A. What Is Hydraulic Fracturing?
Hydraulic fracturing is not a “drilling process.” Hydraulic fracturing is used after the drilled hole is completed. To simplify, hydraulic fracturing is the use of fluid and material to create or restore small fractures in a formation in order to stimulate production from new and existing oil and gas wells. This process creates paths that increase the rate at which fluids can be produced from the reservoir formations, in some cases by many hundreds of percent.
To ensure that neither the fluid that will eventually be pumped through the well, nor the oil or gas that will eventually be collected, enters the water supply, steel surface or intermediate casings are inserted into the well to depths of between 1,000 and 4,000 feet. The space between these casing “strings” and the drilled hole (wellbore), called the annulus, is filled with cement. Once the cement has set, then the drilling continues from the bottom of the surface or intermediate cemented steel casing to the next depth. This process is repeated, using smaller steel casing each time, until the oil and gas-bearing reservoir is reached (generally 6,000 to 10,000 ft). With these and other precautions taken, high volumes of fracturing fluids are pumped deep into the well at pressures sufficient to create or restore the small fractures in the reservoir rock needed to make production possible. The diagram shown below is a generalization of a typical Eagle Ford Shale gas well in south central Texas.
B. What’s in Hydraulic Fracturing Fluid?
Water and sand make up 98 to 99.5 percent of the fluid used in hydraulic fracturing. In addition, chemical additives are used. The exact formulation varies depending on the well.
C. Why is Hydraulic Fracturing Used?
Experts believe 60 to 80 percent of all wells drilled in the United States in the next ten years will require hydraulic fracturing to remain operating. Fracturing allows for extended production in older oil and natural gas fields. Hydraulic fracturing is also used to extend the life of older wells in mature oil and gas fields.
D.Hydraulic Fracturing Process)
The placement of hydraulic fracturing treatments underground is sequenced to meet the particular needs of the formation. Each oil and gas zone is different and requires a hydraulic fracturing design tailored to the particular conditions of the formation. Therefore, while the process remains essentially the same, the sequence may change depending upon unique local conditions. It is important to note that not all of the additives are used in every hydraulically fractured well; the exact “blend” and proportions of additives will vary based on the site-specific depth, thickness and other characteristics of the target formation
1. An acid stage, consisting of several thousand gallons of water mixed with a dilute acid such as hydrochloric or muriatic acid: This serves to clear cement debris in the wellbore and provide an open conduit for other frac fluids by dissolving carbonate minerals and opening fractures near the wellbore.
2. A pad stage, consisting of approximately 100,000 gallons of slickwater without proppant material: The slickwater pad stage fills the wellbore with the slickwater solution, opens the formation and helps to facilitate the flow and placement of proppant material.
3. A prop sequence stage, which may consist of several substages of water combined with proppant material (consisting of a fine mesh sand or ceramic material, intended to keep open, or “prop” the fractures created and/or enhanced during the fracturing operation after the pressure is reduced): This stage may collectively use several hundred thousand gallons of water. Proppant material may vary from a finer particle size to a coarser particle size throughout this sequence.
4. A flushing stage, consisting of a volume of fresh water sufficient to flush the excess proppant from the wellbore.
Other additives commonly used in the fracturing solution
• A dilute acid solution, as described in the first stage, used during the initial fracturing sequence. This cleans out cement and debris around the perforations to facilitate the subsequent slickwater solutions employed in fracturing the formation.
• A biocide or disinfectant, used to prevent the growth of bacteria in the well that may interfere with the fracturingoperation: Biocides typically consist of bromine-based solutions or glutaraldehyde.
• A scale inhibitor, such as ethylene glycol, used to control the precipitation of certain carbonate and sulfate minerals
• Iron control/stabilizing agents such as citric acid or hydrochloric acid, used to inhibit precipitation of iron compounds by keeping them in a soluble form
• Friction reducing agents, also described above, such as potassium chloride or polyacrylamide-based compounds, used to reduce tubular friction and subsequently reduce the pressure needed to pump fluid into the wellbore: The additives may reduce tubular friction by 50 to 60%. These friction-reducing compounds represent the “slickwater” component of the fracing solution.
• Corrosion inhibitors, such as N,n-dimethyl formamide, and oxygen scavengers, such as ammonium bisulfite, are used to prevent degradation of the steel well casing.
• Gelling agents, such as guar gum, may be used in small amounts to thicken the water-based solution to help transport the proppant material.
• Occasionally, a cross-linking agent will be used to enhance the characteristics and ability of the gelling agent to transport the proppant material. These compounds may contain boric acid or ethylene glycol. When cross-linking additives are added, a breaker solution is commonly added later in the frac stage to cause the enhanced gelling agent to break down into a simpler fluid so it can be readily removed from the wellbore without carrying back the sand/ proppant material.
E. Fracture Orientation
Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience, horizontal fractures will occur at depth less than approximately 2000 ft. because the Earth’s overburden pressure at these depths provides the least principal stress. If pressure is applied to the center of a formation under these relatively shallow conditions, the fracture is most likely to occur in the horizontal plane, because it will be easier to part the rock in this direction than in any other. In general, therefore, these fractures are parallel to the bedding plane of the formation.As depth increases beyond approximately 2000 ft., overburden stress increases by approximately 1 psi/ft., making the overburden stress the dominant stress This means the horizontal confining stress is now the least principal stress. Since hydraulically induced fractures are formed in the direction perpendicular to the least stress, the resulting fracture at depths greater than approximately 2000 ft. will be oriented in the vertical direction.In the case where a fracture might cross over a boundary where the principal stress direction changes, the fracture would attempt to reorient itself perpendicular to the direction of least stress. Therefore, if a fracture propagated from deeper to shallower formations it would reorient itself from a vertical to a horizontal pathway and spread sideways along the bedding planes of the rock strata.
F. Fracture Length/ Height
The extent that a created fracture will propagate 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.. This is important because the greater the distance between the fractured formation, the more likely it will be that multiple formations possessing the qualities necessary to impede the fracture will occur.
The results from the extensive fracture mapping in unconventional North American shale reservoirs database2) show that hydraulic fractures are better confined vertically (and are also longer and narrower) than conventional wisdom or models predict. Even in areas with the largest measured vertical fracture growth,the tops of the hydraulic fractures are still thousands of feet below the deepest aquifers suitable for drinking water. The data from these shale reservoirs clearly show the huge distances separating the fracs from the nearest aquifers at their closest points of approach, conclusively demonstrating that hydraulic fractures are not growing into groundwater supplies, and therefore, cannot contaminate them.
1) Pennsylvania Department of Environmental Protection
“Hydraulic Fracturing Overview.” 07/20/2010.
2)Extensive Fracture Mapping was done in the Barnett Shale in the Fort Worth Basin in Texas and in the Marcellus Shale in the Appalachian Basin.
Written By : Teguh Kristian Tampubolon