nmr 06 hydrocarbon analysis hc

6 Hydrocarbon Analysis

Contents

Notes on Fluid Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Predicting Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Hydrocarbon Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Recommended Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Properties Calculator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Hydrocarbon Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Porosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Inversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Corrections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Paradigm Rock & Fluid Canvas 2009 | Epos 4.0 Hydrocarbon Analysis 6-1

Notes on Fluid Identification

As discussed in Introduction to NMR on page 1-1, T2 relaxation depends on pore size and fluid properties. By comparing data acquired using different echo spacings and wait times, the fluid type and volume can be determined. Fluid typing was pioneered by NUMAR and most methods are most applicable to the MRIL tool.Methods for identifying fluid include:

Differential Spectrum, Delta Wait Time Experiments (DTW) on page 1-21 Diffusion Analysis on page 1-22 Enhanced Diffusion on page 1-23

Critical to identification is the understanding of the NMR properties of fluids at reservoir temperature and conditions.

Predicting Fluid Properties

Fluid properties important for the interpretation of NMR data include: T1, T2 bulk properties T2 at reservoir conditions The diffusion coefficient Hydrogen Index

Some of these properties are dependent on tool, pore size and whether or not the fluid is wetting or non-wetting. Geolog provides a module for the calculation of NMR fluid properties. These properties act as guidelines for the identification and quantification of hydrocarbons in the reservoir. However, it should be noted that the calculated fluid properties are the starting point for fluid typing and quantification, since the fluid properties are also dependent on other factors that cannot be determined during normal petrophysical analysis.See also "Properties Calculator" on page 6-5.

Hydrocarbon Analysis

The principles underlying hydrocarbon analysis are described in the Differential Spectrum, Delta Wait Time Experiments (DTW) on page 1-21.Hydrocarbon analysis is used for the identification of gas and light oils (< 5 cp). The Hydrocarbon Analysis modules assume that a significant T1 contrast exists between water and the light hydrocarbons, and that the gas and oil have different T2 values. These assumptions are valid for high porosity water-wet reservoirs.Hydrocarbon Analysis 6-2Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Hydrocarbon Analysis MethodStep 1Acquire two different echo-trains with dual TW activation. TW should be selected to maximize the contrast between water and the hydrocarbons.

Step 2Process the CPMG data, applying the minimum RA, phase rotation and environmental corrections.

Step 3Estimate the bulk properties, T1, T2 and Hydrogen Index of the oil and gas at reservoir conditions.

Step 4Subtract the CPMG acquired with the shortest wait time from the CPMG acquired with the longest wait time. The resultant CPMG will contain only the oil and gas signatures.

Step 5Search the T2 distribution for oil and gas. This is achieved by "inverting the T2 distribution" based on T2 time constants that have been predicted for the oil and the gas. The T2 amplitudes acquired from the two T2 time components are proportional to the apparent gas porosity and the apparent oil porosity.

Step 6To calculate the true porosity, the apparent porosities must be corrected for incomplete polarization and Hydrogen Index ("Step 5" on page 6-3 assumes a Hydrogen Index of 1):

(Eq. 1)

where:= apparent porosity of the fluid phase (oil or gas)= polarization function for the fluid phase

HIf = Hydrogen Index of the fluid phase= true porosity of the fluid phase

(Eq. 2)

where:TWS = short wait timeTWL = long wait timeT1f = T1 bulk of the fluid phase.

fA fHIff=

fA

f

f

f expT WS T1f( ) exp T WL T1f( )Hydrocarbon Analysis 6-3Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Recommended Methodology

The following methodology is recommended for hydrocarbon analysis using Geolog.

Step 1Calculate T1bulk and T1, T2 of oil and gas and reservoir. See "Properties Calculator" on page 6-5 module.

Step 2Fluids > "Hydrocarbon Analysis" on page 6-7Use this module to estimate apparent porosity. Porosity can be estimated by extrapolating the CPMG echo data back to time = 0. A regression through the first few echoes can be used to calculate the intercept at the y-axis, which is the amplitude at t=0.

