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Perth basin
exploration32
Cyber security solutions 14
Malaysia delivers safety training 36
aogdigital.com ▼
May - June 2015
AS IAN O I L & GAS
AOG
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archerwell.com /qaContent is copyright protected and provided for personal use only - not for reproduction or retransmission.
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EDITOR’S COLUMN
6 Investing in Asia A look at potential investment opportunit ies.
REGIONAL UPDATES
8 Briefs CNOOC brings Kenli 10-1 oilfield online and more news fromIndia, Malaysia, Indonesia, Thailand, Papa New Guinea and New Zealand.
FEATURES
14 Cybercrimes in AsiaAs cyber criminals continue to advance their techniques, CyberArk’sregional director for ASEAN, Cynthia Lee tells us how this can also impactoil and gas organizations in the Asia-Pacific region.
16 BP strengthens presence in RussiaBP’s involvement in Russia could potentially increase oil exports to energy-thirsty Asian countries like China, Japan, India and South Korea.Eugene Gerden investigates.
18 Subsea reliability of multiphase metersAlthough multiphase meters bring a number of benefits like reducingcapital and operational expenditures, the recovery cost from wrongmetering can also be exceptionally high. Emmelyn Graham explains.
22 Valve endurance with Nanotechnology
Dr. Yuri Zhuk, Hardide Coatings’ technical director discusses the use ofadvanced chemical vapor deposition (CVD) tungsten carbide coatings toextend the life of valves in subsea environments.
26 Capreolus 3D illuminates newoil prospect offshore AustraliaPolarcus discusses the 22,130sq km Capreolus 3D seismic survey acrossthe Roebuck Basin, considered to be the bir th of a new oil province forAustralia.
30 Under construction in SingaporeAlan Thorpe gives a rundown of some of the floating production, storageand offloading unit conversions and shipbuilding underway in SembcorpMarine and Keppel Offshore and Marine shipyards.
32 Perth basin gas discovery prompts economic boomAWE’s onshore exploration could deliver significant gas into the WesternAustralia domestic market, plus generate economic opportunities in theregion. Ian Howarth reports.
GEOFOCUS: MALAYSIA
34 Malaysia has ambitious plansMalaysia aims to grow its oil and gas production capacity by 5% per annum,plus increase the energy sector’s GDP contribution to US$70 billion by 2020.The Malaysian Investment Development Authority (MIDA) shows how.
36 Safety and technical skills developmentMalaysians can now be trained to globally recognized industryqualifications allowing them to work in oil and gas sectors anywherearound the world.
PRODUCTS & TECHNOLOGY 40 Solutions
New tools and software to improve performance, production, and modeling.
COMPANY NEWS
42 Activity C-Mar and Shanghai Maritime University launch dynamicpositioning center, plus other regional news.
SPOTLIGHT
44 Moving to Southeast AsiaThe culture, entrepreneurial spirit and experience of being in a growthmarket makes it all very appealing to work in the Southeast Asian oil andgas sector, says Suerd Polderdijk, general manager Asia-Pacific, Frames.
FACTS & FIGURES
46 Numerology A capsule view of interesting industry statistics.
Contents
On the cover
AOG looks into a three well
exploration and appraisal
drilling campaign with upside
potential of 1.3 Tcf of gas, mak-
ing this the largest onshore
gas discovery in Western
Australia since the 1960s.
Read more on page 32.
Photo from Awe Ltd .
P e r t h ba s i n
e x p l o ra t i o n 3 2
C y b e r s e c u r i t y
s o l u t i o n s 1 4
Ma la y s ia d e l i v e
r s sa f e t y t ra i n i
n g 3 6
ao g d i g i t a l.co m
▼
Ma y - J u ne 2 0
1 5
A S IA N
O I L & G
A SAOG
22
30
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ANNIVERSARY
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Editor’s Column
Investing in AsiaChallenges and opportunities in Vietnamese fractured basement dril ling was one of the few Asian h ighlightsat the 2015 Offshore Technology Conference (OTC) held in
Houston this May.
Most of Vietnam’s oil production comes from the granite
basement in the Cuu Long basin, comprising of large oil pro-
ducing fields with an estimated 3.37 billion bbl of crude oil
potential.
In an interview, Nguyen Tien Long, vice president for explo-
ration at PetroVietnam Exploration and Production noted that
out of the 935 drilled wells in the Cuu Long basin, 500 were
drilled in the granite basement.Although the Cuu Long basin is one of the most difficult
environments to explore, thanks to improved technologies,
wells that once took about three months to drill can now be
completed within six weeks, Long said, as he encouraged
exploration investments.
China, on the other hand, is home to some 1.1 Tcf of shale gas
deposits. In its attempt to replicate a US-style shale boom, the
Chinese are also promoting foreign oil and gas investments.
Cost, complex drilling and insufficient infrastructures like
pipelines and supporting facilities are some of the key chal-
lenges for this development.
In a meeting organized by OTC and the US Department of
Commerce, Michael Haney, director of Douglas Westwood saidexploration and production activities are expected to grow
from moderate to high in China.
With PetroChina and Sinopec actively exploring for shale
gas in the Sichuan Basin, China will look into expanding
business in the Sichuan a rea.
However, while the natural gas market is expected to grow,
China will still rely on imports for the coming years, because
domestic production will not keep up with demand.
Back in the Queensland state of Australia, about 11,000sq
km is being released for exploration in the Cooper, Eromanga
and Surat basins.
The bargain here, according to the Australian government,
potential investors will also have access to approximatelyAU$70 billion worth of infrastructure in pipelines, processing
facilities and liquefaction plants.
Furthermore, Australia is also offering 29 offshore blocks
across eight basins for investors to bid, as part of it its annual
Offshore Petroleum Exploration Acreage Release.
These blocks are located offshore the Territory of Ashmore
and Cartier Islands, Western Australia, Victoria, South Aus-
tralia, the Northern Territory and Tasmania.
Specific areas to look out for include six in the Bonaparte
basin, four areas in the Browse basin, one for the Roebuck
basin, eleven in the Carnarvon basin, one area in the Ceduna
basin, three for Otway basin, one spot in t he Sorell basin and
two in the Gippsland basin.
Indonesia, a former Organization of the Petroleum Export-
ing Countries (OPEC) member, is shifting exploration activi-
ties from the west to the eastern parts of the country.
Basins in Papua, Moluccas, Halmahera and Sulawesi have
been said to have some large quantities of hydrocarbon po-
tentials, but due to its’ remote and offshore locations, explor-
ing these basins are becoming costly, plus require advanced
technologies.
According to KATADATA, an Indonesian research firm,
Papua alone has around 61.7 MMbbl of oil and 23.46 Tcf of gas
reserves, while Sulawesi holds about 50.17 MMbbl of oil and
2.56 Tcf of gas reserves.Underinvestment has hindered progress in the Indonesian
oil and gas sector because of regulatory frameworks in the last
couple of years.
This draws back to the land tax imposed by the government
in 2010 to have production sharing contract (PSC) operators
pay tax while exploring for hydrocarbons, whether a success-
ful attempt or not.
New regulations introduced in 2014 to restrict foreign
investments in Indonesian oil services has also hampered
investor opportunities, as the government was keen to give
priority to domestic companies. In order to revive exploration
investments, Indonesia has now scrapped land tax, as part of
its investor-friendly reform.According to the Malaysian Investment Development Au-
thority (MIDA), Malaysia has attracted its fair share of inves-
tors in the upstream, midstream and downstream sectors.
