Module F:
Drilling in Unusual Stress Regimes
Part I – Overpressured Cases
Maurice B. Dusseault
University of Waterloo
Drilling in Overpressured Zones
For practical purposes ($), reducing the
number of casings or liners is desirable
 However, drilling in OP zones carries
simultaneous risks of blowouts and lost
circulation that are difficult to manage.
 There now exist new options that help us:

 Drilling
slightly above shmin with LCM in the mud
 Bicentre bits and expandable casings

Understanding overpressure and also the
deep zone of stress reversion will help
Pressures at Depth
~10 MPa
pressure (MPa)
Fresh water: ~10 MPa/km
8.33 ppg
0.43 psi/frt
Sat. NaCl brine: ~12 MPa/km
10 ppg
0.516 psi/ft
Hydrostatic pressure distribution: p(z) = rwgz
1 km
Underpressured case:
underpressure ratio = p/(rwgz),
a value less than 0.95
underpressure
depth
Overpressured case:
overpressure ratio = p/(rwgz),
a value greater than 1.2
overpressure
Normally pressured range:
0.95 < p(norm) < 1.2
Some Definitions






For consistency, some definitions:
Hydrostatic: po = “weight” column of water
above the point, r = 8.33 ppg to 10 ppg in
exceptional cases of saturated NaCl brine
Underpressure is defined as po less than
95% of the hydrostatic po, usually found
only at relatively shallow depths (<2 km) or
in regions of very high relief (canyons…)
Mild overpressure: po of 10 ppg to 60% sv
Medium overpressure: po of 60 to 80% sv
Strong overpressure: po > 80% of sv
Abnormal Pressure, Gradient Plot
1.0
2.0
16.7 ppg
0
1
po
shmin
2


sv
thick shale
sequence
3

po
4
Target A
5
6
Target B
Target C
depth - kilometres


Typically, po is close to
hydrostatic in the upper
region
shmin is close to sv in
shallow muds, soft
shale, but lower in stiff
competent deeper shale
A sharp transition zone
is common (200-600 m)
The OP zone may be 2-3
km thick
A stress reversion zone
may exist below OP
GoM –The Classic OP Regime
Other Well-Known Strong OP Areas
Iran, Tarim Basin (China), North Sea,
Offshore Eastern Canada, Caspian
 In many thick basins, OP is found only at
depth, without a sharp transition zone
 Most common in young basins that filled
rapidly with thick shale sequences

 Good
ductile shale seals, undercompaction
 Watch out for OP related to salt tectonics!

These are most common offshore:
 Land
basins have often undergone uplift
 Tectonics have allowed pressures to dissipate
Eastern Canada Overpressured Areas
Nova Scotia Gas Belt
Importance of Geomechanics
Exports
Porosity vs Depth & Overpressure
0
0.25
0.50
0.75
1.0
porosity
sands &
sandstones
mud
clay & shale,
“normal” line
clay
mudstone
In some cases, 28%
f at depths of 6 km!
Anomalously high
f, low vP, vS, and
other properties
may indicate OP
shale
effect of OP
on porosity
4-8 km
depth
+T
slate (deep)
Permeability and Depth
Muds and shales have
low k, < 0.001 D, and as
low as 10-10 D
 Exception: in zones of
deep fractured shale,
k can approach 0.1-1 D
 Sands decrease in k
with z
 Exception, high f
sands in OP zones can
have high k
 Anhydrite, salt k = 0!
 Carbonates, it depends
Permeability – k – Darcies

0
1
Muds and
Shales
2
3
4
Sands and Sandstones
Depth – z – 1000’s ft
5
10
15
Intact muds and shales
have negligible k
High porosity OP sands
have anomalously high
porosity & permeability
20
Fractured shales at depth may
have high fracture permeability
25
5
Abnormal po Causes

Delayed compaction of thick shale zones
 Water
is under high pressure
 Leak off to sands is very slow (low k)






