American Oil and Gas Reporter - June 2014 - 100

SpecialReport: Artificial Lift Technology
attempted within the SACROC Unit included polymer gel, cement squeeze,
crystallized polymer squeeze (polycrystalline), and various mechanical methods
of isolation. The mechanical methods
(straddle packer assembly, cemented liner,
expandable liner) can be successful with
vertical conformance when the flow unit(s)
or zone is sufficiently flooded out, assuming cement integrity is good behind
the production casing.
Crystallized polymer squeezes have
been the least effective, generating the
most marginal change in oil and gas production. Historical polymer gel treatments
generally were small volume, ramping
up concentration quickly and finishing
with or without pressure responses at
volumes between 5,000 and 10,000 barrels. These treatments usually put CO2
in contact with unflooded matrix near
the wellbore, but the injected CO2 would
return very quickly to the nonmatrix
flow feature, and GOR would return to
high levels.
Historical cement squeezes were small
volume (fewer than 300 sacks) and
achieved little more success than a mechanical isolation method, showing no
significant increase in sweep efficiency.
Currently, cement squeezes for conformance are used only in cases where CO2
breakthrough has been verified across an
injector-producer pair over a period of
hours or days.
These jobs normally are 500-1,200
sacks of cement pumped over multiple
days, with the first 500 sacks pumped
away on a vacuum and allowed to set up
before adding more cement the next day.
This method has been successful in shutting down direct channels in multiplepattern injectors, allowing CO2 flooding
to resume.
The method of choice for conformance
control at SACROC is large volumes of
Cr(III)-carboxylate/acrylamide-polymer
(CC/AP) gels. These are aqueous-based
gels in which acrylamide polymers are
cross-linked chemically with a Cr(III)carboxylate-complex cross-linking agent
in a single fluid (Sydansk, 2000).
Polymer gel has been used for decades
in a variety of formations and situations.
Gel's ability to set up and reduce permeability has been confirmed in the laboratory, using crushed carbonate porous
media (Taabbodi, 2004). The porous
medium had more than 10 Darcies of
permeability prior to injecting four pore
volumes of gel solution, after which per-

the polymer gel breaking through, requiring producer(s) to be shut in.
Current candidate selection looks at
historical injection profiles and premature
water production during waterflood. Radioactive tracer surveys have been run in
injection wells for decades at SACROC
to determine zone(s) of water and CO2
entry. This allowed problem wells with
injection profiles showing dominant injection intervals to be identified during
waterflooding.

FIGURE 2
Platform Map

Producer
Injector
Polymer Treated Well

2,759
Feet

meability to CO2 was reduced by a factor
of 1,500.
Candidate Selection
Candidate well selection criteria can
vary based on the operating environment
of the field. A decade of experience with
the CC/AP gel technology and treatments
(Sydansk, 2000) has concluded that good
injection well candidates for gel treatments
are characterized by having:
* Early injectant breakthrough;
* Excess injection capacity;
* Substantial movable oil saturation
within the well pattern; and
* Unexpectedly low oil recovery within the well pattern.
Good production well candidates for
gel treatments are characterized by having:
* A high water-to-oil or gas-to-oil
ratio;
* High producing fluid levels in the
wellbore;
* Excessive competing water or gas
co-production;
* A substantial movable oil saturation
within the well pattern;
* Unexpectedly low oil recovery; and
* Early water or gas breakthrough.
Well selection criteria for SACROC
conformance treatments typically have
been based on premature CO2 production.
Pattern injectors would be activated to
CO2, and if breakthrough occurred in
offset producing wells within days or
weeks, the injector would be treated with
polymer gel. This frequently results in

100 THE AMERICAN OIL & GAS REPORTER

Candidate Evaluation
Another important tool is an injection
step rate test, which is designed primarily
to calculate an injectivity index in barrels
per day per psi (bpd/psi), but also provides
an estimate of reservoir pressure in a 48
hour shut-in. In certain tests, near wellbore
skin and perforation friction also can be
determined on shutdown.
Any well with a calculated injectivity
index greater than 20 bpd/psi is expected
to be a problem with regard to channeling.
Wells between 10 and 20 should be investigated further, and wells under 10
are not expected to cause problems. As
an example, when the well 27-5A shown
in Figure 2 was used to inject water prior
to CO2, a step rate test revealed its injectivity index to be 83. This well was immediately treated with polymer gel and
the injectivity index was reduced to 22.
Acid stimulation rates and pressures
are utilized to evaluate newly drilled injectors for potential issues. Prime candidates are wells with zones treating more
than four barrels per minute (bpm) at
less than 500 psi, and that drop to zero
pressure instantly at shut-in.
One such example is the proposed
WAG injector 18-3A in the Platform 3
South (P3S) project area. The LMC treated
at an average six bpm and 500 psi with
an instantaneous shut-in pressure (ISIP)
of zero psi. The MCN3 area treated at an
average six bpm and 200 psi with ISIP
of zero psi. The GZ treated at an average
six bpm and zero psi with ISIP of zero
psi. And the lower Cisco stage treated at
an average six bpm and zero psi with
ISIP of zero psi. These results strongly
suggested this well was a candidate for a
large polymer treatment, even before a
channeling problem had been identified.
Producing wells are treated frequently
for conformance issues. Some wells are
treated after CO2 breakthrough, while
others are screened using historical total
fluid production rates. As a screening

American Oil and Gas Reporter - June 2014

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