Offshore Drilling Challenges Solved with Closed-Loop Systems
The solution to many modern drilling challenges involves a fundamental change to one of the rig’s core components—the circulating system. Shifting from a traditional system that is open to the atmosphere to a closed-loop system requires only a few changes to common hardware. It yields significant new capabilities to monitor downhole pressures and contain, control and manage annular flow. The result is a significant improvement in safety, operational capabilities and well economics.
In offshore applications, scalable closed-loop systems and specialized marine technologies are increasing efficiencies and opening new reservoirs to development.
The industry’s first subsea rotating control device (RCD) extends these benefits to deepwater operations. Closed-loop capabilities as a well control barrier promise to further advance offshore use.
Subsea rotating control device
Closed-loop drilling systems are fully scalable from early kick and loss detection to wellbore control and management. This versatility provides answers to many issues that have long frustrated traditional offshore drilling operations, including expensive kick/loss episodes, total circulation losses and narrow pore-pressure/fracture-gradient windows.
The basic capability of a closed-loop system is early kick and loss detection (EKLD) to mitigate kick/loss events that can double and triple rig time and can escalate to devastating well control events.
Kick/loss cycles are often difficult to mitigate with traditional measures. Managing mud weight can be a slow response to equally slow and imprecise kick detection. However, within a closed-loop system, the drilling fluid provides a unique and immediate window to the wellbore. A kick or loss is detected as it occurs, so mitigation—conventional or managed pressure drilling (MPD)—can begin quickly before the problem escalates.
The step up to MPD occurs with the use of a choke manifold to manipulate surface pressure. This method has the same effect on equivalent circulating density as changes in mud weight.
Unlike the slow processes of circulating a column of modified density mud into the wellbore (as would be performed in conventional drilling systems) the backpressure imparted by MPD equipment is transmitted through the entire fluid column in seconds to counteract influxes or losses.
This process can be automated by the addition of a new control system. The system monitors and responds to complex sets of downhole pressure fluctuations much faster than humanly possible. Characterization or fingerprinting of pressure patterns discerns between common drilling events, such as connection gas and downhole events—even when circulation is stopped.
In deepwater environments, these capabilities are key to identifying gas breakout in the riser that occurs above subsea well control systems.
Offshore Automation and Integration
Two key technologies in the growing offshore use of closed-loop systems are automation and the recent integration of RCDs with marine risers. Automation is a proven enabler for offshore MPD operations during which even the best crew can be challenged by the response time necessary to mitigate complex downhole pressure sequences.
Kick/loss scenarios often exhibit rapid influx and loss oscillations. Managing these complex fluctuations requires an equally rapid response that is achieved only with automation. By quickly managing backpressure in small increments within the pressurized circulating system, the system can precisely balance wellbore pressures within predefined limits.
A faster automated response also improves drilling efficiencies and lowers fluid costs by providing the high degree of operational control needed to safely work at lower mud weights.
The second technology is a unique subsea RCD for riser installations. Integrating the RCD with the riser is a major fit-for-purpose achievement for deepwater applications.
A below tension ring (BTR) RCD is the first device to be deployed as a subsea riser component. Because the RCD is made up below the tension ring, no modifications are required to the riser’s telescoping slip joint.
The BTR design also limits human exposure to risk below the rig floor during RCD installation, maintenance and operation. Bearing and sealing element replacement is accomplished with a hydraulic latching system that does not require personnel in the moonpool area. A bearing assembly running tool and ancillary equipment provide for rig-floor positioning and removal.
Hydraulic and electrical connections are made below the waterline, using a subsea-rated hydraulic stab plate. Multiport connections speed the deployment and makeup of hydraulic and electrical lines.
A Case Study: Subsea Drilling with RCD
The difficult-to-drill fractured carbonates in the Makassar Straits of Indonesia benefited from installing the RCD system in the riser. The system enhanced drilling capabilities and improved safety and efficiency through early kick detection, riser gas handling MPD and pressurized mud-cap drilling—an MPD variant used in total lost-circulation conditions.
The RCD was installed above the intermediate flex joint in the riser and below a standard flip joint. This configuration enables the riser to be used in a conventional manner with full bore access to the well. The entire system is installed through the rotary table when the riser and blowout preventer (BOP) are deployed.