Deterministic Petrophysics
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Log Evaluation Workflow
Lithology
Clay Volume Estimation
Porosity Computation
Water Saturation Calculation
Fluid Zones
Permeability Determination
Net Pay / Net Reservoir Quantification
Reality check
2
Log Evaluation Workflow
• Lithology
• Clay Volume Estimation
• Porosity Computation
Reasons for iteration
New Well data
• Core calibration
• Water Saturation Calculation
New Production data
• Core derived parameters
• Comparisons with core
• Saturation-height
• Fluid Zones
• Fluids present
• Fluid contacts
• FWL
New core data
Part or Total iterations
Inconsistencies seen in
sense checks
Fluid samples
• Permeability Determination
• Core derived predictors
• Net Pay / Net Reservoir Quantification
• Reality checks
• Uncertainty Analysis
3
Problems in 3-D
modelling
Problems in
simulation
Log Evaluation Workflow: Reality Checks 1
• Look for consistency:
• Between parameters from different data types.
• Different data types may not all tell the same story but any conflicts
should be explained.
• Lithology, hydrocarbon shows and core data should be identified prior to
log evaluation.
• Lithology and Clay volume:
• Compare with clays and other minerals seen in core.
• Use core grain density as guide to main matrix material.
• Compare with core mineralogy (XRD, thin section).
• Porosity
• Porosity: Differences or similarity of different log porosities.
• Log to core comparison or calibration.
• Sense check magnitude of porosity.
4
Log Evaluation Workflow: Reality Checks 2
• Log derived water saturation should be compared with:
•
•
•
•
Capillary pressure curves.
Core fluid saturation measurements (Dean Stark).
DST and WFT samples.
Discrepancies may point to the need for modified interpretation.
• Log derived permeability should be calibrated to core data.
• Compare cumulative log permeability with production log inflow profiles.
• Compare permeability-height (KH) from log permeability with KH from well tests.
• Net Pay and Net Reservoir should be compared to permeability indicators
and core if available.
• Effective formation evaluation is a process of integration of different data
types in order to provide a robust interpretation.
5
Deterministic Petrophysics:
Lithology & Clay Volume
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Basic Interpretation Workflow Lithology Interpretation
├ The Gamma Ray log responds to natural radioactivity in rocks. Contrast
between sand and shale.
├ Exceptions: Feldspathic (potassium feldspars), micaceous, or glauconitic
sands will show an atypical, high gamma ray response. Source rock shales
can have very high GR values – often a characteristic of the Kimmeridge Clay
Formation in the North Sea.
├ Neutron and Density logs when run together are, by convention, displayed
with the curves superimposed in the same log track, on standard scales such
that curves overlay in water-bearing limestones. The curves shift according to
lithology and porosity.
├ Some minerals have characteristic D/N responses and cross-plots can be
used to determine these.
├ Calcite, Coal, Salt, Anhydrite, Gypsum etc
├ The photo-electric curve (PE or PEF) can also be used.
7
Typical Log Responses to Lithology and Gas
Density
Reservoir Rock
Neutron
Log response Decreases
with Increasing Porosity
Low
High
Limestone
(Reference)
2.71
g/cc
Sandstone
2.65
g/cc
Log response Increases
with Increasing Porosity
High
Low
≈ 0%
Log response Decreases
with Increasing Porosity
High
Low
47.5
us/ft
≈ 52.5 – 55.5
us/ft
Variable with
Compaction
≈ - 4%
2.83 to 2.87
g/cc
Dolomite
Sonic
≈ 42.5
us/ft
≈ 6 to 8 %
Non Reservoir Rock
2.98
g/cc
Anhydrite
2.33
g/cc
Gypsum
Salt
Shale
2.08
g/cc
≈ - (1 to 2) %
52
us/ft
48 %
67
us/ft
0%
Wide Range 2.3 –
2.7 g/cc Variable
with Clay Density
≈ 50
us/ft
Reads High
Increases with
Clay Bound Water
≈ 130 – 175 us/ft
Variable with
Compaction
Hydrocarbon
Gas Effect
8
Reads Low
Reads Low
Reads High
Lithology Example 1
Minerals Determined from
D/N Cross-plot:
41/8-2
DEPTH (2300.FT - 3000.FT)
DB : IPDB (4)
Plattendolomit
1.
ip:VSILT (Dec)
0.
ip:PHIE (Dec)
Anhydrite 
0.
ip:VSALT (Dec)
0.
1.
Roter Saltzon
coalflag ()
0.
2.
40
40
30
2.2
30
30
20
20
2.4
10
20
10
Basalanhydrit
StrassfurtDeckanhydrit
Halite
9
Hauptdolomit
Werraanhydrit
2900
40
SS 0
10
LS 0
2.8
DOL 0
(WA) Neutron Density Overlay, Rhofluid = 1.0 (Ch.6-42 1985)
3.
-0.05
0.05
0.15
0.25
0.35
Neutron
2800
Hauptdolomit

