American Oil and Gas Reporter - May 2017 - 51

SpecialReport: Market In Motion
FIGURE 3
All Injection Logs (Left) and Reference versus
Final Log (Right) Acquired During Pilot
10,0

Zone 2

Zone 3

20,0

Flow (%)

30,0

40,0

0,0

50,0

Zone 1
Before pilot - Reference

Immediately after 2nd surfactant slug
2 weeks after 2nd surfactant slug
2 weeks after 3rd surfactant slug

CO2 injectivity dropped during the first
days of injection and then recovered linearly with time after the second and third
surfactant slugs.
Foam quality as a function of injection
time (calculated as the quantity of gas
injected relative the total volume of surfactant slug and gas) increased with each
cycle. The second surfactant slug achieved
90 percent foam quality, while the third
cycle had 94 percent foam quality when
injectivity returned to the baseline value.
The successive decreases in initial CO2
injectivity after each supplementary cycle
can be interpreted as an increasing volume
of foam in the reservoir, with foam propagating away from the near-wellbore and
deeper into the reservoir.
When gas follows a surfactant slug,
wet foam is formed rapidly, with a 50
percent quality theoretically reached after
only a few days of CO2 injection. After
the initial wet foam formation, injected
CO2 progressively expands the foam and
increases its gas fraction (maximizing
injectivity loss). The gas finally dries out
the foam in the near-wellbore and flows
again as free gas. At the foam front, surfactant is missing as a result of adsorption
and foam cannot be regenerated. These
two effects explain the progressive increase
in injectivity over time.
Sustained Oil Production
Although less CO2 was injected, oil
production was sustained at a constant
rate during the duration of the pilot. This
translated into a higher CO2 efficiency
and a slight GOR decrease. However, a
marked decrease in oil production and a
strong increase in GOR was observed one
month after the end of foam effect on in-

Zone 2

Zone 3

4,991
4,998
5,002
5,006
5,020
5,038
5,052
5,074
5,088
5,092
5,096
5,112
5,118
5,126
5,142
5,154
5,156

5,0

Depth (ft)

0,0

Depth (ft)

Zone 1

4,991
4,998
5,002
5,006
5,020
5,038
5,052
5,074
5,088
5,092
5,096
5,112
5,118
5,126
5,142
5,154
5,156

jection, suggesting that foam was instrumental in maintaining the level of oil production while minimizing the amount of
CO2 utilized, especially for the P3 and P4
producing wells that were closed because
of high GORs after the pilot. No significant
change in water production was observed
compared with prepilot values, with rates
maintained around 200 bbl/d.
Overall, the 20 percent increase in injection pressure could not compensate
for the strong injectivity decline of CO2
in the presence of foam. Therefore, much
less CO2 was injected, and observing a
constant oil rate in these conditions is a
sign of foam efficiency to divert CO2 toward poorly swept reservoir zones.
Figure 4 shows data for the three producing wells in the pattern from before
the first surfactant slug injection ("start
DAVID D'SOUZA is reservoir engineering advisor for Denbury Resources
in Plano, Tx. He has 26 years of experience and has worked on CO2 floods
in the Gulf Coast and Permian Basin.
He holds a B.E. in petroleum engineering
and an M.S. in petroleum engineering
from the University of Wyoming.
JAMES COCHRAN is a senior pro-

duction foreman with Denbury Resources. He has been with Denbury for
20 years, and was instrumental in the
operational setup of the Gulf Coast
CO2 foam field test.
MAX CHABERT is senior project
manager at Solvay. Since joining Solvay
in 2008, he has been involved in designing chemical EOR solutions for

10,0

15,0

20,0

Flow (%)

25,0

30,0

35,0

40,0

Before pilot - Reference
2 weeks after 3rd surfactant slug

foam") to the end of the third slug ("stop
foam") and the end of the foam's effect
on injector I1 ("end of effect").
The foam's positive impact is clear on
the P3 well, with GOR divided by nearly
four and the oil rate more than doubled
during foam injection and sustained for a
long period after the pilot. A positive
GOR impact also was observed on P4 in
the post-foam injection period, with a
rather constant oil rate. On P5, a strong
GOR increase and oil rate decrease was
observed when the foam's effect on I1
vanished. This well was shut before the
pilot, and one can infer that foam was instrumental in maintaining its production
at an acceptable GOR and oil rate.
Overall, the pilot project illustrates
how foam can be used as a straightforward, low-risk conformance method. Avwettability alteration and foam applications. Chabert heads the technical
platform on foam EOR for Solvay and
EOR Alliance partners. He holds an
M.S. in engineering from ESPCI in
Paris and a Ph.D. in liquid physics
from Paris 6 University.
ERIC DELAMAIDE is general manager of IFP Technologies (Canada) Inc.
in Calgary. He also is manager for
EOR in the Americas for the EOR Alliance. With 25 years of reservoir engineering experience, Delamaide has
worked on EOR and heavy oil projects
in 24 countries. He holds a B.S. in
chemical engineering from the School
of Mines in Saint Etienne, and an M.S.
in petroleum engineering from the IFP
School.
MAY 2017 51



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