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EPA/601/R 14/004 l July 2016 l www.epa.gov/hfstudy 

Review of Well Operator Files 

for Hydraulically Fractured 

Oil and Gas Production Wells: 

Hydraulic Fracturing Operations 
Hydraulic Fracturing Operations July 2016 

[This page intentionally left blank.] 
 

Hydraulic Fracturing Operations July 2016 

Review of Well Operator Files for
 

Hydraulically Fractured Oil and Gas Production Wells:
 

Hydraulic Fracturing Operations
 

U.S. Environmental Protection Agency
 

Office of Research and Development
 

Washington, DC
 

July 2016
 

EPA/601/R-14/004
 
 

 

Hydraulic Fracturing Operations July 2016 

Disclaimer
 

This document has been reviewed in accordance with US Environmental Protection Agency policy
 

and approved for publication. Mention of trade names or commercial products
 

does not constitute endorsement or recommendation for use.
 

Preferred Citation: U.S. Environmental Protection Agency. 2016. Review of Well Operator Files for 

Hydraulically Fractured Oil and Gas Production Wells: Hydraulic Fracturing Operations. Office of 

Research and Development, Washington, DC. EPA/601/R-14/004. 
Hydraulic Fracturing Operations	 July 2016 

Table of Contents 

Table of Contents......................................................................................................................................... iii
 

List of Figures ................................................................................................................................................ v
 

Preface ......................................................................................................................................................... vi
 

Authors and Contributors ........................................................................................................................... vii
 

Acknowledgements.................................................................................................................................... viii
 

Executive Summary....................................................................................................................................... 1
 

Hydraulic Fracturing Characteristics ......................................................................................................... 1
 

Monitoring and Testing Activities ............................................................................................................. 2
 

Subsurface Fluid Movement During Hydraulic Fracturing........................................................................ 3
 

Study Limitations ...................................................................................................................................... 6
 

Summary ................................................................................................................................................... 7
 

1. Introduction .......................................................................................................................................... 9
 

2. Hydraulic Fracturing Overview ........................................................................................................... 10
 

3. Research Methods .............................................................................................................................. 11
 

3.1. Hydraulic Fracturing Characteristics ........................................................................................... 12
 

3.2. Monitoring and Testing Activities ............................................................................................... 13
 

3.3. Well Design and Construction Characteristics............................................................................ 15
 

3.4. Estimates of Hydraulic Fracturing Characteristics and Monitoring and Testing Activities.........16
 

3.5. Quality Assurance and Quality Control....................................................................................... 17
 

4. Analytical Results ................................................................................................................................ 18
 

4.1. Hydraulic Fracturing Characteristics ........................................................................................... 19
 

4.1.1. Hydraulic Fracturing and Well Construction ...................................................................... 21
 

4.2. Monitoring and Testing Activities ............................................................................................... 24
 

4.2.1. Surface Treating Pressure Monitoring ............................................................................... 26
 

4.2.2. Casing Pressure Tests ......................................................................................................... 26
 

4.2.3. Microseismic Monitoring.................................................................................................... 29
 

5. Discussion of Subsurface Fluid Movement During Hydraulic Fracturing ........................................... 30
 

5.1.	 Mechanical Integrity ................................................................................................................... 30
 

5.2.	 Potential Intersection of Fractures with Operator-Reported Protected Ground Water
 

Resources or Existing Pathways.................................................................................................. 33
 

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Hydraulic Fracturing Operations	 July 2016 

5.2.1.	 Potential Intersection of Fractures with Operator-Reported Protected Ground Water
 

Resources ........................................................................................................................... 33
 

5.2.2.	 Potential Intersection of Fractures with Existing Pathways...............................................35
 

5.3. Monitoring and Testing for Subsurface Fluid Movement During Hydraulic Fracturing .............36
 

5.3.1.	 Mechanical Integrity........................................................................................................... 37
 

5.3.2.	 Potential Intersection of Fractures with Operator-Reported Protected Ground Water
 

Resources or Existing Pathways ......................................................................................... 38
 

6. Study Limitations ................................................................................................................................ 40
 

7. Summary............................................................................................................................................. 40
 

References .................................................................................................................................................. 42
 

Appendix: Variance Estimation................................................................................................................... 46
 

Appendix References .............................................................................................................................. 47
 

Glossary....................................................................................................................................................... 48
 

Glossary References................................................................................................................................ 51
 

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Hydraulic Fracturing Operations July 2016 

List of Figures 

Figure 1. Well completion types reported in the well operators’ files.................................................... 10



Figure 2. Locations of the 323 study wells............................................................................................... 16
 

Figure 3. Number of hydraulic fracturing jobs conducted per well at the oil and gas production
 

wells represented in this study................................................................................................. 19
 

Figure 4. Types of hydraulic fracturing jobs conducted at the oil and gas production wells
 

represented in this study .......................................................................................................... 20
 

Figure 5. (a) Job duration. (b) Number of stages per hydraulic fracturing job ........................................ 21

Figure 6. Measured length of the cement sheath behind the production casing above the point of
 

shallowest hydraulic fracturing................................................................................................. 22
 

Figure 7. Estimated age of well components (e.g., casing, cement, and packers) at the beginning of
 

the hydraulic fracturing job ..................................................................................................... 23
 

Figure 8. Percent of the total measured depth that was hydraulically fractured in the oil and gas
 

production wells represented in this study .............................................................................. 24
 

Figure 9. Reported occurrence of the number of different types of monitoring and testing activities
 

conducted per hydraulic fracturing job .................................................................................... 25
 

Figure 10. Reported occurrence of four types of monitoring and testing activities among the 

hydraulic fracturing jobs represented in this study ................................................................. 26
 

Figure 11. Maximum treating pressures applied during the hydraulic fracturing jobs conducted at
 

the oil and gas production wells represented in this study...................................................... 27
 

Figure 12. Magnitude of the difference between the casing test pressure and the maximum treating
 

pressure when the casing test pressure was (a) greater than or equal to or (b) less than 

the maximum treating pressure ............................................................................................... 28
 

Figure 13. Generic well diagrams illustrating the four monitoring and testing activities discussed in
 

this study .................................................................................................................................. 36
 

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Hydraulic Fracturing Operations	 July 2016 

Preface 

The U.S. Environmental Protection Agency (EPA) is conducting a study of the potential impacts of 

hydraulic fracturing for oil and gas on drinking water resources. This study was initiated in Fiscal Year 

2010 when Congress urged the EPA to examine the relationship between hydraulic fracturing and 

drinking water in the United States. In response, the EPA developed a research plan (Plan to Study the 

Potential Impacts of Hydraulic Fracturing on Drinking Water Resources) that was reviewed by the 

Agency’s Science Advisory Board (SAB) and issued in 2011. A progress report on the study (Study of the 

Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report), detailing the 

EPA’s research approaches and next steps, was released in late 2012 and was followed by a consultation 

with individual experts convened under the auspices of the SAB. 

The EPA’s study includes the development of several research projects, extensive review of the 

literature, and technical input from state, industry, and non-governmental organizations as well as the 

public and other stakeholders. A series of technical roundtables and in-depth technical workshops were 

held to help address specific research questions and to inform the work of the study. The study is 

designed to address research questions posed for each stage of the hydraulic fracturing water cycle: 

•	 Water Acquisition: What are the possible impacts of large volume water withdrawals from 

ground and surface waters on drinking water resources? 

•	 Chemical Mixing: What are the possible impacts of surface spills of hydraulic fracturing fluids on 

or near well pads on drinking water resources? 

•	 Well Injection: What are the possible impacts of the injection and fracturing process on drinking 

water resources? 

•	 Flowback and Produced Water: What are the possible impacts of surface spills of flowback and 

produced water on or near well pads on drinking water resources? 

•	 Wastewater Treatment and Waste Disposal: What are the possible impacts of inadequate 

treatment of hydraulic fracturing wastewaters on drinking water resources? 

This report, Review of Operator Files for Hydraulically Fractured Oil and Gas Production Wells: Hydraulic 

Fracturing Operations, is the product of one of the research projects conducted as part of the EPA’s 

study. It has undergone independent, external peer review in accordance with Agency policy, and all of 

the peer review comments received were considered in the report’s development. 

The EPA’s study has produced multiple EPA technical reports and scientific journal publications that 

collectively advance understanding of the potential impacts of hydraulic fracturing for oil and gas on 

drinking water resources and identify factors that may influence those impacts. The products of the 

EPA’s study also facilitate and inform dialogue among interested stakeholders, including Congress, other 

Federal agencies, states, tribal governments, the international community, industry, non-governmental 

organizations, academia, and the general public. 

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Hydraulic Fracturing Operations July 2016 

Authors and Contributors 

Glen Boyd, PhD, The Cadmus Group, Inc., under contract EP-C-15-022 

Susan Burden, PhD, US EPA 

Charles J. Hillenbrand, PhD, US EPA 

Andrea T. Joffe, BS, Randstad Technologies, under contract EP-D-12-050 

David Marker, PhD, Westat, under contract EP-D-12-050 

Susan L. Sharkey, MA, US EPA 

Steve Souders, BS, US EPA 

Chuck Tinsley, BS, US EPA 

Nathan M. Wiser, MA, US EPA 

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Hydraulic Fracturing Operations July 2016 

Acknowledgements 

The EPA acknowledges the companies that provided information for this report. The Agency also 

acknowledges Cynthia Roberts (US EPA) and Stephen Watkins (US EPA) for their assistance in the 

development of this report. Support was provided by The Cadmus Group, Inc., under contract EP-C-15-

022; Westat, under contract EP-D-12-050; and Maryam Cluff (a student services contractor under 

contract EP-13-H-000438). An independent, external peer review of this report was conducted through 

the Eastern Research Group, Inc., under contract EP-C-12-021. The contractors’ role did not include 

establishing Agency policy. 

The EPA would also like to acknowledge the participants of the US EPA-States Technical Meeting on the 

Well File Review for their insights on hydraulic fracturing operations and monitoring and testing 

activities. The meeting was held in Dallas, Texas, on May 3, 2016, and included representatives from the 

following state agencies: 

Arkansas Department of Environmental Quality 

Colorado Department of Public Health and Environment 

Colorado Oil and Gas Conservation Commission 

Louisiana Department of Environmental Quality 

New Mexico Energy, Minerals, and Natural Resources Department 

North Dakota Industrial Commission 

Oklahoma Corporation Commission 

Oklahoma Secretary of Energy and Environment 

Pennsylvania Department of Environmental Protection 

Railroad Commission of Texas 

Texas Commission on Environmental Quality 

Wyoming Oil and Gas Conservation Commission 

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Hydraulic Fracturing Operations July 2016 

Executive Summary
 

In 2010, the US Environmental Protection Agency (EPA) conducted a survey of onshore oil and gas 

production wells hydraulically fractured by nine oil and gas service companies in support of the 

Agency’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water 

Resources.1 Data from the survey were first used to describe the relationship of well design and 

construction characteristics to drinking water resources and the number and relative location of 

well construction barriers (e.g., casing and cement) that can block pathways for potential 

subsurface fluid movement in Review of Well Operator Files for Hydraulically Fractured Oil and Gas 

Production Wells: Well Design and Construction.2 The current report provides insights into the 

potential for hydraulic fracturing fluids, or subsurface fluids affected by hydraulic fracturing, to 

move to underground drinking water resources during hydraulic fracturing, based on additional

analyses of data collected during the survey. 

The objective of this report was to explore the role of the following factors in subsurface fluid 

movement during hydraulic fracturing: 

(1) the ability of the hydraulically fractured production well to transport fluids through the well 

to and from the targeted rock formation without leaking and to prevent fluid movement 

along the outside of the well (i.e., the mechanical integrity of the well), and 

(2) the potential intersection of newly-created fractures with underground drinking water

resources or nearby existing pathways (e.g., faults or nearby production wells). 

The scope of the report is limited to the information collected during the EPA’s survey of oil and gas 

production wells hydraulically fractured by the nine service companies. As part of the survey, a

statistically representative sample of 323 study wells was selected from a list of well identifiers 

corresponding to onshore oil and gas production wells that were reported to the EPA by the nine

service companies. Drilling, construction, and completion information for the selected study wells 

was collected from nine well operators and summarized. Data describing hydraulic fracturing 

characteristics and monitoring and testing activities for the study wells are statistically 

representative of an estimated 23,200 wells that were hydraulically fractured by the nine service 

companies between approximately September 2009 and September 2010. The results are

presented as estimates of occurrence with 95 percent confidence intervals. 

Hydraulic Fracturing Characteristics 

One hydraulic fracturing job was identified for 84 (95 percent confidence interval: 67-94) percent 

of the 23,200 (21,400-25,000) wells represented in this study, and two or more hydraulic 

1 Information on the EPA’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water 

Resources is available at www.epa.gov/hfstudy. 

2 US EPA. 2015b. Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells: Well Design and 

Construction. Office of Research and Development, Washington, DC. EPA/601/R-14/002. Available at

http://www2.epa.gov/hfstudy/review-well-operator-files-hydraulically-fractured-oil-and-gas-production-wells-welldesign. 

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Hydraulic Fracturing Operations July 2016 

fracturing jobs were identified for 16 (6-33) percent of the wells.3 Because some wells were 

hydraulically fractured more than once, there were an estimated 28,500 (25,100-31,900) hydraulic 

fracturing jobs conducted at the wells represented in this study. The majority of the jobs [71 (60­

80) percent] were conducted between September 30, 2009, and September 30, 2010. 

Hydraulic fracturing jobs were categorized as initial fracture treatments, re-completions, or refractures, depending on the timing and depth interval over which hydraulic fracturing was

conducted in the well. For this report, initial fracture treatments were defined as the first reported 

hydraulic fracturing job conducted at a well, regardless of the depth interval at which hydraulic 

fracturing occurred. A re-completion was defined as a job in which no portion of the depth interval 

at which hydraulic fracturing was conducted overlapped with a depth interval fractured in a

previous job. Under this definition, a re-completion can include hydraulic fracturing of previously 

un-fractured portions of a well within the same geologic formation and hydraulic fracturing of 

previously un-fractured portions of a well within a different geologic formation. A re-fracture was

defined as a job in which any portion of the depth interval at which hydraulic fracturing was 

conducted overlapped with a depth interval fractured in a previous job. Of the 28,500 (25,100­

31,900) hydraulic fracturing jobs, 81 (71-89) percent were initial fracture treatments, 11 (5-23)

percent were re-completions, and 8 (5-12) percent were re-fractures. 

The age of well components (i.e., casing, cement, and packers) at the time of hydraulic fracturing

was estimated by comparing the start date of the hydraulic fracturing job to the date drilling started 

at the well.4 From this comparison, the estimated age of well components at the time of hydraulic 

fracturing ranged from less than one month to approximately 50 years. Sixty-four (48-77) percent

of the hydraulic fracturing jobs were conducted in wells having well components less than six 

months old. The estimated age of well components at the time of an initial fracture treatment

(median value of 45 days) was generally smaller than the estimated age of well components for

either a re-completion or a re-fracture (median value of six years). 

Monitoring and Testing Activities 

Four types of monitoring and testing activities were reviewed in this study: casing pressure tests, 

surface treating pressure monitoring, annular pressure monitoring, and microseismic monitoring.

Each type of monitoring and testing activity can provide information on subsurface fluid movement 

during hydraulic fracturing, because they provide information on either the mechanical integrity of 

the well, fracture growth, or the potential intersection of induced fractures with existing pathways. 

The number of different types of monitoring and testing activities reported for a single hydraulic 

fracturing job varied, from no indication of any of the monitoring or testing activities considered in 

this study to the use of all four types. Two or more of the monitoring and testing activities were 

3 For this report, a single hydraulic fracturing job consisted of one or more hydraulic fracturing stages in which the time

between consecutive stages was less than or equal to 90 days. A hydraulic fracturing stage refers to a specific measured

depth interval for which hydraulic fracturing began on a specific date. 

4 Hydraulic fracturing jobs conducted using a temporary frac string were not included in this analysis. Temporary frac

strings are installed in a well, used for hydraulic fracturing, and then removed from the well when hydraulic fracturing is

complete. 

