50
CONFIDENTIALITY This manual section is a confidential document which must not be copied in whole or in part or discussed with anyone outside the Schlumberger organization. COILED TUBING DRILLING Contents Contents Page Page 1 EVOLUTION OF CTD ................................. 2 1.1 Advantages of CTD .......................... 2 1.1.1 Safety 1.1.2 Economic ................................ 2 1.1.3 Operational ............................. 3 1.1.4 Environmental ......................... 3 1.2 Limitations and Disadvantages ......... 3 1.3 CTD Applications .............................. 4 2 JOB DESIGN AND PREPARATION ........... 5 2.1 Establishing Objectives ..................... 5 2.2 Technical Feasibility .......................... 4 2.2.1 Weight on Bit .......................... 4 2.2.2 Annular Velocity ...................... 13 2.2.3 Pump Pressure and Rate ........ 13 2.2.4 CT String Tension ................... 13 2.2.5 Torque .................................... 13 2.2.6 CT Life and Fatigue ................ 15 2.2.7 CT Reel Handling .................... 15 2.2.8 Directional Requirements ........ 15 2.3 CTD Project Preparation ................... 15 2.3.1 Technical Preparation ............. 16 2.3.2 Basic Equipment and Services 16 2.3.3 Procedures and Plans ............. 16 2.3.4 Drawings and Diagrams .......... 17 2.3.5 Personnel ................................ 17 2.3.6 Administrative Preparation ...... 17 3 EXECUTION ............................................... 18 3.1 Well Pressure Control (Overbalanced Drilling) ..................... 18 3.2 Conventional Sidetracking ................ 18 3.2.1 Well Preparation ..................... 18 3.2.2 Setting the Whipstock ............. 19 3.2.3 Window Milling ........................ 20 3.3 Thru-tubing Reentry .......................... 20 3.3.1 Well Preparation ..................... 21 3.3.2 Tubing Whipstock ................... 21 3.3.3 Thru-tubing Whipstock ............ 22 3.3.4 Cement Kick-off Techniques ... 22 3.4 Underbalanced Drilling ...................... 24 3.4.1 Definition and Objectives ........ 24 3.4.2 Creating Underbalance ........... 24 3.4.3 Controlling Underbalance ....... 25 3.4.4 Well Pressure Control ............. 26 3.4.5 Drilling Fluid ............................ 26 3.4.6 Wellbore Returns .................... 26 3.4.7 BHA Deployment .................... 27 3.4.8 Installing Completion Tubulars 27 3.5 Running Wellbore Tubulars .............. 28 4 SURFACE EQUIPMENT ............................. 29 4.1 Rigs and Structures for CTD ............. 29 4.1.1 CTD Substructures ................. 29 4.1.2 Location Requirements ........... 29 4.2 CT Equipment Package .................... 29 4.3 Well Pressure Control Equipment ..... 31 4.4 Kick Detection Equipment ................. 34 4.4.1 Flow Comparison .................... 34 4.4.2 Mud Tank Level Monitoring ..... 34 4.5 Mud System ...................................... 34 4.5.1 Mud Tanks .............................. 34 4.5.2 Mud Treatment Equipment ..... 36 4.6 Pumping Equipment .......................... 36 4.6.1 Low-pressure Equipment ........ 36 4.6.2 High-pressure Equipment ....... 36 4.7 Monitoring and Recording ................. 36 4.8 Pipe Handling Equipment ................. 37 4.9 Ancillary Surface Equipment ............. 37 4.10 Safety and Emergency Equipment ... 37 4.11 Equip. and Consumable Checklists .. 37 5 DOWNHOLE EQUIPMENT ......................... 41 5.1 Bits ..................................................... 41 5.1.1 Rock Bits ................................. 41 5.1.2 Drag Bits ................................. 41 5.2 Downhole Motors .............................. 42 5.2.1 Positive Displacement Motors . 42 5.3 CTD Downhole Equipment ............... 44 5.3.1 BHA for Vertical Wellbores ..... 44 5.3.2 BHA for Deviated Wellbores ... 46 5.4 Principal Directional Components ..... 46 5.5 Specialized CTD Tools ..................... 49 6 MANUFACTURERS AND SUPPLIERS ...... 50 Schlumberger Dowell COILED TUBING ENGINEERING MANUAL Rev A Section 1110 Page 1 of 50 October 1995

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Page 1: Coiled Tubing Engineering Manual

CONFIDENTIALITY

This manual section is a confidential document which must not be copied in whole or in part ordiscussed with anyone outside the Schlumberger organization.

COILED TUBING DRILLING

ContentsContents Page Page

1 EVOLUTION OF CTD ................................. 21.1 Advantages of CTD .......................... 2

1.1.1 Safety1.1.2 Economic ................................ 21.1.3 Operational ............................. 31.1.4 Environmental ......................... 3

1.2 Limitations and Disadvantages ......... 31.3 CTD Applications .............................. 4

2 JOB DESIGN AND PREPARATION ........... 52.1 Establishing Objectives ..................... 52.2 Technical Feasibility .......................... 4

2.2.1 Weight on Bit .......................... 42.2.2 Annular Velocity ...................... 132.2.3 Pump Pressure and Rate ........ 132.2.4 CT String Tension ................... 132.2.5 Torque .................................... 132.2.6 CT Life and Fatigue ................ 152.2.7 CT Reel Handling.................... 152.2.8 Directional Requirements ........ 15

2.3 CTD Project Preparation ................... 152.3.1 Technical Preparation ............. 162.3.2 Basic Equipment and Services 162.3.3 Procedures and Plans ............. 162.3.4 Drawings and Diagrams .......... 172.3.5 Personnel ................................ 172.3.6 Administrative Preparation ...... 17

3 EXECUTION ............................................... 183.1 Well Pressure Control

(Overbalanced Drilling) ..................... 183.2 Conventional Sidetracking ................ 18

3.2.1 Well Preparation ..................... 183.2.2 Setting the Whipstock ............. 193.2.3 Window Milling ........................ 20

3.3 Thru-tubing Reentry .......................... 203.3.1 Well Preparation ..................... 213.3.2 Tubing Whipstock ................... 213.3.3 Thru-tubing Whipstock ............ 223.3.4 Cement Kick-off Techniques ... 22

3.4 Underbalanced Drilling...................... 243.4.1 Definition and Objectives ........ 243.4.2 Creating Underbalance ........... 243.4.3 Controlling Underbalance ....... 253.4.4 Well Pressure Control ............. 263.4.5 Drilling Fluid ............................ 263.4.6 Wellbore Returns .................... 263.4.7 BHA Deployment .................... 273.4.8 Installing Completion Tubulars 27

3.5 Running Wellbore Tubulars .............. 284 SURFACE EQUIPMENT ............................. 29

4.1 Rigs and Structures for CTD ............. 294.1.1 CTD Substructures ................. 294.1.2 Location Requirements ........... 29

4.2 CT Equipment Package .................... 294.3 Well Pressure Control Equipment ..... 314.4 Kick Detection Equipment ................. 34

4.4.1 Flow Comparison .................... 344.4.2 Mud Tank Level Monitoring ..... 34

4.5 Mud System ...................................... 344.5.1 Mud Tanks .............................. 344.5.2 Mud Treatment Equipment ..... 36

4.6 Pumping Equipment.......................... 364.6.1 Low-pressure Equipment ........ 364.6.2 High-pressure Equipment ....... 36

4.7 Monitoring and Recording ................. 364.8 Pipe Handling Equipment ................. 374.9 Ancillary Surface Equipment ............. 374.10 Safety and Emergency Equipment ... 374.11 Equip. and Consumable Checklists .. 37

5 DOWNHOLE EQUIPMENT ......................... 415.1 Bits .....................................................41

5.1.1 Rock Bits ................................. 415.1.2 Drag Bits ................................. 41

5.2 Downhole Motors .............................. 425.2.1 Positive Displacement Motors . 42

5.3 CTD Downhole Equipment ............... 445.3.1 BHA for Vertical Wellbores ..... 445.3.2 BHA for Deviated Wellbores ... 46

5.4 Principal Directional Components ..... 465.5 Specialized CTD Tools ..................... 49

6 MANUFACTURERS AND SUPPLIERS ...... 50

SchlumbergerDowell

COILED TUBINGENGINEERING MANUAL

Rev A Section 1110

Page 1 of 50October 1995

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COILED TUBING ENGINEERING MANUALCOILED TUBING DRILLING Schlumberger

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DOWELL CONFIDENTIAL

Page 2 of 50 October 1995

Section 1110 Rev A

Well Status

Wellbore Trajectory

Well Preparation

Wellbore Conditions

Reentry New well or

Well finishing

Tubing/completion removed

Through tubing operation

Well deepening

(No directional control)

Side track (Directional control)

Underbalanced Overbalanced

Figure 1. Classification of CTD applications.

1 EVOLUTION OF COILED TUBING DRILLING

The techniques and equipment associated with coiledtubing drilling (CTD) have undergone rapid developementsince the first operations attempted in 1991. A principalstimulus for this activity was the availability of reliablelarge diameter CT which enabled sufficient hydraulichorsepower to be delivered downhole. This energy isrequired to power the downhole motor and providesufficient flow rate to ensure adequate hole cleaningthrough efficient cutting transport. In addition, larger andheavier wall tubing provides the necessary weight forefficient drilling and to safely withstand the torque andfatigue imposed by drilling operations.

In 1991 Dowell established a coiled tubing drilling taskforce to utilize the expertise of several organizationswithin the Schlumberger group. Engineers from Sedco-Forex (drilling), Anadrill (MWD) and Dowell (coiled tubing)formed a group dedicated to the engineering anddevelopment of CTD tools, equipment and practicesrequired to form an integrated CTD service package. Astep-by-step approach was adopted to ensure thatoperational capability was developed to support the newtools and equipment.

1.1 Advantages of CTD

The factors, or advantages, associated with CTD whichhave provided the impetus for the service developmentcan be categorized as shown below.

• safety

• economic

• operational

• environmental.

1.1.1 Safety

The configuration of the well control equipment used inCT operations provides a higher degree of control andsafety than that associated with conventional drillingequipment. This level of control is maintained throughoutdrilling and tripping operations. A large proportion ofaccidents are associated with pipe handling and themaking and breaking of tooljoints. With CTD, exposure tosuch hazards is much reduced.

1.1.2 Economic

Under the right conditions, CTD has the potential toprovide a general reduction in drilling and well costs.While this was a significant objective for early CTDattempts, it was seldom achieved due to the difficultieswhich are typically associated with an emergingtechnology.

The principal areas of cost saving in CTD are related tothe reduced hole size (slimhole) and wellsite area. Inaddition, CT units and equipment typically have lowermobilization and demobilization costs.

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SchlumbergerDowell

COILED TUBING ENGINEERING MANUALCOILED TUBING DRILLING

DOWELL CONFIDENTIAL

Section 1110Rev A

October 1995 Page 3 of 50

Figure 2. CTD operations 1991 through 1995 (est).

1.1.3 Operational

The safety advantage brought by CT well controlequipment enables underbalanced drilling operations tobe completed safely and efficiently. The principaladvantage of underbalanced drilling being reducedreservoir damage caused by the invasion of drilling fluidand cuttings.

Since the majority of CT services are performed throughthe production tubing, specialized thru-tubing CTD canbe undertaken with the completion tubulars in place. Welldeepening and side-tracking of existing wells in depletedreservoirs is an area in which CTD offers significantoperational and cost benefits compared with conventionaldrilling techniques.

Ultimately, it is intended that the techniques and equipmentused in CTD will provide a level of control and responsewhich will permit “joystick drilling”.

1.1.4 Environmental

In several locations, for example, urban areas, minimizingthe wellsite area, as well as the visual and noise impact,is a significant factor in the preparation and execution ofdrilling operations. The configuration of CT equipmentenables operations to be completed from a smaller work

site using equipment which is less visually intrusive.Additionally, operations using continuous tubing causesignificantly less noise polution than those using jointedpipe.

1.2 Limitations and Disadvantages

The limitations and disadvantages of CTD can besummarized in the following categories.

• Economic – in many areas, the abundance of low-costconventional rigs render the use of CTD for someapplications uneconomic. In such areas, only specializedCTD techniques which cannot be completed byconventional equipment will be viable.

• Hole size – the advantage of being able to drill slimholeis, in some applications, countered by the inability to drilllarger hole sizes.

• Rotation – since the CT string cannot be rotated,steering adjustments in directional drilling applicationsmust be initiated using downhole tools.

• CT fatigue and life – although the fatigue and useful lifeof CT strings are now well understood and monitored,it can be difficult to accurately predict the extent to whicha strings life may be used during any CTD operation.

0

20

40

60

80

100

Specialized CTDConventional CTD

1995 (est)1994199319921991

WO

RLD

WID

E J

OB

CO

UN

T

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DOWELL CONFIDENTIAL

Page 4 of 50 October 1995

Section 1110 Rev A

1.3 CTD Applications

There are several ways in which CTD applications havebeen classified. Most operations can be described usingthe following criteria (Fig. 1):

• well status – new well or reentry

• well preparation – tubing/completion removed or thru-tubing

• wellbore trajectory – well deepening or side track

• wellbore conditions – underbalanced or overbalanceddrilling.

The illustration in Fig. 2 shows the world wide trend inCTD from 1991 through 1994. In this period, two distinctareas of CTD operation were identified; operations whichutilize the unique capability of CT and operations whichcould have been completed by conventional drillingtechniques and equipment. It is generally accepted, thatthe increasing trend toward specialized applications willcontinue as the reliability of the techniques improve andthe resulting benefits become more apparent.

