| dc.description.abstract | The complexity of the shale system coupled with the mystery of low fracturing fluid recovery has puzzled many researchers. Field reports from hydraulic fracturing operations performed on shale formations have highlighted the low recovery of the fracturing fluid. Despite the low recovery observed in field reports, neither the fate nor the impact of these trapped fluids is well-understood. The shale membrane behavior was observed in the drilling operations and the application of low salinity water flooding. Therefore, first objective was to incorporate chemical osmosis in the modeling of hydraulic fracture cleanup which could better simulate the physical phenomena and might resolve the enigma of the impact of the elongated shut-in time on the well performance. The combination of the large surface area, the mild reactive nature of shale and the massive trapped volume of fracturing fluids raises a question on the impact that geochemical interactions have on load recovery, well performance and reservoir characteristics, which was the second objective of this study. The third objective was the development and implementation of an experimental workflow to investigate the impact of fluid salinity and rock mineralogy on the spontaneous imbibition of slick water. Quantifying the formation strength loss due to water soaking was also investigated.
In this study, a reservoir simulator capable of simulating the chemical osmosis and the concentration gradient driven flow is used to mimic the hydraulic fracture cleanup stage along with well performance. The significance of the chemical osmosis on load recovery and the salinity of the produced water is pointed out by simulating the same model with and without the osmotic flow. Sensitivity analysis for the effect of membrane efficiency, salinity contrast between the fracturing fluid and the formation brine, the reservoir temperature, natural fracture spacing, organic volume and shut-in time on load and gas recovery is reported along with the relevancy factor of every parameter.
For the Geochemical Coupling, a fit-for-purpose model is built where a hydraulic fracture stage is modelled using LG-LR-DK model. The initial conditions are simulated by injecting the fracturing fluid, then shutting-in the well to allow the fluids to be soaked into the formation. Different relative permeability sets are used for high and low salinity water since the fluid’s mobility is affected by its salinity. Actual connate water composition from Haynesville shale is used to study the impact of connate composition on geochemical coupling. The formation mineralogy and fracturing fluid composition impact on gas and load recovery is investigated.
The introduction of the oxygenated, low salinity, fracturing fluid to a reducing environment would definitely catalyze both precipitation and dissolution reactions depending on the formation mineralogy. The dissolution and precipitation rates show a positive correlation with the carbonate content of the rock. Interestingly, the incorporation of the dependence of relative permeability on ion exchange and fluid salinity might reveal the fate of the fracturing fluid. Overestimation of both gas and load recovery is observed when geochemical coupling is neglected. In addition, sea water shows an enhanced performance suggesting a good alternative fracturing fluid. In addition, better performance is observed for less saline connate water cases. The carbonates reactions outweigh the clays reactions in most cases. Also, treating carbonates as only calcite results in more reactions compared to the dolomite case. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and illite and calcite mineral content of the rock, along with the reservoir temperature are the main key factors affecting well performance. It is worth noting that the salinity contrast between the injected fluid and the formation brine shows a negative correlation with well performance.
Regarding the Experimental Investigation, Samples from Woodford and Caney outcrops in the Unites States of America were obtained. Spontaneous imbibition, contact angle and interfacial tension measurements were conducted for these samples using slickwater with an added KCl weight percentage of 0, 5, and 10. Both the rock-water-gas and the rock-water-oil systems were examined. The formation softening was quantified by recording the rock mechanical parameters before and after the imbibition and soaking tests. The results were analyzed in terms of the capillary suction characteristics for each formation.
According to the experimental results, a positive relationship was observed between water salinity and imbibition in Caney formation. However, the opposite was observed for Woodford samples. The formation mineralogy was identified to be the major factor in this surprising reversal of wettability. Similar trends were observed for the recovery of both oil and gas where the low salinity imbibition yielded a higher recovery factor for the Caney formation samples and a lower recovery factor for Woodford. In addition, the formation softening results suggest that water salinity and formation mineralogy should both be considered in the selection of the proper fracturing fluid. Interestingly, the high the salt content the water had, the more softening was observed in Woodford samples and the less softening in Caney formation. This study provides insights into the water dynamics in ultra-low permeability reservoirs. The formation mineralogy is a key factor for properly describing the water dynamics whether in fracturing treatments or in low salinity flooding projects. The low salinity flooding does not always imply better hydrocarbon recovery, as we observed in carbonates-rich samples. The wetting characteristics are directly related to the capillary suction and clay content.
In conclusion, the incorporation of the geochemical coupling and Chemical Osmosis in simulating fracturing fluid dynamics, and their impact on load recovery and well performance, is essential. Careful selection of a fracturing fluid optimized for specific formation mineralogy will enhance well performance | en_US |
