Home / 2017 / Evolution of intelligent coiled-tubing technologies drives need for better sensors, data interpretation tools to aid real-time decision-making

Evolution of intelligent coiled-tubing technologies drives need for better sensors, data interpretation tools to aid real-time decision-making

Increasingly long laterals, multilaterals also creating need for CT tools to prevent buckling, stuck tubing and for debris removal

By Kelli Ainsworth, Editorial Coordinator

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Baker Hughes has added TCT sensors to its TeleCoil system. The sensors are housed in the BHA and measure strain via gauges within the sensor walls. The strain measurements are then converted to measurements of tension, compression and torsion.

Coiled-tubing interventions, like everything else in the upstream sector, have taken a hit since oil prices tumbled in 2014. In fact, the coiled-tubing industry declined by 41% from 2014 to 2015 and by an additional 39% from 2015 to year-end 2016, according to data from Spears and Associates. “This is an unprecedented decline in the industry,” said Teoman Altinkopru, VP of marketing and technology, Well Services at Schlumberger. “We haven’t seen such a severe and extended low activity in a very long time. The general theme now is how can we make things more efficient and more cost effective for operators.”

Along with advances to keep up with the increasing temperatures, pressures and complexities in today’s wells, coiled-tubing providers are also developing tools to prevent buckling and stuck tubing. This is critical in the longer laterals that operators are drilling and completing. Such tools can also help to better steer coiled tubing when reentering multilateral wells.

Beyond these advances, the industry is also placing significant attention on intelligent intervention technologies, which provide real-time data about the well’s condition. “Coiled tubing has been around for a long time, but until recently, our downhole capabilities had not evolved very much,” said Stuart Murphy, Coiled Tubing Product Line Director at Baker Hughes. “Over the last three years, it’s become much more common to perform coiled-tubing operations on wells using sensors in the bottomhole assemblies (BHAs) that provide real-time downhole information.” Such data can inform both the operator and service provider on whether the job is being executed according to plan. It also allows for adjustments to be made if necessary.

The THERMA on Techlog software determined the volume of fluid injected along the zone of interest during an operation in Kuwait last year. Fluid intake at each stage of the matrix acidizing treatment was obtained by interpreting the distributed sensing data and used to control fluid placement for an optimized stimulation result.

The THERMA on Techlog software determined the volume of fluid injected along the zone of interest during an operation in Kuwait last year. Fluid intake at each stage of the matrix acidizing treatment was obtained by interpreting the distributed sensing data and used to control fluid placement for an optimized stimulation result. Image courtesy of Schlumberger.

As the amount of data being collected increases, so too does the need for better software that can interpret coiled-tubing data in real time. “These measurements are becoming more cumbersome,” Mr Altinkopru said. “Software needs to catch up so we can continue with efficiency improvement.”

In this article, DC speaks with subject matter experts from Baker Hughes, Schlumberger and Weatherford about the innovations in coiled-tubing intervention technology.

Certainty through data 

In this lower-price environment, operators are unlikely to take financial risks if the reward is uncertain. The same logic applies when it comes to interventions – operators are hesitant to perform an intervention unless they are highly confident that it will succeed, Mr Murphy said. “They may see more risk than potential reward regarding their investment,” he commented.

To reduce the risks involved in intervention operations, Baker Hughes recently added force-measuring sensors to its TeleCoil intelligent coiled-tubing service. When the service was originally launched in 2009, it was able to collect temperature, pressure and depth data in real time, using sensors placed on the BHA.

Force measurements were added in August 2016 when the company commercialized its tension, compression and torsional (TCT) sensors, which measure strain via gauges within the sensor walls. With these sensors incorporated into TeleCoil, the service can now convert the strain measurements into measurements of tension, compression and torsion. Such measurements can be used to optimize tools, such as downhole motors, that operate best within a narrow defined force range.

