Coiled-Tubing-Intervention para la industria

Coiled-Tubing-Intervention para la industria petrolera

1. 1
Section 10
Coiled Tubing

2. 2
Surface Equipment

3. 3

4. 4
World Wide CT Records
Largest CT in Use 3-1/2"
Max Depth 24,000'
Max Horizontal 17,000' (80 deg)-Wytch BP
Longest BHA 1500' - perf guns - UK
Longest Strings 23,000' of 2-3/8"
28,000' of 1-1/2
Max Wellhead Pressure9800 psi
Max Deployment Press 4500 psi
Max BH Temp 700F - Mex, 780F Japan
Max Acid at Temp 28% at 280F in Dubai
CT in H2S 75% in Greece
98%/300F- Gulf of Mexico
(string used one time)
CT in CO2 15% - (string ruined)
Coiled Tubing Worldwide Records

5. 5
Power Pack
Injector
Reel
Operator’s Cab
Transports
And
Pumpers
wind direction
Typical Coiled Tubing Layout

6. 6
Typical Onshore CT Unit

7. 7
Operator’s
View

8. 8
Source: Alaska PE Manual
Alaskan Coiled Tubing Unit With North Slope Modifications

9. 9
Injector Head With Support Rig

10. 10
Coiled Tubing Equipment Basics
•Surface Components
–Coil
–Power Pack
–Component Controls
–Reel
–Injector Head (with guide arch)
–Well Control Components

11. 11
Varied CT Unit Component Types
•CT diameters
•CT wall thickness
•CT tapered strings
•CT strength ranges
•CT metal choices
•Composite material tubing

12. 12
Coiled Tubing Diameters (O.D.)
•1/2”, 3/4”, 1” early diameters
•1-1/4” & 1-1/2” onshore workhorses (also 1-3/4”)
•1-3/4” to 2-3/8” larger work strings offshore (3-1/2”)
•3-1/2” & 4-1/2” recent advances
•6-5/8” & 7” these larger strings for flow lines

13. 13
Tapered Strings
•Common
–I.D. taper or weld area taper
•Uncommon
–O.D. taper
•deeper wells
•hydraulic problems

14. 14
junction weld
in flat strip
Early Weld Types
To Connect CT Lengths

15. 15
bias weld
in flat strip

16. 16
Field Welds On Coiled Tubing
•always a butt weld
•may decrease tensile strength of coiled tubing
by 50% or more
•quality of field welds varies enormously
•avoid field welds where possible
–upper part of tubing is worst place for a butt weld
•area of highest stress in tension

17. 17
Material Strengths
•55,000 psi (limited)
•70,000 psi (still in use)
•80,000 psi (most common)
•90,000 psi
•>100,000 psi
–Which strength to use ?
Higher strengths are a good investment, but can
fail under corrosion and mishandling
- increasingly used

18. 18
Coiled Tubing Usage
By Tubing Strength
Strength % Units In Service Type Service
•100 & 90 ksi 24% Specialty
•80 ksi 44% W/O, Drill, & Comp
•70 ksi 20%
•60ksi 7% Hangoff
•52 ksi 5% Pipelines

19. 19
Trade-Offs
•strength vs cost
•ductility / weakness vs strength / cost
•corrosion possibilities
•strength vs service life
•in general, high strength CT lasts longer and is more
fatigue resistant
•regarding corrosion, high strength CT is susceptible
–hardness matters
–stress corrosion cracking and embrittlement

20. 20
Analysis of Coiled Tubing
Mod A606Mod A607
Carbon 0.08-0.150.08-0.17
Manganese 0.60-0.900.60-0.90
Phosphorus0.030 max0.025 max
Sulfur 0.005 max0.005 max
Silicon 0.30-0.500.30-0.45
Chromium 0.45-0.700.40-0.60
Nickel 0.25 max0.10 max
Copper 0.40 max0.40 max
Molobidum 0.21 max0.08-0.15
Cb-V 0.02-0.04
Molybdenum
. .
Coiled Tubing Metallurgy

