Channel Fracturing in Horizontal Wellbores: the New Edge of Stimulation Techniques in the Eagle Ford Formation

Abstract

The hydraulic channel fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, which provides for highly conductive paths for the flow of fluids from the reservoir to the wellbore. These channels are created through a process that combines fit-for-purpose geo-mechanical modeling, surface equipment controls and fluid and fiber technologies. This paper reports the first implementation of the channel fracturing technique in horizontal wellbores. A section of the Eagle Ford formation (TVD 10,900 - 11,500 ft) in the Hawkville field near Cotulla, Texas was selected for this study. This section comprises mainly limestone with 100 to 600 nD permeability and 7 to 10 % total porosity. The formation requires horizontal laterals with multi-stage hydraulic fracturing for economic production. The channel fracturing technique was evaluated in twelve horizontal wells. Results from thirty eight offset wells treated with conventional techniques (slickwater or hybrid-type treatments) are also reported to compare performance. Non-normalized data from this sample of fifty wells showed hydrocarbon production increases ranging between 32% and 68% in favor of the channel fracturing technique. The Hawkville field comprises a gas-rich section and a condensate-rich section. Reservoir simulations were performed on a sample of four wells located in the gas-rich section and two wells located in the condensate-rich section of the field to generate sets of normalized production data. These simulations accounted for variations in completion strategy, bottom hole flowing pressures and reservoir quality. Normalized production data for the sample of wells located in the gas-rich section of the field showed that the channel fracturing technique increased gas production by 51%. Normalized production data for the sample of wells located in the condensate-rich section of the field indicates increase in condensate production by 46%. Results from these history matches are consistent with the hypothesis that the channel fracturing technique enabled higher production by two concomitant mechanisms: increased area of contact with the reservoir and enhanced connectivity between the reservoir and the wellbore through highly conductive channels. Positive features that were also observed during this campaign such as the elimination of near-wellbore screen-outs and significant reductions in proppant and water consumption are also summarized and discussed.

Modeling of Fracture Width and Conductivity in Channel Fracturing With Nonlinear Proppant-Pillar Deformation

“…Currently, when design calculations are performed, the ratio (s) of the formation's Young's modulus to closure stress (usually the minimum horizontal stress) is used to evaluate the applicability of channel fracturing in a particular formation, Schlumberger (2012) recommends that channel-fracturing technology is applicable when s > 275. The values of s for formations in various oil fields have been reported in the literature, such as 280 in Eagle Ford Shale (Rhein et al 2011), 287 in Zagorskoe Field (Kayumov et al 2014), 293 in the Barnett Shale Formation (Samuelson et al 2012), 312 in Taylakovskoe Field (Sadykov et al 2012), 419 and 556 in western Egypt (Gawad et al 2013;Emam et al 2014), 532 in the Ordos Basin (Li et al 2015a), 583 in Jonah Field (Turner et al 2011), 797 in the Burgos Basin (Valenzuela et al 2012), and 632 in the Shengli Oil Field. All these fields have a s-value greater than 275, and channel-fracturing stimulations generally lead to more than a 30% increase in production.…”

On the Mechanisms of Channel Fracturing

“… Viability of the technique in formations in which the predominant lithological component is sandstone (e.g., Kayumov et al, 2012;Turner et al, 2011), carbonate (e.g., Rhein et al, 2011) or shale (e.g., Samuelson et al, 2012);  Applicability of the technique in vertical (e.g., Johnson et al, 2011) andhorizontal (e.g., Viswanathan et al, 2011) completions;  Applicability in reservoirs bearing dry gas (e.g., Gillard et al, 2010), wet gas/condensate (e.g., Altman et al, 2012), and oil (e.g., Sadykov et al, 2012).…”

Channel Hydraulic Fracturing and its Applicability in the Marcellus Shale

“…Figure 10. Cumulative Gas Production of Conventional fracture and Channel Fracture Potential Johnson et al, 2011, state that a 23% increase in initial gas production was obtained from field results for channel fracturing in a tight gas field while Rhein et al,2011, state that the field results of channel fracturing in an Eagle Ford shale gas field show a 51% normalized increase over conventional slickwater treatment results and conclude that the dominant contribution to performance of channel fracturing in shales is due to an increased effective stimulated reservoir volume.…”

“…Channel fracturing has been implemented in other low permeability unconventional reservoirs in the United States with significant increase in production over conventional fracturing techniques (Johnson et al, 2011). A total of over 1400 successful channel fracturing stage treatments have been pumped in the Eagle Ford shale in Texas (Rhein et al, 2011), the Bakken Shale in North Dakota and Montana, the Lance formation in Wyoming and the Almond formation in Wyoming. This paper investigates the geomechanical properties of the Marcellus shale to determine whether the channel fracturing technique is applicable in the gas play.…”