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.

Oil and gas production from unconventional reservoirs has witnessed significant growth in the last few years. Historically, massive stimulation treatments have been used to produce these hydrocarbons. While the in-place hydrocarbon volumes are often large, the challenge is to increase recovery while using fewer resources. One of the technologies that have been used to address this challenge is the channel fracturing technique. A number of horizontal wells have been stimulated in the Hawkville field of the Eagle Ford shale with this technique. The objective of this work was to evaluate the impact of the channel fracturing technique in these wells by using numerical reservoir simulation. Numerical simulations were performed on a total of 15 horizontal wells. Six wells were completed with channel fracturing and nine wells were completed with slickwater or hybrid fracturing treatments. Because the Hawkville field has large variations in fluid composition, wells producing in the condensate-rich section were studied separately from those in the dry gas section. A consistent history matching methodology and workflow was applied across all wells which enabled a direct comparison of results. Results from analytical work, such as normalized production comparisons, were used to narrow down the range of uncertainties and assumptions made in the numerical simulations. A trend emerged from the analytical evaluations, showing that wells completed with the channel fracturing technique have higher productivity while using significantly less proppant and fracturing fluid. Numerical simulations confirmed the finding and provided insights on the cause of higher production on these wells. Unlike analytical methods, numerical simulation can model changes in complex fracture properties between wells, the effects of transient flow, shale gas desorption from kerogen, interference effects between perforation clusters, and accounts for differences in shale reservoir quality between wells. Furthermore, calibrated well models allowed for sensitivity studies such as evaluating the impact of changes in fracture geometry and conductivity on future wells. Reservoir modeling provided an estimation of effective stimulated fracture volume and fracture conductivity. Wells treated with the channel fracturing technique were observed to have on average 50% greater effective stimulated volume and more than double the stimulated conductivity compared to wells fractured with slickwater. When compared to wells fractured with hybrid treatments, channel fracturing wells had on average 27% greater effective stimulated volume and 50% more stimulated conductivity.

Since the initial success of multi-stage fracturing in horizontal laterals in the Eagle Ford Shale, multiple completion techniques have been implemented to optimize productivity. This paper discusses completion practices being followed in the Hawkville field, encompassing La Salle and McMullen counties in south Texas. While slickwater treatments provided the initial successes in the dry gas areas of the Eagle Ford, hybrid and channel fracturing treatments quickly showed improved, if not at least equal success in the wet gas areas while utilizing significantly less fluid and proppant volumes. The challenge has been to determine an optimum balance between the various completions parameters to increase production with less cost. Optimization of Eagle Ford stimulation techniques became the most important objectives for completion and production engineers over the last two years, since the first horizontal multi-stage well was completed in the Hawkville field. Fracturing fluid systems, treatment rates, proppant types and concentrations along with completion details such as number of clusters, number of stages, and perforation intervals in horizontal laterals created a large number of variables impacting production for any operator. Implementation of any technology requires proper evaluation metrics that minimize geology, petrophysical and completion uncertainties. This paper describes the evaluation process of a novel stimulation technology – channel fracturing based on a heterogeneous proppant placement technique, and its comparison to existing conventional slickwater and hybrid stimulation treatments. The focus will be on the evaluation of in-situ conditions, challenges and production evaluation of different completion techniques using the following methodologies: normalized production comparison, productivity index analysis, neural network trained self-organizing maps and numerical simulations. The initial production (IP) of the wells completed with the channel fracturing technique was 32–37% better, compared to offset conventional slickwater and hybrid wells. A detailed evaluation of horizontal well performance is described in this paper, based on statistical approaches and reservoir modeling. The combination of two evaluation techniques substantiates the statement that the incorporation of the channel fracturing technology as part of the completion design had a positive impact for the stimulation of wells in the Eagle Ford formation.