On October 23rd, 2014, we updated our
Privacy Policy
and
User Agreement.
By continuing to use LinkedIn’s SlideShare service, you agree to the revised terms, so please take a few minutes to review them.
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
6.
NMR And Petrophysics
NMR is primarily a porosity and fluid characterisation tool
Its primary advantage is that NMR porosity is lithology independent and the derivation of porosity requires no correction for matrix properties
Secondary Benefits
Pore size distribution
Fluid characterisation
Saturation (clay, capillary, free water and hydrocarbons)
Nice to have (but difficult)
Wettability
Capillary pressure
Risky (but possible)
Facies or rock typing information
7.
NMR And Permeability
Permeability (Holy Grail)
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
10.
Porosity Definitions
Effective (log analysis):
Void volume available for storage of hydrocarbons
Includes capillary water
Excludes clay bound water in pore volume
Unconnected pore volume not necessarily excluded
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 :
16.
Calibration of Lab Data
A sample reference is used
Water bottle partly filled to a known volume
Doped with a relaxation agent (to reduce T2)
Sometimes doped to reduce signal with D 2 0
(To a specific porosity)
Amplitudes are then compared
17.
Calibration of Logging Tools
Shop calibration
Calibrated using a special calibration tank
Calibrated at well site using bottle of water (100% porosity)
18.
Calibration of Logging Tools (MRIL Example)
Pre logging:
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)
21.
Pore Size in 100% Water Saturated rocks
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
24.
Exercise
If ρ increases but pore size is constant what happens to the value of T2.
If ρ increases, what are the implication for the measurement of T2.
If ρ is low what is the implication for wait time (T1).
25.
Impact of Lithology
Lithology and relaxivity
Sandstone ρ e = 23 um/s
Dolomite ρ e = 5 um/s
Limestone ρ e = 3 um/s
For example a T2 of 33 msec in sandstones = T2 of 0.033 sec = pore (throat) size of 0.759 um
26.
Pore Size
NOTE:
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
31.
Demonstration of Inversion
LIVE DEMO BASED ON CMR200 Data
Echo trains
Time domain porosity
Inversion
Smoothing weight
Effect of echo filtering
Porosity from T2
32.
The Limitations of Inversion
Supplementary Notes
Inversion limitation discussion
33.
Fluid effects
100 % Water saturated pores:
Surface limited relaxation
Pore-size information
Oil in water wet pores:
Oil does not see pore wall
Bulk relaxation
Water sees pore wall
Surface limited relaxation
Relaxation is a function of film thickness h
h
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
37.
Bulk Relaxation Oil and Gas Oil viscosity and T2 (150 degF) Density of gas (150 degF)
38.
Density and diffusion coefficient of gas 150 deg F
39.
Fluid Properties
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
49.
Diffusion Contrast
Uses diffusion contrast
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
51.
Enhanced Diffusion
Water has an upper bound for apparent (pore size limited) T2
Vary effectiveness of the diffusion component of water T2
Create a detectable contrast between water and oil
Medium viscosity oils
52.
Enhanced Diffusion 0.1 1.0 10 100 10 100 1000 T2 oil T2DW TE = 3.6ms G = 19.1 G/cm T = 200 deg F Viscosity (cp) Relaxation Time (msec)
53.
Enhanced Diffusion T2DW
54.
Logging Gas Reservoirs
NMR porosity will underestimate Total porosity because:
The low hydrogen index (tool calibration assume HI = 1.0)
Insufficient polarization of gas
Density logging overestimates porosity because:
Measured formation density is reduced by gas (assuming that fluid density
is not corrected for gas)
ρ b = ρ ma (1- Φ + ρ fl Φ (1-S g,xo )+ ρ g Φ S g,xo Φ nmr = Φ S g,xo (HI) G Pol g + Φ (1-S g,xo )(HI) f
55.
Logging Gas Reservoirs Polariztion function for gas: Pol g =1-exp (-W/T1g)
56.
DMRP Inputs & Calculated Logs
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.
58.
Magnetic Resonance Fluid characterization
Station log
with
CMR+
Pulse sequences investigate the different polarization and diffusivity of the fluids. POLARIZATION SHORT TE BULK & SURFACE RELAXATION (Short TE) LONG TE DIFFUSION (LONG TE)
59.
