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.
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.
Following the approval of the Petroleum Safety Authority Norway, Equinor have retained the services of the Wellserver light intervention vessel, owned by Island Offshore.
Since its construction in 2008, the ship has been almost exclusively in use by Equinor (previously Statoil when it was first acquired) and it is now entering its twelfth year of service with the option to extend the contract for another three years. The vessel is suited for a number of tasks including construction work, subsea installation work, securing of wells, trenching, P&A work, tower and module handling, crane work, and has carried out more than 250 well interventions for Equinor.
A spokesperson from Island Offshore commented, “We are very pleased with the consent for the continued use of Island Wellserver. This year we avoided winter lay-up for the vessel as Equinor will be using it throughout the winter. Normally the campaign commences in April, so this is positive for us and for the crew in particular.”
This consent allows for the operation of the vessel on fields in the Norwegian Sea, Barents Sea, and North Sea and comes as Equinor marked the end of 2020 with a flurry of activity in these areas:
-The Norwegian company and its licence partners agreed to provide NOK3bn to improve operations on the North Sea Statfjord Øst field. This investment will result in the drilling of four new wells from existing subsea templates, modifications for the Statford C platform and a new pipeline for gas lift. As a result of this project, Equinor expects the recovery factor to increase from 56% to 62%, improving recovery by 23mmbbl. The production start is scheduled for 2024.
-The Snorre Expansion Project commenced production which will add nearly 200mmbbl of recoverable oil reserves and extend the life of the Snorre field through to 2040. Expected in Q1 2021 the project was completed ahead of schedule, with 11 wind powered turbines to power the Snorre and Gullfaks fields expected in Q3 2022.
-Alongside its licence partners, Equinor awarded a NOK500mn contract to hook-up the fifth platform on the John Sverdup field to Aker Solutions. The processing platform is currently under construction with installation on the field to begin in 2022, and the project is expected to employ around 1,200 people across three offshore shifts.
With the continued procurement of the Island Wellserver vessel it appears Equinor is looking to start 2021 as it finished 2020, promoting positive activity despite the challenging times.
Genoa Black caught up with Craig Feherty, Director of FiberLine Technology (FLI) at Well-SENSE, to discuss their new product after it burst onto the market last year and subsequently received the award of Most Impactful Technology at the OWI Global Awards 2020.
FLI is an intervention system for downhole data acquisition which enables the operator to perform high-quality well surveys faster than ever before. It employs single-use bare fibre-optic lines for distributed temperature and acoustic sensing, placing them directly into the wellbore from surface to total depth.
This compact and lightweight technology does not rely on the use of rigs, wireline, sickline or coiled tubing for deployment - reducing cost, risk and time taken for well intervention, while still providing a dynamic picture of a well over time. Only one engineer is needed to deploy the system and it can be used for a number of different applications.
Behind the projects success:
Feherty reflected on why the product has received so much attention over the last year. He commented, “We have been running the technology for a couple of years, developing it, trialling it, making it commercial. We knew all along it was something important for the market, that will enable well surveillance to be carried out more efficiently. Over the last year FLI has delivered impressive field results."
When asked what value the FLI system brings to customers, Feherty responded, “One struggle for the industry is efficient data collection of the right type - understanding what is happening within assets, how they are performing and where things are going wrong that may be put right. Standard intervention methods can be costly and have not evolved much over time.
“We have approached this from different angle - how to give our customers faster, richer data sets and reduce the risks that especially offshore interventions can carry. All the way through our development we have tried to address the problem of gathering more meaningful data using a simpler technique. By doing so you minimise the risk. Our product is capturing such rich data sets that it gives our customers much more of an understanding of what is going on within their well, which in turn allows them to make decisions fast. And it is delivered at a very affordable price.
Why recognition was significant:
The FLI Director continued by observing that the company is a small team that has evolved from humble beginnings, mainly through determination. He noted, “It is not easy bringing a new product to market, especially something as different as ours. Developing and building the business up, really is a true reflection on the hard work of our team and the commitment we have had. We have always known that this would be something quite special and it is only through perseverance that you get there. It is the icing on the cake that the hard work that we have committed to, and the work we have done in partnership with our customers, has been recognised by these awards.”
Reflecting on 2020:
2020 was a difficult year for every company across the oil and gas industry and Feherty did not shy away from addressing the obstacles Well-SENSE had faced. He admitted, “I won’t lie and say it hasn’t been a challenge. It has been a challenge for all of us with a lot of uncertainties about. But I think, if anything, it gives us more pride in what we are doing.
“We have had a tough year, but we have ridden through it and with the commercial benefits FLI can offer, we still have a fantastic level of customer engagement, enquiries and orders. We are still growing and that is a testament in itself that, even in challenging times, a small, dedicated team with a great product designed to deliver value, can really make a difference.”