2 JOB DESIGN AND PREPARATION

The job design and preparation sequence for CTDoperations comprises several distinct tasks or areas ofinvestigation.

• establish the client's objectives

• review the technical feasibility

• technical preparation

• administrative preparation.

2.1 Establishing Objectives

Unlike most CT service activities, the overall objective(s)of the client may not always be immediately apparent.(For example, is the well being drilled for production,appraisal, delineation or exploration purposes?) It isbeneficial to the overall process if all parties involved inthe design and execution of the CTD operation are awareof the objectives and goals associated with them. In

addition, the means and criteria by which the achievementof the objectives will be assessed should also be known.

There are several specific applications for CTD. Thefollowing information and guides are based on the fourmost common applications, that is, the majority of CTDenquiries or feasibility studies requested by clients maybe included in these categories.

• new exploration wells

• new development wells

• existing well deepening

• existing well sidetracking.

The location and logistic concerns provided in Fig. 3apply to all CTD applications. To assist with the dataacquisition process, an enquiry guide for each applicationis included in Fig. 4 through 6. A summary of the currenttechnical capabilities is also included.

2.2 Technical Feasibility

When assessing the technical feasibility of any CTDoperation a logical and methodical approach is essential(Fig. 7). The following areas should be investigated andthe relevant criteria determined (depending on the specificapplication and conditions). A summary of the constraintsthat may limit the application or extent of CTD operationsis shown in Fig. 8.

• weight on bit

• annular velocity

• pumping pressure and rate

• CT string tension

• CT life/fatigue

• torque

• CT reel handling

• directional requirements.

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Section 1110Rev A

October 1995 Page 5 of 50

Location

• What are the dimensional and deck load constraints for the operational, storage and fluid

handling areas?

Logistics

• Is a crane of adequate capacity available? Is it located in a position that allows unrestricted

access to the well and operational areas? What are the load capacity and boom length?

• Where is the personnel accomodation?

Environment

• What provisions may be necessary to enable adequate environmental protection, for

example, noise, spill protection or temporary chemical storage?

• What local weather, sea, seasonal conditions may restrict operations?

CTD ENQUIRY GUIDE – LOCATION, LOGISTICS AND ENVIRONMENT

Location

• In which type of environment is the wellsite, for example, urban area, jungle or desert?

• What are the location constraints, for example, size, obstructions and obstacles?

Logistics

• Are there any known logistical constraints, for example, limits to access, operational

windows, etc.?

Environment

• What provisions may be necessary to enable adequate environmental protection, for

example, noise, spill protection or temporary chemical storage?

Onshore

Offshore

Figure 3. CTD enquiry guide – location, logistic and environment.

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DOWELL CONFIDENTIAL

Page 6 of 50 October 1995

Section 1110 Rev A

CTD ENQUIRY GUIDE – NEW WELLS & VERTICAL WELL DEEPENING

Figure 4. CTD enquiry guide –new exploration well.

Exploration andproduction objectives

Wellbore design

• Is this an oil or gas well?

Data collection• How extensive is the logging program to be?• What are the mud logging requirements?• What is the minimum acceptable size of the productioncasing or liner ?

HolesizeUp to 12-1/4-in. hole – for hole sizesgreater than 6-3/4-in. formations must beunconsolidated (motors OD:– 4-3/4-in. ormodified 6-1/2-in.)

DepthAchievable depth dependent on holesize and formation drillability (new wellCTD generally limited to 5,000 to 6,000 ftwith three or four casing strings.

Typical limitations• Torque tolerance of the CT string limits

the motor size.

• The CT pumping pressure limits the depth

of the hole sizes larger than 4-3/4-in.

CT string size• 2-3/8-in. CT is recommended for hole

sizes greater than 6-3/4-in. or for 4-3/4-

in. sections deeper than 5,000 ft.

Wellbore geometry• What is to be the TD and open-hole sizes?• What is the casing program, that is, casing size and shoedepths?

Deviation• If the wellbore is deviated, what is the projected well profile, i.e,

inclination and azimuth versus depth.

• What is the acceptable target tolerance fromprojected profile?

• If the wellbore is vertical, what is the maximum acceptable

deviation?

Downhole conditions• What are the formation pressures and temperature?• What is the well lithology?• Is there a risk of shallow gas?• Are there any sloughing shales?• What is the likelihood of H2S?

Operations

Bit and drilling performance• What is known of the formation(s) drillability ?• Are offset well bit records available?

Drilling fluid• Is the reservoir to be drilled under or overbalanced?

• What drilling fluid(s) is to be used, that is, mud, foam or air?

• What are the properties of the mud system to be used, that is,

type, density and characteristics?

• What is the likelihood of lost circulation?

Current Technical Capability

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COILED TUBING ENGINEERING MANUALCOILED TUBING DRILLING

DOWELL CONFIDENTIAL

Section 1110Rev A

October 1995 Page 7 of 50

CTD ENQUIRY GUIDE – EXISTING WELL SIDETRACK REENTRY

Figure 6. CTD enquiry guide – existing well sidetrack reentry.

Production andcompletion objectives

Wellbore design

Production• Is this an oil, gas or injection well?

Completion• What will be the liner size?• What is the minimum acceptable liner size?• Will the liner be cemented?• How is the new completion to be configured?

Wellbore geometry• What is to be the TD and open-hole sizes?• What are the existing casing sizes and shoe depths?

Deviation• What is the existing well profile, i.e, inclination and azimuth

versus depth?

• Which kick-off technique will be used, for example, window or

section milling?

• What is the reentry well profile, that is, kick-off depth, build up

rate, inclination, azimuth and drain hole length?

• What is the acceptable target tolerance from projected profile?

Downhole conditions• What are the formation pressures and temperature?• What is the well lithology?• Are there any sloughing shales?• What is the likelihood of H2S

Current Technical Capability

Bit and drilling performance• What is known of the formation(s) drillability?• Are offset well bit records available?

Drilling fluid• Is the reservoir to be drilled under or overbalanced?

• What drilling fluid(s) is to be used, that is, mud, foam or air?

• What are the properties of the mud system to be used, that is,

type, density and characteristics?

• What is the likelihood of lost circulation or losses?

Operations

Hole sizeThrough-tubing• Minimum completion size of 4-1/2-in.,

allowing a 3-1/2- or 3-3/4-in. hole.

Conventional (completion removed)• Up to 4-3/4-in. with a build-up radius of up

to 60°/100ft.

• Up to 6-in. with a build-up radius of up to

15°/100ft.

Depth• Horizontal drainhole can exceed 2,000 ft,

but is dependent on BUR, KOD, casing

and CT sizes.

Total depth• Through tubing: up to 15,000 ft• Conventional (completion removed): more

than 10,000 ft

Typical limitations• Build-up radius (BUR) limited by bending

friction force of the BHA which limits the

available WOB.

• Downhole WOB provided by the CT limits

the horizontal drainhole length (CoilCADE

check)

CT string size• 1-3/4- to 2-3/8-in. depending on the hole

profile

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DOWELL CONFIDENTIAL

Page 8 of 50 October 1995

Section 1110 Rev A

No

Gather Data

Project is feasible as proposed

Horizontal or highly deviated

wellbore

Are velocity criteria

met ?

Can job design changes

be made ?Project not feasible

as proposed

Investigate Pressure Parameters Run CoilCADE to calculate CT string and annular pressure loss at 80% of

the maximum motor flowrate.

Calculate Establish maximum tension required

by adding 15,000 lb safety factor to the CoilCADE output.

Check Results • Against the maximum allowable

tension for the CT string. • Injector head pulling capacity.

Tension Criteria Options • Use a higher capacity

injector head • Use CT string with greater

wall thickness and/or

higher yield strength

Calculate Estimate the pumping pressure by

adding the estimated BHA pressure loss to CoilCADE output.

Check Results Against the maximum allowable

working pressure for the CT string.

Pressure Criteria Options • Use CT string with greater OD

and/or greater wall thickness • Use a smaller motor • Downsize the hole

Investigate Annular Velocity Calculate conditions for largest hole size and highest deviation section. Use 80% of maximum

motor flow rate.

Velocity Criteria Options • Install a suspended casing

•Downsize the hole

Above maximum

allowable ?

Investigate Tension Parameters Run CoilCADE to calculate the

maximum CT string tension.

Above maximum

allowable ?

Investigate DWOB Parameters Run CoilCADE to determine CT

compressive load before lock-up at; • the total depth (TD)

• the end of build-up section

Calculate • Estimate the bending friction in

in the build-up section. • Calculate the downhole weight on bit

(DWOB) available at the end of the build-up section, i.e.,

CoilCADE output less bending friction

Check Results • Against the estimated minimum

DWOB for the hole size; • 4-3/4-in. hole – 1,500 lbf • 4-1/8-in. hole – 1,000 lbf

DWOB Criteria Options • Use CT string with greater OD

and/or greater wall thickness

• Decrease the build-up rate • Downsize the hole

Below minimum

allowable ?

Yes

Yes Yes

No

No

Yes

No

Yes

No

YesNo

Figure 7. Step-by-step feasibility study flowchart.

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SchlumbergerDowell

COILED TUBING ENGINEERING MANUALCOILED TUBING DRILLING

DOWELL CONFIDENTIAL

Section 1110Rev A

October 1995 Page 9 of 50C

OIL

ED

TU

BIN

G D

RIL

LIN

G –

LIM

ITIN

G P

AR

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ET

RS

Use

the

larg

est f

isha

ble

mot

or fo

r the

hol

e si

ze fo

r max

imum

flow

rate

(con

side

r m

ax a

llow

able

CT

pre

ssur

e). U

se C

T s

trin

g le

ngth

app

ro-

pria

te to

the

wel

l TD

. Use

a s

hear

thin

ning

mud

to m

inim

ize

the

pres

-su

re lo

ss.

Use

a m

otor

with

the

max

imum

torq

ue in

its

cate

gory

. Mak

e su

re th

eC

T a

nd B

HA

max

allo

wab

le t

orqu

e is

less

tha

n tw

ice

the

mot

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tall

torq

ue.

Two

basi

c ty

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of s

lim h

ole

mot

ors

are

avai

labl

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igh

spee

d/lo

wto

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or

low

spe

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igh

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dril

l off

test

is n

eces

sary

to

opti-

miz

e R

OP

and

min

imiz

e vi

brat

ions

for

a gi

ven

form

atio

n an

d m

otor

/bi

t com

bina

tion.

In th

e ca

se o

f ver

tical

or

slig

htly

dev

iate

d ho

les,

dril

l col

lars

are

use

dto

pro

vide

WO

B,

but

for

high

ly d

evia

ted

or h

oriz

onta

l w

ells

, th

e C

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e W

OB

and

the

max

imum

com

pres

sive

load

at t

he C

T e

ndbe

fore

loc

k up

, is

the

lim

iting

fac

tor.

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max

imum

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e co

m-

pres

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at t

he e

nd o

f the

CT,

mus

t be

estim

ated

usi

ng c

oilC

AD

Ein

two

criti

cal p

ositi

ons:

in th

e bu

ild u

p se

ctio

n an

d at

the

tota

l dep

th(T

D).

• In

the

build

up

sect

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the

max

CT

com

pres

sive

load

bef

ore

lock

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t be

suffi

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t to

over

com

e th

e be

ndin

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ictio

n fo

rce

of th

e B

HA

(not

take

n in

to a

ccou

nt b

y co

ilCA

DE

) w

hile

pro

vidi

ng s

uffic

ient

WO

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l at a

n ac

cept

able

rat

e.• A

t TD

in th

e ho

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tal o

r dev

iate

d se

ctio

n, th

e m

ax C

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ompr

essi

velo

ad b

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ck u

p gi

ven

by c

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AD

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is t

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um a

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ble

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t TD

.

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imum

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ion

mus

t at l

east

be

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l to

the

max

imum

han

g-in

g C

T a

nd

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+ t

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est

ima

ted

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xim

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rag

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a r

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ty m

argi

n fo

r ov

erpu

ll (1

5,00

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20,0

00 lb

f).

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l rul

e, th

e m

inim

um v

eloc

ity in

a v

ertic

al w

ellb

ore

sect

ion

is 4

0 ft/

min

. In

high

ly d

evia

ted

wel

lbor

es 1

00 ft

/min

sho

uld

be u

sed

asa

guid

e. T

he W

ellb

ore

Sim

ulat

or s

houl

d be

use

d in

the

asse

ssm

ent o

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itica

l cas

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he a

nnul

ar v

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ity s

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d be

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Section 1110 Rev A

2.2.1 Weight On Bit

The necessary force, or weight on bit (WOB), required tomaintain penetration while drilling, can be obtained fromtwo sources. When drilling vertical or slightly deviatedwellbores, drill collars are used to provide weight on bit.In these cases, the CT is kept in tension to ensure a stabletrajectory. In highly deviated wellbores the CT string isused to provide the necessary weight on bit.

In conventional drilling operations using jointed pipe, theactual weight on bit is relatively easy to calculate. However,due to the buckling which occurs in a CT string, suchcalculations are no longer valid for CTD. A tubing forcesmodel (such as found in CoilCADE*) must be used todetermine the available compressive load at the bitbefore the CT locks up. At the point of lock-up, no furtherweight can be applied to the bit, but surface indications(weight indicator) may not reflect this condition. The termdownhole weight on bit (DWOB), refers to the actual forcebeing transmitted to the bit, not the apparent forcedisplayed by the weight indicator at surface.

While drilling the buildup section of a deviated wellbore,the CT must provide sufficient force to bend the BHAaround the build up curve and still provide sufficientDWOB to ensure penetration at a reasonable rate. Thisbending friction force must be calculated then subtractedfrom the CoilCADE output value. The resulting forcerepresents the available DWOB.

