George Rizk
Baker Hughes Inteq
Houston
Mike Clough
Baker Hughes Inteq
Aberdeen
Integrated services and incentive contracts helped deliver an onshore horizontal gas well ahead of schedule.
Elf Petroland By's Harlingen 8 well in Holland was drilled and completed in 26 days, instead of the 33 days planned. Incentive bonuses were awarded, and the gas well began production early.
Elf Petroland used one supplier to coordinate service operations and make rig site operations more efficient. The streamlined organization on site improved communication and simplified administration and logistics.
Rig site problems were addressed quickly, and solutions implemented effectively because of the integrated-services structure.
The Harlingen 8 well design included an aggressive casing program that eliminated the 13 3/8-in. string of surface casing, which was run on other similar wells in the area. In addition, the well was drilled with three different mud systems, one of which was an oil-based system requiring on site treatment to meet stringent environmental regulations.
Baker Hughes Inteq provided the majority of services on the project, including directional drilling equipment and personnel, directional and formation evaluation measurement-while-drilling (MWD) services, gyroscopic surveying, mud products, and mud engineering. Baker Hughes Inteq also coordinated procurement of drill bits, waste treatment and solids-control services, and liner and completion equipment from other Baker Hughes companies.
To streamline operations, a well site coordinator was provided to be a liaison with the company man and to oversee the performance of rig site service personnel. The company man, the well site coordinator, the rig manager, the geologist, and other relevant personnel held meetings each morning.
In addition, the well site coordinator reported daily to the Baker Hughes Inteq project coordinator in Alkmaar Holland. This communication ensured that all parties stayed informed of progress on the project and that unexpected problems could be dealt with quickly.
The performance incentive scheme was based on a plan to drill and complete the Harlingen 8 well in 33 days, with a bonus paid for each day less than 32, to a maximum of 4 days.
Conversely, for each day more than 34, up to a maximum of 4 days, the agreed upon lump-sum payment would be reduced by a penalty. After 38 days, a day rate would apply.
The drilling contractor worked under a separate incentive program.
WELL PLAN
Harlingen 8 was planned as a J-profile well drilled with a medium radius (Fig. 1). The well was planned to have a 6-in. diameter, 500-m long horizontal drainhole in the Ommelanden chalk formation. The top of the chalk is at 1,045 m true vertical depth.
The original plan caned for a 17 1/2-in. hole with 13 3/8-in. casing run from surface. During further planning and comparison to the offset Harlingen 7 well, however, the 13 3/8-in. casing string was eliminated because no gas was expected from the shallow, overlying sandstone formation, the Brussels sand.
Instead, the Harlingen 8 would be drilled with a 12 1/4-in. hole. The water-based mud would then be displaced with an oil-based system for drilling the 8 1/2-in. hole from 925 m to 1,319 m and to 79 of inclination.
The oil-based mud system would be used to drill a 6-in. hole out of the 7-in. liner run in the 8 1/2-in. hole. The 6-in. section of the well would reach horizontal at 1,337 m and remain horizontal to 1,830 m total depth (TD). After the logging runs, a 4 1/2-in. slotted liner would be set, and a 4 1/2-in. completion string would be run.
The final well plan was to drill vertically to the initial kick-off point at 309 m, then kick off at 3/30 m building the inclination angle to 30.
12 1/4-IN. SECTION
Because of the very soft clays and unconsolidated sands in the 12 1/4-in. hole section, kicking off the well was difficult.
Four additional trips were required to change motors and reset the adjustable kick-off sub to improve the build rate. When firmer claystones and sandstones were penetrated at around 600 m, the build rate was more easily achieved.
The modified directional profile produced a final inclination of 37 1/2 at 908 m in the 121/4-in. interval.
The bottom hole assembly (BHA) included an 8-in. adjustable kick-off motor, an 81/4-in. MWD tool, and a 121/4-in. bit. The MWD tool provided survey and gamma ray data throughout the 121/4-in. section.
One 12 1/4-in. ATM G1 bit with three 20/32-in. nozzles drilled the section (870 m) in 54 1/2 hr, for an average penetration rate of 16 m/hr.
A bentonite/polymer mud system was used in the upper part of the 12 1/4-in. interval. When the well reached 500 m, the mud was treated with KC1 to inhibit the claystones. In general, the penetration rate was controlled to less than 30 m/hr to avoid solids buildup in the annulus. Additionally, several periods of circulation off bottom were required to treat the system.
