Fracture pattern development has been a challenging area of research in the Earth sciences for more than 100 years. Much has been learned about the spatial and temporal complexity inherent to these systems, but severe challenges remain. Future advances will require new approaches. Chemical processes play a larger role in opening‐mode fracture pattern development than has hitherto been appreciated. This review examines relationships between mechanical and geochemical processes that influence the fracture patterns recorded in natural settings. For fractures formed in diagenetic settings (~50 to 200 °C), we review evidence of chemical reactions in fractures and show how a chemical perspective helps solve problems in fracture analysis. We also outline impediments to subsurface pattern measurement and interpretation, assess implications of discoveries in fracture history reconstruction for process‐based models, review models of fracture cementation and chemically assisted fracture growth, and discuss promising paths for future work. To accurately predict the mechanical and fluid flow properties of fracture systems, a processes‐based approach is needed. Progress is possible using observational, experimental, and modeling approaches that view fracture patterns and properties as the result of coupled mechanical and chemical processes. A critical area is reconstructing patterns through time. Such data sets are essential for developing and testing predictive models. Other topics that need work include models of crystal growth and dissolution rates under geological conditions, cement mechanical effects, and subcritical crack propagation. Advances in machine learning and 3‐D imaging present opportunities for a mechanistic understanding of fracture formation and development, enabling prediction of spatial and temporal complexity over geologic timescales. Geophysical research with a chemical perspective is needed to correctly identify and interpret fractures from geophysical measurements during site characterization and monitoring of subsurface engineering activities.

Assessing the production potential of shale gas can be assisted by constructing a simple, physics-based model for the productivity of individual wells. We adopt the simplest plausible physical model: one-dimensional pressure diffusion from a cuboid region with the effective area of hydrofractures as base and the length of horizontal well as height. We formulate a nonlinear initial boundary value problem for transient flow of real gas that may sorb on the rock and solve it numerically. In principle, solutions of this problem depend on several parameters, but in practice within a given gas field, all but two can be fixed at typical values, providing a nearly universal curve for which only the appropriate scales of time in production and cumulative production need to be determined for each well. The scaling curve has the property that production rate declines as one over the square root of time until the well starts to be pressure depleted, and later it declines exponentially. We show that this simple model provides a surprisingly accurate description of gas extraction from 8305 horizontal wells in the United States’ oldest shale play, the Barnett Shale. Good agreement exists with the scaling theory for 2133 horizontal wells in which production started to decline exponentially in less than 10 yr. We provide upper and lower bounds on the time in production and original gas in place. NOMENCLATURE Symbols and dimensions of key quantities Symbol SI dimensions Field dimensions c –compressibility Pa − 1 μ cip d –half-distance between hydrofractures m ft D –production decline coefficient k –permeability m 2 darcy K –partitioning coefficient m –gas pseudopressure Pa s − 1 psi 2 / cp m –cumulative produced mass kg ton M –Original gas in place kg ton M –molecular weight kmol lbmol H –formation thickness m ft p –pressure Pa psi q –volumetric flow rate m 3 s − 1 bbl/d Q –volumetric cumulative production m 3 bbl R —universal gas constant J/kmol-K psi-ft3/lb-mol RF –recovery factor S –saturation t –time in production s month, y T –temperature K °F, °C v ^ –specific volume m 3 / kg ft 3 / lbm y –molar composition Z –compressibility factor α –hydraulic diffusivity m 2 s − 1 ft 2 / y κ –dimensionless constant for gas production in square root phase K –dimensional constant for gas production in square root phase kg / s ton / month μ –gas viscosity Pa s cp ρ –density kg m − 3 lbm / ft 3 τ –time to interference s y ϕ –porosity Subscripts and Superscripts Symbol Meaning a adsorbed f (hydro)fracture g gas i initial L Langmuir S T stock tank conditions w water w c connate water ∼ dimensionless ∧ specific 0 reference or standard conditions

We conducted experiments in which steel and silicon or quartz are clamped together. Even with the smallest tangential forces we could apply, we always found reproducible sliding motions on the nanometer scale. The velocities we study are thousands of times smaller than in previous investigations. The samples first slide and then lock up even when external forces hold steady. One might call the result “slip-stick” friction. We account for the results with a phenomenological theory that results from considering the rate and state theory of dynamic friction at low velocities. Our measurements lead us to set the instantaneous coefficient of static friction that normally enters rate and state theories to zero.

About half of US natural gas comes from gas shales. It is valuable to study field production well by well. We present a field data-driven solution for long-term shale gas production from a horizontal, hydrofractured well far from other wells and reservoir boundaries. Our approach is a hybrid between an unstructured big-data approach and physics-based models. We extend a previous two-parameter scaling theory of shale gas production by adding a third parameter that incorporates gas inflow from the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find that on average stimulation fractures are spaced every 20 m, and the effective permeability of the unstimulated region is 100 nanodarcy. We estimate that over 30 years on production the Barnett wells will produce on average about 20% more gas because of inflow from the outside of the stimulated volume. There is a clear tradeoff between production rate and ultimate recovery in shale gas development. In particular, our work has strong implications for well spacing in infill drilling programs.

We examine the fracture mechanics of tearing graphene. We present a molecular dynamics simulation of the propagation of cracks in clamped, free-standing graphene as a function of the out-of-plane force. The geometry is motivated by experimental configurations that expose graphene sheets to out-of-plane forces, such as back-gate voltage. We establish the geometry and basic energetics of failure and obtain approximate analytical expressions for critical crack lengths and forces. We also propose a method to obtain graphene's toughness. We observe that the cracks’ path and the edge structure produced are dependent on the initial crack length. This work may help avoid the tearing of graphene sheets and aid the production of samples with specific edge structures.