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Ba Geri, Mohammed (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology)
Understanding proppant transport in complex fracture systems plays an essential role in determining propped fracture area, fracture conductivity, and their impact on well productivity and economics. Despite extensive, historical work that has studied proppant transport in vertical fractures, very limited investigation exists regarding proppant transport appraisal in inclined hydraulic fractures. This study provides a better understanding of proppant distribution in inclined hydraulic fractures.
Proppant transport is governed by several factors such as varying of slurry velocity, fracture geometry, proppant size, and proppant concentration. The main purpose of this experimental study is to evaluate the proppant settling and transport and to determine fracture propped area as a function of the key proppant transport factors in different inclined fracture geometry. Low viscosity fracture fluid (slickwater) was used with different particle sizes: 20/40, 40/70, 100- mesh ceramic proppant. To mimic slurry transport in hydraulic fracturing treatments, a 2 ft. × 2 ft. fracture slot model was constructed with gap of 0.25 in. representing the fracture width. Orientation of the fracture model can be adjusted from vertical to inclined positions. Four injection points perpendicular to the wellbore were used to simulate injection through multiple perforations, in addition to single point injection scenarios.
Equilibrium dune height (EDL) is expressed in three regions (near the wellbore, in the center of the fracture, and at the fracture tip) for created fractures. Variations in EDL as a function of the number of perforations that contributed during proppant transport are compared for both vertical and inclined fractures.
Experimental results show that both fracture inclination and number of contributing perforations impact EDL and propped fracture area. Inclination of fractures can have significant impact on proppant transport due to the friction or contact force, which comes from the fracture wall. This friction impacts settling velocity of the proppant and impacts the proppant distribution efficiency inside the fracture. Increasing fracture inclination angle increases fracture propped area. Finally, this work observed that number and perforations and their position play an important role in proppant transport, particularly in inclined fractures.
ABSTRACT: A series of laboratory in-situ visualization experiments was conducted on shale samples with different ductility (or brittleness) for improved understanding of the process of hydraulic fracture closure. In these experiments, a circular shale disc (diameter 44 mm, height 19 mm) was pressed against either a transparent glass disc with a roughened surface or a sapphire disc mediated by a single layer of proppant (grain size ∼1 mm). The compaction experiments were conducted under room temperature (∼25°C), with the maximum effective stress of ∼27 MPa. The test durations were 2 weeks and 1 month. The fracture closure and proppant crushing and embedment were visualized optically, using UV-induced fluorescence of dye mixed with the pore fluid (5% NaCl aq.). The closure of the fracture and the permeability reductions were monitored throughout the experiment. Two Marcellus shale samples with very different mineralogical compositions exhibited very different fracture closure behavior. A brittle, high-calcite-content sample caused progressive crushing of quartz proppant. In contrast, the other, high-clay-content sample resulted in strong proppant embedment and matrix disintegration. Interestingly, in spite of the very different properties, the creep closure of the fractures in both samples exhibited near-perfect semi-logarithmic time dependency.
High-performing hydrocarbon reservoirs usually consist of brittle, clay-poor, high TOC (total organic carbon) shales (e.g. Bourg, 2015. See Fig.1). However, clay-rich, ductile reservoirs with a good production potential do exist (e.g. Pair, 2017). Additionally, as the high-quality, “low-hanging-fruits” of the hydrocarbon-bearing shales get depleted, there will be increasing needs to produce from more difficult, ductile shales. Hydraulic fracturing has become an indispensable tool for enhancing permeability of otherwise very impermeable shales containing oil and gas. However, clay-rich, ductile shales are difficult to fracture, and the hydraulic fractures created in the rock tend to be short and have a smaller surface area. Proppant placed in these fractures tends to be embedded in the soft fracture walls, and the open space created by the fracture can be filled by mobilized clay minerals and by the expanded fracture walls if clay swelling happens. This is particularly a problem for the far-ends of the created fracture network, where proppants are distributed as a sparse monolayer, or no proppant present. Although these poorly propped fractures provide a significant drainage footprint for hydrocarbon production, they tend to close prematurely and lead to rapid permeability loss.