Magnetic Resonance Fluid characterization
Plot of T2 v. diffusivity
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
60.
Magnetic Resonance Fluid characterization
Example of MRF station
Align at top corner on each page Consistent image height Image Area Gas Reservoir oil Oil Filtrate Bound Water
61.
Wettability
The tendency of one fluid to spread on to or adhere to a solid surface in the presence of other immiscible fluids
Fluids that in molecular contact with a mineral surface have a relaxation time less than the bulk fluid relaxation time
This enhanced relaxation is due to surface relaxation phenomena
NMR core experiments have been made to try and qualify wettability
62.
Wettability From NMR Logging, Coates et al .
63.
Bound Fluid
Bound Fluid Includes
Chemically bound water (crystal lattice water)
Adsopbed water (surface)
Clay bound water
Capillary bound water
64.
Bound Water
NMR has the potential to detect
Clay bound water
Capillary Bound Water
65.
Connate Water Saturation
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
67.
Bound fluid in relation to pore size
The average capillary radius:
Pore size and T2 relaxation
68.
T2 Cutoffs 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
69.
T2 Cutoffs
T2 is proportional to pore-size
T2 cutoff is pore-size cutoff
More meaningful as a capillary pressure cutoff
T2 cutoffs are a function of
Capillary pressure chosen for Swc
Choice depends on interpretation
Producible water (i.e. capillary pressure)
Permeability equation (i.e. pore-size)
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
72.
T2 Cutoff From Capillary Pressure (Mercury)
Calculate T2 cutoff at S wc
Calculate T2 cutoff at 100 ft HAFWL
Show equivalent Pc on cap pressure curve
Calculate Sw at 100 ft
Convert to T2
Exercise
73.
Spectral Bound Fluid
Bound flluid resides in:
Small pores
Pore throats
Pore lining
Each pore size in the NMR spectra is assumed to contain some bound water
The distribution of of bound water is defined by a weighting function.
74.
Spectral Bound Fluid Bound fluid = Capillary bound + Surface film b W = f(T2) Sandstone Model: m = 0.0113; b = 1.
75.
Permeability.
Permeability is a dynamic property
NMR does not measure fluid flow
NMR measures static properties that can be linked to permeability
76.
Permeability. Exercise
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
78.
Permeability
79.
Permeability and Pore Size
Capillary pressure curves suggest a strong correlation between permeability and:
Pore throat size
Pore volume
NMR measures:
pore body size, but in almost all sandstones and some carbonates a correlation exists between pore body size and pore throat size
The amount of trapped bound fluid is related to pore throat size
The average throat size (pore size) is related to the average T2 value
80.
Permeability Models
Two most common models, permeability varies as Φ 4 .
Arbitrary (loosely based on Archie’s explanation of resistivity).
Require an additional factor to account for pore throat size.
All are based on empirical considerations.
81.
Coates Model
The bound fluid term relates NMR pore-size to threshold pore size
Problems
BFV cannot include hydrocarbons
BFV should not be affected by OBM filtrate
In gas zones or zones with hydrocarbon that has low hydrogen Index porosity may read too low from NMR log
Heavier oils with low T2 may be counted as bound fluid, causing bound fluid to be over-estimated.
82.
The Mean T2 Model (SDR Model)
Uses NMR effective porosity
T2 is geometric mean of T2 and therefore represent the ‘average’ pore size.
Works well in water zones
Bulk T2 responses (i.e. hydrocarbon) can skew the response
Mean T2 model can fail in hydrocarbon bearing formations.
83.
NMR LOGGING
84.
When Should I Use NMR Logging.
Good question, many benefits (and many overheads)
Excellent porosity tool
Expensive
High LIH charges
Pore size distributions can be used to quantify petrophysical units
Requires calibration
Fluid identification
Shallow reading tool, logs flushed zone
Low resistivty pay
Possible applications for permeability prediction
Requires extensive core calibration
85.
Primary and secondary objectives
Primarily a lithology independent porosity tool, offering great accuracy.
