In this chapter, rock-physics modelling provided insights to the sensitivity of saturated sandstones to induced production effects such as changes due to pore pressure increase, and decrease, and water and gas saturation. An understanding of the dependence of the sensitivity to lithology variations was also achieved by analysing three sandstone samples which ranged from high porosity (18-27.1%) unconsolidated sandstones to a low porosity (5%) cemented sandstone. Properties for these sandstones were obtained from MacBeth (2004). The reservoir’s sensitivity was quantified using two standard attributes for 4D seismic data interpretation, amplitudes and time-shifts. The amplitude sensitivity measures the relative change in amplitude in percentage (i.e. relative to baseline) to a unit change of dynamic property. The time-shift sensitivity measures the intra-reservoir 4D time-shift (in microseconds normalised by the reservoir’s thickness, in metres) to a unit change of dynamic property, expressed as (ms/km) per dynamic change. The dynamic property is either pressure change (in MPa) or saturation change (in percentage), where change is simply monitor-baseline (i.e. pre-production state).
Both amplitude and time-shift sensitivities were of complementary trends. Amplitudes offer a more balanced sensitivity to pressure and fluid saturation changes, whereas, time-shifts show more dispersion between pressure changes and water saturation changes. This suggests the usefulness of combining both attributes for discriminating pressure from saturation effects in 4D seismic data. Sensitivity decreases significantly from the unconsolidated sandstones (highest) to the cemented sandstone (lowest). The cemented sandstones are more sensitive to pressure changes than to saturation changes, whilst the unconsolidated sandstones provide a balance. For the higher porosity sandstones, sensitivity to gas saturation changes can be up to 20 times greater than that for water saturation changes, but typically are around 2.5 to 3.5 times greater. An asymmetry in pressure sensitivity was also observed, where the sensitivity to pressure increase can be up to 14 times greater than the sensitivity to pressure decrease (in unconsolidated sandstones), but this disparity has a lower margin in cemented sandstones - only 2 times greater.
These findings offer a foundation for interpreting production-induced 4D effects and the balance between them. However, it is all based on a rock-physics model, properties of an outcrop sandstone sample and a recovered sample from a West of Shetland reservoir, and a narrow range of pressure changes of up to 20 MPa. The effective-medium model applied (i.e. Gassmann theory), has limitations with regards to its assumptions, namely: the rock is isotropic, pore spaces are well connected and completely saturated and low seismic frequency (< 100 Hz) of observation. The latter is practically applicable to the seismic experiment. The low frequency assumption implies that pore pressures are equilibrated throughout the pore space and the fluids can flow easily through the pore space, otherwise, at high frequencies (> 100 KHz), fluids do not have enough time to flow and this will increase the stiffness of the rock. The limitations of Gassmann’s (1953) assumptions mostly affect low porosity cemented sandstones. In any saturated rock, fluids are not homogenously distributed throughout the pore space, a patchy saturation model which spans the range of fine-scale (homogenous) to patchy mixing is recommended (for example, Brie et al., 1995). In addition, rocks are not isotropic, relations such as those detailed in Brown and Korringa (1975) must be used to account for anisotropy. In terms of the rock mineral moduli, the Voigt-Reuss-Hill average (Hill, 1952) was used, but Hashin-Shtrikman bounds (Hashin and Shtrikman, 1963) can also be applied, or a modified version by combining it with Dvorkin’s contact cement model (Dvorkin and Nur, 1996) and this may be widely applicable to a variety of unconsolidated and cemented sandstones. Asveth et al. (2010) details the various rock- physics models that could be applied, but it is expected that similar conclusions on the sensitivity for the sandstones used, as well as the relative magnitudes between pressure and saturation sensitivity will be reached. On a reservoir-constrained modelling on three different fields (two clastic fields and one carbonate field), Briceno (2017) shows that different rock-physics models give similar results, and it is the parameterisation of the various rock-physics models that affect the results. The purpose of the generalised rock- physics modelling performed in this chapter is to provide some guidelines, and it is not intended to try to match any observations on real field studies; this is beyond the scope of this thesis.
In the next chapter, the observed 4D seismic data will now be calibrated to quantify the reservoir’s sensitivity on four different clastic fields.
3 Chapter 3
Quantification of the sensitivity of sandstone
reservoirs to pressure and saturation changes using
full-stack 4D seismic amplitudes and time-shifts
In Chapter 2 rock-physics modelling provided basic understanding of the pressure and saturation sensitivity of different sandstones. In this chapter, the in-situ reservoir’s sensitivity is quantified directly from the observed 4D seismic data. The main motivation for this is to provide an alternative to laboratory measurements on core plugs or rock-physics models. This complementary technique for estimating pressure and saturation sensitivity compares 4D seismic and pressure/saturation measurements. This is possible in selected areas around and away from wells where pressure or saturation variations contribute predominantly to the 4D seismic signatures. Multiple monitor 4D seismic data are used to sample these areas as a function of field production time. The technique is applied to 4D seismic amplitudes and time-shifts across four producing North Sea clastic reservoirs (Shearwater, Norne, Heidrun and Schiehallion). The results indicate that pressure and saturation sensitivity varies according to the geology of each reservoir. This also indicates the reliability of the approach to better tackle the separation of pressure versus saturation for improved reservoir management.