Module F: Drilling in Unusual Stress Regimes Part I – Overpressured Cases Maurice B. Dusseault University of Waterloo.

Module F:Module F:Drilling in Unusual Stress Drilling in Unusual Stress

Regimes Part I – Overpressured Regimes Part I – Overpressured CasesCases

Maurice B. DusseaultUniversity of Waterloo

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 p

pg

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 Geomechanics

Nova 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

De

pth

– z

– 1

000

’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 zonesWater 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

stress

hmin

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


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)


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


OP zone

vhpo

2.0 (16.7 ppg) 1.0 (8.33 ppg)


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


OP zone

vhpo

2.0 (16.7 ppg) 1.0 (8.33 ppg)


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

vh

po

2.0 (16.7 ppg) 1.0 (8.33 ppg)


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 Depth

stress (or pressure)

depth

vertical stress, v

horizontal stress, h

pore pressure, po

4 kmRegion 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


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. PredictionPrediction

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 IPore Pressure Prediction Basics I

Data from offset wellsLogs, Dr data, sonics, neutron porosity,

resistivity, etc. Transfer data to new well stratigraphy, z

Plot 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 Differences


1

2

3

4

5

6

0

Stiff shales and silts

OP zone

Reversion zone


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 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

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


1

2

3

4

5

6

0

Stiff shales and silts

OP zone

Reversion zone


Expected OP transition

v

po

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 Prognosis

WELL DESIGN - HI 133 No. 1

MW, PF, & EST. 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 - ppg

DE

PT

H -

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

DE

PT

H

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 issuesBelow 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 holeDrill 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 ballooningTo 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 PF

Special 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


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


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?


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


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


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)

PKN

Penny Shape


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

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)

PKN

Penny Shape


Classical results: effect of the fracture width

0

2

4

6

8

10

12

0 1 2 3 4 5 6

Fracture width (mm)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)

PKN

Penny Shape


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)

PKN

Penny Shape


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


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)

Fra

ctu

re w

idth

at

we

llb

ore

(m

m)


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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)

Ho

op

str

es

s i

nc

rea

se

(M

Pa

)


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

http://www.geomec.com/

Module F: Drilling in Unusual Stress Regimes Part I – Overpressured Cases Maurice B. Dusseault University of Waterloo.

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