The country currently homes over 3500 oil and gas busi-
nesses comprising of internat ional oil firms, independent
service providers and manufacturing companies.
It is of no doubt that Asia can provide lucrative opportuni-
ties for both local and international investors seeking business
expansion in the region. AOG
Audrey Raj
Editor
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Regional Briefs
AS IAN O I L & GAS
AOG
May · June 2015
Australia
• BEACH HITS AT COOPER BASIN
Beach Energy encountered oil shows at
the Callawonga-10 oil development well
onshore South Australia.
Callawonga-10 is located in PPL 220 on
the western flank of the Cooper basin and
is the first of a three-well drilling cam-
paign target ing the Namur Sandstone.
Drilling with the EDA Rig 903, the well
reached 1482m in the Westbourne forma-
tion where oil shows were observed in
the primary targets, McKinlay Member
and Namur Sandstone with a total gross
oil column of 4.8m. Joint venture pa rtners Beach and
Cooper Energy have cased and suspend-
ed the well to accelerate oil production
from the southern area of the field.
According to Cooper Energy, pre-drill
modeling indicated Callawonga-10 has
potential to produce up to 200,000 bbl
of oil, of which approximately 85,000
bbl could be incremental 2P reserves.
Further work is required post-Callawon-
ga-10 to confirm these estimates.
• AUSTRALIA PACIFIC LNG
POWERS UP
The start-up of the first of seven gas
turbine power generators that are de-
signed to provide electrical power to the
Curtis Island LNG facility has begun in
Australia.
Australia Pacific LNG said that while
the majority of the natural gas arriving
at the LNG facility will be processed and
exported as l iquefied natural gas (LNG),
a small amount will be used to power
the gas turbine generators to generate the
electrical power required to operate the
two LNG processing trains.
Each of the Bechtel-constructed sevengas turbine generators will produce a
peak output of approximately 15 mW and
combined will deliver 105 mW.
“We will progressively test and start ad-
ditional critical elements of the process-
ing trains to bring the LNG facility on
line and ready for first LNG export,” Page
Maxson, Australia Pacific LNG CEO said.
• CHEVRON FINDS GAS IN GORGON
Chevron Australia hit an additional gas
discovery at the Greater Gorgon Area,
located in the Carnarvon Basin, offshorenorthwest Australia.
The Isosceles-1 exploration discovery
well encountered approximately 134m
of net gas pay in the Triassic Mungaroo
Sands in 968m of water.
The well is located in the WA-392-P
permit area approximately 95km north-
west of Barrow Island, off the coast of
Western Australia.
“This discovery is a continuation of
our exploration and further positions our
company as supplier for future liquefied
natural gas (LNG) demand in the Asia-Pacific region,” said Melody Meyer, presi-
dent, Chevron Asia-Pacific Exploration
and Production.
• BENGAL UPDATES
CUISINIER OPERATIONS
Bengal Energy Ltd., completed the phase
two drilling campaign on ATP 752 Barta
Block, where it has a 30.357% working
interest.
Average gross production from the
Cuisinier field, prior to the tie-in of the
new phase two wells and the reactivation
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of the Cuisinier-6 well was approximate-
ly 1653 bo/d.
The drilling campaign exceeded
Bengal’s technical and commercial ex-
pectations. With three of the four cased
wells now completed as oil wells, the
group expanded the pool boundaries and
tested the structural flank positions for
the presence of oil.
The last well of the phase two drillingcampaign, Cuisinier-21, tested the north-
west flank of the Cuisinier structure. The
well encountered oil in the Murta DC70
zone with reservoir pressure at approxi-
mately 96% of virgin pressure.
The Murta DC70 zone in this well
came in structurally below what had
been established by other producing
wells. Upon perforation the Cuisinier-21
well naturally flowed approximately 380
bo/d at 100% oil cut.
China• CNOOC BRINGS
KENLI 10-1 ONLINE
China National Offshore Oil Corp.
(CNOOC) began production at the Kenli
10-1 oilfield in the Bohai Sea, offshore
China.
The Kenli 10-1 oilfield is located in
the South of Bohai with an average
of 17m water depth. CNOOC said the
main production facilities of this
oilfield include one central process-
ing platform, two wellhead platforms
and 70 producing wells.There are currently 12 wells pro-
ducing approximately 10,750 b/d of
crude oil, with expectations of reach-
ing 36,000 b/d at peak production in
2016. CNOOC is the operator of Kenli
10-1 with 100% interest.
• TECHNIP BAGS
CHINA’S FIRST TLP GIG
CNOOC also awarded the Technip
and China Offshore Oil Engineering
Co. (COOEC) consortium a front-end
engineering design (FEED) contractfor two tension leg platforms (TLPs)
for the Liuhua 11-1 and 16-2 joint
development project located in the
South China Sea.
Liuhua sits 240km southeast of
Hong Kong, in about 370m water
depth. Technip will be responsible
for the FEED work of China’s first
two TLPs. The contract covers the
design and engineering of the top-
sides (including two drilling rigs),
hulls, mooring and riser systems.
It is to be completed by the end of
2015. Technip’s Houston operating center
will execute the FEED contract.
• SINO GAS DOUBLES
SANJIAOBEI CAPACITY
Operations are well underway at the
Sanjiaobei block adjacent to Linxing
West and Mizhi fields in the Ordos
Basin, located in the Shanxi province of
North China.The second compressor at the
Sanjiaobei central gathering station has
been brought online, said Sino Gas and
Energy Holdings Ltd., increasing capac-
ity from approximately 2-8 MMcf/d.
Current production has been increased
to about 6 MMcf/d with 13 wells on-
line from the pool of 16 wells currently
connected.
New wells that have been brought
online to fill the additional capacity are
currently choked back and will gradu-
ally be opened up as flow rates stabilize.Field operations are underway with
four wells drilling and a fur ther two rigs
preparing to commence operations.
Six wells are currently undergoing
testing operations, which include devel-
opment and appraisal wells on Linxing
West and deep exploration wells on
Linxing East.
Japan• JAPAN’S TEPCO, THAILAND’S
EGAT TEAM UP ON LNG
Tokyo Electric Power Co. (TEPCO) signed
a memorandum of understanding (MOU)
with the Electricity Generating Authority
of Thailand (EGAT) in late May to createan LNG value chain business, which cov-
ers the procurement, transportation and
supply of LNG for electricity generation.
TEPCO said the new venture would be
its first undertaking of such an LNG busi-
ness overseas.
TEPCO said it decided to enhance its
cooperation with EGAT, which plans to
build a new LNG thermal power station
in Thailand and has been negotiating
with TEPCO towards cooperation in LNG
value chain business.
Going forward, the two companies willimplement activities in accordance with
the MOU, such as information exchange
and mutual training courses. TEPCO said
it believes its newly formed joint venture
with Chubu Electric Power Co., called
JERA, would be useful in this endeavor.
Indonesia• OIL FLOWS FROM BUNIAN-3
WELL
Testing of the Bunian-3 sidetrack 2
(ST2) development well has begunwith oil flows from the primary
target TRM3 sand.
Bunian-3 is located 730m south-
west of Bunian-1 and the primary
target is the Talang Akar Formation
TRM3 sand. It is an onshore well
in the Sukananti KSO in South
Sumatra, Indonesia.
The TRM3 sand flowed
for two hours at a stabilized
flow rate equivalent to
1742 bo/d through a 1/4-in
choke, with a flowing tubing
head pressure of 500 psi.
