In Tarek Ahmeds ‘Reservoir Engineering Handbook’ the fundamentals of rock properties are The petrophysicists’ primary role is the quantification of these properties, through the evaluation of laboratory and log evaluation.
5.
Petrophysics Log analysis is part of the discipline of petrophysics ‘ A log analyst is a scientist, a magician and a diplomat…… He has extensive knowledge of geology, geophysics, sedimentology, petrophysics, mathematics, chemistry, electrical engineering and economics’ E. R Crain
NMR does not directly measure permeability, but does provide parameters useful for the calculation for of permeability from empirical equations
Porosity,
Mean pore size
Porosity partitions
Clay bound water
Capillary bound
Free fluid
8.
Porosity (after Hook). The ratio of void (or fluid space) to the bulk volume of rock containing that void space. Porosity can be expressed as a fraction or percentage of pore volume . 1) Primary porosity refers to the porosity remaining after the sediments have been compacted but without considering changes resulting from subsequent chemical action or flow of waters through the sediments. 2) Secondary porosity is the additional porosity created by chemical changes, dissolution, dolomitization, fissures and fractures. 3) Effective porosity is the interconnected pore volume available to free fluids, excluding isolated pores and pore volume occupied by adsorbed water (the engineers Porosity). 4) Total Porosity is all the void space in a rock and matrix, whether effective or non effective. Total porosity includes that porosity in isolated pores, adsorbed water on grain or particle surfaces and associated with clays.
9.
Porosity Definitions TOTAL: Total void volume. Clay bound water is included in pore volume Not necessarily connected Core analysis disaggregated sample NMR core analysis Density, neutron log (if dry clay parameters used) NMR logs Effective (connected): Void volume contactable by fluids Includes clay bound water in pore volume? Possibly sonic log Effective connected Rock Bulk Volume Rock Matrix Clay Clay bound water Total Porosity Effective Porosity log analysis Capillary bound water Free water Hydrocarbons Minerals
Porosity logging tools if wet clay parameters used
Effective connected Rock Bulk Volume Rock Matrix Clay Clay bound water Total Porosity Effective Porosity Log Analysis Capillary bound water Free water Hydrocarbons Minerals
11.
T2 Model 0.1 1.0 10.0 100.0 1000.0 10000.0 Rock Bulk Volume Rock Matrix Clay Clay bound water Total Porosity Effective Porosity Capillary bound water Free water Hydrocarbons Minerals T2 cutoff NMR is unique it measures total porosity and can be partitioned into pore-size and fluid component
12.
T2 & Porosity - Echo Data Underlying CPMG decay CPMG echoes T 2 relaxation (msec) AMPLITUDE Calibrated To porosity At start of sequence Immediately after polarization All ‘fluid’ is polarised = Total Porosity Total porosity
13.
Possible Error in Total Porosity Underlying CPMG decay CPMG echoes First echo (e.g TE = 200 usec) Noise Noise and timing of first echo effects the extrapolation to time = 0
14.
Porosity From T2 Data 0.1 1.0 10.0 100.0 1000.0 10000.0 Inversion to T2 Distribution of Exponential Decays Porosity is calculated as sum of T2 bins in distribution
15.
Exercise – Calculation of porosity The CMR tool is calibrated using a 100 p.u. signal using a water bottle. CMR porosity is calculated using the general equation: Actual equation for the CMR tool :
Calibration tank made of fibre glass, lined with thin metal coating
Tank acts as container for water sample and faraday cage to shield unwanted RF
Three chambers
Outer chamber, water is doped with cupric to reduce relaxation time of water and speed up relaxation
Inner chamber filled with brine to simulate bore hole conditions
19.
Pore Size Distributions The NMR measurement measures the relaxation of proton spins. Relaxation occurs by three main processes Assuming the rocks are 100% water saturated relaxation due to surface relaxation is much faster then bulk relaxation (in the fast diffusion limit). In a homogenous field diffusion is negligible. Diffusion is an important process if field gradient of fluid has a high diffusion coefficient The fast diffusion limit is where all the pores are small enough and surface relaxation mechanisms slow enough that a typical molecule crosses the pore many time before relaxation.
