analysis, comparison and application of cwd against conventional drilling operations

7/29/2019 Analysis, Comparison and Application of CWD Against Conventional Drilling Operations

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Analysis, Comparison and Application of Casing while

Drilling against Conventional Drilling Operations

Report submitted in partial fulfillment of the requirement for the award

of the degree of

BACHELOR OF TECHNOLOGY

IN

PETROLEUM ENGINEERING

By

Abhinav Chaudhary 09BT01101

Prakhar Mathur 09BT01180

Sonez Shekhar 09BT01088Rohit Kumar 09BT01116

Adarsh Pal 09BT01086

Vinay Varghese 09BT01092Siddhant Kumar Prasad 09BT01065

Atul Bansal 09BT01179

Srujan Rajuri 09BT01112

Under the supervision of

Mr. Vinay Babu

SCHOOL OF PETROLEUM TECHNOLOGY

PANDIT DEENDAYAL PETROLEUM UNIVERSITY


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CERTIFICATE

This is to certify that the project entitled ANALYSIS, COMPARISON AND

APPLICATION OF CASING WHILE DRILLING AGAINST CONVENTIONAL

DRILLING OPERATIONS submitted by Abhinav Chaudhary (09BT01101), Prakhar Mathur(09BT01180), Sonez Shekhar (09BT01088) , Rohit Kumar (09BT01116), Adarsh Pal

(09BT01086) , Vinay Varghese (09BT01092) , Siddhant Kr. Prasad (09BT01065), Atul Bansal

(09BT01179) and Srujan Rajuri (09BT01112) in partial fulfilment of the requirements for the

award of the degree Bachelor of Technology in Petroleum Engineering at Pandit Deendayal

Petroleum University is an authentic work carried out by them under my supervision and

guidance.

To the best of my knowledge, the matter embodied in the project has not been

submitted to any other University / Institute for the award of any Degree or Diploma.

(Mr. Vinay Babu)

Supervisor,

School of Petroleum Technology

Pandit Deendayal Petroleum University

Date: 10 April, 2012 Gandhinagar - 382007


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ACKNOWLEDGMENT

The final work of the B.Tech project titled Analysis, Comparison and Application of Casingwhile Drilling against Conventional Drilling Operations has been a persistent endeavour from

lot of people and so we would like to thank all of them for their support and guidance throughout

this session.

First of all, we would like to thank Mr. Vinay Babu, mentor of our project who guided us

throughout the project work. His guidance helped us to carry out the work smoothly and

efficiently.

We would also like to thank Mr. Moji Karimi; Application Engineer; Solid Expandables and

Drilling with Casing/Liner, Weatherford,for his continuous online guidance. We would like to

extend our gratitude to Mr. Nishant Parikh for his valuable inputs and suggestions and last but

not the least, we thank Mr. Naveen Velmurugan for helping us with modelling on software.

We would also like to thank all the group members and colleagues who were along with us

during the entire tenure of the project and worked with us to endeavour through all the phases of

our project. The project work was an enriching experience which will be beneficial to us in our

professional career. It enabled us to develop technical skills and also helped us in improving our

communication and management skills.

Abhinav Chaudhary (09BT01101)

Prakhar Mathur (09BT01180)

Sonez Shekhar (09BT01088)

Rohit Kumar (09BT01116)Adarsh Pal (09BT01086)

Vinay Varghese (09BT01092)

Siddhant Kumar Prasad (09BT01065)

Atul Bansal (09BT01179)

Srujan Rajuri (09BT01112)

i
http://www.linkedin.com/search?search=&title=Application+Engineer%3B+Solid+Expandables+and+Drilling+with+Casing%2FLiner&sortCriteria=R&keepFacets=true&currentTitle=Chttp://www.linkedin.com/search?search=&title=Application+Engineer%3B+Solid+Expandables+and+Drilling+with+Casing%2FLiner&sortCriteria=R&keepFacets=true&currentTitle=Chttp://www.linkedin.com/search?search=&title=Application+Engineer%3B+Solid+Expandables+and+Drilling+with+Casing%2FLiner&sortCriteria=R&keepFacets=true&currentTitle=Chttp://www.linkedin.com/search?search=&title=Application+Engineer%3B+Solid+Expandables+and+Drilling+with+Casing%2FLiner&sortCriteria=R&keepFacets=true&currentTitle=C


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List of Figures

Fig No. Name Of the Figure Page No.

2.1 Modified casing program design, without surge/swab consideration 3

3.1 Casing Clamp 8

4.1 S-N Curve 11

4.2 Forces acting on Individual Casing Segment 12

5.1 Drill Lock Assembly 15

5.2 Wire line Retrievable BHA 16

5.3 Casing Drilling Under reamer 16

5.4 Rear Band 17

5.5 Hydro Formed Crimp-on Stabilizer 18

5.6 Non Retrievable System 19

6.1 Casing Drive System 21

6.2 Partial Cross-sectional View of the Spear 23

7.1 Interior Body Portion Of CwD Bit 29

7.2 Outer Surface of CwD Bit 30

7.3 Components of the Blade 31

7.4 Prototype Design for PDC drillout Bit 34

10.1 Thread corner contact 44

10.2 Premium connection threads and seal damage 44

10.3 Effect of measurement of uncertainty on applied torque 46

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10.4 Combined effects of measurements and control uncertainty on applied

torque

46

10.5 Full coverage die 49

10.6

13.1

13.2

Exaggerated illustration of pipe and die contact

Wellbore stability improvement by casing drilling as compared to

conventional drilling.

Annular difference between conventional drilling and CWD

49

55

56

13.3 Plastering Effect phenomena 57



13.6 Wellbore cross section, comparison between Casing Drilling and 59

Conventional drilling

13.7 Contact angle comparison between Casing drilling and Conventional drilling 60

13.8 Contact area comparison between Casing Drilling and conventional drilling 60

13.9 Penetration depth into the filter cake, comparison between Casing drilling 61

And conventional drilling

13.10 Typical PPT value comparison for mud sample 64

14.1 Forces acting on a drilled cutting in a section of annulus 67

14.2 Spiral motion of the drilled cuttings as they rise up in annulus 68

15.1 Typical relative sizes of cuttings and their distribution 74

15.2 Typical Simulated results depicting particles sizes deposited at different depths 75

16.1 Typical Piceance well 76

16.2 Directional CWD BHA 76

16.3 LOT at 9.625 inch shoe and first test after CwD at 3811 78

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16.4 LOT after CwD with 60 rpm and a LOT after CwD with 60 rpm and adding 79

LCM for last half of the stand

16.5 LOT after CwD with 80 rpm 79

16.6 Case of CwD with 60 rpm 81

16.7 Case of Conventional drilling with 60 rpm 81

16.8 Case of CwD with 80 rpm 82

16.9 Case of Conventional drilling with 80 rpm 82

iv


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List of Tables

13.1 Summary of the successful Plastering effect applications 58

15.1 Calculated diameter and residence time 74

16.1 Piceance Well Data 77

v


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Abbreviations Used

API - American Petroleum Institute

CWD - Casing While Drilling

BHA - Bottom Hole Assembly

ECD - Equivalent Circulating Density

CDS - Casing Drive System

CCI - Cutting Carrying Index

WOB - Weight On Bit

NPT - Non-Productive Time

PDC - Poly-Crystalline Diamond Compact

DLA - Drill Lock Assembly

UCS - Unconfined Compressive Strength

LCM - Lost Circulation Material

PSD - Particle Size Distribution

PPT - Permeable Plugging Test

CBL - Cement Bond Log

VFD - Variable Frequency Drive

SAGD - Steam Assisted Gravity Drainage

vi


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Contents

Page No.

