Census 2014.
Building support for women in energy
While great strides have been made over
the past two decades to increase oppor-
tunities for women in energy, the reali-
ties of working in traditionally male dom-
inated sectors can still be a challenging.
In addition to the issue of gender ste-
reotyping, many women cite not having
enough role models as a barrier in enter-
ing and becoming successful in STEM
fields. However, more companies are es-
tablishing mentoring programs and hav-
ing more women chair recruitment ad-
visory boards.
By investing money into professional
organizations devoted to providing wom-
en with support throughout their career
development and advancement, the en-
ergy industry helps provide women with
role models needed to encourage other
women to pursue STEM fields.
Organizations such as Women of
Wind Energy (WoWE), offer women
an opportunity to connect with a men-
tor who can offer them advice and guid-
ance through the lens of their personal
experiences. Through the organization’s
mentoring program, mentors and men-
tees can contact each other anywhere
they have an Internet connection.
“I fundamentally believe that the suc-
cess of renewable energy in the U.S. and
around the world depends on our abili-
ty to bring together the best minds from
as many diverse backgrounds as possi-
ble to solve the critical problems of our
day,” Kristen Graf, executive director of
WoWE, said in an interview with the
Union of Concerned Scientists. “Reports
continue to show that having more wom-
en on teams leads to better decisions and
better financial performance as well, so
we know we need them there.”
The cultivation and support of wom-
en in the energy sectors has also been
long supported by professional organiza-
tions such as the Women’s Energy Net-
work (WEN) and the Society of Women
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1404PEJEW_4 4 4/21/14 2:19 PM
FREE • CONFIDENTIAL • ALL JOB TYPES & EXPERIENCE LEVELS
Top Oil & Gas Industry Employers are
RECRUITING
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Don’t miss another
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Visit PennEnergyJobs.com to UPLOAD YOUR RESUME to the database today.
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|
Spring 2014 5
Engineers (SWE). These organizations
have committed themselves to the sup-
port of women in what have long been
perceived as “non-traditional” careers
paths. Through networking events, men-
toring opportunities, and scholarships
these organizations have been success-
fully fostering professional advancement
for women in STEM fields for decades.
The U.S. government is also taking
steps to establish a viable path to success
for women in STEM careers. In 2011, the
Obama administration unveiled a cam-
paign to encourage the participation of
women and girls in STEM fields through
increasing education and career oppor-
tunities through its $4.35 billion Race to
the Top competition.
In 2012, the Department of Energy
(DOE) launched the U.S. Clean En-
ergy, Education, and Empowerment
(C3E) program to advance the careers
and leadership of women in clean ener-
gy fields. Led by the DOE in partner-
ship with the MIT Energy Initiative, the
new program includes an ambassador
network, annual symposium and the
C3E Awards program.
DOE has also put in place an ongoing
series celebrating the successes of women
in energy through its Women @ Energy
initiative, which profiles leading women
in the federal workforce.
“We hope that the stories of these,
and many more, women in STEM can
inspire others as they think about the fu-
ture,” said the DOE on its website. “Only
24 percent of the STEM workforce is fe-
male, an alarming gap as over 51 percent
of the workforce overall is female. We
can and should share our own STEM
stories to help engage others and offer
our voices on how our STEM careers
have impacted us.”
As industry and governments become
increasingly engaged in seeing wom-
en representing a larger portion of the
STEM workforce, these efforts may sig-
nal a lasting shift toward a robust and
thriving economy of diversity for the en-
ergy sectors. ⊗
1404PEJEW_5 5 4/21/14 2:19 PM
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EnergyWorkforce
T
HE global focus on attract-
ing more women into the
oil and gas industry is not
just about creating a more di-
verse workforce, it is of vital im-
portance if we are to continue to
serve the world’s growing energy
needs. With demand for engi-
neering expertise far outstrip-
ping supply and half the expe-
rienced engineering workforce
set to retire in the next decade,
the sector is facing a crippling
skills shortage. In order to power
future energy projects, the oil
and gas industry must act now to
fully tap into this enormous po-
tential talent pool.
It has been widely report-
ed that women have tradition-
ally been underrepresented in the oil
and gas engineering sector and while a
great deal is being done to encourage
young women to study science, tech-
nology, engineering and mathematics,
the STEM subjects, this gender dispar-
ity continues to exist.
So, what should the sector be doing to
solve this problem? The industry needs
to find creative ways to attract women,
not just at primary and secondary school
level, but at an undergraduate and grad-
uate level. It must also continue to work
to attract women working in other indus-
tries to oil and gas engineering, shining
a spotlight on what a welcoming and
rewarding career it can be and highlight-
ing the opportunities.
