An Experimental Study to Evaluate Water Vaporisation and Formation Damage Caused by Dry Gas Flow through Porous Media

Abstract

Experiments were conducted to evaluate the rate of water vaporisation and the consequent permeability reduction caused by the flow of dry gas through porous media. Two sets of porous media were studied: unconsolidated Ottawa sandpacks and consolidated Berea cores, as well as various salinity brines ranging from 0 to 150 g/litre of NaCl. The experiments were conducted at an initial water saturation of about 14% for sandpacks and 24.6% for Berea cores. Tests indicate that the rate of water vaporisation increases with gas flow rate and decreases with salinity. The vaporisation of water from the porous media can result in halite drop-out. This might cause a reduction in the permeability of the porous media. The experiments showed that the reduction in permeability for sandpacks ranged from 0% for the lowest salinity to around 21% for the highest salinity used. In consolidated Berea cores this reduction ranged from 9% to 53% for the lowest and highest salinity respectively. Introduction The flow of dry gas through porous media vaporises water in order to fulfil the thermodynamic requirements at a given pressure, temperature and salinity of the brine saturating the rock. Also, the development of an increasing number of high- pressure, high-temperature (HT/HP) fields has arisen important issues concerning inorganic deposition in these systems given their frequently high salinity brines. As the pressure declines at constant temperature, water is vaporised given the increase of the molar water content in the gaseous phase. This produces an over-concentration of dissolved salts and the solubility limit can be reached with the subsequent salt precipitation. Several authors have reported field cases where precipitation of NaCl is believed to be the cause of formation damage and it has been usually associated to water vaporisation1,2,3,4. Background Dodson and Standing5 reported experimental studies in PVT cells to determine the solubility of a natural gas (?=0,655) in brine and to determine the solubility of water vapor in natural gas. The experiments were performed at pressures ranging from 500 to 5000 psia, temperatures from 100 to 250°F and brines having up to 25000 ppm of total solids. It was found that the amount of water in the gas phase increases with temperature and decreases with pressure and solids content. Place and Smith1 reported a severe decline in productivity for the well Shell Ridgway 1-R in the Southwest Pineywoods Field, MS. After observation of the decrease in Cl-/K+ and Cl-/Li+ ratios in the produced fluids, the authors concluded that the deposition of NaCl at the open hole was responsible for the significant loss of productivity. Even though the water saturation in the main pays was considered to be inmmobile (15% to 26%), the overlying and isolated zones had water saturations in the range of 35% to 50%. Under this scenario, the flowing gas would evaporate water from the main pays increasing the concentration of the brine. Also, if less concentrated brine is flowing into the wellbore from the high saturation zones, the gas would evaporate this less concentrated brine with the subsequent NaCl deposition. The author's point out that only when the salinity of the pay zones exceeds that of the overlying high saturation zones the episode of salt deposition and plugging will be initiated. Morin and Montel3 studied the dehydration process in order to predict the conditions for precipitation of NaCl in the tubing. The authors mention three situations that contribute to the vaporisation process including the flow of gas from layers at different water saturation, important pressure drop with small temperature decrease and the increase in vaporisation when the gas flows from the near wellbore area to the well. The latter situation appears because the porous media causes a decrease in the water content of gas compared to the value outside of it given that capillarity and adsorption tend to retain the water in the rock. The authors remark the influence of water saturation on the rate of water vaporisation.

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).…”

Effect of Wettability Changes on Evaporation Rate and the Permeability Impairment due to Salt Deposition

“…This claim has however been disproved by many studies including this present study 1,[3][4][5][6][7][8][9][10][11][12] . The falling rate period and the receding rate period are often combined together as stage-2 evaporation 6,[13][14][15] .…”

Effects of temperature on salt precipitation due to formation dry‐out during CO2 injection in saline aquifers

“…11 Because the salinity of the deep formation water is commonly high, the solid salt precipitation is likely to occur near the injection well, which may dramatically alter formation porosity, permeability and injectivity. [12][13][14][15][16][17][18][19] To date, some models and experiments have been conducted to investigate salt precipitation and its effect on the injectivity. 13,[20][21][22][23][24][25][26] Pruess and Muller 9 set up isothermal one-dimensional and two-dimensional numerical models to investigate the salt precipitation process and influencing factors.…”