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
The TITAN RS System - Combining our field proven BHA Systems with a Ardyne developed resonance tool to aid casing recovery by reducing the pulling force required to free stuck casing. Successful trial wells have been completed recovering casing encased settled solids.
View our introduction video below - To find out more about the TITAN RS System please contact us.
Ardyne’s toolbox approach creates a 62m window for open hole sidetrack, saving 14 days planned rig time
Gain insight into how to create a best practice Well Integrity Management System (WIMS)
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.
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.
A case study by 3M explored the issues caused by sand production and tested their ceramic sand screen against a utility disrupted by this problem
Many factors such as the strength of a reservoir, cementation and reduction in pore pressure, fluid viscosity, and drawdown can all induce sand production. This can cause damage to downhole, subsea and surface equipment and can even lead to catastrophic failure. Production engineers across the industry have grappled with this potentially serious problem with solutions focused on reducing wellbore stress, improving consolidation, or transferring stress to some form of mechanical retention.
3M have recognised this issue, and have developed a ceramic sand screen as a solution. They have released a case study to test their product against a facility restricted by sand production:
The Challenge:
At a facility in the Caspian Sea, due to reservoir depletion, the operator was forced to restrict flow rate in order to achieve sand-free production. Without sand control already in place, the operator sought a cost-effective retrofit sand control solution to assure desired production rate in a high flux and impingement velocities environment.
The Solution:
The ceramic sand screen solution was speced-in to a given wellbore restriction and to set across the perforation zone using a rigless deployment technique. The coil tubing unit was utilised for wellbore clean out and subsequent deployment of the screen BHA in 2 runs.
The Results:
The case study demonstrated the applicability of ceramic sand screen as a stand-alone screen solution in unconsolidated, poorly sorted sand with nearly 30% fines content. The industry rule of thumb would have led to complaint sand control techniques adding complexity and cost. The operator achieved his goal of increasing production through a cost-effective retrofit solution deployed on coil tubing. Sand control was maintained at a higher drawdown so that within 5 days the equipment was paid back based on incremental oil production.
A strong collaboration and team effort between the operator, coil tubing service provider and 3M as a technology provider, enabled a cost-effective approach to achieve sand free production and unlocked the production potential from a challenging offshore oil producing well.
Visit https://multimedia.3m.com/mws/media/1903939O/3m-ceramic-san-screens.pdf to find out more.
In our previous article, I promised to address the doubts of the readers around the material that could be placed in the hole as a barrier for plug and abandonment, and whether those materials differ depending on time span defined for the barrier’s life.
I gave you a spoiler when I told you that cement IS NOT the only material for well abandonment. So now, let’s dig further into the matter.
This article was originally published 25. October 2017 by former Wellcem employee Miguel Diaz. An updated version is republished now by Svein Normann, in order to introduce this important topic to our new blog readers and followers since then:
Hopefully, you all remember that we defined the Gulf of Mexico (GoM) and the North Sea as the two more relevant places regarding the availability of detailed and comprehensive legislation that addresses the well abandonment process.
Moreover, we gave special attention to the UK offshore oil and gas organization (UKOG) (https://oilandgasuk.co.uk) series of three documents on well abandonment practices. They include a “Guideline on qualification of materials for the abandonment of wells.”
It was issued in 2012 and reviewed three years after with contributions from experts from Shell, the University of Dundee, ConocoPhillips, SINTEF, TNO, Schlumberger, BP, Chevron, ExxonMobil, Los Alamos National Lab, Sandaband, Halliburton, Baker BJ Services, TOTAL, Raw water and Wellcem.
Read also: Our cases “Collapse in the tubing and casing” and “Plugging a well with no mechanical integrity“
TEMPORAL OR PERMANENT IT IS ALL THE SAME
When we place barriers in the well to isolate formations from each other and the surface with no intention to ever re-enter the abandoned part of the wellbore, the abandonment is considered a permanent one.
Where there is an intention to re-enter, we call it temporary abandonment (typically a matter of months). Besides the timeline of the application, the only other difference between permanent and temporary abandonment is that a temporary barrier is not required to extend across the full section of the well and include all annuli.
Other than that, a temporary barrier must fulfil some functions, which we discuss below, and they do not differ from those of permanent barriers, except possibly for a relaxed timescale of required durability.
FUNCTIONAL REQUIREMENTS OF PERMANENT BARRIERS
Again, the UKOG guideline defines the requirements for a well abandonment barrier to be successful, those are:
1. Sealing
A leak is a breach of integrity which passes entirely through the barrier. Such a gap can take the form of a crack or channel and may be present from the start of placement or develop over a long or short period. Failure can occur due to debonding, dissolution or cracking.
The primary function of a permanent barrier is to provide a seal against leaks. But, the curious thing is that the guideline considers inevitable that fluid within the well will ultimately migrate past a barrier, albeit at a low rate.
Thus, appropriate barriers are those through which the rate of permeation is acceptably low. The approach taken is to require that the barrier permits leakage of fluids at the same or a lower rate than the caprock. The permeability of caprock is typically within the range of 0.001-1 micro Darcy.
But from historical industry experience, barriers of 30m (100 ft) of “good” cement (usually with a permeability of 10 micro Darcy) are performing to a level satisfying the oil and gas industry.
A maximum permeability of 10 micro Darcy has then become the acceptance criteria for the qualification of a cement barrier of the sort discussed above. If permeability is lower, a shorter barrier may be installed. Longer barriers could be used for more permeable materials.
2.Position
Once placed, the barrier should not move, either along the wellbore or in a lateral direction. For instance, the barriers should not be pushed upwards by pressure developing below. The barrier materials are required to remain attached to interfaces to where it was installed.
