how the Bit Profile and Gages Affect the Well Trajectory

Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the IADC/SPE Drilling Conference held in Dallas, Texas, 26–28 February 2002 This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract The importance of wellbore deviation is well recognized by the drilling industry. An analysis of the directional behaviour of a drilling system must include the directional characteristics of the drilling bit. A comprehensive analysis of the directional behaviour of PDC bits is presented in this paper, including the effect of bit profile, gage cutters and gage length. Numerical simulations as well as laboratory tests have been carried out in order to better understand the mechanisms of PDC bits deviation and to evaluate the most important parameters affecting the directional behaviour of PDC Bits. The analysis of the directional behaviour of PDC bits presented in this paper shows that each part of the PDC bit (bit profile, active and passive gages) plays a major role on the walking tendency and steerability of the bit. A quantitative evaluation of the contribution of these factors on the well trajectory (inclination and azimuth) is given. A full-scale directional drilling bench was built to measure, for the first time, the walking tendency and the steerability of PDC bits. The results obtained demonstrate that the bit profile, the gage cutters and the gage length have a significant effect on the walking tendency and on the steerability of the PDC bits. A 3D theoretical rock-bit interaction model was developed to reproduce the drilling tests results. Introduction The oil and gas industry relies greatly on directional drilling to develop petroleum reserves in environmentally sensitive areas

or in restricted surface areas through an increasing number of multilateral, horizontal and extended reach wells. To drill and control the deviation of these becoming more complex wells, many directional systems can be used. Depending on the well characteristics, one can select a rotary Bottom Hole Assembly, a steerable mud motor or more recently a Rotary Steerable System. Whatever the system used, the drill bit has an influence on the directional behaviour of the drilling system. This paper enables to define the contribution of the different parts of the PDC bit on its directional behavior (steerability and walking tendency) and their impact on the well trajectory. Background Theory The directional behaviour of PDC bits is generally characterized by its walk tendency and steerability. The walk tendency or bit turn is a concept well known by the drillers and a natural phenomenon existing in any rotating cutting drilling heads. From this walk tendency, Ho1 introduced for PDC bits the walk angle, which is the angle measured in a plane perpendicular to the bit axis, between the direction of the side force applied to the bit and the direction of the lateral displacement of the bit (figure 1). The walk angle quantifies the intrinsic azimuthal behaviour of the PDC bit. When the lateral displacement of the bit is on the left of the side force, the bit has a left tendency. If the lateral displacement is on the right of the side force, the bit has a right tendency. A neutral bit means that the lateral displacement is in the same direction than the side force. Considering this definition, according now to the surface position, when we are in a building phase, if the bit goes to the left, then its tendency is left; if it goes to the right, then its tendency is right. Now, if the bit is going to the left while dropping, its tendency is right; if it goes to the right, then it has a left tendency. At last, it is worth noting that an intrinsic neutral bit does not give necessarily a zero turn rate because this turn rate depends not only on the bit characteristics behaviour but also on the BHA behaviour and the formation characteristics, mainly its anisotropy. The bit steerability (BS) corresponds to the ability of the bit, submitted to lateral and axial forces, to initiate a lateral

SPE 74459

How the Bit Profile and Gages Affect the Well Trajectory S. Menand, SPE, and H. Sellami, SPE, Armines/Ecole des Mines de Paris; C. Simon, DrillScan ; A. Besson, TotalFinaElf ; N. Da Silva, Security DBS

2 S. MENAND, H. SELLAMI, C. SIMON, A. BESSON, N. DA SILVA SPE 74459

deviation. The bit steerability can be defined as the ratio of the lateral drillability over the axial drillability :

ax

lat

DDBS = (1)

