Analysis of Short-term (Flowback) and Long-term (Online) Production ...


Long-term (Online) Production Data from. Low-Permeability Black Oil/Gas. Condensate Reservoirs Using. Analytical/Semi-Analytical Methods. C.R. Clarkson.

Analysis of Short-term (Flowback) and Long-term (Online) Production Data from Low-Permeability Black Oil/Gas Condensate Reservoirs Using Analytical/Semi-Analytical Methods C.R. Clarkson University of Calgary

Outline  Introduction  A few facts  Problem statement and objectives

 Methods  Modification of pseudovariables  Iterative integral  Dynamic drainage area

 Special Application of RTA Methods:  Fracture Height Estimation

 Future Work  Conclusions

Slide 2

Introduction  Fact:  When producing from MFHWs completed in ultra-low permeability reservoirs:

 Horizontal Well

a complex series of processes occurring at multiple scales are initiated that we don’t completely understand Extent of Contacted Reservoir Area

Induced Hydraulic Fracture Network

Perforations

1000 m+ From: Clarkson et al. (JNGSE, 2016)

Slide 3

Introduction  Fact:  When producing from MFHWs completed in ultra-low permeability reservoirs:

 Reactivated Natural Fractures

a complex series of processes occurring at multiple scales are initiated that we don’t completely understand

Induced Hydraulic Fracture meters

Matrix with interspersed organic and inorganic matter

Matrix with fine-scale laminations and fractures

Matrix

Nanopore structure of organic and inorganic matter

Natural Fracture

centimeters

micrometers

millimeters

nanometers

A

STYLIOLINA

0.5 mm

From: Clarkson et al. (JNGSE, 2016)

Slide 4

Introduction  Fact:  Reservoir characterization methods that account for the appropriate physics are in their infancy Pore Confinement Effects

Multi-Phase Flow

Complex Fracturing

Gas phase

Velocity ≠ 0

Hydraulic fracture

Condensate phase

Free gas Adsorbed gas

pi

C?

B

Zone A

Pressure

pd

pw

Distance from hydraulic fracture

etc.  Understanding how to advance characterization methods is critical for sustainable development through primary and enhanced recovery processes Slide 5

Introduction  Reservoir and Hydraulic Fracture Characterization: Analysis Category

Development Stage Pre-Drill

Analysis Type

Seismic, 2D, 3D

Reservoir Sample Analysis

km, kf, So, Sg, Sw, kro, krg, krw, ρm, ρb, øm, PSD, PTD, Pc, a, m, n, OM, IOM, Ro, Gc, Es, νs

Log Analysis

km, kf, h, So, Sg, Sw, ρb, øm, øf, PSD, OM, IOM, ED, νD

Pre-Frac

Pre-Frac Welltest (DFIT)

khsys, Pclosure , Preservoir

Frac Treatment

Frac Monitoring (Microseismic)

Drill/Post-Drill

Reservoir and Hydraulic Fracture Characterization

Properties Derived

Flowback Analysis Post-Frac

Frac Modeling Post-Frac Welltest (F/BU)

Long-Term (Online) Production

From: Clarkson et al. (JNGSE, 2016)

Production Analysis

Frac geometry, SRV

khf , khsys, Pbreakthrough, xf xf, A c, FcD

khsys, xf, Ac, FcD

khsys, OGIP/OOIP, CGIP/COIP, xf, Ac, FcD

Slide 6

Introduction  RTA – Flowback/Online:

From SPE 166279

Slide 7

Flow-Period Flow Period STEP 1:

Illustration of Flow-Periods Flow Periods ASSESS DATA VIABILITY

X-Section X-Section View View Introduction Review Well History

Flow-Regimes

Plan Plan View View Gather Reservoir, Completion and PVT Data

Review Production Data

 RTA – Flowback/Online: STEP 2: Flowback: Flowback: Before Before Breakthrough Breakthrough of of Formation Formation Fluids Fluids (single-phase (single-phase flow flow in in fracture) fracture) STEP 3:

Depletion Depletion (Fracture) (Fracture)

CHECK FOR DATA CORRELATION PRELIMINARY DIAGNOSIS

Review/Edit Data

Filter Data for Clarity

IDENTIFY FLOW REGIMES

STEP 4:

Flowback: Flowback: After After Breakthrough Breakthrough of of Formation Formation Fluids Fluids 5: (multi-phase (multi-phase flow flow STEP in in fracture, fracture, single single or or multi-phase multi-phase flow flow in in formation) formation)

PERFORM STRAIGHTLINE ANALYSIS Obtain Preliminary Estimate of Hydraulic Fracture Properties

STEP 8:

From: Clarkson et al. (TLE, 2014)

Obtain Preliminary Estimate of Reservoir Permeability

Obtain Preliminary Estimate of Hydrocarbons-in-Place

PERFORM TYPE-CURVE ANALYSIS

STEP 6: Long-Term Long-Term Production: Production: Formation Formation Fluid Fluid Production Production Dominant Dominant (multi-phase (multi-phase flow flow in in fracture, fracture, multi-phase multi-phase flow flow in in formation) formation) STEP 7:

Transitional Transitional

Validate Hydraulic Fracture Property Estimates

Validate Reservoir Permeability Estimate

Validate Hydrocarbonsin-Place Estimate

Linear Linear Flow Flow

PERFORM FORECAST WITH MODEL FIT EMPIRICAL MODEL TO FORECAST

Slide 8

Introduction  Problem Statement:  Analytical solutions used in RTA commonly assume: • Single-phase flow of liquids

• Static reservoir and fracture properties • Darcy’s Law is valid • Constant rate or pressure production

• …..

Slide 9

Introduction  Objectives: 50

Fracture UnproppedPressure (MPa) Gas (N2) Permeability (D)



14 Phase Envelope of a Gas-Condensate Fluid Under Confinement Pore Confinement Effects that account Mean Develop approaches for:Pore Pressure = 0.19 MPa 12

• Multi-phase flow 45 40

10

• Stress-dependent 35 30

Mean Pore Pressure = 0.53 MPa Mean Pore Pressure = 0.88 MPa

“Dewpoint fracture and Meanmatrix Pore Pressureproperties = 1.23 MPa Suppression”

8

• Pore confinement effects: non-Darcy flow 25

6 • Pore confinement Freeeffects: gas fluid properties 20 15 10 5

Adsorbed gas

4 2

0 -150

-100

-50

0

0

50

Velocity ≠ 0

100

150

200

250

300

350

400

Temperature (oC)

0 pore width = 300 nm

10

20 pore width = 10 nm

30 pore width = 5 nm

40

50

pore width = 2 nm

Effective Stress (MPa) Slide 10

Methods  Multiple Approaches to Account for Non-Linearities:

• Modification of pseudovariables • Iterative integral method • Dynamic drainage area

Slide 11

Methods: Modification of Pseudos 1.Linearization Technique

• Linearization of governing PDE • Using Pseudovariables

2.Method of Calculation

• Pseudovariables calculations • Saturation pressure relationship

3.Backward Modeling

• Liquid solution • Validation

Image Courtesy of Hamid Behmanesh

Slide 12

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Linearization

Pseudopressure

Pseudotime

Liquid Solution Analogy! Images Courtesy of Hamid Behmanesh

Slide 13

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Pseudovariable Calculations:

Image Courtesy of Hamid Behmanesh

p (1)

PVT (2)

So

a

pp

(3)

(4)

(5)

Slide 14

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Pseudovariable Calculations: Ginv.

p

Image Courtesy of Hamid Behmanesh

t

Np Gp

(1) (2)

Ginv.

Material Balance

p

(3)

(4)

(5)

ta (6)

(7) Slide 15

Methods: Modification of Pseudos  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  Inverse Modeling

 Infinite-acting linear flow solution - CP Images Courtesy of Hamid Behmanesh

Slide 16

Methods: Modification of Pseudos  Application: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  MFHW, tight (lean) gas condensate reservoir 4800

Oil Rate

Gas Rate Water Rate pwf Condensate Gas Ratio Water Gas Ratio

50 1000

3600

40 100 30

2400

20 10

1200

10 0 1 00

Constant CGR

Flowing Bottomhole Pressure, psia

CGR and WGR, STB/MMscf

Gas Rate (Mscf/D), Oil, Water Rate (STBdD)