3.
2.6
2600
2700

1.
1.
Plattendolomit
2500
0.
Leine Halite
2400
Salt   Dolomite 
ip:VWCL (Dec)
Hauptanhydrit
DEPTH
raw :RD (OHMM)
CAL
ZDENds (G/CC)
0.
150. FT 0.2
2000. 6.16. 1.95
2.95
raw :SP (MV)
raw :RMLL (OHMM)
CNCds (dec)
-200.
200.
0.2
2000.
0.45
-0.15
BIT (FT)
ZCORds (G/CC)
5.
20.
-1.
0.25
raw :CAL (INCH)
ACds2 (US/F)
5.
20.
140.
40.
rftp (psia)
PEds (BARN)
1700.
2000.
0.
20.
07/03/2006 15:47
raw :GR (API)
Density
Scale : 1 : 1000
1319 points plotted out of 1334
Zone
Depths
(7) Leine Halite
2319.F - 2474.F
(9) Plattendolomit 2485.F - 2611.F
(10) Deckanhydrit 2611.F - 2654.F
(11) Strassfurt Halite
2654.F - 2657.F
(12) Basalanhydrit 2657.F - 2775.F
(13) Hauptdolomit 2775.F - 2994.F
0.45
FMT Gradient = 0.474 psia/ft . Sample results similar to mud filtrate.
Lithology Example 2
41/8-2
Scale : 1 : 1000
DEPTH (4300.FT - 5050.FT)
DB : IPDB (4)
Minerals Determined from
D/N Cross-plot:
07/03/2006 16:02
raw :GR (API)
DEPTH
raw :RD (OHMM)
CAL
ZDENds (G/CC)
2000. 6.16. 1.95
2.95
FT 0.2
raw :SP (MV)
raw :RMLL (OHMM)
CNCds (dec)
-200.
200.
0.2
2000.
0.45
-0.15
BIT (FT)
ZCORds (G/CC)
5.
20.
-1.
0.25
raw :CAL (INCH)
ACds2 (US/F)
5.
20.
140.
40.
rftp (psia)
PEds (BARN)
1700.
2000.
0.
20.
0.
ip:VWCL (Dec)
150.
0.
1.
ip:VSILT (Dec)
0.
1.
ip:PHIE (Dec)
1.
0.
ip:VSALT (Dec)
0.
Limestone
1.
coalflag ()
0.
3.
Claystone-sandstone
4400
Interval : 4200. : 5100.
2.
raw :GR
150.
40
40
135.
40
4500
30
2.2
20
2.4
Density
Undifferentiated Carboniferous
4700
105.
30
20
4600
Undifferentiated Carboniferous
120.
30
10
90.
20
75.
10
2.6
60.
SS 0
10
45.
LS 0
4800
2.8
30.
DOL 0
4900
(WA) Neutron Density Overlay, Rhofluid = 1.0 (Ch.6-42 1985)
3.
-0.05
0.05
0.15
0.25
Neutron
1791 points plotted out of 1801
Well
Depths
41/8-2
4200.F - 5100.F
5000
10
15.
0.35
0.45
0.
Clay Volume Determination from Wire-line Logs
• Clay Volume (Vclay)
• The clay content reflects the amount of clay minerals present in a
rock. The term ‘SHALE’ normally denotes assemblages of ‘clay
grade’ particle sizes which include clay minerals as well as other
minerals such as quartz, mica etc. The proportion of clay in ‘shale’
can range from 50 to 100%.
• Clay volume is estimated to determine:
•
•
•
•
•
11
Shale / Sand ratios.
Shale corrections in porosity determination.
Shale corrections to Sw .
Log facies.
Reservoir Delineation.
Clay Volume Determination from Wire-line Logs
• Commonly used Clay Indicators are:
• GR.
• SP.
• Resistivity (in hydrocarbon-bearing reservoir).
• Neutron-Density log Cross Plot.
• Typically determine Vclay using several alternative
methods and use either the minimum or average value of them
• Care required:
• If radioactive minerals (other than clays) occur in sands VclayGR is an overestimate.
• If hydrocarbon type is gas VclayDN is an underestimate.
• The Vclay from logs should be calibrated or compared with core data where
possible:
• Shale count observed in core.
• Thin section point count data.
• XRD data.
12
Clay Volume from Gamma Ray VclayGR
• Normally shales contain radioactive minerals and sands do not.
• Sands may contain radioactive minerals e.g. Biotite, Potassium feldspars or
Glauconite. Need corroboration with other clay indicators.
• Select ‘clay’ and ‘clean sand’ lines.
• A linear relationship is normally assumed (non-linear versions Larinov or
Clavier used in FSU for older rocks).
• Vclay is obtained from the following equation:
VclayGR 
Where,
13
VclayGR
GRlog
GRsand
GRclay
= Clay volume from GR (v/v)
= Log GR (GAPI)
= GR in clean sand (GAPI)
= GR in clay/shale (GAPI)
(GRlog  GRsand )
(GRclay  GRsand )
Clay Volume from Gamma Ray: Thin Beds
• Heterogeneity – Thin Bed Problem
In rock beds less than 2 feet thick, log resolution starts to have an
impact by being strongly influenced by adjacent beds.
Thinly laminated sand-shale sequences can have clean sands, which
are not resolved and are interpreted as ‘shaley’ sands or shales.
Note: This problem is not limited to shale volume detection and the
GR log. Similar effects with respect to non-resolution of thin beds also
occur with porosity and resistivity tools.
14
Clay Volume from Gamma Ray – Plot
illustrating picking sand and clay GR
• It is often difficult to decide which shales are
characteristic of the clays dispersed in the
sands:
• This will depend on the mode of
deposition of sands and shales.
• Talk to the project geologist to get his
insights!
DEPTH (8100.FT - 8400.FT)
GR Sand Line
DEPTH
0.
FT
• Other considerations
• It is likely that different parameters will be
required in different intervals in the well.
• Take care to note changes of hole
diameter or presence of casing. Both will
change the attenuation of the GR.
• Parameters are chosen by one of several
methods:
• By “eyeballing” sand and clay GR.
• Using sand and clay lines in a depth plot.
• Note: GRsand <= the smallest Log GRlog
and GRclay< largest GRlog .
15
Test Well
Scale : 1 : 750
GR Clay Line
8200
8300
GR (GAPI)
22/05/2004 15:02
VCLGR (DEC)
150. 0.
1.
Clay Volume from Gamma Ray – Histogram illustrating picking
sand and clay GR
Exercise Well
GR (GAPI)
Interval : 7450. : 8150.
100
10
80
Percent of Total
8
60
6
40
4
20
2
• Typically 5 and 95 percentile
values of GR are adopted as
GRsand and GRclay respectively.
16
Cumulative Frequency
• In some cases to render the
process of choosing less
subjective or to facilitate fast
interpretation in a large number of
intervals the parameters may use
specified percentile points in
histograms
of GR.
0
0
0.
10.
20.
1347 points plotted out of 1401
Curv e
Well
GR
All Zones
Exercise Well
30.
40.
50.
60.
70.
80.
90.
100.
Depths
Min
Max
Mean
Std Dev Mode
P5
P50
P95
7450.F - 8150.F
27.54
99.125
55.968
14.36
47.
39.95
51.459
86.126
27.54
99.125
55.968
14.36
47.
39.95
51.459
86.126
Clay Volume from SP VclaySP
• Responses in clay and sand – sand line and clay line.
• Select ‘clean’ and ‘clay’ lines (methods for choosing parameters are
essentially the same as for GR).
• Vclay calculated using the following equation:
VclaySP 
( SPlog  SPsand )
( SPclay  SPsand )
• Where,
VclaySP = Clay volume from SP (v/v)
= Log SP (mV)
SPsand = SP in clean sand (mV)
SPclay
= SP in clay/shale (mV)
17
SPlog
Clay Volume from SP
• SPsand and SPclay are picked in a similar manner to the GR
equivalents
• Considerations:
• SP deflection is suppressed (reduced) in hydrocarbon-bearing
sands.
• SP deflection varies with Formation Water Salinity changes.
• Hence require different parameters in different zones of the well if
formation (or mud-fluids) salinity changes.
• SP is not effected by non-clay radioactive minerals.
• SP has poor vertical resolution – “lazy” response compared with
GR.
18
Clay Volume from Neutron-Density VclayDN
• Typically VClayDN is determined using Density-Neutron cross-plots:
• Choose appropriate lithology line by observation and hence select
clean points.
• Choose a clay point as a “SE” point in the data distribution.
• Parameters are likely to vary by zone in a given well and between
wells.
• Clay volume determined based on location of data points in the
cross-plot.
19
Clay Volume from Neutron/Density Cross-plot
Gas affected data: will lead to
underestimate of Vcl from D/N
cross-plot unless clean line is
adjusted in gas zones.
May wish to place the Clay point at
a position of greater data density; it
should not be at the extreme edge
of plotted data.
Callenish 1
CNC / ZDEN
2.
GR
100.
40
40
90.
40
30
2.2
80.
30
70.
30
20
20
ZDEN
2.4
10
60.
20
50.
Clay Point
10
2.6
40.
SS 0
LS 0
10
30.
2.8
20.
DOL 0
(SWS) Density Neutron(TNPH) overlay Rhofluid = 1.0
3.
-0.05
0.05
0.15
0.25
0.35
CNC
20
10.
0.45
0.
VClay Comparison of Methods
Pro’s
Cons
Pro’s
Cons
Pro’s
Cons
Insensitive to
borehole
conditions
Radioactive
Minerals in sands
Insensitive to
borehole
conditions
Requires water
based mud
Not as sensitive
to radioactive
minerals as GR
Sensitive to
Borehole
Conditions
Available through
casing
Radioactive
Mineral variation
in shales
Not affected by
radioactive
minerals
Poor Bed
Resolution
Mineral typing
Sensitive to
presence of gas
Not affected by
hydrocarbons
21
Affected by
Hydrocarbons
Clay Volume Calculation in IP
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Clay Volume - GR
• GR minimum picked in clean
zones. Minimum value in the
cleanest zones.
• GR max picked in shales. Value
picked to give a maximum of
about 80% clay in the shale. Note
that shales hardly ever have
100% clay. 60-80% normal
range.
• Can overestimate clay volume
due to radioactive minerals in the
sands
23
Clay Volume GR
• Non linear GR methods have
been designed to work under
specific conditions; certain ages
of rocks or certain formations in
certain fields. Usually developed
in zones that have radioactive
minerals associated with the
sands (feldspars, micas, some
heavy minerals).
• They generally need some sort of
calibration to verify their validity.
24
Clay Volume - Neutron
• The neutron Vcl nearly always
overestimates clay volume and
the tools have a non-linear
response. It is useful for tight
streaks and gas sands where
other indicators may
overestimate.
• Neutron clean is generally left at
zero. Anything greater than that
you risk underestimating Vcl.
• Neutron clay set to calculate 6080% Vcl in the shale zones. Set
to give same sort of results as the
VclGR in the shales.
25
Clay Volume - Resistivity
• Can work well in hydrocarbon
bearing zones. Does not work in
shales or wet zones. Since it
depends on the deep resistivity
there are potential problems of
vertical resolution. Needs to be
used with care.
• Usually used as a last resort
when all else fails.
• Res clean picked at maximum
value in the hydrocarbon interval.
• Res clay picked in the shale
zones.
26
Clay Volume - SP
• The SP quite often has a very lazy
shape and does not respond quickly to
bed boundaries. Will only work with
high salinity contrasts between Rmf and
Rw. The example shows a poor SP Vcl
indicator and should not be used.
• SP will probably need to be base-lined
before use
• SP response is suppressed by
hydrocarbon
• SP response is suppressed by thin
beds
• SP clean picked in thick, clean zones.
• SP shale picked in the shales.
• Use with great care.
27
Clay Volume - Neutron Density
• One of the best clay indicators
since the neutron and density
tools respond linearly to
increasing amounts of clay. The
light hydrocarbon effect on the
logs will mean an
underestimation of Vcl unless this
is adjusted for with the clean line.
The indicator does not work well
in complex carbonates (dolomite
and shale can have similar
responses).
• Clean line and clay point normally
picked using cross-plots. Clean
line must be adjusted for matrix
type (sand, lime) and also
hydrocarbon. The hydrocarbon
correction is made by changing
the slope on the clean matrix line.
Above plot shows the picks in the light hydrocarbon zones
Note the Active Zones are 2 and 4
28
• The Clay point is normally picked
so that the N/D Vcl gives about
60-80% clay in the shales.
Clay Volume - Sonic Density
• Can work well as a clay indicator,
but generally is similar to the N/D
Vcl.
• Clean line is adjusted to fit the
data in the clean zones.
Hydrocarbon effects will be
smaller than the N/D Vcl since
gas has the effect of increasing
both the sonic and density
porosity.
• Clay point is adjusted to give
about 60-80% clay in the shales.
29
Clay Volume - Sonic Neutron
• The S/N Vcl is generally not very
effective since the response to
clay is to increase both the
neutron and sonic readings.
However can be useful in
situations where nothing else
works.
• Clean line and clay point are
adjusted similar to the other
double clay indicators.
30
Clay Volume
31
Deterministic Petrophysics:
Porosity
www.senergyworld.com
Basic Petrophysical Properties:
Porosity
• Defined as the ratio of Void space to Bulk Volume of the rock:
• Porosity is a measure of the space available for storage
of fluids:

• Where,
Vp
Vt
Ø = Porosity
Vp = Pore Volume
Vt = Total Volume
• Expressed as Percentage (%) or Decimal (v/v)
33
Basic Petrophysical Properties: Porosity Types by mode of formation
• Types of porosity
• Primary – originating as the sands were laid down
• Inter-granular or inter-particle
• Intra-granular
• Inter-crystalline
• Bedding planes
• Secondary – formed by various processes after sands were formed
• Solution porosity or Dissolution
• Dolomitisation
• Fractures
• Vugs
• Shale Porosity
• Secondary porosity is generally far more important in
carbonates than sandstones
Fracture
Inter-granular or intercrystalline pores
Micropores
Vugs
• For clean sandstones and carbonates,
• Porosity can readily be derived from logs
• For complex formations porosity data from core is required to calibrate the log response
34
Basic Petrophysical Properties:
Porosity Types Total versus Effective
• Total Porosity Øt
• Ratio of all pore space (and clay structural water seen by some tools) to bulk volume.
• Includes all pores regardless of the degree of connectivity or pore size.
• Includes water in clay structure.
• Effective Porosity Øe
• Ratio of interconnected pore volume to the bulk volume.
35
Basic Petrophysical Properties: Volumes and
Porosity
Porosity Definitions
Absolute or Total Porosity Øt
Matrix
Effective Porosity Øe
VSHALE
Quartz
Clay
Layers
Clay surfaces &
Interlayers
Small
Pores
Large Pores
Hydration or
Bound Water
Capillary
Water
Hydrocarbon
Pore Volume
Isolated Pores
Structural Water
Irreducible or
Immobile Water
Usually assumed
negligable in Clastics
Often assumed
negligable in Carbonates
36
Usually significant in
Clastics
May be significant in
Carbonates
Basic Petrophysical Properties: Porosity Ranges
Type
Porosity Range (%)
Recent Sands – Unconsolidated
35-45
Sandstones
15-35
Tight Sandstones
5-15
Limestones
2-20
Dolomites
2-30
Chalks
5-40
Note: Theoretical maximum inter-granular porosity for
cubic-packed spherical grains is 47.6%
37
Basic Petrophysical Properties: Porosity measurements
• Core porosity
• Measure two of: pore volume, grain volume and bulk volume of core plug
and ratio them.
• Direct measurement but:
• Measure Øt or Øe (or something in between) depending on pore types present,
clay content and method of cleaning and drying.
• Measured under laboratory conditions rather than reservoir stress. Require
correction to reservoir conditions for comparison with or calibration of log
porosity.
• Log Porosity
•
•
•
•
38
Sonic, Density, Density/Neutron, NMR.
Porosities measured differ.
No log measures porosity directly.
Calibrate to core when possible.
Basic Petrophysical Properties:
Porosity and measuring techniques
Log and core Porosity Measurements
Total Porosity, Sonic Log
Total Porosity, Neutron Log
Total Porosity, Density Log
Absolute or Total Porosity
VSHALE
Quartz
Clay
Layers
**
Humidity-dried Core Porosity
Clay surfaces &
Interlayers
Small
Pores
Large Pores
Hydration or
Bound Water
Capillary
Water
Hydrocarbon
Pore Volume
Structural Water
Irreducible or
Immobile Water
** If sample is completely disaggregated
(after Eslinger and Pevear, 1988)
39
**
Oven-dried Core Porosity
Matrix
Isolated Pores
Which Porosity Log Should I Use ?
1.
40
Where possible all porosities should be calibrated to core data.
2.
Density porosity Ød is preferred provided that:
•
The well is in gauge.
•
The matrix density is known and reasonably uniform.
•
The reservoir fluids are liquids.
3.
Sonic porosity Øs (using RHG equation) is used as an alternative to Ød if:
•
The borehole is washed out or DRHO>0.05 gm/cc.
4.
Density/Neutron porosity Ødn is substituted for Ød if:
•
Gas is present in the formation.
•
The lithology is unknown or variable (exploration wells)
5.
NMR porosity ØNMR is of similar quality to Ød except in some carbonates and in gas zones. It is
a specialised log used most often to address complex porosity issues:
•
Measure effective porosity in complex pore structures.
6.
In many instances there will only be one porosity log available in which case the best
interpretation possible must be made with that available:
•
Early exploration wells using single detector neutron or sonic log.
Porosity from Sonic -Wyllie Time Average (WTA)
Equation
For much of the depth interval drilled in any well, the sonic log is likely to be the
only means of deriving porosity.
There are two equations (Wyllie time average and Raymer-Hunt-Gardner)
In the Wyllie Equation, or the ‘Time Average’ equation, porosity is assumed
to be a linear function of the interval transit time:
s 
Where,
Øs
tlog
tma
tfl
Bcp
(t log  t ma )
(t fl  t ma )
*
1
Bcp
=
Sonic porosity (v/v)
=
Interval transit-time measured by the sonic log (μsec/ft)
=
Matrix transit-time (μsec/ft)
=
Transit-time of fluid contained in the formation (μsec/ft)
=
‘Compaction factor’ determined by comparison with core or
regional experience. Often assumed to be 1.
41
41
Porosity from Sonic: Comparison of WTA & RHG equation
with Porosity
• Experience with WTA showed that
it overestimated porosity at high
transit
times or in
unconsolidated formations.
• Comparison of core and other log
porosities with WTA confirmed:
• Overestimation of ØS at
high transit times.
• Underestimates ØS at
intermediate transit times
• RHG derived an alternative
equation for ØS that better fits
porosity over the whole range of
magnitude.
Comparison of WTA and RHG equations
with Field Data. After Porosity Reference1.
42
Porosity from Sonic- Raymer-Hunt-Gardner (RHG)
Equation
The Raymer-Hunt-Gardner relationship is an empirically-based Porosity
solution using the comparison of sonic log transit times, core porosities
and porosities from other logs. It provides more realistic values than the
Wyllie equation particularly at high porosities and in poorly consolidated
formations. In simplified form it is:
 t ma 

