ANTIWHIRL PDC BITS INCREASED PENETRATION RATES IN ALBERTA DRILLING

Doug Bobrosky
Baker Hughes Inteq
Calgary

Glenn Osmak
Petro-Canada
Calgary

The use of antiwhirl polycrystalline diamond compact (PDC) bits and improved drilling practices improved penetration rates and decreased well bore washout problems in a multiwell drilling program in northern Alberta.

The drilling economics on the wells in the Shekilie field program improved with an estimated savings of $20,000-40,000/well.

The primary objective of the drilling optimization program was to increase the rates of penetration (ROPS) in a 1,300-m intermediate section of the wells. Average ROPs increased considerably compared to runs with conventional roller cone bits.

By drilling with less weight on bit (WOB) and a stabilized bottom hole assembly (BHA), Petro-Canada consistently stayed within a 30-m target radius at a depth of approximately 1,650 m.

The antiwhirl PDC bits and an inhibitive mud system contributed to the quicker drilling of the time-sensitive shales. The hole washouts in the intermediate section were dramatically reduced, resulting in better intermediate casing cement jobs.

Also, the use of antirotation PDC-drillable cementing plugs eliminated the need to drill out plugs and float equipment with a steel tooth bit and then trip for the PDC bit.

By using an antiwhirl PDC bit, at least one trip was eliminated in the intermediate section. Offset data indicated that two to six conventional bits would have been required to drill the intermediate hole interval.

The PDC bit was rebuildable and therefore rerunnable even after being used on five wells. In each instance, the cost of replacing chipped cutters was less than the cost of a new insert roller cone bit.

ANTIWHIRL BITS

The backwards whirling motion of PDC bits can have a detrimental effect on the useful cutter life. 1-4 Basically, when a bit whirls, its instantaneous center moves about the bit face rather than about its true center as in smooth rotation. Consequently, the path taken by any single cutter will not be circular.

The cutters will impact the formation at various angles unanticipated during the bit design phase, leading to cutter damage in the form of spalling and chipping. The result is often premature bit failure.

The recent development of antiwhirl PDC bits has renewed interest in the use of PDC bits in many areas. 5 The development of whirl-resistant bits has resulted in longer bit life, improved rates of penetration, and increased reliability.

Antiwhirl PDC bit technology is based in part on the premise that bits will resist rotating off balance if the cutter loads are directed toward the low friction gauge pads, thereby forcing the bit against the borehole wall where it is stabilized. The most significant design features address the magnitude and the direction of the out-of-balance force. 6

The bit profile is a key design feature that enables the bit to resist whirl. Tests in laboratory conditions have shown that a very flat bottom profile is the most resistant to whirl. However, the effectiveness of the flat profile, or B-crown, is hindered by the limited number of cutters that can be placed on the shoulder and gauge areas of the bit (Fig. 1). In certain cases, a short parabolic profile may provide sufficient antiwhirl characteristics and offer improved shoulder and gauge protection (Fig. 2).

Field trials in Canada demonstrated the need for both bit profiles depending on the targeted interval.

BIT DEVELOPMENT

Antiwhirl bits are generally defined by a set of design rules put forth by Amoco Production Co., which began testing various styles of PDC bits at its research facility near Tulsa in the late 1980s. 1-4

These antiwhirl features include a flat profile, a resultant cutter force, a slick gauge, and a cutter devoid area (Fig. 3). Additionally, the bits should be run using specific operation criteria.

Amoco researchers discovered that in addition to the flat bottom profile, the cutter placement resulted in a significant side load. The side force helped stabilize the bit against the borehole wall, preventing the center of the bit from moving around its face, thereby eliminating whirling motion.

The first true antiwhirl PDC bits were introduced in the last quarter of 1990. The bit design was based on the flat bottom profile which provided the most stability when the formations and rock type change. The face of the bit showed extremely even cutter loading which lessened the chance of ringing out the nose while various lithologies were drilled.

Early in the development of antiwhirl bits, much of the field testing was in South Texas where the formations are typically soft shales with minor abrasive sands. 7 Although the original B-crown design was very stable, a weakness was identified on the shoulder gauge area where a typical dull grade was 2-5-WT-S-X-1-WE-PR. The bit design was altered to a short parabolic profile with extra cutters in the shoulder area. Although not as stable as the B-crown, this profile was significantly more stable in lab tests than that of a standard PDC bit. Field tests of this profile in South Texas showed significant improvement in bit life.

