Shale formations present anisotropic characteristics in mechanical, acoustic, and flow properties due to their layering and pre-existing natural fractures. This anisotropic behavior can create a complex fracture network rather than the conventionally presumed planar fractures. Although incorporating anisotropic behavior is essential for optimizing the hydraulic fracturing design and analyzing the post-fracture data, there are limited studies addressing the anisotropic tensile behavior of organic-rich shale formations. The objective of this study is to explore the tensile strength and tensile fracture patterns in shales by conducting splitting tests on variety of shale formations. Core samples from the Eagle Ford shale in the oil window, its overlying Austin Chalk and the underlying Buda formation, Green River immature oil shale, Mancos shale, and Berea sandstone samples have been tested to investigate the effects of layering, natural fractures, total organic carbon (TOC), maturity and mineralogy on tensile behavior. Having different types of Green River shale, the impact of TOC on the tensile strength was obtained. The anisotropic tensile behavior of Mancos and Green River shales were studied systematically at various orientations between the applied force and the bedding direction providing key understanding on the fracture growth patterns at any direction. Finally, the tensile strength and fracture patterns for several Eagle Ford, Austin Chalk and Buda core samples with extensive natural fractures are discussed.
The primary objective of a cementing job is to create a stable mechanical link between the casing and formation. This link provides a strong support for the casing and isolates different zones to prevent any contamination to aquifers during the lifecycle of the well. The damage of the cement sheath may result in contamination of drinking water resource and negative environmental impact. Hence, the loss isolation of the cement has received much attention from researchers and the public.The possibility of losing the isolation of the cement sheath during the lifecycle of the well is summarized and the potential risk in contaminating underground water formations is discussed in this paper. A mathematical model for predicting the failure of the cement sheath in an anisotropic stress field is presented. The model combines the effect of temperature, the variation of stress around the wellbore, internal pressure, and the integrity of the casing, cement, and rock formation. The objective of the model is to obtain the maximum internal pressure that we can apply on the casing without causing cement sheath failure. A numerical simulator was developed to calculate this maximum pressure for any inclination and azimuth angle. Computational results show that cement sheath failure depends strongly on the in-situ stress field of the surrounding formation. With stronger uniform formation support, the casing and cement can withstand larger internal stress. The failure of the cement sheath is more severe in a highly anisotropic stress field than in an isotropic field. Hence, the assumption of uniform formation stress around the wellbore may cause significant error in predicting failure of the cement sheath.The results of this study provide petroleum engineers a tool to determine the maximum internal pressure during drilling, production and stimulation to avoid losing cement isolation. It is recommended to use this model to check the integrity of the wellbore during any operations during the lifecycle of the well. IntroductionCurrently, there is a public concern regarding contamination of drinking water resources by the oil and gas operations. This contamination was originally claimed to be the result of well stimulation operations such as hydraulic fracturing. However, recent researches showed that the loss of the cement sheath isolation also is the main contributor to this contamination. Cement failure may destroy the integrity of the wellbore and create the channel for fluid mitigation between different formations. This can lead to lost production due to excessive water production, create the hazard to rig and production operations, and also contaminate shallow aquifers. The loss of isolation of surface aquifers is the result of many factors. In general, poor cementing job and the damaging effect of drilling, stimulation, and production activities are the main reasons for the failure of cement bond. With the increasing in number of wells in unconventional reservoirs, more stimulation operations are needed to successfully develop th...
Summary The condensation of the gas inside nanopores at pressures lower than the dewpoint pressure, or capillary condensation, is an important physical phenomenon affecting the gas flow/transport process in shale. This work investigates the underlying transport mechanism and governing factors for the gas transport at a pore scale associated with capillary condensation. We numerically simulate and compare the gas-transport process within pores for two cases, with and without capillary condensation, while Knudsen diffusion, wall slippage, and phase transition are included in the numerical model. In each case, the simulations are performed for two pore geometries corresponding to a single pore and two parallel-connected pores. The main objective is to determine whether capillary condensation blocks or enhances gas transport during production. The results show that the presence of the liquid phase in the pore throat initially enhances the gas flow rate to the outlet of the pore, but significantly reduces it later. This blockage depends on pore geometry and the properties of the oil and gas phases. The relatively low mobility of the condensed liquid in the pore throat is the main factor that reduces the mass transport along the pore. The reduction of overall mass transport in a single pore is more significant than that for the parallel pore geometry. Implications of this work for predicting large-scale gas transport in shale are also discussed.
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