Understanding NMR Geoff Page Baker Hughes Region Petrophysics Advisor 1 2017 B A K E R H U G H E S I N C O R P O R A TED. A LL R I G H TS R E S E R V E D. TERMS A N D C O N D I TI O N S O F U S E : B Y A C C E P TI N G THIS DOCUMENT, THE RECIPIENT A G R E E S THAT THE DOCUMENT TOGETHER W I TH A LL I N FORMATI O N I N C LUDED THEREIN I S THE C O N FI D E N TI A L A N D P R O P R I E TARY PROPERTY OF B A K E R H U G H E S I N C O R P O R A TED AND INCLUDES VALUABLE TRADE SECRETS AND/OR PROPRIETARY INF ORMA TI O N O F B A K E R H U G H E S (C O LLECTI V E LY "I N FORMATI O N "). B A K E R H U G H E S R E TAINS A LL R I G H TS U N D E R C O P Y R I G H T LAW S A N D TRADE SECRET LAW S O F THE U N I TED STATES OF A M E R I C A A N D O THER COUNTRIES. THE RECIPIENT FURTHER A G R E E S TH A T THE D O C U M E N T M A Y N O T B E D I S TRIBUTED, TRANSMITTED, C O P I E D O R R E P R O D U C E D I N W H O LE O R I N P A R T B Y A N Y M E A N S, E LECTRONIC, MECHANICAL, O R O THERWISE, W I THOUT THE EXPRESS PRIOR WRITTEN C O N S E N T O F B A K E R H U G H E S, A N D M A Y N O T B E U S E D D I R E C TLY O R I N D I R E C TLY IN A N Y W A Y D E TRIMENTAL TO BAKER HUGHES INTEREST.
NMR: Basic Principles Measures relaxation of hydrogen nuclei in fluids Electromagnetic: No nuclear sources Measures fluid-filled porosity Lithology independent Measures fluid type Oil, water, gas: Volumes and properties Measures pore size Texture information Compartmentalises porosity Productivity Incremental Porosity (pu) 4.00 3.00 2.00 1.00 0.00 3ms T 2 Cutoff CBW BVI BVM 0.1 1 10 100 1000 T 2 Decay (ms) 4.00 3.00 2.00 1.00 0.00 10000 Matrix Dry Clay Clay- Bound Water Capillary Bound Water Mobile Water Hydrocarbon 2
Magnetic Resonance 3
Hydrogen Atom Properties 1 Proton 1 Electron Magnetic Dipole Spin (1/2) P N e S 4
How Does NMR Work? Magnetic field produces A time-dependent interaction is needed for proton transitions occurring between Zeeman energy levels: Resonance condition E B 0 E m= -1/2 m=+1/2 B B 0 0 quantum physics eqn. classical physics eqn. 5
Hydrogen in Fluids No external magnetic field B=0 Randomly distributed spins of hydrogen nuclei Water molecules H 2 O 6
Add External Magnetic Field B 0 Magnetic Field B 0 N Larmor Precession H freq. = 4258 z Gauss Know the magnet strength -> Know the frequency B o S 7
Nuclear Magnetization When placed in a magnetic field, B 0, the 1 H protons align parallel and anti-parallel with the field B 0 The ratio of parallel to anti-parallel is: 100,006 : 100,000... It is the extra 6 parallel protons that produce the NMR signal that we measure This is (absolute K) temperature dependent = A calibration parameter (0 K = -273 C) 8
N Tipping Pulse When a pulsed radio frequency field, B 1, is applied, the 1 H protons will realign with the B 1. When B 1 is switched off the 1 H protons begin to precess as they realign with B 0. S B 1 RF Antenna Protons align with B 1 when RF field is switched on, or pulsed 9
Nuclear Magnetization RF Antenna When the RF field is switched off the protons precess back to realign with B 0 As they precess r they emit a small RF signal that is received in the RF antenna. This signal decays as they re-align with B 0 Larmor Frequency = 4258 x H z B 0 Gauss 10
Pulse Sequence 11
Pulse Sequence Multiple protons A short time later 9 0 R F P u l s e Fast Slow 180 R F P u l s e F S F S F S 12 ECHO