NES Global Talent is focused
on solving the staffing issues
that keep our clients awake at
night. We are committed to
sourcing and placing the female
talent our clients so desperately
need. We conducted this survey
to find out more about women
working in the oil and gas indus-
try, their career path and the
challenges and opportunities of
working in the sector, in a bid to
help highlight what the indus-
try could be doing to attract and
retain female employees.
Our survey flags many inter-
esting points for further discus-
sion. For instance, while it is
great to hear that the majority
of women feel welcome in the
industry and would encourage other
females to join, 45% say they do not get
the same recognition as men. Under-
standably, this perception needs to
change if the sector is to become more
attractive to women.
Our survey also reveals that while
a huge majority (95%) view mentors
as important for career advancement,
Attracting and Retaining Women
in Oil and Gas Engineering:
A survey examining the gender talent gap
It’s not just a talent gap; it’s a gender gap
By Neil Tregarthen, CEO at NES Global Talent
1404PEJEW_6 6 4/21/14 2:19 PM
Do you feel you get the same recognition
for your work as male peers?
45%
55%
Yes No
EnergyWorkforce
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Spring 2014 7
a large proportion (42%) said they were
neither a mentor nor a mentee. In order
to help women progress to senior posi-
tions in the oil and gas industry and
become the role models of tomorrow,
this also needs to change.
As a business, we understand the
need to promote diversity within our own
workforce. We recently launched a glob-
al graduate recruitment
scheme – the NES Glob-
al Talent Futures Academy
– where graduates will be
mentored to become expert
consultants. By providing
inspiring role models com-
panies can retain and nur-
ture talent. After all, men-
toring is important for all employees,
both female and male.
Creative recruitment techniques exe-
cuted with women in mind will also help
with attraction, but it has to be more
than the token ‘women in hard hats’
images that we so often see. Tapping into
women’s networks and using positive
role models to give speeches at schools
and universities will help
to encourage more females
to enter the sector. The
industry needs to show that
there is nothing stopping
women with the right skills
and qualifications from
enjoying a successful engi-
neering career.
Engineering is an exciting and
dynamic profession and we look forward
to supporting our clients and welcoming
more women into the oil and gas indus-
try in the future. ⊗
Key Findings
: Three quarters (75º) cf the wcmen that respcnd-
ed tc the survey sald they felt welocme wcrklng ln
the cll and gas lndustry yet almcst half (45º) sald
they dc nct feel they get the same reocgnltlcn as
thelr male oclleagues.
: 89º sald they wculd enocurage a female frlend
tc pursue a oareer ln the lndustry ncw, wlth 82º
saylng they wculd reocmmend a oareer ln the seo-
tcr tc scmecne whc ls due tc flnlsh thelr studles
ln a deoade`s tlme. Scme respcndents sald cth-
er energy lndustrles suoh as nuolear and renew-
ables oculd jcln cll and gas as attraotlve cptlcns
ln the future.
: 95º sald mentcrs were lmpcrtant fcr oareer
advanoement, wlth 74º saylng lt was very lmpcr-
tant and 21º saylng lt was sllghtly lmpcrtant,
yet 42º sald they were nelther a mentcr ncr a
mentee.
: Respcndents prcvlded a dlverse range cf sugges-
tlcns when asked what ocmpanles oculd be dclng
tc attraot and enocurage wcmen emplcyees suoh
as: eduoatlng wcmen early (ln seocndary sohccls)
abcut oareers ln the cll and gas lndustry; glvlng
wcmen a ohanoe tc take cn mcre ohallenglng cff-
shcre rcles; and prcvldlng equal beneflts and
cppcrtunltles.
: 39º sald they wculd ocnslder taklng less mcney
ln return fcr mcre wcrk flexlblllty, wlth many oltlng
a better wcrk llfe balanoe and spendlng mcre tlme
wlth the famlly as the maln reascns.
: 0ver fcur flfths (82º) sald they planned tc stay ln
the lndustry fcr the next 2 ÷ 5 years.
1404PEJEW_7 7 4/21/14 2:20 PM
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I
STARTED my career in 1998 as an ex-
ploration geologist at Marathon Oil
Company and worked offshore Gulf
of Mexico (GoM) in the Lease Group.
My primary role was undertaking seis-
mic and geologic interpretations in or-
der to determine what leases we were
going to bid on at the next GoM lease
round. It was not a great time in the
oil and gas industry, as oil was around
$9-10/barrel, therefore expensive GoM
exploration wells were being drilled,
primarily only on prospects that were
already in our portfolio. Subsequently,
I decided it would be a good time to
make a switch in my career.
My next role was a technical con-
sultant for Landmark Graphics, bought
over by Halliburton. Here, I worked
with oil and gas companies on learn-
ing what software they had, mentoring
users and giving presentations. During
this time, I worked closely with geol-
ogists and geophysicists to help them
create accurate maps, correlate logs and
make seismic interpretations. It was a
great role for me because I still used my
technical skills daily, but gained experi-
ence on a wide range of projects.
