Aker BP has announced that is has found oil in its latest discovery off Norway at an exploration well located in the Alvheim area.
In a statement, Aker BP said that the drilling of the Frosk exploration well 24/9-12 has proved oil and that preliminary analysis indicate a discovery size of 30-60 million barrels of oil equivalents (mmboe), which is significantly more than the company’s pre-drill estimates of 3-21 mmboe. The discovery also has a positive impact on the assessment of further exploration potential in the area.
Frosk is located in PL340, which also contains the Bøyla field. Bøyla has been producing oil since 2015 through a subsea installation tied back to the Alvheim FPSO.
“The Frosk discovery adds significant volume and value to our resource base, and provides an ideal basis for another profitable expansion project which will secure optimal utilisation of the infrastructure in the Alvheim area for many years,” said Gro G. Haatvedt, senior vice president Exploration in Aker BP.
She added: “The discovery has given us valuable new information about the geological conditions in the area, and has further increased the attractiveness of other possible exploration targets.”
Aker BP is the operator of PL340 with a 65 per cent working interest. The partners are Point Resources with 20 per cent and Lundin Petroleum with 15 per cent.
Neptune Energy Group has announced the completion of the acquisition of France's Engie E&P International (EPI). The private-equity producer now has global reach and access to a balanced portfolio of oil and gas production.
For undisclosed terms, Neptune said it acquired Engie exploration arm and enables Neptune to become an international independent E&P company across the North Sea, North Africa and South East Asia, producing 154,000 net barrels of oil equivalent per day in 2017.
Sam Laidlaw, Executive Chairman of Neptune Energy Group, said: “I am pleased to announce the completion of this significant achievement, which is the result of some three year’s work and marks a new beginning for Neptune Energy. Building on the success and hard work of the EPI team and leveraging its strong portfolio of assets, we aim to generate long term sustained value for the countries in which we operate, our employees and for our investors in order to create a leading international independent E&P company within the next 5 years."
The North Sea region benefits from a strong operating base in strategic assets such as Cygnus in the UK and Gjøa in Norway, while Neptune is the leading offshore operator in the Netherlands. North Africa and Southeast Asia provide near-term gas volume growth into strengthening markets while Germany offers a strong, long-life oil production base.
Deirdre Michie, the chief executive at trade group Oil & Gas U.K., said the spending effort from Neptune was a testament to the legacy of North Sea operations.
"This transaction highlights that the U.K. oil and gas sector continues to offer smart investors good commercial opportunities on the back of the huge efficiency improvements of recent years," she said in an emailed statement.
Neptune's oil and gas arm was established three years ago by equity funds Carlyle Group and CVC Capital Partner, and now China Investment Corp.
Russian oil producer Lukoil said its 2017 hydrocarbon production rose in 2017 on back of gas development projects, but its oil production was down in the fourth quarter.
Its hydrocarbon production in the fourth quarter of 2017 excluding West Qurna-2 project increased by 2.9 percent quarter-on-quarter to 2,284 thousand barrels of oil equivalent (boe) per day.
On an annual bases, this was up by 2.4 percent year-on-year to 2.234 million boe per day.
In the fourth quarter of 2017, the Lukoil Group’s gas production increased by 12.5 percent quarter-on-quarter to 8.2 billion cubic meters. In 2017 gas production increased by 15.7 percent year-on-year to 28.8 billion cubic meters.
Lukoil said it achieved significant progress in the Uzbekistan gas projects.
In the fourth quarter of 2017 production at Kandym and Gissar projects increased by 30.7 per cent quarter-on-quarter to 2.8 billion cubic meters. The growth was driven by the launch of new gas treatment facilities.
Gas production growth in Russia was mainly attributable to the launch of gas facilities at Pyakyakhinskoe field in January 2017.
Meanwhile, oil production excluding West Qurna-2 project slipped to 85.6 million tonnes in 2017 from 91.99 million tonnes in 2016. This included fourth quarter production of 21.5 million tonnes.
Lukoil said its 2017 oil production volumes and dynamics were defined by external limitations of Russian companies’ production volumes.
It produced a 21.2 per cent increase on a quarterly basis from the V. Filanovsky field, outperforming the planned output by 170,000 tonnes to reach 4.6 million tonnes.
It also raised production in a few other fields such as: Timan-Pechora, Yaregskoe, Usinskoe field.
