Improved Gas Flooding Efficiency
The objectives of this study are to acquire the information to develop adsorption/desorption models for reservoir rock at reservoir conditions, determine economic sweep efficiency and injectivity criteria for reservoir scale systems, expand foam gas flooding to shallow reservoirs, and develop models and modules for simulating carbon dioxide flooding mechanisms. This work will be based on laboratory tests, supplemented with modeling, to determine practical information for designing gas foam systems for a wide range of reservoir types.
New Mexico Institute of Mining and Technology, Petroleum Recovery Research Center, Socorro, NM
Among the major accomplishments to date, researchers have:
- Designed, set up, and performed tests on a large, high-pressure, high-temperature coreflood apparatus. Tests have been completed for surfactant adsorption and desorption with and without oil saturation, mobility changes due to foam, and using both nitrogen and carbon dioxide as injection gases all at reservoir conditions. Researchers also determined oil effects on mobility changes, identified critical gas fraction flow, and identified relative efficiencies of injection modes.
- Determined rate of adsorption versus available system surfactant for crushed rock, whole core flow systems, and whole core diffusion systems with two rock types and a range of surfactant concentrations. From these parameters, adsorption and desorption rates are being determined versus flow behavior and available surfactant.
- Begun ascertaining the rate of gas saturation reduction versus saturation of flowing brine and developing predictions of injectivity change due to gas saturation in water-alternating-gas projects.
Research in this project will benefit efforts to improve oil recovery, thus extending the life of petroleum reservoirs and adding to U.S. oil reserves through cost-effective and environmentally attractive means. Benefits to the Nation include maintaining or increasing employment, enhancing government revenues, bolstering energy security, and potentially sequestering greenhouse gases.
Project results will significantly benefit the future of gas injection enhanced oil recovery by:
- Reducing surfactant cost.
- Expanding CO2 flooding to low-pressure reservoirs.
- Delaying production of CO2 and/or increasing retention of CO2 in geologic formations.
- Improving injectivity predictions of CO2 and water.
- Enhancing CO2 flooding predictions.
- Decreasing CO2 mobility.
After primary and secondary oil recovery, two-thirds of the original oil in place in the United States remains unrecovered. The application of advanced IOR technologies can increase recovery. Among the available IOR methods, CO2 flooding has both the greatest promise for additional oil recovery and the potential to economically support carbon management goals of the United States. This is the only IOR method that has experienced a steady increase in projects and oil production over the last 2 decades. However, the current status of CO2 flooding technology is not satisfactory. Many floods display poor sweep efficiency and/or inadequate injectivity, and other reservoirs are not considered because they are too shallow or too heterogeneous. This work addresses improving sweep while minimizing injectivity reduction and examining improvements that can be used on shallow reservoirs.
Project tasks are as follows:
Reservoir Condition Foam Tests. Large core samples are being used to estimate occurrences under reservoir conditions. Because of the time constraints for each test, two large coreflooding systems are in operation. Bulk saturation, injectivity, fluid recovery, and porosity and permeability changes are being determined for each test. Ongoing tests using limestone cores have been completed, showing results for nitrogen and carbon dioxide (Fig. 1). The nitrogen results were previously reported. The CO2 tests included oil saturation. The foam flow tests were performed at reservoir conditions by injecting gas (N2 or CO2) and aqueous solution (with or without surfactant). All tests reported here were performed at reservoir conditions of 104 °F (40 °C) and 1,500 psia (10.34 MPa) at a constant injection gas flow rate. The foam quality (fg) is the injected volume fraction of gas compared with the total injected fluid volume. In these tests, the gas-injected flow rate was constant and the total flow rate was adjusted by changing the aqueous phase injection rate. The first figure compares results from N2 in limestone and CO2 in sandstone. There are differences in the critical fg (fg*), where the mobility values switch trends from decreasing to increasing with increasing gas ratio changes. The changes can be due to several factors, such as gas type, core type, core permeability, and surfactant concentration. The critical foam quality aids in determining the slug ratios when alternating between aqueous phase and gas injection.
Surfactant Adsorption. A number of adsorption/desorption kinetics/equilibrium tests have been performed on sandstone and carbonate samples. This work is establishing mechanisms that can be used to model reservoir adsorption and desorption. Values of CD adsorption density on crushed limestone were similar to non-flow solid limestone cubes, but both were higher than the flow system adsorption (Fig. 2). For sandstone, the crushed rock had lower adsorption than did the non-flow solid cubes, but crushed rock had similar adsorption density to the flow system. The dominant parameter in describing adsorption in all systems is surfactant availability (mass of surfactant available per mass of solid) in the system. The time required for adsorption to reach equilibrium in the non-flow core was an order of magnitude greater compared with the flow experiment in the core and three orders of magnitude greater compared with the crushed rock. Thus the rate of adsorption is dependent on the availability of surfactant and flow conditions, with the kinetics and equilibrium being rapid in comparison once reaching the rock surface. The results should be considered when determining reservoir adsorption requirements and rates. The mathematically complete format of pseudo-first- and second-order adsorption and desorption models has been derived. A simple non-linear optimization method has been adapted to determine the parameters of the adsorption and desorption models. The sorption processes of surfactant onto/from Berea sandstone have been found to follow second-order adsorption and first-order desorption models, respectively.