20.
Pore Size in 100% Water Saturated rocks Rock Grain Spin diffuses to pore wall where a proton spin has a probability for being relaxed In a porous system filled with a single phase Each pore-size has a characteristic T2 decay constant. The smaller the pores the faster the relaxation (short or fast T2)
22.
Pore Size in 100% Water Saturated rocks 0.1 1.0 10.0 100.0 1000.0 10000.0 Rock Bulk Volume Rock Matrix Clay Clay bound water Total Porosity Effective Porosity Capillary bound water Free water Hydrocarbons Minerals T2 cutoff
23.
Measurement of Relaxivity and Pore Size Pc/r & T2) Pc/r & (k*1/T2) Lab Calibration of Data Relaxivity ( ρ ) is expressed in units um/s
When comparing NMR and capillary pressure, NMR measures surface to volume ratio of the pore and capillary pressure equates to pore throat size.
The two are only exactly comparable if the pore systems approaches that of a bundle of tubes.
However comparison of NMR and capillary pressure does alllow NMR to be related to pore throat size.
27.
Inversion & Porosity and Pore Size Distribution T 2 x T 2 y T 2 z Exponential decay characterises Pore size Total amplitude characterises pore volume
28.
Inversion T 2 x T 2 y T 2 z T 2 x T 2 y T 2 z T2x, y and z are T2 bins, or if scaled to pore size, pore size bins. Height of column is pore volume
29.
T2 Distribution Reflects Porosity ‘Bins’ Porosity is sum of porosity bins (x+y+z) T 2 x T 2 y T 2 z
30.
Inversion quality Control Underlying CPMG trend Fit 1 (good) Fit 2 (poor) T2 (ms) Echo Amplitude RMS Error of Fit Well fitted data with evenly distributed error of fit Poorly fitted data with systematic variation in error of fit
34.
Hydrocarbon effect on T2 distribution Hydrocarbon effect on T2 distribution 100% Brine Saturated Water wet with oil Producible water (free fluid) Bound fluid (irreducible water) Producible hydrocarbon (free fluid) Bound fluid (irreducible water) T2 increases since hydrocarbon Is not limited by pore-size T2 is limited by pore size in 100% Sw rocks
40.
Fluid Properties Calculator /*convert temp to kelvin temp_k = (0.555556)*(temp_F+459.67) /*calculate Bulk T1 T2 oil, water and gas /*convert to ms since equation for seconds /* MU in cp, density in g/cc, temp in Deg K T12B_OIL = (3*(temp_k/(298*MU_OIL))) * 1000 T12B_WATER = (3*(temp_k/(298*MU_WATER))) * 1000 T12B_GAS =(25000*(RHO_GAS/(temp_k**1.17))) * 1000
48.
Polarization (T1) Contrast Hydrocarbon Typing Using Polarization Contrasts T1 WATER T1 WATER + OIL + Gas T2 T2 Differential OIL + Gas T2 Time Domain Processing gas oil water water gas oil
Increased echo spacing shortnes T2 of fluid with high diffusion coefficients
Gas application (limited)
More viscous oils (medium – high viscosity)
Limited success for gas due to difficulty of measuring extremely short T2 of gas at long echo spacing
50.
Diffusion Contrast (medium – high viscosity oils) SHIFTED WATER + OIL WATER + OIL TE=Short: no diffusion TE=long: diffusion Water shift Hydrocarbon Typing Using Diffusion Contrasts
57.
Logging Gas Reservoirs & Density NMR Porosity (DMRP) In the presence of gas: Density log overestimates porosity (Fluid density deficit) NMR log underestimates porosity (HI index deficit) Providing that the polarization effect is understood, the deficit between the porosity estimates of the two logs is proportional to the gas saturation. This effect can be approximated using the equation: PHIT_DMR = 0.6*PHIA_DEN + 0.4 * PHIT_NMR where: PHIT_DMR = combined density NMR porosity PHIA_DEN = apparent porosity derived from the density log PHIT_NMR = porosity derived from the NMR log Freedman, R., Chanh Cao Minh. Gubelin, G. Freeman, J. J. McGuiness, T. Terry, B. and Rawlence, D. 1998. Combining NMR and Density Logs for Petrophysical Analysis in Gas Bearing Formations . Transactions of the SPWLA 39th Annual Logging Symposium, May 26-29, Keystone Colorado. 1998. Paper II.
