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Distinguishing fizz gas from commercial gas reservoirs using multicomponent seismic data

Texas A&M University, College Station, Texas, U.S.

Corresponding author: F. Zhu, fzhu@shellus.com

The first 20% of the full text of this article appears below.

Partial gas discrimination is a challenging problem because low and high gas saturation can result in very similar seismic AVO, bright spot, and velocity sag anomalies. This is typically explained using Gassmann's theory: i.e., (1) small amounts of gas in the pore space cause large decreases in rock incompressibility while further increasing gas content does not reduce rock incompressibility significantly, and (2) the shear modulus is not affected by nonviscous fluids in the rock pore space. In addition, rock bulk density varies gradually with water saturation, as predicted using the volume-average equation. Consequently, low-gas saturation reservoirs and high-gas saturation reservoirs can have similar V_P and V_P/V_S values (or, equivalently, Poisson's ratios). Therefore, in many cases, high and low gas saturations cannot be distinguished using existing hydrocarbon indicators and techniques. These indicators include those based on V_P variations, such as velocity sags, and those based on Poisson's ratio variations. The latter category has many variations—bright spots, amplitude variation with the offset of P-wave seismic data, V_P/V_S from P-wave or multicomponent seismic data, the fluid factor (Smith and Gidlow, 1987), Lamé's petrophysical parameters (Goodway et al., 1997), and other similar approaches. Density information may sometimes distinguish high and low gas saturations. However, density variation due to lithology changes can be much larger than density variation associated with fluid changes so that the latter is masked (Zhu, 2000).

Fortunately, when high-quality multicomponent seismic data are available, ratios of amplitude measures from P-P and P-S seismic reflections (R_PP and R_PS, respectively) may be good partial gas indicators (PGIs). These ratios, R_PP/R_PS and R_PS/R_PP, are determined by the differences between coefficients measured in a water saturated area and another target area with unknown saturation. The basic idea is to compare reflectivities from . . . [Full Text of this Article]

This article has been cited by other articles:

				P. KRISTIANSEN and J. WAGGONER Using multicomponent seismic data to better characterize and manage reservoirs Geological Society, London, Petroleum Geology Conference series, January 1, 2005; 6(0): 1377 - 1384. [Abstract] [PDF]