The African Export-Import Bank (Afreximbank) is supporting the advancement of Mozambique’s energy industry and economy by committing up to US$400 million in guarantees and direct lending to the Area 1 LNG Project.
The total Project is estimated to cost about US$24 billion and is set to be the largest private foreign direct investments in Africa, and one of the largest LNG projects in the world. It will play a key role in Mozambique’s economic growth and support the wider region.
The $400 million financing will be used to partially finance the project development activities required to extract natural gas offshore, its transfer to onshore processing facilities and then its conversion to LNG for export to various markets around the world.
The Mozambique Area 1 LNG project is an integrated LNG development that will initially comprise two LNG liquefaction trains – each capable of processing 6.44 million metric tonnes a year. The initial development is expected to produce more than sixteen trillion cubic feet of gas and ninety-three million barrels of condensate over the 30-year development and production period.
A key focus is for the project to be developed in an environmentally and socially sustainable manner and that it operates responsibly, protecting the environment, as well as the health and safety of the public, employees and contractors. Investment into the region will create jobs, increase the standard of living and is expected to drive long-term sustainable economic growth for the country and the region.
The $400 million commitment to the project is in line with Afreximbank’s strategy of promoting intra-African trade as well as industrialisation and export development. The guarantee is done jointly with Export Credit Insurance Corporation of South Africa SOC Limited (ECIC) which has enabled significant African contribution to the overall financing of the Project. This joint collaboration is offered under the South Africa-Africa Trade and Investment Promotion Programme (SATIPP), launched in 2018, to promote and expand trade and investments between South Africa and the rest of Africa.
Prof. Benedict Oramah, President of Afreximbank, said: “We are confident the Mozambique LNG project will create opportunities for the people of the country and drive sustainable economic growth. We believe that the success of projects such as this will create a precedent through which other development projects in Africa can secure funding and gain international traction. We are delighted to be one of the key stakeholders involved in this project which will accelerate the rate of growth of intra-African trade.”
Following the regulatory approvals and the agreement of partners, Total closed the sale of UK North Sea non-core assets to NEO Energy.
“As announced on May 20, we have worked closely with HitecVision and its portfolio company NEO Energy to conclude this sale. This sale of assets contributes to the action plan currently being implemented to address the economic crisis by focusing on cash delivery and demonstrates our ability to relentlessly lower the breakeven of our portfolio,” declared Jean- Pierre Sbraire, chief financial officer of Total.
The detailed transition plan prepared with NEO Energy will ensure a smooth transfer of operations.
Eni and ASSTRA, the national association of local public transport companies in Italy, have signed a collaboration agreement to implement a series of initiatives and trials to decarbonise transport and reduce the levels of particulates released into the air, using a holistic and technologically neutral approach to identify the appropriate solution for each area of use.
The agreement provides for joint studies to share expertise, mutual participation in thematic working groups and the promotion of a joint position paper highlighting the different existing energy, technological and organisational opportunities.
These opportunities include those deriving from the integration of public transport and forms of sharing mobility, the use of biolubricants and biofuels in public transport and the application of the Life Cycle Assessment (LCA) and "Well to Wheel" approach in assessing the impact the various mobility solutions have on emissions.
Hydrogen mobility is also included in the agreement. Eni and Asstra will assess the possibility to begin experiments involving the use of hydrogen as an alternative fuel.
The agreement aims to promote training initiatives for member companies and public transport users to help create and disseminate a culture of circularity and greater environmental and social awareness of alternative mobility solutions.
UK's BP has reported big losses of US$16.8 billion for the second quarter as it halves its dividend and lays out a new 10 year energy strategy to deliver its net-zero ambition.
The reported loss of $16.8 billion compares with a profit of $1.8 billion for the same period in 2019. BP had second-quarter underlying losses of $6.7 billion, with the main hit coming from $17.4 billion of impairments and exploration write-offs.
“These headline results have been driven by another very challenging quarter, but also by the deliberate steps we have taken as we continue to reimagine energy and reinvent bp. In particular, our reset of long-term price assumptions and the related impairment and exploration write-off charges had a major impact. Beneath these, however, our performance remained resilient, with good cashflow and – most importantly – safe and reliable operations,” Bernard Looney chief executive officer said.
