Download ppt - FracproPT Short Course

By

Pinnacle Technologies

Fracture Modeling

FracproPT System - Highlights• Estimates fracture geometry and proppant placement in real-time

by net pressure history matching

• Provides unique tool to capture what is learned from direct fracture

diagnostics through calibrated model settings

• Performs near-wellbore tortuosity / perf friction analysis – allows

identification and remediation of potential premature screenout

problems

• Integrated reservoir simulator for production forecasting and

matching

• Optimizes fracture treatment economics

• Supports remote access via modem or internet

• Contains preloaded libraries of stimulation fluids, proppants,

and rock properties for many lithologies

FracproPT Module Interaction

Production Data

Calibrated ModelSettings

FracproPT Fracture Analysis

FracproPT Production Analysis

FracproPT Economic

Optimization

FracproPT Fracture Design

Treatment Schedule

Production Forecastor Match

Wellbore InformationLog/layer Information

EstimatedFracture

Geometry

Treatment Data

DataAcqPT Real-Time

Data Acquisition

Motivation for Frac Engineering & Diagnostics

Hydraulic fracturing is done for well stimulation

NOT

for proppant disposal

Fracture Pressure Analysis - Advantages

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

• Relatively inexpensive and quick diagnostic technique to apply

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

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

Fracture Pressure Analysis - Limitations

• Fracture Entry Friction Evaluation– Using surface pressure increases results uncertainty – Problematic near-wellbore friction level variable

• Net Pressure History Matching– 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• Production data & welltest analysis• Direct fracture diagnostics

Example Application – “Pressure Out” on Pad

• Formation: Naturally fractured dolomite @ 8200’ (gas)• Completion: 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 • Situation: Declining injectivity leading to “pressure-out” on pad • Diagnosis: Severe near-wellbore fracture tortuosity• Solution: 1 and 2 PPG proppant slugs very early in the pad to

screen out fracture multiples

Time (min)

Surf Press [Csg] (psi) Slurry Flow Rate (bpm)Proppant Conc (ppg) Btm Prop Conc (ppg)

0.0 28.0 56.0 84.0 112.0 140.0 0

1200

2400

3600

4800

6000

0.0

20.0

40.0

60.0

80.0

100.0

0.00

4.00

8.00

12.00

16.00

20.00

0.00

4.00

8.00

12.00

16.00

20.00

Example Application – “Pressure Out” on Pad1400 psi friction reduction (1st slug)

Max surface pressure 6000 psi

Increased max prop conc

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

no tortuosity at end of pumping

S/D#2: 300 psi tortuosity

Example Application – Estimation of Realistic Fracture Half-Length

• Formation: Hard sandstone @ 7600’ (gas) in West Texas

• Completion: 5-1/2” casing frac string; 40’ perf interval shot with 4 SPF, 90 phasing, 0.31” diameter holes

• Situation: Disappointing production performance for expected 600 ft fracture half-length (based on fracture

growth design without real-data feedback)

• Diagnosis: Sand/shale stress contrast much lower than estimated, resulting in significant fracture

height growth and a much shorter fracture half-length (250’)

• Solution: Utilize fracture pressure analysis to optimize fracture treatment design


Geometry inferred design without real-data feedback

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

Time (min)

Slurry Rate (bpm) Prop Conc (ppg)Btm Prop Conc (ppg) Net Pressure (A) (psi)

0.0 20.0 40.0 60.0 80.0 100.0 0.0

20.0

40.0

60.0

80.0

100.0

0.00

10.00

20.00

30.00

40.00

50.00

0.00

10.00

20.00

30.00

40.00

50.00

0

400

800

1200

1600

2000



Time (min)

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

0.0 20.0 40.0 60.0 80.0 100.0 0

400

800

1200

1600

2000

0.0

20.0

40.0

60.0

80.0

100.0

0.00

10.00

20.00

30.00

40.00

50.00

0.00

10.00

20.00

30.00

40.00

50.00

0

400

800

1200

1600

2000

Observed net pressure does not match design net pressure response


Geometry inferred from net pressure matching


Time (min)

