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The Importance of Stresses inPetroleum Engineering
Chapter 2.1 - Mud Weight Selection
Approach
This presentation:
Approach
Drilling problems
Pressure Testing
Stresses as Design Criterion
Summary
Drilling Problems
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Drilling Problems
Mud loss: 2.5 days
Tight hole: 0.3 days
Squeeze cmt: 2.5 days
Stuck csg.: 3.3 days
Fishing: 0.3 days
Lost time: 9 days
Cost: +2 mill.$
If problems get worse:
Stuck + sidetrack
New well
Drilling Problems
Stress as Design Criterion
EFFECTS OF HIGH MUD WEIGHT
Element Advantage Debatable Disadvantage
Reduce borehole collapse X
Reduce fill X X
Reduce pressure variations X
Reduce washouts X X
Reduce tight hole X X
Reduce clay swelling X X
Increase differential sticking X X
Increase lost circulation X
Reduced drilling rate X X
Expensive mud X
Poor pore pressure estimation X X
Stress as Design Criterion
From solid mechanics:
Petroleum Rock Mechanics: Materialproperties
Recent view: Stress dominated processes
This leads to simplified design methods
E
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Stress as Design Criterion
Horizontal stresses from Kirch eqn.:
= ½(LOT+Pore Pressure)
Mid-Line Principle
Stress as Design Criterion
Stress as Design Criterion
Example from the North Sea
Stress as Design Criterion
Example of specific reaming time fromselected North Sea wells.
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Stress as Design Criterion Pressure Testing
Stress as Design Criterion Summary
In-situ stresses important for well problems
LOT testing defines stress level
Borehole collapse not fully understood
Traditional approach: Rock mechanical data limited
by data available
Complementary approach: Stress analysis from
Mid-Line Principle
New principle demonstrated the past 8 years
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2.2-Design of Well Barriers toCombat Circulation Losses
-
Design of Well Barriers
This presentation:
Introduction
Experimental work
Fracturing lab
New fracture model
Barrier stress model
Design of fluid barriers
Field case
Summary
Introduction
Circulation losses and stuck pipe two unresolved
issues in drilling
Yearly losses Billions US$ worldwide
Operational factors important
Circulation losses:
Geomechanics (stresses, lithology,….)
Mud barrier (filtrate loss, bridging,…)
Improvements depends on complementary processes
Fundamental research Field application
Experimental work
Fracturing lab built at U. of Stavanger in 1996
Focus on basic mechanisms Fracturing of concrete cylinders
Chemical effects(wettability,…)
Hole geometry (circular, oval, square, trianguler
holes,…)
Controlled loading(confining, axial, borehole stress)
Many types of barriers
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Experimental work, fracturing lab
Test cell
HollowConcrete
Core
Axial loadPump 1
Pump 3
Pump 2
Confining
Pressure
PCControlSystem
Well Pressure
1 Pump 2 Pum
Mud ncirculatioMud cell
1Valve
2Valve
3Valve LabView
Mudcake
Mudcake
1Cell 2Cell 3Cell
4Cell 5Cell 6Cell
Fracturing cell
Mudcake strength
Experimental work
Mudcake strength cell
Experimental work, new fracmodel
Example,
3 drilling muds:
a
t yo P w P 1ln
3
22
0
20
40
60
A B C
Drilling fluids
F r a c t u r i n g p r e s s u r e ,
M P a . .
Measured
Kirsch equation
New Kirsch eqn.
Experimental work
Stone bridge principle
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2.3 Hole CleaningMethodology
Based onAPI RP 13D: Rheology and Hydraulics of Oil-
well Drilling Fluids.
Based on BP research early 1990s
Mainly based on experimental correlations
Hole cleaning is a key issue, must control ROP to avoid
overloading annulus with cuttings
Mechanisms
Variables Mud flow rate
ROP Mud rheology/flow regime
Mud weight (buoyancy)
Hole size and angle
Uncontrollable variables eccentricity
cuttings size density
Applications
Transport index
TI = RF (rheology factor) xMW (mud weight)x AF (angle factor)
If hole is washed out:
CFRwashout = CFR (flow rate)
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Example
8.5” horizontal well
MW = 1.45 sg, PV = 25 CP, YP= 18 lbf/100 ft2
Questions:
Maximum ROP if maximum flow is 480 gpm? (Correct book)
If ROP = 20 m/hr, what is minimum flow?
If hole is washed out 10 in, what flow rate is required?
Solution
From Fig. 2.16, RF = 0.91
From Table 2.5, AF = 1
From Eqn. 2.7, TI = 0.91x1.0x1.45 = 1.32
Solution, cont.
From Fig. 2.16b: at TI=1.32, Q=480 gpm, ROPmax=23
m/hr
If ROP = 20 m/hr, Qmin=470 gpm
Solution, cont.
If hole is washed out, correction factor:
Minimum flow rate now:
CFRwashout = 1.38 x 470 = 649 gpm
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Hydraulic OptimizationChapter 2.4
Hydraulic System
P 1 = pump pressureP 2 = nozzle pressure
P 3 = system loss (parasitic)
P 1 = P 2 + P 3
Pressure drop
Laminar flow
Turbulent flow
Empirical flow equation
P Q
2
P fQ m P CQ
Hydraulic System
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Hydraulic System
P 3 = system lossP 3 = CQ
m
lnP 3 = lnC + mlnQ
Hydraulic System
Nozzle pressure drop from Bernoulli
System losses
2
2 2 22 0.95
Q P
gA
3 2300bar P P
Hydraulic Optimization
Nozzle Horsepower
Maximum
2
1 3
1
( )
( m
HP P Q
P P
P CQ
13
1
dHP P P
dQ m
Hydraulic Optimization
Classical criteria
Max. Hydraulic horsepower
Max. Jet impact
Limitations
Physically correct?
Adequate Q for hole cleaning?
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Hydraulic Optimization
Performance indices
Performanceindex
Equation CriterionFraction parasitic
pressure lossFlow rate
1 Max. HP
2 Max. Jetimpact
3 New A
4 New B
5 New C5 2
2q P
2
2q P
3 2
2q P
2q P
2qP 1
1m
2
2m
3
3m
4
4m
5
5m
1
( 1)
P
C m
12
( 2)
P
C m
13
( 3)
P
C m
14
( 4)
P
C m
15
( 5)
P
C m
Application
1. Determine hole cleaning rate Q
2. Select performance index3. Compute system loss (P 3) and bit loss
(P 2)
4. Compute nozzle area, A
Proposed criteria
Other data: Drill pipe: 675 m of 5 inch, rest 6-5/8 inch; Drill collars: 120 m 8-1/8 inch OD,
2.81 inch ID; Mud density: 1.65 s.g., Yield point: 32 lbf/100 sq.ft.; Plastic viscosity: 42 cP.