Materials used for P&A should pass shear bond stress tests demonstrating what delta pressures are needed to extrude the materials out of a cylindrical cell that mimics a cased well.
3.Placement
The permanent barrier material should be easily placed in a wellbore at the desired depth and perform as required. Therefore, it should have appropriate properties that allow it to displace the existing fluids and form a continuous sealing medium, even when considering its inevitable contamination.
Where a barrier material undergoes a transformation from liquid to a solid, this period of change must be sufficiently short to prevent an escape of fluid and unacceptable disruption of the barrier.
Verification of the barrier placement must be possible even in deviated wells.
Read more: Lab tests to review when designing a “gas-tight” cement slurry
4.Durability
The barrier material should not degrade such that its sealing capabilities or position are compromised. It should be able to withstand wellbore changing conditions for ages.
5.Removal and reparability
Being removable is a fundamental element if the abandonment was a temporal one. The barrier should be easy to remove with existing conventional industry methods (drill bits, mills, acid, etc.). Also, if a leak through a barrier would develop, there should be a method to remove/repair it to regain integrity.
6.Operating conditions
After placement and activation, the permanent barrier material will have to withstand external loadings that could vary with time, among those are:
MATERIALS
Having read these expected requirements for a material to be considered a qualified abandonment barrier;
Cement is currently used in wells as the prime material for abandonment purposes because it is found to have similar properties to the rock that it is replacing. However, given its operational limitations, alternative materials, which offer significant advantages over cement, are being proposed and developed by the industry.
These substances, however, still don’t replace cement. That’s because – when compared with cement that has been used for hundred years or so – uncertainty with regards to long-term integrity of the alternative materials acts as disincentive for their use.
The legislation, as reviewed last week, also play a role in the incentive to use cement for P&As; some countries refer only to cement as abandonment material in their legislation, while some others ask for an abandonment material to be “equivalent to cement.”
The UKOG guideline for qualification of materials then defines (see table above) a list of materials that offer characteristics that meet all the functional requirements for permanent barriers that we reviewed above.
I will give you a summary:
INTERESTING CASE STORIES
From the list, the two that have made more advances in recent years are Thermo-setting polymers (Group C) and the modified in-situ materials (group J).
This last case particularly refers to “Melting the cap rock,” which consists of using a thermite plug to seal off the well by melting both the well components and the rock formation around them to recreate the cap rock.
This method was trialed in 2016 by Centrica in Canada claiming it could potentially reduce well P&A costs by more than 50%.
The Thermo-setting slurries have been around for a slightly longer time. Once introduced, it was evident that resins have a lot to offer. Using the “requirements for permanent barriers” as a checklist – and with a comparison against cement in mind – the resins have:
In 2012, the first couple of cases of bull-heading abandonment were documented in the Gulf of Mexico (Charpiot & Jones, Offshore Magazin, May 2013). In the first one, a weighted resin with low-viscosity was used to abandon a well due to its ability to be placed with minimal injectivity and yet provide high-compressive strength after setting. The well represented a closed system because the platform sheared away during a hurricane.
The same year in another Gulf of Mexico-well, bubbles were coming from the annulus after an initial cut on the casing. In this case, the resin was used in a squeeze application, stopping the annular leak. Subsequently, a 50-ft (15-m) resin plug was set. The resin had a low yield point, and due to its ability to be formulated free of solids, it penetrated small cracks and micro-annuli without the risk of particle bridging.
In March 2016, the Gulf of Mexico’s first lower abandonment using resin took place. Because there was a downhole obstruction, the operator of this particular field determined that it could not reliably carry out a lower temporary abandonment with cement. Cement could have separated or dehydrated under tight spaces in the restricted flow paths, whereas resin would have had no such issues. In this particular case, dual-coiled tubing risers were used to deliver fluids from the waterline down to the mudline.
In June 2017, another interesting P&A operation was carried out in the Middle East, with a thermos-setting polyester resin. The well involved was drilled in November 1979 and in April 2017 it developed 1,100 psi of sustain casing pressure in the 4½” x 9⅝” tubing-casing annulus (TCA). At the same time, the H2S Rupture Exposure Radius (RER) for the well was reported as 63 meters to the half “Low flammable limit” (LFL) and 1049 meters to the 30 ppm concentration threshold.
As per client definition, a well is located in a populated area “if the population exceeds 20 persons residing, working, or otherwise located within the 30 ppm rupture exposure radius (RER)”. In this case, significant civilian’s structures existed within that radius; a Highway at 524 meters and a hospital at 786 meters, for instance.
The ultimate goal of the workover operation was to re-complete the well running a 4-1/2” liner inside the 7-inch liner (covering the existing perforations). But before a rig could move in and remove the existing completion, the integrity of the well have to be re-gained taking into consideration the limitations given by the pressurized annulus, H2S levels present on the formation and the well surface location.
The operation was set to be done with a 1-1/2” Coiled tubing giving the ID restrictions of the 2-7/8” completion tubing in the well. Resin was chosen as the barrier. The low viscosity allowed lower pumping pressures while placement, and the solid free nature enabled maximum penetration during the squeeze operation. (1,000 – 1,200 psi pressure limitation set for the job due to casing conditions).
Nine and a half barrels of an 88 pcf thermo-activated polymer resin was spotted without inconvenience.
The resin plug was then pressure tested and milled allowing the well to be circulated with full returns and a new 4-1/2” liner cemented in place.
The job was a success proving resins can be used for P&A and, also, it can be placed safely with one of the smaller available coiled tubing pipes in the market.
By Svein Normann
Svein Normann has a MSc from the Norwegian University of Science and Technology and 27 years’ experience in the oilfield. 10 years in field operations as cement operator, design engineer and operations manager. Further on 16 years in oilfield equipment engineering and development. He is today working as VP Global Operations & Technology at Wellcem AS.
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