21. 21
Yield StrengthHRB HRCMin. Elong.
(psi)
50,000 22
70,000 85-94 30%
80,000 90-98 28%
90,000 94 22 25%
100,000 20-2522% est.
110,000 22-2818% est
SPE 46052
New Coiled Tubing Properties

22. 22
Hardness vs SSC
0
2
4
6
8
10
12
14
16
18
20
19 20 21 22 23 24 25 26 27 28 29
Hardness, HRC
S
S
C

R
e
s
i
s
t
a
n
c
e
,

S
c
Corrosion Resistance vs Hardness

23. 23
Composites
•one company producing now in limited lengths
•composites lighter / more flexible than steel
•3 to 5 times the cost of steel or higher
•not a replacement for steel
•limitations:
–Temperature
–Downhole buckling resistance

24. 24
Advanced Composite
Spoolable Tubing Design
•Thermoplastic Liner For
Pressure Containment
•Carbon Fiber And Epoxy
Matrix Structural Body
•Kevlar And/Or Fiberglass
Outer Layer For Wear
Protection And Damage
Tolerance

25. 25
Surface Equipment
•Power Pack
•Reel
•Controls
•Injector
•Seals

26. 26
Power Pack
•Prime Mover
–hydraulic pump
•requirements set by equipment in use

27. 27
Coiled Tubing Unit Controls
•not just a weight indicator
•load cell readout(s)
•injector monitoring
•injection pressure monitoring
•well control equipment
> also monitor micro vs macro movements

28. 28
Inside The Operator’s Cab

29. 29
Weight & Pressure Indicators

30. 30
Digital Data Readout & On Board Computer

31. 31
Running Speeds
•first time in a well - 40 to 70 ft/min
•normal operations - 50 to 100 ft/min
•emergency - as required, with caution
•runaway - experienced 800 to 900 ft / min

32. 32
Reel Functions
•storage of CT
•dispensing / take-up of tubing
•fluid head junction
–maintained seals prevent pressure loss

33. 33

34. 34
Reel Details
Reel
Components

35. 35
Fluid Head
Connection

36. 36
Reel Capacity Variables
•reel diameter
•reel width
•hub diameter - set by CT OD
•pipe OD
•tightness of wind (operator expertise)
•total tubing weight
A Function Of:

37. 37
Reel Information for Various Sizes of CT
CT Diam.Reel Hub Diam.Guide Arch(Reel Width)Approx. Capacity
(in) (in) (in) (in) (ft)
0.75 48 48
1 60 48-54
1.25 72 48-72 117 17500
1.5 84 (48)-72 128 15000
1.75 96 72-96 148 18000
2 96 72-96
2.375 108 90-120
2.875 108 90-120
3.5 120 90-120
Selected Reel Diameter Information

38. 38
Spooling Yield
•coiled tubing reel must have proper radius
•tubing yields as it is spooled
•radius to produce proper yield is:

R = E (D/2) / S
y
where:
R = bend radius, ft
E = elastic modulus, 30x10
6
psi
D = tubing diameter, in
S
y = yield strength, psi

39. 39
Levelwind
•helps position the CT on the reel in the
most compact arrangement
•depth control device mounting point

40. 40
Levelwind

41. 41
“Gooseneck” Or Guide Arch
(On All CT Units)
an offshore layout
tubing from reel

42. 42
below horizontal to
horizontal

43. 43
Coiled Tubing Injector Head
•injector head evolution
–wheel, chains, and back to the wheel
•gripper design and effect on the tube
•power requirements
•load cells
•wear and failure points
•control vs “micro” control

44. 44
Coiled Tubing Unit Injector Heads

45. 45
Complete Coiled Tubing Unit Offshore Layout
Injector Head

46. 46
Injector Head Problems
•older injector heads
–valves in hydraulic lines were problems areas
•chain breaks - runaways
•power ratings may vary
•total size, height & coil contact problems
–in tight areas or offshore tight spaces

47. 47
Injector
Head
Sketch

48. 48
Ribbed
Injector
Block

49. 49
Smooth
Faced
Injector

50. 50

51. 51
Bottom Injector Sprocket

52. 52
Snubbing / Stripping Forces On CT
•Force to push CT through stuffing box/stripper
– opposite running
•Force on CT from Well Head Pressures
–upward force
•Force to overcome friction
–opposite running
•Force from weight of CT & BHA
–downward