Step 3Fluids > "Inversion" on page 6-8Use this module to subtract the TWS CPMG data from the TWL CPMG data and invert the resulting CPMG to a continuous distribution of exponentials (minimum T2 = 0.3ms, maximum T2 = 3000ms, bins = 30).

Step 4Check the T2 distribution for gas and oil. Peaks in the T2 distribution should correspond with the predicted T2 for oil and gas. If the predicted values cannot be correlated with the T2 distribution, the T2bulk properties will need to be recalculated using the correct parameters. Geolog Xplot can be used to investigate the distribution of T2 values.

Step 5Determine the correct values for T2 gas and T2 oil from the peaks in the T2 distribution. Providing that the T2 peaks are close to the predicted values, T2 oil and T2 gas can be adjusted to reflect the peaks found in the inverted T2 distribution.

Step 6Fluids > "Hydrocarbons" on page 6-11Use this module to calculate the apparent porosity for oil and gas. Use T2 for oil and gas determined in "Step 4" on page 6-4 and "Step 5" on page 6-4.

Step 7Fluids > "Corrections" on page 6-15Use this module to calculate the true porosity for oil and gas.Hydrocarbon Analysis 6-4Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Properties Calculator

The Fluid Properties module calculates fluid properties relevant for the analysis of NMR data.

Operation1. Select Petrophysics > NMR > Fluid properties to display the nmr_fluid_predict module.2. Set the required input Values as described in Table 6-1, "nmr_fluid_predict Parameters" on

page 6-6.

The nmr_fluid_predict ModuleHydrocarbon Analysis 6-5Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Table 6-1: nmr_fluid_predict Parameters

Name Default Description

C MRIL tool constant.G Magnetic field gradient.TE 1 Echo-spacing of the acquisition.HI_GAS 1 Hydrogen Index of gas.HI_WATER 1 Hydrogen Index of water.HI_OIL 1 Hydrogen Index of oil.HI_MF 1 Hydrogen Index of mud filtrate.FTEMP Formation water temperature.MU_OIL Oil viscosity.MU_WATER Water viscosity.RHO_GAS Gas density.T1_WATER Bulk T1, T2 water.T1_OIL Bulk T1, T2 oil.T1_GAS Bulk T1, T2 gas.DCO_WATER DCO_WATER Diffusion coefficient for water.DCO_OIL DCO_OIL Diffusion coefficient for oil.DCO_GAS DCO_GAS Diffusion coefficient for gas.T2_OIL T2_OIL T2 oil (reservoir conditions).T2_GAS T2_GAS T2 gas (reservoir conditions).HOIL HOIL Hydrogen Index for oil.HWATER HWATER Hydrogen Index for water.HGAS HGAS Hydrogen Index for gas.HMF HMF Hydrogen Index for the mud-filtrateT2DW T2DW Diffusion-limited value for the T2 of water. T2 amplitude beyond this value is

assumed to be hydrocarbon.Hydrocarbon Analysis 6-6Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Hydrocarbon Analysis

Porosity

This module calculates NMR porosity by extrapolating the CPMG echoes back to Time = 0 (i.e., the beginning of the experiment). Fits a regression line to the first few echoes.

Operation1. Select Petrophysics > NMR > Hydrocarbon analysis > Porosity to display the

nmr_tda_phi module.2. Set the required input Values as described in Table 6-2, "nmr_tda_phi Parameters" on page 6-7.

