MS-GEOLOGIST

1.0 HISTORY

• Nuclear Magnetic Resonance technology originated in the medical field and is still used as a major diagnostic tool today.
• The technology was applied to the oil industry in the early 1990's.

2.0 APPLICATION

• The NMR measurement is able to measure the fluid volume in the formation, the types of fluids and the size of the pores space containing these fluids.
• Volume of clay bound fluids, irreducible fluids and free fluids being water, oil and gas can be determined.
• Formation permeability and hydrocarbon density can be determined.
• Conventional logging tools measure the entire formation and are more sensitive to the larger volume matrix material rather than the formation fluids. NMR technology only sees the formation fluid and therefore provides a formation porosity independent of formation rock type.

3.0 THEORY OF MEASUREMENT

3.1 Operation

Figure 1: Schematic of the Nuclear Magnetic Resonance Tool

The NMR tool uses a large permanent magnet which magnetises the formation for a predetermined period of time. Different transmission frequencies can be used to measure at different depths of investigation as represented by the regular spaced cylinders around the tool. Oil based muds provide a better tool response than water based muds.

Figure 2: Borehole mud invasion profile

Figure 3: Vector representation of Polarisation and burst frequency

Figure 3 shows the vector representation the magnetic polarisation of magnitude Mo. Polarisation is applied for a time TW. The fluid particles (or more specifically the hydrogen atoms or protons) are then exposed to regular bursts of radio-frequency energy (transverse magnetic pulses of frequency fo) transmitted into the formation in the form of an alternating magnetic field. The transverse magnetic pulses are applied at 180deg intervals.

Figure 4: Spin Echo Train

After each successive transverse pulse of period TE, the decrease in magnitude is measured. The decay of the spin echo magnitude over the period of the pulse train is given by: -

Mx(t) = Mox e^(-t/T2)

where Mox is the initial magnitude of the transverse magnetisation and Mx(t) after time t. T2 is the transverse relaxation time constant and is representative of the magnitude of the transverse magnetic decay.

Figure 5: Polarisation and pulse sequence

After a period of decay time equaling several times the T2 value, the measured magnitude is essential zero. Further transverse pulsing will not be possible. Polarisation and pulsing must start again. The photons are therefore polarised again for a period TW (approx. 6-8msec) and pulsed at a period of TE (approx. 1.2msec)

3.2 Depth of Investigation and Vertical Resolution

3.3 Specifications

Figure 6: Schlumberger CMR tool
Magnet length = 2ft, tool is eccenterred. Pulsing rate = 0.2msec.

Figure 7: Halliburton MRIL tool
Magnet length = 7ft, tool is centralised. Pulsing rate = 0.6 and 1.2 msec but up to 9 readings simultaneously.

4.0 CALIBRATION

The NMR tool requires a monthly calibration using a calibration tank. Before and after survey calibration checks are also required.

5.0 LIMITATIONS AND PRESENTATION

5.1 Limitations
Nuclear Magnetic Resonance tools where initially used to measure bound fluid volumes. The T2 decay times for clay bound fluids is in the vicinity of 3msec and 10msec for capillary bound fluids. This requires a very small polarisation time. Logging speeds therefore are not restricted. Free fluids however have a far greater T2 decay time and require a far greater polarisation time. This restricts the logging speed considerably to less than 10ft/min. Stationary readings are often required over very porous, large porosity zones.

The Halliburton MRIL tool has a larger permanent magnet than Schlumberger's CMR allowing it polarise formation fluids faster. The larger magnet however is approximately 7 feet in length compared to the CMR at approximately 2feet. The CMR therefore has a superior vertical resolution. The MRIL is a centred tool and the depth of investigation is reduced as the hole size increases. The CMR is an eccenterred tool and is not as badly affected by hole size.

5.2 Presentation

Figure 8: Typical NMR presentation

Track 1: Various T2 bin cut-offs representing pore sizes. Bin 1(black) is the smallest pore size up to Bin 6(green) the largest pore size.
Track 2: Depth
Track 3: Various fluid volumes. TFV - total fluid volume, BFV - bound fluid volume.
Track 4: Permeability calculations and T2 averages. KCMR - perm from CMR, PKEN - perm from PETROLOG, T2LM - Logarithmic of T2, T2AV - Average T2
Track 5: T2 wave train trace amplitude representation.
Track 5: Colour image representation of T2 wave train

6.0 TOOL COMBINATIONS

7.0 LQC, CORRECTIONS AND INTERPRETATION

7.1 Log Quality Control
Logging speed is critical to the correct operation of the NMR tool. Depending upon the tool gain and the TW wait times being used, the logging speed and vertical resolution are determined. Curves can be displayed in real-time on the logging run, showing signal to noise ratios and ringing. The MRIL tool has a log called the CHI that is a measure of the quality of the calculated T2 decay curves determined from the echo decay amplitudes.

Short polarisation times (TW) will underestimate porosity. If the TW is increased and porosity increases then the tool should operate at this new TW. The correct TW is critical since hydrocarbon bearings zones are usually where porosity is underestimated.

Other checks are: -
NMR Effective porosity < NMR Total porosity
Clean water filled formation MPHI = Cross plot porosity

7.2 Corrections
No environmental corrections are applied to the NMR tool.

7.3 Interpretation

Figure 9: High and low permeability echo times
Each pore size has different decay times and a specific T2 time constant. High permeability large pores have slow echo times and high T2 values. Low permeability small pores have fast echo times and low T2 values.

Figure 10: The T2 relaxation time
Figure 10 show the conversion from multiple pore sizes in the echo decay time plot to the T2 distribution plot.

Figure 11: Echo times depends upon permeability

Although porosities are the same, pore size is different and therefore echo decay times are different and permeability significantly different The T2 value is proportional to the surface to volume ratio of the pore space which is a measure of the size of the pore space. Low T2 values occur in low permeability formations and high T2 values occur in high permeability formations.

7.3.1 Permeability from NMR

Figure 12: Bound Fluids and Free Fluids on the T2 spectrum

Kenyon permeability:
k = aPHI^4(T2,log)^2
where a = 4mD/(ms)^2 for sandstone
a = 4mD/(ms)^2 for carbonates
PHI = porosity
T2,log = the logarithmic mean T2 in msec

Timur/Coates permeability:
k = a'PHI^4(FFI/BFV)^2
where a' = 1000mD for sandstone
PHI = porosity
FFI = Moveable fluid volume
BFV = Bound fluid volume

7.3.2 Water saturation from NMR

Figure 13: T2 representation of various fluid types

By selecting different T2 cut-offs, the various bins can be applied to clay bound water (MCBW), capillary bound water (MBVI), free movable water, light oil, heavy oil and gas (MBVM).

Bound Water Saturation:
Swb = (MCBW+MBVI)
(MCBW+MBVI+MBVM)

Hydrocarbon Saturation:
Shc = (Vol. oil and gas)
(MCBW+MBVI+MBVM)

The bottom part of Figure 13 shows how a long wait time TW will increase the volume of oil and gas determined from the NMR. Also a long TE will move the free water volume to the left.

The correct TW and TE values are clearly critical to distinguishing the different fluids in the formation. Zones of interest should have multiple passes to confidently establish what values should be used.

Caution: The volume of hydrocarbon using the above mentioned method is highly dependant on the residual hydrocarbon. Since the tool measures in the invaded zone, this method is less effective where Swirr is high and hydrocarbons have been flushed out.