Managed pressure drilling (MPD) methods that regularly enable drilling in difficult environments are proving to be an effective tool in cementing operations. In a vertical exploratory HP/HT well in British Columbia, Canada, MPD methods were applied through coiled tubing (CT) to successfully cement an openhole section to temporarily abandon the well after drilling and logging operations.

In HP/HT drilling environments, managing the bottomhole pressure (BHP) to cement an open hole is very difficult to accomplish with conventional methods, which are typically unable to respond quickly or effectively to counter fluctuations in wellbore pressure without exceeding the window limits. With excessive pressure, the fracture gradient is exceeded and fluid losses occur; however, an insufficient amount of pressure can precipitate a kick as formation pore pressure pushes gas into the wellbore.

By closing the loop, the MPD system provided early kick/loss detection and control while displacing kill fluids prior to cementing and while cementing. MPD allowed real-time flow detection and modeling to help avoid costly cement additives and higher cement weight, eliminate mud and cement losses (and related formation damage), and minimize high standpipe pressure.

The closed-loop cementing operations successfully maintained a constant bottomhole pressure to stay within an almost nonexistent .3024 kPa/m window. The real-time operations simultaneously balanced the hydrostatic pressure from pumping cement with the swabbing effect of retrieving the CT. Weatherford’s Microflux control system managed this automatically by reading mass flow out of the annulus and adjusting equivalent circulating density (ECD) by applying annular surface backpressure (SBP).

The British Columbia project

MPD technologies were used to close the loop and thus drill the conventionally challenging exploratory HP/HT well vertically to 4,402 m (14,442 ft) measured depth (MD). After logging the well from 3,271 m (10,732 ft) to 4,402 m MD, the operator planned to cement the 165.10-mm openhole section from 3,825 m (12,549 ft) to 4,402 m through CT. A formation pressure gradient of 19.71 kPa/m and a fracture gradient of 20.01 kPa/m presented a very narrow pressure window and a significant risk of the wellbore either gaining from a formation influx or losing circulation while cementing.

After drilling concluded, the well was displaced with 2,020 kg/cu. m (126.1 lb/cf) kill mud. Prior to the cementing operation the kill fluid was displaced with a lighter 1,890 kg/cu. m (118 lb/cf) mud. During both displacements, MPD was used to maintain a constant bottomhole ECD of 2,015 kg/cu. m (126 lb/cf). The openhole section was cemented through CT while maintaining a constant bottomhole ECD of 2,015 kg/cu. m. No losses or gains were experienced.

The kill mud weight of 2,020 kg/cu. m was determined by a formation pressure equivalent to 2,010 kg/cu. m (125.5 lb/cf) mud density and formation fracture pressure equivalent to 2,040 kg/cu. m (126.1 lb/cf). Precise data on the downhole pressure regime were obtained by MPD in the drilling phase.

In conventional operations, a 2,040 kg/cu. m cement pumped into the annulus would fracture the formation and precipitate a well control event. If the kill mud density was reduced enough to circulate the mud without exceeding 1,950 kg/cu. m (121.7 lb/cf) bottomhole ECD, the wellbore would be underbalanced and risk taking a kick.

Application of MPD allowed the lighter fluid to be safely circulated. As the process involved four different fluid densities in the annulus, managing the bottomhole ECD was a challenge even with MPD and involved precise calculation of annular frictional pressure across the four fluids.

Closed-loop cementing approach

A closed-loop cementing plan was developed for operational procedures, and prewell calculations were updated with real-time data. Key steps in the plan involved running in the hole with CT, displacing the kill mud with the lighter mud, pulling CT while pumping cement, circulating on top of cement after it was placed, tagging total organic carbon and pulling the CT out of the hole. At each step, the bottomhole ECD was held constant.

While running CT in the hole, the shut-in tubinghead pressure was equalized using invert mud, and the wellhead swab valve was opened prior to the trip. The tubing was initially run in the hole at 20 m/min (66 ft/min) while circulating invert mud at a minimum rate of 0.3 cu. m/min (11 cf/min). Every 500 m (1,640 ft) a pull test was performed. Tripping speed was reduced to 5 m/min (16 ft/min) while running in the openhole section to minimize any surging. The bottom was tagged to confirm the depth and determine cement volume.

The hole was displaced through the CT prior to cementing operations to replace the 2,020-kg/cu. m kill mud with 1,890-kg/cu. m mud. MPD was used to monitor bottomhole ECD to ensure that it did not fall below 2,015 kg/cu. m. While displacing with the lighter mud, the pump rate began at 270 l/min (71.3 gal/min) and was increased to 400 l/min (106 gal/min) based on drops in annular frictional pressure and hydrostatic pressure. Afterward, the pump rate was increased to the maximum to keep bottomhole (BH) ECD constant at 2,015 kg/cu. m; surface backpressure was increased gradually to 580 psi. Once the kill mud was circulated out of the well, surface backpressure was set at 580 psi using annular pressure mode of the automated MPD software. The lighter mud was circulated bottoms-up a second time to ensure that no gas was in the wellbore prior to the cementing operation. The MPD choke was set to 580 psi SBP on the second circulation.

When cementing through the CT, 3 cu. m (106 cf) of 1,910-kg/cu. m (119.2-lb/cf) invert pre-flush and 3 cu. m of 1,910-kg/cu. m invert spacer was pumped ahead of the slurry. The spacer was followed by 6.84 cu. m (241.5 cf) of the first cement slurry, a 1,885-kg/cu.m (117.6-lb/cf) thermal cement designed for the openhole interval from 4,402 m to 4,050 m (13,287 ft). Next was the second cement slurry, which consisted of 5.59 cu. m (197 cf) of 1,910 kg/cu. m thermal cement designed for the interval between 4,050 m and 3,825 m. Once 600 l (558.5 gal) of cement exited the CT nozzle, the CT was retrieved at 14.63 m/min (48 ft/min) while the two slurries were pumped. The MPD operations followed a SBP ramp table, which was precalculated to maintain a BH ECD constant at 2,015 kg/cu. m. Then a backpressure of 545 psi was applied, increased gradually to 560 psi and then reduced to 531 psi because of hydrostatic pressure changes.

The cement plug was displaced with an invert spacer and preflush followed by spacers. A SBP of 531 psi was applied to hold the cement plug and maintain the BH ECD constant at 2,015 kg/cu. m. SBP was increased to 548 psi once the spacers were circulated out of the well. SBP was maintained while drilling fluid was circulated for eight hours while waiting on cement to set.

At the end of eight hours, the top of the cement was tagged at 3,772 m (12,374 ft), successfully concluding the challenging cementing operations and verifying that closed-loop cementing was able to achieve the same pressure control and safety experienced in difficult drilling conditions.

Expanding the breadth

The ability to cement the HP/HT exploratory well using CT and MPD methods further enhanced the capacity to safely and effectively drill wellbores in extreme pressure profiles. The application of MPD provided a means to safely cement the well without kicks or losses, whereas conventional techniques presented the risk of a well control event.