The nmr_tda_phi Module

Table 6-2: nmr_tda_phi Parameters


FIRST_ECHO First CPMG echo to use in the regression.LAST_ECHO Last CPMG echo to use in the regression.PHIA_LIM Maximum porosity.TE Echo spacing for the acquisition mode TWL.ECHOA Echo data acquired using TW = long (longest wait time).PHIA_MRIL PHIA_MRIL Apparent MRIL porosity.PHIA PHIA Apparent porosity where PHIA is PHIA_MRIL limited between 0 and

PHIA_LIM.Hydrocarbon Analysis 6-7Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Supplementary InformationIn fluid filled rocks, the volume of rock occupied by fluid is equal to porosity. Petrophysical NMR measurements utilize hydrogen proton spins to generate a signal. Because hydrogen is abundant in fluids, the magnitude of the NMR signal is proportional to the formation fluid volume.When all the proton spins are aligned in the magnetic field, the NMR signal is proportional to the porosity of the rock. Consequently, at the start of the CPMG experiment, at t=0, and before relaxation of the proton spins has occurred, the signal is proportional to porosity.NMR logging tools are calibrated using a 100% porosity reference (i.e., a water-filled bucket). The determination of porosity therefore assumes that the hydrogen nuclei in the formation fluid are equal to an equivalent volume of water such that the Hydrogen Index is 1. Porosity estimates must be adjusted to reflect variation in the Hydrogen Index of the formation fluid.Porosity can be estimated by extrapolating the CPMG echo data back to time = 0. A regression through the first few echoes can be used to calculate the intercept at the y-axis, which is the amplitude at t=0.

Inversion

The module performs an inversion of CPMG data generated from the subtraction of TWS CPMG data from TWL data. The resultant T2 distribution will contain T2 components associated with hydrocarbons. L2 and L1L2 inversion parameters use zeroth order regularization methods.

Operation1. Select Petrophysics > NMR > Hydrocarbon analysis > Inversion to display the

nmr_invert_tda module.2. Set the required input Values as described in Table 6-3, "nmr_invert_tda Parameters" on

page 6-9.Hydrocarbon Analysis 6-8Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

The nmr_invert_tda ModuleTable 6-3: nmr_invert_tda Parameters


OPT_COMPRESS YesDouble click in the field then click on the Dropdown List button to select either yes or no and thus turn data compression on or off.

FIRST_ECHO Available when OPT_COMPRESS is set to "yes"; first echo of the CPMG data to be included in the inversion.

LAST_ECHO Available when OPT_COMPRESS is set to "yes"; last echo of the CPMG data to be included in the inversion; all echoes lying between the FIRST_ECHO and LAST_ECHO contribute to the solution.

COMPRESS_BINS Available when OPT_COMPRESS is set to "yes"; data redundancy can be reduced by averaging the data into discrete windows. COMPRESS_BINS defines the number of averaging windows. For example, COMPRESS_BINS = 10 means that the data will be reduced to 10 points. Windows are logarithmically spaced.Hydrocarbon Analysis 6-9Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Table 6-3: nmr_invert_tda ParametersSupplementary Information

L2 and L1/L2 inversion parameters use zeroth order regularization methods. The L1/L2 hybridization model attempts to deal with outliers in the CPMG data set. L1/L2 is particularly useful for noisy data or CPMG decays that display spiking.

L2 SolutionL2 inversion utilizes a design matrix that has a row for each of the data points (in this case, the CPMG data). Each equation is then multiplied by a number (common to all the equations) that standardizes the data. Standardization serves to eliminate the effect of small or big data:parameters ratios. Furthermore, each equation is multiplied by a number that is inversely proportional to measurement error. The measurement error accounts for equations that have small measurement errors associated with the data.

INVERSION_TYPE L2Double click in the field then click on the Dropdown List button to select either L2 or L1L2 inversion (see "Supplementary Information" on page 6-10).

REG_PARAM Controls the smoothness of the T2 distribution. Larger values increase the smoothing component.