The proposed trajectory co-ordinates are required toenable CoilCADE analyses. This information is typicallyobtained from the directional drilling (DD) representative.Variations in azimuth and inclination affect the tubingforces and add to the complexity of the simulation (Fig. 9).If severe, the doglegs resulting from azimuth andinclination changes will significantly limit the extent ofpenetration–this applies both to the drilling process andsubsequent well intervention.

The tables shown in Fig. 10 and 11 illustrate the forcerequired for a range of hole and BHA sizes. Short radiusBHAs containing knuckle joints (or similar) will requiremore detailed modelling.

Several CoilCADE simulations may be required to compilea table incorporating variables in BHA or hole size. In thisway the the design can be optimized to provide adequate

DWOB throughout the build-up horizontal (or deviated)sections. For example, larger or heavier CT work stringsprovide more available DWOB while a higher build-upradius reduces the available DWOB.

A friction coefficient of 0.4 should be used in CoilCADEanalyses of openhole sections.

The minimum recommended DWOB available for CTD invarious hole size ranges is shown below.

Openhole Recommended Diameter Minimum DWOB

(in.) (lbf)

3-3/4 to 4 10004-1/8 to 4-3/4 1500

5 to 6-1/4 2500

Figure 9. Azimuth/inclination.

Surface reference point

Survey point• Measured depth• True vertical depth• Borehole Inclination• Borehole Azimuth

North axis

East axis

* Mark of Schlumberger

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Section 1110Rev A

October 1995 Page 11 of 50

Figure 10. BHA bending friction forces.

BHA BENDING FRICTION FORCE – 2-7/8-in. MOTORS

Dog Leg Hole Friction BHA BHA BendingSeverity Diameter Coefficient OD ID Friction Force(°/100 ft) (in.) (in.) (in.) (lbf)

15 4.75 0.35 3 2.25 25420 4.75 0.35 3 2.25 39125 4.75 0.35 3 2.25 54630 4.75 0.35 3 2.25 71835 4.75 0.35 3 2.25 905

40 4.75 0.35 3 2.25 110645 4.75 0.35 3 2.25 131950 4.75 0.35 3 2.25 154555 4.75 0.35 3 2.25 178360 4.75 0.35 3 2.25 2031

15 4.125 0.35 3 2.25 31720 4.125 0.35 3 2.25 48825 4.125 0.35 3 2.25 68130 4.125 0.35 3 2.25 89635 4.125 0.35 3 2.25 1129

40 4.125 0.35 3 2.25 137945 4.125 0.35 3 2.25 164550 4.125 0.35 3 2.25 192755 4.125 0.35 3 2.25 222360 4.125 0.35 3 2.25 2533

15 3.75 0.35 3 2.25 38820 3.75 0.35 3 2.25 59725 3.75 0.35 3 2.25 83430 3.75 0.35 3 2.25 109735 3.75 0.35 3 2.25 1382

40 3.75 0.35 3 2.25 168945 3.75 0.35 3 2.25 201550 3.75 0.35 3 2.25 236055 3.75 0.35 3 2.25 272360 3.75 0.35 3 2.25 3103

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Section 1110 Rev A

Figure 11. BHA bending fricion forces.

BHA BENDING FRICTION FORCE – 3-1/2-in. MOTORS

Dog Leg Hole Friction BHA BHA BendingSeverity Diameter Coefficient OD ID Friction Force(°/100 ft) (in.) (in.) (in.) (lbf)

5 6 0.35 3.5 2.5 8210 6 0.35 3.5 2.5 23215 6 0.35 3.5 2.5 42620 6 0.35 3.5 2.5 65625 6 0.35 3.5 2.5 91630 6 0.35 3.5 2.5 120435 6 0.35 3.5 2.5 151840 6 0.35 3.5 2.5 185445 6 0.35 3.5 2.5 2213

5 4.75 0.35 3.5 2.5 11610 4.75 0.35 3.5 2.5 32815 4.75 0.35 3.5 2.5 60220 4.75 0.35 3.5 2.5 92725 4.75 0.35 3.5 2.5 129630 4.75 0.35 3.5 2.5 170335 4.75 0.35 3.5 2.5 214640 4.75 0.35 3.5 2.5 262245 4.75 0.35 3.5 2.5 3129

BHA BENDING FRICTION FORCE – 4-3/4 -in. MOTORS

Dog Leg Hole Friction BHA BHA BendingSeverity Diameter Coefficient OD ID Friction Force(°/100 ft) (in.) (in.) (in.) (lbf)

5 6 0.35 4.75 3 44710 6 0.35 4.75 3 126415 6 0.35 4.75 3 232220 6 0.35 4.75 3 3576

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Section 1110Rev A

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2.2.2 Annular Velocity

It is necessary to determine if the available annularvelocity will be sufficient to provide adequate hole cleaning.This is critical in two general areas.

• horizontal and highly deviated sections

• large diameter casings or top hole sections.

Hole geometry, cuttings size and drilling fluidcharacteristics greatly influence the hole cleaning abilityof any system. However, due to the high-speed motorand bit combinations typically used in CTD operations,the cutting size is generally very small (<50 microns). Thesmall cutting size significantly assists with removal.

The following annular velocity rules of thumb can be usedin preliminary feasibility and design work.

• Vertical hole sections – 30 to 40 ft/min annular velocity(new wells and shallow sections with coarser cuttingsmay require velocities as high as 50 ft/min).

• Horizontal hole sections – 100 ft/min (depends a greatdeal on the length of horizontal section and the drillingfluid characteristics).

A table of common hole, motor and CT sizes is shown inFig.12.

There are several recently developed mud and drillingfluid systems which provide improved hole cleaning abilityand fluid performance. Investigation and selection ofCTD drilling fluids should be conducted in co-operationwith DFS personnel.

Shear-thinning fluids (for example, some polymer muds)can decrease pressure losses by 30 to 40%. TheCoilCADE hydraulic model cannot accurately simulatethe performance of such fluids with yield point (YP) andplastic viscosity (PV) inputs alone–results are typicallyconservative.

High-pressure wells requiring high mud weight can presenta problem which limits the depth (length of CT string) thatcan be efficiently drilled.

2.2.3 Pump Pressure and Rate

The friction pressure induced by long or small diameterCT strings can be a limiting factor for some motor/bit/CTstring combinations. Hydraulic models should be used toensure the compatibility of the various components andpumping equipment. The CoilCADE model should beused to calculate pressure loss within the CT string andannulus. An estimate of the pressure loss within the BHAshould be added to the resulting value. The total pressureloss is then compared with the allowable CT stringpressure or pumping equipment limitation(s).

As a general guide, the following BHA pressure lossvalues can be used.

EstimatedType of BHA pressure loss (psi)

4-3/4-in. OD vertical hole BHA 4003-in. OD Directional BHA 1000

2.2.4 CT String Tension

A tubing forces model should be used to determine themaximum anticipated tension required to operate underthe expected wellbore conditions. A safety margin foroverpull (typically around 15,000 lbf) should be added tothe maximum anticipated tension. The resulting totalmust then still be below the Dowell maximum allowabletension as determined by the CoilLIMIT* module ofCoilCADE.

2.2.5 Torque

Excessive torque is not generally a problem with the bit/motor/CT string combinations typically used in CTDoperations. However, an awareness of the torque limits,and factors influencing such limits, is essential in hole/bitsizes larger than 4-3/4-in.

The torque generated by 6-in. motors can exceed thetorque limits of 2-3/8-in. CT. Consequently, CTD of largehole sizes (for example, 8-1/2- or 12-1/4-in.) should becompleted using a 4-3/4-in. motor or 6-3/4-in. low torquemotors (for example 1-2 or 2-3 lobes).

The maximum allowable CT torque should be less thantwice the motor stall torque.

* Mark of Schlumberger

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Section 1110 Rev A

ANNULAR VELOCITY – MOTOR/HOLE SIZE vs. CT SIZE

Flowrate Hole ID Annular Velocity (ft/min)(bbl/min) (in.) 1-3/4-in. CT 2-in.CT 2-3/8-in. CT

2-7/8-in. motor 2.00 3.750 187 205 2442.00 4.125 148 158 1812.00 4.750 106 111 1222.00 6.125 60 61 652.00 7.000 45 46 472.00 8.000 34 34 352.00 9.000 26 27 27

2-3/8-in. motor 2.30 3.750 215 235 2812.30 4.125 170 182 2082.30 4.750 121 128 1402.30 6.125 69 71 742.30 7.000 52 53 552.30 8.000 39 39 412.30 9.000 30 31 31

3-1/2-in. motor 2.30 4.125 170 182 2082.30 4.750 121 128 1402.30 6.125 69 71 742.30 7.000 52 53 552.30 8.000 39 39 412.30 9.000 30 31 31

3-1/2-in. motor 2.60 4.125 192 206 2352.60 4.750 137 144 1582.60 6.125 78 80 842.60 7.000 58 59 622.60 8.000 44 45 462.60 9.000 34 35 36

4-3/4-in. motor 4.75 6.125 - 146 1534.75 7.000 - 109 1134.75 8.000 - 81 844.75 9.000 - 64 65

4-3/4-in. motor 6.00 6.125 - - 1946.00 7.000 - - 1426.00 8.000 - - 106

Figure 12. Annular velocities for different hole size/motor/CT string combinations.

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Section 1110Rev A

October 1995 Page 15 of 50

2.2.6 CT Life and Fatigue

There are two principal areas of importance regarding CTlife and fatigue in CTD operations.

• A careful study of the anticipated cycles and operatingconditions should be undertaken to assess the expectedlife usage of the specified string.

• Once the operation has started, a careful record must bekept and regularly reviewed to ensure that actual lifeusage is within that predicted.

Because of the variable and unknown factors associatedwith most drilling operations, it is extremely difficult toestimate the expected life usage. Nonetheless, theconsequences of exceeding the fatigue and life limitationscan be severe (in the case of a failure) and inconvenient(in the case of a reel change being required).

As a general guide, data gathered from completed CTDoperations indicates the following life usage.

Vertical wells

Shallow wells, for example, 2000 ft can be drilled withthe CT being exposed to relatively few bending cycles(2 or 3 cycles being typical). Therefore the life expectancyof a string can reasonably extend to several wells.

Deviated wells

Data from previous operations indicate that a 2-in. CTstring can, on average, be used for three or four reentrywells. Similarly, a 2-3/8-in. CT string is typically used ontwo to three wells.

In all cases, continuous monitoring (TIM* and CoilLIFE*)is essential to ensure that prescribed limits are notexceeded.

2.2.7 CT Reel Handling

One of the main constraints on the size and length of CTstrings are the limits imposed by road transport weightregulations and offshore crane capacity. While it may beundesirable to assemble (field weld) work strings, it maybe the only option in the case of limited road weights.Offshore crane capacity restrictions can be overcome, in

some circumstances, by spooling the tubing between asupply boat and platform. Using this technique, the emptyreel is lifted to the platform and rigged up to spool thetubing string from a shipment spool on the boat deck.

2.2.8 Directional Requirements

Applications which require directional control andmonitoring require special investigation and theinvolvement of directional engineers at an early stage. Asa guide of current capability, the following limits apply.

• Downhole temperature – currently limited to 310°Fmaximum.

• Deviation build rates – A function of tool string lengthand stiffness with, in general, longer tool strings requiringlower build rates. Also, aggressive build rates can limitthe efficiency of orienting tools. The current orientingtool is designed to operate within dog-legs of up to 30°/100 ft. The SLIM1* tool (with low-flow pulser) canoperate in a dog leg severity of 55°/100 ft.

• Hole size – Currently, directional assemblies utilize a 2-7/8-in. monel housing. Consequently, the minimumhole size with directional control is 3-1/2 in.

2.3 CTD Project Preparation

The preparation for a CTD project typically involves co-ordinating the input of several specialist disciplines tocompile an overall job plan or procedure. In most casesit is desirable to assign one engineer as the person incharge of the design and preparation of the CTD operation.Logically, this person will provide a focused point ofcontact between client and contractor(s), and be availablefor operation support duties during the execution of theCTD project.

The tasks required to be completed in this phase of CTDproject preparation may be summarized as technical oradministrative. Regardless of how the various elementsare categorized, each should be regarded as a keycomponent which is essential for completion of a safe andsuccessful CTD project.

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Section 1110 Rev A

2.3.1 Technical Preparation

There are several tasks to be performed, each withassociated deadlines, in the process of technicalpreparation. The tasks can be planned, and appropriateduties delegated, with the help of checklists in the followingprincipal areas.

• basic equipment and services

• procedures and planning

• drawings and schematic diagrams

• personnel.

To enable the efficient management and coordination ofthese individual areas, it is advisable to prepare a list oftasks required to complete technical preparation. Such alist should contain information on the task, designatedperson, deadline and additional information appropriateto the specific task.

2.3.2 Basic Equipment and Services

To help identify the source(s) of equipment, services andexpertise necessary to complete the project,comprehensive check lists should be prepared under theheadings shown below.

Each list should be formatted to include an accuratedescription of the item or service, the source and applicabledeadlines or leadtimes.

• surface equipment

• consumables

• spare parts and supplies

• dowhhole tools

• associated services.

2.3.3 Procedures and Plans

Due to the complex nature of the overall operation, it isrecommended that detailed procedures and plans be

prepared for the principal project elements. Theseprocedures should take account of the specific wellsite,wellbore and reservoir conditions (or anticipatedconditions) under which they will be executed.

