A Systematic Laboratory Approach to Low-Cost, High-Performance Chemical Flooding
- Adam Flaaten (University of Texas at Austin) | Quoc P. Nguyen (University of Texas at Austin) | Gary A. Pope (University of Texas at Austin) | Jieyuan Zhang (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 2009
- Document Type
- Journal Paper
- 713 - 723
- 2009. Society of Petroleum Engineers
- 4 in the last 30 days
- 2,399 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive, and highly effective means to select the best chemicals and minimize the need for relatively expensive coreflood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, cosolvents, and alkalis with a particular crude oil and in reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in coreflood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in corefloods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how alkali-surfactant-polymer (ASP) flooding can be used in this case even with very hard saline brine.
Many mature reservoirs under waterflood have low economic production rates despite having as much as 50 to 75% of the original oil still in place. These reservoirs are viable candidates for chemical enhanced oil recovery (EOR) that uses both surfactant to reduce oil/water interfacial tension (IFT) and polymer to improve sweep efficiency. However, designing these aqueous chemical mixtures is complex and must be tailored to the reservoir rock and fluid (i.e., crude oil and formation brine) properties of the application. The early success of a systematic laboratory approach to low-cost, high performance chemical flooding depends on the efficiency of designing a formula for coreflood injection in accordance with sound evaluation criteria. A general, a three-stage procedure has been developed previously to screen hundreds of potential chemicals (i.e., surfactant, cosurfactant, cosolvent, alkali, polymer, and electrolytes), and arrive at a mixture having good recovery of residual oil in cores (Jackson 2006; Levitt 2006; Levitt et al. 2006). Additionally, furthering laboratory and field-testing in this area contributes to an expanding research database to help broaden reservoir types that can become candidates for routine chemical EOR application.
This paper describes a systematic laboratory approach to low cost, high performance chemical flooding, and explores novel approaches to ASP flooding in reservoirs containing very hard saline brines. The design strategy first uses microemulsion phase behavior experiments to quickly select and optimize concentrations of injected chemicals. Assessment of formula optimization strategies are carried out through varying surfactant-to-cosurfactant ratio, reducing cosolvent concentration, reducing total surfactant concentration, selecting a suitable alkali, and using formation brine in the injection mixture. Formulations performing well in phase behavior are validated in coreflood experiments that adhere to necessary design criteria such as pressure and salinity gradients, surfactant adsorption, and capillary effects.
We illustrate the application of our design approach in prepared Berea sandstone cores previously waterflooded with very hard saline brine, and show how ASP flooding can use some of the same brine in the chemical formulation. Conventional ASP flooding requires soft water that may not always be available, and softening hard brines can be very costly or infeasible in many cases depending on the location and other factors. These new results demonstrate high tolerance to both salinity and hardness of the high performance surfactants, and how novel alkalis--in particular sodium metaborate--can provide similar benefits in such harsh environments as sodium carbonate has shown in environments without divalent cations. This experimental success begins to vastly increase the range of conditions for economical EOR using chemicals.
|File Size||780 KB||Number of Pages||11|
Aoudia, M., Wade, W.H., and Weerasooriya, V. 1995. Optimum microemulsionsformulated with propoxylated tridecyl alcohol sodium sulfates. Journalof Dispersion Science and Technology 16 (2): 115-135.doi:10.1080/01932699508943664.
Bourrel, M. and Schechter, R.S. 1988. Microemulsions and Related Systems:Formulation, Solvency, and Physical Properties, Vol. 30. New York:Surfactant Science Series, Marcel Dekker.
Falls, A.H., Thigpen, D.R., Nelson, R.C., Ciaston, J.W., Lawson, J.B., Good,P.A., Ueber, R.C., and Shahin, G.T.1994. Field Test of Cosurfactant-EnhancedAlkaline Flooding. SPE Res Eng 9 (3): 217-223.SPE-24117-PA. doi: 10.2118/24117-PA.
Emeleus, H.J. and Sharpe, A.G., 1982. Advances in Inorganic Chemistry andRadiochemistry. New York City: Academic Press, 229.
Flaaten, A.K. 2007. Experimental Study of Microemulsion Characterization andOptimization in Enhanced Oil Recovery: A Design Approach for Reservoirs withHigh Salinity and Hardness. MS thesis, The University of Texas at Austin,Austin, Texas (December 2007).
Green, D.W. and Willhite, G.P. 1998. Enhanced Oil Recovery. TextbookSeries, SPE, Richardson, Texas 6.
Healy, R.N., Reed, R.L., and Stenmark, D.K. 1976. Multiphase Microemulsion Systems.SPE J. 16 (3): 147-160; Trans., AIME, 261.SPE-5565-PA. doi: 10.2118/5565-PA.