Refinery throughput in the fourth quarter of 2017 was practically flat quarter-on-quarter and amounted to 17.3 million tonnes. Refinery throughput in 2017 increased by 1.8 percent year-on-year to 67.2 million tons.
In Russia, refinery throughput in Russia increased by 3.2 per cent year-on-year, which was mainly due to Volgograd refinery upgrade, as well as scheduled maintenance works at Nizhny Novgorod and Volgograd refineries in 2016.
Australia's biggest oil and gas producer, Woodside said it signed a deal to buy ExxonMobil's share of the Scarborough gas field located in the Carnarvon Basin, offshore Western Australia.
Woodside will pay A$400 million for the stake and the deal includes a contingent payment of $300 million once the final investment decision has been made, it said in a statement.
The company will acquire an additional 50 percent interest in WA-1-R which contains the majority of the Scarborough gas field. Upon completion of the transaction Woodside will have a 75 percent interest in WA-1-R and a 50 percent interest in WA-61-R, WA-62-R and WA-63-R.
Separately, Woodside said it would raise A$2.5 billion ($1.96 billion) from shareholders to fund the purchase of ExxonMobil Corp’s stake in the Scarborough gas field and fund developments in Australia and Senegal.
Peter Coleman, CEO of Woodside said the Scarborough acquisition delivered greater alignment, control and certainty for the project while also unlocking shareholder value
In November 2016, Woodside completed the acquisition of half of BHP Billiton's Scarborough area assets which include the Scarborough, Thebe and Jupiter gas fields, which are estimated to contain contingent resources (2C) of 2.6 Tcf of dry gas (8.7 Tcf, 100 percent).
Woodside estimates its LNG flow will be boosted by 40 percent when Scarborough production starts in 2025.
Coleman said: “Our Burrup Hub concept is advanced by our announcement today of an increased stake in the Scarborough gas field. The development concept involves maximizing existing infrastructure at the Pluto LNG plant to meet a market gap we expect will emerge from the early 2020s.”
With the announcement of the stake purchase, Woodside also announced a full-year net profit of A$$1 billion. Its 2017 production was 84.4 MMboe and sales revenue was $3.62 billion.
“Our net profit after tax has increased by 18 per cent year-on-year, driven by higher prices for our products and sustained low production costs,” Coleman said. “At the same time, we were able to maintain our outstanding safety performance and our three FPSO facilities achieved a record average reliability of 95 per cent.”
Norway’s Statoil said it awarded a construction and installation contract to Kværner for the Johan Castberg floating production, storage and offloading vessel (FPSO) in the Barents Sea valued at 3.8 billion Norwegian kroner (US$481 million).
Kværner will utilise a number of yards along the Norwegian coast for the construction work of the FPSO including yards in Sandnessjøen, Verdal, Stord and Egersund.
The contract includes building a total of ten modules, a flare boom and central pipe rack, Statoil said in a statement.
“This is one of the large pieces of the Johan Castberg puzzle, and is a key component of the FPSO,” said Torger Rød, Statoil’s senior vice president for project management control. “The international competition for the contract has been tough, and we look forward to working closely with Kværner in the years to come.”
The construction work is scheduled to last until 2021, followed by a complex assembly period. In this period the topside structure will be installed on the hull and connected to the turret. First oil from the field is scheduled for the first half of 2022.
“The Johan Castberg development will generate substantial spinoffs for Norwegian supply industry in the years ahead. The field is also essential to the further development of industry in Northern Norway, and we are pleased that this contract will help increase activities in the north,” said Pål Eitrheim, Statoil’s chief procurement officer.
Johan Castberg will be the sixth project on stream in Northern Norway. The field has been important to the further development of the oil and gas industry in the north. Thanks to Johan Castberg infrastructure will be developed in a new area of the Norwegian Continental Shelf.
Capital expenditures for the Johan Castberg project are estimated at some NOK 49 billion (capex numbers in nominal terms based on fixed currency) and the jobs generated nationwide during the development are estimated at slightly less than 47,000 man-years.
The field will be producing for more than 30 years, and substantial spinoffs will be generated in the long production phase. Castberg will create considerable activities for Norwegian supply companies and generate ripple effects in Northern Norway. Recoverable resources are estimated at 450 – 650 million barrels of oil equivalent.