All procedures and plans should be carefully reviewed bythe personnel, groups or organizations involved. In somecases it may be necessary to adopt a formal review andapproval process to ensure all parties acknowledgeacceptance.

Note: Ensure that each document is clearly identified witha date or version number. This will minimise confusionand error where several parties are provided withprocedures or plans.

The following list includes typical elements of a CTDproject. This list comprises the basic requirements of anumber of CTD applications, consequently, someelements may not be applicable. Similarly, additionalelements may be required for specific CTD project(s).

• mob/demob organization

• rigging up/down

• setting whipstock & milling window (if required)

• well control

• well control equipment testing

• BHA deployment even overbalance

• running and setting liner or casing (if required)

• running completion string

• cementing job design

• mud program

• contingency plans

• emergency responses (in the event of fire, etc.).

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Section 1110Rev A

October 1995 Page 17 of 50

2.3.4 Drawings and Schematic Diagrams

Much of the explanation required within procedures andplans can be simplified by the use of clear and suitablydetailed drawings and schematic diagrams. The followinglist includes typical examples of drawings or schematicdiagrams for CTD projects.

Note: Ensure that each document is clearly identified witha date or version number. This will minimise confusionand error where several parties are provided withprocedures or plans.

• wellbore schematic (at each stage of the operation)

• trajectory plot if deviated

• surface equipment lay out with dimensions (or scale)including indication of restrictive zoning where applicable,for example, Zone II

• BOP stack schematic with heights and dimensions

• BHA schematics (fishing diagram for each assembly)

• schematics of high- and low-pressure lines

• electrical wiring of surface equipment.

2.3.5 Personnel

In addition to the availability and assignment of personnel,there may be several issues which should be addressed.The following examples may apply to the organization ofCTD personnel for various applications and locations.

• training and certification of personnel

• personnel job descriptions

• operations and support organization organograms.

2.3.6 Administrative Preparation

Clarify and finalize arrangements between the client andthird party contractor(s). The final agreement should includethe following sections:

• equipment list provided by contractor and operator

• personnel list provided by contractor

• list of services provided by contractor and operator

• liability clauses

• day rates, lump sums, incentives and penalties includingforce majeure.

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Section 1110 Rev A

3 EXECUTION

3.1 Well Control (Overbalanced Drilling)

This section addresses only well control in overbalanceddrill ing applications. The issues concerningunderbalanced drilling are addressed separately in Section3.4.

Most conventional well control precautions and proceduresused for conventional drilling apply to overbalanced CTD(with minor modifications). For example, in slimhole wells,it is vital that kicks are detected as soon as possible.Within the relatively small wellbore, even small influxes ofreservoir fluid can displace a significant volume of drillingfluid–resulting in a rapid worsening of the situation.

Dynamic kill is not a viable option for CTD because of thesmall annular pressure loss. The wait and weight methodor the driller's method, such as used for kick control onconventional drilling operations is typically used.

The preferred kick detection system for CTD operationsis to use a flowmeter installed on the return line. Theequipment is described in the surface equipment sectionof this manual.

If foam or air is being used as a drilling fluid, the implicationis that the reservoir pressure is very low. In the event ofa kick, the well will generally kill itself, or worst case,pumping water will kill the well. Pressure deployment ofthe BHA is typically required if drilling with foam in a gasreservoir. This is necessary as the foam may break whentripping, resulting in unstable wellbore conditions.

CTD well control procedures and policies are describedin the Dowell Safety and Loss Prevention Manual (SLP22)which also refers to the Sedco Forex Well Controlhandbook.

3.2 Conventional Sidetracking

The term conventional sidetracking or reentry applies toCTD operations which are undertaken under the followingconditions.

• The well is killed and all subsequent CTD activities areperformed in overbalanced conditions.

• The original completion tubulars have been removed.

• A mechanical whipstock is used to initiate windowmilling operations in the casing or liner.

There are four distinct operational phases in completinga conventional side tracking operation. Each phase willrequire the involvement of different speclialist skills whichmay require the participation of third party suppliers orservice companies.

• well preparation

• preparing/setting the whipstock

• milling the window

• drilling the sidetrack.

Conventional sidetracking is currently undertaken atdepths in excess of 10,000 ft, with resulting drain holediameter within a range of 3-1/2 to 6 in. (Fig. 13).

The application of conventional CTD sidetrackingtechniques have special significance on offshoreplatforms, where mobilization and logistic difficulties mayrender conventional rig-based reentry techniques non-viable. The economic viability of onshore CTD reentryoperations is greatly dependent on the local availability,and suitability, of conventional rigs and equipment.

3.2.1 Well Preparation

The following list summarizes the operations typicallyrequired as well preparation for setting the whipstockthen continuing with subsequent milling and drillingoperations.

• Kill the well.

• Nipple down christmas tree and nipple up well controlequipment.

• Test the well control equipment.

• Pull the production tubing and retrieve packer (if required).

• Squeeze cement off perforated interval (if necessary)or set cement plug and/or set bridge plug.

• Run CCL (to check for casing collars at the KOD), CBL

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Section 1110Rev A

October 1995 Page 19 of 50

(to check cement/bond quality) and Gamma Ray (tocorrelate depth).

• Run a casing scrapper to the KOD.

3.2.2 Setting the Whipstock

The procedures and equipment necessary to set thewhipstock depends on the operation objectives. If azimuthcontrol is required, then a whipstock anchor must be set.The whipstock anchor is necessary to ensure thewhipstock is correctly orientated, to allow milling anddrilling operations to be started along the correct trajectory.

The following list summarizes the activities which may benecessary to run and set a mehanical whipstock ready formilling operations.

• If azimuth control is required, set the whipstock anchor.This is typically run on wirline, but CT conveyance maybe appropriate in some circumstances.

• Perform a gyro survey to determine the orientation of thewhipstock anchor. The orientation must be known toallow the whipstock key to be set. Thereby ensuring thewhipstock orientation is correct when set on thewhipstock anchor.

• Prepare the whipstock – if run without an anchor, thewhipstock is equipped with a set of slips which are seton the casing wall (similar to packer slips). A bridge plugor cement plug must be set at the kick off depth toenable the whipstock slips to be set with set-downweight.

If the whipstock is to be used with an anchor, a muleshoe and orientation stinger will be made up to thebottom of the whipstock.

• Run and set the whipstock.

Whipstock Run with an Anchor and Stinger

The BHA is run in the hole, the anchor is tagged andstinger engaged into the anchor. A swivel assemblyallows the stinger to rotate freely allowing correct alignmentof the whipstock and anchor. Weight is then applied to setthe slips in the anchor, overpull confirms that the stingeris anchored. A release stud between the whipstock and

Figure 13. Typical conventional sidetrackconfiguration.

Completion tubularsremoved

Top of window

Controlled wellbore conditionsallows appropriate wellheadequipment to be fitted.

Whipstock

Bottom of window

Whipstock packer

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Section 1110 Rev A

the running tool is then sheared with additional overpull,and the running assembly is retrieved or milling of thewindow starts if a starting mill was run with the runningtool.

Whipstock Run Without an Anchor

The BHA is run in the hole, the cement plug or bridge plugtagged and the whipstock slips set. A shear stud on therunning tool is sheared by applying weight (or by pullingdepending on the type of whipstock). The runningassembly is then retrieved or milling of the window startsif a starting mill was run with the running tool.

In some applications a special mill/motor assembly isused as a running tool. The advantage being the ability tostart milling immediately the whipstock is set, with noneed to retrieve and change the BHA (see below).

3.2.3 Window Milling

It is generally recommended that window milling beperformed using low speed motors (typically 3-1/2- or 4-3/4-in. motors, depending on hole size). The necessaryweight-on-bit is provided by drill collars. The WOB requiredto mill a casing window does not generally exceed 1,000to 2,000 lbf. A representative of the whipstock vendor ordirectional drilling company is generally required onlocation to supervise the preparation and execution ofwindow milling operations.

There are two basic options for window milling using amechanical whipstock.

• using a conventional starting mill/whipstock lugcombination.

• using a diamond speed mill.

Starting Mill/Whipstock Lug Combination

The following list summarizes the activities necessary tomill a casing window using a starting mill and whipstocklug.

• A conventional starting mill is first made up to a lowspeed motor and run in the hole to mill about 3 ft ofcasing and the whipstock lug.

• The starting mill is replaced by a window mill and awatermelon mill. The watermelon mill being made upbetween the window mill and the motor. About 9 ft ofwindow is milled, followed by appropximately 5 ft offormation. Drilling the formation allows the next millingassembly to enter the open hole when dressing off thewindow.

• A string mill is made up on top of the watermelon mill forreaming the window section.

As an alternative to the multiple runs and BHA changesoutlined above, the low-speed motor can be used as awhipstock running assembly. This enables window millingto commence immediately after the whipstock shear studhas released, that is, a BHA change is not necessary tostart milling. A check must be made to ensure the motorcan withstand the necessary pull or set down weightsrequired to set the whipstock and shear the stud.

Diamond Speed Mill (No Lug in the WhipstockConcave)

• A diamond speed mill and low speed motor assembly isused to mill approximately 5 ft of window.

• A watermelon mill is then made up above the speed millto complete the window and to drill approximately 5 ft offormation.

• A string mill is then made up above the water melon millfor reaming the window section.

3.3 Thru-Tubing Reentry

The term thru-tubing reentry applies to CTD operationsthat are undertaken under the following conditions.

• Operations are conducted over (or through) the christmastree.

• The original completion tubulars remain in place.

• Well control equipment is used to enable under- or over-balanced drilling to be conducted safely.

Thru-tubing reentries can only be undertaken using milland bit assemblies which are compatible with the minimumID (restriction) present in the tubing string or completion.

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In some cases, tubing restrictions can be milled out or cutto allow access for larger mills and bits. Nondirectionaldeepenings and sidetracks may generally be undertakenthrough completion strings of 3-1/2-in. or greater.Directional applications generally require tubing 4-1/2-in.or greater to allow passage of the 3-in. OD directionalBHA. The resulting drainhole hole is generally 3-1/2 or 3-3/4-in. depending on the minimum restriction.

Thru-tubing reentry techniques have special significanceon applications where completion removal is uneconomicor impossible. The constraints associated with workingwithin the completion tubulars generally precludeconventional rigs and equipment from this type ofoperation.

Significant benefits can be gained from thru-tubing CTDin underbalanced conditions. Consequently thru-tubingCTD can offer great potential in the development ofdepleted reservoirs.

There are three basic techniques that can be used to kick-off and mill a casing or liner window below the tubingtailpipe. The regional CTD specialist should be contactedduring the design phase of any thru-tubing CTD applicationto ensure that the most recent design and executingtechniques can be applied (Fig. 14).

• whipstock in production tubing

• thru-tubing whipstock

• cement kick-off techniques– time drilling in a cement plug– whipstock in cement plug pilot hole.

3.3.1 Well Preparation

The following list summarizes the operations typicallyrequired as well preparation for thru-tubing CTDoperations.

• Nipple-up CT well control equipment.

• Plug and abandon existing perforated zones.

• Run CCL (to check for casing collars at the KOD), CBL(to check cement/bond quality) and Gamma Ray (tocorrelate depth).

Figure 14. Typical thru-tubing sidetrackconfiguration.

Production packer

Completion tubularsin place

Tail pipe

Build-up section

Completionrestriction(s)

Controlled wellboreconditions allowsappropriate wellheadequipment to be fitted.

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• Mill some nipples in the tubing or cut tail pipe if necessarybecause of restrictions.

3.3.2 Whipstock in Production Tubing

If the kick off is to be performed from the productiontubing, a conventional whipstock and anchor can be setin the tubing and a window milled in tubing and the casing/liner. The hardware and techniques required are currentlyavailable and are relatively conventional. However, someequipment modifications may be required.

It is generally not possible to set a whipstock in theproduction tubing tail pipe. Therefore, the whipstock willneed to be set above the production packer. This isgenerally an unacceptable option, consequently thistechnique has limited application.

3.3.3 Thru-tubing Whipstock

Thru-tubing whipstocks are a relatively recentdevelopment that requires ongoing refinement to improvereliability. The size ranges available are currently restrictive(through 4-1/2-in. tubing to set inside 7-in, casing or liner).However this will undoubtedly increase as the tool reliabilityimproves and the techniques become more common.

Current (1995) thru-tubing whipstocks can only be usedto sidetrack on the high side of the hole. They areavailable from Baker Oil Tools, Weatherford and TIW. Asof mid-95, only the Baker thru-tubing whipstock has beensuccessfully field tested.

3.3.4 Cement Kick-off Techniques

Both of the cement kick-off techniques outlined below arerecently developed and are undergoing continued testingand development. They both require the accurateplacement of a high quality, high compressive-strengthcement plug. Consequently, sufficient effort and resourcesshould be allocated to ensure the successful design andexecution of the cement plug placement (Fig. 15).

Cement Plug Preparation

• A cement plug of high compressive-strength is placed inthe interval 50 ft below the kick-off depth to the bottomof the tail pipe (subject to length and volumes). After thecement has adequately cured, the top of the cement is

tagged and dressed if necessary.

• The cement in the tail pipe is then drilled out using adirectional BHA comprising a diamond speed mill and aslightly bent motor (±0.25°)

• Once out of the tubing the bend is oriented in thedirection of the desired sidetrack. This is achieved usingthe gravity tool face and the hole gyro survey. Drilling iscontinued through the cement plug, keeping the toolface until it reaches the kick-off depth (KOD).

Time Drilling from a Cement Plug

• The BHA is retrieved and the bend changed to a higherangle (±2.5°).