In Q4 2016, Baker Hughes deployed the TeleCoil service with TCT sensors in a production well in the Caspian Sea near Baku, Azerbaijan. The well had originally been drilled and completed in April 2014 through a sandstone formation. By May 2016, produced sand was detected. The operator initially choked back production by 50% to slow the flow of sand, but this was a short-term solution that significantly impacted the well’s profitability.

To provide a longer-term solution, the operator decided to apply expandable steel patches in two sections where there was sand in-flow. However, application of the patches would be extremely sensitive to force, as it was critical to keep the setting BHA at the neutral load, Mr Murphy explained.

If too much downward force is applied during installation, the inflatable rubber elements used to install the patches could be shredded. Pressure-related coiled tubing shrinkage could also potentially create sufficient force to break the shear pin. Too much upward force could result in the patch being disconnected. “The patch really needed to have that downhole tension and compression sensor capability to ensure that it could be effectively placed and installed,” he added.

Prior to installing the patch with TeleCoil, the well was cleaned out using Baker Hughes’ Concentric Coiled Tubing and SandVac system to circulate hundreds of pounds of sand out of the well. While deploying the patches, the TCT sensors ensured that no excess force was applied to the BHA.

In the end, both of the patches were successfully installed – one close to the bottom and another approximately 10-12 screen joints from the top of the interval. Sand flow into the well was eliminated. The job was completed five days ahead of schedule and $1.5 million under the estimated cost, according to Baker Hughes. The company has since performed two identical jobs for the operator in the same area.

Without the TCT sensors, the job was a risky one, Mr Murphy said. “I believe the operation would not have been done without this sensor capability. The operator would have seen a high level of risk. By having the sensors, the risk profile is much lower.”

Providing answers on site

Schlumberger is also pushing advances in its intelligent coiled-tubing technologies. In particular, the company is focusing on innovations that can improve efficiency by reducing the number of runs required to complete a job, Mr Altinkopru said. “(Real-time data) gives you eyes and ears downhole, which enables us to make decisions while we’re performing the job,” he explained.

To help wellsite engineers make use of such data, the company recently merged two existing technologies – the THERMA software and the Techlog software platform. THERMA has been around for years and takes distributed temperature measurements in permanent fiber optic installations. However, it didn’t produce data that could be analyzed and used to inform real-time decisions. “Analyzing the data is a very cumbersome process that couldn’t be completed at the well site,” Mr Altinkopru said. “It had to be done post-job in an office environment, but we needed this to be on location at the job.”

By combining THERMA with Techlog, which was launched in 2012, Schlumberger can now decipher distributed temperature sensing (DTS) raw data in real time. Fluid intake at each stage of the matrix acidizing treatment is obtained by interpreting the distributed sensing data and using that to control fluid placement for an optimized stimulation pumping schedule. This makes the data much more useful for wellsite engineers.

In 2016, the merged product – THERMA on Techlog – was deployed for Kuwait Oil Company in the Middle East in conjunction with the Schlumberger ACTive real-time downhole coiled-tubing services. These technologies collect both distributed temperature and vibrational measurements in real time – between an estimated 1 to 3 terabytes of data per well, according to Mr Altinkopru. Based on “warm back” response, the THERMA on Techlog software determines the volume of treatment fluid injected along the length of zone of interest.

Inflow control devices (ICDs) that had been installed in two wells in the Minagish and Sabriyah fields had became plugged. “Because they are so small, the fines coming in from the formation, as well as any debris that is left in the completion, causes those ICDs to get plugged up. Hence, the entire zone was not contributing to overall production,” Mr Altinkopru said. “Identifying which ICDs are plugged is a huge challenge.”

The operator first used the ACTive platform to collect distributed temperature data. If there was a temperature change at a given depth, it indicated that oil was flowing in that part of the well. If there was a no temperature response in a given area, it meant that area was not producing oil, and the ICD was plugged. This information helped to determine which ICDs needed to treatment.

