Springfield set to reveal offshore discovery bigger than Jubilee

Ghanaian company Springfield Group is set to reveal deepwater oil discovery located offshore Ghana that will reportedly be bigger than the Tullow-operated Jubilee offshore field. 

Stena Forth drillship; Source: Springfield

The Financial Times reported on Sunday that Springfield would, in the following days, reveal it had made two discoveries offshore Ghana totaling 1.2 billion barrels of crude. The discovery is said to be bigger than Jubilee, Ghana’s biggest so far.

Ghana’s news outlet GhanaWeb also reported on Springfield’s historic oil discovery offshore Ghana.

Springfield started drilling the Afina-1x well, the first of its much anticipated new wells located off the coast of Ghana, in October, using the Stena Forth drillship.

The Afina-1x well is located at the West Cape Three Points Block 2 (WCTP Block 2) where Springfield is the operator with an 84% interest with the Ghana National Petroleum Company and its exploration company, EXPLORCO, holding the remaining interest.

Offshore Energy Today has reached out to Springfield seeking confirmation of the reports of a major oil discovery and further details about it.

In an email, Springfield told Offshore Energy Today it would very soon officially announce details of its maiden Afina-1 well discovery in the West Cape Three Points Block2, offshore Ghana.

The company said that the Afina-1, which is located at a water depth of 1030 metres, was drilled to a total depth of 4082 metres and encountered light oil with a gross thickness of 65 metres, with 50 metres light net oil pay in good quality Cenomanian sandstones.

The secondary target in Turonian age sands was drilled at the edge of the structure and encountered 10 metres of hydrocarbon bearing sands consisting of light oil and gas.

Chief Executive Officer of Springfield, Kevin Okyere, said: “This is great news for Springfield, Ghana and Africa. We are excited about the discovery as it ties into our vision of becoming a leading African upstream player with a global focus. This for us means increased opportunities to impact the lives of our people positively with the resources.”

Springfield’s discovery ‘historic for local content’

Commenting on reports of Springfield’s discovery, the African Energy Chamber said in a statement on Monday that he soon-to-be-announced deep water oil discovery offshore Ghana by independent Springfield Group is historic for Ghana and Africa’s local content.

“Not only does it mark the first deep water oil discovery made by an African oil company, but it could also be a bigger find than Ghana’s Jubilee Field, which remains the biggest oilfield in the country,” the African Energy Chamber said.

According to the African Energy Chamber, while figures are still temporary and several additional assessments need to be conducted, the discovery is the result of the drilling of two wells over the past 40 days, which both struck oil. As much as 1.2bn barrels of oil could be held within the deposit, with up to 35% recoverable according to Springfield. Equally important, commercially viable quantities of gas were also discovered, the African Energy Chamber added.

Nj Ayuk, Executive Chairman of the African Energy Chamber and CEO at the Centurion Law Group, said: “Africa is a burning exploration frontier where the most significant oil & gas discoveries are being made not only by international explorers, but by our own companies. The Ghana discovery is the result of efforts made by African entrepreneurs, in a country where first discoveries were made only 12 years ago.

“More importantly, it was made within a block that was relinquished by US explorer Kosmos Energy, known to be a front-runner in making massive discoveries across Africa and opening up new frontiers. It speaks volumes to the value that local content development can create when African companies and entrepreneurs are given an opportunity to contribute to their industry.”

From no oil to sub-Saharan Africa’s fourth-biggest oil producer

The Afrucan Energy Chamber noted that, in only a decade, Ghana went from not producing oil to becoming sub-Saharan Africa’s fourth-biggest oil producer, with current production averaging about 195,000 barrels of oil per day (bopd).

The country has been spearheading transformations within the continent’s energy sector, providing the right market-driven policies and environment for African companies to acquire world-class assets from international counterparts, such as Springfield’s acquisition of Kosmos Energy block, or Chrome Resources and Rockefield’s acquisition of the West Keta block operatorship from Hess Corp after its exit in 2014.

Since the discovery of the Jubilee oilfield by Kosmos Energy in 2007, Ghana has managed to bring three offshore projects on stream, resolve its maritime border dispute with Cote d’Ivoire, and position itself as a key hydrocarbons province in the Gulf of Guinea.