One of my most impactful work
experiences to date was working in
business development for Landmark’s
geoscience applications in Asia Pacif-
ic. Again, it meant I could apply my
technical skills when explaining the
software across many cultures, coun-
tries, and resource plays. There were
regions such as Australia where Coal
Bed Methane (CBM) was dominant,
which I had not encountered previous-
ly in the U.S. It is not straight-forward
to give an offshore deepwater overview
of software to a geologist who is work-
ing CBM. You have to be specific in
what types of properties they look for in
a reservoir, how they produce wells and
how the rocks behave differently than
unconsolidated sandstone.
Landmark had also acquired a com-
pany that had a 3D visualization and
interpretation application, which was
very cutting edge. Companies were
building large visualization centers
in order to get ‘in’ to their data in 3D.
This meant I could expand my techni-
cal skills because not only was I help-
ing geoscientists use the 3D world to
find better prospects and look at larg-
er amounts of data, I was now work-
ing on the technical computing side in
designing and building these visualiza-
tion centers in which the 3D applica-
tions would work. There is a whole oth-
er area around understanding graphics
pipes, CPU usage, different types of
projectors and the benefits and pit-
falls of each; passive v. active seismic,
rear projection v. front projection and
curved or flat screens.
Returning from Asia, I spent three
years in Halliburton’s production opti-
mization global business development
and marketing group, learning a com-
pletely new set of products. Instead of
software, I worked with chemicals and
production enhancement techniques
such as fracing, acidizing, and com-
Women in Energy
Spotlight: Christi Gell
By Christi Gell
1404PEJEW_8 8 4/21/14 2:20 PM
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Spring 2014 9
pletion tools. I was giving presentations
on asphaltene and paraffin control, and
surfactants for increasing regained per-
meability after a frac. This was not far
from my technical realm because my
master’s degree in Geology was focused
on hydrogeology and hydrochemistry.
From this I was able to grow my knowl-
edge of the industry from geoscience, to
production and engineering.
Prior to joining Expro, I was again
involved more in business development
and sales for Landmark (back to soft-
ware). I worked a project that required
quite a bit of research and development
(R&D) and was able to learn about the
R&D process of software. It is a totally
different skillset than being a geologist,
but the R&D people need the technical
support to help them understand how
the software should work - they cannot
be separated.
Therefore, when I joined Expro
in 2013 as a product line manager for
SafeWells in North America, it almost
seemed like a natural progression to
what I had done in the past. SafeWells
is a software solution specifically devel-
oped by Expro as an effective well
integrity data management system. It
monitors and reports on well integrity
performance and has been successful-
ly deployed by major operators globally.
My role in SafeWells is to set up and
grow the business within my region. By
taking a strategic approach and combin-
ing other Expro PLs/services, we can sell
more holistically into a customer rather
than just as a point product. I spend a lot
of my time understanding well integrity
regulations and how those can be incor-
porated into our software. These can
differ from country to country, region to
region, and even state to state.
Although having a successful career
in oil and gas is dependent on your
skill and attitude, and not necessarily
whether or not you are male or female,
I believe being a female has had a pos-
itive impact on my career. There have
been many occasions when I have not
needed to work around the gender issue.
For instance, on a past project we
were drilling an offshore well using a
drill ship. It is tight quarters on any off-
shore rig, so getting the experience of
being on the rig meant waiting until we
could get an open spot for me and one
other female in order to share a room. It
was a logistics thing; a female would not
be put in a room with three males, shar-
ing bunk beds. That said, once we were
out there, it was just learn, learn, learn.
Ask questions. See everything. I
was in awe the first time I was
on a rig – and I am still often
gobsmacked by what we do in
this industry because it is just so
technically complicated.
Another instance of when
the gender issue came to the
fore, was when I had my two
children, as I was anxious about
taking time off after they were
born. I questioned what kind
of traction I would lose at work
and whether or not the value I
brought to the group would be
lost when other people start-
ed picking up the slack. Some
team members were also anx-
ious about it, which did not help
my situation. But after children
comes the whole ‘work-life bal-
ance’. The hard part is making
sure that one does not dominate the oth-
er overall. I was fortunate to have a job at
the time that did not require much trav-
el so I was able to work and be a new par-
ent fairly stress-free. Now that my kids
are a little older and more self-sufficient,
I am able to have a job that I can travel a
few days out of the month.
I have worked in cultures where it
was obvious that a more male-dominat-
ed approach was upheld and I had to fig-
ure out creative ways to be effective in
my job and have my voice heard. But
then, there have also been times when
being a female has worked in my favor.
