Intro to Petrophysics
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Transcript of Intro to Petrophysics
FORMATION EVALUATION
BASED ON LOGGING DATA
Pradyut Bora
Senior Geologist
Geology & Reservoir Deptt.
• Objective
• Quick look log interpretation
• Deterministic log analysis method
• Shale effects
• Shaly sand models
Outline
• What kind of rock is present ?
reservoir or non-reservoir rock?
• If Reservoir rock exists.
Are any hydrocarbon present ?
• Type of hydrocarbon present –
whether oil or gas?
• How much hydrocarbon is there ?
(pay thickness, porosity, saturation etc. and finally the estimation of reserve)
The fundamental questions that has to find answers during Formation evaluation
Formation Evaluation & Objective
Formation Evaluation & Objective
• Well logs contains key information about the formation drilled in different petrophysical measurements. i.e.
Prospective zones of hydrocarbon.
Reservoir type and thickness.
Estimation of Porosity, permeability.
Fluid type present in the pores and saturation level.
• Objective: To economically establish the existence of producible hydrocarbon reservoirs (oil & gas).
Electrical Logs: measure the electrical properties of the formation
alongwith the formation fluids.
Gamma Ray Logs: measure the natural radioactivity of the
formation.
Self Potential Log: measures the potential difference in milli-volts
between an electrode in the borehole and a grounded electrode at
surface.
Density Logs: measure electron density of the formation which is
related to formation density.
Neutron logs: measure hydrogen index of the formation.
Sonic Logs: measure the elastic or (sound) wave properties of the
formation.
Caliper Logs: measure the size or geometry of the hole.
Basic Logging Tools and their Measurements
Basic Logging Tools & Interpretable
Parameters
Log Type Physical
Measurement
Derived
Parameter
Interpreted
Parameter
Resistivity
-Induction
-Laterolog
-Micro Laterolog
Voltage (V)
V and Current (I)
Current
Rt
Rt
Rxo
Sw
Sw
Sxo
Acoustic
- Sonic
Transit Time
PHIs, ITT
Lithology
Nuclear
- Density
- Neutron
Electron
Hydrogen
RHOB, PHID
PHIN
Lithology
Lithology
Auxiliary
-Natural GR
-Self Potential
-Caliper
Natural Radioactivity
mV
(in)
None
None
Dh, Volume
Vsh
Vsh
Petrophysical Interpretation
• Qualitative: Assessment of reservoir
properties, fluid type form log pattern.
• Quantitative: Numerical estimation of
reservoir properties viz. % of oil, water etc.
Identification of Reservoir and Non-Reservoir Rocks
From SP & GR logs
RESERVOIR ROCKS –
Low Gamma Ray
Good SP development
NON RESERVOIR ROCKS-
High Gamma Ray
Flat SP development
Sand
Shale
Reservoir Rocks: Porous & Permeable rock
Sand
grain
Sand
grain
G
A
S
G
A
S
O
I
L
Low GR
SP Deflection
Indicates
Reservoir
Rocks
High Resistivity
RHOB-NPHI
SHOWS VERY
GOOD CROSSOVER
INDICATING
GAS
Composite Log
Gamma Ray
Caliper
Resistivity
Density
Neutron
Qualitative Interpretation Of Well Logs
Quick-look hydrocarbon detection
Rgas>Roil>Rwater
Oil-Water contact
Gas-Oil contact
W
A
T
E
R
O
I
L
Sand Top G
A
S
Integration of drill-cutting sample ,
Side-wall core data, nearby well
data is important to confirm the
predication of fluid type.
Advanced logging tools are also
used to record sometimes to
ascertain the fluid type.
Qualitative
Interpretation Of Well Logs
Rgas>Roil>Rwater
RHOB-NPHI
GOOD CROSSOVER
INDICATE GAS
• Estimation of effective porosity & permeability.
• Estimation of volume of clay fraction.
• Estimation of hydrocarbon saturation.
• Determination of the depth and thickness of
net pay.
• Estimation of reserves of hydrocarbon.
Quantitative Interpretation of Well logs
Estimation of Porosity From Neutron, Density and Sonic Logs
POROSITY (Ø) = VOL. OF PORE SPACE / BULK VOL. OF
ROCK
EFFECTIVE POROSITY (Øe) = VOL. OF INTERCONNECTED PORE SPACE / VOL. OF ROCK
Inter particle Porosity
Estimation of Porosity From Neutron, Density and Sonic Logs
Estimation of Porosity By using Cross-plots From Neutron, Density and Sonic Logs
Can not be measured directly but inferred from determination of
WATER SATURATION (Sw) from RESISTIVITY and POROSITY
logs.