Hirasaki, G., Miller C.A., Pope, G.A., and Jackson, R.E. 2005. SurfactantBased Enhanced Oil Recovery and Foam Mobility Control. 2nd Annual TechnicalReport (July 2004-June 2005), Contract No. DE-FC26-03NT15406, US DOE,Washington, DC (July 2005).
Hirasaki, G.J. and Zhang, D.L. 2004. Surface Chemistry of Oil RecoveryFrom Fractured, Oil-Wet, Carbonate Formations. SPE J. 9(2): 151-162. SPE-88365-PA. doi: 10.2118/88365-PA.
Huh, C. 1979. Interfacial tensions andsolubilizing ability of a microemulsion phase that coexists with oil andbrine. Journal of Colloid and Interface Science 71 (2):408-426. doi:10.1016/0021-9797(79)90249-2.
Ingri, N. 1963. Equilibrium studies of polyanions containing BIII, SiIV,GeIV and VV. Svensk Kemisk Tidskrift 75: 199.
Jackson, A.C. 2006. Experimental Study of the Benefits of Sodium Carbonateon Surfactants for Enhanced Oil Recovery. MS thesis, The University of Texas atAustin, Austin, Texas (December 2006).
Labrid, J. 1991. The Use of Alkali Agents in Enhanced Oil RecoveryProcesses, Vol. 33. Rueil-Malmaison, France: Critical Reports on AppliedChemistry, IFP.
Lake, L.W. 1989. Enhanced Oil Recovery. Englewood Cliffs, New Jersey:Prentice Hall.
Levitt, D.B. 2006. Experimental evaluation of high performance EORsurfactants for a dolomite reservoir. MS thesis, University of Texas at Austin,Austin, Texas.
Levitt, D.B., Jackson, A.C., Heinson, C., Britton, L.N., Malik, T.,Dwarakanath, V., and Pope, G.E. 2006. Identification and Evaluation ofHigh-Performance EOR Surfactants. Paper SPE 100089 presented at SPE/DOESymposium on Improved Oil Recovery, Tulsa, 22-26 April. doi:10.2118/100089-MS.
Nelson, R.C. and Pope, G.A. 1978. Phase Relationships in ChemicalFlooding. SPE J. 18 (5): 325-338; Trans., AIME,265. SPE-6773-PA. doi: 10.2118/6773-PA.
Nelson, R.C., Lawson, J.B., Thigpen, D.R., and Stegemeier, G.L. 1984. Cosurfactant-Enhanced AlkalineFlooding. Paper SPE 12672 presented at the SPE Enhanced Oil RecoverySymposium, Tulsa, 15-18 April. doi: 10.2118/12672-MS.
Pope, G.A., Tsaur, K., Schechter, R.S., Wang, B. 1982. The Effect of Several Polymers on thePhase Behavior of Micellar Fluids. SPE J. 22 (6):816-830. SPE-8826-PA. doi: 10.2118/8826-PA.
Pope, G.A., Wang, B., and Tsaur, K. 1979. A Sensitivity Study ofMicellar/Polymer Flooding. SPE J. 19 (6): 357-368.SPE-7079-PA. doi: 10.2118/7079-PA.
Sanz, C.A. and Pope, G.A. 1995. Alcohol-Free Chemical Flooding: FromSurfactant Screening to Coreflood Design. Paper SPE 28956 presented at theSPE International Symposium on Oilfield Chemistry, San Antonio, Texas, USA,14-17 February. doi: 10.2118/28956-MS.
Sorbie, K.S. 1991. Polymer-Improved Oil Recovery. Glasgow, Scotland:Blackie & Son.
Stegemeier, G.L. 1976. Mechanisms of oil entrapment and mobilization inporous media. Proc., AIChE Symposium on Improved Oil Recovery bySurfactant and Polymer Flooding, Kansas City, Missouri, USA, 12-14 April,55-91.
Wellington, S.L. and Richardson, E.A. 1997. Low Surfactant Concentration EnhancedWaterflooding. SPE J. 2 (4): 389-405. SPE-30748-PA.doi: 10.2118/30748-PA.
Winsor, P.A. 1954. Solvent Properties of Amphiphilic Compounds.London: Butterworth's Scientific Publications.
Wreath, D.G. 1989. A Study of Polymer Flooding and Residual Oil Saturation.MS thesis, The University of Texas at Austin, Austin, Texas.
Zhang, D.L., Liu, S., Yan, W., Puerto, M., Hirasaki, G.J., and Miller, C.A.2006. Favorable Attributes ofAlkali-Surfactant-Polymer Flooding. Paper SPE 99744 presented at theSPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April. doi:10.2118/99744-MS.
Zhang, J., Nguyen, Q.P., Flaaten, A.K., and Pope, G.A. 2008. Mechanisms of Enhanced NaturalImbibition with Novel Chemicals. Paper SPE 113453 to be presented at theSPE/DOE Symposium on Improved Oil Recovery, Tulsa, 20-23 April. doi:10.2118/113453-MS.