• The window is milled using a time drilling technique, thatis, milling with low WOB (or low motor differentialpressure), running the CT string in short intervals (1/4-in. or 1/2-in. only) with predetermined delay intervals.The delay time will vary throughout the milling operationas the quantity of steel to be cut varies through thewindow.

• When the window and approximately 5 ft of formationhave been drilled, the BHA is retrieved.

• The window is then dressed using a watermelon millassembly similar to that outlined in the conventionalsidetracking section. A bull nose(no bit) is made up atthe bottom of the watermelon mill to avoid drilling out thecement by accident while dressing the window.

Whipstock Set in the Cement Plug Pilot Hole

• The pilot hole is drilled in the cement plug approximately10 ft deeper than the KOD. This rat hole is used to setthe bottom section of the whipstock.

• The BHA is retrieved and the appropriate whipstock isrun to bottom.

• After carefully tagging bottom, the whipstock assemblyis correctly oriented using an orienting tool. By applyingweight, the slips of the whipstock are set against thecasing/cement. Additional weight parts the shear-studallowing retrieval of the running assembly.

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Figure 15a. Time-drilled cement kick-off (thru-tubing).

Completioncomponents in place

Cement inside tailpipe

Drillout tailpipe

Hole oriented to casingwall

Hole made to kick-offdepth

Time-drill window cut

Window dressed andbuild-up radius drilled

Cement inside tailpipe

Drillout tailpipe

Hole oriented to casingwall

Hole made to kick-offdepth + requiredrathole for whipstock

Thru-tubing whipstock

Whipstock window cut

Figure 15b. Whipstock cement kick-off (thru-tubing).

Completioncomponents in place

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• A straight milling BHA with a diamond speed mill is runto mill the window and approximately 5 ft of formation.

• The window is then dressed using a watermelon millassembly similar to that outlined in the conventionalsidetracking section.

The regional CTD specialist should be consulted duringthe design phase of any thru-tubing CTD application onwhich either of the above cement kick-off techniques areto be used.

3.4 Underbalanced Drilling

3.4.1 Definition and Objectives

There has been confusion regarding the definition ofunderbalance drilling. For example, foam/air drilling ordrilling with a parasite string without the well flowing iscalled sometimes underbalanced drilling. However, thisis in fact overbalanced drilling if the well does not flow.The term underbalanced drilling implies that the reservoirpressure is at all times higher than the equivalentcirculating density of the fluid in the annulus. Under theseconditions, the well will be capable of flowing reservoirfluid while drilling or tripping.

The principal objective of underbalanced drilling is toavoid formation impairment caused by the invasion ofdrilling fluid. Some of the horizontal wells drilledunderbalanced by CTD have production ratesapproximately twice that of nearby wells which weredrilled overbalanced. These nearby wells were drilledusing conventional techniques and are completed withlarger wellbore and completion tubulars.

Underbalanced drilling is not a damage-free technique;however, the potential increase in well productivityoutweighs most of the associated risks. Permeabilityreduction resulting from the imbibition of drilling fluid canoccur; however, the relative effect is significantly lessthan overbalanced drilling damage. The absence of aprotective sealing filter cake can also result in someformation damage when the well is shut in. Furtherinvestigation is necessary to assess the extent of thesedamages for the various types of drilling fluids in differentformation types. An appropriate choice of deploymenttechnique to avoid shutting the well, may be the key tolimiting reservoir damage.

One of the main concerns while drilling underbalanced ismaintaining borehole stability. Such concerns areheightened under the following conditions.

• if no liner or casing has been set over the cap rockinterval above the pay zone

• in unconsolidated reservoirs

• in heterogeneous reservoirs with, for example, shalestringers.

Consequently, the reservoir stability and homogeneityneed to be evaluated for all candidate wells. Precautionsto contol or limit borehole instability include the following:

• Carefully controlling the degree of underbalance.

• Selecting appropriate drilling fluids to minimize adversereactions with sensitive formations.

• Setting a casing or liner above at the top of the reservoir.

Underbalanced drilling may be likened to drilling whiletaking a kick. However, the equipment and techniquesused are specifically designed to operate under theseconditions, unlike conventional drilling. Also, since thecompletion tubular and christmas tree are still in place, ahigh level of control can be maintained. Safety issues arealso affected by the reservoir pressure.

Thru-tubing underbalanced drilling is generally acceptableto regulatory agencies, largely as a result of long-established CT workover procedures and experience inlive wells.

3.4.2 Creating Underbalanced Conditions

Creating and controlling the correct degree ofunderbalance can be an extremely complex process. Forexample, computer models provide the only practicalmeans of predicting the wellhead and bottomholepressures in a two-phase flow.

The means of creating suitable underbalanced conditionsdepends greatly on the anticipated reservoir pressure.Reservoir pressure can be characterized as being eitherabove or below the hydrostatic pressure of a column ofwater in the wellbore.

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Reservoir Pressure above Water Column HydrostaticPressure

Under these conditions, underbalanced pressure can becreated by using a fluid(s) which is less dense than water.In marginal cases, careful analyses of the equivalent fluiddensity while circulating solids in the annulus should beconducted to ensure underbalanced conditions exist.

Reservoir Pressure below Water Column HydrostaticPressure

Underbalanced pressure conditions can be created inthree basic ways.

• Use a low-density drilling fluid.

• Use annular gas-lift.

• Use nitrogen to kick-off the well, then use appropriatefluids.

Low-density Fluids

The following low- and ultra-low-density fluids have beenused for drilling. This method is applicable to most wellswith low or high gas-oil-ratios (GOR).

• Oil-base fluids – use is limited to reservoirs with pressurecorresponding to an equivalent mud weight (EMW) of atleast 7 ppg. Oil-base fluids must be conditioned afterthe well returns have been passed through the separatorsand mud treatment equipment.

• Nitrified or aerated fluid or foam – in wells with a highGOR, nitrified foam or mud is the only solution to avoiddownhole explosion or fire. In wells having a low GOR,the use of an aerated foam or mud instead of nitrifiedsystems requires careful risk analyses. Foam is typicallythe best option since a number of computer models areavailable to predict foam performance, pressure lossesand resulting EMW. Treatment and disposal of thewellbore returns are significant problems encounteredwith foam-base fluid systems.

• Gas – natural gas, air or an inert gas like nitrogen haveall, at some time, been used in drilling operations. Dueto the risk, and consequences, of downhole fires andexplosions, Dowell recommends only nitrogen. A careful

risk analyses is required for all non-inert gas (or air)applications. Regardless of the gas used, this type ofdrilling is generally performed in very hard formationwith very low permeability (such as found in the RockyMountain region). Such applications are quite distinctfrom "normal" underbalanced drilling with CTD.

Annular Gas Lift

Two methods are in relatively common use to assist withdrilling operations. Both being applicable in wells with lowGOR.

• Parasite string – the existing production tubing is pulledand a casing or tubing string with a parallel parasitestring is set in place. The setting depth is dependent onthe formation pressure, that is, the more depleted thereeservoir, the deeper the string injection point will be.

On concluding the drilling operations, the parasite stringis pulled and a production tubing string run. Ideally,retrieving the parasite string and running the productiontubing should be performed under live well conditions toavoid potential damage during shut-in. From a cost andefficiency standpoint, a parasite string is generally notthe best option.

• Gas lift system in the production tubing – if the well is orneeds to be equipped with a gas-lift production stringand the tubing is large enough to achieve the scope ofwork, then the gas lift assisted drilling can be aneconomic option. If the well is not suitably equipped, theproduction string can be pulled and replaced with largertubing.

Well Kick-off and Appropriate Fluids

Some marginal wells may quickly load-up and be capableof flowing only in ideal conditions. In these cases, nitrogenkick-off and careful fluid selection (and control) may besufficient to support underbalanced drilling with CT. Thismethod is only applicable in wells with high GOR.

3.4.3 Controlling Underbalance Pressure

A surface choke is the primary means of controlling thedegree of underbalance created downhole. However, ifgas-lift mandrels or a parasite string is used, the gas ornitrogen injection rate will also provide a means of control.Experience has shown that the surface equipment

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improved hole cleaning (especially in 9-5/8-in. or largercasing). A mud system with the appropriate PV, YP, andgel characteristics is preferred, especially in nonthru-tubing applications.

• Cool and lubricate the bit – generally not a major issue.

• Control corrosion – controlled by additives, not generallya major issue.

• Provide sufficient inhibition over shale – may be aconcern if shale stringers are to be drilled, although canbe addressed with OBM or mud with appropriateadditives.

If a production tubing gas-lift system is used, and shaleinhibition is not a concern, water is generally recommendedas a drilling fluid. Water can generally achieve adequatehole cleaning in 4-1/2-in. tubing and even 7-in. liner belowtailpipe. Disposal is simplified since water can generallybe dumped or pumped into the production line.

3.4.6 Wellbore Returns

The simple solution for handling and disposal of wellborereturns, that is, drilling fluid, oil, gas, formation water andcuttings, is to route the entire return flow to the productionline. Concerns regarding the routing of solids to productionfacilities are minimal, since the volumes of cuttings for thesmall hole sizes drilled are generally tolerated–even athigh penetration rates. However, the flow line may createenough back pressure to prevent the well from flowing. Ifthe production facilities cannot treat the returned fluids, itmay be necessary to treat the returns independently, thatis, using three-phase separators (see SchlumbergerTesting).

The schematic diagram in Fig. 20b outlines a typicalprocess for treatment of wellbore returns. Returns arecontrolled by the choke manifold, following which, theyare routed to the separator(s) where oil, gas, drillingsolids, and water are separated. Sample catchers (forexample, a tee with valves and screens) can be installeddownstream the choke manifold or returns fluid samplesare recovered and centrifuged to recover cuttings.

The separated gas will be vented or flared depending onvolume and local constraints. The separated oil is generallystored in an appropriate tank. The residual water and

commonly used to treat return fluid creates a significantback pressure. Consequently, varying the gas-lift systemparameters to control the degree of underbalance is oflimited value.

A downhole annulus-pressure sensor helps to accuratelymonitor the bottomhole pressure. This can ensure theunderbalance is maintained over a horizontal wellboresection (assuming the reservoir pressure remains constantover the horizontal interval).

3.4.4 Well Pressure Control

Well control procedures used for conventionaloverbalanced drilling are no longer applicable forunderbalanced drilling. A gas or oil kick does not requirethat the well be killed even when tripping.

For a thru-tubing underbalanced operation, with thechristmas tree in place, the well control or safetyprocedures are the same as when performing live wellservice operations, and are well documented.

For non thru-tubing underbalanced operations, acceptedprocedures are not well documented and each applicationmust be carefully reviewed on a case-by-case basis.

3.4.5 Drilling Fluid

The type of drilling fluid is largely determined by themeans by which the underbalance conditions are created.The the required functions of a drilling fluid used inunderbalanced drilling are not the same as that requiredfor overbalanced drilling. For example, a drilling fluid forunderbalanced operations is not required to fulfill thefollowing functions:

• balance the formation pressure

• minimize formation damage (filter cake and water loss).

However, the fluid must fulfill the following basicrequirements.

• Efficiently transport cuttings from the wellbore (slip andannular velocity) – previous experience demonstratesthat cuttings size in underbalanced conditions are suchthat slip velocity is very low. A circulating sub above themotor provides the first option to increase flow rates for

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solids are routed to a settling tank system, from where thewater is disposed or recirculated and the solids cleanedand dumped (either periodically or at the end of theproject). If water or mud needs to be dumped or treated,the same procedures as for normal drilling operations canapply.

If some of the fine solids are allowed to recirculate, anincrease in fluid density and pumping pressure canresult. In this likelyhood, a centrifuge can be used to treatthe mud downstream the separator(s). Cuttings from thecentrifuge will be collected in cutting bins and sent fortreatment later.

On gas wells, when foam is used, the returns will requirepartial separation to allow the gas to be vented or flaredand the broken foam disposed. On foam-drilled oil wells,the surface equipment may need to be adapted or modifiedto ensure efficient breaking of the returns prior toseparation.

Recirculating foam fluid is an option but requires a specificseparator built to break the foam (by lowering the pHvalue). Following separation, the liquid pH value isincreased to allow recirculation of the foam liquid phase.

3.4.7 BHA Deployment

In underbalanced drilling, the BHA needs to be deployed,that is, run and retrieved under pressure and live wellconditions. There are two basic options, either use anexternal wireline lubricator or an internal lubricator (forexample, deployment against the SSSV).

Lubricator/Riser

The deployment procedures are similar to those usedwhen deploying CT service tools. It will generally benecessary to deploy the BHA in more than one sectionwhen using a wireline lubricator. At some offshorelocations, there is sufficient riser length to allow the BHAto be deployed in one section.

Techniques allowing the well to flow while tripping willminimize formation damage that could result from shut-in.

SSSV Deployment

Deploying against the SSSV results in the well being shutin and therefore balanced. As discussed in a previoussection, the absence of filter cake can affect the formationduring shut-in. However, further studies are required todetermine the extent and nature of such damage.

3.4.8 Installing Completion Tubulars

Installing a Liner

The deployment technique limits the type of liner to apredrilled liner (jointed or coiled) with the holes pluggedwith aluminium. The liner float shoe has an aluminium ballto allow the deployment under pressure. The aluminiumplugs or ball are removed by spotting acid (with a CT workstring) after running and/or setting the liner. A pluggedliner can withstand a maximum differential pressure ofonly 2,000 psi.

If a jointed slick liner (without collars) will be rununderbalanced, the injector head can be used to snub theliner into the well. The length of liner being run will belimited by the CT and injector head maximum pullcapacities.

