Surface Area vs Conductivity Type Fracture Treatments in Shale Reservoirs
- Muthukumarappan Ramurthy (Halliburton Energy Services Group) | Robert David Barree (Barree & Assocs. LLC) | Donald P. Kundert (Halliburton Energy Services Group) | James Erik Petre (Hunt Oil Co.) | Michael J. Mullen (Realm Energy)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference, 24-26 January, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 2 Well Completion, 5.1.1 Exploration, Development, Structural Geology, 5.5.2 Core Analysis, 5.8.4 Shale Oil, 5.8.3 Coal Seam Gas, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.2 Shale Gas, 5.6.1 Open hole/cased hole log analysis, 3 Production and Well Operations, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 1.2.3 Rock properties
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Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of the tight shale reservoirs. Ever since the success of Barnett shale program, operators are inclined to pump similar large volume water fracture treatments with little or no proppants in their respective shale plays. This assumes that all shale plays are the same and react accordingly to large volume treatments. The basic objective behind such treatments is to contact large surface area, which has been very successful in the Barnett shale play. Such large volume treatments in other shale plays may not be an optimized solution for the specific shale attributes and the response may lead to uneconomical production results. Some shales based on their reservoir characteristics might require a conductivity type fracture treatment. So, it is important to understand the characteristics of these shales before deciding the stimulation treatments. In addition to core and log analysis of these shales, fluid sensitivity tests, Brinell hardness tests, unpropped fracture conductivity tests and more importantly a Diagnostic Fracture Injection Test (DFIT) can help define the guidelines for choosing between a surface area and a conductivity type fracture treatment.
Integrating the various data sources is important in arriving at these guidelines. The main objective of this paper is to provide these guidelines along with examples such that the costly trial and error approach for stimulating shales can avoided. Examples from both oil and gas shales namely, the Gothic, Haynesville, Eagle Ford and Barnett shale plays in the USA are included in this work.
Shales are defined as organic rich, fine grained sedimentary rocks containing a minimum of 0.5 wt% total organic carbon (TOC) (Brian Cardott, 2006) with a mean grain size of less than 0.0625 mm (0.0025 in.) (Energy Information Administration 2006). The shales can then be identified as gas or oil shales by their organic matter (i.e. kerogen or maceral types). By crossplotting the Hydrogen index vs Oxygen index (Van Krevelen, 1961) one can define the oil or gas window the shale is in. A pseudo Van Krevelen plot with all the four type curves is shown in Figure 1. Type I and II can be lumped into the oil generative window and Type III can be lumped into the gas generative window while Type IV indicates no potential.
For shale plays to be economically successful, it is essential that they have good reservoir characteristics. So the first objective in developing shale plays should be to understand the shale reservoir quality and its potential from logs and cores (Grieser et al. 2007; Kundert et al. 2009). Once the reservoir potential has been identified then the challenge is to produce these shales economically. As the flow capacity (i.e. permeability) is very low in shales, it requires stimulation to produce economically. A lot of work regarding shale stimulation has been published since early 1990. Lancaster et al (Lancaster et al 1992) presented the evolution of massive hydraulic fracturing in the Barnett shale. Such stimulation treatments yielded 200 to 250 MMscf in the first year and the wells recovered between 1-to-1.5 Bscf. Shelly et al (Shelley et al 2008) investigated 393 Barnett shale well completion strategies in their work. They show that it took 17 years in the Barnett shale to evolve from pumping crosslinked fluid systems, carrying more than 1 million lbm of proppant per job to waterfrac systems that contain large volumes of water and small quantities of sand. Their study showed that such waterfrac systems generally outperformed the crosslinked fluid systems. Because of this success, operators in other shale plays are still attempting similar "Barnett type waterfracs?? in their projects, however, with mixed success. This mixed success shows us that these large volume waterfrac treatments might work in the Barnett shale but may not be the correct solution in other shale plays. Hence, it is imperative that we clearly understand the reservoir characteristics of these shales and optimize the fracture treatments to fit their specific attributes.
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