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Hydraulic Fracturing Operations July 2016 

reported to have occurred for 76 (62-86) percent of the hydraulic fracturing jobs. No evidence of

any of the monitoring or testing activities was found for 2 (1-5) percent of the jobs. 

Casing pressure tests, which can provide information on the mechanical integrity of the well, were 

reported to have been conducted for 57 (44-70) percent of the hydraulic fracturing jobs. Surface 

treating pressure monitoring was reported for 97 (94-99) percent of the hydraulic fracturing jobs. 

The surface treating pressure is the pressure observed at the surface when hydraulic fracturing

fluids are injected into the casing string used for hydraulic fracturing. Changes in the surface 

treating pressure can provide information on the mechanical integrity of the well and, under a

given set of assumptions, estimate fracture growth. Annular pressure monitoring was reported in 

53 (27-77) percent of the hydraulic fracturing jobs. Annular pressure monitoring can measure the

pressure in the annular space between nested casing strings or between the casing and the 

surrounding geology. Pressure increases in the annular space can indicate the introduction of fluids 

into the space from the surrounding geology or through a leak in the casing, cement, or packer (if

present). Microseismic monitoring was reported to have been conducted during 0.5 (0.1-2) percent 

of the hydraulic fracturing jobs. Microseismic monitoring maps microseismic events that occur

during hydraulic fracturing. These events are assumed to be indicative of fracture growth during

hydraulic fracturing. 

Because information in the well files was sometimes insufficient to conclusively determine whether

the monitoring or testing activities reviewed in this study occurred, estimates of the occurrence of 

monitoring and testing activities presented in this report may be underestimates. Similarly,

estimates of the lack of monitoring or testing activities may be overestimates. 

Subsurface Fluid Movement During Hydraulic Fracturing 

The potential for hydraulic fracturing fluids, or fluids naturally present in the subsurface, to move 

to underground drinking water resources during hydraulic fracturing depends on many factors. In 

general, these factors include, but are not limited to, the design and construction of the 

hydraulically fractured production well, the design and execution of the hydraulic fracturing job,

the characteristics of subsurface rock formations, and the relative location of induced fractures to 

underground drinking water resources or existing pathways that may lead to drinking water

resources. Together, these factors affect how fluids move through the subsurface during hydraulic 

fracturing and whether they can reach underground drinking water resources. 

Data obtained in this study provide insight on the role of mechanical integrity and the potential 

intersection of newly-created fractures with underground drinking water resources or existing

pathways in subsurface fluid movement during hydraulic fracturing. These factors are the focus of

this report, because the available data are most relevant to these factors. 

Mechanical Integrity. The mechanical integrity of a well depends on the mechanical integrity of the

individual components of the well. During hydraulic fracturing, pressure is applied to the inside of 

the production casing or, if used, a temporary frac string. When these well components have

mechanical integrity, the hydraulic fracturing fluid remains in the production casing or the 

temporary frac string and reaches the targeted geologic formation without moving into the annular 

space behind the production casing or the temporary frac string. When the well components used 

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Hydraulic Fracturing Operations July 2016 

for hydraulic fracturing do not have mechanical integrity or lose mechanical integrity during 

hydraulic fracturing, fluids can move outside of the production casing or the temporary frac string

into one or more of the annular spaces in the well. If multiple casings and cement sheaths are 

present within a well, they can block fluid movement into the surrounding environment by serving 

as additional barriers between the invaded annular space and the surrounding geology. A well

integrity failure occurs when no barriers (e.g., casing and cement) are left to block fluid from

entering the surrounding environment. 

Failures associated with downhole well components used for hydraulic fracturing were reported by 

well operators in 3 (1-8) percent of the hydraulic fracturing jobs.5 For some hydraulic fracturing 

jobs, these events were reported using phrases such as “communication to surface” or “casing leak.” 

For other jobs, these events were inferred from information available in the well files. For example, 

“came around” and “annular pressure increase” were interpreted as well component failures during 

hydraulic fracturing when written descriptions of the well’s status and well operations indicated a

well component failure. In all of these cases, information in the well files suggested that hydraulic 

fracturing fluid flowed from the inside of the casing string used for hydraulic fracturing to one or

more of the annular spaces behind the casing string. 

Well component failures occurred during initial fracture treatments, re-completions and refractures, and in jobs conducted using a temporary frac string. When compared to the larger

population of hydraulic fracturing jobs, a greater proportion of jobs conducted using a temporary 

frac string reported a well component failure [20 (7-46) percent] than jobs that did not use a 

temporary frac string [0.9 (0.2-3) percent]. This observation suggests that temporary frac strings 

were less effective at containing fluids during hydraulic fracturing than permanent well 

components. Additionally, 6 (2-19) percent of re-fractures and re-completions reported a well 

component failure during hydraulic fracturing, compared to 2 (0.5-8) percent of initial fracture 

treatments. While the confidence intervals overlap, the point estimates suggest that re-fractures 

and re-completions may have been more likely than initial fracture treatments to experience a well

component failure during hydraulic fracturing. 

When well component failures were reported, well operators generally stopped the hydraulic 

fracturing job, addressed the cause of the failure, and completed the job. There were often multiple

barriers (e.g., casing and cement) between the well components that failed and operator-reported 

protected ground water resources. As noted above, multiple casings and cement sheaths can block

fluid movement into the surrounding environment by serving as additional barriers between the 

invaded annular space and the surrounding geology. There was no evidence in the well files to 

suggest that these additional barriers failed. However, there were well component failures in which 

there were no additional barriers between the casing string used for hydraulic fracturing and the 

operator-reported protected ground water resource (i.e., a well integrity failure). Well integrity 

5 The reported occurrence of annular pressure monitoring may have implications for the reported occurrence of well

component failures. Well component failures may not have been observed and documented in the well files if annular

pressure monitoring was not conducted during hydraulic fracturing. Because the reported occurrence of annular pressure 

monitoring was 53 (27-77) percent, some hydraulic fracturing jobs may have experienced well component failures that 

were not detected. Therefore, the estimated occurrence of well component failures [3 (1-8) percent of hydraulic 

fracturing jobs] may be an underestimate. 

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Hydraulic Fracturing Operations July 2016 

failures were reported in 0.5 (0.1-2) percent of all of the hydraulic fracturing jobs. Information in 

the well files suggested that, in these cases, hydraulic fracturing fluid entered the annular space

between the casing string used for hydraulic fracturing and the surrounding geology at depths 

corresponding to the protected ground water resource reported by the well operator. Based on the 

information contained in the well files, it was not possible to determine whether fluid moved from 

the annular space into protected ground water resources in these cases. 

Potential Intersection of Newly-Created Fractures with Operator-Reported Protected Ground Water 

Resources. Information on the potential intersection of induced fractures with protected ground

water resources reported by well operators was available for two cases: (1) hydraulic fracturing 

jobs with microseismic monitoring, which provides information on how far up fractures grow, and

(2) wells in which the point of shallowest hydraulic fracturing was above the base of the operatorreported protected ground water resource. 

In the first case, the depths of the maximum vertical component of fracture growth estimated from 

microseismic monitoring data were compared to the depths of the operator-reported protected

ground water resources. This comparison was done for individual hydraulic fracturing jobs that 

had microseismic monitoring data [0.5 (0.1-2) percent of the hydraulic fracturing jobs]. The

difference between these values was used to assess whether induced fractures could have extended 

directly through the geologic strata to protected ground water resources reported by well 

operators.6 Among the hydraulic fracturing jobs in which microseismic monitoring was conducted, 

induced fractures grew no closer than 5,000 feet below the base of the operator-reported protected 

ground water resource. For these hydraulic fracturing jobs, the potential for induced fractures to

intersect operator-reported protected ground water resources was likely low, because the distance 

separating the estimated fracture depth and the operator-reported base of the protected ground

water resource was much larger (at least 5,000 feet) than the maximum vertical component of 

fracture growth estimated from microseismic monitoring data. 

In the second case, the estimated separation distance between the point of shallowest hydraulic 

fracturing in the well and the base of the operator-reported protected ground water resource was 

used to evaluate the potential for induced fractures to reach protected ground water resources in 

the absence of information on fracture growth. As reported in US EPA (2015b), the estimated

separation distance was less than zero feet in 0.4 (0.1-3) percent of the wells. In these wells, 

perforations used for hydraulic fracturing were placed shallower than the depth of the base of the

operator-reported protected ground water resource. When perforations used for hydraulic 

fracturing are shallower than the base of the operator-reported protected ground water resource, 

the potential for induced fractures to directly intersect with the protected ground water resource is

high, if the protected ground water resource is present at that depth. Based on the information 

6 The maximum vertical component of fracture growth estimated from microseismic monitoring data ranged from 380

feet to 1,340 feet per hydraulic fracturing job (median value of 680 feet per job). The maximum lateral component of

fracture growth estimated from microseismic monitoring data ranged from 700 feet to 2,250 feet per job (median value of

1,000 feet per job). 

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Hydraulic Fracturing Operations July 2016 

contained in the well files, it was not possible to determine whether hydraulic fracturing fluid 

entered protected ground water resources in these cases. 

For the majority of the wells represented in this study, it was not possible to assess with a high 

degree of certainty the potential for induced fractures to intersect operator-reported protected 

ground water resources, because they did not fall into either of the cases described above. The 

above cases, however, highlight the importance of the vertical separation distance between the

point of shallowest hydraulic fracturing in a well and the base of protected ground water resources. 

If the vertical separation distance is less than, or comparable to, the vertical component of fracture

growth, induced fractures may potentially reach protected ground water resources. Conversely, if 

the vertical separation distance is greater than the vertical component of fracture growth, induced

fractures are unlikely to extend directly into protected ground water resources. 

Potential Intersection of Newly-Created Fractures with Existing Pathways. If newly-created fractures 

intersect with other features in the subsurface, hydraulic fracturing fluids may flow into these 

features. Examples of these features include, but are not limited to, existing faults, natural fracture

systems, nearby oil and gas production wells, and uncemented intervals within the hydraulically 

fractured production well. Information on the relative location of induced fractures to existing

faults, natural fracture systems, and nearby wells was generally not found in the data obtained from

well operators. 

Hydraulic fracturing at a well was reported to have affected a nearby oil and gas production well in 

1 (0.4-4) percent of the wells represented in this study.7 These events are often referred to as “frac 

hits” and were reported in the well files using the phrase “frac’d into [well name].” It was not 

possible to determine whether hydraulic fracturing fluids, or subsurface fluids affected by hydraulic 

fracturing, reached operator-reported protected ground water resources during the frac hits, 

because information available in the well files was insufficient to determine whether fluids flowed 

along the outside of the nearby oil and gas production well and into protected ground water 

resources. 

Study Limitations 

The survey design and data collection process may have implications for the interpretation of the 

results presented in this report. The results are statistically representative of the onshore oil and

gas production wells hydraulically fractured by the nine oil and gas service companies between 

approximately September 2009 and September 2010. Estimates of the frequency of occurrence of 

hydraulic fracturing characteristics and monitoring and testing activities are summarized at the

national level. The estimates may be different for different regions of the country, because of 

differences in local geologic characteristics, regulatory requirements, and company preferences. 

The estimates may also not apply to wells hydraulically fractured after 2010, as hydraulic 

fracturing practices and regulatory requirements change over time. 

7 Frac hits are often detected through changes in pressure or fluid production at nearby wells. Because this study

collected information for the study wells and not wells near study wells, the reported occurrence of frac hits may be an

underestimate. 

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Hydraulic Fracturing Operations July 2016 

The results presented in this report are generated from data provided by oil and gas well operators. 

The data are limited in scope to the information requested by the EPA and the information 

provided by the well operators. While quality assurance and quality control measures were used to 

ensure that analyses presented in this report accurately reflect the data supplied by the well 

operators, the EPA did not attempt to independently and systematically verify the data.

Consequently, the study results reflect the scope of the information request and are of the same

quality as the supplied data and the analyses conducted by the EPA. 

Summary 

This report presents the results of a survey of onshore oil and gas production wells hydraulically 

fractured by nine oil and gas service companies in the United States during 2009 and 2010. Two

factors that affect the potential for subsurface fluid movement during hydraulic fracturing were 

examined: the mechanical integrity of the hydraulically fractured oil and gas production well and

the potential intersection of newly-created fractures with protected ground water resources 

reported by well operators or nearby existing pathways. 

Situations that potentially allowed hydraulic fracturing fluids to move to protected ground water 

resources reported by well operators were identified in a small number of wells. These situations

included: 

Well integrity failures during hydraulic fracturing [0.5 (0.1-2) percent of the hydraulic 

fracturing jobs]. In these cases, well components (e.g., casing, cement, or packers) failed 

during hydraulic fracturing, and no additional casing or cement barriers separated the well 

components that failed from the operator-reported protected ground water resources.

Information in the well files suggested that, in these cases, hydraulic fracturing fluid entered 

the annular space between the casing string used for hydraulic fracturing and the 

surrounding geology at depths corresponding to protected ground water resources

reported by well operators. Based on the information contained in the well files, it was not 

possible to determine whether hydraulic fracturing fluid moved from the annular space into

protected ground water resources in these cases. 

Perforations used for hydraulic fracturing were shallower than the base of protected ground 

water resources reported by well operators [0.4 (0.1-3) percent of the wells] (US EPA, 2015b). 

When perforations used for hydraulic fracturing are shallower than the base of the 

operator-reported protected ground water resource, the potential for induced fractures to 

directly reach the protected ground water resource is high, if the protected ground water

resource is present at that depth. Based on the information contained in the well files, it was 

not possible to determine whether hydraulic fracturing fluid entered protected ground

water resources in these cases. 

Information on the relative location of newly-created fractures to existing pathways was generally 

not found in the well files, although 1 (0.4-4) percent of the wells reported a frac hit. Frac hits 

occurred when hydraulic fracturing at a well affected a nearby oil and gas production well. It was 

not possible to determine whether hydraulic fracturing fluids, or subsurface fluids affected by 

hydraulic fracturing, reached operator-reported protected ground water resources during the frac 

7 
 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

hits, because available information in the well files was insufficient to determine whether fluids 

flowed along the outside of the nearby oil and gas production well and into protected ground water 

resources. 

These results, as well as other information on hydraulic fracturing characteristics and monitoring 

and testing activities before and during hydraulic fracturing, highlight important well design, 

construction, and operation practices that should be considered when assessing the potential 

impacts of hydraulic fracturing on drinking water resources. 

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Hydraulic Fracturing Operations July 2016 

1. Introduction 

Hydraulic fracturing is used to increase oil and gas production from underground rock formations. 

During hydraulic fracturing, a specially engineered fluid is injected down an oil and gas production 

well and into a targeted geologic formation at pressures great enough to create and grow fractures 

in the oil- and gas-containing rock. When the applied pressure is released, the natural pressure in 

the rock formation moves oil and gas from the formation through the newly-created fractures and 

the production well to the surface, where it is collected for distribution. 

Concerns have been raised about the potential for hydraulic fracturing to negatively impact 

drinking water resources through the subsurface movement of gases and liquids (i.e., fluids) to 

ground water resources [Council of Canadian Academies, 2014; Kissinger et al., 2013; Rozell and

Reaven, 2012; US Environmental Protection Agency (US EPA), 2011a]. To better understand the 

role of well construction and hydraulic fracturing in subsurface fluid movement, the US

Environmental Protection Agency (EPA) conducted a survey of onshore oil and gas production 

wells hydraulically fractured by nine oil and gas services companies in 2009 and 2010. Data 

collected during the survey were first used to describe the well design and construction 

characteristics of these wells in Review of Well Operator Files for Hydraulically Fractured Oil and Gas 

Production Wells: Well Design and Construction (US EPA, 2015b). That report examined the

relationship of well design and construction characteristics to drinking water resources and the 

number and relative location of well construction barriers (e.g., casing and cement) that can block

pathways for potential subsurface fluid movement. 

