SLIM-HOLE CASING PROGRAM ADAPTED TO HORIZONTAL WELL

Sept. 6, 1993
Leigh Foster ARCO British Ltd. Guildford, England A type of slim-hole well design reduced the cost of drilling a horizontal well in the southern North Sea. The basic slim-hole drilling and casing program was similar to that used in conventional directional wells in the field, but with slight modifications for drilling with logging-while-drilling (LWD) tools and running production liners.
Leigh Foster
ARCO British Ltd.
Guildford, England

A type of slim-hole well design reduced the cost of drilling a horizontal well in the southern North Sea. The basic slim-hole drilling and casing program was similar to that used in conventional directional wells in the field, but with slight modifications for drilling with logging-while-drilling (LWD) tools and running production liners.

The oriainal field slimhole casing design incorporated only the minimum number of casing strings required to drill conventional slant wells. The design is referred to as slim-hole because there is no 26-in. surface hole or 20-in. casing. This design saves approximately 380,000 (about $570,000) per well.

Nearly 2,600 ft were successfully drilled at over 80 inclination in ARCO British Ltd.'s Pickerill A6 well, the first time in the southern North Sea that a horizontal well was drilled through the reservoir without first casing off the overlying evaporate sequence.

The Pickerill gas field was discovered in the U.K. southern North Sea in 1984, and development drilling began in May 1991. The Pickerill field is located in approximately 72 ft of water, some 40 miles east of Humberside, England, and between the Amethyst and Sole Pit fields.

The field development plan included two 9-slot, not-normally-manned platforms with the gas delivered to shore via a dedicated pipeline. The geology of the field is fairly complex compared to other southern North Sea fields. The reservoir is the Permian Rotliegend sandstone, which is a thin dunal sand of variable quality.

To minimize well cost but without risking well safety or drilling efficiency, the number of casing strings is limited to four, with a fifth as a contingency. An 8-1/2-in. hole is still normally drilled through the reservoir.

Horizontal drilling was proposed for the northwestern corner of the field to improve well performance. The horizontal well would cost more than the other wells but would be expected to yield a higher flow rate and better reserve recovery.

Despite the growing popularity of horizontal drilling in the North Sea, ARCO British Ltd. had relatively, little experience with horizontal wells, having previously drilled only one in the southern North Sea in 1990. However, ARCO's worldwide horizontal well experience, accumulated in the research center in Plano, Tex., was used to augment the available expertise.

The plan for the horizontal well, designated 48/llb-A6, was based on the existing field well design but adapted to allow the drilling of a pilot hole, coring, and logging. If necessary, the pilot hole could be suspended and not completed while another well was drilled. At that time a horizontal sidetrack would be planned. The purpose of the pilot hole was to assess reservoir quality and structural elevation.

The drilling program was setup to meet the requirements of the reservoir engineering, geology, and drilling departments. The geologists required real-time LWD tools to be used through the reservoir for the directional driller to steer the well into the most productive zones. Because these tools were not available for a 6-in. hole, an 8-1/2-in. hole was essential.

WELL DESIGN

Fig. I shows the basic casing design planned for all the Pickerill wells. Below the predriven 30-in. conductors, the surface formations are Cretaceous chalk and reactive clays. A 16-in. hole is drilled through these formations and cased off with 13-3/8-in. surface casing.

A 12-1/4-in. hole is then drilled through Jurassic shales and limestones and a complex faulted Triassic sequence of shales, sands, mobile salts, and anhydrites. These formations make oilbased mud essential. Below this section is the massive Zechstein evaporite/dolomite sequence. The 9-5/8-in. protective casing is set at the top of this section because the Zechstein dolomite are sometimes over pressured (up to 18 ppg).

After an 8-1/2-in. hole is drilled through the salts, the Rotlie-end target sandstone is encountered. If the dolomite are not over pressured, it is ARCO British Ltd.'s practice in the southern North Sea not to case off the salts before drilling into the reservoir. The mud weight can usually be kept low enough not to cause losses or damage to the sandstone. This practice had not previously been attempted in a horizontal well, however.

One drawback of the slimhole design is that it provides little flexibility for unforeseen events. the most likely event that would change the casing scheme is over pressure in the Zechstein dolomite. The contingency plan in this case is to set the 7-in. liner above the reservoir and to complete the well with a 6-in. hole and run a 5-in. liner.

