FracproPT Short Course (March 2008)

• • • • • • • •

Introduction Fluid Rheology, Flow Leak-off, Proppant Transport Rock mechanics & Stress, Fracture Modeling Concepts Tortuosity & Perforation Friction Net Pressure Matching Fracture Conductivity & Design Considerations Production Modeling Fracture Diagnostics & Model Calibration

Fracture Engineering & Modeling

for proppant disposal

NOT

Hydraulic fracturing is done for well stimulation

Motivation for Frac Engineering & Diagnostics

Time during fracture treatment Frac width

Frac length

Simplified cross-sectional view of the fracture

7 – Formation closes on proppant and a conductive path remains in the reservoir

6 – Pumping of the fluid/proppant mixture is stopped and fluid continues to leak away into the permeable formation

5 – Proppant advances further in the fracture and may reach the tip of the hydraulic fracture as fluid continues to leak into the permeable formation

4 - Proppant advances further into the fracture as pumping continues

3 – Proppant (usually sand) enters hydraulic fracture as it is suspended in the fracturing fluid

2 - Fracture propagation with fluid

1 - Fracture initiation as pumping of fluid is started

Hydraulic Fracture Growth

1

2

3

4

Prop conc

Flow rate

5 6

Surface pressure

7

General pressure response, flow rate, and proppant concentration during a propped fracture treatment

7 – Formation closes on proppant and a conductive path remains in the reservoir

6 – Pumping of the fluid/proppant mixture is stopped and fluid continues to leak away into the permeable formation

5 – Proppant advances further in the fracture and may reach the tip of the hydraulic fracture as fluid continues to leak into the permeable formation

4 - Proppant advances further into the fracture as pumping continues

3 – Proppant (usually sand) enters hydraulic fracture as it is suspended in the fracturing fluid

2 - Fracture propagation with fluid

1 - Fracture initiation as pumping of fluid is started

Hydraulic Fracture Growth

Rock deformation Fluid flow inside fracture Fluid leakoff Fracture propagation Proppant transport Heat transfer

• Understanding these mechanisms and their interrelationships provides a starting point for understanding hydraulic fracture growth behavior

– – – – – –

• Hydraulic fracturing is a complicated process that involves several coupled physical mechanisms

Hydraulic Fracturing

Physical Processes

0

frac

0

+ Vleakoff = 2γ 1wi Li H i + ∫

ti

Ct 2 Ai dt t − ti ( x )

Assumes spurt loss is zero

Qt = V frac + Vleakoff ≅ 2γ 1ww LH + 2 LH 2Ct t

∫ Qdt = V

ti

• At all times, the injected fluid volume is equal to the fracture volume plus the volume of fluid that has leaked off

Conservation Of Mass

Fluid Rheology & Leakoff

3   ∂p  w   Q = h.q ; q = v • w =   µ  ∂x 

• Generally modeled as laminar flow between parallel plates • Flow rate is extremely sensitive to fracture width

Fluid Flow Inside A Fracture

∂ ∆ p 64 Qu = ∂x π Hw 3

• Flow down an elliptical tube

∂∆p Qu = 12 ∂x Hw 3

• Flow between 2 parallel plates

Laminar Fluid Flow

– Controls Crosslinker Reactions – Impacts Fluid Properties

• pH

– Controls Surface Treating Pressure – Impacts Injection Rate

• Friction

– Controls Hydrostatic Gradients – Impacts Proppant Convection

• Density

– Controls Amount of Fluid in Fracture – Impacts Fracture Geometry

• Fluid Loss

– Controls Fracture Width (Near Wellbore) – Impacts Proppant Transport

• Viscosity

PROPERTIES OF A FRACTURE FLUID

∆p

Q or Shear Rate (γγ)

Q

∆p µ Constant = Q for Newtonian Fluid

Newtonian Fluid

WHAT IS VISCOSITY?

Q

∆p or Shear Stress (τ)

SHEAR STRESS ( τ )

0

τy

τb

0

µ

Drilling Mud

Water

Fracturing Fluid

Dilatant (Shear Thickening)

Newtonian

PseudoPlastic (Shear Thinning)

SHEAR RATE (γ )

µp

Bingham Plastic

Example

RELATIONSHIP OF τ AND γ

LOG-SHEAR STRESS ( τ)

LOG-SHEAR RATE γ( )

k‘ = Intercept

n’= Slope 2

τ = Shear Stress, lb/ft -1 γ = Shear Rate, sec k = Consistency Index, lb-secn2 /ft n = Flow Behavior Index, dimensionless

τ = k’γγn’

FRACTURING FLUIDS ARE TYPICALLY

µ a = 47880 k’a

[γγ]

n’- 1

γ

= Shear Rate, sec-1

µa = Apparent Viscosity, cp ’ n / ft2 k’a = Consistency Index, lb-sec n’ = Flow Behavior Index, Dimensionless

Where:

• To Calculate the Apparent Viscosity of a NonNewtonian Fluid, the Following Equation is Used

VISCOSITY AT A KNOWN SHEAR RATE

• Shear Rates in Tubular: 1000 - 5000 sec-1 • Shear Rates in Fractures: 10 - 100 sec -1 • Measurements of n’ and k’ Often Made Between 170 and 600 sec -1 • May Not Be Representative of the Fluid Behavior in the Fracture (40 sec -1)

TYPICAL SHEAR RATES DURING FRACTURING

Shear Rate

{

40.46 Q w2 h

= Apparent Viscosity, cp = Consistency Index, lb-secn’/ft 2 = Flow Behavior Index, Dimensionless Q = Injection Rate, bpm w = Fracture Width, in h = Fracture Height, ft

µa k’a n’

Where

µa = 47880 ka’

n −1

• Apparent Viscosity of a Non-Newtonian Fluid in the Fracture, ’

ESTIMATING VISCOSITY IN FRACTURES

ROTATING CUP

TEST FLUID

STATIONARY BOB

Torsion Spring

VISCOSITY MEASUREMENTS

0.03 0.55

0.8

Linear Gel

Crosslinked 0.5

0.00002

1.0

Water

k’

n’

Fluid Type

2000

50

1.0

Viscosity @ 170 sec-1

TYPICAL VISCOSITY VALUES

0.1

1.0

1

D 2 3 4 5 6 TIME, hours

B

A C

0.6 .

0.8

1.0

1

2

3 4 5 TIME, hours

6

B C A

250°F 50 lb/1000 HPG w/ Titanium

0.2 0

0.4

D

EXAMPLE RHEOLOGICAL DATA

Source: Halliburton Energy Services

0.001 0

0.01

ka

n

Typical Extent

Cw

< 1/10 inch

Fracture Fracture Filtercake Filtercake

Cc

100’s of feet

FLUID LOSS

0.5 to 3 feet

Cv

Invaded Zone Invaded Zone

Reservoir

Reservoir

m A

kr Cr µr

ki ∆p φ µa 1/2

= Slope of Volume vs t Graph = Area of Core Used to Measure Cw

0 .0164m (Measured in Lab) Cw = A

= Permeability to Reservoir Fluid, md = Formation Fluid Compressibility, psi -1 = Formation Fluid Viscosity, cp

k C φ  Cc = 0. 0374∆ p  r r   µr 

= Permeability to Filtrate, darcies = (σ σx + pnet) - p, psi = Formation Porosity, fraction = Viscosity of Filtrate, cp

k ∆p φ  Cv = 0.0469  i   µa 

1/ 2

FLUID LOSS EQUATIONS

TIME

Spurt Loss

Slope = Cw * Area / 0.0164

MEASUREMENT OF WALL BUILDING COEFFICIENT (Cw)

VOLUME

60 lb

40 lb

60 lb

250

350

With 25 lb/1000 gal Solid Particulate FLA

40 lb

Without FLA

FLUID TEMPERATURE, °F

150

Titanate Fluid

50

0.002

0.004

0.006

0.008

.