If a conventional jointed liner with external collars will berun, it will be deployed with a wireline lubricator and thecapacity of the wire line will limit the weight and thereforethe length of the liner.

Coiled tubing liners are run as normal CT using theappropriate size of coiled tubing and well controlequipment.

Installing a Production String

A production string will only be required on CTD operationsnot performed through the production tubing. Either a CTcompletion string is run and the CT unit used to run itunder pressure or a conventional jointed tubing productionstring is run by a snubbing unit.

The maximum CT completion size is currently 3-1/2-in.Transportation and handling of 3-1/2-in. CT strings canbe logistically difficult offshore and onshore. It is likelythat the majority of CT completion strings will be limited to2-7/8-in. or 2-3/8-in.

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3.5 Running and Pulling Wellbore Tubulars

It may be necessary to pull the completion string onreentry wells before sidetracking or deepening. In addition,the completion may be removed to allow access for a linerto cover and protect the build up section. On new wells,it may be necessary to run one or two strings of casing.Two options are available, crane or jacking substructure.Selection depends on the weight of the tubulars to be runor pulled.

Crane

Providing the weight of the tubing or casing string doesnot exceed the crane capacity, this is the simplest methodof running or retrieving the string. However, if the stringgets stuck, there is limited pulling capacity in reserve.

Conventional drilling slips, elevators, and safety clampsare used. Single joints are handled with the crane whichalso holds the entire tubing or casing string in much thesame way as a rig does. A power tong is required to makeup the connections.

The liner or casing string can be run and made up floating,that is, partially empty to limit its hanging weight.

To run a liner we need to consider the weight of the totalweight of the string (comprising the liner string, linerhanger, running tool, and drill collars to provide weight topush the liner around the build up if it is a directional well).

A conventional CT logging deployment technique is usedto make up the connection between the the stripper andthe wellhead after the CT connector has been connectedto the liner string (that is, the liner string is hung off in theBOP rams and the CT connector is made up to the liner).The skate pressure is released to allow the injector headto be stripped over the CT until the BOP/stripper connectioncan be made up. Once all connections are made up andtested, the string weight is picked up and the liner releasedfrom the BOP ready to RIH.

Substructure with Jacking System

Dowell has designed and built three different types ofjacking systems to run or pull wellbore tubulars withoutthe requirement for a mast. Both systems include a

substructure and a set of snubbing jacks. The jacksoperate only with downward loading (that is, they do nothave any snubbing capability).

The Hydra-Rig or Kremco systems have two jacks with a160,000-lbf pull capacity and an 11-ft stroke. The HydraRig system can only be used with 7-1/16-in. or smallerBOPs.

The third system built by Dreco has four jacks with a200,000-lbf pull capacity and an 8-ft stroke. The systemcan be used with an 13 5/8-in. BOP stack and is the bestsystem for drilling aplications.

These substructures accommodate a tubing power tongto make-up or break the tubing connections. Single jointsof tubing are handled by the CTU crane. Both systemsalso allow the injector head to be skidded off the well whenrunning or retrieving the BHA.

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4 SURFACE EQUIPMENT

The type of application, location and complexity of theoperation will determine which items of surface equipmentare specified and then selected. The principal componentsrequired to complete most CTD projects can becategorized as follows:

• CTD substructure or rig

• CT equipment

• well control equipment

• pumping equipment

• mud storage and treatment equipment

• pipe handling equipment

• ancillary surface equipment

• monitoring and recording equipment

• safety and emergency equipment

• rig camp and wellsite facilities.

4.1 Rigs and Structures for CTD

Coiled tubing drilling is performed with the support ofconventional rotary rig masts and substructures, and withspecially designed substructures and jacking systemsdeveloped for CTD. For obvious reasons, substructuresdesigned specifically for CTD offer the greatest potentialfor efficient and economic CTD operations.

4.1.1 CTD Substructures and Jack Systems

On specialized CTD rigs, the functions of the draw-works,crown block, travelling block and drilling line are replacedby the injector head and jacking system . The rotary tablefunction being replaced by a downhole motor.

4.1.2 Location Requirements

New Wells

The location is typically required to be as small aspossible, currently 25m x 32m (Fig. 16) is the minimumfoot print of a CTD rig. A conductor pipe must be drivenprior to the rig mobilization. A small cellar around theconductor will help collect mud and water spills whentripping.

The wellsite requires minimal preparation, basic gradingand levelling generally being sufficient. Provision for guycable anchor points may be required (depending on theconfiguration of the selected equipment).

Reentry Wells

The location has already been established and is generallylarger than is required.

Offshore Wells

The selection and placement of CTD equipment isdetermined by the space and handling capability of the rig(semi) or platform. Tender-assisted operations can simplifyequipment placement. Basic considerations for offshorelocation planning include the following:

• exact dimensions of available space, including details ofareas effected by zoning requirements (Zone I or II)

• deck load capacities, including location of load bearingbeams or restricted areas

• details of the crane capacity and boom extensioncapability.

4.2 CT Equipment Package

• Coiled Tubing – for new and directional wells, CT sizesof 1-3/4, 2 or 2-3/8-in. are required. A wall thickness ofat least 0.156-in. manufactured from 70,000- or 80,000-psi yield strength material is recommended.

For sidetracks, determine the optimum size, wallthickness and yield strength using CoilCADE simulation.For simple well deepenings,1-1/2-in. CT can be used insome circumstances.

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1 – Fuel Tank2 – Generator3 – Choke Manifold

Figure 16a. Typical CTD equipment and location layout – minimum footprint.

Figure 16b. Typical CTD equipment and location layout – heavy set up.

1 – Fuel Tank2 – Generator3 – Choke Manifold4 – Cuttings Bin5 – Centrifuge6 – Tong Power Pack7 – Septic Tank8 – Potable Water9 – Koomey Unit

1 2Cabin

Coiled Tubing Unit

Pump Unit Cra

ne

Tub

ular

sto

rage

Water Mud

3

Mud Mixing

Access

Approx 30m

Approx 18m

15m Zone II

1 2

4 56

7 8

9 3

Store StoreDry MudWater

Cabin

Coiled Tubing Unit

Pump Unit

Cra

ne

Tub

ular

Sto

rage

Mud Treatment

Cabin

Access

Approx 32m

Approx 25m

15m Zone II

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• Injector Head – for new and directional wells, a minimumof 60,000-lbf pull capacity is recommended. For welldeepening a 40,000-lbf capacity injector head may beused if conditions allow. A 72-in. radius gooseneck isrequired for 1-3/4-in. and larger CT.

• Reel – the reel capacity (string length) and weightshould be confirmed. A reel core expander may berequired for 1-3/4-in. and larger CT.

• Powerpack – If nonstandard equipment (for example,high-capacity injector head) or auxilliary equipment is tobe powered by the CTU powerpack, confirmation shouldbe made that the output of the power pack is adequateand that the pressures and flowrates are compatible.

• Crane – for onshore operations, an independant cranetruck is prefered to an integrated crane CTU trailer.Boom length must be sufficient to handle a 40-ft pipe/BHA over the substructure.

• Wireline (for directional drilling with wireline) –A monocable is needed for the Baker Inteq or ENSCO or Drillexsteering tool operation. A Hepta cable is required for theAnadrill Cobra wireline BHA.

The CTL* reel will be equipped with normal reel collectorand pressure bulkhead equipment.

4.3 Well Pressure Control Equipment

• BOP size and pressure rating –The BOP size or boredepends on the hole or planned completion size. TwoBOP sizes commonly used are 4-1/16-in. and 7-1/16-in.In special cases 11-in. BOPs are used. For most CTDapplications, a 5000-psi pressure rating is adaquate butthe operating pressure rating must exceed the expectedbottom hole pressure.

• 4-1/16-in. 10,000-psi quad-ram BOP– standard for CTDoperations (Fig. 18).

• 7-1/16-in. ram BOP – found in single or double, shear/seal or ram configurations. The shear rams can shearthe 3-in. OD BHA components.

• Annular BOP/CT stripper – for CTD, the only function ofthis BOP is to close on the BHA when tripping the BHAor on the liner if a double ram BOP is to be used.

Alternatively, an accepted drilling practice is to drop theBHA in the hole in case of a kick while tripping the BHA.However, local regulatory agencies generally ask forone annular BOP. Annular BOPs are available in 4-1/16- and 7-1/16-in. sizes.

• Kill line – used to kill the well by pumping through/downthe annulus.

• Choke line – used to divert the flow to the choke manifoldwhile controlling a kick and choking wellbore returns.

• Choke manifold – pressure rating must be consistentwith the BOP rating. The manifold must be a drilling-type choke manifold with two manual chokes and onepressure gauge (some applications may require a remoteoperated choke). This equipment is as important as theBOP for the rig safety (Fig. 17).

• Mud return line – normally not part of the well controlequipment but when using two BOP stacks, the mudreturn must be closed if it is necessary to shut in the well.This is achieved with a remote operated valve installedon the outlet of the mud return mud cross.

• BOP controls and instruments – the stripper and BOPare controlled from the CT unit control cabin.

* Mark of Schlumberger

Figure 17. Choke manifold configuration.

Choke line

Degasser Waste

Manual choke

Buffer chamber

Valve

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Figure 18a. Typical well control equipment configurations – for hole sizes up to 4 in.

Choke linewithmanualand remotevalve fitted

Deck/floor levelStripper

4-1/16-in. Quad BOP

Mud cross

Casing spool

Mud cross with manualvalve fitted

Kill line to mud pump

Deck/floor levelStripper

Mud cross with manualvalve fitted

Annular BOP

4-1/16-in. Quad BOP

Mud cross

Kill line to mud pump

Choke linewithmanualand remotevalve fitted

Casing spool

Up to 4-in. hole sizewith annular BOP

Up to 4-in. hole sizewithout annular BOP

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Stripper

4-1/16-in. Quad BOP

Mud cross with manualand remote valve fitted

Deck/floor level

7-1/16-in. Annular BOP

7-1/16-in. Shear/seal BOP

Casing spool

Stripper

Mud cross with manualvalve fitted

7-1/16-in. Annular BOP

7-1/16-in. Shear/seal BOP

Casing spool

7-1/16-in. Pipe/slip BOP

Deck/floor level

Figure 18b. Typical well control equipment configurations – for hole sizes 4-1/16 to 6-3/4 in.

4-1/16-in. hole size andgreater with annular BOP

and shear/seal

4-1/16-in. hole size andgreater with annularBOP, shear/seal and

pipe/slip rams

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For the 7-1/16-in. BOPs and the remote operated valveson the mud return or choke lines, the control position islocated on the accumulator or Koomey unit that must bepositioned next to the CTU cabin. Remote controlsbetween the Koomey unit and the CTU BOP commandpanel can be adapted if necessary.

4.4 Kick Detection Equipment

When drilling overbalanced, rapid detection of kicks orlosses is essential in slimhole drilling applications. Thereare two common methods used in kick detection systems.Both have advantages and disadvantages when used inCTD operations.

• flow comparison (flow in versus flow out)

• mud tank level monitoring.

4.4.1 Flow Comparison

One of the best ways of detecting a flow variation, is tohave a flow meter on the pump suction and one on thewellbore return line. The flow difference is monitored andrecorded versus time. A flow increase indicates a kick,while losses are indicated by a drop in flow.

A mud-pump stroke counter and a flowmeter fitted on themud return line can also provide adequate data for flowcomparison. The outputs of both devices plotted versustime can give a reasonable indication. However, anassumption of constant pump efficiency must be made.

A variety of flowmeters are available for this application.A low-pressure electro-magnetic flowmeter like the DowellMag Flow can be used on the return line.

4.4.2 Mud Tank Level Monitoring

While in principal this system is simple, it is only efficientif the tank section is small enough to enable a smallvolume variation to be detected. An accurate monitoringand recording system is needed to provide a suitabledisplay. A general trend versus time display format isrequired; a digital display is not sufficient. The MartinDecker-Totco sensor system is recommended.4.5 Mud Sytem

4.5.1 Mud Tanks

There are three types, or functions, of mud tank: settling,active and reserve. Additional tankage or storage facilitiesmay be required for water (Fig. 19).

Settling Tank

This is the first tank through which the wellbore returnspass. The shale shakers (where fitted) willl normally belocated above this tank. An overflow system from thesettling tank passes to the the active tank. The settlingtank volume is typically 10 to 15 bbl for 2 to 3 bbl/min flowrates. A large (butterfly) valve is generally fitted to the baseof the tank to allow easy removal of the accumulatedsolids.

Active Tank

The active,or suction, tank stores the drilling fluid andsupplies the mud pump suction. If continuous treatment oradditive is required it may be added to this tank. The tankvolume is generally around 50 bbl for 2 to 3 bbl/min flowrates. This allows a mud volume buffer to help stabilize themud characteristics. Smaller volume active tanks may beused; however, key fluid parameters such as viscosity anddensity can vary quickly if the mud volume is small.

The active tank suction is manifolded to allow recirculationand precharging of the high-pressure pump. In addition tothe recirculation line, a tank agitator is required to maintainthe homogenity of the fluid.

Reserve Tank

The reserve tank(s) are used to store a reserve of drillingfluid and also provide a facility for mud treatment orpreparation. Ideally, the reserve mud volume should beequal to the hole volume plus the active an settling tankvolumes. However, this may be reduced if the well type(exploration or development), downhole pressure or riskof losses allow. Approximately one-half to one-third of thisvolume can be provided in reentry of depleted reservoirwells. Similar to the active tank, the reserve tank shouldbe fitted with a recirculation and agitation system to allowconditioning of the mud.

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Figure 19b. Typical configuration of drilling-fluid equipment – underbalanced operations.

