OILWELL

DRILLING

ENGINEERING

&

computer

programs

MITCHELL

©Copyright. USA Library of Congress, 1974 toMitchell Engineering

10th EditioQ, 1st Revision, July 1995

Dr. Bill MitchellMITCHELL ENGINEERING12299 West New Mexico PlaceLakewood, CO 80228, USAEmail: bmitchel@mines.eduTel#: 303 9867453 USA

All rights reserved. This book or any partthereofmust not be reproduced in any formwithout the written consent ofMITCHELLENGINEERING.

Printed in the United States ofAmerica.

For additional copies contact:The Society ofPetroleum Engineers ofthe AIME, PO Box 833836, Richardson,Texas, 75083-3836, USA.Tel#: 9729529393Fax#: 972 952 9435Email: spedal@spelink.spe.org

TABLE OF CONTENTS

ClIAP'IER I 'IUBl.JIAR DESIGN .AND USE 1Tubular Design and use ; lFailure Theories 1Tubular End Conditions 1Names of Casings , 2Loads 2Salt and Diaperic Shale 6Casing Design Criteria 7Management I s Guidelines 7Popular Desigri Factors : 11Drilling Burst Criteria 11An Overview of Casing Selection 13Minimum Tubular Strengths: 14Failure Mode 15Triaxial Equation 16Real Gas 2OFundamentals of Tubulars 22Stress Analysis CZ7Effective Tension roBuoyed Weight 31Free Bodies 34Stretch and Wall Strains 41Change in the Diameter of a Tube .41Bending Stress in Doglegs 49Lubinski Bending Stress 49Buckling v. Tension & Compression 53Critical Buckling Events of Casing 54Buckling Tendency & Wellhead Load 57Intermediate Casing Design 63Tubular Strengths 68API Collapse Resistance OOAPI Internal Pressure Resistance 75Pipe Body Yield Strength 79API Hydrostatic Test Pressures 82Tolerances on Dimensions 83Make-up Torque for API Couplings 86Round Thread with Bending and Tension 86Tubular Connections 89Slack-off Bending Loads OOSurface Running Loads 92Dogleg Running Loads 92Tubing Design $Drillpipe Design 1fJ7Combined Tension, Torsion, Bending & Pressure Loads , 108Von Mises Stress 108Slip Crushing 116

TABLE OF CONTENTS 1 MITCHELL Box 1492 Golden CO 80402

Fatigue of Drillpipe , 117Life of Drillpipe 121Casing Tally 122Casing Centralizer Spacing 125Casing Sag between Centralizers 127Wall Force Equation 129Helical Buckled pipe length 130

CHAPTER n DRJI,IJNG OPTIMIZATION METHODS 144Cost per foot Equation 144Time Value of Money 147Expected Value Method 148Lagrangian Multiplier 153Multiple Regression with Least Squares 156Confidence Lines 100Lagrange's Interpolation Formula 162

CHAPTER III DRILL HOLE MECHANICS I64Selecting Casing Setting depths 165Stresses around a Drill Hole 168Leakoff Test ' 171Fractures in a Drill Hole· 174Fracture Gradient Plot 180Filtration of Mud into the Formation 182Barite & Water required to drill a Section of Hole 183Solids Concentration Selection 185

ClIAPrER IV KICK REMOVAL .••..•..••...••..•.•.•.••••..•••.••..•..•.•...•..••••.•192Kill Parameters 197Initial Conditions 197Drillers Method 199Engineer's Method 204Kick Control Worksheet 210Gas Migration 217Recognition 223High Weight Pill 223Barite Plug WFilling the Hole on Trips ..' 228Novel Techniques 229

CHAP'rER V RIG HYDRA~ICS .•...•....••••.••••....•••••.••.••.•........•.....•.•zraEffect of Mud Weight on Bit Hydraulics 243Bingham's Drilling efficiency Diagram 246Optimal Bottom Hole Cleaning 249Theory of Maximizing Impact Force 259Effect of Mud Weight of Bit Hydraulics 261Hole Cleaning 262Drill Cuttings concentration in the Annulus 264Hopkin's Particle Slip Velocity Chart 267

TABLE OF CONTENTS 11 MITCHELL Box 1492 Golden CO 80402

Oribital Motion of the Drill String 274Surge and Swab for Long Pipe Strings 276Surge and Swab Pressures of Short Tools 285Circulating Pressures for Short Tools 2i57Equivalent Circulating Density 289

