Shrikant Tiwari
Oil & Natural Gas Corp. Ltd.
Dehradun, India
A diagnostic approach to bit selection, including aspects of rock strength, formation properties, and bit dulling characteristics, can help a field engineer choose the best rock bit available.
Selecting the appropriate bit for a particular interval can improve the rate of penetration (ROP) and increase bit life, and, likewise, an inappropriate bit may wear prematurely.
A drilling engineer must make many vital decisions while working on a rig, but many times a lack of information forces him to settle for less than the best option. Selecting a rotary rock bit for drilling a particular formation is one such decision. A wrong bit selection, because of incomplete information or understanding, can increase drilling time and costs.
Innovations for achieving longer bearing life have considerably improved the performance of roller cone bits. In many field applications, the new generation tungsten carbide insert and rock bits have proven less expensive than polycrystalline diamond compact bits. Nonetheless, it has also been proven that the use of the appropriate bit, regardless of type, for the interval being drilled plays a crucial role in achieving this success.
The selection of a suitable bit appears simple and straightforward if one merely reads bit comparison tables; however, in the field bit, selection is considerably more difficult. Many times bit selection is more of an abstract and intuitional decision based on experience rather than an analytical decision based on facts.
Usually bits are selected by an analysis of offset bit records on the basis of cost per foot of drilling. Such an analysis may not result in an optimum bit program if the best bit had never been used in the offset wells. The use of offset records will indicate the best bit from the list of used bits only,
The following bit selection procedure has five parts:
- Determine the rock compressive strength.
- Identify the type of bit on the basis of rock compressive strength.
- Accurately grade and analyze the previously run dull bit.
- Clearly identify the causes of bit wear and suggest possible improvements in operating practices and bit type.
- Determine the features on the next bit based on formation characteristics and wear pattern of previous bit.
This diagnostic approach of bit selection imparts the desired weight to each factor: formation strength, formation properties, bit limitations, and operating practices. All the practical limitations of field operations have been kept in mind in designing these procedures.
A flexible (large and diverse) inventory of bits near the drill site will facilitate the effective implementation of this bit selection procedure.
ROCK STRENGTH
A drilling bit is simply a rock breaking tool. For effective cutting, the tool must counter the strength of its target, and the important aspects in drilling are the failure criteria and the strength of the rock. The failure criteria of rocks vary with their strength.
In general, the ROP varies inversely with rock compressive strength. At the well site, bits are usually selected with the presumption that rock compressive strength increases with depth; however, it is generally not known how much and at what rate the compressive strength increases. The drilling engineer should be aware of the rock compressive strength before the next bit is run.
Compressive strength for a particular type of rock can vary with temperature and pressure. The type of deposition and the age of the rock also affect- compressive strength. The physical properties of any formation can be determined from testing a core sample in the laboratory, but these properties at atmospheric conditions can be significantly different from the rock's in situ properties. Hence, a bit selected solely on lab tests may not necessarily be very effective. Moreover, extensive lab tests cannot be carried out in the field and therefore may be of little help for on site decisions. Additionally, in exploratory drilling, decisions based on lab physical tests may not produce positive results in subsequent wells because of stratigraphic variations.
Because of these practical limitations, there is a need to use a quick, easy method to determine the in situ rock strength on the basis of operating parameters. The method needs to be carried out on site with results available for immediate use.
A linear approximation method for finding out the compressive strength established by M.G. Bingham serves this purpose.1 This method can help in determining an approximate value of the strength of the formation drilled by a particular type of bit. Fig. 1 shows variations of ROP/revolution (R/N) with weight on bit/bit diameter (W/D).
A performance line plotted on the basis of these records helps in determining the rock strength. Previous studies revealed that the slope of the performance line decreases with rock strength, whereas the line's intercept on the X-axis increases. If the values for the slope and the X-axis intercept of the performance line satisfy Equation 1, then the performance line drawn should pass through the points on the plot.
Bit wear reduces ROP, and its effects should be incorporated into the equation. For all practical purposes, the half-worn condition of a bit can be assumed to represent the performance line for a fully used bit. Table 1 lists the bit capability constant (K) for various bit wear conditions.