53. 53
Pressure Induced Snubbing Force VS Well Head Pressure for Various Coiled
Tubing Sizes, (Must add stripper friction force)
0
20000
40000
60000
80000
100000
120000
140000
160000
0 2000 4000 6000 8000 10000 12000 14000 16000
Well Head Pressure, psi
B
a
s
e

S
n
u
b
b
i
n
g

F
o
r
c
e
,

l
b
s
1" CT
1-1/4" CT
1-1/2" CT
1-3/4" CT
2" CT
2-3/8" CT
2-7/8" CT
3.5" CT
Wellhead Snubbing Force On CT

54. 54
Injector Head Physical Brace
To Prevent Pipe Collapse
Between the lower injector head and the first seal, a
brace may be necessary to prevent coiled tubing
collapse.
Coiled tubing pipe diameter, wall thickness, and
buckling force dictate the need for the brace.

55. 55
Gap between injector and stuffing box
Pipe here very susceptible to bending
- Note the brace around the CT -

56. 56
Weight Indicator
•Provides continuous readout of actual total
weight (can be negative with no tubing or
shallow tubing in hole) on injector.
•What negative weight will cause injector to
lift off load cell ?

57. 57
Seals
•Stuffing Box
–primary sealing mechanism for isolating the well
–positioned above the BOP, just underneath the injector head
–connector attaches the box to the BOP
•BOP
–multi-level control for closing in the well
–capability to shear the CT
–capability to seal around the CT
–capability to grip the CT
–may be used in pairs in extreme applications

58. 58
Example:
Typical Loads: 1.5” CT, 5000 psi
•snub force = (1.767 in
2
x 5000 psi) = 8835 lb
•stuffing box friction (drag force) = 2000 lb
•total load = 10835 lb
at start of the CT run-in

59. 59
Load Change With CT In Hole
Coiled Tubing Unit 1.5” CT, 0.109” wall, 1.623 lb/ft
•one foot of CT in well = 10833 lb compr
•1000’ CT in well
10835lb - (1000 x 1.623lb/ft) = 9212 lbs compr
•10,000’ CT in well
10835lb - (10,000x1.623lb/ft) = -5395 lbs tens
•above assumes no wall friction

60. 60
Well Application CT Sizing
•Clearances
–for circulation
–for passing debris thru the CT / tubing annulus
•Worst case CT collapses
–stick in a profile or other close clearance ?
–what is diameter of collapsed CT ?
•For large prod tubulars OD / CT OD ratio
–can CT buckle ? can CT collapse ?

61. 61
Working Tensile Loads of Conveyances
WirelineWorking Load Weight of Wire/Tube Running Speed
0.072 720 0.014 100-150 ft/min
0.082 930 0.018
0.092 1160 0.023
0.108 1827 0.031
CT
1.25 21900 1.332 50-100 ft/min
1.5 26600 1.623
1.75 31440 1.915
2.375 49520 3.011

Tubing
2.375 57,000 4.6 5 - 15 ft/min
2.875 79,200 6.4
3.5 119,200 9.2
3-1/2" DP 189,000 15.5

62. 62
Pressure Balance
•Injection
•BHP = P
h + P
s - P
fct
•Circulation
•BHP = P
h + P
s - P
fct + P
fa
•Reverse Circulation
•BHP = P
h + P
s + P
fct - P
fa

63. 63
CT Circulation Procedures
•Basic
–establish rate at top of well, get friction pressure
drop in system
–circulate as coiled tubing is run in or out
•stop periodically and get reading
•note fluid level when tagged
•note pressure increases and reasons
•caution urged when annular surface pressure
increases

64. 64
Friction
•resistance to flow
–holds a back pressure that increases with rate
•tubular vs annular flow
•consider the entire system
•variables
–rate being pumped
–coiled tubing i.d.
–fluid properties
•viscosity, friction, gas, etc
–solids

65. 65
Buckling Factors
•hole diameter and pipe diameter
–large holes and small pipe O.D is worst combo
•increasing pipe weight speeds onset of buckling
•high wall friction factors increase buckling
•debris in wellbore increases friction