The lateral drillability (Dlat) is defined as the lateral displacement per bit revolution over the side force. The axial drillability (Dax) is the axial penetration per bit revolution over the weight on bit (WOB). The BS (equivalent to the bit anisotropic index1,2) is generally in the range of 0.001 to 0.1 for most PDC bits, depending on the cutting profile, gage cutters and gage pad characteristics, as evaluated in the present paper. A bit with a high steerability means a strong propensity for lateral deviation, enabling to obtain a maximum potential build or drop rate. In the field, assuming that the BHA applies a non-zero side force on the bit without bit tilt angle, the bit steerability can be linked to the build or drop rate of well trajectories. Field and laboratory observations Steerability Many studies have been carried out in laboratory or in situ in order to estimate the effect of PDC bits on the build and drop rate of well trajectories. In analyzing the data of Gulf of Thailand wells, Perry3 reported that the profile and the gage length of PDC bits could affect the build and drop tendencies of BHAs. Pastusek et al 4 conducted some directional tests in laboratory in order to study the behaviour of anti-whirl PDC bits. The authors noticed that the anti-whirl PDC bits had a lower side cutting ability than the conventional PDC designs. Pastusek et al 4 attributed this difference to the smooth gage pads used for the anti-whirl bits and concluded that the build rate of anti-whirl bits on steerable systems was lower than it is with conventional PDC designs. O’Bryan and Huston5 studied the effects of gage length on the build and drop tendencies of PDC bits. In testing two different gage lengths (3.5” and 6”), the authors reported that the highest build/drop rate was obtained with the longest gage. O’Bryan and Huston5 explained this phenomenon by a higher WOB on the PDC bit with the longest gage, generating a higher side force on the PDC bit. More recently, Norris et al 6 carried out a study in laboratory and in situ to evaluate the bit side cutting ability. One roller cone bit and two PDC bits with various gage aggressiveness were tested in laboratory in Carthage marble. In varying WOB and side force applied on the bit, the authors observed a BS in the range of 0.04 to 0.4. The lateral drillability of the PDC bit with aggressive gage was almost 10 times higher than the one with unaggressive gage. However, some irregularities and ledges on the borehole were observed with the PDC bit having the most aggressive gage. Furthermore, the roller cone bit showed a lower side

cutting ability than the two PDC bits. At last, in analyzing field data, the authors noticed a good correlation between the PDC bit side cutting ability evaluated in laboratory and the build/drop rate measured in the field. Walking tendency Based on field observations, it is generally accepted that the roller cone bits have nearly always a right tendency and most PDC bits have a left tendency. Kerr7 noticed that PDC bits have generally a left tendency but emphasized that the azimuthal behaviour of the drilling system is influenced by formation characteristics, bit profile, bit size, formation dip, WOB, BHA, and other factors. In analyzing some well trajectories in the Gulf of Thailand, Perry3 concluded that the bit profile could affect the azimuthal behaviour of the BHA. Indeed, a BHA with a flat PDC bit profile showed a right tendency. Perry3 also supposed that the gage cutters and the gage length did not influence the turn rate. In studying the azimuthal behaviour of BHA in Alwyn North field, Bannerman8 confirmed the observations made by Perry3 : the right turn measured in the field is supposedly attributed to the flat profile of PDC bit, although the parabolic profiles exhibited a left tendency. Synthesis It emerges from these laboratory or in situ studies that a comprehensive analysis of the directional behaviour of PDC bits has never been conducted to quantify the intrinsic azimuthal behaviour of the PDC bit. Moreover, the directional behaviour of a whole drilling system cannot be explained only by the directional behaviour of the bit. A bit with a high side cutting ability does not produce necessarily a high rate of inclination on the well trajectory. This rate depends on the side force and weight applied on the bit, on the bit tilt angle and also on the rock formation. Likewise, the azimuthal behaviour of a drilling system must not be attributed only to the walk tendency of the bit. Some friction phenomenon along the BHA (mainly at stabilizers levels) can greatly influence the azimuthal tendency of the drilling system. At last, the formation effect (rock anisotropy) may be decisive in both the build/drop and azimuth rate of the trajectory9. Rock-Bit Interaction Model Over the past thirty years, Ecole des Mines de Paris has developed a methodology for designing and selection of cutting and drilling systems. Drilling efficiency10, wear reduction, vibrations control and efficient cleaning have been carefully studied. A 3D rock-bit interaction model9,11 has been developed in order to calculate the directional behaviour of PDC bits in isotropic and heterogeneous formations. The bit model takes into account the 3 parts of the bit which interact with the formation (figure 2) : the cutting structure, the

