FORMATION EVALUATION BASED ON LOGGING DATA
Pradyut Bora Senior Geologist Geology & Reservoir Deptt.
Outline
• Objective • Quick look log interpretation • Deterministic log analysis method • Shale effects • Shaly sand models
Formation Evaluation & Objective The fundamental questions that has to find answers during Formation evaluation • 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)
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).
Basic Logging Tools and their Measurements 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 & 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 ROCKSHigh Gamma Ray Flat SP development Reservoir Rocks: Porous & Permeable rock
Sand grain
Sand grain
Sand Shale
Qualitative Interpretation Of Well Logs Quick-look hydrocarbon detection
Composite Log Gamma Ray Caliper Resistivity Density Neutron
Low GR SP Deflection Indicates Reservoir Rocks
RHOB-NPHI SHOWS VERY GOOD CROSSOVER INDICATING GAS G A S
High Resistivity G A S
O I L
Rgas>Roil>Rwater
Qualitative Interpretation Of Well Logs
Sand Top G A S O I L
W A T E R
Rgas>Roil>Rwater
Gas-Oil contact
Oil-Water contact RHOB-NPHI GOOD CROSSOVER INDICATE GAS
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.
Quantitative Interpretation of Well logs • 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.
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
Estimation of Hydrocarbon Saturation 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
oil 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.
Sw = 100%
Current travels along the path of least resistance which is measured as wet resistivity (Ro). Ro
As the porosity changes the value of Ro consistently changes.
Sand grains Rw : Formation water resistivity
water
Water Saturation Estimation
Rw 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.
Archie’s Equation For Water Saturation (Sw) Estimation
a x Rw Sw = 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.
Rw Estimation: From salinity & temperature chart Resistivity of NaCl Solution (at certain temperature) Given (1)Salinity= 10000 ppm @ 70 0 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 @ 150 0 F
Resistivity= 0.3 0hm.m
Rw Estimation: From Self Potential Log •
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).
Clean sand line Shale Base line SP Curve
Sand Shale
SP scale is 15 mV/div.
SSP= -45 mV
Rw Estimation: From SP Log Total Electrochemical emf (Ec) for the two phenomena: 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
Estimating Rw from SP-Basic parameters
Rw Estimation: From SP Log Rweq Ohm-m
0.025
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.
G A S O I L
Sw= 1
W A T E R
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 - Shale volume evaluation GRShale
Gamma ray log is an indicator of shaliness of sand
GRLog GRlog- GRClean
V Shale = GRShale- GRClean
80- 20 V Shale =
180- 20
GRClean
Self Potential Log - Shale volume evaluations SP log is an indicator of shaliness of sand
SPLog
SPShale
SPClean
Vsh Correction- Effective porosity Estimation Effective Porosity from Density porosity ρb = Φe* ρf +Vcl*ρclay+(1- Φe-Vcl)* ρma Φe=
ρma - ρb ρma - ρf
Vsh
ρma - ρsh ρma - ρf
Φe, ρf
Vsh , ρsh 1- Φe-Vsh ρma
Effective Porosity from Neutron porosity Φe= ΦN – Vsh* Φsh where, Φcl is the neutron porosity against clean shale
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.
Petrophysical Interpretation Inputs
Model generation
Measurements Rsistivity, Density GR, SP Parameters Rw, Rmf, MW, BHT
Model Satisfactory Model Generation
Model Doubtful Volumes (variables) Quartz, Clay, coal Oil, water, gas
Outputs
Sand% Clay% Φe % Sw (% of Φ) Oil (% of Φe) Gas (% of Φe)
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)
CUT OFF TO ESTIMATE NET PAY H1 Net pay
Net reservoir
Net thickness
Gross Thickness
H2 0----------Vcl-----------1
Cut off values
Vclay>0.4
0-----------Phie- -----0.5 1-----------Sw----- -----0
Phie<0.10
Sw>0.6
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)
Conclusion • 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.
