Deterministic Petrophysics

1
Deterministic Petrophysics
2
Log Evaluation Workflow
Lithology
Clay Volume Estimation
Porosity Computation
Water Saturation Calculation
Fluid Zones
Permeability Determination
Net Pay / Net Reservoir Quantification
Reality check
3
Log Evaluation Workflow

• Lithology
• Clay Volume Estimation
• Porosity Computation
• Core calibration
• Water Saturation Calculation
• Core derived parameters
• Comparisons with core
• Saturation-height
• Fluid Zones
• Fluids present
• Fluid contacts
• FWL
• Permeability Determination
• Core derived predictors
• Net Pay / Net Reservoir Quantification
• Reality checks
• Uncertainty Analysis

Reasons for iteration
Part or Total iterations
4
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.

5
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.

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Deterministic Petrophysics Lithology Clay
Volume
7
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.

8
Typical Log Responses to Lithology and Gas
Density
Neutron
Sonic
Log response Decreases with Increasing Porosity
Log response Increases with Increasing Porosity
Log response Decreases with Increasing Porosity
Reservoir Rock
Low
High
High
Low
High
Low
Limestone (Reference)
2.71 g/cc
0
47.5 us/ft
52.5 55.5 us/ft Variable with Compaction
2.65 g/cc
Sandstone
- 4
2.83 to 2.87 g/cc
42.5 us/ft
Dolomite
6 to 8
Non Reservoir Rock
2.98 g/cc
50 us/ft
Anhydrite
- (1 to 2)
2.33 g/cc
52 us/ft
Gypsum
48
Salt
2.08 g/cc
67 us/ft
0
130 175 us/ft Variable with Compaction
Wide Range 2.3 2.7 g/cc Variable with Clay
Density
Reads High Increases with Clay Bound Water
Shale
Hydrocarbon
Gas Effect
Reads Low
Reads High
Reads Low
9
Lithology Example 1
Minerals Determined from D/N Cross-plot Salt ? ?
Dolomite ? ? Anhydrite ? ?
10
Lithology Example 2
Minerals Determined from D/N Cross-plot Limestone
Claystone-sandstone
11
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
• Shale / Sand ratios.
• Shale corrections in porosity determination.
• Shale corrections to Sw .
• Log facies.
• Reservoir Delineation.

12
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.

13
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
  equationWhere, VclayGR Clay volume from
  GR (v/v) GRlog Log GR (GAPI) GRsand
  GR in clean sand (GAPI) GRclay GR in
  clay/shale (GAPI)

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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.

15
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!
• 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 lt the smallest Log GRlog and
  GRclaylt largest GRlog .

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Clay Volume from Gamma Ray Histogram
illustrating picking sand and clay GR

• 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 histogramsof GR.
• Typically 5 and 95 percentile values of GR are
  adopted as GRsand and GRclay respectively.

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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
• Where, VclaySP Clay volume from SP
  (v/v) SPlog Log SP (mV) SPsand SP in
  clean sand (mV) SPclay SP in clay/shale
  (mV)

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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.

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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.

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Clay Volume from Neutron/Density Cross-plot
Clay Point
21
VClay Comparison of Methods
Pros Cons Pros Cons Pros 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 Affected by Hydrocarbons
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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

24
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.

25
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 60-80 Vcl in the
  shale zones. Set to give same sort of results as
  the VclGR in the shales.

26
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.

27
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.

28
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.
• The Clay point is normally picked so that the N/D
  Vcl gives about 60-80 clay in the shales.

Above plot shows the picks in the light
hydrocarbon zones Note the Active Zones are 2
and 4
29
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.

30
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.

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Clay Volume
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Deterministic PetrophysicsPorosity
33
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
  storageof fluids
• Where, Ø Porosity Vp Pore Volume Vt
  Total Volume
• Expressed as Percentage () or Decimal (v/v)

34
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
• 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

35
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.

36
Basic Petrophysical Properties Volumes and
Porosity
Often assumed negligable in Carbonates Usually
significant in Clastics
37
Basic Petrophysical Properties Porosity Ranges
Note Theoretical maximum inter-granular porosity
for cubic-packed spherical grains is 47.6
38
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
• Sonic, Density, Density/Neutron, NMR.
• Porosities measured differ.
• No log measures porosity directly.
• Calibrate to core when possible.