Certificate by Internal Guide

Acknowledgement i

List of Figures ii

List of Tables v

Abbreviations Used vi

Chapters:

1. Chapter 1: Introduction 12. Chapter 2: Well Planning 2

2.1 Introduction2.2 No Swab and Surge; Wider Operational Mud Weight

Window

2.3 ECD versatility2.4 Hydraulics design: Cutting Carrying Index2.5 Stiffer Pipe, Better Verticality2.6 Plastering Effect increases Fracture Gradient2.7 Cement Job Quality2.8 NPT (Non Productive Time)

3. Chapter 3: Rig Modification 63.1 Introduction3.2 Industry Practices3.3 Case Study3.4 Special Considerations

4. Chapter 4: Casing Design 94.1 Introduction4.2 Fatigue Life Evaluation of Casing String4.3 Loads Subjected to Casing

5. Chapter 5: Downhole Assembly 145.1 Casing While Drilling with Retrievable Drilling Assemblies5.2 Casing Drilling Accessories5.3 Non-Retrievable BHA

6. Chapter 6: Casing Drive System 20


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6.1 Introduction6.2 Description of the Casing Drive System6.3 Description of the Spear (in fig 6.2)6.4 Description and Actuation of Slips6.5 Casing Running Process

7. Chapter 7: Drill Bits 277.1 Introduction7.2 Drillable Drill Bit Design

7.2.1 Body Portion7.2.2 Blade and Cutters Structure7.2.3 Forces acting on Blades and cutters during drilling operations

7.3 Drill out and Drill ahead7.4 Prototype Development7.5 Lab Testing, Field trials7.6

Drill-out Performance Comparison

8. Chapter 8: Plastering Effect 378.1 Introduction

9. Chapter 9: Cementing 389.1 Introduction9.2 How Cementing in CwD differs from conventional practices9.3 Centralization9.4 Floating equipments used in cementing in CwD9.5 Cement excess factor9.6 Other common Cementing Practices for CwD

10. Chapter 10: Downhole Problems and Solutions 4310.1 Mechanical Problems

10.1.1 Casing Thread Damage & Solutions10.1.2 Makeup Monitoring and Control

10.1.2.1 Monitoring10.1.2.2 Control10.1.2.3 Solutions

10.1.3 Pipe Body Damage & Solutions10.1.4 Pipe Handling Logistics & Solutions

11. Chapter 11: Well Control 5112. Chapter 12: Advantages and Disadvantages 5213. Chapter 13: Plastering Effect: A Qualitative analysis 54

13.1 Introduction13.2 Occurrence of Plastering Effect13.3 Mechanism13.4 Casing drilling pipe geometry


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13.5 Various conditions for plastering13.6 Particle Size Distribution (PSD)13.7 Significance13.8 Permeable Plugging Test (PPT)13.9 Conclusion derived from Permeable Plugging Test

14.Chapter 14: Prediction of Particle Size Distribution in CWD 6614.1 Principle Involved14.2 Our Proposed Model

14.2.1 Assumptions14.2.2 Figure14.2.3 Derivation

14.3 Some Details14.4 Observations

15.Chapter 15: Simulated Results 7416.

Chapter 16: Case study-Piceance well 78

16.1 Piceance Creek Directional CWD16.2 Particle Size Distribution Discussion16.3 Conclusions pertaining to discussed case study

17.Chapter 17: Field Application of CwD 8517.1 Casing Drilling Technology17.2 Drilling Salt Dome Field17.3 Permafrost Drilling17.4 Managed Pressure Casing Drilling (MPCD)

18.Chapter 18: Inferences 9019.Chapter 19: Further Scope 91

References 92


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Chapter 1: Introduction

Casing While Drilling is innovation in action technology that gets casing to bottom by

circulating, reciprocating and rotating simultaneously. Every well is drilled and cased at thesame time. By using the full capabilities of your rigs top drive, the system is the solution:

Casing While Drilling is a proven process after millions of feet drilled, on- and off shore,

straight, directional and horizontal wells.

Because of its application flexibility, Casing While Drilling can successfully execute

anything that can be accomplished with conventional drilling, while delivering operating and

labour cost savings, capital investment reductions and faster time-to-targets.

With Casing While Drilling, casing is always on bottom, letting you change your bottom hole

assembly (BHA) without a trip. The process requires less drilling fluid, further reducing costs

and environmental impact: the mechanical characteristics of the casing plaster cuttings into

the face of the bore hole, sealing pores in the formation that contribute to lost circulation.

Directional and horizontal applications have been proven on- and off shore. Directional

Casing While Drilling has been used successfully in difficult shales in North America; in

completing complex 3D North Sea wells; and in drilling extended reach wells furtherexamples of the flexibility and adaptability of Casing While Drilling in a wide variety of hole

angles, with on-bottom ROPs equal to or better than conventional methods.

It requires few adaptations to a standard drilling rig in most cases, just a few hours of rig-up

time. Casing While Drilling can be accomplished on nearly any rig with a top drive. Casing

While Drilling significantly reduces lost fluids due to this Plastering Effect and enhances

reservoir productivity from producing horizons. Improved well control is enhanced with

continuous circulation even when tripping. Having casing constantly on the bottom reduces

well kicks creating a safer environment.

The Casing While Drilling process increases safety because it requires fewer people on the

rig floor and less pipe handling than conventional drilling. Casing While Drilling design

provides superior strength and rigidity in drilling operations.Casing While Drilling expertise

and technology together help control and minimize todays borehole integrity issues and

other drilling challenges. From basic casing running procedures to complex drilling

scenarios, Casing While Drilling gets the job done with superior efficiency.

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Chapter 2: Well Planning

2.1 Introduction:

Before initiation of any drilling operations, a thorough planning is done so as to determine

many parameters beforehand, like:

Well details Well objective Casing Policy Wellhead selection BOP requirements Cementing programme Deviation programme Survey requirements Mud programme Bit and Hydraulics programme Evaluation requirements Estimation of well cost, etc.

There are many well established and proved methods to determine each of the parameters

above for conventional drilling. And there are large numbers of industry standards that are set

as best practices and are followed rigorously when planning a new well. However, only few

people really know the benefits offered by Casing While Drilling technology in achieving

these industry standards with minimum input. We would be touching some of the very

important aspects of planning a well for casing while drilling application, keeping in mind the

conventional method.

2.2 No Swab and Surge; Wider Operational Mud Weight Window:Swab and surge during tripping can be very problematic because this can cause the pressure

to exceed the fracture gradient or fall below the kick tolerance. The CDS eliminates off-

bottom well control situations and eliminates the possibility of kicks due to the swab

pressure while tripping out of the hole. Moreover, the continuous circulation even when

tripping prevents surge or swab conditions even when a new BHA is being used. The

importance of eliminating swab/surge cannot be overstated, as this frees operators from

having to consider the trip margin when drawing the operational mud weight window. Tripmargin is an overbalance to compensate for the loss of ECD and to overcome the effects of

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swab pressure during a trip out of the hole (trip margin is usually 0.5 ppg to 1 ppg).

Elimination of trip margins from the operational mud weight window can help set the casing

deeper or even eliminates a string.

Fig 2.1Modified casing program design, without surge/swab consideration

2.3 ECD versatility:

We know that ECD (Equivalent Circulation Density) is dependent on 3 factors, they are:

Mud weight Flow rate (pump rate) Plastic viscosity

Casing Drilling geometry provides a better control on the annulus pressure profile. The small

annulus brings about higher friction which leads to higher equivalent circulating density

(ECD) in comparison to conventional drilling.

Hence the above mentioned 3 factors can be varied to an optimum value which is small and

can be easily attained on field, in comparison with the values required for conventional

drilling on same project.

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2.4 Hydraulics design: Cutting Carrying Index:

It is believed that the small annulus of the Casing Drilling generates a mechanical agitation

effect of the casing that helps prevent formation of cutting beds and facilitates cuttingtransfer. Moreover, due to the elimination of tripping, the well is being circulated most of the

time. This eliminates the opportunity for cuttings to settle at the bottom of the wellbore as

much as they do with conventional drilling. The higher annular velocity, the casings

mechanical agitation, and consistent circulation could be the reason why much less barite sag

problems are present in Casing Drilling.

CCI is calculated using the following formula, where Av is annular velocity in ft/min, Mw is

mud weight in ppg, and K is the Power Law Constant:

2.5 Stiffer Pipe, Better Verticality:

The stiffer the casing, the less effect stabilization/centralization will have on the directional

performance of the casing drilling assembly. When drilling with casing larger than 7 OD,

fulcrum or pendulum assemblies become largely unrealistic, as creating the requisite bit tilt

requires increasingly large WOB.