60 10000

0 100 100

200 300 300 200 Time, days Time, days

400

400 500

500 Slide 17

Methods: Modification of Pseudos  Application: model inversion - linear flow analysis (2P flow – JNGSE 2015, SPE 172928)  MFHW, tight (lean) gas condensate reservoir 2.0

Inverse of Gas Rate, 1/(MMscf/D)

1/qgas, 1/(qoil) versus √t 1.5

Cartesian coordinates

1.0

Initial Properties

xf√k*

mCP

= 21.5 ft.md0.5 xf√k

Distance of Investigation

0.5

Material Balance

p 0.0

0

5

f

10CP

Square Root of Time, days0.5

15

20

Slide 18

Method: Iterative Integral  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176)  Integrate non-linearities over the domain

g 1 (mD ) dmD 0  (m ) D D

0.95 0.9 0.85

1



ˆ   exp  2 0  0  D (mD mD  g    1   ˆ  0 exp   20  D (mD 

 d dˆ  erfc ( ))  .   d dˆ  erfc ( )) 



1 Image Courtesy of Farhad Qanbari

fc

1 tor :   fc

(c)

Bubble point pressure

m( pw )  mCP t f c ( pw ) qo

0.8 0.75

0.7

dSo/dp = 2 10-4 psi-1 dSo/dp = 1.75 10-4 psi-1 dSo/dp = 1.5 10-4 psi-1

0.65 0.6

Initial guess : mD  erfc( )

1000

2000

3000

4000

pw (psi) Slide 19

Method: Iterative Integral  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176) Hydraulic fracture

Gas phase

pi

Condensate phase

C?

B

Zone A

Pressure

pd

pw Distance from hydraulic fracture Image Courtesy of Farhad Qanbari

Slide 20

Method: Iterative Integral  Application: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176)  Example 1: MFHW, tight (rich) gas condensate reservoir Single-phase gas Two-phase gas+condensate Three-phase gas+condensate+water Three phase + stress-sensitivity

(∆m)1P/qg/fc1P; (∆m)2P/qg/fc2P; (∆m)3P/qg/fc3P 106 psi2/cp/MMscf

14000 12000

(Ac√k)2P = 1.3 (Ac√k)1P (Ac√k)3P = 1.5 (Ac√k)1P

10000

Correction for condensate dropout Correction for water

8000 Correction for stresssensitivity of permeability

6000

4000 2000 0 0

5

10 15 20 Gas linear superposition time (√day)

25

30

Clarkson et al. (JNGSE, 2016)

Slide 21

Method: Iterative Integral  Calculation procedure: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176) Hydraulic fracture

Oil phase

pi

Gas phase

C

B

Zone A

Pressure

pb

pw Distance from hydraulic fracture Image Courtesy of Farhad Qanbari

Slide 22

Method: Iterative Integral  Application: model inversion - linear flow analysis (2P flow – JNGSE 2013; 2016 and SPE 167176)  Example 2: MFHW, tight oil reservoir 70 Single-phase oil Two-phase oil+gas

Δp/qo, (Δmo)/qo/fc2P; (Δmo)/qo/fc3P

60

Three-phase oil+gas+water (Ac√k)O+G = 0.97 (Ac√k)O (Ac√k)O+G+W = 2.67 (Ac√k)O

50 40 30 20 10 0 0

5

10

15 20 25 30 35 Oil linear superposition time (√day)

40

45

50

Image Courtesy of Farhad Qanbari

Slide 23

Method: Iterative Integral 3000

3

 Calculation procedure: model inversion - linear flow analysis 2-Phase boundary 2-Phase boundary confined Reservoir pressure path Critical point Critical point

2500

z bulk z confined

2.5 2

z-factor

Pressure, psia

(Pore confinement – SPE 171357 and 180264)

2000 1500

Square-root-time plot 1000

Stress sensitivity and adsorption layer

1.5 1

k ( pˆ )  Changes in gas ˆ  ( p )  d p  critical properties  p0  ( p ˆ ˆ ) B ( p ) g g    1  1  ( D )  ( D )[cg  cr  cd ] d D  f c 0 k ( D ) p

