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