According to Cooper
Energy Ltd., the flow con-
sisted of oil and gas with no
water, and measurements
to quantify the gas rate are
ongoing.
Oil flows are being direct-
ed to a temporary produc-
tion facility and produced
oil is being trucked directly
to market. •
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design, engineering, procurement,
fabrication, installation and commis-
sioning of six pipelines totaling to 60km,
scheduled for completion by the second
quarter of 2016.
“The company is optimistic about
prospects despite the fall in oil price
and including the cutbacks in capital
expenditure by some of the oil majors.
We believe that our strategy of establish-ing long-term relationships with clients
and suppliers has put us in good stead for
a time like this,” said group chief execu-
tive officer and president, Francis Wong.
• RIL DEVELOPING
MJ OFFSHORE INDIA
India’s Reliance Industries’ (RIL) MJ dis-
covery is estimated to have 1.4 Tcf of un-
risked contingent resources offshore India,
according to partner Niko Resources.
The joint venture recently received an
independent resources evaluation frompetroleum engineering firm Deloitte LLP
on the MJ Discovery, in the D6 Block.
D6 is located in the Krishna-Godavari
basin and spans over 1.88 million acres.
Dhirubhai 1 and 3 MA gas and oil fields
are also located in the block.
According to the report, Deloitte evalu-
ated the contingent resources based on
available information, including the
drilling, testing and coring results of the
MJ-1 discovery well and the MJ-A1, MJ-
A2, and MJ-A3 appraisal wells.
“The discovery and successful ap-praisal of MJ adds a new and exciting
chapter to the D6 Block,” said William T.
Hornaday, Niko chief operating officer.
“Going forward, the contractor group in
the block will be working on plans to
develop MJ, which may lead to potential-
ly significant additions to reserves and
production levels in the coming years.”
Malaysia• LUNDIN ACHIEVES
FIRST BERTAM OIL
Lundin’s Bertam field hit first oil offshore
Malaysia, with plans to continue produc-
tion from remaining wells throughout
2015.
The Bertam field is located in Block
PM307, offshore the eastern side of
Peninsular Malaysia. Production began
from four pre-drilled development wells.
The remaining production wells will
be drilled sequentially and put onstream
through the rest of the year, with thefield’s gross plateau rate of 15,000 b/d
expected to be achieved by late 2015.
The field is estimated to contain gross
reserves of 18.4 MMboe.
• JX NIPPON FINDS OIL
OFFSHORE EAST MALAYSIA
Japan’s JX Nippon Oil & Gas Exploration’s
Malaysia subsidiary is planning two
additional exploration wells offshore
Malaysia after confirming a deepwater
oil discovery.
The discovery was made at theBestari-1 exploration well in deepwater
Block R, located offshore East Malaysia
covering an area of 672sq km with water
depth ranging from 100-1400m.
Preliminary findings point to an ap-
proximate 70m column of oil bearing
sands across multiple horizons, an-
nounced joint venture partner Inpex.
The group will analyze and evaluate
the data retrieved from the well, and pro-
ceed with plans to dril l two exploratory
wells to assess the possibility of new oil
and natural gas deposits.
• STATOIL COMPLETES SALE OF
SHAH DENIZ SHARE
Statoil completed their sale of 15.5%
share in Shah Deniz to PETRONAS, an-
nounced previously on 13 October 2014.
The sale involved the transfer of
Statoil’s 15.5% participating interest in
the Shah Deniz production sharing agree-
ment, 15.5% share in the South Caucasus
Pipeline (SCPC), 15.5% share in the SCPC
holding company, and 12.4% share in the
Azerbaijan Gas Supply Co. (AGSC).Following this transaction the State
Oil Company of Azerbaijan, SOCAR, will
assume operatorship of AGSC and com-
mercial operatorship of SCPC as of 1 May
2015, which have both previously been
held by Statoil.
New Zealand• AWE PRODUCES OIL
OFF NEW ZEALAND
The subsea tie-back and installation
project to connect the Pateke-4H devel-
opment well to the Tui area oil fields
Myanmar • INTERRA TAPS OIL IN MYANMAR
Singapore-based Interra Resources
completed the development of the CHK
1196 well in the Chauk oil field in Myanmar,
where it holds 60% interest in the
Improved Petroleum Recovery contract.
CHK 1196 was drilled using the ZJ 450
rig owned by Goldpetrol Joint Operating
Co. Since Interra also owns 60% ofGoldpetrol, which is the operator of the
field, drilling costs were relatively low.
Indonesia• OPHIR EYES 2016-7
INDONESIAN DRILLING
Ophir Energy is to commission 2D and
3D seismic with a view to drilling on
2016-17 on four deepwater production
sharing contracts (PSCs) in Indonesia it
has now acquired from Niko Resources.
The PSCs, all in two core areas in
Eastern Indonesia – West Papua and theWestern Birds Head – are West Papua IV,
Aru, Kofiau and Halmahera-Kofiau, all of
which will be operated by Ophir now the
deal has completed.
Ophir is also in the process of com-
pleting the acquisition from Niko of two
additional PSCs – North Makassar Strait
and North Ganal; a further update on
these will be provided in due course.
Ophir has separately decided that it will
no longer be proceeding with the acquisi-
tion of the Obi PSC.
• OTTO MARINE DELIVERS
VESSELS WORTH US$36.6 MILLION
Singapore-based Otto Marine completed
the construction of two harbor tug and
two anchor handling tug supply (AHTS)
vessels for Indonesian PT Pertamina
Trans Kontinental (PTK).
The vessels were built by Otto Marine’s
PT Batamec shipyard team in Batam,
Indonesia, where an official delivery
ceremony was also held.
The deliveries consisted of two 3000 bhp
harbor tugs, Patra Tunda 3151 and PatraTunda 3152, plus two 5150 bhp AHTS,
Transko Balihe and Transko Moloko, all for
a total contract value of US$36.6 million.
India• SWIBER BAGS INDIAN EPIC
Singapore-based Swiber Holdings
secured an engineering, procurement,
installation and construction (EPIC) con-
tract worth US$133 million from same
Indian oil company, which awarded two
major contracts in February and March.
Previous agreements involved surveys,
Interra’s share of the cost of drilling was
funded from existing funds on hand. CHK
1196 was drilled to a total depth of 2900ft
in the Chauk South-Central fault block as
an up-dip offset development well to pro-
ducing wells CHK 1185 and CHK 1192, both
of which were completed as oil producers
in 2014.
Following four days of production testing,
CHK 1196 has been completed throughcasing perforations over 76ft covering nine
reservoirs for 30 bo/d.
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gathering system has been completed and
oil production has commenced.
Australian-based energy company
AWE Ltd., is the operator of the Tui area,
which comprises the Tui, Amokura and
Pateke oil fields located approximately
50km off the coast of Taranaki, New
Zealand.
“The Pateke-4H project was completed
with no safety or environmental inci-dents and initial production from the
well is in line with expectations,” said
AWE Managing Director Bruce Clement.
Papa New Guinea• SEARCHER BEGINS
2D BROADBAND PSDM
Searcher Seismic is currently reprocess-
ing two regional seismic datasets in the
Philippines and Papua New Guinea.
In the Philippines, the Pala-Sulu
seismic survey was acquired in 2011. The
dataset is currently being reprocessedwith broadband deghosting and pre-
stack depth migration (PSDM) to further
enhance the quality of the existing data.