EFFECT OF FLUID LOSS ADDITIVES (FLA) ON WALL-BUILDING FLUID-LOSS COEFFICIENT, Cw ) 1/2

FLUID LOSS COEFFICIENT, C w (ft/min

Ct =

• William’s Method

• Series Average

(

2 CvCw + C2wCr2 + 4Cc2 Cv2 + Cw

[

1 1 1 1 + + Cv Cc Cw

2 CcCvCw

Ct =

)]

1/2

TOTAL FLUID LOSS C t

High Filtration

Longer Fracture

Low Filtration

HIGH SLURRY EFFICIENCY

Short Fracture

LOW SLURRY EFFICIENCY efficiency (t) =

Fluid Leakoff And Slurry Efficiency

Vpumped (t)

Vfrac (t)

• • • •

– Convection – Settling

Percentage of Fluid in the Fracture Affects Created Fracture Dimensions High Leakoff Can Lead to Screenouts Low Leakoff Will Increase Closure Time Affecting Proppant Placement

FLUID EFFICIENCY

18µ Terminal settling velocity for Newtonian fluid

Vs =

gd p2 (ρ p − ρ f )

What Is Proppant Settling? Downward Transport Of Dense Proppant Grains In Fluid

ρ3

>

ρ2 >

Convection velocity for Newtonian fluid

γ cn gw 2f (ρ max − ρ min ) Vc ≈ 12 µ

ρ1

ρ3

ρ2

ρ1

What Is Proppant Convection ? Downward Transport Of Dense Slurry

Rock Mechanics, Closure Stress, Fracture Modeling

Mini-fracs, small volume injection tests (DFIT, stress test) Drilling data Logs Estimated using net pressure matching

Need rock properties and stress for all depths where fracture propagates

– – – –

• Stress Data

– Core – Logs

• Rock mechanics

Sources for Rock Mechanics & Stress Data

σ = Stress = ε = Strain = E = Young’s modulus =

Assume linear elasticity: F/A δ/L σ/ε

L

F

A

Deformation Of A Bar Due To Uniaxial Compressive Load

δ

ν = Poisson’s ratio =

δ/L δr /R

ε r/ε (-1,1/2)

ε = Strain in axial direction = εr = Strain in radial direction =

Assume linear elasticity: L

F

R

Deformation Of A Bar Due To Uniaxial Compressive Load

δr

δ

Net Pressure is the Pressure Inside the Fracture Minus the Closure Pressure Net Pressure = 2,500 - 2,000 = 500 psi

Definition Of Net Pressure

Balloon Analogy For Opening Fracture With Constant Radius

w pnet

Generalization: w = Deflection E = Crack-opening modulus C = Compliance

R

Rock

= E/4(1-υ2) = γ R/ E

= γ pnetR/ E

Fracture cross-section

Opening Of A Fracture Due To Internal Pressure

50 psi

800 psi

Pnet =

Pnet =

Predicted net pressure

= 650 feet = 0.25 in

= 260 feet = 1.6 in

R w

R w

Predicted fracture dimensions

• Two radial fracture model solutions for the same treatment (no barriers):

Influence Of Net Pressure

Predicted frac dimensions

L = 1200 feet

R = 240 feet

Predicted net pressure

Pnet = 100 psi

Pnet = 800 psi

• Two modeling solutions for the same treatment; if 500 psi stress contrast exists around payzone

Fracture Geometry Changes With Net Pressure

• 2D models – Perkins, Kern and Nordgren (PKN) – Christianovitch, Geertsma and De Klerk (CGD) – Radial Model • 3D models – Pseudo 3D models – Lumped 3D models – Full 3D models – Non-planar 3D models

Different Models

• Solid mechanics • Fluid dynamics • Fluid Leakoff

Fluid dynamics

Fluid Leakoff

Solid Mechanics

Simplified Fracture Problem

Ww

L

h=H

Simplified Fracture Problem – Constant Height

hpnet w≈ E E L = εV 2h2pnet

• Fracture width:

• Combining these:

• Mass balance:

εV ≈ 12 2 h2 Lw

• Given: volume pumped, fluid efficiency and measured net pressure

Simple Dimensions Calculation For PKN Model

• Fluid Loss:

• Width & Fluid Flow:

• Mass balance:

LM N

2

VFL = 2 HL 2 2Ct t

π Qµ (1 − ν ) L w = ww = 4 5 5 2πE

π

Qt = 2 HLw + VFL

• Given: volume pumped, injection rate & job time, and total fluid loss coefficient

Simple Dimensions Calculation (PKN)

OP Q

1/ 4

VFL = 5.657 HLCt t Assume v=0.15

5

• Fluid Loss:

ww

QµL O L = 0.238M P E N Q

w=

π

1/ 4

5.61Qt = 01667 . HLw + VFL

• Width & Fluid Flow:

• Mass balance:

• Given: volume pumped, Fracture Height and total fluid loss coefficient

Oil Field Units

Simple Dimensions Calculation (PKN)

pnet ∝ t

• Net pressure:

1/ 5

1/ 5

w ∝t

L ∝t

• Width:

• Length:

4/5

Fracture Growth Versus Time For PKN Model

ww R

Simplified Fracture Problem – Radial Fracture

R w

Yields:

Radius Width @ wellbore

V e E ν pnet

~ ~

= = = = =

103 ft 1.51 in

1,000 bbl (~ 5,610 ft3) 0.5 1x106 psi 0.2 500 psi

Elastic opening

For: Volume pumped Efficiency (@ EOJ) Young’s modulus Poisson’s ratio Net pressure (@ EOJ)

 6 eVp net  w= 3  2 π E  

2 pnet ⋅ R w≈ π E

Mass balance

2

 3 eVE  R=  4 p net  

2 e • V = πR 2w 3

1 3

1 3

Estimating Frac Dimensions Radial Fracture

VFL = πR 2 2Ct t 2

• Fluid Loss:

2

• Width & Fluid Flow:

LM N

Qt = πR w + VFL 2

2 2 27Qµ (1 − ν ) R w = ww = 3 3 4π 2 E

• Mass balance:

• Given: volume pumped, injection rate & job time, and total fluid loss coefficient

OP Q

1/ 4

Simple Dimensions Calculation (radial model)

• Fluid Loss:

• Width & Fluid Flow:

• Mass balance:

Assume v=0.15

2

VFL = 8.886 R Ct t

2 QµR . w = ww = 0147 3 E

LM N

2

OP Q

1/ 4

5.61Qt = 0.262 R w + VFL

• Given: volume pumped, Fracture Height and total fluid loss coefficient

Oil Field Units

Simple Dimensions Calculation (radial model)

pnet ∝ t

• Net pressure:

−1/ 3

1/ 9

w ∝t

R∝t

• Width:

• Radius:

4/9

Fracture Growth Versus Time For Radial Model

GR

h3

PH = σ3 h3 + σ2 h2 + σ1 h1

σ3

h2

P

σ2 H

h1

σ1

Neglects fracture toughness, tip effects, composite layer

Simple Force Balance for Height Growth

Height Growth Depends on Stress Contrast, Net Pressure, and Geology

Mode I Mode II Mode III Mode IV

-

I

p' = Critical Net n Pressure

log (∆t)

II IV

III

Confined Height, Unrestricted Growth (slope = 0.20) Stable Height Growth Or Increased Fluid Loss (slope = 0) Growth Restriction, Tip Screen-out (slope=1) Rapid Height Growth

Classical Interpretation of Fracturing Pressures

log (pn )

• •

• •

•

Direct Injections Pressure decline analysis • Square-root time plot • G-function plot • Log-log plot Flow back test Step-rate test (upper bound) Logs Dipole Sonic Log (DSI) Synthetic profiles from standard logs

Different Methods To Obtain Fracture Closure Stress

• Closure stress (pressure) is identified by the transition between the two flow regimes

• reservoir diffusivity

– Radial flow regime; Pressure decline depends on:

• fluid leakoff rate • fracture compliance

– Linear flow regime; Pressure decline depends on:

• Pressure decline after a mini-frac passes through two flow regimes:

Pressure Decline Analysis

•

• • •

Tp

Tc Time

Rate

Pnet

ISIP

Efficiency ~

Closure

TcTc+ Tp

Tc Tp+Tc

Fracture closure pressure (minimum stress) Fluid efficiency Leakoff coefficient, reservoir permeability and pressure Fracture geometry estimate

What Can You Obtain From Pressure Decline Analysis?

