Application of NMR for Evaluation of Tight Oil Reservoirs Rick Lewis & Erik Rylander Iain Pirie Stacy Reeder, Paul Craddock, Ravi Kausik, Bob Kleinberg & Drew Pomerantz
Lots of oil in place – what is pay? • •
Organic Shale Pore System Diameter (nm) 0.38 Methane Molecule 0.38 to 10 Oil Molecule 4 to 70 Pore Throat 15 to 200 Virus 5 to 750 Organic Pore 10 to 2000 Inter/Intra Particle Pores 200 to 2000 Bacteria 35000-65000 Shale Size Particle (mean)
Evolution of organic fractions of shale with increasing thermal maturity.
NMR T 2 Time Distribution (Conventional vs. Organic Shale) 1 1 T 2 T 2 bulk 1 1 1 T 2 T 2 T 2 bulk surface 1 1 1 . 001 . 1 ~ T 2 T 2 T 2 surface • •
Comparison of Core NMR to Log NMR: investigate expelled fluids • 0.5 0.5 0.5 0.5 Shifted Oil - Core CMR Porosity: 9.9 p.u. Oil - Core T 2 - Core T 2 - Core Oil - CMR Core NMR Porosity: 9.1 p.u. Oil - CMR 0.4 T 2 - CMR T 2 - CMR 0.4 0.4 0.4 Water Porosity (p.u.) Porosity (p.u.) Porosity (p.u.) Porosity (p.u.) 0.3 0.3 0.3 0.3 • m 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 • 0 0 0 0 0.01 0.1 1 10 100 1000 0.01 0.1 1 10 100 1000 0.01 0.1 1 10 100 1000 0.01 0.1 1 10 100 1000 T 2 (ms) T 2 (ms) T 2 (ms) T 2 (ms) • •
T 2 -cutoff = 9.4 ms T 2 Cutoff ~ 9.4 ms xx99 ft 10.1 pu xx10 ft 10 pu xx23 ft 13 pu xx33 ft 8.8 pu T2 distribution (pu) xx40 ft 5.8 pu xx58 ft 10.5 pu xx65 ft 7.5 pu xx81 ft 8.1 pu xx93 ft 9.9 pu xx02 ft 7.1 pu -2 -1 0 1 2 3 10 10 10 10 10 10 T 2 (ms)
Bulk Relaxivity • •
Shale Constituents by Volume Tight Oil Reservoir Clay bound water Pore Water Bitumen Light oil Kerogen Mineral matrix Eff Phi Total Phi
Pore Distribution Clay-Bound Water Cap-Bound Water Cap-Bound Water Producible Fluids Bitumen Cap-Bound Oil Free Oil Oil and Water (OM Pores) (Larger OM Pore (Water wet pores) > 250 nm)
Eagle Ford Oil Producer 20000 15000 BOPM 10000 5000 0 Mar-00 Jun-00 Oct-00 Jan-01 Apr-01
20000 Eagle Ford Oil Producer 15000 BOPM 10000 5000 0 Mar-00 May-00 Jun-00 Aug-00 Oct-00
Tmax Data
T 2 relaxation of native and re-saturated shale
T 2 relaxation of native and re-saturated shale
T 2 relaxation of native and re-saturated shale Native state Resaturated porosity oil porosity 12.11 3.91 12.70 4.79 12.14 4.19 8.09 3.43 4.25 2.15 11.66 3.77 10.74 3.66 10.19 3.06 8.20 2.94
Rock Eval Pyrolysis Measurements of • S1: oil in the sample • S2: potential oil and gas • S3: CO 2 • S4: residual hydrocarbon • Tmax: maturity indicator • TOC
The Importance of Oil Saturation Index (OSI) Jarvie, 2012 : As much as 70-80 mg Oil / g TOC is sorbed to Kerogen An OSI > 100 mg Oil / g TOC may produce oil
Oil Saturation Index (OSI) Free Bound Matrix Oil Kerogen Bitumen Water Water S 1 TOC Oil S1 OSI = = TOC Oil Kerogen Bitumen Jarvie, 2012 : As much as 70-80 mg Oil / g TOC is sorbed to Kerogen An OSI > 100 mg Oil / g TOC may produce oil
Shale-Oil Systems Hybrid Shale Juxtaposed organic-rich and organic-lean intevals Bakken is end member OSI provides method to ID contribution of organic-lean intervals in finely juxtaposed system
TOC standard workflows Estimating TOC from logs: - Schmoker (density) Δ log R (Sonic-Resistivity) - - Uranium - NMR-PHIA deficit Based on indirect measurements Require calibration to core data Specific to a particular formation All are kerogen-only TOC
