METHODOLOGY FOR SELECTING PDC BITS CUTS DRILLING COSTS

Jan. 15, 1990
Charles Wampler Enron Oil & Gas Co. Corpus Christi, Tex. Kent Myhre Eastman Christensen Houston A bit-selection methodology proved effective for choosing polycrystalline-diamond-compact (PDC) drill bits in Zapata and Webb counties of South Texas. This program reduced drilling days per well up to 50% compared to wells drilled just 10 years ago. This decrease in drilling and tripping time has typically saved more than 30% of authority for expenditure (AFE) dry hole costs.
Charles Wampler
Enron Oil & Gas Co.
Corpus Christi, Tex.
Kent Myhre
Eastman Christensen
Houston

A bit-selection methodology proved effective for choosing polycrystalline-diamond-compact (PDC) drill bits in Zapata and Webb counties of South Texas.

This program reduced drilling days per well up to 50% compared to wells drilled just 10 years ago. This decrease in drilling and tripping time has typically saved more than 30% of authority for expenditure (AFE) dry hole costs.

The significant savings are, in part, a result of increasing PDC bit performance in the production hole, oil mud interval, where PDC bits have already been proven. More significantly, PDC bits have been successfully expanded to the intermediate hole, water-based mud interval where earlier PDC bit designs generally experienced poor or uneconomical results.

SOUTH TEXAS DRILLING

The Wilcox (Lobo) trend of Webb and Zapata Counties in South Texas is an established major gas-producing horizon. Since the early 1970s, more than 1,000 wells in nearly 100 fields have been drilled in the prolific trend, which became more actively developed after its classification as a "tight" gas formation by the Federal Energy Regulatory Commission (FERC) in 1979. Successful development of the Lobo has been a result of advances in reservoir evaluation, stimulation, and completion methods technology.1

Real advances in drilling efficiency were not realized until PDC drill bits were introduced in the early 1980s. The standard practice became to displace the water-based mud system with an invert-emulsion oil mud after setting 7-in. intermediate casing. Oil muds proved beneficial to PDC bit operations in the Tertiary sandstone and shale sequences of South Texas. The combination quickly gained acceptance in drilling below the intermediate casing depth.

PDC bits in the intermediate hole with water-based drilling fluids generally proved uneconomical in these earlier tests.

A growing understanding of PDC thermal wear-rate response, rock-cutting mechanics, and design features that affect bit performance has contributed to the rapid evolution of PDC bits. New, more hydraulically and mechanically efficient bit designs and optimization of operating parameters have expanded the PDC bit application zone to include the intermediate hole interval in water-based mud.

The bit designs currently used in the Lobo trend area evolved from a bit-development program approach. This is a methodology of evaluating dull characteristics, field data, and bit performance after each run. From this step-by-step design, modifications are made until an optimum design is determined.

This method of bit selection and design modification was used by Enron Oil & Gas Co. to significantly lower costs in its Webb and Zapata County drilling operations.

LOCATION AND GEOLOGY

The Lobo trend extends from northwestern Webb County to southwestern Zapata County, and into Mexico to the south and west. It is bounded to the north by the Sligo shelf margin and the west by the Salado arch (Fig. 1). Drilling continues to expand the boundaries to the south and east. In these directions, the Lobo sands dip to depths of approximately 10,000-12,000 ft.

The Tertiary stratigraphic section was deposited as a series of gulfward-thickening terrigenous clastic wedges. Sandstone geometry in the section reflects the interaction of fluvial and marine processes. The lower-most Wilcox (Lobo) section, consisting of alternating sandstone, siltstone, and shale sequences, overlies the Midway shale.

Gravity sliding and intense faulting of the Lobo section into numerous fault blocks over the Midway shale occurred soon after deposition. Lobo sands are very fine grained, with a shalely matrix and are interbedded with shales that represent 50-75% of the entire section.

A thick lower Wilcox shale unconformably overlies the Lobo, while the upper Wilcox consists of alternating sandstone and siltstone sequences with a massive sandstone at the top. This sandstone is often referred to as the Carrizo sand. A thick shale of the lower Claiborne group overlies the top of the Wilcox group. The Queen City formation overlies the shale and consists of a sandstone and shale sequence.

