OSEA2018 Show Daily Day 3

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OFFICIAL SHOW DAILY PRODUCED BY UPSTREAM

Thursday 29 November 2018

IN THIS ISSUE

Westex by Milliken and Teijin Aramid join forces to revolutionise aramid FR fabric Page 9 Survive dangers of oil and gas environments with specialised PPE Page 10 Hughes Pumps launches new UHP pump Page 10 Seamap completes Phase 1 construction of new Malaysia manufacturing facility Page 11 Franklin Offshore signs agreement with Lankhorst Ropes Page 12 Tunnel vision no more Page 12 Snapshot: OSEA Networking Night Page 12

Australia to firm up Timor-Leste border deal THE Australian government has taken a big step forward towards formalising its new maritime border with Timor-Leste by introducing a bill to parliament that will implement the new boundary and the Greater Sunrise special regime.

Page 3

Australian Foreign Affairs Minister Marise Payne

Photo: AFP/SCANPIX

INSIDE Floater fortunes

EMA believes FPSO market will stay resilient as recovery continues.

Page 2

Small-scale riches

Southeast Asia expected to hold great opportunities for small-scale LNG projects.

Page 4

Jadestone on track

Company on course with Nam Du and U Minh projects off Vietnam.

Page 5

China push

Chinese government approves three CBM ventures.

Page 7

Fight over Bight

Equinor sets out plans to drill in environmentally sensitive area off Australia.

Pages 14&15 Get up to speed with the latest news from the world of oil and gas. Visit us at Stand BH2 - 10 or log on to www.upstreamonline.com

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Thursday 29 November 2018

INDUSTRY OUTLOOK

Forecast: EMA managing director David Boggs at OSEA 2018

Photo: UBM

FPSO sector to stay strong Consultancy EMA believes market will remain resilient as recovery continues into 2020 NISHANT UGAL Singapore

THE floating production storage and offloading vessel market is expected to be resilient over the next four years, according to consultants Energy Maritime Associates (EMA).

Speaking at the OSEA 2018 conference in Singapore, EMA managing director David Boggs said the FPSO market was back on a strong footing, with the recovery expected to continue through to

2022. EMA said about 11 FPSO awards have been placed so far in 2018 after a lull in the floating production market that had lasted for two years.

Boggs believes there could be a pick-up in FPSO awards next year, with between 12 and 15 awards likely to be placed by various oil majors.

Under EMA’s high-case scenario, it predicts between 13 and

17 FPSO awards could take place each year up until 2022, assuming an oil price of between US$70 and US$90 per barrel.

It has also given a prediction for a mid-case scenario which estimates between 10 and 12 FPSOs being ordered globally given an oil price of between US$50 and US$70 per barrel, while its less likely low case scenario estimates seven orders annually at an oil price of

US$30 to US$50 per barrel. EMA sees strong FPSO demand until 2022 in the high case scenario, but it has cautioned capacity constraints and rising costs could limit orders after a two to threeyear period.

It is also assuming strong global economic growth and energy demand when arriving at the estimates for the FPSOs that are likely to be ordered over the next few

China and Singapore yards benefit in contract shift

THE locations at which floating production systems are being built have shifted in the past year towards China and Singapore, according to Energy Maritime Associates (EMA), writes Russell Searancke.

South Korea has been a traditional construction base for floaters, but some of the South Korean yards have experienced financial difficulties and this has been a contributing factor in a shift towards yards in China and Singapore, EMA’s managing director David Boggs told delegates at the OSEA 2018 conference in Singapore.

Chinese yards have, for example, dominated in the award of floating production, storage and offloading vessel contracts in 2018, with

six projects accounted for — P-71 in Brazil, Layang-Helang in Malaysia, Liza 2 in Guyana, Penguins in the UK North Sea, Tortue in Senegal and Mauritania, and Hai Yang Shi You 119 in China.

Boggs said there was a recognition among oil and gas operators that Chinese yards have improved their delivery performance in terms of quality and safety.

In Singapore, the major yards have secured a variety of recent floating system awards for projects including Johan Castberg in the Norwegian North Sea, Vito in the Gulf of Mexico and the main integration contract for Karish-Tanin in Israel. Meanwhile, South Korea, has been

successful in the liquefied natural gas arena, particularly with floating storage and regasification units.

Boggs said there are currently 49 floating production systems under construction, six floating storage and offloading vessels and four mobile offshore production units.

These floating production systems comprise 20 FPSOs, 16 FSRUs, five are floating LNG vessels, five are semisubmersible platforms, two are production barges and one is a tension-leg platform.

Boggs said there are nine speculative floaters on order, eight of which are FSRUs and one of which is a SBM Offshore’s Fast4Ward 2 FPSO.

years. Boggs also added that EMA sees a shift towards the FPSO newbuild market.

“We are seeing quite a shift towards newbuild units that are likely to be almost 40% of the FPSO market” Boggs said.

Brazil is expected to continue to lead FPSO demand globally and the number of floaters to be ordered by state-controlled oil giant Petrobras will play a crucial role in determining global demand for such units.

Boggs said that FPSO awards by Petrobras resumed in 2017 after a two-year hiatus and EMA is hopeful the state-controlled giant will place orders for two to four units each year until 2022 in the highest case scenario.

However, Boggs added that Petrobras’ demand remains a key uncertainty and EMA’s low case scenario sees the Brazilian giant only ordering one or two FPSOs annually if oil prices remain low.

Floating Production Focus

The official OSEA2018 show daily is published by Upstream, an NHST Media Group company, Christian Krohgs gate 16, PO Box 1182, Sentrum, N-0107 Oslo and printed by Markono Print Media Pte Ltd, Singapore.

This edition was printed on 28 November 2018. © All articles appearing in the Upstream OSEA2018 show daily are protected by copyright. Any unauthorised reproduction is strictly prohibited.

This newspaper is published by Upstream, which is solely responsible for its editorial content. The editorial content is not necessarily the opinion of the event organisers.

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Thursday 29 November 2018

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OCEANIA

Oz in Timor-Leste progress Australian government takes steps to formalise new maritime border and agreement over Greater Sunrise project RUSSELL SEARANCKE Singapore

THE Australian government has taken a big step forward towards formalising its new maritime border with Timor-Leste by introducing a bill to parliament that will implement the new boundary and the Greater Sunrise special regime.

Australia’s Foreign Affairs Minister Marise Payne and the Minister for Resources and Northern Australia, Matt Canavan, said in a joint statement that the bill covered the core elements of the Maritime Boundary Treaty.

Both parliaments are required to ratify the treaty before it comes into force.

The new boundary follows roughly the southern boundary of the existing shared joint petroleum development area (JPDA), which is effectively the median line between the two states.

The new boundary places the Bayu-Undan field exclusively within Timor-Leste’s jurisdiction, as it does the suspended Kitan oilfield, the Eni-operated Block 11-106 plus the Chudditch and Kelp Deep gas discoveries.

In addition, the Buffalo oilfield, which is being redeveloped, will also fall under Timor-Leste’s jurisdiction.

The JPDA will be dissolved as soon as the Maritime Boundary Treaty is ratified and enters into force.