The standard directional program includes a simple slant design with a kick off in the 16-in. section at about 530 ft. All the angle is typically built with a steerable assembly before the surface casing joint is reached at about 3,000 ft true vertical depth (TVD). This angle is then maintained by using a combination of steerable and rotary drilling assemblies to total depth (TD) at around 9,000 ft TVD. Fig. 2 is a typical directional well plan. Steerable drilling assemblies are used wherever possible because of directional uncertainty.

The wells are logged by wire line across the reservoir interval. Some wells are cored where reservoir properties are not well known.

The emphasis on the completion design was on simplicity and reliability, using field-proven components designed for long life (Fig. 3). Chrome steel components are used because of the high C02 content of the produced gas.

PILOT HOLE PLAN

Throughout the planning process for the pilot hole and sidetrack, the geologists, geophysicists, reservoir engineers, and drilling engineers held regular meetings to optimize the well design to meet all the project needs. Once the design was complete, the team gave final approval in a formal review meeting.

The casing plan for the pilot hole was identical to that in the other wells. The only exception was that the final production liner would not be set unless the reservoir was of sufficient quality, as determined in predrill criteria, to justify completing the pilot hole. The 9-1/8-in. casing would be the last string set in the pilot hole at about 9,600 ft measured depth (MD).

DIRECTIONAL PLAN

Fig. 4 shows the directional plan and the actual well path. The target radius was only 260 ft-it was important to avoid some large faults seen on seismic surveys to the north. The pilot hole's azimuth would have to be turned from 340 to 300 by the 9-1/8-in. casing point.

This azimuth would line up the 8-1/2-in. hole with the preferred horizontal section path which would begin at more than 6,000 ft step-out. It was also necessary to be able to drill the sidetrack and reach horizontal at a point relatively close to the original pilot hole for depth control, but using a long-radius profile. This plan was achieved by building angle in the 8-1/2-in. pilot hole from 45 to 60 inclination.

By holding a 45 inclination angle in the same section in the planned sidetrack before making the final build, it would be possible to enter the reservoir less than 400 ft from the pilot hole, but using a build rate of only 4/100 ft.

Before the pilot hole was drilled, it was not known whether over pressure would force the 7-in. liner to be set above the reservoir. Thus, a contingency directional plan was prepared for a sidetrack with a 6-in. diameter. In this case, using LWD would not have been possible.

EVALUATION PROGRAM

LWD tools would be required for steering in the horizontal sidetrack. Thus, the tools would be run in the pilot hole for comparison with ",ire line logs to show the U.K. Department of Trade & Industry that they were fit for purpose. The entire reservoir was planned to be cored to help identify the best reservoir zone in which to drill the horizontal section.

PILOT HOLE DRILLED

Fig. 5 shows planned and actual drilling time for the pilot hole and subsequent sidetrack. This plot indicates the main delays during the drilling operation.

A steerable 1/2 bent-housing 9-5/8-in. motor was used in the 12-1/4-in. hole to turn the well's azimuth. A gradual turn from 345 to 312 azimuth was achieved below 6,000 ft MD with a maximum dogleg of approximately 2/100 ft. This dogleg had no adverse effect on torque and drag in this hole section.

Another steerable assembly was used in the 8-1/2-in. hole to make the required build and turn. This assembly had a slick 1-1/4 bent-housing motor; it was extremely effective at making directional changes and also drilled efficiently when rotated. The same type of steel-bodied polycrystalline diamond compact (PDC) bits were used as had been run on the conventional wells.

EVALUATION

The reservoir was successfully cored at 58 inclination in three runs totalling 268 ft MD. The hole was logged with a combination resistivity/sonic/neutron tool on wire line, and formation pressures and samples were taken from the reservoir. The pilot hole did not meet the predrill criteria for reservoir quality confirming the requirement for the horizontal sidetrack. Analysis of the logs and core showed a higher permeability zone 70 ft TVD from the top of the reservoir and approximately 20 ft TVD thick. This zone would be the target for the horizontal section.

Because the reservoir was cored, the LWD tools were not run until after TD was reached. The LWD tools were run on a wiper trip after the first wire line logging run and recorded as the assembly reamed through the reservoir. Reaming was necessary because the LWD neutron density tool requires rotation to take an accurate reading because of the mud standoff effect. Rearning speeds were controlled at 100 ft/hr to provide sufficient data density.