 ( pi )  ( pw )  m 500

0 -200 0.0095

f c qg

0.0085

t

0 200 CP100 o Temperature, F Bg bulk

0

300

0

0.035

Bg confined

µ bulk µ confined

4000 6000 Pressure, psia

8000

10000

0.03

Desorption

0.025

0.0065

0.02  Z i  gi  f c   0.015 0.0045 x f Confined  kai cti  ( pi )  ( pw ) Confined0.01 0.0035  0.005   x    fc 0.0025f Bulk gi 0 i  Z4000  0 2000 6000 8000 10000 0  kaiPressure,ctipsia ( pi )   ( pw )    Bulk

0.0055

2000

0.04

µ, cp

Bg, bbl/scf

0.0075

-100

0.5

2000

4000 6000 8000 Pressure, psia Clarkson et al. (JNGSE, 2016)

10000

Slide 24

Method: Dynamic Drainage Area  Calculation procedure: model inversion - linear flow analysis (2P flow – SPE 180230) Hydraulic Fracture

ye1

S o ,invS2 o ,inv1

pinv pinv 1 2

yinv1

yinv2

Slide 25

Method: Dynamic Drainage Area  Calculation procedure: model inversion - linear flow analysis (2P flow – SPE 180230) m g ( pinv )  m g ( p wf )

 gD ( pinv ) D ( pinv )ctD ( pinv )

qg

k D ( pinv )



576.56T

t

Ac ki

i  gicti

4 x ft yinvh  i S gi  ( pinv ) S g ,inv  ( pinv ) S o,inv  i S oi   Gp   Rsi   Rs ( pinv )  1000  Bgdi 5.615Boi Bgd ( pinv ) 5.615Bo ( pinv ) 

yinv  

ki t i i cti

 An approximate semi-analytical/empirical method  Uses boundary-dominated solution for transient flow Slide Courtesy of Farhad Qanbari

Slide 26

Method: Dynamic Drainage Area  Calculation procedure: model inversion - linear flow analysis (2P flow – SPE 180230)  An iterative process  Time instead of superposition time  Average pressure instead of initial pressure

 Coefficient of linear flow equation is different

f (A√k)

m g ( pinv )  m g ( p wf ) qg

 t

A√k

Slide Courtesy of Farhad Qanbari

Slide 27

Method: Dynamic Drainage Area  Application: model inversion - linear flow analysis (2P flow – SPE 180230)  Example 1: MFHW, wet gas reservoir (CGR=20 STB/MMscf) 3000

3000

(a)

2000

2000

1500

1500

1000

1000

500

500

0 0

pwf (psia)

2500

qg (Mscf/Day)

2500

0 200 400 600 800 1000 1200 Time (days) Gas Rate - Field Fata

Flowing Bottomhole Pressure

SPE 180230

Slide 28

Method: Dynamic Drainage Area  Application: model inversion - linear flow analysis (2P flow – Gas Rate (Mscf/Day)

3000 180230) SPE

5000

2000 1500 1000 500

0 0

500 Time (days) Gas Rate - Field Fata

1000

DDA-Corrected Gas RNP (psi2/cp/scD)

 2500 Numerical history-match and DDA-corrected linear flow plot 4000 3000 2000 1000

Gas Rate - Numerical Simulation

Parameter Total Ac√ki – numerical simulation Total Ac√ki – DDA-corrected linear flow plot

0 0

10 20 √Time (√day)

30

RC1 8200 7400 (10%) Slide 29

Method: Dynamic Drainage Area  Application: model inversion - linear flow analysis (2P flow – SPE 180230)

3000

3000

2500

2500

2000

2000

1500

1500

1000

1000

500

500

0

0 0

100 200 300 400 Time (days) Gas Rate - Field Fata Flowing Bottomhole Pressure

pwf (psia)

Gas Rate (Mscf/Day)

(a)

Condensate Rate (STB/Day)

 Example 2: MFHW, gas condensate reservoir (CGR = 100 STB/MMscf) 500

400 300 200 100

0 0

100

200 300 Time (days)

400

SPE 180230

Slide 30

Method: Dynamic Drainage Area  Application: model inversion - linear flow analysis (2P flow – SPE 180230) 3000