66. 66
Sinusoidal / Lateral Buckling
is normal in pipe under compression
results in changing slack-off or
injection force
disappears mostly when pipe is
picked up
SPE March 1997

67. 67
Helical Buckling
maximum wall contact and
very high friction force
usually precedes lock-up
SPE March 1997

68. 68
Concentric Coiled Tubing
•1-3/4” inside of 2-3/8”
–jet pump at bottom
–pump down CT/CT annulus and up tubing
–weight?
–stiffness?
–lengths?
•Canada operations - very well proven method
for cleanout of horizontals
1-3/4” in 2-3/8”

69. 69
Well Cleanout Jobs

70. 70
Cleanouts
Removing . . .
•loose solids
•compacted solids
•soft deposits
•hard deposits
•steel debris

71. 71
Lift And Cleanout Factors
•annular area
•liquid density and carrying capacity
•solid size and density
•rate available from Coiled Tubing
•well deviation

72. 72
Cleanouts
•lift requirements should be met throughout job
–sufficient fluid supply on hand ?
•circulate while RIH and POOH
–monitor solids returns
•perform proper pressure test(s)
–under-reamers and other opening tools
–will tools stick in lubricator ?
•keep the coil moving
•test motors prior to RIH
–lubrication

73. 73
Design Rule Of Thumb
•On the Hole or Casing to CT sizing
–for hole ID / coiled tubing OD ratio
•for ratio < 3.5 : 1 1.5” CT in 5-1/2”
–can usually lift solids or liquids
•for ratio 3.5 < ratio < 4.5, 1.5” CT in 6-5/8”
–can usually lift liquids
–need vis or sweep help for solids
•for ratio > 4.5, use vis and sweep help

74. 74
Coiled Tubing Formulas
CT Volume (bbls) = 0.0009714 x (ID)
2
CT Displace (bbls) = 0.0009714 x (OD - ID)
2
(for open end tube displacement)
CT Displace ( bbls) = 0.0009714 x (OD)
2

(for closed end tube displacement)

75. 75
Annular Area Comparison
1-1/4" CT - Vertical Well
Casing CT AnnularThreshold Rate Estimate
OD area Area to lift sand in annulus
inch in2 in2 with straight liquids
2.375 1.23 1.88 0.15
2.875 1.23 3.44 0.25
3.5 1.23 5.78 0.45
4.5 1.23 10.71 0.79
5.5 1.23 17.62 1.3
7 1.23 27.03 2
8.785 1.23 42.93 3.2
Design Chart To Lift Sand In Annulus
BBLS/min

76. 76
Annular Area Comparison
1-1/2" CT - Vertical Well
Casing CT AnnularThreshold Rate Estimate
OD area Area to lift sand in annulus
inch in2 in2 with straight liquids
2.375 1.77 1.33 0.1
2.875 1.77 2.9 0.2
3.5 1.77 5.3 0.4
4.5 1.77 10.2 0.8
5.5 1.77 17.1 1.3
7 1.77 26.5 2
8.785 1.77 42.4 3.1
Design Chart To Lift Sand In Annulus
BBLS/min

77. 77
Annular Area Comparison
1-3/4" CT - Vertical Well
Casing CT AnnularThreshold Rate Estimate
OD area Area to lift sand in annulus
inch in2 in2 with straight liquids
2.375 2.4 0.7 0.05
2.875 2.4 2.3 0.2
3.5 2.4 4.6 0.3
4.5 2.4 9.5 0.7
5.5 2.4 16.5 1.2
7 2.4 25.9 2
8.785 2.4 41.8 3.1
Design Chart To Lift Sand In Annulus
BBLS/min

78. 78
Circulation With Entrained Solids
•Concerns
–potential bridging in annulus
–solids density / loading changes
–low pressure wells
–erosion

79. 79
An Unusual Cleanout Method
(following 5 slides)
•very low pressure wells
•not recommended where other
alternatives are available

80. 80

81. 81

82. 82

83. 83

84. 84
Repeat

85. 85
Cleanout In A 22,611 ft Gas Well
•SPE 38770
•1.5” tapered string
•wall 0.095” to 0.156”
•100,000 psi yield
•overpull design of 9,060 lbs
–72% of min yield value