• Sw – Fraction of pore space occupied by water.
• Sh – Fraction of pore space occupied by hydrocarbon.
Sw+Sh=1 or Sh=1-Sw
Estimation of Hydrocarbon Saturation
water
oil
Current travels along the
path of least resistance
which is measured as wet
resistivity (Ro).
As the porosity changes
the value of Ro consistently
changes.
Sw = 100%
Ro
Rw : Formation water resistivity
Sand grains
water
Water Saturation Estimation
Objective: whether the pores of the formation is completely saturated
with formation water or the pore space is partially saturated with
oil/gas.
Water Saturation Estimation
Sw= 100%, Rt= Ro Sw<100%, Rt>Ro
Ro = Resistivity of the formation with pores 100% saturated with water
Rt = Actual resistivity of formation measured
Water saturation can be expressed as a function of Rw, Ro, Rt and
porosity.
Rw
Archie’s Equation For Water Saturation (Sw) Estimation
Sw = a x Rw
Фm x Rt
1/2
Formation Water Resistivity (Rw) Estimation
• Measured various ways:
– Direct laboratory measurements of formation water sample.
– From water salinity value by using chart.
– From Self Potential log.
– From resistivity log using Archie’s equation.
Resistivity of NaCl Solution (at certain temperature)
Given
(1)Salinity= 10000 ppm @ 700 F
Enter salinity at Y-axis (right)
Temerature at X-axis
Resistivity value at Y-axis(left)
Resistivity= 0.6 0hm.m
(2) Salinity= 10000 ppm @ 1500 F
Resistivity= 0.3 0hm.m
Rw Estimation: From salinity & temperature chart
Rw Estimation: From Self Potential Log
Shale Base line
Clean sand line
SP Curve
Shale
Sand
SSP= -45 mV SP scale is 15 mV/div.
• SP current develop due to difference in
salinity between formation fluid and the
borehole fluid (Mud).
– Liquid Junction Potential
– Membrane Potential
• The movement of ions, which causes the
SP phenomenon is possible only in
formation having a certain minimum
permeability.
• The first step is to compute the Static
SP (SSP), which is the ideal SP
response for thick clean water bearing
zone (shale free).
Rw Estimation: From SP Log
SSP = -K Log aw/amf -----1
SSP= Static SP
aw, amf = chemical activities of formation water & mud filtrate respectively
K= a constant =71 at 77°F, varies directly proportion to absolute temperature
For NaCl solutions, Chemical activities are inversely proportional to resistivity, but not for all type of waters.
So terms Rweq & Rmfeq are used, which, by definition
aw/amf=Rmfe/Rwe
Hence, SSP = -K Log Rmfeq/Rweq -----2
Calculation of Rmfeq:
if Rmf>0.1 ohm m at 75° F, then Rmfeq = 0.85 Rmf
if Rmf< 0.1 ohm m at 75° F, the use Chart SP-2 to find Rmfe
Total Electrochemical emf (Ec) for the two phenomena:
Estimating Rw from SP-Basic parameters
Rw Estimation: From SP Log
0.025
Rweq
Ohm-m
Rweq=0.025 ohm-m
Rw = 0.31 ohm m
Rw Estimation: From Resistivity Log
Archie’s equation solve for Rw
Rw= (Rt x Sw2)/ Φ2
For clean water bearing sand:
Sw=1
Hence, Rw = Rt x Φ2
Read Rt from log.
Calculate porosity (Φ) from porosity log.
Find Rw.
W
A
T
E
R
O
I
L
G
A
S
Sw= 1 Ro= Rt
Quicklook Summary of Estimation of Water saturation
(Sw) by using Archie’s Equation
Clean (Shale Free) Formation
Shaly Formation
• No sand/ reservoir is practically clean and free of any clay or
other fine minerals.
• When the volume of clay is >15%, formation is termed as shaly.
• Shale contains water that affects Sw evaluation because its
reduce the true resistivity of the formation.
• Porosity and permeability is also affected due to presence of
shale.
