Enhanced Formation Evaluation of Shales Using NMR Secular Relaxation* Hugh Daigle 1, Andrew Johnson 1, Jameson P. Gips 1, and Mukul Sharma 1 Search and Discovery Article #41411 (2014)** Posted August 11, 2014 *Adapted from oral presentation given at AAPG Rocky Mountain Section Meeting, Denver, CO, July 20-22, 2014 **AAPG 2014 Serial rights given by author. For all other rights contact author directly. 1 Department of Petroleum and Geosystems Engineering, University of Texas at Austin, Austin, TX (daigle@austin.utexas.edu) Abstract Determining the porosity associated with organic and inorganic components of shales is an important but difficult part of formation evaluation in unconventional resources. Nuclear magnetic resonance (NMR) measurements offer a means of quantifying organic and inorganic porosity by separating the inorganic porosity, where proton relaxation occurs by paramagnetic interactions, from the organic porosity, where proton relaxation occurs by intermolecular dipole interactions. We performed laboratory measurements on preserved Bakken and Eagle Ford samples with a 2.2 MHz nuclear magnetic resonance (NMR) core analysis system. Additional measurements were performed on a Barnett sample in the as-received state. We constructed two-dimensional maps of T1 and T2 with different echo spacings for the T2 measurement and computed distributions of T1/T2 ratio and the secular relaxation rate, which is the difference between the transverse and longitudinal relaxation rates. Based on the distribution of T1/T2 ratios and the change in secular relaxation rate with echo spacing, we were able to differentiate organic porosity, inorganic porosity, and the relaxation signal from the organic material itself. The differentiation is based on theoretical consideration of relaxation times due to paramagnetic and dipole interactions. The T2 values we found for the organic material and associated porosity are generally shorter than 1 ms while the T1 values are generally 1 10 ms, indicating that T1 measurements may be a feasible means of quantifying organic material downhole. Reference Cited Passey, Q.R., K.M. Bohacs, W.L. Esch, R. Klimentidis, and S. Sinha, 2010, From Oil-Prone Source Rock to Gas-Producing Shale Reservoir - Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs: SPE 131350, 29 p.
Enhanced formation evaluation of shales using NMR secular relaxation Hugh Daigle Andrew Johnson Jameson P. Gips Mukul Sharma Department of Petroleum and Geosystems Engineering, University of Texas at Austin RMS-AAPG Annual Meeting July 22, 2014
Key points Shales are challenging for 1 H NMR because hydrocarbons are present as liquids and (semi)solids Relaxation times at pore walls vary in predictable ways depending on the type of pore wall material (inorganic or organic) We can combine standard relaxation time measurements and separate the pore space into inorganic & organic porosity
NMR relaxation mechanisms 1. Intermolecular dipolar coupling 2. Intramolecular dipolar coupling 3. Interactions with Bulk relaxation paramagnetic ions on pore wall (Surface relaxation) 4. Diffusion in internal field gradients (Diffusion relaxation) (T 2 only) In general, T 1 T 2
NMR in conventional rocks 2.54 cm Bulk & diffusion relaxation can be ignored T1,2 r
Pores and fluids in the Barnett Passey et al., SPE 131350, 2010 Water films Free gas Sorbed gas (dots) +viscous hydrocarbons associated with kerogen
Key differences in shales (for NMR) Pores are very small Porosity in organic and inorganic matter Viscous hydrocarbons present These differences can be used to our advantage.
Different relaxation mechanisms 1 μm Inorganic pore Paramagnetic ions Fe 3+ Fe 3+ Fe 3+ Diffusion in internal H H H H gradients Fe 3+ Fe3+ Fe 3+ 10 nm Organic pore H H H H H H H H H H Proton-proton relaxation Diffusion restriction due to pore size *CH 4 diameter is about 0.4 nm
T 1 /T 2 ratios by pore type Inorganic: surface dominated Organic: bulk fluid dominated (or diffusion restriction in nanopores)
Another dimension to add: secular relaxation..-... C/) E '--"" <.) Q) N '" I- 1 1 1 T T T 2sec 2 1 T 2sec 10 9 10 17 10 7 e 10 5 '\ "(\' 10 3 10 1 T1 T1 1 T2 10 15 10 13 10 11,.-... 10 9 (/) E 10 7 '-' " 10 ill 5 <J) N I- 10 3 10-1 10-1 10-3 10-3 L-------1_----L_---L-_-L-_L------1_---.l 10-5 10-3 10-2 0_1 1 10 100 10 3 10 4 0.001 0.01 0.1 1 10 100 1000104 10 5 Viscosity (Pa.s) Pore radius (microns) (or diffusion restriction in nanopores) 10 1
Behavior in 2 dimensions T 1 /T 2 T 2sec Inorganic pores < 10 1 1000 ms Organic pores Moderate? Moderate? Fluids associated with organic matter Large Small Big pores Big pores T 1 Clay T 2sec Clay T 2 T 1 /T 2
Conventional rocks Big pores Wilcox Delta front Marine Clay Small pores
Preserved shales Bakken TOC = 0% Eagle Ford TOC = 6% 10000 1000 0.003 S) / \:) / /,,<:::> / " / / 1000 / / / 100 0.0025,, :Y " rn /. "\ E " f- '" 100 $3 0.002 rn 10 E 10 u 0 $ 0.0015 '!'. / / / 'l- N 0.001 0.1 / / 0. 1 / 0.0005 / 0 0.01 0.01 0.01 0.1 10 100 1000 10000 1 10 100 1000 T2 (ms) T,1T2 1000 \:),,\:)\:) / / / x 10 ' 1000 4 / -= / '" 100,, 100 10 rn 10 rn "'0 E.s 0 u 2 0 / rn N ;::;: f- '< 0.1 / / / /" /", / 0.1 o 0 / 'l- / 0.01 0.01 0.01 0.1 1 10 100 1000 1 10 100 1000 T2 (ms) T,1T2 ----- 3
Unpreserved shale example (Barnett) Free fluids presumably not present Only have bound fluids and viscous hydrocarbons
Preliminary interpretation 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 Bakken Eagle Ford Wilcox Barnett 0.35 0.3 0.25 0.2 0.15 0.1 0.05 0 Wilcox Bakken Barnett Eagle Ford 0.012 0.01 0.008 0.006 0.004 0.002 0 Wilcox Barnett Eagle Ford Bakken T 2sec Fraction of pore volume T 1 /T 2 < 10 T 1 /T 2 = 10-100 T 2sec < 10 ms T 2sec < 10 ms T 1 /T 2 > 100 Clay-bound fluid Source richness? High viscosity T 1 /T 2
Summary Organic and inorganic surfaces relax 1 H spins in different, predictable ways This allows separation of pore space by comparing T 1 /T 2 ratio and T 2sec Hydrocarbons in shales create significant features in T 1 -T 2 -T 2sec diagrams Further work necessary (ongoing) to correlate what we see with fluids and pores