 S  1 

 t log 
Where,
Øs
=
Sonic porosity (v/v)
tlog
=
Interval transit-time measured by the sonic log (μsec/ft)
tma
=
Matrix transit time (μsec/ft)
x
=
A lithology dependant constant
This equation has the advantage that it does not require tfl as input.
43
1
x
Porosity from Density
•
The Density measurement is the most reliable means of deriving porosity
from logs given:
• Good hole conditions
• Fairly constant grain density
•
Density porosity is calculated using:
 ma   b
d 
 ma   f
Where,
44
Ød
=
Density porosity (v/v)
b
=
Log bulk-density (gm/cc)
ma
=
Matrix density (Sandstone 2.65, Limestone 2.71,
Dolomite 2.88 gm/cc)
fl
=
Apparent fluid density (Approximate using: Fresh
water-based mud 1gm/cc, oil-based mud 0.85 gm/cc)
Porosity from Density-Neutron Combination
• Neutron porosity is seldom used
independently:
• However neutron porosity may be
the only porosity log in some early
wells.
• Usually used in combination with the
density log.
• Weighted average porosity:
• Oil/water
• Gas
 nd 
 nd 
 d  n
2
d 2  n 2 `
2
• Density-Neutron Cross-plot porosity
• Density-Neutron combined porosity is
particularly useful in gas zones where Ød
and Øs tend to be overestimates unless
core is available to calibrate them.
45
If neutron was logged in Limestone
units convert to actual matrix before
use in weighted average Ønd
Porosity and Clay Volume Estimation from Density / Neutron
Cross-plot in shaly sands
• Porosity-Clay volume D/N Overlay
construction:
Density versus Neutron
• Establish the (Wet) Clay point in the “SE” of
Density-Neutron Cross-plotted data.
1.9
0.4
2
•
Scaled linearly in porosity.
• Matrix-Clay line.
• Defined by Matrix and (Wet) Clay
points.
2.1
0.3
Bulk Density (gm/cc)
• Matrix line.
•
Defined by a line joining the matrix
point (porosity 0) to the fluid (water)
point (porosity of 1).
2.2
2.3
0.2
2.4
0.1
2.5
2.6
•
0.2
Effective porosity 0 along this line.
2.7
•
0.4
0.8
Matrix Point
Wet Clay
Point
Scaled linearly in clay volume.
2.8
-0.05
0.05
0.15
0.25
Sandstone Neutron Porosity (v/v)
0.35
0.45
46
46
Effective Porosity
• Effective porosity:
e  t  Vcl  tcl
Where, Øe = Effective porosity (v/v)
Øt = Total porosity (v/v)
Øtcl = Total porosity of clay (v/v)
Vcl = clay volume (v/v)
47
The Borehole Environment
Invasion
The depth of invasion is controlled by the formation
porosity and permeability and the mud characteristics
(pressure differential between mud column and formation,
viscosity and fluid loss).
High permeability beds generally tend to show less
invasion, due to fast mudcake build-up, while lower
permeability beds tend to have more invasion.
Rmc
Ro
Rt
Rxo
Rm
Ri
Sxo
Sw
Si
Invaded
Zone
Non-invaded
Transition Zone
Flushed Zone
Mudcake
Borehole
As mud invasion is a volume system, the depth of invasion in high porosity beds is
shallow and correspondingly the depth of invasion in low porosity beds is deep.
The effect of invasion will decrease away from the wellbore so that there is a ‘transition
zone’ developed, from mud filtrate at the well, through a zone of mixed filtrate and
formation fluid, to the ‘non-invaded zone’ where original formation fluids are found.
48
The Borehole Environment
SECTION VIEW
PLAN VIEW
Rmc
Ro
Hmc
Rxo
Rm
Sxo
Sw
Rt
Ri
Invaded
Zone
Non-invaded
Transition Zone
Flushed Zone
Mudcake
Borehole
49
Si
R = Resistivity
S = saturation
m = mud
mc = mudcake
xo = flushed zone
i = invaded zone
t = uninvaded zone
w = formation
water
o = 100% water
saturated,
uninvaded zone
Mud Filtrate Invasion
Well
Bore
FORMATION
FORMATION
WATER
WATER
MUD
MUD
FILTRATE
FILTRATE
Well
Bore
Mud Cake
Mud Cake
Water-Based Mud System
(a) Water-bearing formation
(b) Oil-bearing formation
MUD
FILTRATE
OIL
FORMATION
WATER
Flushed Zone
Flushed Zone
Transition
Zone
Non-Invaded
Zone
Transition
Zone
Non-Invaded
Zone
OIL
FILTRATE
FORMATION
WATER
Well
Bore
Mud Cake
Well
Bore
Mud Cake
Oil-Based Mud System
(c) Water-bearing formation
(d) Oil-bearing formation
OIL
FILTRATE
OIL
FORMATION WATER
Flushed Zone
Flushed Zone
50
Transition
Zone
Non-Invaded
Zone
Transition
Zone
Non-Invaded
Zone
Fluid Parameter Determination for Porosity
Calculation
• All porosity calculations require a fluid parameter
• Ød fluid density f
• Øs fluid transit time tf
• Øn fluid hydrogen index HIf
• It can be assumed that the porosity logs measure
predominantly in the in the flushed zone.
• Hence the fluid parameter will be a weighted average of
mud-filtrate, formation water and where present
hydrocarbon properties dependent on the saturations of
those fluids in the invaded zone.
• For this reason porosity and saturation calculations are
linked in IP.
51
Fluid Density Determination for Porosity
Calculation in wells drilled with WBM
Assume f=mf
• In the hydrocarbon leg:
 f  (1  S xo )   H  S xo   mf
Calculate Ød
• In the water leg:
 f   mf
Calculate Sxo
• Flushed zone saturation Sxo can be calculated
using the Archie water saturation equation:
S xo
• Where:
1
 2