2.6 Plastering Effect increases Fracture Gradient:

The unique result of CWD, the plastering effect has important role to play in planning a well.

The rotary motion of casing along with very small annulus forms a layer at the wellbore wall.

This layer consists of mainly the formation cuttings and some heavier mud additives. Theseget pressed on walls due to centrifugal force with strengthening taking place due to removal

of water. This layer forms a stress layer over surface and hence increases the fracture

gradient. This net increased fracture gradient provides flexibility in casing program and/or

casing shoe selection.

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2.7 Cement Job Quality:

The reason is the casing has filtered the fluid out of the cake so we have a slick cake which

will bond with cement very good. also the CWD process creates a more gauged wellbore,hence less cement required to pump, better displacement efficiency, so better cement job.

That same plaster also prevents cement filtrate from damaging the formation. Even better

can be achieved by rotate/reciprocate the casing while cementing.

2.8 NPT (Non Productive Time):

Unexpected drilling hazards and operational issues result in nonproductive time, which an

industry consensus estimates can run as much a much as a quarter of many drilling projects,with about half that figure directly related to drilling troubles that can be directly mitigated

with casing drilling. Also, the majority of nonproductive time in any drilling operation comes

when you are tripping pipe. That is when most well control problems show up and when well

bore stability issues really become evident. If you can avoid tripping pipe, you can sidestep

much of the typical NPT.

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Chapter 3: Rig Modification

3.1 Introduction

Casing while Drilling is a very simple yet effective technique of drilling complex wells. This

is evident from the fact that it requires no or very little modifications to the conventional

drilling rig or a special PLC (programmable logic controller) rig.

3.2 Industry Practices

Till date no Casing while Drilling operations have used a Kelly drive rig and hence the only

optional equipment required for this operation is a Top Drive System. In some Instances a

split block assembly that allows wireline to be used in running and retrieving the Bottom

Hole Assembly. There are many operators who use a top drive casing running tool like the

Tesco Casing Drive System, Weatherford Overdrive, Volant CRTi, Canrig Suregrip, NOV

CRT to make up casing connections using the top drive and a Computer Aided Makeup

system instead of using power tongs. Hence, the floor is clear of tongs and there is no need to

have anyone working at the stabber board level. These tools are becoming far more widely

utilized and will eventually take the place of conventional tongs.

To drill with casing, a purpose built rig was constructed. There were four basic changes from

a conventional drilling rig.

(a) The first change was to install a wireline winch capable of running and retrieving the

BHA. The wireline included an electric line for future tool actuation. Operation of this

wireline winch was integrated into the rig PLC control panel.

(b) The second change was to install a split travelling block and crown and a top drive in

order to facilitate running the wireline down through the casing.

(c) The third change was to install a wireline BOP and double pack-off above the top drive in

order to seal off around the wireline.

(d) The fourth change was to add pipe-handling tools to handle casing instead of a

conventional drill string.

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3.3 Case Study

Tesco Rig 1, specifically designed as a Casing Drilling rig was used for the project. The rig

utilizes PLC controlled hydraulically powered rotating, hoisting, and pumping systems. It

was originally designed as a platform to assist in developing and testing the Casing Drilling

system. The major modifications to the rig were the addition of a second mud pump and

improvements to the well control and gas handling equipment. These enhancements assured

the rig could safely handle a large influx of gas if the well encountered a virgin pressured

natural fracture in the pay zone. This equipment also facilitated the normal handling of

reservoir gas while drilling slightly underbalanced. A newly developed Tesco casing clamp,

shown in Figure 3.1, was added to the rig to increase the ease and efficiency of drilling with

casing. Prior to this, a crossover to the casing thread was used below the top drive to screw

into the top of each joint of casing. The threads on each joint of casing were made up and

broken out before being made up for the final time, thus increases the risk of damaging the

casing threads. The casing clamp handles casing sizes from 3-1/2 to 9-5/8and eliminates

the need to make a threaded connection between the top of the casing and the top drive. It

incorporates external slips to hold the casing axially and to transmit rotational torque. An

internal spear and seal assembly provides a seal without using the casing threads. The casing

clamp is hydraulically operated with the top drive controls. After a joint of casing is placed in

the mouse hole, a protective full open thread nubbin is screwed into the box, the top drive is

extended over the mouse hole and the clamp is lowered over the top of the casing. The clamp

is activated and the joint is picked up and stabbed into the stump in the rotary table. The

connection is made-up to the thread manufacturers specification with the top drive and

Casing Drilling is resumed.

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Figure 3.1: Casing Clamp

3.4 Special Considerations

There are some additional considerations when using a top drive casing running tool and that

is with respect to the rig alignment. If the rig is poorly aligned then makeup can be difficult.

If it is known in advance that one of these tools is to be used then time can be taken to align

the rig during rig up. While CWD most operators use these tools, which are already rigged up

ready to drill the casing or ream, to make up the casing.

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Chapter 4: Casing Design

4.1 Introduction

The design approaches for casing drilling are some where similar to conventional drilling

approach. In conventional drilling engineering techniques, the casing is run after the

completion of drilling a well. The design criteria for casing in such case are mostly based on

maximum load, where emphasis is given primarily to tension, burst and collapse loads.

Considerations are also given to account the consequences of borehole stability, well control,

casing setting depths, directional planning, and bit selection. Most of these factors affecting

Casing While Drilling can be predicted with the concept of conventional drilling engineering

techniques. However, fatigue life and endurance limit evaluation for casing in case of Casing

While Drilling approach requires special consideration.

4.2 Fatigue Life Evaluation of Casing String

Despite tension, collapse and burst pressure, the successful design of the casing running

simultaneously while drilling, as known as Casing While Drilling, requires accurate

prediction of different effects primarily torque and drag, and fatigue. The fatigue failure ofcasing is occurred by repeated or cyclic loads at stress levels well below the elastic strength

of its material. The accurate evaluation of fatigue life for Casing While Drilling is a complex

task.

4.3 Loads Subjected to Casing

In order to derive the stress-life model; it is essential to consider all loads subjected to casing

during operations that may contribute to cause failures. In practice, both static loads and

fatigue loads can cause to failure of a casing string. The static loads include axial tension

load; external pressure (or differential collapsing pressure), equivalent tension from bending,

tangential shear from torsion and buckling loads. The static loads subjected a casing have

been determined on the basis of design factors being greater than some recommended values.

The design factor is defined as the ratio of a limit load to its corresponding applied load as

follows:

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DFa =yatc DFr = pycprc DFt = DFs = yrc DFvm = yvm

(1)

In Eq. 1, DFa, DFr, DFt, DFs and DFvm are design factors against axial, radial, tangential,

shear and combined loads (von Misses), respectively. One of the greatest advantages of von

Misses stress as combined stress is that the calculated stress can be compared to the yield

strength of materials resulting single equivalent design factor. Thus, DFvm takes into account

of all other loads subjected to the casing strings. The value of atc is obtained by multiplying

the total axial stress, at by the stress concentration factor Ka for axial load.

The total axial stress, atis calculated as: atc = Kaat in which;

at= a+ b (2)

a is the axial stress due to weight of casing string only and calculated as Weff/As, in which

As is the cross sectional area of casing wall and W eff is the effective tensile load that is

estimated based on the total hanging weight of casing string below the section in question,

considering the buoyancy effect exertedby drilling mud. b is the tensile bending stress

developed at the dogleg calculated by Lubinski's formula :

(3)

where E is the Young's modulus, psi; Do is outer diameter, inch; C is the dogleg severity,

radian per unit length; I is the moment of inertia of the casing section, L is the half-length of

one casing string between joints.

The conventional approach of predicting the fatigue life is based on data presented by S-N

curve, which gives the number of cycles (N) at which the pipe fails due to material fatigue for

a given repeated maximum stress level (S). The mathematical model that evaluates the

fatigue life of casing string can be developed following the local strain model based on

Neuber's rule and/or the fracture mechanics model or conventional stress-life (S-N curve)

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based mode. However, stress-life based model is simpler and provide better prediction. In

present work, the fatigue model for casing joints is developed following the stress-life model

incorporating the stress concentration factor (K).

