In organic shales, hydraulic fracturing is an important parameter to optimize production of horizontal wells. For a lateral standalone, propped surface should be maximized to increase production (by increasing total proppant per well). While in the case of a pad, well spacing is an additional constrain for hydraulic fracture dimensions not to overlap with hydraulic fractures of neighboring offsets. Competition for production between laterals of a given pad should be minimized and is the result of both well spacing and hydraulic fracture design. A numerical model coupling an explicit description of the hydraulic fracture geometry and reservoir simulation is proposed. Fracturing simulator accounts for material balance, geomechanics, interaction with natural fractures and stress shadowing within and in between fracturing stages. Production interference is evaluated by comparing forecasted production of a lateral standalone (single well approach) against this same lateral while surrounded by offsets competing for production (multi well approach). Sensitivities are run assuming different completion and well spacing scenarios varying different parameters such as fluid and proppant volume, fracturing fluid type and staging. Production interference between horizontal wells might reduce the final recovery of each individual well. However it provides an opportunity for simultaneous optimization of completion and well spacing to guide field development. Hydraulic Fracture dimensions must match well spacing. Variation of fracture geometry along the lateral should be accounted for to evaluate well spacing and prevent the excessive growth of one single facture within a given stage. Completion design can be engineered by adjusting hydraulic fracture treatment volume, perforation cluster spacing or fracturing fluid viscosity to increase the overall consistency of the resulting fracture geometry and reduce effect of production interference between laterals of a given pad. Novelty of the proposed methodology relies on the explicit description of the hydraulic fracturing geometry and direct coupling with reservoir simulation, not only for a single well, but considering a whole pad of horizontal wells as per a possible development of the Vaca Muerta shale.

Low-permeability formations must be hydraulically fractured to produce at commercial rates. A good understanding of the formation stress conditions is critical for completion design, but requires in-situ measurement as calibration to support the geomechanical evaluation. This calibration is commonly done using diagnostic formation injection test (DFIT) methodology by creating a hydraulic fracture and then waiting for it to close through leakoff to the formation. However, in a low-permeability low-leakoff environment, application of this approach might become limited because of the time to fracture closure and the non-uniqueness of the interpretation. This paper demonstrates the applicability of the fracture flowback method to define closure pressure. Although proposed in the 1980s, this method has been underused by the industry. One of the objectives of this paper is, therefore, to advocate through field examples its simplicity of development, interpretation, and repeatability, particularly in low-leakoff reservoirs such organic shale formations. The procedure is composed of a sequence of various cycles of pump-in flowback through a fixed choke, pressure rebound, and fracture reopening. The proposed methodology offers several minimum stress measurements for repeatability and quality check purposes, reduces interpretation non-uniqueness, and can be completed within 1 hour, making it compatible with the hydraulic fracturing operations. Test design considerations, such as well geometry, pump rate, fluid volume, choke size, or perforation requirements, are reviewed to maximize the chance of success. Interpretation of the different possible patterns that can be observed is discussed and illustrated with practical examples from the Vaca Muerta shale. Comparison is made between the pump-in flowback and calibration decline approaches performed over the same interval. Repeatability is evaluated, and discrepancies between cycles are investigated. A direct application of the method is the calibration of a stress profile when applied to a vertical well. However, additional observations related to the fracture closure mechanism or residual fracture conductivity can be drawn by detailing the flowed-back volumes or rate of rebound pressure. These observations can be related to the lithology when the procedure is implemented in different intervals of the same formation.