Looking ahead to 2021:
Finally, the FLI Director turned to the future as he concluded, “I would like to say the plans will be bigger and better next year, and of course they are, but really it is keeping to the same path we are on. We are seeing demand growing for our services and our technology and we look to continue servicing that throughout 2021. The more we do, the more we can prove how FLI can make big wins for our customers and we only see that as being fruitful. As a team we are really excited for the next 12 months. 2021 will be a new beginning for all of us, but we are starting in a great position, and we are expecting big things.”
Dedication and perseverance appear to have paid off for Well-SENSE with the recognition from the OWI Awards judging panel, with one of the expert judges noting that the FLI system is ‘giving operators new options’. The new technology is a much needed innovative boost for the industry and is fast becoming the first choice well surveillance and diagnostic tool across the sector.
At the OWI Global Awards 2020, Oil Spill Response Limited (OSRL) claimed Best Example of Collaboration for the Subsea Well Response Project (SWRP) and so Genoa Black sat down with Andy Myers, SWIS Director at OSRL, to discuss the enterprise in more detail.
The SWRP was established in 2011 as a non-profit joint initiative between several major oil and gas corporations to improve the industry’s ability to respond to sub-sea well control incidents. The four objectives of the project were to; develop a capping toolbox to allow wells to be shut in; produce the Subsea Incident Response Toolkit (SIRT) for site survey, debris clearance, BOP intervention and subsea dispersant; collaborate on an international deployment mechanism so equipment could be readily available to the wider industry; and determine the feasibility of a global containment system.
Oil Spill Response Limited has collaborated with the SWRP since its conception and today offers subscribers access to equipment, planning support, exercise assistance and training services as well as facilitating the Global Subsea Response Network (GSRN) to enhance well response capabilities for the industry.
Behind the project's success:
Speculating why the project was chosen by the judges, Myers commented, “This award recognised delivery of SWIS equipment and quite rightly so. That was a huge milestone for the industry. But there is a journey that everyone is on in order to ensure that they are maintaining the response readiness. We are collaborating not only with those members and subscribers but also more widely with companies that we work closely with to help provide a comprehensive service for the subscribers.
“We helped to facilitate the Global Subsea Response Network and participants in that help to provide the comprehensive service. Some of the key participants are; Wild Well Control, the OEMs of the equipment such as Trendsetter Engineering and Oceaneering; and other companies such as Wood - all recognisable names. But we helped to facilitate access to all of those resources to ensure; a comprehensive integrated planning service; to be prepared; but also, in a response, the access to the resources that would be needed.
Why recognition was significant:
When asked what the recognition meant to OSRL, Myers said, “Collaboration is at the core of the company’s business. We are a member owned company and consortium. It really is part of our basis and part of our premise. We are not a traditional commercial organisation. It is good to be recognised as it re-iterates the purpose of our company and why we exist which is to help facilitate that collaboration and ensure everyone is ready to respond if required.
Lessons learned from 2020:
2020 has been difficult for everyone and has thrown up challenges that simply could not have been foreseen this time last year. Myers acknowledged a similar story within his company but preferred to look at the positives, noting that such times opens opportunities and there is now a chance to use the tools that have been developed to embark on a more positive approach moving forward.
Looking ahead to 2021:
A postiive outlook is at the heart of OSRL’s plan for 2021, and Myers concluded, “Into 2021 the key focus area for our subsea business is really related to the global subsea response network and we want to do more to formalise that. We want to do more work to promote it so the industry understands its capability and we hope to grow it in specific areas. We want to look at how that network delivers integrated planning services and a comprehensive response for the industry.”
As the oil and gas industry struggles to mitigate the economic damage caused by COVID-19, voices across the sector have suggested that increased collaboration will be vital for recovery in 2021. Receiving the OWI Award for Best Example of Collaboration has therefore come at a significant time, with the judges labelling the SWRP project as ‘huge for the industry’, and hopefully this will set a precedent that will lead to more cooperation in the future.
After claiming the prize for HSE Innovation at the OWI Global Awards 2020, Kristell Nygård, Operations Manager at TIOS, spoke with Genoa Black to discuss the resounding success of their Transfer Hose Hang Off Unit and their plans to build on this in 2021.
In combination with a Stimulation Vessel the Transfer Hose Hang Off Unit has proven to enhance safety, efficiency and operability during Riserless Light Well Intervention operations. Nygård noted how the new hanger system, in action this year, had eliminated a whole range of problems that were experienced on previous campaigns. These include; the use of crane operations (which required time); human presence on the hose hanger system (where previously engineers had to climb up the hanger system); and repeated connection and disconnecting of pumping lines (now just one connection is needed with testing only required each time the vessel arrives onto the site).