NECH_V Number of data points in the CPMG echo-train.TE Echo spacing.T2_MIN Minimum T2 of the T2 distribution.T2_MAX Maximum T2 of the T2 distribution.T2_BIN Number of T2 bins.ECHO_AMP_A CPMG echoes collected using acquisition TW = Long (TWL ).ECHO_NOISE_A Noise channel, obtained from acquisition TW = Long (TWL ).ECHO_AMP_B CPMG echoes collected using acquisition TW = short (TWS).ECHO_NOISE_B Noise channel, obtained from acquisition TW = short (TWS).ECHOA, NOISEA, ECHOB and NOISEB should have the same number of echoes (samples) and should have been acquired using the same echo-spacing (TE). The wait times should be defined so that TWL > TWS.PHI_T2_DIST_DIFF Amplitude distribution generated from CPMG data calculated from

TWL - TWS.T2_TIME_DIFF Time constants for the amplitude distribution.ECHO_AMP_DIFF CPMG echo-train generated from the subtraction of CPMG data

acquired using TWL and TWS.ECHO_NOISE_DIFF Noise channel generated from the subtraction of CPMG data acquired

using TWL and TWS.ECHO_FIT_DIFF The fitted CPMG data generated during the modeling of the T2

distribution (model fitted to DIFF_ECHO).SIGMA_NOISE Standard deviation of noise for the differential echo-train.INVERT_DIFF_BAD Bad inversion flag.

Name Default DescriptionHydrocarbon Analysis 6-10Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

The design matrix has 2M - 2 rows where M stands for the number of parameters (number of T2

values).The first additional M rows contain zeroth order regularization; the first one has 1 in the first position, . . . the Mth has 1 in the Mth position; all the rest are zeros. This serves to minimize the length of the model. Algebraically, it lowers the condition number of the matrix thus making the process of finding the solution more stable.The rest of M-2 rows have 1 -2 1 around each (no border) parameter. This adds another term to the minimization, causing less second derivative. This uses the NNLS algorithm as described by Lawson & Hanson's book "Solving Least Squares Problems", Prentice Hall, 1974. It solves Ax=b in a least squares sense (A is out matrix, x is T2 distribution, b are the measured echoes), subject to the condition that each element of x is non-negative, as is needed from a distribution.

L1/L2 HybridizationBased on Langan et al, Geophysics, 1997, 1183-1195.Used where the CPMG noise is non-Gaussian and where the data has outliers that will affect the result.The standard deviation of the measured echoes and the calculated theoretical curve are compared. The equations are weighted according to the distance of the actual echoes from the theoretical curve. Those of about

Operation

1. Select Petrophysics > NMR > Hydrocarbon analysis > Hydrocarbons > Exact to display

the nmr_tda1 module.2. Set the required input Values as described in Table 6-4, "nmr_tda1 Parameters" on page 6-12.

The nmr_tda1 Module

Table 6-4: nmr_tda1 Parameters


FLUIDSDouble click in the field then click on the Dropdown List button to select the fluid phases to search for (oil, gas, oil+gas).

OPT_COMPRESS yesDouble click in the field then click on the Dropdown List button to select either yes or no and thus turn data compression on or off.

FIRST_ECHO Available when OPT_COMPRESS is set to "yes"; first echo of the CPMG data to be included in the inversion.Hydrocarbon Analysis 6-12Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Table 6-4: nmr_tda1 Parameters (Continued)Search Range

The Search Range method allows the user to specify a range over which to search, and will find the best relaxation time constant to fit the data. If two fluid phases are specified (Oil+Gas), the user must specify two different ranges over which to search for the best relaxation time constants.

Operation1. Select Petrophysics > NMR > Hydrocarbon analysis > Hydrocarbons > Search Range

to display the nmr_tda1a module.

LAST_ECHO Available when OPT_COMPRESS is set to "yes"; last echo of the CPMG data to be included in the inversion; all echoes lying between the FIRST_ECHO and LAST_ECHO contribute to the solution.

COMPRESS_BINS Available when OPT_COMPRESS is set to "yes"; data redundancy can be reduced by averaging the data into discrete windows. COMPRESS_BINS defines the number of averaging windows. For example, COMPRESS_BINS = 10 means that the data will be reduced to 10 points. Windows are logarithmically spaced.