Pad based eccentred tool (error prone to rugosity)
MRIL
Lower vertical resolution, higher S:N. Fluid typing in a single pass
Centred tool (error prone to wash-out)
Combinability
Contracts
Regional experience
87.
Which Tool – Basic Tool design
Tool specs are continuously changing, for tool sizes and P/T limitations refer to your contractor
Next few slides refer to basic differences between tools
LWD tools also exist
88.
CMR (e.g. 200) Sensitive region Sensitive region Antenna (rf probe) Magnets
89.
CMR Logging – Single Frequency (CMR 200) Polarization Acquisition (CPMG) TR is controlled by the logging speed
90.
CMR Total Porosity Mode T2 L T WL Phase +ve Phase -ve Total NE=3000 TOTAL NE = 3000 CPMG=Phase +ve and Phase -ve TE N S N S
91.
CMR Plus
Increased logging speed:
30” magnets extend above and below 6” measurement antenna
Pre-polarization (prepares the formation)
Increased polarization at same logging speed
Increased logging speed for same polarization
Enhanced precision mode logging
Improve resolution at short T2 (i.e. clay bound water)
92.
Enhanced Precision Mode T2 L T WC …… . Single Frequency TE=120ms NE=800 TE=0.6ms, NE=10 repeat*50 TW = 24 s averaging Effective porosity Clay-bound porosity 4ms-20000ms 0.5ms-2ms = + T WL
93.
Multi-Frequency Tools (e.g. MRIL C & MRIL Prime)
94.
MRIL Prime
95.
Multi Frequency And Depth of Investigation
Gradient field, and therfore magnetic field strength is a function of radial distance (r) from the tool surface.
Larmor frequency (i.e. frequency of proton oscillation) is proportional to magnetic field strength
To detect protons need to select correct frequency band (i.e. radio analogy)
96.
Multi Frequency Tool
Selecting a narrow frequency results in a the sensitive volume being a thin cylindrical shell
Changing frequency band changes the depth of investigation.
Spin tipping only occurs within the tuned frequency band
97.
Multi frequency operation
Delta wait time
Two different Tw
Delta echo spacing
Two different TE
Increased S:N
Multiple acquisitions in different frequency bands
98.
Multi Frequency Acquisition Cycle DTW.
99.
Multi Frequency Tool Advantages
Multiple measurement shells
Multiple acquisitions at same depth
Improved S:N (more than one measurement at same depth available for signal averaging
Multiple experiments – no need for multiple passes for
Polarization contrast experiments
Diffusion Experiments
MRIL C
Two Frequency measurements
MRIL Prime
Multiple frequency measurements
One Disadvantage is:
Lower resolution
100.
LWD MRIL T1 Saturation Recovery
LWD Logging:
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
101.
LWD MRIL Tool
102.
Saturation Recovery
Protons polarised in field
2. Broadband pulse saturates (eliminates) polarisation B 0 Field
Protons allowed to recover for Time = t
B 0 Field After time = t, some of the protons have recovered Magnetization measured by a very short pulse sequence Time for total recovery = T1
103.
T1 Saturation Recovery Recovery times are stepped between measurements Saturation pulse Measurement pulse Variable delay Delay sequence 1, 3, 10, 30, 100, 300, 1000, 3000 msec
104.
T1 Saturation Data Nuclear polarization 1 0 B 0 exposure time (variable delay) 1 0
105.
T1 Saturation Recovery & Logging
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
106.
Depth of Investigation
MRIL (DOI is radius from tool centre)
6 in tool
200 deg F 14.5 in and 16.5 in (high and low frequency)
8.5 in hole, 16 in DOI corresponds to 3-4 in from borehole wall.
4.5 in tool
10 and 11.5 in
CMR (Quoted for CMR 200)
0.5 to 1.5 in
CMR and MRIL tools generally reads in the flushed zone
107.
Setting Up Logging Jobs
Be clear on the objectives
Porosity
Bound fluid
Fluid typing
Etc
Parameters
Wait time
Number of echoes
Frequency mode
108.