Active

Reserve

Water

Centrifuge

Choke manifold

Mixing Hopper

Centrifugal Pump

Centrifugal Pump

Triplex Pump

Wellbore returns

Three phase separator

Vacuum degasser

Gas to flare or production

Oil to production or storage

Active

Reserve

Water

Centrifuge

Shale shaker

Settling Tank

Mixing Hopper

Centrifugal Pump

Centrifugal Pump

Triplex Pump

Solids sampling

and disposal

Wellbore returns

Figure 19a. Typical configuration of drilling-fluid equipment – overbalanced operations.

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4.5.2 Mud Treatment Equipment

Shale Shaker

A shale shaker is necessary for exploration wells todispose of the large cuttings produced in the top holesection and to collect cuttings for geological analyses.

CTD operations on reentry wells often do not requireshale shakers because of the very small cuttings generatedby the high-speed bit/motor combinations. Short welldeepenings, can generally be performed without a shaker.

Centrifuge

The centrifuge is an essential item for most CTDapplications except short well deepening and shallownew wells. The centrifuge removes very fine cuttings andavoids their recirculation, which would in time increasethe drilling fluid density. Any uncontrolled variation in fluiddensity and solids content can increase the risk of stickingor wellbore instability.

Gas Separation System

Two types of mud degassing equipment are commonlyused (similar to conventional drilling operations).

• Poor-boy degasser – located on the mud return line, itknocks out gas using a system of baffles. The resultinggas is vented from a stack designed to route gas awayfrom work areas.

• Vacuum degasser – creates a partial vacuum in a closedtank to knock out remaining gas. This system requiresan additional centrifugal pump. Generally the twosystems are combined for maximum efficiency.

Three-phase Separators

On underbalanced CTD operations, the mud returns aredirected to the choke manifold then to a conventionalthree-phase production separator. The separated gas, oiland solids are then routed to disposal, production orstorage facilities. The gas is either flared or sent to theproduction line. The oil is either sent to the production lineor stored for later hauling. The residual solids are removedeither periodically or upon completion of the project.

4.6 Pumping Equipment

4.6.1 Low-pressure Pumping Equipment

Low-pressure pumping equipment is necessary fortransferring, mixing and conditioning the drilling fluid. Inaddition, the high-pressure pumping equipment requireslow-pressure charge pumps to operate efficiently. Anadequate pre-charge system is especially important ifkick monitoring equipment is relient on the pump strokecounter for fluid inflow data.

A low-pressure manifold system is typically used with twolow-pressure pumps to enable flexibility and redundancy(Fig. 19). The fluid mixing system typically comprises ahopper and jet mixing system supplied by fluid from acentrifugal pump.

4.6.2 High Pressure Pumping Equipment

The high-pressure pump specifications depend largelyon the hole depth and diameter. For holes smaller than 4-3/4-in., it is unlikely the pressure will exceed 5000 psi anda flowrate of 2.5 bbl/min. For larger holes, typicallyvertical exploration wells, the flow rate may be up to 6 bbl/min. Some redundancy in pumping equipment andcapacity is generally required.

A high-pressure pump remote control panel is generallyinstalled in the CTU cabin. This is necessary to alter orstop the pump flowrate for tool operation or orientation. Inaddition, close control of the CTU and pumping equipmentis necessary if the downhole motor stalls.

High-pressure piping and manifolding is generallyassembled from 2-in. treating line, chicksans and thenecessary valves and accessories.

4.7 Monitoring & Recording Equipment

• Conventional CTU monitoring equipment – required torecord the string cycle and pressure data for analysiswith CoilLIFE. A TIM* device should also be regardedas critical monitoring equipment.

• Other monitoring recording systems like the PC-basedPRISM* 2 and 3 software provide real time acquisition,recording and display of the data from a variety ofsensors. It provides the CT operator with digital display

*Mark of Schlumberger

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operations at night.• Air compressor – provide air to start the CTU engine if

the tractor is not on location, or provide compressed airas needed.

• Miscellaneous – cutting torch and welding machine.

4.10 Safety and Emergency Equipment

• Emergency kill – emergency kill on the CTU engine andpump engines.

• Fire fighting equipment – CO2 fire extinguishers on CTU

power pack, pumping unit power pack, near theportacabins, near the fuel tank.

• H2S protective equipment and gas detection equipment–

generally provided by the operator.

• Eye wash station – located next to the mixing facilty witha precharged tank filled up with treated water.

• Mud handling protective equipment – apron, goggles,long sleeves gloves for chemical handling.

• First aid kits.

4.11 Equipment and Consumables Chcklists

The checklists shown in Fig. 20 and 21 are intended as aguide for the compilation of checklists for specificoperations.

or plots versus time through bar charts or strip charts ona monitor in the CTU cabin and also allow data analysisin the CTU or in an office. It makes the CTD job safer(kick detection) and drilling more efficient (all parametersdisplayed versus time, showing trends, rate ofpenetration, etc.).

4.8 Pipe Handling Equipment

This pipe handling equipment is used for handling jointedpipes (for example, drill collars, tubing joints, casingjoints, etc.)

• Tubing spider slips – used to hold the BHA or jointedtubing when making up or breaking two joints.

• Elevators – used to handle single joints of DC or tubingor casing.

• Safety clamps – used as a safety device to prevent thestring from falling into the hole, if the slips do not holdand the string slides.

• Tubing power tong – used to make up or break the BHA,casing or tubing connections at the proper torque.

• Crane – used to handle single joints of BHA, casing ortubing. If necessary, it may be used to handle/run thewhole BHA or casing string if within the crane capacity.

• Substructure and jacking sytem – used to pull or run awhole casing or tubing string. Has a 170,000-lbf pullingcapacity–single joints are still handled by the crane.

4.9 Ancillary Surface Equipment

• Substructure – used as a drill floor when tripping theBHA and as a support for the injector head when drillingor tripping the CT.

• Generator – provides electricity to the portacabins, floodlights, centrifuge, monitoring equipment, koomey unit,etc.

• Electrical distribution panel – provides electricalconnection between the generator and the variouselectrical devices with all necessary breakers and safetyfeatures.

• Flood lights – to provide lights for safe and efficient

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COILED TUBING DRILLING EQUIPMENT CHECKLIST

Offshore Onshore Short Well Other ProviderWells Wells Deepening Wells (guide only)

Coiled tubing equipmentCTU control cabin X X X X DowellCTU Power pack X X X X DowellCT injector head X X X X DowellCT reel X X X X DowellJacking frame As required a/r a/r a/r DowellCrane As required a/r a/r a/r Dowell/client

Well control equipmentBOP – Ram X X X X Dowell/rentalBOP – Annular X X X X Dowell/rentalWellhead adapters X X X X Dowell/rentalMud cross X X X X Dowell/rentalRiser and/or spacer spools X X X X Dowell/rentalAccumulator unit X X X X Dowell/rentalChoke manifold X X X X Dowell/rentalFlowmeters X X X X DowellPit/tank level indicators As required a/r a/r a/r Dowell/rental

Drilling fluid equipmentCTD mud treatment unit n/a If available - X Dowell

Alternative equipment– DowellRemote controlled pump unit X X X X DowellSettling tank X X X X DowellActive tank (with paddle agitators) X X X X DowellReserve tank As required DowellCentrifugal pump and power pack X X X X DowellLow pressure mixing hopper X X X X Dowell

Pump unit (standby) As required DowellDrill water tank n/a X As required X DowellCentrifuge X X n/a X Dowell/rentalCuttings bin X X X X Dowell/clientFlareline As required Dowell/clientHP filter screens (Slim1*) X X n/a As required DowellThree-phase separator As required a/r a/r a/r Well TestingVacuum degasser As required a/r a/r a/r Dowell

Pipe handling equipmentJacking substructure As required a/r a/r a/r DowellPower tong X X X X Dowell/rentalSpider slips X X X X Dowell/rentalElevators and clamps X X X X Dowell/rentalLifting sub(s) X X X X Dowell/rental

Figure 20a. Coiled tubing drilling equipment checklist.

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COILED TUBING DRILLING EQUIPMENT CHECKLIST (continued)

Offshore Onshore Short Well Other ProviderWells Wells Deepening Wells (guide only)

Ancillary surface equipmentSubstructure (if jacks not used) As required X X X DowellFuel tank and pump n/a As required - - DowellGenerator As required a/r a/r a/r DowellElectrical distribution panel X X a/r a/r DowellCabin(s) (furnished) X X a/r -a/r DowellPotable water tank As required X a/r a/r DowellLighting As required a/r a/r a/r DowellAir compressor As required a/r a/r a/r DowellSteam cleaner X X a/r a/r DowellLocation mats - As required a/r a/r Client

Monitoring and recording equipmentTotco monitoring system X X X X DowellDowell PAQ* X X X X DowellMulti channel recorder X X X X DowellFlowmeters X X X X DowellPACR* X X X X DowellTIM* device X X X X Dowell

Safety equipmentEmergency engine kill X X X X DowellH

2S safety equipment As required a/r X X Dowell

Gas detection/monitoring equipment X X X X DowellFire extinguishers X X X X DowellSewage system (cabins) n/a As required - - DowellEye wash station(s) X X X X Dowell

Casing/liner running equipmentElevators and clamps As required a/r DowellCasing or liner joints As required a/r ClientCasing shoe or float As required a/r ClientLiner hanger As required a/r ClientRunning/setting tool(s) As required a/r DowellDrill collars As required a/r Dowell/rentalDrop ball sub a/r Eastman

Figure 20b. Coiled tubing drilling equipment checklist.

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Section 1110 Rev A

COILED TUBING DRILLING CONSUMABLES AND MISCELLANEOUS SERVICES CHECKLIST

Vertical Short Well Sidetrack ProviderWell Deepening Well (guide only)

Equipment spares and consumablesPump parts X X X DowellShaker screens X X X DowellMud unit sparts X X X DowellCTU parts X X X DowellWell control equipment parts X X X DowellFuel, oils and lubricants X X X Dowell

Drilling consumables

Drill water X X X ClientPotable water As required a/r a/r ClientDiesel ClientMud products Dowell/clientLCM As required a/r a/r Dowell/clientCement (and additives) As required a/r a/r DowellBits X X X Dowell/clientCore bits As required a/r a/r Dowell/client

Logistics

Vehicles for crew Onshore only DowellHelicopter or crew boat Offshore only ClientConsumables haulage X X X ClientVacuum truck Onshore only ClientCuttings disposal X X X ClientRadio communications As required Client

Sidetracking equipment

Whipstock - - As required Dowell/VendorWhipstock anchor - - As required Dowell/VendorSetting tool (s) - - As required Dowell/VendorGyro/survey equipment - - As required Dowell/VendorMill(s) - - As required Dowell/VendorLow-speed motor - - As required Dowell/Vendor

Logging tools and service

CCL (for sidetrack KOP) SchlumbergerCBL (for sidetrack KOP) SchlumbergerOther services as required Schlumberger

Figure 21. Coiled tubing drilling consumables and miscellaneous services checklist.

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5 DOWNHOLE EQUIPMENT

The downhole tools and equipment required for any CTDproject is dependent on the complexity and specificconditions under which it is to be completed. Most toolsand equipment used in association with CTD may besummarized in the following categories.

• bits

• downhole motors

• downhole CT equipment

• BHA for vertical well or well deepening- drill collars

• directional drilling BHA- MWD or WL steering tool- monel, UBHO- orienting tool

• special BHA components- drilling jars- thruster- underreamer

• fishing tools- overshots- fishing jars, spears- magnets, junk catchers.

5.1 Bits

Depending on the hole diameter, two kinds of bits aretypically used. For 4-3/4-in. holes and larger, rock bits,tricones or drag bits are used. For holes smaller than 4-3/4-in., drag bits are generally used.

The motor/bit combination for any application is crtiticaland can drastically change the rate of penetration (ROP).The use of small downhole motors developing high rpmand little torque makes the drag bit selection difficult andit is recommended that selection is made by consulting bitmanufacturers with the following information.

• formation type, hardness and abrasiveness

• torque developed by the motor (high torque motors arerecommended)

• motor speed

• available WOB

• frilling fluid type and flow rate.

Experience in a particular area/formation is the best basisfor recommendation of bit/motor combinations.

5.1.1 Rock Bits

Rock bits or tricone bits have three rollers with bearingsthat can be sealed or nonsealed (that is, mud lubricated).There are two main categories, steel tooth bits and insertbits. Both are available in different tooth design to drillvery soft to very hard formations. The insert bit life isgenerally longer and it is more expensive than the milltooth bit.

Roller cone bits operate by crushing, gouging anddeforming the rock (Fig. 22) with the drilling efficiencybeing dependent on the weight-on-bit (WOB). Rock bitsor tricones are designed to turn at relatively low speed(generally not more than 150 rpm) and are not reliable fordiameters smaller than 4-3/4-in. The risk of losing conesis high, especially when used in small diameters and withhigh speed.

5.1.2 Drag Bits

Drag bits do not have any bearings or rotating parts andare designed to cope with the high speed of the downholemotors. Two main types of drag bits are used: PDC bits(Polycrystalline Diamond Compact) and TSP bits(Thermally Stable Polycrystalline).

PDC bits operate by shearing rock material much like theaction of a machinists tool on a lathe. TSP bits have asimilar cutting action, but are more tolerant of heat so aresuitable for harder formations. However, the TSP bitcutting surface is significantly smaller than the PDCcutter, consequently penetration rates are typically less.

In general, drag bits operate more efficiently with lessWOB than roller cone bits but are more sensitive to rateof rotation.

