Oil & Natural Gas Projects
Exploration and Production Technologies
Coupling Alkaline-Surfactant-Polymer Technology and Gelation Technology
to Maximize Incremental Oil Production
This project was selected in response to DOE solicitation DE- PS26-01NT41613
(August 22, 2003). The objective of the Oil Technology section of this solicitation
was to develop methods to improve oil recovery.
The project goal was to investigate whether the alkaline-surfactant-polymer
(ASP) technology and gelation technologies can be combined to increase the applicability
of ASP flooding to fractured reservoirs or reservoirs with high-capacity zones.
Gelation technologies that could be mixed with ASP solutions to improve conformance
and sweep efficiency were identified. The compatibility of the candidate gelation
technologies were determined by monitoring gel and ASP solution properties and
stability over time. Corefloods of the mixtures were performed to determine
their effectiveness in mobilizing oil. The gel systems tested were found not
to be stable in mixtures with ASP solutions and did not improve oil recovery.
The combination of gelation technology and ASP technology could enable increased
production from fractured reservoirs and those reservoirs with high-permeability
zones that channel injected fluids.
Gelation technologies provide more-efficient vertical sweep efficiencies for
flooding naturally fractured oil reservoirs or more-efficient areal sweep efficiency
for those with high-permeability thief zones. The field-proven ASP technology
economically recovers 15% to 25% more oil of the original-oil-in-place than
waterflooding alone in the swept pore space of an oil reservoir. However, ASP
technology is not amenable to the naturally fractured reservoirs or those with
thief zones, because much of the injected solution bypasses the target pore
space containing oil. The objective of this work was to investigate whether
combining these two technologies could broaden the applicability of ASP flooding.
The research was separated into two phases. Phase 1's objective was to identify
which gelation technologies can be used in conjunction with the ASP technology.
Initially, different gel systems will be mixed with ASP solutions to determine
compatibility. ASP solutions' pH, alkali concentration, and alkali type were
varied to define compatibility parameters for each gel system. Gel systems potentially
compatible with ASP solutions were used in linear corefloods to determine if
the gel systems are stable with dynamic flow over an extended period of time
at high rates. Radial corefloods were performed to estimate the volume of additional
oil that can be produced if a gelation technology is implemented-either preceding
or simultaneously with the ASP technology.
The Phase 2 objective was to apply knowledge gained in Phase 1 to actual field
applications and to estimate the volume of additional oil recovery that could
have been produced beyond the volume realized from the actual ASP floods. Numerical
simulation evaluations were performed to investigate the range of reservoir
properties for which coupling the gelation technology and ASP technology would
be beneficial. Economic analyses were made comparing coupling the gel and ASP
solutions with just an ASP flood.
The first milestone was to test the compatibility of different gel systems
with ASP solutions by monitoring gel and ASP solution properties and stability
over time. For those gel systems that are stable in an ASP solution, linear
corefloods were performed to determine if the gel was stable, as multiple pore
volumes of chemical are injected past the gel. Diversion of injection solutions
were demonstrated using artificially fractured radial cores, varied permeability,
stacked-core radial corefloods, and triple-core radial corefloods. Improved
incremental oil recovery rates were defined using stacked radial corefloods.
The second milestone was to evaluate past and current ASP floods and estimate
how much oil recovery could be improved by coupling the ASP technology with
a gelation technology. A more theoretical, parallel evaluation included reservoir
anomalies such as fractures and vugs. Two different reservoir model types were
developed: a dual-porosity (fractured) model and a lenticular multi-layer reservoir
with contrasting layer permeability. Properties of reservoir models were varied
to provide a range of reservoir properties and oil recovery performance to develop
the technology's economics. Economic analysis will be made for coupling gel
and ASP technologies to determine reservoir parameters justifying the technique.
Key findings of the project are:
- Linear corefloods showed that aluminum citrate-polyacrylamide, resorcinol-formaldehyde,
and the silicate-polyacrylamide gel systems did not produce significant incremental
oil. Both flowing and rigid-flowing chromium acetate-polyacrylamide gels and
the xanthan gum-chromium acetate gel system produced incremental oil, with the
rigid-flowing gel producing the greatest amount. However, higher oil recovery
could have been due to higher differential pressures across cores. None of the
gels tested appeared to alter ASP solution oil recovery. Total waterflood plus
chemical flood oil recovery sequence recoveries were all similar.
- Linear coreflood evaluations indicate that aluminum citrate-polyacrylamide
and silicate-polyacrylamide gels were not stable either to subsequent injection
of NaOH or to Na2CO3 ASP solutions. Both flowing and rigid-flowing chromium
acetate-polyacrylamide were stable to both ASP solutions. Rigid-flowing gel
maintained permeability reduction better than a flowing-gel system. Prior injection
of the different gel mixtures did not affect total oil recovery.
- Aluminum-polyacrylamide and iron-polyacrylamide gels were not stable to ASP
solutions, with pH values ranging from 9.2 to 12.6. Chromium-polyacrylamide,
chromium-xanthan gum, silicate-polyacrylamide, resorcinol-formaldehyde, and
sulfomethylated resorcinol-formaldehyde gels were stable to ASP solutions with
pH values ranging from 9.2 to 12.6. Chromium-polyacrylamide gels with a high
polymer-to-chromium ion ratio of 25 or greater were not stable with ASP solutions
greater than 10.6. Stability evaluations consisted of layering ASP solutions
over formed gels. Stability of gel to flowing alkaline.
Current Status (September 2005)
The project is in the final stages of completion.
Semi-annual and technical reports are available from NETL, 918-699-2000.
Project Start: September 29, 2003
Project End: September 28, 2005
Anticipated DOE Contribution: $200,000
Performer Contribution: $50,000 (25% of Total)
NETL - Sue Mehlhoff (email@example.com or 918-699-2044)
Surtek - Malcolm Pitts (firstname.lastname@example.org or 303-278-0877)