Realistic Assessment of Proppant Pack Conductivity for Material Selection

Barree, R.D.; Cox, Stuart Alan; Barree, Valencia L.; Conway, M.W.

doi:10.2118/84306-ms

Cited by 128 publications

(38 citation statements)

References 16 publications

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“…As closure stress increases, the packing geometry changes. The conductivity is also dependent on the grain packing and grain size distribution which is dependent on the roundness and sphericity of the proppants (Barree et al, 2003). Higher strength and better shaped proppants will improve fracture conductivity .…”

Section: Proppant Selectionmentioning

confidence: 99%

“…For formations with a Young's modulus value of less than 2 X 10 6 psi, embedment becomes even a greater issues because a Young's modulus value that low represents a very ductile shale (Lacy et al, 1998). In ductile formations (high clay content formation) embedment may cause proppant pack width to reduce by up to several proppant diameters (Barree et al, 2003). This does not mean brittle formations will not experience proppant embedment.…”

Section: Embedmentmentioning

confidence: 99%

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

Corapcioglu

Miskimins

Prasad

2014

SPE Annual Technical Conference and Exhibition

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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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Section: Proppant Selectionmentioning

confidence: 99%

Section: Embedmentmentioning

confidence: 99%

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

Corapcioglu

Miskimins

Prasad

2014

SPE Annual Technical Conference and Exhibition

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“…The elevated pressure losses in proppant packs under realistic conditions have been described in a number of papers [Barree 2003, Palisch 2007, Vincent 2009]. The effective conductivity of proppant packs are likely 50 to 1000 times lower than traditionally indicated in reference tests.…”

Section: Complications With Liquid-rich Formationsmentioning

confidence: 99%

Optimizing Transverse Fractures in Liquid-Rich Formations

Vincent

2011

SPE Annual Technical Conference and Exhibition

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Horizontal wells provide the opportunity to initiate multiple transverse fractures and dramatically increase the connection between the wellbore and the hydrocarbon-bearing reservoir. This has allowed the economic development of low permeability reservoirs that cannot be pursued without reservoir stimulation. Our success, however, does not imply that we are optimized. Recent field results in the Niobrara, Bakken, Viking, Haynesville, Eagle Ford and other reservoirs completed with transverse fractures are yielding answers to many questions, including: Are we achieving acceptable vertical height growth? What adjustments are necessary to accommodate multiphase flow? What fracture conductivity is needed? How many frac stages will provide the optimal economic returns? Are we effectively stimulating each stage? Are precautions necessary to avoid or reduce overflushing of proppant? Will restimulation of these reservoirs be necessary given current completion strategies? This paper explains the challenges of accommodating multiphase flow in transverse fractures and summarizes theoretical, laboratory, and field results demonstrating the best practices. Evidence is reviewed indicating that fractures fail to sustain hydraulic continuity through many laminations and techniques are suggested that can improve the ability to drain multiple stacked pay intervals with horizontal wells. Updated production results from the Bakken and Eagle Ford should be of benefit to any operator stimulating horizontal wells that produce significant oil, water, or condensate volumes.

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“…It has also been known that gas-well performance is highly influenced by the turbulent flow (Guppy et al 1982;Vincent et al 1999;Alvarez et al 2002; Barree et al 2003). Lopez-Hernandez et al (2005) have prepared an inventory of models to account for the non-Darcy-flow effect of gases in porous medium and provided a methodology for optimum design of fracture-stimulation treatment based on the proppant number concept.…”

Section: Problem Backgroundmentioning

confidence: 99%

Using Distributed Volumetric Sources to Predict Production from Multiple-Fractured Horizontal Wells Under Non-Darcy-Flow Conditions

Amini

Valkó

2009

SPE Journal

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The method of distributed volumetric sources (DVS) has been applied to predict gas production from a horizontal well with multiple transverse fractures in a bounded reservoir. Combining the quasianalytical DVS method, which provides us with the opportunity to predict pressure and production behavior of complex well/fracture configurations, with non-Darcy flow in the fracture enables us to calculate the optimum configuration in terms of the number and dimensions of fractures per well for a certain amount of proppant of a given type. The method is applied to an example case of a tight gas reservoir to maximize the production performance of this complex well/fracture configuration. Comparing results with and without inclusion of the non-Darcy effect in the fracture shows that a decrease in production occurs because of non-Darcy flow in all cases. However, a systematic screening of a realistic set of well/fracture configurations reveals that the detrimental effect of non-Darcy flow can be substantially compensated for by selecting the right number of fractures and shifting the fracture dimensions in favor of thicker fractures. While a simultaneous decrease in optimum lateral (and vertical) extension is necessary, it has limited effect on productivity. The simplicity, robustness, and small computational demand of the model allow seamless integration with external economic and operational constraints, providing a tool to screen and optimize a large set of possible configurations most suited for the development of economically marginal fields. Shahram Amini is with Schlumberger (SRPC),

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Realistic Assessment of Proppant Pack Conductivity for Material Selection

Cited by 128 publications

References 16 publications

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

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

Optimizing Transverse Fractures in Liquid-Rich Formations

Using Distributed Volumetric Sources to Predict Production from Multiple-Fractured Horizontal Wells Under Non-Darcy-Flow Conditions

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