SHALE DISTRIBUTION
Clean Formation (No Shale
Increase of Rt with the increase of Oil saturation
Shaly Formation
Decrease of Rt with the increase of Shaliness at
constant saturation.
Steps of Shaly Sand Analysis
1. Determination of volume of shale (Vsh).
2. Determination of effective porosity (phie).
3. Calculation of effective water saturation (Swe)
using corrected porosities and shaly sand
water saturation equation.
Gamma ray log is an indicator of
shaliness of sand
V Shale =
GRlog- GRClean
GRShale- GRClean
GRLog
GRClean
GRShale
V Shale =
80- 20
180- 20
Gamma ray Log - Shale volume evaluation
Self Potential Log - Shale volume evaluations
SP log is an indicator of shaliness of sand
SPClean
SPShale
SPLog
Vsh Correction- Effective porosity Estimation
ρb = Φe* ρf +Vcl*ρclay+(1- Φe-Vcl)* ρma
ρma - ρb
ρma - ρf Φe=
ρma - ρsh
ρma - ρf Vsh
1- Φe-Vsh
ρma
Vsh , ρsh
Φe, ρf
Φe= ΦN – Vsh* Φsh
where, Φcl is the neutron porosity against clean shale
Effective Porosity from Density porosity
Effective Porosity from Neutron porosity
Shale and Saturation Evaluation
• The Archie equation has changed to take into
account the shale effect.
• To estimate the volume of clay in the reservoir
rock to eliminate their effect in porosity and
water saturation computation.
• There are many equation for shaly formation
evaluation has developed.
Saturation Estimations Equations for Shaly Sand
Building Petrophysical Model
(Elan plus Software)
• Reconstruction of subsurface rock formations along with fluid
saturation using log data.
• Initially Petrophysicist make a preliminary assumption of possible
rock type & fluid present from the log response
Low GR, High density(2.7), low porosity(<0.3) --- ? Limestone
Low GR, very low density, very high porosity ---- ? Coal
High GR, moderate neutron porosity, high density --- ? Shale
High resistivity zone sitting over low resistivity zone against a
sand --- Oil above water ?
Density Neutron crossover ---- ? Gas
Finally the modeling software solve a model using the input data. The
model shows the Lithology and Fluid saturation in quantitative terms.
Parameters
Rw, Rmf, MW, BHT
Measurements
Rsistivity, Density
GR, SP
Volumes (variables)
Quartz, Clay, coal
Oil, water, gas
Model
Generation
Model
Satisfactory
Model
Doubtful
Sand%
Clay%
Φe %
Sw (% of Φ)
Oil (% of Φe)
Gas (% of Φe)
Petrophysical Interpretation
Inputs Model generation Outputs
Interpreted Model
Outputs:
Lithology
Reservoir thickness
Porosity
Gas/oil/water %
Some definitions
Gross thickness: Thickness of a zone between two geological Horizons or markers
Net Thickness: Thickness of certain facies, say sand , within that zone (thickness after GR or Vclay cut-off)
Net Reservoir Thickness: Thickness of that part of net thickness which have certain amount of porosity to be a reservoir (thickness after Vclay & Phie cutoff)
Net Pay thickness: Thickness of that part of net reservoir which have certain amount of oil saturation to be termed as pay (thickness after Vclay & Phie & Sw cutoff)
H2
0----------Vcl-----------1 0-----------Phie- -----0.5 1-----------Sw----- -----0 0----------Vcl-----------1 0-----------Phie- -----0.5 1-----------Sw----- -----0
H1
Gro
ss T
hic
kn
ess
Net th
ickn
ess
Net re
se
rvo
ir
Net p
ay
Cut off values Vclay>0.4 Phie<0.10 Sw>0.6
CUT OFF TO ESTIMATE NET PAY
Well to Well Correlation: Sand Correlation
Well-A Well-B Well-C Well-D Well-E
-Lateral extent of sand body
-Sand development pattern
Reserve of Hydrocarbon
Reserve (OIP)
= Area X Net pay thickness X Average Porosity X (1-water saturation)
• Preliminary assumption of rock and fluid type form
well logs helps in building effective Petrophysical
model of a formation.
• Effective use of these Formation Evaluation
techniques require high level of integration.
• Use of Shaly sand method is primarily important, if
not performed it may possible to overlook a
productive reservoir.
Conclusion
Shaly Formation Equations
Shaly Formation Equations
Permeability Estimation
• Permeability generally controlled by matrix grain size and resulting pore throat diameters.
