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Hydraulic fracturing

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The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field.[1] Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells.


Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking. During injection the resistance to flow in the formation increases, the pressure in the wellbore increases to a value called the break-down pressure, that is the sum of the in-situ compressive stress and the strength of the formation. Once the formation “breaks down,” a fracture is formed, and the injected fluid flows through it. From a limited group of active perforations, ideally in a normal fault stress regime, a single vertical fracture is created that propagates with two "wings" being 180° apart and identical in shape and size. In naturally fractured or cleated formations, it is possible that multiple fractures are created and/or the two wings evolve with branches and offsets. A volume of reservoir rock around the main fracture channel is pressurized, which promotes shear movement on natural fractures and provides additional stimulation effect.

Fluid not containing any solid (called the “pad”) is injected first, until the fracture is opened wide enough to accept a propping agent. The purpose of the propping agent is to keep apart the fracture surfaces once the pumping operation ceases and the pressure in the fracture decreases below the compressive in-situ stress trying to close the fracture. In deep reservoirs, man-made ceramic beads are used to hold open or “prop” the fracture. In shallow reservoirs, sand is normally used as the propping agent.


In general, hydraulic fracture treatments are used to increase the productivity index of a producing well or the injectivity index of an injection well. The productivity index defines the rate at which oil or gas can be produced at a given pressure differential between the reservoir and the wellbore, while the injectivity index refers to the rate at which fluid can be injected into a well at a given pressure differential.

There are many applications for hydraulic fracturing. Hydraulic fracturing can:

  • Increase the flow rate of oil and/or gas from low-permeability reservoirs
  • Increase the flow rate of oil and/or gas from wells that have been damaged
  • Connect the natural fractures and/or cleats in a formation to the wellbore
  • Decrease the pressure drop around the well to minimize sand production
  • Enhance gravel-packing sand placement
  • Decrease the pressure drop around the well to minimize problems with asphaltine and/or paraffin deposition
  • Increase the area of drainage or the amount of formation in contact with the wellbore
  • Connect the full vertical extent of a reservoir to a slanted or horizontal well.

There could be other uses, but most of the treatments are pumped for these reasons.

A low-permeability reservoir is one that has a high resistance to fluid flow. In many formations, chemical and/or physical processes alter the reservoir rock over geologic time. Sometimes, these diagenetic processes restrict the openings in the rock and reduce the ability of fluids to flow through the rock. Low-permeability rocks are normally excellent candidates for stimulation by hydraulic fracturing.

Regardless of the permeability, a reservoir rock can be damaged when a well is drilled through the reservoir and when casing is set and cemented in place. Damage occurs, because drilling and/or completion fluids leak into the reservoir and alter the pores and pore throats. When the pores are plugged, the permeability is reduced, and the fluid flow in this damaged portion of the reservoir may be substantially reduced. Damage can be especially severe in naturally fractured reservoirs. To stimulate damaged reservoirs, a short, conductive hydraulic fracture is often the desired solution.

In many cases, especially for low-permeability formations, damaged reservoirs, or horizontal wells in a layered reservoir, the well would be uneconomical unless a successful hydraulic fracture treatment is designed and pumped. The engineer in charge of the economic success of such a well must design the optimal fracture treatment and then go to the field to be certain the optimal treatment is pumped successfully.

Candidate selection

The success or failure of a hydraulic fracture treatment often depends on the quality of the candidate well selected for the treatment. Choosing an excellent candidate for stimulation often ensures success, while choosing a poor candidate normally results in economic failure. To select the best candidate for stimulation, the design engineer must consider many variables. The most critical parameters for hydraulic fracturing are:

  • Formation permeability
  • The in-situ stress distribution
  • Reservoir fluid viscosity
  • Skin factor
  • Reservoir pressure
  • Reservoir depth
  • The condition of the wellbore

The skin factor refers to whether the reservoir is already stimulated or is damaged. If the skin factor is positive, the reservoir is damaged, and the well could be an excellent candidate for stimulation.

The best candidate wells for hydraulic fracturing treatments have a substantial volume of oil and gas in place and need to increase the productivity index. The characteristics of such reservoirs include:

  • A thick pay zone
  • Medium to high pressure
  • In-situ stress barriers to minimize vertical height growth
  • Either a low-permeability zone or a zone that has been damaged (high skin factor)

Reservoirs that are poor candidates for hydraulic fracturing are those with little oil or gas in place because of:

  • Thin reservoirs
  • Low reservoir pressure
  • Small areal extent

Reservoirs with extremely low permeability may not produce enough hydrocarbons to pay all the drilling and completion costs, even if successfully stimulated; thus, such reservoirs would not be good candidates for stimulation.

