DRILLING BIT OPTIMIZATION
PROJECT ADVISOR Mr. Rehan Hashmat
SUBMITTED BY Talha Umair Hashmi
(2004-PET-36)
Ashfaq Ali
(2004-PET-42)
Mukhtar Ahmed Barre
(2004-PET-52)
Syed Nisar Hussain Shah
(2004-PET-56)
Department of Petroleum & Gas Engineering, UNIVERSITY OF ENGINEERING & TECHNOLOGY LAHORE
PREFACE The choice of this project was quite natural because it is the need of hour to highlight the importance of “Drilling Bit Optimization” in petroleum industry. this
project “Drilling Bit Optimization” can be regarded as a step ahead from the latest technology., first defining basic drilling Optimization Concepts and then illuminate the drill bit analysis based on offset well data. It includes previous well and field records, bit run etc. modern technology in bits have greatly Optimize the ROP and has resulted a huge reduction in trip time. The ability to select and optimize bit and hydraulic criteria is recognizing as a critically important element of drilling operation. Impregnated Hybrid Bits have greatly increased the ROP and has decreased the trip time. Although these things, along with a number of techniques are important but not the prime essential. Case histories can be used to demonstrate the importance of drilling optimization. These factual experiences establish a sense e of reality when learning optimization concepts and methods that cannot be achieved hypothetical simulators exercises or example calculations. Drilling in a very hard, abrasive and inter bedded formation has always been extremely tough and challenging due to sudden changes in the formation characteristics which results in reduction in ROP. Such formations have proved a Museum Of Geology and drilling here has been most challenging and difficult. During Drilling the reduced ROP from an unexpected zone was encountered. Various techniques are applied to increase ROP and reduce trip time. Using Impregnated and hybrid bits with Turbu-drills, this problem is solved in a cost effective manner. The wells drill successfully to producing objectives after applying this optimized technology. This project reviews the optimized selection of bit, optimized hydraulics and in the end discusses a field example, where such techniques were applied successfully.
THIS PROJECT REPORT IS HANDED IN TO MEET NORMS SET FOR CONFERMENT OF BACHELOR DEGREE In
Petroleum Engineering
_________________ Project Advisor
________________ External Examinar
(Mr. Rehan Hashmat)
__________________ Chairman Petroleum and Gas Engg. Deptt. (Dr. Obaid-ur-Rehman Paracha)
Department of Petroleum & Gas Engineering, UNIVERSITY OF ENGINEERING & TECHNOLOGY LAHORE
Acknowledgment We are glad that we have made it to this day when we can cherish the sense of achievement by the blessing of Allah Almighty. This project is a result of hard work and team effort which alone would have had no meaning if the guidance and commitment of our Project Advisor, Mr Rehan Hashmat was not there, whose helping hand has made this project a land mark in our career. We are thankful to Mr. Shaukat Ali & Mr. Noor Ahmed (Dewan Petroleum Pvt. Ltd.) Mr. Hamad Ahmad (Reedhycalog) for providing the desired Data for the Project. We must thank all the Teachers of our Department whose support and experience always served as batten during the project.
Dedication To our Beloved Parents, Respected Teachers and Sincere Friends whose utmost love and attention for us brought us to this height of knowledge with the blessings of Allah Almighty.
PREFACE The choice of this project was quite natural because it is the need of hour to highlight the importance of “Drilling Bit Optimization” in petroleum industry. this
project “Drilling Bit Optimization” can be regarded as a step ahead from the latest technology., first defining basic drilling Optimization Concepts and then illuminate the drill bit analysis based on offset well data. It includes previous well and field records, bit run etc. modern technology in bits have greatly Optimize the ROP and has resulted a huge reduction in trip time. The ability to select and optimize bit and hydraulic criteria is recognizing as a critically important element of drilling operation. Impregnated Hybrid Bits have greatly increased the ROP and has decreased the trip time. Although these things, along with a number of techniques are important but not the prime essential. Case histories can be used to demonstrate the importance of drilling optimization. These factual experiences establish a sense e of reality when learning optimization concepts and methods that cannot be achieved hypothetical simulators exercises or example calculations. Drilling in a very hard, abrasive and inter bedded formation has always been extremely tough and challenging due to sudden changes in the formation characteristics which results in reduction in ROP. Such formations have proved a Museum Of Geology and drilling here has been most challenging and difficult. During Drilling the reduced ROP from an unexpected zone was encountered. Various techniques are applied to increase ROP and reduce trip time. Using Impregnated and hybrid bits with Turbu-drills, this problem is solved in a cost effective manner. The wells drill successfully to producing objectives after applying this optimized technology. This project reviews the optimized selection of bit, optimized hydraulics and in the end discusses a field example, where such techniques were applied successfully.
Table of Contents Chapter # 1
Introduction to Drilling Bit Optimization
1.1 History of Drilling Bit
1
1.2 Concept of Optimization
1
Chapter # 2
Drilling Bit Types and Components
2.1 What is a Drilling Bit?
3
2.2 Drilling Bit Types
3
2.2.1 Drag Bits
3
2.2.2 Types of Drag Bits
3
Chevron Bit, Scratcher Bit, Step Bit 2.2.3 Roller Cone Bit
4
2.2.4 Diamond Bit
5
Polycrystalline Diamond Compact (PDC) Bits Thermally Stable PDC (TSP) Bits 2.3 Drilling Bit Components
5
2.3.1 Journal
5
2.3.2 Bearings
6
2.3.3 Sets of Bearings
6
2.3.4 Seals
7
2.3.5 Nozzle
7
2.3.6 Cone
7
2.3.7 Cutters
7
Chapter # 3
Classification of Drilling Bit
3.0 Bit Classification for Roller Cone Bit
8
3.1 IADC Chart for Mill-Tooth Bits
8
3.2 IADC Chart for Insert Bits
9
3.3 IADC Chart Interpretation
10
3.3.1 Example
10
Chapter # 4
Drilling Bit Selection
4.1 Bit Selection Guidelines
11
4.2 Costs per Foot
12
4.2.1 Example
13
4.2.2 Break-Even Analysis
13
4.3 Specific Energy
14
4.4 Drilling Bit Dullness
15
4.5 Well Bit Records and Geologic information
15
Chapter # 5
Drilling Bit Design
5.0 Drilling Bit Design 16 5.1 Milled Tooth Bits
16
5.1.1 Journal Angle
17
5.1.2 Cone Profile
17
5.1.3 Cone Offset
17
5.1.4 Tooth Number and Spacing
19
5.1.5 Tooth Shape
19
5.1.6 Tooth hard facing
20
5.2 Insert Bits
20
5.2.1 Insert Protrusion
20
5.2.2 Insert Number, Diameter and Spacing
20
5.2.3 Insert Shape
21
5.2.4 Insert Composition
21
5.2.5 Additional Features
21
Gauge Retention, Shirttail Protection 5.2.6 Bearing Systems
22
Bearing Lubrication System 5.2.7 Seals 5.3 Polycrystalline Diamond Compact Bits (PDC)
25 25
5.3.1 Bit Design Elements
25
5.3.2 Bit Body
26
5.3.3 Cutter Geometry
26
Number of Cutters, Cutter Size, Back Rake, Side Rake, Cutter Shape 5.3.4 Bit Geometry
27
Bit Style, Gauge Protection, Bit Length, Bit Profile, Blade Geometry, Blade Height, Number of Blades 5.4 Regular Circulation Bit 5.4.1 Jet Circulation Bits
30 30
5.4.2 Air or Gas Circulation Bits 5.5 Jet Nozzles Chapter # 6
30 31
Dull Grading of Drilling Bit
6.0 The IADC Fixed Cutter Dull Grading System
32
6.1 System Enhancements
32
6.2 Application of Dull Grading System
32
6.2.1Inner/Outer Rows: Spaces 1 and 2.
32
6.2.2 Dull Characteristics: Space 3.
33
6.2.3 Location: Space 4.
34
6.3 Other Evaluation Criteria
35
6.3.1 Bearing: Space 5.
35
6.3.2 Gauge: Space 6.
35
6.4 Additional "Remarks"
35
6.4.1 Other Dull Characteristics: Space 7.
35
6.4.2 Reason Pulled: Space 8.
36
6.5 Conclusion
36
6.6 IADC Roller Bit Dull Bit Grading System
37
6.6.1 Columns (1&2) Steel Tooth Bits
37
6.6.2 Columns (1&2) Insert Bits
38
6.6.4 Column (3) Dull Characteristics: (Use only cutting structure related codes)
38
6.6.5 Column (4)
38
6.6.6 Column (5) Bearings/Seals:
38
6.6.7 Column (6) Gage: (Measure in fractions of an inch.) Codes)
38
6.6.8 Column (7) Other Dull Characteristic: (Refer to Column 3
38
6.6.9 Column (8) Reason Pulled or Run Terminated
38
6.6.10 Discussion of Dulling Characteristics
38
Chapter # 7
Drilling Bit Hydraulics
7.1 Introduction
49
7.2 Pressure Losses
49
7.2.1 Surface Connection Losses (P1)
50
7.2.2 Pipe and Annular Pressure Losses
51
7.2.3 Pressure Drop across Bit
51
7.3 Fundamentals of Hydraulics
51
7.4 Flow Regimes
53
7.4.1 Laminar flow
53
7.4.2Turbulent flow
53
7.4.3 Transitional flow
54
7.5 Fluid Types
54
7.6 Rheological Model
54
7.6.1 Bingham Plastic Mode
55
7.6.2 Power L Aw Model
57
7.6.3 Herschel Buckley Yield Power Law Model
58
7.7 Practical Hydraulics Equations
58
7.7.1 Bingham Plastic Model
59
7.7.2 Power Law Model
60
7.8 Pressure Loss across Bit
61
7.8.1 Procedure
62
7.9 Pressure Drop across Nozzles and Watercourses
62
7.9.1 Multiples nozzles
63
7.10 Example: Hydraulics calculations
64
7.10. 1 Bingham Plastic Model
64
7.10. 1 Power Law Model
70
7.10.3 Comparison of the two models
70
7.11 Optimization of Bit Hydraulics
71
7.11 .1 Surface Pressure
71
7.11.2 Hydraulic Criteria
71
7.11 .3 Maximum Bit Hydraulic Horsepower
71
7.11 .4 Maximum Impact Force
72
7.11 .5 Nozzle Selection
72
7.11 .6 Optimum Flow Rate
73
7.12 Field Method of Optimizing Bit Hydraulic
73
7.13 Example: Hydraulics Optimization
74
7.14 Hydraulic and ROP
75
7.15 A practical check on the efficiency of the bit hydraulic program
75
Chapter # 8
Drilling Bit Optimization
8.0 Optimized Bit Technology
76
8.1 Impregnated PDC Bits
76
8.1.1 Advantages
76
Enhanced Hydraulics, Matrix Flexibility 8.1.2 Disadvantage
77
8.1.3 Effect of temperature
77
8.1.4 Possible Remedies
78
8.2 PDC Hybrid Drill Bits
78
8.3 Design Optimization as Applied to Cutting Structure
79
8.3.1 Action of the cones
79
8.3.2 For a hard formation
80
8.3.3 For a soft formation
81
8.4 Bit Selection and Drilling Parameters
81
8.5 Bit Choices
81
8.6 Refining Bit Choice and Parameters Based On Previous Bit Run
82
8.7 WOB (Weight on Bit)
82
8.7.1 Weight-RPM
83
8.7.2 Variable RPM-weight
83
8.7.3 Constant RPM- Variable Weight
83
8.7.4 Constant RPM and Weight
83
Optimum RPM and Weight, Best Weight for given RPM, Best RPM for given Weight 8.8 Drill off Test
84
8.8.1 To Optimize WOB and RPM.
85
8.8.2 To Optimize Hydraulics
85
8.9 ROP (Rate of Penetration)
85
8.10 Rotary Speed and RPM
85
8.10.1 Longitudinal Drill-string Vibration
86
8.10.2 Transverse Drill-string Vibration
86
8.11 Minimizing Bit Whirl
86
8.12Monitoring Bit Progress While Drilling
87
8.13 When to Pull the Bit
87
8.14 Post-Drilling Bit Analysis
87
Chapter # 9 9.0 Introduction
Case History of Field 89
9.1 Problems Encountered During Drilling the Formations
89
9.2 Cause of such Problems
90
9.3 Solution of such Problems
90
9.4 How Air and Gas Drilling Optimized ROP in Such Formation
90
9.5 Advantages of Bits in Air and Gas Drilling Over Rotary Conventional Drilling90 9.6 Optimization of new well in this formation
91
Introduction
Chapter # 1
1.1 History of Drilling Bit A brief history of drilling bit; 2550 - 2315 BC The Egyptians Used Diamond Drilling Tools For The Construction Of The Pyramids. 600 - 260 BC Chinese Drill Up To 14 Inch Diameter and Depths Up To 2000 Feet 1825 AD First Cable Tool Drilling In Europe 1845 AD The Englishman Beart Obtains A Patent On Rotary Drilling Methods. 1863 AD First Diamond Coring In Switzerland 1878 AD First Patent on a Two Cone Bit 1893 AD Drilling Depths Reach 2004 M. 1908 AD First Rock Bit Used 1933 AD Tri-Cone Bit Introduced. 1947 AD Drilling Depths Reach 5418 M. 1948-1968-Signidicance Bit Improvement
1.2 Concept of Optimization Although bit cost comprises a relatively small fraction in a well's budget (± 5%), but bit performance's impact on overall well cost can be significant. This project address bit types, classification and optimization. In the past, selecting drill bits during well planning hinged to a large extent on the operator’s past experience in drilling offset wells. This practice often was a serendipitous,
1
Introduction
Chapter # 1
hit-or-miss proposition, based on the chance that the company’s drilling engineer on the job might have drilled some of the offsets. The optimization plan also usually involved a survey of historical bit record databases that indicated how certain bit types reacted in formations likely to be encountered in the upcoming well. The process was more qualitative than quantitative, and often required subjective rather than objective decision-making. Such analogous information, when combined with bit manufacturers’ technical data on specific products, yielded a list of bits or bit types that could be used to drill a borehole as clean and as close to gauge as possible in the least amount of time, given safety requirements and cost limits. In any case, it took considerable time to rustle up the necessary historical data, yet the estimated outcome still remained somewhat in doubt. The introduction of the Drill Bit Optimization System was a driving forcing that helped change all that. DBOS is a multidiscipline method for determining the optimum cutting structure, gauge protection, hydraulic configuration, and other bit design features for drilling with either roller cone or fixed cutter bits, whether in the conventional rotary mode or with various down hole motor-driven drilling tools. To characterize the down hole environment of a single well to be drilled, DBOS analysis starts with a thorough reconstruction of expected ideologies, revealed by customer- provided well logs from the closest offset well. The results include a formation analysis, unconfirmed rock strength analysis, and both roller cone and fixed-cutter bit selections. We combine numerous parameters that affect rate of penetration (ROP). These include bit record information, directional surveys, real-time ROPs and mud log data, along with rock type and strength data and hydraulic and mechanical energy factors, among others. In the BPA analysis we evaluates key bit performance variables over the given drillability intervals, identifying which bit type should be the most successful for drilling through each single interval or over multiple intervals. The analysis also includes both fixed cutter and roller cone bits in cases where either can be applied. To optimize the bit performance, we need to quantify and analyze all aspects of the drilling process.
2
Drilling Bit Types and Components
Chapter # 2
2.1 What is a Drilling Bit? The tool used to crush or cut rock. Everything on a drilling rig directly or indirectly assists the bit in crushing or cutting the rock. The bit is on the bottom of the drill-string and must be changed when it becomes excessively dull or stops making progress. Most bits work by scraping or crushing the rock, or both, usually as part of a rotational motion. Some bits, known as hammer bits, pound the rock vertically in much the same fashion as a construction site air hammer.
2.2 Drilling Bit Types 2.2.1 Drag Bits Drag bits are oldest type of rotary drilling bit and are rarely use now drag bits do not have distributed cutters; instead these bits have hard faced blades usually two blades (fishtail) bit or three. Rotary type Drag Bits are limited to softer formations generally. They are, in most cases cheaper than Rock Bits. The cutting profile may be flat, chevron or stepped according to application. They may be used in air or fluid flush. Drag Bits follow the path of least resistance. They cut very fast but will experience more drilling deviation than from using a tri-cone drill bit. 4-Blade bits are generally more user friendly to the drilling rigs as there are more cutting blades on the cutting surface to give a smoother cut.