SPE 74459 HOW THE BIT PROFILE AND GAGES AFFECT THE WELL TRAJECTORY 3

active gage (trimmers or gage cutters) and the passive gage (gage pad). Cutting structure The rock-bit model includes an elementary PDC-interaction model taking into account the PDC geometry characteristics (cutter size and geometry, back rake angle, chamfer, wear and friction) and the rock characteristics (cohesion, angle of internal friction, uniaxial compressive strength, pore pressure, dip angle). From the cutting structure, a cutting profile is defined geometrically and can be divided into 2 parts according to the IADC Classification12: the inner cone (height C) and the outer structure (height G). The cutting structure is defined through the rock-bit model by its cutting profile (geometric parameters) and its cutters position and orientation. Active gage The active gage corresponds to the PDCs that are truncated (trimmers or gage cutters) to the bit diameter, corresponding to the transition between cutting structure and passive gage. From single cutter laboratory experiments, a trimmer-rock interaction model was developed and integrated in the rock-bit model. The active gage is then defined by its length LAG, its trimmers number, its trimmer back rake angle and its rock-friction surface depending on the trimmer truncation. Passive gage The passive gage (or gage pad), which plays a great role in the stabilization of the PDC bit, can have many design features. The main passive gage characteristics are the length, the circumferential coverage (depending on the blades spiral angle), and the surface roughness (smooth gage pads such as the low-friction gage pads14,15 or aggressive gage pads depending on the carbide or diamond insert type for protection). According to these features, the passive gage is characterized in the rock-bit model by its length LPG, and its blades characteristics (number, spiraled or straight, diamond or carbide inserts type) defining a friction surface with the borehole. Kinematics The bit is assumed to continuously rotate around its axis, and is given a prescribed axial and lateral motion. The motion of the bit is described through 5 variables : 3 for a translation movement and 2 for a rotation movement. Then, after prescribing a bit motion, the rock-bit model calculates the forces on all cutting element and integrates the single forces over the bit surface to produce global forces and moments averaged over one bit revolution.

Results The 3D rock-bit model enables to calculate WOB and lateral force on the bit required for an axial and lateral motion, imbalance force, efficiency index and wear evolution. It computes also the steerability and the walk angle of each part (cutting structure, active gage and passive gage) of the bit. It’ s important to note that the bit steerability calculated from the rock-bit model is mainly a function of the WOB, the lateral force and the rock strength and anisotropy. Assuming all the PDC cutters have an identical back rake angle along the bit profile, Menand11 has found that the walk angle is then a function of the inner cone deep C and the outer structure height G, and can be calculated simply by :

)()tan(

)(2arctanGC

GCfc ++−= θωα (2)

C and G are respectively inner cone and outer structure heights according to the IADC classification12, ωc is the back rake angle and θf is the friction angle between PDC and rock. Directional laboratory tests Directional dr illing bench In order to be able to measure bit steerability and walking tendency, the drilling bench of Ecole des Mines de Paris, enabling to test drill bit under simulated downhole conditions (figure 3), was modified. The new system enables to test the side cutting ability and the walk tendency of bit up to 12”1/4 diameter. The directional tests can be performed with a maximum 15 tons WOB and a lateral force up to 1.5 tons. The directional test principle (figure 4) is as follows : during the axial penetration of the bit, a lateral force Fx is applied on the rock sample, which is free to move in the direction of the applied force, generating a lateral displacement of the rock sample. Two sets of strain gages are mounted on the drilling shaft to measure the bending moments (magnitude and orientation). The total resulting lateral force Flat at the bit is computed through the bending moments readings, and the difference of orientation between the lateral displacement and the resulting lateral force Flat at the bit gives the bit walk angle (figure 4). The lateral drillability Dlat of the bit is calculated from the lateral displacement of the rock sample measured by the LVDT sensor and the resulting lateral force Flat; the axial drillability Dax is measured from the rate of penetration (ROP), the rotation speed and WOB.


