Abstract
There is still debate on how shutting fractured wells for a period of time can affect the well performance. In this study, we combined two approaches to better understand the effects of shut-in time on well performance. First, we analyzed flowback and post-flowback production data from a horizontal well drilled in the Montney Formation, which was fractured with water containing a microemulsion (ME) additive. After the shut-in time for 7 months, the oil and solution gas rates significantly increased by 750% and 671%, respectively. However, the free gas rate decreased by 95% in 65 days, before it started to build up again to exceed the values at the start of the production. Second, we performed a series of imbibition oil-recovery, dynamic liquid-liquid contact angle, and interfacial tension measurements to investigate how the interplay of (i) capillary suction and (ii) osmotic pressure affects oil production from core plugs during the counter-current imbibition tests. Combined analyses of field and laboratory results suggest that the increase in oil production rate after the shut-in period is due to combined effects of (i) free-gas dissolution into the oil (ii) capillary imbibition of fracturing water containing ME solution into the rock matrix driven by wettability alteration and osmotic pressure, and (iii) reduction in phase trapping near fracture face due to interfacial tension reduction.
Published Version
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