The bill introduced into Australia’s parliament also acknowledges the Greater Sunrise Special Regime Area, which effectively ring fences the Greater Sunrise gas discoveries, as an area of joint Australian and Timor-Leste jurisdiction.

Under the regime, upstream tax revenues from the Sunrise fields will be split on the basis of 70% to Timor-Leste and 30% to Australia if the fields are developed by a pipeline to Timor-Leste.

They will split 80% to TimorLeste and 20% to Australia if they are developed by a pipeline to Australia.

The current titles over the Sunrise discoveries — two Australian retention leases and two JPDA production sharing contracts — will be converted into one single production sharing contract.

Timor-Leste’s petroleum regulator — the National Authority for Petroleum & Minerals (ANPM) — will act as the regulator for Greater Sunrise, while a new joint governance board will oversee petroleum activities.

Under the treaty, the two countries are expected to agree on a development concept and development plan for Greater Sunrise.

The treaty will enter into force, through an exchange of diplomatic notes, only when Australia

and Timor-Leste have given effect to the treaty and when transitional arrangements are completed.

“The government looks forward to bringing the new treaty with Timor-Leste into force as soon as possible,” said Payne and Canavan.

Timor-Leste sources said the parliamentary ratification process has not yet started there as the government is currently debating the state budget for 2019. A small

government team led by special representative Xanana Gusmao has in the past two months agreed sale and purchase terms with ConocoPhillips and Shell for the oil majors’ interests in the Greater Sunrise fields.

Timor-Leste

Treaty: Australian Minister for Resources and Northern Australia Matt Canavan Photo: REUTERS/SCANPIX

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Thursday 29 November 2018

LIQUEFIED NATURAL GAS

Asset: the Lampung FSRU moored off Indonesia

Photo: HOEGH LNG

Small-scale LNG on agenda OSEA panel said Southeast Asia holds great opportunities for sector, though challenges need to be overcome AMANDA BATTERSBY Singapore

SOUTHEAST Asia, especially archipelagic nations such as Indonesia and the Philippines, offers myriad opportunities across the small-scale liquefied natural gas value chain a panel at OSEA 2018 said yesterday.

However, challenges remain and there are barriers to be overcome before small-scale LNG can

really take off, say those in the know.

“Indonesia has amazing potential for small-scale LNG. Always has had and always probably will,” Tuomas Maljanen, Fearnleys LNG ship broker told the OSEA 2018 session.

Sanjay Verma, Wartsila director of business development LNG Asia

believes the proposed Central Indonesia project being pursued by state electricity player Perusahaan Listrik Negara (PLN) will “kick-start” the small-scale LNG industry in the country after several years’ of delay.

PLN and national oil company Pertamina have ambitious plans for small-scale LNG in both heav-

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ily industrial and remote areas of the island nation that would require floating storage and regasification units and feeder vessels.

However, Saunak Rai, Norgas vice president LNG business development and operations noted that there is “no regulatory push” in Indonesia to underpin a cohesive small-scale LNG industry.

Cabotage is also a hurdle that needs to be overcome in Indonesia — vessels have to be locally flagged and international players will need to partner with an Indonesian partner or establish a local company to participate.

“We believe that the cabotage law (in Indonesia) is something that will stay for quite a long time.

(Whilst not an insurmountable one) it’s one more step that has just to considered,” added Maljanen.

Another challenge for the small-scale LNG sector in Southeast Asia and globally — the Caribbean is also viewed as a region having significant potential — is the lack of an established spot market.

“In small-scale LNG, we don’t really have a spot market. So it’s quite a classic chicken and egg problem,” said Maljanen.

“We have a lot of (ship) owners who would like to enter the smallscale LNG space but they don’t have enough firm demand or understanding of what the demand would be like to go ahead and build those speculative small-

scale LNG vessels,” he said. “On the other hand, when we have demand for an LNG carrier from a project that wants to have a smallscale vessel, they might see that the vessels available aren’t suitable for their project.

“Then they have to call the shipyard and order a purpose-built vessel, so that’s getting more expensive.

“We are at a bit of a stalemate.

We have some vessels available in the market but the demand and supply does not always meet the (needs of) small-scale LNG,” added Maljanen.

Delegates were also told that the cost of developing vessels, be they FSRUs or carriers, for smallscale LNG projects needs to be reduced.

“Industry needs to be more innovative. We need to find alternative ways of building cheaper vessels, we also need to find a way to build more standardised vessels... it’s definitely a challenge for all of us,” Maljanen said.

Conversions are of course one way to reduce capital expenditure.

An existing platform supply vessel, said to be “very cheap” in the market today, could be converted into an LNG feeder or LNG bunkering vessel.

The Singapore government has already introduced “great subsidies” for constructing small-scale LNG vessels, “which have been taken up by a number of ship owners”, added Rai.

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Thursday 29 November 2018

5

VIETNAM

Jadestone on track off Vietnam Company aims to sanction Nam Du and U Minh offshore gas development projects next year JOSH LEWIS Singapore

ASIA Pacific-focused Jadestone Energy is on track to make a final investment decision next year on its Nam Du and U Minh gas developments off Vietnam.

The company said it is targeting a final investment decision in the second half of 2019, adding that progress continues to be made on the front-end engineering and design, field development plan technical studies and the negotiation of commercial agreements.

Nam Du and U Minh lie in blocks 46/07 and 51 and are estimated to contain a combined 200 billion cubic feet of wet gas.

The development plan will see wellhead platforms located on each field, with gas to be exported via the PM-3 subsea gas export pipeline, which runs to Ca Mau in south Vietnam.

Condensate will be stored on a leased floating production, storage and offloading vessel, with first gas anticipated in late 2021.

Jadestone also said it does not expect to begin a planned infill drilling programme off Western Australia until the first quarter of 2019.

It had said earlier this year it expected to start the programme in the fourth quarter but that has been pushed back due to rig availability.

It added its planned infill drilling programme at the Montara oilfield, also off Western Australia, is expected to commence following the completion of regulatory approvals that are anticipated in the first half of next year.

Montara is currently shut-in following a number of safety incidents and is unable to restart until it satisfies a number of conditions set by the National Offshore Safety & Environmental Management Authority (Nopsema), including demonstrating all safety critical equipment is operating as it should.

A backlog of maintenance and inspection activities is also being carried out during the shutdown and Jadestone reaffirmed its expectation that production will resume next month.

It acquired Montara earlier this year, but previous owner PTTEP is still operator, with Jadestone not expected to take the reins until next year as it is still undergoing a transition period in line with normal regulatory approval process.

“Having seconded a number of key operational leaders from Jadestone into the current operation, we are now clearing a maintenance and inspection backlog at Montara which will mean that when we assume operatorship next year, we will inherit a high reliability facility that we can operate with confidence, with improved uptime performance

and without a planned major maintenance shutdown until at least the second half of 2020,” Jadestone chief executive Paul Blakeley said.

The update on Jadestone’s operations came as it revealed it had narrowed its losses over the first nine months of the year.

It posted a loss of less than US$25.5 million for the nine months to 30 September, a reduction from the US$35.2 million net loss booked over the same period last year.

