In the one lateral I worked in the Permian Basin, we identified three reservoir boundaries using Mass Spec data. That means four discrete reservoirs were cut in just two miles. That does not bode well for using CO2 flood to achieve enhanced (tertiary) recovery. Much will depend on the orientation of the laterals relative to the reservoir boundaries, and there is a dearth of data as to the location of those boundaries, simply because most wells there do not have that quality of data.
Our geochemical data was separate, from a separate gas extractor on the shakers to the lab units, from the mud loggers', and that is a good thing. I never met them, as they were conspicuously absent from the location while I was there. Their polyflow line (which brings gas from the extractor on the shaker to analytical equipment in their shack) remained parted for four days and they did nothing to fix it, so any reported gas readings they had, even if more rudimentary, were bogus for that time. You get what you pay for, I guess.
If that data was present and valid, there is a chance that some of it could be of good enough quality to identify some reservoir boundaries there and determine fields/wells/or areas that are more conducive to tertiary recovery, but I think a lot of what is being seen is the normal production decline in horizontal wells: a steep decline from IP to more sustained production, of abut 80% in the first two years, with more sustained production at ~20% of IP after that with a much slower decline rate, a general increase in produced water, and increase in GOR (Gas/Oil Ratio) as the dissolved gas precipitates from the oil with pressure reduction.
Another problem that can rear its ugly head is when the reservoir reaches 'bubble point' and pore blocking by gas bubbles, something the Canadians were looking into at the U of Regina, and the presence of that phenomenon may be an indicator that using CO2 for reservoir pressure maintenance is a good way to restore and maintain production levels to something approaching levels before the decline.
The question remains one of weighing the value/expense (in the case of more water) of any enhanced recovery against whether the NGLs in the wellhead gas and the gas itself is valuable enough to support the reduction in oil production and costs of water disposal or the cost of processing the CO2 out of the wellhead gas in order to market that. There may well be a point where those curves cross, that will be different for every well, but similar enough to come up with a strategy for tertiary recovery operations in a given field area, provided that proof of concept can be obtained.
Just like walking across the ground, walk a mile in virtually any direction and take careful note of the sediments beneath your feet, there are almost always changes that would, in a reservoir, have effects on the efficacy of CO2 flood operations and which would affect production. About the only place I have ever been I did not notice those differences was on the Salt Flats in Utah, which at the surface had the most homogeneous surface sediments of any place I have ever been (at least on that scale).
I am not saying it won't work, but that the application may be more limited than those doing sales may admit. One well, after all may indicate potential problems, but it does not define the entire Basin by any metric. If there is proof of concept, turn that pipeline around and head it south!
During my almost 50 years of working injection projects, whether secondary water injection or tertiary chemical, steam, fireflood, CO2 or natural gases/NGLs, and I have done them all, I have found the chief reason a project does not meet expectations is the inadequate understanding of the geological description of the intended project. Fluids do not travel where they are expected to go, sometimes much better, but mostly detrimentally.
This situation is exacerbated for low permeability reservoirs as fluid contact is much more difficult to achieve, and fracturing, whether natural or induced, cause much bypass of fluid reservoir volumes.
It remains important to better understand that geologic description as the amounts of oil within these low permeability rocks is quite staggering and, in time, the extraction of more oil from these formations will be important to us.
So I am gung-ho at spending time and energy to do so in or our more important oil provinces, and the Williston Basin's Bakken, which I regard as the best unconventional play I have ever seen in the world, remains high on my target list to adequately understand its geology to that end.
