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.
Currently, three unconventional wells have been drilled and three are nearing completion that have been targeted in the Upper Jurassic Pimienta. This source rock formation is a candidate to be Mexico's first shale and could become the most productive shale zone in the country. There are several reasons for this success, which are discussed in this paper.
Proppant flowback following a hydraulic fracture treatment, is a major problem in the Northern Mexico area. Frequently, Proppant flows back as the well returns to production. Generating huge amount of cost associated with wellbore cleanouts and damage to surface facilities. In addition, production is delayed due to long shut-in times and the need to initially produce the well under choke. Therefore, been able to control proppant flowback at fracture closure would not only eliminate the extra expenses associated with it, but would allow to return the well back to production immediately with optimized chokes. In other words, an optimized proppant free robusted production. This paper presents successful applications of stabilizing proppant packs with randomly oriented fibers of similar density to the proppant in dry gas reservoirs with low permeabilities (<0.5 md). All wells were put on production immediately following fracture treatment, with an average of almost 2 fold production increase over resin-coated proppant treatments, having a case with up to 12 folds of increase. During "clean-up" of the wells, return fluids were collected for evaluation confirming expected proppant control and fluid compatibility between fracturing gels and breakers. Finally, production performance months after the treatments are discussed including conclusions and recommendations derived from treatments. Introduction Proppant flowback has been of concern in hydraulic fracturing for more than 20 years. It has received increased attention in recent years as larger fracture widths and use of higher proppant concentrations have become more prominent. A crucial part of many successful hydraulic treatments is preventing the newly placed proppant from being dislodged by produced fluids flowing back into the wellbore. One common practice for controlling such flowback is to coat the proppant with resin, then allow the resin to cure, thereby holding the proppant in place, before the flow is initiated. Curable resin-coated proppants (RCP) are used as all or the last part (tail-in) of the proppant in the fracture. The resin coating cures to form a strong proppant pack under conditions of sufficient closure stress, shut-in, time, and temperature. Curable RCPs control proppant flowback in many cases, but have several disadvantages. They are known to interact with the fluid chemistry (pH crosslinkers, breakers, etc.), can reduce fracture conductivity, and may be prone to failure under cycling loading conditions. In addition, RCPs need specific temperature, shut in time and stress conditions to form a strong bond. At lower temperatures (<150 F) chemical activators must be added to promote cure. An alternative to curable resin-coated proppant is using fibers. Fibers reinforce the proppant pack by forming a net-like structure to hold the proppant in place and allow fluids to flow. The advantage of this method is that it is a physical mechanism without complicating chemical curing reactions. No combination of temperature, pressure or shut in time is needed to stabilize the proppant pack, allowing more flexibility of flowback procedures to maximize well production and reduce costs. P. 201
In 2010, exploration of gas-rich and possible liquid-rich shale reservoirs began in northern Mexico. The initial challenges as in any exploration project were to demonstrate the availability of reserves and set the foundation for future development of plays. Wells were aimed at the upper cretaceous Eagle Ford formation and at the Jurassic Pimienta formation. While exploration campaign continues, the first development wells have been drilled in some areas. A total of 19 horizontal wells have been drilled and completed by January 2014.The wells drilled in the latest stage of the exploration campaign in the Pimienta formation presented additional complexity, which led to an undesired trend of increased costs and extended completion times. Also, some of the wells drilled and completed during an earlier stage of the exploration campaign showed a rapid decline in production which directly threatened future development plans. To reverse these trends, a novel dynamic diversion technology for hydraulic fracturing treatments was implemented with positive results. This technology improves distribution of hydraulic fracturing treatments along the horizontal section of the wells, therefore allowing the stimulation of longer perforated intervals at once, ensuring that a great majority of the perforated clusters are efficiently stimulated. The need for mechanical plugs, to isolate the different hydraulic fracturing stages in the wells; the risk associated with pump down of plugs and milling times to remove these plugs were greatly reduced, which results in improved completion times and costs.This study presents four case histories in which the technology was applied. One of the cases refers to re-fracturing operations of the last 3 stages in a well with a horizontal section of approximately 1,500m which was initially stimulated with 17 hydraulic fracturing stages. The remaining cases refer to the completion of three exploratory wells in which the horizontal section was stimulated with multiple hydraulic fracturing stages using the dynamic diversion technology. The treatments were evaluated using different techniques which mainly included: radioactive tracers and pressure response analysis. Initial results showed evidence of diversion both in pressure response and tracer log analysis, as well as stable production after stimulation. Interpretation of radioactive tracer logs and numerical production forecasting results confirm effectiveness of methodology applied.The application of this technology can lead to a significant improvement in the efficiency of completions and effectiveness of stimulations of unconventional reservoirs in Mexico and around the world.
Occasionally during a pre-frac injection test the observed friction pressures are much higher than expected.These tests have frequently led to significant delays and expense in tight gas wells re-perforating the interval to be fractured in order to remove this ‘excess near-wellbore friction’ pressure.This paper presents a method to identify and mitigate the effects of two-phase flow during an injection test.Examples are presented which encountered very high apparent near-wellbore friction pressures that were actually due to two-phase flow.Subsequent testing with 100% liquid injection revealed normal near-wellbore friction pressures.A technique of repeating the test after a variable shut-in time has routinely served to eliminate the need for a costly and time-consuming re-perforating job. Introduction The Burgos basin is found in northeastern Mexico and is an extension of the south Texas Oligocene-Vicksburg trend.Production is from a series of sandstone reservoirs ranging in depth from 3000 ft (900 m) to more than 11000 ft (3300 m) and is primarily gas with condensate yields varying from 10 bbls/MMscf to more than 60 bbls/MMscf.The majority of these reservoirs are ‘tight gas’ and require fracture stimulation to obtain economical production rates.Permeability ranges from less than 0.02 mD to as high as 3 mD with an average of perhaps 0.2 mD. Gas wells in the Burgos basin are typically "tubingless" completions with a 2–7/8" or 3–1/2" casing string in shallow and intermediate depth wells and 4–1/2" tapered strings in the deeper wells.The small diameter completion precludes the use of a "deadstring" configuration for obtaining bottom hole fracturing pressures directly.A diagram of a typical well completion is shown in figure 1. Due to contractual requirements a low volume (35–40 bbls), single-rate injection test with 2% KCl water (called an ‘admit’ test) is run after perforating each zone.By analyzing the falloff data from these tests the minimum horizontal stress, sHmin in the pay zone is generally well known.In addition, these tests give important clues about the formation permeability and the reservoir pressure, although exact values for these are rarely obtainable.Figures 2 and 3 show an example of an admit test and an estimation of sHmin from a plot of the pressure vs. the Nolte ‘G’ function.After this analysis is complete the well will typically be evaluated with a flow test, prior to designing a fracture treatment.
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