• For same porosity, smaller the grain size, greater the surface area => decrease in permeability
• All lithologies exhibit increasing permeability with increasing porosity
• Logs cannot measure permeability of formation directly
• Permeability is measured in laboratory using core plug or from well test data
• Relationship can be obtained between log derived porosity and permeability
Permeability Estimation
Since irreducible water saturation increases with internal surface
area, Willie and Rose (1950) proposed a relationship between
permeability, porosity & irreducible water saturation:
K0.5= 100 Φ2.25
Swi
P, Q, R = constants to be calibrated from core
measurements
Most widely used version of above equation for
sandstone is Timur Equation (1968)
K= PΦQ
SwiR
Calibration is required for log derived Swi and
computed K with core measurements to effectively
use such equation
Permeability Estimation
Permeability Estimation
NET PAY MAP (OIL ISO PAY MAP)
Mud Invasion Profile Due to the effect of
drilling fluid (mud).
The hydrostatic pressure
of the mud column is
always kept higher than
the formation pressure.
This creates invasion of
the mud filtrate into the
formation around
borehole.
Depth of invasion mainly
depends on the
permeability of the
formation
Estimation of Movable HC
Sw= [FRw/Rt]0.5
Sxo= [FRmf/Rxo]0.5
Sh= 1-Sw-------A
Shr= 1-Sxo-------B
Shm= A-B
= Sh-Shr
= [1-Sw]-[1-
Sxo]
= Sxo-Sw
For un-invaded zone:
For invaded zone:
Movable hydrocarbon saturation:
Spontaneous Potential Logs: Principles
• SP current develop due to difference in
salinity between formation fluid and the
borehole fluid (Mud)
• The SP curve is a recording vs. depth of the
difference between potential of a movable
electrode in the borehole and the fixed
potential of surface electrode
SP Log: Principle
• Electrochemical Component : Membrane Potential
High saline
formation water :
High NaCl
concentration
Less saline Borehole
fluid: Low NaCl Soln.
Shale: Acts as a
membrane* permits
movements of Na+
(Cataions)
Porous & Permeable bed
Shale: Impervious
Mud
Na+
Due to layered clay structure and charges on the layer, Shales are
permeable to Na+ cations but impervious to Cl- anions
When shale separates NaCl solution of different salinities, Na+ cations
(+ve charges) move through the shale from more concentrated to the
less concentrated solution.
This movement of charged ion is an electric current and the force
causing them to move constitutes a potential across the shale.
SP Log: Principle
Liquid Junction Potential
Na+ & Cl- ions can transfer from
either solution to the other
In the edge of the invaded zone, mud
filtrate and formation water are in
direct contact.
Since Cl- ions have more mobility than Na+,
the net result is a flow of –ve charges from
more concentrated soln. to less concentrated
soln.
It is equivalent to current flow in opposite
direction
Total Electrochemical emf Ec for the two phenomena:
Ec= -K log aw/amf
Aw & amf are chemical activity of the two soln. at formation temp. Chemical activity of
soln. is roughly proportional to its salt content (i.e conductivity)
K= Coefficient proportional to absolute temp; for NaCl mud filtrate and formation water
condition, K= 71 @ 25
C
Resistivity log: Focusing Electrode Logs
Current path is focused as a horizontal sheet into the formation
One electrode send an electric current from on the sonde
directly into the formation.
The return electrodes are located either on surface or on the
sonde itself.
Two guard electrodes focus the current into the formation and
prevent current lines from fanning out or flowing directly to the
return electrode through the borehole fluid.
The voltage at the main electrode is constantly adjusted during
logging in order to maintain a constant current intensity. This
voltage is therefore proportional to the resistivity of the
formation.
