Capillary pressure (P c ) is one of the main factors governing the hydrocarbon distribution within a reservoir. Its determination usually requires expensive, time-consuming laboratory experiments on a restricted number of core samples, while the continuous P c profile of a well is practically derived from the nuclear-magnetic-resonance (NMR) downhole logging measurements. This paper presents a robust and inexpensive method of predicting the continuous P c profile of a well from rock models reconstructed using various well log data. The approach first generates a representative rock model for the formation at each given depth of interest. The rock model is constrained by formation parameters derived from the logging data and accounts for diagenetic processes such as compaction and precipitation of carbonate and clay minerals. Simulations of fluid flow and primary drainage are then performed on rock models to determine the P c curve and absolute permeability.To test and validate our modeling approach, we select 16 sandstone core samples from various geologic settings to perform laboratory measurements and numermical simulations. Rock models are reconstructed using the measured grain-size distributions and grain mineralogy from core samples. The drainage P c curves derived from rock models match well with laboratory measurements on the corresponding core samples, while P c curves converted from NMR T 2 distributions using the simple relationship of ξ = 2 T P c show differences in shape. Furthermore, the computed permeability of rock models show good agreement with the core permeability, mostly falling within the ± 2 times measurements. We have also applied the rock modeling technique to predict the continuous P c and permeability profiles of a well. Formation grain-size distribution and mineralogy at each depth are derived from downhole measurements and used to generate rock models. Generally, our computed permeability falls within the same order of magnitude as the measurements on core samples from the same depth. The simulated P c curves differ in shape from those converted from NMR T 2 distributions. However, in this case it is unknown which one represents the real P c curve due to the absence of laboratory core measurements.
The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracturing fluids just before fracture initiation. Because of the unique characteristics of shale formations-including low permeability, existence of microfractures, and sensitivity to contacting fluids-it is difficult to evaluate fluid flow with traditional laboratory methods. Nuclear Magnetic Resonance (NMR) technology has been explored to study the propagation of fracturing fluids inside shale cores before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), and injection pressure were evaluated.Based on experimental results, the leakoff rate inside the shale formation during the hydraulic fracturing treatment can be calculated using NMR technology. NMR confirmed that slickwater and a higher-viscosity fracturing fluid propagated into the larger pores and existing microfractures. Increasing the viscosity from 1 to 200 cP reduced the leakoff rate by 6.5 times. This reduction can significantly affect the shape of the fracture and the corresponding breakdown pressure. Leakoff rate increased 2.65 times by doubling the injection pressure because increasing the injection pressure also increases the communication among the pores, and may 'balloon' the large pores, or increase the microfracture density. Reactive fluids, such as HCl acid, show an infinite value of leakoff as they were found to break through the shale core, even in shale having low HCl solubility (less than 2 wt%).
The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracture fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of micro-fractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. NMR technology has been explored to study the propagation of fracture fluid inside shale core before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), injection pressure were evaluated. Based on experimental results, the volume of fracture fluid that propagated inside shale cores has a strong relationship with fluid viscosity, where increasing fluid viscosity reduced this volume. NMR confirmed that slickwater or a higher-viscosity fracture fluid did not propagate inside the small shale pores (less than 0.01 μm as an average estimation) but did propagate inside larger pores and inside the existing microfractures. High-viscosity fracturing fluid was only able to fill the larger shale pores, while slickwater fracture fluid filled the large pores and connected them to increase the microfracture density. This allows the slickwater fluid to break the shale formation with lower pressure and produce more complex fractures than high viscosity fluids. Reactive fluids, such as HCl acid solution, were also studied and found to leak into the shale core by increasing the contact time, even for shale with low HCl solubility (less than 2 wt%).
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