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Abstract Artificially created fracture networks with sufficient fracture conductivities are essential for economic production from shale reservoirs. Fracture conductivity can be significantly reduced in shale formations due to severe proppant embedment. In addition, proppant embedment induces shale flakes that migrate and clog fracture networks. A laboratory investigation was performed to understand how excessive proppant embedment caused by the shale-water interaction impairs shale fracture conductivity. The experiments were conducted using Barnett shale samples with representative rock properties. The asperities on the fracture surface were carefully preserved. The damage process was simulated in the laboratory by flowing water through the shale fracture packed with proppants. The water used in the experiments had a similar chemical composition to flowback water in the field. The laboratory results were benchmarked with the results from an experimental study conducted with Berea sandstone samples. Post experimental analysis included microscopic imaging of the fracture surfaces and measurement of the proppant embedment depth. A computational fluid dynamics study was conducted to quantify the conductivity loss due to proppant embedment on a theoretical basis. We developed pore-scale physical models of the proppant pack and calculated the fracture conductivity loss at different proppant embedment depths. The computation was repeated for a variety of proppant layers. The worst case assumed a 40% proppant grain volume embedment. The experimental study showed up to 88% reduction in fracture conductivity after water flow under 4,000 psi closure stress. The conductivity loss was due to severe proppant embedment as the shale fracture face was softened after its exposure to water. Direct measurement of embedment depths indicated that for fractures that were exposed to water, the average embedment depth was about 50% of the proppant median diameter, while for fractures that were only exposed to gas, the average embedment depth was just 15% of the proppant median diameter. It was also observed that pore space of the sand grains at the outlet of the fracture was clogged by shale flakes and fragments. The computational fluid dynamics study proved that even a 10% proppant grain volume embedment can cause 45%~80% conductivity loss. With the same proppant volume loss due to embedment, the conductivity reduction was less in fractures containing multiple proppant layers than the fracture containing only one layer of proppants.
This article, written by John Terracina, manager of fracturing technology at Momentive, contains highlights of paper SPE-135502-MS, Proppant Selection and Its Effect on the Results of Fracturing Treatments Performed in Shale Formations, by J.M. Terracina, SPE, J.M. Turner, SPE, D.H. Collins, SPE, and S.E. Spillars, SPE, of Hexion, prepared for the 2010 SPE Annual Technical Conference and Exhibition in Florence, Italy, 19-22 September. In October 2010, Hexion merged with Momentive.
The oil and gas industry has strived to provide methods to test the proppants used in shale formation fracturing, but they still do not adequately address many of the factors that impact their effectiveness. There are many factors that occur downhole that need to be considered, such as:
The hypothesis of this study was that because of the formation characteristics in the three areas studied, curable resin-coated sand (CRCS) with its grain-to-grain bonding technology should provide higher downhole fracture conductivity leading to increased postfracture treatment well production. To verify the hypothesis, laboratory tests outside the traditional long-term baseline conductivity were conducted with proppants and formation core samples from each area. The objective was to more accurately simulate proppant performance under specific downhole conditions of temperature, pressure, fluid, and rock properties pertaining to each area.
Proppant Selection Factors Studied
Proppant fines generation and migration, as well as proppant flowback, were studied in the Fayetteville Shale of Arkansas. Proppant fines and embedment were studied in the Bakken Shale of North Dakota. And finally, proppant pack cyclic stress, embedment, and scaling were examined in the Haynesville Shale of Louisiana.
Proppant Fines Generation and Migration
Proppant fines are the small particles that break off from the proppant grain when subjected to fracture closure stress. The small broken pieces reduce pack porosity and permeability, and cause major degradation in the conductivity of proppant packs. When proppant fines migrate down the proppant pack toward the wellbore, they accumulate and reduce flow capacity.
Proppant Pack Cyclic Stress
When comparing proppants, one factor often overlooked is a proppant’s performance under closure stress changes. The forces of cyclic stress exerted on proppants downhole can cause them to fail. Events often occur multiple times throughout the life of a well, such as shut-ins because of workovers or connections made to a pipeline; in some cases, a well could be shut in because of pipeline capacity. These events lead to cyclic changes in fracture closure stress. This varying amount of pressure and stress can cause the proppants to shift or rearrange, resulting in a decrease in fracture width as well as additional proppant fines and proppant flowback.
