The Egyptian Ministry of Petroleum and Schlumberger have announced the launch of the Egypt Upstream Gateway, an innovative national project for the digitalisation of subsurface information and enable global access to the country's subsurface data. This unique digital initiative will be used to unlock the potential of Egypt's petroleum sector and promote the country for international investment in exploration and production projects.
“Egypt is in the process of launching the Egypt Upstream Gateway, a digital subsurface platform that will act as an up-to-date repository of the country’s subsurface data,” commented H.E. Tarek El-Molla, Minister of Petroleum and Mineral Resources for Egypt. “The Egypt Upstream Gateway will digitally promote Egypt’s oil and gas bid rounds through seamless online access to the sector’s data, as well as endorsing our exploration potential worldwide, it is a defining milestone in the country’s oil and gas digital transformation.”
The Egypt Upstream Gateway provides digital access to over 100 years' worth of accumulated national onshore and offshore seismic, non-seismic, well-log, production, and additional subsurface data under a single platform. This data, which empowers de-risked decisions through the ability to explore multiple basins and evergreen data, can be accessed virtually from anywhere using the platform’s online portal. In addition, the Egypt Upstream Gateway will host Egypt's upcoming bid round highlighting lease availability information to national and international investors.
Rajeev Sonthalia, President of Digital & Integration at Schlumberger, said, "The Egypt Upstream Gateway is the embodiment of the Egyptian Ministry of Petroleum's vision, leveraging digitisation to modernise the country's petroleum sector. With the launch of this industry-first platform, the Egyptian Ministry of Petroleum and its affiliates—EGPC, EGAS, GANOPE—can digitally showcase national assets to investors worldwide, in addition to leveraging the latest digital technology and solutions to accelerate discovery throughout the country."
Digitalisation has become a key issue for the offshore oil and gas industry (and indeed the entire energy sector). The importance of getting a firm grip on data and having the capacity to effectively use this is paramount and can lead to tangible benefits in areas such as production efficiency and lifetime of assets. This is clearly understood by the Egyptian Ministry of Petroleum with this announcement that marks a real sign of intent to get ahead of the curve. It is also noteworthy that the data will be opened up for international consideration with discussions on data sharing and partnerships around this intensifying in recent months.
On the last day of the Upstream Digital Transformation Conference (UDT) EU 2021, Stuart Broadley, CEO of the IEC, outlined that as a result of one of the most tumultuous years in living memory, combined with the growing pressure to decarbonise, there is a plethora of unanswered questions surrounding the energy industry, most especially focused on the need to digitalise and form partnerships to do so.
The need for partnerships
Focusing on the North Sea, Stephen Ashley, Digital Solutions Centre Manager at
OGTC, discussed his company’s dream to eliminate emissions from existing facilities and unleash the full potential an integrated energy system could yield. He commented, “Partnerships are absolutely key to transforming the North Sea for this. The last few months companies have set out net zero strategies, regulators have set out visions – the scene is set but we need action. We need rapid and focused investment to close some technology gaps that exist, such as how to develop a fully offshore power grid or around the production and use of blue and green hydrogen. The key thing is that no single company can do it alone. Partnerships will be required to deliver on these technology challenges.”
Stephanie Díaz, Digital Industry Analyst at BloombergNEF, suggested she had noticed some positive signs from the sector, she said, “We have seen the oil industry move toward digitalisation to reduce costs, extend the lifetime of assets and reduce uncertainty. The sector as a whole has loads of data particularly in exploration just from seismic surveys. The challenge that remains is using this, whether for data management, integration across upstream workflows or advanced analytics. As companies have tried to grapple with this they have moved more towards partnerships than collaborations on the assumption that no one wants to solve the same problem five times.”
However Díaz noted that it can be difficult for IOCs to take the plunge and commit to digitalisation and partnerships as, while this can clearly enhance workflows, it is not necessarily directly revenue generating. Díaz added, “We are still in the early stages of figuring out how the oil energy industry incentivises itself to partner on some of less exciting but very necessary stuff; data management is one of those ‘eat your vegetables’ types of initiatives - you have to do it. Some of that might mean working more with start ups or technology firms who have more experience in this. We have seen, for example, some companies partner with theBlueai, a start-up specifically for developing a file system for seismic data so that it can be processed faster than the cloud. This is something an oil company could not do by itself as it does not have the technological background but a start up could do it, and oil companies could bring their technical expertise with subsurface data to make sure it is useful. Finding a partner is about identifying your strings and recognising where it makes sense to partner with someone else for the strings that they bring.”