APPLICATIONS

Two intervals have been identified for antiwhirl PDC bit applications in Canada: a clastic sequence comprised of Tertiary and Cretaceous shales and sands similar to those encountered in South Texas and a carbonate sequence comprised of Devonian shales and argillaceous carbonates. 8 In the summer of 1991, antiwhirl bits with the short parabolic and B-crown profiles were run successfully in these two lithological sequences; the profiles appear to overlap in application. In harder formations and carbonate sequences, the B-crown may provide better performance because of the greater stability of that design. In the soft clastic formations, the short parabolic profile allows for faster drilling with reduced cutter damage.

CLASTIC SEQUENCE

The clastic sequence in central Alberta has soft shales and sands. This interval is relatively shallow at a depth of 1,506-1,800 m and is normally drilled with an average ROP of 25 m/hr.

The short parabolic profile bits were able to drill faster in the soft formations, apparently because the hydraulic design promoted better cuttings removal. Conversely, cuttings generated near the center of bits with the B-crown profile have to change direction nearly 90 after reaching the shoulder/gauge area. This sharp turn for the cuttings may lead to bit balling and subsequently slower ROPS.

The additional cutters on the outside diameter of the short parabolic profile and the reduced cutter damage allow less expensive rebuild cost when the bit is used for multiple applications.

Interestingly the B-crown outperforms the short parabolic profile in the harder drilling in the lower section of the interval. The lower cutter density of the B-crown results in higher weight on the individual cutters for a given WOB and better whirl resistance thereby improving ROP in the harder formations.

CARBONATE SEQUENCE

The carbonate sequence in northwestern Alberta and northeastern British Columbia comprises shales and limestones with very minor sands and silt lenses. The interval length typically ranges about 500-1,300 m and is generally drilled with an average ROP of 11 m/hr.

Both bit profiles were used in this interval, but the short parabolic profile sustained catastrophic cutter failure in the hard carbonate sections. The B-crown profile performed exceptionally well in the application interval.

In the harder carbonate formations, the B-crown profile's increased stability allowed the interval to be drilled without damaging the cutters. The lighter cutter density of the B-crown also provides better ROPs through the harder carbonate sequence.

SHEKILIE FIELD

The Shekilie oil field is located in the northwest corner of Alberta (Fig. 4). The field's oil producing zone is the Keg River pinnacle reef structure.

The typical well program calls for drilling a 349-mm hole from surface to 320-330 m followed by about 1,2501,300 m of 222-mm intermediate hole. After casing is set, another 200 m of 159-mm main hole is drilled. Fixed cutter bits were expected to produce the best economic results in the intermediate hole section.

After the surface casing is drilled out, the first formation encountered is the Banff, a Mississippian shale consisting of about 120 m of dark to medium gray shales with common siltstone interbeds. The Banff is easily drilled with ROPs typically ranging about 15-30 m/hr. The remaining formations in the intermediate section are Devonian carbonates and shales.

The next formation encountered is the Wabamun, which consists of microcrystalline limestone with common fossil fragments. The Wabamun formation ranges about 350-400 m thick here. The top of the formation is often a dense, weathered zone, and during drilling the formation may cause considerable torque at surface. Two fixed cutter bits (International Association of Drilling Contractors code M646 and S672) were tried in the past, but both failed very shortly after drilling into the Wabamun.

Following the Wabamun is 10-15 m of the jean Marie formation, a dense fossiliferous limestone. After this section, the 500-550 m thick Fort Simpson shale is encountered at about 950 m. The Fort Simpson shale is generally clean, making it well-suited to PDC drilling.

The Fort Simpson formation, however, is the most troublesome primarily because of the time-dependant nature of the shale. In other words, the longer the shale is exposed, the greater the chance for sloughing and hole washouts. Furthermore, the Fort Simpson shale has an unpredictable tendency for deviation problems. These problems may force a significant amount of "fanning" to prevent further angle building.

A short interval of Muskwa shale and Beaverhill Lake shale/limestone follows the Fort Simpson shale. The Slave Point limestone, a potential lost circulation zone, is encountered at approximately 1,550 m. The Slave Point limestone is followed by the Sulphur Point and Watt Mountain limestones and the Muskeg, which is a dolomite and massive anhydrite.