Bottomhole pressure

dP/dt

BHP

Reference line

Square-root-of-shutdown time

Fracture closure

Mini-Frac Analysis: Square-root-of-time graph

Pressure, dP/dt

Log Scale (∆P, t*d∆P,d∆t)

∆ t*d∆P/d∆t

Radial flow

½-slope

Log Scale (∆t = t-t shut-down)

linear flow

∆P = BHP-ISIP

Fracture closure

Mini-Frac Analysis: Log-Log graph

Pressure, dP/dG, G*dP/dG

BHP

G-function

Fracture closure

dP/dG

G*dP/dG

Reference line

Mini-Frac Analysis: G-Function graph

BHP

G-function

Fracture closure

Height recession

dP/dG

G*dP/dG

Reference line

Mini-Frac Analysis: G-Function graph

Deviation below reference line could indicate height recession

Pressure, dP/dG, G*dP/dG

G-function

Fracture closure

Deviation above reference line could indicate pressure dependent leakoff/fissure opening

BHP

dP/dG

G*dP/dG

Reference line

Pressure Dependent Leakoff/Fissure Opening

Mini-Frac Analysis: G-Function graph

Pressure, dP/dG, G*dP/dG

BHP

G-function

Fracture closure

dP/dG

G*dP/dG

Reference line

Fracture Growth After Pump Shut-down

Mini-Frac Analysis: G-Function graph

Linear behavior, but intersection above the origin could indicate fracture growth after shut-down

Pressure, dP/dG, G*dP/dG

Pressure Decline Analysis – Square-root Time Plot

Pressure Decline Analysis – G-function Plot

Pressure Decline Analysis – Log-log Delta Pressure Plot

•

•

Step Rate Test – Start at matrix rate – Increase in steps until fracture extended (≈ 1 to 10 BPM) – Provides upper bound for closure – Can determine if you are fracturing at all Flowback at Constant Rate

Steprate/Flowback test

•

•

" near-well pinch "

~ 15 min

~ 30 psi SI-Rebound < p c independent of " tortuosity" SPE PF Feb '97

FB induced " wellbore pinch”

Here ‘frac WB pinch’ is identified at closure: very small

– otherwise volume of fracture is to small due to high leakoff

High perm well where the FB-SI is run after the gel calibration test

Pump-In/Flowback/Shut-in Test (SPE 24844)

Onion-Skin

Cement

Unfractured Halo

Blue-Dyed Fracture

Perforation Tunnel

Pipe

Perforation Damage - Crushed, Compacted, “Onion-Skin” Zone

Tortuosity & Perforation Friction

• Instantaneous rate changes, e.g. 30, 20, 10 and 0 BPM exact rates are unimportant, but changes should be abrupt • Implemented easiest by taking pumps off line • Each rate step takes about 20 seconds -- just enough to equilibrate the pressure • Fracture geometry should not change during stepdown total stepdown test volume small compared to test injection volume (note: pfrac not proportional to Q1/4 during stepdown test) • Use differences in behavior of the different friction components with flow rate

Tortuosity Can Be Measured: Stepdown Test

What Is Tortuosity? Width Restriction Close To Wellbore

Width Restriction Increases Necessary Wellbore Pressure

Wellbore

Net fracturing pressure Near-wellbore friction

Distance into fracture

Pressure after shut-in

Low

High

Fracture tip

Tortuosity Leads To Large Pressure Drop In Fracture Close To Well

Fractures Grow Perpendicular To The Least Principle Stress -- But What Happens At The Wellbore ?

Near-wellbore Friction Vs. Perforation Friction

Time (min)

20.20

21.00

5500 19.40

0.00

18.60

6100

10.00

17.80

6700

20.00

17.00

7300

8500

30.00

Meas'd Btmh (psi)

7900

Btm Slry Rate (bpm)

40.00

50.00

Near-wellbore Friction Vs. Perforation Friction

Source: “SPE paper 29989 by C.A. Wright et al.

• Perforation friction dominated regime

Tortuosity Can Be Measured: Stepdown Test

• Near-wellbore friction dominated regime

Tortuosity Can Be Measured: Stepdown Test

Use proppant slugs Initiate with high viscosity fluid Increase gel loading

Re-perforate

Ball-out treatment

Spot acid

Future wells may have altered completion strategy such as FEWER perfs

Increase rate

Severe fracture tortuosity

High perf friction

High entry friction

Maximum Treating Pressure Limitation Is Reached -- Can’t Pump Into Zone

• Situation: • Diagnosis: • Solution:

• Formation: • Completion:

Naturally fractured dolomite @ 8200’ (gas) 5-1/2” casing frac string, max. surface pressure 6000 psi; 70’ perf interval shot at 4 SPF, 90°°, 0.45” diameter hole; Previously acidized with 70 gallons/ft 20% HCl Declining injectivity leading to “pressure-out” on pad Severe near-wellbore fracture tortuosity 1 and 2 PPG proppant slugs very early in the pad to screen out fracture multiples

Example Application – “Pressure Out” on Pad

28.0

56.0

84.0

Time (min)

112.0

0.00 0.0 140.0

8.00 40.0

12.00 60.0

16.00 80.0

0.00 0

Increased max prop conc

no tortuosity at end of pumping

4.00 20.0

0.0

S/D#1: 1700 psi tortuosity; small perf fric.

S/D#2: 300 psi tortuosity

20.00 Max surface pressure 6000 psi 100.0

Btm Prop Conc (ppg) Slurry Flow Rate (bpm)

4.00 1200

8.00 2400

12.00 3600

16.00 4800

20.00 6000

Proppant Conc (ppg) Surf Press [Csg] (psi)

1400 psi friction reduction (1st slug)

Example Application – “Pressure Out” on Pad

Encyclopedia Britannica

Petroleum Engineers

Net Pressure History Matching

• Surface pressure OK for decline match • Deadstring or bottomhole gauge required for matching while pumping

– With “anchor points” from diagnostic injections – Recorded pressure, slurry rate and proppant concentration

• Well completion and perforations • Treatment schedule, proppant and fluid characteristics • Treatment data

– Young’s modulus (from core or sonic log) – closure stress profile (injection/decline data or sonic log) – Permeability (from PTA)

• Mechanical rock properties

Minimum Model Input Requirements

Earth Model

Earth Model

• Allows on-site design refinement based on observed fracture behavior

• Provides a powerful tool for on-site diagnosis of fracture entry problems

• Relatively inexpensive and quick diagnostic technique to apply

• Basic analysis data collected (in some sense) during every frac treatment

Fracture Pressure Analysis - Advantages

Net pressure

Pump time

Pump rate Predicted net pressure

Use predicted net pressure

Wellbore

Pay

• Early designs (pre-1980) did not incorporate feedback from real data • Fractures at that time were still smart enough to stay in zone

Modeling without Real-Data Feedback

Fracture Design and Analysis Evolution

Pay

Net pressure

Pump time

Pump rate Predicted net pressure

Measured net pressure

Use predicted net pressure

Wellbore

?

Pay

• Early designs (pre-1980) did not incorporate feedback from real data • Fractures at that time were still smart enough to stay in zone • But measured net pressure was generally MUCH higher than model net pressure

Modeling without Real-Data Feedback

Fracture Design and Analysis Evolution

Pay

Net pressure

Pump time

Matching measured net pressure with model net pressure

Use measured net pressure

Wellbore

• Net pressure history match can be obtained by adding new physics to fracture models • With the right assumptions and physics, inferred geometry has a better chance to be correct

Modeling with Net Pressure Feedback

Fracture Design and Analysis Evolution

Pay

Net pressure

Pump time

Matching measured net pressure with model net pressure

Use measured net pressure

Wellbore

• Net pressure history matching can be implemented by adding new physics to fracture models • With the RIGHT assumptions and physics, inferred geometry has a better chance to be correct • BUT pressure matching inferred geometry does not always fit directly measured geometry

Modeling with Net Pressure Feedback

Fracture Design and Analysis Evolution

Pay

2

Pre-frac com pletion and fracture design

4

3

pressure

E xplo re / bo und altern ative explanations for observed net

M atch m odel net pressure to observed net pressure

Determ ine observed net pressure

Characterize friction param eters using rate stepdow n tests

Determ ine f racture closure stress and m atch perm eability

1

Interpret m odel results, m ake engineering decisions

Perform treatm ent

Post-frac m odeling review and incorporate other fracture diagnostics

Repeat process in succeeding stages or w ells

Basic Fracture P ressure A nalysis Steps

• Obtain surface pressure from service companies recorded data • Obtain hydrostatic head from staging and fluid/proppant densities • Obtain frictional components from S/D tests • Obtain fracture closure stress from pressure decline

pnet ,obs = psurface + ∆phydrostatic − ∆p friction − σ closure

Required to Obtain Observed Net Pressure

Net Pressure Matching

Net Pressure Vs. Friction Pressure

• Model net pressure can be changed to match observed net pressures using several “knobs”

– Correct for fracture closure, frictional effects and hydrostatic

• Match “observed” net pressure with calculated “model” net pressure • Observed net pressure obtained from surface or downhole treatment pressure

Net Pressure Matching

• Provide “anchor points” for real-data (net pressure) analysis • Obtain accurate measurement of the true net pressure in the fracture • On site diagnosis and remediation of proppant placement – Near-wellbore tortuosity – Perforation friction – fluid leakoff • Bottom line: provide accurate estimates of the fracture geometry

Purpose Of Diagnostic Injections

0.00 0

4.00 600

8.00 1200

50.00

58.00

Time (mins)

66.00

74.00

Closure ?