Job Planning Basic Steps
Borehole temperature and pressure
Determine NMR fluid properties:
Bulk T1 and T2, Diffusion coefficient and HI
You will need, viscosity, HI, mud type
Expected porosity
Decay spectrum, polarization
Activation sets and frequency cycling
Porosity logging
Hydrocarbon logging (DTE, DTW)
Clay types (presence)
Enhanced precision mode
109.
Job planning additional information
NMR core data
T1, T2
Capillary pressure data
BFV cutoff
Conventional core analysis data
Porosity and permeability calibration
110.
Pre-logging Checks
Correct acquisition mode
Hole clean up with ditch magnet recommended with hole debris is suspected
Shop calibration checked at well site (if possible)
Tool tuning
May need to be repeated several times through the logging job.
111.
Pre Logging Checks Acquisition Modes
Total porosity
Maximise resolution
Maximise S:N
Fluid Typing
Correct mode for expected fluids
Light hydrocarbons = Dual Tw
Viscous Oil, Dual Te
Intermediate oils, Enhanced diffusion
Frequency cycling diagram
MRF planning (i.e. in MDT program)
112.
Pre Logging Checks Tool Tuning (Example CMR)
The tool must be operated at the Lamour frequency, which is determined by the magnetic field strength
Magnetic field strength will vary with
Formation mineralogy
Temperature
Hole debris
113.
Tool Tuning, Frequency Sweep
Conducted Down hole over a porous zone
Tuned 3 times (1) Repeat pass, (2) Before Main Pass (3)After logging
Ensure temperature stabilization
Tool is moved slowly up and down
Used to determine operating frequency
Tool is retuned if changes in magnetic field gradient occur (change in Delta Bo)
114.
Tool Tuning, Frequency Sweep Signal Amplitude Frequency Lab calibration Result of sweep down hole
115.
Implications of Poor Tool Tuning
Signal amplitudes will be low, compared with the porosity calibration
Shape of T2 distribution not effected
Porosities will be low
Errors in frequency and porosity
1 kHZ -0.2% low
3 kHZ -1.5% low
5 kHZ -3.4% low
116.
Log Quality Control
4 steps
Check acquisition parameters against job plan
Tool behaviour
Tool tuning plots
Noise evaluation
Compare raw and processed data (i.e. pre and post stack)
Get Log QC plot
117.
Log Quality Control Guidelines - CMR
Key parameters are:
Gain
Delta B 0
Signal Phase
Noise standard deviation
Gamma regularization
MORE IN PRACTICAL NMR LOG INTERPRETATION
118.
Log Quality Control Guidelines - MRIL
Key Parameters are:
Gain and Q level
B1 and B1 nod
Chi
Noise indicators
Offset
Noise
Ringing
IENoise
Low and High Voltage sensors
Phase correction information (PHER, PHNO and PHCO)
Amount of loading applied to the tools circuits by fluids and formation
Gain is the amount amplitude of the signal received by the RF antenna
Gain is frequency dependent, and optimum gain depends on correct tool tuning
Gain should not
Have sudden changes or spikes
be 0
Drop below 0.3
123.
CMR Quality Control – Delta B 0
Delta B o
Estimated by the hall probe and temperature sensor
Difference between two is Delta B 0
Indicates amount of debris on on magnets
If it exceeds 0.1 mtesla. The tool should be retuned
124.
CMR Quality Control, Signal Phase
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)
129.
Quality Control of CMR data Signal-to-Noise
The Raw CPMG data is inherently noisy
The S:N is acceptable if distributed evenly across the Echo train
S:N can be increased by data stacking
S:N can be expressed as RMS noise or a S:N ratio
130.
Quality Control of CMR data Signal-to-Noise Good data
131.
Quality Control of CMR data Signal-to-Noise Noisy Data
132.
Quality Control of CMR Gamma
Gamma
A regularization method is used to generate a smooth T2 distribution. For Schlumberger processed CMR data Gamma controls the amount of smoothing
Gamma depends on the S:N, in high S:N environments (high porosity) Gamma is usually less than 5. In low SLN environments Gamma is more than 10.
133.
CMR QC plots
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
139.
S:N and Vertical Resolution (data stacking)
Demonstration
140.
Practical NMR Log Processing: MRIL.
Multi-Phase & Frequency Processing
141.