2.2.2 Types of Drag Bits
Chevron Bit Chevron bits are designed for medium to hard formation and are used in areas that contain a lot of rock and also drilling out concrete casings and plugs.
Scratcher Bit A Scratcher Bit is designed for soft formation such as sand.
Step Bit Step bits are the most common type of drag bit used in the world today. They are primarily designed for soft to medium formation.
3
Drilling Bit Types and Components
Figure Chevron Bit
Figure Scratcher Bit
Chapter # 2
Figure Step Bit
2.2.3 Roller Cone Bits As the name implies, roller cone bits are made up of (usually) three equal-sized cones and three identical legs which are attached together with a pin connection. Each cone is mounted on bearings which run on a pin that forms an integral part of the bit leg. The three legs are welded together and form the cylindrical section which is threaded to make a pin connection. The pin connection provides a mean of attachment to the drill string, each leg is provided with an opening for fluid circulation. The size of this opening can be reduced by adding nozzles of different sizes. Nozzles are used to provide constriction in order to obtain high jetting velocities necessary for efficient bit and hole-cleaning. Mud pumped through the drill string passes through the bit pin bore and through the three nozzles, with each nozzle accommodating one third of the total flow, if all the nozzles were of the same size. There are two types of roller cone bits:
• Milled Tooth Bits: Here the cutting structure is milled from the steel making up the cone.
• Insert Bits: The cutting structure is a series of inserts pressed into the cones.
Figure Mill-tooth & Insert Bits
4
Drilling Bit Types and Components
Chapter # 2
2.2.4 Diamond Bits A diamond bit employs no moving parts (i.e. there are no bearings) and is designed to break the rock in shear and not in compression as is done with roller cone bits. Rock breakage by shear requires significantly less energy than in compression; hence less weight on bit can be used resulting in less wear and tear on the rig and drill string.
Polycrystalline Diamond Compact (PDC) Bits A PDC bit employs a large number of cutting elements, each called a PDC cutter. The PDC cutter is made by bonding a layer of polycrystalline man-made diamond to a cemented tungsten carbide substrate in a high pressure, high temperature process. The diamond layer is composed of many tiny diamonds which are grown together at random orientation for maximum strength and wear resistance.
Thermally Stable PDC (TSP) Bits Diamond also posses the highest thermal conductivity of any other mineral allowing it to dissipate heat very quickly. This is a desirable property from a cutting element to prevent it from burning or thermal fracture due to overheating. Diamond and TSP (thermally stable PDC) bits are used for drilling hard and abrasive formations.
Figures Diamond and TSP Bits
2.3 Drilling Bit Components 2.3.1 Journal The bit journal is the shaft on which the bearing is mounted. It is tilted at some angle depending on the desired structure of the cone.
5
Drilling Bit Types and Components
Chapter # 2
2.3.2 Bearings Bearing is a rotating support placed between moving parts to allow them to move easily. Bit bearings are used to perform the following functions; support radial loads, support thrust or axial loads and secure the cones on the legs There are two types of bearings; 1. Sealed Bearing 2. Unsealed Bearing
2.3.3 Sets of Bearings
Roller-Ball-Roller (RBR) It is the combination of two roller bearings with one ball bearing at the center shown in the figure.
Figure RBR
Roller-Ball-Friction (RBF) It is the combination of roller bearing, ball bearing and friction (case-hardened material) shown in the figure.
Figure RBF
6
Drilling Bit Types and Components
Chapter # 2
Ball-Roller-Ball (BRB) It is the combination of two balls and one roller bearing at the center.
2.3.4 Seals These are flexible slip which prevent the oil and grease leakage and prevent the entrance of dust particles in to bearing as shown in figure
Figure Seal
2.3.5 Nozzle A projecting part with an opening for the regulating and directing the flow of fluid as shown in figure. Figure Nozzle
2.3.6 Cone The conical shell which is surrounding the bearing while the cutters are milled or inserted on it as shown in figure3. Two types of cones are usually used: 1. Flat Cone
Figure Cone
2. Rounded Cone
2.3.7 Cutters The small teeth shape pieces inserted or milled on the cone shell use for chipping and crushing the formation. There are three types of cutters; 1. Milled Cutters 2. Inserted Cutters 3. PDC Cutters
Figure Different Insert Shapes
7
Drilling Bits Classification
Chapter # 3
3.0 Bit Classification for Roller Cone Bits In 1972, the International Association of Drilling Contractors (IADC) established a three code system for roller cone bits. The first code or digit defines the series classification relating to the cutting structure. The first code carries the numbers 1 to 8.For milled tooth bits, the first code carries the numbers 1 to 3, which describes soft, medium and hard (and semi-abrasive or abrasive) rocks respectively. This number actually signifies the compressive strength of rock. For insert bits, the first code carries the numbers 4 to 8.The second code relates to the formation hardness subdivision within each group and carries the numbers 1 to 4. These numbers signify formation hardness, from softest to hardest within each series. The second code is a sub-division of the first code (1 to 8). The third code defines the mechanical features of the bit such as non-sealed or sealed bearing. Currently there are seven subdivisions within the third code: 1. Non-Sealed Roller Bearing 2. Roller Bearing Air Cooled 3. Sealed Roller Bearing 4. Sealed Roller Bearing with Gauge Protection 5. Sealed Friction Bearing 6. Sealed Friction Bearing with Gauge Protection 7. Special Features - Category now Obsolete.
3.1 IADC Chart for Mill-Tooth Bits
8
Drilling Bits Classification
Chapter # 3
3.2 IADC Chart for Insert Bits
9
Drilling Bits Classification
Chapter # 3
3.3 IADC Chart Interpretation Character 1: Formation Hardness 1-3: Tooth Bits 4-8: Insert Bits Character 2: Hardness within Class Example: 1-1 is softer than 1-2 Character 3: Bearing Type 1. Standard Roller Bearing, No Seal 2. Roller Bearing, Air Cooled, No Seal 3. Roller Bearing, Gauge Protected, No Seal 4. Sealed Roller Bearing 5. Sealed Roller Bearing, Gauge Protected 6. Sealed Friction Bearing 7. Sealed Friction Bearing, Gauge Protected Character 4: Additional Design Features A. Air Application
R. Reinforced Welds
C. Center Jet
S. Standard Steel Tooth Model
D. Deviation Control
X. Chisel Inserts
E. Extended Jets
Y. Conical Inserts
G. Extra Gauge / Body Protection
Z. Other Insert Shapes
J. Jet Deflection
3.3.1 Example Bit type with code 125A means that Character 1: Formation Hardness; It’s for Mill-Tooth Bit. Character 2: Hardness within Class; It’s for soft medium. Character 3: Bearing Type; It’s for Sealed Roller Bearing, Gauge Protected. Character 4: Additional Design Features; It’s for Air Application.
10
Drilling Bit Selection
Chapter # 4
4.1 Bit Selection Guidelines Bit selection begins with a thorough examination of bit records from offset wells data. The best and worst performance and dull bit grading in formations comparable to the well being designed should be examined, analyzed and the used to determine the characteristics of the best performing drill bits. In particular attention should be given on the details such as the premature failure of bits, reasons drill bits pulled, dull characteristics of inserts: whether the inserts were worn or broken, etc. A drill bit that had broken inserts clearly indicates that the formation should have been drilled with a much harder drill bit. Data required for the correct bit selection include the following: 1. Prognoses lithology column with detailed description of each formation 2. Drilling fluid details 3. Well profile Formation characteristics should be studied in detail to assess the type of cutting structure required to successfully drill the formation. The existence of abrasive and hard minerals such as chert or pyrite nodules should be identified. This will impact on the aggressiveness of the selected milled teeth or insert bits and, in the case of PDC bits, the requirement for hybrid design bits. Gauge protection (which determines the final hole size) is particularly critical in abrasive formations where the gauge could be lost very quickly resulting in an under gauge hole which requires reaming during the next bit run. For highly abrasive sections the use of insert bits with diamond enhanced gauge protection prevents the occurrence of under gauge hole and reduces reaming on subsequent bit runs. When drilling directional wells the Contractor should be asked to provide an assessment of the required BHA changes, motor requirements and any limitations on bit operating parameters which may impact on the selection of bits. In addition bit characteristics in terms of walk, build and drop tendencies will need to be assessed for their impact on the well path. When using a mud motor in the assembly all tri-cone bits should have a motor bearing 11
Drilling Bit Selection
Chapter # 4
system which allows extended use at high motor RPM‘s or a fixed cutter bit should be selected. Due consideration should always be given to the jet system of the bit. When drilling soft shale sections where the major limitations on ROP is bottom hole and cutter cleaning, the use of centre jet, extended jets or lateral jet bits should be considered.
4.2 Cost per Foot The criterion for bit selection is normally based on cost/ft (C) and this is determined using the following equation: C
B (T t ) R $ / ft F
4.1
Where C=cost per foot ($ / ft), B= Bit Cost ($), T= Trip Time (hrs), t= Rotating Time (hrs), R= Rig Cost per Hr, F= Footage (ft) Equation (4.1) shows that cost/ft is controlled by five variables and for a given bit cost (B) and hole section (F), cost/ft will be highly sensitive to changes in rig cost per hour (R), trip time (T) and rotating time (t). The trip time (T) is the sum of RIH and POOH times. If the bit is pulled out for some reason, say, to casing shoe for a wiper trip, such duration, if added, will influence the total trip time (T) and, in turn, cost/ft. Bit performance, therefore, can be changed by some arbitrary factor and for accurate comparisons of different bit types, the tip time should be based on the time required for straight RIH and POOH. Rotating time is the total time the drill bit is rotating on bottom while drilling. The rig cost (R) will greatly influence the value of cost/ft. For a given hole section in a field that is drilled by different rigs, having different values of 'R', the same bit will produce different values of cost/ft, assuming the same rotating hours are used in all rigs. It should be pointed out that if the value of R is taken as arbitrary (say 2000 $/hr), then Equation 4.1 will yield equivalent values of cost/ft for all rigs. The value of cost/ft in this case is not a real value and does not relate to actual or planned expenditure; it is merely used for comparison. The criterion for selection of bits on the basis of cost/ft is to choose the bit which consistently produces the lowest value of C in a given formation or hole section.
12
Drilling Bit Selection
Chapter # 4
4.2.1 Example: Calculation of Cost /ft Determine the cost/ft for the following bit types which were used to drill the same type of formation in three wells. Which bit would you select for the next well?
Assume bit cost = $10,000 and rig cost= 900 $/hr Solution Using; C
B (T t ) R $ / ft F
C
10000 (8 144) 900 54.9 $ / ft 2670
C
10000 (8 180) 900 63.5 $ / ft 2822
Bit XX;
Bit XY;
On the basis of cost/ft, bit type XX is more economical than bit XY and should be used in the next well.
4.2.2 Break-Even Analysis The break-even analysis is usually used to investigate the economics of replacing a current cheap bit by a more expensive bit or vice versa. The comparison is normally based on a graph of footage against rig hours. The graph is established as follows: Calculate the number of rig hour’s equivalent to bit cost using: A=Cost of new bit ($)/Rig cost ($) Add trip time to A to obtain the total number of rig hours corresponding to the cost of the new bit before drilling commences. Call this time B. B = trip time + A Mark this point on the left-hand side of the X-axis, (i.e. rig hours axis), Figure 4.1.
Figure 4.1
13
Drilling Bit Selection
Chapter # 4
Calculate the number of feet of hole at break-even cost using: F= Cost of new bit +trip cost/Offset cost/ft Mark point F the Y-axis (i.e. footage axis). Draw a straight line through points B and F, Figure 4.1.This line is the break even line. Any footage and hour combination on this line is a break-even point. Above this line, the new bit will produce lower cost/ft than the offset bit and below this line the new bit is more expensive to run.
4.3 Specific Energy The Specific Energy Method gives a simple and practical method for Bit Selection. The energy required to remove unit volume of rock. The equation may be derived by considering the mechanical energy expended at the bit in one minute. Thus, E = W * 2ðR * N in-lb
4.2
Where W = weight on bit (lb) N = rotary speed (rpm) R = radius of bit (in) The volume of rock removed in 1 minute is: V = (ðR2) * PR in3
4.3
Where PR = penetration rate in (ft/hr) Dividing equations 4.2 & 4.3 gives specific energy in terms of volume as SE = E/V = W * 2ðR * N / (ðR2) * PR = 10
W * N lb * in R * PR in3
4.4
Replacing R by D/2, where D is the hole diameter. = 20
W * N in lb D * PR in3
4.5
Since PR = footage (F)/rotating time (t) In Metric Units = 2.35
W *N MJ / m 3 D * PR
4.6
It was decided that SE is not a fundamental intrinsic property of the rock. It is highly dependent on type and design of bit. This means that for a formation of given 14
Drilling Bit Selection
Chapter # 4
strength, a soft formation bit will produce an entirely different value of SE from that produced by hard formation bit. This property of SE therefore, affords accurate means for selection of appropriate bit type. The bit that gives the lowest value of SE in a given section is the most economical bit. Equation of SE also shows that, for a given type in a formation of constant strength, SE can be taken constant under any combination of WN values. This is because changes in WN usually lead to increase value of PR (under optimum hydraulics) and this maintains the balance of equation. The ROP is, however highly influenced by change in WN, and for a particular bit type an infinite number of PR values exist for all possible combinations of WN values. It follows that SE is a direct measure of bit performance in a particular formation and provides an indication of the interaction between bit and rock. The fact that SE. when compared with the ROP, is less sensitive to change in WN makes it practical tool for bit selection.
4.4 Bit Dullness The degree of dullness can be used as a guide for selecting a particular bit. Bits that wear too quickly are obviously less efficient and have to be pulled out of the hole more frequently. Bit Dullness is described by tooth wear and bearing condition. Tooth wear is reported as the total height remaining and is given a code from T1 to T8. T1 indicates that 1/8 of tooth has gone. T4 indicates that ½ height of the bit has gone. Similarly, bearing life is described by eight codes from B1 to B8. The number B8 indicates that bearing life has gone or the bearing is locked. If a bit has high tooth wear and less bearing life is, therefore not suitable for formation selected. If such a bit were a 1-1-1 type, then the use of a bit with a higher numerical code could reduce the wear and bearing deterioration. A bit type 1-2-4 may be chosen; the code 2 for the high rock strength, reducing tooth wear, and the code 4 is for sealed bearing. Code1 indicates that the bit is a milled tooth type.
4.5 Well Bit Records and Geologic information Drilling data from offset wells and geologic information can provide useful guides selection of drill bits. Sonic Logs from such wells can also be used to provide an estimate of rock strength which in turn provides the guide for selecting the proper bit type.
15
Drilling Bit Design
Chapter # 5
5.0 Drilling Bit Design The drill bit design is dictated by the type of rock to be drilled and size of hole. The three legs and journals are identical, but the shape and distribution of cutters on the three cones differ. The design should ensure that the three legs must be equally loaded during drilling. The following factors are considered when designing and manufacturing a three-cone bit:
Journal Angle
Offset between Cones
Cutters
Bearings
5.1 Milled-Tooth Bits Milled tooth bit design depends on the geometry of the cones and the bit body and geometry and composition of the cutting elements (teeth). The geometry of the cones and of the bit body depends on:
Journal Angle
Cone Profile
Offset Angle
The geometry and composition of the teeth depend on:
Journal Angle
Angle of Teeth
Length of Teeth
Number of Teeth
Spacing of Teeth 16
Drilling Bit Design
Shape of Teeth
Tooth Hard facing
Chapter # 5
5.1.1 Journal Angle The bit journal is the bearing load-carrying surface. The journal angle is defined as the angle formed by a line perpendicular to the axis of the journal and the axis of the bit, see Figure The magnitude of the journal angle directly affects the size of the cone; the size of the cone decreases as the journal angle increases. The journal angle also determines how much WOB the drill bit can sustain; the larger the angle the greater the WOB. The smaller the journal angle the greater is the gouging and scraping actions produced by the three cones. The optimum journal angles for soft and hard roller cone bits are 33 degrees and 36 degrees, respectively.