Proposed optimization criteria for typical 12-1/4 inch hole
Hole length Vertical holes Deviated wellsdrilled with motor
Deviated wellswithout motor
Strongerrequirements
Less than 2500 m Max. Hydr. Horsepower
or max. Jet impact force
Max. HHP or
max. Jet impact
Max. Jet impact New A
2500-4000 m Max. HHP
or max. Jet impact
Max. Jet impact New A New B
Deep(5000m) Max. HHP
or max. Jet impact
Max. Jet impact
or New A
New B New C
Example
Determination
of flow ranges
and optimisation
criteria
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Drill Pipe Size Example
Hydraulic parameters for the field case
Criterion Percent parasitic press. loss Flow range (l/min)
Max. Hydraulic power 54 2800-2220
Max jet impact 52 2850-2280
New A 63 3070-2450
New B 69 3250-2580
New C 73 3370-2800
Optimal nozzle selection for New B criterion
Depth (m) Nozzles (inch)
1200 Five 13/32, one 16/32
2200 Five 12/32, on 16/32
3200 Five 11/32, on 16/32
Example
Summary of earlier bit runs
Bit. No. Nozzles q (l/min) ROP (m/hr) Remarks
1 5 x 16, 1 x 12 2960 1.5 Plugged center nozzle
2 5 x 19, 1 x 12 2660 9.8
3 5 x 16, 1 x 12 2600 13.64 5 x 19, 1 x 12 2300 18.2
5 5 x 18, 1 x 12 2400 14.9 Plugged center nozzle
6 6 x 12 2600 18.3
7 5 x 14, 1 x 12 2400 15.4
8 5 x 15, 1 x 12 2450 24
9 5 x 14, 1 x 12 2400 4.8
10 5 x 14, 1 x 12 2530 23.8
11 5 x 19, 1 x 12 20 Plugged center nozzle
12 5 x 19, 1 x 12 30
13 5 x 18, 1 x 12 10
14 5 x 18, 1 x 12 22 Plugged center nozzle
15 5 x 19, 1 x 12 7 Plugged center nozzle
16 5 x 18, 1 x 12 27 Plugged center nozzle
17 5 x 19, 1 x 12 16 Plugged center nozzle
18 5 x 19, 1 x 12 19 Plugged center nozzle
Geomechanic EvaluationChapter 3.1 - Data Normalization
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Data Normalization
Example, porepressure at 1000m:
P(bar)= 0.098d(s.g)D(m)
= 0.0981.03 1000
= 100.9 bar
Data Normalization
Example, continued:New gradient from RKB
1.03s.g.MSLd
100.91.0s.g.
0.098 1025 RKB
bar d
m
Data Normalization
From sea level
From RKB
MSL RKB
Dd d
D h
RKB MSL
D hd d
D
Data Normalization
From floater
From platform
D
h Dd d RKB RKB
12
h D
Dd d RKB RKB
21
)( )(
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Data Normalization
Normalize to seafloor
1. Subtract water pressure
2. Subtract water depth
Data Normalization
Well Csg (in) Depth (m) hw (m) hf (m) LOT(s.g.) P0 (s.g.) 0 (s.g.)34/7-2 20 848 245 25 1.58 1.06 1.83
13 3/8 1549 1.69 1.42 2.00
9 5/8 2031 1.88 1.63 2.00
34/7-8 20 848 286 25 1.62 1.04 1.72
13 3/8 1859 1.83 1.42 1.93
34/7-14 20 491 148 25 1.49 1.00 1.4913 3/8 1559 1.75 1.09 1.70
9 5/8 1988 1.80 1.53 1.92
)( sg o )( sg o
Geomechanic EvaluationChapter 3.2 - Interpretation
Interpretation
Basic data
Leak-Off-Pressure (LOT)
Pore Pressure
Overburden Stress
Lithology
Clays
Sands, Chalks, …
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Interpretation
Simple modelling
Evaluate LOT data
Effective stresses
Horizontal stresses
Effective horizontal stresses
Depth normalize Effective depth normalized data
Interpretation
Example
Well Dataset Depth(m) (s.g.) (s.g.) o(s.g.)
A 1 899 1.46 1.04 1.63
2 1821 1.74 1.28 1.81
B 3 901 1.55 1.04 1.60
4 1153 1.56 1.04 1.73
5 1907 1.81 1.34 1.82
6 2753 1.95 1.52 1.96
Interpretation
Example: LOT Pressure
Interpretation
Example
LOT Gradient
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Interpretation
Horizontal stresses,depth normalized
Effective horizontalstresses, depth
normalized
2
a o
a o
o o
K
LOT P
'
' 2a o
o o o
LOT P
P
Interpretation
Horizontal stresses
Effective horizontalstresses
2
1
2
a o
a o
LOT P
LOT P
'
1'
2
o
a o
P
LOT P
Interpretation
Best fit
Test of model
Prognosis
1' 0.23
20.46
a o
o
LOT P
LOT P
Geomechanical EvaluationChapter 3.2.4 - Advanced Modelling
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Advanced Modelling
Principle: Normalize all data to same
reference, example: Borehole inclination
Compaction
Inversion technique
Advanced Modelling
Borehole inclination
Normalize all LOT’s tovertical for comparison
* 2
2
2
1(0 ) ( ) sin
3
1( ) sin
2(0 )
11 sin
2
wf wf o o
wf o o
wf
P P P P
P P
P
Advanced Modelling
Compaction model
Applications
Normalization
Structural geology Lost circulation
1 2
1
1 3
1
a o
wf o
P
P P
Advanced Modelling
Compaction model
Example
Depth(m) LOT (s.g.) P0 (s.g.)
3885 2.10 1.79
3821 2.13 1.84
3818 1.98 1.44
3914 2.06 1.58
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Advanced Modelling
Inversion Technique
Determines tectonic stress field that fits alldata sets
Use this stress field to make prognosis for
new well
Determines also stress directions as applied
to e.g. fracturing and stimulation
Advanced Modelling
Relaxed Depositional Basin Tectonic Stress
Advanced Modelling
Inversion Technique, Example
Dataset
Well Casing Depth
(m)LOT(s.g.)
P0(s.g.)
o(s.g.)
1 A 20 1101 1.53 1.03 1.71 0 0
2 13 3/8 1888 1.84 1.39 1.82 27 923 9 5/8 2423 1.82 1.53 1.89 35 92
4 B 20 1148 1.47 1.03 1.71 23 183
5 13 3/8 1812 1.78 1.25 1.82 42 1836 9 5/8 2362 1.87 1.57 1.88 41 183
7 C 20 1141 1.49 1.03 1.71 23 284
8 13 3/8 1607 1.64 1.05 1.78 48 2849 9 5/8 2320 1.84 1.53 1.88 27 284
10 New 20 1100 ? 1.03 1.71 15 13511 13 3/8 1700 ? 1.19 1.80 30 135
12 9 5/8 2400 ? 1.55 1.89 45 135
Depth interval(m) H /o h /o Direction Leak-off, new well1100-1148 0.754 0.750 44 1.53
1607-1812 0.854 0.814 96 1.71
2320-2423 0.927 0.906 90 1.86
Advanced Modelling
Inversion Technique, Example
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3.2.4 In-Situ Stress Modelling of the SnorreField
Local Map
This Presentation
Applications
Importance of in-situ stresses
Experience from Snorre Modelling
Regional stress field
Earthquake focal mechanisms
Local stress field
Borehole elongation
Leak-off inversion
Conclusions
Importance of fracture gradientprediction in well planning
Casing seat selection using low frac. curve
30”
13 3/8”
9 5/8”
7”
20”
Gradients
Frac
Mud
Pore
Depth
Casing seat selection using high frac. curve
30”
13 3/8”
9 5/8”
7”
Gradients
Frac
Mud
Pore
Depth
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Horizontal stresses and directionsfrom borehole leak-off data Method: Inversion of leak-off and minifrac data
Parameters: Fracture pressure
Pore pressure
Overburden stress
Borehole inclination
Borehole azimuth direction
Horizontal stresses and directionsfrom borehole leak-off data
Stress fields at reservoir level from leak-off inversion
Horizontal stresses and directionsfrom borehole leak-off data Summary, leak-off inversion:
For shallow depths (to 1500m), the horizontal stress
state has relaxed, nearly hydrostatic state.
In the deeper parts (1500 – 3000m), the horizontal
stresses becomes anistropic with depth.
The stress state varies both depthwise and areawise.
In certain places the max. horizontal stress exceeds
the overburden.