CASING AND MUD PROGRAM

Typically, 9 1/8-in. surface casing is set at 500-1,200 ft to protect the freshwater sands and provide anchoring for the blowout preventer (BOP) equipment. Then, an 8 3/4-in. hole is drilled out with water-based, gel-chemical mud. Mud weight ranges from about 9.0 ppg under the surface hole, to about 10.0 ppg at the intermediate casing point.

These deeper Lobo wells almost always require that 6,500-7,500 ft of 7-in. intermediate casing be set in the lower Wilcox shale for control purposes before drilling the abnormally high pressured Lobo sands.

A 6 1/4-in. hole is drilled to approximately 9,000-12,000 ft TD (Fig. 2). A conversion to oil-based mud is made in this interval and mud weights range from 13.0 ppg to 16.0 ppg

BIT EVOLUTION

There have been basically three evolutionary steps in the bit programs of the deeper Lobo wells. Fig. 3 illustrates representative bit programs for the years 1979, 1982, and 1989 for a particular area about 20 miles east of Laredo, Tex., in Webb County.

In 1979, wells were drilled with roller-cone bits exclusively.

Typically, three to four milled tooth (MT) and two to three tungsten-carbide insert (TCI) roller-cone bits would be required to complete the 8 3/4-in. diameter hole interval. About two MT and two TCI roller-cone bits would complete the 6 1/4-in. diameter hole interval.

By 1982, early design PDC bits successfully replaced roller-cone bits in the 6 1/4-in. hole, oil-mud interval, generally increasing both relative rate of penetration (ROP) and hours per bit.

Typically, intermediate-casing float collar and shoe, and some formation, would be drilled with an MT bit. Then one or two early design 6 1/4-in. PDC bits would drill to TD.

A recent 1989 Enron Oil & Gas offset of the two previous wells used a soft 8 3/4-in. TCI bit (IADC code 437) immediately under surface casing, replacing about three MT bits. After an MT bit was run for a short interval, a current-design 8 3/4-in. PDC bit, style R-437, was run replacing two TCI bits and greatly improving ROP.

Because PDC-drillable plastic-component float equipment is utilized, the intermediate-casing float collar and shoe are drilled out, and the 6 1/4-in. hole is drilled to TD in one bit run at a much greater ROP using a current-design PDC bit, style R-435. Also, these PDC bits are rerun on one to two more wells.

Average drilling and tripping time per well has decreased as a result of these bit-program improvements. (Fig. 4). Wells drilled with all roller-cone bits would require about 15-16 days of rotating and tripping time. Using PDC bits in the 6 1/4-in. hole reduced this time by about 2-3 days. The 1989 bit program in Fig. 3 required about 7 days, or better than a 50% time savings.

BIT PROGRAM METHODOLOGY

In the mid-1980s, an evaluation program was begun in the Lobo trend area to optimize PDC bit design for maximum economic and performance effectiveness. This program consisted of a systematic search methodology that utilized data from successive bit runs to make improvements in bit design and application (Fig. 5). Generally, optimizing PDC bit design involves selecting the proper cutter element size and density, bit profile, and hydraulic arrangement for the particular application.

The first step involved setting the objective of drilling from casing point to casing point or TD using one bit per hole size interval. A field-proven standard-bit style was chosen for the initial test to determine formation drillability and PDC wear resistance. All drilling and bit data were then analyzed and bit design changes recommended for the next test. The iteration was repeated until the optimum bit design was determined (Table 1).

PROGRAM APPLICATION

The 6 1/4-in. hole was first targeted to test current-design PDC bit performance relative to older-design PDC bits that had been proven for this application. Eastman Christensen's R433 PDC bits were run on several wells in Webb and Zapata Counties.

The R433 (IADC code M645) has a short parabolic profile which permits better point loading distribution across the nose of the bit, and allows greater cutter density towards the gauge area. Standard 1/2-in. PDC's are set in a ribbed cutter arrangement with deep waterways in front of the ribs to allow for efficient chip clearance and cuttings removal.

The R433 performed exceptionally well, drilling out the float equipment and on to TD, while greatly improving both ROP and bit life compared to the early design PDC bits. The R433 bits exhibited even wear, indicating an efficient profile and cutter distribution.