CHAPTER VI DffiECTIONAL DRaLING 292Directional Drilling 292Directional well planning 2fJ7Transposing MD to TVD 306Tie Point and Collision : 310Kill Well Design 314Leading the Target with planned walk 316Dogleg Severity of Holes 319Dogleg-abrupt '" , 32DWilson's Equation 322Monitoring of a Directional Well 325Radius of Curvature 327Sectional Method and Minimum Curvature 331Stability of Computational Surveys 338Errors in Surveying 343Ellipse of Uncertainty 343Systematic and Random Errors by Warren 346Circle of Uncertainty 347Declination Changes 350Drilling String Measurements 350Magnetic and other Interferences 351Hot Spots in BHA 352People Recording Errors 3533 Dimensional Drill Hole Planning 355Tool Face Rotation 359

CIlAP"IER vn HORIZONrAL DRll.LING 3mUses of Horizontal Well 373Horizontal Drilling 373Types of Horizontal Wells 374Horizontal Well Costs 376Casing & Drill bit sizes , 378Equipment 381Directional Drilling subs and stabilizers 384Bottom Hole Assemblies 386Length of non-magnetic Drill collars 388Trajectory Planning 3OOVertical Turn to aNew Track 3mSelection of Mud Weights 399Drill bit Hydraulics 403Torque and Drag 405Friction factors 409Buckling of the Drill String .414

TABLE OF CONTENTS 111 MITCHELL Box 1492 Golden CO 80402

Lock-up of the Drill String .415Available Torque for the Drill bit .415Cementing Problems .418Cement Sheath within Casing .418Conveyed Logging 419Case Histories 420Austin Chalk Well 420Tyra field offshore Denmark 422

CHAPTER VIII BOTTOM HOLE ASSEMBLIES...........•...........•....•.....427Purpose of BHA 4ZlType of BHS's 4ZlDiscussion of Components , 429Mechanical Properties of BHA 432Tapered .BHA 436Usable Hole Diameter 438Centrifugal Force : 440Torsional Dampening 441Torque of a Spinning BHA 442Torsional Buckling of a BRA and Drillpipe 443Buckling by Rotational Drag 445Critical Buckling Load 446Weight on Drill bit in Veritcal and Inclined Holes 447Critical Rotary Speeds of BHA .450Placement of the Pendulum Stabilizer 453Packed BRA 458Directional BHA 460BHA Connections 462Make-up of Connections 464Identification of Connections and Drillpipe 464

ClIAP'I"ER:IX. AIR DRII...LIN"G ~

Advantages and Limitations of Air/Gas 467Air Drilling Equipment 4OOPneumatics and Hydraulics .476Pressure Losses in Pipe and Fittings .478Air Temperature Increases on Compression .480Air Pressure Requirements 481Mist Drilling Volumes and Pressure Requirements 486Foam Drilling Volumes and Pressure Requirements 486Aerated Mud Volume and Pressure Requirements 488IKOKU 488Operational Procedures 489Concentric Drillpipe and the Jet Sub .494Parasite String 494Safety Practices 499

CHAPTER X CEMENT fj(l;One Dozen Cementation Problems 506

TABLE OF CONTENTS iv MITCHELL Box 1492 Golden CO 80402

Solutions to a Dozen Problems 506Balanced Plug Cementation Formula 516Cementation Temperatures 517

CHAPTER XI DRILL BIT SELECTION•...........•..........•.••...•.••...•..••....522Drill Bit Characteristics 525Rock Bit Terminology 5CZlRock Failure Models 528Drill Bit Selection Criteria 528Trip Time 530Optimal Weight on Bit Rotary Speeds 530Contour Method 531Analytical Method 533Optimal WOB Rotary Speed Charts 539Diamond Bit Hydraulic Lift Off 545Dull Bit Grading 547

