![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:](https://image.slidesharecdn.com/formationevaluation-vvi-230330035140-0fc6045d/85/FORMATION-EVALUATION-V-V-I-pdf-58-320.jpg)
![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=](https://image.slidesharecdn.com/formationevaluation-vvi-230330035140-0fc6045d/85/FORMATION-EVALUATION-V-V-I-pdf-67-320.jpg)
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FORMATION EVALUATION -V V I.pdf
- 1. FORMATION EVALUATION BASED ONLOGGING DATA Pradyut Bora Senior Geologist Geology & Reservoir Deptt.
- 2. • Objective • Quicklook log interpretation • Deterministic log analysis method • Shale effects • Shaly sand models Outline
- 3. • What kindof 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
- 4. 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).
- 5. Electrical Logs: measurethe 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
- 6. 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
- 7. Petrophysical Interpretation • Qualitative:Assessment of reservoir properties, fluid type form log pattern. • Quantitative: Numerical estimation of reservoir properties viz. % of oil, water etc.
- 9. Identification of Reservoirand 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
- 10. G A S G A S O I L Low GR SP Deflection Indicates Reservoir Rocks HighResistivity 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
- 11. Oil-Water contact Gas-Oil contact W A T E R O I L SandTop 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
- 12. • Estimation ofeffective 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
- 13. Estimation of Porosity FromNeutron, 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
- 14. Estimation of Porosity FromNeutron, Density and Sonic Logs
- 15. Estimation of PorosityBy using Cross-plots From Neutron, Density and Sonic Logs
- 16. Can not bemeasured 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
- 17. Current travelsalong 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.
- 18. 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
- 19. Archie’s Equation For WaterSaturation (Sw) Estimation Sw = a x Rw Фm x Rt 1/2
- 20. 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.
- 21. Resistivity of NaClSolution (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
- 22. Rw Estimation: FromSelf 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).
- 23. Rw Estimation: FromSP 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:
- 24. Estimating Rw fromSP-Basic parameters
- 25. Rw Estimation: FromSP Log 0.025 Rweq Ohm-m Rweq=0.025 ohm-m Rw = 0.31 ohm m
- 26. Rw Estimation: FromResistivity 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
- 27. Quicklook Summary ofEstimation of Water saturation (Sw) by using Archie’s Equation
- 28. Clean (Shale Free)Formation
- 29. Shaly Formation • Nosand/ 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.
- 30.
- 31. Clean Formation (NoShale Increase of Rt with the increase of Oil saturation
- 32. Shaly Formation Decrease ofRt with the increase of Shaliness at constant saturation.
- 33. Steps of ShalySand 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.
- 34. Gamma ray logis 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
- 35. Self Potential Log- Shale volume evaluations SP log is an indicator of shaliness of sand SPClean SPShale SPLog
- 36. Vsh Correction- Effectiveporosity 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
- 37. Shale and SaturationEvaluation • 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.
- 38. Saturation Estimations Equationsfor Shaly Sand
- 39. Building Petrophysical Model (Elanplus 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.
- 40. 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
- 41. Interpreted Model Outputs: Lithology Reservoir thickness Porosity Gas/oil/water %
- 42. 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)
- 43. H2 0----------Vcl-----------1 0-----------Phie- -----0.51-----------Sw----- -----0 0----------Vcl-----------1 0-----------Phie- -----0.5 1-----------Sw----- -----0 H1 Gross Thickness Net thickness Net reservoir Net pay Cut off values Vclay>0.4 Phie<0.10 Sw>0.6 CUT OFF TO ESTIMATE NET PAY
- 44. Well to WellCorrelation: Sand Correlation Well-A Well-B Well-C Well-D Well-E -Lateral extent of sand body -Sand development pattern
- 45. Reserve of Hydrocarbon Reserve(OIP) = Area X Net pay thickness X Average Porosity X (1-water saturation)
- 46. • Preliminary assumptionof 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
- 49.
- 50.
- 52. Permeability Estimation • Permeabilitygenerally 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
- 53. Permeability Estimation Sinceirreducible 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 Swi R Calibration is required for log derived Swi and computed K with core measurements to effectively use such equation
- 54.
- 55.
- 56. NET PAY MAP(OIL ISO PAY MAP)
- 57. Mud Invasion Profile Dueto 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
- 58. Estimation of MovableHC 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:
- 59. 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
- 60. 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.
- 61. SP Log: Principle LiquidJunction 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
- 62. Resistivity log: FocusingElectrode 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
- 63. Resistivity log: FocusingElectrode Logs Dual Laterolog Laterolog LLD LLS
- 64. Induction Logging Required whenmud 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
- 65. Sonic Log – Itis 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
- 66. Porosity Measurements: SonicLog – 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=
- 67. Porosity from DensityLog: 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=
- 68. 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
- 69. 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).
- 70. Neutron Logging • TheNeutron 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.
- 71. 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.
- 72. Resistivity Log • Basicsabout 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.
- 73. • Acoustic toolsmeasure 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
- 74. Pad with 25 buttons Alternatepads 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
- 75. Understanding Depositional facies:Integration of Core and Image Log Information Core Image Log 2d View 3D View
- 76. Field Development :Sand Correlation
- 77. Barekuri - 1 FIELD DEVELOPMENT PRACTICES:PETROPHYSICS PetrophysicalAnalysis Detailed Petrophysical Analysis for Reservoir Characterization HC Fluid typing Re-visiting Old Wells for possible Upsides
- 78. Clay Typing Analysis FaciesAnalysis using Core Major Inputs for Reservoir Modelling FIELD DEVELOPMENT PRACTICES
- 79. Resistivity of CommonRocks & 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
- 80. Porosity from NeutronLog 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
- 81. Porosity from DensityLog 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
- 82. Porosity & Lithologyfrom Density & Neutron Cross Plot
- 83. Porosity Measurements: SonicLog – 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
- 84.
- 85.
- 86. Estimation of HydrocarbonSaturation 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
- 87. 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
- 88. 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
- 89. General Log Responseof Different Formations of Upper Assam
- 90. DEPTH (M) FORMATIONLITHOLOGY 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
- 91.
- 92. Girujan Formation • Lithologyis 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)
- 93.
- 94. Tipam Formation • Lithologyis 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)
- 95.
- 96. Barail Formation • Barailis 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 Argillaceous Unit Arenaceous Unit
- 97. Barail Log response(Argillaceous)
- 98. Barail Log response(Arenaceous)
- 99. Kopili Formation • Monotonousshale, 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
- 100.
- 101. Prang Formation • Limestonebands 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
- 102.
- 103. Narpuh Formation • Lithologysimilar 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.
- 104.
- 105. Lakadong Member • Highlyvariable 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
- 106.
- 107.
- 108.
- 109.
- 110. Langpar Formation • Developmentof 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
- 111.
- 112.
- 114. DEPTH (M) FORMATIONLITHOLOGY 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
- 115.
- 116. Girujan Formation • Lithologyis 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)
- 117.
- 118. Tipam Formation • Lithologyis 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)
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- 120. Barail Formation • Barailis 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 Argillaceous Unit Arenaceous Unit
- 121. Barail Log response(Argillaceous)
- 122. Barail Log response(Arenaceous)
- 123. Kopili Formation • Monotonousshale, 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
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- 125. Prang Formation • Limestonebands 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
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- 127. Narpuh Formation • Lithologysimilar 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.
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- 129. Lakadong Member • Highlyvariable 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
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- 133.
- 134. Langpar Formation • Developmentof 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
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- 136.