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

0.0 20.0 40.0 60.0 80.0 100.0 0

400

800

1200

1600

2000

0

400

800

1200

1600

2000

0.0

20.0

40.0

60.0

80.0

100.0

0.00

10.00

20.00

30.00

40.00

50.00

0.00

10.00

20.00

30.00

40.00

50.00

0

400

800

1200

1600

2000

Lower stress contrast (0.1 psi/ft) required to match observed net pressure

Confirmed with shale stress test in subsequent wells

Example Application -- Tip Screen-out Strategy To Obtain Sufficient Conductivity

• Formation: High permeability layered sandstone at 6000 ft (oil)

• Completion: Deviated wellbore, 3-1/2” tubing frac string

30’ perf interval shot 4 SPF, 180 phasing oriented perfs, 0.5” diameter holes

• Situation: Relatively poor post-frac production response for high perm reservoir

• Diagnosis: Insufficient propped fracture conductivity• Solution: Increase treatment size, and utilize on-site fracture

pressure analysis to consistently achieve tip screenout for enhanced fracture conductivity


Pad sizing for TSO design was done utilizing leakoff calibration with minifrac. The net pressure match shows a significant increase in pressure due to tip screen-out initiation

ARCO Kuparuk River Unit 2K-15A4 sand 6217'-6247' TVD 12/22/96

Net pressure match Pinnacle Technologies

Time (mins)

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

0.0 60.0 120.0 180.0 240.0 300.0 0.0

150.0

300.0

450.0

600.0

750.0

0.0

150.0

300.0

450.0

600.0

750.0

0.0

20.0

40.0

60.0

80.0

100.0

0.00

10.00

20.00

30.00

40.00

50.00

0.00

10.00

20.00

30.00

40.00

50.00

Breakdown injection

Minifrac

Pad fluid volume adjusted based on leakoff behavior following crosslink gel minifrac

Tip screen-out initiation


• Production response in Kuparuk A sand limited by fracture conductivity

• Tip screen-out obtained in more than 90% of treatments– Sizing of pad size using calibration of leakoff coefficient key to

success– On-site real-time closure stress analysis implemented on

every treatment to ensure proper pad size is pumped

Definition Of Net PressureNet Pressure is the Pressure Inside the Fracture

Minus the Closure PressureNet Pressure = 2,500 - 2,000 = 500 psi

Balloon Analogy For Opening Fracture With Constant Radius

Fluid Leakoff And Slurry Efficiency

LOW SLURRY EFFICIENCY

Short Fracture High Filtration

Longer Fracture

HIGH SLURRY EFFICIENCY

Low Filtration

Vpumped (t)

Vfrac (t)efficiency (t) =

Net Pressure Vs. Friction Pressure

Net Pressure Matching

Basic Fracture Pressure Analysis Steps

Match model netpressure to observed

net pressure

Pre-frac completionand fracture design

Determine fracture closurestress and match permeability

Characterize frictionparameters using rate

stepdown tests

Determine observednet pressure

Explore / bound alternative explanations for

observed netpressure

Interpret model results,make engineering

decisions

Perform treatment

Post-frac modeling reviewand incorporate otherfracture diagnostics

Repeat process insucceeding stages or

wells

1

2

3

4

Different Models

• 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

Fracture Design and Analysis EvolutionModeling without Real-Data Feedback

Wellbore

Pay Pay

P red ic ted net p ressureN e t

p ressure

P um p tim e

P um p ra te

U se net pressure

predicted

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

Fracture Design and Analysis EvolutionModeling without Real-Data Feedback

• 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

Wellbore

Pay Pay

P red ic ted net p ressure

M easured ne t pressu re

N e tp ressure

P um p tim e

P um p ra te

U se net pressure

predicted

?

Fracture Design and Analysis EvolutionModeling with Net Pressure Feedback

• Net pressure history match can be obtained by adding new physics to fracture models – Reason for the existence of FracproPT

• With the right assumptions and physics, inferred geometry has a better chance to be correct

Wellbore

Pay

N etp ressure

P um p tim e

M atch ing m easured net p ressurew ith m ode l ne t p ressu re

U se net pressure

m easured

FracproPT Development Philosophy

• 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

– 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

Fracture Modeling in FracproPT

• Wellbore Model

• Perforation and Near-Wellbore Model

• Fracture Growth Model(s)

• Fracture Leakoff Model(s)

• Fracture Temperature Model

• Proppant Transport Model(s)

• Acid Fracturing Model(s)

• Backstress (poro-elastic) Model

• Multiple Fracture Model

FracproPT is Just a Tool

• 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

–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

Minimum Model Input Requirements• Mechanical rock properties

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

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

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

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

pumping

Required to Obtain Observed Net Pressure

• 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

p p p pnet obs surface hydrostatic friction closure,

“Typical” Fracture Treatment Data

Time (mins)

Surface Pressure (psi) Slurry Rate (bpm)Proppant Concentration (ppg)

50.00 58.00 66.00 74.00 82.00 90.00 0

600

1200

1800

2400

3000

0.0

40.0

80.0

120.0

160.0

200.0

0.00

4.00

8.00

12.00

16.00

20.00

Net pressure ?

