1. 1 Laboratory MR Measurements and MRIL ® Integration by Dave Marschall

2. 2 Crucial Formation Evaluation Questions What is the storage capacity (  e and  t ) in a Complex Lithology Environment ? Are there hydrocarbons, ï ï what types of hydrocarbons and, ï ï how are they distributed? What is the permeability (deliverability)? Will the formation produce water free? (what is irreducible saturation (BVI)) MRIL answers them all

3. Magnetic Dipole Proton H Hydrogen N S NMR works with Protons - Hydrogen -> H 2 O and C x H y +++

4. N S N S N S N S N S N S N S N S N S N S N S N S N S N S t = 0 Random Orientation in Natural State Bo

5. N S N S N S N S N S N S N S N S N S N S N S N S N S N S t = 0.75 sec M Bo=External Field M=Bulk Net Magnetization Wait time (sec) Magnetization Buildup Bo

6. N S N S N S N S N S N S N S N S N S N S N S N S N S N S t = 6.0 sec M Bo=External Field M=Bulk Net Magnetization Wait time (sec) Buildup at 95 % polarization Bo

7. 7 hydrocarbon hydrocarbon Oilfield MRI (Relaxation Time Spectrum) Fluids Solids….invisible to MRI time, sec. 0 1 2 3 4 5 6 8 9 10 11 12 13 14 ……. irreducible movable water movable water movable water irreducible clay bound T 1 Magnetization no measurement T 2 relaxation times the measurement rock matrix dry clay

8. 8 Polarization Time T2T2 Decay Time T1T1 Magnetization T 1 characterizes the rate at which longitudinal magnetization builds up T 2 characterizes the rate at which transverse magnetization decays B0B0 MLML MTMT T 1 build-up and T 2 decay

9. 9 NMR Experiment Timing MoMo 0 M  to B o (longitudinal component) M  to B o (transverse component) MoMo 0 RF field 0 B1B1 00.51.01.52.02.53.03.54.04.55.0 time, seconds TWTW TETE TXTX adapted from Murphy, D.P., World Oil, April 1995 T 1 = 400 msec T 2 = 250 msec

10. 10 MRIL-Prime is Fast  NUMAR Corp., 1995 Series C senses two fluid volumes PRIME senses nine fluid volumes 4X Fluid Volume = 4X Speed

11. 11 time (ms) Amplitude (pu) Decay rate (1 / T 2 ) => rock & fluid information Measured signal decay TETE Amplitude = Porosity

12. 12 3 Relaxation Mechanisms Bulk Relaxation - T 2B Intrinsic Property of fluid Diffusion - T 2D Molecular Movement Surface Relaxation - T 2S Pore-walls cause rapid dephasing Effect of Each Mechanism is Additive Time, msec. Amplitude Echo Amplitude vs Time

13. 13 T2T2T2T2 T2T2T2T2 T2T2T2T2 T2T2T2T2 T2T2T2T2 time time time time time Pore Size and T 2 (Water) T 2 = relaxation time constant. S = surface area of the pore. V = volume of the pore.  2 = relaxation rate constant.

14. Data Processing - Inversion T 2i are pre-selected: T 2i = 4, 8, 16, 32, 64, 128, 256, 512, 1024... MAP “Inversion” Processing T 2 [ms] Incremental Porosity [pu] T 2 Spectrum “Best Fit” Water-saturated rock:  2 = V/S  NUMAR Corp., 1995 BVI FFI

15. 15 MRIL Permeability MPERM = ((MPHI/10) 2 (MFFI/MBVI)) 2 MPHI - MRIL Porosity (porosity units) MBVI - MRIL Bulk Volume Irreducible MFFI - MRIL Free Fluid Index MPERM - Permeability (millidarcies)

16. Density Porosity Neutron Porosity Effective Porosity 0 0 0 0 -100 8 0 Variable Density (milliseconds) T2 Distribution 20482