The current report provides insights into the potential for hydraulic fracturing fluids, or subsurface 

fluids affected by hydraulic fracturing, to move to underground drinking water resources during 

hydraulic fracturing, based on additional analyses of information collected during the survey. The

objective of this report was to explore the role of the following factors in subsurface fluid 

movement during hydraulic fracturing: 

(1) the ability of the hydraulically fractured production well to transport fluids through the well 

to and from the targeted rock formation without leaking and to prevent fluid movement 

along the outside of the well (i.e., the mechanical integrity of the well), and

(2) the potential intersection of newly-created fractures with underground drinking water

resources or nearby existing pathways (e.g., faults or nearby production wells). 

The scope of the report is limited to the information collected during the EPA’s survey of oil and gas

production wells hydraulically fractured by the nine service companies (US EPA, 2015b). Data 

collected during the survey were used to describe hydraulic fracturing at these wells and the 

reported occurrence of monitoring and testing activities that provide information about subsurface

fluid movement during hydraulic fracturing. Results presented in this report are statistically 

representative of the oil and gas production wells hydraulically fractured by the nine service

companies. 

9 
 

 

 

 

 

 

 

 

 

Figure 1. Well completion types reported in the well operators’ files. Well completions are depicted for 

horizontal well orientations, but may occur in vertical or deviated wells. (US EPA, 2015b) 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

2. Hydraulic Fracturing Overview
 

Oil and gas production wells are designed, constructed, and completed to access hydrocarbon 

resources in targeted geologic formations. Hydraulic fracturing is a completion activity that occurs 

after a well has been constructed.8 Characteristics of hydraulic fracturing operations depend on 

how the production well is constructed and completed in the targeted geologic formation and on 

the properties of the targeted geologic formation, including in situ stresses and other 

geomechanical rock properties (Hlidek and Weijers, 2007; Martin and Valkó, 2007). Well 

completion in the targeted geologic formation can vary. Figure 1 illustrates the different types of

well completions observed in this study: cemented casing, formation packer, and open hole. 

Cemented casing completions have both casing (e.g., steel pipe) and cement in the targeted geologic

formation. In these completions, the casing and cement are perforated, and hydraulic fracturing is 

performed within the perforated interval. Formation packer completions also have casing in the 

targeted geologic formation, but use mechanical devices (i.e., packers) to seal the annular space 

between the uncemented production casing and the surrounding geologic formation. In these 

completions, the bottom portion of the production casing, located between formation packers, is

equipped with ports that can be opened using pressure applied through the casing. Hydraulic 

fracturing fluid is pumped through these ports into the surrounding rock formation. Open hole 

completions contain no casing and, therefore, no cement in the targeted geologic zone. Hydraulic 

8 Section 2 of US EPA (2015b) provides a general overview of the design and construction of oil and gas production wells. 

10 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

fracturing in an open hole completion occurs within the open hole interval and may be conducted 

using a temporary frac string. If a temporary frac string is used, it is lowered into the well and

secured at its base using a packer or by latching into existing well components located in the well. 

Hydraulic fracturing takes place through the temporary frac string, which is removed when

hydraulic fracturing is complete. 

A hydraulic fracturing job occurs within a designated portion (i.e., interval) of an oil and gas

production well. Jobs can be conducted in a single stage or in multiple stages. In a single stage job, 

the entire designated portion of the well is hydraulically fractured at the same time. In a multi-stage 

job, discrete intervals are sequentially isolated and hydraulically fractured until the entire 

designated portion of the well has been hydraulically fractured. In each stage, hydraulic fracturing

fluid is injected down the well at a calculated, predetermined rate and pressure [Ground Water 

Protection Council (GWPC) and ALL Consulting, 2009], although changes in how a hydraulic 

fracturing job progresses are often made at the well site as the job is executed and monitored

(Malone and Ely, 2007).9 The fluid creates and propagates fractures by transferring the pressure 

applied at the surface to the targeted geologic formation (Gupta and Valkó, 2007). The fluid also

carries proppants into the newly-created fractures; proppants are small, incompressible particles 

(e.g., sand) that keep the fractures open once the injection pressure has been released and

production begins (Brannon and Pearson, 2007; Gupta and Valkó, 2007). 

3. Research Methods 

Data used in this report were provided by nine oil and gas production well operators for 323 study 

wells in response to an information request letter sent in August 2011.10 The well operators and 

study wells were selected from a list of onshore oil and gas production wells that were reported by 

the nine service companies to have been hydraulically fractured between approximately September

2009 and September 2010.11 The letter requested, for each study well, 24 distinct items organized 

into five topic areas: (1) geologic maps and cross sections; (2) drilling and completion information;

(3) water quality, volume, and disposition; (4) hydraulic fracturing procedures and reports; and (5) 

environmental releases. Operators were asked to certify that, to the best of their knowledge, the

information submitted in response to the requested items was true, accurate, and complete. (US 

EPA, 2015b) 

Approximately 9,670 electronic files and four paper files were received in response to the August 

2011 information request. The information in these files was compiled into a single “well file” for 

9 Hydraulic fracturing fluids are often water-based fluids that contain chemical additives (GWPC and ALL Consulting, 

2009; Gupta and Valkó, 2007; US EPA, 2015a). The chemical additives alter the properties of the fluid (e.g., pH, viscosity)

to enhance its performance (GWPC and ALL Consulting, 2009; Gupta and Valkó, 2007). 

10 Study wells were selected from the following nine well operators: Clayton Williams Energy, Inc.; ConocoPhillips; EQT

Corporation; Hogback Exploration, Inc.; Laramie Energy II, LLC; MDS Energy, Ltd.; Noble Energy, Inc.; SandRidge

Exploration and Production, LLC; and Williams Production Company, LLC. 

11 The nine oil and gas service companies included: BJ Services Company; Complete Production Services, Inc.; Halliburton 

Energy Services, Inc.; Key Energy Services; Patterson-UTI Energy; RPC, Inc.; Schlumberger Technology Corporation;

Superior Well Services; and Weatherford International. 

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Hydraulic Fracturing Operations July 2016 

each study well. In September 2013 and August 2014, follow-up letters were sent to each of the 

well operators asking for information not found in the original submissions. Additional information

provided by the well operators was added to the corresponding well file. Some of the data received 

were claimed as confidential business information under the Toxic Substances Control Act. The EPA 

worked with the well operators to summarize and present the data in this report in a way that

protects their claims of confidentiality.12 

Analyses presented in this report primarily used information from two of the five topic areas 

included in the information request: drilling and completion information, and hydraulic fracturing

procedures and reports.13 Data were extracted from various documents contained in the well files, 

including, but not limited to, post-frac reports and completion reports. The extracted data were 

recorded as found in the well files (i.e., without rounding) and organized in a database. The 

database was used to conduct analyses and develop the figures presented throughout this report. A 

description of the extracted data and how they were used is provided below. 

3.1. Hydraulic Fracturing Characteristics 

Information on hydraulic fracturing was generally identified from post-frac reports, completion 

reports, and wellbore diagrams. Post-frac reports were often provided to well operators by the 

hydraulic fracturing service company and generally contained information on specific stages, 

including dates, measured depths, and surface treating pressures. When present in the well files,

post-frac reports were usually the preferred source of information on hydraulic fracturing

operations. 

Hydraulic fracturing stage data were recorded for each study well. These data included the date

hydraulic fracturing started for that stage, the measured depths of the top and bottom of the 

interval hydraulically fractured, the maximum surface treating pressure associated with the stage, 

and whether a temporary frac string was used. Different specific depth intervals were counted as

unique hydraulic fracturing stages, regardless of the start date of hydraulic fracturing. If the same 

depth interval was hydraulically fractured on two or more different start dates, each was

considered a unique stage. 

Hydraulic Fracturing Jobs. Dates associated with the start of unique hydraulic fracturing stages 

were used to define separate hydraulic fracturing jobs that occurred in the same study well. For this

report, a single hydraulic fracturing job consisted of one or more stages in which the time between 

consecutive stages was less than or equal to 90 days. The 90 day cut-off was selected after 

reviewing the number of days between consecutive stages reported for all of the study wells. This

cut-off resulted in 414 separate hydraulic fracturing jobs among the 323 study wells. A 60 day cut12 Non-confidential business information provided by the well operators is located in Federal Docket ID EPA-HQ-ORD2010-0674 at www.regulations.gov. 

13 Information related to geologic maps and cross sections, as well as drilling and completion, was summarized in US EPA 

(2015b). Information collected about environmental releases was reported in US EPA (2015c). Although information in 

some well files was of good quality, the well files generally contained insufficient or inconsistent information on nearby

surface and ground water quality, injected water volumes, and wastewater volumes and disposition; therefore, these data

were not summarized. 

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Hydraulic Fracturing Operations July 2016 

off would have resulted in 416 hydraulic fracturing jobs, and a 120 day cut-off would have resulted

in 413 jobs. 

Hydraulic fracturing jobs were categorized as initial fracture treatments, re-completions, or refractures, depending on the timing and depth interval over which the hydraulic fracturing job was 

conducted. For this report, initial fracture treatments were defined as the first reported hydraulic 

fracturing job conducted at a well, regardless of the depth interval at which hydraulic fracturing

occurred. A re-completion was defined as a job in which no portion of the depth interval at which 

hydraulic fracturing was conducted overlapped with a depth interval fractured in a previous job.

Under this definition, a re-completion can include hydraulic fracturing of previously un-fractured 

portions of a well within the same geologic formation and hydraulic fracturing of previously unfractured portions of a well within a different geologic formation. A re-fracture was defined as a job 

in which any portion of the depth interval at which hydraulic fracturing was conducted overlapped 

with a depth interval fractured in a previous job. 

Temporary Frac Strings. If a temporary frac string was used for any stage of a multi-stage hydraulic 

fracturing job, the entire job was considered to have used a temporary frac string. 

Measured Depth of the Point of Shallowest Hydraulic Fracturing. The measured depth of the point of 

shallowest hydraulic fracturing was identified for each study well, regardless of the number of

hydraulic fracturing jobs. In cemented casing completions, the point of shallowest hydraulic 

fracturing was equal to the shallowest measured depth of a production perforation used for

hydraulic fracturing. In formation packer completions, the point of shallowest hydraulic fracturing 

was equal to the measured depth of the shallowest formation packer used to isolate a hydraulic 

fracturing interval. In open hole completions, the point of shallowest hydraulic fracturing was equal 

to the shallowest measured depth where hydraulic fracturing occurred. 

Measured Depth of the Point of Deepest Hydraulic Fracturing. The measured depth of the point of 

deepest hydraulic fracturing was also identified for each study well, regardless of the number of

hydraulic fracturing jobs. In cemented casing completions, this point was equal to the measured 

depth of the deepest perforation used for hydraulic fracturing. In formation packer completions, the

measured depth of the point of deepest hydraulic fracturing was equal to the measured depth of the 

deepest formation packer used to isolate a hydraulic fracturing interval. In open hole completions, 

the measured depth of the point of deepest hydraulic fracturing was equal to the total measured

depth of the well or, if a temporary frac string was used, the deepest measured depth where

hydraulic fracturing occurred. 

3.2. Monitoring and Testing Activities 

Well files were reviewed for four types of monitoring and testing activities: casing pressure tests, 

surface treating pressure monitoring, annular pressure monitoring, and microseismic monitoring.

These activities were included in this study, because they provide information on the mechanical 

integrity of the well, fracture growth, and the potential intersection of induced fractures with 

existing pathways (Section 5.3). 

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Hydraulic Fracturing Operations July 2016 

Casing Pressure Tests. Driller’s reports and completion reports were reviewed for casing pressure 

tests conducted on production casing or temporary frac strings. For this study, a casing pressure

test was defined as any surface pressure applied and held to a portion or all of the casing string 

used for hydraulic fracturing (i.e., the production casing or a temporary frac string, if used). The

date and the maximum applied pressure were recorded for each casing pressure test identified. 

Surface Treating Pressure Monitoring. Surface treating pressure monitoring was assumed to have 

occurred if a maximum treating pressure was recorded for any stage within a hydraulic fracturing 

job. Surface treating pressures were often reported in post-frac reports, but were also occasionally

reported on wellbore diagrams or in completion reports or driller’s reports. The available data 

often included a single surface treating pressure value; this value was identified as the maximum 

treating pressure. If multiple surface treating pressures were reported within a job, the largest was 

identified as the maximum treating pressure for that job. 

Annular Pressure Monitoring. Annular pressure (also referred to as casing pressure) monitoring 

during hydraulic fracturing was often identified from post-frac reports. If annular pressure

monitoring was identified for any stage of a multi-stage hydraulic fracturing job, the entire job was 

considered to have been monitored. The available data were frequently insufficient to analyze

changes in the annular pressure. In all cases, the monitored annulus was assumed to be the annular 

space directly behind the casing string used for hydraulic fracturing, even when more than one

annulus could have been monitored. 

Microseismic Monitoring. If microseismic monitoring was reported for any stage of a multi-stage 

hydraulic fracturing job, the entire job was considered to have been monitored. Microseismic 

monitoring reports included maps or graphs of microseismic events that were recorded during 

specific hydraulic fracturing stages. In many cases, microseismic monitoring reports also included a 

summary of microseismic monitoring results for each monitored stage (e.g., fracture dimensions

and direction). The available data were used to estimate the maximum lateral and vertical 

components of fracture growth for each microseismically monitored stage.14 If multiple stages 

within a single hydraulic fracturing job were microseismically monitored, the largest lateral and 

vertical components of fracture growth among the monitored stages were identified as the

maximum lateral and vertical components of fracture growth for the entire job. 

For this report, the maximum lateral component of fracture growth was defined as the maximum

reported distance between the point of hydraulic fracturing in the well and the microseismic event 

located furthest away from the well in the x-y plane. The maximum vertical component of fracture

growth was defined as the maximum reported distance between the point of hydraulic fracturing in 

the well and the shallowest microseismic event (i.e., maximum upward vertical fracture growth). If 

the reported vertical component of fracture growth could not be discerned into distance upward 

and downward from the point of hydraulic fracturing, the maximum vertical component of fracture 

14 As discussed in Section 5.3, microseismic monitoring is not a direct measurement of fracture growth. Microseismic

monitoring detects microseismic events caused by changes in stress and fluid pressure in the subsurface (Fisher and

Warpinski, 2012). These events are assumed to be indicative of fracture growth during hydraulic fracturing (Davies et al., 

2012; Fisher and Warpinski, 2012; Flewelling et al., 2013). 

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Hydraulic Fracturing Operations July 2016 

growth was set equal to the entire reported vertical component. This approach was used, because it 

estimated the shortest possible distance between induced fractures and protected ground water

resources. Because fractures often grow up and down, this approach likely overestimated the 

upward vertical component of fracture growth (Fisher and Warpinski, 2012). 

3.3. Well Design and Construction Characteristics 

Some analyses presented in Section 4 compared data described in Sections 3.1 and 3.2 to data 

originally described in US EPA (2015b), including the presence of casing and cement and the depths 

of protected ground water resources. Methods used to identify these data elements are summarized

below, and additional detail is available in US EPA (2015b). 

Casing and Cement. Casing strings were identified from reported casing tallies, driller’s reports, 

completion reports, wellbore diagrams, and occasionally from forms submitted to oil and gas

regulatory agencies. The measured depths of the top and bottom of the casing string were recorded 

for surface, intermediate, and production casing. Conductor casing or other shallow, often 

uncemented casings, were excluded. Cement placement behind surface, intermediate, and 

production casing was determined from various sources, including cement evaluation logs, driller’s 

reports, cement job tickets, wellbore diagrams, and forms submitted to oil and gas regulatory 

agencies. Cement tops were determined from cement evaluation logs, when available. If cement 

evaluation logs were unavailable, other reported data, including driller’s reports, cement job

tickets, wellbore diagrams, and forms submitted to oil and gas regulatory agencies were assessed 

collectively to determine cement tops. Cement bottoms were identified using the point of placement

of cement through the casing. 

