Europe

Aker BP was the first operator worldwide to use bismuth alloy to plug the top section of old oil wells. Since then, the technology is now used on 30 wells on the Valhall field, resulting in safer, permanent well plugging.

The Valhall field

The Valhall field in the southern part of the North Sea has produced over a billion barrels of oil equivalent since it began production. To ensure consistent performance, old oil wells must be plugged to make room for new wells in the hopes that over the next 40 years another one billion barrels of oil will be drawn up.

Martin Knut Straume, Aker BP’s Chief Engineer for Plugging and Abandonment, commented, “We’ll continue to work on Valhall for many decades to come. That means we have to make sure that we shut down and abandon old wells safely, so that it is safe for us to be there when we continue to produce and drill new wells at the same time. We use the best available technology, and in this case, in the top part of the old wells, that means bismuth.”

Aker BP has already started removing the old field centre on Valhall with the living quarters platform removed in 2019. Another two installations will disappear over the next five years and all wells connected to the old drilling platform will be permanently plugged over the course of 2021.

Egil Thorstensen, Senior Engineer for Plugging and Abandonment at Aker BP, said, “We’re currently installing bismuth plugs in the top section of all the wells; in other words, in the 30-inch casing. That’s the last thing we do before we cut and pull the pipes from the seabed to the platform, and the well is permanently abandoned.”

Diverse solutions provided by new technology

Plugging wells on Valhall may pose an additional challenge both due to gas migration to the surface, and due to subsidence and compaction. The seabed around the Valhall field has sunk seven metres since the early 1980s, and the top of the reservoir has dropped about 15 metres.

This means that cement, which is commonly used as a barrier material to plug wells, is an inadequate solution as it can fail when subjected to wellbore or casing stresses resulting from subsidence and compaction events. In the worst case, hydrocarbons in old wells could migrate upwards and potentially leak into the sea.

“Aker BP installed a trial plug over two years ago, and was the first operator worldwide to use bismuth alloy in the top section of the well. When we use this technology, we make sure that the plug is 100% impermeable. Gas cannot leak to the surface,” said Thorstensen.

Bismuth is a metal with unique properties that make it particularly well-suited for applications in P&A operations. As a solid metal, it is completely impermeable and is heavy as lead, making it less prone to contamination during its placement into the well. When melted, liquid bismuth flows like water, giving it the ability to flow into the smallest interstices in the well. When bismuth solidifies, it expands, which helps provide permanent sealing capability inside a wellbore.

Additionally, unlike cement plugs which need to be several dozens of metres in length in order to qualify as barrier, a 2.5 metre-long bismuth plug suffices to provide long term isolation in the well.

Reducing environmental impact

Bismuth alloy is typically a more expensive option than cement but total costs of plugging the top well sections are less due to decreased rig time for these operations.

“Even so, we have chosen to use it on Valhall because of the unique field conditions. For us, this is a matter of making sure that we minimise the carbon footprint from our operations, while ensuring that the wells are plugged and abandoned to the highest standard. Bismuth has what cement lacks: it changes almost instantaneously from liquid to solid when the heating source is removed, it is completely impermeable, and it is not affected by contamination issues,” commented lead technical engineer at Aker BP, Laurent Delabroy.

During the autumn of 2020 and winter this year, bismuth plugs were installed continuously from the Maersk Invincible rig on the Valhall field centre. The plugs are up to 2.5 metres long and weigh 9 tonnes. The work has been performed through the jack-up rig alliance between Aker BP, Maersk Drilling and Halliburton. Time spent per well was cut in half to a record-low 30 hours this winter which has resulted in significant cost savings and freed up several months of rig time that can now be used for new operations.

Delabroy concluded, “We succeeded through strong teamwork and close collaboration with our solid technology partner, BiSN. And last but not least, because we are part of a company that dares to use new technology. Aker BP is not only the first in the world to develop and perform this type of operation, we are now the world’s largest users of this technology, and many other oil and gas operators are following suit. That says something about our company.”

Archer Limited has signed an offer letter with Moreld laying out principle terms to purchase 100% of the shares in DeepWell AS (DeepWell).

DeepWell is a leading Norwegian well intervention company established in 2004 that is focused on mechanical wireline and cased hole logging services. Headquartered in Avaldsnes, Norway, DeepWell had approximately 200 employees and a revenue of NOK355mn in 2020.

Starting from 1 May 2021, Archer will also take over the Equinor wireline services scope from DeepWell, which was awarded in 2018. The light well intervention services for Equinor were to be completed by the AKOFS Seafarer together with Welltec, and included the provision of all wireline and basic logging services, together with operational support and crews.