Thermal effects (H2O expansion)
Nearby topographic highs (artesian effect)
Hydrocarbon generation (shales expel HCs,
they accumulate in traps at higher po)
Gypsum dewatering ( anhydrite + H2O)
Clay mineral changes (Smectite  Illite +
H2O + SiO2)
Isolated sand diagenesis (Df, no drainage)
Mechanisms for OP Generation
Compaction =
H2O expelled to sand
bodies, especially
from swelling clays
Mud, clays
H2H020
Sand
Shale
0-2000 m
H20
2000-4000 m
Montmorillonite = much H2O
Sandstone
Diagenesis
Illite
Kaolinite
Chlorite
4000-6000 m
+ Free H2O
+ SiO2
Compaction and
Clay Diagenesis
Mechanisms for OP Generation
Artesian effect (high elevation recharge)
rain
 Thrust tectonics (small effect)
 Deep thermal expansion

clays and silts
Artesian charging
3-10 km
Artesian charging is
usually shallow only
20-100 km
Thrusting can lead
to some OP
+DT = +DV of H2O: thermal
expansion at depth
Offshore: Trapping of OP
Listric faults on continental margins lead to
isolated fault blocks, good seals, high OP in the
isolated sand bodies from shale compaction
“down-to-the-sea” or “listric” faults
sea
stress
sv
sh
po
shale
slip planes
Sand bodies that have no
drainage because of fault seals,
OP is trapped indefinitely
shale
depth
Stress reversion zone
HC Generation and OP
sv
shale
T, p, s
increase
Semi-solid
organics, kerogen,
po < sh < sv
kerogen
microfissure
sv
high T, p, s
sands
fluid
flow
HCs generated
in organic shales
oil and gas
generation of hydrocarbon fluids
po = sh < sv,
Fractures develop
and grow
Pressured fluids are
expelled through the
fracture network, po
“stored” in OP sands
OP From Gas Cap Development
A
pressures along A-A
stress
gas cap
effect
oil, density
= 0.75-0.85
gas cap,
low density
A
po
depth
Thick gas cap development,
perhaps charged from below,
can generate high OP
sh
Gas migration along
fractured zones,
faults, etc.
Fractured rock
Deep gas source
around fault
Gas rises: gravitational segregation
Abnormal Pressure – Sand-Shales





Overpressure is often generated due to
shale compaction and clay diagenesis
Montmorillonite (smectite) changes to
lllite/Chlorite at depth. H20 is generated
and is a source of OP.
Pressure is generated in shales, sands
accumulate pressure
PF commonly higher in shales than sands
Sand-shale osmotic effects (salinity
differences) can also contribute to OP
PF in GoM Sand-Shale Sequences
Absolute stress values
Stress gradient plot
stress
PF in sand line
shmin
sv
shmin
z
shale
sandstone
shale
sandstone
limestone
shale
depth
Pore pressure distribution, top of OP zone
depth
sv
z
Some Additional Comments





Casing shoes are set in shales (98%)
The LOT value reflects the higher shmin in
the shales, therefore a higher PF
As we drill deeper, through sands, the
actual shmin value is less! By as much as 1
ppg in some regions
Can be unsafe, particularly when we
increase MW rapidly at the top of the OP
zone
You should test this using FIT while drilling
Examination of a “Typical”
Synthetic OP Case
Particularly Difficult OP Case
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0
Sea water depth 800 m
1
800 m soft sediments
2000 m medium stiff
shales and silts
2
3
sh
po
sv
seal
4
1400 m OP zone
5
6
Deep water drilling,
mud heavier than H2O
 Thick soft sediments
section, PF ~ sh ~ sv
 Thin, shallow, gascharged sand
 Zone where sh is
roughly unchanged
 Sharp transition zone
 High OP, 90% of sv
 Deep zone of stress
and pressure reversion

Reversion
zone
Z – kilometers (3279 ft/km)
sharp
transition
Upper Part of Hole
1.0 (8.33 ppg)
2.0 (16.7 ppg)
0
The vertical lines are
several MW choices
 Riser and first csg. MW
 9.16 ppg does not
control gas, but only
fractures above 950 m
 10.0 ppg controls gas,
but losses above 1200 m
will be a problem. It
does allow deeper drlg.
 Solution, riser seat at
~1000 m
 Casing shoe at ~1400 m
9.16 ppg
10.0 ppg

Sea water - 800 m
1
800 m soft sediments
2
Medium stiff
shales and silts
Z – kilometers (3279 ft/km)
Riser Issues in this Example