Digital Platforms
Benjamin Sokolowski, Internal Transformation Specialist at Wintershall Dea, drew attention to the extraordinary potential of the Open Subsurface Data Universe (OSDU), he commented, “The OSDU is essentially an open data storage lake hub where every subsurface data you produce can be put in there, then with machine learning utilisation you can reap the benefit of this data. The future will be on such platforms like this - not just having this an open data platform to give access to partners. There is no need to rebuild the data warehouses that each company owns but its having this externally with a full set of OPIs with a community around it. With this we can provide solutions even if not big part more open sources, this would make a big impact in the future.”
Explaining this further, Ashley said, “Open platforms (such as the OSDU) enable that platform for collaboration to happen and present an opportunity to build an ecosystem around data so multiple companies can solve problems with the same sets of data. A lot of work we do is to answer how to create not only the tech but also the legal controls that get over the philosophical challenge to let go of your own data, as you will often find the immediate industry response is to hold onto your own data.”
Díaz also added, “One of the things that will drive the adoption of big digital platforms is the increased pressure to move to net zero. Companies are moving away from frontier exploration which will mean they will have to rely on data from existing oil fields to determine what more they can get out of existing assets. This will be a drive towards more unified platforms to use across the entire upstream value chain.”
Digitalisation and partnerships in the future
Concluding the session, Broadley invited each participant to envision the sector one year from now and the progress in partnerships and digitalisation that will be made.
Ashley commented, “What we will see is more pressure on majors to demonstrate they are taking action, we are already beginning to see that and it coming to fruition with BP, for example beginning to invest heavily in CCS and wind. I think we will see more partnerships coming to fruition. On data specifically, there are some key areas where people are being psychologically challenged to share data. The regulators have a key role here to support and insist they should be sharing data. Areas where progress might be made is in robotics and autonomous systems in scale, how we do P&A and how can we get this done quickly. Sharing data will be key for these and the tech to support how that data will be pooled also.”
Providing her final thoughts, Díaz, said, “A year from now, I see some of the European IOCs make more progress in terms of tying digitalisation and decarbonisation together. Already we have seen some of this with BP and Shell (separately) announcing deals with Microsoft focusing on tying these two together. BP and Shell will provide renewable energy for Microsoft and Microsoft will supply its cloud analytics to the oil companies. I think we will see more of those types of partnerships. But it remains to be seen how successful they will be.”
Sokolowski finished the session by commenting, “I think one year from now we will be exactly were need to be to kick off decarbonisation from the digital area. But already I have heard many parts of organisations are still anaolog and still rolling with new ways of working. We really have to prepare organisations to really kick off such topics, which is more important than just optimising.”
As Stuart alluded to, a year is not a long time but it feels like there is a lot that will happen, and it will be interesting to see where the industry does end up, especially with COP 26 in November in which many are expecting a global carbon pricing rate to be set. Additionally, while IOCs begin moving into the broader energy sector it does appear they are open for collaboration and partnerships presently, but when they become more established, have a broader knowledge base and have more of the technology in-house this could turn more cut-throat which could result in the partnerships drying up once again.
Deep Casing Tools (DCT), a technology development company for the global energy sector, has secured investment of UK£1.6mn from EV Private Equity and Scottish Enterprise enabling the company to develop and commercialise new innovations that will transform operations across well completion, well construction, well abandonment and slot recovery. In a bid to capitalise on this, the company has made a series of senior appointments and created a new role in its global team.
David Charles
Armed with extensive well and extended reach drilling (ERD) knowledge, derived from 34 years working in the energy sector, David Charles has been appointed as Well Engineer and has been identified as instrumental in helping DCT’s customers maximise return on investment. Prior to joining DCT, David was an ERD Drilling Engineer with ADNOC, delivering ERD wells on a world class projects before becoming a self-employed ERD well specialist consultant. The creation of David’s Well Engineer role demonstrates DCT’s dedication to project performance, with his involvement enabling the expert design, construction and maintenance of wells. Collaborating with well teams onsite, David will lead technical delivery to ensure optimal emissions savings, time savings and cost efficiencies.
Edward Kerr
Edward Kerr joins DCT as Global Sales Manager from Ardyne Technologies where he held the role of regional Vice President, leading Middle East and Asia Pacific operations and global business development activities. At DCT, Edward will focus on driving tool sales, including the firm’s well established TurboCaser and TurboRunner. He will lead business development activities across target international regions, which will increase awareness of the economic and environmental efficiency gains DCT’s suite of well life cycle tools can deliver to major operators.