Figure 5.1
5.1.2 Cone Profile The cone profile determines the durability of the drill bit. Cones with flatter profile are more durable but give lower ROP, while a rounded profile delivers a faster ROP but is less durable.
5.1.3 Cone Offset The degree of cone offset (or skew angle) is defined as the horizontal distance between the axis of the bit and a vertical plane through the axis of the journal.
Figure 5.2
17
Drilling Bit Design
Chapter # 5
A drill bit with zero offset has the centre lines of the three cones meeting at the centre of the drill bit, see Figure 5.2. Skew angle is an angular measure of cone offset. A cone with zero offset has a true rolling action as the cone moves in a circle centered at the cone apex and bit centre. If the cone is offset from the bit centre, then when the drill bit is rotated from surface, the cone attempts to rotate around its own circle which is not centered at the bit centre. The cone is forced by the much bigger drill string to rotate about the centerline of the bit and drill string and this result in the cone slipping as it is rotating. This slipping produces tearing and gouging actions which are beneficial in drilling soft rocks as it removes a larger volume of rock. The amount of offset is directly related to the strength of rock being drilled. Soft rocks require a higher offset to produce greater scraping and gouging actions. Hard rocks
Cone Offset
Figure 5.3
Cone Onset
require less offset as rock breakage is dependent on crushing and chipping actions rather than gouging, Cone offset increases ROP but also increases tooth wear, especially in the gauge area, and increases the risk of tooth breakage. As shown in Figure 5.4, drill bits can have slender and long teeth (Figure 5.4a) or short and stubby teeth (Figure 5.4b). The long teeth are designed to drill soft formations with Figure 5.4a. Tooth Shape low compressive strength where the rock is more yielding and easily penetrated.
Figure 5.4
18
Drilling Bit Design
Chapter # 5
Penetration is achieved by applying weight on bit (WOB) which forces the teeth into the rock by overcoming the rock compressive strength. Rotation of the bit helps to remove the broken chips. Harder rocks have high compressive strength and can not be easily penetrated using typical field WOB values. Hard rock bits therefore have much shorter (and more) teeth with a larger bearing area, therefore the short teeth will be less likely to break when they are subjected to drilling loadings. The teeth apply load over a much larger area and break the rock by a combination of crushing, creation of fractures and chipping. The teeth are not intended to penetrate the rock, but simply to fracture it by the application of high compressive loads.
5.1.4 Tooth Number and Spacing As discussed above, a soft rock requires long and a few teeth allowing the WOB to be distributed over fewer teeth. The teeth are widely spaced to reduce the risk of the bit being balled up when drilling water sensitive clays and shales. Wider spacing also allows the rows of teeth from one cone to engage into the space of equivalent row of the adjacent cone and thereby help to self clean the cutting structure of any build up of drilled cuttings. For hard formations, the teeth are made shorter, heavier and more closely spaced to withstand the high compressive loads required to break the rock.
5.1.5 Tooth Shape Viewed from the side most teeth appear like an A without the crosspiece. There are other design such as the T-,U-, or W-shape which are more durable and are usually found at the gauge area of the bit. Figure 5.5 shows this.
Figure 5.5
19
Drilling Bit Design
Chapter # 5
5.1.6 Tooth Hard-facing To increase the life of the cutting tooth, hard metal facing (usually tungsten carbide) was initially applied to one side of the tooth to encourage preferential wear of the tooth. As the bit drills away, the tooth wears on one side (the uncovered steel side) thereby always leaving a sharp cutting edge on the metal faced side. This style is known as selfsharpening hard facing. Nowadays, most toothed bits use Full Coverage Hard facing, in which the entire tooth is covered with hard metal. This practice provides greater durability of the tooth and offers sustained ROP’s.
5.2 Insert Bits The design factors relating to cone offset, bit profile and cone profile discussed above for milled tooth bits apply equally to insert bits. The cutting structure of insert bit relies on using tungsten carbide inserts which are pressed into pre-drilled holes in the cones of the bit. The following relates to the various design features of inserts which are designed to suit various rock types.
5.2.1 Insert Protrusion Insert protrusion refers to the amount of insert protruding from the cone and is always less than the total length of the insert, Figure5.6. Inserts with large protrusions are suitable for soft rocks as would be seen on a 4-3 type cutting structure
Figure 5.6
and to a limited protrusion as on the insert as on a cutting structure.
5.2.2 Insert Number, Diameter and Spacing The same argument used in milled tooth bits applies here. Soft insert bits have fewer and longer inserts to provide aggressive penetration of the rock. Durable, hard formation bits have many, small diameter inserts with limited protrusion, see Figure 5.7.
Figure 5.7
20
Drilling Bit Design
Chapter # 5
5.2.3 Insert Shape For soft formation bits, the inserts have chisel shapes to provide aggressive drilling action. In soft, poorly consolidated formations the chisel shape is more efficient at penetrating the formation than a more rounded conical shape. Figure 5.8 shows seven shapes.
For Soft Rocks
Figure 5.8
For Hard Rocks
5.2.4 Insert Composition The composition of the inserts can be varied by altering grain size or cobalt concentration. In general changes that increase the wear resistance of the insert will make it more likely to break, while tougher inserts, less prone to breakage, may wear more rapidly.
5.2.5 Additional Features Additional enhancing features (Figure 5.9) include: •Gauge trimmers to assist in cutting a gauge hole
•Shirttail compacts to reduce leg wear in abrasive formations
Figure 5.9
21
Drilling Bit Design
Chapter # 5
Gauge Retention The majority of the drill bit work is spent around the heel and gauge area and therefore this part suffers the greatest amount of wear. Gauge trimmers are used to maintain bit gauge (diameter). This achieved by the use of Tshaped teeth on milled tooth bits and very short inserts in the gauge row. The gauge inserts may be diamond coated.
Shirttail Protection All drill bits may have tungsten carbide inserts placed in the heel area of the bit. A worn shirttail (Figure 5.10) may expose the seal, leading to seal wear and bearing failure. Various devices may be used to limit or delay shirttail wear. Tungsten Carbide Inserts may be placed in the shirttail itself. Lug pads may be added to the upper part of the shirttail. A band of hard metal can be added to the margin of the shirttail.
Figure 5.10
5.2.6 Bearing Systems The first type of bearing system used with roller cone bits was a non-sealed, roller-ballfriction bearing arrangement, utilizing rollers on the heel of the journal. The primary load, or stress was exerted on these rollers, and drilling fluid was used to lubricate the bearings. Bearing size was maximized, since room for a seal was not required. The bearing surfaces were machined and ground to very close tolerances to ensure dependable service. This type of bearing system is also available with modifications for air circulation and for use with a percussion hammer Figure 5.11. The next generation of bearing systems was a sealed roller bearing system, having a sealed grease reservoir to lubricate the bearings. The bearing system is composed of: 1) a roller-ball-friction or roller-ball-roller bearings 2) the seal, which retains the lubricant and prevents drilling 22
Drilling Bit Design
Chapter # 5
fluid and abrasive cuttings from entering the bearing cavities, 3) the shirttail is designed and hard faced to protect the seal, 4) a lubricant, an elastic-hydrodynamic type, is used to ensure minimum friction and wear, 5) the reservoir, which stores and supplies the lubricant to the bearings, and 6) the vented breather plug, which transfers down hole fluid pressure against the lubricant-filled flexible diaphragm to equalize pressures surrounding the bearing seal Figure 5.11.
Figure 5.11
There is, however, one serious drawback to the roller-ball-roller bearing system. The primary cause of roller bearing failure is journal spalling, which causes destruction of the rollers and the locking of the cone. To remedy this, instead of the standard roller bearing assembly, the “journal bearing” system utilizes solid metal bushings for direct cone to journal contact. This offers a distinct mechanical advantage over roller arrangements in that it presents a larger contact area at the load bearing point. This distribution of the load eliminated the chief cause of roller bearing assembly failure - spalling in the load portion of the bearing face. Journal bearing systems in the tungsten carbide insert bits features a metal bearing surface combined with a hard faced journal and a lubricant. Specialized seals and reliable pressure equalization systems keeps the drilling fluid and formation contaminants out of bearings, and positively seals the graphite-based lubricant inside the 23
Drilling Bit Design
Chapter # 5
bearing. Precision fit of the journal and cone distributes contact loading evenly throughout a near-perfect arc. Bearing surfaces are finished to a carefully controlled surface texture to ensure optimum lubrication. The manufacturing of the journal bearing system consists of having the journals milled, grooved or pressed (depending on the bit company) to accommodate the bushing. Then the bushings are inlaid on the journal. Once the cone is fitted with teeth and gauge protection, the journal is then machine-pressed into the cone. To complete the seal between the cone and the journal, special rings (seals) have been developed.
Bearing Lubrication System A sealed bearing system is lubricated by a sealed grease reservoir as shown in Figure 5.12 (Journal Bearing). The pressure of grease within the bearing must be the same as that outside in the mud. The lubrication system works as follows: An elastomeric pressure diaphragm communicates annular pressure to the grease in a grease reservoir (inside the leg) and then, via grease passages to the grease within the bearing itself. Thus zero differential pressure is maintained across the seal at all times. Some leakage of the grease may occur due to rapid pressure changes resulting from axial movement of the cone on the journal. The grease reservoir has enough fluid to allow for minor leakages.
Figure 5.12
24
Drilling Bit Design
Chapter # 5
5.2.7 Seals The first and still most popular seal is the radial seal (used mainly on the sealed roller bearing bits). The radial seal is a circular steel spring encased in rubber, which seals against the face of the shank and the face of the cone. The newer “O” ring seal is considered the most effective seal. The major problem confronting the “O” ring is tolerance, which must be precise in order to maintain an effective seal. An understanding of lubricants and lubricating systems is necessary for successful drilling operations. The lubricating systems are essentially the same, and are composed of an external equalizer located under the bit or on back of the shanks, a grease reservoir with some sort of expandable diaphragm to distribute the grease, and some sort of distribution system to the bearings. In addition, there is a pressure relief valve to release any trapped pressure, which might otherwise rupture the seals. Pressure surges can be detrimental to these sealed systems. As pressure and temperature increase, the viscosity of the lubricant increases. As a result, the system cannot instantaneously compensate for abrupt changes in pressure due to surges (going into the hole, making connections, etc.) and small quantities of mud invade the system. With the close tolerance necessary for effective sealing, mud solids can be damaging. Adequate cleaning is even more important with sealed bearing bits. If drilled cuttings are allowed to build up around the shirttail, seal damage and premature bearing failure may result. Gauge protection is also important to seal and bearing life, because seal damage can occur from shirttail wear caused by inadequate gauge protection. Any time a sealed bearing bit is rerun, the seals and shirttail should be carefully checked for excessive wear or grooving. To complete the journalcone assembly, a positive seal is required to keep drilling fluid out, while allowing the graphite lubricant in, which keeps the bearings from overheating. The positive seal requires a relief valve to allow escape of excess pressure, which can overload the seal and cause seal failure.
5.3 Polycrystalline Diamond Compact Bits (PDC) 5.3.1 Bit Design Elements There are many details relating to bit design which can be covered in detail here. Reference to manufacturers catalogues is recommended for the interested reader. 25
Drilling Bit Design
Chapter # 5
The PDC design is affected by: 1. Body design: can either be steel-bodied or tungsten carbide (matrix) 2. Cutters Geometry
Cutters Number of Cutters and spacing of cutters Size of Cutters Back Rake Side Rake
3. Geometry of Bit
Number of Blades Blade Depth
4. Diamond table
Substrate interface Composition Shape
5.3.2 Bit Body The bit body may be forged or milled from steel (steel-bodied bits) or constructed in a cast from tungsten carbide (matrix bit). From a practical standpoint, steel bodies bit are preferable as they can be easily repaired but suffer from erosion. Matrix bits are more resistant to erosion but are prone to bit balling in soft clay formations due to their low blade height compared with steel bodied bits.
5.3.3 Cutter Geometry Cutter geometry depends on:
Number of Cutters Soft rocks can be penetrated easily and hence fewer cutters are used on soft PDC bits as each cutter removes a greater depth of cut. More cutters must be added to hard PDC bits for harder formation to compensate for the smaller depth of cut.
26
Drilling Bit Design
Chapter # 5
Cutter Size Large cutters are used on softer formation bits and smaller cutters on the harder formation bits. Usually a range of sizes is used, from 8mm to 19mm is used on any one bit.
Back Rake Cutter orientation is described by back rake and side rake angles. Back rake is the angle presented by the face of the cutter to the formation and is measured from the vertical, see Figure the magnitude of rake angle affects penetration rate and cutter resistance to wear. As the rake angle increase, ROP decreases but the resistance to wear increases as the applied load is now spread over a much larger area.PDC cutters with small back rakes take large depths of cut and are therefore more aggressive, generate high torque, and are subjected to accelerated wear and greater risk of impact damage. Cutters with high back rake have the reverse of the above. Back rake angles vary between, typically, 15° to 45°. They are not constant across the bit, nor from bit to bit.
Side Rake Side rake is an equivalent measure of the orientation of the cutter from left to right. Side rake angles are usually small. The side rake angle assists hole cleaning by mechanically directing cuttings toward the annulus.
Cutter Shape The edge of the cutters may be beveled or chamfered to reduce the damage caused by impacts.
5.3.4 Bit Geometry The factors affecting bit geometry include:
Bit Style When all of the above features are put together, a variety of bit styles emerge as shown in Figure. The bit on the extreme left of Figure is a light set bit with a few, high blades and a few but large cutters with small back rake angles. Thus light set bits typically have a few, high blades, with few large cutters, probably with low back
27
Drilling Bit Design
Chapter # 5
For hard rocks, PDC bits will have more blades, with smaller and more numerous cutters and this trend continues to the heavy set bits on the extreme right.
Figure 5.13
Gauge Protection As discussed before, the greatest amount of work is done on the heel and gauge of the drill bit. A PDC bit that wears more on the gauge area will leave an under gauge hole which will require reaming from the next bit. Reaming is time consuming and costly and in some cases can actually destroy an entire bit without a single foot being drilled. Hence maintaining gauge is very important. One or more PDC cutters may be positioned at the gauge area. Pre-flatted cutters are used to place more diamond table against gauge. Tungsten carbide inserts, some with natural or synthetic diamonds embedded in them may be placed on the flank of the bit. A major advantage with fixed cutter bits over roller cone bits are those the gauge on fixed cutter bits may be extended to a larger length of the drill bit.
Bit Length This is important for steer ability. Shorter bits are more steerable. The two bits on the left of Figure 5.14 are sidetrack bits, with a short, flat profile. The ‘Steering Wheel’ bit on the right of is designed for general directional work
Figure 5.14
28
Drilling Bit Design
Chapter # 5
Bit Profile Bit profile affects both cleaning and stability of the bit. The two most widely used profiles are: double cone and shallow cone, Figure 5.15. The double cone profile allows more cutters to be placed near the gauge giving better gauge protection and allowing better directional control. The shallow cone profile gives faster penetration but has less area for cleaning. In general a bit with a deep cone will tend to be more stable than a shallow cone.
Figure 5.15
Blade Geometry PDC bits can be manufactured with a variety of blade shapes ranging from straight to complex curve shapes. Experience has shown that curved blades provide a greater stability to the bit especially when the bit first contacts the rock.
Blade Height A soft formation PDC bit will have a lager blade height than a hard PDC bit with a consequent increase in junk slot area. Higher blades can be made in steel bodied- bits than matrix bits, because of the greater strength of steel over that of matrix.
Number of Blades Using the same analogy for roller cone bits, a PDC bit designed for soft rocks has a fewer blades (and cutters) than one designed for hard rocks. The soft formation PDC bit will therefore have a large junk slot area to remove the large volume of cut rock and to reduce bit balling in clay formations, Figure 5.16a.
Figure 5.16
29
Drilling Bit Design
Chapter # 5
A hard PDC bit with many blades requires many small cutters, each cutter removing a small amount of rock, Figure 5.16b.
5.4 Regular Circulation Bits Regular circulation bits (Figure 3-3a), have one to three holes drilled in the dome of the bit. Drilling fluid passes through the bore of the bit, through the drilled holes, over the cutters, and then to the bottom of the hole, to flush away the drill cuttings.