Sea water is ~ 1.03 ~8.6 ppg
At great depth, MW may be as high as 2.02
(17 ppg) if the riser is exposed fully
The D-pressure at the riser bottom is very
large: 800m  9.81  (2.02 – 1.03) = 7.8 MPa
The riser must be designed to take this
Or, special sea-floor level equipment must
be installed
Special mud lift systems from the sea
floor, etc.
Approaching the Transition Zone
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0

Sea water - 800 m

800 m soft sediments

1
2000 m shales
and silts
2

po
sh
sv

3
sharp
transition
4
OP zone
Z – kilometers (3279 ft/km)
LOT of 1.3, 10.83 ppg
This limits us to 3.6 km
for the next casing
However, this will
require a liner to go
through transition zone
Liner from 3600 m to
3750 – 3800 m
If it is possible to drill
100 m deeper initially,
to 3700 m, we may save
the liner ($1,000,000)
Solution A: Casing or Liners
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0

Sea water
1


2000 m shales
and silts
2
po
sh
sv
3
4
OP zone
Z – kilometers (3279 ft/km)
This is the most
conservative, safest,
and the most costly
Black line is MWmax
If shale problems
occur in the 1.6-3.6 km
shale zone, requiring
an extra casing… (i.e.,
little margin for error)
Sol’n B: Drill OB With LCM?
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0
Sea water
1
2000 m shales
and silts
2
po
sh
sv
3
4
Dashed line is from
the previous slide
 Drilling with the purple
line, saves a liner!
 This is ~1.2 ppg OB at
the shoe (quite a bit!)

OP zone
Z – kilometers (3279 ft/km)
Place upper casings
deeper if possible
 Drill with LCM in mud
(see analysis approach
in Additional Materials)
 Place a denser pill at
final casing trip
 (Approach with caution)

Solution C: Deeper Upper Casings
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0
300 m subsea primary
casing depth
 Casing at 1850 m depth
 Drill long shale section
with MW shown as
dashed black line
 Increase MW only in
last 100 m (LCM to plug
ballooning at the shoe)
 Slight OB of 0.2-0.3
ppg needed
 Casing may be saved (?)

Sea water
1
2
Slight OB
needed
3
sh
sv
po
4
Z – kilometers (3279 ft/km)
OP zone
Deeper Upper Casing Shoes
Depending on the profile of OP stresses
and pressures, this approach can be
effective, but in some cases it is not
 Of course, the best approach is always to
place the shoes as deeply as possible
 This may give us a one-string advantage
deeper in the well if problems encountered
 At shallow depths (mudline to ~4000 ft),
use published correlations with caution
because there are few good LOT data

Comments on the Approaches
There is risk associated with saving a
casing string: risks must be well-managed …
 The stress/pressure distribution sketched
is a particularly difficult case:

 Shallow
pressured gas seam at 1500 m subsea
 PF (sh) is quite low around 3000 m subsea
 Transition zone is very sharp (~250 m)
 OP is high (88-90% of sv)

However, it could even be worse!
 More
 Etc…
gas zones, depleted reservoirs at 3.6 km
Drilling Through a Reversion Zone
Below OP, usually a zone where po, sh (PF)
gradually revert to “normal” values. This is
rarely a sharp transition as at top of OP
 This is related to fractured shales that
“bleed off” OP (i.e. lower OP seal is gone)
 Also, when shales change and shrink, the sh
value (PF) drops as well
 “Reverse” internal blowout possibility

 Blowout
higher in hole
 Fracturing lower in hole
Stress Reversion at Depth
stress (or pressure)
vertical stress, sv
horizontal stress, sh
pore pressure, po
Note that shmin can become > sv
4 km
depth
Z
Region of strong
overpressure
Higher k rocks
(fractured shales)
Stresses “revert” to
more ordinary state
Same Example…
2.0 (16.7 ppg)
1.0 (8.33 ppg)
OP casing was set at
3800 m depth
 Drill with 16.7 ppg MW
 At 5.5 km, large losses
 If we reduce MW,
high po at 4.6 km can
blow out, flow to
bottom hole at 5.5 km
(reverse internal BO)
 Set casing at 5450 m
 Drill ahead with
reduced MW

