American Oil and Gas Reporter - June 2023 - 45

The best method is to size the treatment as a percent of the
movable pore volume in the channel. Once the channel volume
is determined, a decision must be made regarding how much of
the channel's volume to fill with gel. With a small volume, it
may be economically feasible to fill the entire channel. If the
channel volume is large, it may not be economically viable to
fill the entire channel; typically, a percentage is considered. Experience
suggests that " bigger is better. "
Bulk gels usually are processed and injected using mobile or
portable process system plants, including all chemical process
subsystems and the primary injection pumps combined into a
single, integrated mobile facility.
Monitoring the treatment during application is at least as important
as planning, sizing and designing the treatment. Each
formation may respond differently than expected to the treatment,
and decisions must be made in the field to alter the treatment as
necessary in response to the reservoir. These changes may
involve pumping a smaller or larger treatment, increasing or decreasing
the chemical concentrations, changing the pump rate,
or even shutting off producers.
North Slope Case Study
The Kuparuk River Field on the Alaska North Slope is a structural-stratigraphic
trap consisting of two productive sands: Sand
A with low permeability and the high-permeability C sand. The
field has more than 1,100 wells under waterflood and miscible or
immiscible water-alternating-gas. Extensive faulting and drastic
permeability distribution in the C sand has resulted in severed
communication between injectors and their offset producers, instigating
high water production and low sweep efficiency.
Injector Well I-1 initially was drilled as a single wellbore,
completed to inject into the Kuparuk C sand. To increase the injectivity
and support the offset production, two sidetracks were
completed later in the C4, C2 and C1 sands. After sidetracks, the
average injectivity of this well was about six barrels a day per psi
and at times showed as high as 11 bbl/d per psi while the field average
for similar wells was one-five bbl/d per psi.
Quick communication between this injector and its offset producers
was confirmed by immediate gas breakthrough to the
offsets during miscible gas injection. An interwell tracer study
also showed 30.2% of the injected tracer at injector I-1 recovered
in three offset producers in 16-22 days, indicating quick communication
through highly conductive features/faults.
A polymer gel conformance treatment
was recommended to address the communication
and improve the oil recovery
in this pattern. Use of high-molecular
weight cross-linked polymer was specifically
suggested to avoid penetration into
the matrix with lower permeability. Roughly
20,000 barrels of high-molecular-weight
polymer was injected in stages from 3,000
to 10,000 ppm at a 40-to-1 polymer-tocross-linker
ratio. The injectivity was reduced
from 7.0 bb/d to 1.3 bbl/d per psi
during the treatment (Figure 1).
The polymer gel was placed in the
high-permeability feature responsible for
high water production, quick gas breakthrough
and low sweep efficiency in this
pattern without damaging the low-permeability
rock. The conformance treatment
had an immediate impact on the injectivity
of injector I-1, indicating the injection
fluid was being diverted onto unswept
areas of the reservoir (Figure 2). Increased
2,400
2,200
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
Cumulative bbls Injected
JUNE 2023 45
delay in gas breakthrough and increase in oil production (Figure
3) proves that the means of communication was addressed.
In summary, polymer gel conformance treatment resulted in
total incremental oil of 460,000 barrels at an effective incremental
rate of 630 bbl/d for the pattern. Incremental oil production had
to be corrected for the time that injector I-1 was down until it
returned to normal injection. A temporary decline in the trend
of incremental oil production can be observed, which is due to
a lack of miscible gas injection in the pad.
West Texas Case Study
A cross-linked polymer gel solution also was applied in one
of the first waterfloods in a West Texas carbonate reservoir. The
field was discovered in 1953, and because of low original
pressure, was put on waterflood in 1956. The field produces
from the naturally fractured Permian-age Grayburg carbonate,
with a starting depth of 4,700 feet and a maximum pay of 150
feet. The average porosity is 12% and the permeability ranges
from less than 1 milliDarcy to over 1 Darcy, resulting in a
Dykstra Parsons factor of 0.82. This reservoir heterogeneity resulted
in lower-than-expected waterflood recovery factors in
some areas of the field.
The customer identified a significant number of waterflood
patterns that suffered from severe communication between
injectors and their offset producers. High water production and
poor sweep efficiency led to greater operating costs and lower
oil production.
Based on the geological information and waterflood communication
analysis using injection/production data, a crosslinked
polymer gel solution was recommended to correct the
rapid water channeling through fractures and high-permeability
streaks. It was determined the MARCIT polymer gel system
would be optimal based on reservoir temperature and the
injection water total dissolved solids. The gel is made up of a
medium molecular weight, partially hydrolyzed polyacrylamide
and a cross-linker, which are mixed on the surface using
specialty equipment and then injected down hole.
The reaction rate is delayed sufficiently to allow for
placement of the gel in the reservoir. Between 2001 and 2006,
24 injectors were treated in four phases using an average gel
volume of 16,550 barrels of gel polymer per well with concentrations
ranging from 1,500 to 10,000 ppm. Each injection
well had an individual gel volume design based off the
FIGURE 4
Job Log from Permian Grayburg Conformance Treatment
Inj. Rate (BPD)
BHP (psi)
WHP (psi)
Polymer Conc. (ppm)
9,000
10,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
Inj. Rate (bpd) & Pressure (psi)
4,000
3,000
2,000
1,000
5,000
9,000
8,000
7,000
6,000
10,000
14,000
13,000
12,000
11,000
15,000
19,000
18,000
17,000
16,000
20,000
22,000
21,000
Polymer Conc. (ppm)
American Oil and Gas Reporter - June 2023

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