modern well design-presentation

8/17/2019 Modern Well Design-Presentation

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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


From solid mechanics:

Petroleum Rock Mechanics: Materialproperties

Recent view: Stress dominated processes

This leads to simplified design methods

E


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Horizontal stresses from Kirch eqn.:

= ½(LOT+Pore Pressure)

Mid-Line Principle



Example from the North Sea


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


Classical criteria

Max. Hydraulic horsepower

Max. Jet impact

Limitations

Physically correct?

Adequate Q for hole cleaning?


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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






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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23/70

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 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 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







M oh r - C o ul om b f a i l ur em od el




0 3 . 0 6 .2 0 1 1 2








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

0 3 . 0 6 .2 0 1 1 3



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


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


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


32/70

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


38/70

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


39/70

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


40/70

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


41/70

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


42/70

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


43/70

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


44/70

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


45/70

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


46/70

-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


47/70

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


DF = 2.14

Biaxial model

DF = 2.04

Case #4Snubbing

New 3D model

DF = 1.69


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


48/70

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


49/70

.

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


50/70

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


51/70

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


54/70

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.


55/70


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


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


56/70


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


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


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


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


57/70

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


58/70

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


59/70

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


Basic model: Coulomb friction

Linear hole sections

Drag: F 2 = F 1 + w s(cos sin )

Torque: T = w srsin


Drop-off section


Modified catenary profile


60/70

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


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


Combied rotation and axial movement

a) Drag and torque for a pipe.

b) Combined friction from rotationand axial movement.

2

22T F w sr


Downhole motor torque

Analytical models for torque anddrag


61/70

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:


62/70

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


63/70

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


64/70

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


65/70

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

modern well design-presentation

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