5.4.1 Jet Circulation Bits Jet circulation bits Figure 5.17 are manufactured with smooth, streamlined, fluid passageways in the dome of the bit. Drilling fluid passes through the bore of the bit at high velocities with minimum pressure losses, through the jet nozzles, and then to the hole bottom to flush cuttings away from the bit and up the hole. Excess fluid that impinges on the hole bottom flows up and around the cutters for cutter cleaning.
Figure 5.17
5.4.2 Air or Gas Circulation Bits A third type of circulation medium is compressed air or gas, and can be used with either regular or jet circulation bits. Bits manufactured for air or gas circulation have special passageways from the bore of the bit to the bearings, through which a portion of the air or gas is diverted to keep the bearings cool and purged of dust or cuttings. From the special passageways to the bearings, the air or gas passes through a number of strategically located ports or holes in the bearing journal, flows through the bearing structure and exhausts at the shirttail and gauge of the bit, to flow up the annulus.
30
Drilling Bit Design
Chapter # 5
5.5 Jet Nozzles There are essentially three types of jet nozzles used in tri-cone bits. Shrouded nozzle jets provide maximum protection against retainer ring erosion, excessive turbulence or extended drilling periods. Standard jet nozzles are easier to install and are recommended for situations where erosion is not a problem. Air jet nozzles (see above) are used on bits designated for drilling with air or gas. Nozzle sizes play an important role in bit hydraulics. The benefits of the correct selection include effective hole cleaning and cuttings removal, faster drill rates and thus Figure 5.18 lower drilling costs. Orifice sizes are stated in 1/32 inch increments, with the most common being between 10/32 to 14/32 sizes. Directional bit jets are available in sizes from 18/32 to 28/32.
31
Dull Grading of Drilling Bit
Chapter # 6
6.0 The IADC Fixed Cutter Dull Grading System Dull grading systems for fixed cutter bits, described herein, were implemented to improve utilization and effectiveness of the dull grading system.
6.1 System Enhancements The format of the dull grading chart is shown in Figure 6.1. Eight factors are recorded: the first four spaces describe the extent and location of wear of the "Cutting Structure". The next two spaces address other criteria for bit evaluation, with the fifth space reserved for grading "Bearing" wear of roller cone bits. This space is always marked with an "X" when fixed cutter bits are graded. The sixth space indicates "Gauge Measurement". The last two positions allow for "Remarks" which provide additional information concerning the dull bit, including "Other (or secondary) Dull Characteristics" and "Reason Pulled", respectively. Additional enhancements include addition of a dull characteristic code, "BF", to distinguish "bond failure" between the cutter and its support backing from "LT", loss or a cutter. In addition, the optional designations "RR" or "NR" were added to allow for indication of whether a bit is "rerun able" or not. Application of these minor revisions will further "standardize" the meaning of a dull grade. Examples of dull characteristics are shown in Figure 6.1.
6.2 Application of Dull Grading System 6.2.1Inner/Outer Rows: Spaces 1 and 2. Evaluating "Cutting Structure"
Cutting Structure 0
No Wear
4
50% Wear
8
No Useable Cutting
Using a linear scale from 0 to 8, as before, a value is given to cutter wear in both the,
32
Dull Grading of Drilling Bit
Chapter # 6
Figure 6.1
inner and outer rows of cutters. Grading numbers increase with amount of wear, with 0 representing no wear, and 8 meaning no usable cutters left. A grade of 4 indicates 50% wear. For surface-set bits, the scale of cutter wear is determined by comparing the initial cutter height with the amount of usable cutter height remaining. Rather than evaluating "usable cutter height", PDC cutter wear is now measured across the diamond table, regardless of the cutter shape, size, type or exposure. This eliminates the difficulty in determining the initial cutter height on a bit in which PDC cutters are designed with less-than-full exposure. Figure6.2 For both surface-set and PDC bits, the average amount of wear for each area is recorded, with 2/3 of the radius representing the "inner rows" and the remainder representing the "outer rows".
6.2.2 Dull Characteristics: Space 3. Average wear is calculated by simply averaging the individual grades for each cutter 33
Dull Grading of Drilling Bit
Chapter # 6
in the area
Dull/Other Characteristics BC -Broken Cone
LT -Lost Teeth/Cutters
BF -Bond Failure
NO - No Major/Other Dull
BT -Broken Teeth/Cutters
NR -Not Rerun-able
BU -Balled Up
OC -Off-Center Wear
CC -Cracked Cone
PB -Pinched Bit
CD -Cone Dragged
PN -Plugged Nozzle/
CI -Cone Interference
Flow Passage
CR -Cored
RG -Rounded Gauge
CT -Chipped Teeth/Cutters
RO -Ring Out
ER -Erosion
RR –Rerun-able
FC -Flat Crested Wear
SD -Shirttail Damage
HC -Heat Checking
SS - Self Sharpening Wear
JD -Junk Damage
TR -Tracking
LC -Lost Cone
WO -Washed Out Bit
LN -Lost Nozzle
WT -Worn Teeth/Cutters
The most prominent or "primary" physical change from new condition of a cutter is recorded in the third space. "Other" dull characteristics of the bit are noted in the seventh space the difference being that space 3 describes cutter wear, while space 7 may concern other wear characteristics of the bit as a whole. Codes for dull characteristics of both categories are listed in the table in Figure 6.1, including the addition of "BF" for bond failure.
6.2.3 Location: Space 4.
Location C - Cone
G - Gauge
N - Nose (Row)
A - All Areas Rows
T - Taper
M - Middle Row
S – Shoulder
H – Heel Row
34
Dull Grading of Drilling Bit
Chapter # 6
Figure6. 3
The fourth space is used to indicate the location of the primary dull characteristic noted in the third space. Locations are designated in the diagram.
6.3 Other Evaluation Criteria 6.3.1 Bearing: Space 5. This space is used only for roller cone bits. It will always be marked "X" for fixed cutter bits.
Bearing/Seals Non-Sealed Bearing
Sealed Bearing
0
No life Used
E
Seals Effective
8
All Life Used
F
Sealed Failed
X
Fixed Cutter Bit
6.3.2 Gauge: Space 6. The sixth space is used to record the condition of the bit gauge. 'I' is used if the bit is still in gauge. Otherwise, the amount the bit is under gauge is recorded to the nearest 1/16th of an inch.
Gauge 1
in gauge
1/16 under gauge up to 1/16
3/16 under gauge 1/8to 3/16 4/16 under gauge 3/16to1/4
2/16 under gauge 1/16 to 1/8
6.4 Additional "Remarks" 6.4.1 Other Dull Characteristics: Space 7. In the seventh space, secondary evidence of bit wear is noted. Such evidence may 35
Dull Grading of Drilling Bit
Chapter # 6
relate specifically to cutting structure wear, as recorded in the third space, or may note identifiable wear of the bit as a whole, such as "erosion". Many times, this "secondary" dull grade identifies the cause of the dull characteristic noted in the third space. Codes for grading both "primary" and "secondary" dull characteristics are listed in the table shown in Figure. The designations "RR" and "NR" have been included as options for noting whether the bit is rerun-able or not.
6.4.2 Reason Pulled: Space 8. The eighth space is used to record the reason the bit was pulled. A list of codes is shown in Figure.
Reasons for Pulling Bit BHA-Change Bottom hole Assembly
FM-Formation Change
DMF-Down hole Motor Failure
HP-Hole Problems
DSF-Drill string Failure
HR-Hours
DST-Drill Stem Test
PP-Pump Pressure
DTF-Down hole Tool Failure
PR-Penetration Rate
LOG-Run Logs
TD-Total Depth/CSG Depth
RIG-Rig Repair
TQ-Torque
CM-Condition Mud
TW-Twist Off
CP-Core Point
WC-Weather Conditions
DP-Drill Plug
WO-Washout Drill string
6.5 Conclusion Despite their minor nature, the changes described in this "First Revision to the IADC Dull Grading System" are expected to facilitate easier, more accurate evaluation of fixed cutter bit wear. With the addition of new dull characteristic codes, more specific descriptions of bit wear are possible, while the revised criteria for measuring PDC cutter wear will ensure a standard approach is taken in each instance. Thus, a dull grade ultimately will "mean the same thing" to everyone, as originally intended. 36
Dull Grading of Drilling Bit
Worn Cutter (WT)
Bond Failure (BF)
Broken Cutters (BT)
Chipped Cutters (CT)
Worn Cutters (WT), Balled Up (BU)
Lost Cutters (LT), Erosion (ER)
Broken Cutter (BT)
Erosion (ER), Lost Cutters (LT)
Chapter # 6
Plug Nozzle Flow Pasage (PN)
Heat Checking (HC)
Junk Damage (JD)
Rounded Gauge (RG)
The above are some examples of grading for the fixed cutter bits.
6.6 IADC Roller Bit Dull Bit Grading System The IADC Dull Grading System (above) can be applied to all types of roller cone bits as well as all types of fixed cutter bits. Bits with steel teeth, tungsten carbide inserts, and natural or synthetic diamond cutters can all be described with this system. A description of the dull grading system follows with each of the components explained as they apply to roller cone bits. Applications to fixed cutter bits have been discussed before.
6.6.1 Columns (1&2) Steel Tooth Bits A measure of lost tooth height due to abrasion and/or damage where: 0
No lost worn and/or broken inserts.
8
All of cutting structure lost, worn and/or broken. 37
Dull Grading of Drilling Bit
Chapter # 6
6.6.2 Columns (1&2) Insert Bits A measure of total cutting structure reduction due to lost, worn and/or broken inserts where: 0
No lost worn and/or broken inserts.
8
All inserts lost, worn and/or broken.
6.6.4 Column (3) Dull Characteristics: (Use only cutting structure related codes.) Same as for Fixed Cutters
6.6.5 Column (4) Location: N - Nose Row
G - Gage Row (Cone #2)
M - Middle Row (Cone #1)
A - All Rows (Cone #3)
6.6.6 Column (5) Bearings/Seals: Same as for Fixed cutters
6.6.7 Column (6) Gage: (Measure in fractions of an inch.) Gauge 1/16 - 1/16" out of gauge
3/16 - 3/16" out of gauge
2/16 - 1/8" out of gauge
4/16 - 1/4" out of gauge
6.6.8 Column (7) Other Dull Characteristic: (Refer to Column 3 Codes.) 6.6.9 Column (8) Reason Pulled or Run Terminated Same as for Fixed Cutters
6.6.10 Discussion of Dulling Characteristics BC (Broken Cone) or BF (Bond
CD (Cone Dragged)
Failure)
CI (Cone Interference) CR (Cored)
BT (Broken Teeth) BU (Balled
Up)
CC (Crocked Cone)
CT (Chipped Teeth) ER (Erosion) 38
Dull Grading of Drilling Bit
Chapter # 6
FC (Flat Crested Wear)
PN (Plugged Nozzle)
HC (Heat Checking)
RG (Rounded Gage)
JD (Junk Damage)
SD (Shirttail Damage)
LC (Lost Cone)
SS (Self Sharpening Wear)
LN (Lost Nozzle)
TR (Tracking)
LT (Lost Teeth)
WO (Washed Out Bit)
OC (Off Center Wear) PB (Pinched Bit)
WT (Worn Teeth)
Following is a discussion, and photographs of the dulling characteristics common to roller cone bits. While the possible causes listed and possible solutions for problem wear modes are not presumed to be exclusive. They represent situations commonly encountered in the field.
BC (Broken Cone) or BF (Bond Failure) This describes a bit with one or more cones that have been broken into two or more pieces, but with most of the cone still attached to the bit. Broken cones can be caused in several ways.
Some of the causes of BC are: 1.
Cone interference - where the cones run on each other after a bearing failure and break one or more of the cones. Bit hitting a ledge on trip or connection.
2.
Dropped drill string.
3.
Hydrogen sulfide embrittlement.
4.
BF (Bond Failure)
5.
Refers to Fixed Cutter Dull Condition
Figure BC (Broken Cone) CONE)Cone)
39
Dull Grading of Drilling Bit
Chapter # 6
BT (Broken Teeth) In some formations BT is a normal wear characteristic of tungsten carbide inserts bits and is not necessarily an indicator of any problems in bit selection or operating practices.
Figure BT (Broken Teeth)
Some causes of BT are 1.
Bit run on junk.
2.
Bit hitting a ledge or hitting bottom suddenly.
3.
Excessive WOB for application. Indicated by broken teeth predominantly on the inner and middle row teeth. Excessive RPM for application. Indicated by broken teeth predominantly on the gauge row teeth.
4.
Improper break-in of bit when a major change in bottomhole pattern is made. Formation too hard for bit type.
BU (Balled Up) A balled up bit will show tooth wear due to skidding, caused by a cone, or cones, not turning due to formation being packed between the cones. The bit will look as if a bearing had locked up even though the bearings are still good.
Figure Balled Up, BU
Some causes of bailing up are: 1.
Inadequate hydraulic cleaning of the bottom hole.
2.
Forcing the bit into formation cuttings with the pump not running.
3.
Drilling a sticky formation.
CC (Cracked Cone) A crocked cone is the start of a broken or lost cone and has many of the same possible causes.
Some of these causes are: 1.
Junk on the bottom of the hole.
Figure Cracked Cone, CC
40
Dull Grading of Drilling Bit 2.
Bit hitting a ledge or bottom.
3.
Dropped drill string.
4.
Hydrogen sulfide embrittlement.
5.
Overheating of the bit.
6.
Reduced cone shell thickness due to erosion.
Chapter # 6
Cone interference.
CD (Cone Dragged) This dull characteristic indicates that one or more of the cones did not turn during part of the bit run, indicated by one or more flat wear spots.
Some of the possible causes are: 1.
Bearing failure on one or more of the
Figure Cone Dragged, CD
cones. 2.
Junk lodging between the cones.
3.
Pinched bit causing cone interference.
4.
Bit bailing up.
5.
Inadequate break in.
CI (Cone Interference) Cone interference often leads to cone grooving and broken teeth and is sometimes mistaken for formation damage. Broken teeth caused by cone interference are not an indicator of improper bit selection.
Figure Cone Interference, CI
Some of the causes of cone interference are: 1.
Bit being pinched.
2.
Reaming under gauge hole with excessive WOB.
3.
Bearing failure on one or more cones.
CR (Cored) A bit is cored when its centermost cutters are worn and/or broken off. A bit can also be cored when the
Figure Cored Bit, CR
41
Dull Grading of Drilling Bit
Chapter # 6
nose part of one or more cones is broken.
Some things that can cause bits to become cored are: 1.
Abrasiveness of formation exceeds the wear resistance of the center cutters. Improper breaking in of a new bit when there is a major change in bottom hole pattern. Cone shell erosion resulting in lost cutters.
2.
Junk in the hole causing breakage of the center cutters.
CT (Chipped Teeth) On tungsten carbide insert bits, chipped insert often become broken teeth. A tooth is considered chipped, as opposed to broken, if a substantial part of the tooth remains above the cone shell. Some causes of chipped teeth are: 1.
Impact loading due to rough drilling.
2.
Slight cone interference.
3.
Rough running in air drilling application.
Figure Chipped Teeth, CT
ER (Erosion) Fluid erosion leads to cutter reduction and/or loss of cone shell material. The loss of cone shell material on tungsten carbide insert bits can lead to a loss of inserts due to the reduced support and grip of the cone shell material.
Erosion can be caused by: 1.
Figure Cone Erosion, ER
Abrasive formation contacting the cone shell between the cutters, caused by tracking, off-center wear, or excessive WOB.
2.
Abrasive formation cuttings eroding the cone shell due to inadequate hydraulics.
3.
Excessive hydraulics resulting in high velocity fluid erosion.
4.
Abrasive drilling fluids or poor solids control.
42
Dull Grading of Drilling Bit
Chapter # 6
FC (Flat Crested Wear) Flat crested wear is an even reduction in height across the entire face of the cutters. Interpretation of the significance of flat crested wear are numerous, and dependent on many factors, including formation,
Figure Flat Crested Wear, FC
hardfacing and operating parameters.
One of the causes of flat crested wear is: 1.
Low WOB and high RPM, often used in attempting to control deviation.
HC (Heat Checking) This dulling characteristic happens when a cutter is overheated due to dragging on the formation and is then cooled by the drilling fluid over many cycles.
Some situations that can cause heat checking are:
Figure A4-13 Heat Checking, HC
1.
Cutters being dragged.
2.
Reaming a slightly under gauge hole at high RPM.
