ct basics and applications for student

8/19/2019 CT Basics and Applications for Student

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Coiled Tubing

Basics & Applications

Presented By:

Nguyen Tan Khoa

Lead Well Operations Engineer

KNOC Vietnam

Ho Chi Minh City

Nov 14, 2015


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Contents

Part 1: Coiled Tubing Basics

• Why Coiled Tubing?

• Fabrication

• Coiled Tubing Equipment

• BHA

• String Characteristics & Selection

• Safety Considerations & Failure Modes

• Job Modeling

• String Life Management

2


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Contents

Part 2: Coiled Tubing Applications

• Circulating, Cleanouts & N2

Lifting

• Milling, Fishing• Logging & Perforating

• Fluid / Chemical Placement

• Down-hole Camera

• Gravel Packs & Sand Control

• Hydra-Jet Technology

• Fracturing

• Moving & Setting

• Tractors

• Tapered OD Coil

• E-Coil

• Coiled Tubing Drilling

• CT Boat Operations

• Capillary Coil

3


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Why Coiled Tubing?

4

Part 1: CT Basics: Why Coiled Tubing?


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• What are the options, when .. – Fish (object) in the well

– Hard scale deposits in the casing

– You need fluid placed into 1 zone, but not all – Logging into a horizontal well

• You will need something to reach in the well… – To grab objects

– To transport sensors

– To pump & circulate fluids

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6

Electric Line – Wire Line

• A metal wire, or electric cable, inserted into the wellbore.• Carries tools to perform work.


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Pro

• Lightweight, fast, small.

• Can deploy sensors, set

plugs, and move objectsinto the well. (Highly

versatile)

• “Light touch” - can perform

sensitive operations.• Can work under-balanced =

the well is live and flowing.

Con

• Cable is gravity fed into the

well

– Steep deviations andhorizontal wells can be un-

reachable.

– Cannot set-down much

weight on bottom.

• Cable is weak (low pullstrength)

• Cannot circulate fluids.

7

Electric Line – Wire Line


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• Drilling rig

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Pro

• The most powerful option.

• Can deploy heavy-duty tools

into the furthest parts ofany well.

• Can circulate fluids.

Con

• Well must be dead.

• Expensive (!)

• Large (!)

• Slow

9

Drilling Rig


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Hydraulic Work Over

• Like a small drilling rig, uses joints of pipe.• Can work under pressure (well is live).


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Pro

• Can pump fluid.

• Can set-down & pick-up

high weights.• Can deploy tools, sensors,

plugs, etc into the well.

• Stiff, can reach deviated &horizontal sections of the

well.• Can work under-balanced =

the well is live and flowing.

Con

• Large footprint on theplatform. (A lot ofequipment)

• More expensive than E-Lineand Coiled Tubing

• Heavy weights on theplatform structure.

• Uses joints of pipe, like adrilling rig = slowoperations.

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Hydraulic Work Over


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Coiled Tubing

• A continuous metal tube,inserted into the wellbore.


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Pro

• Can pump fluid.

• Can set-down & pick-up highweights.

• Carries tools, sensors, plugs,etc into the well.

• Stiff, can reach deviated &horizontal sections of the well.

• Continuous tubing = fast

• Can work under-balanced =the well is live and flowing.

Con

• Large footprint on the

platform. (A lot of

equipment)• More expensive than E-Line

• Coiled tubing reel is heavy

to pick up.

13

Coiled Tubing

IN SUMMARY …. Coiled Tubing offers a good

balance between size, cost, weight, & efficiency.


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14

Maybe that’s why it’s so popular around the world …


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Fabrication of Coiled Tubing

15

Part 1: CT Basics: Fabrication of Coiled Tubing

Some images courtesy Quality Tubing


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Raw material is suppliedin a roll of standard

mass.


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• Steel is

rolled

into

sheets.

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• Sheets are

pressed to

an exact

thickness

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• 40,000 lb

rolls.

• Each roll is a

specific

thickness of

steel plate.

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• Rolls are

cut down

into

“slits”.

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• The slits are

transported

to another

factory.

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• Slits are

prepared

for the

nextprocess.

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24


Bias welds:

- Distribute the

weight- Distribute the

Fatigue

- Can only be madebefore the metalis rolled to a tube.

End of Strip A

Start of Strip B


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25


Factory Butt Weld(aka “Orbital Butt Weld”)

Factory Bias Weld

- All factory welds- Strongest

- Resist Fatigue


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26

Fabrication of Coiled Tubing


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• Making

a Bias

Weld

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Part 1: CT Basics: Strip welded at 45 deg

•Computer

assisted welding.

•Results

recorded.

•Approved weld

procedure


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29


Conventional Step- Tapered String Design

.109”

Wall

.118”

.125”.134

”

b f l d b


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• Continuous rolling can form a linear taper.

• This design will reduce metal fatigue.

30


P 1 CT B i F b i i f C il d T bi


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• The spool

has become

larger after

many stripsare joined

together.

