Transcript No Slide Title

Laboratory MR Measurements
®
and MRIL Integration
by
Dave Marschall
1
Crucial Formation Evaluation
Questions
• What is the storage capacity (e and t ) in a Complex
Lithology Environment ?
• Are there hydrocarbons,
 what types of hydrocarbons and,
 how are they distributed?
• What is the permeability (deliverability)?
• Will the formation produce water free? (what is
irreducible saturation (BVI))
MRIL answers them all
2
Magnetic Dipole
H
Proton
Hydrogen
NMR works with Protons - Hydrogen -> H2O and CxHy+++
Random Orientation in Natural State
N
S
N
N
S
S
N
Bo
S
t =0
Magnetization Buildup
N
N
S
N
S
N
S
Bo
S
M
N
S
Wait time (sec)
Bo=External Field
M=Bulk Net Magnetization
t = 0.75 sec
Buildup at 95 % polarization
N
N
S
S
N
N
N
S
S
N
S
N
Bo
N
S
S
N
S
N
S
N
N
S
M
S
S
Wait time (sec)
Bo=External Field
M=Bulk Net Magnetization
t = 6.0 sec
Oilfield MRI
(Relaxation Time Spectrum)
Solids….invisible to MRI
Fluids
irreducible
rock matrix
dry clay
clay bound
movable
water
hydrocarbon
clay bound
T2 relaxation times
the measurement
T1 Magnetization
no measurement
0
1
2
3
4
5
6
time, sec.
8 9 10
11
12
13
14 …….
7
T1 build-up and T2 decay
ML
B0
MT
T1
Magnetization
T2
T1 characterizes the rate at which longitudinal magnetization builds up
T2 characterizes the rate at which transverse magnetization decays
8
NMR Experiment Timing
M ||  1  exp  time / T1 
Mo
T1 = 400 msec
M || to Bo
(longitudinal
component)
0
M^  exp time / T2 
TW
Mo
T2 = 250 msec
M ^ to Bo
(transverse
component)
0
TE
B1
TX
RF field
0
0
0.5
1.0
adapted from Murphy, D.P., World Oil, April 1995
1.5
2.0
2.5
3.0
time, seconds
3.5
4.0
4.5
5.0
9
MRIL-Prime is
Fast
Series C senses two fluid volumes
PRIME senses nine fluid volumes
4X Fluid Volume = 4X Speed
NUMAR Corp., 1995
10
Measured signal decay
Amplitude = Porosity
35
Amplitude (pu)
30
25
20
Decay rate (1 / T2) =>
rock & fluid information
15
10
5
0
0
50
TE
100
150
200
250
300
time (ms)
11
3 Relaxation Mechanisms
Echo Amplitude vs Time
Effect of Each
Mechanism is Additive
Amplitude
1
1
1
1