Fig 4.1 S-N Curve

For the calculation of shear stress,t, torsional formula for a hollow circular tube can be used

as;

t= 2 (6)Where T is total torque developed during running the casing string, and J is polar moment of

inertia of casing string.

The torque developed during running the casing is caused mainly by frictional forces resulted

from contact of casing string with the wellbore. The magnitude of such frictional force is the

product of normal contact force and the coefficient of friction between the contact surfaces.

The magnitude of normal force can be calculated by:

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FN = [(Fasin)2 + (Fa + WecHsin)]

1/2 (7)

Where, Fa is the tensile force contributed from the weight of casing string can be calculated as

Fa= WecHcos (8)

The incremental torsion over a length segment is then calculated as:

T= CfFNDo/2 (9)

Where Cfis the coefficient of friction between the casing string and wellbore surface and Do

is the outer diameter of casing. The total torque required at the surface can be calculated by

summing up the incremental torques from the point of interest to the surface:

(10)

The incremental tension force due to frictional drag during sliding the casing by rotation can

be calculated as:

Fd= WecHcos CfFN

Where the plus or minus sign depends either up or down motion of casing respectively.

Fig 4.2 Forces acting on individual casing segment

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The use of casing as the drill shoe or drill bit in situ has revealed several limitationsinherent in the structure of the casing as well as the methodologies used to load and drive

the casing.

The thread form used in casing connections is more fragile than the connection used indrill pipe.

The casing connections have to remain pressure tight once the drilling process has been

completed. Additionally, casing typically has a thinner wall and is less robust than drill pipe,

especially in the thread area at both ends of the casing where there is a corresponding

reduction in section area.

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Chapter 5: Downhole Assembly

5.1 Casing While Drilling with Retrievable Drilling Assemblies

This drilling system is composed of down hole and surface components that provide the

ability to use normal oil field casing as the drill string so that the well is simultaneously

drilled and cased. The casing is rotated from the surface for all operations except slide

drilling with a motor and bent housing assembly for oriented directional work.

A retrievable drilling assembly is attached to the casing inside a proprietary profile nipple

located near the casing shoe. The casing is rotated from the surface with a top drive for alloperations except when there is a normal operational need to drill without drill string rotation.

The drilling fluid is circulated down the casing ID and up the annulus between the casing and

well bore. The drilling assembly extending below the casing usually includes an under reamer

and a PDC or roller cone pilot bit. These assemblies are retrieved with a wireline at the casing

point or at any point in the drilling process when there is a need to change drilling tools. Use

of a retrievable system is the only practical choice for directional wells because of the need to

recover the expensive directional drilling and guidance tools, the need to have the capability

to replace failed equipment before reaching casing point, and the need for quick and cost

effective access to the formations below the casing shoe.

The retrievable Casing Drilling BHA normally consists of a pilot bit with an underreamer

located above it to open the hole to the final wellbore diameter. The pilot bit is sized to pass

through the casing and the underreamer opens the hole to the size that is normally drilled to

run casing. For example, an 8-1/2 pilot bit and 12-1/4 underreamer may be used while

drilling with 9-5/8 36 ppf casing.

The retrievable drilling assembly is attached to the bottom of the casing with a special tool,

shown in Fig. 1 and referred to as the Drill-Lock-Assembly (DLA).

The DLA provides the ability to connect conventional drilling tools with rotary-shouldered

connections to the casing and facilitates running these tools in and out of the casing. It has a

relatively large, full open bore to minimize pressure losses and to facilitate any wireline

operations that might be needed for the drilling BHA suspended below the DLA.

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The retrievable BHA is attached to the casing with the DLA which axially and torsionally

locks and un-locks to the casing, seals in the casing to direct the drilling fluid through the bit,

locates the DLA in the profile without relying on precise wireline measurements, and

bypasses fluid around the tools for running and retrieving. The BHA can be run and retrieved

in deviated wells with inclinations higher than 90o and the DLA can be released with a pump

down dart before running the wireline. A releasing and pulling tool is run on wireline to

release the DLA and pull the BHA out of the casing in a single trip for vertical and low angle

wells. The wireline retrieval system can be used with 13-3/8 and smaller tools, while a drill

pipe running/retrieval option is also available for all of the tools for use in special situations.

Fig 5.1: Drill Lock assembly (DLA)

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Fig 5.2: Wireline retrievable BHA

5.2 Casing Drilling Accessories

1. Underreamers The Casing Drilling system requires that a hole enlarging tool be runbelow the casing to drill a hole large enough to provide normal circulation around the

casing. The feature of Underreamers include the assurance of smooth rotation,

minimising the possibility of leaving the parts in the hole and assuring that it get

closed when being retrieved.

Fig 5.3: Casing drilling underreamer

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2. Connections - Connections that are used in Casing While drilling have an adequateaxial load rating. Sufficient fatigue tolerance and adequate torque carrying capacity.

Multi-lobe torque ring could be inserted into buttress box for increased torque

capacity. The use of Casing Drive System reduces the risk of damaging and failure of

connections.

3. Wear Bands The Casing coupling wear generally causes by angular misalignmentof joints of casing at coupling. For protecting Casing with these wears, a wear band

is installed on casing immediately downhole of the coupling. The lower end of the

wear bands include tungsten-carbide hard facing material similar to that used for the

wear protection of drill pipe.

Fig 5.4: Wear Band

4. Centralizer or Stabilizer The main criteria for a casing drilling centralizer is that it iseconomical, rugged enough to withstand drilling forces, and it can be attached to the

casing without altering the casing performance. A centralizer with blades hydro-

formed directly on a tubular body was developed as an effective wears of centralising

the casing while drilling with it.

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Fig 5.5: Hydro formed crimp-on Stabiliser.

5. Cementing Equipment Once the retrievable drilling assembly is removed from thecasing at the casing point, there is no float equipment in place to prevent back flow of

the cement job is completed. In some cases this has been handled by holding pressure

on the casing after the cement is pumped until it is begins to set up. In other cases, a

relatively expensive composite cement retainer is run and set with wireline. Neither of

these solutions is ideal and better suited cementing accessories are being developed.

5.3 Non-Retrievable BHA

Non-Retrievable Casing While Drilling has been popularised in recent years from

operators drilling top hole sections. The high value of this technology is in reduction

of well construction costs and problem resolution in reactive formations. A non

retrievable Casing While drilling bit, the Defyer, has been successful in avoiding lost

time in penetrating these trouble zones.

In this way of drilling, the BHA is cemented in place through conventional float valve

system without additional trip. The Casing drill bits centre is an aluminium alloy

crown that is drillable using any PDC or Roller cone bits selected for the next run.

This tool utilises Casing Drive tool engaging in the casing string and transmit the

rotary torque and weight to the BHA. The drillable drill bit is made up on the Casing

string and run to bottom. Drilling commences typically with light WOB (1 5 klbs)

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and slow rotary speed (40 60 RPM). Flow rate is typically one half to two thirds the

flow normally used for the respective hole size. After the pattern has been established,

operating parameters are adjusted to optimize performance. In most previous cases, an

RPM of less than 80 RPM has delivered excellent penetration rates. Weight on bit is

adjusted by the hardness of the formation. Normal weight on bit is typically between

what would normally be run on a conventional PDC bit and a roller cone bit in the

particular formation.

Fig 5.6: Non retrievable system

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Chapter 6: Casing Drive System

6.1 Introduction

The CDS, originally designed for Casing Drilling applications, attaches to the top drive API

threaded connection and grips the casing without attaching to the casing threads. As part of

the load path it provides tensile and rotational integrity between the top drive and the casing

and includes a fail-safe system to guard against inadvertent dropping of the string.

The CDS is hydraulically actuated using a standalone hydraulic power unit (HPU) with the

operator and controls positioned near the driller. The CDS accommodates pipe sizes from 20

in. down to 412-in. with working load capacities up to 500 tons, depending on casing size.

The Link Tilt attachment provides an automated method of picking up the casing from the V

door and conveying it up into the derrick. It provides the added benefit of holding the casing

in position as the driller lowers the CDS to grip the casing, eliminating the need for a stabber

and stabbing board. Hydraulically actuated single joint elevators attached to the Link Tilt

provide further automation, eliminating a man position for latching and unlatching the

elevator. This system of tools is not only effective but comes in a kit that is highly portable

and adapts to all top drives.