Archer's CEO, Dag Skindlo, commented, “An acquisition of DeepWell would secure Archer’s access to a modern fleet of electric wireline units, as well as enable participation in the vessel-based light well intervention market. Strengthening our equipment fleet, broadening our low carbon/low emission solutions and continuing our track record for service quality are all key aspects of our strategy on the NCS. We are impressed by DeepWell’s team and look forward to continuing this process with them.”

The contemplated transaction is subject to due diligence, negotiation of the transaction documentation, closing conditions and regulatory approvals.

Archer’s North Sea expansion

The addition of DeepWell is further evidence of Archer’s formidable performance in the North Sea as it continues to expand operations and offerings in the region. The company continues to pursue new technology and digital solutions for well simulations and remote support in order to enhance efficiency and target reducing their carbon footprint.

Additionally, in April 2021, the company secured a long-term frame agreement with ConocoPhillips for the provision of wireline services on the Norwegian Continental Shelf. According to their release, this makes Archer the largest mechanical intervention company on the Shelf, with an estimated total contract back-log of NOK3.5bn.

Aker BP has completed the plugging of wells at the Valhall oilfield centre six years earlier than originally planned, saving more than NOK5bn.

Aker BP is the operator alongside partner Pandion of the Valhall oilfield which first saw oil flow in 1982. Since then, more than one bnboe have been produced from the area, which is three times more than originally expected.

In 2014, as a result of the decision to pursue a policy of modernisation rather than abandonment, Aker BP began a plugging campaign in order to revamp the field and keep it producing for the foreseeable future. Since that time, a total of 30 oil wells from the original drilling platform have been plugged in order to pursue the ambition of bringing up a further one bnboe from the field over the next forty years.

The first plugging campaign spanned 2014-2016 and was conducted by the Maersk Reacher rig. The next two campaigns, between 2017-2018 and 2020-2021, were carried out by the Maersk Invincible drilling rig, the departure of which last week marks the end of plugging operations for the field.

These campaigns were a roaring success as Aker BP have reported that no serious incidents were incurred during the work and that they were carried out in a total of four years, at a cost of NOK10.1bn, as opposed to original estimations of 10 years and NOK15.5bn.

Tommy Sigmundstad, SVP Drilling and Wells in Aker BP, commented, “The work to plug the wells has been a success through three major campaigns. The plugging has been carried out safely and efficiently. We have an unrelenting focus on improvement, and that has paid off in shorter operation times and reduced costs. Our alliance partner Maersk Drilling has been a key factor in all the campaigns. I am incredibly proud of the work delivered by teams across all companies both offshore and onshore.”

Alongside the plugging operations there has been a number of decommissioning activities carried out and planned. The QP accommodation platform was removed in the summer of 2019 by the catamaran crane vessel, Pioneering Spirit, and over the course of the next few years the original drilling platform and process platform will be removed along with the replacement of the original Hod wellhead platform (south of the Valhall field).

Utilising the latest technology

Wherever possible, Aker BP made use of the latest technology in order to optimise their operations.

Martin Straume, Chief Engineer for Well Plugging and Abandonment at Aker Bp, said, “Section milling of cemented casing has been carried out inside larger casing. We have done this to verify that well barriers are in place on the outside of the conductor. This means that we have avoided having to mill or pull entire sections of casing from the surface and down to the relevant depth. This represents up to several weeks of time saved per well, and is an enormous improvement in the plugging work.”

For the first time ever worldwide, Aker BP along with Halliburton and Maersk Drilling, conducted fully automated cementing operations from land, taking place from Aker BP’s offices in Stavanger. The technology increases efficiency, reduces costs and lowers HSE risk.

In addition, the top section of the old Valhall wells have been plugged using bismuth technology, an innovation conceived by BiSN to solve the challenge of potential methane leaks from old wells, and results in lower CO2 emissions compared with cement.

For the future

At the end of 2019, the first oil flowed from Valhall Flank West. As of March 2021, a new Hod platform is nearing completion at Aker Solutions’ yard in Verdal. The concept, implementation model and organisation for the Hod project were copied from Valhall Flank West. The planned production start for Hod is in Q1 2022, and recoverable reserves are estimated at around 40mnboe. Aker BP has also now embarked upon studies for a new central platform on Valhall, which will ensure production capacity for future volumes in the area.

In an operational and financial update, Hurricane Energy plc, a UK-based oil and gas company, has provided an update on production from its Lancaster field and Early Production System (EPS) and net free cash balances.