At the end of the day, I rely on my
technical skills, business expertise, and
positivity to get things done and progress
my career. I think that’s what everyone
should do, whether male or female. ⊗
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1404PEJEW_9 9 4/21/14 2:20 PM
10 Spring 2014
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FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
|
EnergyWorkforce
S
ARAH Cridland is Global Prod-
ucts Manager with DUCO
Limited. With 20 years’ expe-
rience in the industry, Cridland has
delivered numerous projects for oil
and gas clients, including majors Roy-
al Dutch Shell, Petrobras, and Total.
She took some time to answer some
questions for PEJEW.
What were some of your fondest expe-
riences during your education at the
University of Strathclyde
SC: Manufacturing Sciences &
Engineering combined Mechani-
cal, Production and Electrical Engi-
neering with Management Studies
(Law, Finance, and Economics) and
an emphasis on work placements.
The course had been developed with
the aim of developing engineers who
were managers; an aim which has
been achieved. Whilst many courses
had a low percentage of female appli-
cants, we had over 40% of girls in my
year and the top five graduates were
all female. During the whole of the 5
years at Strathclyde no differentiation
was made by the lecturers or my fel-
low students of my being women in
engineering, and this gave me a good
grounding for career after university.
You’ve been Project Manager on sev-
eral projects and also Department
Manager. What draws you to leader-
ship roles?
SC: I am drawn to leadership roles
as it allows me to play to my strengths,
specifically strategic decision making
and the ability to persuade and influ-
ence people. I enjoy the ability to
engage with and motivate people at all
levels in the organization.
If you could return to your early days
in the industry, what advice would
you give yourself?
SC: Don’t feel that you can’t retain
your feminine side in a male environ-
ment and still get taken seriously.
Do you have prominent memories of
how your gender was perceived dur-
ing your educational years? Was your
pursuit of a degree in science and
engineering hindered or helped by
your gender?
SC: The attitude within the engi-
neering department at Strathclyde was
very much that women in engineer-
ing were a ‘normal’ everyday occur-
rence. I think this matter of fact accep-
tance gave me a great grounding for my
career; it just never occurred to me that
I couldn’t or shouldn’t be an engineer
Since entering the industry, how do
you feel your gender has affected the
way you were treated by colleagues?
SC: As a woman in engineering
within the oil and gas industry you are
in a minority and as such you stand
Women in Energy Q&A:
Sarah Cridland
1404PEJEW_10 10 4/21/14 2:20 PM
Books, Books…
So Many Books
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www.PennEnergy.com
PennEnergy.com is your best source
for the largest and most comprehensive
compilation of books related to the
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t Oil & Gas
t Power Systems
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FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
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Spring 2014 11
out. This means that good work/attitude
is noticed but also any mistakes, which
gives a good incentive to not make too
many! In general, I’ve been well accept-
ed by colleagues, whether it has been off-
shore on our installation vessels or on the
Executive Committee at DUCO (Tech-
nical Umbilical Systems).
You’ve held several roles of leadership
during your time in the industry. How
has that leadership been affected by
your gender? Do you feel subordinates
were more or less willing to comply based
on assumptions raised by your gender?
SC: Whilst it is a generalization,
women bring different character traits
to the management role and I’ve found
that sub-ordinates appreciate this dif-
ference. Provided that you have the
respect of your team then they are will-
ing to follow you as a leader rather than
simply complying with the instruction
of a manager. I have on previous occa-
sions had to request some more mature
sub-ordinates to refrain from referring
to me as ‘young lady’. However, as I’ve
aged this has become less of an issue!!
Have you ever felt a company or rep-
resentative was hostile to you because
you are a woman? Have you ever felt
you were given special consideration
because you are a woman?
SC: I have encountered a few per-
sonnel during my career who were hos-
tile to me as a woman, but I do not let
these situations phase me. As I said earli-
er, you do stand out as a minority within
the industry and as such, when you per-
form well this can be more visible.
What advice would you give to young
women entering the industry today?
SC: Join the oil and gas industry!!
Don’t wait for someone to develop your
career, push for everything you want.
Never believe that you can’t do some-
thing and don’t be afraid to ask. ⊗
“As a woman in engineering within the oil and gas
industr y you are in a minorit y and as such you stand out.”
1404PEJEW_11 11 4/21/14 2:20 PM
12 Spring 2014
|
FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
|
EnergyWorkforce
TRAINING Insights
M
ILITARY service is a selfless
commitment undertaken by
a dedicated few. Thanks to
their selflessness, the United States is
able to protect and defend its interests
around the world. However, for many in
the armed services, time spent enlisted
is only part of their story. Once their
enlistment ends, they will return to the
civilian world as veterans, and for some
that is where the real challenge begins.
In 2012, there were 21.2 million
veterans living in the United States.
Although many of these men and wom-
en acclimate back into civilian life with
no problems, for others it is a unique
challenge. One area where some vet-
erans struggle to return to normal-
cy is with employment. The tenacity,
humility, and perseverance required of
serving men and women should make
them an ideal type of potential employ-
ee, but many veterans still have diffi-
culty finding employment when they
return home.