Dual Laterolog
Resistivity log: Focusing Electrode Logs
Dual Laterolog Laterolog
LLD LLS
Induction Logging
Required when mud is non conductive
(OBM)
High frequency alternating current is
sent through a transmitter coil
It creates a alternating magnetic field
which creates a secondary current in
the formation
This current flow in circular ground
loop path co-axial with the transmitter
coil
The ground loop current induce
magnetic field which induce signal in
the receiver coil
Receiver signal is proportional to the
conductivity of the formation
Sonic Log
– It is measurement of time (Δt) taken
by compressional sound wave to
travel 1 foot in the formation
– The basic configuration of the tool
consist of one transmitter (emits
compresional sound wave) & two
receivers
Porosity Measurements: Sonic Log
– Sonic travel time gives idea of porosity in the formation
– Density measured by log is the density of the fluids in the pores + density of the matrix
Δt
Matrix (Δt matrix) Fluid
(Δt Fluid)
Φ 1-Φ
Δtlog = Φ*Δtfluid + (1- Φ)* Δtmatrix
Δtlog - Δtmatrix
ΔtFluid - Δtmatrix
Φ=
Porosity from Density Log:
Hydrocarbon Correction in clean sand
Since the density tool reads the flushed
zone, Water saturation= Sxo
Hydrocarbon saturation is 1-Sxo
The hydrocarbon corrected density porosity
is
ρb = Φ(1-Sxo)ρh + Φ*Sxo*ρw+(1- Φ)*
ρma
1- Φ
ρma
1-Sxo,
ρh
Sxo,
ρw
Φ
1-Φ
Clean Sand Model
ρma - ρb
ρma – [(1-Sxo) ρh + Sxo*ρw] Φ=
GAMMA RAY LOG
• Gamma Rays are high-energy electromagnetic waves which are emitted by atomic nuclei as a form
of radiation
• Gamma ray log is measurement of natural radioactivity in formation verses depth.
• It measures the radiation emitting from naturally occurring U, Th, and K.
• It is also known as shale log.
• GR log reflects shale or clay content.
• Clean formations have low radioactivity level.
• Correlation between wells,
• Determination of bed boundaries,
• Evaluation of shale content within a formation,
• Mineral analysis,
• Depth control for log tie-ins, side-wall coring, or perforating.
• Particularly useful for defining shale beds when the sp is featureless
• GR log can be run in both open and cased hole
Spontaneous Potential Log (SP)
• The spontaneous potential (SP) curve records
the naturally occurring electrical potential
(voltage) produced by the interaction of
formation connate water, conductive drilling
fluid, and shale
• The SP curve reflects a difference in the
electrical potential between a movable
electrode in the borehole and a fixed reference
electrode at the surface
• Though the SP is used primarily as a lithology
indicator and as a correlation tool, it has other
uses as well:
– permeability indicator,
– shale volume indicator
– porosity indicator, and
– measurement of Rw (hence formation
water salinity).
Neutron Logging
• The Neutron Log is primarily used to evaluate
formation porosity, but the fact that it is really
just a hydrogen detector should always be kept
in mind
• It is used to detect gas in certain situations,
exploiting the lower hydrogen density, or
hydrogen index
• The Neutron Log can be summarized as the
continuous measurement of the induced
radiation produced by the bombardment of that
formation with a neutron source contained in
the logging tool which sources emit fast
neutrons that are eventually slowed by
collisions with hydrogen atoms until they are
captured (think of a billiard ball metaphor where
the similar size of the particles is a factor). The
capture results in the emission of a secondary
gamma ray; some tools, especially older ones,
detect the capture gamma ray (neutron-gamma
log). Other tools detect intermediate
(epithermal) neutrons or slow (thermal)
neutrons (both referred to as neutron-neutron
logs). Modern neutron tools most commonly
count thermal neutrons with an He-3 type
detector.
The Density Log
• The formation density log is a porosity log that measures electron density of a formation
• Dense formations absorb many gamma rays, while low-density formations absorb fewer. Thus, high-count rates at the detectors indicate low-density formations, whereas low count rates at the detectors indicate high-density formations.
• Therefore, scattered gamma rays reaching the detector is an indication of formation Density.
Scale and units:
The most frequently used scales are a range of 2.0 to 3.0 gm/cc or 1.95
to 2.95 gm/cc across two tracks.
A density derived porosity curve is sometimes present in tracks #2 and
#3 along with the bulk density (rb) and correction (Dr) curves. Track #1
contains a gamma ray log and caliper.
Resistivity Log
• Basics about the Resistivity:
• Resistivity measures the electric properties of the formation,
• Resistivity is measured as, R in W per m,
• Resistivity is the inverse of conductivity,
• The ability to conduct electric current depends upon:
• The Volume of water,
• The Temperature of the formation,
• The Salinity of the formation
The Resistivity Log:
Resistivity logs measure the ability of rocks to
conduct electrical current and are scaled in units of
ohm-
meters.
