BSEE修订《井控规定》 这个技术或再被“宠幸”（下）

Compatible Equipment

The equipment needed for RFC-HSE MPD in marine environments is similar to that required onshore but adds the stipulations that a fit-for-purpose RCD must be suitable for the rig type being used, and the choke manifold system must be fully automated by a PLC. The resultant setup is essentially the same required for the CBHP variant.

The RFC-HSE MPD system not only can be used for kick-loss detection but can also continuously monitor the wellbore pressures and divert drilling and background gas safely to the appropriate systems. Mud weight returning from the well is monitored in real time and correlated to the associated drilling gas percentage. Connection gases could be routed to the mud/gas separator if deemed necessary.

Operational Benefits

Although RFC-HSE MPD primarily focuses on the safety of the circulating fluids process itself, a range of operational benefits contribute to recovering the cost of the MPD kit. RFC-HSE MPD enables a closed-loop system for diverting wellbore fluids away from the rig floor and applying SBP when needed. The system’s ability to detect flow in gallons rather than barrels and to compensate for floating rig movement helps to minimize false-positive kick alarms. RFC-HSE MPD also facilitates early kick-loss detection by providing precise mass flow in/out measurements in real time.

The ability to conduct dynamic FITs and LOTs whenever advisable enables drillers to verify and quantify pressure containment capability. Other noteworthy capabilities include:

• Real-time quantification of formation and fracture pressures during drilling operation;
• Wellbore ballooning upon regaining circulation and kicks from wellbore breathing;
• Circulating out an influx of known small volume using the automated choke control, as opposed to shutting in and circulating out manually;
• Wellbore monitoring during special operations such as tripping and cementing;
• Managed pressure wellbore strengthening.

Controlling Wellbore Pressure Profile

Conventional drilling hydraulics – which remain virtually unchanged since Spindletop Field, circa 1901 – rely on hydrostatic mud weight as the primary well control barrier. In conventional drilling, secondary well control equipment (i.e., BOPs) is used to manage kicks and stop further intrusion of formation fluids into the wellbore. The influx is then circulated out of the wellbore using conventional methods. Mud weight is typically increased above the pore pressure to resume operations.

Figure 1 illustrates an increase in SBP as the choke reacts after detecting an influx. The corresponding increase in bottomhole pressure results in an increase of downhole EMW, illustrated in Figure 2, which demonstrates that the annular pressure profile can be swiftly manipulated to prevent further intrusion of an influx. Note that faster choke reaction times than those illustrated in these figures are possible depending on the specific well and system configuration.

By enabling a swift response, SBP manipulation can effectively minimize influx size, compared with conventional well control. EMW with and without choke pressure lines represents equivalent mud weight at specific value of choke pressure.

Figure 3 illustrates an influx management matrix that defines the maximum SBP that the system can apply before the well is shut in. The maximum SBP is typically calculated separately for drilling and connection operations depending on wellbore integrity and surface pressure limitations. If permitted and approved by the contractor, operator and applicable regulatory bodies, the system can circulate a small-volume influx instead of shutting in the well. The small influx volume that can be safely circulated through the system is described in the influx management matrix.

After the influx has been circulated out, drilling can continue with increased mud weight in accordance with BSEE regulatory rules. Effective application of RFC-HSE can help minimize the impact of the pore pressure and fracture pressure uncertainty, which the new BSEE rule emphasizes. The RFC-HSE MPD system, therefore, augments the benefits of MPD technology, further enhancing the operator’s ability to comply with the safe drilling margin requirements from regulatory authorities.

Reducing False-Positive Kick Alarms

After several high-profile well control incidents in recent years, there has been a tendency to tighten kick alarms settings on offshore rigs. This practice has increased the frequency of false-positive kick alarms, resulting in unnecessary NPT, as well as increasing the risk of a real kick being interpreted as just another false alarm. A significant operational benefit of RFC-HSE MPD is its ability to reduce the frequency of false alarms, illustrated in Figure 4.

Summary

The availability of MPD-capable offshore drilling units is on the rise. The RFC-HSE variant of MPD is best suited for wells designed with open-to-atmosphere drilling systems. RFC-HSE MPD is intended not only to detect influx but also to apply SBP as needed to stop influx and minimize the influx size before the well is shut in. The RFC-HSE influx management matrix defines the maximum SBP that can be applied while the well is shut in. This effectively increases operational safety and protects personnel and assets.

RFC-HSE MPD may be considered one of the best and safest technologies for drilling in marine environments and offers economic benefits. As proven on thousands of land applications over the past two decades, the cost of drilling with a closed-loop system is often exceeded by the savings resulting from reduced NPT, lower risk of sidetracks and improved zonal isolation during well construction.