Marie Morkved, Head of Production Technology from Maersk Oil, presents a case study of a recent well intervention using coilhose technology, noting how it allows deployment with slick line equipment but still enables pumping to offer flexibility and efficiency.
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.
McKinsey & Co deliver a presentation regarding the value of North Sea well Intervention.
Zach Ruslan, Senior Production Technologist from Dong Energy, delivers a case study which evaluates the lean processes used to establish a technically viable sand management and downhole evaluation solution.
Prolonged challenging market conditions have posed existential threats to operators, contractors and in the case of the North Sea, arguably, an entire basin. The severity and rate of market deterioration has made deep blanket cost reductions an imperative of survival, with little scope to consider more surgical approaches. However, as an impending potential market recovery, performance improvement and efficiency gains begin to appear, it is critical that measures taken to-date are carefully evaluated to ensure gains are sustainable and present a sound basis for long-term value creation for all stakeholders – operators, contractors and investors alike. For example, in February, Statoil said extensive cost cuts had brought the breakeven cost of projects set to start production by 2022 down to $41 per barrel from the $70 seen in 2013. There are initiatives in place to further improve this, but the question remains how much is attributable to margin pressure and how much is truly sustainable, structural, cost and performance improvement.
Despite the ongoing oversupply across much of the depth and breadth of the supply chain, the temptation to excessively leverage this to further reduce costs should be resisted. Any additional short-term benefits of this approach are far outweighed by the potential long-term damage this may do to the supply chain and ultimate impact on future supply and total life-cycle costs. Instead, by focusing on establishing more meaningful partnerships with contractors where risks and rewards can be shared, opportunities exist to develop sustainable structural cost savings through a collective focus on operational excellence and efficiency. By taking more integrated approaches to working and aligning the incentives of operators and contractors, the full benefits of standardisation, cross-functional optimisation and decision streamlining can be realised.
In more practical terms, to ensure cost savings can be sustained in the longer-term and real value is created for shareholders, operators must:
At OFS Partners, a particular focus of our work with oilfield management teams (and oilfield service sector investors) is to help them better understand the needs of operators, improve their chances of success in procurement processes, and ensure products, services and precious R&D spend best positions them to deliver value to operators and create sustainable competitive advantages. Through this work, we consistently discover significant disconnects between what operators’ requirements, objectives and preferences are and how the supply chain in general is seeking to provide solutions. Resolving such misalignments in understanding is crucial to developing long-term sustainable cost improvements, and determining the winners and losers in the downturn.
To increase the likelihood of being a beneficiary of understanding gaps and current market disruption, contractors should:
Macro market uncertainty and difficulties identifying attractive actionable investment opportunities has led many investors to either de-prioritise oil and gas as an investment theme altogether or take an approach of waiting until there are clear signs of a sustainable recovery in progress. Nonetheless, significant opportunities exist, particularly in market segments where the focus on cost reduction and performance improvement by some businesses is creating substantial market disruption by challenging conventional thinking with alternative solutions. Investors can best position themselves to create considerable value by leveraging a deep understanding of structural industry changes and how micro-market recovery expectations vary across the sector. In this regard, OFS Partners are actively working with investors to make timely and intelligent investment in new opportunities or building cases to deploy growth capital to safeguard the market positions of existing investments.
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.
I spent this week in Aberdeen with a group of operators and contractors who are pro-actively addressing well integrity challenges across their existing assets. The group’s well stock, conditions, technologies, geology and countless other elements separated them, but as time went on we managed to find one piece of common ground…
I’m sure you’ve heard this before, but according to Norsok D10 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. Wireline, slickline, coiled tubing and other innovative solutions can help you check out what is going on in your well – but let’s jump back a step, as whether you’re dealing with a shallow platform in the Southern North Sea or a deepwater subsea asset West of Shetland, the first piece of information I was given was universal…
“The well’s life and integrity starts when the pen hits the paper and the well is designed”
…and so on.
Not being an engineer, I won’t pretend to fully understand the implications of the above – but from the inception phase it is imperative to develop a constant and consistent well surveillance plan for the future to ensure monitored and managed integrity from the get go and offer visibility for future crews who will have to work on it. Throughout the week I learnt that this was sometimes the case, sometimes it was not, and sometimes the current operator was the Xth person to own the well and all the documentation was lost. It reminded me of my first car! Perhaps it’s because I’m writing this at the end of 2016, after two years of sub $50 oil, but whether for production efficiency, structural assurance, or barrier verification, the end goal for the majority of operators also remained the same as my first car… How can I get more performance out of it and can I make it live past its life expectancy?
I owned my first car for almost ten years. It was a twenty-year-old classic Mini with a lot of miles on the clock. Ahead of passing my driving test I had managed to locate a modified engine which had been bored out to 1440cc, along with a performance manifold, induction system and straight through exhaust. It went like a rocket, but the car was ultimately a great engine in a light old rusty frame. The issues I was had with my old Mini ‘Bertie’ was similar to the relationship that the Aberdeen group had with their wells. Somehow rust bonded us and Bertie got me in the conversation.