The problems in the 12 1/4-in. interval included mud losses as large as 10 cu m/hr when the sandy upper part of the section were drilled. The desander and desilter overloaded from the large amounts of sand and silt circulated out of the well. The solids control equipment had to be modified on site.
Despite these drawbacks, the 12 1/4-in. hole section was drilled more quickly than the 5 days planned, and 9 1/8-in. casing was set and cemented without problems.
8 1/2-IN. SECTION
The 9 5/8-in. shoe track was drilled with a rotary assembly. The mud system was changed from the water-based system to a low-toxicity, oil-based system. The oil-based mud was easy to maintain and provided excellent hole conditions in the 8 1/2-in. section. Drag on trips was minimal.
Conveyor screws installed on the shale shakers removed the oily cuttings and deposited them in containers for removal from the site to comply with environmental regulations.
A gyroscopic survey confirmed the MWD survey data in the 12 1/4-in. section. A 6 3/4-in. adjustable kick-off motor built hole angle to 80 at a rate of 2 1/2/30 m. At 1,212 m, this BHA was pulled, and a rotary assembly then drilled a short tangent section to 1,319 m.
For the tangent section, a dual propagation resistivity MWD tool was placed as close as possible to the bit. The MWD tool in this position made possible identification of the top of the chalk reservoir. The dual propagation resistivity tool provided directional surveys, gamma ray data, and resistivity data with 100% data recovery.
The 8 1/2-in. hole section was drilled 107 m deeper than originally planned and ahead of schedule.
The 7-in. liner was run to 1,319 m and cemented without problems. The well was cleaned out to the top of the liner, and the pack-off bushing was drilled out. The 7-in. tie-back packer was then run and set without problems.
This operation was completed ahead of the scheduled 4 days, requiring only 2 days, 23 hr from starting to run the liner to drilling out the shoe.
6-IN. SECTION
A rotary assembly drilled out the shoe track. A motor assembly was then run to build angle in the 6-in. hole. The low-toxicity, oil-based mud was used in this hole section also.
The MWD tool, used throughout the 6-in. section, indicated the motor assembly was building angle more quickly than predicted during drilling in the oriented mode (without string rotation). When the BHA drilled up into the shale overlying the chalk at 1,369 m measured depth, the bit had to be steered back into the target zone at 1,427 m.
From there to 1,830 m TD, the well was effectively steered as planned, including being drilled once more into the overlying shale and back into the chalk as the geologist requested.
Two ATJ 22 bits were used to drill 511 m from the shoe to TD in the 6-in. hole; the penetration rate averaged 12 m/hr. Penetration rates were intentionally controlled to limit cuttings-gas liberated into the mud system.
Despite a problem with scale buildup in the drill pipe affecting MWD readings at one point, the 6-in. hole was completed ahead of schedule. This interval was drilled in 4 days and 11 hr, compared to 8 days planned.
Electric logs were run on wire line and drill pipe without problems. A 41/2-in. slotted liner with a concentric inner tubing string was run and set to TD. These operations required 3 days and 3 hr, compared to 5 days planned.
OFFSET COMPARISON
In early 1992, Elf Petroland drilled the Harlingen 7 well with a directional profile similar to that in the Harlingen 8. The Harlingen 7 was drilled with the same type of mud system and the same drilling rig (Kenting Rig 21) as the Harlingen 8.
The earlier Harlingen 7 well, however, had a 17 1/2-in. top hole section with a 13 3/8-in. casing string. Also, a 7 1/8-in. tie-back liner was run and cemented to surface. This operation took 41 hr. A 9-m core was cut in the 6-in. hole section, adding another 17 hr to the total drilling time on Harlingen 7.
The 7 5/8-in. tie-back liner was not run on Harlingen 8 because no significant casing wear (short drilling durations) was expected on the 95/8-in. casing. Consequently, the 9 5/8-in. casing was considered in good condition and suitable for use as the production casing.
A top drive system replaced the kelly/rotary table system on Kenting Rig 21 for the Harlingen 8 project.
During the planning of Harlingen 8, these differences were taken into account and were reflected in the projected drilling time curve. After the time adjustments, the HarLingen 8 well was still drilled faster than the offset Harlingen 7 (Fig. 2).
In particular, in the 6-in. hole section of Harlingen 8, the performance and ability of the motors and bits coupled with reliable data allowed accurate "geosteering" for optimum drilling rates.
ACKNOWLEDGMENT
The authors thank Elf Petroland By and Baker Hughes Inteq for permission to publish this article. The authors also thank F. Bourdages, drilling and completions operations superintendent, and J.M. Sauzay, drilling and completions manager, both with Elf Petroland, for their assistance.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