Compared to conventional technologies, DCT’s TurboCaser and TurboRunner tools are 75% quicker by ensuring casings and completions reach target depth on the first attempt, saving around three days in even the most complex wells. In a typical offshore well, this time saving translates to a saving of around US$600,000. Edward will also introduce new innovations to global markets, such as the highly anticipated Casing Cement Breaker and recently patented MechLOK Drill Pipe Swivel, enabling industry to revolutionise well operations.
Kevin Robertson
Completing the set is Kevin Robertson, who has been appointed Middle East Regional Manager. Having acquired over 20 years’ industry experience, specifically within tubulars, drilling and completions, Kevin Robertson will focus on DCT’s strong presence in the Middle East, which has been a key market for the firm for over a decade. He will further develop current relationships in the region with partners and the world’s largest operators, and identify new opportunities for revenue growth.
Speaking on his appointment, Robertson said, “As a small but global independent company, Deep Casing Tools is very agile and allows its employees to have a creative say in the business, letting all voices be heard. I was excited by its fantastic portfolio of innovative tools that are helping industry achieve remarkable efficiencies and overcome the complex well challenges that drilling teams face today.”
Commenting on the new additions to DCT, David Stephenson, CEO of DCT, said, “We’re pleased to welcome Edward, Kevin and David to the Deep Casing Tools team, their expertise and experience adding a new dimension to our global offering. I am certain they will prove invaluable to client operations and projects, and will play a crucial role in our ambitious growth strategy for 2021 and beyond. Strengthening the expertise and experience within our team, coupled with the recent investment from EV Private Equity and Scottish Enterprise, will ensure we meet growing industry demand for our technologies, helping our customers optimise performance, increase efficiency and ultimately, reduce carbon footprint.”
Wärtsilä has revealed that in December 2020 it signed five year Optimised Maintenance agreement for two offshore well intervention vessels owned by Siem Offshore. Under the agreement Wärtsilä will provide real-time monitoring and support, using the latest digital technology, to reduce the fuel consumption and emissions of two well intervention vessels (the Siem Helix 1 and the Siem Helix 2) operating in Brazil’s offshore oil fields. The agreement also covers the selective catalytic reduction (SCR) emissions-abatement systems installed with the engines.
Wärtsilä will supply its Expert Insight predictive maintenance solution for use on the two vessels, an innovative service that leverage artificial intelligence (AI) and advanced diagnostics to monitor equipment and systems in real time, spot anomalies, foresee potential problems and enable rapid reaction. Also included is Wärtsilä’s Date Driven Maintenance concept which will enable the ship’s crew to conduct condition inspections using borescope optical instruments. These images can then be sent to Wärtsilä’s technical experts for evaluation, and in most cases will lengthen the time required between engine overhauls.
Finally, Wärtsilä will provide the vessels with the Lloyd class-approved connectivity solution with enhanced cyber security - an enabler for onshore digital tools providing cloud based services such as remote monitoring, remote optimisation and support.
Henrik Wilhelms, Director of Agreement Sales at Wärtsilä Marine Power, commented, “Lifecycle support is a key element of our strategy, and our advanced digital and data-based maintenance solutions are central to enabling optimal operational performance. The benefit of being able to efficiently monitor the equipment and support customers remotely is enhanced even more today, since due to Corona-related travel restrictions, in-person visits by service engineers can be difficult to arrange. Since our engineers need to travel less, their carbon footprint is reduced, while at the same time we can optimise the performance of the asset, so it is really a double win.”
Full steam ahead in 2021
Presently, Wärtsilä’s is enjoying a spell in the sun as services are in high demand. So far, in February alone, the company has also revealed agreements to provide Western Pacific Marine Ltd with the advanced hybrid solution for the new Ro-Ro ferry; to supply Norwegian based Solvang with digital Operational Performance Improvement & Monitoring (OPERIM) solution to support the operational efficiency of its fleet; to equip new under construction Isle of Man ferry with a range of comprehensive solutions; and sealed a strategic partnership with SAACKE, to strengthen the companies’ ability to offer a comprehensive range of leading technology solutions to shipyards and ship owners. While in their 2020 annual report Wärtsilä may have reported a contraction in financial performance, it appears they are full steam ahead to reconcile this lost ground in 2021.
Panoro Energy ASA has announced that it has entered into agreements with Tullow Oil plc and its subsidiaries to acquire high-quality oil producing assets offshore Equatorial Guinea and Gabon for an initial aggregate cash consideration of up to US$140mn and aggregate contingent consideration of up to US$40mn, based on an effective date of 1 July 2020.