86. 86
Annular Velocity
•a gas lift problem........
•is coiled tubing gas the sole source of added gas
–sole source > lift limited by CT gas rate at BHP
–added gas > depends as much on producing GOR
•be aware of diameter changes in coiled tubing string in hole
•watch for points of velocity change
•watch for turbulence and separation
•where is the coiled tubing in the tubing?
–centered or x-centered

87. 87
Other Methods
•reverse circulation (high risk)
–it is done in Alaska
•can not do with flapper check valve, ball valve and
many other pieces of equipment in string
–concerns - plugging inside CT
•separation of streams at surface
•high rate erosion
•most service providers will not reverse circulate
•tough with small diameter CT
–expect high tubing friction pressures in any event

88. 88
Soft Deposits
•asphaltenes
–gums bits, use with a dispersant
•paraffins
–gums bits, solvents, heat, agitation
–don’t hot oil if over 150 ft down
–if adding heat, coiled tubing will expand

89. 89
Harder Deposits
•hydrates
–impact tools in use
–can also circulate alcohol or glycol
•scales
–jetting
•liquids along won’t do much
•add solids?
• watch erosion ! (tool stalls)
–milling
–both too slow??? depends on alternatives

90. 90
Watch Out For...
•washouts in hole
•step changes in casing id
•flow rate changes
•sudden loss of rate
•unusual shaped debris
–milled steel flakes
•swab and surge loads

91. 91
Steel Debris
•high yield point fluid for lift
–steel density is 489 lb/ft or 65.4 lb/gal
•odd shaped debris may cause trouble
(bridges and even interlocking nests)

92. 92
Improving Lift
•viscosity - gels, foams
•rate - may not always help
•sweeps - piston like displacement
•smaller annular size

93. 93

94. 94
CT In Very Low
Pressure Wells
•differential sticking
–less with CT? - smaller tube, lower surface/column
pressures needed
–BUT, the BHA size and weight is also important
•what is the availability of foam?
•nitrogen also lessens problem

95. 95
Oilfield Scales
Suggested CT Removal Plans
•CaCO
3 -
layered: use jet and acid
•CaSO
4 - crystals: use jet
•CaSO
4 - solid: use mechanical (mills)
•BaSO
4 - pure, thick: mechanical
•BaSO
4 - mix: mechanical
•FeS - what form? - usually mechanical
•FeCO
3 - normally mechanical, acid???

96. 96
Coiled Tubing
Bottom Hole Assemblies

97. 97
Coiled Tubing
Bottom Hole Assemblies
•What tools are needed to do the job?
•How should BHA be configured for the job?
•What could go wrong in the hole?
•If job does go wrong, what is needed?
•How can perceived CT problems be addressed in
design to prevent them?
•Where to acquire “needed” tools, talent, equip,
fluids, etc.,?

98. 98
Coiled Tubing Applications
•Fluid Movement & Cleanout - 70% of CT use
•All Other Jobs - 30%
–inflatable packers
–fishing
–stimulation
–drilling

99. 99
Coiled Tubing Tool
Connection Types
•CT to tool connections
–crimp on
–threaded
–set screws
–collette / grapple

100. 100
Other Connection Methods
•welding - used for bottom profiles, repair
•threaded CT - rare, usually weak (thin wall)
Note
check every connector with a pull test
(cover the hole first ! !)

101. 101
Downhole Tools
Connectors Hydraulic Push/Pull Tools
Release Tools Packers
Centralizers Valves
Nozzels Logs
Impact Tools Perf Guns
Motors Electric Tools
Cutters
Underreamers
Running Tools
Retrieving Tools

102. 102
Releases
•hydraulic and ball drop releases
•rate sensitive
•trash sensitive

103. 103

104. 104

105. 105

106. 106
Coiled
Tubing
Check
Valves

107. 107
Coiled
Tubing
Circulating
Valve

108. 108
CT Underreamer & Pipe Cutter Tools

109. 109
CT Nozzle Jet Cleaner & Pump Out Plug Tools

110. 110
Jetting Nozzle
Run On
Coiled Tubing
check valve
jetting nozzle

111. 111
Pipe Cutoff Methods
•jet cutter
•linear jet cutter
•chemical cutter
•radial cutting torch
•mechanical cutter
•erosive / abrasive cutter