Looking ahead: Jadestone Energy chief executive Paul Blakely

Photo: JADESTONE ENERGY

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UK in boost for CCUS THE UK government is hoping to have the country’s first carbon capture and underground storage (CCUS) project up and running by the middle of the next decade.

The plan came on the same day the Oil & Gas Climate Initiative entered a partnership with major oil companies including Shell, BP and Total to progress the UK’s first commercial full-cycle CCUS project in the country’s northeast.

The ambition of the government, as part of a wider industrial strategy, is to roll out CCUS on a larger scale in the 2030s.

Plans were set to be unveiled on Wednesday at a summit in Edinburgh, Scotland attended by ministers and top industry executives.

The plan to enable the development of the UK’s first CCUS project will see the government next year detail how it will enable the first such facility in the country, while also investing £20 million (US$25.5 million) in supporting construction of CCUS technologies at industrial sites across the UK, as part of wider £45 million commitment to innovation.

The government will also invest £315 million in decarbonising industrial sites, including the potential to use CCUS, and begin work with bodies including regulator Oil & Gas Authority on identifying existing oil and gas infrastructure that could be converted into CCUS facilities.

The strategic partnership signed on Wednesday between the OGCI and BP, Shell, Total, Eni, Equinor and Occidental Petroleum aims to progress the Clean Gas Project, with sights trained on the town of Teesside for the UK’s first commercial full-cycle CCUS scheme.

IGCI chief executive Pratima Rangarajan said: “CCUS... proud to move this project forward within the context of the Tees Valley Cluster.”

International Energy Agency executive director Fatih Birol said ahead of the summit: “Without CCUS as part of the solution, reaching our international climate goals is practically impossible.”

Sapura LTA confirmed MALAYSIA’S Sapura Energy has confirmed its inclusion in Saudi Aramco’s long-term agreements (LTA) contracts with offshore contractors.

The Malaysian player said that that its wholly-owned subsidiaries, Sapura Fabrication and Sapura Saudi Arabia, have been selected to join Aramco’s LTA programme.

A company statement said Sapura “qualified as an LTA contractor after successfully undergoing an extensive assessment and meeting rigorous operational and safety requirements”.

Thursday 29 November 2018

CHINA

Opportunities: SWS chairman Wang Qi at OSEA 2018

Photo: XU YIHE

Chinese yards urged to weigh up strategies SWS chairman Wang Qi says fabricators need to tread carefully when chasing new opportunities after downturn XU YIHE Singapore

CHINESE yards are being warned to tread carefully before pursuing new orders for offshore production units to replenish their order books at a time when inquires for construction of drilling units have mostly dried up.

Shanghai Waigaoqiao Shipbuilding (SWS) chairman Wang Qi said that yards need to weigh their new strategies carefully as they reposition themselves after the rig market collapse that followed the oil price crash of four years ago.

“We can’t act hastily, triggered by lack of work, we need to think carefully before taking action,” he told Upstream at Osea 2018 in Singapore on Wednesday.

Most Chinese yards have suffered during the downturn, which saw as many as 88 rigs abandoned by the companies that had ordered

them. However, Wang warned that, for many yards, chasing orders for sophisticated units such as floating production, storage and offloading vessels might not be the right strategy as there only a limited number of players in China able to build them successfully.

He said that yards lacking experience and engineering capacity would face potential cost overruns and delays if they pursue business in a sector for which they are not fully prepared.

Most Chinese offshore yards have already shifted their product lines since orders for rigs dried up, with many diversifying into other areas such as gas-based transportation vessels or even fish farms.

That has left relatively few players focused on offshore projects.

“We are among the few yards that

are still maintaining an offshore business,” he said.

Those that have survived the downturn and remained with the offshore sector are now mostly focusing on offshore production units, such as FPSOs, gas processing platforms and floating liquefied natural gas vessels.

Such units are tailor-built for specific fields with almost no risk of being abandoned after being constructed.

About half a dozen FPSOs have been contracted by leading contractors such as Modec and SBM Offshore and by oil and gas companies for fabrication at Chinese yards.

Among the orders, Cosco is building an FPSO for Greek operator Energean’s Karish & Tanin project off Israel, while Offshore Oil Engineering Company (COOEC) is

building a circular FPSO for Anglo-Dutch supermajor Shell’s Penguins project in the UK North Sea. In addition, CIMC Raffles is working on the P-71 FPSO for Brazil’s Petrobras and Dalian Shipbuilding Industry Company is working on the MV-31 FPSO for the same operator.

SWS, for its part, is now working on two generic FPSOs for SBM under its Fast4Ward design, one of which is already destined for US supermajor ExxonMobil’s prolific Stabroek asset off Guyana, with the second expected to head to the same destination.

The first Fast4Ward unit is understood to be on track for delivery at the end of next year, while the second FPSO construction contract was finalised with SBM just last week.

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Thursday 29 November 2018

CHINA

Trio get green light for Chinese CBM drive

Three joint ventures with foreign partners gain development approval as government targets output boost XU YIHE Singapore

THE Chinese government has approved the development of three coalbed methane blocks in joint ventures with foreign companies as it looks to attract fresh investment into the sector to help boost production.

The nation’s National Development & Reform Commission has given the green light to Hong Kong-listed AAG, UK-listed Fortune and G3 Exploration to develop CBM in central China’s Shanxi province, involving a total investment of 7.8 billion yuan (US$1.45 billion).

These developments involving tapping a total of 39 billion cubic metres of CBM reserves and are forecast to see China increase CBM production by 1.48 Bcm in three years’ time.

The developments at Chengzhuang in the Qingshui basin, Liulin in the Ordos basin and Mabi South in the Qingshui basin, all in central China’s Shanxi province, will call for the drilling of 1791 production wells, sources said.

Fortune’s local entity Fortune Liulin Gas Company is working with its production sharing partner China United Coal-bed Methane Company (CUCBM), the CBM outfit owned by China National Offshore Oil Corporation, to jointly develop the Liulin South field.

This field requires an investment of 2.56 billion yuan to build up 300 million cubic metres of CBM production capacity to tap 15.2 Bcm of CBM reserves.

The two companies will drill 218 wells and build three gas gathering stations and export pipelines running 155 kilometres from the field to market. Fortune has a 25% stake in Liulin.

Last year, China boosted its CBM production by 51% to 6.8 Bcm, though that still accounts for only 4.6% of the country’s total gas production.

KISWIRE_N2Hyrope_AD_146x181_161017.pdf 1 2016-10-17 오후 1:34:04

On site: a coalbed methane operation in Shanxi province

For the Chengzhuang CBM block, G3 Exploration (formerly known as Green Dragon) and its PSC partner China National Petroleum Corporation (CNPC) will invest 590 million yuan to drill 232 new production wells and build up annual production capacity of 180 MMcm of CBM. The Chengzhuang development will tap a total of 4.2 Bcm of CBM reserves.

Meanwhile, China-focused independent CBM player AAG Energy and CNPC will invest 4.64 billion yuan at Mabi South to drill 1341 new wells.

