Rotation of a Long Liner in a Shallow Long-Reach Well
- D.A. Gust (Esso Resources Canada Ltd.) | R.R. MacDonald (Esso Resources Canada Ltd.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1989
- Document Type
- Journal Paper
- 401 - 404
- 1989. Society of Petroleum Engineers
- 5.8.7 Carbonate Reservoir, 1.14.1 Casing Design, 1.7 Pressure Management, 5.2 Reservoir Fluid Dynamics, 1.12.1 Measurement While Drilling, 1.14.4 Cement and Bond Evaluation, 2.2.2 Perforating, 2.2.3 Fluid Loss Control, 1.7.7 Cuttings Transport, 5.4.1 Waterflooding, 1.14 Casing and Cementing, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.14.3 Cement Formulation (Chemistry, Properties), 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.6 Drilling Operations, 1.10 Drilling Equipment, 1.1.6 Hole Openers & Under-reamers, 1.6.1 Drilling Operation Management, 1.7.5 Well Control, 3.2.4 Acidising, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.5.1 Surveying and survey programs
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Adequate primary cement quality in horizontal wells is an industry concern. We identified two factors that limit primary cement quality success - free water cavities on the high side of the hole and an inadequately cleaned hole. Casing movement was considered necessary for the second problem. Reciprocation was quickly ruled out because slack-off drag would severely restrict casing return to bottom, and the risk of lost returns caused by surge pressures would be high. Alternatively, rotation was chosen. This paper discusses the design and rotation of a 3,409-ft [1039-m] -long liner run in an 81° well at Norman Wells, NWT. Differentiation between running string torque and liner torque was fundamental to the design of the liner and to the setting of rotary torque limits for the operation.
Esso Resources Canada Ltd. has been expanding the production of the Norman Wells field through development drilling since 1982. Recently, development wells have been drilled along the reef margin areas of the reservoir. Because of topographical constraints, these long-reach wells have 80 to 90° inclinations.
The success of EOR through waterflood depends highly on zone isolation through the primary cement job because the limestone reservoir contains extensive vertical fractures. Four long-reach wells have been drilled in the Norman Wells field since 1979. All have been cemented. Only the last two cement jobs, however, provided adequate isolation between perforation zones.
Norman Wells Well F-50X was spudded on April 28, 1987. This well was kicked off at 167 ft [51 m]. Angle was built at a rate of 60/100 ft [60/30 m] to the planned maximum inclination of 81°. This angle was maintained through the target zone within the reservoir. The target entry point (top of the reef) was 2,826 ft [861 m] from the surface location at 1,440 ft [439 m] true vertical depth (TVD). Final total depth (FTD) was 5,787 ft [1764 m] measured depth (MD) at 1,795 ft [547 m] TVD. The total horizontal displacement was 5,013 ft [1528 m]. Fig. 1 shows the vertical profile of Well F-50X.
Fig. 1 summarizes the casing program for Well F-50X. A 20-in. [50.8-cm] conductor was driven to approximately 49 ft [15 m]. Surface casing (13 3/8-in. [34-cm]) was set at 541 ft [165 m] MD and cemented to surface. Intermediate casing (9 5/8-in. [24.5-cm]) was to be run to the top of the reef, 3,602 ft [1098 m] MD, and cemented to surface. This casing string was not run past 2,720 ft [830 m] MD because of hole problems. A 5 1/2-in. [14-m] production liner was run from 2,372 to 5,781 ft [723 to 1762 m] MD (FTD). Details of the liner design, running procedures, and cementing program will be discussed later.
Drilling Fluid Program.
Well F-50X was drilled with a gel/polymer water-based drilling fluid. The drilling fluid density varied between 8.8 and 10.4 lbm/gal [1050 and 1250 kg/m3] during drilling of intermediate and production hole. Gel and polymer were added to maintain the plastic viscosity and yield point between 15 and 25 cp [15 and 25 mPa·s] and 17 and 32 lbf/100 ft2 [8 and15.5 Pa], respectively. These properties provided adequate hole cleaning during drilling of all hole sections.
Sawdust and medium-sized lost-circulation material were added to the mud to control lost circulation encountered near the reef top. More lost circulation material was added when lost circulation occurred at FTD.
Table 1 summarizes the drilling program for Well F-50X. A 12 1/4-in. [31.1cm] pilot hole was drilled with an 8-in. [20.3-cm] positive-displacement mud motor (PDMM) with a 1.50 bent housing. The well was kicked off at 167 ft [51 m] and angle was built at 6 to 7°/100 ft [6 to 7°/30 m] to a 240 inclination at 548 ft [167 m]. The hole was opened to 17 1/2 in. [44.5 cm] with a bull-nose hole opener. Surface casing was run and cemented to surface. No problems were encountered during drilling of the surface hole.
After heading up a diverter stack, the surface casing was drilled out and 12 1/4-in. [31.1-cm] intermediate hole was drilled to the 3.602-ft [1098-m] intermediate casing point. This entire hole section was drilled with the same 8-in. [20.3-cm] bent-housing PDMM as on surface hole. Angle was built at an average 5.9°/100 ft [5.9°/30 m] and then maintained by rotating the drillstring at 25 rev/min during drilling with the bent-housing motor assembly. When adjustments to inclination and/or direction of the wellbore were required, the motor was oriented for 3 to 6 ft [1 to 2 m]. Measurement-while-drilling (MWD) surveys taken every 30 ft [9 m] provided the directional control required to steer the assembly to the target entry point.
The hole was conditioned to remove the cuttings bed formed during drilling. Drillpipe rubbers were installed on the bottom 1,840 ft [560 m] of drillpipe. The drillstring was tripped to bottom and reciprocated during circulation at 454 gal/min [1.72 m3/min]. The drillpipe rubbers agitated the cuttings bed, enhancing the cuttings transport from the well. The hole was worked at 1 ,640-ft [500-m] intervals from the bottom to ensure that the cuttings bed in all portions of the well with inclinations greater than 35° had been disturbed by the drillpipe rubbers.
Intermediate casing was run after the hole was conditioned. The casing became stuck at 2,713 ft [827 m]. The casing was pulled and rerun to 2,720 ft [830 m], where it was cemented. This left 879 ft [268 m] of 12 1.4-in. [31.1-cm] hole below the intermediate casing shoe.
A full blowout preventer (BOP) stack was installed on the intermediate casing to provide well control during drilling of the 8 3/4-m. [22.2-cm] production hole. The production hole was drilled with a 6 3/4-in. [17.1-cm] PDMM with a 10 slick bent housing. This assembly was rotated at 25 rev/min to hold drift angle and direction. When adjustments to the wellbore path were required, the assembly was oriented for 3 to 6 ft [1 to 2 m]. As in intermediate hole, MWD surveys were taken on each connection to maintain tight directional control.
The drillstring used in this section of hole consisted of five non-magnetic drill collars run above the motor, 1,050 to 1,800 ft [320 to 550 m] of 4 1/2-in. [11.4-cm] drilIpipe, 1,250 to 1,870 ft [380 to 570 m] of 5-in. [12.7-cm] drillpipe, and 5-in. [12.7-cm] heavy-wall drillpipe to surface. This drillstring configuration reduced pipe-handling time and wellbore friction. The amount of 4 1/2- and 5-in. [11.4- and 12.7-cm] drillpipe below the heavy-wall drillpipe depends on the weight on bit, the expected friction coefficient, and the inclination at which the pipe is run. Markie1 discusses use of this drillstring configuration.
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