Download - Drilling Overpressure
Module F:Module F:Drilling in Unusual Stress Drilling in Unusual Stress
Regimes Part I – Overpressured Regimes Part I – Overpressured CasesCases
Argentina SPE 2005 Course on Earth Stresses and Drilling Rock Mechanics
Maurice B. DusseaultUniversity of Waterloo and Geomec a.s
Drilling in Overpressured ZonesDrilling 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 hmin with LCM in the mudBicentre bits and expandable casings
Understanding overpressure and also the deep zone of stress reversion will help
Pressures at DepthPressures at Depth
depth
pressure (MPa)
Hydrostatic pressure distribution: p(z) = wgz
overpressureunderpressure
Overpressured case: overpressure ratio = p/(wgz), a value greater than 1.2
Underpressured case: underpressure ratio = p/(wgz), a value less than 0.95
1 km
~10 MPa
Normally pressured range:0.95 < p(norm) < 1.2
Fresh water: ~10 MPa/km 8.33 ppg 0.43 psi/frt
Sat. NaCl brine: ~12 MPa/km 10 ppg 0.516 psi/ft
Some DefinitionsSome Definitions For consistency, some definitions: Hydrostatic: po = “weight” column of water
above the point, = 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% v Medium overpressure: po of 60 to 80% v Strong overpressure: po > 80% of v
Abnormal Pressure, Gradient Abnormal Pressure, Gradient PlotPlot
Typically, po is close to hydrostatic in the upper region
hmin is close to v 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
depth - kilometres
1.0 2.0
1
2
3
4
5
6
v
thick shalesequence
Target A
Target B
Target C
0
po
hmin
po
16.7
ppg
GoM –The Classic OP RegimeGoM –The Classic OP Regime
Other Well-Known Strong OP Other Well-Known Strong OP AreasAreas 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, undercompactionWatch out for OP related to salt tectonics!
These are most common offshore:Land basins have often undergone upliftTectonics have allowed pressures to dissipate
Importance of GeomechanicsNova Scotia Gas Belt
Exports
Eastern Canada Overpressured Areas
Porosity vs Depth & Porosity vs Depth & OverpressureOverpressure
mud
clay
mud-stone
shale
0 0.25 0.50 0.75 1.0
clay & shale,“normal” line
sands &sandstones
effect of OP on porosity
depth
porosity
4-8 km
slate (deep)+T
In some cases, 28% at depths of 6 km!
Anomalously high , low vP, vS, and other properties may indicate OP
Permeability and DepthPermeability 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 sands in OP zones can have high k
Anhydrite, salt k = 0! Carbonates, it depends
0 1 2 3 4 5
5
10
15
20
25
Fractured shales at depth may have high fracture permeability
Permeability – k – Darcies
Dep
th –
z –
100
0’s
ft
High porosity OP sands have anomalously high porosity & permeability
Intact muds and shales have negligible k
Muds and Shales Sands and Sandstones
Abnormal pAbnormal poo Causes Causes Delayed compaction of thick shale zones
Water is under high pressureLeak 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 (, no drainage)
Mechanisms for OP GenerationMechanisms for OP Generation
H20
SandstoneMontmorillonite = much H2O
Diagenesis
IlliteKaoliniteChlorite
+ Free H2O + SiO2
Sand
Mud, clays
Shale
H20H20
Compaction = H2O expelled to sand bodies, especially from swelling clays
2000-4000 m
4000-6000 m
Compaction and Clay Diagenesis
0-2000 m
Mechanisms for OP GenerationMechanisms for OP Generation Artesian effect (high elevation recharge) Thrust tectonics (small effect) Deep thermal expansion
clays and silts
3-10 km
20-100 km
+T = +V of H2O: thermal expansion at depth
Thrusting can lead to some OP
Artesian charging
rain
Artesian charging is usually shallow only
Offshore: Trapping of OPOffshore: Trapping of OP
“down-to-the-sea” or “listric” faults
sea
slip planes
v
h
po
stress
depth
Listric faults on continental margins lead to isolated fault blocks, good seals, high OP in the
isolated sand bodies from shale compaction
Sand bodies that have no drainage because of fault seals, OP is trapped indefinitely
shale
shale
Stress reversion zone
HC Generation and OPHC Generation and OP
Semi-solidorganics, kerogen,
po < h < v
po = h < v,Fractures develop
and grow
Pressured fluids are expelled through the fracture network, po
“stored” in OP sands
shale
kerogen
micro-fissure
v
oil and gas
generation of hydrocarbon fluids
fluidflow
vT, p,
increase
high T, p,
HCs generated in organic shales
sands
OP From Gas Cap DevelopmentOP From Gas Cap Development
gas cap, low density
stress
depthhpo
gas capeffect
pressures along A-AA
AGas migration along fractured zones, faults, etc.