4
1400 m OP zone
5
Reversion
zone
6
po
Z – kilometers (3279 ft/km)
sh
sv
Real Deep Overpressure Drilling
Watch out for shallow
gas sands
 Dark black line: MWmax
for the interval
 Dashed black line is
the actual drilling MW
 Red stars: excessive
shale caving, blowouts
 Green stars: ballooning
and losses
 Surface casing string
not drawn on figure

This is a deep North Sea case, west of Shetlands
Detecting OP Before Drilling

Seismic stratigraphy and velocity analysis
 Anomalously
low velocities, high attenuations
 Can often detect shallow gas-charged sands
(unless they are really thin, < 3-5 m)
Geological expectations (right conditions,
right type of basin and geological history…)
 Offset well data, good “earth” model, so
that lateral data extension is reliable

Detecting OP While Drilling







Changes in the “Dr” exponent, penetration
rate may increase rapidly in OP zone
Changes in seismic velocity (tP increases)
Changes in porosity of the cuttings
(surface measurements or from MWD)
Changes in the resistivity of shales from
the basin “trend lines”
Changes in the SP log
Changes in drill chip and cavings shapes,
also volumes if MW < po
Mud system parameters, etc
Comments on LWD
Methods of data transmission…
 Mud pulse – 2 bits/s @ 30,000’, 12-25 b/s
is good at any depth
 Issues in data transmission:

 Long
wells, extended reach
 OBM, electrical noise, drilling noise
 ID changes in the drill string
 Pump harmonics, stick/slip sources
“Wire” pipe – extremely expensive
 High rate on out-trip, then download on rig
 New technologies will likely emerge soon…

Reasons for Pore Press. Prediction
Drilling Problems Due to Pressure Imbalance:
 Overbalance:
Slow drilling, Differential
Sticking, Lost circulation, Masked shows,
Formation damage.
 Underbalance:
Imprudently fast drilling,
Pack- offs, Sloughing shales, Kicks,
Blowouts.
Pore Pressure Prediction Basics I

Data from offset wells
 Logs,
Dr data, sonics, neutron porosity,
resistivity, etc.

Transfer data to new well stratigraphy, z
 Plot
sv gradient, sonic transit time, Dr,
resistivity, porosity, etc. with depth
Use trend analyses and published methods,
to determine the “normal compaction line”
 Use an Eaton correlation chart if you have
it for this area (use offset and other data)
 This is the prognosis profile for new well

Pore Pressure Prediction Basics II

With seismic data and geological model of
the new well region, assess:
 Existence
of OB conditions (seals, sources…)
 Existence of faults, salt tectonic features…
Plot depth corrected velocities on profile:
 Carefully compare the two:

 Lower
velocities = greater OP risk…
 Explain existence of any undercompacted zones
and anomalies you have identified

You now have as good a prognosis as you
can develop with existing data
Sonic Transit Time Differences
1.0 (8.33 ppg)
2.0 (16.7 ppg)
Log of sonic transit time
0
650 ms/m
Sea water depth 800 m
1
Soft seds.
2
Stiff shales
and silts
3
sv
po
seal
4
5
PROGNOSES FROM
OFFSET WELL
DATA, CORRECTED
FOR Z, ETC…
Expected OP
transition
OP zone
Reversion
zone
6
Z – kilometers (3279 ft/km)
Normal trend from the
basin, offset data
Seismic
velocity
model
Sonic transit time
from offset wells
Critical region
Prognoses Based on Seismics
Normal compaction line for
the basin
General seismic profile data,
depth corrected for new well
Corrected sonic transit time,
calibrated with the general
seismic velocity data
OP beginning
Large OP expected
Regions of substantial
deviation are highlighted as
“critical”, experience used to
choose likely top of OP
OP magnitude estimated,
based on correlations
Seismic Cross-Sections




Depth Converted
1:1 Horizontal / Vertical Ratio
Offset Well Ties (Regional)
Planned Wellbore (Local)



Full Structural Picture
Fully Annotated
Radial Animation
North Sea Seismic Section - Diapir
1b
Well A
Gas Pull Down
Mid-Miocene regional pressure boundary
Top Balder
Top Chalk
Intra Hod/Salt
Courtesy Geomec a.s.
Other “Trend Line” Approaches

