Bill Johnson
Forwest Inc.
Houston
Eric Hajas
Horwell Engineering & Services
Rueil-Malmaison, France
Horizontal drilling technology has advanced to the point that turnkey drilling contracts can be successfully completed. Forwest Inc., Houston, drilled two such turnkey horizontal wildcat wells for Union Pacific Resources (UPRC) in Dunn County, N.D.
Forwest realizes the dangers of turnkey contracts. But with a good rig, good people, and services, horizontal wells can be drilled profitably. The operating company can incur less cost, and fewer of its personnel are needed.
As in all turnkey wells, Forwest put in a risk factor, and this was realized on the two wells.
The team effort, managed by Forwest, included: Eastman Christensen and Teleco Oilfield Services Inc. furnishing the directional tools and know-how; Milpark Drilling Fluids providing the mud; Horwell giving technical assistance; and UPRC providing a consultant to keep everyone on track.
The two wells were drilled with Forwest Rig No. 5, a National 80 UE SCR rig under a full turnkey contract. Forwest furnished casing, cement, mud, and all services except building the location and roads.
The contract's objective was to drill a minimum horizontal drain of 1,500 ft cased with slotted pipe. Incentive rates were included for additional feet of cased drain between 1,500 and 2,500 ft.
ANDEKER NO. 1
The first exploration well, Andeker No. 1 44-34, was spudded in July 1990.
VERTICAL PART
Because of a salt section from 6,800 to 9,100 ft, the well was drilled with an oilbased mud, oil/water ratio of 75:25, from the top of salt section to TD.
No data were available from nearby wells. Therefore, a 9 7/8-in. straight hole was drilled with a rat hole through the Bakken reservoir to a vertical depth of 10,700 ft. Drilling took 29 days.
Logging confirmed the depth of Bakken that was detected by changes in the rate of penetration (ROP) and by the mud logging analyses. Logging also gave the dip angle of the formation and the thickness of the Bakken pay zone at the location.
BUILD ANGLE
For reaching the Bakken formation, a medium-radius build angle was planned. The well was plugged back to 9,800 ft. Cement was drilled out to the kick-off point at 10,148 ft.
Sidetracking with a steerable medium-radius motor and a diamond bit was done until 70% of the formation returns were observed on the shakers. This took 20 ft to achieve.
A second bottom hole assembly (BHA) with an Eastman medium-radius AB 14 Mach 1 downhole motor and a Smith 8 3/4-in. insert bit was run to build angle up to 65.
The tangent section was drilled with Eastman's double-tilted u-joint (DTU), and the length was adjusted to reach the pay zone with the correct inclination of 89.6 at the next run.
A last run was made with the AB 14 to build angle from 65 up to 86. This stopped just 2 ft above top of the Bakken. Because this stage lasted only a few hours, minimal nonrotating time was spent on bottom for the second buildup.
HORIZONTAL SECTION
Entry into the Bakken was made with a DTU. Drilling of the horizontal section started with an 89.6 inclination.
Forwest Rig No. 5 had three 1,000-hp triplex pumps rigged up to run two at any time. To avoid caving of the formation, the flow regime was kept laminar at 350 gpm. Because of this pump rate, penetration rate sometimes had to be reduced to enable cleaning of the hole.
To avoid possible fractures, which are known to create drilling problems in the lower part of the Bakken reservoir, the drain had to stay in the upper part.
Most of the drilling stayed in the upper part of the Bakken pay, within a 5 ft tolerance.
But following deviation control difficulties in the middle of the vertical part of the Bakken, a few feet were drilled in the bottom portion of the reservoir. After bringing back the well to the upper part of the reservoir, large cuttings were noticed on the shale shakers. This indicated that a fractured zone had been encountered during the offset of the trajectory.
Circulation was done during several minutes before each connection. Because some packing off occurred at the end of the horizontal section, several viscous pills were circulated.
TD was reached at 13,500 ft. It took 7 days to drill the 2,514-ft horizontal section. Three bits were run. A rotary drilling mode was used 89% of the time. During the other 11% of time, drilling took place in an oriented mode.
After the bit was pulled out and drill pipe laid down, 5 1/2-in. centralized casing was run smoothly using UPRC's design program.
The well was successfully cemented after 47 days on the location. Forwest's objectives were reached with 100% success.
DUTCH TREAT NO. 1
After moving Forwest Rig No. 5 to the new location, drilling of the second well, Dutch Treat No. 1 14-8, started at the end of August.
VERTICAL PART
The vertical section was drilled with the same bit sizes, 14 3/4 in. and 9 7/8 in., and the same mud as Andeker No. 1. Kick-off point at 10,629 ft was reached in 27 days.
BUILD ANGLE
An approximate top of the Bakken was determined from two nearby offset wells. Therefore, a rat hole was not absolutely necessary.
At 10,629 ft, an 8 3/4-in. insert bit was used to kick off the build angle. A 400-ft, medium-radius trajectory was planned for hitting the Bakken.
Time was saved by not having to drill the rat hole and the cement plug. Also, one round trip was eliminated.
After the first buildup from vertical to 65, a tangent section of 169 ft was drilled with a DTU at 65. This angle reduced the nonrotating time at bottom while drilling the next buildup.
A BHA with a medium-radius AB 14 Mach 1 downhole motor drilled the second buildup section. An additional gamma ray tool was run with Teleco's measurement-while-drilling tool (MWD) to determine the top of the Bakken pay.
The Bakken was encountered 3 ft above the expected target depth. Inclination at bit was 86.
HORIZONTAL SECTION
A BHA with a DTU was run without the gamma ray tool during the drilling of the horizontal section with an 89.6 inclination.
Mud logging gave a good indication of bit position in the Bakken because of gas shows in the mud.
The formation dip was adjusted because the top of the Bakken was touched in the middle of the horizontal drain. The bit position relative to the Bakken top was determined and followed with good accuracy. To avoid caving problems, laminar flow of 330 gpm was used.
To obtain good hole cleaning when penetration rate was high, the weight on bit (WOB) was reduced, and the cuttings were circulated out before each connection.
The BHA length under the MWD was reduced by 6 ft to improve deviation control and to stay in the upper part of the Bakken.
A total of 2,300 ft of spiral 5-in. heavy weight drill pipe (HWDP) was run in the curve to provide WOB and help the cutting removal by mechanical action on the lower bed of the well.
Because some packing off was observed, more spiral HWDP was added on top of BHA. But hole cleaning was not significantly improved.
After a run of 20 hr, a downhole failure occurred, and one downhole motor had to be changed out.
After running the fourth bit at 13,547 ft in the horizontal section, reaching bottom was difficult, and tight connections were encountered.
At 2,208 ft of horizontal drain, 90% of the objective was reached. Further drilling was risky and not financially justified.
Therefore, Forwest decided, with UPRC's agreement, to circulate and pull out of hole to run casing.
A key seat was encountered while tripping out. The key seat was at the end of the tangent, before the first build-up section and had formed as a result of working the last string at bottom.
The TD reached was 13,610 ft after 7 days of drilling and using 4-in. bits to drill a 2,208-ft horizontal section.
Drilling in a rotary mode was done during 91% of the drain. During the other 9% of the time, the oriented mode was used.
The 5 1/2-in. casing was centralized, smoothly run, and successfully cemented after 43 days on location.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