The Pala-Sulu survey is being pro-
cessed following the recently completed
Mialara 2D new acquisition seismic sur-
vey, creating a comprehensive tied 10km
grid over the PECR5 blocks.
The Perth-based company is also re-
processing the Lahara 2D seismic survey
in Papua New Guinea, which includes
over 12,000km of 2D long-offset seismic
data over the southeastern Papuan Basin.The Lahara survey was acquired in
water depths ranging from 30 to 2500m.
According to Searcher, Lahara is re-
garded as one of the most comprehensive
seismic exploration datasets in the Gulf
of Papua.
• NEPTUNE BAGS SUBSEA GIG
Neptune has been awarded a five-year
offshore diving and subsea inspection
contract by Oil Search (PNG) Ltd.
Diving works will be performed froma client supplied vessel or facility at the
Oil Search base in Port Moresby, Papa
New Guinea.
Works will be focused primarily on the
Kumul Marine Terminal, the oil export
pipeline and CALM buoy with the option
to include other Oil Search assets as
required.
“The award of this contract demon-
strates our strategy for extending our
core capabilities into new geographical
regions. Neptune is well positioned to
service clients in Papua New Guineaand beyond from our various Australian
and South East Asian bases,” said Robin
King, CEO, Neptune.
Singapore • EMAS BAGS US$55 MILLION
PROJECTS
Headquartered in Singapore, EMAS AMC
won multiple new awards f rom various
oil and energy companies worth approxi-
mately US$55 million.
Scope of work includes project sup-
port, inspection, maintenance and repair(IMR), subsea removal work of pipelines
and structures, installation of buoys and
lifting of structures and mattresses, as
well as a f ront-end engineering design
(FEED) study.
EMAS AMC now has a backlog of ap-
proximately $1.0 billion, with majority of
the contracts to be executed over the next
24 months.
Thailand• KRISENERGY IN FIRST WASSANA DISCOVERY
KrisEnergy made its first discovery in the
Wassana oil field as it continues its Thai
drilling campaign.
The Rayrai-1 exploration well inter-
sected 50ft of net oil-bearing sandstones
after reaching a total depth of 1945m
using the Key Gibraltar jackup rig.
The well is in the 4696sq km G10/48
license located in the southern section of
the Pattani basin, in 170ft water depth.
It lies 2.25km north of the Niramai oil
discovery drilled in 2009.Drilling at Rayrai-1 began last week
to test the Early Miocene stacked fluvial
sandstones on a north-south trending
faulted basement high.
Once the well is plugged, the Key
Gibraltar will begin drilling up to 15
Wassana development wells. Production
at Wassana is scheduled to begin in the
second half of 2015 and plateau at up to
10,000 b/d of oil.
• SOLSTAD BAGS
CHEVRON 2016 CAMPAIGNSolstad Offshore (SOFF) received
confirmation from Chevron Offshore
(Thailand) Ltd., Chevron Thailand
Exploration and Production Ltd., and
Chevron Pattani Ltd., for the 2016
offshore installation campaign utiliz-
ing its derrick lay barge (DLB), Norce
Endeavour .
The contract value is confidential among
the parties, said SOFF in a statement.
Norce Endeavour will insta ll multiple
new wellhead platforms and subsea
pipelines for Chevron in the Gulf ofThailand.
The offshore scope of work includes
the installation of 14 wellhead platforms
and 15 pipelines with an estimated
utilization of the DLB Norce Endeavour
of around 200 days with preparation
for mobilization starting first quarter of
next year.
SOFF will also provide project manage-
ment, engineering, procurement and lo-
gistics to support the DLB installation and
construction scope of work through its
DLB Marine Projects group in Singapore.•
Singapore• SEMBAWANG SHIPYARD
WINS FSO GIG
Sembawang Shipyard, a Sembcorp Marine
subsidiary, secured a floating storage and
offloading (FSO) conversion contract from
Teekay Offshore Partners.
The S$56 million deal will see the group
work closely with Teekay to convert the
shuttle tanker Randgrid into an FSO for the
Gina Krog field in the North Sea.
Conversion works in-
clude installation of a new
helideck, hull reinforce-
ments, refurbishment of
submersible turret load-
ing (STL) compartment,
installation of offshore
crane, loading hose reel
package, azimuth thruster
and replacement of two
generators.
The yard will also fabricate and install
new living quarterdecks on the vessel and
associated piping and additional cabling
works.
Scheduled for completion in 11 months,
the vessel is expected to arrive at
Sembawang Shipyard in Singapore this
June. After which the FSO Gina Krog will
head towards the Norwegian North Sea
under a charter contract between Teekay
and Statoil. •
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Last year, oil and gas companies across Europe and North
America were hit by a group of Russian hackers known
as the Energetic Bear, and we in the Asia-Pacific region
escaped the crosshairs this time.
What the perpetrators were after are a lso found in enterprises
across Asia, making a similar attack highly possible. Perhaps,
not by the same group of criminals, but through the use ofsimilar tactics.
The Energetic Bear has been in operation since 2011 target-
ing companies within the energy and pharmaceutical sectors
in US, Spain, France, Italy, Germany, Turkey, Poland and more.
They have been hacking into intellectual properties and valu-
able datas.
Multinational companies have set up operations across the
globe and Asia, too, could become a lucrative target for such cy-
bercrimes. In fact, three out of the top five patent organizations
are based in this region.
According to KPMG, Asia-based energy firms are slowly
migrating their corporate values to digital assets like bid in-
formation. Compared to physical assets, such as facilities and
products in the past, this
makes them vulnerable
to cyber thieves. Thus, it
is critical we prepare adefense for the inevitable
threats that will target
intellectual properties.
Behind the
infiltration
In order to achieve their
goals quickly and ef-
ficiently, the attackers de-
velop privileged account
pathways to identify
themselves as de facto
insiders on networks.They obtain access to
companies’ credentials,
which help them gain
unfettered access to key
systems.
Methods like phish-
ing and watering hole attacks are employed for initial network
penetration, while industrial control systems (ICS) software
providers are infected with malware.
The two primary tools the Energetic Bear use for their opera-
tion are Remote Access Tools (RATs) such as Backdoor Oldrea
and Trojan Karagany.
Backdoor Oldrea is a light tool with minimum capabilities,which lets hackers maintain presence in networks, as well as
install complex malware on the infected machines.
Trojan Karagany, on the other hand, has the ability to
run modules like those that steal credentials and take
screenshots.
In the case of the 2014 attack, the hackers set up infrast ruc-
tures for further attacks. They used both tools to steal authori-
zations and gather system information like file lists, installed
programs, roots of available drives, data from email address
books and VPN configuration files.
These credentials allowed them to go deeper into the net-
works, impersonate employees and use privileged accounts to
reach systems.
As cyber criminals continue to advance their techniques, CyberArk’s regional director for ASEAN,
Cynthia Lee tells us how this can also impact oil and
gas organizations in the Asia-Pacific region.
Cybercrimes
in Asia
Privileged account security
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Low security spending
Energetic Bear is merely one of the many attacks plaguing
the oil and gas industry, with many other malwares, such as
Stuxnet, Shamoon and Night Dragon hitting companies across
the industry since 2009.
For example, a Unisys-commissioned study, conducted by
the Ponemon Institute found that 78% of critical inf rastructure
providers in Malaysia have experienced at least one breach
from 2013-2014.