A seasoned soldier who is com-
fortable on the battlefield may be lost
when trying to re-establish themselves
as a civilian. It’s prevalent enough that
780,000 veterans were unemployed as
of March 2013, including more than
200,000 who’ve served since 9/11.
Luckily, there are tools to aid in this
reintegration, many specifically target-
ed at the unique challenges for veter-
ans. There are numerous job place-
ment organizations aimed strictly at
veterans, and foundations focused on
all manner of veteran care often fea-
ture sections highlighting employment
assistance. Of course, the Internet has
made this process more accessible for
everyone. In some cases, job placement
for a veteran may now begin and end
with a google search
Certain corners of the energy indus-
try have recognized the unique skills
possessed by veterans and taken the ini-
tiative in hiring them. Their philoso-
phy is simple: who better to handle the
harsh environments often encountered
in energy exploration and production
than the men and women who have
fought for freedom across the globe?
This targeted employee search isn’t
just limited to roles at existing compa-
nies. In recent years, whole new com-
panies have been formed by harness-
ing the skills of military personnel and
applying them to the energy industry.
This recognition of these transferrable
skills is not only aiding in the employ-
ment of veterans, but in meeting the
growing the talent shortages across the
energy industry.
From the land to the sea to the air,
military men and women have commit-
ted their lives to service. From onshore
Energy to Serve: Veterans find new
direction in the energy industry
By Hilton Price
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1404PEJEW_12 12 4/21/14 2:20 PM
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1404PEJEW_13 13 4/21/14 2:20 PM
14 Spring 2014
|
FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
|
EnergyWorkforce
exploration to offshore drilling to solar
and wind, the energy industry is welcom-
ing soldiers home with open arms and
opportunity once their time serving ends.
Commanding Resources
There is a wealth of options for veterans
looking to re-enter the workforce at the
end of their service. Specifically in the
energy industry, a myriad of organiza-
tions exist solely to help place these for-
mer warriors in roles suiting their train-
ing, experience, and skill.
Websites like “Veterans to Energy”
(http://www.veteranstoenergy.org/) and
“Troops to Energy Jobs” (http://www.
troopstoenergyjobs.com/) specialize in
industry placement for veterans. Both
sites offer online analysis of a potential
applicant’s military service skills and
training. They can then highlight ener-
gy industry careers where these skills
are most applicable. When additional
education and training is needed, they
can show veterans where to best acquire
this supplemental information. The
whole process is handled on each orga-
nization’s website, streamlining the job
search and compatibility checks.
These websites are built from a mil-
itary perspective, employing codes and
categorization familiar to enlisted per-
sonnel. For instance, jobs are often
listed with relevant career field cate-
gorization from various mil-
itary branches. So, wheth-
er a potential applicant is
Army, Navy, Marines, Coast
Guard, or Air Force, they
can easily determine wheth-
er the training from their
military service is applicable.
Other websites, like
“Battlefields to Oilfields”
(http://battlefieldstooilfields.
com/) takes a comprehen-
sive approach to veteran job
placement. The site offers a
program that provides train-
ing through combination of
classroom work and practi-
cal, hands-on experience.
Once training is complet-
ed, B2O offers job placement
culled from a network of sup-
port groups. B2O walks potential appli-
cants through the resume-building pro-
cess, then puts them in direct contact
with hiring personnel and recruiters
from oil and gas companies, specifically
choosing paths based on the applicants
military training and experience.
These websites share a common ele-
ment; a deep understanding of the mili-
tary experience. By working closely with
military personnel and reflecting an
intricate knowledge of military training,
they can provide a thorough job place-
ment experience, akin to those available
to students from major educational insti-
tutions. And like post-college job place-
ment, they are aiming not to simply pro-
vide jobs, but to help launch careers.
Renewable Battalions
One renewable energy industry is show-
ing notable success in employing veter-
ans. The solar industry employs more
than 13,000 veterans of the US armed
forces, more than 9% of the total US
solar workforce, according to a recent
report. Of that number, 39% are work-
ing in solar installation, and another
27% in solar manufacturing. These are
typically positions with competitive sala-
ries and opportunities for advancement.
The same report shows compa-
nies hiring veterans consistently report
strong worker satisfaction and are opti-
mistic about future growth. 62% of the
companies surveyed planned to add
additional solar workers within the fol-
lowing 12 months. Even more surpris-
ing, only 2% reported expectations to
reduce their workforce.
The solar industry is also seeing
impressive growth year over year. Since
2008, the amount of solar in the US has
grown by more than 500%. This growth,
coupled with strong support of veteran
employment, suggests the industry will
remain a reliable source of jobs for for-
mer servicemen for years to come.