Injectivity Changes. In examining causes of injectivity changes in CO2 floods, several causes have emerged as being likely. The predominant cause seems to be saturation changes, especially near the injection well. Laboratory tests on three reservoir rocks (Frio sandstone, West Pearl Queen sandstone, and Indiana limestone) show gas breakthrough and minimal additional brine production with a gas saturation of 20-40 percent, depending on the core type, permeability, and flow rate. In each case, injectivity was decreased when the test switched to brine injection, compared with the original brine injection before gas injection. In two of the three core materials tested, CO2 gas saturation remained essentially unchanged through displacement. The flowing brine bypassed the gas saturation, with the only produced gas being from gas dissolved in the brine as it displaced brine in the core. In the third system, which also had the highest gas saturation (~40 percent), the gas saturation was reduced to about 30 percent; then no additional gas was displaced, and again the only production was from gas in solution. These results have significant ramifications in understanding long-term changes in injectivity near the wellbore in CO2 enhanced oil recovery operations and gas storage in greenhouse gas injection for sequestration.
Current Status (December 2008)
This project has been completed and the final report is listed below under "Additional Information".
This project was selected in response to DOE’s Oil Exploration and Production solicitation DE-PS26-04NT15450-3F in 2004.
Project Start: April 1, 2005
Project End: September 30, 2007
Anticipated DOE Contribution: $800,000
Performer Contribution: $400,000 (33 percent of total)
NETL - Chandra Nautiyal (firstname.lastname@example.org or 918-699-2021)
New Mexico Petroleum Recovery Research Center - Reid Grigg (email@example.com or 505-835-5403)
Final Project Report [PDF]
Grigg, R.B. and Svec, R.K., “CO2 Transport Mechanisms in CO2/Brine Coreflooding,” SPE 103228, paper presented at the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, TX, September 24-27.
Zeng, Z-W., Grigg, R.B., and Bai, B. “Experimental Development of Adsorption and Desorption Kinetics of CO2-Foaming Surfactant onto Berea Sandstone,” SPE 103117, paper presented at the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, TX, September 24-27.
Grigg, R.B. and Svec, R.K., “Laboratory and Model Tests at Reservoir Conditions for CO2-Brine-Carbonate Rock Systems Interactions,” paper presented at 2006 DOE Carbon Sequestration Conference, Washington, D.C., May 8-11.
Liu. Y., Grigg, R.B., and Svec, R.K., “Foam Mobility and Adsorption in Carbonate Core,” SPE 99756, paper presented at the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, April 22–26.
Zeng, Z-W. and Grigg, R., “A Criterion for Non-Darcy Flow in Porous Media,” Transport in Porous Media (2006) 63: pp. 57-69.
Bai, B., Grigg, R.B., Liu, Y., and Zeng, Z-W., “Adsorption and Desorption of a CO2-Foam-Forming Surfactant onto Berea Sandstone,” SPE 95920, paper presented at the 2005 SPE Annual Technical Conference and Exhibition, Dallas, TX, October 9–12.
Grigg, R.B., et al., “CO2/Brine/Carbonate Rock Interactions: Dissolution and Precipitation,” paper presented at the 2005 Conference on Carbon Capture and Sequestration, Alexandria, VA, May 2–5.
Liu, Y., Grigg, R.B., and Svec, R.K., “CO2 Foam Behavior: Influence of Temperature, Pressure, and Concentration of Surfactant,” 94307, paper presented at the 2005 SPE Production and Operations Symposium, Oklahoma City, OK, April 17-19.
Figure 1. Mobility of flowing solution versus volume fractional flow of gas at reservoir conditions of 1,500 psia and 104 °F. This is on a 2-in. diameter, 5-in. long core. Values are shown for segments and the whole core for N2 and for two different cores for CO2. The difference between N2 and CO2 could well be attributable to the core type and permeability as well as to gas type.
Figure 2. Comparison of CD adsorption density for crushed limestone and flow-through limestone core tests.
High-pressure, high-temperature coreflooding apparatus to test foaming systems at reservoir conditions with reservoir core.
Researcher stands next to equipment to determine surfactant concentration of injection fluid before and after contact porous media.