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P 1 CT B i F b i i f C il d T bi


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32


Coiled Tubing Milling Process

Accumulator

Tube

Forming

HFI

ERW

Seam

Anneal

Air

Cool

Water

Bath

Sizing

Rolls

Eddy Current

NDE

Air Cool

Water

Bath

Full Body

Stress Relief

Take-up

Spool

O.D & I.D.(FF)

Scarfing

P t 1 CT B i F b i ti f C il d T bi


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• Knife cuts off material that is extruded from the welding process

• Any impurities on edge of strip are pushed out of the weld



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36


Part 1 CT Basics Fabrication of Coiled Tubing


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37


• Spool

rotates at

mill speed

• Tubing laidproperly

on spool.

Part 1: CT Basics: QTI Product Size Range


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Part 1: CT Basics: QTI Product Size Range

3.500 in

2.875 in

2.625 in.

2.375 in

2.000 in

1.750 in

1.500 in

1.250 in

1.000 in

0.750 in

0.625 in Wall Thickness: .087” to .203”

Hydrotest/ Drift


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Hydrotest/ Drift

• Test for 15 minto 80% Int.Yieldfor CT & CLP.

• Gauge Ball runto Drift ID

• Alternativepressures andtimes available

Laboratory Testing


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Laboratory Testing

• Each end of each string is testedfor physical properties.

• Inside sections taken from prior

data

• Full sections pulled• Microhardness in body,

in HAZ, & at seam.

Tensile Test OD Measurement


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Tensile Test - OD Measurement

• True OD on tensile

samples

measured

• Used to compute

metal cross-

sectional area

Microhardness Testing


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Microhardness Testing

• Knoop hardnesstesting conducted

axially in weld, HAZ

(heat affected zone)

and body.

• Convert to HRB/C

(Hardness Rockwell

B/C).

Tensile Testing


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Measures strength and elongation (ductility)

Tensile Testing

Flaring Tests


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Flaring Tests

• Flaring testsexpand

pipe wall

and weld.

• Meet API

5LCP

Flash Free Tubing


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Flash Free Tubing

INTERNAL WELD FLASH REMOVAL Internal weld bead is cut from tube

wall during milling, and then pumped-

out of finished, spooled tubing.

1.50” OD and larger

Non-tapered strings only.

ADVANTAGES

Clearance for internal running tools

(swab cups, plungers)

Transfer to Customer Reel


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Transfer to Customer Reel

• From stock toCoiled Tubing

Unit

Coiled Tubing Failures


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Coiled Tubing Failures



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• Did you Know?

– A CT String from the factory usually contains 6 or more sections (and 5or more welds).

– Purchasing a string requires 6 months for delivery, with a cost ofapprox. $100,000 USD.

– One String is good for about 30-40 Runs in the well. (Highly dependenton the company, the fluids being pumped, the application beingapplied).

– The old coils can be sold as scrap metal. However, they are more

commonly purchased by oil companies for use as velocity strings, andbough by locals who use the tubing for a variety of things such asfence-posts, furniture making, etc.

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Part 1: CT Basics: Coiled Tubing Equipment


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Coiled Tubing Equipment

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• Reel (or Drum)

– Holds the CT

– Hydraulically powered,

for spooling purposes

only. – Does NOT pull/push CT

in/out of the well.

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Reel Plumbing


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g

Broken Reels !


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• Level-Wind (or,

Horses-Head)

– Helps guide the CT

onto the reel

57

g q p



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• Gooseneck (or, Guide-Arch)

– Sits on top of the Injector

– Guides and bends CT, as the

CT moves between the Reel,

and the Injector

58

g q p


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• Injector

– Grips the CT with metalblocks, which are attached tochains.

– Pulls and pushes the CT

in/out of the well. – Most units pull between

35,000 lb – 135,000 lb

– Push (snubbing) is usually ½

of pull capacity. – Hydraulically powered.

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• Injector Chains

– Move the coiledtubing

– Two sets of chains

– Are rotated by theinjector, to move

the coil in/out of

the well.

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• Injector Blocks

– Make contact

with the coil.

– Two shapes –

round or “V”

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• Linear Beam Cylinders

– Chains are squeezedtogether by hydrauliccylinders.

– These squeeze the coil until

there is enough friction toprevent slipping on theblocks.

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Weight Indicators


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Hydraulic weight indicator.

Used on 38K Injectors and smaller.

Weight Indicators (cont.)


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Electronic Load Pins

(two used)

Used on all injectors

60K and above.

Tubing Guide


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(95K)

Electronic Depth Head – Below Chains


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• Stripper

– The Key component to CT operations! – Located below the Injector

– It wraps and holds a sealing material around the CT string

– It allows CT to move in/out of the pressurized wellbore and,

prevents wellbore pressure from escaping.

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• Stripper

– Common design: A door opens to expose the rubber

sealing material inside. This allows it to be changed

during the job.

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Sidedoor Stripper Elastomer


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• Lubricator (or, Riser)

– Sections of large, hollow pipe,below the stripper.

– Connect to the BOPs.

– Function as a place to keep thetool-string before and after the job (since, the toolstring cannotpass up through the injector andaround the goose-neck).

– Thus, allows the tool-string to be

completely removed from thewell with the wellhead closed.

– Needs to be as long as the tool-string being used for the job.

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• Quad BOP’s

– Well control for emergencysituations. Function exactlythe same as on a Drilling rig.

– Typical configuration shown(top to bottom).

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Blind

Shear

Slip

Pipe / Tubing



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• Dual-Combi BOP’s

– Save space vs Quad BOPs

– Typical configuration

shown (top to bottom).

