Hydraulic fracturing

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Applying Science and Best Practices which Increases Production Rates from Oil wells.

Hydraulic fracturing is a well stimulation technology used to maximize the extraction of underground resources; including oil, natural gas, geothermal energy, and even water by fracturing the formation to create enhanced pathways for the fluids to flow into gathering wells. Hydraulic fracturing is mostly utilized by the oil and gas industry to enhance and sometime enable shale oil and gas production. The maturation of this technology is the key driver behind current shale gas boom in the United States and around the world.


History of Fracking

Hydraulic fracturing presently the most popular and successful stimulation treatment in the petroleum industry and it gained a lot of attention recently. Fracturing technology has opened numerous unconventional hydrocarbon frontiers.

Hydraulic fracturing, though in primitive form, can be traced all the way back to the 1860’s oil industry, when liquid nitroglycerin (NG) was used to stimulate shallow rock wells .The idea, then referred to as “shooting,” was to use the nitroglycerin to break up the formation in which the oil was contained, fostering better flow and retrieval.

Hydraulic fracturing and horizontal wells are not new tools for the oil and gas industry. The first fracturing experiment was in 1947 and the process was accepted as commercial by 1950. The first horizontal well was in the 1930’s and horizontal wells were common by the late 1970’s. Millions of fracs have been pumped (Society of Petroleum Engineers estimate 2.5 million fracs world-wide and over 1 million in the US) and tens of thousands of horizontal wells have been drilled over the past 60 years. Even shale gas, especially from the Devonian shale’s (including Marcellus), are not new producing intervals. Devonian shale’s are the source rocks for the shallow oil wells of eastern Pennsylvania, where Mr. Drake drilled the first US oil well after noticing a number of natural seeps of oil and gas in the area.. As the hydrafrac process spread, more than 3,000 wells per month were hydrafraced throughout the mid-1950. It is estimated that fracturing advanced US recoverable reserves of oil by at least 30% and of gas by 90%.

High natural gas prices have stimulated interest in development of this unconventional shale’s. Partly because of fracking, natural gas production in 2010 reached its highest level in decades. [1]


What is hydraulic fracturing?

Natural gas plays a key role in nation’s clean energy future and hydraulic fracturing is one way of accessing this vital resource. Over the past few years, the use of hydraulic fracturing for gas extraction has increased and has expanded over a wider diversity of geographic regions and geologic formations.

Hydraulic fracturing is a stimulation technique that has become widely used by the oil industry since its introduction about 20 years ago. In a hydraulic fracturing treatment, fluid is injected into the well at rates higher than the reservoir matrix will accept. Rapid injection produces a buildup in wellbore pressure until a pressure large enough to overcome rock stresses is reached. At this pressure, failure occurs allowing a crack or fracture to be formed. Continued fluid injection with selected propant results in a high conductivity crack in the formation and thereby well stimulation.

This technique used to produce natural gas flow from previously unproductive or uneconomical natural gas sources. This enables the production of natural gas and oil from rock formations deep below the earth's surface (generally 5,000-20,000 feet or 1,500-6,100 m). At such depth, there may not be sufficient porosity and permeability to allow natural gas and oil to flow from the rock into the wellbore. [2]


How is Hydraulic Fracturing Done?

Hydraulic fracturing is a highly engineered process. Proper design of a frac job considers petro physical rock properties, the fluid chemical and physical properties, and the characteristics of the propant (usually sand) used. Frac jobs are closely monitored for volume, pressure, flow rate, temperature, and other parameters.

Careful construction of a well is an important precursor to fracing the well. Wells are drilled to below the lowest drinking water zone, surface casing is inserted, and the casing is cemented in place to ensure good bonding between the casing and the walls of the drilled hole. Various types of logging tools are used to assess whether the cement has formed a good bond and if any voids or small passageways exist in the cement. Additional drilling, including the horizontal leg of the well, is followed by cementing other layers of casing into place.

