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.

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.

There is mounting evidence that, unless greenhouse gas (GHG) emissions fall back quickly, the goals outlined by the 2015 Paris Agreement to keep the global temperature rise well below 2 °C and preferably 1.5 °C will not be met. In response to these concerns, direct air carbon capture and storage (DACCS) technologies are gaining research and development attention. This article provides a thorough comparison of the two leading DACCS variants and reports on their status among major research and policy institutions worldwide. By translating the operating and capital costs to the Australian context, we assess the viability of DACCS implementation using either cheap renewable or legacy fossil energy to power CO2 extraction plants.

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.

As the development of hydrocarbon from shale resources increases exponentially globally, it is essential to have a clear understanding of the key variables for evaluating shale reservoirs and to define the best methods for effectively stimulating wells. However, this is not easy considering that each tool has both advantages and drawbacks with respect to technical, methodological, and economic matters. That is why, for shale projects, it is necessary to know the vital variables to optimize the collection of information, costs, and, of course, the validity of final results and interpretations. For initial characterization, reference information from previously fractured horizontal wells in the same formation should be considered and a holistic approach using characterization from petro-physical, geomechanical, mineralogy, and geochemical analysis should be considered during the determination of the best zones to be fractured. Analysis and use of diagnostic fracture injection testing (DFIT) and minifrac testing is also to be reviewed for the final calibration of fracture models before execution of the operation. Interpretation of micro-seismic monitoring during fracturing has great importance for obtaining models to optimize completions of wells and the development of a reservoir after an initial approach. This work analyzes and evaluates different sources of information and studies performed. Several factors and effects during the design stage are presented, such as using regional stress studies to estimate possible interference between the fracture stages and its effect on final fracture space determination. All in all, using this information is recommended for the initial approach during fracture design for the first wells in a new formation, proving to be a novel methodology to optimize and accelerate the development of a basin that can be applied later to following wells, helping save both time and resources.