exploration | drilling | production february 2019 · 2019-02-11 · agc chemicals americas - out in...
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FEBRUARY 2019 EXPLORATION | DRILLING | PRODUCTION
Redefining Measurements
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FEBRUARY 2019 EXPLORATION | DRILLING | PRODUCTION
ISSN 1757-2134
CCoontentsntentsFebruary 2019 Volume 12 Issue 02
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03 Comment
05 World news
10 Making the most of itBernadette Cullinane and Nye Hill, Deloitte, discuss Australia’s ongoing
move from oil to gas and what may lie ahead in the next year.
15 A new generationJohn Clegg, Weatherford International, USA, reviews the development of
the latest RSS tools.
19 It takes twoAdrian Ledroz, Gyrodata, USA, explains why gyro and magnetic surveys
should be combined for maximum accuracy.
22 Pulling the plugAndreas Fliss, Elisabeth Norheim and Roar Pedersen, Archer, Norway,
explore the use of retrievable bridge plugs to optimise well operations.
28 Striking a balanceBryan Steger, Emerson Automation Solutions, USA, explains how combining
the use of control valves and pressure regulators can help operators achieve
total system efficiency balance.
31 This feature showcases technologies designed to handle the harshest
conditions faced by the global oil and gas industry. Contributions come from:
CERATIZIT - Making the most of materials - Philippe Strebler, Luxembourg,
discusses the potential of cemented tungsten carbide to optimise
performance in the upstream industry.
AGC Chemicals Americas - Out in all weathers - Winn Darden, USA, examines
how corrosion-resistant FEVE-based coatings extend the life of offshore
oilfield structures.
41 Optimising well operationGunnar Hviding and Martin Bennetzen, RESMAN AS, Norway, review the
applications of intelligent chemical tracers for data collection.
45 Decommissioning: driving innovationAlejandro Alcala and Alexi Baker, Leyton UK, discuss the new technologies
and opportunities designed to optimise the decommissioning of offshore
assets.
47 A digitised futureRemco van der List, GustoMSC, The Netherlands, explores some recent
technologies developed as part of the digital transformation of the offshore
industry.
50 Simplifying system managementMatthew Treida, Weir Oil & Gas, USA, discusses how single large-bore
systems are helping to optimise frac site operations.
53 Taking AIM to the upstream sectorDave Maguire, Metegrity, explains how the right asset integrity management
(AIM) technology can digitalise processes and deliver actionable intelligence
for improved profitability.
Comment February 2019
David Bizley, Editordavid.bizley@oilfi eldtechnology.com
February 2019 Oilfield Technology | 3
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T here’s been much excitement around the North Sea over the last
few days as Total and CNOOC made what has been described as
the “the largest gas discovery in the UK since Culzean in 2008.”1
The Glengorm prospect, located in the Central Graben basin, was
drilled to a final depth of just over 5000 m and encountered 37 m of gas
and condensate pay in a high quality Upper Jurassic reservoir. Initial
analysis suggests that the find could hold as much as 250 million boe in recoverable resources –
right at the top end of expectations.2
The discovery didn’t come easily, however. Kevin Swann, a senior analyst in Wood
Mackenzie’s North Sea upstream team said, “This was third time lucky for CNOOC at Glengorm.
Technical problems saw it try and fail to drill the prospect twice in 2017, so persistence has paid
off. This is a good start to what could prove to be a pivotal year for UK exploration with several
high-impact wells in the plan.”3
According to analysts at Westwood Global Energy Group, the Glengorm find “will reignite
interest in the high temperature, high pressure plays in the North Sea and heralds a mini
renaissance in UK exploration.”4 Ross Dornan, Market Intelligence Manager for the trade
association, Oil & Gas UK, said: “The location of the discovery, in the central North Sea, also
provides a valuable opportunity to make use of the UKCS’ extensive infrastructure network.