 Rmf

 Rxo



1
2
• Rmf is the mud-filtrate resistivity
• Rxo is measured by the micro-resistivity log
(MSFL or MLL)
• Ø is the porosity
52
Calculate f
Calculate Ød
Is Ødn~ Ødn-1?
Yes
Calculate Sw
No
Fluid Density Determination for Porosity
Calculation in wells drilled with OBM
• In the hydrocarbon leg:
 f  (1  S xo )  I   mf  (1  S xo )  (1  I )   H  S xo   w
• In the water leg:
 f  (1  S xo )   mf  S xo   w
• No log measurement of Rxo is made in OBM.
• The iterative method used in WBM wells is not possible!
Instead:
• Estimate the invasion factor I
• Assume Sxo is the minimum of Sw or I
53
Porosity Calculation in IP
www.senergyworld.com
Equations
• As much as possible the complete tool response equations
are utilised within IP.
• This Means That:
• We don’t just consider a single fluid parameter (e.g.
Fluid Density) but we split this up into the single
components (e.g. flushed zone water and hydrocarbon).
• Excavation effects on the neutron log and apparent
hydrocarbon electron density corrections are
considered.
• The equations are solved simultaneously and iteratively.
• This Results In:
• A superior and more believable interpretation result that
tends to match core results better.
55
Equations
• Flushed Zone Water properties as seen by the Porosity tools are
calculated from water resistivity values.
• Alternatively these values can be entered by zone or a trend curve
can be used.
56
Equations
• If not entered then hydrocarbon density and neutron HI
values are calculated using Gaymard-Poupon equations
from an entered input true hydrocarbon density value for
each zone.
57
Porosity Models - Density
58
Porosity Models - Density
• Easy to use but assumes complete understanding of fluid and matrix
types.
• In gas errors in gas density and flushed zone (Sxo) saturation can
cause large porosity errors.
• Matrix density entered as curve or fixed parameter.
• Used in Multi-mineral analysis for porosity.
• Lithology is used to calculated the matrix density
59
Porosity Models - Neutron
60
Porosity Models - Neutron
• Non linear response equation to minerals and hydrocarbons
• Equations are tool specific
• IP allows the selection of the tool type
• Tools are very sensitive to borehole corrections.
• Large gas correction required
• Gas correction reverse of the density
• The neutron is rarely used by itself. Normal used in conjunction with
the density to calculate a neutron / density porosity.
• To use non linear matrix enter Rho matrix for required mineral (2.65
for sand) otherwise enter the matrix neutron porosity
61
Porosity Models - Sonic
• Two empirical relationships in IP
• Wyllie
• Raymer Hunt
• Input parameters are hard to pin down and best set by
calibrating to another porosity
• Gas effects can be large in high porosity
• Hard to correct for
• Sonic used when
• No density available
• Density effected by hole washout
• Unusual lithology where density matrix is not known
62
• Volcanics
Porosity Models – Neutron / Density
63
Porosity Models – Neutron / Density
• Preferred method in IP
• Two input equations so can calculated two outputs
• Porosity + Hydrocarbon Density
• Porosity + Matrix Density
• Porosity + Clay Volume
• Three methods for controlling the logic
• Calculate hydrocarbon density using a fixed matrix density
• Calculate matrix density using a fixed hydrocarbon density
• Calculate clay volume using a fixed hydrocarbon and matrix
density
64
Porosity Models – Neutron / Density
Input
Neutron, Density
Vclay, Sxo
Is Variable hydrocarbon
flag set?
Yes
Calculate
Phi, Rho Hydrocarbon
Is Rho Hydrocarbon
within limits set?
No
Yes
Exit
No
Calculate
Phi, Rho matrix
Yes
Exit
Is Rho matrix within
limits set?
Yes
Is Variable Matrix
density flag set?
Set Rho Hydrocarbon
to limit
No
No
Set Rho matrix
to limit
Is Variable Vclay
flag set?
No
Yes
Calculate
Phi, Vclay
Is Vclay > 0 and < 1
No
Calculate
Phi density and Phi Neutron
Phi result is the minimum
Exit
65
Set Vclay
to limit
Yes
Exit
Porosity Models – Neutron / Sonic
• Used similar logic to Neutron / Density
• Rarely used since the N / D is more accurate and
easier to understand and control
• Sonic parameter selection
66
Porosity and Water Saturation
Check for Coal and Salt
Check for Bad hole
if found calculate
Phi sonic
Set iteration defaults
Sxo = 1.0
Calculate Umatrix RhoMatrix
Dtmatrix
Yes
Calculate mineral volumes and
clean matrix density
Is Multi-Mineral
analysis option set
No
Calculate porosity depending
on porosity method
If bad hole limit Phi
to Phi sonic
If Vclay > Vclay limit
Phi <= Philimit
Calculate Sw and Sxo
No
Limit Sxo depending on mud type
and saturation exponent
Is Sxo >= 1.0
No
Is the Phi and Sxo change
between loops < .001
Yes
67
Make final calculations
Yes
Porosity Models – Pass through Porosity
• For users who want to calculated Phi outside the
normal routine
• Regression against core data
• NMR porosity
• Program needs to know if input porosity is a total or
effective porosity
• All normal logic is applied
• Sw calculations
• Bad hole logic
68
Deterministic Petrophysics:
Water Saturation
www.senergyworld.com
Water Saturation in clean sands - The Archie Equation
• Archie Equation
• Six unknowns:
 a R 
S w   m * w 
Rt 

1
n
• True formation resistivity Rt is taken as the most suitable deep reading resistivity, environmentally corrected if
necessary.
• Formation water resistivity Rw
•
•
•
•
SP interpretation
From Rwa in a water leg
Pickett plots
Water samples
• Porosity: log total porosity
• Tortuosity constant (a), Cementation exponent (m) and Saturation exponent (n):
•
Preferably determined from Core measured Formation Factor (F R) and Resistivity Index (I) respectively.
•
In Sandstones if lacking core choose from:
•
•
•
•
70
Archie Parameters a=1, m=n=2
Humble parameters a=0.62, m=2.15, n=2 parameters for sucrostic rocks
Tixier parameters for sucrostic or granular rocks a=0.81, m=n=2
Check suitability of a and m using Pickett plot
in the absence of core data
Determination of Rw and m from a Pickett
Plot
 a R 
S w   m * w 
Rt 

• From the Archie equation:
1
n
• Rearranging and substituting for
resistivity Index
I
1
n
Sw
Rt 
a  Rw  I
m
• Taking Logs
Log ( Rt )  Log (a  Rw )  Log ( I )  m  Log ( )
• This equation describes a family of
parallel lines, in a log-log plot of Rt
versus Ø, for different resistivity
indices whose slope is –m.
• The line for I=1 (and Sw=1) is the
water line with an intercept a.Rw at a
porosity of 1.
• Such a log-log plot of Rt versus Ø of
this form is called a Pickett Plot.
71
Slope m = 2
a.Rw
Water Saturation Models
• Effective Porosity models
•
•
•
•
Archie
Indonesian (Poupon-Leveaux)
Simandoux
Modified Simandoux
• Total Porosity models
•
•
•
•
Archie Total porosity
Dual Water
Juhasz (Waxman-Smits)
Waxman-Smits
Clean Matrix
Dry Clay
Bound
Water
Water
Oil / Gas
Wet Clay Volume (VWCL)
Total Porosity (PhiT)
Sw = WaterVol / Effective Porosity
Effective Porosity (Phie)
SwT = WaterVol / Total Porosity
72
WaterVol
HydVol
Shaly sands: the effect of clay on the
conductivity
The additional conductive
path reduces the resistivity
of the formation.
The negatively charged clay
surfaces provide an additional
conductive path.
If this effect is not taken into
account this has the effect
of increasing the calculated
water saturation above it’s
real value.
Shaly sand interpretation
corrects for this effect to
calculate Sw.
73
Clean and Shaly Sand Saturation Equations
• Clean sands – Archie equation
• Assumes that the only conducting
component in the reservoir is
water.
• In shaly sands the clays provide a
parallel conductive path hence Rt
is lower than it would be with the
same Sw in the absence of clays.
1
1
1
 