Methods exist for using trend analysis for
many different measures, including:
 Drilling
exponent data
 Resistivity trends lines (salinity of strata)
 Deviations from expected porosity (less
sensitive)
 SP log characteristics
 Perhaps some others…

Shale data are used because sand porosity
is less “predictable” in general
Gas Cutting of the Drilling Mud





Shale behaves plastically at elevated
pressure and temperature gradients.
Significance (and insignificance) of gas cut
mud (GCM). Gas from CH4 in shales?
Very large gas units: 2,000 to 4,000 units ?
Connection gas (CG) - better indicator. Use
it for well to talk. Ineffective when too
much overbalance.
CG increase from 20, 40, 60 to 80 points.
Yes, you are underbalanced.
Is MW a Pressure Indicator?
No. The lower limits of MW in most OP
regimes are related to shale stability,
rather than to pore pressure
 Usually, in difficult shales, 1 to 2 ppg above
po is needed to control excessive shale
problems
 HOWEVER! MW limits from offset well
drilling logs are useful to estimate MWmin
 Of course, this can change as well:

 More
inhibited WBM, using OBM instead, etc…
 Faster drilling, less exposure, etc…
MWmin Prognosis
Offset well pressure,
stress, drilling data…
 Estimate target MWmin
for new well prognosis
 If this generates too
narrow a MW window,
assess approaches
 Will OBM allow a lower
MWmin? (on the plot,
the dashed blue line is
the estimated OBM
MW for shale stability)
 Other factors?

MWmin, MWmax Well Prognosis
2.0 (16.7 ppg)
1.0 (8.33 ppg)
0
Sea water depth 800 m
1
Soft seds.
Weak rocks
Stiff shales
and silts
2
3
4
5
Use a rock mechanics
borehole stability model,
calibrated, to estimate
MWmin from geophysical
logs and lab data
 Use offset well losses,
ballooning, LOT, etc. to
estimate MWmin
 This defines the local
“safe” MW window
 Now, combine with casing
program prognosis to plan
the MW for the well

sv
po
PROGNOSES FROM
OFFSET WELL
DATA, CORRECTED
FOR Z, ETC…
Strong rocks
6
Z – kilometers (3279 ft/km)
Expected OP
transition
OP zone
Reversion
zone
During Drilling…
Remember, in OP drilling we are trying to
“push the envelope” to reduce casings
 Update the well prognosis regularly with
actual LOT, MWD, ECD data
 Monitor, measure, observe…

 Kick
tolerances, ballooning behavior, gas cuts
 Chip morphology and volumes
 Flow rate gauges on flowline, pumps
 Mud temperature monitoring MWD temperature
 Sticky pipe, torque, ECD, mud pressure
fluctuations
 Cuttings analyses: vP, Brinnell hardness are used
Increasing Depth of Casing Shoe
(2.0 = 16.7 ppg) 1.1
1.3
1.5
1.7
1.9
2.1
2.3
density, g/cm3
prognosis
for shmin
prognosis
for po
MW
=1.92
sv
XLOT shmin
value
overpressure
transition zone
area indicates
possible MW
depth
Previous
casing
string
shoe
deeper shoe for
casing string!
strong overpressure zone
Using high weight trip pills and careful monitoring, the lower limit can be extended
High Weight Trip Pills