39
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

Oven-dried Core Porosity
Matrix

Humidity-dried Core Porosity
VSHALE
Clay Layers
Clay surfaces Interlayers
Small Pores
Quartz
Large Pores
Isolated Pores
Hydrocarbon Pore Volume
Capillary Water
Hydration or Bound Water
Structural Water
Irreducible or Immobile Water
If sample is completely disaggregated (after
Eslinger and Pevear, 1988)
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Which Porosity Log Should I Use ?

• Where possible all porosities should be
  calibrated to core data.
• 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.
• Sonic porosity Øs (using RHG equation) is used as
  an alternative to Ød if
• The borehole is washed out or DRHOgt0.05 gm/cc.
• Density/Neutron porosity Ødn is substituted for
  Ød if
• Gas is present in the formation.
• The lithology is unknown or variable (exploration
  wells)
• 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.
• 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.

41
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 Where, Øs Sonic porosity
(v/v) ?tlog Interval transit-time measured by
the sonic log (µsec/ft) ?tma Matrix
transit-time (µsec/ft) ?tfl Transit-time of
fluid contained in the formation
(µsec/ft) Bcp Compaction factor determined by
comparison with core or regional experience.
Often assumed to be 1.
41
42
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.
43
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
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.
44
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

Where, 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)
45
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
• 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.

If neutron was logged in Limestone units convert
to actual matrix before use in weighted average
Ønd
46
Porosity and Clay Volume Estimation from Density
/ Neutron Cross-plot in shaly sands

• Porosity-Clay volume D/N Overlay construction
• Establish the (Wet) Clay point in the SE of
  Density-Neutron Cross-plotted data.
• Matrix line.
• Defined by a line joining the matrix point
  (porosity 0) to the fluid (water) point (porosity
  of 1).
• Scaled linearly in porosity.
• Matrix-Clay line.
• Defined by Matrix and (Wet) Clay points.
• Effective porosity 0 along this line.
• Scaled linearly in clay volume.

46
47
Effective Porosity

• Effective porosity
• Where, Øe Effective porosity (v/v)
• Øt Total porosity (v/v)
• Øtcl Total porosity of clay (v/v)
• Vcl clay volume (v/v)

48
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.
• 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.

49
The Borehole Environment
50
Mud Filtrate Invasion
Water-Based Mud System
Oil-Based Mud System
(c) Water-bearing formation
(d) Oil-bearing formation
51
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.

52
Fluid Density Determination for Porosity
Calculation in wells drilled with WBM

• In the hydrocarbon leg
• In the water leg
• Flushed zone saturation Sxo can be calculated
  using the Archie water saturation equation
• Where
• Rmf is the mud-filtrate resistivity
• Rxo is measured by the micro-resistivity log
  (MSFL or MLL)
• Ø is the porosity

53
Fluid Density Determination for Porosity
Calculation in wells drilled with OBM

• In the hydrocarbon leg
• In the water leg
• 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

54
Porosity Calculation in IP
55
Equations

• As much as possible the complete tool response
  equations are utilised within IP.
• This Means That
• We dont 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.

56
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.

57
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.

58
Porosity Models - Density
59
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

60
Porosity Models - Neutron
61
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

62
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
• Volcanics

63
Porosity Models Neutron / Density
64
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

65
Porosity Models Neutron / Density
66
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

67
Porosity and Water Saturation
68
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

69
Deterministic PetrophysicsWater Saturation
70
Water Saturation in clean sands - The Archie
Equation

• Archie Equation
• Six unknowns
• 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 (FR) and Resistivity Index (I)
  respectively.
• In Sandstones if lacking core choose from
• Archie Parameters a1, mn2

71
Determination of Rw and m from a Pickett Plot

• From the Archie equation
• Rearranging and substituting for resistivity
  Index
• Taking Logs
• 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 I1 (and Sw1) 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.

72
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

73
Shaly sands the effect of clay on the
conductivity
The additional conductive path reduces the
resistivity of the formation. If this effect is
not taken into account this has the effect of
increasing the calculated water saturation above
its real value. Shaly sand interpretation
corrects for this effect to calculate Sw.
The negatively charged clay surfaces provide an
additional conductive path.
74
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.
• Shaly sand saturation equations account for the
  extra conductivity provided by the shales.