They will tap 19.6 Bcm of CBM reserves to establish production capacity of 1 Bcm per annum.

AAG Energy owns a 70% operating stake in the Mabi South concession, with the remainder held

by CNPC. To encourage CBM development, the government has moved to increase the subsidy for its production by 50% to 0.3 yuan per cubic metre from the previous 0.2 yuan during the current 13th fiveyear plan period, which runs from 2016 to 2020.

Last year, China boosted its CBM production to 6.8 Bcm although that still accounts for only 4.6% of the country’s total gas production.

The government aims to boost CBM production to 10 Bcm by 2020 and is working to attract more investors to the CBM exploration sector by delegating power to local authorities to launch licensing rounds for CBM blocks.

China’s CBM production hit 600 MMcm in September, bringing total production for the first nine months of 2018 to 5.41 Bcm. That total is up 6% on the year, with 3.84 Bcm having been produced produced in Shanxi province.

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Photo: REUTERS/SCANPIX

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Aramco ramps up gas push SAUDI Aramco has said its gas programmes will attract investments worth US$150 billion over the next decade as it aims to sharply increase its gas production during the same period.

The state-owned giant aims to ramp up its gas output during the next 10 years to up to 23 billion cubic feet per day from the current 14 Bcfd, chief executive Amin Nasser said in Dubai.

Aramco is looking to attract investment in its conventional and unconventional gas programmes as it aims to become a net gas exporter in the future, he added.

“We have world-class unconventional gas resources that are rapidly supplementing our large conventional resources,” Nasser said.

Aramco presently has 16 drilling rigs focusing on unconventional gas reserves, with more than 70 wells expected to be completed this year.

Nasser believes Aramco will be able to produce up to about 3 Bcfd of gas by 2030 from its unconventional reserves.

He also said the company is venturing into the international liquefied natural gas market.

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Ensign buys up Trinidad CANADIAN driller Ensign Energy Services has snapped up a majority of shares of peer Trinidad Drilling through a hostile bid, causing rival Precision Drilling to scrap its own plans to take over Trinidad through a friendly offer.

Ensign said on Tuesday it had acquired 56.38% of Trinidad’s common shares through the offer.

Combined with a previously owned 9.8% stake in the company, Ensign now controls 66.18% of Trinidad.

The move ended Precision’s hopes of becoming the third-largest onshore driller in the US through the acquisition of Trinidad.

Precision, currently the largest driller in Canada, ended its previous agreement to take over Trinidad in an all-stock offer and said it was due a US$20 million termination fee.

Ensign originally launched its hostile takeover bid for Trinidad in August, offering C$1.68 (US$1.28) in cash for each share of common stock, a 20% premium to the volume weighted average price of the shares for the trading days between 1 and 10 August.

At the time, Ensign valued the deal, which included Trinidad’s C$477 million of net debt, at C$947 million.

Precision Drilling last month then made its all-stock offer for Trinidad, which saw Precision offer 0.445 shares of common stock for each outstanding Trinidad share.

However, Ensign persisted in pursuing its offer.

Progress at Iguana field US contractor Chet Morrison has completed an engineering, procurement, construction, installation and commissioning contract for local upstream operator DeNovo Energy at the Iguana field off Trinidad & Tobago.

The workscope included supply of a conductor-supported platform for three development wells, a 45-kilometre, 14-inch diameter subsea natural gas export pipeline and platform tie-in, pipeline shore crossing and onshore connection for gas processing, and final pre-commissioning and commissioning of integrated systems.

The project is the first gas development campaign in the Gulf of Paria, where the Iguana field sits in water depths of about 27 metres.

The subsea export pipeline connects the field to a newly constructed onshore gas processing unit on Port Lisas in eastern Trinidad.

Chet Morrison said it completed installing and commissioning the pipeline and offshore facility in October, with 80% local content and with help from its joint venture partner Trinidad Offshore Fabricators Unlimited.

Thursday 29 November 2018

PAPUA NEW GUINEA

Capital view: Port Moresby, Papua New Guinea

Photo: REUTERS/SCANPIX

Western LNG partner eyes Stanley scheme Horizon Oil revives possibility of early recovery project at one of fields involved in LNG development RUSSELL SEARANCKE Singapore

THE proposed Western liquefied natural gas project in Papua New Guinea remains viable from a technical and cost perspective, but an early condensate recovery scheme is a nearer-term project, according to a joint venture partner.

Western LNG is planned to be based on the development of a series of onshore fields — Stanley, Elevala-Ketu, Ubuntu, Puk Puk and Douglas - in Western Province.

Combined, the fields contain a gross appraised resource of 2200 petajoules (2 trillion cubic feet) of sales gas and 64 million barrels of associated condensate.

Repsol owns 41% of the resources, Horizon Oil has about 28%, Osaka Gas has 14% and other companies have the remaining 17%. The development concept

envisages a floating LNG vessel in shallow water near Daru Island on PNG’s south coast with capacity of 1.5 million tonnes per annum of LNG. An onshore pipeline of 500 kilometres in length would connect the fields to the LNG vessel.

Horizon said in a project update that completed pre-front end engineering and design work by TechnipFMC and China Petroleum Engineering had confirmed the technical viability of the concept and substantiated Horizon’s overall cost estimates for the project.

“Over the coming 12 to 18 months, we will work with our joint venture partners and the PNG government to progress planning for the Western LNG development,” said Horizon chairman John Humphrey.

However, the Stanley early con-

densate recovery scheme has re-emerged “as an investment proposition with the potential to provide nearer-term condensate and domestic gas revenue, while planning for the longer‐dated Western LNG project”.

The Stanley liquids project was the original development concept before the oil price collapse in 2014 led to its suspension and a shift by the joint venture towards developing the gas resources.

Recent improvements in the oil price contributed to the gas recycling idea re-emerging. In addition, the PNG government has indicated in its proposed Gas Policy that pipeline operators will need to make available third-party access on reasonable commercial terms.

Horizon said yesterday the gazetted route of the gas and condensate pipelines from the

P’nyang field to the PNG LNG facilities will pass within 20 kilometres of the Ketu field, which could provide an opportunity.

However, undermining both the liquids project and Western LNG is the ongoing dispute with PNG’s Petroleum Minister about the minister’s intent to cancel the Stanley licences.

Horizon reiterated Wednesday that project operator Repsol has initiated an independent arbitration process while continuing to work with the minister and the Department of Petroleum and Energy “to resolve any disagreement with respect to the good standing” of the Stanley licences.

Repsol’s sale of its PNG business to a subsidiary of China Changcheng Natural Gas Power has also been undermined by the Stanley licences dispute.

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Thursday 29 November 2018 Marina Bay Sands

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Westex by Milliken and Teijin Aramid join forces to revolutionise aramid FR fabric Brightest minds in global FR fabric technology produce novel comfort in protective aramid fabric launching at OSEA2018

Virtual Reality Welding Demonstration and Competition Show opening hours, Level 1, 1H3-06 Capitalising Benefits of Additive Manufacturing for Marine and Offshore by Nanyang Polytechnic 10.30am – 11.30am & 2.30pm – 3.30pm, Level 1, 1T2-02 Tech Garage 11am – 4.30pm, Basement 2, BT4-04

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eading US flame resistant (FR) textiles brand Westex™ by Milliken™ and global aramid fiber producer Teijin Aramid announced a joint technology and commercial partnership for Southeast Asia and Australasia at OSEA. The companies bring more than 100 years of innovation in trusted FR fabrics for daily wear and best-in-class FR fiber technologies, respectively.