Developing data sets

For most petroleum engineers, developing a complete and accurate data set is often the most time-consuming part of fracture treatment design. The data required to run both the fracture design model and the reservoir simulation model can be divided into two groups:

  • Data that can be “controlled” by the engineer
  • Data that must be measured or estimated, but cannot be controlled.

The primary data that can be controlled by the engineer are:

  • The well completion details
  • Treatment volume
  • Pad volume
  • Injection rate
  • Fracture fluid viscosity
  • Fracture fluid density
  • Fluid-loss additives
  • Propping agent type
  • Propping agent volume

The data that must be measured or estimated are:

  • Formation depth
  • Formation permeability
  • In-situ stresses in the pay zone
  • In-situ stresses in the surrounding layers
  • Formation modulus
  • Reservoir pressure
  • Formation porosity
  • Formation compressibility
  • Reservoir thickness

There are three thicknesses that are important to the design engineer:

  • The gross thickness of the reservoir
  • The net thickness of the oil- or gas-producing interval
  • The permeable thickness that will accept fluid loss during the hydraulic fracture treatment.

The most critical data for the design of a fracture treatment (roughly in order of importance) are the:

  • In-situ stress profile
  • Formation permeability
  • Fluid-loss characteristics
  • Total fluid volume pumped
  • Propping agent type and amount
  • Pad volume
  • Fracture fluid viscosity
  • Injection rate
  • Formation modulus

In hydraulic fracture treatment design, the two most important parameters are:

  • The in-situ stress profile and the permeability profile of the zone to be stimulated
  • The layers of rock above and below the target zone that will affect fracture height growth.

In new fields or reservoirs, most operating companies are normally willing to run logs, cut cores, and run well tests to determine important factors such as the in-situ stress and the permeability of the reservoir layers. With such data, along with fracture-treatment and production records, accurate data sets for a given reservoir normally can be compiled. These data sets can be used on subsequent wells to optimize the fracture treatment designs. It is normally not practical to cut cores and run well tests on every well. The data obtained from cores and well tests from a few wells must be correlated to log parameters, so the logs on subsequent wells can be used to compile accurate data sets.

To design a fracture treatment, most use pseudo-three-dimensional (P3D) models. To use a P3D model, the data must be entered by reservoir layer. Fig. 1 illustrates the important data profiles required by a P3D model. For the example in Fig. 1, the fracture treatment would be started in the sandstone reservoir. The fracture would typically grow up and down until a barrier is reached to prevent vertical fracture growth. In many cases, thick marine shale is a barrier to vertical fracture growth. In some cases, coal seams prevent fractures from growing vertically. Many coal seams are highly cleated, which means that they contain an abundance of small natural fractures. When the fracture fluid enters a highly cleated coal seam, there will be very high fluid leakoff into the coal cleats. In thick, highly cleated coal seams, the fracture is likely to be contained within the coal seam.

The data used to design a fracture treatment can be obtained from several sources, such as:

  • Drilling records
  • Completion records
  • Well files
  • Openhole geophysical logs
  • Cores and core analyses
  • Well tests
  • Production data
  • Geologic records
  • Other public records, such as publications

In addition, service companies provide data on their fluids, additives, and propping agents. Table 1 illustrates typical data needed to design a fracture treatment and possible sources for the data.

Fracture treatment optimization

The goal of every fracture treatment design should be to attain the optimum fracture treatment for each and every well. In 1978, Holditch et al.[2] discussed the optimization of both the propped fracture length and the drainage area (well spacing) for low-permeability gas reservoirs. Fig. 2 illustrates the method used to optimize the size of a fracture treatment.[3][4]


Fig. 2 shows the following:

  • As the propped length of a fracture increases, the cumulative production will increase, and the revenue from hydrocarbon sales will increase
  • As the fracture length increases, the incremental benefit (amount of revenue generated per foot of additional propped fracture length) decreases
  • As the treatment volume increases, the propped fracture length increases
  • As the fracture length increases, the incremental cost of each foot of fracture (cost/ft of additional propped fracture length) increases
  • When the incremental cost of the treatment is compared with the incremental benefit of increasing the treatment volume, an optimum propped fracture length can be found for every situation

Additional economic calculations can be made to determine the optimum fracture treatment design. However, in all cases, the design must consider:

  • The effect of the fracture on flow rates and recovery.
  • The cost of the treatment.
  • The investment guidelines of the company that owns and operates the well.

Field considerations

After the optimum fracture treatment has been designed, it must be pumped into the well successfully. A successful field operation requires planning, coordination, and cooperation of all parties. Treatment supervision and the use of quality control measures will improve the successful application of hydraulic fracturing. Safety is always the primary concern in the field, and it begins with a thorough understanding by all parties of their duties. A safety meeting is always held to review:

  • The treatment procedure.
  • Establish a chain of command.
  • Ensure everyone knows his/her job responsibilities for the day.
  • Establish a plan for emergencies.