JD (Junk Damage) Junk damage can be detected by marks on any part of the bit. Junk damage can lead to broken teeth, damaged shirttail, and shortened bit runs and therefore can become a problem.
Causes of junk damage are:
Figure Junk Damage, JD
1.
Junk dropped in the hole from the surface (tong dies, tools, etc.).
2.
Junk from the drill string (reamer pins, stabilizer blades, etc.).
3.
Junk from a previous bit run (tungsten carbide inserts, ball bearings, etc.).
4.
Junk from the bit itself (tungsten carbide inserts, etc.).
43
Dull Grading of Drilling Bit
Chapter # 6
LC (Lost Cone) It is possible to lose one or more cones in many ways. With few exceptions, the lost cone must be cleared from the hole before drilling can resume.
Some of the causes of lost cones are:
Figure Lost Cone, LC
1.
Bit hitting bottom or a ledge on a trip or connection.
2.
Dropped drill string.
3.
Bearing failure (causing the cone retention system to fail).
4.
Hydrogen sulfide embrittlement.
LN (Lost Nozzle) While LN is not a curing structure dulling characteristic, it is an important "Other Dulling Characteristic" that can help describe a bit condition. A lost nozzle causes a pressure decrease which
requires that the bit be pulled out of the hole. A lost Figure Lost Nozzle, LN While LN nozzle is also a source of junk in the hole.
Some causes of lost nozzles are: 1.
Improper nozzle installation.
2.
Improper nozzle and/or nozzle design.
3.
Mechanical or erosion damage to nozzle and/or nozzle retaining system.
LT (Lost Teeth) This dulling characteristic leaves entire tungsten carbide inserts in the hole which are far more detrimental to the rest of the bit than are broken inserts.
Some causes of lost teeth are:
Figure Lost Teeth, LT
1.
Lost teeth often cause junk damage.
2.
Lost teeth are sometimes preceded by rotated inserts. 44
Dull Grading of Drilling Bit
Chapter # 6
3.
Cone shell erosion.
4.
A crack in the cone that loosens the grip on the insert.
5.
Hydrogen sulfide embrittlement cracks.
OC (Off Center Wear) This dulling characteristic occurs when the geometric center of the bit and the geometric center of the hole do not coincide. This results in an oversized hole. Off center wear can be recognized on the dull bit by wear on the cone shells between the rows of cutters, more gauge wear on one cone, and by a less than expected
Figure Off Center Wear, OC
penetration rate
Off Center Wear can be caused by: 1.
Change of formation from a brittle to a more plastic formation. Inadequate stabilization in a deviated hole.
2.
Inadequate WOB for formation and bit type.
3.
Hydrostatic pressure that significantly exceeds the formation pressure.
PB (Pinched Bit) Bits become pinched when they are mechanically forced to a less than original gauge. Pinched bits can lead to broken teeth, chipped teeth, cone interference, dragged cones and many other cutting structure dulling characteristics.
Figure Pinched Bit, PB
Some possible causes of pinched bits are: 1.
Bit being forced into under gauge hole.
2.
Roller cone bit being forced into a section of hole drilled by fixed cutter bits, due different OD tolerances. Forcing a bit through casing that does not drift to the bit size used.
3.
Bit being pinched in the bit breaker. 45
Dull Grading of Drilling Bit 4.
Chapter # 6
Bit being forced into an undersized blow out preventer stack.
PN (Plugged Nozzle) This dulling characteristic does not describe the cutting structure but can be useful in providing information about a bit run. A plugged nozzle can lead to reduced hydraulics or force a trip out of the hole due to excessive pump pressure.
Figure Plugged Nozzle, PN
Plugged nozzles can be caused by: 1.
Jamming the bit into fill with the pump off.
2.
Solid material going up the drill string through the bit on a connection and becoming lodged in a nozzle when circulation is resumed.
3.
Solid material pumped down the drill string and becoming lodged in a nozzle.
RG (Rounded Gage) This dulling characteristic describes a bit that has experienced gauge wear in a rounded manner, but will still drill a full size hole. The gauge inserts may be less than nominal bit diameter but the cone backfaces are still at nominal diameter.
Figure Rounded Gauge, RG
Rounded Gage can be caused by: 1.
Drilling an abrasive formation with excessive RPM.
2.
Reaming an under gauge hole.
SD (Shirttail Damage) Shirttail damage may be different than junk damage and is not a cutting structure dulling characteristic. Shirttail wear can lead to seal failures. Some causes of shirttail damage are: Figure Shirttail Damage, SD
1.
Junk in the hole.
2.
Reaming under gauge hole in faulted or broken formations.
3.
A pinched bit causing the shirttails to be the outer most part of the bit.
4.
Poor hydraulics. High angle well bore. 46
Dull Grading of Drilling Bit
Chapter # 6
SS (Self Sharpening Wear) This is a dulling characteristic which occurs when cutters wear in a manner such that they retain a sharp crest shape.
TR (Tracking)
Figure Self Sharpening Wear, SS
This dulling characteristic occurs when the teeth mesh like a gear into the bottom hole pattern. The cutter wear on a bit that has been tracking will be on the leading and trailing flanks. The cone shell wear will be between the cutters in a row. Tracking can
sometimes be alleviated by using a softer bit to drill the Figure TR (Tracking) formation and/or by reducing the hydrostatic pressure if possible.
Tracking can be caused by: 1.
Formation changes from brittle to plastic.
2.
Hydrostatic pressure that significantly exceeds the formation pressure
WO (Washed Out Bit) If the bit weld is porous or not closed, then the bit will start to washout as soon as circulation starts. Often the welds are closed but crack during the bit run due to impact with bottom or ledges on connections. When a crack occurs and circulation starts through the crack, the washout is established very
Figure Bit Washout, WO
quickly.
WT (Worn Teeth) This is a normal dulling characteristic of the tungsten carbide insert bits as well as for the soft tooth bits. When WT is noted for steel tooth bits, it is also often appropriate to note self sharpening (SS) or flat crested (FC) wear.
Figure Worn Teeth, WT
47
Dull Grading of Drilling Bit
Chapter # 6
NO (No Dull Characteristics) This code is used to indicate that the dull shows no sign of the other dulling characteristics described. This is often used when a bit is pulled after a short run for a reason not related to the bit, such as a drill string washout.
48
Drilling Bits Hydraulics
Chapter # 7
7.1 Introduction This chapter deals with practical methods of calculating pressure losses in the various parts of the circulating system and the selection of nozzle sizes. Several models exist for the calculation of pressure losses in pipes and annulus. Each model is based on a set of assumptions which cannot be completely fulfilled in any drilling situation. The Bingham plastic, Power law and Herschel-Buckley models are the most widely used in the oil industry.
7.2 Pressure Losses Figure 7.1 below gives a schematic of the circulating system. We have divided the circulating system into four sections: 1.
Surface connections.
2.
Pipes including drill-pipe, heavy walled drill-pipe and drill collars.
3.
Annular areas around drill-pipes, drill-collars, etc.
4.
Drill Bit.
Figure 7.1
49
Drilling Bits Hydraulics
Chapter # 7
Our objective is to calculate the pressure (energy) losses in every part of the circulating system and then find the total system losses. This will then determine the pumping requirements from the rig pumps and in turn the horse power requirements.
7.2.1 Surface Connection Losses (P1) The pressure losses in surface connections (P1) are those taking place in standpipe, rotary hose, swivel and Kelly. The task of estimating surface pressure losses is complicated by the fact that such losses are dependent on the dimensions and geometries of surface connections. These dimensions can vary with time, owing to continuous wear of surfaces by the drilling fluids. The following equation gives pressure losses in surface connections: P1 E 0.8Q1.8 PV 0.2
7.1
Where ñ= mud weight (lbm/gal) Q = volume rate (gpm) E = a constant depending on type of surface equipment used PV = plastic viscosity (cp) In practice, there are only four types of surface equipment; each type is characterized by the dimensions of standpipe, Kelly, rotary hose and swivel. Table below summaries the four types of surface equipment. Table: Types of surface equipment
The values of the constant E in Equation (7.1) are given in Table Table: Values of constant E
50
Drilling Bits Hydraulics
Chapter # 7
7.2.2 Pipe and Annular Pressure Losses The pipe losses take place inside the drillpipe and drill collars and are described in Figure 7.1 as P2 and P3, respectively. Annular losses take place around the drill collar and drillpipe and are given the names P4 and P5 as shown in the figure 7.1. The magnitudes of P2 , P3 ,P4 ,and P5 depend on:
Dimensions of drillpipe (or drill collars), e.g. inside and outside diameter and length;
Mud rheological properties, which include mud weight, plastic viscosity and yield point; and
Type of flow, which can be laminar, or turbulent.
It should be noted that the actual behavior of drilling fluids downhole is not accurately known and fluid properties measured at the surface usually assume different values at the elevated temperature and pressure downhole.
7.2.3 Pressure Drop across Bit Drill bits are provide with nozzles to provide a jetting action, mainly required for cleaning and cooling, but can also help with rock breakage in soft formations. The largest nozzle is one inch in size, often termed open, but more often the nozzles used are a fraction of an inch. Hence, the pressure requirements to pass, say 1000gpm, through such small nozzles will be large. For a given length of drill string (drillpipe and drill collars) and given mud properties, pressure losses P1, P2, P3, P4, and P5 will remain constant. However, the pressure loss across the bit is greatly influenced by the sizes of nozzles used, and volume flow rate. For a given flow rate the smaller the nozzles, the greater the pressure drop and, in, turn the greater the nozzle velocity. For a given maximum pump pressure, the pressure drop across the bit is obtained by subtracting Pc (= P1+ P2 +P3 +P4+P5) from the pump pressure.
7.3 Fundamentals of Hydraulics The following are definitions of terms required to understand the various hydraulics equations. The symbols and units are given with the definitions.
51
Drilling Bits Hydraulics
Chapter # 7
7.3.1 Shear rate (sec -1): This is a term most applicable to laminar flow. It refers to the change in fluid velocity divided by the width of the channel through which the fluid is flowing in laminar flow.
7.3.2 Shear stress, t (lb/100 ft): The force per unit area required to move a fluid at a given shear rate.
7.3.3 Viscosity, µ (centipoises (cp): This is the ratio of shear stress to shear rate.
7.3.4 Plastic viscosity, PV (cp): Plastic viscosity represents the contribution to total fluid viscosity of a fluid under dynamic flowing conditions. Plastic viscosity is dependent on the size, shape, and number of particles in a moving fluid. PV is calculated using shear stresses measured at 600and 300 rpm on the Fann 35 viscometer.
7.3.5 Effective viscosity, µ (cp): This term takes account of the geometry through which the fluid is flowing and is therefore a more descriptive term of the flowing viscosity.
7.3.6 Yield stress (lb/100 ft): This is the calculated force required to initiate flow and is obtained
when the
rheogram (a plot of shear stress vs shear rate) is extrapolated to the y-axis at Y = 0 sec-1. In practice the yield point is calculated using Equation (7.3).
7.3.7 Gel strength (lb/100 ft): All drilling fluids build a structure when at rest. The gel strength is time-dependent measurement of the fluid shear stress when under static conditions. Gel strengths are commonly measured after 10 seconds, 10 minutes, and 30 minutes intervals.
7.3.8 Reynolds number, Re: This is a dimensionless number which determines whether a flowing fluid is in laminar or turbulent flow. A Reynolds number greater than 2,100 marks the onset of turbulent flow in most drilling fluids. For laminar flow (Re < 2,100) and for turbulent flow (Re > 2,100).
52
Drilling Bits Hydraulics
Chapter # 7
Figure7. 2
Critical Reynolds number, Rec: T This value corresponds to the Reynolds number at which laminar flow turns to turbulent flow.
7.3.9 Friction factor (f): This is a dimensionless term used for power law fluids in turbulent low and relates the fluid Reynolds number to a "roughness" factor for the pipe.
7.4 Flow Regimes There are three basic types of flow regimes:
Laminar Turbulent Transitional
7.4.1 Laminar flow: In laminar flow, fluid layers flow parallel to each other in an orderly fashion, this flow occurs at low to moderate shear rates when friction between the fluid and the channel walls is at its lowest. This is a typical flow in the annulus of most wells.
7.4.2Turbulent flow: This flow occurs at high shear rates where the fluid particles move in a disorderly and are pushed forward by current eddies. Friction between the fluid and the channel walls 53
Drilling Bits Hydraulics
Chapter # 7
is highest for this type of flow. This is a typical flow inside the drillpipe and drillcollars. Unlike laminar flow, mud parameters (viscosity and yield point) are not significant in calculating frictional pressure losses for mud in turbulent flow.
7.4.3 Transitional flow: Transitional flow occurs when the fluid flow changes from laminar to turbulent or vice versa.
7.5 Fluid Types: There are two basic types of fluids: Newtonian and non-Newtonian. Newtonian fluids are characterized by a constant viscosity at a given temperature and pressure. Common Newtonian fluids include:
Water Diesel Glycerin Clear brines
Non-Newtonian fluids have viscosities that depend on measured shear rates for a given temperature and pressure. Examples of non-Newtonian fluids include:
Most drilling fluids Cement slurries
In drilling operations, practically all drilling fluids are non-Newtonian. Even brines which are used as completion fluids are not truly Newtonian fluids, as the dissolved solids in them make them behave in a non-Newtonian manner.
7.6 Rheological Models: Rheological models (Figure 7.2) are mathematical equations used to predict fluid behavior across a wide range of shear rates and provide practical means of calculating pumping (pressure) requirements for a given fluid. Most drilling fluids are nonNewtonian and pseudo plastic and, therefore, hydraulic models use a number of approximations to arrive at practical equations.
54
Drilling Bits Hydraulics
Chapter # 7
Figure 7.3
The three rheological models that are currently in use are: 1. Bingham Plastic model 2. Power Law model 3. Herschel-Buckley (yield-power law [YPL]) model
7.6.1 Bingham Plastic Model: The Bingham Plastic model describes laminar Figure 7.3 Bingham Plastic model flow using the following equation:
YP PV
7.2
Where; ô = measured shear stress in lb/100 ft YP = yield point in lb/100 ft PV = plastic viscosity in cp ã= shear rate in sec–1
55
Drilling Bits Hydraulics
Chapter # 7
Figure 7.4
The values of YP and PV are calculated using the following equations: PV = è600 –è300 YP =è300 – PV
YP = (2 × è300) – è600
7.3 7.4 7.5
Figure 7.4a
Figures 7.3, 7.4 and 7.5 describe the Bingham Plastic model. The slope of a line connecting any point on the straight line to the origin is described as the apparent viscosity at that particular shear rate, Figure 9.4.
Figure 7.5
The Bingham Plastic model usually over predicts yield stresses (shear stresses at zero shear rate) by 40 to 90 percent. The following equation produces more realistic values of yield stress at low shear rates: 56
Drilling Bits Hydraulics
Chapter # 7
YP (Low Shear Rate) = (2 ×è3) - è6 This equation assumes the fluid exhibits true plastic behavior in the low shear-a rate range only.
7.6.2 Power L Aw Model The Power Law model assumes that all fluids are pseudo plastic in nature and are defined by the following equation: 7.6
K ( )n Where ô =
Shear stress (dynes /cm)
K=
Consistency Index
ã =
Shear rate (sec-1)
n=
Power Law Index
K and n can be calculated as n 3.321log( K
600 ) 300
300 551n
7.7 7.8
The constant “n” is called the POWER LAW INDEX and its value indicates the degree of non-Newtonian behavior over a given shear rate range. If 'n' = 1, the behavior of the fluids considered to be Newtonian. As 'n' decreases in value, the behavior of the fluid is more non Newtonian and the viscosity will decrease with an increase in shear rate. The constant “n” has no units.
