The literature lacks sufficient evidences about the real practice of gas relative permeability measurements and input for reservoir simulation? The influence of gas type on relative permeability curves seems to be important.
Although industrial studies may rely upon data coming from a wide range of conditions for lack of better source, there is a strong drive to perform relative permeability measurements in representative conditions because it is known that results can substantially differ functions of conditions. That means in your specific focus area real fluids (CO2 and oil, preferably live oil rather than dead oil), realistic pressure and temperature and realistic flow sequences. What practically happens in an industrial context is that precise and reliable relative permeability measurements are nearly systematically only available for fields where economic stakes are large and some time after field discovery. For other fields, one will rely upon analogy, rock and fluid considerations driving the selection of the analog (as well as the database available to the person drawing the analogy). This activity certainly is a specialised domain and not likely to be well publicized considering the large costs involved in the acquisition of data and complexity of the task.
It is always desirable to perform relative permeability experiments with real fluids at reservoir conditions. However, if you only have model fluids you can estimate the effect of the gas on relperm by including interfacial tensions or Capillary number if the wettability does not change.
You can get more details from:
Drainage and imbibition relative permeabilities at near miscible conditions.
Journal of Petroleum Science and Engineering
Volume 53, Issues 3–4, September 2006, Pages 239–253
http://www.sciencedirect.com/science/article/pii/S0920410506001148
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