Pulse sequences investigate the different polarization and diffusivity of the fluids. POLARIZATION SHORT TE BULK & SURFACE RELAXATION (Short TE) LONG TE DIFFUSION (LONG TE)
This indicates expected position of fluids in a clean sandstone formation.
T2 distribution (corrected for diffusion) 1 mS 1000 mS 10 -6 m 2 .s -1 10 -11 m 2 .s -1 Water line Oil line Gas Light Oil Heavy Oil Bound Fluid Diffusivity Gas line
The connate water saturation is defined by capillary bound water, and defined by a finite minimum irreducible water saturation on a capillary pressure curve.
66.
Connate Water Saturation Pc (or h) Water Saturation 0% 100% Pd Swc Pd = Displacement pressure. (minimum capillary pressure required to displace the Wetting phase from the largest capillary pore Swc = Connate irreducible water saturation
70.
Variation In T2 Cutoffs FWL Borehole HAFWL Sw A B A B 100 0 Pc (psia) 480
71.
T2 Cutoff From Capillary Pressure (Mercury) Pc Sh Sandstone ρ e = 23 um/s σ for oil water 22 dynes/cm θ for oil water = 35 degs σ for air mercury water 480 dynes/cm θ for air mercury = 140 degs pw=1.0 g/cc phc=0.85 g/cc Lab Data
List properties that NMR measures that can be used to infer permeability?
List those properties in order of importance
77.
Permeability and Capillary Pressure Pc (or h) 0% 100% sb & Pc Strong correlation between Capillary pressure curves and permeability? Critical threshold pore size and volume
T2 logging requires rf interrogation field to be stable for duration of T2 experiment (10’s of seconds)
Stability is keeping the same sensed volume relative to the rf field generating the CPMG pulses for the duration of the experiment (i.e. sensed volume must be same throughout the experiment).
For MRIL measurement shells are very thin & therefore sensitive to motion. CMR measurement small cubic sensed volume.
Random tool movement during drilling (i.e. vibration) causes instability in magnetic volume.
T1 saturation recovery experiments are insensitive to tool motion
The measurement pulse is very short duration (1/2000 sec). Therefore tool relatively stable in this short time.
Magnetic field and saturation pulse cover large volume compared to measurement pulse. Therefore measurement pulse compared to magnetic field is stable for the short duration of measurement
T1 is much longer experiment than T2. But while drilling this is not a problem
LWD T1 (delivers limited spectrum and mainly used for porosity)
T2 measured while pulling out of hole for full T2 relaxation
The phase angle is used to extract the signal amplitude and signal noise from the x and ycomponents to generate the echo-train data used for inversion to T2 distributions.
In porous intervals, the signal phase should remain relatively stable (±100). In low porosity
In shaly zones, signal noise is difficult to estimate due to low signal to noise. Consequently, the
Signal phase should only be examined with respect to log quality in clean porous intervals.
Signal Phase Calculation Explained in CMR processing
125.
CMR Quality Control (Polarisation Correction)
Older tools only where Tw < 3*T1 of formation & fluids.
As the tool is pulled past the formation, the formation experiences a time dependent magnetic field (wait time) and thus time dependent polarization.
For the CMR 200, at speeds higher than 5 cm/s there is a significant loss in polarization for fluids with a T1 greater than 1s.
Consequently, at logging speeds greater than 5 cm/s there is a significant loss of polarization
For fluids and large pores with long T1's. Since porosity is calculated as the sum of the amplitudes of the T2 distribution multiplied by the CMR calibration value, the porosity estimated from CMR data is affected by the polarization correction.