Oil is now being produced from Jubilee field, Twenneboa, Enyenra and Ntomme fields, and Offshore Cape Three Points Integrated oil and gas development project. Production is expected to reach 250,000 bopd next year, and most optimistic expectations put output at half a million barrels a day by 2025.

The African Energy Chamber called on the government of Ghana to incentivize the full development of the block.

“Such a discovery has the potential to spur considerable economic growth for Ghana, already the world’s fastest-growing economy this year,” The African Energy Chamber concluded.

Offshore Energy Today Staff


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Aker Solutions teams up with oil majors in subsea gas separation JIP

Norwegian oilfield services company Aker Solutions and a group of oil and gas operators have come together in a joint industry project with the aim of making subsea gas separation a reality.

Source: Aker Solutions

Using CO2 injection to increase recovery rates in offshore oil and gas fields can improve the economics of a field significantly, but so far, the separation of ‘back-produced’ CO2 from the well-stream has been considered carried out on an existing platform, adding cost and making the concept economically unattractive.

Now, Aker Solutions together with energy companies Total, Pertamina, Equinor and industry group the CO2 Capture Project (CCP), have initiated a Joint Industry Project (JIP) to identify required membrane qualities for a subsea gas and CO2 separation process, to minimize pretreatment needs and avoid large processing modules, Aker Solutions announced on Friday.

Current CCP members are BP, Chevron, and Petrobras.

Flooding an oil field with CO2 increases recovery rates, and extends the life of an offshore field. Aker Solutions has developed new concepts for subsea processing of well streams from CO2-flooded oil fields, in which CO2-rich gas is separated, compressed and reinjected back into the reservoir. The hydrocarbon-enriched gas can then be routed to the topside production facility.

According to Aker Solutions, subsea gas separation has the potential to make CO2-rich gas fields commercially viable.

Testing membranes

A prerequisite for the concept to be technically and economically attractive is that the gas separation is done with robust membranes that reduce pretreatment requirements and remove the need for large processing plants, the company explained.

Also, the qualified operating range for relevant membrane materials do not match the optimal operating conditions for gas separation on the seabed. Hence, testing must be done in order to obtain knowledge about membrane performance under these conditions.

The project will perform tests of different membrane qualities under relevant conditions related to pressure, temperature, gas composition and rates. The tests will be carried out by the SINTEF research institute in Norway. The project also includes technical and economic engineering studies to assess the technology concept based on the test results.

The project aims to qualify membrane qualities that are suitable for bulk separation of CO2 in a typical subsea process and confirm technical and economic use of subsea processing as a favorable concept for the realization of offshore CO2 EOR in combination with reinjection and storage of CO2.

Aker Solutions delivered the first subsea gas compression system to Equinor for the Åsgard field offshore Norway. The system has been in operation with no unplanned downtime since it was installed in 2015. The subsea gas separation technology in combination with the subsea gas compression technology could make offshore handling of CO2 for EOR technically and economically attractive.


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Petrobras produces first oil at P-68 FPSO offshore Brazil

Brazil’s state-owned oil and gas company Petrobras has started oil and natural gas production at P-68 FPSO in the Berbigão field, in the Santos Basin pre-salt offshore Brazil. 

P-68 FPSO; Source: Estaleiro Jurong Aracruz

Sembcorp Marine’s Brazilian shipyard, Estaleiro Jurong Aracruz, completed the P-68 project for Petrobras and the FPSO left the shipyard in September 2019. The hull was built at the Rio Grande Shipyard, in Rio Grande do Sul, and the module integration and commissioning of the unit were carried out at the Jurong Aracruz Shipyard.

Following P-67, in the Lula field, and P-76 and P-77, in the Buzios field, P-68 is the fourth unit to start up in 2019, Petrobras said on Thursday.

With a capacity to process up to 150,000 barrels of oil per day and compress up to 6 million m³ of natural gas, P-68 will contribute to Petrobras’ production growth, particularly in 2020, with new wells being interconnected in the Berbigão field and the interconnection of wells in Sururu field.

The platform, an FPSO unit, is located approximately 230 km off the coast of the state of Rio de Janeiro, at a water depth of 2,280 meters. The project provides for the interconnection of P-68 to ten production wells and seven injector wells. The oil production offloading will be made by shuttle tankers, while gas production will be transported through the pre-salt gas pipeline routes.

