Formation Evaluation PDF

WELL LOGGING FORMATION EVALUATION J. Laval PGS-RGE 2024/2025 LOG INTERPRETATION QUALITATIVE AND QUANTITATIVE LOG INTERPRETATION 3  METHODOLOGY Deterministic approach: (Quicklook, Complex Litho) Shale Volume...

WELL LOGGING FORMATION EVALUATION J. Laval PGS-RGE 2024/2025 LOG INTERPRETATION QUALITATIVE AND QUANTITATIVE LOG INTERPRETATION 3  METHODOLOGY Deterministic approach: (Quicklook, Complex Litho) Shale Volume Porosity Computation Computation Hydrocarbon & Shaliness correction Lithological Prediction Water Saturation Computation The results of each step are determined by the results from prior steps 4  METHODOLOGY Stochastic Approach: (Multimin, Elan,…) Mathematical matrix inversion technique for predicting each measurement in the logging suite posed in terms of all the volumes of minerals and fluids that actually influenced each sensor; These volumes are adjusted to give the optimum match of the measured and predicted readings across the suite of measurements being modeled. Based on Inversion to « reconstruct » logs Logs Petrophysical Model Best Fitted - Minerals Mineral and fluids - Fluids volumes - Equations Components Responses Reconstructed Log and Quality Curve a model, a set of data and a result 5 LITHOLOGICAL LOG RESPONSES 7  MIXING CROSS-PLOT Application: understand advantages of the different cross plot to describe lithology 0.45 NPHI -0.15 1.95 RHOB 2.95 8  MIXING CROSS-PLOT Application: understand advantages of the different cross plot to describe lithology 0.45 NPHI -0.15 1.95 RHOB 2.95 9 M-N CROSS-PLOT M-N Crossplot is based on Neutron, density and sonic log response M and N parameter are calculated with the following formulas ( DT fl − DT ) M = 0.01* RHOB − RHO fl ( NPHI fl − NPHI ) N= RHOB − RHO fl 10 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the sum of the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Rglobal =  (Velem ( i ) * Relem ( i ) ) i 11 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrix Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl 12 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrix Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  b(1=− S xo )  hc + Vsh  sh + (1 −  − Vsh )  ma Matrix 13 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrix Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  b(1=− S xo )  hc + Vsh  sh + (1 −  − Vsh )  ma shale 14 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrix Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  b(1=− SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma Fluid 15 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrix Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  b(1=− SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma Fluid Neutron N = Vfl Nfl + Vsh Nsh + (1 −  − Vsh ) Nma log porosity shale matrix 16 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  (1 − SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma What kind of fluids can we expect ? 17  BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  (1 − SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma V fl1 V fl1 Case with 2 fluids: S fl1 = = V fl1 + V fl 2  water and HC 18  BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  (1 − SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma V fl1 V fl1 Case with 2 fluids: S fl1 = = V fl1 + V fl 2  water and HC 19  BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  (1 − SVxofl)  hc fl + Vsh  sh + (1 −  − Vsh )  ma V fl1 V fl1 Case with 2 fluids: S fl1 = = V fl1 =   S fl1 V fl1 + V fl 2  water and HC 20  BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S xo  mf +  (1 − SVxof l) fhcl + Vsh  sh + (1 −  − Vsh )  ma water HC Case with 2 fluids: Vw =   S w Vhc =   S hc =   (1 − S w ) water and HC 21 Basics of Log Interpretation – Module 2 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S w  w +  (1 − S w )  hc + Vsh  sh + (1 −  − Vsh )  ma V fl  fl 22 BASIC