(a)

2500

2500

2000

2000

1500

1500

1000

1000

500

500

0

0 0

100 200 300 Time (days)

400

Gas Rate - Field Fata Gas Rate - Numerical Simulation

Condensate Rate (STB/Day)

Gas Rate (Mscf/Day)

3000

Well Bottomhole Pressre (psia)

 Numerical history-match 500

(a)

400 300 200 100 0 0

100

200 300 Time (days)

400

Condensate Rate - Field Fata Condensate Rate - Numerical Simulation SPE 180230

Slide 31

Method: Dynamic Drainage Area  Application: model inversion - linear flow analysis (2P flow – SPE 180230)  DDA-corrected gas linear flow plot DDA-Corrected Gas RNP (psi2/cp/scfD)

500 400 300

200 100 0

Parameter 0 10 20 √Time (√day) Total Ac√ki from numerical simulation Total Ac√ki from DDA-corrected linear flow plot

RC2 23500 26200 (12%) Slide 32

Method: Dynamic Drainage Area  Calculation procedure: long-term forecasting (2P flow – SPE 175929) Hydraulic Fracture

ye1

S o ,invS2 o ,inv1

pinv pinv 1 2

yinv1

yinv2

Slide 33

Method: Dynamic Drainage Area  Calculation procedure: long-term forecasting (2P flow – SPE 175929) qo 



ki h mo ( pinv )  mo ( p wf )



 2  y  141.2 oi Boi   inv     x ft 





Rv ( p wf ) ki h m g ( pinv )  m g ( p wf ) 1000



 2  y  1424T   inv     x ft 

 S i S gi ( pinv )S g ,inv  ( pinv )So ,inv i oi  N p  qo t  4 x ft yinvh  Rvi 6   Rv ( pinv ) 6  5.615Boi 10 Bgdi 5.615Bo ( pinv ) 10 Bgd ( pinv )  

 

+ analogous equations for gas… Pseudopressure calculations require S-P relationships – used empirical approach Slide 34

Method: Dynamic Drainage Area  Application: long-term forecasting (2P flow – SPE 175929)  MFHW, tight gas condensate reservoir 4000 200 Gas Rate Condensate Rate -- Field Field Data Data BHP Condensate Rate - DDA

1800 16000 1600 14000 1400 12000 1200 10000 1000 8000 800 6000 600 4000 400

(MSTB/d) Condensate Gas (MMscf) Cumulative Cumulative

(psia) (STB/d) RateBHP Rate (Mscf/d), Gas Condensate

18000 2000

Gas Rate - DDA

2000 200 00

Gas Rate - Field Data

180 3500 160 3000 140 2500 120

Gas Rate - DDA

2000 100 80 1500 60 1000 40 500 20

Condensate Rate - Field Data Condensate Rate - DDA

00 00

200 200

400 600 400 600 Time(day) (day) Time

800 800

1000

00

200 200

400 600 400 600 Time(day) (day) Time

800 800

1000

Slide Courtesy of Farhad Qanbari

Slide 35

Method: Dynamic Drainage Area  Calculation procedure: flowback forecasting (2P flow – URTeC 2460083) Flow-Period Flow Period

Illustration of Flow-Periods Flow Periods

wf Swi,f Flowback: Soi,f Flowback: Before Before Breakthrough Breakthrough pi,f ofof Formation Formation Fluids Fluids xinv1inin (single-phase (single-phase flow flow fracture) fracture)

ye X-Section X-Section View View Swi,m Soi,m pi,m

Flow-Regimes

Plan Plan View View

Element of symmetry

transient/depletion Depletion (Fracture)

xf

yinv1 yinv2

(Sw,inv,f)1 (So,inv,f)1 (pav,inv,f)1 Flowback/Early Flowback: Production: Breakthrough After Breakthrough of of Formation Formation Fluids Fluids (multi-phase (multi-phase flow flow in in fracture, fracture, single single or or multi-phase multi-phase flow flow in in formation) formation)

Source: Clarkson et al. (URTeC 2016)