The Usage:
Resistivity logs are electric logs which are used
to:
Determine Hydrocarbon versus Water-bearing zones,
Indicate Permeable zones,
Determine Resisitivity Porosity.
• Acoustic tools measure the speed of sound waves in
subsurface formations. While the acoustic log can be
used to determine porosity in consolidated formations, it
is also valuable in other applications, such as:
• Indicating lithology (using the ratio of compressional
velocity over shear velocity),
• Determining integrated travel time (an important tool for
seismic/wellbore correlation),
• Correlation with other wells
• Detecting fractures and evaluating secondary porosity,
• Evaluating cement bonds between casing, and formation,
• Detecting over-pressure,
• Determining mechanical properties (in combination with
the density log), and
• Determining acoustic impedance (in combination with
the density log).
Acoustic Log
Pad with
25 buttons
Alternate pads
offset from each
other
Powered standoff
centralises tool
Microresistivity
imaging portion of
STAR tool
CBIL is attached to
lower end of tool
string
6 alternately offset
electrical imaging pads
FMI
STAR EMI
Electrical tools widely used today
Understanding Depositional facies :Integration of Core and Image Log Information
Core Image Log 2d View 3D View
Field Development : Sand Correlation
Barekuri -
1
FIELD DEVELOPMENT
PRACTICES:PETROPHYSICS Petrophysical Analysis
Detailed Petrophysical Analysis for Reservoir
Characterization
HC Fluid typing
Re-visiting Old Wells for possible Upsides
Clay Typing Analysis
Facies Analysis using Core
Major Inputs for Reservoir
Modelling
FIELD DEVELOPMENT PRACTICES
Resistivity of Common Rocks & Fluids
Though earth material is composed of a whole lot of rock forming minerals, in
sedimentary rock, the number of minerals actually encountered mainly are few.
Resistivity of few rock forming minerals are
Quartz 1010 ohm m
Calcite 107 ohm m
Dolomite 108 ohm m
Clay minerals 1-10 ohm m
Clays are good conductor by virtue of cation exchange on their
surfaces and their resistivity varies as a function of mineral species and
size of surface area
Formation water resistivity controlled by salt concentration and
temperature:
200 ppm NaCl (Drinking water) 26 ohm-m
35000 ppm NaCl (Sea water) 0.18 ohm-m
150000ppm NaCl 0.055 ohm m
Oil/gas 108 ohm m
Porosity from Neutron Log
ΦN against water bearing sand ( ≈17%)
ΦN against Light oil bearing sand ( ≈10%)
ΦN against Gas bearing sand( ≈6%)
ΦN against Clay Change of Neutron porosity in the same sand
due to change in fluid type
Porosity from Density Log
ρblog = Φ* ρf+ (1- Φ)* ρma
ρma - ρblog
ρma - ρf Φ=
ρblog 2.2 gm/cc 2.65 – 2.2
2.65 - 1 Φ=
0.45
1.65 Φ=
Φd= 0.27 = 27%
From Log, ρblog =2.2 gm/cc
ρma=2.65 for sandstone
ρf=1 gm/cc for water
Porosity & Lithology from Density & Neutron Cross Plot
Porosity Measurements: Sonic Log
– Sonic travel time gives idea of porosity in the formation.
Δt
Matrix (Δt matrix) Fluid
(Δt Fluid)
Φ 1-Φ
Δtlog = Φ*Δtfluid + (1- Φ)* Δtmatrix
Δtlog - Δtmatrix
ΔtFluid - Δtmatrix
Φ=
Wyllie time average equation
Study of Depositional Environment
Log Signature Analysis
Estimation of Hydrocarbon Saturation
Φ
(Sonic, density, Neuton
logs)
F=1/Φm (m=2 , 2.15)
Rw
(SP or Resistivity log)
Rt
(Laterolog, Induction log)
Sw=(F*Rw)/Rt
Sh= 1-Sw
Sedimentology
- Facies analysis
- Ichnofabric analysis
- Depositional environment
- Palaeocurrents
- Sandbody geometry
- Sequence stratigraphy
Petrophysics
- Porosity typing
- Permeability heterogeneity
- Flow baffles / barriers
- Diagenetic effects
- Net sand & thin beds
- Input to reservoir models
Structure
- Structural dip
- Fault detection
- Fracture description
- In situ stress
- Correlation
- Integration with seismic
Borehole image applications
Core Analysis Data & Its Application:
Supplementary Tests
Data Use
Vert. Permeability Define coning probability and gravity
drainage potential
Core-Gamma log Define lost core and depth relation of core
with down-hole Gamma Ray logs
Grain Density Refine density log calculations
Water Chloride Define connate water salinity in OB cores
and degree of flushing in WB cores
Oil Gravity Estimate reservoir gravity from correlations
based on retort oil gravity
General Log Response of Different
Formations of Upper Assam
DEPTH (M) FORMATION LITHOLOGY
0 - 1700 ALLUVIUM UNCONSOLIDATED
SAND/CLAY
1700 – 2100 GIRUJANS SOFT MOTTLED CLAY
WITH THIN SANDSTONE
BANDS
2100 – 2600 TIPAMS &
SURMA
MEDIUM TO FINE
GRAINED SANDSTONE
2600 – 3000 BARAILS
MUDSTONE, COAL AND
FINE GRAINED
SANDSTONE.
