The constant bottomhole pressure (CBHP) method of managed-pressure drilling (MPD) provides several advantages over conventional drilling, which include enabling drilling with lower density drilling fluids to increase ROP, allowing dynamic formation integrity testing (FIT) and adding dynamic well control capabilities.

One of the major challenges while drilling through narrow pore-fracture windows has always been controlling gas kicks due to gas solubility and mud compressibility. Continuous closed-loop monitoring of the well and automated early kick detection and control minimizes the influx volume before it reaches the “well control” threshold and threatens the integrity of the well.

All well control methods share the common objective to overbalance the flowing formation and circulate out the kick fluids from the well without exceeding the surface or subsurface pressure limitations of the well. MPD provides significantly improved well control capabilities; however, the industry remains hesitant to accept MPD as a well control tool. Weatherford’s Microflux control system, which offers fully automated kick detection and control, was used in an MPD well control case study.

Case study: Dynamic well control with MPD

A kick was taken while drilling a well in the Montney Formation in Alberta, Canada. The Montney is a tight-gas reservoir with pore pressure gradients ranging from 0.55 psi/ft to 0.70 psi/ft. The well was planned with a 2,591-m (8,500-ft) long horizontal lateral after the buildup section in this formation. The kickoff point was at 2,190 m (7,183 ft). The 7-in. intermediate casing shoe was set at 1,992 m (6,535 ft) measured depth (MD)/true vertical depth and tested to 18.67 lb/gal equivalent by a conventional leak-off test.

FIGURES 1 and 2. In these field data, return flow was compared with the flow-in by the algorithm to confirm the influx. The system then automatically activated the well control module. (Source: Weatherford)

The section was being drilled using the CBHP method, holding surface backpressure (SBP) during the connections to compensate for the loss of annular friction. During the kick event, 10.3 lb/gal oil-based mud was being circulated, and the well was overbalanced with a constant 10.95 lb/gal equivalent bottomhole equivalent circulating density. Prior to the event, the mud logging unit was measuring 200 to 500 units of hydrocarbon gas in the mud, gauging no connection gas.

During drilling of the buildup section a drill-break was observed at 2,458 m (8,063 ft) MD, with the ROP increasing from 6.1 m/hr to 24 m/hr (20 ft/hr to 80 ft/hr) followed shortly by a sudden increase in return flow. The MPD system detected this increase in return flow through the coriolis flow meter and a 35-psig spike in the standpipe pressure sensor (to in Figure 1). Return flow was compared with the flow-in by the algorithm to confirm the influx. The system then automatically activated the well control module (t1 in Figure 1).

The well control incident began with the stepwise addition of SBP while simultaneously monitoring the change in the return flow, with the goal of regaining the wellbore vs. pore pressure overbalance. Figure 2 shows the SBP, standpipe pressure and choke position data recorded during the event. A total of 510-psi SBP was required to reestablish the steady state flow-out vs. flow-in balance, which in turn resulted in a 235-psi increase on the standpipe pressure (t2 in Figure 2).

After verifying this condition for 20 seconds, an additional 100 psi was added to the SBP as a safety factor. The time difference between detection of the kick by the automated MPD system and regaining control was three minutes, and the additional gain of 1.88 bbl was safely circulated out of the well at full circulation rate.

Simulating kick event

While the MPD system’s automated early kick detection and control minimized influx volume and allowed fast regain of pressure control, one might ask if conventional well control methods might achieve the same results. This prompted an in-depth engineering study of the event to yield a quantitative one-to-one comparison with conventional well control methods.

The study began by first reproducing the kick event in a simulation environment using a commercially accepted transient multiphase well control simulator. Throughout the simulation work, the same drilling parameters and drilling fluid properties as were employed during the field operation were used as inputs. Using the geological data for the Montney Formation available from public sources, input values for formation porosity and temperature were estimated as 10% and 79 C (175 F), respectively.

FIGURE 3. Kick data vs. validation with simulation are shown. Annular pressures are on the left. Pit gains are on the right. (Source: Weatherford)

In the initial simulation (Simulation I), the SBP data recorded by the MPD system during a kick of 1.88 bbl were tracked by dynamically manipulating the annular pressure at the surface. A close match in annular surface pressure was achieved between the simulation output and the data recorded from the field event (Figure 3).

In the next simulation (Simulation A), the identical initial-size-kick of 1.88 bbl was controlled, but this time it was done by employing the driller’s method of well control (i.e., detecting the kick based on pit gain and shutting in the well). Iterative conventional well control simulations were run to find the input parameter: total response time needed to control the identical size kick. Total response time is the cumulative time spent for pump ramp-down, flow-check, BOP closure and any operational delays. The simulations revealed that a total response time of two minutes would be needed to complete the detection and control of a kick of less than 2 bbl, reflected by achieving an identical maximum pit gain (Figure 3).

A sensitivity analysis was then conducted to study the effect of total response time on the pressures at the surface and at the casing shoe during the application of a conventional driller’s method of well control. During an actual well control event, total response time is the only operational variable that can be managed and therefore was selected as the input parameter for the sensitivity analysis. Simulations were run for response times of two, five, eight and 12 minutes.

As might be expected, the simulations showed that kick size (as reflected in pit gain) at shut-in is a strong function of total response time, with the volume of fluid lost from the well increasing dramatically the longer it takes to respond to the kick.

A one-to-one quantitative comparison was conducted positioning dynamic well control with MPD vs. the conventional driller’s method of well control. Assuming a pit level alarm setting of 2 bbl and total response time of 12 minutes for the conventional response, the comparison demonstrated how automated early kick detection and control minimizes kick size and, hence, the surface pressures needed to circulate out the kick. The most notable differences using MPD were a decreased kick volume at the surface by 67 gal, a decrease in peak pressure at the shoe by 4.85 lb/gal equivalent and a significant decrease in peak pressure at the surface by 1,570 psi.

The precision and accuracy of the dynamic kick control during the event constitutes a field proof example of the pressure control capabilities of the MPD system. Such accuracy is crucial in CBHP drilling in hydraulically challenged sections where kick tolerance is lower than the safe control limitations of the conventional well control systems. In those sections, the maximum allowable surface pressure is often a more restrictive criterion than the rating of the surface equipment; hence, the risk of triggering an underground blowout is real. Therefore, the merit of an MPD system becomes detecting and controlling influxes at minimum size before they reach the threshold kick-tolerance size.

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