Making better sense of downhole data

Distributed temperature sensing data is now often the first port of call when identifying production issues, not the last resort as it had been prior to the adoption of the latest user-friendly data management packages. Tendeka's Garth Naldrett explains why.

Real-time and accurate downhole monitoring data is crucial to operators in their goal of understanding and controlling wellbore and reservoir performance, while maximising oil and gas extraction. An increasingly used method of sourcing this data is permanently installed downhole monitoring sensors in production and injection wells. Of growing importance in this area is fibre optic distributed temperature sensing (DTS).

While the fibre optic technology is relatively young compared to the other electrical downhole sensors, its unique ability to monitor the complete wellbore from top to toe, the passive in-well components, long field life and non-intrusive flow monitoring means it is being rapidly adopted across the industry.

The fibre optic monitoring industry has come of age and now delivers meaningful information, rather than vast amounts of unmanageable temperature arrays. The shift has been enabled by new generations of high resolution monitoring units coupled with advanced data management solutions. Using the system in combination is known as digital flow profiling (DFP).

In practice, DTS data is transmitted from the field in an open format Wellsite Information Transfer Standard Markup Language (WITSML) through the firewall to a secure database inside the client network. The client is provided full ownership and management of their own DTS data, and multiple end users are able to access this information using a web interface. DTS data is presented with all the relevant contextual data, including wellbore survey data, completion diagrams, log data and production data.

Data is quickly accessible and less time is spent manipulating data sets, ensuring greater user acceptance in the surveillance plans. DTS data is now often the first port of call when identifying production issues, not the last resort as it had been prior to the adoption of user friendly DFP data management packages.

Digital flow profiling
A major operator awarded Tendeka companies Sensornet and FloQuest a five-year contract for the engineering, procurement, installation and management of their fibre optic DFP systems. These differ from conventional DTS equipment in being designed from the ground up to provide the operator with a flow profile, rather than vast arrays of raw temperature and pressure data. This involves high performance measurement equipment being coupled with novel in-well cable designs and all the resulting data being handled by an effective data management and interpretation tool.

The contract engineering phase ensured the in-well equipment was properly designed for the downhole conditions and was capable of being deployed along some of the tortuous horizontal wellbores. This resulted in 100% reliability with no downhole failure or degradation, despite horizontal intervals in excess of 2500m. All the cables were installed with feed-through splices, completely avoiding in-well connectors. Not only has this ensured trouble free operation, but has also allowed improved measurement performance due to lower optical loss. During early evaluation in a static wellbore, the system has shown temperature resolution better than 0.008°C. The resolution has been a critical factor in ensuring the horizontal well performance, with small thermal deviation, can be assessed.

While DFP systems are being installed in newly drilled wells, an increasing number are deployed in existing wells when electric submersible pumps (ESPs) are approaching the end of their run life. As the field produces relatively heavy crude, and reservoir pressures are subhydrostatic, all production wells need to be equipped with artificial lift equipment. The preferred lift solution is ESPs, which significantly complicates wellbore access for the purposes of production logging. As a consequence reservoir production data had previously only been acquired on very few wells, despite over a decade of production from the field. The operator had therefore not had the opportunity to develop a comprehensive understanding of the reservoir, in particular understanding the complex fracture network. When reviewing their overall field surveillance strategy, the importance of reservoir data acquisition through permanent monitoring devices was found to be one of the most important variables in allowing the desired recovery factor to be achieved. Given the restriction imposed by the ESPs the only viable option for complete data acquisition across production intervals was a DFP system.

The data gathered has increased the understanding of the complex fracture network present in the reservoir, and allowed the operator to gain a greater appreciation of issues surrounding long horizontal liners and cement integrity behind the liners. This information has allowed production improving modifications to be made and assessments carried out on new methods of creating annular barriers on the outside of the liner section. By incorporating swellable packers outside the liner, subsequent wells have successfully isolated problematic zones, verified through the use of the monitoring system.

Digital well integrity
Digital well integrity (DWI) is a further benefit of full wellbore coverage using DTS systems. The technology was installed in an adjacent field to monitor the temperature profile across gas lift systems in the upper part of the completion. As injection gas moves from the annulus into the tubing string it experiences a throttling effect, more accurately termed Joule-Thomson cooling.

This cooling allows the gas injection position(s) to be accurately determined, making it possible to differentiate between injection through valves or through a tubing leak and monitor well startup in real time without intervention. By monitoring the sequence of injection valves any issues can be quickly identified and interventions precisely and efficiently planned, if required. This potentially saves many man hours and tens of thousands of dollars which might otherwise be spent replacing incorrect valves.

Without complete coverage, as offered with a DTS system, it would be possible to misinterpret gas lift efficiency. Even intervention-based gradient surveys are not able to compare with DTS as the pressure and temperature profiles derived from these surveys are the result of a single point measurement being scanned along the wellbore. If the system is not in a steady state condition the gradient profiles will not be an accurate reflection of the wellbore pressure and temperature profile. Oversized injection valves, for example, can cause an unsteady state in a gas lift system, meaning the monitoring effectiveness is compromised. They cause the annular pressure to drop too quickly when the valve opens, resulting in the valve shutting until annular pressure again builds up to the usual operating pressure. This causes continuous cycling of the valve moving between open and closed states.

While the potential exists for this to be missed on a gradient survey, the process is quickly and easily visible on a DTS measurement

The benefits derived from digital flow profiling and digital well integrity are beginning to be well understood and as result the uptake of fibre optic based monitoring systems is growing rapidly. OE

About the Author

Garth Naldrett
is vice president reservoir monitoring at Tendeka, the specialist completions company formed in 2009, and is responsible for production data interpretation and software development. His 15 years' experience of electrical and fibre optic permanent monitoring includes the application of downhole sensors and their integration into complex completions.

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