Pinpoint Strike
General Electric, Southern Company,
and many other companies in the ener-
gy industry are hiring veterans. Through
the organizations mentioned earlier,
state and federal agencies, and classic
networking, these companies are reach-
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1404PEJEW_14 14 4/21/14 2:20 PM
PennEnergy.com was created by PennWell, a leader in
the coverage of the global petroleum and power industries
since 1910, to serve as the broadest and most complete
source of energy-related news, research, and insight.
Including content from all PennWell award-winning energy-
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EnergyWorkforce
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Spring 2014 15
ing out to former soldier. But employ-
ment through existing companies isn’t
always the only path for veterans looking
for new careers.
Instead of finding the best applicable
jobs for a former soldier with a specif-
ic set of skills, what if a company was
built around those skills? It’s becoming
increasingly common. One example is
Check 6, a training and logistics com-
pany built from a request to apply mili-
tary training to the oil and gas industry.
Company founder Brian Brurud is a
former Navy pilot, and nearly his entire
staff consists of former personnel from
almost every military branch. With
employees who’ve received real-world
training in some of the world’s harshest
environments, Check 6 can offer expe-
rience that is difficult for other compa-
nies to emulate.
Check 6 isn’t alone employing this
strategy, but with its growing recognition
nationally, the company is exemplifying
how employers can re-think the hiring
process when it comes to veterans.
Worldwide heroes
The choice to enlist in military service
is not one made lightly. Often, these
men and women endure grueling chal-
lenges in harsh environments as they
follow the orders of supervising offi-
cers. When their time enlisted ends,
they face additional challenges in their
return to civilian life. Thanks to the
appreciation of their skills and training
by the energy industry, veterans have a
place to turn to begin the subsequent
chapters of their lives. ⊗
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1404PEJEW_15 15 4/21/14 2:20 PM
16 Spring 2014
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FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
|
EnergyWorkforce
W
HEN troops return to civil-
ian life, the energy industry
is there to welcome them
with fulfilling careers. As more service
members take advantage of transition
assistance programs as well as educa-
tion benefits offered by the Depart-
ment of Veterans Affairs, they can re-
turn home and use their transferable
skills to contribute  to companies. Ac-
cording to the newest report by the
U.S. Bureau of Labor Statistics, the
unemployment rate for veterans who
served on active duty since September
2001 dropped to 9 percent in 2013. The
jobless rate for veterans overall also de-
creased to 6.6 percent in 2013 from 7
percent the previous year.
“I urge all employers to renew their
commitment to veterans, so that those
who served and sacrificed can real-
ize their highest dreams,” Secretary of
Labor Thomas E. Perez said in a state-
ment. “The best way to honor our vet-
erans is to hire them.”
Energy companies are answering
the call to provide employment for the
nation’s veterans in a big way.
Here are 10 of the top employers in
the energy industry:
Exelon Corporation
Chicago-based Exelon Corporation
operates in 47 states and Canada, mak-
ing it one of the biggest power genera-
tion companies in the U.S. The com-
pany not only participates in military
recruiting fairs to advertise Exelon’s
career opportunities for veterans, but
also works with Transition Assistance
Program (TAP) offices to facilitate
their transition from military to civil-
ian life. The appeal of Exelon to vet-
erans is undeniable as nearly 10 per-
cent of Exelon workers have a military
background. The company even has
an Employee Network Group spe-
cifically designed to join together
employees of all military affiliations
called the Exelon Militaries Actively
Connected (EMAC).
PPL Corporation
PPL’s companies provide electricity and
natural gas to more than 10 million cus-
tomers in the U.S. and U.K. The corpo-
ration’s power plants represent a diverse
power generation portfolio using coal,
natural gas, oil and uranium, among
other power sources. An estimated 15
percent of PPL’s workforce are military
veterans who work in a variety of posi-
tions, including nuclear generation and
10 Top Military Friendly Employers
in the Energy Industry
PennEnergy.com
ORGANIZATIONAL Insights
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EnergyWorkforce
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|
Spring 2014 17
energy delivery managers, plant opera-
tors and maintenance technicians.
Xcel Energy
Xcel Energy is the top ranked wind pow-
er provider in the U.S. with revenues
totaling $10.3 billion each year. As a
major electric and natural gas provider,
the company has the resources to offer
competitive benefits to its more than
1,400 employees with military experi-
ence. Xcel Energy created a Time Away
From Work Policy to cover active mili-
tary employees’ pay as well as their ben-
efits and pension. Like Exelon, Xcel
Energy also has a veteran employee net-
work group, Military Ombudsmen for
Veterans and Employees.
Pacific Gas and Electric Company (PG&E)
PG&E generates power for more than 15
million California residents. The com-
pany has implemented military recruit-
ing and training programs, including
on-the-job training programs for veter-
ans as well as programs to train them to
work in management, which allow them
to utilize their leadership skills. Of the
20,000 employees for PG&E, more than
1,200 are veterans.