OIL BEARING
3000 - 3400 KOPILIS SPLINTERY SHALE WITH
VERY FINE GRAINED
SANDSTONE
3400 – 3470 PRANGS LIMESTONE
3470 – 3530 NARPUHS SPLINTERY SHALE AND
SILTSTONE
3530 - 3640 LAKADONG
LIMESTONE,
SANDSTONE, HARD
SHALE AND
CARBONACEOUS SHALE
3640 - 3700 LANGPAR
COARSE GRAINED
SANDSTONE WITH
SHALE
OIL BEARING
3700 - BASEMENT GRANITE BASEMENT
ROCK
Sub Surface Geology
Upper Assam Basin
Girujan
Tip
am
s B
ara
ils
Kop
ilis
Prang
Narpuh
Lakadon
g
Langpar
Girujan Formation
• Lithology is mainly Clay with thin sand bands
• GR serrated but helps to identify lithology
• Mixed type clay, high in montmorillonite
• Thickness varies, increases in SE direction
• Low formation water salinity (200-600 ppm)
• Low Density (2.2 gm/cc)
Girujan Log Response
Tipam Formation
• Lithology is mainly thick sand (>100m) with intervening
shale, sands are silty
• Abundance of radioactive material
• Difficult to differentiate lithology from GR log
• Shales are made up of mainly montmorrilonite, kaolinite clay
• Illite present at deeper zone
• Formation water salinity increases downwards (1000 to 2000
ppm)
Tipam Log response
Barail Formation
• Barail is divided into two
– Upper Argillaceous unit –
• Mainly Shale facies
• High density calcareous bands
• Kaolinitic /Illite type of clay
• Coal bands
• Thin channel sands
– Lower Arenaceous unit –
• Thick sand with fining up sequence
• Kaolinite dominant clay
• Formation water salinity- 2500-3500 ppm
Arg
illa
ceo
us
Un
it
Are
nac
eou
s U
nit
Barail Log response (Argillaceous)
Barail Log response (Arenaceous)
Kopili Formation
• Monotonous shale, splintary in nature, deposited in shallow marine condition
• Thin silty sand present
• Regionally extensive
• Characterized by high GR, Mixed type of clay
• Highly enlarged borehole due to unstable nature of the formation
• Formation water salinity 3600-4000 ppm
Kopili Log response
Prang Formation
• Limestone bands with splintary shale and siltstone.
• Low GR, no SP deflection, high resistivity
• Low neutron porosity, high density (2.71 gm/cc)
• Laterally continuous, good marker bed
Prang Log Response
Narpuh Formation
• Lithology similar to Kopili formation
• Splintary shale and siltstone (sand facies in type area)
• More sandy towards NE part of the basin (Baghjan – Mechaki)
• Kaolonite – Illite dominant clay.