“For Milliken, a collaboration with Teijin Aramid is a meeting of minds,” according to Steve Layton, vice president of sales and marketing for Westex by Milliken.

“Our reliance on research and development is bolstered by Teijin’s worldclass technological capabilities and standing as a trusted global leader in FR aramid fibers. Within a short time, this partnership has produced technologically advanced FR fabric, and this is only the beginning.”

A result of the partnership, Westex by Milliken and Teijin Aramid present Westex™ Synergy™ Pro, a novel aramid fabric with superior softness and six times better moisture-wicking compared to leading aramid fabrics.

Powered by Teijinconex® meta-aramid

Key events at a glance

Panduit Seminar — Asia’s Infrastructure Investment Outlook For Mega Contractor 8.30am — 4.00pm Level 3, Begonia 3002

Westex by Milliken’s Steve Layton and Teijin Aramid’s Bernd Steinmann, along with their respective teams, sign agreement to launch a joint commercial and technological partnership serving the Asia Pacific region

staple fibers, Westex Synergy Pro is compliant to NFPA 2112 and NFPA 70E, and certified to EN ISO 11611 and EN ISO 11612 for oil and gas industry flash fire hazards.

Westex Synergy Pro is exclusive to the Southeast Asia and Australasian markets.

“Teijin Aramid is delighted to team-up with Milliken. We look forward to jointly exploring opportunities to better serve customers, combining our technical brains

as well as commercial power. The vast experience and know-how of Teijin Aramid, combined with the expertise of Westex by Milliken makes for a powerful and winning combination,” says Bernd Steinmann, Teijin Aramid’s global business manager protective apparel.

Westex by Milliken Booth 1Q4-10 Teijin Booth BT3-07

OSEA will return from 24 to 26 November 2020, Marina Bay Sands, Singapore.

Book your space at the Corporate Sales Booth 1T5-01 on Level 1 and enjoy onsite rate of S$570/sqm!

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Thursday 29 November 2018

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Survive dangers of oil and gas environments with specialised PPE Personal protection for workers should be the top priority for oil and gas companies, according to Jerry Paton, Global Category Head of Personal Protection, RS Components

T

he protection of people at work should be a major priority for all companies and organisations.

In the offshore sector, and especially in the oil and gas industry, this priority needs to rise to a higher level yet.

The oil and gas sector is classed as a major hazards industry and there are specific requirements to meet for buyers and maintainers of industrial marine and offshore facilities, for those working on ships, tankers and offshore platforms or extracting oil or gas from the ocean bed.

Although major events in offshore environments are thankfully rare, they can kill or maim workers very quickly due to unique environmental circumstances.

In addition, on a day-to-day basis, oil and gas workers will still encounter the most common accident hazards that are associated with most working environments.

But exposed to the extremes of nature and often the worst that the sea, wind and icy rain can do, then slips, trips and spills become an entirely different order of risk in this harsh working environment.

Risks

Working in offshore environments provides specific dangers. For example, workers might be required to access platforms and equipment located high above the ground such as masts, drilling platforms and other elevated equipment.

Falls are not just falls on to hard stable surfaces, but perhaps into turbulent and potentially freezing waters where the chance of death by drowning or hypothermia is much increased.

This makes protection from spills increasingly important, and further complicated by the regular

addition of seawater washing from crashing waves and wind-blown ocean spray onto floors and surfaces that exacerbates the problem of clean-up because the chemical make-up of seawater makes it highly corrosive.

Workers in the oil and gas sector also face an increased risk of fire and explosion due to the widespread availability of ignition sources and combustible materials and chemicals including oil, cleaning chemicals, lubricants, flammable vapours or gases, which can be released from wells, trucks, production equipment or surface equipment such as tanks and shale shakers.

Potential ignition sources include static, electrical energy sources, open flames, lightning, cigarettes, cutting and welding tools, hot surfaces and frictional heat.

Workers might also be exposed to hazards from compressed gases or from high-pressure pipelines, where the internal erosion of lines could cause leaks or line bursts, which can also cause ‘struck-by hazards’.

Other risks include ergonomics-related causes such as lifting heavy items, bending, reaching overhead, pushing and pulling heavy loads, working in awkward body postures and repetitive strain injuries.

These can be minimised or eliminated by adequate pre-task planning, using the correct tools, appropriate placement of materials, education of workers about the risk and early reporting of injuries.

Personal Protection

To enable greater safety for workers, suitable protection is provided by Personal Protection Equipment (PPE) such as protective clothing and respirators, along with fire extinguishers and blankets, which should be located near to risk hazards, including specialist products

designed to deal with events such as electrical fires.

In addition, PPE such as helmets, gloves, safety glasses and shoes must be designed to withstand icy cold winds as well as decks and equipment made slippery from constant sea spray.

PPE always needs to be selected to meet the requirements of the specific task and suit the particular range of hazards of the specific working environment.

It must be manufactured to the highest standards and comply with any legal regulations, as well as provide reliable and comfortable protection for users during their daily tasks.

And, clearly, the harsh conditions in the oil and gas sector require clothing and footwear that keep people warm as well as provide sufficient grip to avoid slips and falls that have a higher risk.

RS Components, Booth BK3-10

Hughes Pumps launched new UHP pump

H

ughes Pumps’ new HP170 30lpm at 3000bar rated high pressure water jetting unit — designed to deliver truly exceptional performance and reliability — is unveiled by the UK’s leading high pressure pump manufacturer at the Sea and Land Technologies (SALT) booth during OSEA2018, and afterwards for demonstrations anywhere in the ASEAN region.

The Hughes Pumps HP170, rated at 30lpm at 3000bar, is packed with new features that are designed to deliver truly exceptional performance and reliability in a wide range of heavy-duty cleaning and surface preparation applications.

The HP170‘s all new power end has been designed to be extremely robust and easy to maintain. It can be mounted horizontally or vertically.

SALT has recently been appointed exclusive partner for Hughes’ high pressure water jetting pumps and equipment in the ASEAN region.

Since it was established in 1994, SALT has established itself as a leading supplier of water jetting equipment, with regional offices across the ASEAN region.

Hughes Pumps’ is the leading UK specialist manufacturer of water jetting pumps and equipment for heavy-duty cleaning and surface preparation applications in offshore marine/oil and gas applications, delivering exceptional performance and reliability in some of the harshest environments imaginable.

Sea and Land Technologies (SALT), Booth BJ2-01 Hughes Pumps’ new HP170 30lpm at 3000bar

Thursday 29 November 2018

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Seamap manufacturing facility in Johor, Malaysia

Seamap completes Phase 1 construction of new Malaysia manufacturing facility S ingapore-based Seamap, a leading market provider for gun link control systems, tail buoys and steamers, has just recently completed the construction of a new manufacturing facility located in Johor, Malaysia.