EQUATIONS For a rock reference volume, the tool response is equal to the individual response of each component weighted by the relative volume of this element. Rglobal = Velem1 * Relem1 + Velem 2 * Relem 2 + Velem 3 * Relem 3 +... Reference Volume = 1 Matrice Vsh Ф Фma Фsh Фfl (HI) ρma ρsh ρfl Δtma Δtsh Δtfl Density  b =  S w  w +  (1 − S w )  hc + Vsh  sh + (1 −  − Vsh )  ma Neutron  N =  S w  Nw +  (1 −S w )  Nhc + Vsh sh + (1 −  − Vsh )  Nma Sonic t =  S w t w +  (1 − S w ) t hc + Vsh t sh + (1 −  − Vsh ) t ma 23 SHALE VOLUME COMMON USES OF VCLAY, VSHALE A basic visual reference for lithology, reservoir definition Input for the Bound Fluid Volume (BFV) parameters in the Coates permeability prediction Transforming Total porosity into effective porosity: Phie = PhiT – VSH*PhiSh Criteria for Net/Gross definition Shale correction for other logs Input for shaly sand Sw (archie derived formulae) Fault seal evaluation Overpressure detection from seismic 25 COMMON PROBLEMS WITH VSH VCL Difficult to calibrate Non radioactive fines and radioactive non fines (ie Kaolinite with low radioactivity, OM, micas, feldspars…) Gas or Heavy minerals effects when ND or SD logs used to infer VSH Reservoir clays could be different than Shale level clays Ideal clay correction varies between tools as the clay mineral assemblage varies XRD & Thin section biased & too fine scale VSH can be considered as an inaccurate log analysis parameter 26  VSH OR VCL ? VSH : Volume of Shale VCL : Volume of clay Common confusion between both parameters but DIFFERENT By definition, clay is a mineral and shale is a rock or a mix of different argillaceous mineral (50-70% of rock) with other minerals (quartz, calcite…) Note: VSH = VCL+VSILT VSILT= Volume of silt 27 CLAY TYPES AND PROPORTIONS Major Clays: Formed by alteration of silicate minerals (Feldspar…) Kaolinite Al2O32SiO22H2O Illite KAl2(OH)2AlSi(O,OH)10 Smectite (MgCa) Al2O3 5SiO2 nH2O Chlorite (MgFe)5 Al(AlSiO3) O10 (OH)5 Clays Proportions: Illite clay is the most abundant in the shales. Approximately 70% of clays in shales are illite. Kaolinite and Chlorite's are less abundant clays in most shales. However in some places in the world, kaolinite shales may be abundant. 28  ESTIMATION OF SHALE CONTENT : VSH Estimation of VSH VSH = Min VSH( i ) - Gamma Ray - Neutron GR - GR Φ VSH = min VSH = N GR GR - GR N Φ max min Nsh - Spontaneous Potential - Density- Neutron Density X’ PSP X' L L VSH =1− VSH = SP SSP DN X' A A Neutron - Resistivities - Density- Sonic Rsh * (Rtmax - Rt) 1/ b Density VSH = ( ) Rt Rt(Rtmax - Rsh) X' L X’ VSH = L DS X' A A b = ( 2 - ( 2 * RT_SH / RT )) if Rt > 2Rsh b=1 if Rt < 2Rsh Sonic 29 ESTIMATION OF SHALE CONTENT : VSH 30 ESTIMATION OF SHALE CONTENT FROM GR : VSH-GR GR max GR log Estimation of VSH with GR: GR min GR GR - GR min - Visual definition of GR MIN & MAX - Or Values defined from 5 and 95 GR max - GR min percentiles on GR histo Anomaly of radioactivity GR - GR VSH = min GR GR - GR ( Linear Equation) 31 max min  ESTIMATION OF SHALE CONTENT FROM GR : NON-LINEAR RESPONSES VSH Clavier equation GRlog − GRclean VSH Clavier =1.7 − 3.38 − ( + 0.7 ) 2 GRsh − GRclean VSH Steiber equation (Louisiana, Miocene y Pliocene) GRlog − GRclean 0.5 * ( ) VSH (V/V) GRsh − GRclean VSH Steiber = GR − GRclean 1.5 − ( log ) GRsh − GRclean VSH Larionov Old Rocks equation (Mesozoic) GRlog −GRmin 2* GRmax −GRmin 0 20 40 60 80 100 VSH OldRocks = 0.333 * ( 2 − 1) VSH Larionov Young Rocks equation (Tertiary) GRlog −GRmin 3.7* GRmax −GRmin VSH YoungerRocks = 0.08336 * ( 2 − 1) GR (API) Note: in thoose equation GR can be substituted by CGR or TH or K. 32 Different equation can be selected for the same well according to depth, lithology, age... ESTIMATION OF SHALE CONTENT FROM GR : VSH-GR 33 ESTIMATION OF SHALE CONTENT FROM SP : VSH-SP Estimation of VSH with SP SP log SSP Static SP PSP Pseudo SP SSP - PSP SP Shale Baseline PSP SSP - PSP VSH = 1− = 1− = SP SSP