The intercept of the performance line can be related with the shear strength of rock by Equation 2. Kf is a constant which varies only with the bit wear condition (Table 2). So, once the performance line is established for the half-worn condition of a bit, the X-axis intercept can be used to determine the shear strength of the formation drilled by that particular bit. This shear strength can be related to the compressive strength of the formation through Equation 3.
In this manner, the macroscopic strength of any formation can be determined. In field drilling situations, the exact values are not required as in laboratory experiments. The drilling engineer only needs a quick, easily determined approximate value of compressive strength. Approximate results in time are far more useful than the accurate ones later.
BIT TYPE
The rock failure criteria vary significantly with their compressive strength. The generic bit codes are based on their design characteristics for effective drilling of different formations.
If a soft formation bit is used for drilling a hard formation or vice-versa, then ROP and bit life will be adversely affected. Thus, if a bit is selected simply on the basis of predicted formation strength rather than the calculated value, the bit selected may not be optimum for the formation.
A soft-formation bit is preferred for drilling formations with a compressive strength up to approximately 18,000 psi, and a medium-formation bit for formations having a compressive strength not more than 26,000 psi. The average compressive strength of a section seldom exceeds 40,000 psi.1 Fig. 2 shows the standard International Association of Drilling Contractor (IADC) bit codes and their approximate ranges of compressive strength.
There is always the possibility of encountering hard streaks in normally uniform formations. These thin hard bands can be handled by varying operating parameters to prevent prematurely damaging the bit.
This method has been successfully used in the field to determine compressive strength and identify the right type of bit by IADC code (Table 3). Offset bit records were used for plotting the performance lines for various depth intervals. The intercept of the performance line on the X-axis was used for calculating the compressive strength.
This method can be further extended for making decisions at the rig site. Once a bit has been used completely, compressive strength can be calculated through the linear approximation method described earlier. A value slightly greater than that calculated can be a fair approximation of compressive strength of the next section to be drilled. The next bit run can be picked based on this compressive strength value. The choice of the bit can be narrowed to a great extent by putting the calculated compressive strength across the scale in Fig. 2, and then the selection can be compared to the equivalent offset bit record, if available.
The main factors in determining the features on the next bit to be run are drilling depth, hole size, formation characteristics, and bit wear pattern. (For example, at shallow depths ROP is the primary concern, whereas in deeper intervals longer bit life is important. An abrasive formation may require the use of a journal bearing bit with special gauge protection. A center jet bit may prove to be a better choice if the formation is soft and sticky, possibly resulting in bit balling.)
DULL BIT CONDITION
The dull bit condition indicates the difficulty the toot faced on bottom. A critical evaluation of the pulled bit provides vital clues for selection of a bit for the next run.
Dull bit grading can also indicate the weak areas of the tool or even poor operating practices. Improving these weak links and analyzing rock strength can aid in picking the best possible bit for the next run.
Dull bit grading is considered an art, and expertise is gained through experience. A good understanding of how to grade and analyze dull bits can lead to better bit selection and use, eventually cutting overall drilling costs.
Many articles have described new systems of reporting dull bit conditions, but most people working at drill sites find it difficult to identify the exact pattern of bit wear. The accompanying box contains indicators for confirming common wear patterns and some of the more common reasons for them. This checklist also indicates the remedial measures to prevent recurring problems. Once a bit dulling characteristic has been identified, steps can be taken to incorporate the suggested improvements in bit selection and its operation.
ACKNOWLEDGMENT
The author thanks the management of India's Oil & Natural Gas Corp. Ltd. for permission to publish this article. The author also thanks the Institute of Drilling Technology for use of its library and the Institute's senior officers for their support in writing this article.
REFERENCES
- Bingham, M.G., "A new approach to interpreting rock drillability."
- Jumikis, A.R., "Rock Mechanics.
- Estes, J.C., "Selecting the proper rotary rock bit," paper from the Society of Petroleum Engineers, 1971.
- Technical data on application of the roller dull grading system, Hughes Tool Co., 1987
- Attewell and Farmer, "Principles of Engineering Geology."
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
