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.
Offshore Network have created a 2018 Market Forecast. The whitepaper, titled 2018 Market Forecast: What does the oil price mean for well intervention? Highlights the likely path of the oil price throughout 2018 and the correlating well services which will be in demand. The paper includes a forecast of the Brent and WTI oil price throughout 2018, an overview of the uplift works operators can utilize to take advantage of increased oil price and an analysis of why P&A activity will still increase in 2018, even when a higher oil price makes more fields economic.
McKinsey & Co deliver a presentation regarding the value of North Sea well Intervention.
The North Sea is a mature basin, and as with all mature basins the lack of drilling activity over the past 18 months has placed a greater demand on old assets to maintain or increase production levels beyond their initial design life. This inevitably raises many questions about well integrity and asset life extension.
By NORSOK D-010’s definition well Integrity is the “application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.” In order to assure integrity, comply with regulations and increase recovery volumes North Sea operators conduct regular well intervention campaigns to improve, or at least maintain, the productive life of fields in the region.
It is worth mentioning that well intervention as a subject is more inclined towards OPEX engineering work on live wells, including activities such as logging, slickline, coiled tubing, structural maintenance and other workovers to name a few. Well integrity begins at the design phase of the asset, from selecting a completion design, tubing grades and sizes, detailed assessment of reservoir fluids, testing & commissioning and complete well surveillance throughout the lifecycle of a well. Hence, well intervention and integrity activities are multidisciplinary and require excellent communication, working standards, design, engineering and a live status of the well’s behavior.
As the fields are maturing there is a natural decline following the production plateau, requiring additional applications such as Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) to maintain the profitability of the reservoir. It is anticipated with aging wellstock on rise issues such as declining structural integrity of wells will increase. Thus requiring preventative maintenance activities will increase such as diagnostic logging, tubing retrieval and well platform remediation will be unavoidable and necessary.
All of this demonstrates that there is a slow but steady growth towards an increase in well intervention and remediation activities. Whatever the objective is, be it production enhancement, structural assurance or both, integrity and intervention have a common goal – extending the asset’s production life.
Currently, 70% of global Oil & Gas recovery comes from mature fields, but as production decreases on average by 7% year on year, there is significant pressure placed on our mature assets. Significant advances in the technology used for extending production life have greatly contributed to the vast amount of stock outliving its intended design life. A good example being advanced diagnostics that help operators identify wells that are prone to corrosion, fatigue, and abnormal movements. In the long run, regular preventive maintenance serves to be the best option for keeping old assets online and profitable. Structural Integrity and Good Practices
Two main types of well platform construction can be considered for simplicity; the well can be built on the conductors (i.e. the conductor is the structural pile in the well) or built on the surface casing support, (i.e. the surface casing is the structural pile in the well) where the conductor acts only as a marine protector.
Both types are prone to corrosion with each having advantages and disadvantages. For instance, oxygen is more prevalent in casing supported wells because the D-annulus is more exposed. Other sources of corrosion include having a low-pressure seal, having a barrier to atmosphere and seawater acting on the outside of the conductor, but it is noted that casing support wells are less prone to seawater corrosion as conductors act as protection Also, drill fluids (seawater) exist in the seabed and do improve hydraulics, however, the conductor’s joints are below sea-level, and the tidal range in D-annulus gets constantly corroded due to wet and dry cycles, which is a catalyst for corrosion. The installation of debris caps in conductor supported wells seems to be harmless but creates additional corrosion problems due to condensation loops resulting in wet and dry cycles, which in turn results in accelerated corrosion just below the wellhead.
Offshore well structures and related problems, including corrosion, raise issues on how to assess and quantify structural integrity. A process to rank issues based on severity, risk, and opportunity is critical. To effectively execute this process there are four key steps to help you develop a proactive preventative programme to aid the life extension of your assets:
Once the stress conditions have been corrected you have all the most important information to select the most appropriate and efficient remediation methods for low severity and medium severity assets, for example:
Regardless of selecting the appropriate action across your assets, the main takeaway is that best practice is to investigate your wells early, identify and repair critical wells, implement preventive measures to save from developing issues, schedule monitoring, and generic studies. This offers a cost effective approach to life extension and pays off in the long term, as even though you may have to shut in wells for longer during routine inspections, you will identify remedial works and opportunities that you may or will have to address later on and outside of the inspection window. If you work outside of this window you will inherit additional cost and risk dealing with a significantly more challenging project which could have been avoided if the identified symptom was rectified during the inspection.
Preventative and maintenance workovers are more cost-effective in the long run than replacing a failed barrier. It is interesting to note that the oil & gas industry still has differing standards and opinions on barrier definitions, technical interpretations and so forth, but evolving nevertheless. Due to the nature of well integrity being diverse and multidisciplinary, there is a huge demand for entrepreneurship in developing shared management systems to keep the status of well stocks up-to-date. From the operator’s point of view, well integrity is somewhat process-oriented since there are hundreds of active wells and multiple teams working together. This can be leveraged for additional efficiencies. It is necessary to develop an effective relationship between data and inspection to offer a robust, proactive and cost effective integrity programme that supports asset life extension and reduces expensive and complex critical works and rig based activity, which could have been avoided.
