Europe
- Region: North Sea
- Date: Mar, 2021
Neptune Energy has announced the safe and successful installation of four Enhanced Horizontal Subsea Tree Systems (EHXT) for the Duva development project in the Norwegian sector of the North Sea.
The Duva development, on Production Licence 636, is an oil and gas subsea tie-back to the Gjøa semi-submersible facility, of which Neptune Energy is also the operator.
While conventional installation of EHXTs would be carried out with a drilling rig, Neptune Energy, together with its partners and contractors, conducted the installation using the vessel Far Samson, operated by Solstad Offshore.
Thor Løvoll, Director of Drilling & Wells in Norway, Neptune Energy, commented, “By introducing the latest available technology combined with quality planning and teamwork, we completed the installation safely, successfully and ahead of schedule. Deploying the subsea trees from a vessel saved about 20 days of rig time, reducing costs, time and emissions.”
The 20 days of reduced rig time is equivalent to approximately US$12mn savings for the license partners and by using a vessel instead of a rig, emissions were reduced by more than 60% during the installation activities.
It was the first time Neptune Energy has installed EHXTs in a standalone operation with a vessel. They were successfully deployed on the template wellheads over an 18-hour period, with the total installation and subsea system testing completed within eight days. The operation was carried out in close cooperation with TechnipFMC, Ross Offshore, Solstad Offshore, Oceaneering, Fugro, IKM and Tigmek.
The Duva project
Neptune Energy’s Head of Gjøa Subsea Development, Crawford Brown, added, “We are progressing with the Duva project at pace and have reached an important milestone. The efficient installation of the subsea trees allows the project more schedule flexibility as we enter the drilling and completion campaign for the Duva production wells.”
“Duva is an important part of Neptune’s geographically-diverse, gas weighted portfolio of developments, and will both increase production and extend the operational life of our operated Gjøa platform.”
The Duva oil and gas field was Neptune’s first discovery in the Norwegian North Sea, a strategically important area supporting the company’s growth. It is located 14km northeast of the Neptune-operated Gjøa field, at a water depth of 360 metres. Gross 2P reserves are 88 mmboe (gas 76%).
The drilling rig Deepsea Yantai, operated by Odfjell Drilling, will drill and complete the remaining sections of the Duva well programme during Q2/Q3 2021, and first production from Duva is expected in the third quarter of 2021.
- Region: North Sea
- Date: Mar, 2021
Wintershall Noordzee has contracted Swift Drilling BV to carry out a plug and abandonment (P&A) campaign in the North Sea using the Swift 10 light jackup rig.
The Swift 10 is a fully Dutch owned and operated rig, which together with Wintershall Noordzee, will focus on the safe, efficient, and economic P&A of offshore wells on the Continental Shelf of the Netherlands and Germany. Before the three to four year campaign begins in the summer, in the coming period the rig will be revitalised and restarted after its original five year LTI free campaign for Shell/Nam.
The Wintershall Noordzee and Swift team will use the highly automated Swift 10 and focus on continuous improvement to effectively P&A wells. Both parties see the cooperation as a start of a new era, whereby old wells are plugged and abandoned according to the latest standards and protecting the environment of the North Sea.
“We’re extremely happy to revive the Swift 10 for Wintershall Noordzee. Together we share the ambition to create a long-term cooperation to P&A wells safe, efficient and economical as one team. The cooperation with Wintershall Noordzee aiming at the realisation of our shared ambition so far has been enjoyable and the right basis for successful P&A campaign,” said Erwin Lammertink, CEO of Van Es Holding, which Swift Drilling is part of.
The Swift 10 is a 300ft Gusto MSC SEA-2750 fully automated drilling rig, with a POB of 50 originally delivered in 2011. Its light jack up drilling concept matches the shallow water conditions of the Southern North Sea and due to its X/Y cantilever design, it is capable of serving the majority of the production platforms in the region with drilling wells, work overs and well abandonments. It is currently located in Rotterdam where it is getting ready for her P&A campaign.
- Region: All
- Date: Feb, 2021
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.
- Region: North Sea
- Date: Feb, 2021
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.”
- Region: North Sea
- Date: Feb, 2021
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.
- Region: All
- Topics: All Topics
- Date: Feb, 2021
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.”
- Region: North Sea
- Date: Jan, 2021
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.
