Michael L. Johnson
Drilex Systems Inc.
Houston

Improved drilling efficiency and the use of steerable positive displacement motors (PDMs) helped keep an Austin chalk horizontal well on target and below cost.

Some of the first horizontal wells drilled in the Austin chalk typically cost about $1 million at rig release. Union Pacific Resources Co.'s (UPRC) Smith-Knolle Unit No. 1 well, spudded on Apr. 21, 1991, cost only $870,000 because of the use of less expensive and more efficient downhole technology. According to 1993 UPRC figures, similar Austin chalk horizontal wells cost an average of $650,000 at rig release.

The Austin chalk formation is an upper Cretaceous, fractured limestone containing interbedded and sometimes marly shale streaks. The formation extends northeast from the Pearsall field in south Texas through south central Texas and into Louisiana.

Field development in the Austin chalk began more than 60 years ago; however, many wells have had low-to-average oil recovery. Recent thorough studies of the natural fracture matrix in the Austin chalk revealed that the fractures were not interconnected.

The ability of a horizontal well to intersect numerous fracture systems made the Austin chalk an excellent candidate for horizontal drilling.

Two of the original goals of Austin chalk horizontal wells were to test the drillstring at a 90 inclination and to determine whether increased production justified the additional time and cost of horizontal drilling.

Most of the early Austin chalk wells had tangent sections planned for the middle of the curve. Because failure of the drillstring from compression was a great concern, heavy weight drill pipe was often run in the well below the kick-off point through the curve and in the lateral reach intervals. Geologic sidetracks were common.

The reliability of early measurement-while-drilling (MWD) systems, when available, was often questionable. Motor reliability and the predicted build rate were also questionable.

Most Austin chalk horizontal wells no longer have planned tangent sections in the curve because modern angle-build motor systems are capable of changing their effective build rates by rotation of the rotary table for short intervals. Therefore, there is no need to trip for a motor change when predicted build rates are not met.

Additionally, some of the improved downhole motors can drill 100 hr or more. Reliable MWD tools are now readily available and routinely operate without failure for 100 hr or more. Improved gamma ray tools help precisely identify formation boundaries to prevent geologic sidetracks caused by drilling out of the Austin chalk.

WELL PLAN

UPRC's Smith-Knolle Unit No. 1, located in the southern portion of Burleson County, Tex., was planned to intersect the lower Austin chalk with a 4,410-ft lateral section inside a 29-ft true vertical depth (TVD) window. Fig. 1 is a schematic of the lease plat with the well oriented to maximize the horizontal section.

The following plan was closely matched throughout the drilling of the well. The drilling plan was to run and cement a 10-3/4 in. string of surface casing in a 14-3/4 in. hole at 1,925-ft measured depth (MD). A 5,000-psi blowout presenter (BOP) stack was to be nippled up prior to drilling the 9-7/8 in. hole out of the 101/4-in. casing shoe. The 9,-/s-in. hole was to be drilled vertically to 8,614 ft TVD, the planned kick-off point. The vertical portion of the 9-7/8 in. hole from 1,925 ft to 8,614 ft was to be drilled with native mud and with gel sweeps for hole cleaning.

The pH would be kept below 9.5 upon entering the Midway shale at 5,481 ft. Offset data showed that treating the mud pH in this manner would control sloughing shale problems in the Midway shale for 22-24 days. The water loss would be reduced to less than 10 ml prior to reaching the planned kickoff point. The 9-7/8 in. hole would be directionally drilled from 8,614 ft to 9,134 ft MD. High viscosity sweeps would clean the directionally drilled portion of the 9-7/8 in. hole.

If lost circulation occurred in the Pecan Gap formation overlying the Austin chalk, the entire lost circulation zone would be drilled prior to spotting liquid casing across the interval. If lost circulation occurred in the Austin chalk, the well would be drilled to casing point without fluid returns.