About 57% of part icipants said they had experienced secu-rity incidents, due to insecure networks, and one in three were
caused by the use of social networks and unmanaged access to
cloud services.
Over the last few decades, business changes in the oil and
gas industry have affected cyber security standing as well. In
fact, the recent drop in global oil prices has prompted firms
across the industry to drastically reduce capital and operating
expenditures, including cyber security spendings.
Many companies in the industry are exposed to cyberattacks
through Big Data, which is managed by supervisory control
and data acquisition (SCADA) and ICS used for analysis. With
shareholders pressuring companies
to boost returns on investments andreduce costs, information technol-
ogy (IT) is being used for operational
efficiencies.
Thus, there is some hesitation
towards spending extra money on
cyber security; as such technolo-
gies are generally viewed as an add-
on. Even though organizations have
improved their abilities to imple-
ment cyber security tools, making
them invest in this area continues
to remain a challenge.
A recent Ernst and Young reportfound that oil and gas security
budgets have remained static, and
majority of spending on IT secur ity
was to simply maintain existing
security capabilities.
This budget constraint is further
complicated when IT departments
are focused on purchasing the latest
technologies, instead of evaluating
the root cause of security challenges
they face in order to better prioritize
finite budgets.
Lastly, with layoffs taking place inthe oil and gas industry, safeguard-
ing against insider threat has become
even more important than ever.
Businesses will need to closely
monitor and assess disgruntled
employees that may perform risky
acts detrimental to the establish-
ment’s cyber security, such as theft
of sensitive data.
Prevention
With security threats growing every
passing day, cyber security is critical
for the oil and gas industry. Organizations in the Asia-Pacific can
start by protecting privileged accounts, because even if attack-
ers manage to penetrate the network, this can stop them from
achieving their goals. The following techniques should be used
for risk mitigation:
• Using a jump server that disallows credentials f rom residing
on the endpoint machines. This prevents attackers f rom hijack-
ing and accessing sensitive assets;
• Monitoring activities on privileged accounts to understand
the difference between normal and anomalous behavior thatmight point to malicious activities;
• Using an automated password management product to
prevent typing or observing passwords when connecting to
network systems. This also protects against stealing passwords
from computer screenshots or key logging; and
• Using a credentials management system to create complex
passwords to guard against brute force attacks.
All companies in the Asia-Pacific that hold intellectual
properties should take steps by safeguarding their privileged
accounts against external attackers and stopping attackers from
masquerading as privileged insiders. AOG
• Disable inactive privileged accounts
• Use multifactor authentication for all admin access
• Ensure passwords are current with automated password verification/reconciliation
• Regularly change and verify hardcoded passwords embedded in applications
• Prevent password display to users through direct connection to a target system
• Eliminate privileged users directly accessing sensitive assets in IT infrastructure
•
Integrate dual-controls and helpdesk ticketing with credential request workflows• Proactively detect malicious behavior
Higheffective maturity
Mediumeffective maturity
Baselineeffective maturity
Organizations can control and protect privileged accounts through use of the best practices listed
below. Many of these practices require only process changes, while others may involve tools or
solutions to implement. To help you determine which actions give you the most benefit we have
grouped them by maturity level.
Privileged account security solutions best practices
• Automatically change privilegedaccount passwords on a 30 or 60-day cycle
• Use one-time passwords
• Implement session recording
• Eliminate the option of interactive(human)login for service accounts
• Change hard-coded or embedded passwordsfor scripts and service accounts
• Use focused auditing and monitor foranomalous behavior
• Inventory/reduce the number of privilegedaccounts in your organization
• Prohibit standard user accounts from havingprivileged access
• Create a process for on- and off-boarding employees that haveprivileged account access
• Eliminate the practice of accounts that have non-expiring passwords
• Store passwords securely
•Link all shared admin account activity to a specific individual
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Despite western sanctions on Russia, oil major BP plans
to significantly strengthen its presence in the country
during the next several years by entering into a project
for the development of large oil fields in Eastern Siberia.Under the terms of a preliminary agreement signed between
BP and Russia’s state-owned Rosneft, BP will acquire 20% stake
in East Siberian oil producer, Taas-Yuryakh Neftegazodobycha.
The value of the deal has not been disclosed, but it has been
estimated to be between US$700-800 million. Representatives
from Rosneft and BP have decl ined to comment.
Taas-Yuryakh, a Rosneft subsidiary, holds produc-
tion licenses for the Central and Kurungsk blocks of the
Srednebotuobinskoye field. This oil and gas condensate is
known to be one of the largest undeveloped fields in East
Siberia with approximately 135 million tonne of oil reserves.
Through this joint venture, both BP and Rosneft plan to
produce more than 5 million tonne of oil per year from theSrednebotuobinskoye field, with most production exported to
the Asia and Europe.
In 2014, about 25% of Russian crude oil was bought by ener-
gy-thirsty Asian countries like China, Japan and South Korea,
totaling imports to 592 million tonne.
Moreover, due to sanctions imposed on Russia by western
countries and reduced supplies to Europe, Russia has also seen
an increase in crude oil exports to Asia. Oil exports to Europe
fell to less than 3 MMb/d, compared to 3.72 MMb/d in 2013.
China at present accounts for the majority of Russian crude
oil exports, plus remains the world’s second largest consumer
of Russian oil after the Netherlands.
“Despite the sanctions Russia remains an extremely
important market for the company. BP is ready to increase itsinvestments in Russia, which will not violate any sanctions. In
the case of declined oil prices, there are some positive factors
associated with Russia,” commented BP’s CEO, Bob Dudley.
“The cost structure is built in rubles, that move in accor-
dance with oil prices and the company finds it easier to work
with such cost structure. I think Russia is one of the few
world’s countries, which rebuild its taxation policy with the
aim to provide a support to the domestic oil industry.”
Srednebotuobinskoye field development
First oil production from Srednebotuobinskoye started in
October 2013 and oil outputs reached 900,000 tonne the fol-
lowing year. In 2012, the field welcomed its connection to the160km Eastern Siberia Pacific Ocean (ESPO) oil pipeline used
to export Russian crude to the Asia-Pacific region.
Further development of the Srednebotuobinskoye field could
commence in the second quar ter of this year. Rosneft’s tech-
nologies and equipment will be utilized for the initial opera-
tion and those of BP’s, which are not subject to sanctions will
follow suit.
Russian geophysical company, OJSC Geotech Seismic, may
be involved for seismic study of the field, through the use of
foreign equipment and technologies.
“We operate mostly French Sercel and US ARAM equip-
ment. Telemetry systems, which are produced by the Saratov
plant are no inferior to foreign analogs, in terms of quality and
BP’s involvement in Russia could potentially increase oil
exports to energy-thirsty Asian countries like China, Japan,
India and South Korea. Eugene Gerden investigates.
BP strengthens
presence in Russia
Left: The Verkhnechonskoe field in East Siberia Photos from Rosneft.
Right: Rosneft CEO Igor Sechin and BP CEO Bob Dudley.
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speed of data transmission,” explained Salavat Zaripov, head of
Geotech Seismic.Currently, Russia’s dril ling fleet is estimated to be about 1900
units, of which 1500 are operational. Rigs produced from 1987
to 1992 that have a service life of 25 years will end in the next
three or four years.
Therefore, according to analysts at the Russian Ministry
of Energy, the Srednebotuobinskoye field operation may also
require the use of new drilling rigs, which could be supplied
by BP.
