Page 371 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Enhanced Oil Recovery Methods 337

As shown earlier under “Nitrogen and Flue Gas Flooding,” the screening
criteria for flooding with nitrogen or flue gas are similar to those for the high
pressure gas drive. Pressure and depth requirements, as well as the need for a
very light oil, are even greater if full miscibility is to be realized in the reservoir.
The nitrogen and flue gas method is placed between hydrocarbon miscible
and CO, flooding because the process can also recover oil in the immiscible
mode. It can be economic because much of the reservoir space is filled with
low cost gas.
Because of the minimum pressure requirement, depth is an important screen-
ing criteria, and CO, floods are normally carried out in reservoirs that are more
than 2,000 ft deep. The oil composition is also important (see section on
“Carbon Dioxide Flooding”), and the API gravity exceeds 30” for most of the
active CO, floods [403]. A notable exception is the Lick Creek, Arkansas, Cod
waterflood project which was conducted successfully, not as a miscible project,
but as an immiscible displacement [404].
Criteria for Chemical Methods

For surfactant/polymer methods, oil viscosities of less than 30 cp are desired
so that adequate mobility control can be achieved. Good mobility control
is essential for this method to make maximum utilization of the expensive
chemicals. Oil saturations remaining after a waterflood should be more than
30% PV to ensure that sufficient oil is available for recovery. Sandstones are
preferred because carbonate reservoirs are heterogeneous, contain brines with
high divalent ion contents, and cause high adsorption of commonly used
surfactants. To ensure adequate injectivity, permeability should be greater than
20 md. Reservoir temperature should be less than 175°F to minimize degradation
of the presently available surfactants. A number of other limitations and
problems were mentioned earlier, including the general requirement for
low salinity and hardness for most of the commercially available systems.
Obviously, this method is very complex, expen-sive, and subject to a wide range
of problems. Most importantly, the available systems provide optimum reduc-
tion in interfacial tension over a very narrow salinity range. Pref lushes have
been used to attempt to provide optimum conditions, but they have often
been ineffective.
The screening guidelines and a description of polymer flooding are contained
earlier in Section “Polymer Flooding.” Since the objective of polymer flooding
is to improve the mobility ratio without necessarily making the ratio favorable,
the maximum oil viscosity for this method is 100 or possibly 150 cp. If oil
viscosities are very high, higher polymer concentrations are needed to achieve
the desired mobility control, and thermal methods may be more attractive. As
discussed earlier, polymer flooding will not ordinarily mobilize oil that has been
completely trapped by water; therefore, a mobile oil saturation of more than
10% is desired. In fact, a polymer flood is normally more effective when started
at low producing water-oil ratios [405]. Although sandstone reservoirs are usually
preferred, several large polymer floods have been conducted in carbonate
reservoirs. Lower-molecular-weight polymers can be used in reservoirs with
permeabilities as low as 10 md (and, in some carbonates, as low as 3 md). While
it is possible to manufacture even lower-molecular-weight polymers to inject into
lower permeability formations, the amount of viscosity generated per pound of
polymer would not be enough to make such products of interest. With current
polymers, reservoir temperature should be less than 200°F to minimize degrada-
tion; this requirement limits depths to about 9,000 ft. A potentially serious