Building on what Seamap is already producing from its Singapore facility, the new facility in Malaysia will manufacture Seamap’s product lines, including the new SeaLink series of products and solutions for marine data acquisition.

Servicing customers worldwide who are engaged in offshore oil and gas exploration, oceanography and hydrography organisations and scientific research organisations.

The facility will also act as a regional repair and maintenance hub for US-based sister company Klein Marine Systems Inc’s product range of Side Scan Sonar Systems.

Phase 1 of the facility’s construction was completed in June 2018, allowing Seamap to perform hydrophone array repairs.

Phase 2 of construction, currently ongoing throughout 2018, will enable the company to fully assemble new hydrophone arrays as well as perform repairs in parallel, fully utilising all areas and assets available within the factory.

Phase 3 of construction lets the factory take in more products that are better suited and more cost effective to repair and build in Malaysia. Ultimately the goal is to increase the company’s manufacturing and repair capability, and expand on the current manufacturing contracts in place and repair services to customers.

Seamap is participating in OSEA2018 with Australian based sister company Seismic Asia Pacific (SAP).

SAP was established in 1959 as a supply and maintenance company for the mining and drilling industry during that era.

Over the years SAP has entered other sectors including the hydrographic and marine industry.

Having developed strong business ties with suppliers, agents, partners and customers, the company is now one of the leading providers of hydrographic, oceanographic and geophysical systems within Australia and throughout Southeast Asia and the Pacific Rim. Mitcham Industries Inc. acquired SAP in 2002.

SAP’s primary focus and expertise is in the supply of full turnkey solutions, from infancy of a project to final delivery.

This includes FAT’S, HAT’S and SAT’S programmes, full installation and integration, training and after sales support.

The company engages with customers to understand

their needs, requirements and applications, enabling them to provide suitable services and products.

Also part of the OSEA2018 contingent alongside SAP and Seamap is Klein Marine Systems (KMS), based in Salem New Hampshire, USA. KMS is a leading provider of Side Scan Sonar Systems and Maritime Security and Surveillance equipment and solutions.

The company’s roots date back more than 50 years when Marty Klein, the founder of Klein Marine Systems Inc. began building side scan sonar systems. To many, Marty is considered the father of side scan sonar technology.

SAP, along with sister companies Seamap and Klein Marine Systems, believes that OSEA plays an important and integral part in the industry.

The event enables the companies to engage further with fellow industry players and most importantly, their customers.

It also brings a platform to showcase their brands, as well as promote new and re-enforce the reliability of existing and proven products to their target audience.

Seismic Asia Pacific, Booth 1D6-06

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Thursday 29 November 2018

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Franklin Offshore signs agreement with Lankhorst Ropes

Snapshot: OSEA Networking Night

Ms. Angie Tang, Chief Executive Officer & Director, Franklin Offshore Holdings and Dr Wilco Stroet, Senior Vice President Global Maritime, Lankhorst Ropes, signed a cooperation agreement at OSEA2018. Franklin Offshore Holdings will be the authorised stockist and distributor in Singapore and Southeast Asia for Lankhorst’s specialised Dyneema slings used in the offshore oil, gas and wind energy construction and subsea installation industries. The exclusive partnership is estimated to exceed US$1 million in the first year.

Tunnel vision no more

U

niclimb Services — the Singapore-based rope access work specialist is demonstrating the RIEZLER robotic crawler camera’s capabilities at OSEA2018 Coined the “Spiderman” of the oil and gas industry, Uniclimb recently invested in the RIEZLER robotic camera crawler system and you can check out the system’s range of abilities at the company’s booth at the OSEA show floor.

Established October 2010 and based in Singapore with operating offices in Myanmar and Azerbaijan, Uniclimb Services is actively engaged in the provision of integrated services with access solutions in Marine Offshore, Oil & Gas, Civil Construction and Structural Maintenance industries.

The company’s core strength lies in its cohesive workforce, which is the key ingredient to the continued growth of the company, enabling it to serve diverse clients ranging from local leading shipyards to global offshore groups, not only in Singapore but also around the world.

Despite running with a lean team, Uniclimb understands the urgency of clients’ situations.

Hence, they make it a point to be available 24/7, and will respond to any queries swiftly no matter the time.

The team takes the safety of members seriously; everyone will undergo the required safety courses, and there will always be a supervisor present to chaperone new staff.

Uniclimb Services, Booth BF3-09

Uniclimb — “Spiderman” of the oil and gas industry

OSEA2018 Exhibitor Addendum

Booth

Company

Country

1J6-03

Six Tee Engineering Group Pte Ltd

Singapore

1K4-06

OSM International Services

Netherlands

Photos: UBM

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Thursday 29 November 2018

MEXICO

Pemex ups its resource estimate at Ixachi find Company says discovery could be the most important made onshore Mexico for 25 years KATHRINE SCHMIDT Houston

MEXICAN state oil company Pemex has increased its resource estimate for the onshore Ixachi discovery in Veracruz state after drilling two appraisal wells this year, saying the gas and condensate find could represent a possible resource of more than 1 billion barrels of oil equivalent.

Pemex executives said during a presentation livestreamed on Tuesday that the discovery is likely to be the country’s most important onshore find in the last 25 years.

At the height of its development, estimated to be in 2022, the company sees Ixachi as having production potential for 80,000 barrels per day of condensate and more than 700 million cubic feet per day of natural gas.

“The quantity of gas and liquid hydrocarbons identified in this field will assure the viability of supply of these products, in the short and medium term, for the petrochemical complexes in the south-east region of the country,” Pemex said.

The two probes of Ixachi-1DEL, south-east of the original discovery, and Ixachi 1001, north-east of the initial find, aimed to prove up extensions of the field.

The appraisal results indicated that the area of the accumulation spans about 50 square kilometres with an oil column of more than 1000 metres. The objectives targeted Cretaceous limestones on the eastern edge of the Cordoba platform.

Previously, Pemex had sized up the discovery as representing total possible reserves of about 350 million boe.

Pemex officials also highlighted the discovery’s proximity to existing infrastructure. They said the

Centre point: the Pemex headquarters in Mexico City

initial Ixachi discovery well has already been placed online and is producing about 2000 bpd of condensate.

The next step will be to tie in the appraisal wells, executives said.

The company envisages an initial full-field development plan that would involve 40 development wells with a budget of 30.5 billion pesos (US$1.48 billion).

The discovery comes as the latest chapter for the long-prolific oil province of Veracruz, which has been exploited since the late 1940s with trends such as the Golden Lane.

The field lies in the Terra Blanca municipality at a location about 72 kilometres from the port of Veracruz.

Ecopetrol to boost spending in drive to increase output COLOMBIAN state oil company Ecopetrol has increased its spending plans for next year as it looks to boost production.

The company said it will invest between US$3.5 billion and US$4 billion in 2019, which is a 30% increase compared to previous plans.