SSP 34  ESTIMATION OF SHALE CONTENT FROM DENSITY & NEUTRON : VSH-DN RHOB-NPHI CP-1c Fluid point Rhofl = 1.0 RHOB Shaly Sandstone case X' VSH_DN in Shale content for L Water Zone Matrix line Point L VSh = ? VSH_dn = X'L / X' A A MATRIX POINT M RHOma, PHINma SHALE POINT A RHOsh, PHINsh M 2.65 for SS NPHI 35 (Schlumberger) - 4 p.u.for SS  ESTIMATION OF SHALE CONTENT FROM DENSITY & NEUTRON : VSH-DN Calculation with RHOB & NPHI RHO_FL ≈ 1 (except for gas) Example Point A: a = (2.65-1)*(1-0.3)=1.155 A b = (2.4-1)*(1- (-0.02))=1.428 RHO_SH c = (2.65-1)*(1-0.35)=1.0725 d = (2.5-1)*(1- (-0.02))=1.53 RHO_MA VSH_DN = 0.6 NPHI_MA NPHI_SH NPHI_FL ≈ 1 (except for gas) 36 SHALE POINT / WET CLAY POINT ON NPHI/RHOB XPLOT In a shaly shaly-sand we see 2 trends, the Shaley-Sand trend and the Shale trend. Depending on the clay content the shaly sand trend will be close to Wclay point (high clay content) or close to the matrix point (high silt content The Shale Point is the intersection of the two trends, it is the shale in the shaley-sand. The shale trend is important as it provides the means to identify the Wet Clay Point. 37 SHALE POINT / WET CLAY POINT ON NPHI/RHOB XPLOT 38 SHALE POINT / WET CLAY POINT ON NPHI/RHOB XPLOT Dry Clay point is defined knowing the mineralogy of the clays Porosity of Clays (PhiTclay) can be determined from Dry Clay density and Wet Clay Density Wet Clay Point includes the Clay solid part + Water in clays (==PhiTclay) 39 ESTIMATION OF SHALE CONTENT FROM RESISITIVITY : VSH-RES VSH with RT: Rsh Rsh Rclean − RT log RTclean VSH RT = * RT log Rclean − Rsh. RTlog 0.5 ( ) Rsh  ( RT max − RT ) (1− Rsh ) VSH RT =( ) RT ( RT  ( RT max − Rsh) !!!! IN HC ZONE 40  FINAL SHALE VOLUME Three steps in VSH calculation : - In the first step, the VSH is calculated with the GR or SGR (CGR or K or TH) if the latter is available - In the second step, the VSH is calculated with at least one other indicator: RHOB / NPHI, SP or deep resistivity curve RT. - In the third step, the final VSH is calculated by calculating the average or minimum of several VSH calculated. !!!!: If there is gas in reservoir rock , it is preferable to use only the VSHGR or whether the effect of gas is not very strong, the average between VSHGR and VSHRHOB / NPHI. 41 SHALE VOLUME CALIBRATION Shale volume has to be calibrated with available external data: Core description Mudlog Thin sections counts XRD !!! Comparison of results at different scales 42 CORE & CUTTINGS Core: Photos: minimum Vclay and Shale distribution → Vsh’s effect on K & Sw Thin sections: Quantitative Vclay and Clay mineral type, mm scale, distribution o BUT usually biased samples, too small scale of heterogeneity X-Ray diffraction: quantitative analysis of clay minerals type SEM: Clay Morphology, diagenetic sequence Cuttings: Mixing of cuttings, poor depth resolution Useful to identify Minerals that can affect log responses (dolomite, siderite, pyrite, heavy mins (dark silicates), feldspar, micas, anhydrite, coals bitumen) 43 POROSITY ESTIMATION 44 OBJECTIVE OF LOG DERIVED POROSITY Porosity estimation through the entire reservoir section Duplicate core porosities over the full range of lithologies, fluids and borehole conditions Geomodel input (used for petrophysical modeling, HCIIP, Simulation) Basic link between logs, core and special core 45  EFFECT OF POROSITY ERROR Effect of Porosity Error is significant, even in fair Reservoir Quality Sw a n m Phi Rw Rt Depth step 0.133333333 1 2 2 0.15 0.02 50 0 0.125 1 2 2 0.16 0.02 50 1 0.117647059 1 2 2 0.17 0.02 50 2 0.111111111 1 2 2 0.18 0.02 50 3 0 0.05 0.1 0.15 0.2 0 For +2pu error: 1 Increase Bulk volume of 2 Porosity Sw HC of 15% 0.75 0.773 3 4 46 COMMON POROSITY PROBLEMS Badhole affecting log responses hence porosity calculation Inaccurate VSH corrections Gas effect Variable matrix properties Usually, grain density (Rhog) is treated as constant however it can vary significantly Thin beds