Europe

McKinsey & Co deliver a presentation regarding the value of North Sea well Intervention.

Introduction

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.

Targeting the Highest Priority Wells

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:

• The first step is to calculate the well weight by using predictive modeling. Modeling, however, will be as reliable and accurate as well input data. Alternatively, you may have to take a direct measurement if the data is unreliable.
• Once well loads are confirmed by using either of the options (or preferably both!) a health check should be conducted to check how much actual steel is in the asset and how much will be transmitted to the load. A good practice is to record the movement of strings. If movement and behavior is ‘as per design’ it is a good indicator of well’s health.
• Next is to quantify using the remaining wall thickness to assess the total metal loss and strength capability of the structure. This can be quantified by using pulsed eddy current (PEC), C-PEC (for flexible access) and PCE. Also, multiple historical surveys can be utilised to assess the corrosion rate effectively.
• Finally, you can assess the well’s overall condition, casing support, and re-assess the well model with operational loads. External sources such as environmental factors (wave and current loads for example) can be quantified as distributed axial loads in the dynamic model.

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:

• Medium severity assets will need essential stabilization work. A conductor guide reinstatement and conductor/surface casing retro-fit centralisers could be used to increase the fatigue life and reduce VME stress. Further, either mechanical or grout up approaches could be used. For instance, you could either transfer the load of the well and then use conductors with a mechanical clamping mechanism or use grout to transfer the load from the well to the conductor.

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.

Conclusion

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.

CHALLENGE

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.

OUTCOME

• The WASP® tool is efficient to operate as it is deployed using a standard mono-conductor wireline unit. The treatment replaced either multiple slickline runs or a coiled tubing operation.
• The treatment was completed in less than 15 hours total operating time, while strictly following all normal protocols. The technology allows for the treatment of multiple intervals on the same run in the hole, further increasing efficiency.
• The technology is ideally suited for small footprint platforms and does not require an excessive amount of rig-up height or unusual lifting capability.
• The technology requires no chemicals, explosives or controlled goods, and as such is environmentally friendly and extremely safe.
• The technology was proven to be a very cost-effective solution to remove scale inside any completion equipment, including tubing, Subsurface Safety Valves, Side Pocket Mandrels, and Gas Lift Valves.

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.

This Video of the Month showcases how the application of SandVA, paired with Optis Infinity technology, helped the operator of a gas well to confirm the integrity of their asset and demonstrate compliance with regulatory requirements.
 
Sand control or sand management is estimated to be required in more than 50% of wells globally during their productive lives. The need arises in both conventional and unconventional wells with high rate gas production from unconsolidated sandstones reservoirs and flowback from hydraulically fractured wells providing common examples. In certain regions the use of slotted liners or sand screens to control sand production is widespread. In these locations production from unconsolidated sands would not be economically possible without their use.
 
A gas storage well operator in continental Europe required detailed assessment and visual confirmation of the condition of sand screens within the well. Sand control in this well is further complicated by frequently alternating periods of injection and production. Regulatory requirements entail periodically confirming the condition of sand screens and other downhole components.
 
EV’s Optis Infinity M125 tool was deployed on slickline with both downview and sideview video footage acquired over the entire well. Four screen sections with an average length of 6m (20 feet) were captured. The resulting images were subsequently visually inspected and measured to evaluate both erosion and plugging of the screens, to provide a quantitative evaluation of screen integrity and inflow performance.
 
Having demonstrated that the integrity of the screen was indeed intact, the operator satisfied the legislative requirements to continue operation of the well. The plugging of the base holes was noted, but the operator elected to take no further action at this time and would assess changes in the levels of plugging during subsequent inspections. From this time-lapse information a rate of change could be calculated to provide input for decision making on when to schedule wellbore and screen clean-up interventions. This quantified information provided by SandVA allows patterns and trends to be identified, helping diagnose the causes of problems and understand their severity. This information helps operators implement effective sand management programs, enabling them to maximize the performance and productive life of their assets.