CIlAP'rER XII FISHIN"G m>Definitions 551To Fish or Not to Fish ; 551When to Stop Fishing 552Break-even Charts 553Expected Value Method 554Confidence Lines Least Squares 556Differential Sticking ; OO:>Mechanics of Differential Sticking 00:>Freeing Differentially Stuck Pipe 561Jars and Accelerators 566Back-off 569Free Point 569Free Point Procedures 569Free Point with Pipe Stretch 569Back-off Procedure , 571Latching on to a Fish 573Overshot Specifications 574Milling 575Washover Pipe 578Rotary Shoes 578Perforation of Pipe 580Perforating Procedure 581Fishing Wire Line Tools 582Fishing small objects 585Fishing Drill Collars 586Fishing Drillpipe 586Back-off Depth 5f57Cutting of Tubulars 588Sidetracking 589Whipstock .. " " ,..590PDM snd Bent sub 591

TABLE OF CONTENTS v MITCHELL Box 1492 Golden CO 80402

Cement Plugs for Sidetrack 591Common Fishing Tools 593Bottom Hole Motor 597

I~][)~~ •••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••~

TABLE OF CONTENTS VI MITCHELL Box 1492 Golden CO 80402

CHAPTER I

TUBULAR DESIGN AND USEGENERAL

The axiom of tubular design is that the loads placed on a tube by naturalphenomena must be offset by its strengths. There are many natural phenomenawhich could dictate a particular tubular design. Also, there are many theories fordetermining the strengths of a tube. The tubular designer must therefore derivepractical design equations from the theories and phenomena. These equationsrepresent the "criteria for tubular design".

COlVfMONF~URE THEORY ASSUlVIPTIONS

The most common simplifying assumptions with regard to tubular strengths arethat the failure theory known as the MAXIMUM STRAIN ENERGY OFDISTORTION THEORyl applies only to tubular collapse strengths and that onlybiaxial2 loads are considered within the theory. Thus tensile loads and burst loadsare thought to be uniaxial3 and strengths are rationalized with the MAXIMUMPRINCIPAL STRESS THEORY OF FAILURE.4 Design factors are usually basedon experience.

1 This theory predicts failure of a specimen subjected to any combination of loadswhen the portion of the strain energy per unit volume producing change of shape(as opposed to change of volume) reaches a failure determined by a uniaxial test.Refer to Strengths of Materials, by S. Timonshenko, reprint 1976, KriegerPublishing Company.

2 Biaxial loads are those which result in the material of a structure beingsubjected to the simultaneous action of tension or compression in twoperpendicular directions. Reference same as above.

3 Uniaxial loads are those which result in the material of a structure beingsubjected to the action of tension or compression in one direction only. Referencesame as above.

4 This theory predicts failure of a specimen subjected to any combination ofnormal and shear stresses when the maximum principal stress, which is themaximum normal stress acting on a set of perpendicular planes which have noshear stress acting on them, reaches a failure value determined by a uniaxialtest. Reference same as above.

TUBULAR END CONDITIONS

The ends of tubulars (top and bottom of the casing) may either be fixed or free. Thebottom end is usually free until cemented and the top end is free until thewellhead slips are set. These conditions are tubular end conditions. The common

TUBULAR DESIGN AND USE 1 MITCHELL Box 1492 Golden CO 80402

CHAPTER II

DRILLING OPTIMIZATIONMETHODS

Drilling optimization is the application of technology which yields a reduction ofdrilling costs associated with making hole. The following optimization techniquesare popular in drilling.

1. Cost per foot equation2. Time value of money3. Expected value method4. Lagrangian multiplier5. Multiple regression6. Confidence intervals7. Lagrange's interpolation formula

COST PER FOOT EQUATION

The cost per foot equation is used for the comparison of alternative equipment,chemicals, and procedures for the drilling of a formation or an interval. Thecomparisons are often called break-even calculations and are usually betweendrill bit types or manufacturers; however, any of the variables may be compared..

c _ Bit + Tools + Mud + [Drill Time + Trip + Lost] [Rig + Support + Tool Rental]- Drill Rate * Drill Time

CBitToolsMudDrill TimeTripLostRigSupportTool RentalDrill Rate

=Cost per foot for the interval of concern; $/ft=Cost of delivered bit at the drill site; $= Cost of tools or repairs to tools; $=Cost of mud to drill the interval; $=Time required to drill the interval or bit life; hr=Time to pull and run a bit; hr=Time chargeable to non-drilling task; hr=Contract rental rate of a rig; $/hr= Third party contractors rates; $/hr= Rental of tools; $/hr= Average drilling rate over the interval; ftfhr

In a comparison of drill bits, the drilling rate and life of the proposed bit willalways be in question. The usual procedure is to compute the cost per foot with thedata from a standard bit with the proposed bit; and, then construct a chart ofrequired drilling rate and bit life for the proposed bit. The following exampleillustrates the method.

