Separation
of liquids. This is usually carried out
in horizontal or vertical separators that often contain baffles to promote the
coalescence of the liquid droplets that are carried in the gas stream. These liquids are referred to as condensate
and are usually stored at the well site for later removal by truck.
1. Separation Principles
·
Separation of well stream
liquids is by far the most common of all field processing operations and at the
same time, one of the most critical.
·
Well effluent is a
complex mixture of liquid and gaseous hydrocarbons, with water and other
impurities often present.
·
It is necessary to
separate hydrocarbon liquids and water from the hydrocarbon gas.
·
The separation of natural
gas, liquid hydrocarbons, and impurities is accomplished by various field
processing methods which include:
i)
gravity
ii)
heat
iii)
mechanical
iv)
electrical
v)
chemical
2. Separation Processes
A
combination
of these methods is used to separate hydrocarbon gas, liquid and water phases.
1)
Gravity
-
simplest and most common
method in use today.
-
dependant upon the
principle that the liquid components have a greater density than the gas
components.
-
water present is usually heavier than the
hydrocarbon liquid and therefore settles due to gravity.
2)
Impingement
-
relies upon the
difference in momentum between a gas particle and a liquid droplet.
-
takes place when
liquid-laden gas approaches an obstacle and liquid droplets impinge upon the
barrier and increase in size.
-
the effects of gravity
become significant and the drop falls to the liquid section of the vessel.
3)
Centrifugal
-
occurs when the stream to
be separated rotates at high velocities inside a vessel.
-
centrifugal force moves
the liquid to the wall of the vessel where it coalesces and drains to the
liquid section by gravity.
-
Allows a smaller vessel
to be used than other types.
There are two main classes
of separation: Two Phase and
Three Phase
Two Phase
Separation
-
one combined raw product
separated into two distinct products; hydrocarbon gas and hydrocarbon liquids.
-
has an application mainly
in fields with little or no produced water.
Three Phase
Separation
-
Splits the raw well
effluent into three distinct phases or products; hydrocarbon gas, hydrocarbon
liquid and water
-
Used where free water is
produced with the oil or gas stream.
-
Inlet separators at the
gas plant are usually three phase type.
-
Water may be withdrawn by
manual dump or by automatic level control.
3. Staged Separation of Oil and Gas
-
Pressure is reduced a
little at a time, resulting in a more stable stock tank liquid.
-
A large pressure drop can
cause a reduction in stock tank liquids.
-
The objective is not to
lose valuable LPG’s. C3, C4
and C5 to the hydrocarbon gas phase.
Discussion
1.
Give an example of
3-phase separation.
2.
Where might a 2-phase
separator be used?
3. Theoretically, what would be the best way to separate hydrocarbon liquid
from hydrocarbon gas?
4. Separators
Separation is defined as
the division of the phases present in a hydrocarbon stream to:
a)
obtain more pure liquid
and gas products
b)
allow testing or metering
of the individual phases
c)
ensure that downstream
equipment or processes are protected from exposure to components of the
hydrocarbon stream. For example, condensed hydrocarbon liquids should be
removed from compressor suction lines
d)
isolate the downstream
equipment and processes from the field
A properly designed
separator will provide a clean separation of free gas from the free hydrocarbon
liquids. A separator must perform the
following.
a.
Cause a primary phase
separation of the mostly liquid hydrocarbons from those that are mostly gas.
b.
Refine the separation
process by removing most of the entrained
liquids from the gas.
c.
Further refine the
separation by removing the dissolved
gases from the liquids.
d.
Discharge gas and liquids
into clean production streams.
4.1 Types of Separators
The terms “flash drum”, “Free water knockout (FWKO)”, “accumulator”,
“scrubber”, “traps”, “slug catcher” and “inlet separator” are all terms for
separators used for specific applications.
The selection of the type of separator is dependent on several factors
including:
-
Gas to oil ratio
-
Emulsion tendency of the
HC gas, HC liquid and water
-
Possibility of large
liquid “slugs”
-
Available room, both equipment footprint and
height restrictions.
4.2. Vertical Separators
-
common type of separator
in the oil industry.
-
used when there is either
a very high GOR (scrubbers) or a very low GOR.
-
the inlet stream enters
near the midpoint of the vessel.
-
can provide either two
phase separation or three phase separation.
4.3. Horizontal Separators
-
most common application
is in streams with relatively high gas/oil ratios.
-
gas/liquid interface area
is large which results in a quicker gas breakout
-
the double barrel type
consists of an upper separation section and a lower liquid retention and level
control chamber.
-
Tend to require a large
“footprint” so space can be a limitation (offshore for example.)
4.4. Spherical Separators
-
Commonly used for
separation of small amounts of liquid from large volumes of gas.
-
The advantage of a
spherical separator is that it is more compact for a given gas flow than other
separators.
-
Almost never specified
any longer because of difficulties ($$$) in fabrication with no significant
advantage other than size efficiency and pressure containment.
4..5. Slug Catchers (or Inlet Separators)
-
horizontal separators
located at the inlet of a gas processing facility.
-
removes entrained liquid either not
removed at the well site or formed by dropping temperature in the gathering
system.
-
protects the operation of
downstream equipment from liquid slugs originating in the pipeline system
resulting from changes in pipeline flow rate.
-
isolates the plant from
transient conditions in the field.
4.6. Sections of a Separator
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