T1-T2 map
D Deep DOI T2 D-T2 map
D-T1 map T1
> Three dimensions of NMR. Diffusion, T1 distributions and T2 distributions presented in a 3D format provide intrinsic fluid properties. The cube is used to identify diffusion effects and may aid the interpreter in deciding which model best describes the fluid properties.
Shallow T2
> NMR in four dimensions. The fourth dimension of NMR logging is depth. Bound-fluid volumes, associated with both clay- and capillary-bound fluids (yellow), do not generally change when filtrate from the drilling fluid invades the reservoir. Tool or measurement limitations, however, can result in changes in computed fluid properties that do not represent the true fluid distributions. Constraining the volumes of bound fluid measured by deeper-reading shells to be equivalent to that of the more-precise shallower shells and reapportioning the total porosity across the fluid spectrum provide more-accurate fluid analysis. Use of 4D NMR processing is especially beneficial in interpreting data from heavy-oil reservoirs.
allow petro physicists to detect oil mobility, wettability effects and fluid interactions (above right).
Although the interpretation of maps created from 3D or 4D NMR data might seem simple, complications do exist. The results rely on a forward-model approach that assumes the fluid and the reservoir meet certain criteria. When nonideal fluid properties or atypical reservoir conditions are encountered, the response deviates from the model, and conflict ing or erroneous results may ensue.7 In some cases, nonideal effects can be detected and even quantified by inspection of the D-T maps. Relevant parameters in the forward model can be adjusted once these effects are identified.
In another problem, when diffusion of fluid molecules in small pores is restricted, the measured values of diffusion are reduced from those of the ideal model (next page). While the signal from fluids in large pores
appears as expected in the D-T maps, fluids in the small, poorly connected pores may plot at lower diffusivity values. The problem is most common for water diffusion in fine- grained carbonate rocks. If the effect is not identified, the calculated oil saturation may be overly optimistic. However, once the restricted-diffusion effect is detected, model parameters can be adjusted according to the observed 2D map results and fluid-saturation estimations corrected.
Another anomalous effect results from internal magnetic-field gradients caused by paramagnetic and ferromagnetic materials in the rocks, either in the matrix or coating the grains. These are often associated with high chlorite content and create significant localized field gradients, resulting in faster relaxation times. Because the inversion model is based on the tool’s fixed magnetic-field gradient, the D-T map responses of the fluids in these rocks are shifted to higher diffusion
rates, the opposite of the restricted-diffusion effect. For example, water signals may appear above the water line. Fortunately, it is usually possible to identify these effects by inspection of the maps, and model parameters can then be adjusted to provide correct interpretations. The wettability state also affects D-T maps. Under water-wet conditions, the oil viscosity determines the position of the oil signal along the oil line of the map. The trend is from heavy oil at the bottom left to lighter oils and conden sate at the top right of the line. Oil- wet rocks and those with mixed wettability tend to have shorter relaxation times because of the addi tional surface relaxation of the hydrocarbon in direct contact with the pore surface. Although this can compromise the accuracy of oil viscosity estimated from the NMR data, it can also be a useful measurement for petrophysicists in understanding the nature of the reservoir.8
Winter 2008/2009
11
Amplitude
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