The system also allowed control of operation from a safe distance (with the option to use the control panel so people do not have to be close to the equipment); increased distance between the two vessels; and it also significantly extended the weather operating windows for operations resulting in a saving of approximately 18 hours per well.
On what separates the unit from the rest of the market, Nygård commented, “It is the manual handling that is reduced to a minimum. It is also a great wholesale unit that you can replace anywhere. As it has a small footprint, you can put it on a fixed platform on any vessel you like.”
Nygård also spoke on the importance of recognition, “It is good that all the teamwork we are doing is getting recognised as TIOS is a small company. We are trying to come up with new great ideas to make well intervention jobs more achievable in days instead of weeks. We like to do things faster, better and with increased operational ability.”
“We had a challenge when oil prices dropped. Well intervention is more about contract to contract, when the price goes down sometimes companies pull out of contracts and the jobs stop. It was a challenging year but we have achieved more and more,” Nygård added and thanked the continued support from companies within the sector.
Concluding, Nygård looked ahead to 2021, “We have now gone into business with the same oil company and the same equipment to perform one more acid job this year. We are going to stimulate two more wells for the same company. Also, this time we will be able to pump balls through the system for the first time enabling us to do more with the new hosing system. The same company would like us to perform more of the same job next year so actually this gives us more jobs. For the hose hanger system there are other companies who want to use it as well.”
The Transfer Hose Hang Off Unit was a worthy winner of the OWI 2020 HSE Innovation prize, marking a notable advancement in safety and operability for the industry, and it appears that TIOS has every intention to build on this success as it heads into 2021.
The Helix Intervention Tension Frame (ITF) was implemented after Helix Energy Solutions approached OSBIT with a well intervention problem; how to deploy tools safely from a vessel.
OSBIT responded with a tension frame that is constrained onto a vessel so that it slides only vertically with the craft allowing them to establish a walk-to-work system and allowing a relatively large ITF compared to the vessel. The ITF has three platform levels, is accessible via a telescopic gangway and removes the need for engineers to use rope access systems. This means that from a relatively small vessel, a suite of tools can be exchanged without having to come off the well in addition to the swift manoeuvring of personnel.
With the ITF, Helix vessels productivity is greatly enhanced, with crews able to quickly access the wells, use the tools they have, and move from well to well and tooling suite to tooling suite safely and effectively. This ensures that the right people are at the right equipment at the right time, and that maintenance can be carried out as swiftly as possible.
In use on Helix Siem vessels in Brazil the integrated system is field tested, with noticeable benefits such as reducing the time taken to switch between wireline and coil tubing operations (and back again) from days to just a few hours. It has also had a marked improvement on safety with the Siem Helix 2 recently completing 500 days without an LTI.
David Carr, Senior Vice-President of International Development at Helix Energy Solutions commented, “The three ITFs that were built for us by OSBIT have had an outsize effect on increasing the safety and efficiency of our most recent three vessels. Just being able to switch operational modes to go from wireline to coil tubing in a manner of hours is saving our customers significant rig time. More importantly they provide a safe compensated platform for our crews to work at height and because of that we have been able to completely eliminate man riding from these vessels. We are extremely happy with the safe working environment that the ITF brings to Helix.”
For the ITF project, OSBIT was shortlisted for Most Innovative Solution at the OWI Global Awards 2020, capping a positive year for the company despite the pandemic. At the start of the year, OSBIT was awarded a contract by FTAI Ocean, a subsidiary of Fortress Transportation and Infrastructure Investors LLC, to develop and construct a new well intervention tower system and has also recently appointed Robbie Blakeman as joint managing director to reflect the ambitions of the company as it seeks to continue its success and growth into 2021.
See the latest well intervention training from Seaflo and understand how this can increase your project efficiency
If you’re intervening, generally something’s wrong and it’s only going to get worse unless you do something about it. Is there something in the very name and nature of well intervention that is undermining its true potential in the North Sea and the wider global market? Let’s explore why interventions typically take place, what is done and what could be done differently.
By Simon Sparke – International Well Integrity
From a well integrity perspective, there have been several key and defining events have shaped the oil and gas industry in terms of how we construct wells and then monitor and test for operational reliability and regulatory compliance.
Perhaps one of the most significant components was the introduction of the ‘surface controlled sub-surface safety valve (SCSSSV)’.
The history behind this critical well component is very interesting and here is what I have found so far:
It is generally a requirement of many regulators that SCSSSV’s are fitted to wells in a wide range of locations and well types. However, due to the allowable leak rate criteria of 15 SCF/Min, some regulators and operators do NOT accept this piece of equipment as a barrier, though if used it will significantly reduce flow.