BIT RUNS

As the Shekilie drilling program progressed, the use of antiwhirl PDC bits in conjunction with a number of improved drilling practices led to improved economics on the later wells. Besides bit selection, other areas receiving particular attention were BHA selection, hole washout tendencies, and surface casing drill out characteristics. A new IADC M645 (AR435) antiwhirl PDC bit successfully completed five wells in a seven-well drilling program in the Shekilie field. Another M645 PDC bit (rental) completed the targeted intervals of two wells (Table 1).

WELL 1-26-117-8W6

The new M645 PDC bit used on the first well drilled a total of 1,125 m with an ROP of 16.61 m/hr. Although the bit reached total depth in the planned interval, the bit was tripped out because of a potential lost circulation zone in the Slave Point formation. The bit hydraulics on the run were designed to optimize hydraulic horsepower per square inch (hsi) with a flow rate of 1.2 cu m/min, thus generating 3.5 hsi. The bit inspection revealed slight wear on four cutters, which were subsequently replaced. Fig. 5 illustrates the run parameters for Shekilie wells.

WELL 6-4-118-7W6

The bit was rerun on the second well and drilled the entire intermediate hole section--a total of 1,277 m at 12.4 m/hr. The bit took 9 hr to drill out of the casing; it was recommended that a steel tooth bit be used to drill out the next well.

The BHA was a full packed-hole design consisting of a near-bit stabilizer, drill collar, string stabilizer, and drill collar/string stabilizer. It is believed this BHA resulted in lower ROPs because of packing off at the top stabilizer. Furthermore, the use of larger nozzles on the bit reduced the hydraulic horsepower to 1.6 hsi. After the run, 27 cutters on the bit had to be replaced.

WELL 14-31-117-7W6

A rental IADC M645 PDC bit was used in this well and had the best run to date in the intermediate section of the Shekilie field. The bit drilled 1,254 m at 15.63 m/hr and only had moderate cutter damage after the run. Compared to prior runs, the bit was run with a higher flow of 1.4 cu m/min with 2.54 hsi. The higher flow rates improved cleaning at the bit face. The hydraulic horsepower decreased as the nozzle sizes were increased. Thus, the hydraulics on the remaining wells were optimized for maximum flow. The float equipment on this well was drilled out with a steel tooth bit.

WELL 11-13-118-7W6

The original M645-type bit was rerun on a third well and drilled 1,252 m in 93 hr. The bit missed drilling the entire planned interval by 120 m. Although four cutters were replaced, the bit had very little wear. The bit may have been pulled prematurely and may have been able to complete the zone.

Unusually slow ROPs were encountered in the Slave Point carbonate sequence, even after the bit parameters were varied. Antirotation PDC-drillable cementing plugs were used on this well, and drill out time was less than 1-1/2 hr. A field specialist was present only until the bit reached the 821 m depth.

WELL 14-30-117-7W6

The same bit was rerun on a fourth well and drilled the entire 1,277-m interval at 10.34 m/hr. Antirotation cementing plugs were again used, and the drill out time was less than 2 hr.

Centrifuge problems caused mud weights to be higher than usual, contributing to the lower-than-expected penetration rates. After the run, 23 cutters had to be replaced on the bit.

WELL 5-5-118-8W6

In this well a rental IADC M645 bit drilled the deepest of all runs in the Shekilie field. This well was a horizontal prospect with a deep kick off point.

The bit drilled 1,100 m at 10.2 m/hr. The ROP was low because of the high mud weights and because the bit drilled deeper into harder formations. Because the antirotation cementing plugs were not available, a steel tooth bit was used to drill out the float equipment.

WELL 1-8-118-7W6

The initial M645 PDC bit was rerun on a fifth well and drilled 411 m before being pulled because of low ROP in the Wabamun formation. The bit lost three cutters on the nose. The bit encountered extreme torque at the top of the Wabamun.

A rental M645 bit was run in the Fort Simpson formation at 883 m. This bit drilled 207 m before being pulled upon encountering a siltstone stringer in this zone.

ROP IMPROVEMENT

The IADC M645 PDC drill bit significantly improved ROPs compared to previous wells drilled by Petro-Canada in the area (Fig. 6). The number of rotating hours has decreased from an average of 150-250 hr for wells drilled prior to 1990 to the 80-130 hr range for wells drilled since 1990.