BP also announced a new dividend structure. The dividend has been reset to 5.25 cents per share per quarter (compared to 10.5 cents per share for the previous quarter) and intends to remain fixed at this level. It is the first time BP has cut its dividend since the Gulf of Mexico disaster ten years ago.
BP also introduced a new strategy alongside its results that will reshape its business as it pivots from being an international oil company focused on producing resources to an integrated energy company focused on delivering solutions for customers.
Looney explained: “BP has been an international oil company for over a century - defined by two core commodities produced by two core businesses. Now we are pivoting to become an integrated energy company - from IOC to IEC. From a company driven by the production of resources to one that that’s focused on delivering energy solutions for customers.
Within 10 years, BP said it aims to have increased its annual low carbon investment 10-fold to around $5 billion a year, building out an integrated portfolio of low carbon technologies, including renewables, bioenergy and early positions in hydrogen and CCUS. By 2030, BP aims to have developed around 50GW of net renewable generating capacity – a 20-fold increase from 2019 – and to have doubled its consumer interactions to 20 million a day.
Over the same period, BP’s oil and gas production is expected to reduce by at least one million barrels of oil equivalent a day, or 40 per cent, from 2019 levels. BP will also make no exploration in new countries.
By 2030, BP aims for emissions from its operations and those associated with the carbon in its upstream oil and gas production to be lower by 30-35 per cent and 35-40 per cent respectively.
“Energy markets are fundamentally changing, shifting towards low carbon, driven by societal expectations, technology and changes in consumer preferences. And in these transforming markets, BP can compete and create value, based on our skills, experience and relationships. We are confident that the decisions we have taken and the strategy we are setting out today are right for BP, for our shareholders, and for wider society.” Helge Lund, chairman.
Speaking after BP's Q2 earnings announcement, Luke Parker, Wood Mackenzie Vice President - Corporate Analysis, said:
"Today’s strategy update marked a big step forward, filling in many of the blanks, including detailed guidance to 2030. It leaves stakeholders with a much clearer of idea of where BP is headed over the next decade, how it will to get there and what that means for the value proposition.
"We said back in February that no company of BP’s stature had gone as far, or committed so unequivocally, to transforming itself in the face of the energy transition. The guidance that BP laid out today brings that transformation to life – makes it real. It constitutes the clearest and most detailed roadmap to Big Energy that any of the Majors have provided to this point.
"BP's oil and gas business will shrink dramatically, while the low carbon business will grow strongly.
“But if ever there was a moment to reset, this was it. Several factors have converged to make it possible: coronavirus and everything that comes with it; a strategic pivot to net-zero on the horizon; Shell’s dividend reset; a new leadership with credit in the bank. Our view is that BP has taken the prudent course of action."
Neptune Energy and its partners announced the commercial discovery of oil at the Dugong well in the Norwegian sector of the North Sea, the largest discovery in Norway so far this year.
Dugong is located 158 kilometres west of Florø, Norway, at a water depth of 330 metres, and is close to existing production facilities. The Dugong prospect consists of two reservoirs that lies at a depth between 3,250 – 3,500 metres.
The volumes are estimated to be in the range of 6.3 – 19.0 million standard cubic meters (MSm3) of recoverable oil equivalent, or 40 – 120 million barrels of oil equivalent (boe), Neptune Energy said in a statement.
Neptune Energy’s managing director in Norway, Odin Estensen, said: “This is a significant discovery and strategically important for Neptune Energy in this region. Dugong may also open up additional opportunities in the surrounding licences, with the potential for a new core area for Neptune in Norway.”
In addition, the Dugong discovery has significantly de-risked another prospect in the licence estimated by Neptune at 5.2 million standard cubic meters (MSm3) of recoverable oil equivalent, or 33 million boe. This brings Neptune’s estimate of the total resource potential in PL882 to as much as 153 million boe.
Neptune Energy’s director of Exploration & Development in Norway, Steinar Meland, said: “The discovery gives new and valuable understanding of the subsurface in this part of the Tampen area.
“We are very pleased to see that our exploration model developed together with our partners has proved to be successful. We will now initiate studies, as well as consider development options for the discovery.”