When the well is completed, openings must be made in the casing and cement to allow gas to flow into the well. A perforation tool with explosive charges is used. Next the frac job begins. On a well with a long horizontal section in the hydrocarbon-bearing formation, the well is not perforated and fracked all at once. Rather it is done in a series of stages each being several hundred feet in length. The outermost stage is segregated from the rest of the well with a plug. A perforating tool creates the openings in that section of pipe, and then the frac job is performed on the same stage. When that frac job is finished, another plug is set several hundred feet further back to create a second stage, and the perforation and fracking are repeated. This process continues until the entire length of the well in the formation has been completed. [3]

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.

The level of permeability in a rock holding oil and gas dictates whether the reservoir must be hydraulically fractured. When permeability is high enough, roughly 50 md for most oil zones or about 1 to 5 md for gas zones, fracturing may not be needed to establish an economic production rate. At lower permeability’s or where oil viscosity is high or reservoir pressure is low, the flow of fluids toward the wellbore can be assisted by fracturing, which creates a flow path of much higher permeability. Stable fractures offer a flow path with average permeability of 100 to over 1000 times the permeability of the formation (Gaskari, 2006). At lower permeability’s, such as shale, most wells will not flow economic quantities of fluids without extensive hydraulic fracturing. In low permeability formations, the fracture network within the formation. [1]



  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 slick water without propant material: The slick water pad stage fills the wellbore with the slick water solution (described below), opens the formation and helps to facilitate the flow and placement of propant material.
  3. A prop sequence stage, which may consist of several sub stages of water combined with propant 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. Propant 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 propant from the wellbore. [4]

Fracturing and Fracture Monitoring

Hydraulic fracturing produces a break in the rock to release the pressure applied to the rock at the wellbore. The crack that develops is narrow, usually 2 to 3 mm in width (1/10th to 1/8th inch) and grows outward, upward and outward, widening slightly until a barrier is encountered or there is sufficient leak off into side fractures or Permeable formation to stop the fracture from growing. Even at an injection rate of 100 bbls per minute (4200gallons per minute), the secondary fractures and permeable streaks will soon absorb enough liquid from the main fracture to limit outward and upward fracture growth.[1]

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 fractures 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 micro seismic 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. [4]

Down-hole camera pictures in a well with an open-hole completion are shown in Figure 17. The camera was built and run by Amoco Research in the late 1960’s through the 1990’s to study and map hydraulic fracture growth in a variety of formations and compare performance of fracture variables (Smith, 1982; Palmer, 1991). The pictures here have a total view, (width and height), of about 2”x 1.5” (5 x 2.5 cm). Depth is in feet (4500+ feet), with pressure (in 10’s of psi), and time of day in 24 hour time.

Photo “A” shows narrow fractures stopping and starting again at a ¼” (6mm) thick shale break that interrupts the development of vertical fracture growth. Thicker shale layers will effectively stop the fracture growth unless pressure can reapply itself above the barrier such as happens in this open wellbore. If pressure is reduced and cannot be reapplied the fracture will stop growing.

Photo “B” is a fully developed fracture about 6 mm (1/4th inch) wide with a camera-confirmed height of approximately 20 ft. This fracture was in a limestone. The rock in the fracture is a piece of formation debris swept into the fracture after the crack was widened sufficiently to accept particles.

Figures “C” and “D” are of the same fracture. Photo “C” was after the fracture was initiated but while the wellbore was at low pressure. Photo “D” was of the same section of fracture after pressure was applied. The camera was a rare, side-looking camera that used close-ups of fractures in open hole completions to help categorize fracture development from the wellbore. One very unusual experiment with the camera captured creation of a vertical fracture while pressuring up on a formation and pumping at about 5 bpm. The vertical fracture grew past the camera with a recorded creation rate of about 1 ft per second (30 cm per second).[1]


Fluids and propant


The first fracture treatments were performed with gelled crude. Later, gelled kerosene was used. By the latter part of 1952, a large portion of fracturing treatments was performed with refined and crude oils. These fluids were inexpensive, permitting greater volumes at lower cost. Their lower viscosities exhibited less friction than the original viscous gel. Thus, injection rates could be obtained at lower treating pressures. To transport the sand, however, higher rates were necessary to offset the fluids lower viscosity.

