What fracking is all about – Fracking defined Part 2

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Consistent with the Energy Policy Act of 2005, the U.S. Environmental Protection Agency (EPA) published a final rule in 2006 that exempts stormwater discharges of sediment from construction activities at oil and gas exploration and production operations from the requirement to obtain a National Pollutant Discharge Elimination System (NPDES) ‡ stormwater permit as long as stormwater runoff to waters under the jurisdiction of the CWA are not contaminated with oil, grease, or hazardous substances. With this exemption, EPA specifically encouraged the oil and natural gas industry to develop and implement Best Management Practices (BMPs) to minimize the discharges of pollutants, including sediment, in stormwater both during and after construction activities.

In an effort to meet the expectations of EPA under this rulemaking — to incorporate successful voluntary stormwater management practices into day-to-day operations – the American Petroleum Institute (API) and the Independent Petroleum Association of America (IPAA), industry associations, and company representatives (referred to as the Stormwater Technical Workgroup (SWTW)), built upon the 2004 guidance document entitled Reasonable and Prudent Practices for Stabilization (RAPPS) of Oil and Natural Gas Construction Sites.

Through field validation of the RAPPS, gap identification, and concerted program improvements, the SWTW developed a voluntary guidance document that, if implemented correctly, will serve as a readily applicable tool for operators to use in order to efficiently and effectively maximize control of stormwater discharges at oil and natural gas exploration and production activities throughout the contiguous U.S.

Hydraulic fracturing is not new. The first commercial application of hydraulic fracturing as a well treatment technology designed to stimulate the production of oil or gas likely occurred in either the Hugoton field of Kansas in 1946 or near Duncan Oklahoma in 1949. In the ensuing sixty plus years, the use of hydraulic fracturing has developed into a routine technology that is frequently used in the completion of gas wells, particularly those involved in what’s called “unconventional production,” such as production from so-called “tight shale” reservoirs. The process has been used on over 1 million producing wells. As the technology continues to develop and improve, operators now fracture as many as 35,000 wells of all types (vertical and horizontal, oil and natural gas) each year.

Hydraulic fracturing has had an enormous impact on America’s energy history, particularly in recent times.
The ability to produce more oil and natural gas from older wells and to develop new production once thought impossible has made the process valuable for US domestic energy production.
Without hydraulic fracturing, as much as 80 percent of unconventional production from such formations as gas shales would be, on a practical basis, impossible.

This technique uses a specially blended liquid which is pumped into a well under extreme pressure causing cracks in rock formations underground. These cracks in the rock then allow oil and natural gas to flow, increasing resource production.

Hydraulic Fracturing: The Process

What Is Hydraulic Fracturing?

Contrary to many media reports, hydraulic fracturing is not a “drilling process.” Hydraulic fracking is used after the drilled hole is completed. Put simply, 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 creates paths that increase the rate at which fluids can be produced from the reservoir formations, in some cases by many hundreds of percent.

The process includes steps to protect water supplies. 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). A more detailed look at casing and its role in groundwater protection is available HERE.

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.

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. To view a chart of the chemicals most commonly used in hydraulic fracturing and for a more detailed discussion of this question, click HERE.

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. It also allows for the recovery of oil and natural gas from formations that geologists once believed were impossible to produce, such as tight shale formations in the areas shown on the map below. Hydraulic fracturing is also used to extend the life of older wells in mature oil and gas fields.

How is Hydraulic Fracturing Done?*

The placement of hydraulic fracturing treatments underground is sequenced to meet the particular needs of the formation. The sequence noted below from a Marcellus Shale in Pennsylvania is just one example. 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 (described below), 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 employed in Marcellus wells include:

• 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.

Fractures: Their orientation and length

Certain predictable characteristics or physical properties regarding the path of least resistance have been recognized since hydraulic fracturing was first conducted in the oilfield in 1947. These properties are discussed below:

Fracture orientation

Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience, horizontal fractures will occur at depths less than approximately 2000 ft. because the Earth’s overburden 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.