Reversing Race! Start/Finish! 13 90
Reversing Race! Start/Finish! 14 90 180
Amplitude Amplitude Echo Train CPMG Pulse Sequence RF Pulses Echo Signals 90 x 180 y 180 y 180 y 180 y 180 y TE Time T1 T2 Echo Train TW Time TE : TW : intercho spacing wait time ( 3 x T 1 for full recovery) 15
Porosity 16
Echo Echo Echo Amplitude NMR Porosity NMR Porosity = Initial Signal Amplitude Calibrated to Water filled (Hydrogen Index = 1) T 2 Decay Curve Time 17
NMR Total Porosity = Mineral Independent 100% 0% Clay Minerals Non-Clay Minerals Total Porosity T2 too fast to measure in solids NMR does NOT see the extra "H" in clay minerals True porosity in shales 18
Sourceless Porosity 19
T2 Distribution 20
T2 Decay Components Bulk T 2b Depends on fluid type High viscosity = fast, a few ms. Low viscosity = slow, 1000ms + Surface interaction with rock - Surface/Volume ratio Depends on pore sizes, and surface type T2 =.5 1000ms Large pores = slower Diffusion T 2D Depends on viscosity, Magnetic field gradient "G" and TE Gas = fast, fluid = slow 21
MR Relaxation - T2 Decay Effects Echo Amplitude = Porosity 25 20 15 10 5 Wetting Phase Relaxivity 1 T 2a 3 components r S + V Non-wetting Phase Relaxivity 1 T 2b + 1 T 2D Fastest dominates Time (ms) 22
Porosity % Surface/Volume Ratio Pore Size In a single fluid filled pore the T 2 decay rate is inversely proportional to the surface/volume ratio of the rock being measured and directly proportion to the size of the pore. 25 20 1 S 1 r V T 2 r pore 15 10 5 0 0 100 200 300 400 500 600 Time (ms) 23
Incremental (pu) Multi-Exponential Decay A series of exponential decays are fitted to the data, resulting in the T2 distribution = S por. e - t / T 2 256 ms = 30 p.u. y = 5. e -t/16 + 10. e -t/64 + 15. e -t/256 T2 Distribution Typically 20-30 "bins" (decays) increasing by 2 e.g. 1/1.4/2/2.8/4/..ms 64 ms 15 10 16 ms 5 Time 16 64 256 T 2 (ms) 24
Echo Amplitude Incremental Porosity (pu) T2 Pore Volumetric Distribution from NMR, NMR Porosity T 2 cutoff (SS) = 33 msec T 2 cutoff (Carb.) = 92 msec 3ms T 2 Cutoff 20 4.00 4.00 15 T 2 Decay 3.00 3.00 10 Transform 2.00 2.00 5 0 15 30 45 60 75 90 105 120 135 150 Time (ms) 1.00 0.00 CBW BVI BVM 0.1 1 10 100 1000 T 2 Decay (ms) 1.00 0.00 10000 Matrix Dry Clay Clay- Bound Water Capillary Bound Water Mobile Water Hydrocarbon 25
Porosity - MR Analysis 100% 0% Clay Minerals CBW Non-Clay Minerals Total Porosity BVM BVI 26
Incremental Porosity (pu) NMR Log Data GR 4.00 T 2 Spectra T 2 Cutoffs 4.00 Resistivity & Permeability Pore Volumetrics 3.00 3.00 2.00 2.00 CBW BVI BVM 1.00 1.00 0.00 0.00 0.1 1 10 100 1000 10000 T 2 Decay (ms) MBVM MBVI MCBW Permeability 27
Low Resistivity Pay Example (Non-laminated) GR, SP & Caliper Resistivity Neu. & Den. Porosity Fluid Saturations Pore Volume High Capillary- Bound Water Water-Free Production Correctly Predicted Above Actual Transition Zone! High Capillary- Bound Water Transition Zone O/W Contact 28 Ostroff et al, 1999, SPWLA
Thin Bedded Pay Original Perfs Formation Volumetrics Perf s Resistivity & Permeability Sand Lam. Effective Pore Volumetrics Bulk Pore Volumetrics T 2 Spectra 800 BOPD Added Perfs 733 BOPD 29
Permeability 30