The Use of Casing as the rotational drive element to rotate the drill shoe or drill bit in situ has

revealed several limitations inherent in the structure of the casing as well as the

methodologies used to load and drive the casing:

1. The thread form used in casing connections is more fragile than the connections usedin drill pipe and the casing connection has to remain fluid and pressure tight once the

drilling process has been completed.

2. Casing typically has a thinner wall and is less robust than the drill pipe, especially inthe thread are at both ends of the casing where there is a corresponding reduction in

the section area.

3. Casing is not manufactured or supplied to the same tolerances as the drill string andthus the actual diameters and the wall thickness may vary from lot to lot of casing.

Despite these limitations the casing is being used to drill bore holes effectively.

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Fig 6.1 Casing Drive System

6.2 Description of the Casing Drive System

Hence mentioned Casing running and driving system includes a spear or a grapple tool and a

clamping head integral to a top drive. In one embodiment, the axial load of tubular lengths

being added to a tubular string is held by the spear at least during drilling and the torsional

load is supplied by the clamping head at least during makeup And thereafter by the spear ,

and alternatively by the spear and/or the clamping head. The clamping head assembly may

also be used to position a tubular below the spear. In order to enable cooperative engagement

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of the clamping tool and spear such that the spear inserted into the tubular and the clamping

head are mechanically engaged with one another so that torque from the top drive can be

imparted to the tubular through the clamping head. Additionally, a casing collar and the

clamping head have external support functions to minimize the risk of deforming the tubular

when the spear engages the inner diameter of the Tubular.

The spear imparts rotary motion to the tubular forming a drill string, in particular where the

tubular are casing. A thickness compensation element is provided to enable the spear to load

against the interior of the tubular without risk of deforming the tubular.

The CDS includes a top drive suspended on a drilling rig above a borehole, a grappletool or a spear for engagement with interior of tubular such as casing and a clamping

head engage able with the exterior of the casing.

The clamping head mounts on a pair of mechanical bails suspended from a pair ofswivels disposed on the top drive.

The bails are generally linear segments having axial, longitudinally disposed slotstherein. A pair of guides extends from the clamping heads into the slots and provides

support for the clamping head.

As shown in the Figure the 6.1 pair of guides rest against the base of the slots whenthe clamping head is in a relaxed position. The guides are adapted to allow the

clamping head to pivot relative to the bails.

Bails include a pair of bail swivel cylinders connected between the bails and the topdrive to swing the bails about the pivot point located at the swivels. The bail swivel

cylinders may be hydraulic cylinders or any suitable type of fluid operated extendable

and retractable cylinders.

Upon such swinging motion, the clamping head likewise swings to the side of theconnection location and into alignment for accepting and retrieving the casing that is

to be added to the string of casing in the borehole.

The spear couples to the drive shaft of the top drive and is positioned between thebails and above the clamping head when the clamping head is in the relaxed position.

During the makeup and drilling operations the clamping head changes its position

such that the spear is in alignment with the casing; the spear then enters into the open

end of the casing located within the clamping head.

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Fig 6.2Partial cross sectional views of Spear.

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6.3 Description of the Spear (in fig 6.2)

The Spear includes a housing defining a piston cavity and a cup shaped engagementmember for engagement with clamping head.

A piston disposed within the piston capacity and actuatable therein to in response to apressure differential existing between opposed sides thereof.

A plurality of slips disposed circumferentially about the mandrel and supported inplace by slip engagement extension and connector.

The Spear enables controlled movement of the slips in the radial direction from andtowards the mandrel in order to provide controllable loading of the slips against the

interior of the casing.

The mandrel defines a generally cylindrical member having an integral mud flowpassage there through and a plurality of conical sections around which the slips are

disposed.

A tapered portion at the lower end of the mandrel guides the spear during insertioninto the casing.

An aperture forms the end of the mud flow passage such that mud and other drillingfluid may be flowed into the hollow interior or the bore of the casing for cooling the

drill shoe and carrying the cuttings from the drilling face back to the surface through

the annulus existing between the casing and the borehole during drilling.

The spear includes an annular sealing member such as a cap seal disposed on theouter surface of the mandrel between the lowermost conical section and the tapered

portion. The annular sealing member enables the fluid to be pumped into the bore of

the casing without coming out of the top of the casing.

6.4 Description and Actuation of Slips

Each of the slips includes a generally carved face forming a discrete arc of thecylinder such that the collection of slips disposed about the mandrel forms a cylinder.

Slips also include on its outer arcuate face a plurality of engaging members which incombination serve to engage against and hold the casing or other tubular when the top

drive is engaged to drill with casing.

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The position of the slips relative to the conical sections on the mandrel is directlypositioned by the location of the piston on the piston cavity.

The Slips also include a plurality of inwardly sloping ramps on their interior surfacesthat are discretely spaced along the inner face of the slips at the same spacing existing

between the conical sections on the mandrel.

In a fully retracted position of the slips, the greatest diameters of the conical sectionsare received at the minimum extensions of the ramps from the inner face of the slips

and the minimum extension of the conical sections from the surface of the mandrel

are positioned to the greatest inward extension of the ramps.

To actuate the slips outwardly and engage the inner face of a section of the casing, thepiston moves downwardly in the piston cavity, thereby causing the ramps of the slips

to slide along the conical sections of the mandrel thereby pushing the slips radially

outwardly in the direction of the casing wall to grip the casing.

6.5 Casing Running Process

Individual joints of casing are positioned in either the V-door or pick-up machine inconventional manner. As the drillers lowers the block to run a joint that has just been

made up, the operator manipulates the single-joint elevator-link tilt to position the

elevators to catch the next joint of casing in the V-door.

Then the driller remotely latches the elevators on the new joint from the operatorsconsole. These elevators open wide enough and have sufficient power to latch onto

the casing even if it is not in line with the elevator.

The drive tool is relieved from the stump in the rotary table and the next joint to berun is hoisted as the driller runs the blocks up the derrick.

Once the joint is raised sufficiently, the casing running operator rotates the link tilt toswing the new joint of casing over the stump in the rotary table. The pin end of the

rotary table is usually tailed into the well center by a rope in the conventional manner.

The pipe protector is removed and the joint is doped and stabbed into the stump box.Then the tool is lowered into the top of the joint, and the running tool slips are

activated.

The link tilt and elevators include features that facilitate holding and positioning theupper end of the casing correctly for the drive tool to be stabbed easily and aligning

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the casing with the stump in the slips. The feature is more effective than a human

stabber and eliminates the need for a person to work in the derrick.

The joint is then made up with the top drive to the appropriate torque. Rotation for theentire process is applied smoothly with the top drive to makeup the casing without

creating bending forces at the threads.

Torque/Turn measurements can be made and recorded, if desired, by the operator.The Stump can be restrained from rotation by power slips or by tongs until sufficient

weight (approximately 10 joints) is run so that conventional slips provide adequate

torque restraint.

Only two people are required to rig up the equipment and operate it during a casingrunning job. Once the equipment is rigged up, the operators take turns operating the

controls to stay alert and attentive to the repetitive casing running process.

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Chapter 7: Drill Bits

7.1 Introduction

When casing is used as the drill string, any downhole equipment has to be removed as an

obstacle from the interior of the casing before the next smaller diameter casing and drill bit is

sent to further drill the borehole.

There are two mainstream Casing While Drilling (CWD) used in the industry, namely,

retrievable and non-retrievable systems, sometimes referred to as the latch system and cement

in place system respectively. The latch system as the name indicates locks the bottom holeassembly (BHA) to the end of the first casing string that goes into the borehole. When the

desired casing depth is reached, the BHA is retrieved by a wireline to the surface. And the

drilled depth is cemented. This system uses conventional drill bits as there is no special task

for the drill bit to carry out. The rotary motion to the drill bit is supplied by either a top drive

assembly or a motor attached to the bottom hole assembly.

The other method is the cement in place method, in this method the drill bit is left in the

bottom hole and a second drill bit drills through it and continues drilling further into the

formation.

