Experimental Investigation of Cooling Effects Resulting from Injecting High Pressure Liquid or Supercritical CO_2 Into a Low Pressure Gas Reservoir

摘要

Depleted natural gas reservoirs are considered as potential sinks for carbon sequestration. The lack of industry experience in injecting large quantities of CO_2 into depleted gas reservoirs, however, contributes uncertainty regarding the viability of the concept. If Joule-Thomson cooling is significant, injectivity could be affected by formation of hydrates or freezing of connate water. The focus of this study was to evaluate phase behavior and potential impact of Joule-Thomson cooling during injection of liquid or supercritical CO_2 into pressure depleted systems. The intent was to mechanistically model conditions considered in the design of CO_2 injection operations in a pressure-depleted offshore gas reservoir. The following conceptual model is offered from experience gained in this effort. Initially, when injecting cold, high pressure CO_2 into a hot low pressure environment, heat transfer from the surrounding reservoir environment will mask or counter Joule-Thomson gas expansion cooling effects. The most significant early-time cool down effect may be the result of injecting a cold fluid into a hot reservoir. As the near-well region cools and the cool zone extends deeper into the reservoir, injected CO_2 may remain in the liquid phase for greater and greater distances into the reservoir. The worst-case scenario will occur if, when, and where CO_2changes from liquid to vapor. This will occur with pressure and temperature below the critical point (1070 psia and 87.7 deg F). A pronounced cooling effect accompanies the phase change from liquid to vapor. When and where this occurs, if the rock is still partially saturated with brine/the potential will exist for forming ice or hydrates that may significantly decrease CO_2 injectivity.