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This paper discusses the workflow for developing a model to predict gas production for hydraulic fracture stages in a brittle shale environment. In our last paper (SPE 163829), we developed a model to predict fracture network geometry (width, length, and height) obtained from microseismic data for various fracture treatment designs. In this study, using both microseismic data and fracture/completion data; frac treatment production is estimated. The well database used for this purpose is comprised of fracture design parameters including treatment volumes, rates, proppant mass and size; well properties include perforation interval length, and perforation depth. The goal of this study is to provide insight into factors affecting well production in a brittle shale environment. Initial data screening demonstrated massive data scattering and as a result data mining techniques are employed to find possible hidden relationships to explain the nature of the data. Also, using sensitivity analysis on the predictive model, improvements in the current fracture designs and completion schemes in Barnett shale are made. The database is examined from different aspects using various data mining approaches. After screening and preprocessing the data, non-process affected outlier wells are removed from the dataset. Then, a forward predictive neural network model is trained with fracture design and well data parameters as inputs and well cumulative gas production per stage as outputs. Neural networks are trained with the help of genetic algorithm (GA). The sensitivity study on the trained network provided many insights about well completion and stimulation strategies. Recommendations on how to improve fracture designs and well completion schemes are provided based on sensitivity analysis on the neural networks. Results of neural network modeling in Barnett shale are compared to other gas producing shale assets such as Fayetteville and Haynesville shale to compare the findings. The results of this work potentially help understanding of completion and fracture treatment designs on well productivity in gas producing shale assets. This will potentially help operators understand how to more effectively design frac treatments and/or reduce the operational costs associated with well completion in a brittle shale environment. Considering the fact that the relationship between stimulated reservoir volume and production is not entirely understood, this work may shed some lights on the aforementioned issue.

The emergence of "accepted" proppant conductivity testing methods has led to much discussion about what is needed to regain high conductivity levels, and several marketing campaigns have been based on these findings. The industry has generally accepted the principle that delivering high conductivity levels in the fracture is key to achieving high production levels. This paper does not refute this point, but modifies it. This paper presents theory, laboratory data, and case histories indicating that high initial conductivity levels can only gain high initial levels of potential or actual production. For sustained, high production levels, the proppant pack's integrity must be maintained. With time, most proppant packs are damaged by fines migration, gel clogging, and geochemical precipitation. These processes can be abated with various additives and techniques. This paper discusses these techniques in detail and shows case histories in which the techniques proved costeffective in sustaining higher levels of production than those found in comparable wells.

Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico. This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs. The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.

The dewatering process, which stimulates gas desorption, is essential for gas production in coalbed methane (CBM) reservoirs. Many CBM wells require hydraulic fracturing to provide interconnectivity and hydraulic access to the cleat/matrix system. Without hydraulic communication and access to the hierar-chical flowpath, gas desorption is severely limited or nonexistent. When economics allow operators to continue long-term gas production, the gas rate of most coalbed wells will eventually increase. Over time, gas desorbs from the coal macerals that form the cleat blocks. However, some coalbed fields experience premature or severe declines in production because of poor hydraulic-fracture conductivity. Particulates have been discovered as a primary cause of poor hydraulic-fracture conductivity. These particulates flow with produced water; they are then deposited within the proppant pack where they block pore throats and interfere with gas desorption. A surface modification agent (SMA) that prevents or reduces hydraulic-fracture conductivity damage has been developed and successfully field-tested. This agent, which has strong adhesive properties, helps delay or prevent conductivity damage to the proppant bed. This paper discusses (1) the problems associated with poor hydraulic-fracture conductivity, (2) why it occurs in coalbed wells, and (3) how a new SMA can minimize the problem.

Abstract The Morrow formation in Hutchison County, Texas was long considered incapable of producing hydrocarbons at an economic rate. Most post-frac production rates were the same or less than pre-frac rates. Only high flow rate, non-stimulated completions were considered economic, but these completions were few in number. These facts lowered expectations for sufficient recovery of investment necessary to continue developmental drilling. Utilization of modern fracture model techniques, core analysis, fluid testing and stress data lead to a system of stimulation techniques, fluids and proppants that has created a cost-effective stimulation system for the Morrow formation. Lithology studies showed that the frac fluid was primarily critical to success. These studies lead to an unorthodox fluid. It contained two elements that would not be considered practical in any other formations or circumstances in the Western Anadarko basin. Proppant placement was identified as the second most important issue. Fracture height was found to be controlled by permeability, not stress. This led to the discovery that proppant convection did not allow for good proppant placement. Proppant staging methods were augmented to combat excessive convection and then acquire advantageous proppant placement. Proppant selection was identified as the third most important criteria. Reservoir stresses and modeling showed that high cost, high stress proppants were not necessary. Lower cost, larger sized proppants yielded much higher conductivity than in previous completions. These criteria were integrated into a solution which brought the post-frac production rate from a one fold to a ten fold increase. Introduction The West Arrington Morrow field of Hutchison County, Texas contains many producing horizons. One of which is the Morrow sandstone. This zone has been long overlooked for it's potential in supplying hydrocarbons due to problems in completions. Fortunately for Arrington CJM, Inc., their first three experiences with the zone were high flow rate, natural completions. Unfortunately, this was not the standard for completions to come. P. 129