The assets in detail
The acquisitions represents a 14.25% working interest in Block G offshore Equatorial Guinea and a 10% working interest in Dussafu Marin Permit offshore Gabon. Panoro will therefore increase its net interest in its core asset Dussafu from 7.5% to 17.5% and achieves significant diversification through the entry into Block G, offshore Equatorial Guinea, which comprises six producing offshore fields through the Ceiba and Okume Complex assets.
The assets have excellent operators, low operating costs and have a reserve life of an estimated 13 years. They will add an estimated 6,900bpd net production, 25mnbbl net 2P reserves and hold a significant upside potential with 2C resources of 29mnbbl. The acquisitions will be financed through a contemplated US$70mn equity private placement and an up to US$90mn underwritten debt facility by a company within the Trafigura group.
John Hamilton, CEO of Panoro, commented, “These truly transformational acquisitions will establish Panoro as one of the world’s leading independent E&P companies focussed on Africa. We are purchasing high-quality, low operating cost assets, substantial production and material reserves in West Africa. These are highly accretive assets that deliver a major change in our operational and financial profile, and position the company well to generate sustainable long-term value for our shareholders.”
“We welcome the opportunity to increase our exposure in Dussafu, offshore Gabon, where Panoro has been an integral part of its success since 2007. In Equatorial Guinea we are new entrants and look forward to excellent cooperation and working with the field partners and the Ministry of Mines and Hydrocarbons to grow further in the country. We look forward to realising the significant upside potential that we see in these assets through an active and fully funded work programme,” Hamilton added.
Panoro's increasing presence in West Africa
With these acquisitions Panoro will hold assets in Gabon, Equatorial Guinea, Tunisia, Nigeria (prior to completion of the sale of its interests in Aje to PetroNor) and South Africa and will quadruple its 2021e production and triple its 2P reserves. This marks another step for Panoro as it seeks to establish itself as one of the leading independent E&P companies focussed on Africa.
Julien Balkany, Chairman of Panoro said, "These two very attractive and highly value accretive acquisitions perfectly complement our existing upstream E&P portfolio in West Africa and represent a major step in the execution of Panoro’s ambitious growth strategy to continue building a balanced full-cycle E&P company focused on Africa. We are proud and excited to strengthen our position in Gabon and to enter Equatorial Guinea and intend to deliver strong returns for all the stakeholders involved."
For more than 25 years Grant Pierce has worked for onshore and offshore service and oil and gas operations across the globe, accruing an extensive knowledge base in this time. He sat down with Offshore Network to divulge his insights on the offshore oil and gas industry in the aftermath of the Covid-19 pandemic, what the associated media is failing to cover, and which regions could potentially be hotbeds for well intervention operations in the future.
You have been vocal about media outlets lacking in terms of future well intervention and plugging and abandonment (P&A) work. Could you elaborate on this?
Pierce: “I do not think there has ever been a large focus on upcoming work that is happening unless it is a big contract win - that is when you will hear about work being publicised. But you never really see publications on campaigns coming up until they are done, then you might hear about three or four extra jobs that service companies have done - they normally come out in a group.”
“You might hear a job about Helix and a client in the Gulf of Mexico and then you may hear something about C-innovation in the same region a few weeks later but it has never really been consistent. Of course these days the focus has been more on clean tech and politics; that is what is in the media these days as that is what generates numbers.”
It does seem that P&A work is somewhat avoided by the industry, but with green targets and sustainability increasingly on the agenda do you think we will see more P&A work in the future?
Pierce: “Absolutely there will be more work pushed forward. They were talking about it during the OWI Australia conference on 9 February. Government regulators are pushing this work to be done. Definitely in Australia NOPSEMA had given deadlines and were reducing them. That is the kind of thing that is happening – this work is being pushed forward rather than back by the government and regulators are saying we have to get this done now. For sure P&A is being focused on globally right now and will feature more in the future.”
Do you have any suggestions to increase P&A efficiency to get more of this work done in the future?
Pierce: “Really just sharing from other areas in the industry. Taking lessons from the UK and applying into them Africa, or from Africa into Australia. Of course the same model cannot work everywhere; we work differently in different countries and regions. The regulations are more stringent in some places, for example, and so it is difficult to apply the same cookie cutter model everywhere.”
“One other method is collaboration to share vessels. They are speaking about it now in more areas, but it has recently become more normal in Africa to bring in a well intervention vessel and share it between operators. By doing this one operator is not taking all the cost - they have a schedule where they work for one operator and then they will move onto another, sharing the cost of the vessel. This keeps the vessel working in the country rather than having a huge cost to come in, then huge cost to go back home, then the vessel remaining idle for two months and then going back out to the same area for a different client.”
Looking to the future, are there any regions we should be keeping our eye on over the next few years for development or P&A work?
