Nmr Course

Class Exercise (NMR Perceptions) The purpose of petrophysics in formation evaluation Primary Objectives Secondary Objectives Nice to have (but almost impossible)

Class Exercise (NMR Perceptions) Based on you conclusions about petrophysics Where does NMR fit in? Primary products Secondary products Might deliver (but unreliable)

Petrophysics Review Porosity Saturation Wettability Surface and Interfacial tension Capillary pressure Permeability 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.

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 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

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

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.

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 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

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

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

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

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

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 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

Calibration of Logging Tools Shop calibration Calibrated using a special calibration tank Calibrated at well site using bottle of water (100% porosity)

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

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.

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)

Pore Size in 100% Water Saturated rocks

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

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

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).

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

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.

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

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

T2 Distribution Reflects Porosity ‘Bins’ Porosity is sum of porosity bins (x+y+z) T 2 x T 2 y T 2 z

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

Demonstration of Inversion LIVE DEMO BASED ON CMR200 Data Echo trains Time domain porosity Inversion Smoothing weight Effect of echo filtering Porosity from T2

The Limitations of Inversion Supplementary Notes Inversion limitation discussion

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

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

Bulk Relaxation T2 LM Viscosity (cp) 1 10 100 1000 10000 1 10 100 1000 0 50 100 150 200 0.1 1 10 100 T2 LM secs) water 6 cp oil 20 cp oil Temp (deg C)

Bulk Relaxation Oil and Gas Oil viscosity and T2 (150 degF) Density of gas (150 degF)

Density and diffusion coefficient of gas 150 deg F

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

Fluid Properties Calculator /*calculate the diffusion coefficents DCO_WATER = ((1.3*temp_k)/(298*MU_WATER))*(10**-5) DCO_OIL = ((1.3*temp_k)/(298*MU_OIL))*(10**-5) DCO_GAS = (0.085*((temp_k**0.9)/RHO_GAS))*(10**-5) /*Tool Coefficients (TE in MSEC) tco = (C*GMR*G*TE)*(C*GMR*G*TE)

Fluid Properties Calculator t2do = 12 / (tco*DCO_OIL) T2_OIL = 1/((1/t2do) + (1/(T12B_OIL/1000)) ) * 1000 t2dg = 12 / (tco*DCO_GAS) T2_GAS = 1/((1/t2dg) + (1/(T12B_GAS/1000)) ) * 1000

Qualitative Fluid Substitution. Bound fluid = Sw irr 2. Remove free-fluid (water) 3. Add in free fluid water so that T2LM of free fluid = T2 predicted for hydrocarbon 1.

Exercise - Predicting Fluid effects USE 250 deg F, C=1.08, G = 19.1 g/cm and, GMR = 18.1) (TE 0.6 msec) BRINE 20 cp Oil 6 cp Oil Gas (0.2 g/cc)

Exercise - Predicting Fluid effects Excercises\Model Answers\Solution Fluid Excercise.ppt

Fluid Typing Basics: Exploit T1 contrasts of fluid Diffusion contrasts fluids Set acquisition parameters That separate water from hydroocarbons Depends on T1 or diffusion contrasts

Polarization (T1) Contrast T1, amount of time taken to polarize water Requires large T1 contrast Used in gas and light oils (< 5 cp) Best in oils < 1 cp Not suitable for more viscous crude oils Acquistion Two wait times Long (TWL): polarizes water and hydrocarbons Short (TWS): polarizes water only

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

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

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

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

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)

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

Logging Gas Reservoirs Polariztion function for gas: Pol g =1-exp (-W/T1g)

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.

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)

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

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

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

Wettability From NMR Logging, Coates et al .

Bound Fluid Bound Fluid Includes Chemically bound water (crystal lattice water) Adsopbed water (surface) Clay bound water Capillary bound water

Bound Water NMR has the potential to detect Clay bound water Capillary Bound Water

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.

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

Bound fluid in relation to pore size The average capillary radius: Pore size and T2 relaxation

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

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)

Variation In T2 Cutoffs FWL Borehole HAFWL Sw A B A B 100 0 Pc (psia) 480

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

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

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.

Spectral Bound Fluid Bound fluid = Capillary bound + Surface film b W = f(T2) Sandstone Model: m = 0.0113; b = 1.

Permeability. Permeability is a dynamic property NMR does not measure fluid flow NMR measures static properties that can be linked to permeability

Permeability. Exercise List properties that NMR measures that can be used to infer permeability? List those properties in order of importance

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

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

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.

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.

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.