Coming so soon after the Glendronach discovery in September, Glengorm is a major milestone
towards adding another generation of productive life to the UK North Sea and realising the
ambition of Vision 2035.”5
This positive news will come as a pleasant change for many in the region; the UK North Sea
has found itself in a difficult place over the last few years as low oil prices, mature fields and
ageing infrastructure have all weighed heavily on operators. Even before the downturn, UK
North Sea oil production had been on the decline for years. Peaking at 2.6 million bpd in 1999,
output subsequently fell to lows of 800 000 bpd in 2014. More recently there has been a period
of respite as new fields (BP’s Quad 204 and Enquest’s Kraken, for example) came online and new
technologies and processes, such as infill drilling, were deployed.6
With the downward trend expected to continue through 2019, there’s now hope that the
Glengorm discovery signals the beginning of a turnaround or, at the very least, a further pause
in the decline. Swann added, “There is a lot of hype around frontier areas like West of Shetland,
where Total discovered the Glendronach field last year. But Glengorm is in the Central North Sea
and this find shows there is still life in some of the more mature UK waters.”7 Indeed, companies
operating in the UK North Sea decided to press ahead with 13 new developments this year, a total
larger than the previous three years combined.
Despite the challenges, the UK North Sea still offers sizable opportunities to those with the
right expertise. There’s life in the old dog yet.
References1. ‘Glengorm ‘largest UK gas find since 2008’’ – https://www.woodmac.com/press-releases/glengorm/ 2. ‘UK: Total Announces a New Discovery in the North Sea’ – https://www.total.com/en/media/news/press-releases/uk-total-
announces-new-discovery-north-sea 3. Ibid. at 1.4. ‘High impact Glengorm discovery heralds a big year for exploration in NW Europe’ – https://www.westwoodenergy.com/
news/westwood-insight/high-impact-glengorm-discovery-heralds-a-big-year-for-exploration-in-nw-europe/ 5. ‘Oil & Gas UK welcomes Glengorm discovery as a major find’ – https://oilandgasuk.co.uk/oil-gas-uk-welcomes-glengorm-
discovery-as-a-major-find/ 6. ‘UK North Sea oil output to resume decline after brief respite’ – https://www.reuters.com/article/us-northsea-oil/uk-north-
sea-oil-output-to-resume-decline-after-brief-respite-idUSKBN1H213Y 7. Gas find in North Sea hailed as ‘biggest in a decade’ – https://www.bbc.co.uk/news/uk-scotland-scotland-
business-47041270
World news February 2019
In brief In brief
February 2019 Oilfield Technology | 5
Equinor: gas and condensate discovery south of Kristin fieldEquinor has, together with its partners Petoro, ExxonMobil and Total, proven gas
and condensate in the Norwegian Sea Ragnfrid North (6406/2-9 S) exploration well.
Recoverable resources are estimated at 6 - 25 million boe.
“We are pleased to start the new year by announcing a new discovery. Exploring for
resources close to existing infrastructure is a central part of Equinor’s strategy to further
develop the Norwegian continental shelf (NCS). We need these kinds of discoveries in the
years to come,” says Nick Ashton, Equinor’s senior vice president for Norway and the UK.
Ragnfrid North is located around 20 km south of the Kristin platform in the
Norwegian Sea. The discovery will help clarify the resource base in the area for the next years.
“Ragnfrid North will, together with the former discoveries Lavrans and Erlend East,
give a more detailed picture of the potential in this area of the Norwegian Sea,” says
Ashton.
The licence partners will now evaluate the discovery for development and tie-in to the
Kristin field and further maturing of the Kristin South project.
“The Ragnfrid North discovery will increase the probability of discovery for other
prospects and pave the way for more drilling operations in this central part of the
Norwegian Sea. This is something we will consider going forward while further analysing
the results. The NCS still offers great potential,” says Ashton.
IKM Testing awarded Tyra redevelopment contractTotal E&P Denmark A/S has awarded
IKM Testing a comprehensive contract on
the Danish Continental Shelf. The contract
includes cleaning and preparation for
the removal of existing platforms and
associated subsea pipelines. The contract
will mainly be carried out in 2019 and parts
of 2020.
The project will be managed from
IKM Testing’s Head Office at Sola, Norway. A
large amount of equipment and personnel
will be mobilised in Denmark during
offshore operations.
IKM Testing’s contract is divided into
three work packages: satellite pipeline
flushing, interfield pipeline flushing
and cleaning of Tyra East and Tyra West
topsides.
“We are very pleased with
Total DK trusting us with this award and
acknowledgment of our expertise in de- and
re-commissioning services. We look forward
to close cooperation with, and contribution
to Total Tyra”, says Vidar Haugland,
Vice President – IKM Testing AS.
