Basic NMR Course

1. NMR PETROPHYSICS

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

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

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 :

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

27. Inversion & Porosity and Pore Size Distribution T 2 x T 2 y T 2 z Exponential decay characterises Pore size Total amplitude characterises pore volume

28. Inversion T 2 x T 2 y T 2 z T 2 x T 2 y T 2 z T2x, y and z are T2 bins, or if scaled to pore size, pore size bins. Height of column is pore volume

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

30. Inversion quality Control Underlying CPMG trend Fit 1 (good) Fit 2 (poor) T2 (ms) Echo Amplitude RMS Error of Fit Well fitted data with evenly distributed error of fit Poorly fitted data with systematic variation in error of fit

34. Hydrocarbon effect on T2 distribution Hydrocarbon effect on T2 distribution 100% Brine Saturated Water wet with oil Producible water (free fluid) Bound fluid (irreducible water) Producible hydrocarbon (free fluid) Bound fluid (irreducible water) T2 increases since hydrocarbon Is not limited by pore-size T2 is limited by pore size in 100% Sw rocks

35. Fluid and T2 Relaxation

36. 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)

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

41. 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)

42. 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

43. 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.

44. 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)

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

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

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

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.

62. Wettability From NMR Logging, Coates et al .

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

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

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

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

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

83. NMR LOGGING

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

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

98. Multi Frequency Acquisition Cycle DTW.

101. LWD MRIL Tool

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

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

119. PRACTICAL NMR LOG EVLAUTAION

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

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

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

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

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

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

149. Time Based Data and Depth Conversion

150. Environmental Corrections

154. Gain And Q Level

157. Noise Indicators

158. Noise Indicators High Q Med Q Low Q

159. Voltage Sensors

161. T2 Analysis Work Flows

164. Porosity

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.

172. Bisecting Method. ‘ saddle point’

173. Permeability

174. Lab Calibration of NMR data

176. 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)

177. 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

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

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

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

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

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

189. Cluster Analysis Distance Coefficient Distance Cutoff

191. 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

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)

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.