The discovery well 34/4-15 S and the down-dip sidetrack 34/4-15 A proved oil in the Viking and Brent Groups of the Dugong prospect. These are the first exploration wells in production license 882. The license was awarded in 2017 as result of the Norwegian licensing round Awards in Predefined Areas (APA).
Dugong partners: Neptune Energy (operator and 40 per cent), Concedo (20 per cent), Petrolia NOCO (20 per cent), and Idemitsu Petroleum Norge (20 per cent).
Aker Solutions has secured a five-year contract extension from ExxonMobil for the provision of engineering, procurement and construction (EPC) services for the Hebron platform, offshore Newfoundland, Canada.
The contract is an extension for a 5-year period, starting in the summer of 2020. Aker Solutions has provided EPC services to Hebron since 2015. The work will be led from Aker Solutions’ premises in St. John’s, Newfoundland and Labrador.
Aker Solutions estimates the contract value to be NOK 1.4 billion, which will be booked as order intake in the third quarter of 2020.
“We are delighted to be extending our strong relationship with ExxonMobil in Canada, and to further strengthen the international footprint of our brownfield services business,” says Linda Aase, executive vice president, brownfield projects, at Aker Solutions.
Weatherford International announced it successfully and remotely used a restricted crew to install a 16-inch liner hanger on an offshore platform in Sakhalin Island, Russia during the COVID-19 lockdown.
Remote training and monitoring procedures enabled the successful installation of the liner hanger system, cementing products and tubular running services.
The operator objectives were clear: First, install and cement a 16-inch liner and hanger at an offshore platform that was locked down as a precaution to protect against COVID-19 viral exposure. Second, provide remote guidance and technical support to ensure a trouble-free liner installation. The lockdown restricted the number of personnel aboard the platform to reduce potential contamination risks.
“The Weatherford liner team developed remote training and monitoring procedures to enable successful installation and testing of a 16-inch liner using a restricted crew that reported zero equipment malfunctions,” said Fayaz Kamalov, vice president, Russia, Weatherford. “Weatherford met all service quality and HSE standards in absolute accordance with the operator’s expectations.”
The Weatherford team provided remote guidance to ensure a trouble-free outcome for each step, including equipment rig-up, liner running, hanger installation, cementing, packer setting, pressure testing, and rig-down. The liner team prepared schematics and training videos on equipment preparation and installation for the operator to share with platform workers. As their next step, the liner team set up an office at the Weatherford Sakhalin base to provide remote, 24-hour support for the installation. They also monitored and assisted the equipment preparation and loadout before transporting it to the platform.
To assure the job went smoothly, the liner team held online conferences before each major step, from rig-up to installation, cementing and rig-down. The liner team also reviewed photos and remotely monitored equipment-preparation videos sent by the operator representative to confirm that procedures were conducted properly. From their shore base, the liner team guided the platform crew through each process to successfully set, cement and pressure-test the liner.
Total and Apache Corporation have made a significant third discovery with the Kwaskwasi-1 well, in Block 58 off the coast of Suriname.
The well was drilled by a water depth of about 1.000 meters and encountered a total of 278 meters net pay of hydrocarbons, which comprises 149 meters net in good quality Campano-Maastrichtian (composed of 63 meters of high quality oil and 86 meters of volatile oil and gas condensates reservoirs), along with 129 meters of net hydrocarbon pay in Santonian reservoirs, where further wireline logging is ongoing to confirm the quality of the fluids.
“We are very pleased to announce a third discovery in a row, following the two oil discoveries at Maka Central and Sapakara West this year,” said Kevin McLachlan, senior vice president Exploration at Total. “This very encouraging results confirm our exploration strategy in this prolific zone, which targets large volumes of resources at low development costs.”
The Kwaskwasi-1 exploration well was drilled by Apache, as operator with 50 per cent working interest, and with Total as the JV partner with 50 per cent working interest.
The next and fourth exploration well will be drilled back to back on the Keskesi prospect. Total will take over as operator of the Block after the drilling of the fourth well.
Total in a statement said that in early 2021, an appraisal campaign will be carried out to better characterise the 2020 discoveries, along with an additional exploration campaign.
