July 2, 2014
Hydraulic Fracturing and Water Use in California
Hydraulic fracturing (sometimes referred to as fracking) is a
None of the available fracturing disclosures for California
technique that uses water, sand, and chemicals under
in 2012, 2013, or early 2014 revealed fracturing for gas
pressure to enable or enhance the production of natural gas
well stimulation. Data from the limited set of disclosures
and crude oil from formations with low permeability. In
(19) from gas wells fractured in 2011 in California (Sutter,
California, recent drought and estimates of recoverable
Colusa, and Glenn counties) indicate an average water use
energy resources have drawn attention to the current and
of 25,000 gallons.
future impacts of fracturing on the state’s water quantity
and quality. While available data and data gaps on water
Figure 1. Depth of Fractured Well and Water Use for
use in hydraulic fracturing are presented herein, analysis of
Fracturing in California in Early 2014
water quality topics is beyond the scope of this discussion.
Fracturing has gained attention nationally in association
with energy development from shale and related tight oil
formations, such as the Bakken (ND), Eagle Ford (TX), and
Marcellus (PA, WV, MD). These “unconventional”
formations are both sources and reservoirs for
hydrocarbons. In these formations, fracturing is combined
with horizontal drilling to enhance permeability to access
natural gas and crude oil trapped in the shale.
How Much Water Is Used in Fracturing in California?
In California, fracturing historically has been associated
with aging conventional petroleum fields in central and

southern California. Data from the California Department
of Conservation’s Division of Oil, Gas, and Geothermal
Source: Data from DOGGR well stimulation disclosures (accessed
Resources (DOGGR) for early 2014 indicate that fracturing
June 26, 2014, included data from January 2014 to May 6, 2014).
in California is used primarily in shorter vertical wells
Figure 2. Estimates of Water Use for Well Fracturing
(often with some directional drilling), rather than in
in California During 2012 and 2013 and in Early 2014
extended horizontal wells or wells accessing deeper
formations. These vertical wells intercept low-permeability
formations. More than 95% of recent fractured wells are
accessing California’s diatomite formations, which are
sedimentary rock formed mainly of the hard skeletons of
fossilized unicellular algae (diatoms). The wells in these
formations are at depths of 1,000 feet on average (see
Figure 1). And the fractured intervals are short—50 to 100
feet—compared to the long fractured intervals used to tap
shales being developed in other states.

To stimulate production from these diatomite formations,
Source: Data from FracFocus and DOGGR.
relatively fewer fracture stages are often used, in contrast to
the multistage fracturing along the comparatively long
laterals used to stimulate natural gas or oil production from
Voluntary disclosures of fracturing in California in 2013
shale formations such as the Marcellus, Bakken, and Eagle
(791 wells fractured using, on average, 123,000 gallons of
Ford. Also, fracturing in California rarely involves the use
water per well) indicate an annual freshwater use of around
of friction reducers. (When reducers are used, more water is
300 acre-feet (97 million gallons), with the majority of the
typically required.) Due to these differences, the water
use in Kern County. For regional context, this quantity
quantity used in fracturing a well in California (Figures 1
represents less than 0.01% of the average annual freshwater
and 2) is on average an order of magnitude lower than the
withdrawals in Kern County. For context within oil and gas
high-volume, multistage fractures of horizontal wells
operations, DOGGR injection well data for 2013 indicate
drilled in shales (e.g., a typical Marcellus Shale gas well
that 12,110 acre-feet (4 billion gallons) of freshwater
uses 3 to 8 million gallons of water). State data on water
sourced from water wells or domestic water supplies were
use associated with well drilling and other completion
used by the oil and gas industry for enhanced oil recovery
activities do not appear to be available in California.
through steam and water flooding. Based on these data,
fracturing freshwater use in 2013 may have represented less
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Hydraulic Fracturing and Water Use in California
than 3% of the freshwater use in the state for oil and gas
1 million gallons) represented 27% of the water use for
production enhancement techniques.
fracturing. More detailed analyses of these higher-volume
fractures are key to forecasting fracturing’s water supply
In contrast to fractured wells in the Marcellus, Bakken,
impact.
or Eagle Ford shales, the water quantity associated
with the typical fractured well in California is on
How Much Water Is Lost Due to Fracturing? DOGGR
average an order of magnitude lower than shale
data for early 2014 indicate that almost 3,000 gallons of the
fractured wells elsewhere.