Test procedure All the tests have been carried out in the Vosges sandstone (homogeneous, porous, medium hard sandstone, uniaxial compressive strength = 40 MPa). A 1 150 kg/m3 water-based mud (bentonitic) was used with a mud flow fixed to 600 l/mn. During the tests, the rotation speed was held constant at 60 rpm while WOB and lateral force were varied in order to evaluate their possible effect on steerability and walking tendency. Off-bottom tests were also performed in order to test the lateral drillability of active and passive gage. During the off-bottom test, the bit is maintained above the bottom of the hole and a lateral force is applied, enabling to test only the gage interaction with the borehole formation. Character istics of the PDC bits selected Three PDC bits having different profiles have been tested on the directional drilling bench (figure 5) : Bit A, Bit B and Bit C. The back rake distribution is identical along these 3 profiles, ranging from 15° inside the cone to 30° in the outer structure. The common characteristics of the bits are : 8 ½” diameter, 8 highly spiraled blades with 13.3 mm PDC cutters and 4 nozzles. The 3 bits have different active gage lengths ranging from 15 mm for the Bit A to 30 mm for the Bit C. The 3 bits have passive gages with different type of inserts to protect the gage. In order to evaluate the effect of the three different parts of the bit (cutting structure, active gage and passive gage), each bit was tested with 5 different configurations (figure 6). Firstly, each bit was tested with a passive gage length LPG = 4” , 2” and 1” . Then, the bits were tested without passive gage, only with their active gage and cutting structure. Lastly each bit was tested with only the cutting structure, that is without any active or passive gages. Results Steerability For the various bits tested, one can notice that the bit steerability highly increases with the reduction of the passive gage length (figure 7). All the tests plotted on this figure have been carried out with the same WOB and lateral force. The highest steerability is measured for the Bit A. These results are mainly explained by the different active gage lengths and the bit profiles, and are confirmed by the 3D rock-bit model calculation (table 1). Tests carried out without passive gage (that is with only the active gage and cutting structure corresponding to the bit configurations #4 and #5) have revealed that the highest steerability for the bit configuration #4 was obtained for the Bit A and the lowest steerability for the Bit C (figure 8). This result can be mainly attributed to the active gage length, since the Bit C has the longest active gage and the Bit A has the

shortest one. Nevertheless, one can also notice that the highest steerability for the bit configuration #5 (test with the cutting structure alone) was observed for the Bit B, although the Bit C exhibited the lowest steerability (figure 8). This result can be analyzed by examining the bit profiles. Indeed, the highest steerability is obtained for the Bit B (IADC bit profile code 9) having a flat profile, although the lowest steerability measured corresponds to the Bit C (IADC bit profile code 5) having a medium taper and cone. Some tests performed with various lateral forces demonstrated that the bit steerability of a PDC bit depends on the intensity of the side force. For example, the Bit C steerability with a 2” passive gage (configuration #2) is increased by 30% with a 25% increase in lateral force. The off-bottom tests confirmed that the lateral drillability of the active and passive gage depends on the lateral force applied. Indeed, the off-bottom lateral drillability of the Bit B in configuration #3 is almost multiplied by 3 as the lateral force increases from 268 daN to 710 daN (figure 9). At last, WOB seems to have no effect on the lateral drillability of the three bits tested. Walk tendency For the various bits tested with an active or passive gage, one can clearly notice that the PDC bits have a left tendency whatever the passive gage length is (figure 10). Even the tests carried out with the cutting structure and the active gage have demonstrated that the bits have a left tendency. At last, when the cutting structures alone were tested, the Bit A demonstrated a right tendency, the Bit C a left tendency and the Bit B a neutral tendency. These walk tendencies measured on the directional drilling bench correlated well with the values computed from the rock-bit model (table 1). The Bit B showed a tendency to spiral in the hole since the walking tendency was successively neutral, left, right, neutral etc… (figure 11). Nevertheless, the mean walk angle measured was close to 0°. These spiraling problems observed only for the Bit B can be generalized to bits having flat profile. Bit-BHA coupled computer model In coupling the 3D rock-bit model with a 3D mechanical model of BHA, Ecole des Mines de Paris has developed a software that enables to predict the inclination and azimuth of well trajectories. Based on finite element method, the 3D mechanical model enables to know the deformed shape of the structure, forces exerted on the system and contact forces between any part of the drill string and the wall of the borehole. In integrating the directional behaviour of both BHA and bit, the software calculates the theoretical 3D equilibrium curvature of the drilling system.