126.
CMR Quality Control (Polarisation Correction) Analogue Model Inversion Fluid Sub Tw = 1 sec Lost porosity With Tw = 1 sec
127.
CMR Quality Control (Polarisation Correction)
The polarization correction is
128.
CMR Quality Control (Polarisation Correction)
As part of the quality control checks, three different porosity estimates are calculated usingthree different T1:T2 ratios (R). The default values taken for R are 1, 1.5 and 3.
ERRMINUS and ERRPLUS are the differences between the default and limit values for R
The CMR log can be checked for incomplete polarization (insufficient wait time) by comparing the three different porosity estimates calculated using the three different values of R. Where theformation has been subject to a sufficient wait time, and complete polarization has occurred,there should be no difference in porosity calculated using different wait times. In cases wherethe wait time was insufficient for complete polarization, porosities will differ over the range ofT1:T2 ratios selected.
Insufficient wait time is normally flagged when the difference between porosity calculated using the minimum R and maximum R is greater than 2 p.u. (WAIT_FLAG)
134.
CMR Porosity Calibration. Alternatively CMR porosity can be calibrated directly to another measurement (i.e. core data).
135.
CPMG (Echo) Processing CPMG data is collected using a quadrate detection system in which the signal is recorded in two channels (R and X). The R and X data is used to estimate the phase of the signal and the two channels are combined to generate (1) a phase coherent channel that contains the signal, and (2) a noise channel. Echo R Echo X Phase Angle signal noise
136.
CPMG (Echo) Processing The phase angle is calculated as: where φ = phase angle i = ith echo of the echo train k = number of echoes to be used in the phase angle calculation
137.
CPMG (Echo) Processing R and X = inphase and quadrature detected component of the CPMG The CPMG signal and noise is calculated by rotating the channel data through the phase angle . signali = Ri *cos φ + Xi * sin φ noisei = Ri *sin φ - Xi *cos φ where: signali = signal of the ith echo noisei = noise of the ith echo Ri = inphase component of the ith echo Xi = quadrature component of the ith echo
138.
S:N and Vertical Resolution (data stacking) 8 Level Stack Stack Base to Top
142.
Practical NMR Log Processing: MRIL. DTE DATA Frequency 1 Frequency 2 Frequency 3 Frequency 4 md time Running Average = 8 (PAP * NF) Phase Alternated Pairs PAP’s .
145.
MRIL Running averages & Minimum Running Average
Running Average (RA)
Stack several echo trains to improve S:N
Data is collected in phase alternated pairs
Data is collected over several frequencies (depending on acqusition mode)
Minimum Running Average
Similar data is gathered together over the acquistion cycle.
Minimum RA is Number of frequencies * 2
For example DTE uses 4 frequencies.
The sort TE data is collected over 2 frequencies
The Long TE is collected over 2 frequencies
The minimum RA is 4 for the short and long TE data
The running average can be increased to imrove S:N but must be a multiple of the minimum RA
146.
MRIL Running averages & Minimum Running Average DTE data Minimum RA = 4 RA = 16 NOTE RA always in Direction of time (not depth) Q? In which direction was This data logged, up or Down? md time
CPMG data is collected using a quadrate detection system in which the signal is recorded in two channels (R and X). The R and X data is used to estimate the phase of the signal and the two channels are combined to generate (1) a phase coherent channel that contains the signal, and (2) a noise channel. Echo R Echo X Phase Angle signal noise
The salinity correction is only applied if the Rmf < 10 ohm.m at 75° C. The correction compensates from the loss of hydrogen atoms replaced by salt ions.
Temperature Corrections
Temperature affects the thermal relaxation of protons and reduces the amplitude of the returned signal. The temperature correction should always be applied.
Hydrogen Depletion Correction
Increased temperature of the formation reduces the density of the formation fluid and decreases the hydrogen index. Higher pressures increase the hydrogen index. This effect is compensated for by using a Hydrogen Depletion Multiplier, which is a function of porosity and temperature.