With the advent in 1953 of water as a fracturing fluids, a number of gelling agents were developed. The first patent (US Patent 3058909) on guar cross linked by borate was issued to Loyd Kern with Arco on October 16, 1962. One of the legends of hydraulic fracturing. Surfactants were added to minimize emulsions with the formation fluids, and potassium chloride was added to minimize the effect on clays and other water-sensitive formation constituents. Later, other clay-stabilizing agents were developed that enhanced the potassium chloride, permitting the use of water in a greater number of formations

Other innovations, such as foams and the addition of alcohol, have also enhanced the use of water in more formations. Aqueous fluids such as acid, water, and brines are used now as the base fluids in approximately 96% of all fracturing treatments employing a propping agent.

In the early 1970s, a major innovation in fracturing fluids was the use of metal-based cross linking agents to enhance the viscosity of gelled water-based fracturing fluids for higher-temperature wells.

As more and more fracturing treatments have involved high-temperature wells, gel stabilizers have been developed, the first of which was the use of approximately 5% methanol. Later, chemical stabilizers were developed that could be used alone or with the methanol. Improvements in cross linkers and gelling agents have resulted in systems that permit the fluids to reach the bottom of the hole in high-temperature wells prior to cross linking, thus minimizing the effects of high shear in the tubing. Ultraclean gelling agents based on surfactant-association chemistry and encapsulated breaker systems that activate when the fracture closes have been developed to minimize fracture-conductivity damage.


The first fracturing treatment used screened river sand as a propant. Others that followed used construction sand sieved through a window screen. There have been a number of trends in sand size, from very large to small, but, from the beginning, from –20 +40 US-standard-mesh sand has been the most popular, and currently approximately 85% of the sand used is this size. Numerous propping agents have been evaluated throughout the years, including plastic pellets, steel shot, Indian glass beads, aluminum pellets, high-strength glass beads, rounded nut shells, resin-coated sands, sintered bauxite, and fused zirconium. The concentration of sand (lbm/fluid gal) remained low until the mid-1960s, when viscous fluids such as cross linked water-based gel and viscous refined oil were introduced.

Large-size propping agents were advocated then the trend then changed from the monolayer or partial monolayer concept to pumping higher sand concentrations. Since that time, the concentration has increased almost continuously, with a sharp increase in recent years. These high sand concentrations are due largely to advances in pumping equipment and improved fracturing fluids. Now it is not uncommon to use propant concentrations averaging 5 to 8 lbm/gal throughout the treatment, with a low concentration at the start of the job, increased to 20 lbm/gal at the end. [5]

Other than propant and base fluids there are many components to be added in the frac fluid different companies supply these chemicals with different names but the main purpose and function of those chemicals being same and they are mentioned in the following fig 4.

Fig 5. Shows the different kinds of cross linked gels and polymers used in the process and Fig.6 shows different kinds of propant used.


Equipment used

Hydraulic-fracturing equipment used in oil and natural gas fields usually consists of a slurry blender, one or more high-pressure, high-volume fracturing pumps (typically powerful triplex, or quintiplex pumps) and a monitoring unit. Associated equipment includes fracturing tanks, one or more units for storage and handling of propant, high-pressure treating iron, a chemical additive unit (used to accurately monitor chemical addition), low-pressure flexible hoses, and many gauges and meters for flow rate, fluid density, and treating pressure. Fracturing equipment operates over a range of pressures and injection rates, and can reach up to 100 megapascals (15,000 psi) and 265 liters per second (9.4 cu ft/s) (100 barrels per minute).[4]


What Makes Hydraulic Fracturing Controversial?