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

Primary and secondary objectives Primarily a lithology independent porosity tool, offering great accuracy. Secondarily Fluid typing Pore size distribution Petrophysical facies Permeability

Which tool? The cheapest? CMR High vertical resolution, lower S:N. Fluid typing requires multiple passes (older generation tools). 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

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

CMR (e.g. 200) Sensitive region Sensitive region Antenna (rf probe) Magnets

CMR Logging – Single Frequency (CMR 200) Polarization Acquisition (CPMG) TR is controlled by the logging speed

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

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)

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

Multi-Frequency Tools (e.g. MRIL C & MRIL Prime)

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)

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

Multi frequency operation Delta wait time Two different Tw Delta echo spacing Two different TE Increased S:N Multiple acquisitions in different frequency bands

Multi Frequency Acquisition Cycle DTW.

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

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

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

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

T1 Saturation Data Nuclear polarization 1 0 B 0 exposure time (variable delay) 1 0

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

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

Setting Up Logging Jobs Be clear on the objectives Porosity Bound fluid Fluid typing Etc Parameters Wait time Number of echoes Frequency mode

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

Job planning additional information NMR core data T1, T2 Capillary pressure data BFV cutoff Conventional core analysis data Porosity and permeability calibration

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.

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)

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

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)

Tool Tuning, Frequency Sweep Signal Amplitude Frequency Lab calibration Result of sweep down hole

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

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

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

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) Temperature MORE IN PRACTICAL NMR LOG INTERPRETATION

General Work Flow Evaluate raw data QC checks Porosity calibration checks Echo data processing Inversion Porosity calculation Cross check with other logs Evaluate T2 distributions Fluid typing Multi acquisition processing Bound and free fluid T2 cutoff Spectral Bissecting Clay bound water Permeability Rock Typing Capillary pressure conversion Specialist Activities Core Calibration Forward Modelling Log Analyst / Interpreter

Practical NMR Log Processing: CMR CMR quality control Porosity calibration CPMG processing Phase angle Phase rotation Data stacking Inversion

CMR Quality Control - GAIN Gain: 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

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

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

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.

CMR Quality Control (Polarisation Correction) Analogue Model Inversion Fluid Sub Tw = 1 sec Lost porosity With Tw = 1 sec

CMR Quality Control (Polarisation Correction) The polarization correction is

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)

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

Quality Control of CMR data Signal-to-Noise Good data

Quality Control of CMR data Signal-to-Noise Noisy Data

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.

CMR Porosity Calibration. Alternatively CMR porosity can be calibrated directly to another measurement (i.e. core data).

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

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

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

S:N and Vertical Resolution (data stacking) 8 Level Stack Stack Base to Top

S:N and Vertical Resolution (data stacking) Demonstration

Practical NMR Log Processing: MRIL. Multi-Phase & Frequency Processing

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

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 .

Practical NMR Log Processing: Data Coding

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

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

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

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

Time Based Data and Depth Conversion

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.

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

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.

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.

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

Noise Indicators High Q Med Q Low Q

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)

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.

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

Polarisation Correction The polarization correction is

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

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

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.

Bisecting Method. ‘ saddle point’

Lab Calibration Calibration Lab NMR data for Porosity T2 cutoffs Capillary Pressure Data T2 cutoffs Pore size Forward Modelling Reconfiguring lab data for log response Fluid substitution Optimising inversion

T2 Cutoffs 0 0.1 0.1 1.0 10 100 1000 10000 T2 (ms) Por (p.u.) Sw irr (core) T2 Cutoff 0.1 1.0 10 100 1000 10000 0 1.0 0.8 0.4 0.6 0.2 Porosity Deviation (Frac) BFV Cutoff T2 (ms)

T2 cutoffs 0.1 1.0 10 100 1000 10000 0 1.0 0.8 0.4 0.6 0.2 Porosity Deviation (Frac) T2 cutoff (ms) Multiple Samples T2 cutoff range

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

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

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.

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

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

Forward Modelling : Fluid Substitution 3 CP Oil T2 = 1130 msec (150 deg F) Analogue Model Inversion Fluid Sub

Forward Modelling : Decreased Wait Time (1 sec) Analogue Model Inversion Fluid Sub Tw = 1 sec Lost porosity With Tw = 1 sec

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

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.’

Facies Analysis ft 0 50 100 150 Porosity Permeability Porosity Permeability Porosity Permeability

Cluster Analysis Distance Coefficient Distance Cutoff

Example 1. Using Analogue Data Log Data Analogue 5 4 3 2 1 Shale Meander Point-bar Braided 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 0.1 1 10 100 1000 10000

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

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

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)

Example Ghadames Basin Sh (1-Sw) PC (h)

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

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

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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