DRILLING OPTIMIZATION METHODS 144 MITCHELL Box 1492 Golden CO 80402

CHAPTER III

DRILL HOLE MECHANICSINTRODUCTION

Drill hole mechanics is the topic which aids most of all in the choice of a mudweight for drilling a section of hole. The choice of mud weights is one of the mostanalytically complex, political taxing, and critical task. The following list arethose factors which may have an effect.

1. Fracture gradients (there are two)

2. Pore pressure

3. Kick tolerance

4. Casing shoe depths

5. Borehole stability (sloughing formations)

6. Surface pressure control equipment

7. Annular circulating" pressures

8. Pressure surges (swabbing and running pipe)

9. Differential sticking of pipe

10. Filtration of mud

11. Filling of the hole

12. Gas cutting of the mud

13. Bit hydraulics

14. Mud cost

15. Drilling rate

16. Removal of drill solids

17. Formations porosity, permeability, and fluids

18. Safety margin over the pore pressure

19. Safety margin under the fracture gradients

20. Electric log analyst

21. Geologist (cuttings analysis)

22. Reservoir engineering (formation damage)

DRILL HOLE MECHANICS 164 MITCHELL Box 1492 Golden CO 80402

CHAPTER IV

KICK REMOVALThe driller's and engineer's removal methods are two reliable methods ofcirculating a drilling kick from a hole. The other methods presented below aresatisfactory in special circumstances. The depicting attributes of each method arethe following:

Driller's

1. kill mud is pumped after the kick is removed from the hole2. two circulations of the hole are required3. annular and surface pressures will be higher while removing the

kick than those of the engineer's method

Engineer's

1. the drilling mud is weighted to kill mud weight prior to pumping2. kill mud is pumped while removing the kick3. one circulation is required to kill the hole

Concurrent

1. drilling mud is weighted as it is pumped into the hole but notnecessarily to the weight of kill mud

2. the hole will contain a variable weight mud3. annular and surface pressures will be higher than the engineer's

and less than the driller's

Gas Migration

1. the gas bubble is allowed to rise in the annulus withoutcirculating

2. the casing pressure is allowed to rise to a selected value withoutbleeding mud

3. mud is bled from the annulus while keeping the pressure at theselected value

4. after the kick rises to the surface, heavy mud is lubricated into theannulus to kill the annulus and well.

Dynamic

1. kill weight mud is pumped at a rate sufficient to raise thepressure at the bottom of the hole above or equal to that of thekicking formation. The increase in bottom hole pressure occursbecause mud is occupying more and more of the volume of the

DRILLING OPTIMIZATION METHODS 192 MITCHELL BOX 1492 Golden CO USA

CHAPTER V

RIG HYDRAULICSOBJECTIVES

Objective of Rig hydraulics has eleven facets and one myth:

1. cleaning of the bottom of the hole while drilling

2. cleaning of the drill bit

3. transportation of solids to the surface at a reasonable rate

4. removal of drill solids and cavings with mud cleaning equipment

5. equivalent circulating density for the prevention of lost circulation

6. running of close clearance tools

7. circulating by close clearance tools

8. friction pressure losses through and around the drillstring andrig piping

9. hydraulic energy consumption and pressure drop through downhole tools within the drillstring

10. circulation of cement and completion fluids

11. surge and swab

12. holes do not wash out (This is the myth.)

BASIC RIG HYDRAULIC EQUATION

Pump Pressure = ~Ppipe&ann + ~Pjets +i i

lifts cleanscuttings bottom of

hole andbit teeth

MUD RHEOLOGY

~Pmotor +iturnsbit

~Pliftoff +i

diamondbits

~Ptoolsi

powerfortools

Recall that the University of Tulsa data showed that a powerlaw Reynold'sNumber of 1,800 cleaned cuttings beds and prevented their accumulation in highangle holes.

RIG HYDRAULICS 232 MITCHELL Box 1492 Golden CO 80402

CHAPTER VI

DIRECTIONAL DRILLINGINTRODUCTION

Directional wells are defined as those wells which are to follow a prescribedtraverse and intersect a specific objective. The objective is called a target and isusually an enclosed area in a horizontal plane. A target could be a circular areaat the top of a producing zone.

