Laboratory Investigation of Low-Tension-Gas Flooding for Improved Oil Recovery in Tight Formations
- Stefan M. Szlendak (University of Texas at Austin) | Nhut M. Nguyen (University of Texas at Austin) | Quoc P. Nguyen (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- August 2013
- Document Type
- Journal Paper
- 851 - 866
- 2013. Society of Petroleum Engineers
- 5.8.7 Carbonate Reservoir, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.1 Waterflooding, 5.6.5 Tracers, 5.2.1 Phase Behavior and PVT Measurements
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This paper establishes low-tension gas (LTG) as a method for submiscibletertiary recovery in tight sandstone and carbonate reservoirs. The LTG processinvolves the use of surfactant and gas to mobilize and then displace residualcrude after waterflood at greatly reduced oil/water interface tension (IFT).This method allows extending surfactant enhanced oil recovery (EOR) insub-20-mD formations in which polymer is impractical because of plugging,shear, or the requirement to use a low-molecular-weight polymer.
The proposed strategy is tested through the coinjection of nitrogen and aslug/drive surfactant solution. Results indicate favorable mobilization anddisplacement of residual crude oil in both tight-carbonate and tight-sandstonereservoirs. Tertiary recovery of 75-90% of residual oil in place (ROIP) wasachieved for cores with 2- to 15-mD permeability. High LTG tertiary recovery iscontrasted with results from reference surfactant (no gas) flooding (28% ROIPtertiary recovery) and immiscible gas coinjection (no surfactant) flooding (13%ROIP tertiary recovery). In addition, high initial oil saturation was tested todetermine the process tolerance to oil and to evaluate the potential forapplication during secondary recovery. Under such conditions, this methodachieved recovery of 84% of oil originally in place (OOIP), suggesting thepotential application of this process at secondary recovery.
To better understand the physical mechanisms that affect mobilization anddisplacement, the early production of an elongated oil bank at reducedfractional flow of oil was shown to be an attribute of high crude-oil relativemobility and low pore volume (PV) available to mobile oil. This shouldfavorably affect economics during chemical flooding by accelerating productionof an oil bank. Next, by application of salinity as a conservative tracer andoil material balance, gas saturation during LTG floods was calculated to be 18to 22%. By comparing effluent salinity profiles across floods, a qualitativeunderstanding of in-situ fluid dispersion associated with macroscopicdisplacement stability is developed. The results indicate that in-situ foamingwas present, which enabled mobility control, and that stable displacement ofin-situ fluids was achieved during flooding.
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