NECH_V Number of data points in the CPMG echo-train.TE Echo spacing.T2_COMP1 Available when GAS or OILGAS is selected for FLUIDS; first T2

component associated with Hydrocarbon 1.T2_COMP2 Available when OIL or OILGAS is selected for FLUIDS; second T2

component associated with Hydrocarbon 1.Note: T2_COMP1 and T2_COMP2 are T2 components associated with hydrocarbons found in the reservoir where T2_COMP1 < T2_COMP2. Normally, T2_COMP1 is gas and T2_COMP2 is light oil. The T2 components are predicted from the equations, and the inspection of T2 distributions obtained from the inversion of the differential echo-train. Hydrocarbon analysis assumes that the hydrocarbons decay with a single exponential, and that the hydrocarbons are non-wetting.ECHO_AMP_A CPMG echoes collected using acquisition TW = Long (TWL).ECHO_NOISE_A Noise channel, obtained from acquisition TW = Long (TWL).ECHO_AMP_B CPMG echoes collected using acquisition TW = short (TWS).ECHO_NOISE_B Noise channel, obtained from acquisition TW = short (TWS).PHIA Apparent porosity where PHIA is PHIA_MRIL HC_SIGMA HC_SIGMA Standard deviation of noise for differential echo-train.HC_DIST HC_DIST T2 distribution containing the hydrocarbons components (2-bin

distribution).HC_BAD HC_BAD Bad analysis flag.PHIA_COMP1 PHIA_COMP1 Porosity associated with T2 component 1 (gas).PHIA_COMP2 PHIA_COMP2 Porosity associated with T2 component 2 (light oil).ECHO_FIT ECHO_FIT The fitted CPMG data generated during the modeling of the T2

distribution (model fitted to DIFF_ECHO).DIFF_ECHO DIFF_ECHO CPMG echo-train generated from the subtraction of CPMG data acquired

using TWL and TWS.


2. Set the required input Values as described in Table 6-5, "nmr_tda1a Parameters" on page 6-14.The nmr_tda1a Module

Table 6-5: nmr_tda1a Parameters


FLUIDSDouble click in the field then click on the Dropdown List button to select the fluid phases to search for (oil, gas, oil+gas).

REG_PARAM1 Regularization for inversion.BINS Number of bins over which to conduct the search.FIRST_ECHO First echo of the CPMG data to be included in the inversion.LAST_ECHO Last echo of the CPMG data to be included in the inversion; all echoes

lying between the FIRST_ECHO and LAST_ECHO contribute to the solution.Hydrocarbon Analysis 6-14Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Table 6-5: nmr_tda1a ParametersCorrections

This module corrects PHIA calculated for gas and light oil for variable Hydrogen Index and incomplete polarization due to an insufficient wait time.

Operation1. Select Petrophysics > NMR > Hydrocarbon analysis > Corrections to display the

nmr_tda2 module.2. Set the required input Values as described in Table 6-6, "nmr_tda2 Parameters" on page 6-16.

COMPRESS_BINS Data redundancy can be reduced by averaging the data into discrete windows. COMPRESS_BINS defines the number of averaging windows. For example, COMPRESS_BINS = 10 means that the data will be reduced to 10 points. Windows are logarithmically spaced.

NECH_V Number of data points in the CPMG echo-train.TE Echo spacing.T2_COMP1_MIN Available when GAS or OILGAS is selected for FLUIDS; minimum

value for first T2 component associated with Hydrocarbon 1.T2_COMP1_MAX Available when GAS or OILGAS is selected for FLUIDS; maximum

value for first T2 component associated with Hydrocarbon 1.T2_COMP2_MIN Available when OIL or OILGAS is selected for FLUIDS; minimum

value for second T2 component associated with Hydrocarbon 2.T2_COMP2_MAX Available when OIL or OILGAS is selected for FLUIDS; maximum