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: P, Q, R = constants to be calibrated from core PΦQ K= S R measurements wi Most widely used version of above equation for sandstone is Timur Equation (1968) Φ2.25 0.5 K = 100 S wi
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 For un-invaded zone: Sw= [FRw/Rt]0.5 Sh= 1-Sw-------A For invaded zone: Sxo= [FRmf/Rxo]0.5 Shr= 1-Sxo-------B Movable hydrocarbon saturation:
Shm= A-B = Sh-Shr = [1-Sw]-[1Sxo] = Sxo-Sw
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 Less saline Borehole fluid: Low NaCl Soln.
Shale: Impervious Na+
Mud
Porous & Permeable bed
Shale: Acts as a membrane* permits movements of Na+ (Cataions) High saline formation water : High NaCl concentration
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 Dual Laterolog 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.
Resistivity log: Focusing Electrode Logs Laterolog
Dual Laterolog
LLS
LLD
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
Δtlog = Φ*Δtfluid + (1- Φ)* Δtmatrix
Δtlog - Δtmatrix Φ= ΔtFluid - Δtmatrix
Φ Fluid (Δt Fluid)
1-Φ
Matrix (Δt matrix)
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 ρma - ρb ρbΦ== Φ(1-Sxo)ρh + Φ*Sxo*ρw+(1- Φ)* ρma – [(1-Sxo) ρh + Sxo*ρw] ρma
Sxo, ρw
1-Sxo, ρh 1- Φ ρma
Clean Sand Model
Φ 1-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 ohmmeters. The Usage: Resistivity logs are electric logs which are used to: Determine Hydrocarbon versus Water-bearing zones, Indicate Permeable zones, Determine Resisitivity Porosity.
Acoustic Log •
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).
Electrical tools widely used today FMI Pad with 25 buttons Microresistivity imaging portion of STAR tool
Alternate pads offset from each other
6 alternately offset electrical imaging pads
Powered standoff centralises tool
CBIL is attached to lower end of tool string
STAR
EMI
Understanding Depositional facies :Integration of Core and Image Log Information
Core
Image Log 2d View
3D View
Field Development : Sand Correlation
FIELD DEVELOPMENT PRACTICES:PETROPHYSICS Petrophysical Analysis
Barekuri 1
Detailed Petrophysical Analysis for Reservoir Characterization
HC Fluid typing Re-visiting Old Wells for possible Upsides
FIELD DEVELOPMENT PRACTICES
Clay Typing Analysis
Facies Analysis using Core
Major Inputs for Reservoir Modelling
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 Calcite Dolomite
1010 ohm m 107 ohm m 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) 35000 ppm NaCl (Sea water) 150000ppm NaCl Oil/gas
26 ohm-m 0.18 ohm-m 0.055 ohm m 108 ohm m
Porosity from Neutron Log ΦN against Clay
Change of Neutron porosity in the same sand due to change in fluid type
ΦN against Gas bearing sand( ≈6%)
ΦN against Light oil bearing sand ( ≈10%)
ΦN against water bearing sand ( ≈17%)
Porosity from Density Log ρblog = Φ* ρf+ (1- Φ)* ρma Φ=
ρma - ρblog ρma - ρf
From Log, ρblog =2.2 gm/cc ρma=2.65 for sandstone ρf=1 gm/cc for water 2.65 – 2.2
Φ=
2.65 - 1
0.45 Φ=
1.65
Φd= 0.27 = 27%
ρblog 2.2 gm/cc
Porosity & Lithology from Density & Neutron Cross Plot
Porosity Measurements: Sonic Log – Sonic travel time gives idea of porosity in the formation.