Pierce: “The problem with new frontier places is sometimes costs can be prohibitive and so the company wouldn’t make a lot of money on long term investments. Because of this there are fewer frontier areas left. However, there is some focus on some places in Africa, such as Senegal, some regions like Guyana and Suriname and even around the Bahamas and South America are gaining interest. Brazil is probably the next cost-efficient area to do work in so there will probably be more development there – I expect that area to pick up.”
“In terms of P&A, there is work everywhere. It is really huge in Thailand and Malaysia with a lot of hydraulic workover units doing loads of P&A work and this is ongoing all the time. There are new units and new work over units constantly being built to do that work. Additionally, Australia is ramping up in a serious way and I would also highlight P&A work in Mauritania, Angola, Nigeria, Ghana, and in the Gulf of Mexico.”
Daniel Yergin has suggested that the term energy transition is used a lot without it being properly understood and said ‘you can’t just change the system overnight’. Do you have any thoughts on this and what it means for the future of offshore oil and gas?
Pierce: “I am in full agreement. What fossil fuels can do is astounding. For instance, they assist every other technology that we can imagine with more than 6,000 products made from by-products of petroleum. It is very hard to think that we can just un-marry from fossil fuels. The use will start going down with people becoming more attuned to using alternative energy technologies, but I don’t think there will be a complete transition within the next thirty years.”
“A lot of energy companies are responding to government initiatives and saying ‘Okay if you say we cannot do it we will distance ourselves’ but they are still buying up acreage in South Africa and Suriname. It still goes on; it can’t just go away tomorrow. It is something that will have to be worked on over the next fifty years.”
“The key is to reduce emissions produced by the industry and work in a more sustainable way such as reducing the amount of equipment that is being moved around. But we cannot stop development. If we shut things off tomorrow we would be where we were one hundred years ago.”
You are very passionate about the well being of offshore workers, which has been at risk due to the pandemic with people having longer stays offshore. What is the best way to treat this problem and ensure employees are protected?
Pierce: “More collaboration and sharing ideas and ways of doing business between service companies, operators and any contractors involved is needed to prevent people being stuck for long periods of time. I know that regionally, the upper management at Petronas seem to have done a good job at managing their bridging documents ahead of time and changing those documents to accommodate the situation. They worked together with their partners to better utilise the time and people in a more efficient way to minimise negative effects. They were definitely a company that stayed on top of their business and kept their people moving despite it being very difficult to get employees around with all the quarantine restrictions in Malaysia. They were a very good example in this regard.”
“I know as well that in Australia even though they have tight control orders (a person cannot move between states without major procedures) they have done a good job there, with Cooper Energy for example still managing to facilitate work in the region.”
Maersk Drilling has secured a contract from Korea National Oil Corporation (KNOC) for the drillship Maersk Viking to drill one exploration well in Block 6-1 offshore the Republic of Korea. The contract is expected to commence in June 2021, in direct continuation of the rig’s previous work scope, with an estimated duration of 45 days. The contract value is approximately US$14.5mn, which includes mobilisation and demobilisation fees.
Morten Kelstrup, Chief Operating Officer of Maersk Drilling commented, “We are pleased to be awarded this contract with a new customer in the form of KNOC for their first-ever drillship operation and are confident in our ability to quickly start up operations in Korean jurisdiction after Maersk Viking moves on from its previous job. The rig and its crew have shown an impressive ability to always deliver safe and efficient operations, even during this challenging period marked by a global pandemic.”
Maersk Viking
Maersk Viking is a high-spec ultra-deepwater drillship vessel which has a maximum drilling depth of 12,000m and a maximum water depth of 3,657m. It boasts a variety of features such as a 3.5t pipe handling knuckle boom crane; five National 14-P-2200, 7500psi HP single-acting triplex mud pumps; the TDX 1250 system rated for 7500 psi and 2680 hp; and accommodation to allow for up to 230 personnel on board.
Delivered in 2013, the Maersk Viking has a wealth of experience after conducting jobs for ExxonMobil, Aker Energy, AGM and POSCO in a variety of different regions such as the Gulf of Mexico, Ghana and Myanmar. Currently, the vessel is mobilising for a campaign in Brunei Darussalam after Brunei Shell Petroleum Company exercised the option to add exploration drilling work. This will see the vessel start work in May 2021 for an estimated duration of 35 days continuing on from the rig’s previously agreed work scope. The contract value extension of these operations is approximately US7.1mn.