Practical NMR Log Processing: MRIL.
Raw data on time-based file
Apply running average (minimum stack)
Phase angle and phase rotation
Environmental corrections
Time to depth conversion
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 .
143.
Practical NMR Log Processing: Data Coding
144.
Practical NMR Log Processing: Data Coding
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
147.
MRIL Phase Rotation
Identical technique used for processing CMR data
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
148.
Time Based Data and Depth Conversion
Raw MRIL data on time based file
After processing the data, the data is converted to depth by sampling the data
Time to depth conversion can only be done after the minimum running average has been applied.
Time to depth conversion can be carried out:
Post minimum RA (Real and Imaginary Data)
After phase rotation (ECHO and NOISE)
After environmental correction
After inversion
149.
Time Based Data and Depth Conversion
150.
Environmental Corrections
151.
Environmental Corrections
Salinity Correction
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.
152.
MRIL Quality Control
Gain and Q level
B 1 and B 1mod
Chi
Noise Indicators
Offset
Noise
Ringing
IENoise
Low voltage sensors
High voltage sensors
Phase Correction Information
153.
Gain And Q Level
Gain
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.
154.
Gain And Q Level
155.
B1 Field (B 1 and B 1mod )
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.
156.
Chi
Equivalent to gamma used in CMR inversion of T2 data.
A regularization method is used to generate a smooth T2 distribution
Chi limits
Mo less than 2, except in low Q situations
157.
Noise Indicators
158.
Noise Indicators High Q Med Q Low Q
159.
Voltage Sensors
160.
Phase Angle Corrections
PHER
Mean of the noise channel, and should be close to zero, less than 1 for good quality data
PHNO
Standard deviation of the noise channel, should be comparable in magnitude with other noise indicators
PHCO
Phase correction angle, should be relative constant in porous intervals (high Q environment), random variation in Low Q (i.e. shales)
161.
T2 Analysis Work Flows
162.
T2 Analysis Work Flows
The T2 analysis tool kit
Porosity calculation.
Denisty NMR Porosity calculation.
Estimatation of the T2 geometric mean (T2LM).
Calculation of the bound fluid.
Estimation of T2 bumps.
Permeability.
Tracking the T2 of the modes of the distribution (Peak Tracking).
Calculation of viscosity.
163.
Porosity
Calibrated as previously discussed
May be calibrated against core data
Calculated from the sum of the amplitudes of the T2 distribution
Represents total porosity, including capillary and clay bound water
164.
Porosity
165.
Polarisation Correction
The polarization correction is
166.
Polarisation Correction
167.
Porosity Log
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
170.
Bound Fluid
171.
Spectral Analysis Bound fluid = Capillary bound + Surface film b W = f(T2) Carbonate Model: m = 0.0113; b = 1. Sandstones m = 0.0618, b = 1.
178.
T2 cutoffs 0.1 1.0 10 100 1000 10000 0 1.0 0.8 0.4 0.6 0.2 Porosity Deviation (Frac) RMS average 9.3ms RMS Error Plot Error Associated with single value T2 cutoff
179.
Forward Modelling
Predict fluid properties of hydrocarbon
Calculate bound fluid
T2 cutoff
Spectral Bound Fluid
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
184.
Forward Modelling : Decreased Wait Time (1 sec) Analogue Model Inversion Fluid Sub Tw = 1 sec Lost porosity With Tw = 1 sec
185.
ADDED VALUE FROM NMR
186.
Other Applications
NMR facies analysis and flow unit identification
Non parametric & statistical techniques
Capillary pressure from NMR
Pseudo water saturated T2
Capillary pressure conversion
Saturation height modelling
187.
NMR Facies
‘ 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
194.
Capillary Pressure Modelling
195.
Scaling T2 to Pc Pc & k*(1/T2) Pc & k*(1/T2) Pc = K*(1/T2) NMR PC Sw 100000 0 100000 0 0 1 Sw 100000 0 0 1 Pc (height)
196.
Example Ghadames Basin Sh (1-Sw) PC (h)
197.
Rocks With Sw < 1 (i.e. dual phase T2)
Rocks with hydrocarbons:
T2 influenced by hydrocarbons
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.