(Sw,inv,m)1 (So,inv,m)1 (pav,inv,m)1

(Sw,inv,f)2 (So,inv,f)2 (pav,inv,f)2

(Sw,inv,m)2 (So,inv,m)2 (pav,inv,m)2 transitional/linear Transitional

Slide 36

Method: Dynamic Drainage Area  Application: flowback forecasting (2P flow – URTeC 2460083)  MFHW, tight oil reservoir 10000

10000

1000

8000

100

6000

10

4000

1

2000

0.1

Pwf (psia) and GOR (SCF/STB)

Gas (Mscf/D), Water and Oil (STB/D) Rate

Fluid Production Rates

0 0

2

4

6

8

10

12

Time, days Water Rate

Oil Rate

Pwf

GOR

From Clarkson et al. (TLE, 2014)

Gas Rate

Slide 37

Method: Dynamic Drainage Area  Application: flowback forecasting (2P flow – URTeC 2460083)  MFHW, tight oil reservoir 600 3000

b) b) b)

a)a) a)

1.28 1.2 7 11

2500 500

6 2000 400

Npp (MSTB) G (MMscf) Wp (MSTB)

q (STB/day) (STB/day) qgo w(Mscf/day)

0.8 0.8 5

1500 300

4 0.6 0.6

1000 200

0.4 0.4 2

500 100 0 0 0 0

3

0.21 0.2

2 2

4 6 4 Time (day) 66 (day) Time (day)

Water rate - field data Gas -- field data Oil rate rate field data

8 88

Water rate - DDA Gas - DDA Oil rate

10 10 10

0 00 0 00

2 22

4 6 44 Time (day)66 Time(day) (day) Time

Cumulative - fielddata data Cumulative water gas field oil - -field data

8 88

10 10 10

Cumulative water - DDA Cumulativeoil gas - DDA Cumulative - DDA

Slide 38

Special Application: Fracture Height  Concept  With known initial compositions of two layers (target and bounding), it is possible to estimate penetration height ratio (h1/h2) based on the short-term flow rate and composition of the production stream

Impermeable Layer Source: Ghaderi and Clarkson (JNGSE, in press)

Slide 39

Special Application: Fracture Height  Calculation procedure:  Writing material balance for each individual component, it can be concluded that:

It is important to find a proper average pressure to evaluate these properties for each layer with different composition

Source: Ghaderi and Clarkson (JNGSE, in press)

Slide 40

Special Application: Fracture Height  Calculation procedure: Behmanesh (2014) proposed the following relationship for average pressure:

It is possible to show that the above equation is equivalent to:

If we make the equation more general we can it use more efficiently:

Source: Ghaderi and Clarkson (JNGSE, in press)

Slide 41

Special Application: Fracture Height  Comparison with numerical simulation: τ = 0.80 84.00

12

83.40

83.80

η, mole percentage

83.60

h2/h1 (Analytical)

η, mole percentage

83.80

10

83.20 83.00

8

82.80 82.60

6

82.40 82.20

4

83.60 83.40 83.20 83.00 82.80 82.60

Config. I

82.40

Config. II

82.20

82.00

0

84.00

y = 1.0017x - 0.0008 R² = 0.9924

Config. III Config. IV

82.00 5

2

10

15

20

25

0

Time, day

5

10

15

20

25

Time, day

0 0

2

Source: Ghaderi and Clarkson (JNGSE, in press)

4 6 8 h2/h1 (Simulation)

10

12

Slide 42

Future Work  Continue development of multi-phase RTA analysis, including improvement of our previous work on boundarydominated flow (FMB; SPE 169515)  Incorporation of fluid chemistry (e.g. salinity) into the analysis  Extension of methods to account for inter-well/stage communication

 Application of fracture height-growth method to field data Slide 43

Conclusions  Conventional RTA methods use simplified solutions that do not capture the physics of flow and storage in unconventional reservoirs  Our research group have applied 3 different approaches (pseudovariables, interative integral, dynamic drainage area) to account for unconventional reservoir complexities  These approaches have been successfully applied to extract reservoir and hydraulic fracture information from multi-fractured horizontal wells producing from tight oil/gas condensate reservoirs Slide 44

Acknowledgements  AITF, Encana, Shell  TOC sponsors  Students  NSERC CRD program  SPE

Slide 45

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