T2 T2 B T2 D T2 S
Bulk Relaxation - T2B
Intrinsic Property of fluid
Diffusion - T2D
Molecular Movement
Surface Relaxation - T2S
Pore-walls cause rapid dephasing
Time, msec.
12
Pore Size and T2 (Water)
1
T2
 2 S
V
T2 = relaxation time
constant.
S = surface area of
the pore.
V = volume of
the pore.
T2
time
T2
time
T2
time
T2
time
2 = relaxation rate
constant.
T2
time
13
Data Processing Inversion
MAP
“Inversion”
Processing
Spin-echo data
T2 Spectrum “Best Fit”
15
Incremental Porosity [pu]
35
30
25
20
15
10
5
0
50
100
150
200
250
300
T2i are pre-selected:
T2i = 4, 8, 16, 32, 64, 128, 256, 512, 1024...
12.0
10
6.0
5.0
5
3.0
4.5
2.0
0.5 0.5
0
0
FFI
BVI
1
10
100
1000
T2 [ms]
Water-saturated rock: T2 = V/S
NUMAR Corp., 1995
10000
Depth
0
8
-100
100
XX200
Gamma Ray
(GAPI)
Caliper (in)
150 0.2
18 0.2
SP (mv)
100
Bins 1 - 8 (PU)
0
20
Shallow
Resistivity
Deep
Resistivity
Permeability
(md)
20
20 2
20
2000
T2 Distribution
Variable Density 2048
(milliseconds)
60
Density Porosity
0
60
Neutron Porosity
0
60
60
BVI
0
Effective Porosity 0
Laboratory MRI - Textural
Properties
3.2
Relaxation Time (T2), msec.
2.4
% Clay
1.6
Delta MPHI
0.8
Kair, md
0
3.2
2.4
1.6
1.2 Te
0.6 Te
0.8
0
0.1
3.2
1
10
100
1000
Relaxation Time (T2), msec.
10000
2.4
1.6
0.8
0
17
1
10
100
1000 10000
NMR - Porosity Model
Integration of MR Log and
Resistivity Log
Interpretation
NMR
BVI
hydrocarbons
movable
water
capillary
bound water
BVI
rock matrix
clay
matrix
clay bound
water
Neutron 
Density 
Resistivity Sw
NMR FFI
MR porosity
(effective)
MR porosity
(total short TE)
nonmovable
water
Producible
hydrocarbon
will produce some
water
18
Suitable Sample Types
• Rock Sample
–
–
–
–
Conventional Core
Rotary Sidewall
Cuttings
Percussion Sidewall
Cuttings and Percussion Sidewall have
some limitations to their ability to
represent some petrophysical parameters.
• Fluid Samples
– Oils
– Gas/Condensate
– Brines
19
Example Lab Program
Pre-clean and dry
Sample Preparation
Trim, clean, and dry
Fresh State -OB mud
Sample Preparation
Trim, measure
bulk volume
Determine Routine
Properties, K, Por.,
Grain Density
MRI on Fresh sample
Dean Stark for Swi
Resaturate Sample
to 100 % Sw
Lab MRI @ 100 % Sw
Desaturate the sample
to a capillary pressure
that = non movable
saturation
Clean and dry the sample,
measure routine
properties, K, Por., and
Grain Density
Optional
Lab MRI @ Swi
Develop Interpretation Model
20
Porosity Comparison:
Lab MRI (MPHI) vs Core
20
MPHI 1.2 TE
18
MPHI 0.5 TE
16
y=x
= +/- 1 p.u.
MPHI, %
14
12
10
8
6
4
2
0
0
2
4
6
8
10
12
Core Porosity, %
14
16
18
20
21
Standard Method to
Determine BVI
2.00
Bulk Volume
Irreducible
(BVI)
Incremental Porosity, %
1.80
1.60
Free Fluid
Index
(FFI)
1.40
1.20
Standard Fixed T2 cutoff
Relates to a capillary
pressure or pore radius
1.00
0.80
Relaxation
time
distribution
0.60
0.40
0.20
0.00
0.1
1
10
100
1000
10000
T2 Relaxation time, msec.
A Subsidiary of
HALLIBURTON ENERGY SERVICES
22
Effect of Air/Brine Desaturation
on T2 Distributions
Dominated by
Surface Relaxation
Mechanism
1.6
1.4
1.2
1
S
 2
T2
V
1
0.8
0.6
0.4
0.2
6309.6
100% Brine saturated
2511.9
1000.0
398.1
Relaxation Time (T2), msec.
158.5
63.1
25.1
After air/brine 100 psi
10.0
4.0
1.6
0.6
0.3
0
0.1
Incremental Porosity, p.u.
Sample 98
23
Lab Determination of Cutoff T2
25
100% Saturated
cumulative
incremental
FFI
1.5
After Pc to Swi
cumulative
incremental
1
0.5
15
10
Cumulative Porosity, %
20
MRI Porosity
2
BVI
Incremental Porosity, %
2.5
5
0
0
0.1
1
10
100
1000
10000
Relaxation Time (T2), msec.
24
Variation in T2 Cutoff Values
T2 - Cutoff
1
10
100
0
Sample Number
5
10
15
20
25
25
T2, Cutoff T2 and Pore Size
MRI Relaxation Time (T2) &
Surface to Volume Ratio
Capillary Pressure (Pc) &
Pore Throat Radius (r)
Since S/V of a capillary
tube = 2/r then;
1/T2 = 2 S/V
Pc =cos 2/r
1/T2  2 2/r
Since T2 is related to Pore Size & S/V:
• then T2 is directly proportional to K,
• and T2 is inversely proportional to Swi
26
T2 Cutoff Related to Pc
Bore hole
350
Rock Type A
Rock Type B
B
A
B
300
250
200
150
A
100
Equivalent T2
cutoff @ 50 psi
Free Water Level
50
0
2
4
6
8
10
Bulk Volume Water, %
0
12
27
Capillary Pressure , psi
Height Above Free Water, ft.
400
Spectral BVI Model
1.0
1.0
0.9
0.9
0.8
0.8
BVI
0.7
FFI
0.7
0.6
0.6
0.5
0.5
SBVI Model:
a step function
0.4
0.3
0.4
0.3
0.2
0.2
0.1
0.1
0.0
0.0
10000
0.1
1.0
10
100
1000
Spectral Fraction
Normalized Incremental Porosity
standard cutoff model
Relaxation Time (msec.)
28
SBVI Model Linked to
Permeability Equations
Given:
K1/2 = 1002 (FFI/BVI)
K1/2 = 4
2
T2GM
Substituting:
(1-SWIRR) for FFI
SWIRR for BVI
Equating the two
equations gives:
1-SWIRR
SWIRR
1
SWIRR
= 0.04 T2GM , or
= 0.04 T2GM + 1
Coates equation becomes: The empirical form is:
K1/2
=
1002
1-SWIRR
1
SWIRR
SWIRR
= mT2GM + b
29
Lab Method to Determine SBVI
Swi (Core), frac.
1
Core Swi vs T2
0.8
0.6
SBVI = 1/((0.0243 T2) + 1)
0.4
0.2
0
0
8
1/Swi (Core)
• Correlate Core Swi and T2
• Compute fraction for each
T2 Bin
50
100
150
200
T2, Geometric Mean, msec.
SBVI - Slope Determination
7
6
5
4
y = 0.0243x + 1
R2 = 0.89
3
2
1
0
20
40
60
80
100
120
140
T2, Geometric Mean, msec.
Bin #
1
2
3
4
5
6
7
8
9
10
T2 time BVI Fraction
2
4
8
16
32
64
128
256
512
1024
0.919
0.849
0.738
0.585
0.414
0.261
0.150
0.081
0.042
0.022
30
BVI Model Comparison
100
100
Cutoff T2
80
80
70
70
60
50
40
30
60
50
40
30
20
20
10
10
0
0
0
10 20 30 40 50 60 70 80 90 100
Core Swi
SBVI Model
90
Swi from SBVI
Swi from cutoff T2
90
0
10 20
30
40
50 60
70
80
90 100
Core Swi
31
NMR Adds Surface Area
Ability to Determine Swir
· Three Mechanisms Control Transverse Relaxation Time
(T2)
 Bulk Relaxation
 Diffusion
 Surface Relaxation
· Surface Relaxation
 It is the dominating mechanism in porous media (for the wetting
fluid - assumed to be water)
 Controlled by surface area and pore structure
1
S
 2
T2
V
where:
2
= relaxivity, m/sec.
S/V
= surface area to
pore volume ratio
33
Predicting K with NMR
The surface relaxation mechanism provides
the relationship of T2 to radius and K:
1
S
 2
T2
V
1
2
 2
T2
r
From Kozeny estimates of kzSp are given
by T2 as follows:
K