Closure ?

Leak-off ?

Friction ?

Purpose Of Diagnostic Injections

• 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

Recommended Diagnostic Injection Procedures

Diagnostic Step When Fluid & Volume Purpose / Results Breakdown Injection / rate stepdown / pressure decline

Always ~50-100 Bbl KCl Establish injectivity; obtain small volume ISIP; estimate closure pressure and formation permeability.

Crosslinked Gel Minifrac with proppant slug / rate stepdown / pressure decline

New areas Real-time pad resizing TSO treatments

~100-500 Bbl fracture fluid including 25-50 Bbl proppant slug (possible range 0.5-5 PPG)

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.

End Frac Rate Stepdown / Pressure Decline Monitoring

Always Minimum of 10 minute decline data

Characterize fracture entry friction; Post-frac leakoff calibration.

“Anchor Point”: Fracture Closure Stress

“Anchor Points”: Isip Progression

“Anchor Points”: Frictional Components

Main Input Parameter - Permeability

• Matching perm is “permeability under fracturing conditions” – not necessarily under production conditions– Relative permeability issues– Opening of natural fractures– Relies on many other assumptions

• Keep it simple: – only change permeability in pay interval.– Keep permeability zero in shales

• If permeability profile is “known”, use Kp/Kl ratio for matching instead

• Fix by matching decline slope of B/D KCl injection

Main Input Parameter - Closure Stress• 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)

Closure Stress Profile

• Closure stress min 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

Main Input Parameter - Young’s Modulus

• 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

Different Methods To Obtain Fracture Closure Stress (in Pay)

• Pressure decline analysis• Square-root time plot• G-function plot• Log-log plot• Rate normalized plot• Horner plot (lower bound)

• Flow pulse technique• Flow back test• Steprate test (upper bound)• Hydraulic Impedance testing (HIT)

Pressure Decline Analysis

• Pressure decline after a mini-frac passes through two flow regimes:– Linear flow regime; Pressure decline depends on:

• fluid leakoff rate• fracture compliance

– Radial flow regime; Pressure decline depends on:• reservoir diffusivity

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

What Can You Obtain From Pressure Decline Analysis?

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

pressure• Fracture geometry estimate

T p +Tc

Bot

tom

hol

e p

ress

ure

R a te

C lo su re

E ffic ie n cy ~

T im e

Tc

P ne t

T p

Tc

IS IP

Tc

Tc + Tp

Pressure Decline Analysis – Square-root Time Plot

Time (min)

Meas'd Btmh Press (psi) Surf Press [Csg] (psi)Surf Press [Csg] (psi) Implied Slurry Efficiency (%)

5000

5700

6400

7100

7800

8500

1500

2200

2900

3600

4300

5000

-700

-560

-420

-280

-140

0

0.0

40.0

80.0

120.0

160.0

200.0

0.0 2.0 4.0 6.0 8.0 10.0

BH Closure Pressure: 5423 psiClosure Stress Gradient: 0.658 psi/ftClosure Time: 6.0 minPump Time: 3.0 minImplied Slurry Efficiency: 53.0 %Estimated Net Pressure: 1093 psi

Pressure Decline Analysis – G-function Plot

G Function Time

Meas'd Btmh Press (psi) Surf Press [Csg] (psi)Surf Press [Csg] (psi) Surf Press [Csg] (psi)Implied Slurry Efficiency (%)

0.000 0.620 1.240 1.860 2.480 3.100 5000

5700

6400

7100

7800

8500

1500

2200

2900

3600

4300

5000

0.0

160.0

320.0

480.0

640.0

800.0

0

200

400

600

800

1000

0.0

40.0

80.0

120.0

160.0

200.0


Pressure Decline Analysis – Log-log Delta Pressure Plot

Time (min)

Delta Pressure (psi) Delta Pressure (psi)Implied Slurry Efficiency (%)