Berbigão and Sururu fields are located in the BM-S-11A (Iara license), operated by Petrobras (42.5%), in partnership with Shell (25%), Total (22.5%), and Petrogal Brasil (10%). Reservoirs of these fields also extend to areas under the Transfer of Rights Agreement (100% Petrobras) and, after the unitization process, they will compose the joint reservoir of Berbigão and Sururu.

In a separate statement on Friday, Total said that the FPSO P-68 was first of the two FPSOs on the license. The second FPSO, the P-70, is expected to come on stream in 2020. Each unit has a capacity of 150,000 barrels of oil per day.

“First oil from Iara is a new milestone for Total in Brazil. It increases our share of production from the highly prolific pre-salt area, adding to current output from the Total-operated Lapa field, and the extended well tests under way on the Mero field,” said Arnaud Breuillac, President Exploration & Production at Total.

Shell also confirmed the startup of oil and gas production at P-68 FPSO in Brazil.

Wael Sawan, Shell’s Upstream Director, said: “It has been a banner year for Shell Brasil. From winning new acreage to setting records in drilling and production, the country continues to solidify its place as a heartland in our Upstream portfolio.”

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Karoon takes Stena drillship for Peru well

Australia-based Karoon Energy has executed binding agreements with drilling contractor Stena Drilling and oil company Tullow Oil to contract the Stena Forth drillship for Karoon’s Marina-1 exploration well located offshore Peru.

The Stena Forth drillship
The Stena Forth drillship; Source: Karoon

As previously reported, Karoon started tendering for a drilling rig to drill the Marina-1 well in March 2019.

The Stena Forth has been contracted to drill one well, being the Marina-1 exploration well, in Karoon’s 40% owned and operated Block Z-38 in the Tumbes Basin in Peru with drilling scheduled to start early in the first quarter 2020, Karoon said on Friday.

The Marina-1 well sits in water depth of approximately 350 metres and is targeting a gross prospective resource of 256 million barrels (102 million barrels net to Karoon).

Karoon said that, in the case of success in Marina-1, there is potential for a de-risking of a list of additional prospects in the block totaling over a billion barrels of prospective resource on a gross basis.

The drillship assignment agreement provides Karoon with a single well slot from the existing rig contract between Tullow and Stena. The drillship has already drilled two wells for Tullow offshore Guyana.

Karoon Managing Director, Robert Hosking, commented: “The contracting of the “Stena Forth” for the exploration of the Marina Prospect is an exciting opportunity for Karoon. Karoon has been working for some time to assess the prospectivity of the block, attract a farmout partner and prepare for drilling. The drilling of Marina-1 is a critical milestone for assessing the prospectivity of the deeper waters off northern Peru, and, on success, could de-risk several further exploration targets within Block Z-38, and Karoon’s 100% owned Area 73 Technical Evaluation Area, potentially providing important future production for Peru.

“The “Stena Forth” Drillship is a recently delivered harsh water drillship with capabilities to drill in far deeper water depths and much harsher sea states than those found in Northern Peru, Karoon is happy to have secured the use of such a high quality vessel for this well.”

The Marina exploration Prospect is a large fault bounded structure located in the Tumbes Basin with prospective reservoirs at multiple levels from 900 metres subsea down to 2900 metres subsea. Gross Prospective Resources in the Marina Prospect are estimated at 256 million barrels. Planned total depth of the well is 3026 metres.

According to Karoon, the Marina-1 will be the first well drilled in Z-38 and as such will be an important calibration point for the petroleum geology of the block. The information derived from the well will be valuable in assessing the other prospects and leads in Z-38, with over a billion barrels in gross prospective resources, and in the 100% owned Technical Evaluation Area 73.


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Tamarind administrators eyeing Tui drilling restart

Administrators of Tamarind’s New Zealand subsidiary have revealed they would be looking to continue the Tui drilling campaign in the Taranaki Basin.

Tamarind used the COSL Prospector rig for Tui well / Image source: COSL
Illustration: Tamarind used the COSL Prospector rig for Tui well / Image source: COSL

Tamarind said on Tuesday that it’s New Zealand subsidiary Tamarind Taranaki went into voluntary administration due to an “unsustainable financial position.”

Jason Kardachi and Mitchell Mansfield of Borrelli Walsh were appointed as the administrators of the company.

The administrators told Offshore Energy Today via email that the board of directors of Tamarind Taranaki made the decision to appoint the voluntary administrators due to unsustainable debt levels which have accrued for several reasons.

