31
soaked rags hung on the end of the pipe to ignite or “flare” any gas. Flaring is only
allowed for short time periods under revisions to the U.S. Clean Air Act, and by
many state regulators.
Flowback typically consists of the frack fluids pumped downhole to break the
rock, plus some percentage of water from the formation. It starts out relatively fresh
with just frack fluids, but becomes increasingly salty over time (Hayes 2009). The
origin of the high total dissolved solids (TDS) content of these waters, which can be
six to ten times saltier than seawater is not well understood. Shale was deposited on
the seafloor, and thus it does contain connate saltwater in the pores, but this water
phase is almost never mobile (Soeder 1988). USGS studies indicate that the TDS in
the produced water was already in solution downhole, and did not come from solid
mineral crystals in the shale being dissolved out by the frack fluid (Engle et al.
2011). Current thinking is that the produced brines in shale wells are a remnant
mobile water phase from the introduced frack fluid that has grown salty by reaching
osmotic equilibrium with very saline connate water in the shale pores. This would
explain the increase in salinity over time, and the marginal mobility of the liquid.
Brines produced from oil and gas wells must be properly disposed of using Class II
Underground Injection Control (UIC) wells.
People originally labeled the returned fresh water used in the frack as “flowback,” and called the saltier water from the formation “produced water.” However,
flowback has acquired a regulatory meaning with a number of state agencies, and
some authors now use produced water as a more generic term for all non- hydrocarbon
liquids that come out of the well. Oilfield brine is also sometimes used as a descriptor. It is important to be aware of these conventions when reading the literature.
Some operators filter out suspended solids and recycle the recovered water into
another frack to reduce the waste volume and minimize the costs of disposal. This
requires a degree of logistics to be effective, and is only economical on certain shale
plays like the Marcellus where active development can readily use the water. On
other plays like the Bakken, the water is used only once before disposal. The water
slated for disposal is classified as “residual waste,” a term used for waste produced
by industrial processes, to distinguish it from municipal waste. The most common
method for disposal of residual waste is by injection down UIC wells (Maloney and
Yoxtheimer 2012). However, everything has consequences. Disposing of wastewater down UIC wells can pressurize existing deep faults, causing them to “unlock”
and create earthquakes.
It is important to note that residual waste is not the same as hazardous waste.
Hazardous wastes are regulated under Subtitle C of the U.S. Resource Conservation
and Recovery Act (RCRA), while residual wastes are managed by state authorities
under approved waste plans. Oil and gas exploration and production wastes are
considered natural materials that are exempted from the definition of hazardous
waste. The U.S. Environmental Protection Agency (EPA) has published guidance
encouraging operators to manage these wastes appropriately (USEPA 2020).
Almost all O&G wells produce some water or brine along with the hydrocarbons. A common humorous saying in the industry is they operate water wells
2.3 Hydraulic Fracturing Step by Step
soaked rags hung on the end of the pipe to ignite or “flare” any gas. Flaring is only
allowed for short time periods under revisions to the U.S. Clean Air Act, and by
many state regulators.
Flowback typically consists of the frack fluids pumped downhole to break the
rock, plus some percentage of water from the formation. It starts out relatively fresh
with just frack fluids, but becomes increasingly salty over time (Hayes 2009). The
origin of the high total dissolved solids (TDS) content of these waters, which can be
six to ten times saltier than seawater is not well understood. Shale was deposited on
the seafloor, and thus it does contain connate saltwater in the pores, but this water
phase is almost never mobile (Soeder 1988). USGS studies indicate that the TDS in
the produced water was already in solution downhole, and did not come from solid
mineral crystals in the shale being dissolved out by the frack fluid (Engle et al.
2011). Current thinking is that the produced brines in shale wells are a remnant
mobile water phase from the introduced frack fluid that has grown salty by reaching
osmotic equilibrium with very saline connate water in the shale pores. This would
explain the increase in salinity over time, and the marginal mobility of the liquid.
Brines produced from oil and gas wells must be properly disposed of using Class II
Underground Injection Control (UIC) wells.
People originally labeled the returned fresh water used in the frack as “flowback,” and called the saltier water from the formation “produced water.” However,
flowback has acquired a regulatory meaning with a number of state agencies, and
some authors now use produced water as a more generic term for all non- hydrocarbon
liquids that come out of the well. Oilfield brine is also sometimes used as a descriptor. It is important to be aware of these conventions when reading the literature.
Some operators filter out suspended solids and recycle the recovered water into
another frack to reduce the waste volume and minimize the costs of disposal. This
requires a degree of logistics to be effective, and is only economical on certain shale
plays like the Marcellus where active development can readily use the water. On
other plays like the Bakken, the water is used only once before disposal. The water
slated for disposal is classified as “residual waste,” a term used for waste produced
by industrial processes, to distinguish it from municipal waste. The most common
method for disposal of residual waste is by injection down UIC wells (Maloney and
Yoxtheimer 2012). However, everything has consequences. Disposing of wastewater down UIC wells can pressurize existing deep faults, causing them to “unlock”
and create earthquakes.
It is important to note that residual waste is not the same as hazardous waste.
Hazardous wastes are regulated under Subtitle C of the U.S. Resource Conservation
and Recovery Act (RCRA), while residual wastes are managed by state authorities
under approved waste plans. Oil and gas exploration and production wastes are
considered natural materials that are exempted from the definition of hazardous
waste. The U.S. Environmental Protection Agency (EPA) has published guidance
encouraging operators to manage these wastes appropriately (USEPA 2020).
Almost all O&G wells produce some water or brine along with the hydrocarbons. A common humorous saying in the industry is they operate water wells
2.3 Hydraulic Fracturing Step by Step