Drill ahead beyond “limit” (if shales permit)
with MW = LOT at the shoe PF
Some gas cutting of the mud and shale
sloughing… If too severe, casing
For trip, set a pill of higher weight
This creates a change in slope of the mud
pressure line in the “window” (see figure)
Pull out carefully, no swabbing please
Set casing (best with top drive and some
ability to pump casing down a bit)
Unlikely to succeed with gas sands present
An OP Well Prognosis
PORE PRESSURE (PPG)
EXPECTED MW (PPG)
FRAC GRAD. (SAND)
FRAC. GRAD (SHALE)
WELL DESIGN - HI 133 No. 1
MW, PF, & EST. po
DEPTH - ft
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
13000
14000
8
9
10
11
12
13
MUD WEIGHT - ppg
14
15
16
17
18
19
Same Overpressured Well, GoM
WELL DESIGN - HI 133 No. 1
MW, PF, & ESTIMATED po
0
1000
2000
PORE PRESSURE (PPG)
3000
EXPECTED MW (PPG)
FRAC GRAD. (SAND)
FRAC. GRAD (SHALE)
4000
DEPTH
5000
6000
7000
8000
9000
10000
11000
12000
13000
14000
8
9
10
11
12
13
14
MUD WEIGHT
15
16
17
18
19
Approach for this Well - I
From 8600´to 9400´po goes from 9.5 ppg to
15.7 ppg (1.14  1.89 g/cm3)!
 A liner over a 800-1200´length is necessary,
but we don’t want to install a second liner
 Strategy:

 Below
the 3000´ shoe, drill as close to po as
possible, as fast as possible to avoid shale issues
 Below 8200´, weight up while drlg. to as high as
possible (upper part of hole will be overbalanced)
 This is a case where we may add carefully graded
LCM to help build a stress-cage higher in the hole
 Drill as deep as possible, hopefully to 9100´…
Approach for this Well - II

Strategy (cont’d)
 Push
the envelope for depth, managing your ECD
carefully, living with a bit of ballooning
 To trip out and case, place a high density “pill” for
safety (e.g. 18 ppg mud for bottom 1500´)
 Set casing (partly cemented only) at 9100-9200´
 Mud up to MW slightly higher than po, drill out, do
XLOT, advance carefully, gradually increasing MW
 Set a liner as deep as possible, 9900´ if possible
 Mud up before drilling out with 16.5 ppg mud with
carefully designed LCM to “strengthen the hole”
 Do a precision XLOT, drill ahead to TD, increasing
MW only as required
Deep Water Drilling & Stability

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Narrow operating window is common
Circulating risks, ECDs, monitoring….
Special mud rheology: low T, riser cools the
mud massively, down to 5-10° is common
Casing design often requires many short
casing strings, shallow muds, overpressure,
and the zone of pressure reversion
Well control is tricky because of the
narrow window, long risers, etc…
Rig positioning and emergency disconnect
critical for safety (no circulation for days)
Gullfaks
North Sea case
Overpressure
Reversion zone
Depletion effect
Franklin Field, UK West Sector
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120-130 MPa po in deep Triassic zones
T to 200-211°C measured
6300 m deep (~20,000 feet)
Mud weights of 18-19 ppg required
Very narrow MW window near reservoir
Retrograde condensate field, liquids are
generated near the well, reducing k
Surface pres. up to 101 MPa (15000 psi)!
Reservoir experienced rapid depletion and
this led to very high effective stresses, as
well as massively reduced lateral stresses
Lessons Learned
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OP drilling: a major challenge, particularly:
 In
young offshore basins
 In deep water (riser length issues)
Careful well prognoses are critical (PF, po…)
 Prognoses must be updated while drilling
 The envelope can be pushed!
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 Living
with breakouts for lower MW
 Using LCM to generate somewhat higher PF
 Special trip practices, special equipment…