“These reasons include but are not limited to weaker oil price environment, the failure of the drilling campaign to access the additional ~4.5mbbls of oil remaining in the Tui field and other commercial factors.

“The purpose of the administration will be to reach an outcome which offers the best return for creditors, which we believe certainly includes a continuation and extension of the operations currently active on the field,” the administrators stated.

To remind, New Zealand’s Scoop Business website reported in September that  Tamarind had drilled a duster at the first of three planned development wells at the Tui oil field in the Taranaki Basin. The news website at the time cited the company’s CEO who said the result was unexpected, but that the other two wells were worth testing.

However, Scoop also reported that Tamarind – which acquired full Tui ownership in 2017 – had put its drilling plans to a halt as the company had not been able to reach an agreement with the drilling contract COSL for the second and the third well planned to be drilled with semi-submersible drilling rig used for the drilling of the first well – the COSL Prospector.

The administrators from Borrelli Walsh have also told Offshore Energy Today that they are assessing the potential to access new capital to continue the Tui drilling campaign on the Amokura and Pateke sidetrack wells.

“Further work has been undertaken by the company since the failure of the initial drilling campaign on these remaining two wells, and all indications are they are entirely viable and represent a solid independent investment with a very high probability of being successful.”

The Tui area oil project constitutes three fields, Tui, Amokura, and Pateke, which started production on July 30, 2007, and produce from four horizontal wells flowing to the FPSO Umuroa. The oil is processed on the Umuroa before being exported via export tankers destined for refineries on Australia’s eastern seaboard. The FPSO has a storage capacity of 700,000 barrels of stabilized crude oil.

Tamarind in October terminated a contract for the BW Offshore-owned FPSO Umuroa, operating at its Tui field in New Zealand.

The vessel owner said it would seek to recover all outstanding hire from Tamarind Resources and its parent company under the provisions of the existing contracts.

Offshore Energy Today Staff


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VIDEO: Peregrino C topside, living quarters set sail for Brazil

The Peregrino C topside and living quarters have set sail for its namesake field offshore Brazil from Texas and Norway, respectively.


Equinor published a video of the topside’s sail-away onboard Heerema’s H-541 cargo barge on its YouTube channel on Tuesday, November 12.

According to the company, it will take the topside more than a month to sail 5,485 nautical miles from Texas to Brazil.

On the same day, Equinor published a video of the sail-away of the living quarters for the Peregrino C platform. The living quarters set sail from Stord, Norway, onboard the BigRoll Beaufort vessel.



Equinor stated in its video descriptions that it was also installing subsea equipment and pipelines on the seabed at the field at the same time.

Once the platform comes on stream in late 2020, it will create approximately 350 long term jobs offshore and onshore Brazil.

In the videos, Equinor said that the new Peregrino C platform would be installed in December by Heerema’s heavy-lift vessel Sleipnir.

It is worth reminding that the jacket for the platform left the Netherlands in October, now followed by the topside and living quarters.

As for the Peregrino C jacket, it was built by Heerema Fabrication Group in the Netherlands. Equinor awarded HFG the procurement & construction contract for the Peregrino II WHP C Jacket in May 2017. The construction started in November 2017 at Heerema’s Vlissingen yard.

The jacket is approximately 135 meters tall with a footprint of 66 x 53 meters, and it weighs 9,200 tonnes.

The Equinor-operated Peregrino oil field is located in licenses BM-C-7 and BM-C-47, approximately 85km offshore Brazil, in the Campos basin, in water depths of 100m. The field consists of two fixed wellhead platforms and floating production storage and offloading unit.

The Peregrino C platform is part of the Peregrino Phase II Project, which includes the addition of a third fixed wellhead platform to the field. The second phase is expected to be developed at a cost of $3.5 billion.

The platform will contribute to prolonging the lifetime for the Peregrino field and will create value for 20 years. It will add 273 million in recoverable reserves.


Offshore Energy Today Staff

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AAOG finds rig for Tilapia drilling

Anglo African Oil & Gas plc has reached an agreement to source a drilling rig for a well at its Tilapia field offshore the Republic of the Congo. 

Aerial view of AAOG Congo site / Image AAOG

The Tilapia field is located 1.8 kilometers offshore of the Republic of the Congo, located in the Lower Republic of the Congo Basin. It is drilled from an onshore location and has production and storage facilities onshore.