0.100 1.000 10.000 100.00

10

100

1000

10000


Steprate/Flowback test

• 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

Pump-In/Flowback/Shut-in Test (SPE 24844)• High perm well where the FB-SI is run after the gel calibration test

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

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

~ 30 psi

SI-Rebound < p cindependent of " tortuosity" SPE PF Feb '97

FB induced" wellbore pinch”

" near-well pinch "

~ 15 min

Tortuosity Can Be Measured: Stepdown Test

• 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

What Is Tortuosity? Width Restriction Close To Wellbore

Width Restriction Increases Necessary Wellbore Pressure

Net fracturingpressure

Tortuosity Leads To Large Pressure Drop In Fracture Close To Well

Pressure after shut-in

Wellbore Distance into fracture

Fracture tip

Near-wellbore frictionHigh

Low

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

Near-wellbore Friction Vs. Perforation Friction

Near-wellbore Friction Vs. Perforation Friction

Time (min)

Btm Slry Rate (bpm) Meas'd Btmh (psi)

17.00 17.80 18.60 19.40 20.20 21.00 0.00

10.00

20.00

30.00

40.00

50.00

5500

6100

6700

7300

7900

8500


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

• Perforation friction dominated regime


• Near-wellbore friction dominated regime

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

High entry friction

High perf friction Severe fracture tortuosity

Re-perforate

Ball-out treatment

Spot acid

Use proppant slugs

Initiate with high viscosity fluid

Increase gel loading

Increase rate

Future wells may have altered completion strategy such as

FEWER perfs

Net Pressure Matching

• Match “observed” net pressure with calculated “model” net pressure

• Observed net pressure obtained from surface or downhole treatment pressure– Correct for fracture closure, frictional effects and hydrostatic

• Model net pressure can be changed to match observed net pressures using the following general “knobs” (see next page)

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

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

Time (min)

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

0.0 30.0 60.0 90.0 120.0 150.0 0

500

1000

1500

2000

2500

0

500

1000

1500

2000

2500

0.0

25.0

50.0

75.0

100.0

125.0

0.00

5.00

10.00

15.00

20.00

25.00

0.00

5.00

10.00

15.00

20.00

25.00

FracproPT Net Pressure Matching Parameters • “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

Net Pressure Matching Strategy• B/D Injection

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

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

• Prop frac:– 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

FracproPT Net Pressure Matching Parameters

Parameter Range Unit Mainly Affects When Net

P

ress

ure

Slu

rry

Eff

icie

ncy

Hal

f-L

eng

th

Hei

gh

t

Wid

th

Permeability 0.000001 - 10000 mD Decline slope B/D injection - - - -

Wallbuilding Coefficient Cw 0.0001 - 0.1 ft/(min)0.5 Decline slope Minifrac - - - -

Pressure-dependent Leakoff* >=1 fracs Decline slope Prop frac - - - -

Fracture Complexity** >=1 fracs Level All injections + +

Stress Contrast (Pay-Barrier) 0.00 - 0.40 psi/ft Level All injections + +

Tip Effects 0.00001 - 0.4 - Level All injections - +

Proppant Drag 0 - 25 - Level TSO +

TSO Backfill 0.0 - 1.0 - Level TSO +

Composite Layering 1 - 1000 - Geometry All injections + + -

Width Decoupling 0.01 - 1.00 - Geometry All injections - +

* Multiple fracture leakoff factor. ** Multiple fracture volume&opening factor

Response with Parameter Increase +

Prop Frac

Main Matching Parameters – Tip Effects Coefficient (Gamma 2)

• 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

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

• 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 Effects Coefficient

Non-linear elastic model (Gamma 2 = 0.0001)

Linear elastic model (Gamma 2 = 0.4)

pnet

Lf

Non-linear elastic model

Linear elastic model

wfrac

Lf

Net pressure decline slope w/ distance represents Gamma 2)

Tip Effects -- Increased Fracture Growth Resistance

Process Zone Around Fracture Tip

• 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

Main Matching Parameter – Multiple Fractures• 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

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

Multiple Hydraulic Fractures In FracproPT

Modeling Approach for Multiple Hydraulic Fractures

Situation Equivalent number of growing multiple

fracs (MV)

Equivalent number of fractures

with leakoff (ML)

Equivalent number of

fracs competing for width

(MO)