Most of the capital expenditure will target projects in Colombia, with only 8% aimed at projects in “highly prospective basins in the

US, Mexico, and Brazil”, Ecopetrol said. According to the company, 81% of capex will be spent on the upstream sector, as the goal behind the increase is to help boost production figures.

Ecopetrol said it is targeting production of between 720,000 barrels of oil equivalent per day and 730,000 boepd next year, with plans to drill more than 700 development wells and “at least” 12 exploration wells in Colombia.

Photo: REUTERS/SCANPIX

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Great White Frio deal SHELL has awarded US contractor McDermott a subsea installation contract for work on its Great White Frio project in the US Gulf of Mexico.

McDermott will install a flexible flowline from the well to a pipeline end termination, one 200-foot steel flying lead and two electrical flying leads as part of the umbilical and flowline installation deal.

The contractor is looking to wrap up offshore installation work in the middle of next year.

McDermott did not provide a contract value but described it as “sizeable”, which it denotes as being a contract valued at between US$1 million and US$50 million.

Great White Frio is part of the Perdido complex in Alaminos Canyon Block 857 and lies in a water depth of 8000 feet.

The Perdido hub, which started production in 2011, processes oil and gas from the Great White, Tobago and Silvertip fields.

In August, McDermott landed an earlier subsea contract from Shell for brownfield work at the Perdido project, involving installation of a single flexible flowline and one umbilical at the Silvertip field.

The engineering, procurement, construction and installation deal also involves electrical flying leads and pre-commissioning.

McDermott will carry out project management and engineering from its Houston base, with offshore installation targeted for next year.

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Thursday 29 November 2018

AUSTRALIA

Environmentally sensitive: Kangaroo Island in the Great Australian Bight

Photo: NATIONAL PARKS SOUTH AUSTRALIA

Equinor gears up for a fight BP and Chevron have pulled out - but the Norwegian giant stays committed to drilling in spectacular frontier area RUSSELL SEARANCKE Wellington

T

HE anti-fossil fuel movement in Australia is ramping up its efforts to disrupt potential activities in the deep-water Great Australian Bight, where Norway’s Equinor is about to begin an unprecedented programme of community engagement as part of its preparation for drilling its first exploration well.

Equinor has maintained its commitment to this pristine frontier area even though BP and Chevron have withdrawn.

Both supermajors pulled out not because the prospectivity of their acreage had lessened, but because they did not have the appetite to spend on high-risk exploration at a time of low oil prices.

Equinor is now considered to be the trailblazer, and other Bight permit holders are watching to learn from its experiences. The

anti-fossil fuel movement is watching Equinor and the Bight intently and has done so since 2011, when BP was awarded four exploration permits.

Activist groups such as Greenpeace, the Wilderness Society and the Sea Shepherd Conservation Society are understood to be supported by other environmental activists involved in campaigns against the onshore gas sectors in Queensland, New South Wales and Victoria.

Public opinion

The campaigns centred on influencing public opinion and lobbying politicians for regulatory change, and the efforts were largely successful.

Some of the local councils in South Australia are reportedly opposed to drilling in the Bight, as are 12 municipalities. In recent

weeks, the Australian Greens party has tried to alarm the public with statements citing an unnamed report that an oil spill in the Bight would lead to a A$158 billion (US$114.4 billion) hit to the economy.

“This shocking new report should be the death knell of plans to drill in the Bight. Drilling in the Great Australian Bight is bad for the economy, bad for the environment, bad for the planet and it must be banned,” says Greens environmental spokesperson and South Australian senator Sarah Hanson-Young.

The Greens also claim that Equinor’s own data show that spilled oil could reach the famous Bondi Beach in Sydney.

“Equinor has identified the risk but refuses to do the right thing and back out of the Bight. BP and Chevron got the message, it’s time

for Equinor to pack up their bags and go home. It’s time the community prevailed over corporate profits,” adds Hanson-Young.

Equinor’s Australia country manager Jone Stangeland says that parts of its oil spill modelling have been taken out of context.

Hypothetical oil spill simulations are created to make sure an operator has response plans to deal with any possible scenario, he says.

“This process produces different images. Taken out of context, these images are alarming,” says Stangeland.

“For example, some show the sum of 100 different spill events where no intervention action is taken.

“Of course, that is not a realistic scenario and such an event would never occur in reality. We are extremely proud of our track

record and we are always looking to improve. We will only undertake drilling if it can be done safely and with (Australian regulator) Nopsema’s approval.”

Given the level of scrutiny, Equinor has taken the unprecedented step of inviting the public to comment on its environmental plan for the drilling campaign before the plan is submitted to Nopsema for assessment.

Usually a plan is opened up to the public after it has been assessed by Nopsema.

In Equinor’s case, Nopsema will facilitate the process by making the environmental plan available online along with online submission forms, which will ensure that comments are received by both Nopsema and Equinor.

Nopsema says it welcomes Equinor’s decision to publish the plan ahead of the requirement to do

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Thursday 29 November 2018

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PGS still waiting for seismic go-ahead

Context: Equinor Australia’s country manager Jone Stangeland

Photo: ALF OVE HANSEN/DN

over the Bight so. Stangeland, who is new to the job of country manager, says the Great Australian Bight “is beautiful and I understand the great responsibility we have to protect it. It is my job to make sure that we only undertake activities if it is safe for people and the environment”.

He says the “fantastic and spectacular” coastline reminds him of the sheer cliff faces in the fjords where he grew up in Norway.

Environment plan

His company expects to complete the first draft of its environment plan next year.

“Equinor will be the first company to publish an exploration drilling environment plan for public comment under the existing regulations,” he says.

“This is a very important step as it demonstrates our commitment to openness and transparency.”

An Equinor spokesman says the plan will be ready in the first quarter of 2019, and that if it is approved by the authorities, the company aims to drill the Stromlo well in Block EPP39 at the end of 2019 or the beginning of 2020.

The Stromlo prospect lies in a water depth of 2239 metres, 372 kilometres off the south coast and 476 kilometres west of the city of Port Lincoln.

The spokesman said the drilling season in the Bight is between October and May as it is a breeding ground for the endangered southern right whale and also a feeding area for blue whales, humpback whales, orcas and sea lions.

In June 2017, Equinor, then known as Statoil, became operator and 100% owner of blocks EPP39 and EPP40 following a swap agreement with BP. The Norwegian

company is seeking a partner to share risk and costs for one-well commitments in both permits.

Senior advisor of Greenpeace Norway, Martin Nordman, is stunned that the partly stateowned oil company plans to drill the Stromlo well.

“It is unbelievable that Equinor wants to continue with this campaign, especially after BP and Chevron pulled out.

“The Great Australian Bight has the richest marine life diversity in the world.

“It should be one of the last places in the world with oil and gas drilling,” he says.

Industry sources say Equinor would never drill in this controversial area without seeing potential for something significant.

“They believe there is potential for a huge oil discovery,” says one source familiar with the plans.

THE geophysical giant Petroleum Geo-Services (PGS) is still trying to gain regulatory approval for a large multi-client 3D and 2D seismic survey in the Great Australian Bight, writes Russell Searancke.

PGS first submitted its environmental plan application for the 30,100-square kilometre Duntroon survey to the national petroleum regulator Nopsema in February 2017, but the application has bounced back and forth between the two.