- Region: North Sea
- Topics: All Topics
- Date: Jan, 2021
Spirit Energy has announced it will drill a new well in the Grove North East area which, if successful, could extend the life of the Grove field by five years to 2028.
Neil McCulloch, Executive Vice President of Technical and Operated Assets at Spirit Energy, commented, “The infill well is planned to target the un-appraised north-eastern limb of the Grove field and has the potential of delivering 4.2 million barrels of oil equivalent net additional reserves. Further, it could add five new years to the life of the Grove field and improve the prospect of additional opportunities in the area.”
Options available:
Several concept solutions have been studied, including horizontal, simple vertical and platform deviated wells, subsea tie-back concepts as well as an appraisal well before the development well from the platform.
McCulloch said: “Based on the subsurface, well technical complexity, value and strategic fit criteria, we have decided on a platform deviated well. We believe this is the optimal way forward and a robust well design has been developed – our team is experienced in drilling similar wells in the Southern North Sea, including other wells in the Grove area.”
Maersk Resolve:
The development well will be drilled by the harsh-environment, Gusto-engineered MSC CJ50 jack-up rig ‘Maersk Resolve’, which recently completed a campaign offshore the Netherlands. Operator, Maersk Drilling, was awarded the contract worth around US$11.3mn with additional services of mobilisation, demobilisation and an option to add plugging and abandonment of one well.
Morten Kelstrup, Chief Operating Officer of Maersk Drilling, commented, “We are excited to be able to build on our relationship with Spirit Energy with our first UK well for the customer, for whom we previously completed a highly successful subsea development campaign in Norway. We will surely be able to continue our close collaboration and mutual focus on operational excellence, and in addition the campaign at Grove will benefit from Maersk Resolve’s experience with safely and efficiently drilling challenging Zechstein formations as part of the rig’s latest assignment in Dutch waters.”
Drilling is scheduled to start in Q1 2021, with production expected to begin by Q3 2021. Alistair Macfarlane, Area Manager for SNS & EIS at the Oil and Gas Authority, said, “After a challenging time for the industry in 2020, we welcome this positive news for the basin, with activity at the Grove field bringing opportunities for the UK’s supply chain.”
- Region: North Sea
- Topics: Integrity
- Date: Jan, 2021
Causes of a wellbore influx:
Safe Influx Ltd has been granted a patent by the UK Patent Office covering its Automated Well Control technology including a wide range of modules using the same technology.
If the formation pressure exceeds hydrostatic pressure in a wellbore it can result in an undesirable flow of formation fluid, called a wellbore influx. This is caused by factors such as human error, abnormal pressure, light density fluid in the wellbore, and lost circulation. If the influx deteriorates, this could potentially escalate into a blowout which could threaten lives, contaminate the environment and incur severe financial loss.
The Automated Well Control technology:
The patent granted to Safe Influx recognises the ability of their Automated Well Control system to detect the presence of a fluid influx condition in a wellbore, make a decision against criteria to shut-in, and then automatically initiate an initial well control protocol that results in the well being safely shut-in.
The Safe Influx Automated Well Control system enables fast identification, decision-making and reaction to well control events. This technology is capable of reducing the size of an influx compared to conventional techniques, and this means a reduction in delays, costs and operational issues in getting back to drilling. Additionally, the confidence obtained with reliably smaller influxes can lead to much more efficient well designs, leading to an estimated 15-20% saving in well costs.
Implications for the industry:
Bryan Atchison, Co-founder and Managing Director at Safe Influx, commented, “I believe that applying automation in well control represents a step change in the area of process safety. Implementing this novel technology allows faster decision making, and significantly reduced well control risks and costs. The system’s ability to detect and automatically initiate and complete the vitally important well control protocol without manual intervention will represent a much-needed step change for the industry. With the technology behind this patent, we are able to provide a system with unique capabilities unavailable from any other company.”
At the end of 2020, Safe Influx conducted a report analysing the frequency of blowouts in the Gulf of Mexico, concluding that these are still occurring and that there is much evidence to suggest human error is a key factor in many of these incidents. With the introduction of Automated Well Control Safe Influx aims to eradicate human error leading to blowouts, which could potentially reduce the frequency of such catastrophic events across the globe.
Page 30 of 35
Copyright © 2024 Offshore Network