IMPACT OF COLD WATER INJECTION ON GEOTHERMAL PRESSURE TRANSIENT ANALYSIS: A RESERVOIR MODELLING ASSESSMENT

Abstract

Geothermal pressure transients are currently analysed using standard analytical methods from oil and gas well testing theory. It is known that these analytical models do not fully apply to geothermal well test analysis as the underlying assumptions that allow for an analytical solution are not satisfied. Of particular interest for this study is that the analytical models require one fluid temperature to be specified, which sets the fluid properties such as viscosity and density. This is a great dilemma to the geothermal reservoir engineer looking at an injection/falloff test - whether to use the properties of the hot reservoir fluid, or the properties of the cold injected fluid. This issue has previously been examined and the conclusion reached that it is best to use the properties at reservoir conditions. However, this is done with the knowledge that the reality is something in between: the temperatures and fluid properties in the reservoir will be non-uniform, time-varying, and will range between the injectate and reservoir properties.
This issue is addressed in this study using the TOUGH2 numerical reservoir simulator to model well tests. Both the properties of the cold injection fluid and the hot reservoir can be specified. A test model is setup based on a particular injection test into a single well, using a standard model design. The temperature of the injectate is varied from ambient temperature up to hot reservoir temperature, a range from 15°C to 310°C. The impact on the results of pressure transient analysis are examined. In particular the changes to the derivative plot are studied. The modelling showed that the injected fluid temperature has a major impact on the skin factor and a minor impact on the reservoir permeability. This issue is examined in isolation from thermal stimulation effects.