Protected Ground Water Resources. As noted by the Ground Water Protection Council: 

“There is a great deal of variation between states with respect to defining protected ground 

water. The reasons for these variations relate to factors such as the quality of water, the

depth of Underground Sources of Drinking Water, the availability of ground water, and the 

actual use of ground water.” (GWPC, 2009) 

As a result, this report does not use a single definition of “protected ground water resource” and 

relies solely on information provided to the EPA by well operators in response to the Agency’s 

request for the depth of the base, or bottom, of the protected ground water resource at each study 

well. Data sources used by well operators to report depths of protected ground water resources are

described in detail in US EPA (2015b). In general, data presented in Table 5 of US EPA (2015b) 

show that depths of protected ground water resources were provided by well operators for nearly 

all of the study wells. For the majority of wells, protected ground water resources were identified 

by the well operators from state or federal authorization documents (e.g., permits to drill or 

approved permit applications). The base of the protected ground water resource was reported for

most study wells. 

15 
 

 

 

Figure 2. Locations of the 323 study wells. The study wells were selected from a list of wells that were 

reported by nine oil and gas service companies to have been hydraulically fractured between 

approximately September 2009 and September 2010. The number of wells reported by the service 

companies are shown at the county-level for comparison. Fewer than 20 well identifiers were reported 

in Alaska, and none were among the 323 study wells. (US EPA, 2015b) 

 

 

 

 

 

Hydraulic Fracturing Operations	 July 2016 

3.4.	 Estimates of Hydraulic Fracturing Characteristics and Monitoring and 

Testing Activities 

The 323 study wells are statistically representative of the wells reported to the EPA by the nine 

hydraulic fracturing service companies (US EPA, 2015b). As shown in Figure 2, the study wells also

reflect the geographic distribution of the wells reported by the nine service companies. 

Because the study wells are statistically representative of the wells reported by the nine hydraulic 

fracturing service companies, results from analyses conducted on the 323 study wells were 

extrapolated to the sampled population (i.e., the wells reported by the nine hydraulic fracturing

service companies). To conduct the extrapolation, each of the 323 study wells was assigned to a 

category (or characteristic) defined by a given analysis. Statistical weights, which ranged from 4 to 

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Hydraulic Fracturing Operations July 2016 

190, were then used to estimate the number of wells out of the sampled population that were 

within each category (i.e., point estimates). Ninety-five percent confidence intervals were calculated 

for each point estimate. Point estimates and confidence intervals are presented at the national level 

and are statistically representative of the oil and gas production wells hydraulically fractured by the 

nine service companies. Any characteristics not identified by the study wells are not represented in

this report. (US EPA, 2015b) 

Some analyses identified rare characteristics (e.g., near zero percent of the wells) or focused on 

subsets of the population of all wells (e.g., among hydraulic fracturing jobs with casing pressure

tests). For some of these analyses, the set of study wells examined were found in only a few of the 

nine sampled well operators or the confidence intervals were unrealistically narrow. As a result, 

the approach for calculating confidence intervals was adjusted to improve the accuracy of the 

confidence intervals (Appendix). 

3.5. Quality Assurance and Quality Control 

The EPA does not make any claims on the quality or accuracy of the data or information received 

directly from the well operators in response to the information request. Quality assurance and 

quality control measures were used to ensure that data were of sufficient quality for analysis and

that the analyses performed were conducted properly. Three separate measures were employed to 

assess the data used to describe hydraulic fracturing characteristics and monitoring and testing

activities: logical tests of the data in the database, re-review of at least 10 percent of the extracted 

data, and well operator review of the extracted data. Together, these measures assure the quality of

the data used in the analyses presented in this report. 

Logical Tests of the Data in the Database. Following the initial extraction of data from the well files, 

database queries were used to identify logical inaccuracies or inconsistencies and missing data. The 

queries included, but were not limited to, searches for blank entries, text entries that should have

been numeric, shallower depths incorrectly occurring below deeper depths, and dates for earlier 

events occurring after later events. Inconsistencies identified from these queries were corrected in 

the database after reviewing the original information provided by the well operators. 

Re-review of the Extracted Data. At least 10 percent of the well files from each well operator were 

re-reviewed by a different person for the data elements used in this report.15 The re-review was 

used to assess the repeatability of the data extraction. For most data elements, there was good 

agreement between the original data extracted and the data extracted during the re-review (less 

than or equal to 10 percent difference), and no changes were made to the database. 

There was initially poor agreement between the original data extracted from the well files and data 

extracted during the re-review for two data elements: dates and test pressures associated with 

15 One hundred percent of microseismic monitoring reports were re-reviewed simultaneously by two reviewers, because 

the data provided often needed more interpretation than other data elements used for the analyses presented in this

report. The reviewers discussed the applicability and accuracy of data reported for each microseismically monitored

hydraulic fracturing job before determining the maximum vertical and lateral components of fracture growth (Section 

3.2). This process provided a more consistent data extraction effort for the microseismic monitoring data and a higher

degree of accuracy in the resulting dataset. 

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Hydraulic Fracturing Operations July 2016 

casing pressure tests and maximum treating pressures. The poor agreement occurred, because 

individual hydraulic fracturing jobs were not defined prior to the original data extraction, which

resulted in both missing data and incorrectly assigned data for study wells with more than one 

hydraulic fracturing job. Once individual hydraulic fracturing jobs were identified (Section 3.1), 

data from study wells with more than one job were re-reviewed to correct entries for casing

pressure tests and maximum treating pressures. This corrected issues of missing or incorrectlyassigned data for study wells with more than one hydraulic fracturing job. 

Operator Review of the Extracted Data. Data extracted for each study well were shared with the

respective well operator in August 2014, after the re-review of the extracted data. In total, 17,472 

data elements were provided to the well operators for their review. Well operators identified

changes to 1,598 data elements (less than 10 percent of the data elements provided to the well 

operators). The majority of these changes (1,171 data elements) described the use of annulus 

pressure monitoring as standard operating procedures for hydraulic fracturing operations, the

documentation of which was not always recorded in the well files. Well operators also identified 

changes to 247 data elements related to hydraulic fracturing stages, 80 data elements related to

casing pressure tests, 53 data elements related to maximum treating pressures, and 47 data 

elements related to the use of temporary frac strings. All updates provided by the operators were

incorporated. 

This work was conducted following the methods and procedures contained in the project-related 

quality assurance project plans (The Cadmus Group, 2013; US EPA, 2013, 2014; Westat, 2013). The 

project underwent a series of technical systems audits by the designated EPA Quality Assurance

Manager between April and August of 2012. No corrective actions were identified. 

4. Analytical Results 

The results presented below represent an estimated 23,200 (95 percent confidence interval: 

21,400-25,000) onshore oil and gas production wells that were reported by nine oil and gas service 

companies to have been hydraulically fractured between approximately September 2009 and

September 2010. Results are presented as rounded estimates and, where appropriate, 95 percent

confidence intervals. 

As described in US EPA (2015b), the wells were predominantly vertical wells drilled between 2000

and 2010, but also included other well orientations (i.e., horizontal and deviated) and wells drilled 

prior to 2000.16 True vertical depths of the wells ranged from less than 2,000 feet below ground 

surface to more than 11,000 feet below ground surface. Hydraulically fractured rock formations 

included sandstone, shale, carbonate, coal, and chert. Eighty-seven (68-96) percent of the wells had 

cemented casing completions, while 6 (4-11) percent had formation packer completions and

another 6 (1-33) percent had open hole completions; Figure 1 illustrates the different well

completion types. 

16 An estimated 65 (48-80) percent of the wells were vertical, 24 (11-44) percent were deviated, and 11 (7-16) percent

were horizontal. 

18 
 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

1 2 3 ≥4

Percent of Wells 

Number of Hydraulic Fracturing Jobs per Well 

Figure 3. Number of hydraulic fracturing jobs conducted per well at the oil and gas production wells 

represented in this study. For this report, a single hydraulic fracturing job consisted of one or more 

stages in which the time between consecutive stages was less than or equal to 90 days. Error bars 

display 95 percent confidence intervals. 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

4.1. Hydraulic Fracturing Characteristics 

One hydraulic fracturing job was identified for 84 (67-94) percent of the 23,200 (21,400-25,000) 

wells represented in this study, and two or more hydraulic fracturing jobs were identified for 16 (6­

33) percent of the wells. Because some wells had more than one hydraulic fracturing job, there

were an estimated 28,500 (25,100-31,900) hydraulic fracturing jobs conducted at the wells 

represented in this study, and job dates ranged from 1961 to 2011.17 The majority of the jobs [71

(60-80) percent] were conducted between September 30, 2009, and September 30, 2010.18 

The number of jobs per well ranged from one to more than four (Figure 3). For those wells 

hydraulically fractured more than once, the time between hydraulic fracturing jobs at a single well 

ranged from approximately three months to 25 years. The median time between hydraulic

fracturing jobs at a single well was nearly four years. 

Of the 28,500 (25,100-31,900) hydraulic fracturing jobs, 81 (71-89) percent were initial fracture 

treatments, 11 (5-23) percent were re-completions, and 8 (5-12) percent were re-fractures (Figure 

4). As noted in Section 3.1, re-completions were defined as a job in which no portion of the depth 

interval at which hydraulic fracturing was conducted overlapped with a depth interval fractured 

during a previous job. In 95 (75-99) percent of the re-completions, hydraulic fracturing occurred at

shallower depths than the previous job. In 6 (1-25) percent of the re-completions, hydraulic 

17 References to oldest, longest, or other extreme values from among the 323 study wells should not be interpreted to 

mean that these are the most extreme values among the 23,200 wells in the sampled population. For example, 1961 is the

year when the oldest hydraulic fracturing job from among the 323 study wells was conducted, but there are likely older

jobs in the population of 23,200 oil and gas production wells reported by the nine service companies. 

18 An estimated 7,100 (2,900-11,300) jobs occurred before September 30, 2009, and 1,200 (700-1,800) jobs occurred

after September 30, 2010. 

19 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Initial fracture 

treatment 

Re-completion Re-fracture 

Percent of Jobs 

Type of Hydraulic Fracturing Job 

Figure 4. Types of hydraulic fracturing jobs conducted at the oil and gas production wells represented in 

this study. For this report, initial fracture treatments were defined as the first reported hydraulic 

fracturing job conducted at a well, regardless of the depth interval at which hydraulic fracturing 

occurred. A re-completion was defined as a job in which no portion of the depth interval at which 

hydraulic fracturing was conducted overlapped with a depth interval fractured in a previous job. A refracture was defined as a job in which any portion of the depth interval at which hydraulic fracturing 

was conducted overlapped with a depth interval fractured in a previous job. Error bars display 95 

percent confidence intervals. 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

fracturing occurred at deeper depths than the previous job. Among all re-completions, the 

measured distance between the points of shallowest hydraulic fracturing in the re-completion and

the previous job ranged from 2,400 feet below the point of shallowest hydraulic fracturing in the 

previous job to 4,630 feet above the point of shallowest hydraulic fracturing in the previous job. 

The median distance between the points of shallowest hydraulic fracturing in the re-completion

and the previous job was 1,060 feet above the point of shallowest hydraulic fracturing in the 

previous job. The median time between a given fracture job and a re-completion was two years

(range of three months to 25 years). The median time between a given fracture job and a refracture, defined as a hydraulic fracturing job in which any portion of the depth interval at which 

hydraulic fracturing was conducted overlapped with a depth interval fractured in a previous job,

was six years (range of nine months to 21 years). 

The hydraulic fracturing jobs varied in duration and number of stages (Figure 5). Job durations

ranged from less than one day to more than 50 days, with nearly two-thirds of the jobs [65 (51-77) 

percent] conducted in one day (panel a). The number of stages within a single hydraulic fracturing

job ranged from one to more than 13 (panel b). 

20 
 

 

 

(a) 90% 

70% 

80% 

60% 

obs of J 50% Percent 40% 

30% 

20% 

10% 

0% 

0-1 2-10 11-25 26-50 >50 

Job Duration (days) 

(b) 

70% 

80% 

Percent of Jobs 40% 

50% 

60% 

10% 

20% 

30% 

0% 

1-3 4-6 7-9 10-12 ≥13

Number of Stages 

Figure 5. (a) Job duration. (b) Number of stages per hydraulic fracturing job. For this report, a hydraulic 

fracturing stage refers to a specific measured depth interval for which hydraulic fracturing began on a 

specific date. Error bars display 95 percent confidence intervals. 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

4.1.1. Hydraulic Fracturing and Well Construction 

Hydraulic fracturing depths and job start dates were compared to well design and construction 

characteristics to describe the spatial and temporal relationship of hydraulic fracturing to the well’s 

construction, including the presence and age of the casing and cement and the proportion of the

measured length of the well that was hydraulically fractured. 

Casing and Cement. Casing and cement are the primary components of oil and gas production wells. 

Casing is installed during well construction to isolate hydrocarbon production from the 

surrounding geology. After the casing is lowered in the drilled hole, cement is often placed between 

the outside of the casing and the inside of the drilled hole (i.e., the wellbore) or an existing outer 

21 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

0-250 251-500 501-1,000 1,001-

2,000 

>2,000 Uncertain 

Measured Length of Cement Sheath (feet) 

Percent of Wells 

Cement Sheath above 

Point of Shallowest Hydraulic Fracturing 

Uncemented 

Figure 6. Measured length of the cement sheath behind the production casing above the point of 

shallowest hydraulic fracturing. “Uncemented” includes wells that did not have cement behind the 

production casing directly above the point of shallowest hydraulic fracturing; these wells were often 

open hole or formation packer completions. Information in the well files was insufficient to determine 

the top of cement for some wells; this is reflected by the “uncertain” category. Error bars display 95 

percent confidence intervals. 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

casing to seal off this annular space (Baker, 1979; Smith, 1976). The cement also provides support 

behind the casing and protects it from corrosive fluids in the subsurface (Baker, 1979; Smith,

1976). 

Ninety (73-96) percent of the 28,500 (25,100-31,900) hydraulic fracturing jobs occurred in wells 

with cemented casing completions, 5 (3-9) percent occurred in wells with formation packer 

completions, and 5 (1-28) percent occurred in wells with open hole completions. Ten (3-30)

percent of the hydraulic fracturing jobs were conducted using a temporary frac string for one or 

more stages of the job. Temporary frac strings were used in wells with production casing and wells 

with open holes. 

Figure 6 displays the measured length of the cement sheath behind the production casing above the 

point of shallowest hydraulic fracturing. Thirteen (5-32) percent of the wells had uncemented

production casing directly above the point of shallowest hydraulic fracturing; these wells were

often open hole or formation packer completions. 

As shown in Figure 6, the most commonly reported measured length of the cement sheath above 

the point of shallowest hydraulic fracturing was greater than 2,000 feet.19 Thirty-three (20-49) 

percent of the wells had a cement sheath that was 2,000 feet or less, and 21 (10-39) percent had a 

cement sheath that was 1,000 feet or less. The measured length of the cement sheath could not be 

19 The measured length of the cement sheath above the point of shallowest hydraulic fracturing ranged from 90 feet to 

9,750 feet. The median measured length of the cement sheath above the point of shallowest hydraulic fracturing was

2,550 feet. 

22 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

<1 month 1-6 months 6-12 

months 

1-5 years >5 years Temporary 

frac string 

Percent of Jobs 

Estimated Age of Well Components 

Figure 7. Estimated age of well components (e.g., casing, cement, and packers) at the beginning of the 

hydraulic fracturing job. Well component age was estimated by calculating the time between the start 

date of the hydraulic fracturing job and the spud date of the well (i.e., the date drilling started). 

Hydraulic fracturing jobs conducted using temporary frac strings are identified in a separate category, 

because temporary frac strings are not permanent well components. Temporary frac strings are placed 

in the well prior to hydraulic fracturing and removed when hydraulic fracturing is complete. Error bars 

display 95 percent confidence intervals. 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

determined for 4 (2-8) percent of the wells, because cement top information behind the production 

casing was unavailable. 

The age of well components (i.e., casing, cement, and packers) at the time of hydraulic fracturing 

was estimated by calculating the time between the start date of the hydraulic fracturing job and the 

spud date of the well (Figure 7). This approach assumes that casing, cement, and packers present at 

the time of hydraulic fracturing were installed when the well was constructed and were not

replaced over the lifetime of the well. Hydraulic fracturing jobs conducted using temporary frac 

strings were identified in a separate category in Figure 7, because temporary frac strings are not

permanent well components. Temporary frac strings are placed in the well before hydraulic

fracturing and removed when hydraulic fracturing is complete. 

