The relative permeability of carbon dioxide (CO2) to brine influences the injectivity and plume migration when CO2 is injected in a reservoir for CO2 storage or enhanced oil recovery (EOR) purposes. It is common practice to determine the relative permeability of a fluid by means of laboratory measurements. Two principal approaches are used to obtain a relative permeability data: steady state and unsteady state. Although CO2 has been employed in enhanced oil recovery, not much data can be found in the open literature. The few studies available report wide ranges for CO2 relative permeability in typical sedimentary rocks such as Berea sandstone, dolomite, and others. The experimental setups vary for each study, employing steady and unsteady state approaches, different experimental parameters such as temperature, pressure, rock type, etc. and various interpretation methods. Hence, it is inherently difficult to compare the data and determine the origin of differences. It is evident that more experiments are needed to close this knowledge gap on relative permeability. This article concludes that standards for lab measurements need to be defined a. to establish a reliable CO2-brine relative permeability measurement method that can be repeated under the same conditions in any lab and b. to enable comparison of the data to accurately predict the well injection and fluid migration behavior in the reservoir.