Statoil sanctioned projects worth 90 billion Norwegian kroner in 2017 on the NCS. Norwegian suppliers have secured 70 per cent of the contracts related to these projects so far.
The contact is subject to government approval of the plan for development and operation.
Faroe Petroleum, an independent oil and gas company said it sold a 17.5 per cent interest in offshore Norway’s Fenja development to Canada’s Suncor Energy for US54.5 million.
The Norway and UK-focused company will retain a stake of 7.5 per cent, which will align its equity at 7.5 per cent across the Greater Njord area, including Njord, Fenja, Bauge and Hyme.
The sale will to reduce Faroe’s future capital expenditure on Fenja to approximately £70 million, based on the operator’s gross projected development cost of NOK 10.2 billion, Faroe said in a statement. It will also help maintains Faroe’s strong balance sheet and fully funded position across its portfolio of Norwegian field developments, it added.
“Suncor’s acquisition of a 17.5 per cent stake in Fenja from Faroe confirms our belief in the attractiveness of this project. We look forward to working together with Suncor as the Fenja project progresses to first oil,” said Graham Stewart, CEO of Faroe Petroleum.
Faroe took Fenja through exploration and appraisal drilling to predevelopment work. It said the sale validates Faroe’s business model of generating tangible shareholder returns from its exploration portfolio. “Having held a significant interest in PL586 from its discovery, Faroe has now generated cash returns through a partial-monetisation while still giving shareholders exposure to future cash flows from a continuing interest in this high quality project,” Stewart said.
As detailed in the Plan for Development and Operation (PDO) submitted on 19 December 2017, the operator, VNG Norge AS, expects total gross recoverable reserves from the Fenja development of approximately 97 million barrels of oil equivalent (72 per cent of which is oil), Faroe said.
The transaction has a 1 January 2018 effective date and remains subject to the usual and customary conditions including regulatory approval of the transfer and approval of the Fenja PDO by the Norwegian Ministry of Petroleum and Energy. The sale is expected to complete during the first half of 2018.
U.S. natural gas exporter Cheniere Energy (Cheniere) said it entered into two liquefied natural gas (LNG) sale and purchase agreements with China National Petroleum Corporation (CNPC), breaking into the Chinese market for the first time.
CNPC unit PetroChina International Company will purchase approximately 1.2 million tonnes per annum of LNG from Cheniere’s subsidiaries, Corpus Christi Liquefaction and Cheniere Marketing International.
A portion of the supply will begin in 2018 and the balance beginning in 2023 and running through to 2043. The purchase price for LNG will be indexed to the Henry Hub price plus a fixed component, Cheniere said.
“We are pleased to announce these LNG contracts with China National Petroleum Corporation, an important global energy player in one of the largest and fastest growing LNG markets worldwide,” said Jack Fusco, Cheniere’s president and CEO. “These long-term SPAs build upon the Memorandum of Understanding we signed in November, and we look forward to a successful long-term partnership with CNPC. We expect these agreements to support the development of Corpus Christi Train 3, and we are now focused on completing the remaining necessary steps to reach a final investment decision later this year.”
Eni said it made promising a natural gas discovery offshore Cyprus, which looks similar to the nearby giant Zohr field.
“Calypso 1 is a promising gas discovery and confirms the extension of the “Zohr like” play in the Cyprus Exclusive Economic Zone (EEZ),” said the Italian oil and gas producer, who discovered Zohr, the giant Mediterranean gas field offshore Egypt in 2015.
Located in the Egyptian offshore Shorouk block about 190 km north of Port Said, Zohr holds an estimated 30 trillion cubic feet of gas, the largest ever discovered in the Mediterranean.
Calypso in Cyprus’s waters is an estimated 80 km away. The well, which was drilled in 2,074 meters of water depth reaching a final total depth of 3,827 meters, encountered an extended gas column in rocks of Miocene and Cretaceous age.
Eni is the operator of Block 6 with 50 per cent of participation interest while Total is partner with the remaining 50 per cent.
Eni said the Cretaceous sequence has excellent reservoir characteristics. An intensive and detailed data collection (fluids and rock samples) has been executed on the well.
Additional studies will be carried out to assess the range of the gas volumes in place and define further exploration and appraisal operations.
Eni holds interests in six licenses located in the EEZ of Cyprus (in Blocks 2, 3, 6, 8, 9 and 11), five of which are operated.