Δt
Wyllie time average equation Δtlog = Φ*Δtfluid + (1- Φ)* Δtmatrix
Δtlog - Δtmatrix Φ= ΔtFluid - Δtmatrix
Φ Fluid (Δt Fluid)
1-Φ
Matrix (Δt matrix)
Study of Depositional Environment
Log Signature Analysis
Estimation of Hydrocarbon Saturation Φ (Sonic, density, Neuton logs)
Rw (SP or Resistivity log) Rt (Laterolog, Induction log)
F=1/Φm (m=2 , 2.15)
Sw=(F*Rw)/Rt
Sh= 1-Sw
Borehole Structure image applications Petrophysics
Sedimentology
- Facies analysis
- Structural dip
- Porosity typing
- Ichnofabric analysis
- Fault detection
- Permeability heterogeneity
- Depositional environment - Palaeocurrents - Sandbody geometry - Sequence stratigraphy
- Fracture description - In situ stress
- Flow baffles / barriers
- Correlation
- Diagenetic effects
- Integration with seismic
- Net sand & thin beds - Input to reservoir models
Core Analysis Data & Its Application: Supplementary Tests Use
Data 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
Oil Gravity
Define connate water salinity in OB cores and degree of flushing in WB cores Estimate reservoir gravity from correlations based on retort oil gravity
General Log Response of Different Formations of Upper Assam
DEPTH (M)
Sub Surface Geology
Upper Assam Basin
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
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
LAKADONG
LIMESTONE, SANDSTONE, HARD SHALE AND CARBONACEOUS SHALE
LANGPAR
COARSE GRAINED SANDSTONE WITH SHALE OIL BEARING
BASEMENT
GRANITE BASEMENT ROCK
2600 – 3000
3530 - 3640
3640 - 3700 3700 -
Kopilis
Barails
Tipams
Girujan
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 – Upper Argillaceous unit – • Mainly Shale facies
• High density calcareous bands • Kaolinitic /Illite type of clay • Coal bands
Argillaceous Unit
Barail is divided into two
• Thin channel sands – Lower Arenaceous unit – • Thick sand with fining up sequence • Kaolinite dominant clay • Formation water salinity- 2500-3500 ppm
Arenaceous Unit
•
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)
Sub Surface Geology
Upper Assam Basin
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
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
LAKADONG
LIMESTONE, SANDSTONE, HARD SHALE AND CARBONACEOUS SHALE
LANGPAR
COARSE GRAINED SANDSTONE WITH SHALE OIL BEARING
BASEMENT
GRANITE BASEMENT ROCK
2600 – 3000
3530 - 3640
3640 - 3700 3700 -
Kopilis
Barails
Tipams
Girujan
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
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Abundance of radioactive material
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Difficult to differentiate lithology from GR log
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Shales are made up of mainly montmorrilonite, kaolinite clay
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Illite present at deeper zone
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Formation water salinity increases downwards (1000 to 2000 ppm)
Tipam Log response
Barail Formation – Upper Argillaceous unit – • Mainly Shale facies
• High density calcareous bands • Kaolinitic /Illite type of clay • Coal bands
Argillaceous Unit
Barail is divided into two
• Thin channel sands – Lower Arenaceous unit – • Thick sand with fining up sequence • Kaolinite dominant clay • Formation water salinity- 2500-3500 ppm
Arenaceous Unit
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Barail Log response (Argillaceous)
Barail Log response (Arenaceous)
Kopili Formation •
Monotonous shale, splintary in nature, deposited in shallow marine condition
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Thin silty sand present
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Regionally extensive
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Characterized by high GR, Mixed type of clay
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Highly enlarged borehole due to unstable nature of the formation
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Formation water salinity 3600-4000 ppm
Kopili Log response
Prang Formation
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Limestone bands with splintary shale and siltstone.
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Low GR, no SP deflection, high resistivity
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Low neutron porosity, high density (2.71 gm/cc)
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Laterally continuous, good marker bed
Prang Log Response
Narpuh Formation •
Lithology similar to Kopili formation
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Splintary shale and siltstone (sand facies in type area)
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More sandy towards NE part of the basin (Baghjan – Mechaki)
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Kaolonite – Illite dominant clay.
Narpuh Log Response
Lakadong Member •
Highly variable lithology
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Broadly subdivided to three distinct units: – Upper calcareous zone
– Middle sandy zone – Bottom carbonaceous zone
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Clay type is mainly kaolinite
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Sands are clean – low GR
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Shales are Hot at bottom zone! – GR upto 200 API
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Formation water salinity 3500-4000 ppm
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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
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Blocky to fining up sequence
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Fluvial to near shoe facies
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Shales show high resistivity
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Devoid of coal / carbonaceous shale
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Thickness increases to east & southeast direction
Langpar Formation
Geological Time Scale