17. 17 Laboratory MRI - Textural Properties % Clay Delta MPHI Kair, md Relaxation Time (T2), msec. 0.1110100100010000

18. 18 NMR - Porosity Model Neutron  Density  rock matrix clay matrix clay bound water capillary bound water BVI movable water hydrocarbons MR porosity (effective) MR porosity (total short T E ) Resistivity  Sw NMR BVI NMR FFI Integration of MR Log and Resistivity Log Interpretation nonmovable water Producible hydrocarbon will produce some water

19. 19 Suitable Sample Types Rock SampleRock Sample –Conventional Core –Rotary Sidewall –Cuttings –Percussion Sidewall Fluid SamplesFluid Samples –Oils –Gas/Condensate –Brines Cuttings and Percussion Sidewall have some limitations to their ability to represent some petrophysical parameters.

20. 20 Example Lab Program Sample Preparation Trim, measure bulk volume MRI on Fresh sample Dean Stark for Swi Clean and dry the sample, measure routine properties, K, Por., and Grain Density Optional Pre-clean and dry Fresh State -OB mud Sample Preparation Trim, clean, and dry Determine Routine Properties, K, Por., Grain Density Lab MRI @ 100 % Sw Resaturate Sample to 100 % Sw Desaturate the sample to a capillary pressure that = non movable saturation Lab MRI @ Swi Develop Interpretation Model

21. 21 Porosity Comparison: Lab MRI (MPHI) vs Core 0 2 4 6 8 10 12 14 16 182002468101214161820 Core Porosity, % MPHI, %

22. 22 Bulk Volume Irreducible (BVI) Free Fluid Index (FFI) 0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00 0.1 110100100010000 T 2 Relaxation time, msec. Incremental Porosity, % Standard Fixed T2 cutoff Relates to a capillary pressure or pore radius Standard Method to Determine BVI A Subsidiary of HALLIBURTON ENERGY SERVICES Relaxation time distribution

23. 23 After air/brine 100 psi Effect of Air/Brine Desaturation on T 2 Distributions Dominated by Surface Relaxation Mechanism 100% Brine saturated

24. 24 Lab Determination of Cutoff T 2 BVI FFI MRI Porosity After Pc to Swi cumulativeincremental 100% Saturated cumulativeincremental

25. 25 Variation in T 2 Cutoff Values T 2 - Cutoff 0 5 10 15 20 25 110100 Sample Number

26. 26 T 2, Cutoff T 2 and Pore Size MRI Relaxation Time (T 2 ) & Surface to Volume Ratio Capillary Pressure (P c ) & Pore Throat Radius (r) Since S/V of a capillary tube = 2/r then; Since T 2 is related to Pore Size & S/V: then T 2 is directly proportional to K, then T 2 is directly proportional to K, and T 2 is inversely proportional to Swi and T 2 is inversely proportional to Swi 1/T 2 =  2 S/V P c =  cos  2/r 1/T 2   2 2/r

27. 27 T 2 Cutoff Related to P c Rock Type A Rock Type B Capillary Pressure, psi 0 50 100 150 200 250 300 350 400 024681012 Bulk Volume Water, % Free Water Level AA BB Shale Equivalent T 2 cutoff @ 50 psi Height Above Free Water, ft. Bore hole

28. 28 Spectral BVI Model BVIFFI 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 0.1 1.0 10 100 1000 10000 Normalized Incremental Porosity Relaxation Time (msec.) 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 Spectral Fraction standard cutoff model SBVI Model: a step function

29. 29 SBVI Model Linked to Permeability Equations Given: K 1/2 = 100  2 (FFI/BVI) K 1/2 = 4  2 T 2GM Substituting:  (1-S WIRR ) for FFI  S WIRR for BVI Coates equation becomes: K 1/2 = 100  2  1-S WIRR  S WIRR = 0.04 T 2GM, or  1-S WIRR  S WIRR  1  S WIRR = 0.04 T 2GM + 1 Equating the two equations gives: The empirical form is:  1  S WIRR = mT 2GM + b