3 3 1

3 2 2

3 1 3

Equivalent number of spaced identical fractures

without interference

Equivalent number of fractures competing

For width

Evidence for the Simultaneous Propagation of Multiple Hydraulic Fractures

• 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

Conclusion: multiple fractures are the rule rather than the exception

Multiple Strands in a Propped Fracture

NEVADA TEST SITE MINEBACK

Courtesy: N.R. Warpinski, Sandia Labs

Use Multiple Hydraulic Fractures Prudently for Modeling Purposes

• Potential causes for high net pressures:– 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

Region ofnear-wellbore

tortuosity

Conceptual simplification ofnear-wellbore tortuosityand multiple fractures

Modeling strategy fornear-wellbore tortuosityand multiple fractures

Multifrac Modeling Approach For Limited Different Perforation Strategies

Main Matching Parameters – Proppant Drag Exponent

• 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 Parameter – Quadratic Backfill Exponent

• How does it work– 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.

• When do you change it?– Increase it when the TSO-induced observed net pressure rise is

steeper than model predicts

New Matching Parameter – Width Coupling Coefficient

• How does it work ?– 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• When do you change it ?

– 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)

pnet

R

= WcpnetR/ E

Main Matching Parameters – Composite Layering Effect

• How does it work ?– This parameter controls the near-tip pressure drop in each

individual layer• When do you change it ?

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

– Keep unity in pay zone

Estimating Frac Dimensions Using Real Data And Radial Frac Assumption:“Back-of-the-Envelop Model”

E

Rpw

net

2

For: Volume pumped V = 1,000 bbl (~ 5,610 ft3)Efficiency (@ EOJ) e = 0.5 Young’s modulus E = 1x106 psiPoisson’s ratio = 0.2Net pressure (@ EOJ) pnet = 500 psi

Yields: Radius R ~ 103 ftWidth @ wellbore w ~ 1.51 in

Mass balance

Elastic opening

e V R w 23

231

4

3

netp

EeVR

31

2

2

3

6

E

eVpw

net

Influence Of Net Pressure

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

R = 650 feet

w = 0.25 in

R = 260 feet

w = 1.6 in

Pnet = 50 psi

Pnet = 800 psi

Predicted netpressure

Predicted fracturedimensions

Fracture Geometry Changes With Net Pressure

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

L = 1200 feet

R = 240 feet

Pnet = 100 psi

Pnet = 800 psi

Predicted net pressure

Predicted frac dimensions

Net Pressure Analysis Untruths

• “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 !

• “You used the wrong frac model !” Or

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

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

• “We analyzed the treatment and determined optimum frac design”– Optimization is an evolutionary process, completed over the

course of a series of fracture treatments

Fracture Pressure Analysis Problems / Opportunities

• 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

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

• Appropriate Mechanisms for Net Pressure History Matching– ? Modulus, stress, leakoff, and multiple fractures – ? Layer interface mechanisms

Fracture Analysis - Conclusions

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

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

• 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

Production Analysis of HF Wells

Simple Approach:

• Evaluate performance based on EUR’s or other indicators such as IP’s, 6-month and 12-month cumulative, best 3-month of production etc.

• Cumulative Frequency plots can be useful as a simple statistical method to compare and evaluate well performance

ReservoirPT

• 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

1

10

100

1000

10 100 1000 10000

Time (days)

Oil

Ra

te (

bb

l/d

ay)

Log-Log Rate versus Time Plot Transient & Boundary Influenced

Flow High Conductivity Fracture

2300 ac

100 ac

200 ac

360 ac

Transient Flow

Boundary Influenced Flow

1

10

100

1000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Time (days)

Oil

Rat

e (b

pd

)

Semi-Log Rate versus Time Plot Transient & Boundary Influenced

Flow High Conductivity Fracture

2300 ac

360 ac

200 ac100 ac

1

10

100

1000

10 100 1000 10000

Time (days)

Oil

Rat

e (

bb

l/day

)

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

High & Low Conductivity Fracture & Un-fractured Case

High Conductivity Fracture

No Fracture

Low Conductivity Fracture

360 acres

Beginning of Boundary Influenced Flow

1

10

100

1000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Time (days)

Rat

e (

bb

l/day

)