A comparison of the wire line density log and LWD density log showed discrepancies in some formations. Further comparison runs from another well, drilled after suspending the A6 pilot hole, were needed before the tool was considered adequately proven.

HORIZONTAL SIDETRACK PLAN

The well was to be reentered, cleaned out, and then sidetracked using the cement plug set across the 9-1/8-in. casing shoe. The 8-1/2in. hole was to be drilled through the Zechstein and the Rotliegend formations. However, drag in the final build and horizontal sections was predicted to be too great to run a 7-in. liner all the way to the planned TD of 14,000 ft MD. Also, the Zechstein salt has been known to collapse uncemented or poorly cemented casing, but no simple and economic plan could be developed for cementing (and then perforating) a single 4,400 ft liner with a 2,000 ft horizontal section.

The solution chosen was to drill 4,400 ft of 8-1/2-in. hole and then run a 7-in. liner to just above the reservoir. The liner would then be cemented 2,000 ft off bottom and then cleaned out with a 6-in. bit. A 5-in. preperforated liner would be run to TD through the 7-in. liner and left uncemented (Fig. 6). The cement around the 7-in. liner would protect it from salt collapse, but the reservoir interval would be left uncemented. The advantage of this plan was that the completion design would be exactly the same as that for the conventional wells, but without the perforating guns.

To prevent the 7-in. liner cement from slumping into the open hole below and possibly forming a bridge, two external casing packers would be used above the guide shoe. A ported collar above the packers was designed to open after the packers inflated, allowing the cement to be pumped into place.

After the 5-in. liner was run, it was planned to pump a complex series of spacers and solvents through the open hole and casing to displace the oil-based mud with completion brine. Return permeability tests were performed to select the best solvents and to ensure the formation would not be damaged during this process.

DIRECTIONAL PLAN

Fig. 7 shows the planned and actual sidetrack paths. The sidetrack was planned to kick off 100 ft below the 9-1/8-in. shoe and to drop angle to below the original hole, which built angle in the same section. The same angle was to be held for 500 ft in a tangent section planned to allow flexibility on azimuth or final TVD. The final build would begin at around 11,770 ft. The reservoir was expected to be penetrated during this build, with 90 inclination reached at 12,100 ft MD, only 23 ft TVD below the top of the reservoir. This depth was selected because it was thought the well would be drilled up dip, and even at a 90 inclination the well would penetrate deeper into the reservoir.

The plan called for no doglegs greater than 4/100 ft. The dogleg limitation would reduce drill string torque and drag, drag and bending loads on the 7-in. liner run into the 8-1/2-in. hole, and drag on the 5-in. liner run through the 7-in. liner.

EVALUATION PROGRAM

The real-time LWD resistivity and neutron density tools required in the reservoir would be run coupled to the transmitter for the directional and gamma ray measurement-while-drilling (MWD) tool.

The resistivity sensor is at least 40 ft from the bit, and the neutron density is even farther from the bit. However, the positions are still close enough to react and make changes to the well path when necessary.

SIDETRACK DRILLED

Because of the success of the steerable assembly in the pilot hole, a similar assembly was used in the sidetrack. A 1-1/2 bent-housing motor with a 7/4-in. maximum OD was run. This assembly easily achieved the kick off, drop, build, and turn as required.

The drill string design used is commonplace in horizontal wells in the southern North Sea. Above the bit, motor, and MWD tools, a jar is run to free the bottom hole assembly if it becomes stuck. About 2,000 ft of drill pipe are then run in compression to above the final build section. Above this section of drill pipe, heavy weight drill pipe is run to provide weight on bit, and another jar is run in case the pipe becomes stuck in the build section. No drill collars are used, except those in the MWD/LWD tools. Table 1 lists a typical drillstring.

The reservoir was not encountered at the expected depth, so 94 inclination was maintained for 240 ft MD until it was penetrated. The angle was then built to 89 inclination. The maximum dogleg created in the build section was 6/100 ft, which was still within the limits required for running the liners.

EVALUATION

The sands at the top of the reservoir were extremely abrasive, mainly because of the high angle. After drilling just 600 ft., the PDC bit was pulled. The bit was 3/8-in. under gauge, and the motor and MWD tools had lost up to 1/2-in. in diameter.

The LWD tools suffered a high failure rate because the wire channel protection on the outside of the tools wore away.

