Proppant Selection and Its Effect on the Results of Fracturing Treatments Performed in Shale Formations
- John M. Terracina | John Morris Turner (Hexion) | Donald Heith Collins (Hexion Specialty Chemicals) | Scott Spillars (Hexion Specialty Chemicals)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 1.4.3 Fines Migration, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.5 Processing Equipment, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.2.2 Perforating, 5.8.2 Shale Gas, 4.1.2 Separation and Treating, 1.8 Formation Damage, 5.1.1 Exploration, Development, Structural Geology, 4.2 Pipelines, Flowlines and Risers, 2.4.3 Sand/Solids Control, 5.5.2 Core Analysis, 3 Production and Well Operations, 2.5.1 Fracture design and containment, 4.3.4 Scale, 1.6 Drilling Operations, 5.8.4 Shale Oil, 5.3.2 Multiphase Flow, 1.6.9 Coring, Fishing, 1.2.3 Rock properties, 2.4.5 Gravel pack design & evaluation, 5.2 Reservoir Fluid Dynamics
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Since the introduction of hydraulic fracturing, the industry has been attempting to establish laboratory testing parameters that assist operators and service companies in their effort to select the optimum proppant for a particular field application. An example of this effort is the development of the "long-term baseline conductivity laboratory test?? for proppants. While this test is a huge leap forward in subjecting proppant to simulated downhole conditions, it still does not adequately address many additional factors that can impact the effectiveness of the proppant such as:
1. Proppant fines generation and migration in the fracture
2. Proppant resistance to cyclic stress changes
3. Proppant embedment in the fracture face
4. Proppant flowback and pack rearrangement in the fracture
5. Downhole proppant scaling
Most proppant choices are currently based on which one has the highest baseline conductivity, cost, and availability. While this approach seems logical, it runs the risk of overlooking or under-valuing other critical factors effecting proppant performance in downhole environments.
To better define what constitutes the most effective proppant for a particular application, field cases will be presented that focus on the impact of proppant selection in a number of wells completed in various shale formations. The analysis will examine the production history associated with a variety of proppant choices. In an effort to better understand the production results, a series of lab tests will be performed on the proppants utilized in the field cases. These tests will attempt to establish how these factors (such as proppant fines, cyclic stress, embedment, proppant flowback, and scaling) could be used to explain and support the results of the field cases.
This paper reviews a number of fracturing treatments performed in three active areas in the United States; the Fayetteville Shale in Arkansas, the Bakken Shale in North Dakota, and the Haynesville Shale in north Louisiana. Reservoir characteristics, proppant type, and post fracture treatment production results were examined in each area. The proppants compared in this study were routinely utilized in the three areas. They are, in the Fayetteville, uncoated frac sand (UFS) and curable resin coated sand (CRCS); in the Bakken, uncoated frac sand, lightweight ceramic (LWC), and curable resin coated sand; and in the Haynesville, lightweight ceramic and curable resin coated sand.
The hypothesis of this study is that due to the reservoir and formation characteristics in the three areas, CRCS with its grain-tograin bonding technology should provide higher downhole fracture conductivity (FC) leading to increased post fracture treatment well production.
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