As shown in Figure 7, nearly two-thirds of the hydraulic fracturing jobs [64 (48-77) percent] were

conducted within six months of the spud date. The estimated age of well components at the time of 

an initial fracture treatment ranged from eight days to nearly 51 years, with a median of 45 days. 

The estimated age of well components at the time of a re-fracture or re-completion ranged from 

nearly six months to approximately 26 years, with a median of six years. 

Hydraulically Fractured Well Lengths. Hydraulically fractured well lengths ranged from less than 

1,000 feet to greater than 5,000 feet per hydraulic fracturing job. Ninety-five (87-98) percent of the

wells had 50 percent or less of the total measured length of the well hydraulically fractured (Figure 

8). The percentages shown on the x-axis in Figure 8 were calculated by subtracting the measured 

23 
 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

<10% 10-20% 20.1-30% 30.1-40% 40.1-50% >50% 

Percent of Wells 

Percent of Total Measured Depth Hydraulically Fractured 

Figure 8. Percent of the total measured depth that was hydraulically fractured in the oil and gas 

production wells represented in this study. Percentages were calculated by subtracting the measured 

depth of the point of shallowest hydraulic fracturing in the well from the measured depth of the point of 

deepest hydraulic fracturing in the well and dividing this difference by the total measured length of the 

well. This approach likely overestimates the length of the well that was hydraulically fractured, because 

the entire length between the points of shallowest and deepest hydraulic fracturing may not have been 

hydraulically fractured. Error bars display 95 percent confidence intervals. 

60% 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

depth of the point of shallowest hydraulic fracturing in the well from the measured depth of the 

point of deepest hydraulic fracturing in the well and dividing this difference by the total measured

depth of the well (Section 3.1). This approach likely overestimated the length of the well that was 

hydraulically fractured, because the entire length between the points of shallowest and deepest 

hydraulic fracturing may not have been hydraulically fractured. For example, wells completed in

more than one targeted geologic zone were not hydraulically fractured in the intervening nontargeted geologic zones. 

4.2. Monitoring and Testing Activities 

As described in Section 3.2, well files were reviewed for four types of monitoring and testing 

activities: casing pressure tests, surface treating pressure monitoring, annular pressure monitoring, 

and microseismic monitoring. Two or more of these monitoring and testing activities were reported 

for 76 (62-86) percent of the hydraulic fracturing jobs, with all four types of monitoring reported

for 0.08 (0.004-2) percent of jobs (Figure 9). None of the monitoring or testing activities considered 

in this study were reported for 2 (1-5) percent of the hydraulic fracturing jobs. Information in the

well files was sometimes insufficient to conclusively determine whether a given monitoring or 

testing activity occurred. Therefore, the reported occurrence of monitoring and testing activities 

may be underestimates of the actual occurrence of the monitoring or testing activities considered in 

this study. Similarly, the lack of reported monitoring or testing activities may be an overestimate. 

24 
 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

1 2 3 4 Unknown 

Percent of Jobs 

Number of Monitoring / Testing Activities 

Figure 9. Reported occurrence of the number of different types of monitoring and testing activities 

conducted per hydraulic fracturing job. Four types of monitoring and testing activities were considered: 

casing pressure tests, surface treating pressure monitoring, annular pressure monitoring, and 

microseismic monitoring. “Unknown” refers to hydraulic fracturing jobs for which no evidence of any of 

the four types of monitoring and testing activities was found in the well files. Because information in the 

well files was sometimes insufficient to conclusively determine whether a monitoring and testing 

activity occurred, the first four categories (1-4) may be underestimates and the last category (unknown) 

may be an overestimate. Error bars display 95 percent confidence intervals. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

As shown in Figure 9, the use of two different types of monitoring and testing activities was most

commonly reported among all of the hydraulic fracturing jobs [42 (28-57) percent of jobs]. Among 

the jobs with two different types of monitoring and testing activities reported, the most commonly 

identified combination was a casing pressure test and surface treating pressure monitoring. 

Figure 10 displays the reported occurrence of each of the four types of monitoring or testing

activities among the hydraulic fracturing jobs represented in this study. Surface treating pressure 

monitoring, as determined by the identification of maximum treating pressures, was reported to

have occurred in 97 (94-99) percent of the hydraulic fracturing jobs. In contrast, microseismic 

monitoring was reported to have been conducted for 0.5 (0.1-2) percent of the hydraulic fracturing

jobs. Annular pressure monitoring was reported to have occurred in 53 (27-77) percent of the jobs, 

and activities considered to be casing pressure tests for the purposes of this study (Section 3.2) 

were reported to have occurred in 57 (44-70) percent of the jobs. 

With the exception of annular pressure monitoring, analyses using data from the monitoring and

testing activities considered in this study are presented below. As noted in Section 3.2, the available 

data from annular pressure monitoring were frequently insufficient to analyze changes in annular

pressure. Therefore, no further analyses of annular pressure monitoring data were performed. 

25 
 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Surface Treating 

Pressure 

Monitoring 

Casing Pressure 

Test 

Annulus Pressure 

Monitoring 

Microseismic 

Monitoring 

Percent of Jobs 

Monitoring / Testing Activity 

Figure 10. Reported occurrence of four types of monitoring and testing activities among the hydraulic 

fracturing jobs represented in this study. These may be underestimates of the occurrence of each type 

of monitoring or testing activity, because information in the well files was sometimes insufficient to 

conclusively determine whether the monitoring or testing activity occurred. Error bars display 95 

percent confidence intervals. 

4.2.1. Surface Treating Pressure Monitoring 

Surface treating pressure monitoring provides information on the maximum pressure applied to 

wells during hydraulic fracturing. Among the hydraulic fracturing jobs conducted at these wells, 

maximum surface treating pressures ranged from less than 2,000 pounds per square inch (psi) to 

more than 9,000 psi, as shown in Figure 11. The median maximum treating pressure was 5,640 psi. 

Maximum treating pressures could not be determined for 3 (1-6) of the hydraulic fracturing jobs 

due to insufficient data in the well files. 

4.2.2. Casing Pressure Tests 

Casing pressure tests can be conducted before hydraulic fracturing to assess the mechanical 

integrity of the well and to determine whether or not the well can withstand the pressures expected

during hydraulic fracturing (US EPA, 2011b). Test pressures from casing pressure tests conducted 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

in 2009 and 2010 were compared to maximum treating pressures recorded for hydraulic fracturing 

jobs that occurred in the same time frame. The two-year time frame was selected for this analysis,

because the majority of the hydraulic fracturing jobs occurred during this time and because records 

were generally more complete for more recent hydraulic fracturing jobs. 

Each casing pressure test was assigned to a hydraulic fracturing job that both occurred at the same

well and was conducted closest in time after the date of the casing pressure test. A casing pressure 

test was assigned to multiple hydraulic fracturing jobs at a single well, if there were no additional

casing pressure tests performed between hydraulic fracturing jobs. Of the 28,500 (25,100-31,900) 

hydraulic fracturing jobs represented in this study, 15,600 (11,800-19,300) jobs occurred in 2009

or 2010 and had an assigned casing pressure test that occurred before the hydraulic fracturing 

26 
Percent of Jobs 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

≤1,999 2,000- 3,000- 4,000- 5,000- 6,000- 7,000- 8,000- ≥9,000 Uncertain 

2,999 3,999 4,999 5,999 6,999 7,999 8,999 

Maximum Treating Pressure (psi) 

Figure 11. Maximum treating pressures applied during the hydraulic fracturing jobs conducted at the oil and gas production wells represented in 

this study. Information in the well files was insufficient to determine maximum treating pressures for some wells; this is reflected by the 

“uncertain” category. Error bars display 95 percent confidence intervals. 

Hydraulic Fracturing Operations July 2016 

27 
 

 

 

 

 

 

 

 

 

 

 

 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Percent of Jobs 

(a) 

≤999 1,000-1,999 2,000-2,999 3,000-3,999 ≥4,000

Pressure Difference (psi) when 

Test Pressure ≥ Maximum Treating Pressure 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Percent of Jobs 

(b) 

≤999 1,000-1,999 2,000-2,999 3,000-3,999 ≥4,000

Pressure Difference (psi) when 

Test Pressure < Maximum Treating Pressure 

Figure 12. Magnitude of the difference between the casing test pressure and the maximum treating 

pressure when the casing test pressure was (a) greater than or equal to or (b) less than the maximum 

treating pressure. In all cases, the casing pressure test was conducted on the same well as the hydraulic 

fracturing job, and the casing pressure test occurred prior to the hydraulic fracturing job. An estimated 

8,100 (4,000-12,200) jobs are represented in panel a, and 7,400 (4,200-10,700) jobs are represented in 

panel b. Error bars display 95 percent confidence intervals. 

 

 

Hydraulic Fracturing Operations July 2016 

job.20 In 52 (20-82) percent of these jobs, the casing test pressure was greater than or equal to the 

maximum treating pressure, and in 48 (18-80) percent, the casing test pressure was less than the

maximum treating pressure. Figure 12 displays the magnitude of the difference between the casing 

test pressure and the maximum treating pressure for each of these categories. 

20 The time between the assigned casing pressure test and the date of the hydraulic fracturing stage corresponding to the

maximum treating pressure for the hydraulic fracturing job ranged from zero days to approximately two years. 

28 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

As shown in Figure 12a, when the casing test pressure was greater than or equal to the maximum 

treating pressure, the most common difference between these pressures was found to be less than

1,000 psi. When the casing test pressure was less than the maximum treating pressure, the most 

common difference between the pressures was found to be between 1,000 and 1,999 psi (Figure

12b). 

4.2.3. Microseismic Monitoring 

While microseismic monitoring is not a direct measurement of fracture growth during hydraulic 

fracturing, data collected during microseismic monitoring are often considered to be indicative of 

fracture growth (Davies et al., 2012; Fisher and Warpinski, 2012; Flewelling et al., 2013). As

described in Section 3.2, microseismic monitoring data provided for the study wells were used to 

estimate the maximum vertical and lateral components of fracture growth. Among the 100 (40­

300) jobs in which microseismic monitoring was reported, the maximum vertical component of

fracture growth (i.e., fracture height) per job ranged from 380 feet to 1,340 feet, with a median 

value of 680 feet. The maximum lateral component of fracture growth per job ranged from 700 feet

to 2,250 feet, with a median value of 1,000 feet. 

Maximum fracture heights estimated from microseismic monitoring data were compared to cement 

sheath heights directly above the point of shallowest hydraulic fracturing to estimate whether

induced fractures extended above the top of the cement. The comparison was done for individual 

hydraulic fracturing jobs. Among the 100 (40-300) hydraulic fracturing jobs that reported 

microseismic monitoring, the true vertical depth of the top of the cement sheath behind the

production casing in the well was always shallower than the true vertical depth of the top of the 

maximum fracture height estimated from microseismic monitoring data. Fractures created during

these hydraulic fracturing jobs were therefore unlikely to extend beyond the cement sheath directly 

above the point of shallowest hydraulic fracturing. Due to the small number of hydraulic fracturing

jobs in which this analysis was possible, this observation should not be interpreted to be reflective 

of all of the wells represented in this study. 

Maximum fracture heights were also compared to the depths of operator-reported protected 

ground water resources to assess whether induced fractures could have extended directly through 

the geologic strata to protected ground water resources reported by well operators. Again, the 

comparisons were done for individual hydraulic fracturing jobs. Given the assumptions identified in 

Sections 3.2 and 3.3, induced fractures were estimated to have grown no closer than 5,000 feet 

below operator-reported protected ground water resources during the jobs for which this distance

could be calculated. Fractures created during these hydraulic fracturing jobs were therefore 

unlikely to have reached the protected ground water resources reported by well operators. Because 

of the small number of wells for which this analysis was possible, this observation should not be

interpreted to be reflective of all of the wells represented in this study. 

29 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

5. Discussion of Subsurface Fluid Movement During 

Hydraulic Fracturing 

During hydraulic fracturing in an oil or gas well, hydraulic fracturing fluids are injected down the 

well under pressures great enough to fracture the targeted rock formation. The applied pressure 

moves the hydraulic fracturing fluid through the well and into the targeted rock formation. Once in 

the rock, the pressurized hydraulic fracturing fluid creates and grows fractures in the subsurface.

Hydraulic fracturing fluid travels through the subsurface via the newly-created fractures, 

interconnected pore spaces within the rock, or other permeable pathways (e.g., faults, natural

fracture systems, or nearby wells) (King, 2014; Ross and King, 2007). The pressurized hydraulic 

fracturing fluid can also displace fluids naturally present in the subsurface (e.g., brine, methane, or 

other hydrocarbons), causing these fluids to move through the subsurface during hydraulic 

fracturing (Brownlow et al., 2016). 

The potential for hydraulic fracturing fluids, or fluids naturally present in the subsurface, to move 

to underground drinking water resources during hydraulic fracturing depends on many factors. In 

general, these factors include, but are not limited to, the design and construction of the 

hydraulically fractured production well, the design and execution of the hydraulic fracturing job,

the characteristics of subsurface rock formations, and the relative location of induced fractures to 

underground drinking water resources or existing permeable pathways that may lead to drinking 

water resources (Fisher and Warpinski, 2012; Stringfellow et al., 2015; US EPA, 2015b). Together,

these factors affect how fluids move through the subsurface during hydraulic fracturing and 

whether they can reach underground drinking water resources. 

Data presented in Section 4, and other information included in the wells files, are used below to 

explore the role of the following, specific factors in subsurface fluid movement during hydraulic 

fracturing at the oil and gas production wells represented in this study: 

(1) the mechanical integrity of the hydraulically fractured oil or gas production well, and 

(2) the potential intersection of newly-created fractures with underground drinking water

resources or nearby existing pathways. 

The above factors are the focus of the discussion below. Data relevant to the design and

construction of hydraulically fractured production wells were summarized and presented in US 

EPA (2015b). 

5.1. Mechanical Integrity 

A well has mechanical integrity when it contains fluids within the well and prevents fluid 

movement along the outside of the well, between the outermost casing and the wellbore wall 

(GWPC, 2014). Mechanical integrity is achieved through well design and construction, which can 

include the presence of multiple barriers (e.g., casing and cement), and is retained through well

maintenance (GWPC, 2014; King and King, 2013; Ross and King, 2007). 

The mechanical integrity of a well depends on the mechanical integrity of the individual

components of the well. During hydraulic fracturing, pressure is applied to the inside of the 

30 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

production casing or a temporary frac string, if used. When these well components have mechanical 

integrity, the hydraulic fracturing fluid remains in the production casing or the temporary frac

string and reaches the targeted geologic formation without moving into the annular space behind 

the production casing or the temporary frac string. When the well components used for hydraulic 

fracturing do not have mechanical integrity or lose mechanical integrity during hydraulic

fracturing, fluids can move outside of the production casing or the temporary frac string into one or 

more of the annular spaces in the well. If multiple casings and cement sheaths are present within a

well, they can block fluid movement into the surrounding environment by serving as additional 

barriers between the invaded annular space and the surrounding geology. A well integrity failure 

occurs when no barriers (e.g., casing and cement) are left to block fluid from entering the

surrounding environment (King and King, 2013). 

Downhole well component failures during hydraulic fracturing were reported by well operators in 

3 (1-8) percent of the hydraulic fracturing jobs represented in this study. For some hydraulic 

fracturing jobs, these events were reported using phrases such as “communication to surface” or 

“casing leak.” For other jobs, these events were inferred from information available in the well files.

For example, “came around” and “annular pressure increase” were interpreted as well component 

failures during hydraulic fracturing when written descriptions of the well’s status and well 

operations indicated a well component failure. In all of these cases, information in the well files

suggested that hydraulic fracturing fluid flowed from the inside of the casing string used for

hydraulic fracturing to one or more of the annular spaces behind the casing string. 