It has become part of the periodic testing requirement and for many years now the reliability has improved significantly. Broadly speaking, the valve is a flapper and not a ball valve and is run as an integral part of the completion (tubing retrievable) or they can be wireline retrievable.
While it is not my place to make recommendations about which type of valve to run, there are a range of reliability databases available that will help an Operator make that decision.
My recommendation is that when looking to identify which SCSSSSV to purchase and run, consider several factors -:
Finally, once purchased and before this tool is run, determine the hydraulic signature of the valve. This will provide invaluable support data when trying to diagnose problems.
North Sea oil and gas operators are failing to make the most from their existing well stocks, with some 30% (600) shut-in and 33 million barrels of oil equivalent (boe) lost due to well losses – the equivalent of a new west of Shetland field.
The figures, from 2017 but reflective also of 2018, were presented by Margaret Copland, senior wells and technical manager at the Oil & Gas Authority (OGA) at this morning’s Offshore Well Intervention Europe (OWIE) conference in Aberdeen.
Restoring shut-in wells can add production at economic rates said Copland. According to the OGA’s data, 22 million boe of production was added in 2017, through intervention operations, at an average well restoration costs in 2017 averaged just US$6.4/boe. “That’s an amazing rate of return,” Copland told the event, which continues tomorrow. Yet, well intervention was carried out on just 14% of wells in 2017, she said. “We need to think about these wells in terms of economics. Given that 30% of wells are sitting shut-in – that’s not wells that are in cessation of production (COP), it’s 30% of the active well stock – there is something wrong with a 14% intervention rate. We should be at 30%, trying to get these shut-in wells online, assuming facilities can handle it (eg. water handling etc.).”
The biggest cause of shut-in wells is integrity issues, which drove 45% of intervention operations in 2017. The second biggest is water production, either being too much and choking off hydrocarbon production or there not being enough capacity to handle the water topside, said Copland.
Production losses, which amounted to 26 million boe in 2015, 37 million boe in 2016, and 33 million boe, hasn’t seen an obvious trend, said Copland. “33 million boe is the equivalent of a big field west of Shetland,” she said. “That’s the potential. These well losses are not an issue with compressors or pipelines, it’s issues with wells and we are not seeing this being addressed. We are not sure that the industry knows at a granular level what’s causing these losses. Some are obvious: wells falling over and nothing being done about it, but that’s not the majority of losses. We are often asking if they understand their well losses, are they doing failure mode analysis, what are they doing to prevent it happening and we are getting a lot of blank faces.”
A big concern is the lack of well surveillance. Operators appear to not be doing enough to learn about what is happening in their wells. The rate of well surveillance work was just 8% of the active well stock in 2017, despite a large prize that could be had by doing well intervention, Copland said. “I don’t know what that number should have been but 8% is too low. We need to increase surveillance. The amount of data gathering going on is abysmal. Many companies have performance standards for data gathering, but how many have met it? I think not many. Without surveillance data, without going in to get data, without using new technology like the logging on fibre line, we cannot make the business case to make these projects work.”
John Hand, Technology Program Manager, Conventional Assets, ConocoPhillips, agrees. Opening the second day of the OWIE conference this morning, he said that, for the US onshore conventional business, increasing production rates, “is a big data problem and all you have to do is get that data and get it in a form people can look at across disciplines. In the Eagle Ford (play), we used data analytics to cut the time to drill in half over four years.” At 22 days per well, drilling teams had said they were at their technical limit. That time was reduced to 12 days and then seven days, over a four year period, Hand said.
Shut-in wells that are not going to be brought back online should be abandoned instead of left until cessation of production for abandonment work, added Copland. “It would be more economic to do something to isolate the well and preliminary log well before that,” she said. “Maybe an operator will be short of trees, they could get a tree off one of these wells and get it turned around ready for the next time a tree falls over. Waiting until the end of field life doesn’t help anyone.”
The bigger picture is a UK North Sea that’s largely mature but still with remaining potential. Some 7500 wells have been drilled in the UK to date, with 44 billion barrels of oil produced. More wells are now being plugged and abandoned than drilled, and exploration drilling is at an all time low. But, production efficiency in existing fields has been improved, new seismic data is being shot, and “Elephant fields” could still be found west of Shetland, said Copland.
Improving well intervention and increasing production could help push back COP dates and extend the life of the UK Continental Shelf, she said. To aid that drive, Copland says the OGA is close to finalising a wells strategy which it will then use to question operators on their own activities to make sure they’re doing all they can. This strategy was due to be published by the end of Q1 2019.
We are pleased to announce that the Oil and Gas Authority will be speaking at OWI EU 2019 for the first time and are allowing us to distribute their latest Well Insights report to our audience of well intervention experts.
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