RT R1 R2
R1
R2
C 
• Shaly sand saturation equations
account for the extra conductivity
provided by the shales.
74
1
R
CT  C1  C2
Measures of Shaliness
• The number of positive ions (cations) attracted to the clay surface depends on the amount of clay and
the type of clay. The number is called the Cation Exchange capacity (CEC), also denoted by Qv.


• CEC is expressed in milli-equivalent of exchangeable ions per hundred grams (meq/100gm).
• Qv is expressed in milli-equivalent per milli-litre (=cc) pore volume
• The conversion between the two is:
Qv
 CEC 
g

(1 
100 
t
)
t
• The Qv is indicative of the degree of shaliness of a formation:
• Qv<0.1
Clean sands
• 0.1<Qv<0.2
Slightly shaly sands
• 0.2<Qv<0.3
Moderately shaly sands
• 0.3<Qv<0.5
Shaly sands
• Qv>0.5
Very shaly sands
• Clays vary in their electrical activity as indicated by their CEC:
• Kaolinite
3-15 meq/100gm
• Illite and Chlorite
10-40 meq/100gm
• Montmorillinite
80-150 meq/100gm
• The GR is not a good indicator of CEC , for instance montmorillinite contains no potassium and
hence has a low GR response but high CEC.
75
Shaly sands
• The Archie equation assumes that the matrix is non-conducting.
• In shaly sands the resistivity is lower than in clean sands for the same Ø and Sw. This
is caused by the additional electrical conductivity of the clay.
• Hence use of the Archie equation in shaly sands will result in too low a hydrocarbon
saturation.
• There are a large number of shaly-sand Sw equations.
• All have the basic Archie form with an additional term to account for the extra conductivity
of the clay.
• The clay-distributions for which the equations are intended are not always clear.
• Two equations will be described here:
• The Indonesia Equation – well adapted for application without supporting core analysis
data.
• The Waxman-Smits equation – which is intended for application where the clays coat the
matrix grains (dispersed shale). This equation performs well when core measurements of
the clay properties are available.
76
Alternative Shaly Sands Water Saturation Equations
Comparison
• Several equations are shown at
right in conductivity form which
facilitates comparison.
• The similarities and differences
between equations are apparent.
77
77
77
When do I Need to use a Shaly Sand Interpretation?
• If possible treat sands as “clean” – non-shaly because it is much simpler to do so!
• In that case Øt = Øe and the Archie equation can be used to determine S w.
• How can you tell if you need to use a shaly sand approach or not?
• If the formation has high shale volumes as seen in core.
• If CEC or Qv measurements on core indicate high values.
• Compare wetting phase saturations from air-mercury and air-brine Pc data. If the latter are
significantly larger than the former then the difference is due to clays (which do not influence
air/mercury saturations) and the need for shaly sand interpretation is indicated.
• The fresher the formation water the more significant will be the effect of shale content. At high
salinity (100’s of kppm) shale effects become negligible even with substantial clay content.
• Examine the formation resistivity in sands; if it shows a dependence on shale volume you
need to use Shaly sand interpretation.
• If in doubt as to the significance of shales calculate S w using the Archie equation and a simple
shaly sand equation (suggest the Indonesia equation) and see how much difference the two
approaches make to Sw (and Sh)
78
Indonesia Equation
• Has the advantage that it can be used without core derived
parameters (although core derived m and n are preferred).
• Equation developed by Poupon & Leveaux)
V
m
(1( cl ))

Vcl 2
1
 e


a

R
Rt 
Rcl
w

• Where,
79
Swe
Øe
a
m
n
Rw
Rcl
=
=
=
=
=
=
=

n

  S we 2

Effective water saturation (v/v)
Effective porosity (v/v)
Tortuosity constant
Cementation exponent
Saturation exponent
Formation water resistivity (ohm.m)
Clay resistivity (ohm.m)
Use of Indonesia Equation
• Calculate Vcl from logs.
• Use conventional methods for Vcl (typically GR and D/N)
• Calculate Øe from logs.
• Effective porosity from density, sonic or density/neutron logs:
• Cross-plot Rt versus Vcl to determine Rcl.
• Determine Rcl as the value of Rt as Vcl tends to 1.
• Investigate the need for Rcl variation by zone.
• Compare saturations with Swirr from Pc data and Dean-Stark saturations if
available. Tune parameters as necessary.
80
Waxman Smits Equation
• Has the advantage that it does not require Vcl as input and uses Øt rather than
Øe. However it is best applied when core measurements of Cation Exchange
Capacity (CEC) or Qv are available.
• Equation developed by Waxman & Smits
1 t  S wt

Rt
a *  Rw
m*
• Where, Swt
81
=
Øt
a*
m*
n*
Rw
B
Qv
n*

R 
 1  B  Qv  w 
S wt 

Total water saturation (v/v)
=
Total porosity (v/v)
=
WS Tortuosity constant
=
WS Cementation exponent
=
WS Saturation exponent
=
Formation water resistivity (ohm.m)
=
Cation Mobility (mho cm2/meq)
=
Cation Exchange Capacity (meq/ml)
Use of Waxman Smits Equation
• Calculate Øt from logs.
• Calculate B using the Thomas equation:
B
Where, B
=
T
Rw
 1.28  0.225T  0.0004059T 2
1  Rw
1.23
(0.045T  0.27)
Cation Mobility (mho cm2/meq)
=
Formation temperature (ºC)
=
Formation water resistivity @ T (ohm.m)
• Obtain a relationship between Qv and Øt using special core analysis data.
• a* m* and n* are best determined from SCAL.
82
Comparison of Total and Effective Saturations
• If saturations are determined by a number of different
methods are to be compared care is needed if water
saturation is calculated with reference to total porosity Swt
is to be compared with that calculated relative to effective
porosity, Swe.
• Conversion from Swe and Swt is achieved by:
(1  S wt )  t  (1  S we )  e
83
Example of the Effect of Shaly Sand Analysis
• Water salinity 11,000ppm; Rw 0.2
ohm.m @ 200ºF
• Hence from Thomas equation
B = 10.5
• a*=1, m*=1.78, n*=1.33
• Qv=-2.086*Ø+0.55
• Moderately shaly formation but
relatively fresh water.
• Hence treat as shaly sand.
• Comparison of log derived Sw with
Sw/Height Function and DeanStark data much improved.
84
Water Saturation Calculation in IP
www.senergyworld.com
Water Saturation Models
• Selecting the default Sw equation on the Phi/Sw setup
window changes the default plot.
• The interactive default plot has special interactive
parameter lines and crossplot depending on the setup.
• Changing the default Sw equation will not change the
Sw equation for any already created zones.
86
Water Saturation – Effective Phi Models
• Resistivity clay can be interactively
picked from the Rt / VWCL crossplot.
Right mouse click in the resistivity track
to access this cross-plot.
• Resistivity clay is adjusted to make Sw
average 100% in the shaley wet zones.
• Rxo clay is adjusted the same way so
that Sxo is 100%.
87
Water Saturation – Total Phi Models
• Total porosity
• øt = øe + Vcl x øtclay
• Clay porosity
Øtclay
• Entered as a fixed parameter
• Calculated from density dry and wet clay parameters
• Best method of obtaining this is from core analysis data
88
Water Saturation – Dual Water
1 Tm  SwT n  1
Swb  1
1 

