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.
The upgrades will be applied to rigs in the Norwegian sector of the North sea, Deepsea Atlantic and Deepsea Nordkapp, with the opportunity to include Deepsea Stavanger, Deepsea Aberdeen, and Deepsea Yantai at a later stage.
BlueDrive DC-Grid technology
Siemens Energy’s BlueDrive DC-Grid technology was developed to meet the offshore industry’s demanding energy distribution requirements, especially for propulsion and drilling systems. It is an efficient, environmentally friendly solution that provides high levels of reliability, availability, and ease of service, with low emissions.
The solution consists of DC/DC converters connected to the existing four drilling drive DC buses from one side and to DC/DC converters connected to energy-storage systems. This allows platform operators to conduct peak shaving of drilling loads, so fewer generator sets can run at higher and steadier loads resulting in a reduction in fuel consumption and carbon emissions. Further, the solution increases reliability by reducing blackouts, which will prevent downtime and boost asset utilisation.
In regards to drilling applications, the Siemens Energy BlueDrive system will be an integral part of the entire drilling process, enhancing the drill string's performance when applying high torque during drilling operations.
On the Odfjell platforms
Odfjell Drilling is committed to reducing the harmful impacts its operations may have upon the environment wherever it can and is therefore pioneering the use of the BlueDrive DC-Grid technology – the first of its kind to be installed on an offshore drilling rig.
Per Lund, Chief Technology Officer and Executive Vice President of Technology & Sustainability at Odfjell Drilling commented, “These projects are the result of asking a simple yet challenging question: ‘What would be the most efficient technological approach to minimise emissions from a rig in the short term?’ The resulting ideas were very well received by Odfjell Drilling’s customers and will contribute to their long-term emission targets, so this is business and low-emission targets working hand-in-hand.”
Jennifer Hooper, Senior Vice President of Industrial Applications Solutions for Siemens Energy added, “Our agreement with Odfjell Drilling affirms our ability to understand and deliver complete, innovative, and cutting-edge solutions in line with our customers’ expectations, which include design, engineering services, interfacing with third parties and fabrication of state-of-the-art power electronics, as well as financial advice and support.”
The long-term relationship and technology cooperation between Odfjell Drilling and Siemens Energy also includes several R&D initiatives related to power from shore or nearby platforms and floating offshore windmills to fixed platforms or rigs. These solutions will complement the Siemens Energy DC-Grid and BlueVault battery solution system and provide customers with a holistic approaches to solving their power challenges that Siemens Energy can deliver entirely.
With these upgrades, the rigs will push the boundaries for conventionally powered offshore rigs and set a new technological standard in Odfjell Drilling’s strategy towards zero-emission drilling.
According to a recent PwC survey 90% of upstream companies have begun investing in digital initiatives and research by McKinsey suggests that 70% consider digital operations at the top of their operations strategy agenda. LTI and Offshore Network hosted a webinar entitled ‘Simplifying the Journey to Industry 4.0 through "Connected X as a Service”’, as Kartik Raman Iyer Head of Delivery of Indusrial IoT at LTI, and Frode Støldal, Chief Digital Officer at Tampnet, discussed the benefits of digitalisation that the upstream oil and gas industry has begun to recognise and identified connectivity as crucial step along this journey.
Connectivity as the key
Raman began by outlining that with new advances in technology the potential to transform and optimise business within the upstream oil and gas industry is enormous and one fundamental enabling factor has been the advancements made in communication technology.
Raman commented, “If you look at the oil and gas vertical, especially with operations whether onshore or offshore, connectivity has been a challenge all along. But with advancements in connectivity there lots of possibilities opening up in terms of digital interventions. All these used cases and innovations help bring in operational efficiency and also bring in efficiency from a workforce standpoint. This helps in accelerating the entire digital transformation journey. In terms of technology trends connectivity is the backbone but beyond that you have AI, automation and analytics as well.”
Due to demand fluctuation, a current industry dynamic as a result of the pandemic, operators are increasingly seeking to strike the correct balance between production and demand, making visibility and quick action vital.
Raman continued, “Organisations need to be agile, nimble and flexible to really adapt to the changing market dynamics. Providing real time visibility of an entire operation allows necessary interventions based on insights you are getting in real time. Because of the advancement on the connectivity side there are lots of used cases emerging around convergence as well because now you have access to the right working data on the enterprise side and analytics is possible. Many of these insights you are getting will help you take decisions very fast.”
Tampnet Infrastructure
For Tampnet, connectivity is everything, and Støldal outlined his company’s role as planners, builders and operators of fiber that connects offshore assets. They have also now implemented mobile infrastructure that can extend around 50-60 km from each asset, which allows complete coverage of the entire value chain and enables faster communication along it.
He commented, “Latency is core of what we do at Tampnet, one of the reasons for this is we also have a carrier business where some of the most advanced customers in financial industry are customers of Tampnet. If you are doing trading you are obsessed with latency. So we try and assign the entire infrastructure to minimise latency.”
Støldal added that the company also provides services to introduce complete coverage over the whole of an asset, regardless of size and complexity, so that there is a connection between different use cases, be them sensors, tablets or service containers. Together with DNV GL, Tampnet conducted a complete quality assurance test of the infrastructure at a Dutch site. Støldal said, “Feedback was very very good. The survey concluded that there was less safety exposure, no helicopter flight needed, no real travel needed, no offshore presence of a surveyor needed, smaller environmental footprint, efficient time and cost, and kept company assets compliant, safe and reliable. For business cases the improvements are quite significant.”
Connected X as a Service
For a quick, simple and cost effective way to make the most of new connectivity technology and embark on the journey to Industry 4.0 Støldal and Raman recommended the Connect X as a Service. This has been developed to evaluate the range of new digital technologies on the market, provide comprehensive a assessment to identify where digital advancements can be made, and guide and maintain businesses along the path to digitalisation. To listen to the webinar recording exploring this service in more detail, click here.
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