The channel fracturing technique combines fracture modeling, materials and pumping methods to generate a network of highly conductive channels within the proppant pack. These channels aim at expediting the delivery of hydrocarbons from the reservoir to the wellbore (Gillard et al., 2010). This paper provides a comprehensive summary of the implementation of this novel technique in the Burgos basin, Mexico North. The Eocene Yegua formation in the Palmito field near Reynosa, Mexico was selected for this study. This formation comprises sandstone layers with average permeability of 0.5 mD and Young’s modulus in the order of 2.5 Mpsi. Key historical issues for the stimulation of this formation using conventional fracturing materials are limited polymer recovery and the consequential fracture conductivity impairment. Use of resin-coated proppants has also been implemented to prevent proppant flowback from these operations. Gas production, treating pressure and polymer recovery data from a twelve-well campaign in the Palmito field (six wells treated via channel fracturing, six offset wells treated conventionally and aiming for similar fracture geometry) are summarized in the manuscript. Results indicate that the implementation of the channel fracturing technique improved fluid and polymer recovery, thus leading to increases in initial gas production by 32% and 6-month cumulative gas production by 19%. Such improvements in production were obtained with 50% less proppant per stage and smaller proppant particles. These observations are consistent with the hypothesis that the channel fracturing technique promotes the decoupling of fracture conductivity from proppant pack permeability. Positive features that were also observed during this campaign such as absence of proppant flowback issues without the use of resin-coated sand and non-occurrence of near-wellbore screen-outs are also reported and discussed. The study concluded that the channel fracturing technique is a viable alternative to conventional fracturing methods for the stimulation of wells in the Burgos basin.

Lately, the United States of America has experienced tremendous growth in shale plays development. To date, more than 5,000 wells have been drilled and completed in more than 20 fields. Worldwide, exploration and development of shale plays has also increased. Currently, due to low gas prices, operating companies are shifting resources to explore and develop condensate or oil producing shale plays. In 2010, exploration of gas-rich and possible liquid-rich shale reservoirs began in northern Mexico. The main challenges were to demonstrate the availability of reserves and set the foundation for future development of these plays, with the information gathered in a few exploratory wells. Wells were aimed at the upper cretaceous Eagle Ford formation and at the Jurassic Pimienta formation. As of July 2012, six horizontal exploratory wells were drilled and completed, implementing in four of them a two stage integrated workflow to achieve the objectives set. The drilling stage used a petrophysical and geomechanical static model to identify the most prospective interval in the reservoir, define the best drilling azimuth direction and landing point, and reduce drilling risk. Real-time geosteering was implemented to achieve the targeted navigation window. In the completion stage, a reservoir-centric completion and stimulation software, which integrates petrophysical and geomechanical data, was used to optimize the completion and stimulation design. Results were evaluated using various techniques, including micro seismic monitoring, production history matching, production logging and well testing. This study presents the details of the workflow implemented and the lessons learned in each well. The main lessons learned were: 1. Proper well landing was key to achieving predicted production and booking of reserves; 2. Anisotropic geomechanical models were the most appropriate for simulating hydraulic fracturing treatments; 3. Conventional hydraulic fracturing models do not always represent the behavior of fractures in the unconventional formations evaluated; 4. Production rates along the lateral of the well can vary significantly with single stages producing up to 20% of the total well production. The conclusions and lessons learned in this study have formed the bases and will be important to the subsequent development of the different shale plays in Mexico-and around the world.

Mexico, the world's fourth largest producer of geothermal energy, generates 965 MW of electricity. One field alone produces 195 MW. However, to maximize the steam production of geothermal wells it is often necessary to perform matrix stimulation treatments. The temperature and mineralogy of the naturally fractured volcanic formations and scales tendency present some unique challenges. The potential of many geothermal wells is limited by formation damage. Drilling fluid invasion, fines migration, silica plugging, and scaling being the most common. Mineral scale deposition occurs in the wellbore or in the natural fractures through which water is either injected or produced. In producing wells, the composition of scale is dependent on the mineralogy of the metamorphic formation. In injection wells, the scale is dependent on the composition of the injected water. With limited information regarding the mineralogy of the scale and the formation, many conventional matrix treatments are unsuccessful. A hybrid design methodology, combining sandstone and carbonate acidizing techniques has proved to be the first step to successfully treating Mexico's and Central America's geothermal wells The treatments are then further customized for each field to optimize productivity and injectivity. The final fluid composition is often very different from that used in conventional treatments due to different selection criteria and placement techniques. Identifying and understanding this concept has helped producers in Mexico and Central America increase their energy production per well by an average of 65%. While in some cases energy production has increased 300%. The hybrid design methodology has been successfully used to stimulate more than 50 geothermal wells in Mexico and Central America - Humeros (Puebla), Tres Virgenes (Baja California), Azufre's (Michoacan), Berlin (El Salvador) and San Jacinto (Nicaragua). The results of these campaigns demonstrate that it is possible to consistently improve the productivity of geothermal wells through the correct treatment.

Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells. However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model. A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations. This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.