Does anyone know what method of "Enhanced Oil Recovery" EOG has been using in their EF trials as mentioned repeatedly in many of their presentations?

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I understand that they are injected natural gas to "re-energize" the reservoir and subsequently create a situation where more O&G are recovered.

This is similar to the research that Tx Tech has done using this same approach on a hypothetical reservoir that has Eagle Ford characteristics. That research paper is out there somewhere - I believe it indicates that recovery factors can be doubled using this approach.

Thanks Mark. Would they be drilling dedicated gas injection wells between the horizontals or using the original well bores and injecting gas through the well bore somewhat like a gas lift system?

My understanding is that they are taking wells that are already producing and using them for gas injection. With the multiple wells EOG has on many leases, this should allow for an efficient recharge of fracture stimulated rock volumes near the injection wells

That's interesting, I didn't think the wells had communication after the frac that would allow for pressure transfer between well bores for the entire treated bore length. On another note, do you know if a gas lift system allows for better EUR over the standard mechanical pumps of is gas lift just more economical when the leases have 5 or more wells and the compressor/lift system can operate multiple leases?

There is probably enough perm (both natural and micro fracture enhanced) to transfer injected gas into the reservoir over time. Some pretty complicated dynamics downhole that I don't pretend to totally understand.

I am no expert on artificial lift options, but I do understand that too much gas will mess up (lock up) surface pumping units. I believe that one needs to tailor their artificial lift approach to the wellbore in question and make adjustments over time to optimize ultimate recoveries (EUR). As well as do a good job of maintenance, corrosion control and other work (e.g. paraffin control, scale control, etc.)

Thanks Mark. In Gonzales county EOG is installing gas lift and doing away with the pump jacks in a few areas so I'm assuming there is more benefit to the gas lift system over time as the compressor and piping for the gas lift compressor to all the various wells has to be very expensive.

Equipment and set up for gas lift is costly, but this can be a very efficient system that essentially runs itself without a lot of moving parts. Regular pump jacks need a lot of care and maintenance and can have a lot of problems with gas locking up the pumps.

Don't be surprised if - after a lot of the gas is produced - EOG (or whoever is the operator in the future) goes back to surface pumps to recover the last bits of oil.

One thing that may help us amateurs on all this would be to examine a "typical" Eagle Ford well's decline curves for both oil and gas separately.

If one assumes that prior to any drilling the shale is reasonably uniform and that the initial concentration of oil is uniform throughout the area of interest, and furthermore that the initial concentration of gas is also uniform, then it seems intuitively obvious to the casual observer that

i) if the gas declines at a greater percentage rate, it is "faster" given post-frack formation properties and the diffusion of gas through oil in the fissures from formation to wellbore.  There would even be a feedback mechanism in that, if the gas is "faster," its more rapid decline would take away from the driving force for the oil.

ii) if the gas declines at a smaller percentage rate, it is "slower" given post-frack formation properties and the diffusion of gas through oil in the fissures, and stays "behind" the oil, relatively speaking.

My guess, and only a guess, is that i) is correct sorta.  In that case, although pressurizing a theretofore producing but largely declined horizontal wellbore would initially "drive" oil away from the wellbore and back into formation, if the gas is "faster" it would, net net, get back "behind" the oil and serve as propulsion for the oil on the rebound.  This would seem to create a kind of "sloshing" of the oil back and forth, with fortuitous recovery of some on each slosh, each slosh resulting from the gas pressurization, in turn on the wellbore side and "behind" the oil.  Maybe you can get only one slosh per well.  Me no savvy.

Of course, as Mark pointed out, there are all kinds of mechanical and thermodynamic things happening down there, e.g., gas going into solution in the oil.  And my simple-minded model does not contemplate communication between adjacent horizontal wellbores.

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