Environmental corrections are applied during phase rotation of the real and imaginary data.
is dependent upon the loading of the MRIL transmitter coil by borehole fluids and the formation, and is measured continuously throughout logging. Gain is also frequency dependent, and generally, the operating frequency is chosen to achieve the maximum gain.Gain should be constant; spiking usually indicates tool problems.
Q Level
is an estimate of coil quality; certain MRIL activations are designed to run at agiven Q Level (high, medium or low). Q Level depends on the Gain.
The B1 Field is responsible for generating the pulse sequence that is used to acquire the CPMG sequence. With every pulse sequence, the B1 is measured using a test coil.
The B1 Field should remain relatively constant but should show some variation with changes inconductivity and gain. Consequently, the B1 Field should be checked for overall variation andvariation with conductivity and gain.
168.
T2 Attributes Geometric mean Number of peaks Peak(s) position Ratio of volume under peaks Bound Fluid Free Fluid Clay Bound Water Skewness Kurtosis Principal Components etc
169.
Bound Fluid 0.1 1.0 10.0 100.0 1000.0 10000.0 Rock Bulk Volume Rock Matrix Clay Clay bound water Total Porosity Effective Porosity Capillary bound water Free water Hydrocarbons Minerals T2 cutoff
Use core calibration (i.e. porous plate de-saturation)
Remove free fluid from T2 distribution
Substitute in ‘hydrocarbon’ with bulk properties
Model raw data
180.
Forward Modelling Spectral bound fluid = Swirr 2. Remove free-fluid (water) 3. Add in free fluid water so that T2LM of free fluid = T2 predicted for hydrocarbon 1.
181.
Forward Modelling : Optimising Inversion of Log Data Inversion: SVD T1 min = 0.3 T2 max = 3000 No Bins = 30 T2 maximum is not long enough to capture Long T2 associated with carbonate Analogue Model Inversion
182.
Forward Modelling : Optimising Inversion of Log Data Inversion: SVD T1 min = 5 T2 max = 5000 No Bins = 30 Analogue Model Inversion New bin range better captures the full T2 spectrum
‘ A set of similar NMR T2 distributions that summarise the petrophysical characterics of the rock’
Walsgrove Stromberg and Lowden 1997
‘ Categorization of types that are recognisable away from the core point allow the extrapolation of petrophysical parameters and interpretation models.’
192.
Example 1. Analogue Data Log Data 5 4 3 2 1 Shale Analogue Low K < 100 mD High K > 100 mD 0.1 1 10 100 1000 10000 0.1 1 10 100 1000 10000 0.1 1 10 100 1000 10000 0.1 1 10 100 1000 10000 0.1 1 10 100 1000 10000 0.1 1 10 100 1000 10000
193.
Interpretation from Analogues GR CMRP BFV Permeability T2 Dist Meander Meander Braided Point-bar Low K Model 1 High K Model 2 0 GAPI 150 0.5 V/V 0 0 mD 10000
Fluid substitution to construct psuedo 100% Sw T2 distribution
Method only exists for sandstones at present
Method:
Calculate Swirr (using SBFV method)
Predict theoretical T2LM in water wet sandstones
Remove free fluid part of spectrum using SBFV method
Add in water spectrum such that T2LM = theoretical T2LM
198.
T2LM in Sandstones (from sandstone rock catalogue) Log10(1-Swirr/Swirr) T2LM Yakov Volokitin, Wim Looyestijn, Walter Slijkerman, Jan Hofman. 1999. Constructing capillary pressure curves from NMR log data in the presence of hydrocarbons . Transactions of the Fortieth Annual Logging Symposium, Oslo, Norway, 1999. Paper KKK 10**(0.772*(LOG10((-1-SWirr)/SWirr))+k K = 1.5
199.
Pseudo 100% Sw T2 Spectral bound fluid = Swirr 1. 2. Remove free-fluid (hydrocarbon) T2LM =10**(0.772*(LOG10((-1-SWirr)/SWirr))+k K = 1.5 3. Predict T2LM Add in free fluid water so that T2LM = predicted T2LM 4.
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