Sonic-Magnetic Resonance Method: A Sourceless Porosity Evaluation in Gas-Bearing Reservoirs

Summary For environmental reasons, there are times when the use of radioactive chemical sources for density and neutron logging is not possible. The inability to use these logging tools seriously affects porosity determination in gas-bearing reservoirs. Several tools, such as the nuclear magnetic resonance (NMR) tool, the sonic tool, or a minitron-based tool, determine porosity without using a radioactive source. These tools, however, are influenced by many effects and, when used alone, cannot deliver an accurate gas-independent porosity. A new methodology that combines sonic and NMR logs for improved porosity evaluation in gas-bearing reservoirs is proposed. The first variant of the method uses the sonic compressional transit time and the total NMR porosity (ft, NMR) to determine the total porosity, corrected for the gas effect, and the flushed-zone gas saturation. In this approach, a linear time-averaged equation corrected for compaction is applied to the sonic compressional log. The simplicity of the solution, much like the previously published DMR1 Density-Magnetic Resonance Interpretation Method, allows fast, easy computation and a complete error analysis to assess the quality of the results. In the second variant of the method, we show that the rigorous Gassman equation has a very similar response to the Raymer-Hunt-Gardner (RHG) equation for a water/gas mixture. This allows substitution of the complex Gassman equation by the much simpler RHG equation in the combined sonic-NMR (SMR) technique to estimate total porosity and flushed-zone gas saturation in gas-bearing formations. Both techniques are successfully applied to an offshore gas well in Australia. In this well, the porosity in the well-compacted sands is in the 20 to 25 p.u. range and the compaction factor is approximately 0.77. The sonic-magnetic resonance results compared favorably to the established density-magnetic resonance results and also to core data. In another offshore gas well from the North Sea, the porosity in the highly uncompacted sands is in the 35 to 40 p.u. range, and the compaction factor is around 1.85. Both SMR techniques were able to produce a very good porosity estimate comparable to that estimated from the density-neutron logs. Introduction Many authors have discussed the applications of sonic logs in gas-bearing formations.2–4 Stand-alone sonic techniques that use Wyllie's equation or the RHG equation are based on empirical observations of water-saturated samples that are extended to water/gas mixtures.5,6 Stand-alone sonic techniques that involve the Gassman theory are generally too complex for the petrophysicist to consider the effects of many sonic moduli parameters that must be determined to solve for porosity.7–9 Other authors have discussed the applications of NMR logs in gas-bearing formations.10,11 Porosity logs derived from NMR alone suffer from the low hydrogen index of the gas and the long T1 polarization time of the gas when the data is acquired with insufficient wait time. To provide a robust estimate of total porosity in gas-bearing formations, a combined density-NMR technique has been proposed. However, density logging uses a radioactive chemical source, and in certain sensitive environments, it is not used because the radioactive source might be lost in the hole. The sonic-magnetic resonance technique has been developed to provide an accurate porosity in these situations. This paper will demonstrate the following:The Gassman and RHG methods predict very similar sonic responses.Both Gassman and RHG sonic porosities are quite insensitive to fluid type, and hence to water saturation.The solution of the Gassman approach is more complex, requiring five parameters compared to only one for the RHG method (RHG is, therefore, more practical).Combining ft, NMR and RHG provides a good estimate of porosity in gas-bearing formations.Combining ft, NMR and a modified Wyllie scheme gives a simple analytic solution analogous to the DMR method.Gas-corrected porosity could be estimated at the wellsite by rescaling the sonic log. The ft, NMR/RHG and ft, NMR/Wyllie schemes are applied to two field examples. The results are compared to those from DMR, to core data in the first well, and to density/neutron analysis in the second well. Sonic Porosity Equations The three methods (in order of increasing complexity) used to compute sonic porosity from the compressional slowness are based on the Wyllie, RHG, and Gassman formulas. In this section, each approach is analyzed, and the predictions from each are compared with the others. Wyllie Method. The Wyllie equation is Equation 1 Eq. 1 can be rearranged intoEquation 2a withEquation 2b In these equations, f=porosity, ?tc=the sonic compressional slowness, ?tma=the matrix compressional slowness, ?tf=the fluid compressional slowness, and Cp=the compaction factor needed to correct the sonic porosity to the true porosity.