75
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
• The Qv is indicative of the degree of shaliness
  of a formation
• Qvlt0.1 Clean sands
• 0.1ltQvlt0.2 Slightly shaly sands
• 0.2ltQvlt0.3 Moderately shaly sands
• 0.3ltQvlt0.5 Shaly sands
• Qvgt0.5 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.

76
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.

77
Alternative Shaly Sands Water Saturation
EquationsComparison

• Several equations are shown at right in
  conductivity form which facilitates comparison.
• The similarities and differences between
  equations are apparent.

77
77
78
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 Sw.
• 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 (100s 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 Sw 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)

79
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)
• Where, Swe Effective water saturation
  (v/v) Øe Effective porosity
  (v/v) a Tortuosity constant m Cementation
  exponent
• n Saturation exponent
• Rw Formation water resistivity (ohm.m)
• Rcl Clay resistivity (ohm.m)

80
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.

81
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
• Where, Swt Total water saturation
  (v/v) Øt Total porosity (v/v) a WS
  Tortuosity constant m WS Cementation
  exponent
• n WS Saturation exponent
• Rw Formation water resistivity (ohm.m)
• B Cation Mobility (mho cm2/meq)
• Qv Cation Exchange Capacity (meq/ml)

82
Use of Waxman Smits Equation

• Calculate Øt from logs.
• Calculate B using the Thomas equationWhere, B
  Cation Mobility (mho cm2/meq) T Formation
  temperature (ºC) Rw Formation water
  resistivity _at_ T (ohm.m)
• Obtain a relationship between Qv and Øt using
  special core analysis data.
• a m and n are best determined from SCAL.

83
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

84
Example of the Effect of Shaly Sand Analysis

• Water salinity 11,000ppm Rw 0.2 ohm.m _at_ 200ºF
• Hence from Thomas equation B 10.5
• a1, m1.78, n1.33
• Qv-2.086Ø0.55
• Moderately shaly formation but relatively fresh
  water.
• Hence treat as shaly sand.
• Comparison of log derived Sw with Sw/Height
  Function and Dean-Stark data much improved.

85
Water Saturation Calculation in IP
86
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.

87
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.

88
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

89
Water Saturation Dual Water

• 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.

90
Water Saturation Juhasz

• 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.

91
Water Saturation Waxmann-Smits

• 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.

92
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.

93
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.

94
Limits and Bad Hole

• 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.

95
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.

96
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.

97
Deterministic Petrophysics Net and Pay
98
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

99
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.

100
Determining Net Sand cut-offs

• Determine using a Vcl cut off.
• The cut off is generally arbitrary and of the
  form Vcllt Cut-off.
• 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

101
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 k1mD
• Gas field k0.1mD
• 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
  VclltCut-off and ØgtCut-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 DensityVersus 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.

102
Net Cut-offs Useful Plots
103
Determination of Net Cut-off using
Porosity/Permeability cross-plot

• Determination of porositycut-off equivalent to a
  1mDpermeability cut-off in an oil reservoir.

103
104
Determination of Net Pay

• Net Pay is determined by the addition of a water
  saturation cut off to the Net Reservoir
  Criteria VclltCut-off and ØgtCut-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.

105
Reservoir Summaries in IP
106
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.
• Note that additional curves can be selected for
  averaging without being used as cut-offs.

107
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

108
Cutoffs and Summation Output Curves

• Specify output set
• Specify Reservoir and Pay flags.
• Specify names for curves to be cumulative in the
  summaries

109
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.

110
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.

111
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.

112
Parameter Sets
113
Parameter Sets

• Parameter Sets are created when any of the
  zonable interpretation modules are run.
• 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

114
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.

115
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.

116
Delete Parameter Sets Well

• Selecting the Well gt 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.

117
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.

118
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.

119
Multi-well 3-D Parameter viewer

• Viewgt3-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

120
Curve History

• CHgt 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

121
Movie

• On the IP installation disk we supply a movie
  file which takes the user through a quick look
  Petrophysical interpretation.

122
Summary

• Over the past few days you should have learnt
• How IPs 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

123
Interactive Petrophysics (IP4)Advanced
124
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
• Pore Pressure Calculations in IP

125
Statistical Curve Facies Prediction

• Fuzzy Logic

126
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

127
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

128
Fuzzy Logic

• Reproduces the dynamic range better than
  regression.
• Curve to be predicted.
• Curves used to predict from.

128