Equinor has agreed to sell a 40.8 per cent interest in and transfer operatorship of the Bressay oil field development on the UK continental shelf to EnQuest.
The initial consideration is £2.2 million, payable as a carry against 50 per cent of Equinor’s net share of costs, with a contingent consideration of US$15 million following authority approval of a field development plan for Bressay.
“This transaction supports Equinor’s strategy to continually optimise our portfolio. We welcome EnQuest as the new operator of Bressay and believe the knowledge and experience both parties can share from our existing Mariner and Kraken developments will further strengthen the project,” saod Arne Gürtner, Equinor’s senior vice president for UK & Ireland offshore.
The Bressay oil field was discovered east of Shetland in 1976 and Equinor became operator in 2007. The concept selection for the field development was deferred in 2016 due to challenging market conditions and the need to simplify the development concept.
“Equinor will continue to be the U.K.’s leading energy supplier, and we are committed to delivering oil, gas, wind power and hydrogen to the country - playing our role in creating jobs, boosting investment and lowering carbon emissions. We look forward to working with EnQuest and the U.K. authorities to progress the Bressay project,” added Gürtner.
The transaction is subject to customary conditions, including partner and authority approval, with an estimated completion date in Q4 2020. Following completion, EnQuest will have an 40.8125 per cent interest and operatorship, Equinor will have 40.8125 per cent, with Chrysaor retaining a 18.375 per cent interest.
Petrofac’s Engineering and Production Services (EPS) business announced the award of a two-year contract with NEO Energy in the UK.
Under the terms of the agreement, Petrofac will provide well management and well operator support for 25 production wells across the Affleck, Balloch, Dumbarton, Flyndre and Lochranza fields. The contract also positions Petrofac to support future well construction and intervention campaigns.
As the well operator, Petrofac will be responsible for direct procurement and management of all sub-contracted services. Petrofac will also deploy its industry-leading project management software, Turus, to ensure efficient and assured project delivery.
Commenting, Nick Shorten, managing director for Petrofac Engineering and Production Services in the Western Hemisphere, said: “Through the deployment of our extensive asset and well management expertise, we will work closely with NEO Energy to assure the integrity of its wells and deliver safe and cost efficient construction in support of any future field development.
“This award builds on our existing track record for delivering Well Operator services for clients in the UKCS, bringing the size of our well portfolio in the basin to 50.”
Russia's LUKOIL concluded a deal with UK-based Cairn Energy to acquire a 40 per cent interest in RSSD (Rufisque, Sangomar and Sangomar Deep) project in the Republic of Senegal for US$400 million.
The deal is based on $300 million in cash and the potential bonus payment to Cairn Energy of up to $100 million after the commencement of production.
The blocks of the project covering 2,212 sq. km are located on the deepwater shelf of the Republic of Senegal 80 km from the shore with the sea depth of 800-2,175 meters. The blocks include two discovered fields: Sangomar and FAN.
The transaction is subject to customary conditions, including the approval by the government of the Republic of Senegal.
"Entering the project with already explored reserves at early stage of their development is fully in line with our strategy and allows us reinforcing our presence in West Africa. Joining the project with qualified international partners will allow us to gain additional experience in development of offshore fields in the region", said Vagit Alekperov, president of LUKOIL.
The Final Investment Decision (FID) on the Sangomar field was taken in the beginning of 2020 and the field development has begun. According to the Company's estimates, the recoverable hydrocarbon reserves of the Sangomar field total approximately 500 million boe. The field is planned to be launched in 2023 with designed production level of 5 million tons of crude oil per year.
The RSSD project is being implemented under a production sharing agreement. Woodside is the project's operator with 35 per cent stake. Other participants are FAR (15 per cent) and state-owned company Petrosen (10 per cent).
Indian Oil Corporation, India’s largest refiner and marketer of petroleum products, and France’s Total, announced the formation of a 50:50 joint venture (JV) company that will manufacture and market high-quality bitumen derivatives.
Total is the leading bitumen manufacturer and supplier in Europe, while Indian Oil is the largest player in the Indian bitumen market. The two companies have already an established business relationship in India, notably in LPG and fuel additives businesses.