Eastern Siberian oil and gas reserves have so far been un-
tapped, because of geographical remoteness and harsh environ-
ment in the region. Poor infrastructure, too, makes it difficult
to transport equipment to Srednebotuobinskoye, as well as
export products from it.As a result, partners, BP and Rosneft, plan to transport
majority of future productions from the field through the
Baikal-Amur Mainline. It is one of Russia’s longest rail lines,
traversing Eastern Siberia and the Russian Far East. Parts of the
future production will also be transported through the ESPO
oil pipeline system.
Russia Sanctions
According to BP, the project does not violate any of the recent
sanctions imposed on Russia, because of its involvement in the
Ukraine crisis.
“However, the sanctions may significantly delay implementa-
tion of projects in Russia that involve the production of shale
gas, but it will not create serious problems for the country,” said
BP’s Dudley.The entry of the British company in Eastern Siberia has been
discussed for a long time. BP became a key foreign par tner
with Rosneft two years ago, after receiving a 19.75% stake in
the company, as part of the TNK-BP (Tyumenskaya Neftyanaya
Kompaniya-BP) consolidation.
Through TNK-BP both parties have planned to explore the
Domanik oil field in the Orenburg and Volga-Urals regions, but
plans were put on hold, due to sanctions and lack of resources to
import advanced technologies needed for the operation.
Despite this, BP will continue its operations in Russia for it
has already invested heavily in the country and to leave would
result in multimillion dollar losses, noted analysts at the Russian
Ministry of Energy. The company has also no plans to sell itsshare in Rosneft and is ready for implementation of its joint proj-
ects with the Russian company.
“Sanctions imposed on Russia were not as painful for BP, as
they were for ExxonMobil, who had to halt operations in the
Russian Arct ic,” said an official spokesman for Russia’s Minister
of Industry and Trade, Denis Manturov. According to the
Minister, departure of competitors from Russia, due to sanctions
will provide new opportunities for those companies who decide
to stay.
Strengthening its presence in Russia is par t of BP plans for
the expansion of its operations in the entire post-Soviet region.
This also involves the $6 billion worth development of the Shah
Deniz gas field in Azerbaijan. AOG
Lubricant drums in Vietnam.
Photo from BP.
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I
ntroduced in the early 1990’s as a game changing technology
for the oil and gas industry to meter unprocessed oil and gas
streams, the use of multiphase meters have grown significant-
ly over recent years.Multiphase meters are now installed topside and subsea in
fields around the world, including the deepwater Kikeh field
located 120km north of Eastern Malaysia, in water depths of ap-
proximately 1300m. The field has a recoverable reserve base in
excess of 400-700 MMbbl of oil.
As advancements have been made in multiphase flow meter-
ing technology, the industry has become more confident in the
performance and reliability of multiphase measurements.
Operators have also gained significant experience using themeters in subsea applications and now understand the magni-
tude of the issues and chal lenges involved.
Although much has been done to advance multiphase me-
tering technologies over recent years, improvements in their
reliability and performance for subsea applications is still
aogdigital.com AOG | May · June 201518
Although multiphase meters bring a number of benefi ts like reducing
capital and operational expenditures, the recovery cost from wrong
metering can also be exceptionally high. Emmelyn Graham explains.
Subsea reliability
of multiphase meters
Flow meters calibrated under laboratory conditions. Images from NEL.
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necessary to exploit full potential.
This is key to the economical development of deeper and
more complex fields, which would otherwise prove cost
prohibitive.
Multiphase meter benefits
Multiphase meters bring a number of benefits, such as reduc-
ing capital and operational expenditure, increase capability
to monitor individual wells in real time, reduce need for test
separators and associated maintenance, as well as minimal lossof production through well shutdowns during tests.
For subsea activities, installing multiphase meters can
provide further benefits, such as reduction in required piping
infrast ructure and the capability to install meters on each well
to continually monitor production.
It also allows different operators to share pipeline systems,
reducing cost and disruption, as individual well production
can be metered before commingling. The information provided
by multiphase meters is, therefore, crucial in allowing opera-
tors to make informed decisions.
Subsea impacts
Special considerations have to be made when installing amultiphase meter subsea, as the meters are exposed to much
harsher environments, which can have a major impact on mate-
rials, reliability, safety and accuracy.
When considering solutions to the issues of using subsea
multiphase flow meters, one major operator condensed this to
the ‘three Rs’ – retrievability, reliability and redundancy.
The cost of getting subsea metering wrong can be exception-
ally high. Retrieval alone of defunct meters can be extremely
expensive in deep waters, with one operator reporting costs of
around US$7.5million to recover one poorly performing subsea
meter.
Meters normally undergo a factory acceptance test (FAT) at
a multiphase flow measurement facility, before being installedsubsea. There is, however, still a risk that following installation
subsea the meter may fail to work. This makes the design for
meter retrieveability a major consideration, which can impact
on the overall cost of the meter.
First and foremost, a flow meter has to be capable of me-
chanically surviving the hostile conditions it will be exposed
to during its lifetime in service.
Like all equipment destined for subsea installations, to avoid
catastrophic failure, mul-
tiphase meters have to be
robust, reliable and contain
the fluid without leakage or
degradation to materials.Subsea meters must also
be compliant with subsea
equipment standards. From
an international perspec-
tive, this usually includes
ISO 13628, (Petroleum
and natural gas industries
design and operation of
subsea production systems)
and API MPMS Chapter 20.3
Measurement of Multiphase Flow.
The overall use of flow meters in Malaysia for well and reser-
voir management and allocation measurement are required to
comply with the Petronas Operations Management Guidelines
(PUGGA) Volume 7.
The installation and configuration of multiphase flow meters
require careful consideration to avoid any undesirable exter-
nal loading, thermal cycling and movement of meter joints.
These can significantly impact the meter’s reliability and
performance.
Meter failure
Fundamentally, multiphase meters have to be capable of with-
standing the flow assurance issues, which come with subsea
multiphase oil and gas production. This includes the formation
of hydrates, waxes, scaling, slugging, chemical deposits, ero-
sion and corrosion.
Although the multiphase meter on many accounts is used to
detect the very presence of these flow assurance issues to allow
early intervention, the meter itself and its performance can be
seriously hindered through exposure to such conditions.
Flow assurance issues.
The main reasons for meter failure include:
•Formation of waxes, hydrates, scales etc. inside the flow meter
body and in differential pressure impulse lines;
•Measurement sensors coated in deposits and fail to work or
provide incorrect measurements;
•Restrictions and blockage of pipes and inside the flow meter; •Damage of equipment from slugging; and
•Corrosion and erosion of the meter body and sensors.
Chemical deposits and formation of waxes and hydrates can
depend on the fluid temperature and pressure, fluid composi-
tion and flow conditions. Rapid changes in the temperature and
pressure, for example, during well shutdowns can cause major
flow assurance issues.
During well start-up extreme cooling to temperatures of
-40oC may occur and lead to large effects on the integrity and
reliability of multiphase sensor and components, as well as flow
assurance issues.
When looking at the reliability and performance of multi-
phase flow meters subsea, it is important to remember that the
NEL’s flow measurement
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overall measurement relies heavily on accurate fluid properties
input data, which is obtained from fluid sampling.Information relating to the water, oil and gas phases, such
as density and conductivity can have a very large effect on
the gamma densitometer and electrical sensor measurements
within the meter.
Therefore, inaccurate physical properties data can have a
large impact on measurement accuracy. For example, collecting
fluid sample topside may not be fully representative of fluids
subsea at the meter location, due to liquid holdup in lengthy
tiebacks.