Total posted a 28 per cent jump in 2017 adjusted net income as higher oil prices and production growth pushed up the oil major’s upstream revenue.
The French company reported an adjusted net income or profit of US$10.6 billion for the year, while its fourth-quarter profit rose 19 per cent to $2.9 billion.
Its profit outpaced the average rise in Brent crude prices for 2017 of $54 per barrel, compared to $44 per barrel in 2016.
“The group demonstrated its ability to capture the benefit of higher prices-the Upstream, in particular, increased its results by more than 80 per cent and its operating cash flow by close to 40 per cent,” chairman and CEO Patrick Pouyanné.
He said the company had a return on equity above 10 per cent, the highest among the oil and gas majors.
The biggest share of profits was from its exploration and production, which was up 86 per cent year-on-year to $5.99 billion.
The French group in 2017 saw a 5 per cent growth in production to 2.56 million barrels of oil equivalent per day. It started production in Moho-Nord in the Republic of Congo, ramped-up Kashagan in Kazahkstan, and entered into the Al-Shaheen project.
Additionally, the group launched five upstream projects including the first phase of the Libra development in Brazil, as well petrochemical projects in the United States and South Korea.
In the US Gulf of Mexico, Total was part of a major discovery at the Ballymore prospect, its largest discovery in the area.
Total’s downstream operations yielded $7 billion in cash flow and reported a return on capital employed of more than 30 per cent. However, refining and chemicals revenue was down 10 per cent to $3.79 billion.
The company’s cost reduction strategy implemented since 2015 has helped it to reduce its pre-dividend organic breakeven to $27 per barrel in 2017 and generated $22 billion of debt-adjusted cash flow.
The group also continued to strengthen its balance sheet, ending the year with 14 per cent gearing or debt-to-equity ratio, which Total said was a significant decrease compared to 2016.
Total rewarded shareholders with a 10 percent increase in dividends over the next three years. The 2018 interim dividend will rise 3.2 percent, and it plans to buy back up to $5 billion shares over the 2018-2020 period.
Aker Solutions said it won a contract to provide maintenance and modifications services for three platforms at Petrobras-operated oil and gas fields offshore Brazil, expanding its business in a key international market.
The four-year contract is valued at about NOK 800 million (US$101.3 million) and includes an option for a one-year extension, Aker said in a statement.
The contract covers a range of services to renovate, repair and upgrade the floating production storage and offloading platforms, or FPSOs, at the Barracuda, Caratinga and Albacora Leste fields in the Campos Basin. It also entails management at the yard where replacement parts and other equipment will be fabricated.
"Brazil is an important global market and growth area for servicing oil and gas fields," said Aker Solutions chief executive officer Luis Araujo. "We look forward to helping Petrobras optimise and extend the life of these assets."
The company will execute the work from its C.S.E. Mecânica e Instrumentação Ltda services base in Macaé, Rio de Janeiro. Aker Solutions acquired a majority stake in C.S.E. in December 2016.
The work starts in March 2018, with final deliveries scheduled for the first quarter of 2022.
Aker will book the contract in first-quarter orders.
Norwegian oil producer Statoil said it has brought down the breakeven price for Johan Sverdrup by cutting cost and increased resource estimate to boost the value of the offshore project.
The breakeven price of the project’s first phase was reduced to $15 per barrel and to $20 per barrel for the full project, Statoil said in a statement.
Phase 1 of the project, Statoil said, is currently estimated at NOK 88 billion ($11.23 billion), which amounts to a reduction of NOK 35 billion ($4.47 billion) or close to 30 percent since the plan for development and operation (PDO) was approved in August 2015.
The offshore project is 70 per cent complete, on plan and investment costs are continuing on a positive trend, Statoil said.
“There is high quality in project execution, the costs are decreasing, and the resource estimate goes up,” said Margareth Øvrum, executive vice president for Technology, Projects & Drilling in Statoil.
“Johan Sverdrup is now even more robust and valuable for both the partners and society.”
Øvrum said the project is also benefiting from the drilling and well improvement programme in Statoil.
“We’ve drilled more wells than planned, more than one year ahead of plan, which has contributed greatly to cost reductions in the project. The wells also make our production plans even more robust and have improved our knowledge of the reservoir. Based on this, we are now able to increase the resource estimate for Johan Sverdrup further,” she said.
