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Coupling Alkaline-Surfactant-Polymer Technology and Gelation Technology to Maximize Incremental Oil Production
Project Number

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.

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.


Surtek, Inc 
Golden, CO


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.

Project Results
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.

Project Summary
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
Project End
DOE Contribution


Performer Contribution

$50,000 (25% of Total)

Contact Information

NETL - Sue Mehlhoff ( or 918-699-2044)
Surtek - Malcolm Pitts ( or 303-278-0877)