Homburg, J. M. (ExxonMobil Upstream Research Company) | Crawford, B. R. (ExxonMobil Upstream Research Company) | Reese, W. C. (ExxonMobil Upstream Research Company) | Amoruso, J. (ExxonMobil Development Company) | Corbell, C. (ExxonMobil Development Company)
ABSTRACT: Fracture treatments are critical for economic production from some low-permeability deepwater reservoirs. An example of this is the Julia field in the Gulf of Mexico where there is evidence that high drawdowns are damaging completions leading to an apparent loss of permeability. The aim of this study is to identify potential damage mechanisms causing this permeability loss. To this end a series of experiments was undertaken to measure the stress dependent permeability of the formation, proppant pack and formation/proppant pack interface. This testing identified that the formation and proppant are minimally stress dependent whereas the interface is strongly stress dependent. Characterization methods including petrographic analysis, micro-CT imaging and x-ray fluorescence were used to identify damage mechanisms including: grain/proppant cracking, fines migration and geometric loss of fracture surface area to flow. The interface displays evidence of all of these mechanisms and is more pervasively damaged than either the formation or proppant pack supporting the observation that the interface is the most stress sensitive system component.
Production of hydrocarbon at economic rates from low permeability reservoirs typically requires some form of stimulation, commonly hydraulic fracturing. The induced fractures facilitate production by exposing large surface areas of the formation and by providing a high conductivity pathway to the wellbore. Thus, in order to maintain economic production rates, it is important to identify what factors might contribute to loss of formation permeability and propped fracture conductivity.
As the formation, proppant pack and formation/proppant pack interface are subjected to increasing mechanical stress during production several processes may contribute to loss of formation permeability and fracture conductivity including proppant crushing, proppant embedment, reduction of fracture aperture and production of either formation or proppant fines (Anderson et al., 1989). Many studies have evaluated the role that these mechanisms play in affecting fractured system behavior (e.g. Behr et al., 2003, Freed et al., 2000, Pope et al., 2009, Reinicke et al., 2012, Terracina et al., 2010) however most of these studies have focused on understanding the behavior of hydraulic fractures in mudrocks. This study was undertaken in order to better understand the behavior of fracture completions in tight sandstones from the Julia field in the Gulf of Mexico.
ABSTRACT It has been frequently reported that in unconventional shale formations, fractured well productivity can be dramatically reduced by severe proppant embedment due to a reduction in fracture aperture and conductivity. However, the mechanisms of this decline are poorly understood. In the absence of this understanding, very few models take proppant embedment into account when predicting production decline. In this study, we present both new experimental techniques and analytical analysis to explore proppant embedment mechanisms and to quantify stress dependent elastic and plastic deformation, as well as time dependent creep deformation. Two independent experimental setups have been employed for this purpose. To determine elastic and plastic deformation a constant displacement test is conducted while monitoring load in a simple and novel experimental setup. Creep deformation under constant load while monitoring the displacement is combined with these measurements to extract parameters for elastic, plastic and creep deformation from these two experiments. Results show that plastic and creep deformation dominate proppant embedment in shale (over 75%), while elastic deformation is usually small (less than 15%). 1. INTRODUCTION In the petroleum industry, hydraulic fracturing has been used to produce hydrocarbons from unconventional shale reservoirs. These fractures have been created by a pressurized fluid with proppants. Proppants have been used to maintain conductive paths for hydrocarbons to flow. Once the pumping of the fracturing fluid is stopped, created fractures begin to close. Fracture closure is a function of many different phenomena, including proppant fines generation and migration, proppant crush resistance, proppant embedment into the fracture surface, reorientation of proppants during stress variation and proppant flow back (Economides and Nolte, 1989; Sato and Ichikawa, 1998; Reinicke et al., 2006, 2010; Terracina et al., 2010; Alramahi and Sundberg, 2012). Also, closure stress, proppant size, concentration, and distribution, formation hardness, surface roughness (Volk et al., 1981), water saturation, dynamic fluid leak-off, cyclic loading conditions (Lacy et al., 1998), fluid viscosity (Lacy et al., 1997), shale mineralogy (Alramahi and Sundberg, 2012), fracturing fluid effect (Corapcioglu et al., 2014), elastic, creep deformation (Guo and Liu, 2012), and pumping strategy (Huang et al., 2019) are other factors that affect proppant embedment.