NMR on the Ogbon-1 Well

A Log the Well Does Not Have

Ogbon-1 is the book's synthetic well: it has a density, a neutron, a gamma ray and a resistivity, and a permeability that is Timur's equation at 18 % irreducible water (Section 9.6). It has no NMR log. Figure 10.6 builds one, and it is plain about how. From the well come the porosity, the 18 % irreducible water, the net-reservoir flag and the permeability. The model then writes the spectrum: every foot of net reservoir gets two peaks of T2, a bound peak at 4 ms holding the irreducible water and a free peak at 300 ms holding the rest, each 0.3 decades wide, and a shale gets the bound peak alone. The amplitudes add up to the well's porosity, so the NMR porosity equals the well's by construction. That agreement is the model's and is not a test of any tool.

Bound, Free, and the Cutoff

Section 10.3 split a distribution at a T2 cutoff: the fluid that relaxes faster than the cutoff is bound (BVI) and the rest is free (FFI). At 5890 ft, in the upper oil sand, the NMR porosity is 23.2 %: 4.2 % bound and 19.0 % free at the sandstone cutoff of 33 ms, which falls in the gap between the two peaks. In the shale at 5830 ft the NMR porosity is 9.2 % and all of it is bound, so the free fluid is nothing and no permeability is read. The density-neutron porosity reads 21.2 % there, 12.0 porosity units above the NMR's: the neutron counts the water bound in the clay (Section 4.6), and the NMR here is the well's true porosity. Over the shale beds the density-neutron porosity averages 12.5 porosity units over the NMR's; in the net reservoir, 1.4.

The figure's net reservoir is the book's: a shale volume of 40 % or less, from the gamma ray, and an NMR porosity of 8 % or more. That leaves 386 ft of the 600 ft logged, the same 386 ft as in Section 9.6.

Two Permeabilities, Uncalibrated

The Timur-Coates permeability of Section 9.5 uses the split:

with $\phi$ in per cent and $C = 10$. The SDR permeability uses the log-mean T2 instead:

with $a = 4.5$, the PetroWiki sandstone value, the porosity as a fraction and $T_{2,\text{gm}}$ in milliseconds. Both constants are the kernel's defaults and neither has been calibrated to a core. At 5890 ft Timur-Coates gives 595 mD and SDR, from the log-mean T2 of 138 ms, gives 247 mD, against the well's Timur permeability of 425 mD: 1.4 times it and 0.58 times it. Both estimates follow the porosity to the power 4, and the well's Timur follows it to the power 4.4, so the ratios are not constant. The model puts the same spectrum in every bed, and so across the 386 ft of net reservoir Timur-Coates reads 1.3 to 2.1 times the well's permeability, from the main sand to the tight limestone, and SDR 0.55 to 0.89 times. The figure does not say which of the three permeabilities is right; the well's is itself a formula and not a core.

What Moves and What Does Not

The cutoff moves the split and not the spectrum. At 92 ms, the textbook carbonate cutoff of Section 10.3, it cuts the low edge of the free peak at 5890 ft: BVI rises from 4.2 % to 5.0 %, and Timur-Coates falls from 595 mD to 381 mD, 1.6 times lower. SDR stays at 247 mD, since it never uses the cutoff. A density matrix 0.03 g/cc too high moves the density-neutron porosity at that depth from 23.8 % to 24.4 % and leaves the NMR porosity, BVI, FFI and both permeabilities where they were, because the amplitudes add up to the porosity with no matrix in the sum. The density-neutron porosity moves by half of the density porosity's change, since it is the mean of the density and neutron porosities.

The oil-water contact is where the figure is most easily misread. At 6230 ft the log's water is 100 % and Timur's equation on it gave 22 mD in Section 9.6, against the well's 670 mD. The NMR permeabilities do not drop: Timur-Coates gives 899 mD and SDR 373 mD, as at 6150 ft (882 mD and 365 mD). That is the model's assumption and not a finding. The bound fluid is built as the same share of the pores whatever fills the larger ones, so water or oil makes no difference to it. A real tool would measure the bound fluid, and the SLB glossary notes that an oil of more than about 60 cP in a sandstone can be counted in the bound signal; the figure has no such case.

Onward

The NMR gives a porosity without a matrix, a bound-fluid volume without resistivity and a permeability from pore size, and all three cross-check the density, neutron and resistivity logs. Sections 10.4 and 10.5 add the fluid type, from T1 and T2 and from diffusion. Chapter 11 turns to capillary pressure, which says how much water a rock of a given pore size holds at each height (Section 11.1).

References

• Schlumberger Oilfield Glossary. Nuclear magnetic resonance, bound fluid and free fluid. https://glossary.slb.com
• PetroWiki (SPE). Nuclear magnetic resonance logging, and Permeability estimation with NMR logging. https://petrowiki.spe.org
• Chen, S., Ostroff, G. and Georgi, D. T. (1998). Improving estimation of NMR log T2cutoff value with core NMR and capillary pressure measurements. Society of Core Analysts, paper SCA-9822.