The method gives realistic stress ratio. Also, the
directions are consistent with the fault pattern of the
area.
Conclusions
The stress field at Snorre is anisotropic due to tectonics of the area
Focal mechanisms, borehole elongation and leak-off data have been
used to assess the in-situ stress levels and direction at Snorre.
The three methods shows consistency, but model various scales:
Focal mechanism regional scale
Elongation data local scale (one borehole)
Leak-off inversion local scale (several boreholes)
Maximum horizontal stress is regionally in a North-West direction
Stresses near faults dominated by faults
The described approach has significantly improved fracture pressure
prediction
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0 3 . 0 6 .2 0 1 1 1
G e om e c h a ni c a l E
v a l u a t i on
G e om e c h a ni c a l E
v a l u a t i on
Ch a p t er 3 .4 -B or eh ol e
C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e S t r e s s e s
C ol l a p s eM e c h a ni s m
F i el d c or r el a t i on s
T i m ed e p end en c y
T i m em od el
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e S t r e s s e s
R a d i a l s t r e s s :
r =P
w
= b o
r eh ol e pr e s s ur e
T a n g en t i a l s t r e s s :
=2 a -P
w
V er t i c a l s t r e s s :
v = o v er b ur d en= c on s t a n t
P or e pr e s s ur e :
P o
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
C ol l a p s eM e c h a ni s m
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
C ol l a p s eM e c h a ni s m
M oh r - C o ul om b f a i l ur em od el
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
F i el d c or r el a t i on s
0 3 . 0 6 .2 0 1 1 2
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
F i el d c or r el a t i on s
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
T i m em od el
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
B or eh ol e c ol l a p s e
B or eh ol e c ol l a p s e
0 3 . 0 6 .2 0 1 1 3
B or eh ol e C ol l a p s e
B or eh ol e C ol l a p s e
3.5 Drillability Evaluation
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ROP models
The simplest ROP model is:
A more common model is the
d- exponent:
The d-exponent
This model is used:
Continuously in mudlogging units offshore
Estimate pore pressure
Assess bit wear with rollercone drillbits
Various geological interpretation
It is actually a normalised ROP model, but the linear model works as well
The drillability is the only (?) measurement at the drillbit face. Other
measurements are behind in depth.
Drillability is always measured and provide a very important source of
information . Examples follows.
Clay diaper example
Tophole drilling found soft sediments
that could not be detected on logs.
Drillability analysis performed
Found increase in drillability at a given depth
interval
Conclusion: Discovered an unidentified clay
diaper characterized by:
High water content
High porosity
Easy drillable
Relief well example
An underground blowout in a HPHT
well was killed with a relief well.
Difficult to detect distance between wells at 5000 m
Breakthrough point critical as both wells could lose control
Relief well finished one year after initial blowout.
The blowing well had produced 18 000 bbls/day for one year leading
to reduced pore pressure and changes in in-situ stress.
Comparing the two drillabilities defined proximity and also extent of
damage caused by underground flow. This was the only information at
that time.
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Relief well example
.
Drillability summary
Examples shows the power of drillability information
Drillability should be further explored as a formation evaluation
tool and a well dignostic tool
Fracture Model for GeneralOffshore Applications
Chapter 3.6
Fracture Model for General Offshore Applications
Objectives
Introduction
The overburden stress
Fracturing Empirical model
Method to normalize data
Field cases
Summary and conclusions
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Introduction
Problems increase with water depth
Shallow water flow
Hole collapse
Circulation losses
Fracture gradient decrease with increased
water depth
The overburden stress
Overburden stress
0
w
w
D D
sw bulk ob
D
ob g dD g dD gd D
Depth (m)
Overburden
stress grad. (s.g.)
1.0 1.5 2.0
1000
2000
3000
1000 50015002000
Water depth (m)
0
Eatons modelLinear approx.
Linear approx.
1
2.015 000
w
D
ob sw w bulk
D
w f w f w sw
d D d D dD D
D D D D D D Dd
D D
d
Overburden stress gradient
Fracturing
Fracturing equation
Horizontal stress
Conclusion
03v i j ywf d d P P d
0v y vwf P P f d K
Depth (m)
Stress grad. (s.g.)1.0 1.5 2.0
1000
2000
3000
LOT
v,h H v
Fracture directions
StressesEqual horizontal stresses Different horizontal stresses
H h H h
H
h
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Fracturing – Flow barriers
Pressure
Radius
Flow barrier
P0
Pw
Pressure
Radius
Flow barrier
P0
Pw
Non-penetrating fluids Penetrating fluids
02 t wf P P P 01 2 1 t wf P P
Variation in break-down pressure: 02 wf P P
Fracturing – LOT testing
Pressure
Volume
Non-penetrating case
Mud compressibility
Penetrating case
LOT
Pressure
Volume
Water-based drilling fluid Oil-based drilling fluid
Empirical fracture model
Leak-off (LOT) data studied from 175-2071m waterdepth
All data normalized by subtracting water pressureand depth
Data correlates well with overburden andhorizontal stress curves
Valid for all relaxed sedimentary depositional basins
Fracture Model for General Offshore Applications
Method to normalize data
hf1
hw1
Dsb1
Depth
New depth
New gradient
1 1 1 1 f w sbh D D h
2 1 f w sbh D D D h
12 1 2 22 1
2 2 2 1 1
wf w w b sbwf sw wf sw
wf wf wf b sb
Dh h d Dd d d d
D D D d D
1 1 22 1
2 2 1
N N N fw ob N N ob
fw fw N N N
fw ob ob
P K P P P P
P K P P
dwf1 dwf2
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Empirical correlation
Five deep-water wellsselected for analysis
Fracture prognosis of 98%of overburden stressgradient
Standard deviation of 0.05
Fracture Model for General Offshore Applications
Ratio between le ak-off data and overburden
0
500
1000
1500
2000
2500
3000
3500
4000
0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30
d(LOT)/do
D e p t h ( m )
Ratio A ver age r atio
Field case 1
Well used for empirical
correlation
1274m water depth
Variations in LOT influenced by:
Rig procedures
Interpretations of P-V-plots
Mud density
Quality of mud cake Assessment of bulk density and
overburden stress
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
1,00 1,10 1,20 1,30 1,40 1,50 1,60 1,70 1,80 1,90 2,00
Overburden Frac gradient LOT data
Field case 2 - Prognosis
Fracture prognosis used forplanning of shallow penetration
gas well
380m water depth
Good agreement betweenprognosis and measured FIT
Major contributor to thesuccess of the drilling operation
Mud designed for strong mud
cake
350
400
450
500
550
600
1 1,05 1,1 1,15 1,2 1,25 1,3 1,35 1,4
D e p t h ( m )
s.g.
Overburden Frac ture gradient Peon FIT
Summary and conclusions
Overburden gradient decreases with increasing water
depth
Fracture pressure governed by: Overburden stress
Fluid barrier
Field data fits general model
Model presented to derive prognosis
Normalization method derived to adjust data forarbitrary water depth
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3.6 General Fracturing ModelKey issues
Important findings
Overburden stress important Seabed penetration important as well
A general fracturing model valid from land wellsto deepwater wells emerged from this
Overburden stress
In deepwater most overburden is water, leading to lowhorizontal stress
This gives low fracture
pressure
Direct correlation betweenLOT and water depth
Seabed penetration
Using seabed reference by:
Removing water pressure
Removing water depth
Led to a LOT correlation:
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Normalization
Have data from Well 1. Prognose LOT for Well 2 by
normalizing to new water depth
Equations
General equations:
Different but constant bulk densities:
Equal constant bulk densities:
Example 1
Well 1 is drilled in 400 m water, what is expected LOT if it drills
inn 1100 m water depth, assuming equal conditions?