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Blind + Shear

Slip + Pipe



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• Control House

– Cabin for personnel to operate all CT controls

– Data storage, display, recording.

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Part 1: CT - Data Acquisition System


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• Provide Real-time Operator Information – Measured parameters - weight, speed, depth pressure

– Calculated parameters - stresses, collapse, tubing life

utilization

• Determine Tubing Status – Tubing life management

– Real time effects

• Provide Job Records



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• Power Pack

– Diesel engine supplies Hydraulic energy to operate

the BOPs, Injector, and Reel (connected through

hydraulic hoses).

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• Injector Stand / Lift Frame

– Usually includes hydraulicup/down movement to adjustthe injector height.

– Supports the Injector, when acrane is not available for theduration of the job.

– Most land jobs cannot use aninjector stand due to lack of

suitable foundation (the groundis too soft and un-even).

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• Offshore Lift Frame – Can be used inside a drilling rig

derrick – Can be heave-compensated for

floating applications.

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• High Pressure Fluid Pump

– Diesel engine, drives a Positive-DisplacementPump

– Capable of extremely high pressures (15k psi)

– Fluid rates up to 10 BPM is common.

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• N2 Converter

– Converts liquid N2 to gas form by applying heat. – Pumps gaseous N2 at specified pressure and rate

(up to 300,000 scf/hr and 15,000 psi is common)

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• N2 Tanks

– 2,000 gal liquid N2 is

common

– Cannot store long time –they are well insulated but

heat does get in, N2

vaporizes every Part.

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• Batch Mixer

Large mixing tanks(typically 50 - 100

BBL) with paddles

inside to mix

chemicals, fluids.

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• Acid Tank

– Safely transport rawHCl or other acids.



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• Fluid Holding Tanks – 100-200 BBL is

common

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• Generator

with Lights

• Sand Trap

– Prevent

returned sand

from entering

production


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• Treating Iron basket

86

• Air Compressor

(used to start thediesel engines)

Also brought to location, but Not shown:

• Chemical Totes

• Downhole-tool basket

• Hoses basket

In Summary, CT Jobs Require a Lot of Equipment and Preparation

Part 1: CT Basics: BHA


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BHA (Bottom-Hole Assembly)

87Some images courtesy Gaggie Tool Corporation



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• BHA (Bottom Hole Assembly)

– The Coiled tubing is often just a means of conveyance,to carry tools into the well.

– The tool-string attached to the end of the coil is called

the BHA.

• Nearly all BHA’s have 1 thing in common: the MHA.

– The Motor-Head Assembly (MHA), is the first part of the

tool-string. It joins the coiled tubing with the tool-string.It also provides some basic safety functions.

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• Coil Connectora. Attaches to the coiled

tubing with rolls/dimples,

or grapples.

b. Provides a threaded

connection for the

remaining tools.

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• MHA

1. Double Flapper Check Valve

a. Allows pressure and fluid to flow out of the

coil, but not in.

b. This is a critical safety tool in the event that

CT develops a leak or break on surface. Inthat case, only the DFCV will be preventing

wellbore pressure escape.

c. Spring actuated flappers automatically close

when flow is stopped

d. Balls can be pumped through the flappers

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• MHA

2. Hydraulic Disconnecta. Sometimes the tools being run in thewell can get stuck. By offering ameans to remove the BHA, it can beleft behind while the CT string isrecovered to surface.

b. Can be activated by dropping a ball(which lands in the tool and shearssome connecting pins).

c. Lower body has internal fishing neck

d. Circulation above ball after

disconnecte. Pressure-balanced to preventaccidental release

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• MHA

3. Circulating Suba. If the tool being used gets blocked (and fluidcan no longer be circulated), it’s important toregain the ability to circulate.

b. This tool has openings on the side of the

tool, allowing fluid to be circulated throughit, instead of the BHA below.

c. Can be activated by dropping a ball

d. Gives a circulation path above motors orother tools

e. Saves excessive motor wearf. Higher circulation rates than available with

drilling motors

Rupture Disc Sub


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• MHA

4. Rupture Disc Suba. Provides a method of establishing

circulation in a bull - plugged

situation or in emergencies

b. Available in a wide range of burstpressures

c. Generally run as a component of

the BHA in CT drilling applications

Motorhead Assembly


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Double Flapper

Check Valve

Hydraulic

Disconnect

Ball DropCirculating

Valve

Rupture

Disc Sub

• Can be constructed using the

previously mentioned tools,

or

• Can be purchased as a single, morecompact assembly

• Below the MHA, more tools can be

added for increased functionality.

Part 1: CT Basics: String Characteristics & Selection


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String Characteristics & Selection

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• Length:

– Long enough to reach the deepest zone +contingency

– Weight issues if it’s too long?

• Diameter:1.00” - 1.250” - 1.500” - 1.750” - 2.000” – 2.375” –

2.875” – 3.500”

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Higher fluid rates

(better for cleanout)

Higher pull strength

1” Smallest 3.5” Largest

Smaller Coil Larger Coil

Higher fatigue life

(more runs)

Higher collapse resistance

(for high pressure wells)


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100

• Grade of steel – 70, 80, 90, 100, 110, 125 (newly developed)

– Higher numbers = harder, stronger.• Allows higher pull weights. OR same pull weights w/ smaller coil.