Narpuh Log Response
Lakadong Member
• Highly variable lithology
• Broadly subdivided to three distinct units:
– Upper calcareous zone
– Middle sandy zone
– Bottom carbonaceous zone
• Clay type is mainly kaolinite
• Sands are clean – low GR
• Shales are Hot at bottom zone! – GR upto 200 API
• Formation water salinity 3500-4000 ppm
• Thickness varies from 120-160m
Lakadong Log Response
Lakadong
Top calcareous zone
Lakadong
Middle Sand zone
Lakadong
Bottom Carbonaceous zone
Langpar Formation
• Development of thick sand body
• Blocky to fining up sequence
• Fluvial to near shoe facies
• Shales show high resistivity
• Devoid of coal / carbonaceous shale
• Thickness increases to east & southeast direction
Langpar Formation
Geological Time Scale
DEPTH (M) FORMATION LITHOLOGY
0 - 1700 ALLUVIUM UNCONSOLIDATED
SAND/CLAY
1700 – 2100 GIRUJANS SOFT MOTTLED CLAY
WITH THIN SANDSTONE
BANDS
2100 – 2600 TIPAMS &
SURMA
MEDIUM TO FINE
GRAINED SANDSTONE
2600 – 3000 BARAILS
MUDSTONE, COAL AND
FINE GRAINED
SANDSTONE.
OIL BEARING
3000 - 3400 KOPILIS SPLINTERY SHALE WITH
VERY FINE GRAINED
SANDSTONE
3400 – 3470 PRANGS LIMESTONE
3470 – 3530 NARPUHS SPLINTERY SHALE AND
SILTSTONE
3530 - 3640 LAKADONG
LIMESTONE,
SANDSTONE, HARD
SHALE AND
CARBONACEOUS SHALE
3640 - 3700 LANGPAR
COARSE GRAINED
SANDSTONE WITH
SHALE
OIL BEARING
3700 - BASEMENT GRANITE BASEMENT
ROCK
Sub Surface Geology
Upper Assam Basin
Girujan
Tip
am
s B
ara
ils
Kop
ilis
Prang
Narpuh
Lakadon
g
Langpar
Girujan Formation
• Lithology is mainly Clay with thin sand bands
• GR serrated but helps to identify lithology
• Mixed type clay, high in montmorillonite
• Thickness varies, increases in SE direction
• Low formation water salinity (200-600 ppm)
• Low Density (2.2 gm/cc)
Girujan Log Response
Tipam Formation
• Lithology is mainly thick sand (>100m) with intervening
shale, sands are silty
• Abundance of radioactive material
• Difficult to differentiate lithology from GR log
• Shales are made up of mainly montmorrilonite, kaolinite clay
• Illite present at deeper zone
• Formation water salinity increases downwards (1000 to 2000
ppm)
Tipam Log response
Barail Formation
• Barail is divided into two
– Upper Argillaceous unit –
• Mainly Shale facies
• High density calcareous bands
• Kaolinitic /Illite type of clay
• Coal bands
• Thin channel sands
– Lower Arenaceous unit –
• Thick sand with fining up sequence
• Kaolinite dominant clay
• Formation water salinity- 2500-3500 ppm
Arg
illa
ceo
us
Un
it
Are
nac
eou
s U
nit
Barail Log response (Argillaceous)
Barail Log response (Arenaceous)
Kopili Formation
• Monotonous shale, splintary in nature, deposited in shallow marine condition
• Thin silty sand present
• Regionally extensive
• Characterized by high GR, Mixed type of clay
• Highly enlarged borehole due to unstable nature of the formation
• Formation water salinity 3600-4000 ppm
Kopili Log response
Prang Formation
• Limestone bands with splintary shale and siltstone.
• Low GR, no SP deflection, high resistivity
• Low neutron porosity, high density (2.71 gm/cc)
• Laterally continuous, good marker bed
Prang Log Response
Narpuh Formation
• Lithology similar to Kopili formation
• Splintary shale and siltstone (sand facies in type area)
• More sandy towards NE part of the basin (Baghjan – Mechaki)
• Kaolonite – Illite dominant clay.
Narpuh Log Response
Lakadong Member
• Highly variable lithology
• Broadly subdivided to three distinct units:
– Upper calcareous zone
– Middle sandy zone
– Bottom carbonaceous zone
• Clay type is mainly kaolinite
• Sands are clean – low GR
• Shales are Hot at bottom zone! – GR upto 200 API
• Formation water salinity 3500-4000 ppm
• Thickness varies from 120-160m
Lakadong Log Response
Lakadong
Top calcareous zone
Lakadong
Middle Sand zone
Lakadong
Bottom Carbonaceous zone
Langpar Formation
• Development of thick sand body
• Blocky to fining up sequence
• Fluvial to near shoe facies
• Shales show high resistivity
• Devoid of coal / carbonaceous shale
• Thickness increases to east & southeast direction
Langpar Formation
Geological Time Scale