LOT1 = 1.5 sg at 900 m (RKB)
Solution, new depth: D2 = 900 + (1100-400)+(25-25) = 1600 m
Expected LOT at 1600 m:
Example 2
Now we assume different bulk densities. Same data as in Example
1, except bulk densities are 2.05 sg and 1. 85 sg
Solution, new depth: D2 = 900 + (1100-400)+(25-25) = 1600 m
Expected LOT at 1600 m
Lower bulk density in well 2 leads to lower LOT
Fi ld l
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Field example
Well offshore Norway in water depth 1349 m:Well Design Premises
Chapter 4
4.1 Well Integrity
Full well integrity Reduced integrity(Weak point below shoe)
Reduced integrity(Weak point below wellhead)
4.1 Well Integrity
Full Well Integrity
Required for Production Csg. Only
Min. LOT to reach end open hole
Reduced Well Integrity
All other Csg. strings (exept 30”)
Min. LOT to reach end open hole
Max. LOT to ensure weak pt. below shoe
Maximum kick size to ensure full integrity
4 1 M i LOT 4 2 C i S i D h
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4.1 Maximum LOT
Shut-in Gas Filled Well
Wellhead Press. 200 bar =
Burst Strength Csg.
Shoe Pressure 200 bar (2.02s.g.)
If LOT>2.02 s.g. Weak pointwellhead.
UNACCEPTABLE
4.2 Casing Setting Depth
Pressure Conditions
Frac. Pressure at Shoe
Pore Pressure Open Hole
Operational Conditions
Borehole Stability, Collapse Mud Loss
Completion Conditions
Drilling conditions, No. Of Bits/Trips
Example 1: Mud Weight
Casing size
(inch)
Depth
(m)
Mud weight
(s.g.)
7 2700 1.60
9 5/8 2400 1.60
13 3/8 1300 1.30
18 5/8 700 1.20
30 400 Sea water
Example 2: Riser Margin
E l 2 Ri M i E l 3 Ki k C it i
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Example 2: Riser Margin
Casing size
(inch)
Depth
(m)
Mud weight
(s.g.)
7 2700 1.69
9 5/8 2400 1.69
13 3/8 1700 1.40
18 5/8 900 1.20
30 440 Sea water
Example 3: Kick Criteria
Casing size
(inch)
Depth
(m)
Mud weight
(s.g.)
7 2700 1.69
9 5/8 2400 1.69
13 3/8 1700 1.40
18 5/8 900 1.20
30 440 Sea water
Summary, Csg. Seat Selection
Determine depth requirements from Mud
Weight (frac pressure and pore pressures)
Determine operational factors based on
experience
Determine riser margins on floaters
Only production csg. Need full integrity.
Use kick margin for other strings.
4.3 Completion and ProductionRequirements Wellhead design pressure (i.e. 5000 psi)
Bullheading pressures
Design alternatives
Drilling only, or drilling and testing
Other effects
Temperature
Time
Perforation, stimulation,…
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Burst Design Burst Design
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Burst Design
Leaking tubing
Burst Design
Gas Filled Casing
For all csgs. except 30 in. and production csg.
Leaking Tubing
For production csg.
Maximum gas kick
Max. vol. reservoir fluid without breakingdown shoe
Burst Design
t D P
A F i
t
t t
21
t
D P
A
F i
a
aa
4
1
t=2a
Burst Design
Governed by tangential stress:
P burst = 2 tensilet/D
Parameters: tensile and t/D Use manufacturers data
Use equation for wear assessment
Burst Design Kick Scenario
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Burst Design
Casing wear
Proportionality, Example: Burst pressure: 419 bar
Csg. wall worn from 8.92 to 5 mm
Compute reduced burst strength
Kick Scenario
Gas filled casing Conservative criterion
Leaking tubing For the production casing
Maximum gas kick For all casings except production casing
Relates to csg. shoe strength
Minimum LOT to reach next shoe
Maximum LOT to ensure weak point at shoe Maximum influx volume
Collapse Design
More complicated than burst
Yield collapse, plastic collapse,
transitional collapse and elastic
collapse depend on t/D ratio
Elastic collapse:
Collapse design
Wear example: same as burst example
Collapse reduction from 169bar to 80
bar appears unrealistic
Collapse criteria
Mud losses to a thief zone
Collapse during cementing
Collapse criteria Tension design
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Collapse criteria
Thief zone
During cementation
Tension design
Major design criteria: Weight of casing including buoyancy
Casing stretch caused by pressure testingwhile bumping cement plug
Other criteria: Dynamic loads, difficult to assess
Bending effects
Temperature effects
Example of B-annulus pressure in Chapter 4.3.4
If temperature exceeds 80-100°C (200°F)
Yield strength reduces
Tensile strength
Burst strength
Bi-axial loading
From von Mises yield criterion:
Elliptic equation:
Combination collapse and tension
leads to reduced strength
Other criteria Common design criteria
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Other criteria
Sour service Weight loss corrosion
Hydrogen embrittlement (H2S)
Time scenario Exploration wells short life
Production wells long life
Casing wear
Wear and damage reduces well integrity
Common design criteria
5.2 Casing test pressure
Requirements, casing must:
Be pressure tested for
expected loading
Not exceed 90% of yield strength (SF=1.11)
Example surface casing and
deeper casing
Pressure tests critical wells
Sometimes the casing is tested only in one end, e.g. at the
wellhead
Critical wells like HPHT wells may require testing of the
entire casing from top to bottom Problem: Kick scenario assumes reservoir gas in annulus.
During testing the annulus is filled with mud.
Possible approaches:
Bump plug during cementing - Assume pressure exceeding
saltwater behind casing - Set packer in the middle of the casing
and test both sides - Establish back pressure behind casing -
Evacuate upper part to seawater, example to follow
HPHT pressure test HPHT pressure test
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HPHT pressure test
Design basis:
HPHT pressure test
Test load with 1.9 sg mud in
well
OK in top
Overloaded at bottom
Test is unacceptable
HPHT pressure test
Upper half displaced to
seawater
Test is OK throughout
well
HPHT pressure test
When displacing upper half
to seawater, always check for
casing collapse
Introduction
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5.3 Casing design example-
t o uct o
Summary Setting depth
Design basis Casing design Summary
Summary
-
Casing depths
.
Design basis 18-5/8” Casing design
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g
Describe all assumptions for each casing string
Collapse
Burst
tension,
Cementation
Wellbore stability
Fluid densities
Bullheading
Wear and corrosion
And so on…….
g g
.
18-5/8” Casing design
Collapse loading during
cementation:
18-5/8” Casing design
.