Since the PDO for the first phase was submitted the range of the full-field resource estimate has improved from 1.7-3.0 to now 2.1-3.1 billion barrels of oil equivalents.
The Johan Sverdrup project will be developed in several phases, and the PDO for phase 2 will be submitted to Norwegian authorities in the second half of 2018. Further maturation has reduced the estimated investment costs for phase 2 to below NOK 45 billion.
With this, the break-even for the full-field development of Johan Sverdrup has been improved to below $20 per barrel.
“The standardisation of equipment packages, copying of good solutions, and doing things right the first time – in collaboration with our suppliers – has been critical to the positive developments that we see in the first phase of Johan Sverdrup,” said Kjetel Digre, project director for Johan Sverdrup in Statoil. “In phase 2 we are taking this one step further, and we are starting to see the results of this.”
A more streamlined operation and maintenance model, combined with increased use of digital and automated solutions, has also helped reduce estimated yearly operating costs by nearly NOK 1 billion or approximately 30 percent since the PDO was approved in August 2015, Statoil said.
BP’s annual profit more than doubled on back of higher oil prices and its strongest output growth in recent history.
BP reported a surge in full-year profits to $6.2 billion from $2.6 billion in 2016. It’s fourth-quarter net profit was $2.1 billion, a jump from $400 million a year earlier.
“2017 was one of the strongest years in BP’s recent history,” chief executive officer Bob Dudley said in a statement. “We delivered operationally and financially.”
Upstream production for the year rose 12 percent to 2.47 million barrels per day (bpd) after BP launched seven new oil and gas fields in 2017, a record year.
BP plans to start up six additional projects this year including in U.S., Egypt, Azerbaijan and Britain’s North Sea, helping boost production by 900,000 barrels of new, major project production by 2021, most of it gas. It previously said it would launch five new projects this year.
BP’s refining and trading business, (downstream), saw profits rise to $7 billion in 2017, up 24 per cent from the year-earlier period as margins rose.
Meanwhile, payments for the Deepwater Horizon spill continued to weigh. BP paid $5.2 billion for the full year, which was down from $6.9 billion in 2016. The company took a $1.7 billion charge in the fourth quarter due to higher-than-expected claims settlements, bringing the total legal and clean-up costs to $65 billion.
BP also took a one-off charge of $900 million to adjust to new U.S. tax rules, but Dudley said BP will invest more in the United States as a result.
BP’s full-year capital spending reached $16.5 billion, within the annual range of $15-$17 billion it plans to maintain until 2021.
“We enter the second year of our five-year plan with real momentum, increasingly confident that we can continue to deliver growth across our business, improving cash flows and returns for shareholders out to 2021 and beyond,” Dudley said.
BP began a shares buyback in the fourth quarter, spending $343 million, which fully offset the dilution from scrip dividends issued in the third quarter, it said.
Dudley said BP is currently a 3.6 million barrel per day company including equity production in Russia, with an estimated 18.4 billion barrels of proved oil equivalent reserves, which gives BP 13.7 years of reserve life.
“Across our total Upstream resource base of 48 billion barrels, we have sufficient opportunities to deliver quality growth through the next decade, and beyond, without the need for acquisitions or further exploration,” he said.
Lukoil is planning to invest a 120 billion roubles (US$2.1 billion) to build a chemicals complex on the Northern coast of the Caspian Sea that will use natural gas as a feedstock.
“We have decided to invest in the construction of a gas-chemical complex there, which will manufacture chemicals, and its second stage will turn out polyethylene and polypropylene,” Vagit Alekperov, CEO of the Russian oil producer said in a meeting with Russian President Vladimir Putin, according to a statement on the Kremlin's official website.
“We have drafted a new project stipulating the comprehensive development of the Caspian Sea’s northern sector. Today, a gas pipeline has been built towards Budyonnovsk,” he added.
The chemicals complex will enable the development of the southern section of Stavropol Territory, Which is in need of jobs. The complex will employ 600 workers and over 3,000 builders.
Alekperov said the investment project has been approved, and preparations are now underway. Lukoil is working on the project at a government level to move the complex along.
Chemicals produced from the complex will exported using the Novorossiisk port as well as sold domestically since the Stavropol and Krasnodar territories remain agricultural regions, Alekperov told Putin.
Petrofac said it has been hired for well operator services on the next phase of Tullow Oil’s Thames decommissioning project, following the award of a new multi-million dollar contract.