Calibration of porosity with Core measurement: Representativity of the reservoir Overburden correction Reliability of measurements in unconsolidated sands 47  POROSITY CALCULATION METHODOLOGY The porosity is calculated from porosity logs: RHOB, NPHI and DT. During the calculation, we must take into account the parameters affecting these tools: The matrix (lithology). Fluids: water, mud and mud filtrate drilling, oil and gas. The presence of clay, clay type and its distribution within the reservoir rock. These three parameters differently affect porosity reading tools (eg with RHOB): ρb= ρma*(1- Φ) + Φ*(Sxo*ρmf+(1-Sxo)*ρhc)+ Vsh*ρsh Matrix effect Fluid effect Shale effect (HC) 48  POROSITY CALCULATION METHODOLOGY Formation with water without shale Formation with water with shale ρb=Φ*ρf + ρma*(1- Φ) ρb=Φ*ρf + ρma*(1- Φ) + Vsh*ρsh Δt= Φ*Δtf* + Δtma*(1- Φ) Δt= Φ*Δtf* + Δtma*(1- Φ) + Vsh*Δtsh ΦN= Φ*ΦNf + ΦNma*(1- Φ) ΦN= Φ*ΦNf + ΦNma*(1- Φ) + Vsh*ΦNsh Formation with hydrocarbon without shale Formation with hydrocarbon with shale ρb=Φ*(Sxo*ρmf+(1-Sxo)*ρhc)+ ρma*(1- Φ) ρb=Φ*(Sxo*ρmf+(1-Sxo)*ρhc)+ ρma*(1- Φ) + Vsh*ρsh Δt= Φ*(Sxo*Δtmf+(1-Sxo)*Δthc) + Δtma*(1- Φ) Δt= Φ*(Sxo*Δtmf+(1-Sxo)*Δthc) + Δtma*(1- Φ) + Vsh*Δtsh ΦN= Φ* (Sxo* ΦNmf +(1-Sxo)* ΦNhc) + ΦNma*(1- Φ) Vsh*ΦNsh ΦN= Φ* (Sxo* ΦNmf +(1-Sxo)* ΦNhc) + ΦNma*(1- Φ) 49 POROSITY ESTIMATION SIMPLE MATRIX 50 POROSITY IN A SIMPLE MATRIX Type of porosity logs Sonic log Density log Neutron log None of these logs measure porosity directly The density and neutron logs are nuclear measurements The sonic log use acoustic measurements A combination of these logs gives good indications for lithology and more accurate estimates of porosity 51 SONIC POROSITY: DEFINITION Interval transit time (Δt) of a compressional sound wave travelling through the formation along the axis of the borehole The acoustic pulse from a transmitter is detected at two or more receivers. The time of the first detection of the transmitted pulse at each receiver is processed to produce Δt (compressional). Δt = the transit time of the wave front over 1 foot of formation and is the reciprocal of the velocity. Interval transit time is both dependent on lithology and porosity Units: μsec/ft, μsec/m SLB document Mnemonics: DT, AC, DTC, DTCO (compressional), DTS (Shear), … 52 SONIC POROSITY: FORMULA From the Sonic log, a sonic derived porosity log (SPHI, PHIS, ФS) may be derived: Wyllie / Time-average Wyllie Time-average For unconsolidated formations Raymer-Hunt-Gardner / field observation This requires a formation matrix transit time to be known. Hydrocarbon effects: Δt increases with HC 53 SONIC POROSITY COMMONLY USED VALUES 54  SONIC POROSITY: EFFECTS Environmental effects: Enlarged borehole, formation fractures, gas in the borehole or formation, or improper centralization can produce signal attenuation resulting in ”cycle skipping” or DT spikes to higher values Improper centralization, lack of standoff, or excessive logging speed can result in ”road noise”, or DT spikes to either higher or lower values Interpretation effects: Lithology: porosity calculated from sonic depends on the choice of matrix transit time, which varies with lithology Porosity calculations for uncompacted formations may yield porosity values higher than the actual values when using the Wyllie equation. Use instead the Raymer-Hunt-Gardner equation or correct for decompaction Porosity calculated in gas bearing zones will be slightly higher than the actual values because the traveltime in gas is higher than in water 55  DENSITY POROSITY: DEFINITION Gamma rays emitted from a chemical source (Ce137, Co60), interact with electrons of the elements in the formation. Two detectors count the number of returning gamma rays which are related to formation electron density. For most earth materials, electron density is related to formation density through a constant Returning gamma rays are measured at two different