In the same run, an ACTive Straddle CT real-time multiset inflatable packer was run to clean out the plugged ICDs. The platform’s real-time monitoring capabilities allowed the operator to confirm that the ICDs were treated correctly in real time. Immediately after the well was brought back online, production more than doubled in both wells, Mr Altinkopru said. At the same time, the job was completed about seven days faster than it would have been using conventional intervention techniques, which would have required separate runs for production logging, well cleanup and treatment, he added.

Having the software that analyzed the distributed temperature data in real time and presented it in a log that was easy to read and interpret was critical to the operation’s success and to reducing the number of runs required, Mr Altinkopru said. “We can do everything on one run only with the data that is available, so that data is critical,” he said. “It is essential to acquire it accurately and to analyze it and decipher it efficiently so the whole process is seamless.”

Running smoothly 

Weatherford’s MacFlow modeling software calculates pressure changes within the well. The newest module, released in January, is able to calculate changes in how much fluid is passing through the motor.

Weatherford’s MacFlow modeling software calculates pressure changes within the well. The newest module, released in January, is able to calculate changes in how much fluid is passing through the motor.

As the lengths of lateral sections increase, friction between the tubing and the well also increases and can cause the tubing to buckle or lock up. “When you get friction-locked, your pipe stops,” said Charlie Grigor, Global Product Manager for Thru-Tubing Fishing and Milling at Weatherford. “Then, when you break the friction, the pipe moves down relatively quickly and applies too much weight onto your mill, which can stall the motor.” To address this challenge, Weatherford commercialized the Renegade friction reduction tool in 2016. It is a vibrating device that attaches to coiled tubing just above the motor and sends pulses throughout the coiled-tubing string. These pulses keep the string in constant motion to prevent friction and buckling.

The tool was initially tested in onshore Canadian wells and has also been deployed onshore Latin America. To date, it has primarily been used to mill out sleeves in multizone fracture jobs, as well as composite bridge plug millouts.

Another tool that Weatherford recently launched is the FloMax Sequencing Valve. In long horizontal wells, whether onshore or offshore, it can be difficult to achieve enough annular velocity to remove debris. In the past, the industry had typically worked around this challenge by producing motors that can tolerate higher flow rates. Another traditional workaround is to use larger-diameter coiled tubing, which allows higher fluid volumes to be pumped through. However, both options had limitations, including decreasing the life of the tools.

With FloMax, the valve is attached to the downhole motor and is preprogrammed to open and close at a specified flow rate, depending on the limitations of the motor. If the operator needs to remove debris from the wellbore and needs to pump fluid at a rate beyond the motor’s limitations, the valve will activate once flow hits the pre-specified rate. This allows the flow to bypass the motor.

Once the debris has been removed and the flow rates drops back down, the valve deactivates and the flow is sent through the motor once more. “You can do that multiple times when you’re in the wellbore. You don’t have to drop balls or do anything else apart from changing flow rates to activate and deactivate the tool,” Mr Grigor said.

To help reduce risk in plug milling operations, Weatherford commercialized a new module for the Mac Flow modeling program in January. The Mac Flow software, originally commercialized in 2014, allows the company to input a variety of parameters, from well conditions to the equipment on the BHA. The software then calculates pressure changes in the well.

The newest module is equipped to calculate changes in how much fluid is going through the motor, so the operator will know what the motor is doing at all times. With tools like the FloMax, where the amount of fluid flowing through the motor may change regularly, the software will account for those changes.

This provides a guide for what flow rates and pressures should be during an operation, so they can be adjusted as needed. “You know what pressures you should be running and what pump rates should be,” said Bob Murphy, Global Product Manager for Thru-Tubing Packers. “There will be no guesswork. The software does planning for you.”

During the planning process, it can help determine whether a job is feasible and what changes might be needed. “Sometimes we run the program, and it reveals that the job can’t be performed within the planned parameters. Then we go back and work with the operator to replan the job,” Mr Grigor said. “By adjusting the coiled-tubing size or other parameters based on the model, we are able to avoid nonproductive time during the operation.” DC

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