Robert T. Fabian
Hycalog
Houston
A rock strength analysis program, through intensive log analysis, can quantify rock hardness in terms of confined compressive strength to identify intervals suited for drilling with polycrystalline diamond compact (PDC) bits. Additionally, knowing the confined compressive strength helps determine the optimum PDC bit for the intervals.
Computing rock strength as confined compressive strength can more accurately characterize a rock's actual hardness downhole than other methods. The information can be used to improve bit selections and to help adjust drilling parameters to reduce drilling costs. Empirical data compiled from numerous field strength analyses have provided a guide to selecting PDC drill bits.
Early rock hardness analyses focused on using sonic velocity profiles from wire line sonic logs as a substitute for a more direct measurement or computation of rock hardness. More recently programs have been developed to characterize rock strength by using sonic log information to compute a value for the unconfined compressive strength of the rock. Although this approach is an improvement over using sonic velocities directly, a calculation of unconfined strength often understates the actual strength of the formation when the rock is drilled in its pressured environment.
A computer analysis program has been developed to aid in PDC bit selection. The program more accurately defines rock hardness in terms of confined strength, which approximates the in situ rock hardness downhole. Unconfined compressive strength is rock hardness at atmospheric pressure.
The program uses sonic and gamma ray logs as well as numerous input data from mud logs. Within the range of lithologies for which the program is valid, rock hardness can be determined with improved accuracy. The program's output is typically graphed in a log format displaying raw data traces from well logs, computer-interpreted lithology, the calculated values of confined compressive strength, and various optional rock mechanic outputs.
IDENTIFYING PDC INTERVALS
Because the use of PDC bits can reduce total drilling costs in some cases, the identification of all the PDC-drillable intervals is highly desirable. A properly chosen bit may cut costs substantially; however, care must be taken in selecting intervals because a PDC bit used in the wrong interval could be costly.
The following are two primary methods of determining which sections can be drilled with PDC bits: the analysis of bit records from offset wells and the use of well logs. Although bit records remain the principal means of identifying PDC applications, the use of records alone may not always be adequate. Bit records generally do not contain information on formations or lithologies. At best, they have only summary information on drilling parameters, mud data, basic hydraulics, and dull bit grading information. When bit records alone are used to select PDC bits, it is often necessary to go through a learning curve.
Well log analysis is a more recent technique for identifying PDC-drillable formations. The well log data are used to develop a quantitative estimate of rock hardness.1 2
In most cases, a computer program generates rock hardness in terms of compressive strength, expressed in pounds per square inch. Compressive strength values have been shown to correlate directly with a formation's drillability.1 The program's output is typically graphed into a log format, displaying raw data traces from well logs, computer-interpreted lithology, compressive strength, and various optional rock mechanic outputs. Lithological data and compressive strength values are a more accurate method of determining if a PDC bit can be used. There are, however, alternative methods of calculating compressive strength values for determining PDC drillability. A comprehensive background of work documents the various techniques applied to compute in situ compressive strength.1
CONFINED STRENGTH
The use of well logs to select PDC bits has been practiced for some time. In general, where compressive sonic time values are greater than 65 [see formula], these intervals are considered acceptable zones for using PDC bits.
Sonic value cutoffs for running PDC bits can vary regionally and sometimes can vary Within a field.
In the Timor Sea for example, sonic values greater than 75 [see formula] have been used for bit selection with moderate success.3
Nevertheless, there are limits to this practice, because sonic transit times are affected not only by rock hardness but also by other factors such as lithology porosity, grain size, and pore pressure. Relationships that are valid for a specific interval in one geographic area may not be valid in another geographic area.
Traditionally rock hardness is expressed in terms of unconfined compressive strength-the compressive strength of the rock at atmospheric pressure. The unconfined compressive strength is the strength of the rock outside of the well, and this value ignores the overburden pressure and its associated hardening effect on the rock. Unconfined compressive strength does not account for the additional stress, and thus the incremental strength, created downhole.
Despite the potential shortcomings of using unconfined rock strength analysis for PDC bit selection, this method represents a considerable improvement over previous methods. A new rock strength analysis (RSA) program, developed by Hycalog, has further improved quantitative PDC bit selection techniques by using a model based on confined compressive strength. Fig. 1 is a sample output. The confined compressive strength can vary from the sonic log and unconfined compressive strength, as shown by the relative changes in magnitudes and maximum values on the graph.
