In previous posts about hydrocarbon gas ratio analysis and drill cuttings volatiles, I talked about
measuring natural gas directly from wells being drilled or from drill cuttings.
These are upstream examples of natural gas measurement. Typical mud logging
units often use flame ionization detection to detect and quantify total gas and
a hydrocarbon gas chromatograph to quantify the main gaseous components,
usually C1-C5. Sometimes, though quite rarely, chromatographs can be outfitted
to detect and quantify heavier hydrocarbons as well. Drill cuttings volatiles
analysis was pioneered by Mike Smith of Advanced Hydrocarbon Stratigraphy.
Smith invented and patented a cryo-mass spectrometer that formed a vacuum below
atmospheric pressure to release hydrocarbon gases from drill cuttings or cores
in sequence according to temperature and pressure. When I was involved in
getting wells drilled and analyzed, we often sent a gas sample to a lab for
more detailed gas analysis. This was very important in fields that had high
levels of different components. If ethane levels were too high, it made the gas
BTU too high for pipeline specs, and the ethane would have to be removed or
blended with lower BTU gas. We had a field area that was very high in nitrogen
and, as a result, suffered from low BTU values. There was a danger that the low
BTU gas would cause things like a pilot light to go out if demand was high in
winter and blending could not be ensured. We looked at building a nitrogen
treatment plant, but the high costs were prohibitive. I took all of the gas
analysis data from the lab and made contour maps of BTU and nitrogen content.
These worked pretty well to predict gas quality in subsequently drilled wells.
Pipelines have specifications
for gas quality, with gas of adequate purity expected to be delivered to the
point of use. In most gas streams closer to distribution, the “contaminants”
are H2S, H2O, O2, and CO2.
According to Alan Garza at
Endress +Hauser, in an article for Gas Processing and LNG:
“The presence of contaminants in distribution pipelines
can cause corrosion, equipment damage, environmental pollution and even rare
catastrophic events that harm human life. As a result, robust gas quality
processing, monitoring and maintenance are essential to ensure compliance with
regulatory standards, and to safeguard gas processing assets, infrastructure
and people.”
“While methods exist to measure and scrub these
impurities, the intermittent nature of certain gas streams—with fluctuating
compositions and contaminants like glycol, methanol, amines and other sulfurous
compounds—complicates reliable gas analysis. As a result, traditional
measurement methods often struggle to accurately identify complex permutations,
which compromises process control and safety.”
Gas processing plants
typically remove these components and others, as well as the heavier natural
gas liquids that can be transported toward the market as their own stream or in
various combinations.
The following section about
natural gas quality standards is from Wikipedia.
“Raw natural gas must be purified to meet the quality
standards specified by the major pipeline transmission and distribution
companies. Those quality standards vary from pipeline to pipeline and are
usually a function of a pipeline system's design and the markets that it
serves. In general, the standards specify that the natural gas:
“Be within a specific range of heating value (caloric
value). For example, in the United States, it should be about 1035 ± 5% BTU per
cubic foot of gas at 1 atmosphere and 60 °F (41 MJ ± 5% per cubic metre of gas
at 1 atmosphere and 15.6 °C). In the United Kingdom the gross calorific value
must be in the range 37.0 – 44.5 MJ/m3 for entry into the National Transmission
System (NTS).”
“Be delivered at or above a specified hydrocarbon dew
point temperature (below which some of the hydrocarbons in the gas might
condense at pipeline pressure forming liquid slugs that could damage the
pipeline.) Hydrocarbon dew-point adjustment reduces the concentration of heavy
hydrocarbons so no condensation occurs during the ensuing transport in the
pipelines. In the UK the hydrocarbon dew point is defined as <-2 °C for
entry into the NTS. The hydrocarbon dewpoint changes with the prevailing
ambient temperature, the seasonal variation is:
“The natural gas should:
“Be free of particulate solids and liquid water to
prevent erosion, corrosion or other damage to the pipeline.”
“Be dehydrated of water vapor sufficiently to prevent
the formation of methane hydrates within the gas processing plant or
subsequently within the sales gas transmission pipeline. A typical water
content specification in the U.S. is that gas must contain no more than seven
pounds of water per million standard cubic feet of gas. In the UK this is
defined as <-10 °C @ 85barg for entry into the NTS.”
“Contain no more than trace amounts of components such
as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common
specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet
of gas, or approximately 4 ppm. Specifications for CO2 typically limit the
content to no more than two or three percent. In the UK hydrogen sulfide is
specified ≤5 mg/m3 and total sulfur as ≤50 mg/m3, carbon dioxide as ≤2.0%
(molar), and nitrogen as ≤5.0% (molar) for entry into the NTS.”
“Maintain mercury at less than detectable limits
(approximately 0.001 ppb by volume) primarily to avoid damaging equipment in
the gas processing plant or the pipeline transmission system from mercury
amalgamation and embrittlement of aluminum and other metals.”
Below is a typical natural
gas treatment plant configuration to transform raw natural gas into
pipeline-quality natural gas.