Case study PDC bits character istics

In order to evaluate the influence of the walk tendency and steerability of the bit on the well trajectory, some PDC bits with assumed BS and walk angle were selected for the analysis. For each bit (Bit X, Bit Y and Bit Z) having various bit steerability (table 2), the walk angle was varied between –20° (bit intrinsic left tendency) and +20° (bit intrinsic right tendency). Well and BHA character istics In order to observe an influence of the bit directional behaviour on the well trajectory, two assemblies producing a significant side force on the bit were selected : a dropping and a building assembly (figure 12). The data used come from two wells in phase 9”7/8 drilled by TotalFinaElf with the same PDC bit (Bit W). The run of the well #1 has been performed with the building assembly from 1380 m to 2534 m MD, producing a measured build rate of 0.29°/30 m and turn rate of -0.11°/30 m. The run of the well #2 has been performed with the dropping assembly from 2405 m to 3881 m MD, producing a measured drop rate of -0.55°/30 m and turn rate of 0.30°/30 m. Table 3 gives the parameters used for BHA simulations. As previously discussed, the bit steerability depends on the side force applied. In the two cases studied, two theoretical bit steerability have been calculated since the side force generated by the dropping assembly is greater than the one generated by the building assembly. The theoretical bit steerability of the Bit W is 0.03 for the well #1 (building assembly) and 0.04 for the well #2 (dropping assembly). The intrinsic theoretical walk angle is –12° (left tendency). Results The Bit-BHA model was used to compute the build/drop and turn rates for the two wells. In the calculations performed, all the stabilizers are full gage which prevent to evaluate any walk rate due to BHA walking tendency. Concerning the well #1 (figure 13), one can clearly notice that the bit steerability has an influence on the predicted build/drop rate of the drilling system since it varies from –0.12°/30 m with the Bit Z to 0.34°/30 m with the Bit X. The theoretical bit steerability calculated for the Bit W (BS=0.03) used to drill the well #1 enables to produce a predicted build rate very close to the measured build rate (0.29°/30 m). For the well #2 (figure 14), the predicted build/drop rate varies from –0.42°/30 m with the Bit X to 0.38°/30 m with the Bit Z. The theoretical bit steerability of the Bit W for this well is not high enough to give a predicted drop rate close to the measured value (-0.55°/30 m), but qualitatively the increase in bit steerability due to the higher side force is consistent with the higher drop rate observed on the field. Moreover, as previously discussed, one have to keep in mind that the build/drop rate is not only

due to the side force applied on the bit but also due to the bit tilt angle. It is interesting to note that in both cases, the bit steerability has such an influence that it can turn the drilling system from building to dropping angle. Such a result is due to the fact that the bit tilt and lateral force act in opposite directions. These results confirm the impact of the bit steerability on the well trajectory and a strong necessity to calculate an accurate bit steerability in order to predict correctly the inclination of well trajectories. The simulations have shown that the walk angle has no influence on the predicted build/drop rate whatever the bit steerability. Concerning the azimuth predictions, one can clearly observe that the bit walk angle and the bit steerability have an influence on the predicted turn rate (figure 13 and 14). For the well #1, with an intrinsic left tendency bit, the simulations give a left turn up to –0.06°/30 m, although with an intrinsic right tendency bit, the predicted turn is right. This result is accentuated for the well #2 since the predicted turn rate is in the range of -0.7°/30 m to 0.7°/30 m, depending on the intrinsic bit walk angle. It is also interesting to note that for a given bit walk angle, the predicted turn rate depends on the bit steerability. The influence is more important as the bit steerability increases. This tendency can be attributed to the bit side cutting ability that makes the bit walks on the wall of the borehole. Comparison between prediction and actual turn rate for the well #2 shows that the theoretical bit steerability (BS=0.04) and walk angle (α = -12°) enables to produce a turn rate very close to the measured value (0.3°/30 m). Synthesis Even though the directional behaviour of a drilling system can not only be attributed to the bit directional behaviour (formation effect, curvature of the borehole, hole enlargement, friction phenomenon, etc…), these simulations have shown that the bit steerability and the walk angle have a strong influence on the well trajectory. Conclusion The analysis of the directional behaviour of PDC bits presented in this paper leads to the following conclusions :