Maersk in 2021
The KNOC contract is the latest of a number of those received by Maersk Drilling in 2021 with the company most notably also securing a two-well contract for the low emission rig Maersk Integrator with Aker BP in the North Sea; an agreement for the deepwater rigs Maersk Valiant and Maersk Developer for exploration and appraisal projects offshore Suriname with Total E&P Suriname; and deploying Maersk Resolve to drill a new well for Spirit Energy in the North Sea.
EnQuest PLC, an independent oil and gas production and development company, together with its subsidiaries has signed an agreement with Suncor Energy UK Limited to purchase Suncor’s entire 26.69% non-operated equity interest in the Golden Eagle area, comprising the producing Golden Eagle, Peregrine and Solitaire fields.
A prized asset
The acquisition is expected to add an immediate incremental production of c.10,000mboepb, c.18mnbl to net 2P reserves and c.5mnbl to net 2C resources. The field life is expected to extend into the 2030’s and with an ongoing four-well infill drilling programme, as well as a host of unsanctioned activities associated with further drilling and various third-party near-field tie-back opportunities being assessed, there is huge potential for this field still remaining.
The assets also boast a strong safety record with zero lost time injuries since its start up and zero safety critical maintenance backlog at the end of 2020. With a CO2e emissions intensity ratio lower than the UK North Sea industry average, it is no surprise that EnQuest are elated with the deal.
Amjad Bseisu, Chief Executive at EnQuest, commented, “We are delighted we have agreed the acquisition of a material interest in Golden Eagle, a high-quality, low-cost UK North Sea development. Upon completion, this acquisition will add immediate material production and cash flow to EnQuest and will allow us to accelerate use of our substantial tax losses. It also demonstrates our continued commitment to the UK North Sea and diversifies our existing production base. We look forward to a productive partnership with the operator, CNOOC and our future joint venture partners, NEO Energy and ONE DYAS,” Bseisu added.
EnQuest will acquire all of the shares in North Sea Resources Ltd, a company which will hold Suncor’s non-operated equity interest in the Golden Eagle area. The initial consideration has been set at US$325mn with an additional contingent consideration of up to US$50mn. This will be financed through a combination of a new secured debt facility (the group is currently working closely with its leading banks BNP and DNB), interim period post-tax cash flows and an equity raise.
An auspicious period for EnQuest
The acquisition comes off the back of the company recording a good performance in 2020 despite Covid-19 which saw the company reduce net debt to US$1.28bn (from US$1.413bn in 2019) and hold an Average Group production rate of 59,115boepd.
Bseisu said, “During 2020, our operations remained materially unaffected by the COVID-19 pandemic and the Group delivered in line with its production guidance, with a particularly strong performance at Kraken. Our focus on cost control and capital discipline, combined with an improving oil price environment, saw the Group deliver free cash flow breakeven of c.US$32/Boe and generate free cash flow of c.US$210mn.”
“We transformed our business in 2020, significantly lowering our operating costs and re-focusing the portfolio on the highest value assets. As such, I am confident we are well placed to succeed in a changing world.”
Equinor and partners DNO Norge, Petoro and Wellesley Petroleum have struck gas and oil in production licence 923. Recoverable resources are estimated at between 7-11mn cu m of oil equivalent, corresponding to 44 – 69mnboe.
“The discovery is a direct consequence of thorough subsurface work in the Troll/Fram area over many years, and shows the importance of not giving up, but starting over, looking at old issues from new angles. Exploration thus creates great values for society, at the same time as the resources can be realised in accordance with the requirements for CO2 emissions through the value chain, from discovery to consumption,” commented Nick Ashton, Senior Vice President for Exploration in Norway at Equinor.
The discovery details
Exploration well 31/1-2 S and appraisal well 31/1-2 A in production licence 923 were drilled some 10km northwest of the Troll field, 18km southwest of the Fram field and 130km northwest of Bergen.
The primary exploration target for exploration well 31/1-2 S was to prove petroleum in the Brent group from the Middle Jurassic period and in the Cook formation from the Early Jurassic period. The purpose of 31/1-2 A was to delineate the discovery made in the Brent Group in well 31/1-2 S.
Both wells proved hydrocarbons in two intervals in the Brent Group. Well 31/1-2 S encountered a c.145m gas column in the Brent Group (Etive and Oseberg formations) and a 24m oil column where the oil/water contact was not encountered. A total of 50m of effective sandstone reservoir with good reservoir quality was found in this interval. In addition 6m of oil-bearing sandstone with moderate to poor reservoir quality was struck in the upper part of the Dunlin Group.
