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.

The purpose of this research was to identify challenges related to optimizing hydraulic fracturing in tight-gas condensate reservoirs using liquid resins to coat fracturing proppants. The selected case histories illustrate specific documented solutions of recent, successful approaches using this technology in the Burgos basin by analyzing production behavior before and after treatment in an exploratory well. When discussing post-treatment production evaluation, the immediate pressure response and water flowback are commonly the very first parameters to observe during the cleanup stage. This surging process may indicate whether the objective was reached or not. However, additional uncertainty can arise when undesired monthly decline rates are observed, suggesting a loss of conductivity that can be caused by several factors—fracture embedment, early diagenesis, proppant crushing, fines migration caused by high producing rates, and stress cycling, among others—compromising the propped fracture effectiveness. Real fracture growth during stimulation treatments, which can be monitored by microseismics, determines production longevity and is the actual criteria for determining fracturing success. This ultimate goal has been achieved in Burgos basin by applying the appropriate fracture design and considering a wide range of permeabilities present in the reservoir, as well as using proper geomechanical models along identified gas-condensate pay zones. Based on these findings, the recommended and applied treatment design used a liquid resin coating on 40 to 100% of the ceramic proppant, which was applied on-the-fly during pumping of the high-concentration proppant stages. This new technique led to obtaining an important production increase, maximizing reserves, and creating new opportunities for the operator to drill several wells in the area.

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.

Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico-located in the North-East area of the country and bordered with South Texas in the USA-problems still persist.This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.