• The walk angle of a PDC bit depends not only on the bit profile but also mainly on the active and passive gages. The directional lab tests have demonstrated that the various bits tested with a passive gage had a left tendency whatever their bit profiles and PDC set-up.

• The walk angle of a PDC cutting structure is calculated using a simple equation linking the inner cone and outer structure heights and the PDC back rake angle.

• The active and passive gages affect dramatically the walk angle of PDC bits.


• The directional tests enable to observe spiraling problems and define minimum requirements to avoid such phenomenon.

• The steerability of a PDC cutting structure depends greatly on the bit profile : the flatter the profile is, the more steerable the bit is.

• The bit steerability is a non-linear function of the active and gage length, and decreases as the active and passive gage lengths increase.

• The bit steerability depends on the side force applied on the bit.

The Bit-BHA simulations and comparisons with field results have shown that :

• The bit walk angle has no influence on the build/drop rate of well trajectories.

• There is a strong correlation between bit steerability and build/drop rate.

• An accurate calculation of bit steerability is necessary to make a good trajectory prediction.

• The bit steerability and the bit walk angle have an influence on the predicted turn rate.

Nomenclature PDC - Polycrystalline Diamond Compact BHA - Bottom Hole Assembly BS - Bit Steerability IADC - International Association of Drilling Contractors Dlat - Lateral drillability Dax - Axial drillability WOB - Weight On Bit Flat - Resulting lateral force Fx - Lateral force applied by the jack ROP - Rate Of Penetration MD - Measured Depth θf - Friction angle between PDC and rock ωc - Back rake angle Acknowledgment Part of this work was carried out within the EEC Thermie PAB-BIT project conducted by Ecole des Mines de Paris/Armines, TotalFinaElf and Security DBS. The authors would like to thank the European Commission for its financial support enabling to carry out a part of the work presented in this paper. Thanks are also addressed to DrillScan company for performing well trajectory calculations.

References 1. Ho, H.S.: “ Method and System of Trajectory Prediction and

Control using PDC Bits” , United State Patent 5,456,141, Oct. 10, 1995.

2. Barton, S.: “ Development of Stable PDC Bits for Specific Use on Rotary Steerable Systems” , paper SPE 62779 presented at the 2000 IADC/SPE Asia Pacific Drilling Technology, Kuala Lumpur, Sept. 11-13.

3. Perry, C.J.: ”Directional Drilling With PDC Bits in the Gulf of Thailand” , paper SPE 15616 presented at the 1986 Annual Technical Conference, New Orleans, Oct.

4. Pastusek, P.E., Cooley, C., Sinor, L.A. and Anderson, M.: ”Directional and stability characteristics of anti-whirl bits with non-axisymmetric loading” , paper SPE 24614 presented at the 1992 Annual Technical Conference and Exhibition, Washington, Oct. 4-7.

5. O’Bryan, P.L. and Huston C.W.: “ A study of the effects of bit gauge length and stabilizer placement on the build and drop tendencies of PDC bits” , paper SPE 20411 presented at the 1990 Annual Technical Conference and Exhibition, New Orleans, Sept. 23-26.

6. Norris, J.A., Dykstra, N.W., Beuershausen, C.C., Fincher R.W.and Ohanian, M.P.: “ Development and successful application of unique steerable PDC bits” , paper SPE 39308 presented at the 1998 IADC/SPE Drilling Conference, Dallas, March 3-6.

