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Gas flooding compared with huff-n-puff gas injection 145

(flooding) is 7.3%. These results show that the huff-n-puff does not perform
as well as the gas flooding or the primary depletion without any CO 2 injec-
tion. Several factors may contribute to this result. (1) From the paper, it
cannot be figured out whether all the four wells in the pattern are under
the huff-n-puff injection. If all the wells are not under huff-n-puff injection,
then the performance cannot be directly compared with the continuous
injection. (2) The soaking time of 1 month is too long in the case of
5 days of injection. In other words, the huff-n-puff is not optimized.
(3) The injected amount of CO 2 of 300 tons (or 5 days of injection) may
be too small. (4) This huff-n-puff injection has only one cycle. One of
the advantages of huff-n-puff injection is that it can have many cycles,
and even late cycles may contribute to gas recovery. But for a gas flooding
case, once the injected gas breaks through, addition recovery is significant, or
a significant recovery takes a long time. (5) The permeability of 18 mD may
be high for a gas reservoir so that huff-n-puff may not have the advantage.
Meng et al. (2017) conducted experiments to compare the liquid
condensate recovery from the two modes as well. They found that the
recovery from huff-n-puff was higher than that from gas flooding for the
same operation time.
From the above discussion, we may conclude that huff-n-puff gas injec-
tion should outperform gas flooding in shale and tight reservoirs, if the huff-
n-puff is well designed (optimized). In other words, for huff-n-puff to be
better than flooding, the huff-n-puff scheme (e.g., huff, puff, and soaking
times) needs to be optimized.

6.4 Field applications of gas flooding
In this section, four field cases of gas flooding are presented.

6.4.1 Gas flooding in Viewfield Bakken field, Saskatchewan
(Schmidt and Sekar, 2014)
In this project, immiscible continuous gas injection was carried out through
one central horizontal injection well (east-west orientation) that was
perpendicular to nine horizontal production wells (north-south orientation).
See Fig. 6.11. The pilot project covered 1280 acres and was developed on a
combination of 80-acre and 160-acre spacing. The wells were about 1 mile
long. The wells were multistage hydraulically fractured. The center injec-
tion well created a toe-to-heel injection pattern. The distances from the
injector to the nearest hydraulic fracture of each offset producer were almost