The Lancaster (EPS) consists of two wells tied back to the Aoka Mizu floating production storage and offloading (FPSO) vessel, a relatively new system with first oil achieved in June 2019. Hurricane Energy has now reported that between Q4 2020 and Q1 2021, oil production shrank from 1.17mnbbl to 1.01mnbbl, with an average oil rate of decline of 12,700bpd to 11,200bpd.

The company has identified the decline in oil production in 2021 is a result of:

•The decision to reduce production from the 205/21a-6 well (the ‘P6 well’) in November 2020 for reservoir management purposes, which resulted in a reduced rate of increase in water cut
•Natural decline in the period
•A temporary reduction in the production rate in early March 2021, which required an unscheduled well intervention

Hurricane Energy continued by stating that production efficiency during the first quarter of 2021 was 95%, exceeding its planning assumption of 90%. The first quarter outturn compared to a production efficiency of 99% in the fourth quarter of 2020, with the sequential decrease explained by the unplanned well intervention.

As part of the Hurricane Energy’s periodic well testing programme for reservoir management purposes, the Lancaster field is currently producing from both the P6 and 205/21a-7z wells. Immediately prior to the testing programme, the field was producing from the P6 well alone at a rate of c.11,600 bopd on artificial lift via electric submersible pump, with an associated water cut of 28%.

Despite the unscheduled operations, the 21st cargo of Lancaster oil was still lifted on 17 March 2021 with the 22nd cargo already sold and due for lifting between end April and early May 2021. Additionally, despite the drop in production and the impact of Covid-19, Hurricane Energy reported that as of 31 March 2021, it had a net free cash of US$127mn, compared to US$106mn at 31 December 2020.

At Hannover Messe, April 12-16, Bosch Rexroth will present the SVA R2 Subsea Valve Actuator, a disruptive innovation for electrically actuating valves in the subsea process industry.

The SVA R2 is the world’s first electric actuator that can replace conventional hydraulic cylinders with field-proven safety technology and without taking up additional space. The integrated electric controller offers precise motion control and, thanks to condition monitoring and a safety spring, the SVA R2 satisfies Safety Integrity Level (SIL) 3 in accordance with IEC 61508 and IEC 61511.

The actuator minimises energy consumption and is geared toward delicate ecosystems. The functions, operating life and safety of the actuator have already been successfully tested in accordance with international standards and when the SVA R2 is used in subsea factories at a depth of up to 4,000 meters, hydraulic pipes or power units are no longer required. The electric supply pipes which are already installed for sensors are adequate to ensure the reliable operation of the actuators.

Changing the subsea process industry

Up until now, the operators of process systems have mainly relied on hydraulic cylinders in order to open and close subsea valves with a quarter turn and a defined force. With offshore installations, for example for oil and gas production, these cylinders are supplied by a central hydraulic power unit with hydraulic pipes several kilometres in length. This solution uses a great deal of energy in order to compensate for the cumulated losses and it cannot control the movement with precision. To date, plant engineers and operators have still relied on hydraulic cylinders because they are the only components to offer field-proven safety systems with a mechanical spring in a compact design (the electric actuators which are currently available do not have such a safety function as this is not possible given the size and weight requirements). Additionally, approaches designed to ensure safety using subsea batteries cannot guarantee the reliable closing of valves over the required operating life of up to 25 years.

For the agile development of the SVA R2, the Bosch Rexroth team worked closely with a number of suppliers and operators of offshore installations, as well as international universities. The new module comprises a pressure-compensated container that contains an electric drive, a motion control system and a safety device – and can replace the hydraulic cylinders previously used on a 1:1 basis. It requires only one cable for the power supply and communication. The SVA R2 is designed to actuate valves reliably with the power supply that is commonly used for subsea sensors. Switching to compact and safe electric actuators means that hydraulic pipes (several kilometres in length along with the associated power units and controllers) are no longer required.

The Subsea Valve Actuator is designed for high volume production, has proven robustness and reliability and is suitable for applications above and below water such as hydrogen production, CO2 storage and general applications in the oil and gas process industry. This innovative new technology has been nominated for the prestigious Hermes Award and, after its premiere at Hannover Messe in April, the first pilot tests are due to start in the third quarter of 2021 before being offered to Bosch Rexroth’s global client base.

Safe Influx has announced that the rig trial of the industry’s first ever integration of Managed Pressure Drilling (MPD) and Automated Well Control technology has been completed following months of preparation by Weatherford, Safe Influx and Finesse Control Systems.

A series of pre-agreed tests were successfully performed on Weatherford’s test rig in Houston, to demonstrate and verify the integration and functionality of both systems.

