Fractured Reservoirs Part 2b

7/28/2019 Fractured Reservoirs Part 2b

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Part 2 How to Characterize a Fractured Reservoir?

Hydraulic characterization

How to characterize a fractured reservoir?


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Hydraulic characterization

Outcrops

Seismic facies analysis

Wireline Logs

Core data

Image Logs

Mud Losses

Transient well tests

Curvature analysis

Dynamic analysis

Well data Inter-well data

Static analysis

Production data

Drilling reports,

Pressure data,

Tracer tests, etc

Flowmeter

Simulation grid Block

4

Full field simulation

Fracture Up-scaling

Equivalent parameters

(Kfx, Kfy, Kfz, a, b, c, ff)

3

DFN model

(Discrete fracture model)

2

Log-Logplot

Static & dynamic calibration

HOW TO MODEL A

FRACTURED

RESERVOIR ?

1

Locallyconnected fractures

Regionaldiffuse fractures

Locallyconnected fractures

Regionaldiffuse fractur

es

Conceptual model


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OBJECTIVES: Estimate the impact of natural fractures on fluid flow Validate the fracture network geometry

Determine the distribution of fracture conductivities

Estimate the fractures aperture

APPROACHES: Conventional dynamic data analysis

Flow simulation of well tests and/or flowmeters in the discrete

fracture network models and comparison/tuning to actual well

test results

History match using a full field model

Hydraulic characterization of fractures


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Useful data for hydraulic characterization

Drilling reports: mud losses and rate of penetration

Well testing:

Drawdown, bui ldup: equivalent permeability, dual-medium parameters (l, w) Interference: flow anisotropy

Tracer in ject ion: main flow paths, block size (single well test)

Production logs (flowmeters, TC):

Location of conductive fractures, conductivity

Production history:

Maps of PI and II: correlation with the density of conductive fractures

Pressure maps: idem + communication between panels (sealing faults)

WOC maps (evolution): conductive sub-seismic faults and fracture swarms

Individual wells water-cut/GOR evolution with time


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Example 1

Mud losses due to conductive joints

Mud losses at a depth where GR is higher than 70 APIConductive or resistive joints

Mud losses due to resistive joints

Fracture characterization using mud losses


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Example 2

Fracture characterization using mud losses

1300 ft (400 m)

100% loss

100% loss

100% loss

3% loss

Highest fracture density

250 m


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Fracture characterization using well tests

Transient well test signature

Specific signatures are expected in a fractured reservoir:

- large wellbore storage

- fracture corridor

- hydraulic fracture

- constant pressure boundary

- Dual porosity signature

Transient well test parameters: Equivalent permeability (KH)

Dual-medium parameters (, )

Conductivity of the fracture crossing the well

Distance between the well and the fracture swarm / fracture network / fault


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Build-up

- -3 0 .0 1 0 .1 1 1 0 1 0 0 1 0

10 0

1 0 0 0

0 0 0 0

Semi-log plot - Horner plot Log-log plot

Transient well tests analysis


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KH_2000

KH_500 (ref )

KH_1000

Log-Log plot

KH_2000

KH_500 (ref)

KH_1000

Semi-Log plot

History plot

Kh = 2000 mD.ft

Kh = 500 mD.ft

Kh = 1000 mD.ft

KH impact on well test plots


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1Part 2 How to Characterize a Fractured Reservoir?

History plot

Log-Log plotSemi-Log plot

C = 0.001 bbl/psi

C = 0.1 bbl/psi

C = 0.01 bbl/psi

Wellbore storage effect

Th L l l t i t t ti


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The Log-log plot interpretation

t (log scale)

Pressure(logsca

le)

Skin

K.H

C (= fluid in well compressibility . wellbore volume)

Well Bore Storage

Radial Flow

K.H

Large StorageSmall Storage

Large Skin

Small Skin

Horizontal Slope

Pressure curve

Derivative curve

Homogeneous reservoir, WBS + Skin

T i t ll t t l i


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Transient well tests analysis

Log-Log plot Log-Log plot

Homogeneous reservoir Fractured reservoir

2

w

f

m

tmmtff

tff

rk

k

CC

C

l

ff

fw

Omega: storativity ratio the fraction of the pore volume occupied by the fissures to the total

interconnected pore volume.

Lambda: interporosity flow parameter the ability of the matrix to flow into the fissure network.

T i t ll t t i F t d i


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Transient well tests in Fractured reservoir

First radial flowFractures only

K.H fracture

Matrix starts flowing

=> Pressure support

=> Derivative curve decreases

Second Radial Flow

Final Steady state Flow in Matrix & Fractures

K.H (Matrix + Fracture) ~ K.H fracture

T2(Begining 2

nd

R.F.)

T1(End 1

st

R.F.)