energy levels High energy gamma rays (Compton scattering) determine bulk density and therefore porosity Low energy gamma rays (due to photoelectric effect) are used to determine formation lithology Symbol for density: ρ (rho) 56  DENSITY POROSITY Bulk Density: Units: g/cm3, kg/m3 Mnemonics: RHOB, DEN, (ZDEN) Density Porosity: Units: %, v/v decimal Mnemonics: DPHI, PHID, DPOR Density Correction: Units: g/cm3, kg/m3 Mnemonics: DRHO Photoelectric effect Factor: Units: b/e (barns per electron) Mnemonics: PE, Pe, PEF 57  DENSITY POROSITY: FORMULA Formation bulk density (ρb) is a function of matrix density (ρma), porosity and formation fluid density (ρf) Density porosity is defined as: The matrix density and the fluid density need to be known 58 DENSITY POROSITY: COMMONLY USED VALUES 59  DENSITY POROSITY: EFFECTS Environmental effects: – Enlarged borehole – Rough borehole: is due to the sensor pad losing contact with the borehole wall. Highly variable Caliper curve, and a high- valued density correction (DRHO) – Barite muds: RHOB > Fm. Bulk Density (DPHI < PHI> PEF) Interpretation effects: – Lithology: porosity calculated from density depends on the choice of matrix density, which varies with lithology – Fluid content: porosity calculated from density depends on the choice of fluid density, which varies with fluid type and salinity. – Hydrocarbons: Presence of gas (light HC) in the pore space causes DPHI to be more than the actual porosity.. – In all three cases above, the RHOB value from the tool is correct, but 60 the calculated DPHI is erroneous. – The shallow investigation of the density normally results in investigating the flushed zone  COMPENSATED NEUTRON TOOL Example of Compensated Neutron Tool CNT (Schlumberger) Pulse – Echo Type tool: A radiocative source (Am/Be), or electrical source emits a series of neutrons Far Detector (25’’) Neutrons collide mainly with hydrogen atoms in the formation (because they have a similar mass) and slow down. Each collision emits energy (“echo”) (gamma rays) Near Detector (15’’) On older tools, this energy is measured through 1 detector and provides a direct indication of the amount of hydrogen atoms in a formation. Later, size of the neutron cloud was directly recorded by the Am - Be Neutron Source tool through 2 detectors (Far/Near) by characterizing the falloff of neutrons between the two detectors. Through calibration of the neutron signal, this can be related to porosity. Tool Excentraliser 61  COMPENSATED NEUTRON POROSITY The Hydrogen Index HI which represents the amount of Hydrogen atoms per unit of volume in a fluid is derived from the ratio of the neutron counts on both detectors. In a clean fresh water bearing limestone, which is the reference matrix for neutron calibration, the Neutron Porosity Hydrogen Index NPHI recorded in Limestone Matrix corresponds to the porosity of the Limestone. (Master Calibration Pit in Houston ) In the case of different lithology (Sandstone or Dolomite ) or type of fluid (Salty water , Oil or Gas ) , a correction will have to be applied to the NPHI log to obtain the formation porosity. 62  NEUTRON TOOL TYPE Schlumberger Tools and Logs : SNP : Sidewall Neutron Porosity Tool (obsolete) o Epithermal Neutrons o Log in API Units CNT : Compensated Neutron Tool o Thermal Neutrons o Logs NPHI (Neutron Porosity Hydrogen Index) or TNPH Thermal Neutron Porosity Hydrogen o in % or V/V or Porosity Units (Pu) APS : Accelerometer Porosity Sonde (> 1990) o No Chemical source but Electrical (PNG: Pulsed Neutron Generator) o Epithermal & Thermal Neutrons o Log APLC and SIGMA ( Capture crossection) Equivalent for Baker Atlas => CN Tool => CNCF ( Field Normalized Compensated Neutron Porosity) 63 COMPENSATED NEUTRON Neutron will be affected by: Drilling fluid type (WBM, OBM) Mud Salinity and Density (Presence of Barite) Mud Filtrate Salinity Hole Diameter - Tool Standoff Presence of mudcake Presence of casing