In Fig. 1, the two high-strength intervals beginning at about 1,515 ft and 1,590 ft would have been missed by sonic analysis. In fact, sonic analysis would have identified the interval from 1,530 to 1,550 ft as being the most difficult part of the section to drill.
The confined compressive strength is the rock's strength while it is subjected to pressure in a confined medium. Rocks exhibit a strengthening effect (called the confinement effect) while under pressure. Generally, the deeper the rock, the greater the effect. Taking the confinement effect into account is key in the determination of in situ rock hardness for use as an indicator of a formation's drillability.
In situ rock mechanic analysis, in principle, embraces all variables that affect the rock strength (including confining pressure, formation stress, formation composition, pore pressure, porosity, density, temperature, and anisotropy). For comparison, the ranges of confined compressive strength data will typically be 1.8-2.3 times the value of the unconfined strength. The relationship between confined and unconfined strength is highly sensitive to a number of formation characteristics and will differ substantially between sand and shales because of differences in compressibility.
To illustrate the value of confined strength analysis, confined strength is plotted vs. unconfined strength in Fig. 2. The raw data were obtained from Amoco Production Co.'s research drill site in Catoosa, Okla.1
Fig. 2 shows the inverse tracking of penetration rate (ROP) to rock strength. The ROP correlates better with the confined rock strength log than with the unconfined rock strength log.
One bit drilled this interval and was pulled for photographs and dull grading at four depths. The bit had less than 5% wear at its last checkpoint at 1,400 ft. After drilling its last section to 1, 631 ft, the bit was pulled and graded to have 35% overall wear. In this test, the rotary speeds were held constant at a 120 rpm. The weight on bit was adjusted as necessary, but the ROP was limited to a maximum of 150 ft/hr.
The RSA program has been tested during its first 9 months in a wide range of lithologies worldwide. The field studies have included more than 100 wells. More than 500,000 ft of hole have been analyzed to determine PDC drillability.
The primary work areas were the Gulf of Mexico, on-shore Texas and Louisiana, the Rocky Mountains, Alaska, the North Sea, South America, and the Middle East. After using RSA to identify PDC drillable sections, the next critical step was to choose the optimum drill bit.
OPTIMUM BIT SELECTION
The confined compressive strength was computed and then applied in the PDC selection process. By using a well log's gamma ray, sonic, and mud log data, RSA's output profile shows actual rock-hardness over the interval (Fig. 1). Based on profile characteristics, lithology, and mud type and whether a mud motor will be used, an optimum bit is selected to reduce total well costs.
The PDC bit was selected based on comparisons of bit performance data and dull condition of bits where RSA was used. The confined compressive strength value of a rock was then related directly to the performance of the bit.
Current analysis has established the maximum value for PDC drilling at a confined compressive strength of about 45,000 psi for conventional PDC bits with 13-mm cutters. This limit relates to the effectiveness of a PDC cutter in overcoming the shear strength of the formation, without failure of the cutter itself. However, high-cutter-density PDC bits with 8-mm cutters have drilled in formation strengths up to 55,000 psi. Future developments in PDC bit designs and improvements in materials technology are likely to push the maximum value even higher.
Analyses show that similar bit designs performed almost equally well in a specific hardness range. Within similar designs, however, drilling characteristics did vary. For example, small differences in a design allow one bit to drill better in shales that include hard stringers. In addition, some bit designs withstood higher peak strength values than others.
These findings help to group bits according to their ability to drill a defined range of confined compressive strength values (Table 1). This table has been proven valid through field results to date. Within a hardness range, more than one bit may be acceptable, and the optimum bit selection can then be based on the RSA's hardness profile, lithology, mud type, and mud motor usage.
Note that the majority of bits studied were hybrid designs that incorporated diamond impregnated backup elements behind the PDC cutters. Similar values may not apply to comparable bits without the backup elements.
In Fig. 2, the confined compressive strength profile shows average rock strengths of 15,000 psi near the top to averages of 25,000 psi near the bottom of the log. However, several hard stringers start at 275 ft. Maximum confined compressive strength values of 43,00045,000 psi occur at five locations. From the data in Table 1, a DS56H bit was chosen because of the hard stringers and that bit's ability to drill such stringers without excessive wear. The DS56H bit is heavy set and has diamond-impregnated backups to the PDC cutters (Fig. 3). The backups protect the cutters when hard stringers are drilled, yet they allow the bit to drill at its maximum ROP.4
However, if the unconfined compressive strength profile with one maximum peak of 18,000 psi had been used (Fig. 2), a softer formation PDC bit might have been indicated. If a less-heavy-set PDC bit or a bit without diamond-impregnated backups had been selected, the bit would have started wearing in the first hard stringer near the top of the well. Such a bit probably would not have drilled the entire interval as it encountered subsequent hard stringers.