Anglo African said Tuesday that it had entered into a rig option agreement (the “Rig Agreement”) with Société de Forage Pétroliers (“SFP”) for the provision of a rig to carry out drilling operations on well TLP-103C-ST at the Tilapia field.

“The Rig Agreement gives AAOG the right to contract the rig for TLP-103C-ST and a further four wells at our call. The SFP #1 Rig (the “Rig”) is the subject of contractual commitments to a super-major which will expire on 30 December 2019. SFP may extend such contractual commitments until (but not beyond) 30 March 2020 and will notify AAOG on or before 30 November 2019 as to whether its contractual commitments have been extended,” AAOG said.

Based on the schedule above, the drilling operation at AAOG’s well should begin either in the first or the second quarter of 2020.


Related: AAOG in Djeno discovery offshore Congo


AAOG said update the market once there is more certainty on timing, dependent on the rig’s current commitments.

Once the rig is secured, AAOG plans to re-enter the existing TLP-103C well and drill the new sidetrack just below the Mengo formation to test the Upper Djeno and explore the Middle Djeno formations. The objective is to determine whether the Djeno can be brought into production from either horizon.

Drilling activity is never without risk. However, the Directors believe that the sidetrack operations have an attractive risk/reward profile. TLP-103C has already proven the geological model and confirmed the presence of the Djeno at Tilapia. The fallback plan is to produce TLP-103C from the Mengo formation.

James Berwick, CEO said: “We are very pleased to have entered into the Rig Agreement and look forward to commencing operations at TLP-103C-ST as soon as the Rig becomes available. The Rig is the most suitable rig available in country and will come to TLP-103C-ST directly from drilling operations for a super-major. The Board of AAOG appreciate that drilling operations will commence later than we had hoped but, following the problems encountered in drilling TLP-103C, it was important that we found the right rig for this drilling campaign to avoid any similar issues.”


Offshore Energy Today Staff

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Reuters: Spirit Energy up for sale

Centrica and SWM have reportedly launched a sale process of the North Sea oil producer Spirit Energy.

Illustration: Spirit Energy's Chiswick platform
Illustration: Spirit Energy’s Chiswick platform

Reuters on Monday cited a document sent to prospective buyers, according to which Centrica wants to sell its 69 percent ownership in Spirit Energy. Reuters also said that SWM would evaluate proposals for the remaining stake.

Spirit Energy was established in 2017, through a combination of Centrica’s E&P business with Bayerngas Norge. Centrica plc owns 69% of Spirit Energy, with Bayerngas Norge’s former shareholders, led by Stadtwerke München Group (SWM), holding 31%.

The company’s 2018 production was 46.8 million barrels oil equivalent (mmboe), proven and probable (2P) reserves of 270 mmboe, and contingent (2C) resources of 512 mmboe.

Per the company’s 2018 summary document, Spirit Energy had operated and non-operated interests across the UK, Norway, the Netherlands, and Denmark, with 33 producing fields and 148 exploration licenses.

Offshore Energy Today has reached out to Spirit Energy seeking comment about the reported move by Centrica to sell the company. We’ll update the article if we receive a response.

Worth reminding, Centrica in July announced its intention to exit the oil and gas exploration and production business. Centrica at the time said it expected to exit its interest in Spirit Energy by the end of 2020 via a trade sale.

“Spirit Energy is a robust, self-financing entity in a range of price environments. However, E&P is not strategically core for Centrica and our intended exit from Spirit Energy is aligned with the global transition to a lower-carbon energy mix,” Centrica said in July.

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i3 Energy spuds new pilot well on Liberator field

UK independent i3 Energy has started drilling a new pilot well at its Liberator field in the outer Moray Firth, offshore UK.

Borgland Dolphin under mobilization to the current drilling operations for i3 Energy in August 2019. Source: Dolphin Drilling CEO Bjørnar Iversen

i3 said on Friday that this was the third and final well in a three-well campaign the company was carrying out with the Borgland Dolphin rig.

According to the company, the Liberator A2 pilot well will help i3 choose where to drill the future LP-02 production well.

The drilling of the final well follows the successful drilling, plugging, and abandonment of the Serenity well. The well struck oil in late October, confirming the strong commercial potential of the Serenity area.