82.00

Leak-off ? 90.00

0.0

40.0

80.0

120.0

200.0

12.00 1800

Friction ?

Slurry Rate (bpm)

160.0

Net pressure ?

Proppant Concentration (ppg) Surface Pressure (psi)

16.00 2400

20.00 3000

“Typical” Fracture Treatment Data

End Frac Rate Stepdown / Pressure Decline Monitoring

Diagnostic Step Breakdown Injection / rate stepdown / pressure decline Crosslinked Gel Minifrac with proppant slug / rate stepdown / pressure decline ~100-500 Bbl fracture fluid including 25-50 Bbl proppant slug (possible range 0.5-5 PPG) Minimum of 10 minute decline data

New areas Real-time pad resizing TSO treatments

Always

Fluid & Volume ~50-100 Bbl KCl

When Always

Purpose / Results Establish injectivity; obtain small volume ISIP; estimate closure pressure and formation permeability. Leakoff calibration; Net pressure sensitivity to volume and crosslink gel; Characterize fracture entry friction; Evaluate near-wellbore reaction to proppant; Screen out or erode near-wellbore multiple fractures. Characterize fracture entry friction; Post-frac leakoff calibration.

Recommended Diagnostic Injection Procedures

0 0.0

2000 20.0

4000 40.0

6000 60.0

8000 80.0

10000 100.0

0.0

Rate

70.0

Time (mins)

140.0

Pulses ?

Step-down Test

Surf Pressure (psi) Slurry Rate (bpm) Breakdown Mini-Frac Injection

210.0

Proppant

Proppant Slug ?

280.0

Surface Treating Pressure

Step-down Test

350.0

Step-down Test

Prop Conc (ppg)

0.00

4.00

8.00

12.00

16.00

20.00

History Matching “Anchor Points”: Shut-in Pressure Decline Slope and Net Pressure Level

Time (min)

120.0

150.0

0.00 0 90.0

0.00 0.0 0

60.0

5.00 500

5.00 25.0 500

30.0

10.00 1000

10.00 50.0 1000

0.0

15.00 1500

15.00 75.0 1500

25.00 2500

20.00 2000

Prop Conc (ppg) Net Pressure (psi)

20.00 100.0 2000

25.00 125.0 2500

Btm Prop Conc (ppg) Slurry Rate (bpm) Observed Net (psi)

History Matching “Anchor Points”: Shut-in Pressure Decline Slope and Net Pressure Level

• “Decline Slope” parameters – Permeability – Wallbuilding coefficient (Cw) – Pressure-dependent leakoff (Multiple fracture leakoff factor) • “Level” parameters – (Sand-shale) Closure stress contrast – Fracture complexity (Multiple fracture opening/volume factor) – Tip effects coefficient – Proppant drag exponent – Tip screen-out backfill coefficient – (Young’s modulus) • “Geometry” parameters – Composite layering effect – Crack opening / width coupling coefficient

FracproPT Net Pressure Matching Parameters

– Level (low perm): stress contrast, proppant drag – Level (high perm): TSO backfill, Young’s modulus, stress contrast, proppant drag – Decline slope: Pressure-dependent leakoff – Geometry: composite layering effect, width decoupling

• Prop frac:

– Level: Tip effects, Fracture complexity – Decline slope: Wallbuilding coefficient Cw

• Minifrac

– Level: Tip effects, Fracture complexity – Decline slope: permeability

• B/D Injection

Net Pressure Matching Strategy

5-1/2” casing frac string; 40’ perf interval shot with 4 SPF, 90°° phasing, 0.31” diameter holes Disappointing production performance for expected 600 ft fracture half-length (based on fracture growth design without real-data feedback) Sand/shale stress contrast much lower than estimated, resulting in significant fracture height growth and a much shorter fracture half-length (250’) Utilize fracture pressure analysis to optimize fracture treatment design

• Completion:

• Situation:

• Diagnosis:

• Solution:

Hard sandstone @ 7600’ (gas) in West Texas

• Formation:

Example Application – Estimation of Realistic Fracture Length

Geometry inferred design without real-data feedback

Time (min)

80.0

100.0

0 0.00 60.0

0.00 0.0

40.0

400 10.00

10.00 20.0

20.0

800 20.00

20.00 40.0

0.0

1200 30.00

30.00 60.0

2000 50.00 1600 40.00

Net Pressure (A) (psi) Prop Conc (ppg)

40.00 80.0

50.00 100.0

Btm Prop Conc (ppg) Slurry Rate (bpm)

High stress contrast 0.3 psi/ft (based on Dipole Sonic log interpretation)

Example Application: Estimation of Realistic Fracture Length

Geometry inferred design without real-data feedback

Time (min)

80.0

100.0

0.00 0.0 60.0

0 0.00 0

40.0

10.00 20.0

400 10.00 400

20.0

20.00 40.0

800 20.00 800

0.0

30.00 60.0

1200 30.00 1200

50.00 100.0 40.00 80.0

Btm Prop Conc (ppg) Slurry Rate (bpm)

1600 40.00 1600

2000 50.00 2000

Net Pressure (A) (psi) Prop Conc (ppg) Observed Net (psi)

Observed net pressure does not match design net pressure response

Example Application – Estimation of Realistic Fracture Half-Length

Geometry inferred from net pressure matching

Geometry inferred design without real-data feedback

0.0

40.0

60.0

80.0

0 0.00 100.0 0

0.00 0.0 0

Lower stress contrast (0.1 psi/ft) required to match observed net pressure Confirmed with shale stress test in subsequent wells

Time (min)

400 10.00 400

10.00 20.0 400

20.0

800 20.00 800

20.00 40.0 800

1200 30.00 1200

30.00 60.0 1200

2000 50.00 2000 1600 40.00 1600

Net Pressure (A) (psi) Prop Conc (ppg) Net Pressure (psi)

40.00 80.0 1600

50.00 100.0 2000

Btm Prop Conc (ppg) Slurry Rate (bpm) Observed Net (psi)

Example Application – Estimation of Realistic Fracture Half-Length

• Closure stress σmin determines minimum pressure to open a fracture • Usually closure increases with depth • Closure stress is lithology dependent (shales usually higher than sands) • Represents only the minimum principal stress component in the vicinity of the well

Closure Stress Profile

• Closure stress profile determines fracture shape – Radial if stress profile is uniform (theoretical decrease in net pressure with pump time) – Confined height growth if closure stress “barriers” are present (theoretical increase in net pressure with pump time) • Effectiveness of “barrier” determined by – Closure stress contrast – Level of net pressure • “Typical” sand-shale closure stress contrast 0.05 - 0.1 psi/ft – Higher if there has been significant depletion (~2/3 of pore pressure change) – Lower if sands and shales are not clean • When do you change it? – Increase contrast when net observed pressures are higher – Increase contrast when fracture is more confined (up to 1.0 psi/ft)

Matching Parameter -Closure Stress Profile

• Modulus should be obtained from static tests (preferably similar to fracturing conditions) – Dynamic modulus two times or more larger than static modulus (use with caution !) • Once modulus is determined, this should be a FIXED parameter in a net pressure matching procedures • An increase in Young’s modulus results in less fracture width (for the same net pressure) • For simple radial model: Lfrac ∝ E1/3 (for the same net pressure) • Modeling results not extremely sensitive to modulus. • When do you change it? – With low moduli in GOM environment when modulus uncertainty is high – Character of TSO net pressure slope depends on modulus

Main Input Parameter - Young’s Modulus

GR.......................Vshale ........................Φ , E ,ν , σ , CLE , K Ic

• Calculation logic for GR-only log data (for sand-shale reservoirs):

Φ N ......................Φ, E......................  Sw , k Rt .....................................................  GR.......................Vshale ........................ν , σ , CLE , K Ic

• Calculation logic for triple-combo log data:

GR.......................Vshale ........................K Ic

 Φ D or ρ b ..............M...........  Φ.......... Φ N ..................................   Sw , k Rt .................................................... 

Tcomp ................................................ ν , σ , CLE Tshear ..................... E........................ 