When well component failures were reported, well operators generally stopped the hydraulic

fracturing job, addressed the cause of the failure, and completed the job. There were often multiple 

barriers (e.g., casing and cement) between the well components that failed and operator-reported

protected ground water resources.21,22 As noted above, multiple casings and cement sheaths can 

block fluid movement into the surrounding environment by serving as additional barriers between 

the invaded annular space and the surrounding geology. There was no evidence in the well files to

suggest that these additional barriers failed. However, there were well component failures in which 

there were no additional barriers between the casing string used for hydraulic fracturing and the

operator-reported protected ground water resource (i.e., a well integrity failure). Well integrity 

failures were reported in 0.5 (0.1-2) percent of all of the hydraulic fracturing jobs. Information in

the well files suggested that, in these cases, hydraulic fracturing fluid entered the annular space 

between the casing string used for hydraulic fracturing and the surrounding geology at depths 

corresponding to the operator-reported protected ground water resource. Based on the 

21 An estimated 800 (10-1,800) hydraulic fracturing jobs reported a well component failure. Of these jobs, an estimated

700 (10-1,600) had one or more additional barriers between the invaded annular space and the operator-reported

protected ground water resource. 

22 As described in US EPA (2015b), the wells represented in this study generally had multiple layers of casing and cement 

that can act as barriers to subsurface fluid movement by interrupting pathways for potential subsurface fluid movement.

The most common number of barriers to potential subsurface fluid movement from the inside of the well to the outside, at 

any point along the well, was either two (one casing string and one cement sheath) or three (two casing strings and one

cement sheath), with a range from zero to six. Additionally, there were often two or more barriers (i.e., cemented casings)

to potential subsurface fluid movement along the outside of the well, from the targeted rock formation to operatorreported protected ground water resources, with a range from zero to four. A detailed discussion of these pathways, and

the presence or absence of barriers, can be found in Section 5 of US EPA (2015b). 

31 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hydraulic Fracturing Operations July 2016 

information contained in the well files, it was not possible to determine whether fluid moved from 

the annular space into protected ground water resources in these cases. 

The well component failures reported in 3 (1-8) percent of the hydraulic fracturing jobs occurred 

during initial fracture treatments, re-completions and re-fractures, and in jobs conducted using a 

temporary frac string. When compared to the larger population of hydraulic fracturing jobs, a 

greater proportion of jobs conducted using a temporary frac string reported a well component

failure [20 (7-46) percent] than jobs that did not use a temporary frac string [0.9 (0.2-3) percent]. 

As described in Section 2, a temporary frac string is lowered into the well and secured at its base

using a packer or by latching into existing well components located in the well. Hydraulic fracturing 

fluids are pumped through the temporary frac string into the targeted geologic formation, and the

temporary frac string is removed from the well when hydraulic fracturing is complete. The data 

presented above suggest that temporary frac strings were less effective at containing fluids during

hydraulic fracturing than permanent well components. 

Six (2-19) percent of re-fractures and re-completions reported a well component failure during

hydraulic fracturing, compared to 2 (0.5-8) percent of initial fracture treatments. While the 

confidence intervals overlap, the point estimates suggest that re-fractures and re-completions may

have been more likely than initial fracture treatments to experience a well component failure 

during hydraulic fracturing. As discussed below, re-fractures and re-completions may have been

more likely to experience well component failures, because well design or well age can affect the 

mechanical integrity of the well or because temporary frac strings may be more likely to be used in 

re-fractures and re-completions. 

When a new oil and gas production well is expected to be hydraulically fractured, the well can be

designed to contain the fluids injected under the pressures expected during hydraulic fracturing 

(Ross and King, 2007; US EPA, 2011b). When hydraulic fracturing is not considered as part of the

initial well design, the well may not have sufficient mechanical integrity to be re-completed using 

hydraulic fracturing, and remedial work on the well may be conducted prior to hydraulic fracturing

(Fleckenstein et al., 2015; Martin and Rylance, 2007). For example, wells that are re-completed 

using hydraulic fracturing above their original completion interval may have insufficient cement at 

the shallower depth to contain the pressure applied during hydraulic fracturing. Hydraulic 

fracturing was conducted at shallower depths in 95 (75-99) percent of the re-completions 

identified in this study (Section 4.1). In some of these cases, cement was already present within the

re-completion interval. In other cases, remedial cementing occurred in the re-completion interval 

prior to hydraulic fracturing. 

Older wells, regardless of initial well design goals, may not be able to withstand the pressures 

applied during hydraulic fracturing, because mechanical integrity can change over time. The

mechanical properties of well components, including casing and cement, can degrade over time, 

potentially creating pathways for subsurface fluid movement (Brufatto et al., 2003; Council of 

Canadian Academies, 2014; Ross and King, 2007; Smith et al., 2012). Re-fractures and recompletions may have been more likely to experience well component failures, because refractures and re-completions often occurred in older wells. The median estimated age of well 

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components at the time of a re-fracture or re-completion was six years, compared to 45 days for

initial fracture treatments. 

Re-fractures and re-completions may also have been more likely to experience well component 

failures than initial fracture treatments, because temporary frac strings may be more likely to be 

used in re-fractures and re-completions. Temporary frac strings can be used in re-fractures and recompletions when there are concerns about whether the existing casing can withstand the

pressures applied during hydraulic fracturing (Babaniyazov et al., 2012; Babaniyazov and Jackson, 

2013; US EPA, 2011b). Temporary frac strings can also be used to isolate specific portions of the

well for hydraulic fracturing. For example, re-completions at depths deeper than the initial fracture 

treatment may be conducted using a temporary frac string, because the temporary frac string can 

exclude existing, shallower perforations from hydraulic fracturing. Data presented in this report 

suggest that well component failures were more likely to occur when a temporary frac string was 

used for hydraulic fracturing than when permanent well components were used for hydraulic 

fracturing. 

5.2.	 Potential Intersection of Fractures with Operator-Reported Protected 

Ground Water Resources or Existing Pathways 

Fracture growth is affected by the characteristics of the hydraulic fracturing job and the 

characteristics of the subsurface. During hydraulic fracturing, injection volumes and pressures can 

be used to control fracture growth in the subsurface (Fisher and Warpinski, 2012; Flewelling et al., 

2013; Kim and Moridis, 2015; Martin and Valkó, 2007). Formation characteristics, such as 

permeability, in situ stresses, and rock hardness, affect fracture creation, geometry, and growth 

(Fisher and Warpinski, 2012; Martin and Valkó, 2007; Canadian Water Network, 2015). Layered

geology, where it exists, and natural fractures in the subsurface can hinder vertical fracture growth, 

causing induced fractures to remain within or near the targeted geologic formation (Fisher and

Warpinski, 2012; Kim and Moridis, 2015). 

Fractures created during hydraulic fracturing provide a pathway along which fluids can move in the

subsurface. If local geologic conditions allow it, the intersection of induced fractures with operatorreported protected ground water resources can result in hydraulic fracturing fluids reaching

drinking water resources. Additionally, the intersection of induced fractures with existing 

subsurface pathways may create a continuous pathway to underground drinking water resources 

along which fluids may travel. The potential for each situation is described below, using data 

available in the well files. 

5.2.1.	 Potential Intersection of Fractures with Operator-Reported Protected Ground Water 

Resources 

Information on the potential intersection of induced fractures with protected ground water 

resources reported by well operators was available for two cases: (1) hydraulic fracturing jobs with

microseismic monitoring data and (2) wells in which the point of shallowest hydraulic fracturing

was above the base of the operator-reported protected ground water resource. 

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Hydraulic Fracturing Operations July 2016 

In the first case, microseismic monitoring data was used to estimate the maximum vertical 

component of fracture growth in 0.5 (0.1-2) percent of the hydraulic fracturing jobs. As reported in 

Section 4.2.3, these data suggest that fractures created during these jobs grew no closer than 5,000 

feet below operator-reported protected ground water resources. For these hydraulic fracturing 

jobs, the potential for induced fractures to intersect operator-reported protected ground water

resources was likely low, because the distance separating the estimated fracture depth and the 

operator-reported base of the protected ground water resource was much larger (at least 5,000 

feet) than the maximum vertical component of fracture growth estimated from microseismic

monitoring data. 

In the second case, the estimated separation distance between the point of shallowest hydraulic

fracturing and the base of the operator-reported protected ground water resource was used to 

evaluate the potential for induced fractures to reach protected ground water resources in the 

absence of information on fracture growth.23 As reported in US EPA (2015b), the estimated 

separation distance was less than zero feet in 0.4 (0.1-3) percent of the wells. In these wells, 

perforations used for hydraulic fracturing were placed shallower than the depth of the base of the

operator-reported protected ground water resource. When perforations used for hydraulic 

fracturing are shallower than the base of the operator-reported protected ground water resource, 

the potential for induced fractures to directly intersect with the protected ground water resource is

high, if the protected ground water resource is present at that depth. Based on the information 

contained in the well files, it was not possible to determine whether hydraulic fracturing fluid 

entered protected ground water resources in these cases. 

For the majority of the wells represented in this study, it was not possible to assess with a high 

degree of certainty the potential for induced fractures to intersect operator-reported protected

ground water resources, because they did not fall into either of the cases described above. The 

above cases, however, highlight the importance of the vertical separation distance between the 

point of shallowest hydraulic fracturing in a well and the base of protected ground water resources.

If the vertical separation distance is less than, or comparable to, the vertical component of fracture 

growth, induced fractures may potentially reach protected ground water resources. Conversely, if

the vertical separation distance is greater than the vertical component of fracture growth, induced

fractures are unlikely to extend directly into protected ground water resources. 

Data presented in Section 4.1 show that the estimated separation distance can change over time, if a

well is re-completed using hydraulic fracturing.24 Among the wells re-completed in this study, the 

23 As reported in US EPA (2015b), the separation distance was estimated for each study well by subtracting the depth of

the operator-reported protected ground water resource from the measured depth of the point of shallowest hydraulic

fracturing in the well. The estimated separation distance is not always equal to the true vertical separation distance, 

which is defined as the vertical distance between the point of shallowest hydraulic fracturing and the depth of the

operator-reported protected ground water resource. In perfectly vertical wells, the estimated separation distance is equal

to the true vertical separation. True vertical separation distances for deviated and horizontal wells are expected to be

smaller than estimated separation distances. 

24 This may also be true for the wells that were re-fractured, because in this study, a re-fracture was defined as a hydraulic

fracturing job in which any portion of the depth interval at which hydraulic fracturing was conducted overlapped with a 

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Hydraulic Fracturing Operations July 2016 

percent change in the estimated separation distance ranged from -147 percent to 64 percent, with a 

median of -22 percent.25 A negative percent change indicates that the estimated separation distance 

became smaller when the well was re-completed. A positive percent change indicates that the 

estimated separation distance became larger when the well was re-completed. These data show 

that re-completing a well changes the separation distance between the point of shallowest

hydraulic fracturing in a well and the operator-reported protected ground water resource. 

The discussion presented above relied on depths to protected ground water resources reported by 

well operators (Section 3.3). The use of different depths would likely affect the results presented

above. 

5.2.2. Potential Intersection of Fractures with Existing Pathways 

Computer modeling studies suggest that the connection of induced fractures to other features in the 

subsurface may lead to subsurface fluid movement within these features, if they are highpermeability pathways (Birdsell et al., 2015). Examples of these features include, but are not 

limited to, existing faults, natural fracture systems, nearby oil and gas production wells, and 

uncemented intervals within the hydraulically fractured production well (Ciezobka and Salehi,

2013; Energy Resources Conservation Board, 2012; Fisher and Warpinski, 2012; US EPA, 2015b). If 

these features are located within or near the fracture network created during hydraulic fracturing,

then fluids may flow into these features either through intersecting pathways or fluid displacement. 

Information on the relative location of induced fractures to existing faults, natural fracture systems, 

and nearby wells was generally not found in the well files, although 1 (0.4-4) percent of the wells 

represented in this study reported a frac hit. Frac hits were reported in the well files using the 

phrase “frac’d into [well name].” Frac hits are generally understood to occur when hydraulic 

fracturing at a well affects a nearby oil and gas production well (Energy Resources Conservation

Board, 2012; King, 2014). The potential for hydraulic fracturing fluids, or subsurface fluids affected 

by hydraulic fracturing, to move to underground drinking water resources during a frac hit

depends on (1) the mechanical integrity of the offset (i.e., nearby) well and (2) the depth of 

hydraulic fracturing compared to the well construction characteristics of the offset well (e.g., 

location of cement). Information in the well files was insufficient to assess the potential for

subsurface fluid movement to operator-reported protected ground water resources during the frac 

hits reported at the wells represented in this study. 

Frac hits are often detected through changes in pressure or fluid production at offset wells (Ajani

and Kelkar, 2012; Energy Resources Conservation Board, 2012). Because this study collected 

depth interval fractured in a previous job. Under this definition, it is possible that the point of shallowest hydraulic

fracturing in a re-fracture was shallower than the point of shallowest hydraulic fracturing in a previous job. 

25 The percent change in the estimated separation distance was calculated using [(ds2-ds1)/ds1]*100, where ds1 is equal to

the estimated separation distance between the point of shallowest hydraulic fracturing in job 1 (i.e., initial completion or

previous hydraulic fracturing job) and the operator-reported protected ground water resource and ds2 is equal to the

estimated separation distance between the point of shallowest hydraulic fracturing in job 2 (i.e., the re-completion of

interest) and the operator-reported protected ground water resource. Note that the same value was used for the 

operator-reported protected ground water resource when calculating ds1 and ds2. Of the 3,000 (100-5,900) recompletions identified in this study, 50 (20-70) were ineligible for this analysis, because no depth to a protected ground

water resource was provided by the well operator. 

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Hydraulic Fracturing Operations	 July 2016 

information for the study wells and not offset wells, the reported occurrence of frac hits may be an 

underestimate. Similarly, the percentage of wells that did not report a frac hit [99 (96-100) percent]

may be an overestimate. 

5.3.	 Monitoring and Testing for Subsurface Fluid Movement During Hydraulic 

Fracturing 

Each of the four types of monitoring and testing activities discussed in this report can provide 

information on subsurface fluid movement during hydraulic fracturing, because they provide

information on the mechanical integrity of the well, fracture growth, and the potential intersection 

of induced fractures with existing pathways. Figure 13 illustrates how casing pressure tests, surface 

treating pressure monitoring, annular pressure monitoring, and microseismic monitoring are

conducted and identifies which parts of the well can be monitored or tested during these activities. 

Figure 13. Generic well diagrams illustrating the four monitoring and testing activities discussed in this 

study. (a) Depiction of a casing pressure test, which can occur before or after hydraulic fracturing. (b) 

Depiction of surface treating pressure monitoring, annular pressure monitoring, and microseismic 

monitoring. These monitoring activities can occur during hydraulic fracturing. 

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Hydraulic Fracturing Operations July 2016 

5.3.1. Mechanical Integrity 

Knowledge of the mechanical integrity of a well during hydraulic fracturing relies on information 

that can be obtained using three of the monitoring and testing activities illustrated in Figure 13:

casing pressure tests, surface treating pressure monitoring, and annular pressure monitoring (King 

and King, 2013; US EPA, 2011b). As illustrated in Figure 13a, casing pressure tests can be 

conducted before or after hydraulic fracturing. During a casing pressure test, pressure is applied to

the inside of the casing string used for hydraulic fracturing (e.g., the production casing in Figure

13a) and monitored to determine whether there are leaks in the well components being tested. 

When conducted prior to hydraulic fracturing, casing pressure tests can indicate whether the well 

components are likely to contain the fluids injected during hydraulic fracturing (US EPA, 2011b). In 

this study, the casing test pressure was equally likely to be below the reported maximum treating 

pressure as above the reported maximum treating pressure when a casing pressure test was

conducted prior to the hydraulic fracturing job (Section 4.2.2). Casing pressure tests in which the 

test pressure is less than the reported maximum treating pressure may occur if the reported

maximum treating pressure was greater than the anticipated maximum treating pressure or if the 

casing pressure test was done for another purpose (e.g., packer setting tests, bridge plug setting

tests, or remedial cementing tests). Casing pressure tests conducted at pressures less than the 

reported maximum treating pressure do not provide data, prior to hydraulic fracturing, that the 

well components used for hydraulic fracturing can contain fluids under the pressure applied during

hydraulic fracturing. 

