The objective of this project is to increase effectiveness and viability of CO₂ mobility control using foaming systems, to minimize injectivity losses, and to model these mechanisms. 

Program
This project was in response to DOE's FY2001 solicitation DE-PS26-01NT41048, Development of Technologies and Capabilities for Developing Coal, Oil, and Gas Energy Resources.

New Mexico Petroleum Recovery Research Center, (PRRC)
New Mexico Institute of Mining and Technology
Socorro, NM

Results of previous work have been described in reports to DOE/NPTO, in papers presented to the Society of Petroleum Engineers, and in other conference proceedings and refereed publications. A comprehensive review of recent accomplishments can be obtained from DOE Annual and Final Project Reports and in over 40 publications on specific topics, including: injectivity, phase behavior and multiphase flow, pressure effects, mobility control and foam properties, selective mobility reduction, foam mechanisms, mixed surfactants and sacrificial agents, gravity drainage, imbibition, interfacial tension, field foam modeling and history matching, numerical methods, and CO₂ reservoir injection studies. The present project is concentrating on determining the mechanisms of adsorption and desorption of surfactants in a reservoir, the effects of reservoir conditions on surfactant solution - CO₂ foamability, and causes of injectivity changes in CO₂ injection systems.

Project Results
Parameters that have been tested for their effects on foam stability include: salinity, pH, surfactant concentration, surfactant structure (composition), temperature, pressure, rock type, rock composition, rock structure, and adsorption and desorption kinetics and equilibrium. Parameters that have been considered and tested for temporary versus permanent effects on injectivity and productivity in CO₂ IOR injections include: flow rate, contamination, dissolution, precipitation, and saturation.

Benefits
Project results will have significant consequences for the future of IOR. Parameters will be determined that will result in more efficient CO₂ flooding in heterogeneous reservoirs and will include the following benefits:

• Extending the life of the petroleum reservoir, maintaining or increasing employment, and increasing oil recovery.
• Expanded range of reservoirs amenable to CO₂ flooding
• Reduction of chemical cost: optimizing oil saturation tolerance of foam, decreasing primary foaming agent adsorption, and decreasing required primary foaming agent concentration.
• Delayed production of CO₂ and increased retention of CO₂ in the reservoir (sequestration),
• Improved injectivity of CO₂ and water,
• Improved CO₂ flooding predictions, and
• Decrease in the mobility of CO₂ during the alternate injection of brine and CO₂.

CO₂ flooding potential has been demonstrated in the US, particularly in the Permian Basin of west Texas and southeast New Mexico. Much of the research on CO₂ flooding can be applied to other gas flooding processes, such as hydrocarbon injection projects. Today over 300,000 bbl/day are produced by gas injection in the US that barely scratches the surface of the 351 billion barrels of remaining U.S. oil reserve. The potential recovery is at least one order of magnitude greater with moderate success in developing improved methods, expanding the use of existing technology, expanding market availability of CO₂, and sequestration incentives.

Project Summary
This project attempts to improve understanding of foaming agents and injectivity. Most of the study will be laboratory-related with supporting modeling and field liaison projects. The foam study includes the: 1) evaluation of hybrid foam systems (synergetic effects of multi-component systems), 2) evaluation of low-cost/higher performance systems, 3) development of transport and adsorption models, and 4) evaluation of mobility improvements for reservoirs with severe heterogeneities. The injectivity and related flow mechanisms study includes: 1) the review of field data to assess extent and causes of WAGIL, 2) laboratory tests to identify mechanisms, and 3) tests to determine the effects of permeability alteration, contamination, relative permeability, saturation, flow rate, stress, and other identified parameters. Modeling includes: 1) the determination of sweep mechanisms, 2) hybrid foam flow adsorption and transport, and 3) injectivity. Finally, optimizing the benefits of using public funds is being achieved by transferring to the public information of the discoveries and developments of this project through publications and presentations in public forums.

The following have been achieved:

• Identified properties that affect foaming agent adsorption, i.e.: rock type, surfactant type, surfactant concentration, co-surfactants, and sacrificial agents.
  Identified the synergistic effects on foam in dual chemical systems.
• Determined results affects of salinity, pH, surfactant concentration, cosurfactant combinations, temperature, and pressure on foam stability.
• Determining causes of injectivity reduction: contamination, fines migration, permeability changes, stress/pressure gradient, phase behavior, and flow rate with permeability changes resulting from dissolution and precipitations appears to be the only permanent change.