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Some drag bits, and all rock bits, are equipped withtungsten carbide nozzles that are interchangable andavailable in different diameters. The nozzles create a jetimpact onto the formation and help clean the bottom ofthe hole. Most small drag bits do not have nozzles buthave ports which give a jetting effect (Fig. 23).

5.2 Downhole Motors

There are three types of dowhhole motors: turbines, vanemotors and positive displacement motors.

• Vane motors – there is limited experience with this typeof motor. Currently, only one manufacturer continues todevelop vane motors (Volker Stevin).

• Turbines – not yet available in small diameters.

• Positive-displacement motors (PDM) – available in allsizes but especially small diameters.

5.2.1 Positive Displacement Motors

The basic specifications for PDMs relate to the followingcriteria.

• OD – the size of a motor has a direct bearing on most ofthe other criteria, for example, larger motors outputgreater torque and require a greater flow rate (Fig. 24).

• Number of stages (stator and rotor lobes) – the numberof stages define the type, that is, low or high speed (Fig.25). In general, for a given size of motor, the greater thenumber of lobes,the higher the motor torque and thelower the output speed.

• Maximum flow rate – each size of motor is designed tooperate within a specific throughput volume of fluid.Multi-lobe motors typically have a wider flow range witha higher maximum allowable flowrate. This can be animportant consideration which effects the hole cleaningability for a given bit/motor combination.

The flow rate through motors is frequently used tocharacterize performance.

• speed versus flow rate

• operating torque versus flow rate

Bit insert

Crushing action

������

��������

PDC insert

Shearing action

Figure 22. Rock bit cutting characteristics.

Figure 23. PDC bit cutting characteristis.

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Rubber stator

Rotor

����

�����

���

7:8 (multilobe) configuration for lower-speed and

higher torque

1:2 lobe configuration for high-speed and

low torque

Motor housing

TYPICAL PDM SPECIFICATIONS

Hole size 6-in. to 7-7/8-in 4-3/4-in. to 5-5/8-in. 3-1/2-in. to 4-1/8-in.Motor OD (nom in.) 4-3/4 3-1/2 2-7/8Motor type Low High Very Low Low High Low High

Speed Speed Speed Speed Speed Speed Speed

Maximum speed 140 to 250 350 to 450 170 400 600 to 700 400 800Operating torque (ft/lbf) 1500 950 700 500 300 300 200Flowrate (gal/min) 250 250 110 110 100 100 100Max differential pressure (psi) 350 500 400 500 700 500 700

Figure 24. Typical PDM specifications.

Figure 25. Typical PDM stator/rotor configurations.

• Maximum pressure drop – when a motor is operatedoff-bottom, a certain pressure loss is required to turn therotor. This pressure loss and motor speed is proportionalto flow rate. A typical no-load pressure loss is ±100 psifor motors used in CTD applications.

As WOB is applied, the pressure required to turn therotor will increase. This increase in pressure is generallycalled the motor differential pressure (Pressure on-bottom – Pressure off-bottom).The motor torque-outputis directly proportional to the motor differential pressure.For a typical 3-1/2 or 2-7/8-in. multi-lobe motor thepressure drop across the motor can be 500 psi or more.

• Differential pressure at max operating torque – thepower output curve of a PDM is parabolic (Fig. 26).Although the operating characteristics of the motor willchange with “operating hours” the same generalperformance profile will be mainained. All motors havea maximum recommended differential pressure. At thispoint, the optimum torque is produced by the motor.

• Maximum stall torque – if the WOB is increasedsufficiently to cause the motor differential pressure torise above the maximum recommended, a stall is likely.At this point, the stator distorts, allowing some passageof fluid without turning the rotor (that is, the drilling fluidflows through the motor without turning the bit). A sharp

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pressure increase will result, and no variation will beevident as further WOB is applied. The motor is stalledand severe damage will result if pumping continues.

Other specifications like maximum overpull and maximumWOB are generally not limiting parameters for CTDapplications.

Recommendations regarding the selection of PDMsinclude the following.

• OD – select the largest possible motor size.

• motor speed – select a low-speed high torque motor forslim holes, with the highest maximum torque rating forthe given size. A high flow rate is desirable to ensureadequate hole cleaning.

• large motors (4-3/4-in.) – the maximum stall torque plusa 30% safety margin should be less than 80% of themaximum allowable torque of the CT string.

5.3 CTD Downhole Equipment

CT Connectors

After performing several jarring and pull tests of varioustype CT connectors, it is recommended that a grub screw

connector be used for CTD applications.

Disconnecting Subs

For CTD applications in large vertical hole (6-in. or greater),a pull disconnect release is recommended.

In reentry wells or deep vertical wells, pull disconnects(such as Griffco) are not recommended due to very limitedoverpull margin it allows because of the drag.

For MWD applications, the Dowell/Anadrill drilling head,which includes a ball-actuated disconnect, isrecommended.

Wireline steering tool BHAs can include an electricallyoperated disconnect (Anadrill Cobra), or a pull disconnectwith a fail-safe (Baker Inteq BHA).

Check Valves

Double flapper valves should be used on top of thepressure disconnect in case of disconnection in a kicksituation (even if a float valve is installed on top of themotor).

5.3.1 BHA For Vertical Wellbores

The BHA required to drill vertical wellbores usesconventional components, the larger versions of whichare commonly used in conventional rotary drillingapplications.

A typical CTD BHA for drilling vertical wellbores willinclude the items shown in Fig. 27.

Drill collars are used to provide the weight on bit (WOB),with the CT being kept in tension at all times. This createsa pendulum effect which, in the majority of circumstanceswill maintain a vertical wellbore. Spiralled drill collars arerecommended to minimize differential sticking–especiallyfor slide-drilling applications. The selection of drill collarsof the appropriate size (OD) is dependent on the bit/holesize. The following recommendations are made.

Hole Size Drill Collar OD>6 in. 4-3/4 in.

3-3/4 to 4-3/4 in. 3-1/8 in.<3-7/8 2-7/8 in.

Figure 26. Typical PDM performance curve.

Ho

rsep

ow

er

Pump Pressure

Stall starts

Rapid pressure rise

Total stallOff-bottom

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Figure 27. CTD BHA for vertical wellbores. Figure 28. CTD BHA for deviated wellbores.

CT connector

Disconnect sub

Drill collars –length determinedby necessaryWOB

Downhole motors

Bit

Coiled tubing

CT connector

Disconnect sub

Coiled tubing

Orienting tool

Bit

Downhole motorwith adjustablebent sub

Nonmagnetichousing forsteering tool

Check valve(Double)

Check valve(Double)

±3 ft

WOB

±10 ft

±3 ft

±10 ft

±30 ft

±12 ft

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5.3.2 BHA for Deviated Wellbores

The BHA required to successfully drill deviated wellborescontains several specialized components which, in mostcases, have been specifically developed for CTDapplications.

There are no drill collars in this BHA. The weight on bit isprovided by CT string, part of which will be in compression.

A typical CTD BHA for drilling deviated wellbores willlinclude the items shown in Fig. 28.

5.4 Principal Components of a Directional BHA

Directional BHA used for CTD are also called steerablesystems. A steerable system provides the directionaldrilling engineer with data to enable information relatingto the the tool face, wellbore inclination and azimuth to bemonitored and recorded. By combining this informationwith the measured depth of the wellbore, the progress ofthe wellbore can be compared, and, if necessary,corrections to the planned wellbore profile can be madeby changing the toolface (that is, the relative position ofthe bent housing to the low [or occassionally high] side ofthe wellbore).

Two steerable systems are commonly used in CTDapplications:

• wireless steerable BHA including a measurement whiledrilling (MWD) tool

• wireline steerable BHA including a wireline steering tool.

MWD Tool/System

The MWD tool sends data to surface by inducing codedpressure pulses in the drilling fluid being pumped throughthe CT string. The signals recovered at surface aredecoded and displayed using a personal computer.

A schematic diagram of the Slim 1 MWD system is shownin Fig. 29.

The principal advantage of the MWD system is theabsence of wireline and electrical connections, which area potential source of problems.

The disadvantage of the MWD system is the slow datarate, that is, one tool face every 30 seconds, one survey(inclination and azimuth) every 30 minutes. However, thisis generally sufficient to control the trajectory of a CTDwellbore. Since the downhole components are sensitiveto debris in the drilling fluid, it is generally necessary touse a high-pressure filter system. This is typically locatedadjacent to the reel manifold.

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Figure 29. MWD system schematic diagram.

MWD assembly

Nonmagnetic

housing for MWD

Upper CT BHA

Coiled tubing

PDM with bent sub

Bit

Pressure transducer on reel manifold

Data processing and display of directional information

Remote display/monitoring or recording

Fluid pumps

Data transmitted by pressure pulse telemetry

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Section 1110 Rev A

Figure 30. Wireline steering system schematic diagram.

Wireline steering

tool assembly

Nonmagnetic

housing for

wireline steering

tool

Upper CT BHA

Coiled tubing

PDM with bent sub

Bit

Pressure bulkhead – electrical access to tubing

Data processing and display of directional information

Remote display/monitoring or recording

Fluid pumps

Data transmitted through wireline inside CT string

Components within reel core and on reel axle

Reel   collector – electrical access to rotating reel

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Electrically Operated Orienting Tools

A wireline provides electrical power to a DC motor in theorienting tool, which drives a gear train (Dowell, Anadrill,Cobra) or a hydraulic pump (Baker Inteq) to adjust thetool face angle.

These orienting tools provide high torque and allow toolface correction while drilling. Alternative tools are operatedor controlled by electrical or hydraulic systems throughcables or conduits installed in the CT string.

Hydraulically Operated Orienting Tools

A hydraulic orienting tool is operated via hydraulic controlline(s) installed in the CT workstring (Camco andTransocean).

5.5 Specialized CTD Tools

Float Sub

The float sub (where fitted) is installed above the motor toprevent wellbore fluids from entering the BHA andworkstring. The internal valve closes in the event of a kickor underbalanced drilling situation. A Baker 1R floatinstalled in a 3-in. OD sub is recommended.

Drilling Jars

Drilling jars should be included in a CTD BHA if there isa risk of sticking through formation instability of differentialpressure.

Underreamers

There are two common conditions in which underreamersenable a larger hole to be drilled; in through-tubingapplications where a fixed restriction limits the bit sizeand in conventional applications where the CT stringcannot provide the necessary WOB. It is not generallyrecommended that drilling and underreaming areundertaken at the same time. Instead, it is preferable todrill a pilot hole which is then underreamed to the desiredsize.

The underreamer is positioned in the BHA above the bitor bullnose.

Wireline Steering Tool

Wireline steering tools are basically the same type of toolas MWDs but data is transmitted to surface through awireline. The advantage being the high data rate, whichprovides almost real-time measurement. However, thenumber of electrical connections required presents anumber of potential problems (Fig. 30).

Some operating conditions (for example, drilling withfoams and gaseous fluids) preclude the the use of MWDsystems since pressure pulses are absorbed by the fluidcolumn. In such circumstances the wireline steeringsystem and associated toolstring must be used fordirectional control.

Monel – Nonmagnetic Drill Collar

A non-magnetic tubular is required to house the steeringtool assembly. This typically consists of two 15-ft sectionsof 3-in. OD drill collar made of non-magnetic material tolimit magnetic interference.

Orienting Tool

An orienting tool is necessary to change the orientation oftool face. The MWD system incorporates an orienting toolthat rotates in 30° increments. This tool can only be usedwith a wireless steering system.

Similar orienting tools are available for use with wirelinesteering tools (Sperry Sun and other vendors). Theygenerally provide a low torque, with the toolface correctionbeing made off bottom.

Three main types of orienting tool are currently available.

• pump-actuated orienting tools

• electrically operated orienting tools

• hydraulically operated orienting tools.

Pump-actuated Orienting Tools

The first generation Dowell Anadrill CTD orienting tool isan indexing tool which is actuated by shutting down thepump, then resuming circulation. Each cycle causes thelower section of the tool to rotate 30°.

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Section 1110 Rev A

Thruster

Thrusters were developed to avoid the consequences ofthe heavy vibration, which is typical of equipment used inslimhole applications. The thruster dampens vibrationsand equalizes the WOB.

Fishing Tools

A selection of fishing tools should be prepared for, or atleast be on stand-by during CTD operations. The natureand size of the fishing tools will be dependent on the CTDBHA to be used and the anticipated downhole conditions.Fishing tools may be needed at any time. Appropriatecontingency plans should be prepared during the well-planning phase of the operation.

A typical fishing tool selection can include the followingitems:

• GS fishing tool (or similar) – to suit the fishing neck of therelease joint being used

• overshots and spears – available in a variety of sizesand configurations to suit the toolstring in use

• junk catchers and magnets – appropriate precautionsmust be taken at all times to avoid the introduction ofjunk to the wellbore. In addition, it is recommended tohave fishing tools for small items and junk on-site at alltimes.

6 MANUFACTURERS AND SUPPLIERS

Following is a list of manufacturers and suppliers ofequipment and tools that can be required during CTDoperations. This list was prepared for information purposesand does not necessarily constitute a recommendation orpreference. In most cases, it is the ability of availablesuppliers to provide a reliable and efficient service thatdetermines the ultimate choice of equipment.

Bits

• Baker Hughes• Security• Hycalog• Smith

Motors

• Anadrill• Drillex• Baker• Black Max

Steeriable CTD Systems

• Dowell Anadrill wireless BHA (with SLIM1)• Dowell Anadrill wireline Cobra BHA• Baker Inteq (wireline system)• Sperry Sun (wireless system)• Camco (wireline system)• Drillex (wireline system being devloped)

Fishing Tools and Equipment

• Tristate• Enterra.