Well component failures during hydraulic fracturing were reported by well operators in 3 (1-8) 

percent of the hydraulic fracturing jobs (Section 5.1). In 79 (28-99) percent of these jobs, there was 

no casing pressure test prior to hydraulic fracturing or, if there was a casing pressure test, it 

occurred after hydraulic fracturing or the casing test pressure was less than the reported maximum

treating pressure. In 7 (2-25) percent of the jobs, a casing pressure test was conducted before 

hydraulic fracturing using a test pressure that was greater than the reported maximum treating 

pressure.26 These data suggest that the reported rate of well component failures during hydraulic 

fracturing might have been lower, if casing pressure tests were conducted before hydraulic 

fracturing at test pressures greater than the maximum treating pressure among the jobs that

reported a well component failure. 

As illustrated in Figure 13b, surface treating pressure monitoring and annular pressure monitoring 

can occur during hydraulic fracturing. While both pressures are monitored at the wellhead, each

provides information on different parts of the well. The surface treating pressure reflects the 

pressure created inside the casing string used for hydraulic fracturing (e.g., the production casing in 

Figure 13b) when hydraulic fracturing fluids are injected. Sudden or unexpected changes in the

surface treating pressure can indicate casing or cement failure (US EPA, 2011b).27 If there is a loss 

26 In 14 (8-22) percent of the hydraulic fracturing jobs with a well component failure, a casing pressure test was

conducted outside of the date range used for the casing pressure test analysis described in Section 4.2.2. Casing test 

pressures were not compared to maximum treating pressures reported for these jobs. 

27 Sudden or unexpected changes in the surface treating pressure may also indicate equipment problems on the surface 

(e.g., a leak in a hose used to transfer hydraulic fracturing fluid) (US EPA, 2011b). 

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Hydraulic Fracturing Operations	 July 2016 

in casing and/or cement integrity during hydraulic fracturing, there may be a corresponding 

increase in the pressure in the annular space behind the casing string used for hydraulic fracturing

(e.g., the space behind the production casing in Figure 13b) (Ross and King, 2007; US EPA, 2011b). 

Annular pressure increases can also occur because of pressure-induced casing expansion or

thermal expansion of fluids already present in the annular space (Arnold, 1991; US EPA, 2011b). 

The reported occurrence of annular pressure monitoring (Section 4.2) may have implications for

the reported occurrence of well component failures. As noted in Section 5.1, well component 

failures were identified from text in documents contained in the well files and not through the

EPA’s review of the monitoring and testing activities considered in this study. Well component 

failures may not have been observed and documented in the well files if annular pressure

monitoring was not conducted during hydraulic fracturing. Because the reported occurrence of 

annular pressure monitoring was 53 (27-77) percent, some hydraulic fracturing jobs may have 

experienced well component failures that were not detected. Therefore, the estimated occurrence

of well component failures [3 (1-8) percent of hydraulic fracturing jobs] may be an underestimate. 

Additionally, the estimated percentage of hydraulic fracturing jobs that did not have a well 

component failure [97 (92-99) percent] may be an overestimate. 

As described above, different monitoring or testing activities provide different types of information 

on mechanical integrity. Collectively, data from these tests can indicate whether unintentional

subsurface fluid movement may occur or is occurring due to a well component failure. Depending 

on the particular well construction, failing a test or detecting unexpected pressure changes may 

suggest, but does not necessarily indicate, that impacts to drinking water resources will occur or

have occurred. Rather, these results may suggest that one or more components of the well may not

be performing as designed and that corrective actions may be necessary (US EPA, 2011b). 

5.3.2.	 Potential Intersection of Fractures with Operator-Reported Protected Ground Water 

Resources or Existing Pathways 

As described in Section 5.2, the potential intersection of induced fractures with operator-reported 

protected ground water resources or existing pathways that may connect to underground drinking 

water resources could result in subsurface fluid movement to drinking water resources during 

hydraulic fracturing. Knowledge of this type of situation relies on information about fracture

growth, the intersection of newly-created fractures with existing pathways, and the depth of 

protected ground water resources. As discussed below, three of the four types of monitoring and

testing activities included in this report can provide information on fracture growth and the 

intersection of fractures with existing pathways. None of the four monitoring and testing activities

provide information on the depth of protected ground water resources.28 

Fracture Growth. Information on fracture growth during hydraulic fracturing can be obtained 

through two of the monitoring and testing activities illustrated in Figure 13b: surface treating

pressure monitoring and microseismic monitoring (Fisher and Warpinski, 2012; Malone and Ely, 

2007; US EPA, 2011b; Warpinski, 2009). Changes in the surface treating pressure can be used to 

28 Section 3.3 provides a brief summary of the data sources used by well operators to report depths of protected ground

water resources. A more detailed discussion can be found in US EPA (2015b). 

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Hydraulic Fracturing Operations July 2016 

estimate vertical fracture growth and fracture propagation under a given set of assumptions 

(Malone and Ely, 2007; US EPA, 2011b). While surface treating pressure was monitored during 97

(94-99) percent of the hydraulic fracturing jobs, the surface treating pressure monitoring data 

available in the well files was often insufficient to estimate fracture growth.29 

Microseismic monitoring uses long arrays of sensitive receivers in offset wells at depths that are 

relatively close to the depth of hydraulic fracturing (Figure 13b), or on the surface, to detect energy 

released during microseismic events (Warpinski, 2009). As described in Fisher and Warpinski

(2012): 

“Microseismic monitoring is based on detecting and locating the small reservoir movements 

that take place as a result of the [hydraulic] fracturing process. These movements are 

caused by changes in stress (fracture opening) and fluid pressure (leakoff), and they occur

along natural fractures, bedding planes, and other weakness zones in the rocks with which 

the fracture makes contact. Therefore, it is an excellent technology for monitoring fracture

growth by tracking the distribution of microseismic events.” 

While microseismic monitoring can be used to estimate fracture growth, it was reported to have 

been conducted in only 0.5 (0.1-2) percent of the hydraulic fracturing jobs. The relatively low 

reported occurrence of microseismic monitoring likely reflects the strategy generally used by the

industry: microseismic monitoring is often used in the early stages of a field’s development when 

fracture growth is uncertain (Council of Canadian Academies, 2014). As more wells are completed,

additional microseismic monitoring is not conducted, because it is not expected to provide 

significant new information about fracture growth within the targeted geologic formation (Council

of Canadian Academies, 2014). 

As described in Section 5.2.1, the lack of hydraulic fracturing job-specific data on fracture growth 

among the wells represented in this study limited our ability to assess the potential for induced

fractures to reach protected ground water resources reported by well operators. 

Intersection of Fractures with Existing Pathways. Information on the intersection of induced 

fractures with existing pathways, or on subsurface fluid movement into existing pathways during 

hydraulic fracturing, can be obtained through surface treating pressure monitoring and annular

pressure monitoring. Sudden or unexpected pressure changes in the surface treating pressure can 

indicate fracture growth out of zone, fracture growth into a permeable pathway (such as an offset

well), or the cessation of fracture growth (US EPA, 2011b). Unexpected changes in the annular 

pressure can indicate the introduction of fluids into the annular space. Fluids can reach the annular 

space if induced fractures extend above the cement and into the annular space or if pressure

changes in the subsurface push fluids through existing permeable pathways into the annular space

(US EPA, 2011b). 

29 The available data often included a single surface treating pressure value, which prevented an analysis of changes in the

surface treating pressure. 

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Hydraulic Fracturing Operations July 2016 

With the possible exception of frac hits, information in the well files was insufficient to determine 

whether fractures created during hydraulic fracturing intersected existing pathways in the

subsurface (Section 5.2.2). 

6. Study Limitations 

The survey design and data collection process have implications for the interpretation of the results 

presented in this report. As described in Section 3.4, the results presented in this report are 

statistically representative of onshore oil and gas production wells that were hydraulically

fractured by nine oil and gas service companies between approximately September 2009 and 

September 2010. The results may not be statistically representative of all oil and gas production 

wells hydraulically fractured in the same time period. However, comparisons between the list of

wells reported by the nine service companies and oil and gas production activities in the United 

States in 2009 and 2010 suggest that the observations made in this report are likely indicative of

onshore oil and gas production wells hydraulically fractured during the time frame examined in this

study (US EPA, 2015b). 

Estimates of the frequency of occurrence of hydraulic fracturing characteristics and monitoring and

testing activities are summarized at the national level. Given the survey design, it was not possible 

to display results at a smaller scale (e.g., by targeted geologic formation). The estimates presented 

in this report may be different for different regions of the country, because of differences in local

geologic characteristics, regulatory requirements, and company preferences. The estimates may 

also not apply to wells hydraulically fractured after 2010, as hydraulic fracturing practices and

regulatory requirements change over time. Despite these limitations, the data presented in this 

report provide an overview of onshore oil and gas production wells hydraulically fractured by the

nine service companies during the time frame of this study. 

Finally, the results presented in this report are generated from data provided by oil and gas well 

operators. The data are limited in scope to the information requested by the EPA and the 

information provided by the well operators. While quality assurance and quality control measures

were used to ensure that analyses presented in this report accurately reflected the data supplied by 

the well operators, the EPA did not attempt to independently and systematically verify the data.

Consequently, the results presented in this report reflect the scope of the information request and

are of the same quality as the supplied data and the database created by the EPA (Section 3.5). 

7. Summary 

This report presents the results of a survey of onshore oil and gas production wells hydraulically 

fractured by nine oil and gas service companies in the United States during 2009 and 2010. Two

factors that affect the potential for subsurface fluid movement during hydraulic fracturing were 

examined: the mechanical integrity of the hydraulically fractured oil and gas production well and 

the potential intersection of newly-created fractures with protected ground water resources 

reported by well operators or nearby existing pathways. 

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Hydraulic Fracturing Operations July 2016 

Situations that potentially allowed hydraulic fracturing fluids to move to protected ground water 

resources reported by well operators were identified in a small number of wells. These situations

included: 

Well integrity failures during hydraulic fracturing [0.5 (0.1-2) percent of the hydraulic 

fracturing jobs]. In these cases, well components (e.g., casing, cement, or packers) failed 

during hydraulic fracturing, and no additional casing or cement barriers separated the well 

components that failed from the operator-reported protected ground water resources. 

Information in the well files suggested that, in these cases, hydraulic fracturing fluid entered 

the annular space between the casing string used for hydraulic fracturing and the 

surrounding geology at depths corresponding to protected ground water resources

reported by well operators. Based on the information contained in the well files, it was not 

possible to determine whether hydraulic fracturing fluid moved from the annular space into

protected ground water resources in these cases. 

Perforations used for hydraulic fracturing were shallower than the base of protected ground 

water resources reported by well operators [0.4 (0.1-3) percent of the wells] (US EPA, 2015b). 

When perforations used for hydraulic fracturing are shallower than the base of the

operator-reported protected ground water resource, the potential for induced fractures to 

directly reach the protected ground water resource is high, if the protected ground water

resource is present at that depth. Based on the information contained in the well files, it was 

not possible to determine whether hydraulic fracturing fluid entered protected ground

water resources in these cases. 

Information on the relative location of newly-created fractures to existing pathways was generally

not found in the well files, although 1 (0.4-4) percent of the wells reported a frac hit. Frac hits 

occurred when hydraulic fracturing at a well affected a nearby oil and gas production well. It was

not possible to determine whether hydraulic fracturing fluids, or subsurface fluids affected by 

hydraulic fracturing, reached operator-reported protected ground water resources during the frac

hits, because available information in the well files was insufficient to determine whether fluids 

flowed along the outside of the nearby oil and gas production well and into protected ground water 

resources. 

These results, as well as other information on hydraulic fracturing characteristics and monitoring

and testing activities before and during hydraulic fracturing, highlight important well design, 

construction, and operation practices that should be considered when assessing the potential 

impacts of hydraulic fracturing on drinking water resources. 

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Hydraulic Fracturing Operations July 2016 

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GWPC. 2009. State Oil and Natural Gas Regulations Designed to Protect Water Resources. Ground 

Water Protection Council for US Department of Energy. Available at http://www.gwpc.org/sites/

default/files/state_oil_and_gas_regulations_designed_to_protect_water_resources_0.pdf. Accessed 

May 9, 2014. 

GWPC. 2014. State Oil and Natural Gas Regulations Designed to Protect Water Resources. Available 

at http://www.gwpc.org/sites/default/files/files/ 

Oil%20and%20Gas%20Regulation%20Report%20Hyperlinked%20Version%20Final-rfs.pdf. 

Accessed October 27, 2014. 

Gupta, D.V.S., and Valkó, P. 2007. Fracturing Fluids and Formation Damage. In Economides, M.J., and

Martin, T., editors, Modern Fracturing: Enhancing Natural Gas Production. Energy Tribune

Publishing, Inc., Houston, Texas. 

Hlidek, B., and Weijers, L. 2007. Fracture-to-Well Connectivity. In Economides, M.J., and Martin, T.,

editors, Modern Fracturing: Enhancing Natural Gas Production. Energy Tribune Publishing, Inc.,

Houston, Texas. 

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Hydraulic Fracturing Operations July 2016 

Kim, J., and Moridis, G.J. 2015. Numerical Analysis of Fracture Propagation During Hydraulic 

Fracturing Operations in Shale Gas Systems. International Journal of Rock Mechanics & Mining 

Sciences 76:127-137. 

King, G.E., and King, D.E. 2013. Environmental Risk Arising from Well Construction Failure: 

Differences between Barrier and Well Failure, and Estimates of Failure Frequency across Common

Well Types, Locations, and Well Age. SPE Production & Operations 28:323-344. 

King, G.E. 2014. 60 Years of Multi-Fractured Vertical, Deviated and Horizontal Wells: What Have We 

Learned? SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October 

27-29, 2014. Society of Petroleum Engineers. 

Kissinger, A., Helmig, R., Ebigbo, A., Class, H., Lange, T., Sauter, M., Heitfeld, M., Klünker, J., and

Jahnke, W. 2013. Hydraulic Fracturing in Unconventional Gas Reservoirs: Risks in the Geological 

System, Part 2. Environmental Earth Sciences 70:3855-3873. 

Malone, M., and Ely, J.W. 2007. Execution of Hydraulic Fracturing Treatments. In Economides, M.J.,

and Martin, T., editors, Modern Fracturing: Enhancing Natural Gas Production. Energy Tribune

Publishing, Inc., Houston, Texas. 

Martin, T., and Rylance, M. 2007. Technologies for Mature Assets. In Economides, M.J., and Martin,

T., editors, Modern Fracturing: Enhancing Natural Gas Production. Energy Tribune Publishing, Inc.,

Houston, Texas. 

Martin, T., and Valkó, P. 2007. Hydraulic Fracture Design for Production Enhancement. In 

Economides, M.J., and Martin, T., editors, Modern Fracturing: Enhancing Natural Gas Production.

Energy Tribune Publishing, Inc., Houston, Texas. 

Ross, D., and King, G. 2007. Well Completions. In Economides, M.J., and Martin, T., editors, Modern

Fracturing: Enhancing Natural Gas Production. Energy Tribune Publishing, Inc., Houston, Texas. 

Rozell, D.J., and Reaven, S.J. 2012. Water Pollution Risk Associated with Natural Gas Extraction from 

the Marcellus Shale. Risk Analysis 32:1382-1393. 

Smith, D.K. 1976. Cementing (Monograph – Society of Petroleum Engineers; v. 4). Henry L. Doherty 

Memorial Fund of AIME, Dallas, Texas. 

Smith, L., Lee, C.H., Milanovic, D., and Billingham, M. 2012. Modeling and Prediction of the Corrosion 

of Onshore Well Casings. Corrosion 2012 Conference & Expo, Salt Lake City, Utah, March 11-15,

2012. NACE International. 

Stringfellow, W.T., Cooley, H., Varadharajan, C., Heberger, M., Reagan, M.T., Domen, J.K., Sandelin, W., 

Camarillo, M.K., Jordan, P.D., Donnelly, K., Nicklisch, S.C.T., Hamdoun, A., and Houseworth, J.E. 2015. 