The main qualities expected from this kind of drill bits are that they should be drillable and

durable. Achieving both these conditions is a very difficult and complex task. There is always

a tradeoff between the two, if the drill bit is drillable and a soft material is used to

manufacture the drill bit, the drill bit will wear out very quickly as the formation grinds

against the body of the drill bit. On the other hand, if a drill bit is designed to be durable;

drilling through it to continue further drilling into the formation becomes a difficult task. The

drill out bit that is used will wear out while drilling a harder, more durable bit and will have

to be replaced by another bit, making this a costly method, and negating the economic

benefits of the CWD process.

To balance these two requirements of drillable and durable bit, a few bit designs have been

suggested and implemented in the industry. One design is as follows; an aluminum body with

displaceable PDC cutting structures, this design is widely used.

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7.2 Drillable Drill Bit Design

7.2.1 Body Portion

Fig7.1 describes the body of a CWD drill bit, the structure of the drill bit and its various parts

are described in the figure. A detailed explanation of the various parts and their uses is given

below.

A drillable body portion is attached to the casing shoe, this drillable material isnormally an aluminium alloy, over this body potion there are several cutting

structures or blades that are fixed to the body in the notches that are incorporated in

the design of the body portion. The body portion consists of a main counter bore, which generally ends at a conically

concave base from which a mud bore extends inwardly into the backup portion of the

body portion which limits the deformation of the drilling sleeve during drilling

operations. The mud bore splits into a plurality of mud passages, which terminate at

the lower portion of the body portion. The mud bore also consists of a tapered seat

section, into which a ball may be seated.

The outer surface of the body portion consists of right circular outer face, and an end

portion which is profiled and machined to receive a portion of the blades.

The outer face of the body includes, at the opening of the counterbore, an extendinglip, which sealingly or substantially closely fits to the major diameter of the major

diameter bore, as well as at least one axial slot extending along the outer face from the

end portion.

A pin is secured within the sleeve and extends into the slot and serves to prevent therotation of the body portion when another drill bit is used to drill out the body portion

of the drill bit in use.

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Fig 7.1 Interior of body portion of CWD bit

7.2.1.1 Blade and Cutters Structure

The cutters are configured on blades and attached to the surface of the body portionby notches.

The base of the blades consists of projections and slots to fix the blade to the surfaceof the notch. The projections and slots also help in maintaining the blade in the notch

by not allowing the blade to move when the cutters come in contact with the

formation and the drilling procedure begins.

Generally, the blades are received within a profile which extends along the outersurface of the sleeve and the base of the body portion. An exemplary profile is a

notch which is configured to interact with the blade to keep the blade in position on

the bit during drilling operations.

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Each blade is made of a single length of steel, or similar material having theproperties of high strength, rigidity and ductility, it is bent to form opposed first and

second linear section which are interconnected by curved shoulder segment. A no. of

cutters is located on the outer surface of the blades, to be engaged with, and cut into

the formation to be drilled.

Fig 7.2 OUTER SURFACE OF CWD RILL BIT

7.2.1.2 Forces Acting On Blades and Cutters during Drilling Operations

When the drilling operation begins and the drill bit moves along an axis, the bladesengage with the formation by an outward movement. There is a force being subjected

on the blade by the formation, which pushes the blade inwards, this force tends to

cause the blade to rotate within the notch.

The configuration of the multifaceted base of the blade and the notch are specificallydesigned to counter these forces and to keep the blade in place within the notch.

As the loading occurs, the sidewall of the blade is pushed against the side face of thenotch, the first face of the projection on the notch bears against the adjacent flanks of

the slot on the blade to provide lateral support against the primary load of the

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formation, simultaneously, the face of the projection on the inside of the notch, bears

against the coupled moment due to the loading of the blade at the cutters, against the

second projection face of the blade, and each of the faces of the blade are loaded with

the moment against their respective compression faces on the notch, which prevent

the movement of the blade within the notch.

Fig 7.3 Components of the blade

The blade geometry, in addition to the blade profile, helps in maintaining the blade onthe sleeve.

During the drilling operation, the entire length is never engaged with the formation,specific parts of the first and second linear section are engaged at particular instants of

time.

The standoffs on the sleeve of the drill shoe, allows the cutters on the first linearsection of the blade to penetrate the formation to a certain extent. When the drill bit is

pushing against the bottom of the borehole, the secondary section will be engaged

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with the formation and other sections may not be engaged. Thus, the forces will be

imparted on the second linear section of the blade, tending the blade to tip in the

notch. To prevent this from happening, the included angle of the blade, as shown in

the above figure is kept less than 90o, also the first linear section and the shoulder

segment act as levers and prevent the second linear section from tipping in the notch.

7.2.2 Drill-out, drill ahead

The smaller, conventional bit used for drill-out must not sustain significant damagethat would compromise continued drilling. A damaged drill-out bit can reduce ROP in

the next hole section, or may have to be tripped and replaced.

Damage to the drill-out bit is a particular issue when using a conventional PDC casing

bit. In addition to the problematic brittleness of PDC cutters, damage can occur when

the cutters chemically react with the iron at high temperatures and revert to graphite.

The balance between durability and drillability has been sought with two basicdesigns: an aluminium bit with a displaceable PDC cutting structure mounted on steel

blades, and a steel alloy bit with a fixed PDC cutting structure.

Both designs have limitations. Aluminium CWD bits, which displace the cuttingstructure by pressuring up on a dropped ball and leave only an aluminium plug to be

drilled out, are complex, expensive, and limited to formations under 15,000 psi UCS.

Steel alloy CWD bits are fundamentally a conventional steel-bodied bit designmodified to be somewhat drillable. These bits depend on the strength of the steel to

reduce the amount required in the drill-out path. Because they are single-piece steel

alloy bodies with no moving parts they are easy to manufacture. But they still have a

significant amount of steel in the drill-out path.

7.3 Prototype Development

Several key design requirements were addressed when developing the subject CWD bit.

Full PDC cutting structure with the ability to drill long intervals in hard, abrasive

formations

Fixed, non-displaceable cutting structure

Sufficient blade stand-off to limit potential for bit balling when drilling sticky shale/clay

formations

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Must be easily drillable with any conventional PDC or roller cone bit, without the need

for a custom drill-out bit

Field replaceable, drillable nozzles.

The position of each PDC cutter is optimized to provide an even wear distribution over

critical areas of the bit. The blade count and cutter size can be tailored to drill specific

intervals and formation types. Wear rate models are used to help ensure that the cutting

structure is capable of drilling the required interval, without adding excessive cutters

inside the drillout path.

The resulting Casing while Drilling bit is shown in Figure 6. This tool incorporates a

full PDC cutting structure which is brazed to steel rails (one rail for each blade of thebit). The thickness of the steel rails is sufficient to retain the PDC cutters during drilling

operations, while keeping the amount of steel in the drill-out path to a minimum. The

nose and blades of the CWD bit are manufactured from a drillable aluminium alloy.

The steel rails and PDC cutters are mechanically locked to the aluminium blades. This

provides a rigid support structure, enabling the blades to drill hard formations, without

hindering the drill-out process.

The PDC cutters and rails are supported by drillable aluminium blades, as opposed to

steel alloy blades. Because of this, the amount of blade stand-off can be increased to aid

in cuttings removal, without the negatively affecting drill-out performance. This feature

can be very beneficial when trying to limit the potential for bit balling in clay/shale

formations.

The aluminum surfaces are protected with a high velocity oxy-fuel (HVOF) tungsten

carbide coating to limit fluid erosion. This relatively simple, but rigid design has only a

small amount of steel in the drill-out path. As a result, it can be easily drilled-out with

any conventional PDC or roller cone bit. Laboratory and field testing has shown only

minimal damage imparted to the PDC cutting structure of the drill-out bit after drilling

through the subject casing bit.

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Fig 7.4: Prototype Design for PDC Drillout Bit

7.4 Lab testing, field trialsLaboratory and field testing has shown good ROP and minimal damage to the PDC

cutting structure of the drill-out bit after drilling through the subject casing bit.