Under the terms of the award, Petrofac will provide well engineering project management services and fully execute plug and abandonment operations on seven of Tullow Oil’s subsea wells. This will include detailed planning, direct procurement and management of all sub-contracted services, including provision of a jack-up rig. Petrofac has also been nominated as well operator for the project.
In 2016 the company permanently abandoned two wells for Tullow Oil on its Horne & Wren asset, delivering cost savings of US$2.5million through its differentiated approach to decommissioning.
“Having proven our integrated well engineering services capability and realised substantial cost savings for Tullow Oil, we are delighted to have an opportunity to further strengthen our relationship,” said Alex Macdonald, managing director for well engineering at Petrofac Engineering and Production Services.
“Certainty of cost and schedule are critical success factors for this project. We have worked collaboratively with our supply chain to develop a shared approach to risk and reward, which supports delivery excellence. We very much look forward to realising this added value for Tullow Oil as the project progresses.”
Petrofac became the first outsourced well operator to execute fully integrated Well Operator services in 2016. The company’s well operator capability evolved from its outsourced service operator model and its extensive track record in well project management, enabling Petrofac to provide a standalone or integrated approach to the management of wells, installation and pipeline operations.
Deep Sea Mooring (DSM), a Vryhof company, said it won a Quadrant Energy contract to provide turnkey pre-lay mooring services to the Transocean GSF Development Driller 1 semisubmersible drilling rig offshore Australia.
The deal - a continuation of previous work for Quadrant Energy - begins in March 2018, DSM said in a statement but did not disclose the value of the contract.
The agreement - with the project scope and engineering consultancy coordinated out of Perth - will enable Quadrant to have access to DSM and Vryhof Anchors’ advanced portfolio of pre-lay mooring solutions that include chains, fibre ropes, anchors, connectors, buoyancy and handling equipment. Offshore personnel, back deck services, marine representatives and all equipment will be deployed from DSM’s Karratha, West Australia base.
“Today’s announcement is the continuation of a highly successful track record of delivering for Quadrant and is a significant platform upon which we can continue to grow our Australian business during 2018,” said Barry Silver, managing director, Asia Pacific for Deep Sea Mooring.
The GSF Development Driller 1 rig was built in 2005 and is a sixth generation semi-submersible with a maximum water depth of 7,500 feet and drilling depth of 37,500 feet.
French major Total said it has signed agreements to acquire interests in two exploration licenses offshore Guyana – the Canye Block and the Kanuku Block.
With the new blocks, Total will own exploration rights to an area covering over 12,000 square kilometers in the Guyana Basin once the relevant approvals are in place, the oil major said in a statement.
The deal comes after Total agreed last September to pay $1 million for an option to buy a 25 per cent stake in the Guyana offshore Orinduik Block, operated by Tullow Oil. The Block falls in an area close to where ExxonMobil made one of the largest discoveries of the last decade through Liza drilling campaigns which confirmed a world-class resource discovery in excess of 1 billion oil-equivalent barrels.
“Total is very pleased with this significant entry in the prolific Guyana Basin,” said Arnaud Breuillac, president, exploration and production at Total. “The Canje, Kanuku and Orinduik blocks are located in a very favorable petroleum context, evidenced by the Liza discovery in 2015. Acquiring interests in these highly prospective licenses is in line with the new exploration strategy in place since 2015.”
Total will buy a 35 per cent stake in the Canje Block, located in water depths of 1,700 to 3,000 meters, under the terms of the agreement signed with an affiliate of Canadian company JHI Associates, Inc. and Guyana-based company Mid-Atlantic Oil & Gas, Inc. These two companies will retain a shared 30 per cent interest alongside operator ExxonMobil (35 per cent).
In the Kanuku Block, located in water depths of 70 to 100 meters, Total will acquire a 25 per cent interest, under the terms of the agreement signed with operator Repsol (37.5 per cent), and will be a partner alongside Tullow (37.5 per cent).
The Orinduik Block stake option was in a deal with an affiliate of Canadian company Eco Atlantic Oil & Gas Ltd, who will retain a 15 per cent interest following exercise of the option, alongside operator Tullow (60 per cent), Total said.
WorleyParsons said it was awarded a new engineering and project management agreement by Australia’s QGC Pty Limited (QGC) for three years with options for two additional one year terms.