Fractured rock around faultDeep gas source
Thick gas cap development, perhaps charged from below, can generate high OP
Gas rises: gravitational segregation
oil, density= 0.75-0.85
Abnormal Pressure – Sand-Abnormal Pressure – Sand-ShalesShales 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
PPFF in GoM Sand-Shale Sequences in GoM Sand-Shale Sequences
stresshmin
depth
v
sandstone
PF in sand line
Pore pressure distribution, top of OP zone
limestone
shale
sandstone
shale
shaledepth
hmin
zv
z
Absolute stress values Stress gradient plot
Some Additional CommentsSome Additional Comments Casing shoes are set in shales (98%) The LOT value reflects the higherhmin
in the shales, therefore a higher PF As we drill deeper, through sands, the
actual hmin 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” Examination of a “Typical” Synthetic OP CaseSynthetic OP Case
Particularly Difficult OP CaseParticularly Difficult OP Case Deep water drilling,
mud heavier than H2O Thick soft sediments
section, PF ~ h ~ v Thin, shallow, gas-
charged sand Zone where h is
roughly unchanged Sharp transition zone High OP, 90% of v Deep zone of stress
and pressure reversion
Sea water depth 800 m
800 m soft sediments
2.0 (16.7 ppg) 1.0 (8.33 ppg)
1
2
3
4
5
6
0
2000 m medium stiff shales and silts
1400 m OP zone
Reversion zone
Z – kilometers (3279 ft/km)
sharp transition
vhpo
seal
Upper Part of HoleUpper Part of Hole 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
2.0 (16.7 ppg) 1.0 (8.33 ppg) 0
Sea water - 800 m
800 m soft sediments
1
2
Medium stiff shales and silts
Z – kilometers (3279 ft/km)
9.16
ppg
10.0
ppg
Riser Issues in this ExampleRiser 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 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.
Sea water - 800 m
800 m soft sediments1
2
3
4
0
2000 m shales and silts
OP zone
sharp transition
vhpo
Approaching the Transition ZoneApproaching the Transition Zone 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)
2.0 (16.7 ppg) 1.0 (8.33 ppg)
Z – kilometers (3279 ft/km)
Solution A: Casing or LinersSolution A: Casing or Liners 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)
Sea water
1
2
3
4
0
2000 m shales and silts
OP zone
vhpo
2.0 (16.7 ppg) 1.0 (8.33 ppg)
Z – kilometers (3279 ft/km)
Sol’n B: Drill OB With LCM?Sol’n B: Drill OB With LCM? 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!) 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)
Sea water
1
2
3
4
0
2000 m shales and silts
OP zone
vhpo
2.0 (16.7 ppg) 1.0 (8.33 ppg)
Z – kilometers (3279 ft/km)
Solution C: Deeper Upper Solution C: Deeper Upper CasingsCasings
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
3
4
0
OP zone
vhpo
2.0 (16.7 ppg) 1.0 (8.33 ppg)
Z – kilometers (3279 ft/km)
Slight OB needed
Deeper Upper Casing ShoesDeeper 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 ApproachesComments 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 subseaPF (h) is quite low around 3000 m subseaTransition zone is very sharp (~250 m)OP is high (88-90% of v)
However, it could even be worse!More gas zones, depleted reservoirs at 3.6 kmEtc…
Drilling Through a Reversion Drilling Through a Reversion ZoneZone Below OP, usually a zone where po, h (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 h value (PF) drops as well
“Reverse” internal blowout possibilityBlowout higher in holeFracturing lower in hole
Stress Reversion at DepthStress Reversion at Depthstress (or pressure)
depth
vertical stress, v
horizontal stress, h
pore pressure, po
4 km Region of strong overpressure
Stresses “revert” to more ordinary stateZ
Note that hmin can become > v
Higher k rocks (fractured shales)
Same Example…Same Example… 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
2.0 (16.7 ppg) 1.0 (8.33 ppg)
4
5
6
1400 m OP zone
Reversion zone
Z – kilometers (3279 ft/km)
vhpo
Real Deep Overpressure DrillingReal 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 DrillingDetecting OP Before Drilling Seismic stratigraphy and velocity
analysisAnomalously low velocities, high
attenuationsCan 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 DrillingDetecting 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 LWDComments 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 reachOBM, electrical noise, drilling noise ID changes in the drill stringPump 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. Reasons for Pore Press. PredictionPredictionDrilling 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 IPore Pressure Prediction Basics I Data from offset wells
Logs, Dr data, sonics, neutron porosity, resistivity, etc.
