The optimization of stimulation treatments in Mexico has required the use of novel diversion technologies to increase the productivity of wells by improving the coverage of stimulation fluids and reducing completion costs. Self-degrading particulate has become widely used in the country because of the diverter flexibility. Job experiences range from hydraulically fracturing unconventional reservoirs to the matrix acidizing of naturally fractured carbonate formations. The purpose of this paper is to verify the effectiveness of this material for achieving the selective stimulation of multiple intervals, either in horizontal or vertical wells.Because there is no confidence in a complete stimulation of all open intervals, diagnostic techniques have been implemented to determine the effectiveness of diversions. For near-wellbore (NWB) monitoring, technologies such as radioactive tracers and distributed temperature sensing (DTS) have been used to determine treatment fluid locations after the application or in real-time. Downhole microseismic monitoring has been performed for far-field indications of diversion success in hydraulic fractures of vertical wells with multiple intervals open at the same time. This paper discusses four wells from the north, central, and south regions in Mexico. All of them have completely different reservoir properties and completion types.Improved production increase was the main difference between wells where diversion with selfdegrading particulate diverters was used compared to those that were not treated with diverters; a production increase from 30 to 70% was achieved. Completion time was reduced with the implementation of the novel self-degrading particulates vs. other possible methods, allowing faster return of investment (ROI). Real-time decision making could be performed using both a diverter and monitoring techniques to assure a uniform treatment placement. Another differentiator was the simple logistics required to handle the material compared to other additives employed in the past. Because of the performance of the diverter, it has been applied in more reservoirs with extremely variable permeabilities across the country (tight gas and oil sandstones, gas and oil shales, and naturally fractured oil-bearing carbonates).Downhole temperature is the main controlling factor to accelerate or retard the degradation of the particulate, as it must take into account that in cooler formations, longer times are required to achieve complete degradation. Its independence of the wellbore geometry has increased the implementation in openhole and cased-hole completions, despite the final shape of the perforations.

This paper presents the results from a diagnostic fracture extended injection test performed in a well completed in the first oil shale reservoir confirmed in Mexico, which is situated in the Upper Jurassic in the Burgos basin in the northern part of the country.The test was executed in an exploratory horizontal well during the first stage, perforated with abrasive hydra-jetting, and reservoir properties had been previously set with the correlation information logs. Usually performed before treatment(s), the primary objective of a diagnostic fracture injection test (DFIT) is to estimate parameters that provide fracture information critical both to designing the fracturing treatment and the characterization of the formation, as well as to obtain more reliable information for production engineering. Compared to other methods for the diagnostic of reservoir properties, the economic value that DFIT can provide is particularly effective in formations with ultralow permeability (K Ͻ0.1 md). These injection-falloff tests, which include small volumes of fluid pumped into the formation and use few resources to obtain data, proved to be an essential tool to understand some reservoir characteristics which can provide the information necessary for an optimal fracture design and warn of issues that might be experienced during the stimulation execution.This paper evaluates all aspects related to the pressure falloff and how important values, such as permeability and reservoir pressure, were obtained using analysis in real time from the wellsite.

Northern Mexico has the first major non-associated gas producer basin in the country. However, unconventional reservoirs (mostly very low-permeability shale gas and oil formations) have not been produced so far in this area. These types of reservoirs are located in sedimentary environments where rocks have a high organic-rich content that, when subjected to pressure and temperature conditions, transform this matter into oil and gas. Stimulating a source rock is relatively a new phenomenon in the oil and gas industry. Because these source rock formations have very low permeability, massive hydraulic fracturing stimulation treatments are required to produce at economical rates. Experience and knowledge in drilling and completing wells in this type of reservoir have increased in the last decade. New technologies to evaluate this type of formation and post-production studies have significantly improved, offering better completion methods and techniques.The Eagle Ford formation in Mexico is located in the northern portion of the country and is considered an extension of the Eagle Ford formation that crosses southern Texas in the United States; during June 2011, production from this US formation was 636 MMscf/D and 97,000 bbl/D.For the completion of this subject well, which was drilled horizontally, the evaluation techniques, completion plan, and stimulation design were performed using local experience acquired in unconventional reservoirs (tight oil and tight gas) along with experience from the US in shale gas and oil shale formations.This work shows how this type of formation was identified through several studies, completion was designed and executed, and the fracture treatments were optimized, as well as production matching and forecasting results. This was all performed in the context of an operation that had never been performed in Mexico.

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.

In northern Mexico, from the Burgos basin to the Chicontepec field, horizontal wells have been a viable choice for exploiting hydrocarbons in tight gas and shale reservoirs. Successful drilling and completion of such wells has allowed goals in this complex operation to be reached. The learning curve trend means good knowledge has been acquired and difficulties encountered during completions can be addressed using new techniques available within the area. To achieve high performance when fracturing multiple zones, the application of an abrasive perforating technique using coiled tubing (CT) has proven a very effective alternative for acquiring optimum results. This has been particularly true for applications in highly deviated and horizontal wells. Although this technique has been applied in others regions since 1998, its implementation within this region has only become more common during the past three years. Using field experience with actual cases, this paper illustrates the available technologies and techniques that have become a new process in this region. Because of the undisputed completion and production results, pinpoint multistage fracturing is becoming the preferred completion technique used by the operator and will be used extensively as more horizontal wells are scheduled to be drilled and completed in upcoming years. Similarly, this has been the preferred choice when the formation is estimated to produce liquids.