A drill-out test was conducted from a test rig to evaluate performance of a 13 3/8 x 16-

in. prototype bit with four blades and 16-mm (0.63-in.) PDC cutting structure and using

a conventional PDC bit. The unworn DPA prototype was drilled out in 15 min without

significant damage to the drill-out bit.

Successful testing led to field trials in Malaysia where the operator had extensive CWD

experience with steel alloy casing bits. In these applications, the PDC drill-out bits

exhibited severe wear after drilling through the CWD bit and the following interval of

medium soft formations inter-bedded with hard stringers.

Drilling out the shoe track, steel alloy casing bit, and new formation typically required

one PDC bit per trip. An easier, less-damaging drill out was sought.

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For the CWD bit run, a total 41 casing joints were drilled for 341.5 m (1,120.4 ft) to the

planned depth of 497.5 m (1,632.2 ft). The DPA bit was rotated 6.56 hours for an

average on-bottom ROP of 48.4 m/hr (158.8 ft/hr) for the entire interval, including the

hard stringers. The high ROP indicates the PDC cutting structure remained sharp, even

after drilling out the 20-in. shoe track and a previously cemented 20-in. casing bit.

A conventional PDC bit was used to drill out the 13-3/8 in. shoe track and the drillable

casing bit. It then continued drilling 1,488.5 m (4,883.5 ft) of new formation at an

acceptable ROP.

The CWD bit took only 12 min to drill out. Aluminium and steel shavings from the

casing bit were collected from the shale shakers but no PDC cutters were found. It issuspected that the PDC cutters from the drillable bit were either pushed into the

borehole wall or were fractured into smaller pieces and circulated to surface.

Two additional wells were drilled with the same bit design and they achieved even

higher ROP. The DPA bits averaged an overall ROP of 59 m/hr (193.5 ft/hr) or 52%

higher than the average 39 m/hr (128 ft/hr) ROP achieved with steel alloy CWD bits.

Normalizing the performances of both bit types more than 400 m (1,312 ft) shows the

new bit design saved 3.5 hoursequivalent to $35,000 on $240,000 rig spread cost.

7.5 Drill-out Performance Comparison

Ease of drill-out is one of the most sought after properties of any non-retrievable casingbit. Important factors to evaluate are: the time required to drill through the cemented

CWD bit, the dull condition of the drill-out bit, and the size of the debris from the

CWD bit.

The drillable design provides for exceptionally fast drill-out times in the region of 10minutes, using conventional oilfield PDC bits.

There is no need for a specialized/custom PDC drill-out bit, as is evidenced by the gooddull grade condition of the drill-out bits. To date, only one of the new, drillable CWD

designs has been drilled-out with a roller cone bit.

Although seemingly lacklustre compared to PDC drill-out time, the 110 minute drill-out time is significantly faster than the average 192 minutes required to drill through a

steel alloy CWD bit with a roller cone bit. The size of the debris recovered from the

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new CWD bit was generally small and in no occasion has caused drilling issues in the

next hole section.

7.6 Conclusions

Conventional PDC drill-out bits can sustain severe cutter damage when drilling througha steel alloy CWD bit. The damaged cutting structure can result in poor drilling

performance when drilling subsequent hole sections.

Minimizing the amount of ferrous (steel alloy) and PDC material in the drill-out pathsignificantly reduces the amount of time required to drill through the casing bit. In

addition, less damage is imparted to the drill-out bit.

The newly developed drillable PDC CWD bit provides comparable or better drillingperformance than steel alloy CWD bits used in offset wells.

The subject drillable PDC casing bit can be quickly drilled-out with a conventionalPDC bit in less than 15 minutes.

After drilling through the subject CWD bit, only minimal damage was imparted to thedrill-out bit. There is no requirement for a specialized drill-out bit or a dedicated drill-

out / mill-out run.

The newly designed casing bit can also be drilled out with a conventional roller conebit; however PDC drill-out times are significantly faster.

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Chapter 8: Plastering Effect

8.1 Introduction:-

Particulate lost circulation material (LCM) effectively prevents fluid loss to the formation.

With Casing Drilling, it is possible to drill through low pressure permeable formations with

reduced mud loss and minimized usage of particulate LCM.

The Casing Drilling process grinds drill cuttings as they travel up the annulus andcreates a larger particle size distribution (PSD) profile than conventional drilling

operations.

These finer cuttings are subsequently smeared into the wellbore face by themechanical contact of the large diameter casing with the borehole wall.

The result is a very high quality, tight, thin, almost impermeable mud cake thatisolates the formation from the wellbore.

The PSD analysis reveals that the smaller size and wide range of Casing Drilling cuttings

make it possible for these particles to readily adhere to the wellbore;

This helps seal the pore spaces of the formation and Prevent further solids and filtrate invasion.

Pore throats can most effectively be plugged when the cuttings are in the proper micron size

range as any possible gap between the mud and cuttings PSD can be covered by adding

minimal amounts of properly sized lost circulation materials.

Casing Drilling has proven to be a unique approach in tackling formation damage due to the

drilling process.

The qualitative and quantitative analysis of plastering effect will be discussed in further

chapters.

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Chapter 9: Cementing

9.1 Introduction

Casing while drilling (CWD) is an emerging technology being introduced in different areas

around the world. This new configuration, where the casing is used as a drillstring, presents

new challenges for primary casing cementing operations compared to the conventional

cementing operations. A full understanding of the required changes of the cementing

methodology from conventional drillpipe drilling operations can contribute to the success of

any CWD campaign.

CWD cementing differs from conventional cementing practices because it is impossible to

use standard centralizers attached to the casing while drilling because of extended and faster

casing rotation. When more than one bit is required to reach the next casing point, CWD

requires full-bore casing access to pull and run bottomhole assemblies (BHA) through the

casing. In these instances, conventional floating equipment cannot be used. Wireline logging

is normally conducted in cased hole after the cementing job. The cement volumes are

calculated with a cement excess factor instead of a caliper log.

9.2 CWD differs from conventional cementing practices in several ways.

1. The use of casing attachments, such as centralizers, to provide good pipe standoff.During CWD operations, centralizers are required to be robust enough to drill the

entire openhole section while withstanding the pipe rotation when drilling for

extended periods of time. This\ casing hardware must keep its standoff capability

while staying in place and in one piece.

2. The float equipment is different than that used in conventional cementing operations.Where the possibility exists for more than one bit to reach the next casing point, CWD

must allow full-bore casing access. To pull and run BHAs with wireline instead of

pulling out the complete casing string by single joints, this full-bore access is

required. In such cases, the float equipment is installed once the casing reaches thecasing setting depth.

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3. When installing the floating equipment with casing on bottom, the float equipmentwill be exposed to high circulation rates for considerable time while drilling the entire

hole section. Damage to the floating valves can be expected.

4. The cement volume for the surface, intermediate, and production casing jobs isestimated using a cement excess value. In CWD, wireline logging for formation

evaluation is often conducted in cased hole after the cementing job, so caliper log

information is not available. If caliper hole size or openhole evaluation is required, it

may be obtained with normal openhole logging equipment once the casing is pulled

out of the previous shoe

9.3 Centralization in CWD

In CWD operations, standard bowspring or welded-body centralizers are not recommended.

The casing string will be subjected to longer and faster rotation while drilling the entire

openhole section, and standard centralizers are not suitable for these conditions. They may

cause severe wear damage and may lose their original placement, decreasing pipe

centralization. In addition, these standard centralizers attached to the casing can be lost in the

hole, causing additional problems when drilling ahead.

In CWD, there is no option to place any type of centralizers with an OD larger than the gauge

hole size. Bow- type centralizers are desirable where washouts are expected because they

provide restoring force to centralize the casing in the hole. The bows on this type of

centralizer have lower resistance to casing rotation. A good mud system is essential to

minimize the hole washouts. If washouts are unavoidable, the reduced pipe standoff should

be compensated by enforcing other best cementing practices, such as providing good mud

properties, pumping rates, spacer design, etc.

9.4 Floating Equipments used in cementing in CWD

The use of standard floating equipment installed when the casing string is run will not be

suitable when using retrievable CWD tools due to the requirement for full casing-bore access.