– Quality Tubing company – “QT-700, QT-800”..etc

– Number translates into tensional strength:• 80 grade steel has tensile strength of 80 k psi

• 90 grade steel has tensile strength of 90 k psi• etc

QT-800

80,000 lb to yield

1”

1 “

? lb to yield

Depends on:-Diameter

-Thickness


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Part 1: CT Basics: Safety Considerations & Failure Modes


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103

Axial failure,

too much tension.

Notice the necking.


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105

Collapse,

too much external pressure.



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106

Burst,

too much internalpressure.



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107

All of these can lead to damaged equipment, job failure, wellcontrol issues, and loss of lives with injury.

These incidents occur when:

- The job is not modeled properly.- The job recommendations / program are not taken

seriously (not followed).

- Job parameters change and modeling is not updated.

Job Modeling is the safety-net to prevent these failures.

Part 1: CT Basics: Job Modeling


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Job Modeling

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109

• Coiled tubing has many failure mechanisms and manyforces are at play. – Tension, compression, internal & external pressure, torque,

bending, helical & sinusoidal buckling, fatigue, ovality

• The forces interact with each other - synergy betweenthem.

• Only the computer can account for all forces andinterpret their effects.

(no tables or handbooks should be used )



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110

What is Fatigue?

• Cumulative structural damage to a material, from repeated cyclic loading.

• It’s an invisible phenomenon (lab cannot test a sample and conclude the

degree of material fatigue).

• Highly predictable (with the right model).

• It’s tracked only by computer.

– Accurate record keeping is imperative.

• Only occurs when the pipe is being bent, while moving in/out of the hole

(stationary pumping does not accumulate fatigue).



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111

How many bends does each location in the

coil make, while making one complete trip inand out of the well?

Ans: 6

1. (RIH) Unbending off the reel

2. (RIH) Bending onto the guide arch.

3. (RIH) Unbending off the guide arch.

4. (POOH) Bending onto the guide arch.

5. (POOH) Unbending off the guide arch.

6. (POOH) Bending onto the reel.



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• A Special Note on Fatigue:

• Fatigue is a complex calculation affected by: – CT Diameter

– CT Material

– CT Wall Thickness

– Pressure in the CT while it is being bent

– Radius of bending at the reel, guide arch

– Tension in the coil while bending

– Fluid contacting the coil while bending (H2S, Acid, CO2)

– Stress risers (cuts, step wall changes) – Previous fatigue history

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• Forces (and fatigue) are modeled real-time in the

Control Cab

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Operators watch

fatigue progressand get instant

feedback on

fatigue tracking

0 2000 4000 6000 8000 10000 12000 14000

Length from Reel End (ft)

0

10

20

30

40

50

60

70

80

90

F a t i g u e ( % )

Calculated Fatigue Base Fatigue

Run (Default Run_1) - Fatigue

Project Name: CTU simulation classHALLIBURTON

INSITEforWell Intervention v4.1.0

18-May-10 21:34


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-20000 -10000 0 10000 20000 30000 40000

Surface Weight (lbf)

0

2500

5000

7500

10000

12500

D e p t h ( f t )

Lockup 1 Trip In 1

Trip Out 1 Yield 1

Run (Class Example) - Weight [Trip In/Out]


INSITEfor Well Intervention v4.1.0

18-May-10 23:41

Lockup Yield

POOH WeightRIH Weight



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118

When RIH withcoil at 7500’

deep, what is

the expected

surface

weight?

Ans: ~ 5,000 lb-20000 -10000 0 10000 20000 30000 40000


0

2500

5000

7500

10000

12500

D e p t h ( f t )

Lockup 1 Trip In 1

Trip Out 1 Yield 1




18-May-10 23:41



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119

Notice, thetapered

section is

reflected in

the yieldlimit.

-20000 -10000 0 10000 20000 30000 40000


0

2500

5000

7500

10000

12500

D e p t h ( f t )

Lockup 1 Trip In 1

Trip Out 1 Yield 1




18-May-10 23:41


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121

1000 lb set-down

on surface

0 lb set-down on

bottom

200 lb200 lb

200 lb

200 lb200 lb

Because there is no axial force

pushing the bottom tip of the string,

it stops. It cannot RIH further.

= LOCKUP



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122

What is lockup?

Lockup occurs when the coil

stiffness is no longer

sufficient to overcome

mechanical friction, and no

axial force is beingtransferred down hole.

It can only occur while RIH.

Think of a wet noodle.

-20000 -10000 0 10000 20000 30000 40000


0

2500

5000

7500

10000

12500

D e p t h ( f t )

Lockup 1 Trip In 1

Trip Out 1 Yield 1




18-May-10 23:41



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123

• When lockup is reached, pushing harder on surface will not

get the bottom tip of the coil any further in the hole.• Pushing more may sinusoidally or helically buckle the coil.

Sinusoidal Helical



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• Modeling also accounts for … – Stretch

– Weight on Bit

– Fluid Densities and Loss – Expected pumping pressures

– Fluid Velocities

124


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Part 1: CT Basics: String Life Management


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• The Coiled tubing string is fragile• Service companies will need to interrupt the

job and manage their string life.

