Midstream facilities
Raw natural gas from the well consists of methane as well as many other
smaller fractions of heavier hydrocarbons, and various other components.
The gas has to be separated into marketable fractions and treated to trade
specifications and to protect equipment from contaminants.
5.1 Gathering
Many upstream facilities include the gathering system in the processing
plant. However, for distributed gas production systems with many (often
small) producers, there is little processing at each location and gas
production from thousands of wells over an area instead feed into a
distributed gathering system. This system in general is composed of:
• Flowlines: A line connecting the wellpad with a field gathering station
(FGS), in general equipped with a fixed or mobile type pig launcher.
• FGS is a system allowing gathering of several flowlines and permits
transmission of the combined stream to the central processing facility
(CPF) and measures the oil/water/gas ratio. Each FGS is composed of:
o Pig receiver (fixed/mobile)
o Production header where all flowlines are connected
o Test header where a single flow line is routed for analysis
purposes (GOR Gas to oil ratio, water cut)
o Test system (mainly test separator or multiphase flow meter)
o Pig trap launcher
• Trunk line – pipeline connecting the FGS with the CPF. Equipped with a
pig receiver at the end.
5.2 Gas plants
5.2.1 Gas composition
When gas is exported, many gas trains include additional equipment for
further gas processing to remove unwanted components such as hydrogen
sulfide and carbon dioxide. These gases are called acids and
sweetening/acid removal is the process of removing them.
Natural gas sweetening methods include absorption processes, cryogenic
processes, adsorption processes (PSA, TSA and iron sponge) and
membranes. Often hybrid combinations are used, such as cryogenic and
membranes.
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Gas treatment may also include calibration. If the delivery specification is for
a specific calorific value (BTU per scf or MJ per scm), gas with higher values
can be adjusted by adding an inert gas, such as nitrogen. This is often done
at a common point such as a pipeline gathering system or a pipeline onshore
terminal.
Raw natural gas from the well consists of methane as well, as many other
smaller fractions of heavier hydrocarbons and various other components.
Component Chemical
Formula
Boiling Point
at 101 kPa
Vapor pressure
at 20 °C approx.
Methane CH4 -161,6 °C Tcri t−82.6 °C
@ 4,6 MPa
Ethane C2H6 -88.6 °C 4200 kPa
Propane C3H8 -42.1 °C 890 kPa
Butane n-C4H10 −0.5 °C 210 kPa
Higher order HC
Alkenes
Aromatics
CnH2n
e.g. C6H6
Acid gases
Carbon dioxide
Hydrogen sulfide
Mercaptans ex.
Methanethiol
Ethanethiol
CO2
H2S
CH3SH
C2H5SH
−78 °C
-60.2 °C
5.95 °C
35 °C
5500 kPa
Other Gases
Nitrogen
Helium
N2
He
-195.79 °C
-268.93 °
C
Water H2O 0 °C
Trace pollutants
Mercury
Chlorides
Data source: Wikipedia, Air Liquide Gas Encyclopedia
Natural gas is characterized in several ways dependent on the content of
these components:
o Wet gas is raw gas with a methane content of less than 85%.
o Dry gas is raw or treated natural gas that contains less than 15 liters
of condensate per 1,000 SM3
. (0.1 gallon per 1000 scf).
o Sour gas is raw gas with a content of more than 5.7 mg hydrogen
sulfide (H2S) per scm (0.25 grains per 100 scf); this is about 4 ppm.
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o Acid gas has a high content of acidic gases such as carbon dioxide
(CO2) or H2St. Pipeline natural gas specification is typically less than
2% CO2. Acid gas fields with up to 90% CO2 exist, but the normal
range for sour raw gas is 20-40%.
o Condensates are a mixture of hydrocarbons and other components
in the above table. These are normally gaseous from the well but
condense out as liquid during the production process (see previous
chapter). This is a refinery and petrochemical feedstock.
