Water Vaporization in Gas Reservoirs

Abstract

Experiments have been performed to determine the rate of water vaporization in core samples at initial water saturation. The effect of pressure on rate of water vaporization has been studied. The experiments indicate that as pressure decreases from 2000 to 1000 psi, at constant temperature of 90°C, the rate of water vaporization increases from approximately 0.016 to 0.025 g/min. The effect of increase in temperature from 90°C to 100°C, at constant pressure of 1500 psi, is to increase the rate of water vaporization from 0.018 to 0.029 g/min. All the experiments were performed with the core samples at initial water saturation of 18%. As vaporization takes place, the brine remaining in the core sample becomes more concentrated. If concentration exceeds the critical supersaturation value, minerals will precipitate out into the formation. Additionally, the effect of salt precipitation on absolute permeability was determined. The results indicate that reduction in absolute permeability after the vaporization experiments ranges from approximately 14 to 30%. Introduction Water vaporization has been reported as the cause of permeability reduction in some oil fields and as a potential problem in many others, especially in high pressure, high temperature reservoirs (HP/HP) which are characterized by very high salinity brines4. In gas producing reservoirs, vaporization occurs as a result of the increase in the molar water content as the pressure declines around the wellbore. In the case of gas injection, the dry gas vaporizes water in order to fulfill the thermodynamic requirements at the given pressure, temperature and salinity of the brine. As water is vaporized, salt precipitates if the critical supersaturation value is reached. In gas producing reservoirs, water vaporization initially increases the effective permeability to gas by increasing the area available for flow. This increase in effective permeability to gas due to water vaporization has been reported for the case of water blocks5. However, salt precipitation can increase over time around the wellbore, i.e., due to water imbibition into the zones where water has been vaporized, causing a detrimental impact on gas effective permeability. To the author's knowledge, one of the first experimental studies performed to determine the rate of water vaporization were carried out by Dodson and Standing in a PVT cell3. They found that the rate of water vaporization increases with temperature and decreases with pressure and solids content. The authors did not perform experiments on porous media. Morin and Montel7 studied the conditions for water vaporization as a function of salinity and pressure. The authors pointed out the main conditions that contributed to salt plugging: flow of gas from layers at different water saturation8 and significant pressure drop from the near wellbore area to the well. Other authors2,6 have modified compositional simulators to account for mass transfer between water and hydrocarbon components to be able to predict the amount of water vaporized from the reservoir. Such amount of water is crucial for the design of water handling facilities. Bette and Heinemann2 also confirmed vaporization in the field. They took cores from Arun field gas injectors that showed very low water content and in some cases, the water was completely vaporized. In a different scenario, also associated to water vaporization, the subnormally low water saturation presented by many tight gas reservoirs has been attributed to vaporization of initial water by long term regional migration of undersaturated gas1. Consequently, the brine remaining in the reservoir was saturated (300,000 TDS plus) and additionally, large volumes of crystalline salt, especially halite were encountered in the porous media.

Salt precipitation due to supercritical gas injection: I. Capillary-driven flow in unimodal sandstone

“…There are only a few studies on flow-through drying available, which are relevant for CO 2 storage. Zuluaga et al investigated vaporization and salt precipitation in sand packs and sandstone for gas production wells (Zuluaga and Monsalve, 2001;. At the GHGT-10 in Amsterdam 2010, two experimental studies on dry CO 2 injection have been presented.…”

The Effect of Mineral Deposition on CO2 Well Injectivity

“…Bacci et al (2011) reported porosity changes between 4% and 29% of the estimated initial porosity. Permeability reduction between 0% and 86% of the estimated initial permeability from sandstone core flooding experiments have also been reported (Bacci et al, 2011;Wanga et al, 2009;Zuluaga et al, 2003;Zuluaga et al, 2001).…”

“…Several researchers have confirmed that mineral precipitation could cause significant reduction in gas injectivity (Bacci et al, 2011;Place et al;Wanga et al, 2009;Zuluaga et al, 2003). Bacci et al (2011) reported porosity changes between 4% and 29% of the estimated initial porosity.…”

“…Injection of CO 2 into the formation vaporises brine and precipitate minerals into the pores. As vaporization takes place, the brine remaining in the core become more concentrated and minerals will precipitate out of the solution when the concentration exceeds the critical supersaturation value (Zuluaga et al, 2003). The precipitated minerals impair permeability and porosity and offer resistance to the flow of injected CO 2 .…”

Determining Water Vapour Phase Equilibrium Coefficients at Different Temperatures for Gas Wells

“…As the pressure declines at constant temperature, water is vaporised given the increase of the molar water content in the gaseous phase [4]. This process can be simulated in ECLIPSE by using the GASWAT option.…”