 



 
Rt
a
Rw
SwT
Rwb
Rw



Swb  1 
e
t
• Rwb (Rw bound water) can be
adjusted by moving the Rwb
parameter line in the Rwapp
interactive track.
• Set the Rwf (Rw free water)
parameter to give 100% water in
the clean wet zones. Then set the
Rwb parameter to give 100%
water in the shaley wet zones.
• Rmfb (bound flushed zone water)
can be set in a similar fashion.
89
Water Saturation – Juhasz
1 Tm  SwTn 
Rw 

 1  Bn  Qvn

Rt
a  Rw
SwT 

Vcl  Tclay
Qvn 
T
• The Cwapp / Qvn cross-plot can be created
by right clicking in the Rwapp track and
selecting from the drop-down menu.
• Rw and the Bn parameter can be set
interactively by changing the end positions
of the line. The left edge sets the Rw. The
slope of the line sets the Bn parameter.
• Adjust the Rw parameter to give 100%
water in the wet clean zones. Adjust the Bn
parameter on the crossplot to give 100%
water in the shaley wet zones.
90
Water Saturation – Waxmann-Smits
1 Tm  SwT n 
Rw 

 1  B  Qv

Rt
a  Rw
SwT 

a
Qv 
b
PhiT
• The QVapp / PhiT_Recp cross-plot can be
created by right clicking in the Rwapp track
and selecting from the drop-down menu.
• The interactive line is used to pick the ‘a’
and ‘b’ parameters in the Qv equation.
The user should adjust the line to fit the
data in wet zones.
• If the Qv value is correct then SwT should
read 100% in the shaley wet zones.
91
Vsilt Index
• For a given volume of clay
we expect the resultant Phie
to be within a certain range.
• If however the porosity is
lower than this range then
something else must be
reducing it.
• This porosity reducing
something else is what the
VSILT index represents.
• It indicates that the porosity
is lower than expected and
there must be something else
other than clay reducing it,
This could be cement silt or
whatever.
• It is purely for display
purposes and does not
impact on porosity or Sw
calculations.
92
Limits and Bad Hole
• The effective porosity must be less
than the porosity limit line.
• Phi Max and Delta Phi Max are
entered parameters. Phi Max is set to
the maximum porosity in silt free
sand. It is used to calculate the silt
index. The Delta Phi Max parameter
is adjusted to remove unrealistic
porosities.
• The Vcl cutoff parameter will remove
porosity in shale zones. It is very
useful for cleaning up an
interpretation.
• The Vcl cutoff parameter can also be
used to boost the ‘m’ Archie
parameter in shales. This has the
effect of removing unlikely
hydrocarbon saturations in shales.
m  m  10Vcl VclCutoff 
93
Limits and Bad Hole
•
•
•
•
94
Bad hole discriminator curves can be used (e.g. caliper, den correction).
If the hole is flagged as bad then sonic porosity is calculated.
Porosity will be the minimum of normal porosity or the sonic porosity.
Normal porosity limits are still applied.
Linking Parameter Sets.
• When you first run the Por/Sw the following window will appear.
• Ticking all three effectively joins the VClay and Por/Sw parameters
together as one.
95
Optional Comparison Curves
• Optional porosity and Sw curves using differing methods can be created.
• This will add a comparison track to the interactive log plot.
• These comparison curves should not be used as final output curves as they are
not limited and are also not solved iteratively.
96
Deterministic Petrophysics: Net and
Pay
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Basic Interpretation Workflow Net and Pay
Definition
• Gross Rock:
• Comprises all rock in the evaluation interval.
• Net Sand:
• Comprises those rocks which may have useful reservoir
properties.
• Sand is a generic oilfield term for lithologically clean sedimentary
rock.
• Determined using a Vclay cut-off.
• Net Reservoir
• Comprises those rocks which do have useful reservoir properties.
• Determined using a porosity cut-off on Net sand.
• Net Pay:
• Comprises the net sands that contain hydrocarbon.
• Determined using a water saturation cut-off on Net Reservoir
98
Net Reservoir Determination
• Western Petroleum Industry Practice
• Traditionally adopts rule of thumb cut-offs for the evaluation of net
pay.
• The arbitrary nature of the cut-offs is recognised.
• Usually the cut-offs have been selected to correspond to fixed
permeability values:
• 0.1 mD for gas reservoirs
• 1.0 mD for oil reservoirs
• These nominal cut-offs are still commonly used.
• Because permeability is not measured by logs the normal practice is
to relate core permeability to porosity and/or other log-derivable
parameters.
• The precise type of permeability used to specify the cut-off is not
defined.
99
Determining Net Sand cut-offs
• Determine using a Vcl cut off.
• The cut off is generally arbitrary and of the form Vcl<= Cutoff.
• The sensitivity of Net Sand count to the cut-off is generally examined by
determining the net-sand for a range of cut-offs. The cut off should be
determined in an insensitive region of the sensitivity plot if possible.
• Cut-offs should be validated by comparison of resulting Net sand with that
observed in core.
• If sands with laminations below log resolution are encountered it is possible
no net reservoir will be resolved. In these cases cut-offs may not be
appropriate
100
Determining Net Reservoir cut-offs
• Determined by applying an additional cut-off to intervals that have passed the Net Sand critera.
• Determine cut-offs equivalent to appropriate permeability:
• Oil field k=1mD
• Gas field k=0.1mD
• Usually use a porosity cut-off equivalent to the appropriate permeability cut-off in a cross-plot of core
permeability versus core porosity.
• Permeability and porosity corrected to down-hole conditions should be used.
• Hence the Net Reservoir Criteria are of the form: Vcl<=Cut-off and Ø>=Cut-off.
• The sensitivity of Net Reservoir count to the cut-off is generally examined by determining the Net Reservoir
for a range of cut-offs. The cut off should be determined in an insensitive region of the sensitivity plot if
possible (see next slide).
• Where reservoir can easily be identified in core the net reservoir should be measured and compared with the
log net reservoir to tune the cut-off(s).
• Core photographs in natural and UV light may assist the picking of net reservoir in the core.
• Variation of the Net sand Vcl cut-off may be useful to achieve this match.
• If core data is not available it may be useful to plot Density–Versus GR. A transition to a shale density can
sometimes be observed which serves to define a GR or clay volume cut-off. See cross-plot overleaf.
• Comparison of net picked from logs with the intervals seen to be flowing in the production profile from a PLT
can also be used to validate the cut-offs adopted. Such comparison is not however definitive since factors
other than reservoir quality influence which intervals will flow.
101
Net Cut-offs Useful Plots
Cut-off Sensitivity Plot
N/G
A
Determining GR cut-off in GR-Density Cross-plot
B
3
CUT-OFF
2.8
Density (gm/cc)
Plot indicates whether the cut-off
adopted is in a sensitive (A) or
insensitive region (B). B is
preferable.
2.9
2.7
Model
2.6
GRsand
2.5
GRclay
2.4
Log Data
2.3
Cut-off Point
2.2
2.1
2
0
50
100
GR (GAPI)
102
150
Determination of Net Cut-off using Porosity/Permeability
cross-plot
• Determination of porosity
cut-off equivalent to a 1mD
permeability cut-off in an oil
reservoir.
103
103
Determination of Net Pay
• Net Pay is determined by the addition of a water saturation cut off to the
