Brine T2 Distributions
Clay- bound water
Capillary- bound water
Free water Tar
Oil T2 Distributions Heavy oil Intermediate oil
Light oil
Tar + clay- bound water
T2 cutoff
Total Distribution
Heavy oil + capillary- bound water
Intermediate oils + free water
Light oil + free
water
Pore size
Viscosity and composition
> The effects of oil on T2 distributions. For brine-filled pores, the T2 distribution generally reflects the pore-size distribution of the rock. This distribution is often bimodal, representing small and large pores (left). The small pores contain clay- and capillary-bound fluids and have short relaxation times. The large pores contain movable free water and have longer relaxation times. The dividing line between bound and free fluids is the T2 cutoff. When oil fills the reservoir pore spaces, the measured T2
distribution is determined by the viscosity and composition of the oil (middle). Because of their molecular structure, tar and viscous heavy oils have fast decay rates, or short T2 times. Lighter oils and condensate have a spectrum of T2 times, overlapping with those of larger brine-filled pores. Mixed oil and water in the reservoir result in a combination of T2 times based on both pore size and fluid properties (right).
hydrocarbons, they do help characterize the fluid type. Techniques have been developed to exploit the fluid response and identify the presence and type of hydrocarbons.
The differential spectrum technique combines measurements with two different wait times. Short WTs underpolarize formation fluids, such as gas and light oil, which have long buildup and decay times. Measurements from fluids with short relaxation times are not affected by a change in WT. Differences between sequential logging passes identify the presence of light hydrocarbon, making the differential spectrum technique most effective in gas or condensate environments. Logging sequences have also been developed that acquire the data in a single pass. Enhanced diffusion exploits changes in fluid response that occur when different echo spacings, or TEs, are used.7
Water and oil generally have similar relaxation times when measurements are
2. CPMG refers to the physicists who successfully deployed the RF pulse sequence used in NMR devices— Herman Carr, Edward Purcell, Saul Meiboom and David Gill.
3. During the CPMG sequence, hydrogen atoms are manipulated by short RF bursts from an oscillating electromagnetic field. The frequency of the RF pulses is the Larmor frequency.
4. Freedman R and Heaton N: “Fluid Characterization Using Nuclear Magnetic Resonance Logging,” Petrophysics45, no. 3 (May–June 2004): 241–250.
5. Kleinberg RL, Kenyon WE and Mitra PP: “On the Mechanism of NMR Relaxation of Fluids in Rocks,” Journal of
In the past, there were two primary tech - niques by which NMR data were used to identify fluids: differential spectrum and enhanced diffusion.6
acquired using short TEs, but water often relaxes faster than oil when longer TEs are used. To isolate the oil signal, a measurement with a short TE is compared with an echo train with a longer TE, chosen to enhance the diffusion differences of the fluids in the formation. The water signal decreases with longer TEs, leaving primarily the oil signal. This diffusion sensitivity provides a qualitative indication of the presence of oil, although the measurement may sometimes be quantitative as well.8
Both differential spectrum and enhanced diffusion rely on traditional T2 relaxation measurements to identify hydrocarbons. This limits the results to a one-dimensional aspect of the fluids, and fluid type can only be inferred, not directly quantified. Also, prior knowledge of the expected fluids is necessary to choose the correct acquisition parameters. The primary limitation of the relaxation dimension is the difficulty in distinguishing water from oil (see “Dimensions in NMR Logging,” next page). But, the fact that oil and gas signals are included with the water signal
Magnetic Resonance108A, no. 2 (1994): 206–214.
6. Akkurt R, Vinegar HJ, Tutunjian PN and Guillory AJ: “NMR Logging of Natural Gas Reservoirs,” The Log Analyst37, no. 6 (November–December 1996): 33–42.
7. Akkurt R, Mardon D, Gardner JS, Marschall DM and Solanet F: “Enhanced Diffusion: Expanding the Range of NMR Direct Hydrocarbon-Typing Applications,” Transactions of the SPWLA 39th Annual Logging Symposium, Houston, May 26–29, 1998, paper GG.
8. Looyestijn W: “Determination of Oil Saturation from Diffusion NMR Logs,” Transactions of the SPWLA 37th Annual Logging Symposium, New Orleans, June 16–19, 1996, paper SS.
in the total distribution introduces an exploitable dimension to the relaxation distributions. Remove the water contribution and only the hydro carbon signal remains.
Molecular diffusion is the key to unlocking fluid properties from the NMR data. Gas and water have characteristic diffusion rates that can be calculated for given downhole conditions. Oil has a range of diffusion values based on its molecular structure. This range can also be predicted from empirical data derived from dead-oil samples. The T2 measurement provides the total volume of fluid—bound and free. The addition of diffusion discriminates the type of fluid present. A graphical presentation—the diffusion-T2, or D-T2, map—displays these data in a 2D space formed by the diffusion dimension and the relaxation dimension. The water signal can be separated from that of the hydrocarbons. The intensity of the components in the D-T2 map provides fluid saturations. Maps can also be generated using T1 relaxation data.
This quantification of diffusion is made possible by a new acquisition technique, diffusion editing (DE), which alleviates the limitations of previous methods, such as enhanced diffusion and differential spectrum. Distinguishing water and hydrocarbon by their diffusivity differences not only permits the (continued on page 13)
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