The “K” value is the CONSISTENCY INDEX and is a measure of the thickness of the mud. The constant 'K' is defined as the shear stress at a shear rate of one reciprocal second. An increase in the value of 'K' indicates an increase in the overall hole cleaning effectiveness of the fluid. The units of 'K' are lbs/100ft, dynes-sec or N/cm. The constants n and K can be calculated from Fann VG meter data obtained at speeds of 300 and 600 rpm through the use of Equation and Equation. Hence the Power Law model is mathematically more complex than the Bingham Plastic model and produces greater accuracy in the determination of shear stresses at low shear rates. The Power Law model actually describes three types of fluids, based on the value of 'n': 57
Drilling Bits Hydraulics
Chapter # 7
n = 1: The fluid is Newtonian n < 1: The fluid is non-Newtonian n > 1: The fluid is Dilatants
7.6.3 Herschel Buckley Yield Power Law Model The Herschel-Buckley (yield-power law YPL) model describes the rheological behavior of drilling muds more accurately than any other model using the following equation:
0 K ( ) n
7.9
Where; ô = measured shear stress in lb/100 ft2
ôo= fluid's yield stress (shear stress at zero shear rate) in lb/100 ft K = fluid's consistency index in Pc or lb/100 ft sec2 n = fluid's flow index ã= shear rate in sec -1 The YPL model reduces to the Bingham Plastic model when n = 1 and it reduces to the Power Law model when ôo = 0. The YPL model is very complex and requires a minimum of three shear-stress/shear-rate measurements for a solution
7.7 Practical Hydraulics Equations The procedure for calculating the various pressure losses in a circulating system is summarized below: 5.
Calculate surface pressure losses using Equation (7.1)
6.
Decide on which model to use: Bingham Plastic or Power Law
7.
Calculate pressure loses inside the drill-pipe first then inside drill-collars as
follows:
Calculate critical velocity of flow Calculate actual average velocity of flow Determine whether flow is laminar or turbulent by comparing average velocity with critical velocity. If average velocity is less than critical velocity the flow is laminar. If average velocity is greater than critical velocity the flow is turbulent.
4.
Use appropriate equation to calculate pressure drop Divide the annulus into open and cased sections 58
Drilling Bits Hydraulics 5.
Chapter # 7
Calculate annular flow around drill-collars (or BHA) as follows:
Calculate critical velocity of annular flow Calculate actual average velocity of flow in the annulus Determine whether flow is laminar or turbulent by comparing average velocity with critical velocity. If average velocity is less than critical velocity the flow is laminar. If average velocity is greater than critical velocity the flow is turbulent.
Use appropriate equation to calculate annular pressure drop
6. Repeat step four for flow around drill-pipe in the open and cased hole sections. 7. Add the values from step 1 to 5, call these system losses 8. Determine the pressure drop available for the bit = pump pressure - system losses 9. Determine nozzle velocity, total flow area and nozzle sizes The following equations are given for the Bingham Plastic and Power Law models. The field units used here are: OD = outside diameter (in), ID = inside diameter (in), L = length (ft), ñ = density (ppg) V = velocity (ft/sec) or (ft/min), PV = viscosity (cp), YP = yield point (lab/100ft
7.7.1 Bingham Plastic Model
Pipe Flow Determine average velocity and critical velocity (V´ and Vc): V´=
24.5Q D2
7.10
VC
97 PV 97 PV 2 8.2 D 2YP D
7.11
If V´> Vc flow is turbulent; use P
8.91 105 0.8 Q1.8 ( PV )0.2 L D 4.8
7.12
If V´< V flow is laminar; use P
L PV V´ L YP 90,000 D 2 225 D
7.13
59
Drilling Bits Hydraulics
Chapter # 7
Annular Flow Determine average velocity and critical velocity (V´and Vc): V´=
24.5Q Dh2 OD 2
7.14
VC
97 PV 97 PV 2 6.2 D 2YP De
7.15
Where De Dh OD If V´> Vc flow is turbulent; use P
8.91 105 0.8 Q1.8 ( PV )0.2 L ( Dh OD)3 )( Dh OD )1.8
7.16
If V´< Vc flow is laminar; use P
L PV V´ L YP 2 60,000 D e 225 De
7.17
7.7.2 Power Law Model Determine n and K from: n 3.321log(
600 ) 300
7.18
300 551n
K
7.19
Where
600 2PV YP And 300 2PV YP
Determine average velocity and critical velocity (V´and Vc)
5.82 104 K VC V´
(
1 ) 2n
1.6 (3n 1) 1 n D 4n
24.5Q D2
(
n
)
7.20 7.21
If V´> Vc flow is turbulent; use P
8.91 105 0.8 Q1.8 ( PV )0.2 L ( Dh OD)3 )( Dh OD )1.8
7.22
If V´< Vc flow is laminar; use 60
Drilling Bits Hydraulics
Chapter # 7
KL 2.41V´ 2n+1 P De 3n 300 De
n
7.23
7.8 Pressure Loss across Bit The object of any hydraulics program is to optimize pressure drop across the bit such that maximum cleaning of bottom hole is achieved. For a given length of drill string (drill-pipe and drill collars) and given mud properties, pressure losses P1, P2 ,P3,P4,P5 will remain constant. However, the pressure loss across the bit is greatly influenced by the sizes of nozzles used, and the latter determine the amount of hydraulic horsepower available at the bit. The smaller the nozzle the greater the pressure drop and the greater the nozzle velocity. The graph shows the pressure drop across the bit.
Figure 7.6
In some situations where the rock is soft to medium in hardness, the main objective is to provide maximum cleaning and not maximum jetting action. In this case a high flow rate is required with bigger nozzles. To determine the pressure drop across the bit, add the total pressure drops across the system, i.e. P1+ P2 +P3 +P4+P5 to give a total value of Pc (described as the system pressure loss). Then determine the pressure rating of the pump used. If this pump is to be operated at, say, 80-90% of its rated value, then the pressure drop across the bit is simply pump pressure minus Pc.
61
Drilling Bits Hydraulics
Chapter # 7
7.8.1 Procedure A.
From previous calculations, determine pressure drop across bit, using Pbit = Pstandpipe -P1+ P2 +P3 +P4+P5
B.
7.24
Determine nozzle velocity (ft/s) Vn 33.36
C.
7.25
Pbit
Determine total area of nozzles (in ) A 0.32
D.
7.26
Q Vn
Determine nozzle sizes in multiples of 32 seconds
7.9 Pressure Drop across Nozzles and Watercourses Following figure 7.6 illustrates the flow of an
incompressible
through
converging
(nozzles, orifice, etc.) using steady state, adiabatic and frictionless conditions. Using Bernoulli’s Equation; P1 12 P2 22 2g 2g
7.27
Figure 7.7
Where P1&P2 = pressure lb/sq. ft
= density lb/cu. ft
1 , 2 = velocities at points 1 &2. Rearranging the above equation P 22 12 2g
7.28
Practically v22 v12 v22 , hence
22 2 g
P
7.29
The ideal rate of flow, Qi A2 2 the actual flow rate is Q CQi
7.30
Where C is the flow or nozzle coefficient for a particular design with these substitutions the equation become 62
Drilling Bits Hydraulics P
Chapter # 7
Q 2 2 gC 2 A22
7.31
Alternating Practical unit for mud flow is given by, P
q2 7430C 2 d 4
7.32
Where d= nozzle or water-cut diameter, in Eckal & Bielstein, have shown that C may be as high as 0.98 for properly designed jet bit nozzles; however 0.95 is commonly used for field purposes. For ordinary watercuts which are merely flat drilled holes C= 0.80.
7.9.1 Multiples nozzles Normally a jet rock bit has same number of nozzle as cones. The calculation for the purpose of multiples nozzle bit may be simplified by substituting the sum of the nozzle areas for A in the above equation. For single nozzle P
Q 2 2 gC 2 A22
7.33
For multiple nozzles Pm
Q12 2 gC 2 A12
7.34
Figure 7.8
However Q1 = Q/n, n= number of nozzles. Therefore Pm Q12 A2 Q 2 A2 2 2 21 2 2 P Q A1 n Q A1
7.35
It is desired to choose an area A such as A2 1 A2 n 2 A12 Also A=nA1 n 2 A12
7.36
Similarly for the equation d e nd 2
7.37
Where multiples nozzle vary in size 63
Drilling Bits Hydraulics d e ad12 bd 2 2 etc.
Chapter # 7 7.38
Where a
= number of nozzles having diameter, d1
b
= number of nozzles having diameter, d2
de
= hydraulically single nozzle diameter, in
Figure 7.7 gives the relation between nozzle area and the pressure drop across bit at different GPM.
7.10 Example: Hydraulics calculations Using the Bingham plastic and power-line models, determine the various pressure drops, nozzle velocity and nozzle sizes for a section of 12.25 in (311mm) hole. Two pumps are used to provide 700 gpm (2650 1/min).
Data: Plastic velocity=12 cp Yield point=12 lb/100 ft Mud weight=8.8 lb/gal Drill pipe ID=4.276 in OD=5 in Length=6,480 ft Drill collars ID=2,875 in OD=8 in Length=620 ft (189 m) Last casing was 13.375 in with an ID of 12.565 in. 13.375 in casing was set at 2,550 ft. The two pumps are to be operated at a maximum standpipe pressure of 2,200 psi. Assume a surface equipment type of 4. Solution The solution to this example will be presented in Imperial units only.
7.10. 1 Bingham Plastic Model Surface losses Surface losses in surface equipment P1 are given by P1 E 0.8Q1.8 PV 0.2
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Drilling Bits Hydraulics
Chapter # 7
From Table: Types of surface equipment, the value of the constant E for type 4 is 4.2 x 10; hence, Equation (1) becomes P1 4.2 105 0.8 Q1.8 PV 0.2 P1 4.2 105 8.80.8 7001.8 120.2 52 psi
This graph the relation between circulation rate and pressure losses through surface connections.
Figure 7.9
Pipe losses Pressure losses inside drill-pipe 7.10 figure shows the relation between circulation rate and pressure losses through drill pipe.
65
Drilling Bits Hydraulics V´
Chapter # 7
24.5Q 24.5 700 937.97 ft / min 2 D2 4.276
Figure 7.9
Critical velocity VC
97 PV 97 PV 2 8.2 D 2YP D
97 12 97 122 8.2 8.8 4.2762 12 8.8 4.276 356 ft / min
VC
Since V´ >Vc flow is turbulent and pressure drop inside drill pipe is calculated from: P2
8.91 105 0.8 Q1.8 ( PV ) 0.2 L D 4.8
P2
8.91 105 8.80.8 7001.8 (12) 0.2 6480 (4.276) 4.8
670 psi
Pressure losses inside drill collars Following the same procedure as for drillpipe losses, we obtain V´
24.5Q 24.5 700 2074.9 ft / min D2 (2.875)2
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Drilling Bits Hydraulics
Chapter # 7
Figure 7.10
VC
97 12 97 122 8.2 8.8 2.8752 12 373 ft / min 8.8 2.875
Since V´ >Vc flow is turbulent and pressure loss inside drill collars P3 is determined from P3
8.9110 5 8.80.8 7001.8 (12) 0.2 620 431 psi (2.875) 4.8
7.11 figure shows the relation between circulation rate and pressure losses through drill collar.
Annular pressure losses From Figure 9.12 it can be seen that part of the drill-pipe is inside the casing and the rest is inside open hole. Hence, pressure loss calculations around the drill-pipe must be split into (a) losses around the drill-pipe inside the casing and (b) losses around the drill-pipe in open hole. 7.13 figure shows the relation between circulation rate and pressure losses through annulas. Figure 7. 11
67
Drilling Bits Hydraulics
Chapter # 7
Figure 7.12
Pressure Losses around Drillpipe: Cased hole section 24.5Q D ODdp2
V´=
2 c
Where the subscripts 'c' and' dp’ refer to casing and drill pipe respectively. V´=
24.5 700 129.1 ft / min 12.5652 52
VC
97 PV 97 PV 2 6.2 D 2YP De
VC
97 12 97 122 6.2 8.8 (12.565) 2 12 299.6 ft / min 8.8 (12.565)
Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the cased hole is determined from: P
L PV V´ L YP 2 60,000 D e 225 De
(Where L=2500 ft) 68
Drilling Bits Hydraulics Pa
Chapter # 7
2550 12 129.01 2550 12 21 psi 2 60,000 (12.56 5) 225 (12.56 5)
Open-hole section- Around Drill-pipe V´=
24.5 700 137 ft / min 12.252 52
VC 300.4 ft / min
Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the open hole section is determined from: Pb
3930 12 137 3930 12 35 psi 2 60,000 (12.25 5) 225 (12.25 5)
Where L = 6,480 - 2,550 = 3,930 ft, and L = length of drill-pipe in the open-hole section). Hence, total pressure drop around drill-pipe is the sum of Pa and Pb. Thus, P5 Pa Pb 21 35 56 psi Pressure losses around drill collars 24.5 700 V´= 199.3 ft / min 12.252 82 Vc 314 ft / min Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the open hole section is determined from: P4
620 12 199.3 620 12 10 psi 2 60,000 (12.25 8) 225 (12.25 8)
Pressure drop across bit Total pressure loss in circulating system, except bit. P1 P2 P3 P4 P5
52 670 431 10 56 1219 psi Therefore, pressure drop available for bit (Pbit) 2200 1219 981psi
Determine nozzle velocity (ft/s) Vn 33.36
Pbit 981 33.36 351.7 ft / sec 8.8
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Drilling Bits Hydraulics
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Determine total area of nozzles (in2) A 0.32
Q 700 0.32 0.6369in 2 Vn 351.7
Nozzle size (in multiples of (1/32)
4 16.64 3 Hence, select two nozzles of size 17 and one of size 16. The total area of these 32
nozzles is 0.6397 in2 which is slightly larger than the calculated area of 0.6369 in2
7.10.2 Power Law Model Surface losses
P1 E 0.8Q1.8 PV 0.2
P1 4.2 105 0.8 Q1.8 PV 0.2 52 psi 600 2 PV YP 2 12 12 36
300 PV YP 12 12 24 n 3.321log( 600 ) 0.585 300 K
300 0.626 551n
Remaining calculations are left as an exercise. P2 670, P3 431, P4 5, P5 19, Pbit 1023, Nozzles 2 16 ' s17
7.10.3 Comparison of the two models From the above results, it is obvious that the two models produce different nozzle sizes: the Bingham plastic model produced two 17s and one 16, whereas the power law model produced two 16s and one 17. In practice, this difference is not considered serious, and if the mud pumps are capable of producing more than 2,200 psi, then it is likely that three nozzles of size 16 will be chosen. We should note also that the turbulent flow equations presented here use a turbulent viscosity term equal to (PV)/3.2 and not the plastic viscosity. If the plastic viscosity term is used instead, then pressure losses will be 26% higher than those calculated by our turbulent flow equation.
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7.11 Optimization of Bit Hydraulics All hydraulics programs start by calculating pressure drops in the various parts of the circulating system. Pressure losses in surface connections, inside and around the drill pipe, inside and around drill collars, are calculated, and the total is taken as the pressure loss in the circulating system, excluding the bit. This pressure loss is normally given the symbol Pc
7.11 .1 Surface Pressure Once the system pressure losses, Pc is determined, the questions are how much pressure drop can be tolerated at the bit (Pbit). The value of Pbit is controlled entirely by the maximum allowable surface pump pressure. Most rigs have limits on maximum surface pressure, especially when high volume rates - in excess of 1000 gpm are used. In this case, two or three pumps are used to provide this high quantity of flow. On land rigs typical limits on surface pressure are in the range 2,500 - 3000 psi for well depths of around 12,000 ft. For deep wells, heavy duty pumps are used which can have pressure ratings up to 5,000 psi. Hence, for most drilling operations, there is a limit on surface pump pressure, and the criteria for optimizing bit hydraulics must incorporate this limitation.
7.11.2 Hydraulic Criteria There exist two criteria for optimizing bit hydraulics:
Maximum bit hydraulic horsepower (BHHP) Maximum impact force (IF).
Each criterion yields difference values of bit pressure drop and, in turn, different nozzle sizes. Moreover, in most drilling operations the flow rate for each hole section has already been fixed to provide optimum annular velocity and hole cleaning. This leaves only one variable to optimize: the pressure drop across the bit, Pbit .
7.11 .3 Maximum Bit Hydraulic Horsepower The pressure loss across the bit is simply the difference between the standpipe pressure and Pc. However, for optimum hydraulics the bit pressure drop must be a certain fraction of the maximum available surface pressure. For a given volume flow rate, optimum hydraulics is obtained when the bit hydraulic horsepower assumes a certain percentage of the available surface horsepower. In the case of limited surface pressure, the maximum pressure drop across the bit, as a 71
Drilling Bits Hydraulics
Chapter # 7
function of available surface pressure, produces maximum hydraulic horsepower at the bit for an optimum value of flow rate as shown below: Pbit
7.39
n PS n 1
Where n = slope of Pc VS Q Ps= maximum available surface pressure. In the literature several values of n have been proposed, all of which fall in the range 1.8 - 1.86. Hence, when n = 1.86, Equation above gives Pbit= 0.65 Psi. In other words, for bit optimum hydraulics, the pressure drop across the bit should be 65% of the total available surface pressure. The actual value of n can be determined in the field by running the mud pump at several speeds and reading the resulting pressures. A graph of Pc (=Ps - Pbit) against Q is then drawn. The slope of this graph is taken as the index n.
