Abstract: Systems, tools, and methods for optimizing fracturing schedules located along a horizontal wellbore include obtaining drilling cuttings during a drilling operation representative of a predetermined interval of the horizontal wellbore, performing at least one analytical process on the obtained drilling cuttings to determine at least one geomechanical property of the interval of the obtained drilling cuttings for the interval, generating a formation analysis estimation for the interval from the, wherein the formation analysis estimation comprises at least one of (i) a brittleness of the formation at the interval or (ii) a minimum horizontal stress of the formation at the interval, and based on the formation analysis estimation, at least one of (i) configuring a super-stage for deployment to the interval to perform a fracturing operation or (ii) designing a fracturing schedule to be performed to frac the formation at the interval.

Abstract: A method for evaluating and optimizing complex fractures, in one non-limiting example far-field complex fractures, in subterranean shale reservoirs significantly simplifies how to generate far-field fractures and their treatment designs to increase or optimize complexity. The process gives information on how much complexity is generated for a given reservoir versus distance from the wellbore under known fracturing parameters, such as rate, volume and viscosity. The method allows the evaluation of the performance of diversion materials and processes by determining the amount of fracture volume generated off of primary fractures, including far-field secondary fracture volumes. The methodology utilizes fracture hit times, volumes, pressures and similar parameters from injecting fracturing fluid from a first primary lateral wellbore to create fractures and record fracture hit times, pressures and volumes from a diagnostic lateral wellbore in the same interval.

Abstract: Improving the knowledge about how hydraulic fracture networks are generated in subsurface shale volumes in unconventional wellbores may be accomplished with various configurations of at least one diagnostic lateral wellbore using at least one diagnostic device disposed in the diagnostic lateral wellbore. By extending diagnostic lateral wellbores from adjacent lateral wellbores and/or separately drilling diagnostic lateral wellbores, and analyzing signals received by diagnostic devices placed in the diagnostic lateral wellbores, knowledge about fracture networks, the parameters that control fracture geometry and reservoir production and how reservoirs react to refracturing techniques may be greatly improved. Additionally, such diagnostic lateral wellbores can provide quicker location of sweet-spot horizons in reservoirs.

Abstract: Improving the flow of hydrocarbons from shale lateral wellbores in unconventional wellbores may be accomplished with various configurations of assisting lateral wellbores and/or kick-off wellbores from primary lateral wellbores and/or secondary or assisting lateral wellbores. By extending fracture networks from adjacent lateral wellbores and/or adjacent kick-off wellbores so that the fracture networks from different wellbores are in fluid communication with one another, the flow of various fluids between the adjacent wellbores provides another dimension of control over the wellbores and fracture networks used to recover hydrocarbons from the shale intervals of interest.

Abstract: Diagnostic or assisting lateral wellbores can have a significant benefit for injecting and distributing treatment fluids and other materials within complex fracture networks that surpass conventional injection at the primary lateral wellbore perforations for acquiring empirical knowledge about the numerous processes that influence shale reservoir production which occur after primary shale reservoir stimulation. Injection of diagnostic treatment fluids or treating chemicals for understanding production optimization, such as water-block removal, fines migration removal, and treating chemicals for prevention of scale and paraffin deposition, can be injected along the diagnostic lateral wellbore or frac interval lateral wellbores to give broader and/or deeper distribution into the fracture network than by using mono-bore-centric diagnostic injection techniques.

Abstract: Systems, tools, and methods for optimizing fracturing schedules located along a horizontal wellbore include obtaining drilling cuttings during a drilling operation representative of a predetermined interval of the horizontal wellbore, performing at least one analytical process on the obtained drilling cuttings to determine at least one geomechanical property of the interval of the obtained drilling cuttings for the interval, generating a formation analysis estimation for the interval from the, wherein the formation analysis estimation comprises at least one of (i) a brittleness of the formation at the interval or (ii) a minimum horizontal stress of the formation at the interval, and based on the formation analysis estimation, at least one of (i) configuring a super-stage for deployment to the interval to perform a fracturing operation or (ii) designing a fracturing schedule to be performed to frac the formation at the interval.

Abstract: A method for evaluating and optimizing complex fractures, in one non-limiting example far-field complex fractures, in subterranean shale reservoirs significantly simplifies how to generate far-field fractures and their treatment designs to increase or optimize complexity. The process gives information on how much complexity is generated for a given reservoir versus distance from the wellbore under known fracturing parameters, such as rate, volume and viscosity. The method allows the evaluation of the performance of diversion materials and processes by determining the amount of fracture volume generated off of primary fractures, including far-field secondary fracture volumes. The methodology utilizes fracture hit times, volumes, pressures and similar parameters from injecting fracturing fluid from a first primary lateral wellbore to create fractures and record fracture hit times, pressures and volumes from a diagnostic lateral wellbore in the same interval.

Abstract: Improving the knowledge about how hydraulic fracture networks are generated in subsurface shale volumes in unconventional wellbores may be accomplished with various configurations of at least one diagnostic lateral wellbore using at least one diagnostic device disposed in the diagnostic lateral wellbore. By extending diagnostic lateral wellbores from adjacent lateral wellbores and/or separately drilling diagnostic lateral wellbores, and analyzing signals received by diagnostic devices placed in the diagnostic lateral wellbores, knowledge about fracture networks, the parameters that control fracture geometry and reservoir production and how reservoirs react to refracturing techniques may be greatly improved. Additionally, such diagnostic lateral wellbores can provide quicker location of sweet-spot horizons in reservoirs.

Abstract: Improving the flow of hydrocarbons from shale lateral wellbores in unconventional wellbores may be accomplished with various configurations of assisting lateral wellbores and/or kick-off wellbores from primary lateral wellbores and/or secondary or assisting lateral wellbores. By extending fracture networks from adjacent lateral wellbores and/or adjacent kick-off wellbores so that the fracture networks from different wellbores are in fluid communication with one another, the flow of various fluids between the adjacent wellbores provides another dimension of control over the wellbores and fracture networks used to recover hydrocarbons from the shale intervals of interest.

Abstract: An apparatus having conduits, flattened tubing or pipes of varying widths, heights and/or lengths may simulate a network of fractures that may be used to experimentally evaluate the flow of treatment fluids (e.g. fracturing fluids) within narrow, shale-type fractures. The tubing or pipes each have an interior space with a height and a width, and in one non-limiting embodiment the ratio of height/width is at least 10. The conduits may be constructed of flattened tubing or constructed from components designed and engineered to have the correct height/width ratio. The apparatus may be used to empirically develop diversion principles, more precise numeric models and the parameter relationships that control fluid diversion, secondary fracture initiation and the development of complex fracture networks.