Hydraulic fracturing and reservoir simulation are used by operators in shale to optimize design parameters such as well spacing, cluster spacing, and injection schedule. In this paper, we address ‘freqently asked questions’ that we encounter when working on hydraulic fracture modeling projects with operators. First, we discuss three high-level topics: (1) data-driven and physics-based models, (2) the modeling workflow, and (3) planar-fracture modeling versus ‘complex fracture network’ modeling. Next, we address specific technical topics related to modeling and the overall physics of hydraulic fracturing: (1) interrelationships between cluster spacing and other design parameters, (2) processes affecting fracture size, (3) fracture symmetry/asymmetry, (4) proppant settling versus trapping, (5) applications of Rate-Transient Analysis (RTA), (6) net pressure matching, (7) Initial Shut-In Pressure (ISIP) trends along the wellbore, and (8) the effect of understressed/underpressured layers. We discuss practical modeling decisions in the context of field observations.

In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.