What are everyone’s observations on how secondary and tertiary recovery efforts on natural gas wells fare compare to waterflooding oil wells? Is it even tried as often? And if they do, do they unitize/combine the production from the neighboring gas wells?
There is not really a technically feasible method for secondary or tertiary recovery in a gas reservoir, so no it isn’t tried very often.
Here is a link to a really old but good paper on gas secondary recovery.
Gas injection and waterflooding (and other techniques) are commonly used for secondary and tertiary recovery of oil. Waterflooding for gas is not very effective so using water for a gas field is not as used. Since the molecules of gas are so tiny, the recovery of gas is so much better to begin with.
https://onepetro.org/SPEATCE/proceedings/65FM/All-65FM/SPE-1240-MS/160269
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Thank you for the very interesting link. I imagine the technology has to some degree advanced since that article was written.
There are enhanced recovery techniques being tried in various reservoirs that would be considered “gas” wells, but it would need to be a reservoir with a significant liquid component to the gas. A “rich” gas or “wet” gas, which has the potential to leave liquid hydrocarbons (condensate) behind in the reservoir once depletion of the reservoir pressure starts changing how much of the heavy molecules stay in the gas form.
The type of reservoir also matters. A conventional gas field produced with vertical wells doesn’t have a lot more than primary recovery. An unconventional gas field with horizontal wells frequently has a rich gas component and a high likelihood of liquids getting stuck in the little tiny pores that make up these tight reservoirs.
My favorite method so far is “huff and puff” for these reservoirs and has shown promise in the Eagle Ford (fields with more communication between wells makes this harder, like high permeability Bakken or fractured Woodford). This method is where a light gas (methane or CO2) is pressurized and pumped down a depleted horizontal well, which causes the liquids to go back into gas form (theoretically) and then the same well is produced to get that now wet gas out of the well. Rinse and repeat (metaphorically). The compressors needed to do this scale of pressurizing are no joke (>$500k capital needed to customize one, at least a few years ago).
Finally, the reason waterflooding doesn’t work on conventional gas wells is A) gas depletion is one of the better recovery efficiencies to begin with because the molecules are so tiny and easy to move to the wellbore and can spread out so thinly when pressures get low, and B) the viscosity difference between water and gas is so high that the water would just form an instant tunnel through the reservoir and bypass any remaining gas. The best you could do for a high-value gas field is to sweep it with a dry, cheap gas in hopes to encourage the pentane molecules out of the reservoir by stuffing the pores full of methane molecules. NGL prices need to stay high for this 
But at that point, if you really wanted to do something with your old depleted gas field, you’d probably just look into turning the field into a CO2 storage field for those financial benefits (although CO2 can eat up wells with the wrong kinds of metal and parts, so, advanced planning is needed…).
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