At 9,134 ft, 7-5/8 in., 26 lb/ft and 29.7 lb/ft N-80 grade casing would be run and cemented with a blend of 65/35 premium Poz mix cement weighing 14.5 ppg. The cement would not be brought to surface. Premium casing (Wedge 521 type) connections would be run on the lowest 550 ft of casing.

The mud for the 6-1/8 in. hole section (lower portion of curve and lateral reach) would be freshwater with Xan-Vis sweeps for hole cleaning as needed. Freshwater would be used to minimize damage to microfractures common in the Austin chalk. Brine would be kept on location to weight up the system, if necessary.

Because drilling with water might produce an under-balanced condition, a 500-psi rotating head to help control kicks would be added when the 7-1/16 in. 5,000-psi wellhead and BOPs were nippled up. If lost circulation occurred while the Austin chalk was drilled, the well would continue to be drilled, if possible. If cuttings buildup became a problem because of lost circulation and poor hole cleaning, a Temblok pill would be set and allowed to cure. If no loss circulation occurred, the mud yield point would be maintained below 10 lb/100 sq ft by adding freshwater.

WELL TRAJECTORY

The Smith-Knolle Unit No. 1 well was planned to intersect the lower Austin chalk with approximately 4,410 ft of lateral hole while maintaining a 92.91 inclination. To achieve this goal, the well path was divided into three parts: the upper, second, and third intervals.

The upper section was planned as a 12/100 ft build interval in a 9-7/8 in. hole ending in a 7-5/8 in. casing point at 9,036 ft TVD/9,134 ft MD with a 62 inclination.

The second interval was planned with an 8/100 ft build rate in a 6-1/8 in. hole, starting 5 ft below the 7-5/8 in. casing shoe. This interval was planned to end with a 92.9 inclination at 9,515 ft MD. This portion of the well would be drilled through a bentonite marker. This formation, commonly called the Tuff, is extremely soft and is difficult to exit if entered at a high angle of inclination. The well was planned to cross the Tuff with a 75-80 inclination. The Tuff would also serve as the upper target boundary for the lateral hole section.

The third interval was the lateral reach portion of the well extending 4,322 ft from the end of the second build at 9,515 ft MD to a total well depth of 13,837 ft MD. The 6-1/8 in. hole was planned to have a final inclination of 92.9 for the entire interval.

BHA

Two types of positive displacement downhole motors were planned for use in this well (Fig. 2). The first build interval was planned to be drilled with a 6-3/4 in. shortbearing-housing motor with a 2 x 1-1/4 double bend and a 9-7/8 in. bit. The 6-1/8 in. hole build interval and the entire lateral reach portion of the well were planned to be drilled with a 5-in. motor with a 1-1/2 bend.

The 6-3/4 in., short-bearing-housing motor has a modified thrust and radial bearing section that decreases the distance between the bit and the bend on the motor. Shortening this distance increases the amount of dogleg severity the motor can produce for a given bend. The shortened distance from bit to bend allows this motor to produce 14-16/100 ft of dogleg. This particular motor can be rotated with the rotary table for short intervals to decrease the effective build rate.

The 5-in. motor with a 1-1/2 bend resembles a conventional steerable motor. This motor is designed for drilling continually in a rotary mode or in an oriented fashion. Because of the low build-up rate required for the second build interval (8/100 ft), the 5-in. motor would drill the lower curve in a sliding mode at the end of build, and the motor would drill ahead in the lateral using the rotary table. An MWD system would be used in the directional portions of the well.

A 9-7/8 in. rock bit (International Association of Drilling Contractors Class 116) was planned for the first build interval. A round-profile bladed 6-1/8 in. polycrystalline diamond compact (PDC) bit was planned for the second build interval and the entire lateral reach.

The first build interval would be drilled with 4-1/2 in. heavy-weight pipe in the curve and 4-1/2 in. drill pipe to surface. The 4-1/2 in. drill pipe would be laid down after the 7-5/8 in. casing is set. Thereafter, only 3-1/2 in. grade S135 drill pipe, the downhole motor, and the monel drill collars required for the MWD system would be used through the curve and in the lateral reach.