A "game changer" for the industry

The combination of Weatherford Victus intelligent MPD and Safe Influx’s Automated Well Control system provides automated secondary well control, which will allow wells to be drilled and constructed with the highest level of efficiency and integrity. As a standalone application, the MPD system can detect, control and circulate out an influx, which is within the well’s operational envelope.

If the parameters within the well’s operational envelope are exceeded, the Weatherford MPD system sends a series of real time signals to the Safe Influx Automated Well Control system which then commences the Automated Shut-in sequence: space out, shut down the top drive, shut down the mud pumps, and finally shut-in the BOP.

“We are delighted to have successfully completed the rig trial of the integration of MPD and Automated Well Control systems. The combination of the Safe Influx patented technology with Weatherford’s comprehensive portfolio of MPD products provides a game changer for the industry. We are confident that this is a reliable tool which has the ability to mitigate risks and enhance efficiency and safety in well operations, to prevent the loss of life, minimise environmental impact, deliver substantial cost savings and protect company reputation,” commented Bryan Atchison, Managing Director at Safe Influx.

Fraser Dunphy, Managing Director at Finesse Control Systems who build the Safe Influx equipment and developed the logic programming, said, “It has been great to work with Safe Influx and Weatherford on this ambitious and innovative combination of technologies. We have been involved with this project since its initial phase and we are thrilled to see this integration working on the rig trial. The successful results reveal the value of combining technologies, knowledge and experience to create a cutting-edge solution to the oil and gas industry.”

The rig trial is part of the Memorandum of Understanding (MoU) signed by Weatherford and Safe Influx in September 2020. Under the MoU, the companies will cooperate globally to focus on revolutionising well integrity during the construction phase by bringing to market the integration of MPD solutions and Automated Well Control technology. This integrated offering will automate the mitigation of drilling hazards, while drilling in the most efficient manner possible.

As part of their 2020 Full Year Results publication, EnQuest have outlined their 2021 performance outlook, highlighting the scale of decommissioning work ahead of them as they seek to retire ageing fields.

2020 in review

In 2020 EnQuest’s average production decreased by 13.8% to 59,116boe per day. While Covid-19 implications did stifle production for some time, the company reported that the primary driver of this reduction was the declining production rates and ultimate decision to cease production at high cost assets such as Heather/Broom, Thistle/Deveron and Alma/Galia.

Production at Alma/Galia ceased in June 2020 with the EnQuest Producer floating production, storage and offloading (FPSO) vessel moving off station quickly to the oil terminal jetty at Nigg in September. The group is still evaluating the options for the vessel’s future.

At Heather, the cessation of production (CoP) application was accepted by the regulator also in June, paving the way for decommissioning to commence. The platform remained shut in and depressurised all year, with front end engineering activities being undertaken ahead of the resumption of the well abandonment programme in 2021.

In June, the CoP application for Thistle/Deveron was accepted, allowing for the decommissioning phase to begin. The facility remained unmanned all year, although preservation visits to the Thistle platform took place as part of the preparatory works ahead of the planned 2021 well abandonment programme.

At Broom the application for CoP has been submitted to the regulators and approval is expected shortly.

2021 decommissioning

As expected, the Dons ceased production in early 2021 following the receipt of necessary partner and regulatory approvals in respect of CoP. The Northern Producer floating production facility is being used for initial decommissioning activities, such as flushing of the sub-sea infrastructure and to support implementation of effective well isolations. Once these activities have been completed, anticipated early Q2, the vessel will depart the field and be handed back to the owner.

At Thistle/Deveron, work will continue on the rehabilitation project alongside ongoing preparations for commencement of the well abandonment programme, which is expected to commence in Q4.

On Heather/Broom, activities to optimise the well abandonment programme and ready the rig for decommissioning have continued. Once completed, plug and abandonment of the development’s 41 wells is expected to begin in Q3, with the work programme anticipated to continue for approximately three years.

Restoring production rates

With so many facilities being retired, EnQuest have turned to other fields in order to restore their production rates and, in February this year, signed an agreement 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. EnQuest has estimated that the acquisition will add an immediate incremental production of 10,000boe per day, 18mnbbl to its net 2P reserves and 5mnbbl to its net 2C resources.

The agreement has been signed with an initial consideration of US$325mn, and upon completion, will add immediate material low-cost production and cash flow to EnQuest and will allow the group to accelerate the use of its tax losses. EnQuest plans to finance the transaction through a combination of a new secured debt facility; interim period post-tax cash flows between the economic effective date of 1 January 2021 and completion; and an equity raise.

EnQuest Chief Executive, Amjad Bseisu, 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.”

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.