• Calculation logic for quad-combo log data:

Developing an Earth Model from Log Data

2

2

( VP - VS )

=

2

2

2 ( VP - VS )

2

VP - 3 VS

2

Poisson’s Ratio

E=

2

2

VS ( 3 VP - 4 VS )

2

Young’s Modulus

VP -- Compressional Wave Velocity VS -- Shear Wave Velocity -- Density

Obtained From Logs or Tomograms

Calculating Dynamic Modulus

= 1-

(

Elastic Behavior No History Effects No Thermal Stresses No Strain B.C.

Assumptions

Hmin

OV

OV

P) +

2

P+

T

= 1.05 x Depth (ft)

1

= 0.2 P = 0.45 x Depth (ft) 1 = 2 = 0.9 T = Derived Value

-

STANDARD UNIAXIAL STRAIN

Estimating In Situ Stress from Logs

• If permeability profile is “known”, use Kp/Kl ratio for matching instead • Fix by matching decline slope of B/D KCl injection • Adjust Cw to match decline for gelled fluids

– only change permeability in pay interval.

• Keep it simple:

– Relative permeability issues – Opening of natural fractures – Relies on many other assumptions

• Matching perm is “permeability under fracturing conditions” – not necessarily under production conditions

Main Input Parameter – Permeability, Cw

High Leakoff, 25% Fluid Efficiency

Moderate Leakoff, 50% Fluid Efficiency

Low Leakoff, 65% Fluid Efficiency

Effect of Leakoff

• When do you change it? – Increase from default 0.0001 up to 0.4 when observed net pressure is lower than model (w/o multiples) – When fluid viscosity change has significant effect on observed net pressure behavior

• Tip process zone (with opening fractures) slows down fracture growth • Non-linear rock behavior at large differential compressional stress

• How does it work? – This parameter controls the near-tip pressure drop and thus the net pressure level in the fracture. – Mimics increased fracture growth resistance at the tip

Main Matching Parameters – Tip Effects Coefficient (Gamma 2)

pfrac

σH,min

Fluid Lag

Cohesive Zone

σH,max

Shielding of process zone, crack bridging and offsets

High Shear Stress: Plastic Zone

Tip Effects

wfrac

pnet

Linear elastic model

Lf

Lf Non-linear elastic model

Linear elastic model (Gamma 2 = 0.4)

Non-linear elastic model (Gamma 2 = 0.0001)

Net pressure decline slope w/ distance represents Gamma 2)

Tip Effects Coefficient

Tip Effects - Increased Fracture Growth Resistance

• Experiments by Shlyapobersky reveal fracture process zone • Process zone is scale dependent, and results in multiple fractures ahead of hydraulic fracture tip • Can result in higher net pressures to propagate fracture

Process Zone Around Fracture Tip

• Only change during injections • Tie opening and volume factors for “point source” perfs • Tie leakoff and volume factors for “distributed limited entry” perfs

• How does it work? – Opening and volume factor control the degree of fracture complexity using the amount of overlapping “equivalent” (equal sized) fractures – Leakoff factor can mimic increase leakoff or pressure-dependent leakoff • When do you change it? – When observed net pressure with default Gamma 2 (0.0001) is significantly higher than model net pressure – Use specific starting points for distributed limited entry and point source perforation strategies – Use strict rules

Main Matching Parameter – Multiple Fractures

Multiple Hydraulic Fractures In FracproPT

200 psi

1000

4 ft

400

Failure Zone Around Tip

Offsets at Natural Fractures

Regeneration Due to Plugging

Speculation On Genesis Of Multiple Fractures

1

2

3

3

3

3

Equivalent number of spaced identical fractures without interference

Equivalent number of fractures competing For width

Equivalent number of fractures with leakoff (ML)

Equivalent number of growing multiple fracs (MV)

Situation

3

2

1

Equivalent number of fracs competing for width (MO)

Modeling Approach for Multiple Hydraulic Fractures

1-Fracture

3-Fractures 2-Fractures

4-Fractures

Measured Net Pressure

Effect of Multiple Fractures

• • • • •

Conclusion: multiple fractures may be the rule rather than the exception

Core through and mineback experiments Direct observations of multi-planar fracture propagation Fracture growth outside plane of wellbore Observation of high net fracturing pressures Continuous increases in ISIPs for subsequent injections

Evidence for the Simultaneous Propagation of Multiple Hydraulic Fractures

NEVADA TEST SITE HYDRAULIC FRACTURE MINEBACK

Physical evidence of fractures nearly always complex

Observations of Fracture Complexity

NEVADA TEST SITE HYDRAULIC FRACTURE MINEBACK

Physical evidence of fractures nearly always complex

Multiple Strands in a Propped Fracture (Vertical Well)

Courtesy: N.R. Warpinski, Sandia Labs

NEVADA TEST SITE MINEBACK

Multiple Hydraulic Fracture Strands in a Horizontal Well

M-Site Experiment

Physical evidence of fractures nearly always complex

Multiple Strands in a Propped Fracture (Vertical Well)

– Confined fracture height growth – Increased fracture closure stress due to pore pressure increase – Higher Young’s modulus than anticipated – Fracture tip effects – Tip screen-out initiation – Simultaneously propagating multiple hydraulic fractures

• Potential causes for high net pressures:

Use Multiple Hydraulic Fractures Prudently for Modeling Purposes

• How does it work? – Mimics the increase in frictional pressure drop along the fracture as proppant is introduced – Controls how much the proppant in the fracture slows the fracture length and height growth. – Separate terms for Upper and Lower height growth calculated. Length effect is based on average of upper and lower terms. – Once a stage has become packed with sand (“immobile proppant bank”), there is no more growth in that direction – If both an upper and lower stage are dehydrated, quadratic backfill model takes over (if enabled) • When do you change it? – Significant proppant induced observed net pressure increase during proppant stages (that is not due to TSO)

Main Matching Parameters – Proppant Drag Exponent

Effect of Proppant Drag

Drag = 2

Drag = 6

Drag = 10

Drag = 14

Effect of Leakoff

Low Leakoff

High Leakoff

– Increase it when the TSO-induced observed net pressure rise is steeper than model predicts

• When do you change it?

– When fracture height and length growth are stopped due to dehydration of an upper and lower stage, quadratic backfill model starts working (if enabled) – Quadratic backfill is based on the idea the the fracture dimension controlling fracture stiffness will decrease as the fracture fills with immobile packed proppant from the tip back to the wellbore.

• How does it work

Main Matching Parameter – Quadratic Backfill Exponent

DBF=0

DBF=0.5

Effect of Quadratic Backfill

Linear TSO response

Height Growth due to Leverage

Fracture closure stress/ permeability barrier Interface slippage

Composite layering / width decoupling

Fracture Height Confinement Mechanisms

Poorly Understood Critical Model Input Parameters

Occurs with Height Growth

– Increase in layer adjacent to pay zone if no other confining mechanism can explain actual level of fracture confinement Composite Mechanisms: – Keep unity in pay zone

• When do you change it ?

– This parameter controls the near-tip pressure drop in each individual layer

• How does it work ?

Main Matching Parameters – Composite Layering Effect

NEVADA TEST SITE HYDRAULIC FRACTURE MINEBACK

Fracture Complexity Due To Joints

δ

pnet R

δ = Wcγ1 pnetR/ E

– Decrease it to trade fracture width for half-length – Decrease it to mimic reduced coupling “shear-decoupling” over fracture height (also associated with use of composite layering effect)

• When do you change it ?

– Multiplier for Gamma 1 representing how fracture width is decoupled along fracture height – We will provide automatic correlation as a function of composite layering effect

• How does it work ?

New Matching Parameter – Width Coupling Coefficient

• “We analyzed the treatment and determined optimum frac design” – Optimization is an evolutionary process, completed over the course of a series of fracture treatments

– Results usefulness determined 90% by engineer, 10% by model

The analysis is credible because I used the ‘FracRocket’ model”

Or

• “You used the wrong frac model !”

• “You can get any answer you want” – Not if you are constrained by real-data feedback, engineering judgment, and the results of other fracture diagnostics !