Tunable Diode Laser Absorption Spectroscopy Emerges as a
Leading Technology
Garza goes on in his article
to talk about the limitations of traditional gas analysis, especially that of
using lead acetate tape to detect and quantify H2S, noting that it is “unsuitable
for continuous monitoring and precise measurement.” Another very common
method is UV absorption spectrometry utilizing deuterium lamps. It provides
better accuracy than lead acetate tape and can be used for continuous
monitoring, but has some drawbacks, like interference from sulfuric and
aromatic compounds that occur in natural gas. The deuterium light
source degrades over time, causing measurement issues. An alternative is to add
H2S chromatographic columns, but this often adds too much complexity, cost, and
time to analysis.
Another gas analysis method,
tunable diode laser absorption spectroscopy (TDLAS), is emerging as a reliable
technology to follow gas analysis along the value stream. This is important
because, as Garza noted, the processing methods can add new contaminants.
Therefore, one approach is to check gas quality at different points along the
processing stream. TDLAS is used to analyze gas in many industries. Their benefits and several advantages over other gas analysis methods are given below.
TDLAS analyzers are equipped
with automated validation features that verify they are well calibrated. They
generate calibration and performance evaluation and can generate documentation.
Garza notes that custody transfer points are good locations to measure
contaminant levels of H2S, H2O, CO2, and O2, as shown below, and that detailed
knowledge of pre-processing and post-processing gas quality at each point is
very useful for planning and determining effects on equipment.
Garza goes on to explain the
many uses of TDLAS in the petrochemicals processing industry and in ensuring
gas purity in our gas distribution grids.
“Refiners frequently rely on TDLAS measurement during
flare gas, H2 recycle gas in semi-regenerative catalytic reforming, propane and
propylene mixing, fluid catalytic cracking, and other processes to control
contaminant levels and optimize process efficiency. For example, effective H2S
removal is required in olefin production to prevent catalyst poisoning and
ensure product quality in different refinery applications.”
“Seamlessly ensure quality. In the past,
maintaining rigorous natural gas purity in the utility grid was an ongoing
challenge. However, today’s advanced methodologies—like TDLAS paired with
regimented validation procedures—provide highly accurate, repeatable and
reliable measurement of H2S and other contaminants. This, in turn, empowers
plant personnel to verify process effectiveness, safety, quality assurance and
regulatory compliance, while protecting upstream, midstream and downstream
assets from corrosion and other damage.”
“As the energy landscape continues to evolve, embracing
these advanced gas analytic and other innovative technologies is critical to
ensure safe, reliable and efficient processes, while minimizing emissions.”
Looking at Endress+Hauser’s
website, one can see that they have TDLAS gas analyzers targeted for specific
contaminants such as H2S, H2O, CO2, and trace gases. They note the advantages
of TDLAS over Al2O3 sensors and quartz crystal microbalances, which cannot
distinguish between H2O and methanol. TDLAS analyzers have a lower cost of
ownership than lead acetate tape analyzers and gas chromatographs.
There are three main processing steps for natural gas: 1) amine treatment to remove H2S and CO2 from sour gas, 2) molecular sieve dehydration of the resulting sweet gas, and 3) fractionation to separate and recover NGLs (ethane, propane, butane) from pipeline quality natural gas.
Amine treatment is necessary since about 40% of
natural gas is sour gas containing the so-called acid gases H2S and CO2 in
unacceptable quantities. Many amine treatment plants have a sulfur recovery
unit, which transforms H2S to elemental sulfur.
The post-amine treatment gas
stream is typically saturated with water vapor. Methods such as knockout drums,
compression, and cooling can remove some of the water. However, in order to
fractionate the gas into NGL components or for LNG liquefaction, the water
vapor concentration must be very low (< 0.1 ppm). This is accomplished with
a molecular sieve dehydration unit, shown below.
NGL fractionation recovers
NGLs, typically ethane, propane, butanes, and natural gasoline via cryogenic
fractionation columns. These are utilized for various petrochemical processes
and other end uses. They are abundant in U.S. shale gas, and the U.S. exports
them globally. Below is a fractionation unit configuration. TDLAS gas analysis units can be
used after each of these processes to verify the desired gas quality.
References:
Utilize
tunable diode laser absorption spectroscopy to ensure natural gas purity in the
grid. Alan Garza. Endress+Hauser. Gas Processing & LNG. June 30, 2025. Utilize
tunable diode laser absorption spectroscopy to ensure natural gas purity in the
grid | Gas Processing & LNG
Tunable
diode laser absorption spectroscopy (TDLAS). Endress+Hauser. Tunable
diode laser absorption spectroscopy (TDLAS) | Endress+Hauser
Natural-gas
processing. Wikipedia. Natural-gas
processing - Wikipedia
TDLAS
analyzers for natural gas processing: Accurate and reliable measurement of H2
O, H2S, and CO2. Endress+Haiser. February 2025. TDLAS
analyzers for natural gas processing
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