Summary
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y
Results:
Based on:
Wateroutside
Oil inside
Chapter 6 will assume mud
outside and gas inside
5.4 Fully 3D Well Design ImprovesMargins in Critical Wells
Overview
Uniaxial, biaxial and triaxial well design
Conventional triaxial design
Fully three-dimensional well design
Well examples
Conclusions
Background
Evolution of long, deep and hot wells
Design margins have become small
A need for an accurate model to calculate
burst and collapse
Current technology Uniaxial well design
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gy
Most well designs are based on one- and
two-dimensional mechanics
Recent design packages include a three-
dimensional model
Accurate only for certain conditions
g
Consider one of the three principal
stresses
Axial load design neglects pressure load
effects
Pressure load design neglects axial load
effects
Biaxial well design
Consider two of the three principal
stresses
Hoop and axial stresses dominate
Neglect radial stress
Triaxial well design
Consider all three principal stresses
Combine these stresses to a single
equivalent stress
Classical von Mises distortion energy
theory is used in the industry
Conventional triaxial design Fully 3D well design
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Simplifications give practical design method
For burst calculations, assume zero outside
pressure
For collapse calculations, assume zero inside
pressure
Use pressure differentials instead of actualinside and outside pressures
New dimensionless solution that include
all three principal stresses
Use actual pressures inside and outside
the pipe
Dimensionless pipe analysis
Group 1 ( x ) Inside pressure, axial stress, yield
strength
Group 2 ( y ) Inside pressure, outside pressure,
yield strength, diameter
Group 3 ( z) Equivalent von Mises stress, yield
strength
Group 4 (ß) Outside diameter, wall thickness
3D yield surface
( ) /i o y y p p
( ) /i a y x p
/ y VME z
2D design factors Example cases
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-1.5
-1.0
-0.5
0.0
0.5
1.0
1.5
-1.5 -1.0 -0.5 0.0 0.5 1.0 1.5
( ) /i a y x p
( ) /i o y y p p
Case 1
Case 2
Case 3 Case 4
DF = 1.00
DF = 1.10
DF = 1.20
DF = 1.30 HP/HT wells offshore Norway
Well 1 Subsea wellhead
- Pressure integrity of 10¾” x 9” production casing
- Two burst cases and one collapse case
Well 2 Platform
- Collapse of snubbing pipe during live well intervention
Pressure/load matrixCase #1 Burst below wellhead
New 3D model
DF = 1.37
Conventional triaxialmodel
DF = 1.36
Biaxial model
DF = 1.37
Uniaxial model
DF = 1.44
Case #2 Burst on top of packer Case #3Thief zone
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New 3D model
DF = 1.10
Conventional triaxial model
DF = 1.06
Biaxial model
DF = 1.04
Uniaxial model
DF = 1.17
Thief zone
New 3D model
DF = 2.14
Conventional triaxial model
DF = 2.14
Biaxial model
DF = 2.04
Case #4Snubbing
New 3D model
DF = 1.69
Conventional triaxial model
DF = 1.69
Biaxial model
DF = 1.64
2D design factors
-1.5
-1.0
-0.5
0.0
0.5
1.0
1.5
-1.5 -1.0 -0.5 0.0 0.5 1.0 1.5
( ) /i a y x p
( ) /i o y y p p
Case 1
Case 2
Case 3
Case 4
DF = 1.00
DF = 1.10
DF = 1.20
DF = 1.30
Conclusions6 6 C i d i
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Conventional triaxial design for burst and
collapse is in error under certain
conditions
An accurate 3D model is developed
Improvement in design margins is
achieved using 3D model
6.6 Casing design-
24” Surface casing
Collapse during cementation installation
Burst, gas filled casing next section
Post installation
Integrity: Shoe weak, no kick margin, wellhead weak
point
Production casing
2 Types of tubing Temperature derating Tieback and liner designs
Design summary
Important issues
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.
Assume gas inside
and mud outside
These factors are most important Reservoir pressure
Reservoir fluid density Fracture pressure
Density of fluid behind casing
6. Design of HPHT wells-
Content
The following subjects are covered:
HPHT definitions
Design premises
Geomechanical design
Mud weight design
Production casing considerations
Design of shallow casing strings
Intermediate casing design
Design of the production casing
HPHT Definitions Design premises
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A HPHT well is:
Temperature higher than 150 °C (294°F)
Pressure exceeding 10 000 psi
1 of the above makes it HPHT
Objectives:
Flow test Jurassic reservoir
Drill through reservoir
Core or samle data
Well depth 5000 m but due to geological uncertainty, design depth is 5100 m
Consider sour service conditions
Two designs due to uncertinty of flow testing
Integrated design. Well can handle both drilling and well test phases
Separate drilling and testing. In the unlikely event of flow testing, install a tie-back casing.
This was chosen.
Casing alternatives
Alternatives
1: No finds
2: Run liner
3. Flow test using tie-back
4: Use liner too early
5: Use contingency to reach target
6: Flow test using tie-back casing
Prognosis
Most important design input
Key HPHT problem, narrowmargin at top reservoir
Long openhole sections withwellbore stability issues
Heavy production casingrequiring large drilling rig
2011 cost: 150 M$
Geomechanic design Geomechanic-Deep Fracturing
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Shallow gas require careful placement of upper casing strings
Shall gas followed by losses below may give problems
Riserless preferable from this point of view
Detailed analysis of 70 HPHT wells
Based modeling on Compaction Model,Modern Well Design page 62.
Established frac model
Problem is too much spread
Must consider groups of data
LOT
Pore pressure
Overburden
Depth
Lithology
LOT vs Pore pressure
Trend: High LOT – high Po
Low LOT – low Po
We will in the following
normalize all LOTs to a
pore pressure of 1.8 sg
Resulting Frac Model
Stress regimes Resulting frac prognosis
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Stress regimes in Central Graben
Resulting frac model
Process repeated
for circulation
loss data
Frac from LOT data
Lost circulation from dailydrilling reports during loss
events
Large uncertainty below 4700m, design must assume worstcase
Tiny pressure window thelargest challenge
Approximately 50% of totaltime spent in reservoir
Mud weight design
Drilling problems Well A
Compare Drilling problems with
median-line.
Too low MW in top of well?
MW design cont.
Many drilling problems in
Well B
3 sidetracks in the 17-1/2”
section MW gradually increased to
above median-line
MW design cont. MW selection
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Few drilling problems in Well C
MW roughly around median-
line
Well was reasonably well
MW criteria
Top hole lower than median-line
(ML) because of weak csg. shoes
1000 – 3000 m, approx. ML
Bottom lower than ML because:
Need to ”tag” pore pressure to
seaarch for production csg. Seat
Accept som collapse in chalk
Increase MW gradually to
minimize tight hole
Production casing considerations
Setting point critical
Don´t know what is below
If losses, must use contingency
liners Operational strategy:
Perform LOTs
Kick simulation tools
Drillability analysis
Careful hydraulic monitoring
Casing Setting Depths
.
Chapter 77.1 Wellheads
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Chapter 7Drilling Operations and Well Issues
Operation: Hours used:
Set anchors and pretension 24
Ballast rig down.Make up BHA no. 1 and 1300 m drillpipe 20
Stab into well 1,3
Drill 50 m of 36 in hole 9
Circulate hole clean 2
Perform wiper trip 1
Displace to hivis mud, pull back to mudline 2
Position rig using thrusters
Rig up for running 30 in conductor 0,5
Make up 3,5 in cement stinger and run in hole 2
Run in 30 in. conductor 6
Circulate and cement 30 in., wait on cement 4
Pull out cement tools and drillpipe 4
Position rig using thrusters 0
Total hours 32
7.2 The 36 in. hole and the 30 in.
conductor casing
Operation: Hours used :
Pull out and rack 36 in BHA 1
Break down 36 in BHA 1Pull out and rack cement head in derrick 1
Make up 26 in BHA and run to template 1,5
Position rig w/thrusters, stab in and run to shoe 1
Drill 150 m of 26 in hole 12
Circulate hole clean 3
Wiper trip, run to bottom and displace to hivis mud 4
Pull out to seabed 2
Pull to surface and rack pipes 4
Position rig using thrusters
Rig up and run 145 m 20 in casing 12
Circulate and cement 20 in csg. 4
Release running tool and pull out of hole 2
Total hours: 49
The 26 in. hole and the 20 in. surface
casing
The 17.5 in. hole and the 13-3/8 in.