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

High & Low Conductivity Fracture & Un-fractured Case

High Conductivity Fracture

Low Conductivity Fracture No Fracture

360 acres

Important Parameter Is Relative Fracture Conductivity At Reservoir Conditions

• Fracture Conductivity, wkf

wkf = fracture width x fracture permeability

• Propped Fracture Width is Primarily a Function of Proppant Concentration

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

F = CDwkfkLf

wkf = Fracture Conductivity, md-ft

k = Formation Permeability, md

For FCD > 30 or Cr > 10, Lf is infinite conductive

- No Significant Pressure Drop in Fracture

- Value of 1.6 or larger generally sufficient

L = Fracture Half-Length, ftf

wkCr = f

kLor

(Patts(1961) and Cinco-Ley(1978)) Effective Wellbore Radius Vs. Dim. Fracture Cond.

0.010

0.100

1.000

0.100 1.000 10.000 100.000

Fcd

Rw

'/Xf

At Fcd = 10; Rw’ = 43% of Xf

At Fcd =1.0; Rw’ = 19% of Xf

Need Length Or Conductivity? (After McGuire&Sikora)

Increase in frac length

Increase in conductivity

Pro

du

ctiv

ity in

cre

ase

Frac design change with same amount of proppant

Design In Low-permeability Formation

• 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 High-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

Optimum Conductivity• FCD = 10 results in virtually infinite conductivity fracture

• In permeable reservoirs or in deep formations where closure stress is high, it may be difficult to achieve FCD = 10; FCD of 1.6 is generally sufficient

• Use reservoir simulation to determine optimum L assuming you can achieve adequate FCD

• Choose proppant type and concentration to maximize FCD , up to a value of 10

• Consider Multiphase flow effects• Consider Turbulent flow effects

Fracture ConductivityIn The Reservoir

• Conductivity is reduced by– Closure Stress– Embedment– Crushing (generates fines and damages proppant)– Corrosion– Gel Residue Plugging– Convection– Proppant Settling– Multiphase flow effects – Turbulent flow

Optimization OfFracture Treatments

• Function of:– Permeability– Oil & Gas in Place– Drainage Area– Fracture Conductivity and Ability to Place Proppant

• Economic Criteria Are Optimized– Maximum Increase at Minimal Cost– Multiple Economic Yardsticks to Choose From

Economic Indicators

• Net Present Value (NPV)• Rate of Return (ROR)• Net Present Value to Investment Ratio (NPV/IR)• Other

Optimization MethodologyStep-by-step

1) Predict Well Performance– Unfractured (Base Case)– Different Fracture Half-Lengths– Different Fracture Conductivities– Different Drainage Areas– Worst Case Proppant Placement Scenarios

2) Estimate Treatment Costs Required to Create Half-Lengths Assumed in Step 1

3) Calculate NPV, ROR, and/or Other Economic Indicators Using Incremental Production (Difference Between Fractured and Unfractured Cases)

Optimization MethodologyStep-by-step

Optimization Methodology

FRACTUREHALF-LENGTH

Optimal

CU

M.

GA

S

TR

EA

TM

EN

T C

OS

T

NP

V

TIME FRACTUREHALF-LENGTH

Unstimulated

L = 500

L = 300

L = 100

f

f

f

1 2 3

Fracture Diagnostic Tools

Surface Tilt Mapping

DH Offset Tilt Mapping

Microseismic Mapping

Treatment Well Tiltmeters

Radioactive Tracers

Temperature Logging

HIT

Production Logging

Borehole Image Logging

Downhole Video

Caliper Logging

Net Pressure Analysis

Well Testing

Production Analysis

GROUP DIAGNOSTIC

ABILITY TO ESTIMATEWill Determine

May Determine

Can Not Determine

MAIN LIMITATIONS

Depth of investigation 1'-2'

Thermal conductivity of rock layers skews results

Sensitive to i.d. changes in tubulars

Only determines which zones contribute to production

Run only in open hole– information at wellbore only

Mostly cased hole– info about which perfs contribute

Open hole, results depend on borehole quality

Modeling assumptions from reservoir description

Need accurate permeability and pressure

Need accurate permeability and pressure

Resolution decreases with depth

Resolution decreases with offset well distance

May not work in all formations

Frac length must be calculated from height and width

Example Application - Model Results Are Not Always Consistent with Directly Measured Geometry

1600

1700

1800

1900

2000

2100

2200

-400 -200 0 200 400

Along Fracture Length (ft)

De

pth

(ft

)

Calibrated fracture modeling (composite

layering effect)