Preliminary well results were consistent with i3 Energy’s pre-drill estimate of 197 MMbbls STOIIP for the entire Serenity closure within the company’s license area.

At the time, i3 has also agreed a rig contract extension and payment deferral with Dolphin Drilling. Namely, due to an unexpected on the Liberator field, and standby time incurred before drilling ops at Serenity, the company secured a right of first refusal on the Borgland Dolphin semi-submersible rig to January 31, 2020, so that the company can continue drilling operations at Serenity and Liberator.

Associated with this contract extension, Dolphin agreed to defer certain payments for drilling costs beyond September 30, 2019, which will be due to settle between January and August 2020.

i3 and Dolphin also entered into a strategic operational alliance for the use of Dolphin drilling rigs for i3 operations to August 2023, which would cover potential future appraisal and development drilling on Liberator and Serenity.

The company added in its statement on Friday that it agreed to issue £5 million of equity to the funders of its May 2019 junior loan notes at a price of 35p per share via private placement to provide flexibility to extend the drilling program.

The deadline by which i3 must enter a reserve-based lending facility or find alternative development financing has been extended from December 6 to April 30, 2020.

Majid Shafiq, CEO of i3 Energy, said: “We are excited to be drilling again at Liberator on the back of our success at Serenity.

“The A2 location has been selected as a low-risk target in close proximity to Liberator’s two well penetrations, giving us a high-level of confidence when tied into the recently reprocessed seismic that was used to select the Serenity discovery well location.

“The company is also very pleased with the additional funding we’ve received from our loan noteholders. Their continued material support shows a great level of confidence in i3’s assets and management team.”


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Woodside increases gas estimate for Scarborough project

Australian oil and gas company Woodside has completed subsurface studies on the Scarborough gas field, resulting in a resource volume increase of 52 percent.

Scarborough upstream concept schematic / Image source: Woodside

Woodside said on Friday that the estimated gross contingent resource (2C) dry gas volume for the Scarborough field increased to 11.1 tcf, up 52 percent from 7.3 tcf.

The company’s interest in the Greater Scarborough area, which covers the Scarborough, Thebe, and Jupiter fields, comprises a 75 percent interest in WA-1-R – which contains the majority of the Scarborough field – and a 50 percent interest in each of WA-61-R, WA-62-R, and WA-63-R.

It is worth noting that Woodside is the operator of these retention leases.

As a result of the volume increase, Greater Scarborough contains an estimated gross dry gas contingent resource (2C) volume of 13.0 tcf, a 41 percent increase from the previous 9.2 tcf.

Woodside added that the integrated subsurface studies incorporated full-waveform inversion 3D seismic reprocessing and updated petrophysical interpretation.

The seismic reprocessing improved the reservoir imaging quality and increased reservoir sand distribution.

Also, a comprehensive integrated review of the wireline log data and measurements from special core analysis increased net sand proportion and gas saturations. According to Woodside, assurance of this work was provided by an external independent reserves auditor.

It is worth noting that Woodside’s overall corporate contingent resources (2C) increased by 503 mmboe to 6,020 mmboe.

Woodside CEO Peter Coleman said: “Our understanding of the value of the Scarborough gas resource has increased after applying leading-edge technology to geophysical data collected since the field’s discovery almost 40 years ago.

“By unlocking the huge potential of the Scarborough gas resource we’ve strengthened the case for the development and extended the expected cashflow from Scarborough for years. This resource upgrade further improves Scarborough’s existing value proposition as we target the delivery of a new, globally competitive LNG project from 2024.”

Scarborough field

Woodside took over operatorship over the Scarborough project off W. Australia from ExxonMobil in 2018. Woodside paid $444 million for Exxon’s share and will pay $300 million following a positive final investment decision to develop the Scarborough field. The FID is expected to be made in the first half of 2020.

The Scarborough gas field, discovered in 1979, is located off the coast of Western Australia approximately 220 kilometers northwest of Exmouth in 900 meters of water. It is one of the most remote of the Carnarvon Basin gas resources. Woodside first bought a stake there in 2016 from BHP Billiton.

Scarborough gas would be initially processed on a deep-water floating production unit and transported through a 430 km pipeline to a proposed second LNG production train at the existing Woodside-operated Pluto LNG facility on Western Australia’s Burrup Peninsula.


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