While well intervention spending has been hit harder than average industry cuts, the opportunities are still there to be had, not least from mature North Sea assets, delegates at Offshore Network’s Offshore Well Intervention Europe Conference heard this morning.
But, companies need to have the right attitude, processes and resources in place to get what could be double digit percentage increases in production that could be achieved. They also need to increase well intervention intensity and use a broad range of tools to benefit the most, says Dan Cole, General Manager, Energy Insights, McKinsey & Company. Setting out the industry context, Cole says: “We have been at $50/bbl or so for a year, more or less, and there are signs investment is starting to pick up. But it is hard to ignore the backdrop. A third of the cost has been taken out of the sector since its peak in 2014. Spending levels are the same as they were seven years ago. North Sea well maintenance spending has seen an even greater decrease, down 43%, from $1.3 billion in 2014*. Could it be the opportunity is not there? Absolutely not.”
To see what exactly the opportunity is, McKinsey looked at various metrics. One was the number of shut-in wells, relative to their maturity, measured by water cut. “There are more shut-in wells as fields become more depleted and have higher water cut,” he says. “One in five depleted wells are shut-in, some permanently. But if some could be restored to a level similar to [comparable] onstream wells, you could very quickly get some good production numbers. From a rough calculation, you could get to a couple of hundred thousand barrels of oil equivalent a day production [across the North Sea].”
Another metric McKinsey looked at was production losses, i.e. maximum production capacity compared with actual production. The losses are split into two categories: reservoirs losses, i.e. where a well is not producing as expected, maybe due to mechanical impairment, sand inflow, lack of pressure support, etc.; and losses incurred due to well work, i.e. testing and intervention work.
“From 2008-12, the amount of losses incurred increased year on year and peaked in 2012 (partly driven by the Elgin Franklin well control incident),” Cole says. “Since then, every year has seen fewer losses. The share of the losses has also moved from reservoir losses to losses due to well work [i.e. testing and intervention work], which is encouraging to see.”
The industry also knows more now about what better well work and reservoir management looks like, through more experience and benchmarking. Examples can be given which show that when two operators with similar assets are compared, the one which performs more interventions and with a wider range of intervention tools and techniques sees greater production increases than the other.
McKinsey compared two such operators, one who intervened in one in 15 wells and the other one in three. The second had 9-10% increase in production, compared with 2% on the first. “Consistently, operators with higher levels of intervention and production use a broader range of intervention tools,” says Cole. “Add a broader range of tools and more intensive intervention levels drives overall better performance around well intervention and reservoir management.”
By seeking additional recovery, restoring shut-in wells, improving reservoir management, increasing the ratio of water injection and doing infill drilling (increasing the number of wells per reservoir), could bring $70-350 million additional returns in the first year, says Cole, according to studies by McKinsey. Cole says he’s been talking to operators recently which have been getting 5-7% increases from wells that are years and even months from their cessation of production date.
Previous work the firm has done has shown that well intervention can give higher – and faster – rates of return on investment. “We found, as a portfolio activity, intervention stacked up very well against drilling on payback time and also on over all returns, at about 1.5 X better then drilling,” Cole says.
McKinsey has also looked at the difference between companies with successful intervention programs and those that are less successful. “Typically, the difference between the good and the not so good are; differences in technical system, i.e. the process side; the organisation and how it is organised; and the philosophy or attitudes towards the activity,” Cole says. “Making sure there is a process in place, identifying the opportunities and getting them through the operation, performance tracking and a good way to transfer knowledge between jobs that go well and those that fail,” all help to put the process in place, he says. “It also matters, having an organisation lined up around this and you need clear responsibilities, key performance indicators and targets as resources – cash and capability. It is also important that they [decision makers] understand this is a core part of the business and considered at the top level. We know some interventions fail and some are extremely successful. The success rate overall is more than 50%, but people remember the ones that fail. That needs to be challenged.” Poor plant reliability and poor execution of interventions also results in poor performance in this area he says. “To get this activity humming, you need all of the cogs to work,” he says. The North Sea industry could also learn from outside Europe, including the way onshore North America operators “ruthlessly” approach their wells.
Offshore Network’s event, being held in Aberdeen, continues today and tomorrow.
*Based on data from across 50 assets in the Norwegian, UK and Danish sectors of the North Sea.
During a routine test, a major operator in the Danish North Sea determined that a Sub-surface Safety Valve (SSSV) of a well on an offshore platform would not successfully perform a routine inflow pressure test. The operator believed this was due to scale buildup in the upper completion.
Two separate interventions were attempted using conventional chemical and mechanical methods, but these failed to re-activate the SSSV. The operator had heard about electro-hydraulic stimulation (EHS), which can break up scale using shock waves and pressure pulses. The operator decided to mobilize Blue Spark’s WASP® technology, with its ability to remove scale from complex downhole completion equipment items, without risking any damage to them.
It was also decided to acquire a multi-fingered caliper log through a section of tubing to confirm the build-up of scale, then treat that scale, and lastly run the calipers again after the WASP® treatment to validate the removal of scale.
The post-treatment caliper log was then acquired, confirming that the scale was removed from the tubing (see figure at right). The scale was approximately 0.36 inches thick.
Hear David Smith of TAM International discuss how sometimes inflatable technologies are the only option – including when and where they provides a cost effective P&A or intervention solution.
Page 8 of 9