Eni announces start-up of well, off shore AngolaEni has launched a new production well
in the Vandumbu field, about 350 km
north-west of Luanda and 130 km west of
Soyo, in the West Hub of Block 15/06, in
Angola’s offshore.
The start-up of the VAN-102 well –
which follows the start-up of the second
Subsea Multiphase Boosting System (SMBS)
– took place through the N’Goma FPSO
and achieved a performance of about
13 000 bbls. VAN-102 is a further step in
the development of the Vandumbu field,
launched on 29 November 2018, 3 months
ahead of schedule, and which will be
completed in Q1 2019 with the start-up
of the water injection well. This, together
with the start-up of another production
well in the Mpungi field, will bring the
production of Block 15/06 to a total of
about 170 000 boe/d, further extending the
production plateau.
Block 15/06 is developed by a Joint
Venture formed by Eni (36.84%, Operator),
Sonangol P&P (36.84%) and SSI Fifteen
Limited (26.32%).
Brazil Ocean Infinity has announced that its
partner, Cepemais, has been awarded
a contract to provide high-resolution
hydrographic mapping services to
Petrobras.
The project is for the Campos,
Espirito Santo and Santos basins,
offshore Brazil, and will see Ocean
Infinity working under contract to
Cepemais to map an area of 5000 km2
and inspect 12 000 km of pipelines.
Operating from Ocean Infinity’s
Island Pride vessel, the company’s
autonomous underwater vehicles
(AUVs) will be working in water depths
of between 50 and 3000 m. The data
collected by Ocean Infinity will then
be interpreted and reported upon
by Cepemais. Work commences in
mid-2019 and the contract duration is
for three years.
Oman Eni and the state company Oman Oil
Company Exploration and Production
(OOCEP) have entered into an
Exploration and Production Sharing
Agreement (EPSA) for Block 47 with
the Government of the Sultanate of
Oman.
Block 47 is located onshore in
the Omani A’Dakhiliyah Governorate
and covers an approximate area of
8524 km2.
The Block was awarded to Eni and
OOCEP following their joint bid as part
of the 2017 Oman Licensing Round.
Pursuant the EPSA, Eni is the
operator of the block with a 90%
participating interest and OOCEP
holds the remaining 10% participating
interest. Exploration operations are
expected to commence in 2019.
World newsFebruary 2019
Diary dates Diary Diary dates
To read more about these articles and for more event listings go to:
Web news Web news highlightshighlights
www.oilfieldtechnology.com
6 | Oilfield Technology February 2019
GlobalData: new upstream project startups set to soar in Europe from 2018 lows
UK: OGA launches Supplementary 31st Round for Greater Buchan Area revival
Woodside awards contracts for Scarborough project
McDermott awarded EPC contractMcDermott International, Inc. has
announced a significant contract award by
BP Trinidad & Tobago, LLC (bpTT) for the
engineering, procurement and construction
(EPC) of the Cassia Compression Platform,
located 35 miles (57 km) southeast off the
coast of Trinidad.
“This award demonstrates how,
through strong collaboration and consistent
project execution, we continue to build our
relationship with bpTT,” said Richard Heo,
McDermott’s Senior Vice President for
North, Central and South America.
This EPC contract follows the
completion of a detailed engineering and
long lead procurement services contract
McDermott completed for Cassia C earlier
this year, as well as the completion of the
engineering, procurement, construction,
installation and commissioning (EPCIC)
contract of the Angelin project for bpTT.
INPEX wins two exploration licences in NorwayINPEX has announced that through
its subsidiary INPEX Norge AS, it has
been awarded exploration licenses
PL1027 located in the western Barents
Sea offshore and PL1016 located in
the northern Norwegian Sea as part of
Norway’s Awards in Predefined Areas
(APA) 2018 licensing round.
The annual APA licensing rounds
aim to promote the further exploration
of blocks in previously explored, mature
areas by allowing tenders to be submitted
for any acreage within predefined areas
where licenses have not been awarded.
The licenses provide the groundwork
for INPEX’s third and fourth exploration
projects in Norway following the
company’s acquisition of exploration
license PL950 in 2018, and are expected to
contribute to the further enhancement of
the company’s global project portfolio.