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 and the USDW, the more likely it will be that multiple formations possessing the qualities necessary to impede the fracture will occur. However, while it should be noted that the length of a fracture can also be influenced by natural fractures or faults as shown in a study that included microseismic analysis ‡ of fracture jobs conducted on three wells in Texas, 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 following text and graphs are excerpts from an article written by Kevin Fisher of Pinnacle, a Halliburton Company for the July 2010 edition of the American Oil and Gas Reporter.

“The concerns around groundwater contamination raised by Congress are primarily centered on one fundamental question: Are the created fractures contained within the target formation so that they do not contact underground sources of drinking water? In response to that key concern, this article presents the first look at actual field data based on direct measurements acquired while fracture mapping more than 15,000 frac jobs during the past decade.

Extensive mapping of hydraulic fracture geometry has been performed in unconventional North American shale reservoirs since 2001. The microseismic and tiltmeter technologies used to monitor the treatments are well established, and are also widely used for nonoil field (sic) applications such as earthquake monitoring, volcano monitoring, civil engineering applications, carbon capture and waste disposal. Figures 1 and 2 are plots of data collected on thousands of hydraulic fracturing treatments in the Barnett Shale in the Fort Worth Basin in Texas and in the Marcellus Shale in the Appalachian Basin.

More fracs have been mapped in the Barnett than any other reservoir. The graph illustrates the fracture top and bottom for all mapped treatments performed in the Barnett since 2001. The depths are in true vertical depth. Perforation depths are illustrated by the red-colored band for each stage, with the mapped fracture tops and bottoms illustrated by colored curves corresponding to the counties where they took place.

The deepest water wells in each of the counties where Barnett Shale fracs have been mapped, according to United States Geological Survey (http://nwis.waterdata.usgs.gov/nwis ‡), are illustrated by the dark blue shaded bars at the top of Figure 1. As can be seen, the largest directly measured upward growth of all of these mapped fractures still places the fracture tops several thousands of feet below the deepest known aquifer level in each county.


The Marcellus data show a similarly large distance between the top of the tallest frac and the location of the deepest drinking water aquifers as reported in USGS data (dark blue shaded bars at the top of Figure 2). Because it is a newer play with fewer mapped frac stages at this point and encompasses several states, the data set is not as comprehensive as that from the Barnett. However, it is no less compelling in providing evidence of a very good physical separation between hydraulic fracture tops and water aquifers.

Almost 400 separate frac stages are shown, color coded by state. As can be seen, the fractures do grow upward quite a bit taller than in the Barnett, but the shallowest fracture tops are still ±4,500 feet, almost one mile below the surface and thousands of feet below the aquifers in those counties.

The results from our extensive fracture mapping database 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, such as the Marcellus, the tops of the hydraulic fractures are still thousands of feet below the deepest aquifers suitable for drinking water. The data from these two 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.”

* Pennsylvania Department of Environmental Protection
“Hydraulic Fracturing Overview.” 07/20/2010.
http://www.dep.state.pa.us/dep/deputate/minres/oilgas/new_forms/marcellus/Reports/DEP%20Fracing%20overview.pdf‡ (4/11/2011).

Fracturing Fluid Management


Fluid Storage – “Pits”

From the time the first oil and gas wells were drilled, “pits” have been used to hold drilling fluids and wastes. Pits can be excavated holes in the ground, or they can be above ground containment systems such as steel tanks. Pits are used for storage of produced water, for emergency overflow, temporary storage of oil, burn off of waste oil, and for temporary storage of the fluids used to complete and treat the well.

The containment of fluids within a pit is the most critical element in the prevention of contamination of shallow ground water. The failure of a tank, pit liner, or the line carrying fluid (“flowline”) can result in a release of contaminated materials directly into surface water and shallow ground water. Environmental clean-up of these accidentally released materials can be a costly and time consuming process. Therefore, prevention of releases is vitally important.

For pits constructed from ground excavation, pit lining may be necessary to prevent infiltration of fluids into the subsurface of the ground, depending upon the fluids being placed in the pit, the duration of the storage and the soil conditions. Typically, pit liners are constructed of compacted clay or synthetic materials like polyethylene or treated fabric that can be joined using special equipment.
Read more at FracFocus


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