If tolerance in the deviations of the well from the planned traverse iscritical, the traverse is usually specified as a cylinder surrounding a section of thehole; otherwise, the traverse is given as a line path between the rotary table andthe target.

BOH5tvd

build radius

~

target

B hang angle

X build

"~Iantangle

Y slant

"Zdrop

TU vertical

8004

B053

8082

The horizontal view depicts north­south and east-west axis' which intersectin the center of the rotary table. Thetarget, the traverse, and directionalstations are recorded on the two charts.The axis of the horizontal view mayrepresent magnetic directions if it is desired.

N

Popular visual presentations of RTB 0directional well data are on charts calledhorizontal and section views. The sectionview is a vertical cross-section drawnthrough the centers of the rotary table and KOP 1the target.

The primary purposes of the two views are to pictorially show deviations ofthe drilled traverse from the planned traverse and the progress of the hole relativeto the target.

DIRECTIONAL DRILLING 292 MITCHELL Box 1492 Golden CO 80402

CHAPTER VII

HORIZONTAL DRILLINGUSES OF HORIZONTAL WELL

Horizontal wells are directional wells drilled with an inclination angle near 90degrees. The purposes of drilling horizontal wells are not new. However, theapplication of solid state electronics in directional drilling at long last permits thefulfillment of those purposes. The primary purposes of horizontal wells are thefollowing:

1. Intersect many fractures in a hydrocarbon containing formation.Very popular in limestone and some shale formations.

2. Avoid drilling into water below (or gas above) hydrocarbons orperforating adjacent to water or gas. Either are thought topromote gas and water coning. Popular in formations containingrelatively thin oil zones as compared with the underlying waterzone.

3. Increase both the drainage area of the well in the reservoir and thelateral surface area of the well bore. The first .is thought toincrease the cumulative hydrocarbon production, while thesecond enhances the hydrocarbon production rate. Popular informations containing heavy oil. These holes may be thought of asdrain holes in .some cases.

4. Intersect layered reservoirs at high dip angles.

5. Improve coal gas production (degasification).

6. Improve injection of water, gas, steam, chemical, and polymerinto formations.

The counter proposal to the drilling of a horizontal· well is to drill a vertical welland hydraulically fracture the pay formation. This rarely accomplishes a purposeof a horizontal well, because hydraulic fracturing rarely if ever succeeds inintersecting many fractures in a naturally fractured formation; fractures usuallyintersect underlying water zones, and fractures filled with propants (sand) arenot drain holes.

The above purposes stipulate the requirements for the evaluation of a horizontalhole.

1. Hits all targets

2. Smooth turns and builds for promoting long lateral sections

HORIZONTAL DRILLING 373 MITCHELL Box 1492 Golden CO 80402

CHAPTER VIII

BOTTOM HOLE ASSEMBLIESDEFINITION OF BHA

A bottom hole assembly (known as BRA) is a component of a drill string. A BHAresides in the drill string above the drill bit and below the drillpipe. The primarycomponent of the BHA is the drill collar. The following figure shows the possiblecomponents of a BRA and their typical location within a BHA.

PURPOSE OF BHA

The purposes of a BHA are as listed in the following.

1. protect the drillpipe in the drill string from excessive bending andtorsional loads,

2. control direction and inclination in directional holes,3. drill more vertical holes,4. drill straighter holes,5. reduce severities of doglegs, keyseats, and ledges,6. assure that casing can be run into a hole,7. increase drill bit performance,8. reduce rough drilling, (rig and drill string vibrations),9. as a tool in fishing, testing, and workover operations,

10. not to place weight on the drill bit

TYPES OF BHA'S

The "SLICK" BRA is composed only of drill collars. It is least expensive andperhaps carries the least risk in regard to fishing and recovery.

The "PENDULUM" BHA is designed to drill holes more vertically and to dropinclination in inclined holes. Lubinski and Woods published tables and charts tolocate the lowest most stabilizers in the BHA. Most BHA theories which wereintended for vertical holes apply to holes wliich are inclined 20 degrees or less.

