American Oil and Gas Reporter - May 2017 - 50

SpecialReport: Market In Motion
trending northwest-to-southeast. As indicated by the arrows, in addition to injector I1, producers P1 and P2 are closely
connected with the I2 and I3 injectors. A
refined four-well pattern that excluded
the P1 and P2 wells was defined for the
pilot (panel B). The P3, P4 and P5 producers were expected to be mainly impacted injection in I1, although P3 did
get some of the CO2 injected in I2. The
P4 and P5 wells, which were shut-in for
most of the time because of their high
producing GORs, were re-opened about
two months before the pilot commenced.
Wellbore schematics of the I1 well
are shown in panel C in Figure 1. While
some junk at the bottom of the injection
well was initially impeding log acquisition
below 5,100 feet, the well was cleaned
just prior to implementing the pilot, enabling a log signal to be acquired down
to 5,150 feet. The total perforated net
pay at injector I1 is about 100 total feet
(60 feet for zone 1, 30 feet for zone 2
and eight feet for zone 3). Zones 1 and 3
were taking most of the injected CO2.
The main objective of foam was to divert
CO2 injected in the I1 well from the
bottom reservoir zone (zone 3) to the top
(zone 1) and middle (zone 2) zones. Intra-zone diversion also was targeted.
To distinguish between the effects of
the foam and water used to inject the surfactant, the injection well was converted
to WAG mode for six months, one year
prior to starting the foam pilot. A total of
11 WAG cycles consisting of one week of

water injection followed by one week of
CO2 injection were carried out. The water
injection flow rate was in the 3,000 bbl/d
range. Overall, WAG injection translated
to reducing CO2 injectivity by a factor of
two after each water slug for only few
days, no marked impact on GOR or oil
rate, and increased water production.
A surfactant-alternated-gas injection
scheme was selected to inject surfactant
equivalent to 1 percent of the pattern
pore volume, with relatively short cycle
times to avoid any gravity segregation
between the surfactant solution and CO2
slug injection. It was initially planned to
carry out three injection cycles, each injecting 15,000 barrels of surfactant at 0.5
weight percent in brine followed by
75,000 Mcf of CO2. On average, this
corresponded to five days of surfactant
injection followed by 7.5 days of gas injection, reducing gas injectivity by a
factor of 1.5 during foam injection.
Except for the first cycle, the actual
injection was quite different from the
initial plans as the effort was made to
adapt to reservoir response in order to
maximize foam efficiency, and CO2 injectivity was more impacted by foam
than initially expected. Figure 2 shows
the schedule for all three surfactant injection cycles, covering a period of one
year that starts two months prior to first
slug injection. The CO2 slug following
the first surfactant slug lasted 10 days,
the CO2 slug following the second surfactant slug lasted 21 days, and the pattern

FTP (psi)

FIGURE 2
Injection and Production Data During Foam Injection Pilot
2,000
1,500
1,000
500
300

250

35,000

CO2 Injection

30,000
25,000

200

20,000

150

15,000

100

10,000

50
0

5,000
0

50
First slug

100

150

End third slug

Days

50 THE AMERICAN OIL & GAS REPORTER

200

250

300

350

0

CO2 Injection (Mcf)

Oil (bbl/d); GOR (Mcf/bbl)

GOR

Oil

went back to continuous CO2 injection
after the third surfactant slug.
CO2 Injectivity
The impact of the foam was observed
both in injection logs and on CO2 flow
rates and injection pressures. A strong
decrease in CO2 injectivity is indicative
of foam formation in the near-wellbore
area, and successive injectivity drops
after each surfactant slug also is indicative
of foam propagation away from the wellbore.
Three injection logs were acquired in
injector I1 during the pilot. They are
plotted at the left-hand side of Figure 3)
along with the reference log acquired
just before the first surfactant slug (shown
in red). The logs show that flow was already reduced in the bottom of zone 3
and increased in zone 1 right after injecting
the second surfactant slug (grey). The
opening of new paths in zone 2 also was
observed after injecting the third slug
(green). At right in Figure 3 is the reference
log acquired before starting the pilot
versus the final log after injecting the
third slug. Diversion from zone 3 to zone
1, and the opening of paths in zone 2
after foam injection, are clearly visible,
as indicated by changes between the two
injection profile logs.
A strong decrease in injection pressure
was observed during first water slug injection. This is normal as the aqueous solution replaces gas in the near-wellbore
area. For CO2, injection pressure flowing
tubing pressure increased 20 percent after
each surfactant slug. Foam induces a strong
decrease in CO2 injectivity, indicative of
significant reduction in CO2 mobility, with
an increasing impact after each slug.
After injecting the first surfactant slug,
injectivity decreased to 40 percent of the
value measured prior to starting the pilot.
Within 10 days, injectivity had returned
to close to the baseline. This was rather
short for two reasons: most surfactant
was consumed by adsorption while injecting the first slug, and there was not
much water in the near-wellbore area
previously flooded with straight CO2.
Overall, the first slug had the same injectivity impact as the 10 WAG cycles.
After the second surfactant slug, injectivity was 25 percent of the baseline
and remained 30 percent lower than prefoam value after three weeks. After the
third slug, injectivity was as low as 15
percent of the baseline, ramping up to
the baseline value in 60 days. With the
exception of the first "sacrificial" slug,



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