TAft(End WBS)

decreases

(block size increases &/or km decreases &/or kf increases)

decreases

(m&/o

rCtmincreases)

Dual porosity signature



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2

w

f

m

tmmtff

tff

r

k

k

CC

C

l

ff

fw

Log-Log plot

w=0.1

l=10-6 l=10-7 l=10-8

Kfrac.h

w=0.1




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2

w

f

m

tmmtff

tff

rk

k

CC

C

l

ff

fw

History plot

Log-Log plot

l=10-7

w=0.1

w=0.5

w=0.01

Semi-Log plot

w=0.1w=0.5

w=0.01



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tmmtff

tff

CC

C

ff

fw

Omega: if Ctf= Ctm, then Omega gives an estimation of the percentage of pore volume present

in the fracture network.

Lambda:

is the Warren & Root shape factor (also called sigma)

Between 10-3 and 10-10. If Lambda is higher, the level of heterogeneity is usually too

small for the dual porosity effects to be of importance.

Example:

rw=8.5/2=0.354 feet

Km=10mD

Kf=1.0 D

= 32/L2 = 0.889 (1 fracture every 6 feet)

Lambda = 1.1 10-3

2

w

f

m

rk

kl

One well test several matched model


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Log-Log plot

Log-Log plot

Model :Well : Storage + skin

Reservoir : Homogeneous

Boundary : One sealing fault at

800 ft

Kh = 563 mD.ft Skin = 0

Model :Well : Storage + skin

Reservoir : Two porosity - sphere

Boundary : Infinite

Kh = 292 mD.ft Skin = -3.7

Radial flow periodRadial flow period

One well test, several matched model



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Match obtained withl=10-7 &w=0.01

Log-Log plot

Match obtained withl=8.10-8 &w=0.117

Wellbore storage can make the finding of the dual-porosity parameters a very difficult task!


Influence of wellbore storage

Log-Log plot

Well tests in Fractured reservoir


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Influence of Wellbore storage Phase redistribution effect

Changing wellbore storage

Log-Log plot

Dual mediaOmega 0.0275

Lambda 0.0693

Log-Log plot

Increasing wellbore storageCi/Cf = 0.39



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Conductive fracture at well

Log-Log plot: dp and dp' [psi] vs dt [hr]

Slope between 0.5 (CDf= 0) and 1

The productivity of fractured wells is so high that wellbore storage isnt seen in

most cases.!



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Log-Log plot

Selected ModelModel Option Standard Model

Well Uniform Flux

Reservoir Two Porosity PSS

Boundary Intersecting Faults

ResultsC 0.0612 m3/bar

Skin 0 --

Xf 12.8 mk.h 8.13 md.m

Omega 0.146 --

Lambda 0.00656 --

L1 - Constant P. 18 m

L2 - Constant P. 30.9 m

N 2 --

Log-Log plot


Well Storage + Skin

WBS Type Changing

Reservoir Homogeneous

Boundary Circle

ResultsC 0.555 m3/bar

Ci/Cf 0.189 --Alpha 214 --

Skin -1.65 --

k.h 20 md.m

Re - No Flow 130 m

Hydraulically fractured well (gas field)




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Log-Log plot

Gas field - Europe


Well Storage + Skin

WBS Type Changing

Reservoir Two Porosity PSS

Boundary Circle

Results

C 2.28E-7 m3/Pa

Ci/Cf 2.25 --

Alpha 8830 --

Skin 2.33 --Delta P Skin 30.4574 bar

Pi 387.101 barak.h 6.26 md.m

k 1.25 md

Omega 0.0201 --

Lambda 1.16E-5 --

Re - Constant P. 52.4 m

Constant pressure

boundary at 50 m


Transient well tests in fractured reservoirs


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Comparison KHtest Vs KHmatrix

KHmatrix estimated from core or from synthetic permeability log

The principal difficulty is to estimate H

1

10

100

1000

10000

100000

1 10 100 1000 10000 100000

KHmatrix (mD.m) from synthetic permeability log

KHtest(mD.m

)fr

om

transientwelltestsinterpertation



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Change of KHtest with stimulation

Can indicate the presence of nearby heterogeneities

0

500

1000

1500

2000

2500

0 500 1000 1500 2000 2500

KH test before hydraulic fracture (mD.m)

KHtestafterhydraulicfracture(mD.m

KHtestafterhydraulic

stimulation(mD.m

)

0

500

1000

1500

2000

2500

0 500 1000 1500 2000 2500

KH test before hydraulic fracture (mD.m)

KHtestafterhydraulicfracture(mD.m

KHtestafterhydraulic

stimulation(mD.m

)



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Comparision between KHtest and distance to nearby faults

Can indicate the presence of fracture corridors

Vertical wells drilled in the area covered by the 3D seismic

0.1

1

10

100

0 200 400 600 800 1000 1200

Distance between wells and the closest fault / lineament (m)

KHtest/KHmatrix(mD.m

)



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What can be expected from well test analysis in a fractured

reservoir ?