The new JV will combine the R&D and marketing strengths of both Indian Oil and Total to manufacture and market innovative bitumen formulations and superior quality products such as polymer-modified bitumen, crumb rubber modified bitumen, bitumen emulsions and other specialty products. The JV will set up manufacturing units across the country with cost-effective logistics solutions, keeping innovation, safety and sustainability at the helm of its operations. The JV will also explore possibilities to cater to other South Asian markets.
“India is a strategic country for the future of Total and we are delighted by this partnership, yet another testimony of our commitment to this fast-growing market.” highlighted Patrick Pouyanné, Chairman and CEO of Total. “Today, Total is further cementing its longstanding business cooperation with IndianOil, into a strong and sustainable new partnership. With this agreement, we are pursuing the growth of businesses with key Indian energy players, adding to our ongoing developments in renewables, gas and power.”
Shrikant Madhav Vaidya, Chairman of IndianOil said: “The IndianOil-Total joint venture company would combine IndianOil’s credentials as India’s Flagship National Oil Company and the Total’s strength as an International Energy Major. This would cater to B2B customers involved in road infrastructure development, both in the government and private sectors and I am confident that this would start a revolution in road construction activities in the country by providing superior technology products at competitive prices”.
He added: “This joint venture company would bring in latest technologies and formulations for Polymer Modified Bitumen (PMB) and other fast-growing non-conventional derivatives such as Cold Mix & Micro Emulsion, Block Bitumen, etc. to the Indian market. The operations of this JV would commence by taking over an existing plant of Total at Jodhpur and subsequently set up new Greenfield plants”.
Eni announced that its exploration well, Ken Bau-2X, located in Block 114, Song Hong Basin, offshore Vietnam, has confirmed a significant hydrocarbon accumulation on the Ken Bau discovery, further expanding its potential.
Ken Bau 2X was drilled 2 km apart from the discovery well in 95 meters of water depth till a total depth of 3658 meters below sea level and encountered a pay in excess of 110 meters in several intervals of Miocene sandstones interbedded with shale.
Two mini drill stem tests (DST) were conducted, coupled with an extensive data acquisition campaign comprising fluid sampling. Preliminary estimates of Ken Bau accumulation provide a range between 7 and 9 trillion cubic feet (Tcf) of raw gas in place with 400 – 500 million barrels (Mbbl) of associated condensates.
Ken Bau 2X results confirm the importance of the discovery made in 2019, and Eni Vietnam’s and its partner Essar E&P efforts to swiftly appraise the full extent of the accumulation despite the significant operational challenges posed by the COVID-19 pandemic during these months.
Eni Vietnam is the Operator of Block 114 with a 50 per cent share; Essar E&P holds the remaining 50 per cent. Eni Vietnam with its partner is currently planning additional drilling and testing on Ken Bau discovery coupled with new drilling and seismic activity in the Song Hong basin, where Eni operates with a 100 per cent share the neighbouring Block 116.
Total has signed an agreement to sell the Lindsey refinery and its associated logistic assets, as well as all of the related rights and obligations, to the Prax Group.
Located in Immingham (Lincolnshire) in England, the Lindsey refinery has an annual production capacity of 5.4 million tons. This acquisition will make Prax – an independent British group specialising in the trade and sale of oil products and in possession of a growing network of 150 service stations and numerous supply chain assets – more integrated and competitive in the United Kingdom and will secure its local supply.
“This transaction is in line with our forward-looking strategy for Total’s European refining base, which involves focusing our investments on integrated refining and petrochemical platforms. Since the sale of our British retail network in 2011, the Lindsey refinery hasn’t been part of Total’s downstream system, it will be put to better use within the Prax Group; an independent player with a growing UK network. After considering several options for the future of the Lindsey site, Total chose the one that best protects local jobs,” commented Bernard Pinatel, president of Total Refining & Chemicals.
The sale should be finalised by the end of the year, once the conditions of the sale have been satisfied.
Neptune Energy announced the successful installation of subsea oil and gas production flowlines and gas lift flowlines for its Duva & Gjøa P1 developments in the Norwegian sector of the North Sea.