25 - 27 February, 2019
OpEx in Energy, chemicals & ResourcesHouston, USAE: [email protected]
26 - 28 February, 2019
International Petroleum WeekLondon, UKE: [email protected]
05 - 07 March, 2019
SPE/IADCThe Hague, NetherlandsE: [email protected]
13 - 15 March, 2019
AOG 2019Perth, AustraliaE: [email protected]
27 - 29 March, 2019
OMC 2019Ravenna, ItalyE: [email protected]
Faroe Petroleum in Edinburgh prospect partnershipFaroe Petroleum has announced its partnership with subsidiaries of Royal Dutch Shell
plc (‘Shell’) and Spirit Energy Limited (‘Spirit’) following the award of PL 969 in the recent
APA licensing round with the intention to advance the large, cross-border Edinburgh
prospect towards a drill decision during 2019. Through a series of arrangements entered
into during 2018, the licence partners have agreed to equalise equity in UK Block 30/14a
(Edinburgh Area) and UK Block 30/14b on the same basis as the award in the adjacent
Norwegian Blocks 1/6 and 1/9 (PL 969) (together the ‘Edinburgh Area’) as follows: Faroe
45%, Shell 40%, Spirit 15%.
The equity equalisation remains subject to certain terms and conditions between
the parties and awaits deal completion of the acquisition related to UK Block 30/14a
(Edinburgh Area) from Total Oil UK Limited. It has been agreed by the parties that Faroe
will operate the Edinburgh Area licences up until a final well decision is taken by the
licence partners, after which Shell will become licence operator. The Edinburgh Area
contains the large Edinburgh prospect, which straddles the UK/Norway border in the
Central North Sea at the south eastern end of the prolific Josephine Ridge area. The
structure is a large, tilted Mesozoic fault block, and is considered to be one of the largest
remaining undrilled structures in the Central North Sea covering an area of over 40 km2.
The prospective reservoirs include the Upper Jurassic Ula age-equivalent (Freshney and
Fulmar) and Triassic Skagerrak formations.
Graham Stewart, Chief Executive of Faroe Petroleum, commented: “We are pleased
to announce the alignment of equity in the Edinburgh Area amongst such a strong
partnership, having worked to resolve the commercial impediments in the area for over
eight years. The partnership’s combined operating experience in both the UK and Norway
represents a distinct advantage in bringing the drilling of this high impact exploration
prospect closer to fruition. We look forward to working with the respective UK and
Norwegian authorities to progress this exciting cross-border opportunity.”
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8 | Oilfield Technology February 2019
February 2019World news
FAR Limited: seismic survey on WA-458-P completeFAR limited has announced that the
seismic acquisition across permit,
WA-458-P has been safely completed.
FAR is pleased to have completed
this survey, to enable a full evaluation of
WA-458-P, which lies within the prolific
Dampier sub-basin. This new data will
be used for detailed mapping of the
prospects which have been identified,
leading to selection of potential
candidates for drilling.
The company intends to farm down its
high interest in WA-458-P after completing
its evaluation of the permit using this new
seismic data.
FAR managing director, Cath Norman,
said, “It is great to finally complete
the seismic over the WA-458-P permit.
Offshore Western Australia has seen
a resurgence of activity following the
Dorado discovery and FAR looks forward
to completing this work on the block,
aimed at identifying a drillable prospect,
and then bringing in a partner for the
drilling.”
Contract extensions for SeaBird ExplorationSeabird Exploration has announced
the extension of two existing contracts
for the Voyager Explorer and the
Osprey Explorer.
The contract for the Voyager Explorer,
which is working on an ocean bottom
node survey in the Far East, has been
extended by approximately 90 days
until March 2019, with an option for the
charterers to extend by another 30 days.
The Osprey Explorer is also working
on an ocean bottom node survey in
the Americas region. This contract has
been extended from an initial 60 days to
approximately 180 days at present.
Following the completion of this
contract expected in early March 2019,
the Osprey will immediately commence
on a previously announced ocean bottom
node survey in the same region with
expected completion in mid-April 2019. Wood Mackenzie: Glengorm ‘largest UK gas find since 2008’“At 250 million boe, CNOOC Ltd’s Glengorm is the largest gas discovery in the UK since Culzean in
2008,” Kevin Swann, a senior analyst with Wood Mackenzie’s North Sea upstream team, said after
CNOOC and its partner Total announced the discovery. “There is a lot of hype around frontier areas
like West of Shetland, where Total discovered the Glendronach field last year,” he added. “But
Glengorm is in in the Central North Sea and this find shows there is still life in some of the more
mature UK waters.”