This paper presents an operator's approach to optimize future well performance by fully integrating all the data captured in the Vaca Muerta shale. Based upon insight from the study, the operator needed to make more informed asset management decisions, understand the interaction between the shale and the hydraulic fracture network, and improve economics. Data were captured from several wells, both vertical and horizontal. The data incorporated into the study included fieldwide seismic data, as well as mineralogical, geomechanical, well plan, drilling, completion, microseismic monitoring, and production data from the wells.The project comprised one case history involving the hydraulic fracture stimulation treatment of a cluster of horizontal wells. Microseismic hydraulic fracture monitoring (HFM) was utilized to "track" the development of the hydraulic fractures in real time as they propagated throughout the formation. The stimulation activity from the well was monitored from a horizontal array placed in a horizontal lateral drilled parallel to the target well but landed~80 m shallower in the vertical section.An integrated unconventional-reservoir-specific workflow was utilized to develop and evaluate the completion strategies for the subject well. First, a fieldwide 3D static geologic model was constructed using the aforementioned data to determine the best reservoir and completion qualities of the Vaca Muerta formation. Next, the model was used to develop the completion strategy, including staging, perforation scheme, stimulation design, etc., for the wells. The completion strategy and stimulation design were performed utilizing an automated, rigorous, and efficient multistaging algorithm (completion advisor). This enabled targeting the reservoir section having the best reservoir and completion qualities for the stimulation treatments. The stimulation designs were performed using a state-of-the-art unconventional hydraulic fracture simulator that properly simulates the complex fracture propagation in shale reservoirs, including the explicit interaction of the hydraulic fractures to the pre-existing natural fissures in the formation and performs automatic gridding of the created complex fractures to rigorously model the production response from the tridimensional fracture network.A comparison between the microseismic fracture geometry to the planned fracture geometry is revealing; it shows that the application of this new technology can identify some of the complications and

Production modeling is a process that requires analyzing several steps, from reservoir characterization, completion and hydraulic fracturing, up to the optimization in the production system. Traditionally these processes can be analyzed independently with separated specialized tools. However in unconventional reservoirs, as the Vaca Muerta shale, dependency between the stimulation treatment and the well productivity is critical. This work proposes a workflow to evaluate the joint impact of hydraulic fractures with the static and dynamic characterization of the reservoir.The available static information (geophysics, petrophysics, geomechanics and natural fracture interpretation) is integrated to build a geological model. Then, hydraulic fracturing is simulated numerically using the Unconventional Fracture Model (UFM). The model takes into account the interaction between the existing natural fractures and the created hydraulic fractures during the stimulation treatment. The resulting geometry of the hydraulic fractures is gridded in an unstructured manner. The model reproduces explicitly the volume and permeability with the appropriate distribution along each branch of hydraulic fractures according to the executed completion. Dynamic simulation can be run to perform a history match of the available production data. Hydraulic fracture geometry, driven by geomechanics and natural fractures, is a key component of the process and might be reviewed if no production match can be achieved making the overall workflow iterative. Additionally, automation through assisted history matching is proposed to investigate different possible solution and reduce the timeframe of the study.Once calibrated with production, the model allows several applications. The different possible solutions considered by the assisted history match process permit the evaluation of the uncertainty of final recovery when forecasting production. Sensitivity analysis over a given hydraulic fracture geometry shows the major role of the matrix saturation and conductivity degradation over the final recovery. Completion can be optimized by considering different scenarios and showing the direct correlation between generated propped surface and well productivity. Different fracture designs can be investigated to increase the propped surface highlighting the importance, not only of the proppant volume, but also of the proppant transport capability of the fracturing fluids to be used.

Unconventional wells require hydraulic fracturing to be economic. Several levers for improving well productivity are available including stage spacing, cluster spacing, and sand loading however much of the recent focus has been on perforation design as well as a more uniform distribution of sand and water. This paper proposes to evaluate how optimizing the perforation strategy might enhance stimulation distribution along the lateral, in the Marcellus shale. Three different perforation designs were tested for better understanding of perforation efficiency, when considering design options such as perforation diameter, tapered perforating, and Extreme Limited Entry (XLE). A combination of step down tests, downhole perforation imaging and modeling are used to compare the different designs and support the conclusions. Downhole ultrasonic perforation imaging, even if it only captures an end-of-job snapshot, provides valuable insight to the dynamics of limited entry perforating and sand distribution. The pre-fracture diameter is identified as a key uncertainty, while post-fracture measurements show variations from the specifications of the shape charge and, in some instances smaller perforation diameters when compared to the expected value. The current dataset allows for a better understanding on the concept of erosion and how to correlate erosion with actionable design parameters such as perforation diameter or rate per perf. Downhole ultrasonic measurement of the perforation exit diameter, along with the corresponding erosion assumptions, are combined with modeling to recreate the rate and pressure evolution along the fracture stage., In addition, one can infer the actual volume of sand placed in each cluster in order to provide a quantitative assessment for future performance evaluation.