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Operation: Hours used:
Position rig using thrustersRig up for running BOP stack 4
Run marine riser and BOP 16
Land BOP 4
Rig down riser handling equipment 4
Prepare test plug for running in the hole 0,5
Run in hole with test plug 3
Test connector 1
Test BOP 3
Pull out BOP test tool 3
Lay down test tool 0,5
Total hours: 39
Running BOPOperation: Hours used:
Make up 17,5 in BHA 3
Run in hole with BHA 3Drill 20 in cement, plugs and shoetrack 3
Circulate contaminated mud and perform 2
Pick up drillpipe 1
Drill 700 m of directional 17,5 in hole. 24
Circulate hole clean, wiper trip, pull out of hole 10
Run log 8
Rig up for running of 13-3/8 in. casing 3
Set back cementing head, retrieve seat protector 6
Run 500 m of 13-3/8 in casing 10
Circulate and cement 13-3/8 in casing 3
Set seal assembly and pressure test 1
Perform BOP test and pull out 6
Run and set 13-3/8 in wear bushing 6
Lay down 17-1/2 in BHA 3
Service cement head 1
Total hours: 93
intermediate casing
Operation: Hours used:
Make up 12,25 in. BHA 4
Run in hole to 900 m 6Drill 1100 m of 12,25 in hole 86
Circulate, wipertrip, circulate 8
Pull out and rack 12,25 in. BHA 5
Lay out 12,25 in BHA 2
Retrieve wear bushing 6
Rig up for running 9-5/8 in casing 3
Run in 680 m of 9-5/8 in casing 14
Circulate and cement casing, pressure test. 6
Set and test seal assembly 1
Pull out of well 3
Run in wear bushing. Temporary P/A. Establish barrier 4
Disconnect and secure BOP 8
Total hours: 156
The 12,25 in. hole and the 9-5/8 in.
production casing
Operation: Hours used:Pull marine riser and BOP 8
Prepare for X-mas tree running 8
Run and install X-mas tree 24
Pull running tool 4
Run marine riser and BOP 9
Position and latch 2
Total hours: 55
Wellhead
Install Lower Completion
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Operation: Hours used:
Make up drillcollars and heavy weight drillpipe 4
Pick up and make 8,5 in BHA 6
Run in hole to 800 m 7
Drill composite bridge plug 2
Run in hole to 810 m 6
Drill shoe, circulate, perform FIT 12
Drill 1000 m horizontal section 160
Total hours: 197
The 8.5 in. hole through the reservoir
Operation: Hours used:
Clear rig floor 0,8
Make up scraper and magnet assy. 1,6
Pick up heavy weight drill pipe 12
Make scraper run 18,9
Rig up tubing tongs 3,1Make up wirewrap screens, blanks and swellpackers 27,2
Install screen packer/hanger and running tool 1,6
Rig down tubing tongs 0,8
Run screens on drill pipe 15,7
Drop ball, pump down and set packer 3,1
Test packer from above 1,6
Release running tool and flowcheck 1,6
Displace well above packer to brine 0
Pull out and lay down running tool 7,9
Make up anchor packer assy. 4,7
Run in assembly on drill pipe 15,7
Orient and set anchor packer 1,6
Pull out and lay down running tool 7,9
Total hours: 126
Operation: Hours used:
Pull bore protector 3,1
Install lateral zone assemblies 7,9
Splice and terminate el. cable 15,7
Make up main completion assembly 6,3
Run in 5,5 in. tubing 29,9Install TRSCSSV, splice cables 6,3
Run in 5,5 in tubing 1,9
Make up tubing hanger 6,3
Make up THRT and STT?? 6,3
Run in on WOR?? 18,9
Install lifting frame, flow head 9,4
Land and lock tubing hanger, test seals 1,6
Drop ball, press. Tubing, set and test packer 3,1
Close TRSCSSV, inflow test,equalize and open 1,6
Rig up wirelin, pull packer setting plug 12,6
Pull plug 3,1
Press. Up annulus and test packer from above 1,6
Total hours: 136
Install Upper Completion
Operation: Hours used:
Prepare rig for well flow 3,1
Displace WOR to nitrogen 9,4
Flow out brine and mud and oil 12,6
Bullhead tubing with diesel and wax inhibitor 3,1
Displace WOR to brine 3,1Close TRSCSSV 0,8
Install tubing head crown plug and test on wireline 12,6
Close HXT valves and test 3,1
Remove and lay-out WOR, SST etc. 12,6
Install tree cap, test, pull and lay down running tool 9,4
Pull BOP and marine riser 15,7
Install corrosion cap 6
Deballast and prepare to move rig 6,3
Total hours: 98
Start well for production
7.3 Torque and Drag in 3D
Dogleg
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Operation: Hours used: Percent time:
36 in. hole 32 3.326 in. hole 49 5
Running BOP 39 4
17,5 in hole 93 9.5
12,25 in. hole 156 15.9
Wellhead 55 5.6
8,5 in. hole 197 20
Lower completion 126 12.8
Upper completion 136 13.9
Start well 98 10
Total hours: 981
40,9 days 100%
Summary of well construction time
Dogleg
rad
180)(DL
coscoscossinsincos 212121
X
Y
Z
22
1
1
2
1
R
R
Friction vs. geometry
Straight sections
Curved sections
sincosLwFF 12
sin Lwr T
12
1212
sinsinLweFF 12
121rFrNT
2D Example
500
1500
0
)(m Depth
Horizontal
45335
170
kN 2861661
500 1500
45
45
455
)(Re mach
1 3 0 8
1380
1000
170
1000
2D Results 2D Results
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Table 7.1: Forces in the drillstring during hoisting and lowering
Position
Static weight(kN) H oisting (kN) Lowering(kN)
Well Bottom 0 0 0
Bottom dropoff section 286 286 286
Bottom sail section 286+0.237x120=
286+28.4=314.4
286x1.17+28.4=363 286x0.855+28.4=272.9
Top sail section 314.4+0.237x925=
=314.4+219.2=533.6
363+0.237x1308(cos 45˚+0.20sin45˚)=626 272.9+0.237x1308(cos 45˚-0.20sin45˚)=448.3
Top buildup section 533.6+0.237x120=
533.6+28.4=562
626x1.17+28.4=760.9 448.3x0.855+28.4=411.7
Top well 562+0.237x335=
562+79.4=641.4
760.9+79.4=840.3 411.7+79.4=491.1
500 1000
500
1000
1500
)( m Depth
)( kN Force
Hoisting
Lowering
)( kNmTorque
0 10 20
0
1661
1380
455
335
54.15 4.641 3.8401.491
Static
Torque
Vertical
Build-Up
Straight
Inclined
Drop-Off
BHA
Vertical
500 1000
500
1000
1500
)(m Depth
)(kN Force
)(kNmTorque
0 10 20
0
1661
1380
455
335
kNmTOB 9WOB
Without
Bit Torque
With
Bit Torque
90kN
Off Bottom
2254.1513 4.641
Vertical
Build-Up
StraightInclined
Drop-Off
BHAVertical
Static Weight (Off-Bottom)
Static Weight (On-Bottom)
3D Example
X
Y
Z
500
1052
1512
1752
20632104
40
0
25
73
3D Results
500 1000
1000
2000
3000
)(mMD
)(kN Force
)(kNmTorque
0 10 20
0
500
1100
1700
2075
2865
Hoisting Lowering Static
768576463
Build-up
Straight Inclined
Build-upwith
RightSide Bend
Build-up
withLeftSide Bend
Straight Inclined
BHA
Vertical
5.13
ueStaticTorq
500 1000
1000
2000
3000
)(mMD
)(kN Force0
500
1100
1700
2075
2865
ht StaticWeig
768576463
Build-up
StraightInclined
Build-up
with
RightSideBend
Build-up
with
Left Side Bend
StraightInclined
BHA
VerticalCombined
Hoisting
661513
Pure Hoisting
Pure Lowering
Combined
Lowering
Friction Analysis for Long-Reach Wells
This presentation
I d
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Introduction
Analytical models for torque and drag
Field case
Friction analysis for ultra-long wells
Summary
IntroductionSignificance of well friction
Numerical simulators:
Availability
Limitations
Closed form models:
Increase availability
Analytical approach
Analytical models for torque and drag
Basic model: Coulomb friction
Linear hole sections
Drag: F 2 = F 1 + w s(cos sin )
Torque: T = w srsin
Analytical models for torque and drag
Drop-off section
Analytical models for torque and drag
Modified catenary profile
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pForces:
Fx = 0
Fz = 0
Tension during hoisting:
Tension during lowering:
Torque:
2 1
2 1
2 1
2
2 1( )
2 1 2
2 1
(1 )(sin sin )
1 2 (cos cos )
ewR F F e
e
F F e wR e2 1 2 12 1 2 1 sin sin
1 sin cos cos1 2 1 2 1T r F wR rwR
y pResults:
Well path coordinates:
Deviation from ”ideal”tension: F
Drag:
Torque:
1 11 1 1 11 1
sincosh sinh cot cosh sinh cot
sin
F wx z
w F
s F
w
wx
F
11
1 1
11 1sin sinh sin
sinh cot cos
F F
ws F
F cat
tan
cos
sin
1 1 1
1 1
1 1 1
1 1
costan
sincat
ws F T r F
F
Note: Entrance condition to modified catenary
Analytical models for torque and drag
Side bend
Tension:
Torque:
2 1
2 1
2
22
2 1 122
1 1
1 1
2 2
wR e F F F wR e
F F wR
T r F wR 12 2 2 1
Analytical models for torque and drag
Combied rotation and axial movement
a) Drag and torque for a pipe.
