Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs. From tight gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial viability.
A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral. Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the lateral, the fracture isolation technique and job size. Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique.
While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity receives lesser attention. Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as "infinitely conductive" features. However, many factors that affect the realistic conductivity of the fracture are poorly understood or overlooked. This often leads to a less than optimal outcome with wells producing below the reservoir potential.
This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics, are considered among other variables. The theory behind this concept is presented and supported with case studies where it has been applied in the field to various unconventional reservoirs.