Appraisal well 31/1-2 A struck sandstones with good to moderate reservoir quality in the Etive formation and upper part of the Oseberg formation. The lower part of the Oseberg formation contained sandstone with moderate to poor reservoir quality. An estimated total of 41m of effective sandstone reservoir was found in the two formations. The well proved 12m of oil in the Etive formation, where the oil/water contact was not encountered, and a 17m oil column in the Oseberg formation.
The Cook formation proved to be water-filled in both wells, but with moderate to good reservoir quality. The wells were not formation tested, but extensive data acquisition and sampling took place.
Well 31/1-2 S was drilled to a vertical depth of 3439.5m below sea level and a measured depth of 3555m. The well was terminated in the Amundsen formation from the Early Jurassic period. Well 31/1-2 A was drilled to a vertical dept of 3452m below sea level and a measured depth of 3876m. The well was terminated in the Cook formation.
The licensees consider the discovery commercial, and will explore development solutions towards existing infrastructure.
Previous discoveries in the region
The Røver North discovery adds to a number of discoveries in the Troll/Fram area in recent years such as Echino, in the autumn of 2019, and Swisher in the summer of 2020. Recoverable oil equivalent from these three discoveries can already measure against the total production from fields like Valemon, Gudrun and Gina Krog.
“It is inspiring to see how creativity, perseverance and new digital tools result in discoveries that form the basis for important value creation, future activity and production in accordance with Equinor’s climate ambitions,” said Ashton.
Baker Hughes has committed to reducing its carbon emissions by 50% by 2030 and achieving complete net-zero status by 2050 and, in pursuit of these objectives, engineers from the company have been developing innovative solutions with perhaps the most complex of these centred around subsea technology and carbon capture and storage (CCS).
At the Baker Hughes Annual Meeting 2021, which took place virtually on 1-2 February, Julian Tucker, front end regional lead for Europe, Middle East and Africa at Baker Hughes, provided an in-depth presentation on CCS and explored the company’s projects around this technology.
Tucker explained, “CCS is a process where CO2 is captured from various sources and injected into a suitable store rather than being released into the atmosphere. One application of this technology is to capture CO2 from industrial emitters, transport it offshore via pipeline or vessels and then inject it into depleted oil and gas reservoirs or even saline aquifers. These offshore locations are ideal candidates for C02 stores given their proven capability in trapping fluids underground, as well as the fact that they live in mature basins such as the North Sea which have been comprehensively explored and appraised.”
The injection process
Focusing on the injection system, Tucker outlined three key considerations that must be taken into account when developing technology for this; phase behaviour of CO2 and the impact of this can have; corrosive potential of CO2; and considerations of long step out distances to some of these offshore locations.
Tucker commented, “CO2 is most efficient when transported in a dense phase, so is condensed and pressurised and can be in a supercritical state. This has several implications for materials selection, including solubility effects and fracture toughness. There is also the potential for low temperatures in the system which can occur if expansion drops due to pressure. This effect can be significant, especially when associated with a change of phase. The system therefore needs to be designed to manage these changes and the materials need to be properly selected and tested for these conditions.”
“CO2 is also highly corrosive to steel when water is present, and this will ultimately depend on the water content in the process stream. This can be mitigated by materials selection, dehydration processes or even through the use of chemical inhibitors, of which Baker Hughes has several dedicated products,” Tucker continued.
Tucker added, “It is important to note that CO2 injection systems are inherently different to hydrocarbon production in their operation as well as defining characteristics. These are governed by technical and economic drivers unique to these developments. In that regard there is great opportunity for simplification, but careful consideration of the type of CO2 store, the modes of operations, as well as the system design is needed to make sure equipment is fit for purpose.”
CCS at Baker Hughes
Tucker continued, “Baker Hughes is not only able to leverage decades of experience in the oil and gas industry but also with our experience from having delivered the worlds first subsea CO2 injection system for dedicated commercial storage. This was at Equinor's Snøhvit field. We actually supplied a record setting electro-hydraulic subsea control system for the 175km step out which is actually qualified for 220km.”
Tucker also mentioned other planned CCS projects that Baker Hughes has in store such as developing an all- electric system which can negate the need for hydraulic line in the umbilical. This has the potential to save significant costs for long offsets.
“I think the industry needs to build on the great strides that have been made in recent years to reduce costs and inefficiencies and really apply that mindset to CCS and to take it further even to really support these developments in their infancy and allow CO2 storage networks to grow.”
CCS and the push for sustainability
Tucker stressed he believed that CCS would really help the industry achieve its green targets and could work in tandem, rather than discourage, the industry becoming more efficient or switching to cleaner energy.