“The gas at Glengorm is subject to very high pressures and temperatures (HP/HT), which makes
it more challenging and costly to develop. However, there are other HP/HT fields in the vicinity, such
as Elgin/Franklin and Culzean, which could be used as tie-back hosts.” Mr Swann said: “This was
third time lucky for CNOOC at Glengorm. Technical problems saw it try and fail to drill the prospect
twice in 2017, so persistence has paid off. This is a good start to what could prove to be a pivotal year
for UK exploration with several high-impact wells in the plan.”
“Glengorm continues a spectacular run of high-impact exploration success for both CNOOC
Ltd and Total, ranked fifth and third in the world respectively, by exploration volumes discovered
in 2018. “Dr Andrew Latham, vice president, Global Exploration, said: “CNOOC Ltd is a 25% partner
in the prolific Stabroek Block in Guyana, where 5 billion boe has been found since 2015. It has also
found over 1.5 billion boe offshore China since 2017.” He added: “Total has reset its exploration
strategy under new leadership since 2015 and it is now seeing much improved results. “Over the
past year, Total operated the large Glendronach gas discovery in the UK West of Shetland and is a
partner in the giant Calypso gas discovery, offshore Cyprus, as well as the Ballymore find, a major oil
discovery in the US Gulf of Mexico. Through its 20% equity in Novatek, Total also holds an indirect
stake in the North Obskoye gas find, offshore Russia, the world’s largest discovery in 2018 with
reserves of over 11 trillion ft3.”
“Dr Latham said: “Exploration industry returns averaging 13% in 2018 were the highest in over
a decade, driven by lower costs and a focus on drilling prospects with a straightforward route to
commercialisation in the event of success. Glengorm fits this revitalised exploration model perfectly.
It looks to be a valuable discovery that should help sustain the industry’s profitability into 2019.”
Falcon Oil & Gas: rig contract signed for Beetaloo drilling programmeFalcon Oil & Gas has announced that Origin Energy B2 Pty Ltd. (‘Origin’), its joint venture (‘JV’)
partner and Operator of the Beetaloo project, in the Northern Territory, Australia, has signed
a rig contract with Ensign Australia Pty Ltd. for Rig 963 for the 2019 Stage 2 Beetaloo drilling
programme, with an option to extend the contract into 2020.
Subject to relevant approvals, and implementation of the exploration recommendations
of the Inquiry into Hydraulic Fracture Stimulation in the Northern Territory, the JV will evaluate
the potential of the liquids-rich gas fairways in both the Kyalla and Velkerri plays. Exploration
and appraisal activities include the drilling and hydraulic fracture stimulation of two horizontal
wells. Together with the Velkerri B dry gas play discovered in 2016, this allows for the
assessment of three plays, enabling the most commercially prospective play to be targeted for
Stage 3 drilling during 2020.
Work has already commenced at some well sites, including water bore drilling and
water monitoring, with drilling targeted to commence in June 2019. The Stage 2 Cost Cap is
approximately AUS$65 million for the exploration and appraisal programme, including the
drilling and hydraulic fracture stimulation costs of two horizontal wells.
Philip O’Quigley, CEO of Falcon, commented: “The announcement is an exciting
development for Falcon shareholders as the JV prepares to commence drilling in the highly
prospective Beetaloo Sub-basin. We look forward to updating the market as work progresses
over the coming months.”
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10 |
In 2018, Australia took the crown as the world’s largest LNG exporter
with the build out of ~88 mtpa of LNG production capacity. In the
last quarter of 2018, INPEX’s AUS$40 billion Ichthys project began
hydrocarbon production and Shell’s innovative Prelude Floating LNG
(FLNG) project achieved first gas.1 Both landmark events herald the
end of Australia’s hugely ambitious, US$200 billion, 10-year capital
investment programme, creating an economic growth engine driven
by production and exports.
This tectonic shift has seen oil and gas contribute mightily to
Australia’s GDP growth and economic welfare. According to ABS
data, the ‘value add’ from oil and gas extraction increased 10.8% in
2017 - 18, reaching a record US$30 billion.2 Much of this economic
contribution comes from the sharp increase in LNG exports, up 39%
y/y as new projects entered first production and existing projects
increased export volumes.3 Together with increased volumes of
condensate production, LNG will continue to provide a powerful
platform for Australia’s economic growth.