The next step was to run an R435 (IADC code M646) PDC bit, which is a heavier set version of the R433. The R435's averaged about 6,600 ft at 48 ft/hr over the life of the bits. The increased cutter density increased total footage per bit by about 30%, with no reduction in ROP. This was determined to be the optimum bit style in the 6 1/4-in. hole. The 6 1/4-in. R433/R435 PDC bits lowered cost per foot by 47% compared to the early design PDC bits (Fig. 6). An average savings of $17,537/well was realized in the production hole, and $43,847 over the life of the bits, which can usually be run on three wells before dulling.

The biggest challenge of the bit development program was to successfully use PDC bits in the 8 1/4-in. hole. The standard-design R435 was selected for the first test to determine formation drillability of particular formations, and to provide base data for comparing future PDC bit performance and establishing new bit selections.

The R435 drilled out cement and the surface casing float equipment and then drilled 4,396 ft to 6,036 ft at an average ROP of 74.5 ft/hr. This replaced three MT and one TCI roller-cone bits while increasing average ROP by 23%. Although the R435 greatly increased ROP in the lower interval, it only equalled roller-cone ROP in the top interval. The bit was pulled when it dulled after drilling through the upper Wilcox sands. The wear mode was worn cutters towards the outside diameter.

For the next run, a larger-diameter cutter on the same bit profile was recommended to increase ROP in the upper hole and extend bit life by providing greater diamond height and area available for wear.

An R535 (IADC code M312) King Cutter bit was selected. This style features 1-in. PDC cutters set in a ribbed cutter arrangement, with water courses on a short parabolic profile. The R535 drilled 4,058 ft at 106.7 ft/hr and was pulled when it dulled at 5,1 43 ft.

The dull condition was worn cutters and broken cutters towards the outside diameter. This indicated some impact damage had occurred.

Although the R535 increased ROP in the upper interval, it had become clear that a more durable bit would be required to drill the lower interval from the lower Queen City formation through the upper Wilcox sands. Therefore, attention was turned to the depths below 4,000 ft, where ROP could be improved most.

Both the R435 and R535 had worn out towards the OD.

This is a typical wear pattern for PDC bits that indicates that the work rate of the cutters is too high for the harder, more abrasive sandstone intervals. Adding more cutters to the bit would provide a lower work rate and, therefore, lower wear rate in the critical shoulder area. This would extend bit life.5 6

An R437 (IADC code M646), an ultra-heavy set version of the R435, was selected for the next test. It was run in the hole at 4,201 ft and drilled 2,881 ft to TD at 55.9 ft/hr. This replaced one MT and two TCI roller-cone bits, lowering cost by $1.46/ft for a $4,203 savings.

Only minimally worn, the R437 was clearly capable of more footage per well. The same bit was recommended for the next well. It went into the hole one MT bit under surface casing to find the optimum interval for its use. The rerun R437 drilled 2,039 ft at 62.7 ft/hr, more than doubling roller-cone penetration rate through this interval. It dulled and was pulled at 5,884 ft with worn shoulder cutters.

Although the R437 significantly increased ROP and lowered cost per foot in the lower interval, bit life was still limited by cutter wear on the shoulder. Referring to the bit selection flowchart, it was decided to change the bit profile to a medium-long parabolic. This would increase surface area towards the outside diameter and allow greater cutter density in this critical area.

An R428 (IADC code M646) was selected to replace the R437. The R428 has a medium parabolic profile with ultra-heavy set cutter density in a ribbed cutter arrangement with deep water courses. The bit was run one MT bit under surface casing and drilled 3,620 ft at 51.7 ft/hr. It was pulled at 5,879 ft after dulling, and was rung out on the nose section with minimal wear on the shoulder and flank areas.

OPTIMIZING PARAMETERS

The bit profile, bit hydraulics, and rotary speed were the three parameters that were optimized.

PROFILE

It was apparent that the R428 shifted too much of the work rate to the nose section, leaving it vulnerable to damage while encountering the harder abrasive sandstones of the upper Wilcox.

The R437 with its short parabolic profile and ultra-heavy cutter density (Fig. 7) had exhibited the best performance. It was decided to return to that style and concentrate on optimizing hydraulics and operating parameters to increase both bit life in the lower intervals and ROP in the upper interval.