Many issues contribute to the controversy surrounding hydraulic fracturing, including:

  • Each frac job requires from 1 to 5 million gallons of water (with the trend in new frac Jobs to use even larger volumes) – typically that water must be obtained locally.
  • The ingredients of the chemical compounds used for optimizing a frac job (e.g., biocides corrosion and scale inhibitors, gels and gel breakers) have not been disclosed until very recently. Some of the chemical constituents do have toxic properties at high enough levels. The lack of information about which chemicals were actually used and what the concentrations were led to uncertainty and fear on the part of residents.
  • Improper storage of chemicals and wastewater has the potential to contaminate soil, groundwater, and surface water.
  • Lack of understanding of how fracing works and where the fracs actually move led residents to fear that their drinking water supplies would be disrupted or damaged.
  • Some actual drinking water contamination in areas where gas development has occurred (whether caused by fracing activities or not) fanned the flames of concern.
  • Inadequate treatment of wastewater (flow back and produced water) can contaminate local groundwater and surface water. Historically, much of the gas wastewater was sent to disposal wells located in or near the producing areas. However, production in the Marcellus was unable to rely on underground injection for disposing wastewater due to the lack of suitable geological formations into which the wastewater could be injected. This forced operators to use other wastewater management options, including treatment and discharge to surface water bodies, which in turn created more concern and opposition. [3]


The technique of hydraulic fracturing is used to increase or restore the rate at which fluids, such as petroleum, water, or natural gas can be produced from subterranean natural reservoirs. Reservoirs are typically porous sandstones, limestone’s or dolomite rocks, but also include 'unconventional reservoirs' such as shale rock or coal beds. Hydraulic fracturing enables the production of natural gas and oil from rock formations deep below the earth's surface (generally 5,000–20,000 feet (1,500–6,100 m)). At such depth, there may not be sufficient permeability or reservoir pressure to allow natural gas and oil to flow from the rock into the wellbore at economic rates. Thus, creating conductive fractures in the rock is essential to extract gas from shale reservoirs because of the extremely low natural permeability of shale, which is measured in the micro Darcy to nano Darcy range. Fractures provide a conductive path connecting a larger volume of the reservoir to the well, thereby increasing the volume from which natural gas and liquids can be recovered from the targeted formation. So-called 'super fracking', which creates cracks deeper in the rock formation to release more oil and gas, will allow companies to frack more efficiently. The yield for a typical shale gas well generally falls off sharply after the first year or two.

While the main industrial use of hydraulic fracturing is in stimulating production from oil and gas wells, hydraulic fracturing is also applied to:

  • Stimulating groundwater wells.
  • Preconditioning rock for caving or inducing rock to cave in mining
  • As a means of enhancing waste remediation processes, usually hydrocarbon waste or spills.
  • Dispose of waste by injection into deep rock formations.
  • As a method to measure the stress in the earth.
  • For heat extraction to produce electricity in an enhanced geothermal systems.
  • To increase injection rates for geologic sequestration of CO2. [7]


  1. 1.0 1.1 1.2 1.3 Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells. SPE 152596, By George E. King, Apache Corporation
  2. A. Wells Hyrdrofrac & B. Field Use of "Superfrac" - A New Hydraulic Fracturing Technique, Matthews, T.M., Humble Oil and Refining Co.SPE, Document ID:2625-MS
  3. 3.0 3.1 White paper on SPE summit on hydraulic fracturing
  4. 4.0 4.1 4.2 Hydraulic Fracturing Process
  5. Hydraulic fracturing by Carl T. Montgomery and Michael B. Smith, NSI Technologies, SPE 116124; Case History of Sequential and Simultaneous Fracturing
  6. Fig.4.5.6. Source: SPE Distinguished Lecturer Program by Harold D. Brannon
  7. Hydraulic fracturing Wikipedia