2019 starts on less firm groundThe oil price tailwind, so critical to the recovery in corporate
earnings and a more growth-orientated agenda, has run out
of steam. Oil is on track for its worst run in a decade, falling 22%
in a single month. Just a few months ago, the market was bracing
itself for the imminent arrival of US$100 oil and now, with talk of a
‘tsunami’ of US supply about to flood the market, the narrative is
sub-US$50 oil. Where oil goes next is anyone’s guess.
Tilting towards gasStructural shift s in the market favouring gas and renewables creates
further opportunity. Oil and gas companies are looking ahead, thinking
about future diversified revenue streams, asset configurations and
where growth will come from in a decarbonised world.
As the clean energy narrative develops, gas is expected to play a
critical ‘firming capacity’ role. It provides flexible and dispatchable
energy, mitigating some of the system security challenges that are
emerging with the rapid uptake of intermittent renewable energy
sources. Gas is the bridge fuel that will facilitate the transition from a
coal-based energy system to one powered by renewables. Gas is also
a market play where the sector has genuine expertise and knowledge.
While investments in clean energy from oil and gas companies
are relatively modest, that is not the situation for gas. Speaking
at the Oil and Money conference in London, Shell CEO Ben van
Beurden stressed that 4 - 8% investment in renewables and
clean energy does not reflect a strategic move away from its core
Bernadette Cullinane and Nye Hill, Deloitte, discuss Australia’s ongoing move from oil to gas and what may lie ahead in the next year.
| 11
12 | Oilfield Technology February 2019
hydrocarbon business.4 It is gas where Shell is investing serious
capital. In another telling move, the world’s biggest oil company,
Saudi Aramco, is looking to become a gas exporter; a strategy
that will require US$150 billion worth of investment over the next
decade.5 Additionally, Qatar’s global gas ambition (not to mention
deteriorating relationship with Saudi Arabia) has culminated in
a recent announcement of its decision to pull out of OPEC aft er
60 years of membership.6 The North American oil majors are also
courting gas in a big way, with both Exxon Mobil and Chevron
producing more gas today compared to a decade ago.
Australia’s competitors are not standing stillAft er a quiet few years, 2019 is likely to see a much more
active LNG investment pipeline globally. Recent analysis by
Wood Mackenzie predicts a sharp uptick in project sanctions with
total LNG spend up to US$200 billion estimated over the next
24 months. Operators globally are targeting the sanction of more
than 100 trillion ft 3 of gas projects in 2019, up from 32 trillion ft 3 in
2017, and about 90 trillion ft 3 in 2018.7
Following the lift of the moratorium on the giant North gas
field, Qatar plans to award contracts for four new mega trains.8
This will grow its LNG capacity from 77 to 110 mtpa. The LNG
Canada mega project announced a positive FID in October with
first gas expected in 2025. At least three US LNG projects are
waiting in the wings to receive FID in 2019. Russia’s US$27 billion
Arctic LNG -2 project is likely to be sanctioned in 2019 along with
a number of other big gas projects.
FLNG gaining tractionAccording to research by Westwood Global Energy, global
FLNG CAPEX will reach US$53 billion over the five-year forecast
horizon.9 Favourable cost economics, increased gas demand, fuel
switching and the short lead-time from sanction to operation
are all supporting growth. The next wave of FLNG project
sanctioning is expected to benefit from reduced supply chain
costs and innovative engineering and technology. Westwood
estimate liquefaction cost to average US$856/t per year for new
build vessels. Much of the FLNG spend will be in North America,
consistent with LNG project sanctions in the region.
Small is beautifulDespite a return of ‘mega projects’ in Qatar and Canada, the
next generation of LNG projects is likely to be less capital
intensive and complex than the first wave. Small-scale LNG will
define the next wave of gas development. These projects are
able to access smaller, stranded fields and supply customers
with smaller, shorter and more flexible volumes. We are likely
to see a shift away from the large-scale, capital intensive, land
based developments with modularisation and other innovative
project designs helping to transform the cost profile (and
overall economics) of LNG capital projects. As the chart by CIBC
clearly illustrates, there is work to do if Australian LNG is to be
competitive with other LNG projects.