Lu, Cong (Southwest Petroleum University) | Li, Zhili (Southwest Petroleum University) | Zheng, Yunchuan (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Yin, Congbin (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Yuan, Canming (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Zhou, Yulong (SINOPEC Shengli Oilfield Luming Oil and Gas Exploration and Development Co., Ltd.) | Zhang, Tao (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University)
Abstract The pulse fracturing is widely used in unconventional reservoirs. It alternately pulse pumping the proppant slurry and clean fluid to form discontinuous placement proppant pillars in the artificial fractures and the pulse fracture conductivity is several orders of magnitude higher than conventional hydraulic fracture conductivity. However, the understanding of the deformation law of proppant pillar under the action of closure pressure and proppant normal stress is unclear, resulting in difficult to calculate the fracture conductivity and prefer proppant. Firstly, replacement construction and experimental displacement by Renault Similarity Criteria, three typical proppant pillars placement structures are extracted through the large-scale visualized flat plate device. The Young's modulus of the proppant pillars are calculated in modified API conductivity cell. Secondly, proppant pillars are dispersed into particles by the Smooth Particle Method (SPH). Using the parameters obtain from the above experiments, fracture-proppant pillar contact models are established to simulate the deformation process of proppant pillar and get normal stress of proppant particles. Thirdly, extracting the shape of stabilized proppant pillars, establish the fracture-proppant pillar flow model, calculate the fracture conductivity in different closure pressure. The simulation results show that as the closure pressure increases from 14MPa to 41MPa, the fracture width present an accelerated downward trend, The fracture width under the support of the initial radius of 9 mm proppant pillars are the largest, decreasing from 2.52mm to 1.72mm, the larger the radius of the proppant pillar, the greater the fracture width, the normal stress of three types of proppant pillar particles are both changed from 73MPa to 110MPa. The elliptical cylinder proppant pillar has the largest fracture conductivity. Its fracture conductivity is reduced from 12500D•cm to 3630D•cm. The larger the construction displacement and the pulse time of proppant slurry, the greater the fracture conductivity. The model in this article can calculate the normal stress of proppant particle and fracture conductivity in different closure pressure, which can significantly guide the choice of construction parameters and the type of proppant.
Summary To extract hydrocarbons from shale reservoirs, long horizontal wells must be drilled and many large fractures must be placed. These fractures should intersect the natural fractures in the formation and both the hydraulic fracture and natural fractures should be propped with proppants. This paper addresses placement of proppants in hydraulic and natural fractures. Placement of proppant was studied in a primary slot intersecting a secondary slot, representing a hydraulic fracture intersecting a natural fracture. The height of the secondary slot was varied; that of the primary slot was fixed. Two fracturing fluids were tested, water and foam (of 80% quality). Proppant loading and fluid injection rate (and corresponding shear rate) were varied. Water (or slickwater) can carry proppants into fractures, but proppants form a proppant bed and the proppant bed moves much slower than the water velocity. The proppant transport to the secondary slot is restricted by the height and position of the secondary slot. When carried by foam, proppants move with the foam without any retardation and without forming any significant proppant bed. Proppants are carried into bypass fractures independent of their fracture heights, which can lead to a greater utilization of secondary fractures. Introduction Oil and gas production has increased dramatically in the US due to the development of unconventional shale. Slickwater (water mixed with a small amount of friction reducer) fracturing is commonly used because such a low viscosity fracturing fluid can lead to a thin and long primary fracture intersecting many natural fractures (Y. Xu et al., 2016). However, slickwater does not carry proppants deep into fractures; common proppants, like sand, settle down very quickly in slickwater and leave a large portion of fracture surfaces and network unpropped after stimulation (Kern et al., 1959; Warpinski et al., 2009). The utilization of the secondary fractures is significant because it controls the effective stimulated reservoir volume (SRV). There is a trend of pumping smaller proppants (e.g. 200 mesh) in the industry which also indicates the importance of an extensive propped fracture network (Calvin et al., 2017). Viscous fracturing fluids can carry the proppants better because of stronger drag force and less settling. However, polymer based fracturing fluids can potentially plug the pores in shale fracture face and lead to a poor stimulation (Barati and Liang, 2014). Foam fracturing fluids, which typically have a small liquid fraction, possess high apparent viscosity (K. Xu et al., 2016) and the microstructures like lamellas can significantly reduce proppant settling (Lv et al., 2015). In addition, foams also limit fracturing fluid leak-off, clay swelling and lead to faster fracture clean-up due to gas expansion (Gu and Mohanty, 2014).