Skin: fracture connectivity, damage of mud losses

Dual porosity signature: w, l Direct measurement of fracture conductivity

Reservoir KH

Constant pressure boundary: presence of conductive fault/swarm,

distance to this fault/swarm

No flow boundary: width of fractured zone, presence of a sealing fault,

distance to this fault

y

Fracture characterization using flowmeters


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Correlation between fracture density and flowmeter data

Determination of conductivity using flowmeter data

Hydraulic characterization use of flowmeter data


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Well fracture log

Depth 5

Depth 4

Depth 3

Depth 1

Depth 2

N60

N150

N100

N100

Well production log

Dynamic fracture characterisation Qualitative estimation from PLT

Fault conductivity from flowmeter


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Presence of

a fracture

swarm



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Facies (KM)

Fracture density log

Flowmeter

0

100

M

M

FF K

QQLc

sub-seismic fault (SSF)

QF QM + QF

cF: fault conductivity

L: length of measurement (homogeneous facies)

KM: matrix permeability

QM: matrix rate

QF: fault rate



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CF ~ 70 Darcy.m


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Fracture characterization using history data


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Validation of a fracture network using:

well productivity data

water/gas production

breakthrough times

signature of water/gas production

Validation of fractures against dynamic data


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highly fractured

PI = 33

poorly fractured

Water at the last

500ft

moderatly fractured

PI = 22

High water cut

highly fractured

Up. Res PI = 78

Bot. ResPI = 79

non fractured

PI = 7

Seismic

facies

Influence of faults on well productivity


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Determination of the lineament influence zone in the WEST part of ZONE 1

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

0 200 400 600 800 1000 1200

Distance from the we ll to the lineament (m)

PI/LengthinAsmari(stb/d/psi/m)

N130

EW

3247200 3247200

3247800 3247800

3248400 3248400

3249000 3249000

3249600 3249600

511500

511500

512000

512000

512500

512500

513000

513000

513500

513500

514000

514000B61

B84

Validation of fractures: use of history data


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18

19

91

92

103

105

106

118

13942

304

318

319

320

316

132

Wet

Dry

Injectors

Fracture swarm and water breakthrough


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t

wcut

t

wcut

Well Well

Fracture swarmIncreasing Rate

Fracture swarm and water breakthrough


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Well near a fracture swarmWell far from a fracture swarm Well on a fracture swarm



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Simulation approach:

Simulate transient or steady-state well tests on the detailedgeological model incorporating fracture and sedimentological data

Tune fracture flow properties (conductivities) to match the

measured pressures (distribution of rates) conductive sets

If major discrepancies remain: re-analyse/change the geological

model (fracture attributes in relation with facies properties, faults, ...)

with the help of other information (production history, ...)

Advantages:a flow simulation model better constrained by the geology:

- higher reliability,- possibility of evolution

Well test simulation on a DFN


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Ref.:"Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models," S. Sarda,L. Jeannin, R. Basquet and B. Bourbiaux, SPE 66398, Res. Sim. Symp. 2001 (to be published in SPEFE)

Single-phase compressible flow of oil to well-bore :

from the matrix to the nearest fracture

through the fracture network to the well

The simulation model:

Explicit discretization of the fracture network (nodes and cells)

Aspecific matrix block assigned to each fracture cell

Pseudo steady-state M-F exchanges

Fracture cell definition


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Computation nodes

(intersections)

Fracture cell

Fracture cell limits placed at: - fracture extremities- mid points between two intersections

Matrix block determination


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XY

Matrix block

Fracture nodes

Fracture cell

Matrix-fracture flow transfers


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Pseudo-steady-state approach: flux is proportional to

pressure drop

M-F transmissivity Tmf:

no time dependence

dependence on the matrix block geometry

Assumption: the local matrix pressure varies linearly with

the distance to the nearest fracture.

)mfmf PTF

Well test in a dense fracture network


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400 m

Build-up test simulation


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Simulated pressure maps

T1

T1 (fracture-dominated)

T2

T2 (end of transition)

T3

T3 (pseudo-steady-state)

log(Dt)

dP/dt

P

Well test simulation in a 3D network


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WELL

Complex 3D fracture

network

Exact location of

well-fracture

intersections

Pseudo steady-state

matrix-fractureexchanges

Visualisation of rates

in fractures:

Increasing

rate

Hydraulic characterization - well test simulation


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Fracture sets conductivity determination through well test matching

well

Log-Log plot

History plot

Variable adjusted :

Conductivity Fracture length

of each fracture set

Complex well test match


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Log-Log plot

Constant pressure

boundary

(KH)2

(KH)1


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Fractured Reservoirs Part 2b

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