Invasion Diameter Pressure and Temperature 64 ESTIMATION OF POROSITY FROM NEUTRON LOG 65  For clean formations , without shale ( Vsh = 0 ), in water or oil zone POROSITY FROM NEUTRON LOG only NPHI = Neutron Porosity Hydrogen Index TNPH = Thermal Neutron Porosity Hydrogen Index TNPH 0 kppm Sandstone Example 1 : TNPH Sandstone with a water salinity of 20 kppm 250 kppm NPHIcor = 18 p.u. in limestone lithology Porosity NPHI True porosity = 22.5 p.u = 24 p.u. Example 2 : Sandstone with a water salinity of 250 kppm TNPHcor = 18 p.u. in limestone lithology Porosity = 22.5 p.u. True porosity = 24.0 p.u Porosity Example 3 : = 15.5 p.u. Dolomite Dolomite with a water salinity of 0 kppm Porosity NPHIcor = 18 p.u. in limestone lithology = 10.0p.u. True porosity = 10.0 p.u NPHI or TNPH = 18 p.u. Example 4 : Dolomite with a water salinity of 0 kppm TNPHcor = 18 p.u. in limestone lithology 66 (Schlumberger) True porosity = 15.5 p.u POROSITY USING A COMBINATION OF TOOLS Quicklook Neutron/Density ; Neutron/Sonic ; Density/Sonic Please refer to Chart Books 67 POROSITY ESTIMATION COMPLEX MATRIX 68  COMPLEX MATRIX In this case, there are 2 or more minerals in an unknown proportion forming the matrix. So Rhoma and Dtma are not known and new value have to be defined. In the case of two minerals To set this value a combination of tools such as RHOB / NPHI or DT / NPHI is used. There is also another combination, RHOB / DT, but has a poor resolution to define the lithology. The most common lithology mixing are for sandstones: Sandstone / Limestone, Sandstone / Dolomite And for limestones: Limestone / Dolomite, Limestone / Sandstone, Dolomite / Sandstone, Dolomite / anhydrite, In the case of three minerals To set this value a combination of the three tools porosity (RHOB, NPHI and DT) is used. M-N parameters are calculated and the cross-plot M-N is used to define the proportion of each mineral. 69 POROSITY IN COMPLEX MATRIX WITH WATER AND NO SHALE 70 POROSITY IN COMPLEX MATRIX WITH WATER AND NO SHALE 71 POROSITY IN COMPLEX MATRIX WITH WATER AND NO SHALE 72 HYDROCARBON CORRECTIONS 73  CORRECTION FOR GAS EFFECT IN SIMPLE MATRIX CASE To calculate the effective porosity PHIE in a simple matrix with gas presence, the following methodology is used: - determination of gas presence with observation of the separation between the curves RHOB and NPHI. gas effect can be observed in a cross-plot RHOB- NPHI. - Estimation of porosity with the following equations (QuickLook): N + 3D Φ2 + Φ2 With PHID and PHIN estimated = With PHID and PHIN estimated in LST matrix Φ= D N in the appropriate lithology 4 2 - If one curve is missing and the equations above can not be applied, correction of gas can be applied to the porosity tool available (RHOB or NPHI) and calculate the porosity with using one tool only 74 GAS EFFECT ON DENSITY-NEUTRON CROSSPLOT LIMESTONE WITH WATER, OIL & GAS RHOB RHOB-NPHI CP-1c LS with Gas Rhofl = 1.0 Gas effect on Density log Gas effect LS with oil on D-N Limestone Gas effect on with water Neutron log 20 % NPHI 75 (Schlumberger)  HYDROCARBON CORRECTION : ITERATION 1/4 Processus : Successive iterations until the porosity found is « stable » Formula for Density correction Formula for Neutron correction  = −1.07    S  = −1.013    S b hr N hr Point L Iteration # 1 Point L at 2510 m in the gas zone  b = 2.25 N = 0.13 Iso-Porosity lines Start with  = 0,3 , Shr = 1 , Shr = 0,3 , hc = 0.10 Density b  = −1.07  0.3 = −0.321 correction b  = −0.304 N N Point L1 corrected for gas : Neutron b = 2.25 – ( - 0.321 ) = 2,571 correction Point L1 N = 0.13 – (-0.304 ) = 0.434 Point L1 corrected for gas : Porosity approximately = 26% 76  HYDROCARBON CORRECTION : ITERATION 2/4 Formula for Density correction Formula for Neutron correction  = −1.07    S  = −1.013    S b hr N hr Iteration # 2 Point L at 2510 m in the gas zone  Point L b = 2.25 N = 0.13 Porosity_1 = 26% Compute : Shr = 1-Sxo With Rmf = 0.32 , Rxo = 9  = 26 % a =0.81 m = 2 Density Sxo = 0.65 SHR = 0.35 xShr = 0.26 x 0.35 = 0.091 correction b Point L2 Start with Shr = 0,09 N  = −1.07 x0.09 = −0.096 Neutron b correction  = −1.013 x0.091= −0.092 N Point L2 corrected for gas : b = 2.25 – ( - 0.096 ) = 2,346 N = 0.13 – (-0.092) = 0.222 Point L2 corrected for gas : Porosity approximately = 22 % 77  HYDROCARBON CORRECTION : ITERATION 3/4 Formula for Density correction Formula for Neutron correction  = −1.07    S  = −1.013    S b hr N hr Iteration # 3 Point L at 2510 m in the gas zone  Point L b = 2.25 N = 0.13 Porosity_2 = 22 % Compute : Shr = 1-Sxo Point L3 With Rmf = 0.32 , Rxo = 9  = 22 % a =0.81 m = 2 Density b correction Sxo = 0.77 SHR = 0.23 xShr = 0.22 x 0.23 = 0.051 Start with Shr = 0.051 N Neutron  = −1.07  0.051 = −0.054 b correction  = 1.013x0.051 = −0.052 N Point L3 corrected for gas : b = 2.25 – ( - 0.054 ) = 2,304 N = 0.13 – (-0.052) = 0.18 Point L3 corrected for gas : Porosity approximately = 21.5 % 78  HYDROCARBON CORRECTION : ITERATION 4/4 Formula for Density correction Formula for Neutron correction  = −1.07    S  = −1.013    S b hr N hr Iteration # 4 Point L at 2510 in the gas zone  Point L b = 2.25 N = 0.13 Porosity_3 = 21.5 % Shr = 0.215 x 0,21 = 0.045 Point L4  = −1.07  0.045 = −0.048 b  = 1.013x0.045 = −0.046 N Point L4 corrected for gas very close to Point L3 Porosity = 21.5 % = > Iteration process will stop b = 2.25 – ( - 0.045 ) = 2,295 MATRIX Line for N = 0.13 – (-0.046 ) = 0.176 Porosity = 21.5 % 2.66 g/cc Compute matrix density ρ b = (1 − Φ )* ρ ma + Φρ fl ρ ma = (ρ b − Φρ fl )/ ( 1- Φ) ρ ma = (2.304 − 0.215 *1.007 )/ ( 1- 0.215) ρ ma = 2.66 g / cc ma to be compared with core density 79 If Ok : HC correction is correct POROSITY ESTIMATION SHALE CORRECTION 80 POROSITY MODEL Matrix Shale Pore Space FREE Sand Silt Dry Clay CBW CapW WATER VQuartz VCL Phie(VCL) Log analyst Definition VQuartz VSH Phie(VSH) CBW: Clay Bound Water PhiT TOTAL PHI CapW: Capillary bound water 81  POROSITY MODEL 2 Methodologies to consider shaliness correction: (example for Density) Computing Total Porosity first then correct for « shale effect » to obtain Effective Phi o 1) Calibrate directly to core o 2) Φt = (ρma–ρb)/(ρma–ρfl) and Φe = Φt–Vsh*Φtsh where Φtsh= (ρma–ρsh)/(ρma–ρfl) using VSH o 3) Φt = (ρma–ρb)/(ρma–ρfl) and Φe = Φt–Vcl*Φtcl where Φtcl= (ρma–ρcl)/(ρma–ρfl) using VCL Computing first Effective Porosity o 4) Solving directly the tool responses equations for Phie 82  METHOD 1 Density Log versus Core Porosity It is assumed that Rhoma and RhoFl are constant Read Rhoma value when intercept 0 Porosity Robust in homogeneous formation but not valid for heterogeneous formations Uncertainty related to the volume seen by the log compare to plug values Could be biaised because of selected plug sampling on cores Rhoma=2.71g/cc 83  METHOD 1 Φt = (ρma–ρb)/(ρma–ρfl) and Φe = Φt–Vcl*Φtcl where 𝜌𝑀𝐴 𝜌𝐶𝐿 𝜌𝐵 𝜌𝐹𝐿 Φtsh= (ρma–ρcl)/(ρma–ρfl) Gives the wrong Φt : (ρma–ρb)/(ρma–ρfl) gives the wrong Φt as it ignores the clay minerals 𝜙𝑇 = 0 𝜙𝑇 = 1 𝜌𝑀𝐴 − 𝜌𝐵 Gives the wrong water volume: 𝜙𝑇 = (ρma–ρsh)/(ρma–ρfl) gives the wrong shale water vol as it uses the 𝜌𝑀𝐴 − 𝜌𝐹𝐿 wrong matrix point 𝜌𝑀𝐴 − 𝜌𝐶𝐿 But gives the right Φe 𝜙𝐶𝐿 = 𝜌𝑀𝐴 − 𝜌𝐹𝐿 However, this can lead to several problems Comparing the wrong Φt to core Φt can cause parameters to be 𝜙𝑒 = 𝜙𝑇 − 𝜙𝐶𝐿 ∗ 𝑉𝐶𝐿 wrongly picked, e.g. Vcl Using the wrong Φt in SwT equations will give the wrong SwT The correct Φt still has to be calculated from Φe using the correct water volumes 84  METHOD 1 Correct Shale and Clay Water volumes (PhiT Clay or Shale) should be calculated using the Dry and Wet points, not ρma Φtsh= (ρdsh–ρsh)/(ρdsh–ρw) Φtcl= (ρdcl–ρcl)/(ρdcl–ρw) Dry clay density should be defined according to mineralogical composition of clays Dry shale density by interpolation from dry clay density Φt is then re-calculated again after Φe Φt = Φe + Vsh*Φtsh Φt = Φe + Vcl*Φtcl 85 METHOD 2 86  IN CASE