Net Reservoir Criteria: Vcl<=Cut-off and Ø>=Cut-off.
• Net Pay defines the potentially productive portion of the reservoir.
• The cut off Sw is in most cases largely arbitrary (typically 50% - 60%).
• Relative permeability curves can be used to inform the choice of Sw cut-off ~ Sw Critical.
• Net Reservoir and Net Pay are used to determine Reservoir summary zonal averages.
• Versions of the log interpreted curves, set to null outside the net sands, are often generated.
• Numerical Flags are usually created for Net Sand, Net Reservoir and Net Pay.
104
Reservoir Summaries in IP
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Cutoffs and Summation Input Curves
• Specify:
• Cut-off names
• Short names
• Interpreted curves to
use
• For each cut-off specify its
type or logic.
• Specify the type of
averaging to be used.
• TVD or TVT outputs can
be selected by checking
the appropriate box and
specifying the required
depth curve.
106
• Note that additional
curves can be selected for
averaging without being
used as cut-offs.
Cutoffs and Summation Report Setup
• Define Reports Required:
• Reservoir
• Pay
• Specify the cut-off values
to be used for each cut-off
curve.
• Specify which cut-offs are
to be used for each report
using .
• Can load formation tops to
be used in averaging via
Load/Save ParameterSets
107
Cutoffs and Summation Output Curves
• Specify output set:
• Specify Reservoir and
Pay flags.
• Specify names for curves
to be cumulative in the
summaries
108
Cutoffs and Summation Run
• Select Run
• Select Yes to initiate Cutoff
plot.
• Cut-offs can be adjusted:
• Changed using sliders.
• Enabled or disabled in
individual zones by right
clicking in a track and
selecting.
• Zones can be adjusted:
• Click and drag boundaries in
zone track.
• Zones can be deleted if
required.
109
Cutoff Parameters
• Zone Depths
• Displays Zone names and
depths
• Reservoir & Pay Cutoffs:
• Displays cutoff curves and
values.
• Cutoffs can be selected or
adjusted by zone.
110
Cutoff Sensitivity
• Select Wells – can be multiple
• Cutoff
• Curve
• Lower Limit
• Upper Limit
• Step
• Select Summary Parameter.
• In this case Net Reservoir.
• Select Zones for sensitivity
analysis.
• Make Plot.
111
Parameter Sets
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Parameter Sets
• Parameter Sets are created when any of the zonable
interpretation modules are run.
•
•
•
•
•
•
•
•
•
•
113
Clay Volume
Porosity and Water Saturation
Cutoffs and Summation
Mineral Solver
Basic Log Analysis
NMR Interpretation
TDT Standalone
TDT Time Lapse
Pore Pressure Gradient
User Programs
Parameter Sets
• Each module when run is
populated with a set of
parameters.
• These starting parameters are
then adjusted in order to provide
your interpretation.
• The last set of Parameters run is
stored in the program memory for
each module.
• Alternative Parameter sets can
be saved and later recalled.
• They can be saved into the
database well .dat files or out of
the database into external ASCII
disk files.
114
Parameter Sets
• As Parameter Sets share
the same structure as
Tops Sets with name, top
and bottom they can also
be displayed and used like
tops sets.
• Also tops sets can be used
to populate Parameter
Sets.
115
Delete Parameter Sets [Well]
• Selecting the ‘Well > Delete Parameter Sets' option will delete an
interpretation 'Parameter Set' from the current, active well.
• This is helpful if the current 'Parameter Set' is found to be incorrect and the
user wants to start an interpretation again from the beginning.
• This will not delete any Parameter Sets saved on the hard disk.
• Only the 'Parameter Sets' associated with the currently-active well can be
deleted.
116
Multi-well Parameter Distribution [Multi-Well]
• Allows you to interpret one
key well.
• Then distribute the
parameters you used in
that well to other wells in
memory.
• The parameters are
distributed based on a
common set of formation
tops.
117
Multi-well Parameter Distribution [Multi-Well]
• 'Copy using zone names' - If 'checked', will allow the user to more-accurately
distribute 'Parameter Sets' to multiple wells in an IP project or to distribute
parameters to multiple penetrations of reservoir zones in a single horizontal well.
• Note this is a special case as the user is required to be more rigorous in setting up
the zones in the interpretation modules. It is only useful if the names of all zones are
defined in all the Sets being distributed and in the common 'Tops Set'.
• The ‘Distribute' button will distribute the 'Parameter Sets'. The user will be asked to
confirm whether or not to overwrite existing Sets.
118
Multi-well 3-D Parameter viewer
• View>3-D Parameter Viewer.
• Allows interpretation
parameters, such as Rw, and
Cut-off and Summation
results, such as Average Sw,
to be mapped between wells
and layers
119
Curve History
• CH> History Tab
• Shows curve history
•
•
•
•
Origin
Author
Date of creation
Last update
• Show Parameters Tab
• Shows multiple interim steps
• Tabulates Parameters Used
• Can compare parameter
differences between multiple
curves.
• Can be output as text file
120
Movie
• On the IP installation disk we supply a movie file which
takes the user through a quick look Petrophysical
interpretation.
121
Summary
• Over the past few days you should have learnt:
• How IP’s Database is structured
• Loading data in from external files (LAS etc)
• Presenting Data (Logplots, Crossplots, Histograms)
• Editing Data (Depth shifting, splicing etc)
• How to Run calculations (single or multi-line formulas etc)
• Use the clay volume, Por/Sw and Cutoff deterministic petrophysics
modules to derive Vclay, Porosity, Sw and N/G
• Understand parameter sets (how to save and recall them)
• Use Multi-Well workflows
• We hope you have enjoyed this insight into the basic functionality of IP.
Thank You
122
Interactive Petrophysics (IP4)
Advanced
123
Interactive Petrophysics Advanced: Contents
• Statistical Curve and Facies Analysis: Fuzzy Logic in IP
• Statistical Curve Prediction: Multi-linear Regression in IP
• Statistical Curve Prediction: Neural Nets in IP
• Facies Prediction: Cluster Analysis in IP
• Monte Carlo Analysis in IP
• Capillary Pressure and Saturation-Height
• Principals
• Execution in IP
124
• Pore Pressure Calculations in IP
Statistical Curve & Facies
Prediction
Fuzzy Logic
125
Fuzzy Logic
• Fuzzy logic is the logic of partial truths
• The statement, today is sunny
•
•
•
•
100% true if there are no clouds
80% true if there are a few clouds
50% true if it's hazy
0% true if it rains all day
• This is mathematics of probabilities
• If we can work out the probability of each event outcome then
we can predict the most likely result
• More details read ‘The Application of the Mathematics of Fuzzy
Logic to Petrophysics’ - Steve Cuddy
126
Fuzzy Logic
• Used for predicting petrophysical properties from any combination
of data.
• Predict: Facies, Permeability, Density, Sonic etc.
• Use: Raw logs, Petrophysical results, Core results
• Two basic modes of prediction depending on input data.
• Fixed value input data: Facies
• Continuous value data: Log curves, Core permeability
127
Fuzzy Logic
• Reproduces the dynamic range
better than regression.
• Curve to be predicted.
• Curves used to predict from.
128
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