In hydraulic fracture stimulation of conventional reservoirs (e.g. tight gas and deep water unconsolidated sands), the use of sophisticated design models is almost indispensable. These hydraulic fractures are typically single fracture treatments and executed from near vertical wellbores. It is well understood that the post-fracture productivity is directly linked to achieving an optimum hydraulic fracture conductivity, which is governed largely by propped fracture length and width. From an engineering and operation execution point-of-view, the goal is to pump into the fracture the desired (large) volume of proppant without encountering pre-mature ‘screen-out’. Therefore, the prediction of fracture geometry and the design of pad volume become critical for propped fracture design. Models are calibrated on-site with dedicated mini-frac tests prior to main propped fracture treatments. Two important calibration parameters are fluid efficiency (leak-off behavior) and minimum in-situ stress (stress profile/contrast). The injection pressure during fracturing, which is readily available, is a valuable source of information and often analyzed and compared with model prediction for fracture diagnostics. In practice, a wide range of models have been employed successfully. However, such considerations do not appear to be important for unconventional resources where multiple fractures are pumped from a long horizontal well. In fact, multi-fracced horizontal well technology has advanced through field trials and experimentation without much help from modelling or understanding of multiple-fracture mechanics. Perhaps one reason is the lower risk of screening-out. This could be due to 1) the extreme low permeability of unconventional shales, which renders the use of high proppant concentration unnecessary and 2), the treatment of multiple fractures in one stage of pumping allows for one or two of the fractures to screen-out without causing an unacceptable rise of pumping pressure. In fact, with the pumping of tens and even a hundred fractures in one horizontal well, the ‘system’ appears to tolerate some ‘non-performing’ fractures without impairing the ultimate production. Conventional wisdom has it that fracture length should be maximized, but in the development of onshore unconventional resources, the horizontal wells are spaced evermore closer to each other, and consequently, the fracture length may not need to be long in order to access the reserves. Operators have successfully fractured and produced from unconventional reservoirs without the use of advanced modelling technology. This begs the questions of what areas of research and model design parameters should we focus on? Can we avoid the ‘details’ while dealing with the ‘big picture’ such as fractures spacing, horizontal well length/direction, the well’s landing depth, and their impact on cost and production? Are research and model development sufficiently guided and tested by field data/observations?