112. 112
Cutoff Targets
•pipe (usually tubing)
•tailpipe
•special targets
–multiple strings
–exit windows (experimental)
–casing recovery

113. 113
Use Shaped Charge Or Explosive Cutter ?
note flare after cut

114. 114
Cutter Problems
•full diameter cutter deployment in needed but
often difficult
•obtaining complete pipe separation
•excessive flare at cut
•outer pipe damage

115. 115
Chemical Cutter Schematic

116. 116
Incomplete Chemical Cut In Pipe

117. 117
Split Shot
•breaks the strength of the coupling

118. 118
Owen Tool Split Shot
cutter based on a linear shaped charge
generally good performance but depth control is critical

119. 119
CT With E-line
•running CT with internal E-line requires
–a safety shear joint above the tool string
–the shear joint allows parting
•cannot drop a ball to shear out with e-line in tubing
•shear rods in shear joint have different ratings
•chemical cutter can not be run thru CT-E line

note:
–sticking the coil is to be avoided at all costs
–no way to free the CT if it becomes stuck

120. 120
Coiled Tubing
Fishing And Jetting Operations

121. 121
Coiled Tubing
Fishing And Jetting Operations
•free point
•fishing with and for coiled tubing
•jars
•impact tools
•jetting basics

122. 122
Fishing CT With Wireline
•What is the fish?
–usually, a CT BHA with small amount of CT
•Fishing with what?
–usually 0.125” slickline
•Maximum CT length that can be retrieved?
–depends what is stuck and location of stuck point
•How to fish?
–cutting stuck tubing
•where to cut?
•what to cut with?
–fishing tools

123. 123
Where Is Stuck Point?
•classic free point analysis
•need jar action to free fish
•downhole cut needs to be close to stuck point
–jar placement as close to fish as possible
–coiled tubing in compression not a good jar target

124. 124
long
section of
CT above
the stuck
BHA would
act as a
shock
absorber,
negating
jar action
short “stub”
of CT above
the stuck
BHA would
be ideal for
transmitting
jar shock to
the fish
the length of CT
above the stuck
point makes a
difference

125. 125
Cutting The CT
•surface
–cut above injector if work height permits
–lubricator need for retrieval?
–length?
•downhole
–cut as close as possible to top of the stuck BHA
with chemical cutter
–stub looking up leaves the best fishing
opportunity in the hole

126. 126
Fishing Tools
•if tubing fish is cut with a chemical cutter, make
a square top cut and then use a grapple
•if tubing fish is bent or rolled over, then use a
roller dog type with two sets of dogs

127. 127

128. 128
Special Fishing Tools
are used for odd shapes
in the hole which are
difficult to grab
situations

129. 129
Impact Tools
•about 70% of CT operations include cleanout
including applications in H2S, high temps, and
in hostile fluids and pressures
•impact drills offer alternatives to motors in these
environments

130. 130
Impact Tools
•impact tools offer rotation
•tools designed to give a twisting, downwards
blow somewhat like a jar
•a fluid pulse from the operation of the tool
washes away the cuttings
•impact tools operate with as little as 500 psi
•at higher pressures, the tool lifts further and
delivers a harder jolt

131. 131
Impact Tool Operation
•the single direction tool only operates when it sits
down and bottoms out on something solid
•normally, it is at full extension
•the bi-directional tool will run if circulation is sufficient
•can wear out as it is run into the well if circulation is
maintained
•tools do not store reverse torque (no tendency to
unscrew)
•reports of operating to 600
o
F

132. 132
Impact Tool Specifics
•for impact tools, produce cracks, then wash off
debris
•penetration rates through barium sulfate
reported to 150 ft/hr
•pilot hole followed by cleanup run is best
•leave at least 1/8” scale sheath thickness on
pilot

133. 133
Specifics For Impact Tools
•for barium sulfate cleanouts, use water,
solvents, or acids
•run life? 80 hrs?
–fatigue loading of CT? (none reported)
–some seam splitting on worn strings

