Quantitative Analysis of Proppant-Formation Interactions by Digital Rock Methods

Abstract

Abstract Understanding the mechanisms driving proppant, fluid, and formation interactions, especially in shale reservoirs, provides many advantages, including helping design new treatment methods for stabilizing faces of shale fractures, mitigating proppant embedment, controlling clay and fines migration, and ultimately improving well production. This paper describes new imaging tools and processing methods used to demonstrate the impact of treatment fluids applied during hydraulic fracturing in shale formations. Results are correlated to provide guidance for selecting appropriate clay stabilizers to enhance propped fracture conductivity. Four types of outcrop shale formation samples (Mancos, Barnett, Eagle Ford, and Marcellus) were studied after conductivity tests were performed using fresh water. The workflow involves the following: (1) perform a computed tomography (CT) scan on the shale wafers; (2) process and segment the image to separate proppant, void space, and formation material; (3) calculate proppant embedment depths on both sides of the shale wafers; (4) calculate proppant-induced fracture widths and extract fracture patterns; (5) determine the percentage of void space and broken proppants; and (6) correlate these measures. Fluid interactions with shale materials were manifested in the presence of proppant under closure stress through proppant embedment, effective propped fracture width, proppant-induced fractures, void space, and broken proppant percentage. By performing comparisons between Eagle Ford shale samples with fresh water or certain treatment fluids, proppant embedment depths were observed to be shallower under treatment conditions. While the number of proppant-induced fractures increased, their widths were observed to be narrower in treated shale samples, which is consistent with the trend. This reflects the importance of the treatment fluids, which help reduce the impact of proppant embedment to maintain the effective propped fracture width. The proppant-induced fracture pattern became more complicated in shale samples that were exposed to treatment fluid, resulting in a significant increase in surface area for hydrocarbon desorption. The proppant bed void space was shown to increase significantly after treatment. In addition, broken proppant amounts were reduced in the shale samples after treatment with the fluid, which reaffirms its positive effects. Overall, quantitative comparisons between samples treated with fresh water and certain treatment fluids substantiated the positive impact of clay stabilization for providing protection for various formations. The results provide guidance for selecting appropriate treatment fluids for certain reservoirs and help reduce formation damage risks and costs. Applying novel digital rock techniques to study the interactions between fluid, proppant, and rock samples provides the most straightforward method to visualize and quantify changes. The developed nondestructive workflow proved to be useful for selecting the proper fluid system for treating certain reservoir formations and thus enhancing production. Quantifying proppant-rock interactions enables operators to determine the effects of the fluid system more accurately compared to using current conventional methods.