Southern Company
Southern Company was recently given
the distinction of top military friendly
utility by G.I. Jobs for the seventh year
in a row. In 2014, Southern Company
was ranked No. 8 out of 100. Last year,
12 percent of new hires were military
veterans, guardsmen or reservists with
veterans accounting for 11 percent over-
all of Southern Company’s workforce.
The company’s two flagship construc-
tion projects, Plant Vogtle in Georgia
and the Kemper County plant in Mis-
sissippi, both have a more than 20 per-
cent rate for new hires who are veterans.
MidAmerican Energy Holdings Company
MidAmerican Energy, based in Des
Moines, Iowa, serves almost 7 million
customers around the world and placed
in the top 50 military friendly employ-
ers for 2014 compiled by G.I. Jobs for
the fifth consecutive year. The compa-
ny participates in the Employer Support
of the Guard and Reserve Five-Star pro-
gram to help veterans make a smooth
transition into its workforce. As a way to
reach out to more veterans, the compa-
ny’s human resources department uses
hiring policies and initiatives specifical-
ly targeted to this group.
Dominion Resources, Inc.
As one of the first utilities to partner
with the Troops to Energy Jobs program
designed to connect veterans with ener-
gy careers, Dominion is a well-known
military veteran employer. Dominion
produces energy and provides energy-
related services for a customer base of
6 million across 15 states. The utility
also owns natural gas pipeline and stor-
age operations in the mid-Atlantic and
Northeast. The company hires military
veterans for jobs in engineering, admin-
istrative support and other areas to use
their problem-solving abilities and pas-
sion for teamwork to the fullest.
Devon Energy Corporation
Devon Energy Corporation, headquar-
tered in Oklahoma City, is an oil and nat-
ural gas exploration and production com-
pany that posted revenues of $9.5 billion
in 2012. In addition to being a Fortune
500 company, Devon Energy is also
ranked 36 out of 100 on G.I. Job’s list of
military friendly employers. Devon Ener-
gy previously set an ambitious hiring tar-
get to fill 6 percent of its positions with
military veterans, saying veterans have an
unparalleled level of dedication.
OutBack Power
Based in Arlington, Wash., OutBack
Power is a leading renewable ener-
gy technology manufacturer that was
featured in a report on veterans in the
solar industry, which was published by
Operation Free and The Solar Founda-
tion. More than 9 percent of workers in
the solar industry are veterans, which is
higher than the 8 percent rate for the
entire U.S. workforce. The solar sector is
expected to grow rapidly and many mil-
itary members who already have expe-
rience learning about solar at a service
academy or in the field have an advan-
tage over other workers.
FirstEnergy
First Energy in Ohio operates one of
the largest investor-owned electric sys-
tems in the U.S. with customers spread
throughout the Midwest and mid-
Atlantic regions. The company has an
energy portfolio that accounts for an
estimated 20 gigawatts of power gener-
ation using coal, natural gas and renew-
able energy sources. FirstEnergy has
more than 1,000 armed forces mem-
bers in its workforce and offers active
duty benefits including health insur-
ance coverage and 401(k) retirement
savings plan contributions. ⊗
1404PEJEW_17 17 4/21/14 2:20 PM
18 Spring 2014
|
FOR JOB OPPORTUNITIES, VISIT www.PennEnergyJOBS.com
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EnergyWorkforce
INDUSTRY
Insights
W
ITH AN EVER-INCREASING
focus on environmental is-
sues, Southern Company
employees have developed a number
of patented and patent-pending innova-
tions to address the capture and storage
of carbon dioxide and carbon ash. The
patent-pending innovation for Deep
Well Carbon Dioxide Sequestration,
and the patented Systems and Methods
for Particulate Filtration, were both de-
veloped by company employees solving
a business need.
Dan Patel, a Principal Engineer for
Southern Company, discovered a way
to stabilize carbon dioxide using water,
allowing for its safe
long-term storage deep
underground. Tradition-
al carbon capture and
storage involves separat-
ing and capturing car-
bon dioxide – a byprod-
uct of the coal-burning
process – and transport-
ing the material under-
ground or to a nearby
industrial facility. What
Patel discovered was a way to stabilize
the stored carbon dioxide, which allows
for safe long-term storage deep under-
ground. The innovation avoids use of
pipelines for long distance
transport of carbon diox-
ide, an important need for
power plants as they are
pressed to control costs.
Another important aspect
is that the innovation ben-
eficially uses plant waters,
helping to control the cost
of water treatment to meet
the Environmental Protec-
tion Agency’s (EPA) proposed surface
water eff luent limits.
“Once the carbon dioxide is cap-
tured, it is transported to underground
geological formations for storage, even-
tually in minerals” explained
Patel. “In the past, the pro-
cess of storing pure carbon
dioxide deep underground
posed a risk in that carbon
dioxide had the potential to
move from one area into oth-
er surrounding geological
formations underground.”