b) Combined friction from rotationand axial movement.
2
22T F w sr
Analytical models for torque and drag
Downhole motor torque
Analytical models for torque anddrag
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Downhole motor torque
Bit power during rotary drilling:
Bit power with downhole motor:
Assuming equal power, the torque relation is:
This is the ”gearbox” principle.
Downhole motor may significantly reduce bit torque.
motor motor motor
rotaryrotaryrotary
n
n
CT P
CT P
rotary
motor
rotarymotor T
n
nT
Application:
- Split the well into geometries:
e.g. straight section bottombuild-up section
vertical section
- Adding the equations for these geo metries gives total torque and drag
Analytical models for torque anddrag
Applications:
3-Dimensional well path.
Drag:
Torque:
Total solution:
Drag:F= F 2 from bottom to top
Torque:T= T from bottom to top
2 2
2 2 2 build_or_drop sidebend F F F
2 2
2 build_or_drop sidebend F T T
Field case
Long-reach well in the Yme field:Depth: 2950 mTVD top reservoir
3100 mTVD total depth
Horizontal reach: 7528 m
Rig limitations:Hoist: 4540 kN (1.mill. lbs)
Top drive: 35 kNm (25.800 lb-ft)
Field case
Well profile investigated
Field case
Results Top-drive:
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Hoist
Conclutions:
- Drill string tension not critical
- Torque limiting element
- Modified catenary profile best
Top drive:
WellProfile
Static hookload (kN)
Pick-upload (kN)
Slack-offload (kNm)
Modified
catenary
845 1360 593
Minimum
dog-leg
843 1332 609
Under-
section
842 1321 568
Standard 858 1350 543
WellProfile
Surfacetorque (kNm)
Torque build-upbnd (kNm)
Torquehold
Modified
catenary
28.57 7,11 21,46
Minimum
dog-leg
30.91 11,04 19,87
Under-
section
29.51 6,88 22,63
Standard 30.42 9,05 21,37
Friction analysis for ultra long wells
Example: Prolong Yme well to a horizontal reach of 12 km
Results
Pulling Sta tic Lowering Build-up Hold
section
Total
Steel 179 175 60 10,2 43.7 53.9
Titanium 133 130 60 6,2 26,90 33.1
Composite 102 101 60 3,7 16.0 19,70
Drillpipe Hook load(kN) Torque(kNm)
Conclusions:
Well can be drilled if light drill pipe
is used in the sail section Tension allowable for all cases
Torque limiting factor
Other elements within permissible
limits, like hydraulics, hole cleaning,
borehole stability, …
Summary Analytical expression for torque and drag are derived in this paper.
The models are valid for straight sections, build-up, drop-off and sidebends.
Equations for geometry and torque and drag for a modified catenaryprofile is also given.
Torque and drag analysis can be performed by adding equations for eachhole section.
A field case from Yme demonstrates the application. A modified catenaryprofile was chosen to minimize torque.
An ultra-long well was studied with the models. By using light-weight drillpipe in the sail section a 12 km(or longer) well can be drilled with existingrig equipment.
Dominating limiting parameters:
Friction
Drill pipe weight
Mud density
Friction analysis for ultra-long wells
Guidelines to obtain a low-friction well:
7.4 Stuck pipe in deviatedwellbores
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High inclination in the sail section.
Minimum weight BHA.
Heaviest DP in top of string.
Select modified catenary or another profile.
Minimizing dog-leg and tortuosity.
Downhole motor reduce torque.
Reduce friction by:
Low DP weight
Small tool joint
Self-lubricant matrix.
-
Content
Introduction Industry practice Deviated wells and friction
Depth to stuck point Field case Methods to free pipe Final comments
Introduction
Two most costly drilling problems: Circulation losses
Stuck pipe
Causes high economic risk for long wells Sidetrack often consequence
Operational aspects important Often stuck after static period
Industry practice
If stuck drillstring, apply pull testAl l f d
Deviated wells and friction
This analysis valid for differential sticking
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Alternatively, run free point indicator
Pull test estimate free pipe length fromelongation Current models neglects well friction
Therefore strictly applicable for vertical wellsonly
y g
Differential pressure
Area exposed
Permeable formation
Friction in curved bends and
straight inclined sections
Depth to stuck point
Depth to stuck point,
vertical well
Depth to stuck point,
deviated well(vertical, build, sail)
Torsion test
Field case
DP stuck in long deviated well
Friction coefficient causes uncertainty
Results:
Frictionless: 5097 m
New model: 5693 m
Torsion test: 5675 m
Torsion is independent of friction as
pipe is not pulled
Torsion test should be included in rig
procedures
Methods to free pipe
Maximum mechanical force
Final comments
This analysis is valid for cases with differential sticking. The
diff i l llb /f i i h i i l l
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Pull/twist DP towards limit
Minimum density method
Displace well to minimum density mud to reduce
bottomhole pressure. Also reduces buoyancy
Maximum buoyancy method
Displace DP to seawater. Buoyancy increases giveing higher pull margin
Results:
differential pressure wellbore/formation is the critical element.
If the string is mechanically stuck, the differential pressure is no
longer a factor. For this case reducing MW has no positive effect.
We recommend that the Maximum Mechanical Force method, the
Maximum Buoyancy method and theTorsion method to be used
here.
7.5 Well-Integrity Issues
Offshore Norway
Birgit Vignes, Petroleum Safety Authority Norway
Bernt S. Aadnoy, Univ. of Stavanger
Paper IADC/SPE 112535 presented at the 2008IADC/SPE Drilling Conference, Orlando
1. Introduction of the pilot well integrity study
2. Regulation and standards
3. Results of the study
4. Examples of well failures5. Continued work in 2008
Summary
This presentation
1. Introduction - Background for the survey
Several well integrity incidents
Several shortfalls
Scope:Scope: How comprehensive is theHow comprehensive is the
well integrity problem on the NCS,well integrity problem on the NCS,
and what are the main issues/ challenges?and what are the main issues/ challenges?