Net Pressure Analysis Untruths

• Production data & welltest analysis • Direct fracture diagnostics

– Indirect Diagnostic Technique - frac geometry inferred from net pressure and leakoff behavior – Solution non-unique – careful & consistent application required for useful results – Technique most useful when results are integrated or calibrated with results of other diagnostics

• Net Pressure History Matching

– Using surface pressure increases results uncertainty – Problematic near-wellbore friction level variable

• Fracture Entry Friction Evaluation

Fracture Pressure Analysis - Limitations

– ? Modulus, stress, leakoff, and multiple fractures – ? Layer interface mechanisms

• Appropriate Mechanisms for Net Pressure History Matching

– Pipe friction vs. perforation friction – Identifying marginally unfavorable entry friction

• Minimizing diagnostic injection time & cost without compromising effectiveness • Differentiating between “engineering” and “science” • Unclear fracture closure pressure • Practical bottom hole pressure measurement • Surface pressure rate stepdown complications

Fracture Pressure Analysis Problems / Opportunities

• Measurement of real-data is relatively simple and cheap • The right analysis assumptions and a consistent approach can get you “on the right page”, but geometry require calibration with direct measurements

– Reducing screen-out problems – Improving production economics – Achieving appropriate fracture conductivity

• Benefits of real-data fracture treatment analysis can be enormous

Fracture Analysis - Conclusions

Fracture Conductivity – the key to frac design

• Propped Fracture Width is Primarily a Function of Proppant Concentration

wkf = fracture width x fracture permeability

• Fracture Conductivity, wkf

Important Parameter Is Relative Fracture Conductivity At Reservoir Conditions

Conductivity (Cf) is a measure of the fracture’s ability to transmit fluids

cf = kf * wf wf

Fracture Conductivity

kf

FCD =

kf

k f * wf kform * xf

wf

Dimensionless Fracture Conductivity (FCD) is a measure of the contrast between the flow capacity of the fracture and the formation

xf

kform

Why is Conductivity Important?

or

wkf Cr = πkL

For FCD > 30 or Cr > 10, Lf is infinite conductive - No Significant Pressure Drop in Fracture - Value of 1.6 or larger generally sufficient

Lf = Fracture Half-Length, ft

k = Formation Permeability, md

wkf = Fracture Conductivity, md-ft

wkf FCD = kLf

Dimensionless Fracture Conductivity (FCD) Is Used To Design Fracture Treatments

0.01 0.1 0.2

0.03 0.02

0.05

0.1

0.3 0.2

0.5

1

0.5 1 2 5 10 20 (Kp)(Wf) / (Xf)(Kf) Fcd Fcd = (K=f)(W f) / (Xf)(Kform)

50 100

Increasing Effectiveness of the Fracture

Prats Correlation

Prats, M.: "Effect of Vertical Fractures on Reservoir Behavior-Incompressible Fluid Case," paper SPE 1575-G

rw' / Xf

Frac design change with same amount of proppant

Increase in frac length

Increase in conductivity

Need Length Or Conductivity? (After McGuire&Sikora)

Productivity increase

Need long fractures

Dimensionless conductivity “easily” greater than 10 – Fracture conductivity generally not an issue – “Self propping” (water) fractures may already provide sufficient conductivity

Treatment design – Moderate pad size (avoid long closure times on proppant) – Relatively low maximum proppant concentrations – Poor quality proppant can be OK (if closure stress is relatively low) – Pump rate not very critical

•

•

•

Design In Low-permeability Formation

• •

Sufficient fracture conductivity is critical Treatment design – Minimum pad size to create TSO (Tip Screen-Out) based on crosslink gel minifrac – Use best possible (and economic) proppant for expected closure stress – Larger diameter proppant provides more conductivity and reduces proppant flowback problems – Use high maximum proppant concentrations – Use of large casing frac string makes achieving TSO difficult for small treatments – Pump rates generally high, but can be decreased to initiate TSO

Design In High-permeability Formation

– – – – – – – – –

Closure Stress Embedment Crushing (generates fines and damages proppant) Corrosion Gel Residue Plugging Convection Proppant Settling Multiphase flow effects Turbulent flow

• Conductivity is reduced by

Fracture Conductivity In The Reservoir

• • • • •

Reference: API RP-61

Steel pistons 2 lb/ft2 proppant loading Stress maintained for 15 minutes Ambient temperature Extremely low water velocity (2 ml/min)

API 15-Minute Conductivity Test

1. 2. 3. 4. 5. 6. 7. • •

Ambient temperature Extremely low water velocity (2 ml/min)

Embedment, Duration, Temperature Non-Darcy Flow Reduced Proppant Concentration Multiphase Flow Gel Damage • Steel pistons Fines Migration • Stress maintained for only 15 minutes Cyclic Stress

To obtain a realistic proppant conductivity for design, the API test results must be modified to account for:

Problem

– – – – • • •

Embedment Duration Temperature.

Stim-Lab Consortium 40+ members from industry companies Developed and published a modified procedure in SPE 16415 Modified API test to address:

Deficiencies of the API conductivity testing recognized

1. Embedment, Duration, Temperature

Modified API RP61 Conductivity Test

References: Stim-Lab Consortia Feb 2002 1.6-46, SPE 16415

With proppant concentrations of 1 lb/ft2 (5 kg/m2) and soft core, 90% loss of conductivity has been observed.

Spalling

a) From Steel Plate to Sandstone core; allows modest embedment and spalling

Test Improvements:

Embedment/Spalling

References: SPE 16415, 14133

Longer test captures a portion of the time-dependent decline

b) Test duration increased to 50 hours (from 15 minutes)

Test Improvements:

Duration

Conductivity (md-ft)

0

25

50

75

20/40 Jordan sand, 8000 psi

100 Hours at Constant Stress

100

1000

Fig 4, SPE 16415

•

•

Reference: Stim-Lab Consortia Feb 2002 Fig 1.7-8

Uncoated and resin-coated sand show degradation at high temperatures. Ceramic proppants are manufactured at ~2700°F (1500°C) and are unaffected by reservoir temperature.

c) Realistic temperatures 150° F Sands 150-250° F Resin Coat 250° F Ceramics

(was ambient):

Test Improvements

0

0.2

0.4

0.6

0.8

1

0

2

4 6 8 10 Stress (x1000 psi)

250F (121C) 300F (149C) 350F (177C)

12

14

Temperature Degradation of Premium Precured Resin Coated Sand

Temperature

P e rm e a b ility Im p a c t

1500

7000

Jordan Sand

1137

5715

CarboLITE

API Test 50 Hour Test 6 Conditions: YM=5e psi, zero gel damage, 250°F, 2 lb/ft 2, 6000 psi YM=34e3 MPa, zero gel damage, 121°C, 10 kg/m 2, 41 MPa

0

1000

2000

3000

4000

5000

6000

7000

1) API Test versus Modified 50-hour Test

~20 to 30% reduction against hard core and modest conditions

References: ST Sand: SPE 14133, 16415, CL: Carbo typical, LT: Stim-Lab PredK 2002

Effective Conductivity (md-ft)

1. 2. 3. 4. 5. 6. 7.

Embedment, Duration, Temperature Non-Darcy Flow Reduced Proppant Concentration Multiphase Flow Gel Damage Fines Migration Cyclic Stress

To obtain a realistic proppant conductivity for design, the API test results must be modified to account for:

Problem

∆ P/L = µ v / k + β ρ v2

In realistic tests, the fluid velocity is high. Pressure losses are dominated by acceleration (inertial effects), and are described by Forchheimer’s Equation. This departure from Darcy’s Law can be considered a loss of effective conductivity.

∆ P/L = µ v / k

In the API test, the fluid velocity is extremely low. Pressure losses are dominated by friction, and can be described by Darcy’s Law.

2) Non-Darcy Flow (Inertial Effects)

1137

0

1000

50 Hour Test

672

3481

CarboLITE

Jordan Sand

Inertial Flow with Non-Darcy Effects

Realistic flowrates also consider fluid acceleration.

2000

3000

Low velocity testing measures only friction.

5715

4000

5000

6000

7000

2) Non-Darcy Flow (Inertial Effects)

~40% reduction for low productivity dry gas well

References: Stim-Lab PredK 2002, Forchheimer effect, SPE 54630, 77675

Conditions: YM=5e6 psi, zero gel damage, 250°F, 2 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay YM=34e3 MPa, zero gel damage, 121°C, 10 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay

Effective Conductivity (md-ft)

• It is likely that there are some unpropped regions, which increases the stress, crush, and embedment of the surrounding grains. • The following plot shows the effect of reducing the concentration but maintaining a uniformly packed fracture.

• In the API test, proppant is uniformly distributed with a concentration of 2 lb/ft2, or 10 kg/m2. • In actual fractures, the achieved proppant concentration may be much lower.