Deep saline formations are
also much more widespread
with respect to power plant
locations, than are geologic formations
suitable for long term storage of pure
carbon dioxide.
Current carbon dioxide sequestra-
tion processes pose pos-
sible migration risk into
surrounding geologic for-
mations or aquifers and
nearby layers of perme-
able rock, sand or gravel
through which ground-
water flows. Numerous
studies have been con-
ducted on injection of
carbon dioxide deep
underground, but the process that
Patel developed prevents any potential
migration of the gas once it has been
stored underwater in deep saline geo-
logic formations.
Patel’s innovation has been success-
fully tested at an independent test labo-
ratory facility with positive results.
Another innovation helping cap-
ture carbon was developed by Gerry
Klemm, a principal engineer for South-
ern Company; a low-cost option for
removing powdered activated carbon,
or (PAC) with electrostatic precipita-
tors, or (ESPs). ESP’s are not designed
to remove such particulate in the same
way as other control devices. There-
fore, a solution needed to be found to
enable ESP’s to not only remove PAC
from the gas stream, but also to retain
it. Fortunately, Klemm had previous-
Employee Innovations
Address Environmental Concerns
of CO
2
Storage and Carbon Ash
1404PEJEW_18 18 4/21/14 2:20 PM
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How the carbon trap works
U.S. patent pending
No. 7,828,876
Precipitator
collecting
area
Carbon
trap
baffe
Collection bin
(hopper)
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Spring 2014 19
ly performed extensive studies on loss-
on-ignition (LOI) particulate behav-
ior in conjunction with other clean air
initiatives. LOI and PAC share sim-
ilar properties as both are very high
in electrical conductivity, which can
cause short circuits on the porcelain
insulators. They are also very light in
weight and tend to float right through
the ESP after it has done its job in mer-
cury removal without being captured.
PAC is a highly adsorptive materi-
al that is injected into the gas stream
where it is exposed to the oxidized mer-
cury in the flue gas. After being exposed
for a minimum length of time, the PAC
must then be removed from the gas
path. This is generally done by scrub-
bers or baghouses. In some cases it must
be done with ESPs, but depending on
their size, this may be a challenge. Oxi-
dized mercury exists in exceeding min-
ute concentrations so the PAC particle
size must be very small. This adds to the
difficulty in collecting the particulate.
Patented baffling designs were
developed by using laboratory physical
and computerized modeling as well.
The baffles were installed in the dust
hoppers where they produce the bene-
fit of retaining the PAC after it has
been collected.
1404PEJEW_19 19 4/21/14 2:20 PM
Carbonated FGD process
water, saturated with CO
2
Variable depth of injection
Annular space flled with water
for leak detection
CO
2
content
produced by process
at <1000psig ensures
no gas separation
(water is moving
up in pressure)
Increasing
pressure
temperature
U.S. patent pending No. 13/909,732
Injected water sinks
in well due to it being
cooler than water in
the aquifer
~3,500 ft
1500 psig static
pressure at realease point
P<1000psig
Ground elevation
Seal
Up to 10,000 feet or more
Temp rises
(increasing mineralization reactions)
Temp rises to aquifer
temerature, e.g., 200˚F
P
How the carbon baffe works
U.S. patent pending No. 8,313,566
ISO view
Detail view
Side view
End view
Top view
20 Spring 2014
|
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EnergyWorkforce
The above innovations have been,
and are currently being installed in var-
ious Southern Company units. Field
testing has confirmed the successful
increased removal of carbonaceous
material and, as such, these designs
have been included in the Mercury
and Air Toxics Strategy (MATS) com-
pliance plans.
Based on the results, Klemm devel-
oped the Systems and Methods for
Particulate Filtration, which has been
patented by the United States Patent
and Trademark Office. “This innova-
tion is cost-effective and is easily ret-
rofitted into existing units capturing
fly ash particles before they enter into
the final flue gas stream. This patented
innovation is now operational at sever-
al plants in our system,” says Klemm.
“By looking at things in a different
way, they both were able to come up
with a great solution. It’s one of those
things that we could have just kept
doing the same way and nobody would
have thought much about it. But they
understood that we could create a much
more efficient and cost-effective pro-
cess to help address some of the envi-
ronmental concerns affecting our com-
pany and because of innovative thinkers
like them, our company continues to
be a leader in the electric utility indus-
try.” said Christopher Savage, Intellectu-
al Property manager for Georgia Power.
Southern Company has been grant-
ed a patent for Klemm’s Systems and
Methods for Particulate Filtration, and
has filed a patent for Dan Patel’s Deep
Well Carbon Dioxide Sequestration.
If you are interested in either of these
innovations, please contact Christo-
pher Savage at CHSAVAGE@South-
ernco.com or 404-506-7396 ⊗
1404PEJEW_20 20 4/21/14 2:20 PM
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