– Fatigue – Corrosion

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127

- This coil is only 30% used.

- A single fatigue spike from

milling caused this fatigue

spike to 80%.

- The coil cannot be used

anymore.

- Welding – not a positive

option.

- This is why fatiguemanagement on the job is

critical.

0 2000 4000 6000 8000 10000 12000


0

10

20

30

40

50

60

70

80

90

100

F a t i g u e ( % )

1

Fatigue, String Diagram - 100306/MAWC13/69POT21, Derated Zones



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128

• The welder must be flown in from abroad, as

there are only 4 or 5 people in the world who

meet the standards for welding CT.

• A Manual butt-weld requires approx 1month of planning, 2 Parts in the yard,and approx $20,000 USD to install.

• The manual butt-weld will only extendthe coil life by a maximum of 15%.


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• Part 2

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Contents


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Part 1: Coiled Tubing Basics

• Why Coiled Tubing?

• Fabrication

• Coiled Tubing Equipment

• BHA

• String Characteristics & Selection

• Safety Considerations & Failure Modes

• Job Modeling• String Life Management

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Contents


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Part 2: Coiled Tubing Applications

• Circulating, Cleanouts & N2

Lifting

• Milling, Fishing

• Logging & Perforating

• Fluid / Chemical Placement

• Down-hole Camera

• Gravel Packs & Sand Control• Hydra-Jet Technology

• Fracturing

• Moving & Setting

• Tractors

• E-Coil

• Fluid Pulsing Communication

• Acoustic Communication

• Coiled Tubing Drilling


• CT + HWO Combination

• Capillary Coil

131

Part 2: Applications: Circulating, Cleanouts & N2 Lifting


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Circulating, Cleanouts & N2 Lifting

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• How can you solve these problems? You wantto:

– Inject cement directly into the 3rd set of perfs fromthe top of the well (but 10 sets of perfs are open

…) – Wash acid onto an obstruction in the well.

– Remove produced sand from the top of a bridgeplug, so that you may remove it.

• Will bull-heading cement, acid, or water,achieve these results?

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• Coiled Tubing’s specialty: to circulate fluiddown the coil, and up the annulus.

– Fluid can be water, gel, acid, N2, solvent, … (etc)

– Fluids are not usually reverse-circulated (downannulus & up CT) because of safety concerns.

• Cleanouts (removing sand, debris, etc), and

N2 Lifting, are the most common jobs forcoiled tubing.

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• Fluid Types: – Brine water (to protect open formation from

water/clay damage)

– Sea or Fresh water, (if clays are not present) – “Gel” (guar-based additive + water)

– Acid (to remove scale from the wellbore)

– Solvents (to remove waxes, parrafins, etc) – N2 gas (inert, easy to transport, inexpensive)

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• Wash Nozzles

– Most cleanouts and circulatingtreatments only require a simple

wash nozzle on the bottom of the

coiled tubing string.

136


The idea of a cleanout is simple but requires detailed


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137

The idea of a cleanout is simple, but requires detailedpre-job engineering.

• Confirm the maximum fluid rate possible

(pressure dependent).

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Pressure (psi)

-2500

0

2500

5000

7500

10000

12500

D e p t h ( f t )

Case (1.0 bpm, 1.50 inch coil, FR-48) - CTPressure Case (1.0 bpm, 1.50 inch coil, FR-48) - Annulus Pressure

Case (1.0 bpm, 1.25 inch coil, FR-48) - CTPressure Case (1.0 bpm, 1.25 inch coil, FR-48) - Annulus Pressure

All Cases - Pressures

Project Name: CTU simulation class

HALLIBURTONINSITEforWell Intervention v4.1.0

26-May-10 15:40

1.50” 1.25”

1.0 BPM


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• What velocity is needed to carry solids?


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139

• Depends on the solids, the fluids, and wellbore deviation.

For a Vertical Well:

Fluid Velocity UP

Settling Velocity DOWN

(Particle Density,

Shape, &

Fluid Viscosity)

Resulting

Upward

Motion of

particle



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140

•

How can you get a better cleanout in avertical well?

• Answer:

– Increase fluid velocity (up)

– Decrease particle settling velocity (down)

• More viscous fluid

• Heavier fluid



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• How about in a Deviated well..• Does anything change?

141


For a Deviated or Horizontal Well:


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142

• In well deviations > 30 degrees, fluid velocity is more important

than settling velocity.• Maintaining Turbulence is critical.

Just a few

inches

LAMINAR FLOW


For a Deviated or Horizontal Well:


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143

• In well deviations > 30 degrees, fluid velocity is more important

than settling velocity.• Maintaining Turbulence is critical.

Just a few

inches

TURBULENT FLOW



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144

• If maintaining turbulence is critical in a deviated wellborecleanout, which fluid is best to remove solids from the well –

straight water, or viscous gel?

• Ans: Straight water will maintain turbulence (and cleanoutefficiency) in a deviated wellbore. Gel pills will remain in the

laminar regime, causing solids to settle, thus decreasing

cleaning efficiency.



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145

Wiper Trips through thedeviated section may be

necessary.



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146

• While removing sand/etc from the wellbore, any suspendedsolids act to increase the weight of the annular fluid.

• This changes the hydrostatic weight of the fluid in the

annulus, and must be accounted for to prevent losses to theformation.