Australia finds itself in a strange positionWith future LNG export capacity expected to come from the
US, Qatar, Russia and Canada, as Mozambique builds capacity,
Australia must focus on extending the life of its existing export
LNG projects and low capital intensity growth options like
debottlenecking and backfills. Woodside, for example, plans
to develop the Burrup Peninsula off the coast of WA into a
huge gas hub, developing up to 25 trillion ft3 of gas resources
from the Scarborough, Browse and Pluto fields.10 Beyond life
extension projects like this, it is difficult to see much scope for
greenfield projects.
The current market is intensely competitive, a diff erent
landscape from when the first wave of Australian LNG export
projects were commissioned. It is imperative that Australia keeps
Figure 3. Global FLNG CAPEX by region 2013 - 2014. Source: Westwood’s World
FLNG Market Forecast.
Figure 2. Oil price crash. Source: Datastream.
Figure 4. Estimated costs of recent liquefaction capacity additions. (bubble size
= capacity). Source: Company reports and CIBC World Markets Inc.
Figure 1. O&G economic contribution increases. Source: ABS National Accounts
June-18.
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14 | Oilfield Technology February 2019
costs down, incentivises local gas supply development, accelerates
the approvals process and introduces more attractive commercial
terms to compete with low-cost supply options overseas.
Eastern Australia continues to be an uncertain playing field for oil and gas investorsThe latest Fraser Institute survey on global petroleum investment
identifies the three southern states – Victoria, New South Wales and
Tasmania – among the world’s most unattractive destinations for oil
and gas investment, rubbing shoulders with the likes of Libya, Yemen,
Iraq and Venezuela.11 Worryingly, the investment climate in each state
is deteriorating further at a time when they are increasingly reliant
on imports of gas from other states to meet energy needs following
the closure of coal plants. As APPEA notes, the states most in need of
energy security are the most opposed to resource development.12
There is significant pressure on Queensland – home of the three
big LNG exports projects that rely on coal seam gas (CSG) as ‘feedstock’
(the Santos operated GLNG, ConocoPhillips and Origin’s APLNG and
Shell’s QCLNG) – to do the heavy lift ing. More gas is needed to meet
export commitments as well as ensure there is suff icient gas resource
for the domestic market. Simply drilling for more gas is harder than
it sounds, and no new easy and economical sources of supply are
currently available to the market. Despite ~13 000 PJ of undeveloped
gas resource in east Australia, it is prohibitively expensive to extract at a
time when Australia’s key rivals – Qatar and US – have very competitive
upstream development costs.
Impetus for reformFactor in an uncertain regulatory environment, ongoing tax reform,
mixed energy policy signals and state-imposed drilling moratoria,
and you have a challenging market for investors with no ‘magic
bullet’ or quick fix. Interventions by government – whether formal
punitive mechanisms like the Australian Domestic Gas Security
Mechanism (ADGSM) or tacit agreements between Government
and LNG producers to allocate gas for the domestic market – are
temporary solutions and fail to address the broader problems.
Recent moves by State/Territory Governments to release acreage
for petroleum exploration are a step in the right direction. WA’s
Petroleum 2020 reform project consolidates three petroleum and
pipeline Acts into one modern Act; and the LNG jobs taskforce aims
to establish Perth as an LNG hub similar to other international energy
hubs such as Aberdeen and Houston.13
There is need for further regulatory reform and a more dynamic
exploration policy if Australia is to provide better investment
signals to incentivise oil and gas development. Australia is at risk of
becoming a ‘bit part’ player (at best) in the next wave of LNG projects.
Without further market reform, the king of the castle could become
the butler overnight.
US-China trade ‘truce’ is a potential headwind for AustraliaTrade tensions between the US and China have caused significant
volatility in the world’s financial, equity and commodity markets.
The risks to global economic growth following the disruption to trade
is a negative for oil demand. Oil has pulled back alongside other
commodities due to twin concerns about trade and economic growth.
The 90-day trade truce recently brokered at the G20 summit between
the US and China had an immediate market impact with oil prices up
4%. That said, the devil is in the details, and there are uncertainties
regarding the exact timing of the truce and other key information.
LNG has also been in the firing line with China threatening to
impose a 25% tariff on US LNG imports. Ironically, the trade truce
could damage Australia’s gas industry. While light on detail, China’s
‘commitment’ to the US to buy more US goods could aff ect its
demand for Australian LNG.