30. 30 SBVI = 1/((0.0243 T 2 ) + 1) y = 0.0243x + 1 R 2 = 0.89 Core S wi vs T 2 0 0.2 0.4 0.6 0.8 1 050100150200 T 2, Geometric Mean, msec. S wi (Core), frac. SBVI - Slope Determination 1 2 3 4 5 6 7 8 020406080100120140 T 2, Geometric Mean, msec. 1/S wi (Core) Bin #T2 timeBVI Fraction 120.919 240.849 380.738 4160.585 5320.414 6640.261 71280.150 82560.081 95120.042 1010240.022 Lab Method to Determine SBVI Correlate Core S wi and T 2 Correlate Core S wi and T 2 Compute fraction for each Compute fraction for each T 2 Bin T 2 Bin

31. 31 0 10 20 30 40 50 60 70 80 90 100 0102030405060708090100 Core S wi S wi from cutoff T2 0 10 20 30 40 50 60 70 80 90 100 0102030405060708090100 Core S wi S wi from SBVI BVI Model Comparison SBVI Model Cutoff T 2

32. 32 SBVI Determination for Cotton Valley

33. 33 NMR Adds Surface Area ·Three Mechanisms Control Transverse Relaxation Time (T 2 ) þBulk Relaxation þDiffusion þSurface Relaxation ·Surface Relaxation þIt is the dominating mechanism in porous media (for the wetting fluid - assumed to be water) þControlled by surface area and pore structure Ability to Determine S wir where:  2 = relaxivity,  /sec. S/V = surface area to pore volume ratio

34. 34 Predicting K with NMR From Kozeny estimates of k z S p are given by T 2 as follows: The surface relaxation mechanism provides the relationship of T 2 to radius and K: However, this model is representative of pores with a single fluid.

35. 35 Predicting K with NMR For the linear function y = mx+b where: C= 9.32 r 2 = 0.91 (FFI/BVI) 0.5 Increasing C with increasing pore structure complexity

36. 36 Predicting K with NMR BVI bulk volume irreducible 0.1 1.0 10 100 1000 10000 Relaxation Time (T 2 ), msec FFI free fluid in dex T 2 and K are directly proportional K and T 2 are inversely proportional to Swir Where C is similar to K Z in the Kozeny equation and is a function of the pore geometry.

37. 37 Predicting K with NMR Pores with two nonmiscible fluids 0.1 1.0 10 100 1000 10000 Relaxation Time (T 2 ), msec 100% brine air/brine crude oil/brine Geometric mean 100% brine Geometric mean oil/brine Relaxation Time Cutoff Determines Swir or BVI ·For Two Fluids þGeometric mean values are influenced by the nonwetting fluid. þModel is not correct ·The wetting fluid is dominated by Surface Relaxation þthe wetting fluid has short T 2 times, thus cutoff T 2 ’s can be used to estimate BVI Non-wetting fluid fluid

38. 38 Lab Evaluation: Permeability Model C = 6.2 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 00.050.10.150.20.250.3   FFI BVI Free Fluid (Coates) Model: C is a variable and can be represented as a line function: The equation becomes:

39. 39 Coates Model for a Tight Gas Sand

40. 40 T2Sb K Model Tight Gas Sand

41. 41 How Do the Models Work?

42. 42 Combining K,  and Swir 0 0.1 0.2 0.3 0.4 0.5 0 0.2 0.4 0.60.8 1 Swir Porosity1000 100 10 1.0 (  x Swir) increases K, md Where: C = 250 Also - Timur Equation: Predicting K

43. 43 Predicting K using Swir Predicted K, md Measured K, md Predicting Swir from  Known Swir

44. 44 Cooper Basin Low Porosity Example GR CALI LLD LLS 06 16 200 2000 0.2 PMRI MPERM PMRIC 1000 0.01 1000 PDSS PNSS SBVI MPHI CBVI CBVWE BVID 000000 030 10 MSFL 0.2 2000 X600X500