Despite favorable characteristics of CO₂ for IOR, CO₂ floods frequently experience poor sweep efficiency caused by gas fingering and gravity override, caused by reservoir heterogeneity, adverse mobility ratio, and low productivity caused by lower-than-expected injectivity. Poor sweep efficiency results from a high mobility ratio caused by the low viscosity of even high density CO₂ compared to that of water or oil. The effectiveness of water injection alternating with gas (WAG), a common process used for mobility control during CO₂ floods, is reduced by gravity segregation between water and CO₂ and amplified by permeability differences. Foaming agents introduced in the aqueous phase control mobility. However, costs incurred by the loss of chemicals to adsorption on reservoir rock often exclude this potentially beneficial option for many operators. 

The project seeks to develop systems with lower concentrations of good foaming agents that will reduce cost. These systems are derived using a sacrificial agent or a cosurfactant that shows synergistic improvements when mixed with the good foaming agents. As part of this work the adsorption of surfactants onto common reservoir minerals was studied. 

WAG process frequently reduce injectivity more than expected and the addition of mobility control agents inherently compounds this problem. Normally, improved mobility ratios will reduce injectivity, and for this purpose it is critical that we optimize the two effects together. Improved injectivity will also result from the lower chemical concentrations and through some of the synergistic improvements using the cosurfactant systems mentioned above. The high flow rates at near wellbore conditions have been considered as a cause of decreased injectivity. The gas expansion at and near the wellbore caused temperature reduction and it appears to have also caused damage with a significant reduction in production. 

(December 2004)
This project is nearing completion. The original completion date was September 27, 2004. A one-year no-cost extension to September 27, 2005 was granted. In addition to the original goal the extension is allowing for determination of surfactant sorption properties on five pure minerals common in reservoir rock. Over the years PRRC has work with DOE's pseudo-miscible reservoir simulator MASTER and with the extension a copy of PRRCs debugged version of MASTER with an additional routine for foam flooding will be a deliverable for this project.

Publications
Grigg, R.B.: "Improving CO₂ Efficiency for Recovering Oil in Heterogeneous Reservoirs," 1st, 2nd, and 3rd Annual Reports for DOE Contract No. DE-FG26-01BC15364, U.S. DOE (Nov. 2004) covering Sep. 28, 2001 - Sep. 27, 2004. (Jan. 2003, Nov. 2003, and Nov. 2004).

Grigg, R.B., Zeng, Z., and Bethapudi, L.V.: "Comparison of Non-Darcy Flow of CO₂ and N2 in a Carbonate Rock," SPE 89471, 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery, Tulsa, OK, Apr. 17-21. 

Zeng, Z., Grigg, R.B., and Gupta, D.B.: "Laboratory Investigation of Stress-Sensitivity of Non-Darcy Gas Flow Parameters," SPE 89431, 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery, Tulsa, OK, Apr. 17-21.

Zheng, Z, Grigg, R.B., and Ganda, S.: "Experimental Study of Overburden and Stress Influence on Non-Darcy Gas Flow in Dakota Sandstone," SPE 84069, SPE Annual Technical Conference and Exhibition held in Denver, CO, Oct. 5 - 8, 2003.

Grigg, R.B, and Svec, R.K.: "CO-Injected CO₂-Brine Interactions with Indiana Limestone," SCA 2003-19, International Symposium of the Society of Core Analysts, Pau, France, Sep. 21-24, 2003. 

Grigg, R.B., McPherson, B.J., and Svec, R.K.: "Laboratory and Model Tests at Reservoir Conditions for CO₂-Brine-Carbonate Rock Systems Interactions," The Second Annual DOE Carbon Sequestration Conference, May 5-8, 2003, Washington, D.C.

Wellman, T.P., Grigg, R.B., McPherson, B.J., Svec, R.K., and Lichtner, P.C.: "Evaluation of CO₂-Brine-Reservoir Rock Interaction with Laboratory Flow Tests and Reactive Transport Modeling," SPE 80228, International Symposium on Oilfield Chemistry, Houston, TX, Feb. 5-8, 2003.

Grigg, R.B., Bai, B., and Liu, Y.: "Competitive Adsorption of a Hybrid Surfactant System onto Five Minerals, Berea Sandstone, and Limestone," SPE 90612 2004 SPE Annual Technical Conference and Exhibition, Houston, TX, Sep. 26-29. 

Grigg, R.B., and Bai, B.: "Calcium Lignosulfonate adsorption and desorption on Berea sandstone," Journal of Colloid and Interface Science, 279 (2004) 36-45.

Grigg, R.B., Tsau, J-S., and Martin, F.D.: "Cost Reduction and Injectivity Improvements for CO₂ Foams for Mobility Control," SPE 75178, 2002 SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, Apr. 13-17.

$999,947

$499,974 (33% of total)

NETL - Paul West (paul.westr@netl.doe.gov or 918-699-2035)
PRRC NMT - Reid Grigg (reid@prrc.nmt.edu or 505-835-5403)