The "PACKED" BRA is designed to drill straight holes and to reduce theseverities of doglegs, keyseats, and ledges. It provides the highest assurance thatcasing can be run into a hole. The theory which supports the packedBHA wasdeveloped by Roch. A packed BHA can be expensive and perhaps carries thehighest risk in regard to fishing and recovery.

The "DIRECTIONAL" BRA is designed either to turn the hole to a choseninclination and direction or to maintain a course selected for the hole. Thedirectional BRA is based on the principles of levers and fulcrums.

BOTTOM HOLE ASSEMBLIES 427 MITCHELL Box 1492 Golden CO 80402

CHAPTER IX.

AIR DRILLINGINTRODUCTION

Air drilling utilizes air or gas as the borehole circulating fluid. Four categories ofair drilling exist. These are straight air, mist, foam, and aerated mud. Straightair drilling requires only that air be compressed and circulated such that bitcuttings are lifted from the borehole. Mist drilling requires the addition of afoaming agent (surfactant) to the compressed air. Small volumes of water arelifted as droplets. The bit cuttings are wet; however, the· continuous fluid phasewithin the wellbore is air. Foam drilling requires the addition of a foaming agentand water or mud to the air. If water is used, the :·esulting circulating fluid iscalled foam and if mud is used it is' called stiff foam. Large volumes of water maybe lifted (30-40 gph). The air appears as tightly compressed bubbles in anascending liquid stream. In aerated water drilling, water is the primarycirculating medium and air is added without a foaming agent. Thus, foam is notcreated and the continuous fluid phase is water. If mud replaces the water, it iscalled aerated mud drilling.

ADVANTAGES AND LIMITATIONS OF AIR/GAS

The selection of air drilling systems in preference to normal mud is based on thefeasibility of drilling the hole and, of course, economics. The primary advantagesof straight air drilling are greatly increased penetration rates (2 to 10 timesfaster), more bit footage and fewer borehole drilling problems which lead tofishing operations. Water, gas and/or oil flow into the wellbore from porous zoneslimits the feasibility of straight air drilling. Compressor rental will increase "dailycosts by 50 %.

Mist drilling is usually selected to follow straight air drilling after a porous waterzone is encountered. Generally, drilling rates and bit footage drop and the risk offishing increases. Large water flows from porous zones usually require aconversion to mud drilling. Compressor costs increase slightly over straight airdrilling and chemical costs may become critical.

Foam drilling is a specialty system. Its primary advantages are attributable to itsreduced head on formations near or at the bottom of the borehole and highcuttings lifting capacity. It is frequently used for drilling known lost circulationzones and pay zones. Alaska's operations have shown that near-gage holes can bedrilled with foam through permafrost and frozen zones because of its low heatcapacity and poor heat conductance. Foam disposal can be a problem.

Aerated mud or water is popular in combating lost circulation zones andespecially so if they occur in conjunction with prolific water flows. The problem isthat overlying water zones require subnormal heads while lower zones require amore normal head. Disposal of excessive produced water can be a problem.

AIR DRilliNG 467 MITCHEll Box 1492 Golden CO 80402

CHAPTER X

CEMENTONE DOZEN CEMENTATION PROBLEMS

There are a dozen major problems which may occur during primarycementations. The following is a list of those problems.

1. Poor displacement of the drilling mud, solids, and cuttings bedsover the length of the hole that is being cemented.

2. Lost circulation during or after the cementation.3. Bridges composed of cement filter cake.4. Swapping out of drilling mud left below the pipe and cement

circulated around the pipe (particularly bad in the setting of openplugs).

5. Flash setting of cement.6. Shrinkage of cement.7. Permeability after setting of the cement.8. Gas migration (percolating gas) during the setting of the cement.9. Micro-annulus from pressure and temperature within and of the

pIpe.10. Temperature strength retrogration of the cement.11. Perforation of cement.12. Cement settling in high angle holes".13. Equipment, planning, and execution failures (people errors) and

the quality of cement and additives.

SOLUTIONS TO A DOZEN PROBLEMS

#1 PROBLEM: POOR DISPLACEMENT OF MUD

MECHANISM: The volumetric' fraction of the mud removedfrom the wellbore annulus by the cement slurry is calleddisplacement efficiency. High displacement efficienciesincrease the probability that the set cement will not containchannels of mud or that the cement will not have channeledthrough the mud. Satisfactory displacement efficienciesdepend on many factors; however, the type of flow regime inwhich the cement slurry and the mud being displaced isflowing during displacement is dominant.

