The Role of Microemulsion and Shut-in on Well Performance: From Field Scale to Laboratory Scale
- Taregh Soleiman Asl (University of Alberta) | Ali Habibi (University of Alberta) | Obinna Daniel Ezulike (University of Alberta) | Maryam Eghbalvala (University of Alberta) | Hassan Dehghanpour (University of Alberta)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference and Exhibition, 5-7 February, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 5.7.2 Recovery Factors, 1.6.6 Directional Drilling, 1.6 Drilling Operations, 4.3.4 Scale, 5.7 Reserves Evaluation, 5 Reservoir Desciption & Dynamics, 5.8.2 Shale Gas, 1.6.9 Coring, Fishing
- shut-in period, flowback process, leak-off process, Fracturing fluid
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We analyzed flowback and post-flowback production data from a horizontal well in the Montney Formation, which was fractured with water containing a microemulsion additive. This well was shut-in for 7 months after 5 months of post-flowback production. Oil and gas rates were significantly increased after the shut-in (700% increase), suggesting a reduction in matrix-fracture damage. We performed imbibition oil-recovery tests to evaluate the imbibition of the ME solution into the oil-saturated core plugs. The results show that the microemulsion solution can spontaneously imbibe into the oil-saturated core plugs leading to the final oil recovery factor of 24% of the original oil in place, compared with the tap water case with only 2% oil recovery factor. Combined analyses of the field and laboratory results suggest that imbibition of the fracturing water containing the ME solution during the extended shut-in period leads to 1) reduction of water blockage near the fracture face and 2) counter-current production of oil. These two effects can explain the enhanced production rate of oil and gas after the shut-in period.
|File Size||1 MB||Number of Pages||13|
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