3) Effect of Lower Proppant Concentration

Effective Conductivity (md-ft)

2 lb/sq ft (10 kg/sq m)

672

3481

225

1243

CarboLITE

1 lb/sq ft (5 kg/sq m)

Jordan Sand

References: Stim-Lab PredK 2002, Forchheimer effect, SPE 54630, 77675

0

1000

2000

3000

4000

5000

6000

7000

3) Effect of Lower Proppant Concentration

Non-linear, as pressure drop function of velocitysquared, and embedment more significant

~65% damage for cutting concentration by 50%.

0

1000

2000

3000

4000

5000

6000

7000

Dry Gas

225

1243

liquid

gas

Multiphase Flow

49

479

CarboLITE

Jordan Sand

4) Effect of Multiphase Flow

~60 to 80% reduction for modest liquid rates

References: Stim-Lab PredK 2002, Forchheimer effect, SPE 54630, 77675

Conditions: YM=5e6 psi, zero gel damage, 250°F, 1 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd YM=34e3 MPa, zero gel damage, 121°C, 5 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d

Effective Conductivity (md-ft)

0

1000

2000

3000

4000

5000

6000

7000

Clean Pack

49

479 14

144

CarboLITE

Jordan Sand

50% Gel Damage

5) Effect of Gel Damage

~70% damage for 50% loss in laminar flow. (Gel damage affects beta more than perm)

References: Stim-Lab PredK 2002, Stim-Lab SEM photos

Conditions: YM=5e6 psi, 50% gel damage, 250°F, 1 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd YM=34e3 MPa, 50% gel damage, 121°C, 5 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d

Effective Conductivity (md-ft)

0

1000

2000

3000

4000

5000

6000

7000

No Fines

14

144

Modest Fines

7

RC Sand

130

Ceramic

CarboLITE

Jordan Sand

6) Effect of Fines Migration/Plugging

Uniformly sized, spherical proppants less susceptible to plugging. Larger pore throats reduce bridging.

References: Stim-Lab thin section photos, SPE 24008, 3298, 7573, 11634

Conditions: YM=5e6 psi, 50% gel damage, 250°F, 1 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd YM=34e3 MPa, 50% gel damage, 121°C, 5 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d

Effective Conductivity (md-ft)

0

1000

2000

3000

4000

5000

6000

7000

130

Single Stress Cycle

7

25 Cycles

4

CarboLITE

96

Jordan Sand

7) Effect of Cyclic Stress

Stronger proppants are less damaged by repeated stress cycles.

References: CARBO Tech Rpt 99-062, StimLab July 2000, SPE 16912, 19091, 22850

Conditions: YM=5e6 psi, 50% gel damage, 250°F, 1 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd YM=34e3 MPa, 50% gel damage, 121°C, 5 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d

Effective Conductivity (md-ft)

Effective Conductivity (md-ft)

API Test

1500

7000

Modified 50-Hour Test

1137

5715

"Inertial Flow" with Non-Darcy Effects

672

3481

Lower Achieved Width (1 lb/sq ft)

225

Multiphase Flow

49

479

50% Gel Damage

14

7

130

Fines Migration / Plugging

144

99.73%

Cyclic Stress

4

0.001 D-m reduction

96

98.63%

0.029 D-m reduction

Effective conductivities can be less than 1% of API test values

Conditions: YM=5e6 psi, 50% gel damage, 250°F, 1 lb/ft 2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd YM=34e3 MPa, 50% gel damage, 121°C, 5 kg/m 2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d

1243

CarboLITE

Jordan Sand

References: ST Sand: SPE 14133, 16415, CL: Carbo typical, LT: Stim-Lab PredK 2002, SPE 24008, 3298, 7573, 11634, CARBO Tech Rpt 99-062, Run #6542, StimLab July 2000, SPE 16912, 19091, 22850

0

1000

2000

3000

4000

5000

6000

7000

Cumulative Conductivity Reductions

•

Gel-plugged tip

“Equivalent” infiniteconductivity frac

“Apparent” frac matched to production data, assuming apparent conductivity of 10 md-ft

Cleaned up / Flowing length is likely lower

Slurry / Propped Length may be lower

Mapped half-length

Caveat: Assumes single, planar frac, homogeneous reservoir

Effective Fracture Length

0.720

Time (days)

1.080

1.440

1.800

2000 8000

0 0 0.360

Test

Model

3000 12000

4000 16000

5000 20000

0 0

Test

Model

Production Surf Pres (psi) Production Gas Rate (Mscf/d)

1000 4000

0.000

(scale = 0-20,000 M CFD)

Gas Rates

(scale = 0-5000 psi)

Tubing P ressures

Calc'd Toph Press (psi) HC Rate (Mscf/d)

1000 4000

2000 8000

3000 12000

4000 16000

5000 20000

Production Modeling

• Finite-Difference • Numerical Solution to Diffusivity Equation • Reservoir As Grid System • Single Well Within Rectangular Grid System • Single Flowing Phase • 2-D • Unfractured and Hydraulically Fractured Wells • Fracture Input From FracproPT • Proppant Crushing • Non-Darcy and Multi-Phase Flow Effects in Fracture • Fracture Face Clean-up

Production Modeling - ReservoirPT

Oil Rate (bbl/day)

1

10

100

1000

10

Transient Flow

100 Time (days)

Boundary Influenced Flow

High Conductivity Fracture

1000

100 ac

Log-Log Rate versus Time Plot Transient & Boundary Influenced Flow

200 ac

10000

360 ac

2300 ac

Oil Rate (bpd)

1

10

100

1000

0

1000

2000

3000

4000

100 ac

Time (days)

5000

6000

High Conductivity Fracture

7000

200 ac

9000

360 ac

2300 ac

8000

Semi-Log Rate versus Time Plot Transient & Boundary Influenced Flow

10000

Oil Rate (bbl/day)

1

10

100

1000

10

No Fracture

100

Low Conductivity Fracture

High Conductivity Fracture

Time (days)

1000

360 acres

10000

Beginning of Boundary Influenced Flow

High & Low Conductivity Fracture & Un-fractured Case

Log-Log Rate versus Time Plot Transient & Boundary Influenced Flow

Rate (bbl/day)

1

10

100

1000

0

360 acres

1000

2000

3000

Low Conductivity Fracture

4000

High Conductivity Fracture

Time (days)

5000

No Fracture

6000

7000

8000

High & Low Conductivity Fracture & Un-fractured Case

Semi-Log Rate versus Time Plot Transient & Boundary Influenced Flow

9000

10000

Fracture Mapping & Model Calibration

H?

W? L? pnet

Pay

Pay

Analogies Between Hydraulic Frac and Balloon

H?

W?

pnet

L? pnet

R?

Pay

Pay

Analogies Between Hydraulic Frac and Balloon

Some balloons have a tendency to move up

Mother Nature’s Birthday Party

Some show a huge length-height aspect ratio …

Mother Nature’s Birthday Party

… while others show high levels of complexity

Mother Nature’s Birthday Party

Some grow in a specific way in the US …

Mother Nature’s Birthday Party

… and quite differently in the rest of the world

Mother Nature’s Birthday Party

Incomplete coverage

T-shaped fractures

Horizontal fractures

Perfectly confined frac

Poor fluid diversion

Multiple fractures dipping from vertical

Twisting fractures

Out-of-zone growth

Why Map Fracs? Why Model Fracs?

FRACTURE DIAGNOSTICS

conductive liquidexcitation electrode

gas bubble

Pick-up electrodes

Induced tilt reflects the geometry and orientation of created hydraulic fracture

Hydraulic fracture induces a characteristic deformation pattern

Fracture

Downhole tiltmeters In offset well

Fracture-induced surface trough

Principle of Tilt Fracture Mapping Direct Fracture Diagnostic Technique

• Measure frac height, length and azimuth in real-time

FracSeis Microseismic Fracmapping

SOLUTION: Calibrate model

PROBLEM: Physics of model not consistent with reservoir

SOLUTION: Spend time and money to obtain better inputs

PROBLEM: Poorly defined input parameters

Why Bad Models Happen to Good Engineers

Captain, my frac modeling builds a mountain of results on a molehill of inputs

Use some fudge factors and let’s frac this well

Fracture Models Sometimes Need Calibration

• • • • • • • • • • • •

Fluid rheology Wallbuilding coefficient Pressure-dependent leakoff Closure stress in pay Young’s modulus Permeability and pore pressure Closure stress in neighboring layers Fracture complexity Tip effects Proppant drag Composite layering Fracture width decoupling

Critical Model Input Parameters

Improve Measurements

Impossible to measure directly and physics not well understood

Harder to measure directly and less reliable

Relatively easy & reliable measurement

Color Key:

Too many knobs to turn

Why Bad Models Happen to Good Engineers

Grasshopper, Now You Must Choose!