Initial fracture modeling (no confinement

mechanism)

Measured geometry from downhole

tiltmeter mapping

GR log

Fracture Complexity Due

To Joints

HYDRAULIC FRACTUREMINEBACK

Fracture Height Confinement Mechanisms

Increased fractureclosure stress

Interfaceslippage

C om positelayering

FracproPT Model Calibration Parameters

• Crack Opening Coefficient (Shift-F3)– 0.85 represents “coupled” behavior along frac walls– < 0.7 represents “shear decoupled” behavior along frac

walls

• Tip Effects Coefficient Coefficient (Shift-F3)– 1e-04 represents model with tip effects– 0.4 represents linear elastic fracture mechanics

• Composite Layering Effect (Mechanical Rock Properties)– 1 represents radial growth– >1 represents confined height growth

FracproPT Calibrated Model Limitations

• Sometimes actual closure stress is not well know• Quite often, the closure stress profile is not well

known at all– Make assumptions about continuity in bounding layers

stresses

• Need a substantial number of measurements pointing in the same direction

• We do not really understand when composite layering effect applies and how to assign it

• Consistent strategy to create match, as you can match net pressure and dimensions in more than one way

Model Calibration Discussion Models today are more sophisticated than 20 years ago, but

often still do NOT accurately predict fracture growth Poor characterization of rock/reservoir/geology Incomplete understanding of relevant physics

Model “calibration” Empirical, by matching geometries, Hopefully leading to improved physics in models

Ultimate goal: Fully integrated fracture, reservoir and production models Integrated with real-time direct fracture diagnostics

New Engineering Approach: Modeling AND Measuring

Calibrated models more realistically predict how fractures will physically

grow for alternative designs

Fracture growth models incomplete physical

understanding

Direct diagnostics not predictive

Basic Fracture Pressure Analysis StepsEnter inputs and

define assumptions for treatment design /

optimizationFind closure stress and efficiency from

decline analysis

Characterize friction from rate

S/D tests

In orange: during/following diagnostic injections

In green: during/following prop frac

Determine observed net

pressureMatch observed net pressure with model

net pressure

Interpret model results and make

engineering decisions

Match net pressure for propped frac

Calibrate model with direct diagnostics

Match geometry

Conclusions Direct diagnostic observations on hundreds of hydraulic fracture treatments have

revealed the surprising complexity and variability of hydraulic fracturing

Model calibration proving both heartening and humbling, but to date perhaps more humbling than heartening

Enhanced fracture height confinement most likely due to layer interface effects

Physics of fracture growth along/through layer interfaces not well understood

Not captured well in current models Identifying and understanding fracture complexities leads to

Understanding well performance Enhancing completion/stimulation strategies

Fracture models are essential tools for the engineering of hydraulic fracture treatments, but we must become more humble

By defining main limitations, we can continue to move models forward

FracproPT Version 10.2 – What’s ChangedReleased July 2003 - Highlights

Improved Minifrac Analysis Mayerhofer Method for permeability estimate

Automated Friction Analysis Multiple Step Down Tests Semi-automated picking of rate steps

Production Analysis Improvements Directly reads Excel or ASCII production data Automated production history matching

New Fracture Design & Economic Optimization module Reservoir layers auto-picking from log data (LAS File) Improved report exports tables and graphs directly to Word User-defined graphical output tool

Integrated Fracture Picture

FracproPT Version 10.3 – What’s PlannedHighlights

New calibrated fracture models and new default model Minifrac Analysis improvements:

DFIT analysis plots Semi-automated closure picking algorithms Steprate test analysis

Waste/water Injection module Log-Layer Editor improvements:

Reservoir layer properties from triple/quad–combo log analysis Unlimited number of layers

Visualize direct fracture diagnostic data Production Analysis improvements

Quick Comparison Output interface for Eclipse

Improved XY plots with permanent legend and multiple axis New bar graphs for real-time stage information Program navigation bar that remains on left of screen

FracproPT Version 11.0 – What’s PlannedHighlights

Improvements in navigation “Kick start” menus for quick runs in all modes Forward / Back button on all screens that are part of input "loop"

Net pressure matching wizard with guidelines for matching entire job Improvements in Report:

User-defined Excel report Output to PowerPoint Full flexibility in positioning of graphs and tables in Word report User-defined report templates

Quick Comparison for all modes Full 3D fracture growth model