value for second T2 component associated with Hydrocarbon 2.Note: T2_COMP1 and T2_COMP2 are T2 components associated with hydrocarbons found in the reservoir where T2_COMP1 < T2_COMP2. Normally, T2_COMP1 is gas and T2_COMP2 is light oil. The T2 components are predicted from the equations, and the inspection of T2 distributions obtained from the inversion of the differential echo-train. Hydrocarbon analysis assumes that the hydrocarbons decay with a single exponential, and that the hydrocarbons are non-wetting.ECHO_AMP_A CPMG echoes collected using acquisition TW = Long (TWL).ECHO_NOISE_A Noise channel, obtained from acquisition TW = Long (TWL).ECHO_AMP_B CPMG echoes collected using acquisition TW = short (TWS).ECHO_NOISE_B Noise channel, obtained from acquisition TW = short (TWS).PHIA Apparent porosity where PHIA is PHIA_MRIL HC_DIST T2 distribution containing the hydrocarbon components (2-bin

distribution).HC_SIGMA Standard deviation of noise for differential echo-train.HC_BAD Bad analysis flag.PHIA_COMP1 Porosity associated with T2 component 1 (gas).PHIA_COMP2 Porosity associated with T2 component 2 (light oil).DIFF_ECHO CPMG echo-train generated from the subtraction of CPMG data

acquired using TWL and TWS.


The nmr_tda2 ModuleTable 6-6: nmr_tda2 Parameters


PHIT_MAX Maximum allowed porosity.TW_S The short wait time.TW_L The long wait time.HOIL Hydrogen Index of the oil.HGAS Hydrogen Index of the gas.T12B_OIL Bulk T1, T2 for the oil.T12B_GAS Bulk T1, T2 for the gas.PHIA Apparent porosity where PHIA is PHIA_MRIL PHIA_OIL PHIA_OIL Apparent porosity associated with the oil.PHIA_GAS PHIA_GAS Apparent porosity associated with the gas.PHIT_OIL PHIT_OIL True porosity associated with the oil (see "Supplementary Information" on

page 6-17)PHIT_GAS PHIT_GAS True porosity associated with the gas (see "Supplementary Information"

on page 6-17)BVW BVW Bulk volume of water.PHIT PHIT Total porosity.BVW_OIL BVW_OIL BVW + Oil.BVW_OIL_GAS BVW_OIL_GAS BVW + Oil + Gas.Hydrocarbon Analysis 6-16Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Supplementary InformationTo calculate the true porosity, the apparent porosities must be corrected for incomplete polarization and Hydrogen Index.

(Eq. 3)

where:= apparent porosity of the fluid phase (oil or gas)= polarization function for the fluid phase

HIf = Hydrogen Index of the fluid phase= true porosity of the fluid phase

(Eq. 4)

where:TWS = short wait timeTWL = long wait timeT1f = T1 bulk of the fluid phase.

The total volume of hydrocarbons is calculated as:PHIT_HC = PHIT_OIL + PHIT_GASBecause the gas and oil have been corrected for Hydrogen Index and insufficient wait time, PHIT_NC may be greater than the PHIT calculated using the "Hydrocarbon Analysis" on page 6-7 module. This is because the first calculated PHIT has not been corrected for Hydrogen Index or insufficient wait time. If PHIT_HC > PHIT, PHIT is set so that PHIT = PHIT_HC.This assumes that all of the water is polarized and that if PHIT_HC > PHIT, then BVW = 0.BVW is calculated as PHIT - PHIT_OIL - PHIT_GASPHIT is calculated as BVW + PHIT_OIL + PHIT_GAS

fA fHIff=

fA

f

f

f expT WS T1f( ) exp T WL T1f( )Hydrocarbon Analysis 6-17Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

Index

Ffluid

properties of NMR data, predicting 2

NNMR

proton spins aligned in the magnetic field 8

Ppredicting

fluid properties of NMR data 2

Zzeroth order regularization methods 10Hydrocarbon Analysis 6-18Paradigm Rock & Fluid Canvas 2009 | Epos 4.0

nmr 06 hydrocarbon analysis hc

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