Impacts of Well Stimulation on Water Resources. 2. In An Independent Scientific Assessment of

Well Stimulation in California, Volume II. California Council on Science and Technology. Available at

http://ccst.us/projects/hydraulic_fracturing_public/SB4.php. Accessed August 21, 2015. 

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Hydraulic Fracturing Operations July 2016 

The Cadmus Group, Inc. 2013. Supplemental Programmatic Quality Assurance Project Plan for 

Work Assignment 5-58, Including Amendment 1: Well File Review in Support of Study of Potential

Impacts of Hydraulic Fracturing on Drinking Water Resources, Part 3. Available at 

http://www2.epa.gov/sites/production/files/documents/cadmusspqapp-wellfiles-508.pdf. 

Accessed October 27, 2014. 

US Environmental Protection Agency (US EPA). 2011a. Plan to Study the Potential Impacts of

Hydraulic Fracturing on Drinking Water Resources. Available at http://www2.epa.gov/sites/

production/files/documents/hf_study_plan_110211_final_508.pdf. Accessed June 18, 2014. 

US EPA. 2011b. Proceedings of the Technical Workshops for the Hydraulic Fracturing Study: Well 

Construction and Operations. Available at http://www2.epa.gov/hfstudy/hydraulic-fracturingstudy-march-2011-technical-workshop-well-construction-and-operations. Accessed August 21, 

2015. 

US EPA. 2013. National Hydraulic Fracturing Study Evaluation of Existing Production Well File 

Contents: Quality Assurance Project Plan. Available at http://www2.epa.gov/sites/production/

files/documents/wiser_508qapp_well_file_review_research_final_2012.pdf. Accessed October 27, 

2014. 

US EPA. 2014. National Hydraulic Fracturing Study Evaluation of Existing Production Well File 

Contents: Quality Assurance Project Plan, Amendment 1. Available at http://www2.epa.gov/sites/ 

production/files/documents/wiser_508qapp_well_file_review_research_final_2012.pdf. Accessed 

October 27, 2014. 

US EPA. 2015a. Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure

Registry 1.0. Office of Research and Development, Washington, DC. EPA/601/R-14/003. Available 

at http://www2.epa.gov/hfstudy/analysis-hydraulic-fracturing-fluid-data-fracfocus-chemicaldisclosure-registry-1. Accessed July 15, 2015. 

US EPA. 2015b. Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production 

Wells: Well Design and Construction. Office of Research and Development, Washington, DC.

EPA/601/R-14/002. Available at http://www2.epa.gov/hfstudy/review-well-operator-fileshydraulically-fractured-oil-and-gas-production-wells-well-design. Accessed July 14, 2015. 

US EPA. 2015c. Review of State and Industry Spill Data: Characterization of Hydraulic FracturingRelated Spills. Office of Research and Development, Washington, DC. EPA/601/R-14/001. Available 

at http://www2.epa.gov/hfstudy/review-state-and-industry-spill-data-characterization-hydraulicfracturing-related-spills-1. Accessed July 14, 2015. 

Warpinski, N. 2009. Microseismic Monitoring: Inside and Out. Journal of Petroleum Technology 

61:80-85. 

Westat. 2013. Quality Assurance Project Plan v1 for WA 3-4: Hydraulic Fracturing. Available at 

http://www2.epa.gov/sites/production/files/2014-01/documents/westat-qapp.pdf. Accessed 

October 27, 2014. 

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Appendix: Variance Estimation 

Variance estimates used to calculate 95 percent confidence intervals presented in this report were 

conducted following the approach described in Appendix A of US EPA (2015b) except in two cases. 

First, if an analysis was conducted on a subpopulation using data from fewer than two well

operators in each strata, the approach for estimating the variance was adjusted by collapsing strata, 

as described below. Second, if a percentage estimate had an estimated design effect less than one 

(usually for a rare characteristic, such as near zero percent of the wells or hydraulic fracturing

jobs), the approach was adjusted by setting the design effect to 1.0, also described below. It is 

anticipated that the design effect is actually greater than 1.0, but difficult to estimate with so few

respondents. These adjustments are expected to provide more accurate 95 percent confidence

intervals. 

Collapsing Strata. As described in Appendix A of US EPA (2015b), the strata used for variance

estimation are the first-stage strata used to select well operators. The strata used for variance 

estimation include two strata with two large well operators each (Strata 1 and 2), one stratum with

all medium well operators (Stratum 3), and one stratum with all small well operators (Stratum 4). 

Because variance estimates measure the consistency (or variability) between well operators within 

the same stratum, each variance stratum must contain at least two well operators. When fewer than 

nine well operators are included in an analysis, any of the four variance strata described above

(Strata 1-4) may consist of only one well operator. When this occurred, strata were collapsed 

(Wolter, 1985) so that two or more well operators were in each strata. The sequential rules for

collapsing strata were: 

(1) If Stratum 1 or Stratum 2 did not have at least two well operators with study wells in the

subpopulation, merge all well operators from Stratum 1 and Stratum 2 into Stratum 2. 

(2) If Stratum 3 or Stratum 4 did not have at least two well operators with study wells in the

subpopulation, merge all medium and small well operators from Stratum 3 and Stratum 4 

into Stratum 3. 

(3) If Stratum 2 did not have at least two well operators with study wells in the subpopulation, 

merge all well operators from Stratum 2 into Stratum 3. 

(4) If Stratum 3 did not have at least two well operators with study wells in the subpopulation, 

merge all well operators from Stratum 3 into Stratum 2. 

(5) If Stratum 2 did not have at least two well operators with study wells in the subpopulation, 

do not calculate the confidence interval, because there are not enough well operators. 

When strata were collapsed, the equations listed in Appendix A of US EPA (2015b) were adjusted to 

account for the correct number of well operators, strata, and degrees of freedom. 

Design Effect. The design effect is the ratio of the estimated variance from the survey design used in 

this study divided by the variance of a simple random sample of the same size (Kish, 1965). In most 

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Hydraulic Fracturing Operations July 2016 

cases, the design effect should be greater than one, because clustering study wells within well 

operators reduces the independence of the sampled wells (i.e., there are some commonalities

because a well operator likely uses similar practices across their wells). Unequal sampling weights 

also increase the design effect, because some of the study wells become more important to the 

variance estimate than others. Both of these factors—multiple study wells from a single well 

operator and unequal sampling weights—generally reduce the effective sample size from what

would be expected in a simple random sample and increase the associated design effect.30 

The estimated variance from such small samples is relatively imprecise and may result in estimated 

design effects less than one even through the true design effect is greater than one. Although design 

effects less than one are possible, they are not expected in this study. As a result, estimated design

effects less than one were interpreted as an indication that the variance estimate was unusually low 

due to chance. This is more likely to occur when estimating percentages for rare characteristics and 

when there are fewer well operators from which to estimate the variance. In order to protect

against variance estimates for percentages that are unusually small by chance and associated 

confidence intervals that imply greater precision than warranted, the design effects for percentages

were restricted to be greater than or equal to 1.0. When the calculated design effect for a 

percentage was less than 1.0 after collapsing strata (if needed), it was set equal to 1.0. This replaced 

the sample variance estimate with the simple random sampling variance, which increased the

width of the confidence interval. This does not completely ameliorate the issue of too narrow 

confidence intervals, because the true design effect is likely greater than 1.0. Therefore, the

appropriate confidence intervals may be wider than the reported confidence intervals. A similar 

adjustment for the estimated number of wells (as opposed to percent) was not used, because there

is no simple formula for the random sample variance of sums. 

Appendix References 

Kish, L. 1965. Survey Sampling. Wiley, New York. 

Wolter, K.M. 1985. Introduction to Variance Estimation. Springer, New York. 

30 To the extent that a characteristic is strongly related to well operator size, the stratification may reduce the design 

effect for that characteristic. As described in US EPA (2015b), well operator size was defined by the number of well

identifiers included in the service company well list that were associated with a given well operator. 

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Hydraulic Fracturing Operations July 2016 

Glossary 

Annulus: The space between two concentric objects, such as between the wellbore and casing or

between casing and tubing, where fluid can flow. (ref 3) 

Borehole: The wellbore itself, including the open hole or uncased portion of the well. (ref 3) 

Casing pressure test: Defined in this report as any surface pressure applied and held to a portion 

or all of the casing string used for hydraulic fracturing (i.e., production casing or temporary frac 

string). 

Casing tally: Often provided by well operators, this is a detailed list of the sections of casing placed

into the well during its construction, including the precise length of each section. 

Cement evaluation log: Any of several kinds of logs run within cemented casing that can be 

interpreted to evaluate cement presence, apparent cement bond quality, or the effectiveness of 

cement forming an annular seal. Cement evaluation logs included standard acoustic cement bond 

logs, ultrasonic image tool logs, and temperature logs. 

Completion report: Often provided by well operators, this is a daily log of the activities performed 

at a well after it has been drilled but before it is brought online for oil/gas production. Information

about hydraulic fracturing is included in the completion report. 

Deviated well: Defined in this report as a non-horizontal well where the bottom-hole location is

more than 500 lateral feet from the surface location. 

Driller’s report: Often provided by well operators, this is a daily log of the activities at a well and 

includes details on the well’s drilling, casing, and cementing history from surface to total depth. 

Drinking water resource: Any body of water, ground or surface, that currently serves or in the

future could serve as a source of drinking water for public or private water supplies. (ref 5) 

Formation: A body of earth material with distinctive and characteristic properties and degree of

homogeneity in its physical properties. (ref 4) 

Frac hit: Occurs when hydraulic fracturing at a well affects an offset oil and gas production well. 

(ref 2) 

Ground water resource: Defined in this report as any geologic formation containing ground water. 

Horizontal well: Defined in this report as a well intentionally completed with one or more

boreholes drilled laterally to follow the targeted geologic formation. 

Hydraulic fracturing: A stimulation technique used to increase production of oil and gas from 

underground rock formations. Hydraulic fracturing involves the injection of fluids under pressures 

great enough to fracture the oil- and gas-containing formations. (ref 5) 

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Hydraulic Fracturing Operations July 2016 

Hydraulic fracturing job: Defined in this report as one or more stages in which the time between 

consecutive stages was less than or equal to 90 days. 

Initial fracture treatment: Defined in this report as the first reported hydraulic fracturing 

job that occurred at a well. 

Re-completion: Defined in this report as a hydraulic fracturing job in which an entirely 

new interval of the well was fractured, when compared to previous hydraulic fracturing

jobs. 

Re-fracture: Defined in this report as a hydraulic fracturing job in which any portion of the

fractured interval overlapped with a fractured interval from a previous job. 

Hydraulic fracturing stage: Defined in this report as a specific measured depth interval for which

hydraulic fracturing began on a specific date. 

Lateral component of fracture growth: When microseismic reports contain a plan-view of 

fracture growth during a hydraulic fracturing job, this is the greatest distance from the point of

fracture origination along the wellbore, as measured perpendicular to the wellbore trace. 

Maximum treating pressure: Defined in this report as the largest reported surface treating 

pressure per hydraulic fracturing job. 

Mechanical integrity: The ability of a well to contain fluids within the well and prevent fluid

movement along the outside of the well, between the outermost casing and the wellbore. (ref 1) 

Measured depth: The length of the wellbore, as if determined by a measuring stick. This 

measurement differs from the true vertical depth of the well in all but vertical wells. (ref 3) 

Microseismic report: A report describing results from microseismic monitoring. The report 

typically contains differently-oriented views (such as plan view and side views) showing the

microseismic events detected during hydraulic fracturing. These microseismic events are 

commonly assumed to be related to the growth of induced fractures. The report may show mapped

microseismic events at the stage level of the hydraulic fracturing job and may also state the

magnitude of lateral and vertical fracture growth. 

Open hole: The uncased portion of a well. All wells, at least when first drilled, have open hole

sections. While most completions are cased, some are open, especially in horizontal or extendedreach wells where it may not be possible to cement casing efficiently. (ref 3) 

Packer: A device that can be run into a wellbore with a smaller initial outside diameter that then 

expands externally to seal the wellbore. (ref 3) 

Perforation: The communication tunnel created from the casing or liner into the targeted geologic 

formation through which injected fluids and oil or gas flow. (ref 3) 

Point of deepest hydraulic fracturing: Defined in this report as the measured depth of the

deepest point at which hydraulic fracturing occurred. 

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Hydraulic Fracturing Operations July 2016 

Point of shallowest hydraulic fracturing: Defined in this report as the measured depth of the

shallowest point at which hydraulic fracturing occurred. 

Post-frac report: A report generated by the service company that conducts the hydraulic 

fracturing job on a production well. The report typically, but not always, contains a record of the 

stages of the hydraulic fracturing job, including timing and depth interval, the volume of additives 

and amount of proppant pumped during each stage, the injection rates and associated pump

pressures applied during each stage. The report may or may not contain information about

monitored wellhead pressure in an annular space behind the casing used for hydraulic fracturing. 

Protected ground water resource: This report does not use a single definition for protected

ground water resources and relies solely on information provided to the EPA by well operators. 

Spud: To start the well drilling process by removing rock, dirt, and other sedimentary material with

the drill bit. (ref 3) 

Surface treating pressure: The pressure during hydraulic fracturing that builds within the casing

used for hydraulic fracturing. The surface treating pressure is measured at or near, but not below,

the wellhead. 

Targeted geologic formation: Defined in this report as the geologic formation intended for 

hydrocarbon production. 

Temporary frac string: A temporary well component that is lowered into the well and secured at 

base of the well using a packer or by latching into existing well components located in the well.

Hydraulic fracturing takes place through the temporary frac string, which is removed when

hydraulic fracturing is complete. 

True vertical depth: The vertical distance from a point in the well (usually the current or final 

depth) to a point at the surface. (ref 3) 

Tubing: The narrowest steel pipe set within a completed well, either hung directly from the

wellhead or secured at its bottom using a packer. Tubing is not typically cemented in the well. 

Uncemented interval: Defined in this report as a segment of annular space along the outside of the

well (between the casing and the wellbore wall) that has no cement. 

Vertical component of fracture growth: When microseismic reports contain a side-view of 

fracture growth during a hydraulic fracturing job, this is the greatest vertically upward distance

from the point of fracture origination along the well. 

Vertical well: Defined in this report as a well with a bottom-hole location within 500 lateral feet of 

the surface location. 

Wellbore: The drilled hole or borehole, including the open hole or uncased portion of the well. 

(ref 3) 

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Hydraulic Fracturing Operations	 July 2016 

Wellbore diagram: A schematic diagram that identifies the main completion components installed 

in a wellbore. The information included in the wellbore diagram relates to the principal dimensions

of the components and the depth at which the components are located. (ref 3) 

Glossary References 

1.	 Ground Water Protection Council. 2014. State Oil and Natural Gas Regulations Designed to 

Protect Water Resources. Available at http://www.gwpc.org/sites/default/files/files/

Oil%20and%20Gas%20Regulation%20Report%20Hyperlinked%20Version%20Final-rfs.pdf. 

Accessed October 27, 2014. 

2.	 King, G.E. 2014. 60 Years of Multi-Fractured Vertical, Deviated and Horizontal Wells: What Have 

We Learned? SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, 

October 27-29, 2014. Society of Petroleum Engineers. 

3.	 Schlumberger. 2014. Oilfield Glossary. Available at http://www.glossary.oilfield.slb.com/. 

Accessed May 16, 2016. 

4.	 US Environmental Protection Agency (US EPA). 2006. Terminology Services: Terms and 

Acronyms. Available at http://iaspub.epa.gov/sor_internet/registry/termreg/home/ 

overview/home.do. Accessed December 1, 2014. 

5.	 US EPA. 2011. Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water 

Resources. Available at http://www2.epa.gov/sites/production/files/documents/

hf_study_plan_110211_final_508.pdf. Accessed December 1, 2014. 

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