American Oil and Gas Reporter - June 2014 - 99

SpecialReport: Artificial Lift Technology

Gel Treatments Fix Conformance Issues
By James W. Pipes
and Lanny Schoeling
HOUSTON-Large polymer gel treatments at the SACROC miscible carbon
dioxide flood in Scurry County, Tx., have
proven successful in improving sweep
efficiency and plugging channels between
wells. These treatments have reduced
gas-to-oil production ratios and have reduced CO2 utilization ratios, thus extending
the economic life of SACROC for many
years.
As a result of these treatments, Kinder
Morgan CO2 has increased flooding of
significant bypassed pay and unprocessed
reservoir volume that conventional techniques may have missed, leaving significant oil reserves in place.
Reservoirs with conformance problems
can be addressed in various ways. These
methods are characterized as mechanical
(in the wellbore), near wellbore, and/or
in-depth treatments in the reservoir. All
these methods have been utilized in
SACROC with varying degrees of success.
The most long-term success has come
through large-volume polymer gel treatments, which plug high-permeability
channels and conduits, and divert injected
CO2 to unswept portions of the reservoir.
These treatments generally involve injecting 20,000 barrels or more of polymer
gel consisting of chromium cross-linked
medium and high-molecular-weight polyacrylate polymer. Gel concentrations typically increase from 5,000 parts per million
at the start to as much as 12,000 ppm in
the later stages. One of the keys to the
success of these treatments is a final,
tail-in stage of very high concentration
polymer (>30,000 ppm), or even cement
in certain cases, to prevent near-wellbore
gel from breaking down when the well is
returned to injection or production.
In short, we have concluded that improving CO2 utilization is most effective
with large volume treatments. Additionally,
maximum benefit is realized when the
treatments are implemented prior to injecting CO2 in a new set of patterns.
SACROC Unit
The SACROC Unit is the largest operating unit in the Kelly-Snyder Field,
located on the eastern side of a 120-mile
sinuous chain of Pennsylvanian-aged carbonate reef buildup fields known as the

Horseshoe Atoll in West Texas. The
50,000-acre field was discovered in 1948,
and has an estimated 2.8 billion barrels
original oil in place. Gross reservoir thickness varies from 200 feet in the south to
roughly 900 feet in the northern part of
the unit in a project area named the Platform. The limestone matrix has an average
7.6 percent porosity and 19 milliDarcy
permeability.
Figure 1 shows the reef complex is
divided into four major, distinctly different
zones: Cisco, Green Zone (GZ), Middle
Canyon 3 (MCN3), and Lower Middle
Canyon (LMC).
Average porosity and matrix permeability vary significantly across the zones,
with the GZ containing the highest matrix
permeabilites, although matrix permeability is not the issue. The GZ frequently
FIGURE 1
Typical Canyon Reef Log

Cisco: Moderate Matrix
permeability. Unconnected
fractures result in fast processing
rates in some areas. Porosity
lenses not well connected.

Green Zone: Thick and continuous
with good matrix permeability.
Characterized by nonmatrix flow
features that short circuit sweep
through the matrix.

MCN3: High permeability matrix,
good continuity, excellent sweep.

Lower Middle Canyon: Layered
and continuous. Low porosity and
matrix permeability.

* Gamma ray curve on left (0-100)
* Neutron porosity on right (-0.1-0.3)

contains nonmatrix flow features and
very high conductivity channels, which
result in breakthrough within days or
weeks of starting CO2 injection.
In these areas of rapid breakthrough,
early breakthrough does not always occur
in the nearest producing wells and has
been observed two or more well locations
away. These features commonly appear
on injection profiles at the contact between
two of the 21 flow units in the reef.
During Pennsylvanian times, sea level
rose and fell many times, frequently exposing the reef to erosion and weathering
on the surface of the flow units. These
flow features caused an imbalance to the
spread of water injection, and may have
been enhanced further by the large volume
of water cycled through them during the
decades of water injection.
These flow features have proven laterally extensive and appear in new wells
hundreds of feet from older wellbores.
Loss circulation material pumped during
drilling has shown up more than 1,500
feet away in an offset producing well,
clogging the intake screen and collecting
throughout the pump stages of an electric
submersible pump.
Another serious incident occurred when
the primary cement job from the production
casing of a newly drilled injector showed
up in an offset producer and clogged the
flowline headed to the separation manifold.
These examples illustrate the severity of
the voids contained in the nonmatrix flow
features treated with large-volume polymer
gel treatments.
Conformance Issues
While all the problems are not this
extreme, many patterns activated to CO2
will show early-stage elevated GORs. If
left untreated, this would result in the
early introduction of water from wateralternating-gas (WAG) injection and a
low ultimate recovery because of bad
vertical conformance and bypassed pay.
Conformance issues will exist not only
in the vertical plane, but also areally.
The mobility differences among oil,
water and gas resulting from differences
in viscosity cause CO2 to move through
the formation too quickly, limiting areal
sweep before the CO2 has broken through
on the direct path from injector to producer.
Prior methods of conformance control
JUNE 2014 99

American Oil and Gas Reporter - June 2014

Table of Contents for the Digital Edition of American Oil and Gas Reporter - June 2014