• • • • • • • • • • • •

Fluid rheology Wallbuilding coefficient Pressure-dependent leakoff Closure stress in pay Young’s modulus Permeability and pore pressure Closure stress in neighboring layers Fracture complexity Tip effects Model Calibration Proppant drag Composite layering Fracture width decoupling

Impossible to measure directly and physics not well understood

Harder to measure directly and less reliable

Relatively easy & reliable measurement

Color Key:

• • • •

Net pressure Fracture length Fracture height Fracture width and conductivity

Directly Measured Model Outputs

Improve Measurements

Critical Model Input Parameters

Knobs “locked in” by improved measurements

Why Bad Models Happen to Good Engineers

• • • • • • • • • • • •

Fluid rheology Wallbuilding coefficient Pressure-dependent leakoff Closure stress in pay Young’s modulus Permeability and pore pressure Closure stress in neighboring layers Fracture complexity Tip effects Model Calibration Proppant drag Composite layering Fracture width decoupling

Impossible to measure directly and physics not well understood

Harder to measure directly and less reliable

Relatively easy & reliable measurement

Color Key:

• • • •

Net pressure Fracture length Fracture height Fracture width and conductivity

Directly Measured Model Outputs

Improve Measurements

Critical Model Input Parameters

Knobs “locked in” by model calibration

Why Bad Models Happen to Good Engineers

D e pth (ft)

stress contrast

Stress Profile

Low

3400 1600

3380

3360

3340

3320

3300

3280

2300

Closure Stress (psi)

1950

High

Permeability

Perfs Perfs

2650

Large stress contrast Large sand-shale 3260

3240

3220

3200

3000

0

50

Downhole tilt

Downhole tilt analysis results

Length (ft)

100

150

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.0

Proppant Concentration (lb/ft²)

Pressure analysis

Pressure analysis results

Concentration of Proppant in each Fracture (lb/ft²)

Depleted Portion of Field

200

Perfs

Stress Profile

Low

3550 2000

3520

3490

3460

3430

3400

2250 2500 2750 Closure Stress (psi)

High

Permeability

stress contrast 3370SmallSmall sand-shale

3340

3310

3280

3250

3000

0

75

150 Length (f

1.2

225

0.00 0.20 0.40 0.60 0.80 1.0

1.4

1.6

Proppant Concentration (lb/ft²)

1.8

Fracture Half-length 95 ft Pressure analysis 6 “equivalent” fracture multiples

Pressure analysis results:

Downhole tilt

Concentration of Proppant in each Fracture (lb/ft²)

l

Un-depleted Portion of Field

–Confined fracture growth in significantly depleted sand

–Unconfined height growth in undepleted sand

•Different fracture height growth behavior in two wells is explained by pore pressure depletion

Sometimes the Models Work Without Calibration

2.0

300

Uncalibrated match

But Many Times Models Need Calibration DJ Basin

But Many Times Models Need Calibration DJ Basin

Calibrated match

But Many Times Models Need Calibration DJ Basin

But Many Times Models Need Calibration DJ Basin

Cotton Valley Taylor

Time (min)

160.0

12000

Tools

11800

11600

11400

11200

8/26/03

11000

240.0

320.0

400.0

Calibrated Model

Distance Along Wellbore (ft)

Wright #1-3 GR

frac is assumed to be symmetric

One On frac wing was not fully seen by MS mapping-

-1600

80.0

-1400

0.0

0

-1200

0

400

-1000

10800

-800

400

800

-600

10600

-400

800

1200

-200

10400

0

1200

-2000

Depth (ft)

Wright #1-3 1600

200

1600

400

10200

600

Woolf #1-9

-1800

2000

800

Net Pressure (psi)

1000

Observed Net (psi)

1200

2000

1400

10000

1600

Wright 1-3 Net Pressure Match

1800

11450

11400

11350

11300

11250

11200

Taylor Sands

Taylor Sands

Taylor Sands

GR_STGC (GAPI) 5

But Many Times Models Need Calibration Cotton Valley Taylor Sand

2000

Calibrated Model

But Many Times Models Need Calibration Cotton Valley Taylor Sand

Un-Calibrated Model

But Many Times Models Need Calibration Cotton Valley Taylor Sand

not predictive

Direct diagnostics

Calibrated models more realistically predict how fractures will physically grow for alternative designs

incomplete physical understanding

Fracture growth models

Calibrated Model Approach: Modeling and Measuring

• Model calibration can provide “Good Models to Good Engineers”

– Hopefully leading to improved physics in models

• Model calibration is currently only done empirically, by matching geometries

– Poor characterization of rock / reservoir / geology – Incomplete understanding of relevant physics, especially with respect to height growth

• Models of today are more sophisticated than 20 years ago, but often still do NOT accurately predict fracture growth

Conclusions

Questions ?

0.0 0

20.0 400

14.00

42.00

Net Pressure Match

Time (min)

28.00

Bottom hole proppant concentration

Rate

56.00

70.00

200

8500

8550

8600

8500

8550

8600

0

150

200

250

1.2

1.5

1.8

2.1

Proppant Concentration (lb/ft²)

100

0.30 0.60 0.90

50

2.4

300

Concentration of Proppant in Fracture (lb/ft²)

2.7

350

3.0

1

0

1

Width Profile (in)

Predicted Fracture Geometry

8450

8350

8300

8250

8200

8150

8100

8450

350

350

350

350

350

8400

Gamma Ray (API) 0 Temp 1 150 Temp 2 150 Temp 3 150 Temp 4 150 Temp 5 150

8400

8350

8300

0.00 8250 0

8200

4.00 400

8.00 800

16.00 1600

20.00 2000

40.0 800

Model Net Pressure

Actual Net Pressure

Btm Prop Conc (ppg) Observed Net (psi)

12.00 1200

0.00

Slurry Flow Rate (bpm) Net Pressure (psi)

60.0 1200

80.0 1600

100.0 2000

FracproPT Overview

Depth, TVD (ft)

Depth TVD (ft-TVD) Depth, (ft)

• Contains preloaded libraries of stimulation fluids, proppants, and rock properties for many lithologies

• Supports remote access via modem or internet

• Optimizes fracture treatment economics

• Integrated reservoir simulator for production forecasting and matching

• Performs near-wellbore tortuosity / perf friction analysis – allows identification and remediation of potential premature screenout problems

• Provides unique tool to capture what is learned from direct fracture diagnostics through calibrated model settings

• Estimates fracture geometry and proppant placement in real-time by net pressure history matching

FracproPT System - Highlights

Production Forecast or Match

Estimated Fracture Geometry

Treatment Schedule

FracproPT Economic Optimization

FracproPT Production Analysis

FracproPT Fracture Analysis

FracproPT Fracture Design

Production Data

Treatment Data

Wellbore Information Log/layer Information

Calibrated Model Settings

DataAcqPT Real-Time Data Acquisition

FracproPT Module Interaction

– Capturing the physics of details is not as important as honoring large-scale elasticity and mass balance – Calibrated simplified approximation with full 3D growth model, lab tests and field observations – Model calibration is now a continuous effort

• After development of pseudo-3D models (early 1980’s) the industry was jubilant as it was now known how fractures really behaved -- or not ? • Observed net pressures were consistently far higher than net pressures predicted by these models (discovered in early 1980’s) -- parameter sensitivity also inconsistent • Development of Fracpro started in 1980’s with the aim to honor the “message” contained in real-data

FracproPT Development Philosophy

• Fracture Temperature Model

• Fracture Leakoff Model(s)

• Fracture Growth Model(s)

• Perforation and NearWellbore Model

• Wellbore Model

• Multiple Fracture Model

• Backstress (poro-elastic) Model

• Acid Fracturing Model(s)

• Proppant Transport Model(s)

Fracture Modeling in FracproPT

– Making the right engineering assumptions is key – Garbage in = garbage out – The KEY is to honor the observed data with the most reasonable assumptions possible

• The FracproPT system contains several 2D models, a conventional 3D model, an adjustable 3D model incorporating “tip effects”, and a growing number of calibrated model settings • There is NO “FracproPT answer” • Designed for on-site engineering flexibility • Quality of results are more user-dependent than model dependent

FracproPT is Just a Tool