After pulling the BHA at TD, the casing is now ready to set float equipment. The float

equipment needs to be easy and fast to set, and it must be reliable and easy to drill out.

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In this operation, the advantage of installing the floating device just before the cementing job

is to help prevent the potential erosion and failure of the floating valves during the 3-7 days

of drilling while maintaining the option of retrieving the BHA via wireline. This floating

assembly cement retainer packer is normally set in the middle of the second joint to provide a

shoe track volume.

The cementing wiper plugs are the same as used in conventional cementing jobs and the

bottom and top plug will land on top of the floating assembly. When cementing

intermediate casing, the plugs are released on the fly with cement on top to facilitate the

drillout process. For the 4 -in. casing, the lines are washed clean before displacement, and

the plugs will not be drilled out.

A relatively new approach to install float equipment when using CWD has been the

development of a pumpdown float. The pumpdown float is preinstalled into a pup joint of

casing, then made up to the string on surface. It is then pumped down the casing string, where

it will locate and land in a profile nipple placed in the casing string close to the end of the

casing. Though this tool is available, it has not had enough runs to be proven reliable.

9.5 Cement excess for casing while drilling

When openhole logs are not required in the production hole, evaluation logs could be

performed on cased hole. This method is used to save the involved time to trip the casing in

and out to the previous casing shoe by casing singles. Under these circumstances, caliper log

information is normally missing for the calculation of the cement volumes. The cement

excess factor has been defined from offset wells drilled conventionally with drill pipe where

caliper logs are normally available. The cement excess factor has been verified by the top of

cement on the CBL log runs to evaluate the zonal isolation.

For the surface or intermediate casing cement volumes, the cement excess factor is defined

with the same experience factor used for any DP drilling operation. The use of oil-based mud

on the production hole section contributes to the improved hole geometry, and minimum

wash out are normally observed. This factor will help on the casing standoff considering the

lack of bow-type centralizers. If the cement excess needs to be defined or verified, fluid

markers or liquid calipers can be considered

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9.6 Other Best Cementing Practices for Casing while Drilling

Most of the best cementing practices do not differ from conventional drilling and CWD once

the casing is on bottom and ready to cement. Spacers and flushes are effective displacement

aids because they separate, unlike fluids, such as cement and drilling fluid, and enhance the

removal of gelled mud, allowing a better cement bond. Spacers can be designed to serve

various needs.

Compatibility of the drilling fluid/spacer interface as well as the compatibility of the

spacer/cement slurry is of prime importance. There are no additional considerations for

spacers for CWD as compared to conventional cementing operations, such as mud erodability

or removal capacity, contact time, spacing between mud and cement, compatibility with the

drilling fluid, and density.

Similar to cementing wells drilled conventionally, the condition of the drilling fluid is one of

the most important variables in achieving good displacement during a cement job. A fluid

that has excellent properties for tripping and running casing is generally inappropriate for

cementing purposes. Low rheology and gel strength is always desirable for cementing. CWD

reduces the total amount of static time for the mud in the annulus because there is no tripping

time to pull out of the hole with the drilling string, and the casing is already on bottom when

TD is reached. The best fluid for cementing is already in the hole with no additional

circulating and conditioning time needed. CWD potentially reduces the amounts of gelled

mud in the hole before cementing.

Decreasing the filtrate loss into a permeable zone enhances the creation of a thin filter cake.

A high fluid loss creates a thick, highly gelled mud layer immediately adjacent to the

formation wall that is difficult to remove without mechanical or chemical intervention. The

fluid loss of the mud should be minimized before running casing and cementing.

At last the major factors contributing the success on the cementing operations are:

1. Proper centralization is obtained using helical and hardface blade centralizers,withstanding the longer and faster casing rotation while drilling the entire open hole

section.

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2. The crimping process has provided a strong attachment of the centralizer to the bodyof the casing capable of keeping the original placement even under high-torque

situations.

3. The modifications on the cement-retainer packer designs have provided a suitableoption for CWD operations, allowing the retrieval of the BHA and reducing the

exposure of the floating valve to the drilling mud and reducing the risk of failure.

4. The cement volumes are normally defined by cement excess factor over gauge holesize because caliper log information is not frequently available. The cement excess

has been well defined by the caliper log information and the identified top of cement

on the offset wells.

The zero free water and low fluid loss cement designs for the 4 -in. production casing jobs

have been successfully pumped through the bit nozzles, and there have been no indications of

cement dehydration on the performed jobs.

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Chapter 10: Downhole Problems and Solutions

10.1Mechanical Problems:10.1.1 Casing Thread Damage

Casing threads are typically finer and more delicate than tool joint threads. Casing

threads are cut on relatively thin walled tubulars, relative to drillpipe, and are required to

carry large axial loads. Upset pipe ends increase connection costs and reduce annular

clearance, therefore most high capacity casing connections use a low profile, short pitch

thread with a low angle load flank. As a result, casing threads are generally finer than drillpipe threads. These factors make casing threads more susceptible to damage than drill pipe

threads, particularly during initial engagement. Even if threads are not damaged during

engagement, casing connections are less durable than drill pipe connections. The most

obvious is wear and damage resulting from engagement with a crossover sub between the

top drive and casing thread. Transferring full make-up torque through the casing thread

effectively applies one make/ break cycle to the connection before it reaches the rig floor.

Even if crossover thread interference is reduced to minimize sliding distance under load,

substantial thread contact loads are required for torque transfer. Crossover thread damage is

transferred to the casing thread, thereby reducing thread durability and increasing the chance

of making a bad connection.

The second damage mechanism occurs at the point of initial thread engagement. Casing

threads are most vulnerable to damage at this point because misalignment causes localized

contact between pin and box thread corners (the transition from crest to flank) to contact,

as shown in Figure 1.

The third common source of casing thread damage occurs when threads are engaged

and rotated while misaligned. Although contact stress is reduced when thread flanks are

engaged, the combination of stress and sliding distance is sufficient to induce thread

damage, as in fig 2.

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Fig 10.1: Thread corner contact Fig10.2: Premium connection threads and sealdamage

Solutions for Casing Thread Damage

Casing thread damage is best managed by minimizing externally applied loads.

Stabbing loads, side loads and bending, particularly during initial thread engagement, are the

most common causes of thread damage. These loads can be effectively managed with

equipment that provides freedom of movement where necessary and isolates casing threads

from stabbing loads.

Casing thread loads can be relieved either by careful alignment or providing freedom

for the top of the pipe to move off the top drive axis. This allows pin and box thread axis to

self-align as controlled stabbing loads are applied. Bending loads resulting from rig

misalignment and out-of-straight pipe are effectively managed in this manner.

Side loads resulting from off-axis torque transfer are near-zero when casing threads are

initially engaged because applied torque is very small. These side loads become large only

when threads are fully engaged and make-up torque becomes large. Fully engaged threads

are well suited to reacting side loads without incurring damage.

10.1.2 Make-Up Monitoring and ControlCasing connections must be made up to an appropriate degree to ensure structural

integrity and seal ability consistent with the design intent. Makeup specification varies

between connections. Most premium connections utilize a sealing mechanism that depends

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on precise damage free engagement of the pin and box for maximum seal reliability.

Premium connection make up must therefore be performed with care and strict adherence to

specified procedures.

10.1.2.1 Monitoring

Premium connection makeup is typically monitored and recorded to detect damage and

create a record documenting final assembly of each connection. This documentation serves

two primary purposes: verification of connection make-up and demonstration of compliance

with recommended practices. Measurement of applied torque, connection rotation or turns

and time are the most common recorded parameters.

10.1.2.2 Control

The physical process of connection make-up must be controlled within acceptable

limits to minimize the chance of inducing damage. Galling of mating surfaces is the primary

source of connection damage and is affected by several factors controllable at the field

level. Some are well known, but others are taken for granted in conventional casing running

operations and if ignored, reduce the chance of success.

Well-known parameters that must be controlled during connection make-up are:

Connection cleaning and lubrication;

Rotation speed and,

Applied torque.

The first two parameters are easily satisfied during top drive casing running operations,

but control of applied torque is a more complex challenge. Cleaning and lubrication ensure

analysis, comparison and application of cwd against conventional drilling operations

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