Experimental investigation of surfactant flooding in fractured limestones
| dc.contributor.advisor | Balhoff, Matthew T. | |
| dc.contributor.advisor | Pope, G. A. | |
| dc.creator | Mejia, Miguel, M.S. in Engineering | |
| dc.creator.orcid | 0000-0003-4914-7348 | |
| dc.date.accessioned | 2019-04-15T15:45:16Z | |
| dc.date.available | 2019-04-15T15:45:16Z | |
| dc.date.created | 2018-12 | |
| dc.date.issued | 2018-12-06 | |
| dc.date.submitted | December 2018 | |
| dc.date.updated | 2019-04-15T15:45:16Z | |
| dc.description.abstract | Carbonates are important candidates for enhanced oil recovery, but recovering oil from oil-wet fractured carbonate reservoirs is challenging. Waterflooding bypasses the rock matrix and recovers little oil. Chemical enhanced oil recovery using surfactants increases oil recovery by lowering the interfacial tension, changing the wettability, and generating viscous microemulsions that improve mobility control. Seven Texas Cream Limestone cores with a permeability of 15-30 md were fractured and saturated with 100% oil. The cores were aged for one week at 78 C to make them oil-wet. The fracture permeability was adjusted so that it was 10,000 times higher than the rock matrix by changing the confining stress. Waterflooding recovered an average of 6.5% of the original oil in place with an oil cut of less than 2% at the end of the waterfloods. Aqueous surfactant-alkali solution was injected after each waterflood. All of the surfactant floods produced oil cuts of more than 25% soon after injection started. Surfactant slugs of 3 PV, 1 PV and 0.3 PV followed by brine drives recovered 45, 44, and 30% of the remaining oil after the waterfloods. The 1 PV and 0.3 PV slug sizes were more efficient in terms of oil recovered for a given mass of injected surfactant. In both cases, a high salinity surfactant solution was injected to produce a viscous microemulsion in-situ. The viscous microemulsion increased oil recovery by promoting crossflow and improving mobility control. Low surfactant retention is vital for the economics of surfactant floods. The experiments show that using sodium hydroxide caused surfactant retention to be very low in fractured limestone cores. The average surfactant retention was 0.17 mg/g-rock. Decreasing the flow rate increased the oil recovery at a given injected pore volume. Thus changing practical design variables (salinity, surfactant slug size, flow rate) has a significant effect on oil recovery. | |
| dc.description.department | Petroleum and Geosystems Engineering | |
| dc.format.mimetype | application/pdf | |
| dc.identifier.uri | https://hdl.handle.net/2152/74286 | |
| dc.identifier.uri | http://dx.doi.org/10.26153/tsw/1408 | |
| dc.language.iso | en | |
| dc.subject | Fractured carbonates | |
| dc.subject | Enhanced oil recovery | |
| dc.subject | Surfactants | |
| dc.title | Experimental investigation of surfactant flooding in fractured limestones | |
| dc.type | Thesis | |
| dc.type.material | text | |
| thesis.degree.department | Petroleum and Geosystems Engineering | |
| thesis.degree.discipline | Petroleum Engineering | |
| thesis.degree.grantor | The University of Texas at Austin | |
| thesis.degree.level | Masters | |
| thesis.degree.name | Master of Science in Engineering |
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