The discussions of our group focused on both old and new wells. One person talked of a young three-year-old well that had three corroded joints. There was a change in the internal diameter profile at each joint as the well was constructed with alternate grades of joint, resulting in varied levels of corrosion at different depths. Another member of the group said they had realised a 10% metal loss in just a few months – his ESP had over heated resulting in tubing leaks and fluid circulating without getting to the surface. The general consensus of how to best deal with corrosion was through a robust scheduled monitoring programme to provide an appropriate understanding of the completion integrity status. Then one member asked the big question “what is good integrity?”. A great question… At what point is the level of corrosion “good” and at what point is it “bad”? If it is in line with regulations, does that make it good? The discussion circled but no real consensus was met – it’s dependent on the well, here are too many variables to universally apply “good” to everything, or anything.
Getting Bertie through the MOT was always a problem. He was full of rust and I was constantly welding and replacing panels to keep him certified as safe for another year of motoring. I always went to the annual Mini owners club meet and we talked about rust, as you do. My sils, door skins and floor pan were in bad shape – but somehow the car was deemed safe and road legal. I once met a guy with a 1975 Austin 1275 GT with a 1.8 Honda Civic engine replacing the original motor. This car was dangerous. Not solely due to the engine, but because to avoid corrosion issues he had cut out huge parts of the floor pan, replaced them with plastic and then painted and covered them with metal fillings – when the MOT inspector used a magnet to test the floor it appeared there was a significant and safe width of metal. There was none! The result was a false positive, but nevertheless this dangerous car was certified as safe and was on the road.
So, like this car, how do you ensure the logging data accurately represents the integrity of the well? This was a question debated in Aberdeen and to the credit of the group, they painted the best picture they had of their respective assets. Ultimately the group erred on the side of caution – using multiple logs, cameras, history and behaviour to best understand what was going on downhole. This was rigorous, they picked holes in their own findings, questioned their data and never seemed to take anything as red. This was commendable and it became clear that “good” integrity was never “good enough” – or at least never a point of giving the well a ‘thumbs up’ and not worrying about it anymore. For example, some used a traffic light system to rank the integrity of their stock – but said even a green (and therefore ‘good’) well could bypass Amber and head straight to Red due to variable changes, like reservoir conditions.
It was clear, the group in Aberdeen are not complacent and constantly and consistently monitor, question and work over their assets to ensure they are in the best possible condition. In doing so they are ensuring the productivity of our fields and industry for future generations.
More to come next month…
Innovation, along with ‘collaboration’, ‘standardisation’ and even ‘strategy’, is a buzzword of the day. But what does innovation even mean in the Oil & Gas industry? For some, it is enough to produce trivial novelties and label them ‘innovative’. At OFS Partners, we believe true innovation is deeply pragmatic and creates value.
True innovation requires a depth of understanding that finds patterns and trends, bridges interfaces and connects previously unconnected dots. Without these outcomes, it is nothing more than speculative R&D expenditure with a slim chance of providing sustainable economic benefit. The real litmus test of a decent innovation is not based on its bells and whistles, its ‘digital’ nature or even its novelty, but instead is based on whether or not it has yielded a sustainable economic or social benefit above and beyond what has gone before.
Take decommissioning as an example: it is one of the greatest challenges we face as an industry, but also a great opportunity for the North Sea to pioneer solutions that can later be exported around the world. Here we face a chasm, missed by many, between the oilfield services supply chain and operators. While the supply chain is focusing on a technological solution, operators tend to approach it as a challenge of managing, optimising and where possible eliminating scope. In many ways it is a top-down vs bottom-up dichotomy that could see the hard working supply chain develop solutions that end up offering negligible gains because the scope it can impact has been reduced.
For example, prior to the DNV-GL risk-based guidance to well plugging and abandonment (P&A), there were only very prescriptive guidelines (written by bodies of operators) that dictated equivalent treatment to all wells in terms of P&A. Put simply, there needs to be a permanent barrier to prevent release of hydrocarbons. However, not all wells are equivalent, so why should the treatment of a Southern North Sea depleted gas well (relatively benign) be the same as a High Temperature High Pressure minimally producing oil well in the Central North Sea (very hazardous)? How can innovation come into play most usefully here? One way is taking the operator’s well stock, engaging and understanding what it really needs instead of zooming in on specific technologies for specific applications (for example, milling, lifting, cutting or pressure testing). Once the impact on optimising and changing scope is known, and informed by the engineering and expertise or track record of the supplier, then R&D dollars can be valuably spent on identifying a solution relative to that sub-segment of well stock – therefore investing in an already highly developed client relationship against a specific, actionable, known need.
Those best poised to make gains through innovation are those who understand what operators really need, instead of making assumptions based on static information or using analysts’ assertions as to what is out there. Above and beyond engineering expertise, it requires investing in relationships and developing and demonstrating understanding, before R&D, technology and cutting steel come into play.
By approaching innovation in this way – by first and foremost engaging and understanding – returns are guaranteed, as at a very minimum you are on the front foot building relationship capital with your client. With that comes greater clarity on the future in general and the opportunity to use innovation powerfully to shape the future of decommissioning in the North Sea and further afield.
We are actively working across the sector in specific cases to help bridge the understanding gap and safeguard the future of companies aspiring to make the best of current market conditions. We go above and beyond the simplistic approach of finding and analysing data to determine how specific actions can lead to value delivery. If you are interested, we would be keen to hear from you.
Optis™ E-Line HD camera control from surface allows the best close-up shots, even as completion equipment is operated.
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.
Hear Woodside’s view of the Australian well intervention market, focussing on the characteristics which make Australia a unique place to conduct well work.
Offshore Network have put together an original report which looks at case study on a riserless light well intervention (RLWI) campaign carried out by well services company Sapura Energy Australia.
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