134. 134
Deposit Removal
•jetting
–water jet
–abrasive jet - cutting
–abrasive jet - deposit removal
–fluid/pressure pulse
•mechanical (milling and chipping)
–mill and motor
–impact tool

135. 135
Testing Jetting Tool On Rig Floor Prior To RIH

136. 136
Close Up View Of Jetting Tool

137. 137
Schematic View Of Jetting Tool And Centralizer

138. 138
Jetting Fluids
Filtered Fluid Type Remediation
brines salt, silt fill
foams heavier fill/large annulus
xylene, tolueneOBM, asphaltene, wax
kerosene, #1 dieselsome waxes
acids carbonate scales, rust

139. 139
Water Blast And Abrasive Targets
•mud debris
•pipe dope
•scale (softer scales for water blast)
•cement residue
•mill scale (81 lb/1000 ft)
•corrosion by products
•bacteria colonies

140. 140
Typical Downhole Scales
Potential Jetting Clean Out Candidates

141. 141
Layers of calcium carbonate scale from surface pipe
prior to first stage separator in a North Sea field.
Subsequent inhibitor treating has significantly reduced
the scale deposition.

142. 142
Energy In Jetting
•impact force is generated from pressure drop
•impact force is improved by shaped nozzle
•cavitation is most helpful, but, it disappears with
increasing back pressure

143. 143
Nozzle Energy
•nozzle energy is dependent upon the standoff
distance between the nozzle outlet and the face
of the target
Energy
target face
standoff
nozzle

144. 144
Nozzle Power Drop Off
•for the first 6 to 7 nozzle diameters, there is
essentially no loss of velocity in the center line
of the fluid stream
•from 7 to 24 nozzle diameters, an exponential
loss of up to 80% of the initial velocity occurs
•at clearances over 24 nozzle diameters, a more
gradual decrease of the remaining energy is
seen
•a typical nozzle is 1/32” to 1/8” (0.8 mm - 3 mm)

145. 145
Nozzle Efficiency
•the transfer of momentum between a fluid and a
rock surface is relatively inefficient
•cutting generally only occurs when the force
from fluid impingement momentum is at least
1.5 times the compressive strength of the rock
•typical compressive strengths:
5,000 psi to 12,000 psi

146. 146
Solids
•an improvement over the cavitating nozzle may
be the addition of small solid particles to form a
particle jet
•the cutting ability of particle jets does not fall off
as rapidly as cavitating nozzles
•particle jets are still affected by ambient
pressure, but not to the extent of a cavitating
nozzle

147. 147
Particle Nozzles
•particle jet nozzles are typically on the order of
1/16 to 1/8 in
•erosion of the nozzle is common
•erosion increases with hardness and
concentration of the solids in the stream at any
set of operating conditions

148. 148
Jetting
•water
–may remove softest deposits such as paraffin,
uncured cement and loose rust scale
•abrasives
–can remove any deposit but may cut the pipe

149. 149
Mills
•mill selection based on job
•operator preferences
–PDC cutter type teeth
–highly aggressive mills stall small motors

150. 150
Mills & Milling Rates
•15 to 30 or more ft/hr with mill and motor on CT
•depends on scale hardness and thickness
•depends on motor power
•depends on mill design
• mill selection based on job
• operator preferences
– PDC cutter type teeth
– highly aggressive mills stall small motors

151. 151
Removed With CT Nozzle Jet

152. 152
Problems and Solutions
•Stabilizing and centralizing the downhole motor on the
CT may be the biggest challenge.
•If nipple is present, it prevents use of flexible.
stabilisers, so the motor would probably make a hole
on the "lower" part of the well bore
•A long BHA is recommended since the guns that will
go through are long and rigid.
•Watch hole cleaning hydraulics, especially at hole
diameter change.

153. 153
Coiled Tubing
Fishing Job
Bottom Hole
Assembly #1

154. 154
Coiled Tubing
Fishing Job
Bottom Hole
Assembly #2

155. 155
Coiled Tubing Fishing Job
Horizontal Well Bottom Hole Assembly

156. 156
Basic
CT Unit
Fishing
Tool
Strings