Impact of Imbibition Mechanism on Flowback Behavior: A Numerical Study

Abstract

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.

Numerical Investigation of Fracture Compressibility and Uncertainty on Water-Loss and Production Performance in Tight Oil Reservoirs

“…The parameters of complex fracture network formed after multi-stage fracturing along horizontal wells are unknown, so the typical values of other tight reservoirs [31,40] are assigned here as shown in Table 2. Hydraulic fractures are considered to be propped, while reactivated natural fractures with orthogonal distribution are considered to be un-propped [21]. Since the wellbore flow pressure is always higher than the bubble-point pressure during production, the oil-water two-phase flow can be considered in the simulation process.…”

“…Similarly, experimental data showed that the water imbibition capacity of tight shale was very low, even for hydrophilic rock samples [20]. Furthermore, it was difficult to explain the reason for low water recovery efficiency when the spontaneous capillary forces were absent in oil-wet tight rocks [21,22] or the wells were immediately cleaned up without shut-in. By analyzing the pressure transient data, natural fractures that re-opened during fracturing were apparently closed in subsequent production processes [23].…”

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

“…Indeed, improvements in hydrocarbon permeability have been observed in field operations after performing well shut-ins (Bertoncello et al, 2014). Furthermore, several studies have shown that well shut-ins after the hydraulic stimulation can dissipate the water into deeper regions of the formation rock (Almulhim et al, 2014;Bertoncello et al, 2014;Cheng, 2012;Dutta et al, 2014;Mahadevan and Sharma, 2005;Longoria et al, 2015). However, the efficacy of a well shut-in depends on the petrophysical properties of the reservoir and a recent laboratory study showed that some reservoir samples regain permeability to the hydrocarbon after a shut-in while others do not (Bostrom et al, 2014).…”

Flowback Fracture Closure: A Key Factor for Estimating Effective Pore-Volume

“…Li et al (2013) carried out simulation studies by varying several fracture parameters to develop a correlation between early gas production and the key fracture parameters in a shale reservoir. Similarly Almulhim et al (2014) carried out numerical studies on the impact of water imbibition on flowback behavior. Cheng (2012) found correlations between shut-in time and water production rate, gas production rate and water load recovery.…”

“…As such, the same average values (e.g. of compressibility) are conventionally assigned for all the porous media in the stimulated reservoir volume (Cheng, 2012;Li et al 2013;Almulhim et al, 2014). This can lead to misleading history-match and erroneous forecast when applied to field data.…”