Natural gas in its native environment is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions. Full water saturation of gases used in laboratory core flooding tests may not always be achieved, and it is known that the use of dry gas in such experiments can artificially reduce core permeability to gas by dehydrating and crystallising any brine residues left within the cores. This problem of permeability impairment, as a result of water vaporisation by gas, might be expected to become more acute or evident in laboratory tests with high-pressure high-temperature (HPHT) reservoir cores containing high salinity formation brine and high-density completion brine filtrates. These brines may contain salt concentrations that are already close to saturation levels and are more susceptible to crystallisation by dehydration.
The objective of the work described in this paper was to look at the effect of gas humidification levels on the gas permeability of North Sea HPHT reservoir core material exposed to high-density cesium formate brine under HPHT conditions in laboratory core flooding experiments. The results from core flooding experiments at 200oC (392oF) indicated that full HPHT-humidification of the gas phase resulted in a higher gas return permeability when compared with a test using gas humidified at room temperature and high pressure. This finding highlights the importance of ensuring that any gases used in HPHT core flooding tests are fully saturated with water vapour at the test temperature and pressure. It seems likely that the impact of gas humidification levels will be amplified in very low permeability cores subjected to high drawdown pressures.
Natural gas contains a variety of non-hydrocarbon contaminants. These contaminants include water vapour. In its native reservoir environment the gas is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions [Rushing, et al, 2008; Udell, 1982; Zuluaga and Monsalve, 2003]. The amount of water vapour present in the gas phase is a function of the gas composition, reservoir pressure, reservoir temperature and the dissolved salt content of the connate water. The water content of the gas increases with increasing temperatures, but an increase in pressure or dissolved salt content has the opposite effect.