7. Kerr, C.: “ PDC drill bit design and field application evolution” , Journal of Petroleum Technology, March 1988.

8. Bannerman, J.S.: “ Walk rate prediction on Alwyn North field by means of data analysis and 3D computer model” , paper SPE 20933 presented at Europec 90, the Hague, Netherlands, Oct. 22-24.

9. Simon, C.: ”Modelisation of PDC bit directional behaviour in anisotropic formation” , (in French) PhD thesis of Ecole des Mines de Paris, 1996

10. Gerbaud, L., Sellami, H., Lamine, E., Sagot, A.: “ New PDC bit design increased Penetration rate in slim wells” , Energy Week, paper presented at the 8th Annual Conference and Exhibition of ASME, 1997

11. Menand, S.: “ Analysis and validation of a PDC drilling bit directional behaviour model” , PhD thesis (confidential) of Ecole des Mines de Paris, 2001

12. Winters, W.J., Doiron H.H.: “ The 1987 IADC Fixed Cutter Bit Classification System”, paper SPE 16142 presented at the 1987 SPE/IADC Drilling Conference, New Orleans, March 15-18.

14. Warren, T.M., Brett, J.F. and Sinor, L.A.: “ Development of a Whirl-Resistant Bit” , SPE Drilling Engineering, December 1990

15. Sinor, L.A., Brett, J.F., Warren, T.M. and Behr, S.M.: “ Field testing of low-friction gage PDC bits” , paper SPE 20416 presented at the 65th Annual Technical Conference and Exhibition, Sept. 23-26


Figure 1 : Definition of the walk angle according to Ho1

Figure 2 : Descr iption of the PDC bit structure


Figure 3 : Dr illing Bench and Directional dr illing bench in Pau, France

Figure 4 : Pr inciple of the directional test


Figure 5 : The three bit profiles of tested PDC bits

Figure 6 : Descr iption of the 5 bit configurations tested


Figure 7 : Bit steerability measured on the directional dr illing bench

Figure 8 : Bit steerability measured on the directional dr illing bench

Figure 9 : Off-Bottom lateral dr illability versus lateral force for the Bit B (configuration #3)


Table 1 : Bit steerability and walk angle computed from the 3D rock-bit model

Bit A Bit B Bit C Steerability Walk angle Steerability Walk angle Steerability Walk angle Configuration #1 (CS+AG+PG 4”) 0.032 -11° 0.016 -10° 0.012 -11° Configuration #2 (CS+AG+PG 2”) 0.080 -11° 0.033 -11° 0.038 -12° Configuration #3 (CS+AG+PG 1”) 0.110 -12° 0.118 -11° 0.093 -12° Configuration #4 (CS+AG) 1.6 -12° 1.1 -12° 0.5 -12° Configuration #5 (CS) 5.4 +23° 9.2 +7° 3.5 -30° CS : Cutting structure AG : Active Gage PG : Passive Gage

Figure 10: Bit walk angle measured on the directional dr illing bench

Figure 11 : Spiraling tendency of the Bit B (configuration #5)


Bit X Bit Y Bit Z Bit steerability 0.1 0.01 0.001 Bit walk angle -20° < α < +20° -20° < α < +20° -20° < α < +20°

Table 2 : Bit steerability of the Bit X, Bit Y and Bit Z used for simulations

WELL #1 WELL #2 Hole diameter 9”7/8 9”7/8

Stabilizer diameter 9”7/8 9”7/8 Inclination at the bit 52° 13°

Mud weight 1150 kg/m3 1150 kg/m3 WOB 7.1 tons 5.7 tons ROP 108 m/h 22 m/h RPM 155 137

Bit type PDC PDC Friction coefficient 0.17 0.17

Collar Outside Diameter 6”1/2 6”1/2 Collar Inside Diameter 2”7/8 2”7/8

Table 3 : Parameters used for BHA simulations

Figure 12 : Descr iption of the BHAs


Figure 13 : Effect of the bit steerability and walk angle on the predicted build/drop rate and turn rate (well #1)

Figure 14 : Effect of the bit steerability and walk angle on the predicted build/drop rate and turn rate (well #2)

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how the Bit Profile and Gages Affect the Well Trajectory