TOC from Carbon workflow Direct measurement from Inelastic Carbon Elements from Spectroscopy Spectra TIC = 0.120*Calcite+ Si, Ca, Mg, S, Fe, K, Minerals Na, Mn,P, etc. 0.130*Dolomite+ 0.104*Siderite+ 0.116*Ankerite
Carbon Saturation Index W c oil CSI W c organics 12 oil W c oil NMR bitumen BVW 14 bulk CSI Carbon Saturation Index (unitless, 0 to 1) W Oil Weight fraction of carbon in light hydrocarbo n (w/w) c oil W Total organic carbon content, directly from geochemica l log (w/w) c organics Total NMR porosity (v/v) NMR Volume bitumen (v/v) bitumen Bulk volum e water, from petrophysi cal model or dielectric (v/v) BVW 3 Oil density (g/cm ) oil 3 Bulk density (g/cm ) bulk
Reservoir Producibility Index — Account for Porosity Differences RPI CSI W c oil where W c oil CSI W c organics CSI Carbon Saturation Index (unitless, 0 to 1) W Oil Weight fraction of carbon in light hydrocarbo n, may require correction for bitumen (w/w) c oil W Total organic carbon (TOCj) content, directly from Litho Scanner (w/w) c organics Log generated index Circumvents problems associated with recovery and analysis of hydrocarbons from cuttings and/or core OSI of 100 ~ RPI of 0.1 (fc of porosity)
RPI – Good Well 20000 15000 BOPM 10000 5000 0 Mar-00 Jun-00 Oct-00 Jan-01 Apr-01
RPI - Poor Well 20000 15000 BOPM 10000 5000 0 Mar-00 May-00 Jun-00 Aug-00 Oct-00
BBL or MCF -100 100 200 300 400 500 0 1 28 55 82 109 136 163 190 217 244 271 298 325 352 379 406 • • RPI, Woodford (VRo ~ 0.7)
RPI, Bakken (VRo ~ 1.0) • •
T 2 Distribution of Native Shale Sample Plotted Together with Formation Oil and Brine Re-saturated Shale
Pore Fluids from T 1 /T 2 • Differentiate between hydrocarbon and water- filled pores • Two pore system model • Organic with hydrocarbon • Inorganic with water • T 1 / T 2 ratio higher for oil- saturated pores • Core work performed by OU on Barnett Shale
T 1 / T 2 maps of Eagle Ford Shale at various depths
Universal T 1 - T 2 picture for shale at 2MHz
WT(1) WT(2) WT(3) WT(4) CPMG(1) CPMG(2) CPMG(3) CPMG(4) WT(4) WT(3) M z = M 0 [1 - exp(-t/ T 1 ) ] WT(2) WT(1) t
Potential for T 1 - T 2 in Tight Oil • Differentiate and potentially quantify bitumen • Differentiate and quantify OM and IP pores • Limit from 2 to ~30ms Initial Observations • Can not differentiate between hydrocarbon and water in IP pores • All bitumen may not be quantified due to short relaxation time
Conclusions • Non-producible hydrocarbons are common constituent in liquid producing shales • One type of non-producible hydrocarbon is viscous source rock bitumen • Another type of non-producible hydrocarbon are oils sorbed to organic pore walls • RPI methodology can be used to characterize producible zones, and it takes porosity and pore water into account It recognizes hybrid reservoirs • T 1 / T 2 shows potential to differentiate bitumen and OM vs. IP pore fluids Application of these metrics to landing point selection has had dramatic positive impact to productivity in shale wells!
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