Abstract During gas injection projects (CO2 or hydrocarbon miscible/ immiscible flooding, CO2 huff 'n puff or Vapex), only a portion of the injected gases are produced back during injection periods, with additional amounts thereafter. Significant portions of the injected gases (upwards of 35%) are retained within the reservoir during the project life and are ‘lost’ (sequestered or geologically stored). Amount of the retained gases could significantly impact upon economics of some of these projects. Laboratory studies help in understanding many of the mechanistic aspects of injected gas return. Correspondingly, to obtain further insights on recovery of the injected gas from the swept regions, we conducted some core flood experiments. It was felt that to fully study various phenomena occurring within reservoirs over long term, these insights need to be complemented with analyses of relevant performance data from past field projects. In recent years, limited (and often incomplete) information on gas produced back from some of the field projects have become available in the public domain. Analyses of these for some selected field projects led to some interesting observations. It was concluded that the injected gases disperse over relatively wide regions, via oil and aqueous phases. Intuitively, nature of resulting distribution depends upon pressurization, solubility, diffusion coefficients, heterogeneity, and flow/saturation distributions. Upon flow back (production); many of the above factors are not fully reversed, leading to significant gas retention. It is surmised that generalized data from past field projects, in absence of relevant data from analogous projects, would be useful in projecting solvent retention and production profiles for future gas injection projects. Introduction Gases are often injected for pressure maintenance, or for improving oil recovery from reservoirs where waterflood is not a preferred option. Candidate reservoirs for this mode of gas injection could be tight, contain water sensitive clays (low water injectivity), overlain by gas caps, or contain initial mobile gas saturation. In the past, several gases (N2, CH4, CO2, flue, waste acid or tail gases, air) were injected for this purpose. Another important application of gas injection is for enhanced oil recovery by miscible/ immiscible flooding. In these applications, natural gases enriched by ethane and/or propane, or CO2 have been used as ‘solvents’. Gases in these applications have been injected continuously or intermittently (with water). Gases are also sometimes injected for enhancing recovery of condensates/ natural gas liquids (gas cycling). The amount of the injected gas or ‘slug-size’ or ‘bank-size’ is chosen to optimize economic returns. It has been observed that a significant amount of the injected slug (>35%) is retained within the reservoir during its placement, and some of it is returned slowly thereafter, over several years. Retention of a quarter or more of the slug at the end of the economic oil production from the field is not uncommon.