In the earlier wells, directional fanning of the hole usually was responsible for the longer rotating hours. There is still room for improvement primarily because of the solids control problems prevalent in the Fort Simpson formation. The high mud weights attributed to centrifuge downtime substantially decreased the expected ROPs through the Fort Simpson shale in the two most recent wells.

The IADC M645 has increased ROPs in nearly every zone penetrated through the intermediate hole section (Fig. 7). Table 2 compares the ROP performance of PDC bits with that of the roller cone bits used in off set wells in the Shekilie intermediate hole.

The most dramatic improvements in ROP occurred in the soft shale sequences under the surface casing shoe and in the Fort Simpson, where ROP increased 50-250%. Modest increases in ROP (30-50%) were also recorded in the carbonate sections (Wabamun, Slave Point, and Sulphur Point). As drilling proceeded towards the intermediate casing point, the ROPs dropped to the level of those encountered with conventional roller cone bits.

Besides drilling faster through the intermediate hole section, the M645 PDC drilled the entire interval in one run, thereby eliminating at least one bit trip.

The bit was durable--it was able to be rebuilt after every run. One bit, for example, was able to drill a total of 5,342 m on five wells. The rebuild cost ranged about $1,000-5,000, and after the first well PetroCanada purchased the bit. On several wells where rental bits were used, the rebuild costs were not charged back to Petro-Canada.

BHA SELECTION

Previously, Shekilie drilling programs used packed-hole BHAs to minimize deviation in the Fort Simpson shale. Later, it was concluded that neither slick nor packed-hole assemblies could successfully eliminate the deviation problems encountered in the formation.

This problem is serious because the Shekilie geological structures usually dictate a fairly small (30 m) target radius. In the past, deviation problems in the Fort Simpson resulted in hole angle quickly reaching 3-4. Because of the low WOB and the high speed fanning used to lower the inclination to reach the specified target radius, several rotating hours were lost.

When the IADC M645 (AR435) antiwhirl PDC bit was selected for drilling the intermediate section, PetroCanada followed as closely as possible the BHA selection recommended by the bit manufacturer, Hughes Christensen Co. (Fig. 8). This BHA included a nearbit stabilizer, bypass sub, monel drill collar, string stabilizer, and regular steel drill collars. The difference between the BHA selected by the operator and the one recommended by the bit manufacturer was the bypass sub/monel drill collar combination. A short monel drill collar was suggested for use between the near-bit and string stabilizers, but the "pony" collar was unavailable.

The bypass sub was used in the Slave/Sulphur Point sequence where lost circulation had previously been encountered. Lost circulation material (LCM) could be pumped easily through the bypass sub. The bit nozzles were thought to be too small to handle sufficient volumes of LCM without plugging.

The final BHA selection in combination with less WOB enhanced the antiwhirl tendencies of the IADC M645 to minimize deviation. Inclination did not exceed 2 on any survey, and the majority of the surveys taken in the Fort Simpson formation did not exceed 1.5.

WASHOUT PROBLEMS

Earlier wells drilled in the Shekilie field had excessive washout in the intermediate section immediately below the surface casing shoe and particularly in the Fort Simpson shale. In Shekilie wells drilled prior to 1990, hole washouts in the intermediate section ranged 30-90% over gauge.

A number of reasons have been suggested for this tendency, including directional fanning of the hole, longer bit rotating hours in the time-sensitive Fort Simpson shale, and inadequate drilling fluid properties. Therefore, the drilling plan needed to have this intermediate section drilled as quickly as possible using a shale-inhibiting mud system. 9 10

The mud system used directly below the surface casing shoe was changed from an Alcomer-based fluid (anionic water-soluble organic polymer for shale stability and fluid loss control) to a low fluid loss gel/X-Pel-G (treated gilsonite) system. Wells drilled with the previous mud system had numerous washouts even when fanning the hole was not required. Recently, the muds in the Shekilie wells have been maintained with a fluid loss of 8-10 ml/30 min and an X-Pel-G concentration of 8-9 kg/cu m. The X-Pel-G helps seal microfracture permeability in the Fort Simpson shale and creates a thin film on the borehole wall to prevent excessive shale instability and hole erosion.