The major difficulty with subsea metering is the complexi-
ties involved in obtaining a representative sample at such
water depths. Over the last decade, the industry has therefore
focused on developing dedicated subsea sampling technologiesdesigned to overcome these specific challenges.
The design, modeling and validation of subsea multiphase
sampling systems to demonstrate their ability to obtain repre-
sentative samples under challenging flow assurance conditions
and operating envelope has been crucial to reduce the risk of
failure in the field. The cost of getting a sample wrong can be
costly.
Many multiphase meters use a radioactive source as part of
a gamma densitometer to determine the water, gas and oil frac-
tions in the flow.
This could be problematic if over the lifetime of the meter the
strength of the source deteriorates significantly and interven-
tion at deep waters is necessary to replace it. Consequently,new technologies are now being developed, which do not rely
on radioactive sources to overcome this potential risk.
Redundancy
Redundancy of sensors and components are essential for
subsea applications to provide back up if a component fails.
Redundancy also allows cross checking and verification from
one sensor to another to validate performance and drift.
This is essential in subsea environments when there are
limited options for verification. Redundancy can be considered
for a number of components across the measurement chain,
including flow computers, pressure sensors and temperature
transducers.
The range ability of meters is
extremely important and is fre-
quently overlooked. Meters a re
often required to operate over very
wide flow ranges. It is vital that
the meter can cope with changing
flow conditions over the lifetime
of field production, especially as
the field depletes during the latter
stages leading to lower flows andproduction.
Although flow predictions and
modeling is used to size multiphase
meters for specific applications, me-
ters are sti ll prone to being under or
oversized. For example, the sensors
to measure the differential pressure
across the Venturi tube, which is
a key component when measuring
bulk flow rate, could be saturated or
operating at the lower limits. Hence,
the uncertainty of the measured flow rates will be much higher.
Reportedly, one operator reviewed the dif ferent types ofsubsea multiphase meter failure and the effect on the flow
measurement. They found that 10% of their subsea multiphase
meters had to be retrieved, only 70% to 85% of the meters were
considered as fully functional and 5% of the meters were out of
range.
Slow data communication was also identified as a major is-
sue. The table below provides a breakdown of other reliability
issues encountered during subsea multiphase metering.
Type of failure Meters affected
Gamma measurements to determine thephase fractions
20%
Electrical measurements, e.g. capacitancemeasurements to determine water-cut
Up to 30%
Issues with differential pressure sensorsfrom hydrates or being out of range
5%
Failure of subsea flow computer 2%
Subsea multiphase metering is still very much an evolving
technology and significant resources are being directed at im-
proving their reliability, accuracy and performance.
To overcome many of the challenges operators are working
more closely with meter manufacturers and industry exper ts
through collaborative joint industry research projects designedto advance the technology and best practice.
Looking at longer-term trends, the use of subsea multiphase
meters will continue to grow in order to enable the develop-
ment of remote and deepwater fields. AOG
Emmelyn Graham, senior measurement
consultant at NEL has specialised in wet gas
and multiphase flow metering for more than
eight years. She has also been involved in
producing new equations for the correction
of gas flows with entrained liquid for Venturi
tubes, which has been included in a new ISO
wet gas technical report.
Multiphase meter undergoing test at NEL’s flow measurement facility.
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Working in the oil and gas industry can be tough,
often operating in harsh and difficult environ-
ments. With pressure to extract oil from less
accessible reservoirs and carry out exploration in newfrontiers, it is increasingly important to ensure fields are
exploited economically.
The extreme environments and working conditions put
pressure on the equipment being used. Exposure to sand and
other elements in the oil and gas can lead to corrosion, abrasion
and erosion, resulting in component failures and unscheduled
downtime.
In a subsea environment, components are at particular risk
from chloride, sour gas and sour oil (H2S), all of which attack
stainless steel. Maintenance or replacement of failed parts is
costly as subsea interventions can involve a remotely oper-
ated vehicle (ROV) or saturation diver. In order to prevent
unscheduled downtime and costly maintenance, extending
tool life has become a key focus.
Valves are a vital link in the chain for oil and gas to control
the flow of abrasive, erosive and corrosive fluids and gases.
However, their resistance to wear and gal ling poses a mate-rial problem for oil and gas companies worldwide. Oil and gas
operators are set to spend US$6 billion on solutions to valve
maintenance and operational problems in 2015.
Using the nanostructured tungsten carbide-based coatings
can alleviate many of the issues found with coating valves
effectively.
Valve coating challenges
Bearing the brunt of shock loads and high pressures, some
valve components can become deformed, causing fracture,
chipping and catastrophic malfunction of equipment.
Sour oil and gas containing aggressive H2S, other grades
of crude containing CO2 and acidic fluids can quickly attack
Dr. Yuri Zhuk, Hardide Coatings’ technical director discusses the
use of advanced chemical vapor deposition (CVD) tungsten carbide
coatings to extend the life of valves in subsea environments.
Valve endurance
with Nanotechnology
Hardide coated components
being precision measured.
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valves, pumps and pipelines. Even without this additional
burden, valves in normal operation are still susceptible to
microcracking and fatigue erosion, with a possible outcome of
premature failure.
The hard materials t raditionally
used to coat tools in severe environ-
ments can be brittle when put under
the pressure of shock loads they
risk fracture, which may be cata-
strophic, compromising economics
and viability.
Combining the issues of corro-
sion, abrasion and erosion seenin subsea environments a coat-
ing solution becomes difficult to
determine. Common anti-corrosion
coatings are not hard and will
not effectively protect against
abrasion.
In the past, hard chromium
electroplating was seen as a trusted
solution to extend the life of valves,
but this will be severely restr icted
or banned under environmental
health and safety guidelines as
they utilise carcinogenic hexava-lent chromium salts in their
production.
Hard chrome coatings contain
networks of micro cracks. These
cracks provide pathways for cor-
rosive media to attack substrate materials. This has been con-
firmed by salt spray testing, which demonstrated the superior-
ity of both hard chrome and HVOF coatings.
HVOF is a type of thermal spray coating technology used to
deposit tungsten carbide grains contained in a cobalt binder.
This is a line-of-sight technique, and as such is unsuitable for
coating internal faces and other complex designs.
The resultant coatings are rough and porous in nature and of-ten require grinding which is not possible on intricate shapes.
CVD coating technology
Applied by low temperature CVD coatings are crystallized from
the gas phase atom-by-atom, producing a conformal coating,
which can coat internal and external surfaces and complex
shapes.
CVD takes place in a vacuum chamber reactor at tempera-
tures of approximately 500oC. The coatings are a metallic tung-
sten matrix with dispersed nanoparticles of tungsten carbide
typically between 1-10 nanometers in size.
Dispersed tungsten carbide nanoparticles give the material
enhanced hardness, which can be controlled and tailored togive a typical range of hardness of between 1100 and 1600Hv.
Abrasion resistance is up to 12 times better than hard chrome
or 500 times better than Inconel.
Nanostructured materials are known to possess unique
toughness, crack and impact resistant features. For example,
Hardide-T has proven this by withstanding 3000 microstrain
deformation without any damage; this deformation will crack
or chip most other thick hard coatings.
During t he 30-day test the uncoated control sample
cracked across the ful l 20m width and suffered from exten-
sive micro cracking and pitting, while the same substrate
coated with Hardide-T showed no micro or macro c racking
or degradation after the same test, completely isolating the
Reactor loading. Images from Hardide.