Neptune and its partners accelerated key elements of the development schedule of the subsea tiebacks, which will connect two templates to the nearby Neptune-operated Gjøa platform, with Gjøa P1 in particular on track to achieve first oil two months ahead of the original plan.
The milestones were reached just one year after the development plans for the Duva (PL636) and Gjøa P1 (PL153) projects were approved by the Norwegian authorities.
Neptune’s Head of the Subsea Gjøa Project, Crawford Brown said: “Despite challenges caused by the COVID-19 pandemic, the subsea execution schedule for Duva & Gjøa P1 has been accelerated in comparison with our original plans.
“Developing these two live projects in parallel provides greater flexibility and allows Neptune and its partners to increase efficiency and reduce costs. We have taken a campaign approach in our use of vessels and common equipment, achieving positive synergies through joint mobilisation and focusing on collaboration between project teams for Neptune and our key contractors and partners.
“The Norwegian sector is an immensely important part of Neptune’s geographically-diverse and gas weighted portfolio and the development of these tiebacks will increase production and extend the production life of our operated Gjøa platform.”
Final fabrication of the tie-in spools for the development projects is ongoing at TechnipFMC’s spoolbase in Evanton, UK. The manufacture of both Duva and Gjøa P1 subsea manifolds is nearing completion, and full system integration testing is underway.
The subsea manifolds are scheduled for installation later this year, followed by the associated tie-in operations. Development drilling on both Gjøa P1 and Duva will continue up to the end of February next year, while key topside work on the Gjøa platform will be carried out consecutively.
Neptune said it anticipates first production from Gjøa P1 later this year, with first production from Duva anticipated in the third quarter of 2021.
Golar Power, a joint venture between Golar LNG and Stonepeak Infrastructure Partners, signed a MoU with Norsk Hydro to develop the first LNG terminal in the North of Brazil, a major step towards one of the largest greenhouse gas reduction initiatives, globally.
The project will enable the supply of LNG to Norsk Hydro’s Alunorte refinery plant located close to the Vila do Conde Port in the Municipality of Barcarena, State of Pará, Brazil. Alunorte will also be the first operational customer for the Barcarena FSRU that Golar Power plans to bring into operation during the first half of 2022. Concluding final agreements with Norsk Hydro will therefore be an important step toward a Final Investment Decision within the next 4 to 6 months.
The LNG terminal aims to supply gas to Alunorte and also to the Centrais Elétricas Barcarena 605 MW thermal power plant, which is a subsidiary of Golar Power, previously contracted under a 25-year PPA. Once the terminal becomes operational, Golar Power also expects to operate a comprehensive LNG distribution network across the state of Pará and the region. This LNG supply chain will cover an area larger than Eastern Europe and consist of thousands of kilometres of river and road transportation systems, serving numerous industrial, commercial, and transportation customers.
The project will fulfil Norsk Hydro’s 2017 commitment to the Pará state government to pursue a natural gas-based energy solution for one of the world’s largest aluminium plants.
CEO of Golar Power, Eduardo Antonello, commented: “We are delighted to be helping Norsk Hydro achieve its ambitious global sustainability goal of reducing CO2 emissions by 30 per cent by 2030, and at the same time contributing to a significant reduction in energy prices and environmental emissions within the entire North Region of Brazil. The project should have the potential to significantly reduce energy costs, support environmentally responsible and sustainable industrial growth throughout this immense region, and facilitate the unlocking of its unique natural resource endowment and economic potential. Golar Power estimates a potential for replacing approximately 1.8 million tons of LNG equivalents per annum of LPG, diesel, fuel oil, and coal with the terminal – creating the foundation for a broader transition away from carbon-intensive energy sources in the region.”
Weatherford International announced it has been awarded an exclusive two-year, US$15 million contract with a major independent operator in Argentina.
Weatherford will provide 146 surface pumping units, including the Maximizer II surface pumping unit and the Rotaflex 2.0 long-stroke pumping unit. Both will be deployed in critical and challenging mature fields in Golfo San Jorge Basin to improve the operator’s production efficiency and performance.