Nopsema has twice been unsatisfied with the application, and PGS has received numerous time extensions to provide the extra information that Nopsema has requested.

Earlier this month, PGS resubmitted the application, and the regulator is currently assessing it with a decision due on 7 December 2018.

Nopsema previously told PGS it was not satisfied the plan met the criteria of being appropriate for the nature and scale of the activity, of demonstrating the environmental impacts and risks would be reduced to an acceptable level, and of demonstrating that PGS had carried out the required consultations and responded appropriately.

PGS would like to acquire the survey in the first half of next year.

The shoot will cover blocks EPP41 and Bight Petroleum-owned EPP42, former Chevron permit EPP45, Karoon Gas’ EPP46 and a small amount of open acreage area in water ranging from 100 metres to 3500 metres.

Industry sources say the Duntroon application has become politicised amid concerns about the effects of seismic surveys on fishing stocks and other marine life in the pristine Bight.

Nopsema acknowledges that relationships between seismic survey operators and the seafood industry need to improve.

“Poor communication and misunderstandings about these surveys have attracted community, media and government interest and contributed to heightened tensions, particularly for fisheries

stakeholders and the communities in which they operate,” says Nopsema chief executive Stuart Smith.

He says there are many differences of opinion between the offshore petroleum industry and fisheries stakeholders.

“A key point of contention often appears to be the interpretation and application of relevant science on the environmental impact of seismic surveys on commercially important marine species,” adds Smith.

The regulator hopes that agreements can be reached through a series of planned roundtable meetings involving upstream industry association APPEA, Seafood Industry Australia, commercial fishing groups, Nopsema and state and federal government agencies.

PGS has previous experience of seismic acquisition in the Bight.

In 2015 it acquired 8867 square kilometres of 3D using the vessel Ramform Sovereign “without environmental incident”, says the South Australia government.

Four years prior PGS acquired 12,413 square kilometres of 3D using the Ramform Sterling.

However, since then a significant amount of scientific literature has been published and new conservation management plans have been introduced in the Bight, says PGS. Also, the timeline for preparation of the Duntroon permit has been extended “to allow more time for consultation and engagement with stakeholders”, adds PGS. The geophysical company says the level of public interest is higher now, partly because South Australia is less familiar with offshore petroleum activities than western and northern Australia.

Nopsema has “assessed consistently against the requirements of the regulations and in accordance with the published polices and guidance”, says PGS, adding that it has been “provided the opportunity to modify and resubmit our environmental permit though the regulated assessment process”.

Tensions: Nopsema chief execuive Stuart Smith Photo: NOPSEMA

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Pakistan boost for Vopak DUTCH player Royal Vopak is planning to buy an additional interest in Elengy Terminal Pakistan, giving the company a greater foothold in Pakistan’s burgeoning liquefied natural gas industry.

The deal when completed will give Vopak a total 44% holding in Elengy’s Port Qasim floating storage and regasification unit, which has peak send-out capacity of up to 690 million cubic feet per day of gas.

The LNG import project also involves a jetty with a 7.5-kilometre high-pressure pipeline that is connected to sole customer Sui Southern Gas Company’s grid.

The 44% stake is being acquired through two separate transactions with the International Finance Corporation and Engro Corporation.

Engro’s wholly-owned subsidiary Engro Elengy Terminal, operates the LNG receiving and regasification facility on a 15-year time charter from Excelerate Energy.

Vopak is no stranger to Pakistan, having worked “for a couple of decades” with Engro at the adjacent chemical terminal on the mainland side of the channel into Port Qasim, near Pakistan’s commercial capital Karachi.

Acquisition of an initial 29% stake is envisaged to complete before the end of the year. The deal to acquire a further 15% is subject to certain conditions, including customary regulatory and shareholder approvals, and closing is anticipated to take place in the first quarter of 2019.

Financial terms of the deals have not been disclosed.

Weizhou set for MOPU CHINA’S CNOOC Limited is in the process of acquiring a mobile offshore production unit for the Weizhou 12‐8 East satellite development in the Beibu Gulf.

The joint venture owners will lease the MOPU, which according to co-owner Horizon Oil is already “substantially constructed”.

Horizon said CNOOC Ltd has progressed the commercial and legal arrangements for the project in Block 22/12 and project sanction is due in early 2019.

The field is being developed in phases, with an initial three wells to be drilled from the MOPU and tied back via a flexible subsea flowline to an existing Block 22/12 platform.

Additional production wells will be added later.

Block 22/12 hosts a number of small fields. There are currently 18 producing wells and gross production is 11,500 barrels per day of oil.

Horizon added that further infill drilling opportunities have been identified for 2019 and 2020.

Thursday 29 November 2018

MALAYSIA

Overview: Hibiscus Petroleum chief executive Ken Pereira

Photo: HIBISCUS

Hibiscus sets out drill plans for North Sabah Malaysian independent outlines two drilling programmes for newly-acquired asset RUSSELL SEARANCKE Singapore

MALAYSIAN independent Hibiscus Petroleum has made plans for two infill drilling programmes at its newly-acquired North Sabah multi-field asset off Sabah as it seeks production improvements.

The company earlier this year bought Shell’s 50% operating interest in the North Sabah enhanced oil recovery production sharing contract, which contains four producing oilfields — St Joseph, South Furious, South Furious 30 (SF30) and Barton — plus pipeline infrastructure, the Labuan Crude Oil Terminal and other equipment and assets.

Hibiscus said the asset produced at an average rate of 14,860 barrels per day of oil on a gross basis in the quarter ended 30 September, which was slightly below

the previous quarter. The average uptime of the North Sabah production facilities was 93%.

In an effort to boost production, the company is embarking on the St Joseph infill drilling project and the SF30 infill drilling project.

The St Joseph campaign has been approved by national oil company Petronas, while approval for South Furious will be obtained in the next financial quarter, said the operator.

The St Joseph programme, which will entail the drilling of three infill producers utilising a triple splitter wellhead on the St Joseph jacket-A platform, is expected to add 2600 bpd of production.

The total capital commitment for the work will be about 142.5

million ringgit (US$34.4 million), which will be shared equally with joint venture partner Petronas Carigali. Minimum modifications will be necessary on the topsides of at the St Joseph A platform.

Drilling is expected to begin in April 2019 and first oil production in June of the same year.

Hibiscus said that in the past three months it has integrated the North Sabah operations with its own work processes and performance-based operating culture, and will continue to focus on production optimisation and enhancement initiatives via surface and subsurface activities.

Hibiscus managing director Kenneth Pereira said: “While we have achieved high prices for crude oil sold in this quarter,

world oil markets are experiencing increased volatility. The group has seen oil prices at various levels; on some occasions lower and other times higher, and we have managed to remain profitable throughout.

“This is primarily because our average unit production cost for both the Anasuria (in the UK North Sea) and the North Sabah assets has always been significantly below the average realised oil price.

“The careful management of costs to maintain low operational expenditure and the delivery of production enhancement projects are key towards achieving low unit production costs. This remains an area of focus for the group.”