Stimulation of Gas Shales: They're All the Same

Matthews, H. Scott; Schein, Gary W.; Malone, Mark R.

doi:10.2523/106070-ms

Cited by 21 publications

(14 citation statements)

References 3 publications

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“…Brittle minerals are essential for hydraulic fracturing (Bower, 2007;Montgomery et al, 2005;Jarvie et al, 2007;Mathews et al, 2007;Zhu et al, 2011). In this study, we found that the silicates (Quartz þ feldspar) content also has a positive correlation with gas content (Fig.…”

Section: The Correlation Between Gas Content and Silicates (Quartz þ mentioning

confidence: 63%

Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China

Chen

Jiang

et al. 2015

Marine and Petroleum Geology

168

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Section: The Correlation Between Gas Content and Silicates (Quartz þ mentioning

confidence: 63%

Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China

Chen

Jiang

et al. 2015

Marine and Petroleum Geology

168

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“…al., 2013). Embedment issues increase with the increase of production time, especially in the process of hydraulic fracturing, where the fluid can weaken the rock strength (Akrad et al, 2011 andMatthews et al, 2007). It can also occur through chemical reactions downhole such as diagenesis and degredation of proppants over time (Rayson and Weaver, 2012).…”

Section: Embedmentmentioning

confidence: 99%

Fracturing Fluid Effects on Young's Modulus and Embedment in the Niobrara Formation

2014

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New discoveries of shale plays and their abundant resources have directed the petroleum industry towards their development. Production from shale reservoirs has grown significantly in the past few decades spurred by successful development of plays such as the Barnett and Bakken Shales. Due to their low permeability, hydraulic fracturing is a necessity for economic production in these reservoirs, and the success of these reservoirs is dependent on optimizing hydraulic fracturing designs which are in turn dictated by an understanding of the mechanical properties of these reservoirs. The geometric growth and conductivity of fractures in these reservoirs are influenced by many factors. Young's modulus reduction, which essentially means weakening of the formation, is one of these factors. This reduction damages the reservoir and makes embedment of proppants into the fracture face a detrimental effect on fracturing success. The goal of this research project is to focus on how different fracturing fluids change the Young's modulus of the Niobrara shale and how this change affect the proppant embedment and conductivity when commonly used proppants are subjected to pressure tests in the effected Niobrara shale samples.A series of tests and associated methodology were developed and applied to investigate how the Niobrara shale's Young's modulus is affected by various fracturing fluids and to quantify associated proppant embedment. In order to achieve this, core samples at various depths from the same well were selected from the cores. The selection was made based on mineralogy data. Samples containing the highest, lowest, and median calcite percentage and porosity were selected to be imaged with QEMSCAN in order to understand the mineralogy of the samples being used. Eight selected samples were then saturated with four fracturing fluids (freshwater, KCl, KCl+friction reducer, and freshwater+KCl substitute). Four of these samples were the "expansion" samples to see if the results were more dependent on the fluid selections. Two additional samples were heated with freshwater and KCl at 180°F for five days to investigate the heat effect on Young's modulus and embedment in comparison to room iv temperature experiments. In order to compare in-situ saturated Young's modulus values to dry Young's modulus values of cores obtained by nanoindenter, the Gassmann fluid substitution equation was used.This method showed significant Young's modulus difference between in-situ saturated and dry core values.The saturated/room temperature and saturated/heated cores were then subjected to 3030 psi for one hour while selected proppants were placed in between them. Four different proppant types (16/30 Brady, 20/40 Ottawa, 20/40 Ceramic, and 20/40 RCS) were used in this research. Various combinations of cores affected by fluids and proppants were made in order to simulate actual treatment designs. The cores were also scanned by scanning acoustic microscope (SAM) before and after they were subjected to pressure with proppants, so that...

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“…This behavior is represented using a 1D Carter leak-off model (transversal flow) which has an inbuilt decay of leak-off rate due to the assumed formation of a filter cake on the exposed fracture surface over time [5]. The model assumes an initial volume loss per unit area over a spurt time followed by a constant leak-off coefficient as: (6) where is the current model time,…”

Section: Fracture Fluid Leak-offmentioning

confidence: 99%

“…Hydraulic fracturing is an engineering process often used by the petroleum industry to extract hydrocarbons from very low porosity reservoir rock which would otherwise be economically unviable [1,2,3,4,5,6]. The use of numerical models in the design stage would be an advantageous tool to optimise the hydrocarbon recovery for a given tight shale reservoir.…”

Section: Introductionmentioning

confidence: 99%

Complementary hydro-mechanical coupled finite/discrete element and microseismic modelling to predict hydraulic fracture propagation in tight shale reservoirs

Profit

Dutko

et al. 2015

Comp. Part. Mech.

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This paper presents a novel approach to predict the propagation of hydraulic fractures in tight shale reservoirs. Many hydraulic fracture modelling schemes assume that the fracture direction is pre-seeded in the problem domain discretization. This is a severe limitation as the reservoir often contains large numbers of pre-existing fractures that strongly influence the direction of the propagating fracture. To circumvent these shortcomings a new fracture modelling treatment is proposed where the introduction of discrete fracture surfaces is based on new and dynamically updated geometrical entities rather than the topology of the underlying spatial discretization. Hydraulic fracturing is an inherently coupled engineering problem with interactions between fluid flow and fracturing when the stress state of the reservoir rock attains a failure criterion. This work follows a staggered hydro-mechanical coupled finite/discrete element approach to capture the key interplay between fluid pressure and fracture growth. In field practice the fracture growth is hidden from the design engineer and microseismicity is often used to infer hydraulic fracture lengths and directions. Microsesimic output can also be computed from changes of the effective stress in the geomechanical model and compared against field microseismicity. A number of hydraulic fracture numerical examples are presented to illustrate the new technology.

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Stimulation of Gas Shales: They're All the Same

Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435.

Cited by 21 publications

References 3 publications

Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China

Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China

Fracturing Fluid Effects on Young's Modulus and Embedment in the Niobrara Formation

Complementary hydro-mechanical coupled finite/discrete element and microseismic modelling to predict hydraulic fracture propagation in tight shale reservoirs

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