“This award is the result of years of experience and collaboration with the operator in Argentina,” said Franklin Cueto, vice president, Artificial Lift Systems, Weatherford. “Tough market conditions demand a stronger focus on efficient, optimised production, and that is what we commit to deliver. This contract is a statement that Weatherford continues to deliver the industry’s highest level of continuous, dependable, and cost-effective performance for life-of-well durability.”
Eni, through its subsidiary Eni New Energy, operating under the new business unit Energy Evolution, has started power production from the new photovoltaic plant in Volpiano, Italy with a total capacity of 18 MW.
The project was developed inside Eni’s Fuel Depot in Volpiano and is part of the “Progetto Italia”. This scheme, launched in 2016, redevelops brownfield sites that are part of Eni’s industrial assets into renewable energy plants, creating new opportunities in the district.
The authorisation procedure, in which the town of Volpiano and the local authorities played a proactive role, ended in 2019 when the Metropolitan City of Turin granted the Single Authorisation.
The plant, built on an industrial area of approximately 32 hectares, will generate over 27 GWh, 10 per cent of which will supply energy to Eni’s site, reducing the use of electricity from the national grid by more than 50 per cent. The remaining energy will be supplied to the market, without benefiting from incentive mechanisms.
In addition, this initiative will prevent the emission of around 370,000 tonnes of CO2 over the service life of the plant, therefore contributing to the decarbonisation goals of Italy’s Integrated National Plan for Energy and Climate.
Eni’s strategy in the renewable energy sector aims at reaching a balanced and diversified global portfolio of over 3 GW of installed wind and solar power by 2023 and of 5 GW by 2025.
Italy’s Saipem has been awarded new offshore wind contracts, for projects currently under development off the coasts of England, Scotland and France, worth a combined €90 million ($103.8 million).
Dogger Bank Offshore Wind Farms, a joint venture between Equinor and SSE Renewables, has awarded a contract to Saipem for the transportation and installation of two offshore HVDC (High Voltage Direct Current) platforms for the first two phases of the Dogger Bank project: Dogger Bank A and Dogger Bank B. Both platforms will have a capacity of 1.2 GW and will consist of a ca. 2,900-ton jacket and a ca. 8,500-ton topside. Dogger Bank will be the world’s biggest offshore wind farm when completed and is located over 130km off the North East coast of England. The project is the first to use HVDC technology in the UK’s offshore wind market.
Saipem has also been awarded an installation contract by Seaway 7 related to the Seagreen Offshore Wind Farm, a 1,075MW joint venture project between SSE Renewables (49 per cent) and Total (51 per cent) off the East coast of Scotland. The scope of work entails the installation of 114 foundations for an equivalent number of wind turbines.
Lastly, Saipem has been awarded a contract for the transportation and installation of the jacket and topside of the offshore substation at St-Brieuc offshore wind farm, located in Brittany, France, which is being developed by Ailes Marines, part of the Iberdrola group. All project management and engineering activities shall be executed by Saipem SA, Saipem’s French subsidiary established in Paris.
These offshore installation projects will be carried out by the crane vessel Saipem 7000.
Francesco Racheli, chief operating officer of Saipem’s E&C Offshore Division, commented: “These new contracts confirm Saipem’s participation in the most relevant offshore windfarm developments and are the tangible results of a strategy which has led us to become a global reference player in energy transition. This significant achievement has been attained by leveraging on our capabilities, our technological flexibility and our distinctive assets”.
Atkins, a member of the SNC-Lavalin Group, announced it has been awarded pre-front-end engineering design (pre-FEED) services for hull and mooring engineering for a floating production unit (FPU) in the Gulf of Mexico.
The FPU will be installed in a water depth of approximately 8,200 feet (2,500 meters) and located approximately 30 kilometers south of the U.S./Mexico border and approximately 180 kilometers from the Mexican coastline.
SNC-Lavalin’s Atkins and Houston Offshore Engineering businesses will provide the pre-FEED services for the hull and mooring engineering of the FPU.
Simon Naylor, senior vice-president, Engineering & Consulting, Resources, SNC-Lavalin, said: “This contract win confirms our class-leading hull and floating offshore expertise. We have extensive experience with this type of engineering design service in the Gulf of Mexico, as well as globally. We are pleased to deliver these services and innovative solutions.”