In OP drilling, vigilance is absolutely critical
 Increase
your observations, understand them
Additional Materials
Also, visit the following website for a
comprehensive list of formulae for
your pressure calculations in drilling:
http://www.tsapts.com.au/formulae_sheets.htm
Fracture Pressure Enhancement in
Drilling Through Use of Limited
Entry Fracturing and Propping
Courtesy of:
Francesco Sanfilippo
Geomec a.s., Norway
Courtesy Geomec a.s.
The Concept
To enhance fracturing pressure by drilling slightly
overbalance and, at the same time, by effectively
plugging and sealing the induced hydraulic fractures
Already plugged
Induced fracture
Not plugged
Courtesy Geomec a.s.
How Can this be Analyzed?
1. Find a simple description of this process
1. First-order physics
2. Estimate the fracturing pressure enhancement
3. Evaluate the importance of the involved
factors and identify the first-order parameters
Courtesy Geomec a.s.
Methodology
1. Estimate the enhancement through the
classical results (England and Green equation)
2. Modify the Perkins-Kern-Nordgren model to
take into account the effect of progressive
plugging
Courtesy Geomec a.s.
Classical results
• England and Green’s equation can be used once the
geometrical parameters of the fracture are known.
• It estimates the hoop stress increase from the
mechanical properties of the rock and and the geometrical
parameters of the fracture
Two shapes have been considered:
”Penny shape”-like fractures
PKN-like fractures (length>>height)
Base case for the parametric study:
Young modulus: 40 GPa
Poisson’s ratio: 0.2
Fracture width: 3 mm
Fracture height/radius: 10 m
Courtesy Geomec a.s.
Classical results: effect of the Young modulus
18
PKN
Penny Shape
16
Hoop stress increase (MPa)
14
12
10
8
6
4
2
0
0
20
40
60
Young modulus (GPa)
Courtesy Geomec a.s.
80
100
120
Classical results: effect of the Poisson coefficient
8
PKN
Penny Shape
Hoop stress increase (MPa)
7
6
5
4
3
2
1
0
0
0.05
0.1
0.15
0.2
0.25
0.3
Poisson coefficient
Courtesy Geomec a.s.
0.35
0.4
0.45
0.5
Classical results: effect of the fracture width
12
PKN
Penny Shape
Hoop stress increase (MPa)
10
8
6
4
2
0
0
1
2
3
Fracture width (mm)
Courtesy Geomec a.s.
4
5
6
Classical results: effect of the fracture height
40
PKN
Penny Shape
Hoop stress increase (MPa)
35
30
25
20
15
10
5
0
0
20
40
60
Fracture height/radius (m)
Courtesy Geomec a.s.
80
100
120
Modified PKN model
• With this model the geometrical parameters of the
fracture are estimated according to the measurements
while drilling
• Plugging is considered through a reduction of the
fracture permeability with time up to complete sealing
Base case for the parametric study:
Young’s modulus: 40 GPa
Poisson’s ratio: 0.2
Mud viscosity: 5 cP
Mud loss rate: 1 bbl/min
Time required to plug the fracture at a given depth: 30 min
Rate Of Penetration: 10 m/hr
Courtesy Geomec a.s.
Modified PKN model: fracture aperture vs. time
4
Fracture width at wellbore (mm)
3.5
3
2.5
2
1.5
1
0.5
0
0
5
10
15
time (min)
Courtesy Geomec a.s.
20
25
30
Modified PKN model: effect of Young modulus
30.0
Hoop stress increase (MPa)
25.0
20.0
15.0
10.0
5.0
0.0
0
20
40
60
Young Modulus (GPa)
Courtesy Geomec a.s.
80
100
Modified PKN model: effect of Poisson coefficient
18.0
16.0
Hoop stress increase (MPa)
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
0
0.05
0.1
0.15
0.2
0.25
Poisson coefficient
Courtesy Geomec a.s.
0.3
0.35
0.4
0.45
Modified PKN model: effect of mud viscosity
25.0
Hoop stress increase (MPa)
20.0
15.0
10.0
5.0
0.0
0
5
10
15
20
25
Mud viscosity (cP)
Courtesy Geomec a.s.
30
35
40
45
Modified PKN model: effect of mud loss rate
30.0
Hoop stress increase (MPa)
25.0
20.0
15.0
10.0
5.0
0.0
0
1
2
3
Mud loss rate (bbl/min)
Courtesy Geomec a.s.
4
5
6
Modified PKN model: effect of plugging time
100.0
90.0
Hoop stress increase (MPa)
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
0
10
20
30
40
Plugging time (min)
Courtesy Geomec a.s.
50
60
70
Modified PKN model: effect of Rate of penetration
120.0
Hoop stress increase (MPa)
100.0
80.0
60.0
40.0
20.0
0.0
0
5
10
15
Rate Of Penetration (m/hr)
Courtesy Geomec a.s.
20
25
Role and Design of Plugging Material
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The plugging material is a mixture of mud
clay, barite, formation debris (cuttings),
plus carefully sized LCM
It plugs the induced fracture rapidly, and
sq is increased permanently by propping
The effect is limited in extent, but the sq
stress does not relax during drilling
The LCM is designed (concentration, size
range) based on the mud parameters
: www.geomec.com for further details