average 64,000 gallons injected per well were brought back
to the surface; that is, an average recovery rate of 5%. Other
water also flows to the surface during the operating life of a
Under California’s 2013 well stimulation law, SB 4,
well. This recovered and formation water is broadly known
operators began reporting to the state the water used in
as produced water. In general in California, the ratio of the
fracturing and other stimulation techniques in January 2014.
volume of oil brought to the surface and the produced water
Fracturing in 2014 may be dampened as efforts are made to
is 1:9. DOGGR data for 2013 indicate that produced water
comply with new state rules, including public notification
from oil and gas operations in California totaled 410,000
and groundwater monitoring and testing requirements. In
acre-feet (133.5 billion gallons). Produced water can vary
the long term, the future water supply impact of fracturing
widely in its quality and in its constituents. Therefore,
will be shaped by the numbers and types of wells fractured
determining how much water is lost to a formation or lost
and the level of reliance of fracturing technologies and
due to degradation of water quality as a result of fracturing
practices on freshwater. Geology, regulations, and market
is difficult to calculate. This is especially the case for
conditions are among the factors influencing a producer’s
California, where significant quantities of produced water
decisions on when and where to invest. The discussion
are reused in oil and gas operations (e.g., reinjected to
below provides current information on how well
maintain pressure or to steam flood an oil field) or in some
development in some basins may influence the future water
cases treated and used in agriculture. Available California
use for fracturing in the state.
data do not appear to differentiate between reinjection for
oil and gas operational benefits and reinjection for disposal,
Is the Water Quantity Used for Fracturing Anticipated
as both types of injection use Class II wells permitted
to Increase Substantially? The development of
through the U.S. Environmental Protect Agency (EPA)
California’s shale resources, most notably the Monterey
underground injection control (UIC) program. In February
shale, as a reservoir appears to be constrained by multiple
2014, a California Department of Conservation witness
factors, such as increasing indications that a significant
testified that in California approximately 70%-75% of all
quantity of oil that was formed in the Monterey shale
produced water (flowback fluid and formation water) from
migrated out and into shallower formations (e.g.,
oil and gas wells is injected into hydrocarbon formations
diatomites) and that much of the Monterey shale formation
for enhanced oil recovery (water flooding). Around 20%%-
may not have experienced conditions favorable to oil
25% is injected into Class II wells for disposal, and roughly
generation. Therefore, although there have been attempts
5% is treated for reuse. Industry reports some reuse for
and experimentation with directly developing the Monterey
agricultural purposes where water quality requirements are
shale and other California shales, there are few indications
met. There has been interest in reusing produced water in
that they will produce much natural gas or crude oil in the
subsequent fracturing activities. DOGGR data indicate that
near future.
primarily freshwater continued to be used for fracturing in
early 2014; there also are some recent indications from
In some of southern California’s existing oil fields (e.g., the
DOGGR stimulation notices that produced water use in
Los Angeles basin), fracturing is not needed to stimulate oil
fracturing may be on the rise.
production; instead, water is injected to maintain reservoir
pressure. The gas fields in northern California generally
More information on water use for hydraulic fracturing in
have been in small, discrete conventional formations. While
California will be forthcoming as SB 4 is implemented. By
there is some debate about the utility and economics of
January 1, 2015, the state must have final well stimulation
fracturing to enhance production in these fields, data do not
rules in place and must complete a broad scientific study on
indicate extensive use to date.
well stimulation impacts. Water use and disposal reporting,
groundwater monitoring, environmental assessment, and
As a result, stimulation of the diatomites in Kern County
other requirements associated with the new law should
likely may continue to dominate well fracturing activities in
generate data supporting more quantitative analyses of the
the state. In these formations, new wells are most likely to
impact of oil and gas development using hydraulic
be vertical wells, in close proximity to each other and
fracturing on California’s water resources.
within existing oil fields. How many of these wells are
developed is key to forecasting future impact.
Nicole T. Carter, ncarter@crs.loc.gov, 7-0854
Mary Tiemann, mtiemann@crs.loc.gov, 7-5937
While more fracturing operations may occur in the
Peter Folger, pfolger@crs.loc.gov, 7-1517
diatomites than in other California formations, more
Anthony Andrews, aandrews@crs.loc.gov, 7-6843
information on the likelihood of higher-volume fractures is
needed. That is, not all fractured wells in California fall
IF00033
close to the average water use; for example, 8% of fractured
wells (i.e., the state’s 24 fractures that each used above
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