DRILLING PARAMETERS
Quantifying rock strength is also beneficial in establishing optimum bit-running parameters. An immediate recognition of formation character is possible when an offset well's compressive strength profile is read. The analysis might reveal thin bands of hard rock interlaced within stringers of very soft shale. Not only can the optimum bit be selected, but in anticipation of drilling the hard stringers, running parameters can be adjusted accordingly to minimize sudden bit catastrophes.
Assuming valid logs are used, there are some limitations to the RSA confined-strength technique. The program will work on rocks that are homogeneous, isotropic, and plastic. These rock types include those typically drilled in most oil and gas basins.
Nonhomogeneous rocks, such as conglomerates and very loose unconsolidated sediments, may give erroneous results. Also, rocks bearing secondary porosity or rocks that are highly brittle and nonplastic, such as metamorphic rocks, may not give accurate results. In addition, compressive strength analysis alone will not recognize abrasive formations or damaging minerals such as pyrite.
The RSA output has been used as input data in new bit designs and for modification of current bit designs. In developing bits for a specific field, understanding the rock strength profile helps a designer develop a bit.
The industry has only begun to realize the potential of the program to aid in the selection of other types of bits. The RSA program has the potential to help select all bit types, including roller cone, thermally stable polycrystalline diamond (TSP), diamond, and core bits.
EXAMPLES
The following case histories indicate the savings that are possible when a PDC-drillable well is identified and the optimum bit chosen. In these examples, the operators saved up to $270,000 per well.
- Rocky Mountains
In the Wasatch (Red beds) formations of the Uinta basin in the Rocky Mountain area in Utah, PDC bits had been tried with little success. The drill bits of choice were roller cone and natural diamond bits.
The RSA program identified some PDC-drillable sections. The program helped identify the optimum PDC bit and provided valuable insight during drilling to save $72,000 on a single well. Using RSA on offset well data identified the formations to be ratty sand and shale with hard stringers (Fig. 4).
The average strength was 25,000 psi with peaks of 45,000 psi. Using the PDC bit selection table, the operator chose a DS56H, which is a heavy-set PDC bit with diamond-impregnated backups (Fig. 3). One DS56H bit drilled the interval that previously required two natural diamond drill bits. In addition to eliminating one trip, the ROP increased from 3.8 ft/hr to 9.3 ft/hr with this PDC bit.
From the RSA information, a new bit design with a heavier set cutting structure, the DS71H, was used on another well. This design has 8-mm PDC cutters rather than 13-mm cutters, the more commonly used size. The DS71H bit set a local record, drilling 2,307 ft at 18 ft/hr. The operator saved $106,000.
- North Sea
In the North Sea and other areas with high drilling costs, RSA can be used to identify PDC-drillable areas that will allow replacement of shorter-life roller cone bits and also allow for higher ROPs. The savings include reduced tripping costs and drilling hours.
Elf Petroleum Norge was using two IADC 517 (International Association of Drilling Contractors generic bit code) type roller cone bits in the Lille-Frigg field to drill a Cretaceous formation. Using the RSA program, it was determined that a PDC bit could drill the section.
A hybrid fishtail bit, DS40HFU, was substituted successfully on Elf's 25/2-C-3H well. Elf saved $270,000 on this well from the one fewer trip and the faster ROPS.
- Onyia, E.C., "Relationships Between Formation Strength, Drilling Strength, and Electric Log Properties," SPE paper 18166, presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibition, Houston, Oct. 2-5, 1988.
- Mason, K.L., "Tricone Bit Selection Using Sonic Logs," SPE paper 13256, presented at the SPE Annual Technical Conference and Exhibition, Houston, Sept. 16-19, 1984.
- Bond, D.F., "The Optimization of PDC Bit Selection Using Sonic Velocity Profiles Present In The Timor Sea," OSEA paper 90158, presented at the Offshore South East Asia Conference, Singapore, Dec. 4-7, 1990.
- Williams, J.L., and Thompson, A.I., "An Analysis of the Performance of PDC Hybrid Drill Bits," SPE/IADC paper 1611,-, presented at the Society of Petroleum Engineers/International Association of Drilling Contractors Annual Drilling Conference, New Orleans, Mar. 15-18, 1987.
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