Online Journal for E&P Geoscientists

Filimban, Ayat ^*1; Bakhorji, Aiman ¹
(1) GPTSD, Saudi Aramco, Khobar, Saudi Arabia.

The determination of porosity from elastic properties has not always been very accurate because of the considerable amount of scatter in the velocity-porosity relationships. Many studies have shown that clay content is responsible for much of this observed scatter in clastic reservoirs.

In this study, theoretical and empirical rock physics models that account for the clay content in the velocity-porosity relationships (Avseth et al., 2000; Han et al., 1986) are examined using early Permian sandstones from Saudi Arabia. P- and S-wave velocity, density, and mineral fraction measurements from consolidated gas sand from three wells were used in the analysis. Well 1 was dry and had an average porosity of around 20%, Well 2 tested at low rates and had a 10% average porosity, while Well 3 had an average porosity around 10% and flowed gas on open hole tests at commercial rates.

Brine saturated velocity is plotted versus porosity for all wells with the Hashin-Shtrikman (HS) upper and lower bounds superimposed. Stiff-consolidated sand is expected to fall on or near the upper bound while soft-unconsolidated sand is normally placed on or near the lower bound. Within the same porosity range, a gradual change from very to moderately stiff sands is observed in Wells 2 and 3. Well 1 showed moderately stiff sand with higher porosities compared to Well 2. To understand the reason behind the observed velocity and stiffness differences, modified HS upper bounds for sands with increasing clay content, and the classical empirical trend of Han’s model, are superimposed on the velocity-porosity cross plot. This cross plot implies that the sand in Well 3 is a clean consolidated sand and the sand in well 2 appears to be shaly sand with 20% clay content. The data points from Well 1 fall between the 25% to 35% shaly sand curves. The projection of the data trend from the clean consolidated sand line to the shaly sand lines probably reflects that as clay content increases from almost zero (clean sand) to 35% in shaly sand, permeability sharply decreases to less than 1 mD, which in turn, affects the productivity of the gas sands. This interpretation is confirmed using Marion’s permeability-clay model (1989). The model shows that permeability decreases with increasing clay volume from around 103 mD in clean sand, to 1 mD in 15% clay. Lower permeability values are obtained in clay-rich sand, which may explain the poor production of the shaly sand in Well 2.