American Oil and Gas Reporter - August 2019 - 56

SpecialReport: Production Automation
gas comes off the top of the vessel and
liquids are heated via a submerged firetube. Hot exhaust gases from a burner that
uses some of the gas produced at the site
pass through the inside of the fire-tube.
The temperature set point for this heating
is chosen to break oil/water emulsions and
facilitate oil/water separation. Heating also
prevents wax or paraffin buildup.
A typical separator has pneumatically
actuated, snap-acting controls. For example, when the oil level reaches the
high set point, a valve dumps the fluid to
an atmospheric pressure oil storage tank.
Some oil flashes to vapor because of the
lower pressure downstream of the valve,
which is typically the largest generator
of vapor. Water is dumped from the water
box in a similar manner, but is rarely a
significant generator of vapors. Dump
valves automatically close when the low
liquid level is reached, resulting in discreet
oil slugs going to the storage tanks with
a commensurate production of flash gas.
When well production is at its highest
rate, the oil dump valve can open as frequently as every 15 seconds, generating
a significant amount of flash gas.
Some vapors also are generated in the
storage tank because of liquid level
changes. Withdrawing oil from the tank
lowers the level and some liquid evaporates
to fill the additional head space. When
more liquid is added to the tank, the
vapors are compressed by the rising liquid
level and the vapor goes to a control
device once the pressure in the tank

exceeds a set point (typically a fraction
of 1 psi described in ounces per square
inch). There are also breathing (or standing)
losses that occur when diurnal or other
temperature increases heat the vapors already in a tank's head space. These working
and breathing losses need to be controlled
at the site, but typically are secondary to
the vapors generated by flashing the oil
or condensate to atmospheric pressure.
Separators can have multiple stages
of pressure reduction, which reduces
vapor generation and slightly increases
oil production. It also creates additional
options to recover or treat vapors at an
intermediate pressure between the highpressure separator vessel that rides the
sales gas pipeline pressure and the atmospheric-pressure storage tanks. Reducing the amount of vapor generated
and recovering some of it instead of
flaring can result in higher revenue and
reduce the amount of vapor that needs to
be controlled, which is clearly a win-win
scenario. However, it is important to have
proper pressure and temperature settings
in each stage of the separator to realize
these benefits.
VRU Strategies Evolve
A VRU with sufficient capacity captures nominally all of the vapors and returns them to the sales gas line. Many
sites use a VRU to capture vapors available
at intermediate pressure and one or more
flares to treat atmospheric pressure vapors
coming off the storage tanks. Another

FIGURE 3
Two-Stage Production Separator
Main Fuel for Separator Burner,
Separator Pilot and Flare Pilot

Sales Gas

Feed Stream
From Well
HP (High Pressure) Two-Phase Separator

Low Pressure Vapor to
Storage Tank
LP (Low Pressure) Three-Phase Separator
Oil to Storage Tank

Main
Separator
Burner

Firetube

56 THE AMERICAN OIL & GAS REPORTER

Water

key advantage to this approach is that
the flares serve as backup control devices
when the VRU is out of service.
VRUs also can be used to treat vapors
from atmospheric-pressure oil storage
tanks, but a gas blanketing system, catalytic
oxidation unit, or other measures may be
needed to prevent air ingress into the
storage tanks from leading to issues with
sales gas exceeding oxygen pipeline specifications (typically on the order of 10
parts per million by volume).
Several strategies to dampen the peak
vapor generation rate have been used in
production operations, including slug
catchers upstream of the separators and
interstage pressure vessels (surge bottles
or buffer tanks). Some producers use another heater treater downstream of the
production separator for the intermediate
pressure vessel.
Changing the timing and/or duration
that wells are on line also may be an
option to reduce the peak generation rate
(such as staggering wells instead of having
multiple wells on line at the same time),
but many producers prefer to avoid changing
production operations in favor of adjusting
the downstream vapor control operations.
A related approach, the vapor recovery
tower (VRT) located between the separator
and the storage tank uses hydrostatic
head pressure to drain oil from the VRT
to the storage tank at very low pressure
(~ 3 psig), while vapors from the top of
the VRT go to a control device. The VRT
does not lower the peak vapor generation
rate to the extent that a surge bottle does,
but routing these vapors from the VRT to
a VRU instead of from the storage tank
to a VRU eliminates the potential for air
ingress that can be an issue for recovered
gas sent to the sales gas line. Also, the
vapor generation rate is reduced significantly in the oil storage tank because of
the much lower upstream pressure in the
VRT compared with the production separator or surge bottle.
Pressure relief valves are installed on
separator vessels and oil storage tanks. If
vapors are generated at an instantaneous
rate that exceeds the capacity of the
control device(s), they are vented to the
atmosphere to prevent excessive pressure
in the vessels or tanks. In some locations,
regulations only allow tank venting in
emergency situations. Preventing this is
a major objective of vapor control systems
at these sites.
Managing condensation and solid formation is a common issue. The produced
gas is typically rich in hydrocarbon content

American Oil and Gas Reporter - August 2019

Table of Contents for the Digital Edition of American Oil and Gas Reporter - August 2019