[Editor's note: This story originally appeared in the April 2020 edition of E&P. Subscribe to the magazine here.]
Offshore operators know the value that real-time well monitoring brings to making more informed decisions regarding production optimization, risk reduction and maximizing returns. But when it comes to reliably collecting the data and transmitting those to the surface, operators have been stymied by effectively deploying and connecting lines across long distances downhole. As a result, production decisions were traditionally made with limited knowledge of what was going on in the pay zone.
This is changing, as the industry has reached an inflection point in the adoption of fiber-optic technology, a downhole distributed sensing technology that gives operators a detailed, real-time view of their reservoirs. The technology works by shooting light down a fiber-optic line deployed with the well completion. Changes in temperature, pressure and acoustics in the well distort the light path in the fiber. The degree of distortion is then analyzed at the surface to provide a real-time interpretation of the well’s performance downhole.
While fiber-optic systems have been around for decades, their data-gathering capabilities were limited due to reliability and monitoring techniques. In addition, most deepwater wells are designed with multi-trip completions, which present challenges for installing fiber down to the lower part of the completion and into the pay zone—where data are needed most.
High-definition monitoring from toe to surface
Baker Hughes has developed a downhole technology that gives operators the flexibility to deploy multiple lines in multi-trip completions all the way to the toe of the completion. The company’s SureCONNECT intelligent wet-mate system enables downhole connection and reconnection of the upper and lower completions with hydraulic, electric and fiber-optic lines.
The system is modular in design with a wet-mate that houses up to five connector channels. Each connector channel supports two hydraulic lines, one electric line or one six-fiber line, which allows operators to choose the lines they want to include without the need to custom-configure a new system each time. The system also includes a carrier with an orienting guide that ensures proper connection, even in challenging downhole conditions. In addition, the system is designed to be compatible with other downhole tools such as remotely actuated sliding sleeves, which affords a standardized intelligent completion design.
With the wet-mate system, operators can collect and analyze the kind of data that were always promised from distributed measurement. This step change in sensing and data acquisition is akin to going from shining a spotlight on one part of the well at a time to getting a high-definition, 4K movie playing across the entire wellbore. Such a detailed view gives operators the ability to make data-driven decisions that optimize reservoir performance and actively mitigate risks.
The wet-mate system lets operators perform upper completion workover operations while leaving the lower completion—and all intelligent completion components— in the well. Eliminating the need to retrieve the lower completion during workovers significantly decreases rig time, safety risks and equipment costs.
Proven in the field
The intelligent wet-mate system was developed in close collaboration with BP, which needed a robust, realtime monitoring system for its remote offshore wells. Specifically, the operator wanted to use fiber optics to improve its understanding of the complex, intersecting fracture network in its massive Clair Ridge Field off the coast of Scotland. The data obtained will improve placement decisions for new wells while boosting reservoir recovery through better utilization of sliding sleeve and zonal isolation tools.
In addition to providing in situ pressure and temperature data, the wet-mate connected lines can monitor well integrity, sand control effectiveness and artificial lift performance. The system’s remote monitoring capabilities reduce the need for conventional well intervention surveillance operations such as production logging. For BP and other operators, minimizing offshore interventions reduces opex and limits travel for intervention crews to and from the platform. Overall, the system helps optimize the total expenditure for the life of the well.
BP installed the first intelligent wet-mate system in a producing well offshore Scotland. Baker Hughes intelligent production systems engineers partnered with the operator to coordinate all offshore operations. The Baker Hughes XACT downhole acoustic telemetry service afforded real-time monitoring of run-in parameters and helped navigate through narrow tolerance openhole sections to successfully install the lower completion with no HSE issues. After cleaning the wellbore and landing the upper completion, the SureCONNECT system successfully mated to provide optical continuity from toe to surface. The operator confirmed connectivity between the lower and upper completions on all six fibers.
A fiber-optic surface interrogation unit was installed to transfer the data to the operator’s SCADA system. Personnel could then read pressure and temperature data from the fiber-optic gauges and review distributed acoustic and temperature sensing traces that were recorded throughout the entire length of the completion.
The operator deployed the wet-mate system in a second well, this time a water injector with four separate zones in the lower completion. As before, the XACT service was deployed as part of the running string to aid in navigation through the openhole section. XACT’s live data transmission confirmed the amount of compression at the running tool, which allowed the set down weight to be adjusted at the surface and enabled the tool’s efficient release.
The operation successfully linked six fiber-optic strands between the upper and lower completions nearly 1 mile below the seafloor, affording real-time monitoring across the entire wellbore for the life of the well. It also linked two lower completion zones with SureVIEW P/T gauges for continuous monitoring of well data and distributed temperature sensing data.
The operation was completed without any HSE incidents and about two weeks ahead of schedule—a 50% reduction in completion time from the previous install. Having access to the pressure/temperature data in this injector well will give the operator the ability to interpret and compare injection data throughout their complex reservoirs.
Future plans include moving from remote data collection to remote actuation and control. With data collected across the reservoir, operators will be able to selectively segment their wells into zones that can be controlled independently.
In a producer well, this might mean remotely actuating and producing out of multiple zones that previously were only accessible from two or more wells, thus eliminating a well and delivering significant capex savings. For an injection well, remote actuation might translate to better injection control to ensure the desired sweep efficiency.
Continuing to work with operators like BP will be critical to developing these innovations in fiber-optics-aided monitoring and control. These developments promise production optimization benefits to operators around the globe, whether their assets are on the seafloor, an offshore platform or on land.
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