7.11 .4 Maximum Impact Force In the case of limited surface pressure, it can be shown that for maximum impact force, the pressure drop across the bit (Pbit) is given by: Pbit
7.40
n PS n2
The bit impact force (IF) can be shown to be a function of Q and Pbit according to the following equation. IF
Q Pbit
7.41
58
Where
mudweight ( ppg )
7.11 .5 Nozzle Selection Smaller nozzle sizes are always obtained when the maximum BHHP method is used, as it gives larger values of Pbit than those given by the maximum IF method. The following equations may be used to determine total flow area and nozzle sizes: TFA (0.0096 Q ) d n 32
4 TFA 3
Pbit
7.42 7.43 72
Drilling Bits Hydraulics Where TFA dn
Chapter # 7
= total flow area in2 = nozzles size in multiple of 1/32 in
7.11 .6 Optimum Flow Rate THE Optimum flow rate is obtained using the optimum value of Pc, n and maximum surface pressure, Ps. For example, using the maximum BHHP criterion, Pc is determined from PC PS Pbit
7.44
n PC PS P n 1 S
7.45
n PC P n 1 S
7.46
The value of n is equal to the slope of the Pc- Q graph. The optimum value of flow rate, Qopt is obtained from the intersection of the Pc value and the Pc - Q graph.
7.12 Field Method of Optimizing Bit Hydraulic The index n can only be determined on site and is largely controlled by down hole conditions. The following method for determining n is summarized here briefly. 1. Prior to POOH current bit for next bit change, run the pump at four or five different speeds and record the resulting standpipe pressures. 2. From current nozzle and mud weight determine pressure losses across the bit for each value of flow rate, using Equation of nozzle selection. 3. Subtract Pbit from standpipe pressure to obtain Pc. 4. Plot graph of Pc against Q on log-log graph paper and determine the slop of this graph which is the index n in equations. 5.
For the next bit run, equation 7.7 and 7.8 is used to determine Pbit that will produce maximum bit hydraulic horsepower. Nozzle sizes are then selected by use of this value of Pbit.
For a particular rig and field the index n will not vary widely if the same drilling parameters are used. For standardization purpose it is recommended that the above test be run at three depths for each bit run. The average value of n for each bit run can then be used for designing optimum hydraulics.
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7.13 Example: Hydraulics Optimization Given data: Hydraulic Horse power of pump =1211 hp Maximum permitted surface pressure Ps = 3500 Hole size = 12.25”,
Mud density = 13 ppg,
Drillpipe= 5”/4.276” Pc = K Qn K =0.01,
n =1.86
Use the BHHP to calculate: Pc, Pbit BHHP and IF Solution: 1. BHHP Criterion Pbit
n PS n 1
Pbit
1.86 3500 2276 psi 1.86 1
%Power at bit =2276/3500=65
PC PS Pbit 3500 2276 1224 psi PC kQ n
1225 0.01Q1.86 n Q 554 gpm Hence the optimized values are: Pc = 1224 psi, Q = 544 gpm and Pbit = 2276 psi TFA (0.0096 Q ) (0.0096 544) d n 32
Pbit
13 0.3947in 2 2276
4 TFA 4 0.3947 32 13.1 3 3
(i.e. select three 13’s nozzles for a tricone drillbit) IF IF
Q Pbit 58
544 13 2276 1613lb ft 58
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Drilling Bits Hydraulics
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7.14 Hydraulic and ROP It has been established that penetration rate in many formation is proportional to the hydraulic horsepower expended at the bit. Realization of factor and subsequent widespread use of jet bits has reversed the trend to small drill pipe sizes which existed a few years ago. Pressure drops inside the drill string are a large part of total system losses, and it is obvious that an increase of inside diameter will greatly improve hydraulic efficiency. Consequently tool joints which have little or no internal restriction are most commonly used. The use of large drill pipe and drill collars also entails closer hole-pipe clearance; thus the desired annular velocity can be obtained at lower circulation rates. In addition, annular velocity requirements have been reappraised and lower figures are now being applied.
7.15 A practical check on the efficiency of the bit hydraulic program 1. Detemine pressure drop across bit Pbit. 2. Determine bit hydraulic horsepower (BHHP). BHHP Pbit QkW
7.47
3. Divide BHHP obtained above by area of bit to determine k where k. k
BHHP d2 / 4
7.48
4. For maximum cleaning k should be between 3 and 6 HHP/sq. in (3.74-6.94 watts/ sq. mm).
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8.0 Optimized Bit Technology In this category of bits, two main bits can be discussed and they are given as follow PDC Impregnated Bits PDC Hybrid Bits
8.1 Impregnated PDC Bits These bits are ideal for drilling abrasive formations because of their self-sharpening cutting structure that replenishes itself as the bit wears. Impregnated bits utilize sharp, grit-size diamonds sintered directly into a tough tungsten carbide matrix. The matrix is formulated to match the application so the carbide matrix wears slightly faster than the diamond. This ensures fresh, sharp diamonds are exposed at the optimal rate for maximum ROP and bit life.
Figure 8.1
8.1.1 Advantages Impregnated bits are made of segments consisting of carbide matrix and crystalline synthetic diamonds that are exposed approximately ½ mm. They drill in a similar fashion as natural diamond bit; the improvement is that as diamond becomes worn the new diamonds are exposed. This gives them to drill the hardest, the most abrasive formation at high RPM with a service life several time that of natural diamond. By definition these are matrix bodies bits, the binding material however differ from that used for other type of formation for which the bit is designed. It normally contains not 76
Drilling Bit Optimization
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only cobalt and nickel but also copper and tungsten carbide. As the diamond particle wear, new diamond particles are exposed. 8.1.1 (a) Enhanced Hydraulics Impact-force directed where balling occurs with unique ported design. Enhanced ROP with deep junk slots that optimize cuttings removal and limit hole swabbing during trips. 8.1.1 (b) Matrix Flexibility The matrix wears slightly faster than the diamond to ensure the most efficient cutting structure. Each matrix formulation is matched to the lithology, achieving the optimal rate of fresh, sharp diamonds for enhanced ROP. 8.1.2 Disadvantage Due to the small depth of cutters, impregnated bits are well suited for very hard formation; however, this small diamond exposure can be easily sealed off when encountering soft rock. In the absence of abrasive sandstone to clean the segments, the entire bit can be plugged off. The chart below shows the relation between the ROP and WOB for this bit. The other chart also shows the same relation for the shale.
Figure 8.2
8.1.3 Effect of temperature During drilling the impregnated segment surface should have the texture of sandpaper with sufficient fluid to keep the cutting structure cool in addition to remove cuttings. Inadequate hydraulics could result in excessive temperature causing the segments to burn due to high rotational velocities.
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8.1.4 Possible Remedies A.Due to the hardness and abrasiveness of formation, the primary concern was bit durability. For this purpose, an IADC class M841 Impregnated bit was selected that maximizes diamond volume on bottom with sufficient waterways to keep the segments cool while providing adequate cleaning. B. Whenever there is chance of baling we use a new IADC class M841 impregnated diamond bit with multiple interrupted segments to minimize the distance cuttings are required to travel before reaching a waterway. These bits consist of diamond impregnated segments bonded into the matrix body. The segments are made from a mixture of synthetic diamond and tungsten carbide matrix bonded together under high pressure and temperature. 8.2 PDC Hybrid Drill Bits The main problem with extended PDC usage into these abrasive formations was to resolve the problems associated with excessive temperature arise of PDC cutters. This is a result of this harder formation to shear in a manner most suitable for PDC bit drilling. Combined with this, the susceptibility of PDC to impact damage and it is no surprise that hard formation led to rapid wear to try the decrease in these effects, a secondary cutting structure was developed. This involved setting a diamond impregnated stud behind and separate from the PDC spud cutters. This behaves in following way: When the bit is new the PDC cutting structure acts along to ensure maximum ROP. Upon entering into harder formation wear of PDC brings the diamond impregnated stud into contact with the formation. This serves to reduce the cutter loading on the diamond layer and is associated tungsten carbide wear area reducing heat build up and chances of the impact damage. The increased support to the PDC cutter also allows greater weight to be run with a reduced chance of cutter breakage due to cutter
Figure 8.3
78
Drilling Bit Optimization
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overloading. A diamond impregnated stud was chosen because of its durability in harder formation. The stud was kept separate from the PDC cutter to enable good heat dissipation from the formation and stud interface. Sometimes hybrid consists of PDC cutters along with thermally set polycrystalline cutters and diamond impregnated on the back side for very hard and abrasive formation. PDC and TSP are used for soft to medium and impregnated for hard and abrasive formations. 8.3 Design Optimization as Applied to Cutting Structure In the foregoing only those basic fundamentals of rock-bit design which are common to all types have been considered. Factors which govern basic cone or cutter configuration and various design criteria apply regardless of whether the type under consideration is for a soft or a hard formation. The design of a bit for use in a specific category of formations obviously requires the application of additional design factors. For example, journal angle and offset values, roiling characteristics of the cones, and the effect of tooth depth on bearing-structure size, represent several of the factors which must be considered in the cone-bit design. 8.3.1 Action of the cones The action of the cones on the formation is of prime importance in regard to the ability of a bit to drill with a desirable penetration rate. A soft-formation bit requires a gouging-scraping action, whereas a hard-formation bit requires a chipping-crushing action. Basically, these actions are governed by the degree to which the cones approach that of a true roll. A maximum gouging-scraping action requires rolling characteristics which vary the greatest from that of a true roll. A chipping-crushing action requires that which more nearly approaches that of a true roll. Factors in the design which produce these desirable characteristics are: Degree of journal angle Amount of offset
Profile of the cone Bearing structure Teeth depth
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Drilling Bit Optimization
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A combination of the smallest journal angle, largest offset angle, and greatest variation in cone-profile angles will develop an action which varies the most from that of a true roll. Conversely, a combination of the largest journal angle, no offset and least variation in the cone profile will result in an action which closely approaches that of a true roll. 8.3.2 For a hard formation For the hard formation following factors may be considered No offset; so that a hard-formation bit requires a chipping-crushing action. This factor provides the necessary support. Largest journal angle; so that these journals assist the excessive weight on bit. If we keep journal angle small then this excessive load can break the journals. Largest Bearing Structure; in the hard formation, generally the weight on bit is kept very high to withstand these loads the bearing structure kept large. Least Profile variation; tooth to tooth and tooth to groove spacing kept small because in the hard formation, we have to increase number of cutters so that the maximum impact is require and less wear and tear is observed. Due in part to the abrasiveness of most of the hard formations and, in part, to the chipping action of the bit, the teeth must be closely spaced to counteract rapid tooth. Tooth angles must be kept large to withstand the heavy loads required to overcome the compressive strength of the formation Shallow Teeth; the teeth on a hard-formation bit are shallow, heavy, and closely spaced. Due in part to the abrasiveness of most of the hard formations and, in part, to the chipping action of the bit, the teeth must be closely spaced to counteract rapid tooth wear and excessive lateral loading
For Soft Formation
Figure 8.4
For Hard Formations
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Drilling Bit Optimization
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8.3.3 For a soft formation For the soft formation above considerations are reversed. Largest offset; in the soft formation the offset is kept largest, as here we need gouging and scraping action and cuttings structure should be large. Smallest Journal Angle; as the soft formations are not very abrasive, so the weight on bit is kept small and hence the smallest journal angle. Smallest Bearing Structure; as the weight on bit is kept small in case of soft formation so that bearing structure is also kept small so that we may use more space for other structure. Greatest Profile variation; in the soft formation the tooth to tooth and tooth to groove spacing are kept large for maximum cleaning and to avoid bit balling in such soft and sticky formation. 8.4 Bit Selection and Drilling Parameters: Having arrived at a carefully considered position on which bit is likely to be best for each formation the following information should be included in the drilling program. 1). Recommended bits for each hole size, showing in each case the best offset bit and why the recommended bit differs (if it does). 2). Anticipated BHAs for each part of the well. 3). Recommended ranges of drilling parameter for each bit. 4). Expected performance of each recommended bit for example footage to drill and average ROP. 8.5 Bit Choices: Sometimes the next bit in may have to drill to a particular depth (coring point, for instance), which is considerably less distance than would be expected from a full bit run. It may be possible to run a cheaper (or used, re-useable) bit instead. The rig need a list of bit prices and the drilling supervisor should consider bit cost when making the selection. For example, it may be that the bit being pulled early has already drilled through an abrasive zone where premium gauge protection was used. The next bit in May not require this expensive feature and so a cheaper alternative may be possible.
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8.6 Refining Bit Choice and Parameters Based On Previous Bit Run A good bit choice, run correctly and pulled at the end of its economic life, should show worn cutting structure and/or bearings. Severe dull bit features (excessive gauge loss, broken cutters, cones locked, etc.) are warnings that something went wrong, especially if the performance fell below expectations. Try to ascertain what conditions may have caused the specific dull conditions and evaluate what changes could be made to bit choice running procedures, drilling parameters, BHA, mud, etc., to reduce the impact of these conditions. For example, a common mistake is to assume that broken teeth equates to a bit that is too soft; there are other more likely causes in most cases. Downhole shock or vibration, hard nodules, or junk could all play a part. Running too hard a bit for the formation is likely to compromise your overall bit performance. 8.7 WOB (Weight on Bit): When drilling, weight is applied to the cutters so that rock is penetrated. Up to certain limits the more weight applied the faster the bit will drill. If too much weight is applied, the cutters may become completely buried (known as bit flounder) and weight will be taken by the cones or bit body. This will reduce ROP and rapidly wear the cones. Increasing weight will also accelerate wear on bearings and cutters. Deviation is also affected by WOB. A rotary locked or build assembly will have an increasing build tendency with greater weights; where a rotary pendulum is in an established drop then increasing weight will tend to increase drop, up to a point where further increasing the weight may produce unpredictable results. In a vertical borehole with a flexible pendulum or build BHA, increasing weight will deflect the well path from vertical. In a motorbent sub combination increased weight will increase side force at the bit, and therefore accelerate the rate of direction change in the direction of tool face azimuth, up to the point where motor stalls. When planning to change hole direction, the BHA selected may dictate the approximate WOB to be used, which may affect the bit Choice.
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8.7.1 Weight-RPM: Pan American's optimized drilling program is based on equations developed by Galle & Woods and Billington & Blenkarn, which define how the complex relationship between weight-on-bit and rpm affects the wear of a bit it in a particular formation. To get some concept of optimization, it is important to understand what these equations can provide in terms of data output. Using these equations, the weight: rotary-speed relationship can be categorized as follows: 8.7.2 Variable RPM-weight: Because so few rigs are electric or completely versatile as far as range of rpm and weight is concerned, little use can be made of a variable optimum rpm and weight program. However, it is the most efficient method for drilling with mill tooth bits. 8.7.3 Constant RPM- Variable Weight: This method for drilling with mill tooth bits appears to be practical. Generally, good drillers gradually apply more weight as bits become dull. This method has not been widely accepted since it requires an automatic driller and more supervision than other weight-rpm programs. However where applicable, the constant rpm and variable weight method is considerably more efficient than constant rpm and constant weight programs. 8.7.4 Constant RPM and Weight: Because of the limitations indicated above, most computer programs have been restricted to constant rpm and weight. Because so many limitations do exist, it has been necessary to make programs as flexible as possible and to cover as wide a range as the drilling engineer considers necessary. There are three available approaches: 8.7.4 (a)Optimum RPM and Weight: This is the rpm and weight that one might run if no limitations except the bit could be considered. This is the rpm and weight for absolute minimum cost, not considering any other factors such as condition of drill string, deviated hole or development of torque. 83
Drilling Bit Optimization
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8.7.4 (b) Best Weight for given RPM: Should formation or rig capability limit rpm, the program will determine the proper weight for minimum cost with imposed restrictions. This will cost more per foot than when optimum rpm and weight are used. 8.7.4 (c) Best RPM for given Weight: Should the available drill collars or deviation control dictate a certain weighton-bit this program predicts proper rpm for optimum cost considering this restriction. This cost will also be more than for optimum rpm and weight. 8.8 Drill off Test 8.8.1 To Optimize WOB and RPM. 1. Prior to running bit, check the Drilling Programme for the recommended parameters to be used with the bit. This will typically be a range suitable for the bit type to be used. 2. Check the rotary speed using rope marker on Kelly bushing and stopwatch. 3. Mark and measure drill-off interval on Kelly, L, such that LROP = 0.1. (This is to prevent excessive time spent drilling with less than optimum parameters; the test should take approximately 6 minutes). 4. Set and maintain a predetermined WOB at the light end of the range whilst measuring time taken to drill interval L. 5. Calculate ROP in ft/hr and plot graphically against RPM. 6. Increase rotary speed in 10 rpm increments and plot the resultant ROP. Select the point at which an increase in rpm does not give corresponding proportional increase in ROP. From the graph of data points generated, select the rpm which corresponds to the maximum ROP. Monitor and record the level of torque throughout test. 7. Repeat steps I through 6 above, maintaining the selected rpm whilst varying WOB in 2K increments. Plot the WOB against ROP for each increment. If increased WOB does not result in a proportional increase in ROP, reduce WOB to the previous optimum level. Plot graph of data points to select the optimum WOB. Monitor torque through test.