kz S
2
p
K  CT 
2 4
2
However, this model is representative of pores
with a single fluid.
34
Predicting K with NMR

1 V
T2 
K
2
2 S
kz S p
FFI
BVI
bulk volume irreducible
free fluid in dex
T2 and K are directly proportional
V
FFI
1


S
BVI
Sp
K and T2 are inversely
proportional to Swir
     FFI  

K    

  C   BVI  


2
0.1
1.0
10
100
1000
Relaxation Time (T2), msec
10000
2
Where C is similar to KZ in the
Kozeny equation and is a
function of the pore geometry.
36
Predicting K with NMR
Pores with two nonmiscible fluids
·
 Geometric mean values
are influenced by the
nonwetting fluid.
Nonwetting
fluid
100% brine
air/brine
crude oil/brine
For Two Fluids
K  CT 
2
2
4
 Model is not correct
Geometric mean 100% brine
Geometric mean oil/brine
·
Relaxation Time Cutoff
Determines Swir or BVI
0.1
1.0
10
100
1000
Relaxation Time (T2), msec
10000
The wetting fluid is
dominated by Surface
Relaxation
 the wetting fluid has short
T2 times, thus cutoff T2’s
can be used to estimate
BVI
37
Lab Evaluation: Permeability Model
Free Fluid (Coates)
Model:
2
2


K      FFI

C
BVI




C is a variable and can
be represented as a line
function:
y  Cx  b
1.8

1.6
1.4
FFI BVI 

2
The equation becomes:
FFI BVI   C
4
K   b

1.2
1
0.8
C = 6.2
0.6
0.4
0.2
0
0
0.05
0.1
4
0.15
0.2
0.25
Coreperm
MPHI
38
0.3
Coates Model for a Tight Gas Sand
Permeability Model
Coates Model
Cotton Valley Formation
3.0
2.5
2.0
1.5
y = 23.921x
1.0
2
R = 0.7538
0.5
0.0
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
0.1
CPERM^0.25/MPHI
39
T2Sb K Model Tight Gas Sand
T2Sb max
Cotton Valley Formation
1
y = 3E-07x
2.1688
2
R = 0.9104
0.1
0.01
0.001
0.0001
10
100
T2Sb
1000
40
How Do the Models Work?
Permeability Comparisons
Cotton Valley Formation
100
10
Free Fluid
T2SB
Standard
y=x
=/-50%
1
0.1
0.01
0.001
0.0001
0.00001
0.0001
0.001
0.01
0.1
Core Permeability, md
1
10
100
41
0
0
0
0
0
0
Cooper Basin Low Porosity Example
X500
X600
0
6
BVID
10
GR
LLD
PDSS
PMRI
200 0.2
2000 0.01
1000 30
PNSS
CALI
LLS
MPERM
16 0.2
2000 0.01
1000 30
MSFL
PMRIC
SBVI
0.2
2000 0.01
1000 30
MPHI
30
CBVI
30
CBVWE
30
0
44