Top: Hardide coated ball valves. Above: Hardide coated internal
surfaces.
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reduction feed liquor
(RFL) level control to BHP
Billiton’s Kwinana Nickel
Refinery, located in the
south of Perth.
This is a severe service
application, due to the high
pressures and tempera-
tures and the inherently
erosive natures of the oper-ating environment, which
is primarily ammonium
sulphate with dissolved
nickel metal and ammonia
in water.
Between 1993 and 2010,
WPC redesigned the plug
stem four times in efforts
to extend its lifespan. The
fourth design lasted the
longest with a life span of six to eight weeks. The average repair
cost after a plug failure was AU$12,000.
Hardide Coatings worked with WPC to engineer a coatingsolution on the fourth design, which has extended the life of
the part up to three fold. The plug stem now has a life cycle of
approximately four months in service with minimal wear to
the plug. The coating is now standard on all overhauls, saving
considerable downtime and repair costs.
The UH-550 with integrated ball valve is designed for criti-
cal subsea applications, such as wellhead control. The handle
mechanism on the valve is operated by a ROV manipulator to
control flow at pressures up to 10000psi.
This application required a wear resistant coating that would
protect the ball assembly against abrasion from sand and other
materials, as well as corrosion. It also needed to be smooth and
non-porous for sealing against a PEEK inlay and low friction sominimal torque would be required for operation.
Conclusion
In an industry, which is fast paced and challenging, compa-
nies, are under increasing pressure to seek ways to improve
performance while delivering reduction in downtime and
meeting environmental regulations.
The challenging environments put pressure on the equip-
ment, leading to failure of critical components, downtime
and lost production. Tungsten carbide CVD coatings pro-
vide an effective solution for these problems, ensuring
extended life of critica l components and less time spent on
maintenance.The use of this CVD process opens the door to advance
design for valves operating in extreme subsea conditions, en-
abling a level of engineering flexibility that is not possible with
alternative technologies.AOG
Dr.Yuri Zhuk is the co-founder of Hardide
Coatings and is currently responsible for the
company’s technology, research and develop-
ment, patenting, production improvement
and applications development programs.
substrate from attack.
This demonstrated that the coat ing could help extend the life
of the valves controlling sour oil and gas in both upstream anddownstream applications.
A number of CVD coating variants are offered to solve prob-
lems, such as severe wear, corrosion or galling. Components,
such as valves will be found in subsea equipment like ROVs
and using a CVD coating can increase the lifetime of a critical
component dramatically.
Projects have proven that parts can last up to four times
longer with a CVD coating than traditional materials, saving on
costly component failure and general maintenance.
Applying CVD to valves
Traditional line-of-sight coating methods present issues with
cages and plug trim in choke valves. They would clad the outersurface of the component, but not coat the inner diameters of
the through holes, which run along the sleeve.
Due to their pressure reducing role, the choke valves face
high velocities and abrasive media, so lack of coverage can
cause additional wear and erosion issues on the exposed base
material.
Ball valves can also suffer from severe abrasion by sand or
stone chippings present in fluids, and from erosion by acceler-
ating flow when the valve is being closed or opened. The CVD
coatings make the valve parts resistant to scratching and wear
by sand, which leads to valve leaking.
The metal-to-metal seals in ball valves face a hardwearing
application and there is sometimes a need for flex in the mate-rial. Traditional carbides cannot fulfil this as its rigid nature
is conducive to cracking and the component geometry is also
unsuitable for machining post coating.
The CVD process also eliminates the potential for edge chip-
ping, a particular problem in ball valves up to 4in when using
the traditional methods. Other benefits of utilizing CVD on
smaller balls and seats are the shorter lead times through batch
processing and the coast savings achieved by eradicating the
need for machining after coating.
Australian case study
Western Process Control (WPC) based in Western Austra lia
supplies Fisher ‘AA’ 80mm angle body control valves for
Unitech UH-550 2in male stab connector with integrated ball valve.
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Years
Global Collaboration • Local Resources
lagcoe.com
LAGCOE proudly celebrates 60 years supporting the oil and gas industry
through world-class expositions, technical presentations, and a commitment
to industry education…and we’re Still Climbing.
Attendees enjoy one of the most culturally inspiring areas in the U.S.,
Lafayette, Louisiana - gateway to America’s Energy Corridor.
Register now at:
lagcoe.com/register.
2015
October 27 -29 , 2015 | La fa ye t t e ,Lou i s i ana USA
& StillClimbing
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Polarcus discusses the 22,130sq km Capreolus 3D
seismic survey over the Roebuck basin considered to
be the birth of a new oil province for Australia.
Capreolus 3D illuminates newoil prospect offshore Australia
Top: Polarcus Asima in production mode. Images from Polarcus.
Left: Map of the Capreolus survey.
Polarcus’ Capreolus multi-client 3D seismic surveyoffshore Western Australia covers an area of 22,130sqkm, which is more than 30 t imes the size of Singaporeor about the size of Wales in the UK. The statistic also quali-
fies it to be the largest single 3D survey ever acquired offshore
Australia.
The project idea for Capreolus was conceived in 2014 after
the announcement that the Phoenix South-1 well had encoun-
tered light crude oil nearly 5km below the seabed, while drill-
ing for natural gas.
Discussions with oil and gas companies active on the NorthWest Shelf of Australia confirmed there was significant interest
in this well, because the area was only lightly explored and had
the possibility of a new oil province for Austra lia.
In response Polarcus drew up an initial survey outline for an
extensive broadband 3D seismic survey over the Roebuck basin,
including over the discovery location.
The company presented this plan to the industry and the
Capreolus multi-client 3D seismic survey was born, named
after a roe deer native to the British Isles that also gave its name
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R e g i s t e r
T o d a y !
Contact InformationSponsorship & Exhibits:
Gisset CaprilesTel: +1 713-874-2200
Conference:
Jennifer GrandaTel: +1 713-874-2202
Subsea Innovation and Effi ciency Delivering Economic Success
August 11-13, 2015
www.deepwaterintervention.com
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100m x 8,100m streamer array in the Bedout basin and a 12 x
100m x 9,000m array in the deeper Rowley basin, with a 12.5m
flip/flop source interval and 12-second record lengths.
It was agreed that data would then be processed through
pre-stack depth migration at DUG’s processing center in Perth,
Western Australia.
In order to acquire this vast survey efficiently and enable
final data imaging products to be available within 15 months ofproject mobilization, it was decided to acquire the survey using
dual vessel simultaneous mode acquisition, a technique previ-
ously used by Polarcus offshore Greenland.
The use of continuous data recording further enabled the
capture of the desired 12-second record lengths without com-
promising the objective of very high fold data.
Responsible exploration
The Capreolus survey area covers the North West Shelf
Province and the North West Transition bioregions; a known
humpback and pygmy blue whale migratory route, flatback
turtle breeding site, and a site for breeding seabirds and for
commercial fisheries.Therefore, maintaining a minimal environmental footprint
was critical.
The environmental plan identified that several species of
migratory marine mammals are known to traverse the survey
area during the proposed acquisition period.
Polarcus then decided to design an acquisition plan to pro-
vide temporal mitigation for the known migratory timing and
routes.
During the stakeholder engagement, other socio-economic
issues were also identified and addressed accordingly.
In particular, the pearl industry had concerns related to
periods of pearl oyster spawning, an