OF NEUTRON/DENSITY 2 2 𝜙𝐷𝑐𝑜𝑟 + 𝜙𝑁𝑐𝑜𝑟 𝜙𝑒 = (OIL/WATER) 2 (GAS) –These are empirical averages that give an approximative solution 87  METHOD 2 IN CASE OF NEUTRON/DENSITY iteratively More robust approach 88  POROSITY ESTIMATION COMPLEX MATRIX , WITH HYDROCARBON (GAS) WITH SHALE 89  COMPLEX MATRIX , WITH HYDROCARBON (GAS) WITH SHALE Most complicated case. Indeed, the presence of clays and hydrocarbons (gas or oil light) affect porosity logs and resistivity. However, the effect of clays and the effect of gas are opposite. If enough clays is available in reservoir, the effect of gas can completely disappear and the presence of gas not be detected. Then we must try to identify the intervals that have both gas and clays. To identify these intervals, the following methodology based on the use of a cross-plot GR / ΦN-ΦD is proposed. Once identified these intervals, the following corrections and calculations are made: Correction effect of clay Correction effect of hydrocarbons Defining the proportion of mineral to define the parameters of the matrix Calculation of porosity 90  IDENTIFICATION OF GAS AND CLAYS INTERVALS 30 Identifying intervals with gas and clays. To find out if an interval has both gas and 25 clays, we can make the following cross- plot : 20 Gas effect On the Y axis, put ΦN-ΦD. In the X axis, 15 put the GR. ΦN-ΦD (%) When points have low GR and ΦN-ΦD 10 negative difference, it indicates a clean 5 gas formation. If this difference is near 0 (- 5 to + 10 approximately), it is considered 0 as an interval with gas and clays. 20 40 60 80 100 120 140 160 GR(API) -5 -10 91  EXERCISE Example: Make a cross-plot ΦN-ΦD versus GR showing areas A to G of the figure to the right. Adjacent clays have the following values: ΦDsh = 16% Identificat ΦNsh = 38% Zone GR ΦN (%) ΦD (%) ΦN-ΦD ion GRsh = 85 API A1 30 12 41 ? ? GR sand = 30 API A2 30 13.5 40 ? ? B1 45 24 34 ? ? B2 44 25 32 ? ? C 50 30 27 ? ? D 35 14 41 ? ? E1 47 28.5 25 ? ? E2 45 26 26 ? ? E3 43 25.5 31 ? ? F 65 36 21.5 ? ? G 60 28.5 17 ? ? 92  EXERCISE - CORRECTION 30 The calculation of ΦN-ΦD and point position based on the value of Shale point GR to define whether the point has gas despite having clays. 20 F Zone GR ΦN (%) ΦD (%) ΦN-ΦD Identification G Formation with A1 30 12 41 -29 clean/gas 10 Clean shale formati and ΦN-ΦD (%) A2 30 13.5 40 -26.5 clean/gas E1 water on with C B1 45 24 34 -10 shaly/gas water E2 0 20 40 60 80 100 B2 44 25 32 -7 shaly/gas GR(API) E3 C 50 30 27 +3 shaly/gas B2 - B1 Formation with D 35 14 41 -27 clean/gas 1 shale and gas 0 E1 47 28.5 25 +3.5 shaly/gas E2 45 26 26 0 shaly/gas -20 A2 E3 43 25.5 31 -5.5 shaly/gas D Formation clean A1 with gas F 65 36 21.5 +15.5 shaly/water -30 G 60 28.5 17 +11.5 shaly/water 93 EXERCISE - CORRECTION 30 Shale point 20 F G Formation with 10 Clean shale formati and ΦN-ΦD (%) E1 on with water C water E2 0 20 40 60 80 100 GR(API) E3 B2 - B1 Formation with 1 shale and gas 0 -20 A2 D Formation clean A1 with gas -30 94 SECONDARY POROSITY 95  DEFINITION AND ESTIMATION Because of diagenesis processes occuring during formation life (dissolution, recrystallisation,…) porous system can dramatically be modified. This is particularly true in carbonates. Voids are created and can be connected or not. In the carbonates with a porosity "vuggy" the sonic often underestimate the total porosity unlike the RHOB or NPHI The explanation is that the sonic wave compression always takes the fastest and simplest way to propagate. This road will avoid the "vugs". A simple technique looking at the difference between the calculated porosity with sonic in this case and the specific porosity with RHOB or with ND is called Secondary porosity Index (SPI) or Index of secondary porosity. SPI = ΦD - ΦS With ΦD calculated porosity with RHOB (also it can be calculated with RHOB / NPHI) And ΦS calculated porosity with DT However, ΦS is not always less than ΦD and may be even higher! So in this case SPI