MR Permeability - k nmr Two models in use (Permeability is estimated not measured) Coates-Timur Model : k nmr C NMR m BVM BVI n SDR/Kenyon Model: k nmr C a NMR m T 2 Geo. Mean n Where assumed default parameters are: C =10, m = 4 & n = 2 Note: k nmr is an estimate of permeability based on a model. For accuracy k nmr should be calibrated to local reservoir data. 31
Part Ø [frac] Part Ø [frac] Part Ø [frac] Part Ø [frac] Part Ø [frac] Part Ø [frac] Part Ø [frac] Part Ø [frac] Correlation of k and T 2 Distributions Large pores 2.5 2.5 2 1.5 1 0.5 Ø = 25.8 k [md] = 1181 2 1.5 1 0.5 Ø = 24.8 k [md] = 250 0 0 T2 [ms] 2.5 2 1.5 1 0.5 Ø = 25.5 k [md] = 834 2.5 2 1.5 1 Ø = 19.0 k [md] = 1.65 0 0.5 2.5 2 1.5 1 0.5 0 Ø = 24.8 k [md] = 737 0 2.5 2 1.5 Ø = 18.0 k [md] = 0.14 2.5 2 1.5 1 0.5 0 Ø = 25.1 k [md] = 502 1 0.5 0 0.1 1 10 100 1000 10000 T2 [ms] Small pores 2.5 2 1.5 1 0.5 0 0.1 1 10 100 1,000 10,000 Ø = 24.6 k [md] = 360 NB. NMR provides pore size distribution. Permeability responds to pore throat size! T2 (ms) 32
Core-Calibration Gamma Ray T 2 Spectra Calibrated Core-Calibrated Uncalibrated Permeability Un-Calibrated Calibrated Core-Calibrated Uncalibrated Porosity Un-Calibrated 33
T1 Distribution 34
Porosity Polarization and TW NMR porosity is reduced if sufficient time (TW) is not allowed between experiments due to an incomplete polarization of the protons. T1 Porosity Correct T2 Porosity Low TW Correct TW Short Time 35
T1 Distribution Determination Complete T 1 Recovery T 1 Buildup Echo Train Incomplete T 1 Recovery T 2 Decay TW 1 TW 2 TW 3 TW 4 TW 5 TW 6 Longest Wait Time (TW) Shortest Wait Time (TW) 4.00 4.00 3.00 2.00 1.00 T 1 (ms) 3.00 2.00 1.00 0.00 0.1 1 10 100 1000 0.00 10000 36
Diffusion 37
Gradient Magnetic Fields and Diffusion B0+dB0 B0 B0-dB0 G Larmor Measure Frequency f+df f f-df Diffusion during the pulse sequence causes a reduction in signal amplitude with time and decreases T2. A longer TE or higher gradient increases the effect. Multiple TE Measurements Diffusivity distribution Time 38
Porosity Porosity T2 Shift due to Diffusion Short Echo Spacing Low diffusivity Fluid High diffusivity Fluid Long Echo Spacing 1 10 T 2 Time (ms) 100 1,000 10,000 39
Instrument Magnetic Field Gradients Multiple Frequencies = Multiple Sensitive Volumes Gradient field tools: - Measure Diffusion B 0 Tool 8 12 Borehole Borehole Formation Low gradient field tools: - Minimal Diffusion LWD Borehole Skid Magnet Wireline S S N N Antenna Blind Zone B 0 Sensed Region at fixed Bo=f 40 N.B. All measurements are shallow 1-4" depth
LWD NMR in Drilling Environment High Gradient Low Gradient B RF B RF Vibration Intolerant Vibration Tolerant 41
Fluids 42
Capillary Pressure (psi) Hydrocarbon Affects Clay Bound Water Irreducible Water Immoveable Ht.-Dependent Capillary Bound Water Moveable Water Hydrocarbon 250 200 150 100 43 50 0 0 20 40 60 80 100 Irreducible Sw FWL Total Sw (% ) 1 10 100 1000 T 2 (ms) N.B. Techniques available to re-calculate 100% water saturated T2 from mixed fluids Pore size Distribution
1D NMR Simple Analysis of T2 44
NMR Fluids Response CBW Irred. water Movable Water In porous media with Low Gradient Tar Heavy Oil Medium Oil Light Oil High GOR 0 WBM OBM OBMF Gas 3 sec CBW Irred. water In porous media with High Gradient T 2log Tar Heavy Oil Mov. Water Medium Oil Light Oil Gas High GOR 1 1 1 + T2 app T2int T2 diff ( G TE, D) WBM OBM OBMF 45 N.B. T2 apparent can be corrected back to Intrinsic.