– ECD = Equivalent Circulating Density, ppg

• ECD can be controlled by RIH slowly while cleaning solids with

coiled tubing.



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147

Sea Water

8.6 ppg

Reservoir

4,000 psi

Hydrostatic

@ perfs

3,500 psi

All cleanouts are under-balanced

(Otherwise the fluid + solids would gointo the formation!)

Confirmed by receiving returns at surface.



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148

Sea Water +

Too Much Sand

ECD = 11.0 ppg

Reservoir

4,000 psi

Hydrostatic @

perfs

4,500 psi

Over-Balanced Condition

No Returns at surface(No solids being removed)

Surface pressure < Header Pressure

Chance of getting coil stuck

“N2 Lifting” – Removing fluid from the wellbore



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N2 Lifting Removing fluid from the wellbore

149

• Only need to remove enough fluid to get under-balance.• Calculate the height of fluid you need to remove + 20%

• If N2 is jetted below open perfs, it may go into formation. – That’s why N2 lifts require coil is above the top perf.

N2 Cleanouts – Mixing N2 + Fluid to clean debris



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N2 Cleanouts Mixing N2 + Fluid to clean debris

150

• N2 can be used to lighten the fluid (reduce hydrostatic)• Best cleanouts are using “foam” = 60-95% quality

0 10 20 30 40 50 60 70 80 90

N2 Quality (%)

-2500

0

2500

5000

7500

10000

12500

D e p t h ( f t )

CT N2 Quality Annulus N2 Quality

Case (Default Case_1) - N2 Qualities


INSITEforWell Intervention v4.1.0

26-May-10 21:24

•400 psi WHP

•400 scfm N2

•0.40 bpm sea water

85 Q on surface

60 Q at bottom

This is an acceptable foam.


• Let the model calculate the optimum cleanout


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151

• Let the model calculate the optimum cleanout

or N2 lift.• It will balance the competing forces of:

– Particle size, density

– Fluid viscosity

– Formation pressure

– Hydraulic Friction

– Pump rates

– RIH/POOH speeds


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Part 2: Applications: Milling & Fishing


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• Milling and Fishing are also amongst the mostcommon and useful applications of Coiled

Tubing.

• Extremely wide variety of tools and functions

is available in the market. Only some of the

basics will be covered here.

153


• Rotation is performed with a down-hole, Positive


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154

Displacement Motor - similar to those used in Drilling.

POWER

SECTION

FLEX

SHAFT

BEARING

SECTION

DRIVE SECTION

BIT

SUBROTOR / STATOR

Fluid rates through Coiled tubing can commonly provide 1-3BPM (depending on the size of the CT), to power the down-

hole motor.

• Common reasons to use CT milling:



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Common reasons to use CT milling:

– Remove hardened scale and other deposits on thetubulars.

– Drill out plugs and debris from the well.

– Reaming collapsed or deformed tubing.

• PDM’s can also be used for: – Rotating fishing tools (spears, grabs, fishing necks,

etc)

– Jet nozzles (for cleanout, cutting, etc) – Cutting casing and tubing

155

• Various styles of bits are available for each



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• Various styles of bits are available for each

application.

156

WATERMELON TAPERED

FLAT

BOTTOM

MILLBLADED JUNKPDC

MILL

Concerns during the job:



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g j

• The greatest concern while milling or fishing with coiledtubing is fatigue management . – Milling & fishing both usually require many small movements

of the coil, at the target depth. (Recovering from a stalledmotor, catching the fish, adjusting the milling rate, etc).

– Each pick-up and set-down on bit will create fatigue in the CTsection at the gooseneck.

– Excessive CT movements at the same depth, will build acumulative fatigue spike in the CT section at surface.

– Fatigue spikes will cause the CT string to reach the end of itslife, and interrupt the job, usually with costly delays.

157


70

80

u e ( % )


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• Torque: – Under high torque loads, PDM’s will usually stall

before the torque limit of the CT string is reached (and

therefore, watching torque is not often a concern). – Instead, preventing a stall is important to prolong the

life of the PDM.

158

0 2000 4000 6000 8000 10000 12000


0

10

20

30

40

50

60 F a t i g u

1

Brief overview of tools used in fishing & milling:



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g g

JAR

159

WEIGHT

BAR

BI-DI INTENSIFIERBI-DI JAR

- The JAR provides instant

release of stored energy

to the Fish

- The Weight Bar addsmass

- The Intensifier protects

the CT string from this

energy, and also,

concentrates the energy

onto the fish.



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Impact Hammer

160

-Flow activated impact hammer

-Up to 800 impacts / minute

-Selection of impact bits available.



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Overshot

161

-Holds onto a fish with grapples, or a

fishing neck profile.

-Releases by pumping, cutting, or dis-

assembly (at surface).-Some designs can pump into the fish.

S-150

S-10 & S-

20KELO

SOCKET

GUIDE HOOK

WALLPACK-

OFF


WIRE


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Spears

162

CRANK

SPEAR

WIRE

SPEAR

2 OR 3

PRONG

SPEAR

WIRE

PUSHER

-Grab onto cable

and wire.


