asian oil and gas-may-june 2015

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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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3/48May · June | AOG 3aogdigital.com

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




4/48

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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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8/48AOG | May · June 20158 aogdigital.com

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. •





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.




11/48

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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. •




13/48

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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





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





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.





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.




18/48

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.





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

facilityContent is copyright protected and provided for personal use only - not for reproduction or retransmission.




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.




21/48





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.





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.





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.




25/48

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





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




27/48

R e g i s t e r

T o d a y !

Contact InformationSponsorship & Exhibits:

Gisset CaprilesTel: +1 713-874-2200

[email protected]

Conference:

Jennifer GrandaTel: +1 713-874-2202

[email protected]

Subsea Innovation and Effi ciency Delivering Economic Success

August 11-13, 2015

www.deepwaterintervention.com





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

asian oil and gas-may-june 2015

Documents