T 2 i (ms) 1000 Estimated Oil Viscosity from MR Pore Volumetrics 4.4 cp T2 Spectra 0.1 10 1 100 10000 Samples from Bleridge field Oil viscosity standard 1200 T 2,log 0. 9 5.5 cp Adapted from Morriss, et al, 1997 0.1 1 10 100 1000 10000 100000 Viscosity (cp) Oil Viscosity 4.4 cp 46
NMR Porosity T1 for Various fluids Water T1 depends on pore sizes (wetting phase) Typically need 1-2sec Oil depends on API Typically 5-6sec Gas depends on pressure, temperature Typically 10-15sec T 1 Buildup 1.5 T W (sec) 8 Water Gas Oil 47
Porosity Porosity NMR Porosity Porosity Delta Tw - Differential Spectrum Long Recovery Time (Tw LONG ) Tw Short Tw Long Short Recovery Time (Tw SHORT ) T 1 Buildup Differential Spectrum 1.5 T W (sec) 8 1 10 100 1,000 10,000 T 2 Time (ms) Water Gas Oil 48
Dual TW Porosity & Saturation (LWD) 49 N.B. Shallow measurement
Fluids - T1/T2 Ratio and Diffusivity Non-wetting oil phase: OBM filtrate: Dry Methane: Richer gas: Wet gas, dissolved, condensates: T1/T2~1-1.5 T1/T2~1-2 T1/T2~100 < T1/T2 of methane < T1/T2 of dry gas Bound Water Moveable Water Heavy Oil Light Oil Gas T1 Very Short Medium Short Long Long T2 Very Short Medium Short Long Short D Slow Medium Slow Medium Fast 50
2D NMR Maps - Oil or Water? 51
2D NMR Maps Liquid or Gas? 52
2D NMR Results Oil & Gas Reservoir GAS Oil T 2 Gas T 2 OIL 53
Porosity - MR Analysis 100% 0% Clay Minerals CBW Non-Clay Minerals Hydrocarbon Total Porosity BVMW BVI 54
Magnetic Resonance Imaging Clinical MRI images are determined from - Quantity of 1 H present in the specimen Relaxation times present in the tissue 55
Other Applications 56
Height above OWC (ft) Porosity (pu) Pore size & Capillary pressure MREX T2 converted to pore size 5 4 3 2 1 0 0.01 0.1 1 10 100 Pore Throat Diameter (microns) 1mD 10mD 100mD Synthetic Pc curves from MREX T2 distributions 400 350 300 250 200 150 100 50 0 0 0.5 1 Sw (fr) 1mD 10mD 100mD N.B. NMR responds to pore size Pc responds to pore throat size! 57
Micro Scale Rock Model Fontainebleau sst Random, dense packing of equal spheres Creating a numerical model and cross-section Delaunay cell 58
Productivity Example: Oil Well 59
Coarsening up Coarsening up Grain Size Geology and Completions Sand Shale Clay NMR GR T 2app, ms Volumetric GS, microns GS flags 0 150 0.25 4096 0.45 0 0.25 8192 60
Summary Petrophysics Mineralogically-Independent Porosities Pore Size Distribution (Single Phase Fluid Saturation) In mixed fluids Clay-Bound Water Volume, Capillary-Bound Water & Free Fluid Volumes Permeability In carbonates Fluid types, volumes, distributions, properties Capillary Pressures, Sw irr Geology Grain size distribution Rock Fabric/Facies Characterization Mineralogy changes Cross-Correlation Reservoir Engineering Capillary Pressures Fluid changes Relative permeabilities Effective permeabilities Fractional flow Cumulative production prediction Drilling and Completions Grain size Sand production Screen sizes Completion intervals Completion type Perforation modeling 61