Transfer data to new well stratigraphy, zPlot v 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 IIPore 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 DifferencesSonic Transit Time DifferencesSea water depth 800 m
1
2
3
4
5
6
0
Stiff shales and silts
OP zone
Reversion zone
Z – kilometers (3279 ft/km)
Expected OP transition
vpo
seal
Soft seds.
2.0 (16.7 ppg) 1.0 (8.33 ppg)
PROGNOSES FROM OFFSET WELL DATA, CORRECTED FOR Z, ETC…
Log of sonic transit time
650 s/m
Normal trend from the basin, offset data
Seismic velocity model
Sonic transit time from offset wells
Critical region
Prognoses Based on SeismicsPrognoses Based on SeismicsNormal 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
Regions of substantial deviation are highlighted as “critical”, experience used to choose likely top of OP
OP magnitude estimated, based on correlations
Large OP expected
OP beginning
Seismic Cross-SectionsSeismic 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 - North Sea Seismic Section - DiapirDiapir
Gas Pull Down
Top BalderTop Chalk
Intra Hod/Salt
Well A1b
Mid-Miocene regional pressure boundary
Courtesy Geomec a.s.
Other “Trend Line” ApproachesOther “Trend Line” Approaches Methods exist for using trend analysis
for many different measures, including:Drilling exponent dataResistivity trends lines (salinity of strata)Deviations from expected porosity (less
sensitive)SP log characteristicsPerhaps some others…
Shale data are used because sand porosity is less “predictable” in general
Gas Cutting of the Drilling MudGas 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?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…
MWMWmin min PrognosisPrognosis 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?
MWMWminmin, MW, MWmaxmax Well Prognosis Well Prognosis 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
Sea water depth 800 m
1
2
3
4
5
6
0
Stiff shales and silts
OP zone
Reversion zone
Z – kilometers (3279 ft/km)
Expected OP transition
vpo
Soft seds.
2.0 (16.7 ppg) 1.0 (8.33 ppg)
PROGNOSES FROM OFFSET WELL DATA, CORRECTED FOR Z, ETC…
Strong rocks
Weak rocks
During Drilling…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 cutsChip morphology and volumesFlow rate gauges on flowline, pumpsMud temperature monitoring MWD temperatureSticky pipe, torque, ECD, mud pressure
fluctuations Cuttings analyses: vP, Brinnell hardness are used
Increasing Depth of Casing Shoe Increasing Depth of Casing Shoe 1.1 1.3 1.5 1.7 1.9 2.1 2.3
prognosisfor hmin
XLOT hmin value
shoe
depth
density, g/cm3
v
prognosisfor po
overpressuretransition zone
area indicatespossible MW
MW=1.92
deeper shoe for casing string!
Previouscasingstring
strong overpressure zone
Using high weight trip pills and careful monitoring, the lower limit can be extended
(2.0 = 16.7 ppg)
High Weight Trip PillsHigh 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 PrognosisAn OP Well PrognosisWELL DESIGN - HI 133 No. 1
MW, PF, & EST. po 0
1000
200030004000
500060007000
80009000
100001100012000
1300014000
8 9 10 11 12 13 14 15 16 17 18 19
MUD WEIGHT - ppg
DEP
TH -
ft
PORE PRESSURE (PPG)EXPECTED MW (PPG)FRAC GRAD. (SAND)FRAC. GRAD (SHALE)
Same Overpressured Well, GoM Same Overpressured Well, GoM WELL DESIGN - HI 133 No. 1
MW, PF, & ESTIMATED po
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
13000
14000
8 9 10 11 12 13 14 15 16 17 18 19
MUD WEIGHT
DEP
TH
PORE PRESSURE (PPG)EXPECTED MW (PPG)FRAC GRAD. (SAND)FRAC. GRAD (SHALE)
Approach for this Well - IApproach 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 - IIApproach 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 MWSet a liner as deep as possible, 9900´ if possibleMud 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 & StabilityDeep Water Drilling & Stability 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)
GullfaksGullfaks
North Sea case
Overpressure
Reversion zone
Depletion effect
Franklin Field, UK West SectorFranklin Field, UK West Sector 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 LearnedLessons Learned 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!