The safety meeting should also discuss:

  • The well completion details and the maximum allowable injection rate and pressures.
  • The maximum pressures to be held as backup in the annulus.

All casing, tubing, wellheads, valves, and weak links, such as liner tops, should be tested thoroughly before starting the fracturing treatment. Mechanical failures during a treatment can be costly and dangerous. All mechanical problems should be discovered during testing and repaired before pumping the fracture treatment.

Before pumping the treatment, the engineer in charge should conduct a detailed inventory of all the equipment and materials on location. The inventory should be compared with the design and the prognosis. After the treatment has concluded, another inventory of all the materials left on location should be conducted. In most cases, the difference in the two inventories can be used to verify what was mixed and pumped into the wellbore and the hydrocarbon-bearing formation.

In addition to an inventory, samples of the base fracturing fluid (usually water) should be taken and analyzed. Typically, a water analysis is done on the base fluid to determine the minerals and type of bacteria present. The data from the water analysis can be used to select the additives needed to mix the viscous fracture fluid required to create a wide fracture and to transport the propping agent into the fracture. In addition, samples of the additives used during a treatment and the fracture fluid after all additives have been added should be taken and saved in case future analyses are required.

Field operations should also consider the number of wells to be fractured in an area. In order to optimize the productivity, many wells should be stimulated. However, this might lead to different kinds of interference effects between the wells that might affect production operations. This interference, which is a result of hydraulic fractures propagating into nearby wells, is known as frac hits[5].

Additional terms

  • fracking
  • frac
  • frack
  • frac'ing
  • fracing
  • fracturing


  1. 1.0 1.1 1.2 Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. An Overview of Hydraulic Fracturing. In Recent Advances in Hydraulic Fracturing, 12. Chap. 1, 1-38. Richardson, Texas: Monograph Series, SPE.
  2. Holditch, S.A., Jennings, J.W., Neuse, S.H. et al. 1978. The Optimation of Well Spacing and Fracture Length in Low Permeability Gas Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 1–3 October. SPE-7496-MS.
  3. Veatch, R.W.J. 1983. Overview of Current Hydraulic Fracturing Design and Treatment Technology—Part 1. J Pet Technol 35 (4): 677-687. SPE-10039-PA.
  4. Britt, L.K. 1985. Optimized Oilwell Fracturing of Moderate-Permeability Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, USA, 22–26 September. SPE-14371-MS.
  5. Bou-Hamdan, K. 2020. Key Design Considerations for maximizing the recovery rate of unconventional reservoirs. SPE The Way Ahead.

Noteworthy papers in OnePetro

King, G. 2012. 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. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. SPE-152596-MS.

Fisher, M. K., & Warpinski, N. R. 2011. Hydraulic Fracture-Height Growth: Real Data. Society of Petroleum Engineers.

Potocki, D. 2012. Understanding Induced Fracture Complexity in Different Geological Settings Using DFIT Net Fracture Pressure. SPE-162814.

Noteworthy books

Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. Recent Advances in Hydraulic Fracturing, No. 12. Richardson, Texas: Monograph Series, SPE. SPE Bookstore

Jones, J.R. and Britt, L.K. 2009. Design and appraisal of hydraulic fractures. Richardson, TX: An interdisciplinary approach to topics in petroleum engineering and geosciences, Society of Petroleum Engineers. 2010287084

Jack Jones, Larry K. Britt. SPE bookstore

Online multimedia

Barree, Robert D. 2013. Overview of Current DFIT Analysis Methodology.

Britt, Larry K. 2013. Application of Low Viscosity Fluids To Hydraulic.

Friehauf, Kyle. 2013. Hydraulic Fracture Identification and Production Log Analysis in Unconventionals Using DTS.

Lee, W. John. 2014. Workflow for Applying Simple Models to Forecast Production from Hydraulically Fractured Shale Wells.

Parker, Michael, and Eric J. Esswein. 2013. Hydraulic Fracturing: Environmental and Occupational Health Challenges.

Al-Muntasheri, Dr. Ghaithan A. 2015. "Fluids for Fracturing Petroleum Reservoirs." Web Events. Society of Petroleum Engineers,

External links

Energy4me Hydraulic Fracturing

Data Confirm Safety Of Well Fracturing

See also

Fracture treatment design

Fracturing fluids and additives

Fracture diagnostic techniques

Fracture mechanics

Propping agents and fracture conductivity

Fracture propagation models

Post-fracture well behavior

Fracturing high-permeability formations

Fluid flow in hydraulically fractured wells


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