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Part 2: Applications: Logging & Perforating


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Logging & Perforating

164Some images courtesy Halliburton & SLB

• Wide variety of PL (production logging) tools



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• Wide variety of PL (production logging) tools

available – similar to Eline/Wireline selection

165

• Video– V02 – Cobra PerforatingPart 2: Applications: Logging & Perforating


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166

• Logging and Perforating with CT because:



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Logging and Perforating with CT because:

– CT can reach into deviated and horizontal sections

of the well better than Eline/Wireline

– Ability to perform CT jobs on the same well

without rigging up/down between CT and Eline

167

• Array logging tools



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Array logging tools

– Useful in deviations &horizontal

– True fluid profile

168

Part 2: Applications: Fluid / Chemical Placement


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Fluid / Chemical Placement

169


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• Benefits of Targeted Placement: – Precise placement, only where needed.

– Avoid contamination of expensive treatmentfluids.

– Reduce exposure of completion tubulars tochemicals and pressures.

– Smaller treatment volumes.

• How to do it?

171

• Video – V03 – Straddle Packer Injection


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172



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173

• Perf Balls



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– Ball OD should be ¼” larger than perf OD

– Bio-degradable balls available

– Temperature dependent

174



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• Foam Diverter

– 65% -80% Foam quality• Vgas / ( Vgas + V liq)

– Foam will Increase the apparent viscosity, providediversion of fluid to next section

– Increasing gas saturation, can provide resistance

to liquid in terms of relative permeability

175


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Pulsonix, Continued..


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– Fluid bursts generatepulsating pressure waveswithin the wellbore andformation fluids, thus aidingin placement of treatment

fluids through acousticstreaming.

– Pressure waves can breakup many types of near-wellbore damage through

cyclic loading. – Pressure waves push the

fluid deeper into formation.

177

Part 2: Applications: Down-hole Camera


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Down-hole Camera

178Some images courtesy TecWell

• Downhole cameras

Part 2: Applications: Down-hole Camera


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– Can be run on‘communicating coil’

– Generates down and side-views

– Often, not very clear,unless in dry gas or clearfluid wells.

– In the right circumstance,

better than LIB (orguessing!)

179


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Part 2: Applications: Gravel Packs & Sand Control


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Gravel Packs & Sand Control

181Some images courtesy Halliburton


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• These are the screens.


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183



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184



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185

Part 2: Applications: Hydra-Jet Technology


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Hydra-Jet Technology

186Some images courtesy Schlumberger & Halliburton

• Hydra-Jet Technology:



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y gy

– Strong jets of fluid, mixed with abrasive (sand),

pumped against the tubulars.

– Creates holes in the tubulars, in about 5 minutes,with 1,500-4,000 psi differential pressure.

– Jet size ~ ¼”

– Perforation size ~ 1”

– Perforation depth 3”-10” is common.

187

Part 2: Applications: Hydra-Jet TechnologyHydra-Jet Perforating


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188


Schematic of Jet Stream in a Hydra-jetted Perforation Tunnel


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189

Jet Stream Divergence and Full Returns

10


Hydra-Jetting Perforations


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190

• Eroded Perf Tunnels

• Reduced Near-Wellbore

Fracture Entry Issues

• High Concentration ofProppant at the

Perforations

• Slots can be created

• NWB Damage and Rock

Stress Greatly Reduced.


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• Hydra-Jet Technology, for cutting Casing



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• Jetting Tool + Rotating tool + 100-mesh sand = cuts Casing.

• Slices control lines/varying thicknesses/etc more effectively than

explosive & chemical cuts

192

Part 2: Applications: Fracturing


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Fracturing

193

• Fracturing treatments are generally bullheaded down the well.



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194

• Why use coiled tubing for fracturing?



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– Faster than a traditional bullhead frac.

– Save time and money.

– Isolate the zone, Perforate, Fracture, and Cleanup… all in a single run.

195



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• Video – V06 - Hydra-jetting with coil• Video – V07 – Hydra-jetting, sand plugs,

cleanout.

• Video – V08 – Hydra-jetting, sand plugs, cleanout.

• Video – V09 - TIME SAVED with CT frac

196


Further benefits of using CT for fracturing..

http://c/Users/ntkhoa/Documents/Videos/V06%20-%20SurgiFrac_C.mpghttp://c/Users/ntkhoa/Documents/Videos/V07%20-%20CobraMax.mpghttp://c/Users/ntkhoa/Documents/Videos/V07%20-%20CobraMax.mpghttp://c/Users/ntkhoa/Documents/Videos/V07%20-%20CobraMax.mpghttp://c/Users/ntkhoa/Documents/Videos/V08%20-%20CobraMaxAP_03.exehttp://c/Users/ntkhoa/Documents/Videos/V08%20-%20CobraMaxAP_03.exehttp://c/Users/ntkhoa/Documents/Videos/V08%20-%20CobraMaxAP_03.exehttp://c/Users/ntkhoa/Documents/Videos/V09%20-%20CobraFracFS.exehttp://c/Users/ntkhoa/Documents/Videos/V09%20-%20CobraFracFS.exehttp://c/Users/ntkhoa/Documents/Videos/V08%20-%20CobraMaxAP_03.exehttp://c/Users/ntkhoa/Documents/Videos/V07%20-%20CobraMax.mpghttp://c/Users/ntkhoa/Documents/Videos/V06%20-%20SurgiFrac_C.mpg


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– Better control over the frac job. – Place many small zones.