Under the agreement WorleyParsons will provide engineering, procurement, construction management and project management services to support QGC across the upstream and midstream facilities from the Surat Basin to Curtis Island.
“We are pleased to be awarded this agreement so that we can continue our successful relationship with QGC and support on-going investment in the Queensland energy resources sector” said Andrew Wood, chief executive officer of WorleyParsons.
QGC was previously part of the BG Group, before BG was bought over by Shell in 2016.
TechnipFMC said it signed an agreement with Norway’s Island Offshore group to acquire a majority stake in its subsea unit.
For an undisclosed amount, TechnipFMC will acquire a 51 per cent stake in Island Offshore’s wholly owned subsidiary, Island Offshore Subsea AS, subject to satisfaction of closing conditions.
The unit provides riserless light well intervention (RLWI) project management and engineering services for plug and abandonment (P&A), and well completion operations.
Island Offshore Subsea AS developed proprietary designs related to subsea P&A and riserless coiled tubing. In connection with the acquisition of the controlling interest, TechnipFMC and Island Offshore will enter into a strategic cooperation agreement to deliver RLWI services on a worldwide basis, which will also include TechnipFMC’s RLWI capabilities.
The Norwegian subsea unit will be rebranded and become the operating unit for TechnipFMC’s RLWI activities worldwide.
Odd Strømsnes, vice president of offshore integrated services at TechnipFMC, will become the managing director of Island Offshore Subsea AS.
Morten Ulstein, chairman of the Island Offshore Group, stated: “Over the years we have had a rewarding cooperation with TechnipFMC, and we now see that an even closer integration of our companies and services is right to further develop and strengthen our position within RLWI, both in Norway and internationally.”
The companies’ track record for delivering services together helped significantly boost production from more than 500 subsea wells, Hallvard Hasselknippe, president of TechnipFMC’s subsea business said.
Statoil and licence partners in Barents Sea have signed a contract with North Atlantic Norway for use of the West Hercules semi-submersible rig in drilling two exploration wells in the Barents Sea this year.
The total estimated contract value is USD 15-20 million for the two permanent wells, which includes the options to drill another five exploration wells, Statoil said in a statement.
Mobilisation and demobilisation are included in the amount, but remotely operated vehicles (ROV) and other services will be charged extra. Planned drilling start is summer 2018.
“We have chosen this rig because it is winterized and ready for use in cold waters. We have used this rig before, both in the norther part of the Norwegian continental shelf and in Canada. We expect North Atlantic Norway to provide safe and efficient operations,” said Geir Tungesvik, head of Drilling and Well in Statoil.
UK supermajor BP announced two new exploration discoveries in the North Sea at Achmelvich and Capercaillie that is timely boost for the UK oil and gas industry.
The discoveries at Capercailli were made in Block 29/4e in the Central North Sea, and Achmelvich, in Block 206/9b west of Shetland. Both wells were drilled by the Paul B Loyd Junior rig in Summer 2017.
The Capercaillie well was drilled to a total depth of 3,750 metres and encountered light oil and gas-condensate in Paleocene and Cretaceous-age reservoirs. The Achmelvich well was drilled to a total depth of 2,395 metres and encountered oil in Mesozoic-age reservoirs. Evaluation and interpretation of the well results is ongoing to assess future options.
Mark Thomas, BP North Sea Regional president said: “These are exciting times for BP in the North Sea as we lay the foundations of a refreshed and revitalised business that we expect to double production to 200,000 barrels a day by 2020 and keep producing beyond 2050.
Fiona Legate, Senior Analyst, North Sea Upstream at Wood Mackenzie said: "It's early days in terms of assessing development options for the two discoveries and further drilling may be need to firm up future plans. Both fields are near producing infrastructure and could be fast-tracked into production in the near term.
Despite its recent divestments in the North Sea, BP clearly is clearly still committed to the UK. It plans to double production by 2020 to 200,000 bpd. Development of these two discoveries, plus other opportunities in its portfolio will help to achieve this target. Production from the core West of Shetlands developments Clair and Schiehallion will ramp up over the near term. We estimate BP’s UK production will reach 180,000 b/d in 2020 which highlights the gap future investments can help to fill."
BP is 100 per cent owner of Capercaillie and the Achmelvich well partnership comprises BP (operator, 52.6 per cent), Shell (28 per cent) and Chevron (19.4 per cent).