Collaboration is keyThe recent agreement between two of the Queensland LNG projects
– QCLNG and APLNG – highlights a new collaborative spirit running
through Australia’s oil and gas sector.14 Under the agreement, APLNG
has agreed to buy 350 PJ of gas from QCLNG at an oil-linked price
over 10 years, and it is not one-way traff ic. QCLNG has permission
to transport and process gas and water from the Surat Basin using
the existing APLNG-QCLNG joint infrastructure. Australian LNG is
stronger together than apart and we are likely to see more examples
of infrastructure sharing arrangements and gas supply deals further
down the track.
Collaboration extends well beyond the gas producers. Woodside
and Chevron have formed an alliance with The University of Western
Australia to develop new subsea engineering technologies for
off shore oil and gas production.15 This move boosts Australian
competitiveness in the LNG market and reinforces Perth’s global
reputation as a centre for excellence in LNG technology and skills.
Australia should not risk complacencyWhile 2019 promises to be an extraordinary year for Australia’s LNG
industry, the handsome returns seen are by no means grounds for
complacency. An unpredictable and volatile international market,
coupled with increased competition from all corners of the globe, will
stretch the industry to scale new heights and reach for technological
innovation and greater inter-industry collaboration. If it rises to this
challenge, Australia will retain its global leadership position and
generate tremendous returns to companies, the Australian economy
and the global, low-carbon energy mix.
References1. ‘Shell says production at Prelude FLNG to start at end-2018’ – https://www.
reuters.com/article/us-shell-prelude-production/shell-says-production-at-
prelude-flng-to-start-at-end-2018-idUSKBN1O314R
2. ABS, cat. No. 5206.0, September 2018, Australian National Accounts: National
Income, Expenditure and Product, Jun 2018.
3. ABS, cat. No. 5368.0, August 2018, International Trade in Goods and Services,
Australia, Jun 2018.
4. ‘CEO: Oil, Gas Is Shell’s Core Business For The Foreseeable Future’ – https://
oilprice.com/Latest-Energy-News/World-News/CEO-Oil-Gas-Is-Shells-Core-
Business-For-The-Foreseeable-Future.html
5. ‘Saudi Aramco aims to become gas exporter with $150 billion investment drive’
– https://www.reuters.com/article/us-saudi-aramco-gas/saudi-aramco-aims-to-
become-gas-exporter-with-150-billion-investment-drive-idUSKCN1NW0EZ
6. ‘Qatar to Leave OPEC as Politics Finally Rupture Oil Cartel’ – https://www.
bloomberg.com/news/articles/2018-12-03/qatar-announces-opec-exit-days-
before-pivotal-oil-cuts-meeting
7. ‘Global upstream: 5 things to look out for in 2019’, Wood Mackenzie, 3rd
December 2018.
8. ‘Qatar Petroleum to further boost North Field output with new LNG train’
– https://www.offshoreenergytoday.com/qatar-petroleum-to-further-boost-
north-field-output-with-new-lng-train/
9. ‘World FLNG Market Forecast 2019-2024’ – https://www.westwoodenergy.com/
product/world-flng-market-forecast-2019-2024/
10. ‘BURRUP HUB’ – http://www.woodside.com.au/Our-Business/Developing/
Pages/Burrup-Hub.aspx
11. ‘Global Petroleum Survey 2018’ – https://www.fraserinstitute.org/studies/
global-petroleum-survey-2018
12. ‘Gas investors warned Australian states among world’s worst’ – https://www.
appea.com.au/media_release/gas-investors-warned-australian-states-among-
worlds-worst/
13. ‘WA Petroleum Day highlights Perth LNG hub plan’ – https://www.
proactiveinvestors.com.au/companies/news/204923/wa-petroleum-day-
highlights-perth-lng-hub-plan-204923.html
14. ‘APLNG, QCLNG strike deals on gas purchasing and processing’ – https://www.
afr.com/business/energy/gas/aplng-qclng-strike-deals-on-gas-purchasing-and-
processing-20181105-h17hyn
15. ‘New Australian oil and gas research centre opens’ – https://www.
energynewsbulletin.net/marine-subsea/news/1352189/new-australian-oil-and-
gas-research-centre-opens
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