American Oil and Gas Reporter - June 2014 - 102

SpecialReport: Artificial Lift Technology
tool, total fluid production rate divided
by porosity thickness (phi-h) can highlight
potential problems. Wells over 150 are at
high risk for conformance issues, while
normal wells fall between 50 and 150.
Treatment Design
Polymer gel treatment designs have
evolved over the six years Kinder Morgan
has been putting gel into the SACROC
Unit. Early treatments pumped around
2007 varied significantly well to well,
but generally involved 500-1,000 barrels
of 3,500-4,000 parts per million polymer
to establish injection, followed by 5,0008,000 barrels of 5,500 ppm polymer for
increased volume. The design standard
has evolved to eliminate the 3,500-4,000
ppm stage, with the assumption that wells
unable to take 5,500 ppm gel are not expected to have conformance issues.
The 5,500 ppm stage also has been
capped to 5,000 barrels in exchange for
higher volumes of 7,000 ppm, which is
expected to handle the pressure drop
better than lower-concentration gels. Treatment design calls for a tail-in slug of
30,000 ppm gel, which produces an extremely rigid gel that acts to hold the
entire treatment in place.
Testing of the SACROC supply water
indicated that medium molecular-weight
polymer yielded higher ultimate gel

strength versus high molecular-weight
polymer. This is primarily the result of
better hydration characteristics. Since it
is easier to use and cost effective, it has
become the standard for polymer treatment
designs at SACROC.
This becomes extremely important
with the pressure drop seen in the formation from injector to producer. The final
30,000 ppm stage polymer molecular
weight (MW) varies from a single MW
gel to a mixed MW gel system. Early
treatment designs were derived from tertiary oil recoveries that were less than
expected. These wells did not show the
severe interwell connections seen in the
Platform area of the field. These connections have driven the aggressiveness of
the treatment design.
Timing Of Treatments
While conformance treatments implemented after CO2 activation have been
positive, recent results show pre-CO2 activation treatments generally perform better. The Platform 1 (P1) project area was
activated without screening for conformance issues highlighted during waterflooding. Figure 3 shows the P1 manifold
production rates with vertical flags indicating when polymer gel conformance
work was performed in the project.
The fast CO2 breakthrough required

FIGURE 3
Platform 1 Manifold with Polymer Jobs Flagged
100,000

reactionary treatments in many pattern
injectors. These treatments broke through
to offset producers and required production
to be shut in until the treatments had
been completed. Shutting down these established CO2 flow paths proved difficult
and costly in a few extreme cases.
Well 34-7A in the P1 area has taken
59,036 barrels of polymer gel and has
seen wellhead pressure response, but was
ineffective and CO2 injection continued
to show a direct connection to an offset
producer. This well took 2,300 sacks of
cement to slow this nonmatrix flow feature.
In response to these issues, the Platform
2 (P2) project area was screened for conformance concerns and proactive, preactivation treatments were performed. A
map of the project areas outlined is also
shown in Figure 2, east of the P1 area.
P1 Results
The P1 project area was activated to
CO2 without treating potential conformance issues. The oil production was
quickly outpaced by CO2 production,
causing the GOR to increase 200 percent
in only a few months (Figure 3). The
GOR was rising rapidly in the time between a cumulative recovery of 700,000
and 1.0 million barrels, but the trend was
reversed because of the polymer work
done during the same period.
Seven polymer gel jobs were pumped
totaling more than 113,600 barrels of
polymer gel. The effect of these treatments
was to reduce the GOR from 30 to 20

29 Total Treatments: 384,600 bbls polymer gel

Oil (bbls)/Gas-Oil Ratio (scf/bbl)

7 Treatments: 113,600 bbls polymer gel

FIGURE 4
Platform 1 Channel Map

10,000

GOR (scf/bbl)

7 treatment increment oil:
770,000 bbls
7 treatment incremental cost:
$1.88 per barrel oil
Total project polymer cost:
$0.39 per barrel oil

Oil (bbls)

1,000
10,000
Aug 2009

100,000
Nov 2009

1,000,000
July 2010
Cumulative Oil (bbl)

102 THE AMERICAN OIL & GAS REPORTER

5,000,000 10,000,000
Dec 2011 Aug 2013

Producer
Injector
Polymer Treated Well

American Oil and Gas Reporter - June 2014

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