American Oil and Gas Reporter - June 2014 - 86

SpecialReport: Artificial Lift Technology
FIGURE 4

Injection Scenario Results

Pressure Map of Middle Layer
After 20 Years of Immiscible Gas Injection

6,000

4,500

3,000
psi

The third model represented CO2 injection. An extension of
the black oil model, it consisted of four components: water, oil,
reservoir gas and solvent. It was based on the assumption of firstcontact miscibility between the hydrocarbon components and CO2.
Displacement was dominated mainly by a miscible regime because reservoir pressure did not fall below bubble-point pressure
and was maintained near or above thermodynamic minimum miscibility pressure (3,100 psi).
For all three models, gas was injected using the same four wells
(A1, B2, B3 and A6, with the remaining six wells serving as producers) and the same bottom-hole pressure constraint target value (6,000 psi).

FIGURE 6

FIGURE 5
Oil Saturation after Miscible Gas Injection

Sector Production Rates
(Primary and Three Injection Scenarios)
1,200
0.75

0.57

0.39

Rate (STB/D)

In the first scenario (injecting an immiscible produced gas composition that was not allowed to dissolve back into the oil phase),
the gas saturations increased near the injection wells and pressure increased significantly (Figure 4). Daily injection rates ranged
between 80 Mcf and 225 Mcf, and the total amount of gas injected was 3.78 x 106 Mcf, equal to 0.054 of the pore volume (PV).
This injection scenario showed increased recovery from all six
production wells a few months after starting injection. However, the increase was minor and held steady for the 20 years of injection. This is because immiscible injection only provided pressure support to the reservoir and did not initiate any oil displacement benefits (i.e., an oil bank was not formed and residual saturations were not reduced). Even so, the 6.02 percent calculated recovery factor during primary recovery was more than doubled to 13.3 percent with immiscible gas injection.
In the second scenario (injecting a hydrocarbon gas that was
miscible with the reservoir oil), injection rates ranged between
150 Mcf/d and 600 Mcf/d, accumulating a total PV of 0.18. The
production rates from all six horizontal producers increased one
to two months after initiating injection. The highest field production rate occurred after five years of injection at 678 bbl/d, and
the cumulative recovery at the end of 20 years was 4.26 million
barrels.
The recovery factor was calculated at 21.3 percent, or 15.3 percent higher than during primary production. Solvent breakthrough
occurred after 3.6 years of injection. Figure 5 shows that the oil
saturation is much lower in this scenario than with immiscible
gas. The miscibility allows the displacement mechanism to reduce the residual oil saturation, which translates to higher production rates, better sweep and greater cumulative recovery.

1,000
800
600
400
200
0
0

2,000 4,000 6,000 8,000 10,000

0.21

0.03

86 THE AMERICAN OIL & GAS REPORTER

Time (Days)
Immisc. Gas Injection

Solvent Injection

Misc. Gas Injection

Primary Recovery

American Oil and Gas Reporter - June 2014

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