SOLUTION: The recognized flow regimes are (1) plug, (2) laminar and, (3)turbulent. The dominant solution to poor mud displacement is cementhydraulics. Other aids are pipe rotation and reciprocation. Mobil Oil showedrotation speeds of 35 rpm are sufficient. Exxon showed 800/0 standoff withcentralizers is sufficient with proper cement and hydraulics.

CEMENT 506 MITCHELL Box 1492 Golden CO 80402

CHAPTER XI

DRILL BIT SELECTIONINTRODUCTION

One of the more confusing aspects of oilwell drilling to the young and old a like isthe numerous types of drill bits. The largest manufacturer of drill bits makes 34types and 33 sizes (diameters) and many more on request.

The International Association of Drilling Contractors (IADC) organization has asystem of assigning a designation code to each bit type. The meaning of the codesare shown in the table. The primary short coming of the API coding system iscaused by the fact that manufacturers' bits which on the surface may appearsimilar are very different in substance.

The IADC category of bits and types (called bit codes) are

1. roller cone

FEATURESCD

!

IlADe 01 c.£: 'C

~ c::coo c:: t

BIT CLASSIFICAnON FORM "0 ciS .2 CD 0C c::

CD 01 OJo _ t>.~ .~c:: .S C en ~ o 0 .g

'C

~-g'C - (5 ££ .~ e:;ro roO .;: E

"00 ~ci: cr tt u.a,. c::~m ~8 ~.§ i c ~.§ "0 0 .Q"0- g~ e:> c»

~ C(f) en c~ ~(.) ;u ~.

W So (5.~to C'O tOC'O to ::> ~

W OtO o e:> o to me:> C) to 0 5a: 0- (f)er:. cr< o:e> (f)CD (f)C) (f)C'O (f)e>

w FORMATIONS >- 1 2 3 4 5 6 7 8 9(f) ~

Soft formations with low 1

!l 1 compressive strength 2

iii 3and high drillability 4 I.c:Medium to med-hard 10

0 2 formations with high 2

J-: compressive strength 34

~1

~ Hard semi-abrasive and3 abrasive formations 2

:E 3 I

4

Soft formations with low 14 compressive strength 2

3and high drillability 4

Soft formations with low 1

5 compressive strength 234

.! Medium hard formations 1iii 6 with high compressive 2- ~~ strenoth(1)U)

Hard semi-abrasive and 1.E 7 abrasive formations 2

34

Extremely hard and1

8 2abrasive formations 3

4

DRILL BIT SELECTION 522 MITCHELL Box 1492 Golden CO 80402

CHAPTER XII

FISHINGDEFlNITIONS

A fish is any undesirable object; such as, pipe, tools, wireline, which can not beremoved from a borehole with ordinary practices. Fishing is any action takenwhich attempts to remove a fish from a borehole. For example, lowering a magnetinto the bore hole for the purpose of removing a cone lost from a drill bit is fishing.Removing a broken wireline and a directional survey tool is fishing.

Indirect fishing time is the elapsed. time which is required to regain the boreholedepth and be in the drilling mode from the time the fish evolved. For example, ifon day number 5 with the borehole at a depth of 5,000 feet and while drilling a drillbit cone is lost and thereafter 500 feet of hole are lost, and if on· day 20 the boreholeis once again drilled to 5,000 feet, then the fishing time is 15 days. Direct fishingtime is the time which was spent attempting to remove the fish. In the previousexample the time to regain the 500 feet of hole would not be direct fishing time.

Direct and indirect fishing cost parallels the thought of fishing time except thatdollars replace time. For example daily rig cost and an overshot rental fee wouldbe direct fishing costs; however if a bottom hole assembly were lost then its costwould be an indirect fishing cost.

TO FISH OR NOT TO FISH

There are at least three popular methods for deciding whether to fish or not tofish. The most popular method is to fish for two days and if no progress is madeother alternatives are chosen. One of the others is to construct break-even charts.These charts weigh the value of the borehole and equipment against the cost offishing. The last method is based on the expected value method of decisionmaking. The problem with it is that a data base is required.

FISHING

,~.:' __~~PIi

551 MITCHELL Box 1492 Golden CO 80402