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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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.”

Offshore Energy Today Staff


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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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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.

Offshore Energy Today Staff


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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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Oil majors’ West of Shetland assets to overtake North Sea as major producing basin in UK

Over the last four years oil and gas production in the West of Shetlands has risen and with that, a growing relevance for the biggest players still active in the UK continental shelf (UKCS), says GlobalData, a data and analytics company.

Clair Ridge platforms; Source: BP

The company’s latest research reveals that the West of Shetland (WoS) area retains the attention of major Exploration and Production (E&P) players in the region; however infrastructure restraints could hinder future growth potential in the basin.

Despite the US-based E&P majors, such as Chevron and ConocoPhillips largely divesting out of the UK’s E&P sector of late, their European peers have not followed suit, according to GlobalData.

Of the highly successful 30th UK Offshore Licensing Round held in 2017, approximately 75% of the licensed WoS blocks had European major participation. Moreover, European majors have stakes in 80% of the planned and announced projects in the area compared to approximately 40% in the North Sea.

Daniel Rogers, Upstream Oil and Gas Analyst at GlobalData, commented: “In 2018, Royal Dutch Shell (Shell) and BP Plc (BP)’s hydrocarbon production combined accounted for over half of the WoS total volume. Over recent years both companies have seen North Sea production volumes lose dominance in relation to their UK portfolios. As a result, the WoS is set to overtake the North Sea as Shell’s major producing basin in the UK by 2020, whereas this occurred for BP in 2018”.

The majority of upcoming field developments in the area are oil focused as oil processing capacity at the Sullom Voe terminal is currently around half utilized with expected excess capacity available over the near term. However, the Shetland Gas Plant (SGP), where the areas gas is collected, processed and exported, is currently running at less than 25% spare capacity and newly discovered gas volumes in the basin could push the infrastructure to its limits.

Rogers continued: “Total’s recently discovered Glendronach gas-condensate field is expected to add over 200 million cubic feet per day (mmcfd) of gas supply to the SGP at its peak and could commence production as early as 2021. This, in addition to gas volumes coming from the Cambo and Rosebank oil field developments could further strain the existing infrastructure.

“Operators looking to develop new gas fields in the WoS through the mid-2020s could be challenged by the areas capacity restraints. The investments required for facility expansions may impact project returns and force operators away from marginal gas developments.”


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Rystad: 2019 shaping up to be Norway’s best exploration year since 2014

Equinor on Wednesday announced an oil and gas discovery near the Fram field in the North Sea off Norway. Energy intelligence firm Rystad Energy has said that this has been the best year for discoveries on the Norwegian Continental Shelf since 2014. 

Illustration; Author: SP Mac

Equinor said on Wednesday that the recoverable resources were estimated at 6-16 million standard cubic metres of oil equivalent, corresponding to 38-100 million barrels of oil equivalent.

Commenting on Equinor’s oil and gas discovery near the Fram field in the Norwegian North Sea, Palzor Shenga, senior analyst at Rystad Energy said: “After a string of recent discoveries, 2019 is shaping up to be the most successful exploration year since 2014 on the Norwegian Continental Shelf (NCS).”

Rystad Energy estimates the discovery to hold recoverable resources of around 70 million barrels of oil equivalent (boe). This will bring cumulative discoveries year-to-date to 520 million boe, surpassing the 518 million boe found in 2018.

“Norway could see total discoveries reaching 650 million barrels of oil equivalent by year-end with decent success in ongoing exploration drilling campaigns,” Shenga added.

Aker BP has been the most successful driller thus far in 2019, with 41% of discovered volumes. Equinor comes in second, with 23% of total volumes. Lundin, Vaar Energi, and Wellesley Petroleum share the final place on the podium with 4% each.

“While the Barents Sea has been Norway’s most successful in the past seven years in terms of total volumes discovered, the number of discoveries and the volumes found prove that the mature parts of the NCS still have a lot to offer. The proximity of these discoveries to existing infrastructure makes them lucrative,” noted Shenga.


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Carigali Hess charter Velesto jack-up on a 3-year contract

Malaysian offshore drilling company Velesto Drilling has scored a contract with Carigali Hess for the provision of a jack-up rig.

Naga 8 jack-up rig - Image source: Keppel Corp.
Naga 8 jack-up rig – Image source: Keppel Corp.

Velesto will assign the Naga 8 jack-up drilling rig for the contract which is expected to begin in the second half of 2020.

The contract has a duration of three years and is valued at around $131 million (not including extension options). Hess will have three six-month extension options.

The offshore rig has a drilling depth capability of 30,000 feet and has a rated operating water depth of 400 feet.

Carigali Hess, Velesto’s client for the contract, is a joint venture Oil and Gas company between PCJDA Ltd, and Hess Oil Company of Thailand Ltd based in Kuala Lumpur engaged in gas production in Block A-18 of the Joint Development Area administered by the Malaysian-Thailand Joint Authority (MTJA).

To remind, Velesto earlier this year said that the Naga 8 rig had started its 18-month contract with Hess in 2Q 2018.

Data from the Bassoe Analytics tool shows that the contract is set to expire in April 2020, meaning there will be a short idle period for the rig until the start of the contract announced on Tuesday.


Offshore Energy Today Staff

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