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8.8.2 To Optimize Hydraulics: Where
ECD
Density)
(Equivalent Circulating
conditions
permit
pump
parameters can be optimized by drilloff tests to achieve optimum bit performance. This is particularly important when running PDC bits which require efficient hydraulics to maintain a clean cutting structure and achieve effective bottom hole solids removal.
Figure 8.5
The following procedure may be used 1. Use the optimum WOB and RPM as selected in the above drill-off test. 2. Increase the pump rate in 20 strokes increments and record the resultant ROP. Plot the data points and determine the optimum flow rate which results in the optimum. 8.9 ROP (Rate of Penetration): To prevent damage to bit drill string or lost circulation variations in parameters must never exceed those specified in the Drilling Program. Two drill-off tests must be conducted per tour when drilling the same formation with one additional test when any formation change is encountered. 8.10 Rotary Speed and RPM: Increasing RPM will increase ROP up to a point where the cutters are moving too fast to penetrate the formation before they move on. Excess RPM will cause premature bearing failure or may cause PDC or diamond cutters to overheat. Deviation is also affected by RPM. Higher rotary speeds tend to stabilize the directional tendencies of rotary BHAs. A rotary BHA has a natural tendency to turn to the right; this tendency is weaker at higher rotary speed. 85
Drilling Bit Optimization
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Rotary speeds that cause string vibrations (critical rotary speeds) must be avoided. The driller should recognize this condition and modify RPM accordingly. Two types of vibration can be related to drillstring rotary speed and the calculated approximate speed of occurrence. 8.10.1 Longitudinal Drill-string Vibration: Longitudinal Vcrit
78640 Lp
Where Lp length of DP string, meters (Critical vibrations also at 4x and 9x this value.) 8.10.2 Transverse Drill-string Vibration: Transverse
Vcrit 47000 D 2 d 2 / L2
D = pipe OD d = pipe ID L = joint length (All measurements are in inches) 8.11 Minimizing Bit Whirl: Bit whirl occurs where the friction at the gauge of the bit makes the center of rotation locate itself at the edge of the bit (where the formation is in contact), instead of the geometric center. Since the forces on the cutters are now in different directions than the designed direction, cutter breakage can result. Bit design seems to be the dominant factor. Good stabilization probably decreases bit whirl and many bits are already advertised to be an "anti-whirl" design. Whirl is often initiated when the bit just starts drilling, such as after making a connection. Research has indicated that using the following procedure after making a connection will minimize the chances of bit whirl starting: While still off bottom, bring the mud pumps and the rotary table up to speed. Slowly slack off until the bit starts to take weight. Increase the WOB in small increments (say about 20% of planned total WOB) and allow the rotary table to stabilize in between increments for 10-30 seconds (longer for deeper ho 1 e). 86
Drilling Bit Optimization
Chapter # 8
8.12Monitoring Bit Progress While Drilling: Cost per foot calculations should be done while drilling. Once the cost per foot starts to increase, the bit will be nearing the end of its economic life. However, several other factors should be considered making a decision to pull the bit. Pull the bit earlier if there are indications of bearing failure (high and/or fluctuating torque on bottom compared to steady, reasonable torque just off bottom). Leave the bit in longer if offset information indicates that the slowdown is mainly due to decreasing formation drill-ability. Sometimes a bit is pulled under these circumstances and the next bit in does not drill any faster. Clearly in this case it is better to extend the bit run if there are no concerns as to bit condition. The hole section summary showing offset bit runs at the same place may indicate this. There are different theories that aim to make a bit pull decision easy, such as by hours on bit or number of revolutions. However, these will lead to below optimum drilling performance and should only be used when bit bearing condition cannot be monitored. It is possible to consistently pull bits at the end of their economic lives, maximizing the overall performance without seriously risking leaving cones n the hole. This requires close and skilled supervision of the run. 8.13 When to Pull the Bit: "Cost per foot" calculations can help to decide when to pull the bit. If this is done consistently, the chance of having to fish for cones is small and the overall cost per foot will be minimized. The point where the cost per foot is consistently increasing is the point that the bit should be pulled. If the indications are to pull the bit, do not waste time drilling the Kelly down. This may be modified by other factors. Pull the bit early if there are any signs of bearing failure; 8.14 Post-Drilling Bit Analysis: Proper analysis of the bit run is important to improve future performance. A large problem is that different people will grade a particular bit differently. The IADC 8 point grading scheme is vastly better than the old TBG 87
Drilling Bit Optimization
Chapter # 8
grading, however, if grading are not done with care, it will mislead future drillers. Record grading details and comments on the bit report. Make more extensive comments and recommendati9ns in the end of section report for inclusion in the final well report. The IADC 8 point grading should always be used to grade bits. The first four digits refer to the cutting structure. The last four digits refer to other characteristics.
88
Case Study of A Field
Chapter # 9
9.0 Introduction
A field namely “A” consists of wells X, Y and Z. The name of different formations in this field are F1(shale), F2(limestone), F3(shale), F4(limestone), F5(sandstone), F6(limestone), F7(shale), F8(sandstone), F9(shale),F10(sandstone), F11(shale) and F12(limestone). During drilling these formations, there were losses of circulation in the F1 (shale) and F2 (limestone) formations. Also the there are two abandoned well. One well was abandoned due to fishing, and the other well went dry due to which it was abandoned. There was also a developing well in this reservoir which is under drilling process. The formations in this field were a combination of different rocks due to which different bits and drilling parameters were used to drill.
9.1 Problems Encountered During Drilling the Formations: 1. Reduce rate of penetration 2. Lost circulation 3. Balling of bit 4. Erosion of bit 5. Worn of teeth
9.2 Cause of such Problems: 1. Basically we were drilling soft formation, we put all the parameters of bit according to the soft formation but during drilling encountered hard formation due to which the rate of penetration ROP has been decreased and caused the bit to pull. It was a great loss of trip time because bits were coming out of the hole before its economic life. 2. Due to the lost circulation cutting were not coming back to the surface and the circulation rate was high, due to which the bit was eroded. 3. When you are drilling a sticky formation, a very common problem balling of bit can occur. 4. Excessive hydraulics resulting in high velocity fluid erosion. Abrasive drilling fluids or poor solids control. 5. This is the normal drilling problem and is caused by small metal junk. Excessive string vibrations or shock holding. Excessive WOB.
89
Case Study of A Field
Chapter # 9
9.3 Solution of such Problems 1. For the soft formation we should use bit of such type which has smallest journal angle, largest offset, small bearings structure set and large size of cutters. 2. Drilling such formation having lost circulation problems, the remedy to such types of problems is to use air or foam drilling. 3. Use with bits maximum number of nozzles fitted in optimized geometry. Also check the hydraulics in this situation. 4. For the problem of bit erosion we check the hydraulics for the bit to be used..
9.4 How Air and Gas Drilling Optimized ROP in Such Formation The most severe restriction on air and gas drilling fluids is their inability to control encountered subsurface pressures. When a permeable zone drilled, its fluid content readily enters the borehole and interferes with normal circulation. Water entry is the most common problem and its removal may require prohibitive air circulation rates. Small quantities of water from low permeability formations, while posing no removal problem, do cause cutting balling and general hole stickiness which may result in stuck drill pipe. This is the most severe problem than large water volume. Much work is being done to develop materials and techniques for effectively sealing encountered water formations. Such methods will have to be fast, safe, and must be performed with a minimum of special equipment in order to be economically feasible. This technique holds considerable promise; the cost of the foaming agents, however, must be balanced by the increased penetration rate.
9.5 Advantages of Bits in Air and Gas Drilling Over Rotary Conventional Drilling The principal advantages of air and gas drilling over conventional rotary drilling are given as under Low pressure and low permeability water zones may be drilled without danger of pipe sticking. Quick weight buildup is immediately obtained by shutting off the injected air. Explosion and fire possibilities are minimized by the water in the mixture. Here we include another example of Drilling Bit Optimization. In this example we have a gas producing zone having a thickness of 800 ft of alternating Shale and 90
Case Study of A Field
Chapter # 9
Sandstone. Water sensitive Clay contents, low matrix permeability, and a natural fracture system all contribute to drilling and completion Problems. A comparison of Conventional Drilling and Air Drilling is given the following table:
Bit
Drilling Method
Time Required
Rotary, Conventional Mud
10-20 days
8-10
Sever Formation Damage
Rotary Gas Drilling
4 ½ days
3-4
Higher Well Productivity
Used
Remarks
A major benefit is the greater well productivity brought about by decreased permeability damage. A further, economic incentive is that drilling gas is normally furnished by adjacent gas producing wells this eliminate the need for compressors.
9.6 Optimization of new well in this formation In order to drill a new well in the same formations, we shall make the following considerations. Air and gas drilling in the zone of lost circulation from 0-500 m F1 (shale), F2 (limestone), F3 (shale)) by using extended nozzle bits to overcome the lost circulation. For further drilling from depth 500-2200m (F4 (limestone), F5 (sandstone), F6 (limestone)), we shall use conventional and normal roller-cone bits as there are not problematic zones. As we have different types of formations in this deep zone, we go further with turbodrilling from 2200-3300m (F7 (shale), F8 (sandstone), F9 (shale), F10 (sandstone), F11 (shale) and F12 (limestone)) with the help of impregnated bits for hard and abrasive formation such F12 (lime stone) and hybrid bits for soft formation such as (F7 (shale), F8 (sandstone), F9 (shale), F10 (sandstone), F11 (shale).
91
Case Study of A Field
Chapter # 9
The bits record of the well under discussion Bit
Bit
Bit
Bit
Jet
Depth
FT
ROP
Weight
RPM
No.
Size
Mfgr.
Type
Size
Out
formation
1
26.00
STC
MSDSHC
3X20
104.0
shale
104.00
1.30
0-10
90
700
2
26.00
STC
MSDSHC
3X20
169.0
shale
65.00
1.50
0-10
110
700
3
17.50
HW
GTX-C03
3X20
283.0
lime stone
114.00
5.70
25.00
90
400
4
17.50
VAREL
CR3GJMRS
OPEN
300.0
lime stone
17.00
2.10
28.00
85
100
5RR
17.50
HW
GTX-COR
OPEN
392.0
lime stone
92.00
3.68
28.00
95
100
6
17.50
VAREL
CR1GJMRS
OPEN
502.0
Shale
110.00
5.78
24.00
90
150
7
12.25
HUGHES
GX-09
3x16
792.0
Shale
290.00
5.70
14-16
110
560
LB
Pump Press
6x14 8
12.25
HUGHES
HC606Z
2x16
800.0
Shale
7.00
8.00
4 to 6
120
900
9
12.25
HUGHES
GX-C20
OPEN
836.0
Shale
36.00
2.70
12 to 14
120
500
10RR
12.25
SMITH
FDS
OPEN
872.0
Shale
36.00
3.20
10 to 12
120
422
9RR
12.25
HUGHES
GX-C20
OPEN
974.0
Shale
102.00
3.10
10 to 12
120
500
6x14 8RR
12 1/4
HUGHES
HC606Z
2x16
120976.0
Shale
2.00
0.50
4 to 8
160
834
1207RR
12 1/4
HUGHES
GX-09
3x16
1013.0
Shale
55.00
2.07
6 to 8
130
1363
11011
12 1/4
VAREL
CH1GJM
4x 16
1151.0
Shale
120.00
2.94
12 to 14
120
1135
9012
8.5
SMITH
MFDGH
3x14
1199.0
sandstone
48.00
3.20
6 to 8
120
1000
12013
8.5
SECURITY
EBXS55
3x16
1275.0
sandstone
76.00
2.80
12to14
130
1040
11514
8.5
SMITH
XR+
3x14
1306.0
sandstone
31.00
3.20
6 to 8
3x12,
120
1200
115-
15
8.5
SMITH
M813VPX
3x14
1354.0
sandstone
48.00
4.80
4 to 6
120
1035
14RR
8.5
SMITH
XR+
3x14
1393.0
sandstone
39.00
1.25
10
75
216
13RR
8.5
SECURITY
EBXS55
3x16
1394.0
lime stone
1.00
0.50
10
65
216
16
8.5
REED
TD41A
3X18
1491.0
lime stone
89.00
3.37
10
65-85
325
17
8.5
SECURITY
EBXS55
OPEN
1579.0
lime stone
88.00
2.31
10
65-85
500
18
8.5
SECURITY
EBXS085
OPEN
1680.0
lime stone
101.00
2.50
10
65-85
485
12519
8.5
SMITH
F3
OPEN
1736.0
lime stone
56.00
1.10
12
65
500
20
8.5
REED
TD41A
3X18
2015.0
lime stone
279.00
2.75
12
65
800
21
8.5
SECURITY
FIX6632
6X18
2468.0
Shale
453.00
6.68
6
90
870
22
6
SMITH
XR+
OPEN
2491.0
lime stone
23.00
1.70
7
70
1558
75 to 23
6
REED
SL53
3 x 16
2593.0
lime stone
102.00
1.54
6 to 8
85
2010
75 24
6
SMITH
M813PX
4 x 12
2627.0
lime stone
34.00
3.00
4 to 6
to80
2130
75 to 25
6
HUGHES
HC406
4 x 12
2673.0
lime stone
46.00
1.44
4 to 12
100
2150
75 to 26
6
SMITH
XR10TPS
3 x 14
2751.0
lime stone
78.00
1.85
7 to 9
85
2433
75 to 27
6
REED
SL51HKP
3 x 16
2860.0
Shale
109.00
2.47
7 to 8
85
2130
28
6
SECURITY
XS20S
3 x 16
2956.0
sandstone
96.00
1.96
7 to 8
75 to
2246
92
Case Study of A Field
Chapter # 9 85 75 to
24RR
6
SMITH
M813PX
4 x 12
3009.0
sandstone
53.00
1.73
4 to 9
100
2167
70 to 29
6
HUGHES
STX-20
3 x 14
3070.0
sandstone
61.00
1.39
8 to 10
75
2440
30
6
REED
SL51HP
3 x 14
3229.0
lime stone
159.00
2.65
8
70-75
2500
93
REFERENCES 1) Petroleum Engineering, Drilling and Well Completion; by Carl Gatlin. PRENTICE-HALL, INC. 1960. 2) Well Engineering & Construction by Hussain Rabia. 3) Drilling Practices Manual by Preston L.Moore. Second edition;PennWellBooks. 4) IADC Drilling Manual,eBook Version (V.11) 5) Advanced Oil Well Drilling Engineering Hand book & Computer programs; by Mitchell 10th edition, 1st revision July 1995. 6) Smith Tools “Bit Selection, Design, and Evaluation Manual” by H.G.Bentson. 7) Drilling Optimization Service; End of Well Report; Presented To Norsk Hydro 8) www.bitbrokers.com 9) www.xeg.ca 10) www.HCCbits.com 11) www.lonestarbits.com