HYDRAULICS

The positive effect of hydraulic horsepower on ROP has been recognized in the field. Experimental data suggest that drilling rates in sandstone and less reactive shales increase with bit hydraulic horsepower (HHP) in water-based mud up to 5-6 HHP/sq in. (HSI). After that point the improvements in ROP diminish.6

On subsequent R437 bit runs, the program was redesigned to increase bit hydraulics from about 4.0 to 6.0 HSI, and flowrates from about 380 to 420 gpm.

ROTARY SPEED

It was recognized that the PDC bits were experiencing accelerated cutter wear towards the OD section while drilling the harder, more abrasive Carrizo sandstone interval. This indicated a thermally accelerated wear mode due to the increased cutter/rock friction coefficient in the sandstones, and the greater cutter velocity towards the OD of the bit, relative to the center cutters.

With harder rocks, the critical rotary speed at which thermal PDC cutter wear becomes significant is reduced.5 To maximize bit life, slower rotary speed was recommended in the harder, abrasive Carrizo sandstone interval.

Several 8 3/4-in. R437 style PDC bits were run with the optimized operating parameters. These bits were run after drilling out of surface casing until a depth of 4,0004,500 ft with a TCI roller-cone bit. The R437 would then drill to a casing point at 7,000-7,500 ft.

By slowing the rotary speed from about 130 to 90 rpm through the Carrizo sandstone, the R437's exhibited an even wear pattern and increased bit life.

The 8 3/4-in. R437 PDC bits lowered cost per foot by 42% compared to offset roller-cone bits (Fig. 8). An average savings of $18,783 per well was realized in the intermediate hole, and $34,432 over the life of the bits that were run on two wells before dulling.

The results of the bit selection methodology, which are summarized in Table 1, resulted in a PDC bit that could successfully drill the lower intervals, saving significant time and money. Earlier tests indicated that the upper intervals could be drilled successfully but the PDC bits would dull in the lower intervals, resulting in an uneconomical run.

RESULTS

With the optimized bit style selected and operating parameters determined, a test was planned to drill the entire 8 3/4-in. interval with one bit. On Enron's Vela Cuellor No. 2 well, 4 miles east of Zapata, Tex., a rerun 8 3/4-in. R437 was picked up after setting surface casing at 1,300 ft.

The R437 drilled out the casing float equipment to an intermediate-casing depth of 6,772 ft. The 5,472 ft section drilled in an average ROP of 50.4 ft/hr. This was a $21,121 savings over roller-cone bits. A rerun 6 1/4-in. R435 drilled out the intermediate-casing float collar and shoe before drilling to TD.

The TD was extended from 8,800 to 10,900 ft. The R435 averaged 33.8 ft/hr over the 4,129-ft interval. The bit saved $20,395.

The Vela Cuellar No. 2 was successfully drilled with one bit per hole size interval (Fig. 9). This accomplished the original goal of the bit development program. More astoundingly, it was accomplished using rerun PDC bits. Of those wells with similar casing programs in the Lobo trend area, this well is the first known to be drilled with one bit per hole size interval.

ACKNOWLEDGMENT

The authors thank Enron Oil & Gas Co. for permission to publish this article.

REFERENCES

  1. Robinson, B.M., Holditch, S.A., and Lee, W.J., "A Case Study of the Wilcox (Lobo) Trend in Webb and Zapata Counties, TX," paper SPE 11600, SPE/DOE Symposium on Low Permeability, Denver, Mar. 14-16, 1983.

  2. McClelland, G.M., "Review of Polycrystalline Diamond Compact Bits Run with Invert Emulsion Oil Muds in Shallow South Texas Wells," paper SPE 13110, 59th Annual Technical Conference and Exhibition, Houston, Sept. 16-19, 1984.

  3. Long, John, "The Eocene Lobo Gravity Slide, Webb and Zapata Counties, Texas," South Texas Geological Society, Contributions to the Geology of South Texas, 1986.

  4. Kerr, C., "PDC Drill Bit Design and Field Application Evolution," paper SPE 14075, International Meeting on Petroleum Engineering, Beijing, China, Mar. 17-20, 1986.

  5. Glowka, D.A., "Implications of Thermal Wear Phenomena for PDC Bit Design and Operation," paper SPE 14222, 60th Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25, 1985.

  6. Holster, J.L., and Kipp, R.J., "Effect of Bit Hydraulic Horsepower on the Drilling Rate of a Polycrystalline Diamond Bit," paper SPE 11949, 58th Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8, 1983.

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