Impact of Imbibition Mechanism on Flowback Behavior: A Numerical Study
- Abdulraof Almulhim (Colorado School of Mines) | Najeeb Alharthy (Colorado School of Mines) | Azra Nur Tutuncu (Colorado School of Mines) | Hossein Kazemi (Colorado School of Mines)
- Document ID
- Society of Petroleum Engineers
- Abu Dhabi International Petroleum Exhibition and Conference, 10-13 November, Abu Dhabi, UAE
- Publication Date
- Document Type
- Conference Paper
- 2014. Society of Petroleum Engineers
- Hydraulic Fracturing, Imbibition, Flowback, Water-based fracturing fluid, slick water
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- 392 since 2007
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Horizontal drilling and multi-stage hydraulic fracturing are among key technologies that enable the oil and gas industry to unlock unconventional resources. Water-based fracturing fluids are commonly used in massive volumes to hydraulically crack shale formations and transport proppant to keep open the newly created fractures. After hydraulic fracturing implemented to stimulate a well, the clean-up process takes place by flowing back the well. Most shale reservoirs tend to trap and retain the fracturing fluid (water) in the small pores and microfractures ending with a water flowback which typically not exceeding 50% of the injected volume. The water imbibition mechanism by capillary forces can help explaining the reason behind the retained water in the shale matrix and the dynamic water saturation re-distribution during the shut-in time.
This paper investigates various effects, such as rock wettability, well shut-in time, capillary pressure and natural fracture intensity on the flowback behavior and the ultimate production performance. The specific emphasize was given on brine imbibition as a vehicle to improve gas permeability and the overall gas recovery. It was shown that spontaneous capillary imbibition in strong water-wet formations forces water into the matrix and eliminate water blockage in the fractures while in weak water-wet formations, more water stays in the fractures causing a delay in gas production.
After stimulating a well with hydraulic fracturing, the clean-up process takes place by flowing back the well. Most shale reservoirs behave as “under saturated with respect to water” and trap the fracturing fluid in the small pores and microfractures ending with a low water load recovery that ranges from 5 to 50% (King, 2012). The mechanism of water imbibition by spontaneous capillary forces could explain the retained water into shale matrix (Cheng, 2012; King, 2012; Fakcharoenphol et al., 2013). Moreover, the increase in natural fracture width during stimulation followed by the decrease during production could trap the fracturing water in these closed fractures (Ehlig-Economides et al., 2012). When the spontaneous capillary forces are absent in an oil-wet formation, the low water load recovery and imbibition of water into shale formation could be attributed to osmotic pressure that is caused by salinity difference between formation and fracturing water; shale formation can act as a semi-permable membrane that allows water molecules to transport from low-salinity fracturing water into high-salinity formation water creating the osmotic pressure that retains some water in shale formation to reach equilibrium as schematically presented in Figure 1 (Fakcharoenphol et al., 2013).
A field observation in a Marcellus shale gas well shows the impact of the shut-in period on water production rate, gas production rate and water load recovery (Cheng, 2012). After a short period of flowback, the well was shut-in for almost 6 months then re-opened to flow. The shut-in period indicated a significant increase in gas rate and a decrease in water rate as shown in Figure 2. The mechanism of water imbibition driven by capillary and/or osmotic pressure could explain the dynamic water saturation redistribution during shut-in period that could increase gas rate and decrease water rate after an extended shut-in period and provide a credible explanation of the low water load recovery.
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