S l i f ll f il i i
1. Introduction - Well Categorization
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Several shortfalls
Missing critical information Insufficient openness and access to well-data
Competence issues
Well conversions
Varying management of changes
Selection of wells for pilot examinationSelection of wells for pilot examination
Well integrityWell integrity
failure / issue ?failure / issue ?(or uncertainty)(or uncertainty)
NoNoYesYesWhat kind of barrier/What kind of barrier/
barrier elementbarrier element
failure/ issue/ uncertainty ?failure/ issue/ uncertainty ?
Well barrierWell barrierintactintact
Impact?Impact?YesYes
Cat. A:Well isshut In,
E.g.: Leaks,over criteria,
well contr .,
Cat. B:Working
under
conditions/exemptions
E.g.: No gas lift
NoNo
Cat. F:
Shut in
because of
topsides
bottlenecks,planned
testing and
maintenance
Incl.: SD&P
Cat.G:
Shut in
while
awaiting
P&A
Cat. C:Insignificant
deviation
for currentoperation
Determine injury/ damage/ Determine injury/ damage/
production impact/ production impact/
financial lossfinancial loss
Shut in well ?Shut in well ?NoNoYesYes Well
OK /
active
Cat. D:
External
conditionsE.g.:
weatherconditions,
other
activities,
union dispute,
Cat. E:
Shut in
on the
basis of
reservoar related
issuesE.g.: high
water cut
2. Regulation and standards
Primary Well Barrier
Secondary Well Barrier
Ref. “Swiss cheesemodel”
The Primary Well Barrier is the first object to prevent
unintentional flow from the source
The Secondary Well Barrier prevents further
unintentional flow if the primary well barrier should fail
Common production well
with the 2 ”barrier envelopes”
Source
Ref: Activities Regulation §76 w/ref. to NORSOK D010
3. Results - Wells with integrity issues
18% of 406 the assessed production- and injection wells were reported to have well
integrity failures/ shortfalls or uncertainty.
Well issues are related to 33% of the injectors, and 15% of the producers.
Wells with integrity failure, issue or uncertanty
48
27
75
0
10
20
30
40
5060
70
80
Production Injection Total
Production, injection and total
N u m b e r o f w e l l
3. Results – Well integrity impact
Well integrity impact
20
25
3. Results - Well integrity issues by age
Well integrity failure/issue distribution b y well age, per 1.3.2006
25
30
s s u e
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18
22
8
10
16
1
0
5
10
15
20
A: Shut in B: Working under
conditions
C: Insignificant deviattion
for current operations
Well integrity impact category A, B and C
N u m b e r o f
w e l l s
Producer
Injector
7% wells were shut in9% wells were working under conditions/exemptions
2% wells had an insignificant deviation for current operations
• The frequency of wells with integrity issues in age group 0-14 years is twice as
high as for well group 15-29 years.• WAG wells and recently optimized well design have caused challenges
• P&A wells are not included in this survey
24
26
16
6
12
0
5
10
15
20
25
0 to 4 5 to 9 10 to 14 15 to 19 20 to 24 25 to 29
Age in years
N u m b e r o f w e l l s w i t h f a i l u r e / i s
Numbe r of w ells w ith we ll integrity problem
29
8
4 2 1 1 1 2 12
9 8
12 4
W e l l
h e a d
D H S V
C o n d
u c t o r
A S V T u
b i n g G L
V
C a s i n
g
C e m e
n t
P a c k
e r
P a c k
o f f
C h e m
i c a l i n
j . l i n e
T R S V
F l u i d
b a r r i
e r
D e s i g
n
F o r m
a t i o n
C a t e r o r y b a r r i e r e l e m e n t f a i l ur e
N u m b e r
o f w e l l s
0
5
10
15
20
25
30
35
3. Results - Well barrier element 3. Results - Areas for improvement:
Areas of high priority: Well documentation
Handover documentation
Regular monitoring
Competence and training
Event:
18-5/8” csg. broke due to
corrosion
Reasons:
Cement return port left
open
4. Example I: Surface Casing collapsed
Event:
Casing and tubing hangerand running tool failed
Reasons:
Hangers uprated 50%
Manufacturers up-rating
4. Example II: Production Casing Failure
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corrosion
Wellhead dropped 44 cm Platform structure
arrested further drop,
reducing the damage
potential
open
Fresh seawater and tide
caused severe corrosion
in splash zone
Consequences:
Platform production
stopped
High cost of event Initiated monitoring
program
and running tool failedduring operations
Overloaded duringpressure testing
Manufacturers up-rating
failed
Accepted uprating as OK
Poor equipment design
Consequences:
Cost of well problems
Many installations, cannot
replace Reduce max. allowable
loading
Events:
Severe lost circulation
Plugged drill pipe
Wellcontrol problem
Open well in periods
Reasons:
Depleted reservoirs
Gunk pill plugged off DP
Less good operational
decisions
Consequences:
Sidetracked well
High cost
Improved procedures
4. Example III: Lost wellbore
Events:
Leaks in prod. tubings in
14 wells
Reasons:
Leaks in PBR
Corrosion
Consequences: Increased monitoring
Constraints for availability
and flexibility
4. Example IV: Gas Leaks in Tubings
Events:
Prod. csg. and tubing
collapsed
Reasons:
Wrong csg. joint installed
Leaks through PBR
4. Example V: Production Casing Failure 5. Continued work in 2008Industry:
Operators studies confirm PSA 2006 results
OLF workshop initiative and founding of operators well integrity forum (WIF)
Operators increased focus on well integrity issues and personnel competance
Profile issue in Risk Level Project (KPIs & healthy wells)
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collapsed
Well control incident
during repair operation
Leaks through PBR
Uncertain pressureintegrity of well
Consequences:
High cost
Clarify well integrity
Improve workover
procedures
International Authorities:
Information and documents requested in PSA 2006 study and auditing ofoperators
Information to NOPSA (Australia) in meetings with PSA and Statoil
Cooperation with SSM (Netherlands) 2007-2008 with similar approach as PSA2006
PSA:
Well integrity meeting and auditing of Marathon Norway in June 2007
Well integrity challenges of CO2-injection to be studied by SINTEF
Survey of temporary abandoned wells incl. well barrier schematic
Well integrity issues related to GLV & ASV to be discussed with industry during2008
The wells were a representative selection
A high number of well-related failures and shortfalls
18 % of the wells had well integrity issues or uncertainty
7 % of the wells were shut in
The barrier issues are within tubing, ASV, casing and cement The impairments represents a high potential for HSE
improvement
Examples of well failures presented
Summary
EXTRA VIEWGRAPHS
Initial Questionnaire for PSA’s survey
A. Is the “well picture”/ outcome of the XLS- forms representing the typical situationon the facility ?
B. Are key design premises, well history and current technical condition validatedand easy accessible for key personnel?
C Does hand-over documents include sufficient well data with premises/ limits
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C. Does hand-over documents include sufficient well data with premises/ limits,including updated schematics, exposures, technical condition and changes/
deviations/ precautions with regard to well integrity and well control issues?D. Are there established technical requirements to well barrier envelopes /elements,regular condition monitoring, and systematic management of well integrity issues?
E. Are the company requirements for well barriers consistent with Norsok D-010 ?
F. Is there a consistent practise within the company for managing well integrityissues?
G. Are management of change and non-conformance handling consistently practised?
H. Are requirements to competence and training defined and implemented forcommon understanding of the well barrier concept, barrier performancerequirements, records assurance, and actions required upon indications offailures ?
I. How is openness and reporting of undesirable well incident encouraged, includingexchange of experience internally and externally ?
J. Any specific performance indicators pertaining to well integrity ?
K. Other issues relating to the subject