Living with breakouts for lower MWUsing LCM to generate somewhat higher PFSpecial trip practices, special equipment…
In OP drilling, vigilance is absolutely critical Increase your observations, understand them
Additional MaterialsAdditional 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 Fracture Pressure Enhancement in Drilling Through Use of in Drilling Through Use of
Limited Entry Fracturing and Limited Entry Fracturing and Propping Propping Courtesy of:
Francesco SanfilippoGeomec a.s., Norway
Courtesy Geomec a.s.
To enhance fracturing pressure by drilling slightly overbalance and, at the same time, by effectively
plugging and sealing the induced hydraulic fractures
The Concept
Already plugged
Not plugged
Induced fracture
Courtesy Geomec a.s.
1. Find a simple description of this process1. First-order physics
2. Estimate the fracturing pressure enhancement
3. Evaluate the importance of the involved factors and identify the first-order parameters
How Can this be Analyzed?
Courtesy Geomec a.s.
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
Methodology
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 fracturesPKN-like fractures (length>>height)
Base case for the parametric study:Young modulus: 40 GPaPoisson’s ratio: 0.2Fracture width: 3 mmFracture height/radius: 10 m
Courtesy Geomec a.s.
Classical results: effect of the Young modulus
0
2
4
6
8
10
12
14
16
18
0 20 40 60 80 100 120
Young modulus (GPa)
Hoo
p st
ress
incr
ease
(MPa
)
PKNPenny Shape
Courtesy Geomec a.s.
Classical results: effect of the Poisson coefficient
0
1
2
3
4
5
6
7
8
0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5
Poisson coefficient
Hoo
p st
ress
incr
ease
(MPa
)
PKNPenny Shape
Courtesy Geomec a.s.
Classical results: effect of the fracture width
0
2
4
6
8
10
12
0 1 2 3 4 5 6
Fracture width (mm)
Hoo
p st
ress
incr
ease
(MPa
)
PKNPenny Shape
Courtesy Geomec a.s.
Classical results: effect of the fracture height
0
5
10
15
20
25
30
35
40
0 20 40 60 80 100 120
Fracture height/radius (m)
Hoo
p st
ress
incr
ease
(MPa
)
PKNPenny Shape
Courtesy Geomec a.s.
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 GPaPoisson’s ratio: 0.2Mud viscosity: 5 cPMud loss rate: 1 bbl/minTime required to plug the fracture at a given depth: 30 minRate Of Penetration: 10 m/hr
Courtesy Geomec a.s.
Modified PKN model: fracture aperture vs. time
0
0.5
1
1.5
2
2.5
3
3.5
4
0 5 10 15 20 25 30
time (min)
Frac
ture
wid
th a
t wel
lbor
e (m
m)
Courtesy Geomec a.s.
Modified PKN model: effect of Young modulus
0.0
5.0
10.0
15.0
20.0
25.0
30.0
0 20 40 60 80 100
Young Modulus (GPa)
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Modified PKN model: effect of Poisson coefficient
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45
Poisson coefficient
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Modified PKN model: effect of mud viscosity
0.0
5.0
10.0
15.0
20.0
25.0
0 5 10 15 20 25 30 35 40 45
Mud viscosity (cP)
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Modified PKN model: effect of mud loss rate
0.0
5.0
10.0
15.0
20.0
25.0
30.0
0 1 2 3 4 5 6
Mud loss rate (bbl/min)
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Modified PKN model: effect of plugging time
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
0 10 20 30 40 50 60 70
Plugging time (min)
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Modified PKN model: effect of Rate of penetration
0.0
20.0
40.0
60.0
80.0
100.0
120.0
0 5 10 15 20 25
Rate Of Penetration (m/hr)
Hoo
p st
ress
incr
ease
(MPa
)
Courtesy Geomec a.s.
Role and Design of Plugging Role and Design of Plugging MaterialMaterial The plugging material is a mixture of mud
clay, barite, formation debris (cuttings), plus carefully sized LCM
It plugs the induced fracture rapidly, and is increased permanently by propping
The effect is limited in extent, but the stress does not relax during drilling
The LCM is designed (concentration, size range) based on the mud parameters
: www.geomec.com for further details