The first hydraulic stimulation in the oil and gas production industry occurred in 1949. It is estimated that more than two million fracture treatments have been performed since then throughout the world with the majority in North America. Initial use focused on conventional oil and gas reservoirs but has recently been expanded to other reservoirs where permeabilities are much lower. Hydraulic stimulation is used to create fractures in a targeted rock formation permitting oil or natural gas to flow to the wellbore.
Hydraulic stimulation improves hydrocarbon production by pumping a sand-water mixture into the hydrocarbon formation, natural gas shales in this instance, at controlled pressures high enough to crack (‘fracture’) the rock. The sand in the water is used to maintain the small fractures open and create small pathways for the natural gas to flow into the well.
Fractures: Their orientation and length
Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience and technical data, horizontal fractures will occur at depths less than approximately one kilometer. As depth increases beyond approximately one kilometer, overburden stress increases making the overburden stress the dominant stress. Since hydraulically induced fractures are formed in the direction perpendicular to the least stress, the resulting fracture in shale formations at depths greater than approximately one kilometer will be oriented in the vertical direction.
The distance that a fracture will travel is controlled by the upper confining zone or formation and the volume, rate, and pressure of the fluid that is pumped. The confining zone will limit the vertical growth of a fracture because it either possesses sufficient strength or elasticity to contain the pressure of the injected fluids or an insufficient volume of fluid has been pumped. The greater the distance between the fractured formation and a groundwater aquifer, the more likely it will be that multiple formations possessing the qualities necessary to stop the fracture will occur. Natural attenuation of the fracture will occur over relatively short distances due to the limited volume of fluid being pumped and dispersion of the pumping pressure regardless of intersecting migratory pathways.
The completion fluids are comprised of approximately 99.9 % fresh water and proppant. The proppant is usually sand but can be other material with similar characteristics as sand but more appropriate for the type of shale being fractured. The remaining 0.1% are additives required in order to ensure proper placement of the proppant into the small cracks created in the shale. Because the make-up of the completion fluid varies from one geologic basin or formation to another to meet the specific needs of each area, there is no one size fits all formula for the volumes for each additive. Although the hydraulic fracturing industry may have a number of compounds that can be used in a hydraulic completion fluid, any single fracturing job would only use a few of the available additives.
The chart shown below depicts generic hydraulic fracturing chemical usage including the types of chemicals, their uses in the process and the consequences of not using them.
Once the shale rock has been fractured and the proppant placed within the small fractures, the water and highly diluted additives are flowed back to the surface (also called ‘flowback’). The flowback water can be comprised of as little as 3% and as much as 80% or more of the total amount of water and other material used to fracture the well. Besides the original fluid used for fracturing, flowback water can also contain fluids and minerals that were in the fractured formation.
The flowback water is either recycled and re-used through the use of filtration, reverse osmosis, ion exchange and other technologies or treated at certified treatment and disposal facilities. The remaining water within the hydrocarbon shale formation are either produced with the natural gas or permanently trapped within the reservoir via adsorption.