DRILLING RESULTS

The 14-3/4 in. hole was drilled to a depth of 1,925 ft, and a string of 10-3/4 in. casing was run and cemented as planned. The 5,000-psi BOP stack contained two sets of pipe rams, one set of blind rams, one annular, and a 500-psi rotating head. The straight hole portion of the 9-7/8 in. hole was drilled to the kick-off point at 8,614 ft MD in 8 days.

Three washouts in the drillstring occurred during this interval.

On the twelfth day from spud, the kick-off assembly was picked up and run in the 9-7/8 in. hole (Table 1). A multishot survey performed on the last trip out before the kick-off assembly was picked up indicated the well's bottom hole location had drifted northwest 47-ft from vertical. The well had an inclination of 1.9 at this point.

The build rate required to achieve the planned 62 inclination at casing point from this new bottom hole location was 11.93/100 ft. Because this rate was so close to the planned build rate of 12/100 ft, no changes were made to the first proposed bottom hole assembly.

The 9-7/8 in build assembly, using MWD for orientation, drilled to 9,143 ft MD, a distance of 529 ft (Fig. 3). The motor drilled in a sliding mode for 80% of this interval. The relatively large amount of rotation (20%) was necessary because of abnormally high build-up rates (up to 19.7/100 ft) encountered. Rotating the motor when needed kept the average build rate for the 9-7/8 in. assembly at 12.07. No significant hole problems occurred during the 2 day's of drilling. The 7-5/8 in. casing was run and cemented according to plan with the casing shoe at 9,143 ft. The inclination at this point was 67. The TVD of the casing shoe was 9,000 ft, approximately 36 ft higher than planned.

The casing was set high for two reasons:

Typically, 1-2 of inclination are lost when a stick BHA is used to drill out of the casing. Additional vertical depth is needed to make up this loss.
The higher casing setting depth also reduced the build rate required in the lower build interval. The casing shoe and 5 ft of new formation were drilled with a 6-3/4 in. rock bit on a nonstabilized (slick) BHA and 3-1/2 in. drill pipe (Table 2).

The 5-in. steerable motor assembly was picked up and run with a 6-1/8 in. PDC bit (Table 3). MWD was again used for orientation of the assembly.

The motor drilled in the sliding mode from 9 148 ft to 9,290 ft. At this point with 74.9 inclination, MWD surveys showed the well approximately 42 ft high in the curve; therefore, the steerable assembly was rotated ahead for 63 ft of measured depth. The well path was then back on line, and the assembly drilled ahead in the sliding mode. At 9,622 ft with approximately 90 of inclination, the motor was again rotated to drill straight hole. At 9,792 ft, a 32-ft slide was made to reach the final hold inclination of 92.6 (only 0.3 below the plan of 92.9). At 9,824 ft, rotary drilling with the motor was initiated with occasional 15-ft slides to maintain inclination. From 9,824 ft to 12,072 ft MD, five slide intervals were drilled to build angle. At 12,072 ft, a 26-ft slide increased inclination from 92.201 to 941.

Drilling continued in the rotary mode with 94 inclination held to a depth of 12,452 ft. The BHA was then tripped out because of an MWD failure. After a new MWD tool and 60 joints of 3-1/2 in. drill pipe were picked up, drilling continued in the rotary mode to 12,670 ft MD. The bentonite marker (Tuff) was then entered at 8,948 ft TVD.

The Tuff was expected to be approximately 45 ft higher. The close proximity of the Tuff to most of the lateral well section may have caused the angle dropping tendency of the 5-in. steerable motor assembly. Because drilling out of this stringer would take 500-600 ft of lateral section, it was decided to drill an open hole sidetrack.

After two unsuccessful attempts, an open hole sidetrack was drilled at 12,426 ft MD (Fig. 4). Drilling continued with occasional slides for correction of inclination and direction. The well reached a total MD of 13,703 ft on day 27 from spud. The well was logged and then completed open hole.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.

SLIDING AND ROTARY PDM DRILLING KEEP HORIZONTAL WELL ON TARGET

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