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英文翻译-石油钻井方面的
When cementing the 133/8-in. casing,the top wiper plug did not bump because of a failed drillpipe wiper dart.A cleanout run was performed, and the 133/8-in. casing was pressure tested to 345 bar against a deep-set mechanical plug. After the 133/8-in. casing was cemented in place, the 133/8×20-in. annulus was fractured for future cuttings injection.
121/4×131/2-in. Hole Section: 2820 to 7415 m. The drilling BHA was a 121/4-in. PDC bit, a 9-in. RSS with inclination-hold feature, an 8-in. Compensated dual resistivity with gamma ray tool MWD tool, and a 121/4×131/2-in.underreamer. This BHA drilled 4595 m in one run. The hole was opened to 131/2 in. to increase the margins for running the long 103/4-in. liner. Good performance was obtained from the RSS with respect to the inclination hold setting. The nudge command was very accurate. At section total depth(TD), the well was only 4.5 m away from the planned trajectory. No shocks were recorded while drilling, and the stick/slips were also maintained at a minimum.
Simulations and risk evaluations concluded that liner flotation was not required. Detailed friction analyses were performed, with both internal and external resources, to prove that the liner could be run conventionally. To verify the drag simulations, three other Visund wells above 7000 m MD were analyzed and calibrated for friction factors.
By use of these friction factors, a liner-running string was designed to withstand helical buckling. The running string consisted of 300 m of 8-in. drill collars above the hanger and 2400 m of 65/8-in. heavyweight drillpipe (HWDP) to surface.
81/2×97/8-in. Hole Section: 7265 to 9082 m. A pilot hole was planned through the oil/water contact (OWC), because of the high TVD uncertainty.A pumpdown gyro was run inside the 57/8-in. drillpipe at 6500 m to verify the MWD survey before drilling out the 103/4-in. liner. The MWD survey was used as the definitive survey because it was regarded as the better TVD measurement, proved later when drilling through the OWC. However, the gyro azimuthal measurement was regarded as better, and this information was used for optimizing reservoir well placement.
The planned well path was followed accurately, with a maximum DLS of 3.8°/30 m and the requested 77° inclination through the Draupne formation.The TD for the section was set when the OWC was detected in a sand formation.When running in with the cement stinger to plug back the pilot hole, the Draupne formation was found to have collapsed. The Draupne formation is an unstable shale formation. Fig. 3 shows a laboratory test on a core sample from the Draupne formation that was drilled through at a 90° angle. The cement plug then was set as planned by use of the pump-and-pull method from the top of the Draupne formation at 7801 m into the 103/4-in. liner.
When cementing the 133/8-in. casing,the top wiper plug did not bump because of a failed drillpipe wiper dart.A cleanout run was performed, and the 133/8-in. casing was pressure tested to 345 bar against a deep-set mechanical plug. After the 133/8-in. casing was cemented in place, the 133/8×20-in. annulus was fractured for future cuttings injection.
121/4×131/2-in. Hole Section: 2820 to 7415 m. The drilling BHA was a 121/4-in. PDC bit, a 9-in. RSS with inclination-hold feature, an 8-in. Compensated dual resistivity with gamma ray tool MWD tool, and a 121/4×131/2-in.underreamer. This BHA drilled 4595 m in one run. The hole was opened to 131/2 in. to increase the margins for running the long 103/4-in. liner. Good performance was obtained from the RSS with respect to the inclination hold setting. The nudge command was very accurate. At section total depth(TD), the well was only 4.5 m away from the planned trajectory. No shocks were recorded while drilling, and the stick/slips were also maintained at a minimum.
Simulations and risk evaluations concluded that liner flotation was not required. Detailed friction analyses were performed, with both internal and external resources, to prove that the liner could be run conventionally. To verify the drag simulations, three other Visund wells above 7000 m MD were analyzed and calibrated for friction factors.
By use of these friction factors, a liner-running string was designed to withstand helical buckling. The running string consisted of 300 m of 8-in. drill collars above the hanger and 2400 m of 65/8-in. heavyweight drillpipe (HWDP) to surface.
81/2×97/8-in. Hole Section: 7265 to 9082 m. A pilot hole was planned through the oil/water contact (OWC), because of the high TVD uncertainty.A pumpdown gyro was run inside the 57/8-in. drillpipe at 6500 m to verify the MWD survey before drilling out the 103/4-in. liner. The MWD survey was used as the definitive survey because it was regarded as the better TVD measurement, proved later when drilling through the OWC. However, the gyro azimuthal measurement was regarded as better, and this information was used for optimizing reservoir well placement.
The planned well path was followed accurately, with a maximum DLS of 3.8°/30 m and the requested 77° inclination through the Draupne formation.The TD for the section was set when the OWC was detected in a sand formation.When running in with the cement stinger to plug back the pilot hole, the Draupne formation was found to have collapsed. The Draupne formation is an unstable shale formation. Fig. 3 shows a laboratory test on a core sample from the Draupne formation that was drilled through at a 90° angle. The cement plug then was set as planned by use of the pump-and-pull method from the top of the Draupne formation at 7801 m into the 103/4-in. liner.
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