The most recent wells have had fewer rotating hours in the intermediate hole (80-130 hr vs. 150-250 hr) and have eliminated the fanning to correct directional problems. Therefore, hole washouts have decreased significantly from 30-90% over gauge to about 4-20% over gauge.

The decrease in hole washout resulted in the use of much less cement and water volumes. The change to a light-weight cement on the second stage and casing rotation above the stage tool has also been effective in preventing gas vent flows from the shallow, hydrocarbon-bearing zones under the surface casing shoe.

DRILL-OUT CHARACTERISTICS

The selection of a PDC bit instead of a conventional roller cone bit was thought of as a means of drilling out surface cementing plugs, float equipment, and the entire intermediate hole interval in one run.

In the first couple of wells, much longer to drill out the conventional rubber cementing plugs than did the conventional roller cone bit.

The plugs were spinning under the bit, which made adequate drill-out shearing action more difficult. Once the bit passed the cementing plugs, drilling out the float collar, cement, and float shoe progressed at about the same rate as that for a roller cone bit. After about 9 hr were spent drilling out of the surface casing on one well, the drill-out procedure was changed.

In the next well, a conventional steel tooth bit was used for the drill out. This bit worked adequately, but a trip was necessary to run the PDC bit for drilling under the surface casing shoe.

At that time, new antirotation PDC-drillable cementing plugs were planned for the remaining wells. The top and bottom cementing plugs consisted of a plastic core covered by a 3/8-in. thick rubber coating. The plugs were designed to be easily sheared by a PDC bit and not to have the spinning tendencies of conventional rubber plugs.

The results from drilling out the last two wells were impressive. The time needed to drill out the plugs and float equipment decreased to 1'/4 hr, and it was no longer necessary to trip out a steel tooth bit before running the PDC bit. The antirotation plugs are an economical alternative to drilling out with a steel tooth bit.

ACKNOWLEDGMENT

The authors thank PetroCanada, Hughes Christensen Co., and Baker Hughes Inteq for permission to publish this article and Jim Redden for preparation of the manuscript.

REFERENCES

1. Cooley, C.H., Pastusek, P.E., and Sinor, L.A., "The Design and Testing of Anti-Whirl Bits," SPE paper 24586, presented at 67th Annual SPE Technical Conference and Exhibition, Washington, D.C., Oct. 4-7, 1992.

2. Brett, J.F., Warren, T.M., and Behr, S.M., "Bit Whirl: A New Theory of PDC Bit Failure," SPE Drilling Engineering, December 1990, pp. 275-281.

3. Langeveld, C.J., "PDC Bit Dynamics," IADC/SPE paper 23867, presented at 1992 IADC/SPE Drilling Conference, New Orleans, Feb. 18-21, 1992.

4. Pastusek, P.E., Cooley, C.H., Sinor, L.A., and Anderson, Mark, "Directional and Stability Characteristics of Anti-Whirl Bits With Non-Axisymmetric Loading," SPE paper 24614, presented at 67th Annual SPE Technical Conference and Exhibition, Washington, D.C., Oct. 4-7, 1992.

5. Sinor, L.A., and Warren, T.M., "Application of Anti-Whirl PDC Bits Gains Momentum," SPE paper 25644, presented at SPE 8th Middle East Oil Show and Conference, Bahrain, Apr. 3-6.

6. Warren, T.M., Brett J.F., and Sinor, L.A., "Development of a Whirl Resistant Bit," SPE Drilling Engineering, December 1990, pp. 267-274.

7. Wampler, C., and Myhre, K., "Methodology for Selecting PDC Bits Cuts Drilling Costs," OGJ, Jan. 15, 1990, pp. 55-60.

8. Schnell, D.M., "Composite Cutter Bits Extend Application of Conventional PDC Bits in Western Canada," SPE paper 19569, presented at 64th Annual SPE Technical Conference & Exhibition, San Antonio, Oct. 8-11, 1989.

9. Davis, N. III, and Tooman, C.E., "New Laboratory Tests Evaluate the Effectiveness of Gilsonite as a Borehole Stabilizer," presented at IADC/SPE Drilling Conference, Dallas, Feb. 28-Mar. 2, 1988.

10. Cagle, W.S., and Schwertner, L.F., "Gilsonite Stabilizes Sloughing Shales," OGJ, Mar. 27, 1972, pp. 61-64.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.