American Oil and Gas Reporter - May 2017 - 49

SpecialReport: Market In Motion

Foam Enhances CO2 EOR Performance
By David D'Souza
James Cochran,
Max Chabert,
and Eric Delamaide
HOUSTON-Using foam for conformance control in enhanced oil recovery
projects has the potential to not only improve oil rates, but also to increase gas
injection efficiency and reduce gas injection and cycling costs.
A dedicated foaming formulation was
developed for a Denbury Resources-operated Gulf Coast field undergoing continuous carbon dioxide injection. The
foam injection pilot was carried out on
an existing 40-acre pattern where premature breakthrough had resulted in high
gas-to-oil ratios and reduced oil rates.
The goal of injecting surfactant was to
generate foam in-situ in the near-wellbore
area to optimize pattern performance.
Continuous CO2 injection has several
advantages over CO2 water-alternatinggas (WAG) injection, especially in strongly
water-wet reservoirs. However, a significant
problem with continuous CO2 injection is
poor sweep efficiency when flooding multiple distinct sands with significant permeability variations. Premature gas breakthrough and high GORs result in an inefficient flood and diminished oil recovery.
This explains why the macroscopic efficiency of CO2 injection was limited in the
field, despite the excellent microscopic
efficiency of CO2 to unlock oil trapped by
capillarity during waterflooding.
The multilayered sandstone reservoirs
are open in several sands in the injectors
and producers, and are grossly divided
in three main zones. The foam pilot
sought to divert CO2 from a "thief zone"
to the other zones by generating stable
CO2 in water foam in the offending zone.
It was expected that this would result in
more efficient CO2 utilization and lower
GORs (i.e., lower produced gas rates
with stable or higher oil rates). Indeed,
foam injection is a proven method to improve CO2 flood conformance and increase
CO2 efficiency. Compared with mechanical
or gel treatments, foam is relatively inexpensive and easy to apply with minimal
risk of reservoir damage.
Because the pilot targeted conformance
rather than in-depth mobility control, a
relatively low foam volume (1 percent of
the pattern's pore volume) was injected.

The treatment was applied as three alternating slugs of aqueous foaming solution
and CO2 over a period of four months.
Formulation Design
One of the main challenges to successfully implementing the pilot was designing an adapted foaming formulation
using an extremely high-salinity and hard
produced water for chemical injection
(sodium concentrations as high as 78.6
grams per liter, and total dissolved solids
to 317 grams/liter). In addition, water
salinity across the field varies depending
on the configuration of producing wells.
Extreme values correspond to saturated
brine with possible salt precipitation at
surface conditions.
This challenge was overcome based
on successive steps in laboratory experimentation, including automated solubility
evaluating multicomponent formulations,
adsorption measurements, foam stability
evaluation and core floods under actual
reservoir conditions. A specific "fasttrack" workflow combining simultaneous
bulk and porous media measurements
was applied. Five formulations of hydrocarbon-based surfactants were studied to
evaluate solubility in injection water at
ambient and reservoir temperatures, CO2
foam stability and life at reservoir pressure/temperature conditions, static adsorption and foam-induced mobility reduction in porous media.

Besides the technical performance of
the formulations, complementary data
also were considered, including determining optimal blend concentration for
easy handling, timing for blend dissolution
in injection water at surface conditions,
and blend emulsion risk assessment.
In preparing the formulation, the decision was made to mix the high-salinity,
hard produced water in a one-to-one ratio
with freshwater from a shallow well. The
selected surfactant represents the best
compromise between the lab-measured
performance indicators. It is soluble at
ambient temperature in salinities up to
1.5 times that of the injection water, and
at reservoir temperature (150 degrees
Fahrenheit with permeability and porosity
averaging 300 millidarcy and 28 percent
porosity, respectively) in injection water.
It foams well and gives a very stable,
dense and long-life CO2 foam.
The formulation also shows a classical
shear thinning behavior, with mobility reductions above 20 at velocities of 25
feet/day down to 10 at high near-wellbore
velocities of 150 feet/day. This was expected to favor near-wellbore foam injectivity, followed by longer-range propagation
at higher mobility reduction factors.
Pilot Implementation
The confined nine-well pattern chosen
for the pilot is shown in panel A in Figure
1. The pattern is limited by two faults

FIGURE 1
Original Injection Pattern (Left), Pilot Injection Pattern (Center)
And Injector I1 Wellbore Schematic (Right)

(A)

(B)

4,988 - 5,006'
4,996 - 5,000'
5,020 - 5,038'
5,052 - 5,074'

Zone 1

5,088 - 5,096'
5,112 - 5,118'
5,126 - 5,142'

Zone 2

5,152 - 5,160'

Zone 3

American Oil and Gas Reporter - May 2017

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