P.2 ~ Continued - Managed pressure drilling meets challenges of deepwater well
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Extensive planning, simulation
Pre-job planning and testing, including a rig survey to assess the practical aspects of installing and operating the MPD system, riser assembly, and RCD, proved critical to the success of the operation. Due to space constraints on the rig, a special platform to accommodate the MPD manifold was installed on the BOP cart in the moonpool, with the main flowlines from the flow spool connected to the manifold using hoses, isolation valves, and a custom buffer manifold. A high-capacity mud gas separator (MGS) was positioned on the lower pipe deck.
The two-part MPD riser assembly, including the RCD, was installed on top of the surface annular preventer in two parts: an upper sub-assembly, with a three-part slip joint and slip joint riser adapter, and a lower sub-assembly, with a riser adapter, flow spool, and the riser annular and RCD.
The operator, drilling contractor, and service company conducted a two-day hazardous operations exercise to assess what hazards might occur and the mitigation tools in place for addressing over-pressure, high temperature, and flow problems. The team studied two primary nodes – one from the drill bit to the surface via the annulus, the other from the buffer spool to the MGS and onto the rig choke and kill manifold. Procedures for testing pressure of the riser stack-up, third-party equipment installation, training requirements, and the RCD element change-out also were reviewed, along with kick matrix requirements.
An oil-based fluid, shown in deepwater well studies to be effective in keeping gas dissolved in solution, was selected. The slip joint/riser pressure limitation was increased to 1,000 psi (69 bar) to apply the required surface backpressure to compensate drilling friction losses without over-pressurizing the slip joint and riser assembly. This adjustment also provided a means to safely divert gas-bearing fluid away from the rig floor and toward the MPD choke manifold system.
The team performed hydraulic, temperature, and kick simulations to determine if influxes could be circulated out using the MPD system, or if the well would need to be shut in for conventional circulation. Transient simulations, by adjusting the conventional kick module of dynamic well control software for the MPD application, took into account the dissolution of gas in an oil-based mud. A well control matrix was developed to provide a clear protocol for dealing with various volumes of influx based on surface pressure:
- Green operating limit: normal state with no influx and surface backpressure less than 150 psi (10 bar), allowing operations to continue as planned
- Yellow limit: an influx of up to 5 bbl with a surface backpressure limit of less than 800 psi (55 bar), dictating drilling be stopped and the influx circulated out before resuming operations
- Red limit: influx of more than 5 bbl and backpressure of more than 800 psi, signaling that drilling be suspended and the well shut in using the subsea BOP, the last line of defense in an MPD well.
The well control plan also included procedures for circulating gas out of the riser if the BOP was closed and the well shut in. A decision tree was devised to identify the severity of an influx and the necessary response actions.
The MPD campaign was launched in February 2012, and achieved all well goals in two months. The 14¾-in. well was vertically drilled to a TD of 14,927 ft (4,550 m), 532 ft (162 m) deeper than the planned objective, allowing the 133⁄8-in. casing to be set lower and eliminating the need for the 105⁄8-in. section. Surface backpressure was applied during connections to keep the BHP from fluctuating and to control the annular pressure profile. The MPD system adjusted the surface backpressure to circulate out some minor water kicks (2 bbl), and also applied 170 psi (12 bar) to the wellbore while pulling out of hole to keep the well stable and free from swabbing influx.