• Operators used to have to try andcover many small zones with 1 frac.

• Now, they can target each oneindividually.

– Horizontal & Vertical wells.

– No Isolation Needed• Un-cemented wells = ok

– Perforating is low cost.

– Better quality perforations.

197

Side

View

Hydraulic Fracture

D

Lf

KOP

Pzy

HM

AXHM

AX

HMI

N

Part 2: Applications: Moving & Setting


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Moving & Setting

198

• Because CT can usually reach to



199/230

Because CT can usually reach to

all parts of the well, (andpush/pull once it gets there), it’s

also used to:

– Shift sliding sleeves (open/closezones). Hydraulic or manual

operation.

– Set plugs, junk catchers, sensors,

and tools in the well.

199



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• Video – V10 – Stim-sleeve movement

200

http://c/Users/ntkhoa/Documents/Videos/V10%20-%20DeltaStimSleeve.exehttp://c/Users/ntkhoa/Documents/Videos/V10%20-%20DeltaStimSleeve.exe


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• A “Tractor” is an electrical or fluid powered tool,

Part 2: Applications: Tractors


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which can be put on the end of Coiled Tubing,and helps Pull or Push the end of the coil.

202

• Sometimes CT doesn’t have the stiffness to



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Sometimes CT doesn t have the stiffness to

reach the furthest parts of a well.

• Tractor can assist, generally pulling ~ 2-10,000

lb (varies widely with configuration and size)

• Also helps CT move sliding sleeves and

operate other down-hole hardware.

203



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• An alternative design: – Video – V11 – crawler action

204

Part 2: Applications: E-Coil

http://c/Users/ntkhoa/Documents/Videos/V11%20-%20Crawler_Action.wmvhttp://c/Users/ntkhoa/Documents/Videos/V11%20-%20Crawler_Action.wmv


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E-Coil

205

• One method to communicate with the bottom

of the CT string: E-coil



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of the CT string: E coil

• An electrical cable is injected into the CT string

206

• E-line Cable InjectorReturned Fluid

to Storage Tank

Wireline Pressure

Control Head

“Stuffing Box”

PumpedFluid

Wireline

Spool

Cable

Injector

Coiled Tubing

Reel


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•

208


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• Slack management needs to be watched

211

Part 2: Applications: Coiled Tubing Drilling


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CTD (Coiled Tubing Drilling)

212

Some images courtesy X-Treme Coil Drilling,

NOV, Schlumberger, and Baker Hughes

• Coiled Tubing Drilling and Finishing



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– CT cannot rotate, but a wide range of motors and mills exist formilling and drilling

– Underbalanced: CT’s built-in pressure control system, reducesformation damage (no losses to formation).

– Faster trip times, shorter rig-up time, than drilling rig

– Common application of CTD

• Re-Entry drilling• Wellbore extensions

• Sidetracks

• Economically access new/bypassed payzones

• Slim-hole exploration wells213

– Underbalanced “finishing” also gaining acceptance

• Well is drilled using conventional methods, and casing is run.Th CT i d t d ill ( d b l d) th h th i



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Then CT is used to drill (underbalanced) through the reservoirsection.

• CT is better suited to deal with the formation pressure andproduced hydrocarbons.

214


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216



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217

Part 2: Applications: CT Boat Operations


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CT Boat Operations

218Some images courtesy Schlumberger, Halliburton




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219

– When the platform is too small – Or the crane capacity too light (20 MT crane =

minimum)

• Faster operations for many platforms

– No rig up/down on each platform

• Injector and Reel usually on the platform

– Pumps, power pack, fluids, etc, on the boat

• “Catenary Operations” = reel is on the boat



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220

• Catenary Operations



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– Reel Control house

– Main-Gooseneck

– Deck-Gooseneck

– Video Monitoring

221

• Catenary Operations



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222

• Emergency CT Disconnect System



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223

Part 2: Applications: CT and HWO Combination


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CT and HWO (Jointed Pipe)

Combination

224Some images courtesy Halliburton

Part 2: Applications: Micro-Coil


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Micro-Coil / Capillary Coil

225Some images courtesy BJ Services


Micro-Coil (Capillary Coil)


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226

• Miniature CT unit – similar to wireline• 5/8” CT is common

• When size & weight are a priority, this unitcan save money vs full-sized CT

• Useful for low-rate fluid injection, orspotting small amounts of fluid – Scale inhibitors

– Foaming agents

– Parrafin solvents


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•

227


Pro

• Lightweight

Con

• Very low pumping rates (2-4


228/230

• Small and easy to transport

• Fast rigup / rigdown

gpm)• Low pickup / setdown

capability

• Low torq resistance (cannotuse a rotating motor)

• Easy to get stuck (in waxes,sludge, etc) and very littleover-pull available to getfree.

228

• Conclusions


229/230

– CT can be scaled up & down, but it remains an

extremely versatile Well Intervention technology

• Work under pressure• High tech, low-tech, large and small

• Overlaps abilities of HWO, Eline, Wireline, Drilling Rig

– Many new technologies are being developed to

further increase the functionality of CT

229

Thank you for your time !


230/230

Future questions, comments, and more information:

Nguyen Tan Khoa , Lead Well Operations Engineer