Tucker commented, “I really think that CCS is just one tool available in the fight against climate change, one piece of the puzzle. The world’s population and energy demand is still growing and this needs to be met. CCS is going to be absolutely vital for this. It has a huge role to play in addition to alternative fuels, renewable energies and also increasing energy efficiencies. It will be especially vital in industries and sectors where we have energy intensive processes. Action is needed now, and as more of these projects come to light, the technology will become cheaper and the process will be far easier to implement.”
A pioneering design for a Floating Normally Unattended Installation (NUI), that has the potential to unlock smaller and deepwater oil and gas reservoirs, is one step closer to commercialisation following an announcement of a collaboration agreement between the engineering consultancy behind the design, Buoyant Production Technologies (BPT), and Subsea 7, a subsea engineering, construction and services company.
The BPT Floating NUI
BPT’s patented proprietary design is a compact single column offshore facility, designed and equipped specifically for unmanned operations. The unit’s low OPEX and low CAPEX deliver optimised lifecycle costs to offshore developments.
With increasing focus on the environmental impact of oil and gas projects, as well as uncertainty surrounding commodity prices, Floating NUIs can offer a robust development solution for a wide range of future projects. BPT has developed Floating NUI into several configurations:
-Utility buoys powered using renewable sources, that can replace subsea umbilicals for well control and management
-Normally unattended production units
-Offshore substation units for use in offshore wind farms and for power import/export to oil and gas infrastructure
Central to the patented design, which is scalable for different field requirements, are several features:
-Slender “hull” structure and integrated (buoyant) “deck box”
-Open deck for topside process equipment and personnel access
-Deck box housing power generation and utilities
-Minimal motions, enabling deployment in harsh environments
-Minimal offshore installation cost
The Floating NUI series includes:
-Production Buoy: A standalone production facility for smaller deep-water developments
-Power & Control Buoy: Providing well-site services to enable subsea developments such as long-range /complex gas and oil tiebacks
-Floating substation: Supporting offshore substations for use on offshore wind developments and power import/export applications
The NUI conecept was developed and tested with multiple industry partners including the Oil and Gas Technology Centre, Premier Oil, Total E&P UK, Lloyds Register, Siemens, Wärtsilä, Ampelmann and BW Offshore.
The Subsea 7 and BPT collaboration agreement
BPT will bring their proprietary Floating NUI designs, configured for a range of offshore developments while Subsea 7 will provide field development and delivery expertise, supporting the integration of Floating NUIs into offshore energy developments and the engineering, construction, procurement, and installation phases of the project.
Duncan Peace, Managing Director at Buoyant Production Technologies, said, “By entering into this collaboration agreement with Subsea 7, we have developed a robust delivery model for Floating NUI projects, which we believe will enable us to successfully deliver projects to our global customer base.”
Thomas Sunde, Vice President Strategy at Subsea 7 added: “We believe BPT’s Floating NUI technology is well placed to help us support clients to improve lifecycle development economics of their offshore energy projects. By working together, we believe both parties will be able to better support our clients’ ambitions.”
For BPT, a wholly owned subsidiary that was formed in 2018, this announcement is a step along their journey to create novel designs to reduce HSSE risks and minimise lifecycle costs with a clear route to the market for the Floating NUI now established.
Logan Industries, a hydraulic repair, manufacturing and rental company, has manufactured and delivered the second set of a new and innovative design of small-footprint coiled tubing (CT) reelers.
The new CT reelers, the largest reeler Logan has manufactured, are suitable for storing and deploying 10,000ft of 2 3/8in tubing and enable operators to perform open water well interventions without bringing in a full drilling rig; boosting efficiency and reducing costs.
Dean Carey, Technical Director at Logan Industries, said, “One of our most valued customers trusted our expertise to deliver them with a unique solution when nothing on the market met their needs. Our new CT reelers are truly innovative designs and game changers for the offshore intervention market because they feature such a small footprint. This enables customers to take on more well stimulant fluid load, meaning they can perform a bigger job for longer. Logan has become the industry leader and the preferred option in CT deployment for open water intervention service providers.”
Logan pioneered new ways of assembling drive systems on large drums, and new methods of ensuring the CT lays and stays on the drum and wraps. Prior to Logan’s development of this solution, no fatigue models existed for CT performance. Since Logan’s development of these types of reelers, distinguished professors have investigated new methods of evaluating CT and have published their findings. Now, Logan’s CT reelers are specified in several of these papers and Logan has helped introduce a new requirement for CT fatigue evaluation.
Logan maintain the mantra, ‘if you can describe it, we can bring it to life; make it safe; and make it work for you’ and the CT reeler set is the latest from their extensive catalogue (alongside products such as winches, hydraulic machinery, spools and handling equipment) that aims to prove it.
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