The need to rotate the density tool meant it had to be reamed through any sections drilled in oriented mode. These sections would have been reamed anyway' but not so slowly. The whole reservoir section was eventually logged, and the data were used for reservoir interpretation.

HOLE CONDITIONS

As in the pilot hole, the actual torque and drag were not extreme. They were monitored for trends daily on the rig, but they did not change significantly once the well reached horizontal.

MWD surveys were taken at least once or twice per stand drilled. Rotational cluster surveys were taken regularly to check for drillstring magnetic interference, although none was found.

No differential sticking was encountered, despite an overbalance of more than 600 psi. The overbalanced mud weight was required to stabilize the exposed salt formation above.

Hole cleaning was optimized by maintaining high mud flow rates with annular velocities of 200-240 fuming in the horizontal section. Occasional wiper trips were made to where the hole angle was less than 45 inclination to clear away any cuttings beds. Also, regular hole cleaning sweeps were made by pumping oil-based pills to induce turbulence followed by high viscosity pills. As each pill reached the surface, the shakers were monitored for increases in cuttings returns.

The oil-based mud properties were very similar to those used in previous wells, but with slightly higher yield point and gel strength to improve hole cleaning.

In the early stages of the horizontal section, it was thought necessary to ream all the way out of the hole to the shoe when tripping. As more hole was made and no tight spots were experienced, however, this procedure was relaxed until eventually only the first five stands off bottom were backreamed. The pipe could be pulled through the rest of the horizontal section without problems.

LINERS

Once the hole was drilled, the 7-in. and 5-in. liners were run as planned. There were no serious problems running the liners, but the 7-in. liner encountered some 40,000 lb of resistance in the build section. When the 7-in. liner had been hung off, the hydraulic-release running tool would not release as expected. It was thought that the brass setting ball was not "seating" on the landing collar, which was at over 80 inclination. A plastic ball was then dropped, and it seated. The running tool then released, the external casing packers inflated, and the cementing valve opened. The cement job was then performed as done on the conventional wells.

The 7-in. liner, shoe, and horizontal open hole section were cleaned out with a 6-in. bit, and the 5-in. liner was then run as planned. A string of 2-3/8-in. tubing was run inside the liner to enable circulation through the shoe. The tubing was to have been used for the displacement, but because of an internal pack-off failure it was impossible to displace the oilbased mud from the open hole as planned. The spacers efficiently removed the mud from inside the casing, however.

COMPLETION

The completion string was run without problems. A short tailpipe with a perforated joint and wire line plug profiles was run below the packer to just above the top of the 5-in. liner. Because the well was to be suspended prior to testing, a wire line plug was set in the tailpipe before the string was run. Tools were available to pull the plug with coiled tubing because the inclination at the nipple was 73', but the plug was successfully pulled with conventional slick line.

After the initial flow period, a coiled tubing clean out run attempted to remove any residual mud, but the drag was too high for the tubing to enter the horizontal section.

RESULTS

  • The horizontal well was drilled using the same basic design as that for a standard directional well. In the Pickerill field, the practice of drilling the Zechstein and the Rotliegend formations with the same hole section worked well in the horizontal well. Squeezing salt, torque and drag, and the high hydrostatic overbalance presented no real problems.

  • Without having a 6-in. hole drilled, this well saved more than 380,000 (about $570,000) compared to the cost of a more conventional horizontal well. The relatively large 8-1/2-in. well bore enables the use of LWD to find the best reservoir rock in which to put the horizontal section, which greatly improves the chances of a successful well.

  • An improvement in the rearning speeds for logging oriented sections with the density tool could save a significant amount of rig time.

  • Almost 2,600 ft of hole at more than 80 inclination was drilled in A6; the horizontal departure was more than 6,300 ft. Other horizontal wells could be drilled using a similar well design. Because torque and drag were not limiting factors, a longer horizontal section could be drilled given a suitably continuous reservoir.

ACKNOWLEDGMENT

The author would like to thank ARCO British Ltd. and its partners (Superior Oil (U.K.) Ltd., Conoco (U.K.) Ltd., Deminex U.K. Oil and Gas Ltd., Britoil plc, Sun Oil Britain Ltd., Industrial Scotland Energy, and Coatite Oilex Ltd.) in the Pickerill project for permission to publish this article. The author also thanks his colleagues for reviewing the manuscript.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.