Hydrocarbon Processing | JANUARY 2015�51
Special Report LNG, NGL and Alternative FeedstocksS. HAMMOND, Barben Analytical, Reno, Nevada
Optimize amine sweetening with an optical O2 analyzer
After extraction, raw natural gas must go through processing before it is suitable for industrial, commercial and residential usage. The first stage of gas processing is known as “sweeten-ing,” where hydrogen sulfide (H2S) and carbon dioxide (CO2) are removed through exposure to amines (FIG. 1).
Here, the negative effects of entrained oxygen (O2) on the amine sweetening process are examined, and the use of an opti-cal O2 analyzer as a measurement solution is explored.
Gas contaminants. Purified, or “pipeline-quality,” natural gas typically consists of 95% methane (CH4). However, raw gas from the wellhead is actually a mixture of many components:
• Methane (CH4): 70%–90%• Ethane (C2H6): 5%–15%• Propane and butane: < 5%• CO2, nitrogen (N2), H2S, O2 and helium (He): balance.As a contaminant, H2S has multiple negative attributes. It is
a well-known toxin and is lethal at high levels. If condensation is present in the pipeline, water will absorb H2S to form sulfuric acid (H2SO4), resulting in pipeline corrosion. When H2S levels exceed 4 ppm/100 cf, the natural gas is considered “sour gas” and must be treated to meet US EPA standards per 40CFR72.2.
CO2, while not quite as undesirable as H2S, also can cause similar acidic conditions in pipelines through the formation of carbonic acid (H2CO3). Excess CO2 also creates problems in the cryogenic processing of LNG, since it has a melting point above that of CH4. Pipeline companies strive to achieve less than 2 vol% of CO2 in natural gas, while LNG facilities will further remove CO2 to less than 50 ppm.
What role does O2 play? Amine sweetening is a frequently used method for removing H2S and CO2 from natural gas. Most amines have some selectiv-ity toward one of the contaminant gases; therefore, a blend is typically used to knock out both H2S and CO2. Methyl-diethanolamine (MDEA) is the primary amine for absorption of H2S, while di-ethanolamine (DEA) and monoethanol-amine (MEA) remove CO2.
Oxidation is the enemy of amines. The presence of O2 causes amines to degrade into heat-stable amine salts (HSAS) such as acetate, oxalate, glyco-
late, bicine and formate. The formation of these salts creates multiple problems. The acid-removal capabilities of an amine solution decrease due to the conversion to salts. Chemical us-age must increase to reduce the risk of contaminants passing through to the dehydrator.
A second problem is the corrosive nature of the newly formed HSAS. Since moisture is present, the salts can dis-solve in condensation. The result is acidic corrosion, which will damage the absorber and related piping in much the same way that H2S and CO2 would damage them. If these salts pre-cipitate in downstream piping, they can create harmful buildup in pumps and valves, while reducing the efficiency of heat ex-changers. Furthermore, HSAS promote excess foaming in ab-sorber towers, thereby reducing the contact area of the amines and inhibiting gas flow.
Causes of O2 in gas. Trace-level O2 may be found in the wet natural gas coming directly from the wellhead. More common-ly, however, O2 gets into the piping through leaks in the system at common intrusion points:
• Separation/water knockout: stuck separator dump valves• Vapor recovery unit: poorly sealed or open tank hatch
(thief hatch), or leaking relief valves• Compressors: leaking seals, worn piston packing• Piping: flanges, threaded connections and valves.The gas processing plant is at the mercy of the gathering
wells and midstream suppliers, making the sour gas pipeline the final measurement point for catching O2 contamination.
Sweet gas O2measurement
Sour gas O2measurement
Amineabsorber
Cooler
Acid gasstripper
Leanamine
storage
Rich aminesolution
Heatexchanger
Steam
CondensateReboiler
Sour gas from wellhead
Sweet gas to dehydrator
Acid gas to flare or SRUCondenser
FIG. 1. In gas sweetening, H2S and CO2 are removed through exposure to amines.
52�JANUARY 2015 | HydrocarbonProcessing.com
LNG, NGL and Alternative Feedstocks
O2 measurement challenges. Electrochemical cells are the traditional method for O2 measurement. These sensors func-tion in a similar manner as a battery using a cathode and a lead (Pb) anode in an electrolyte solution. An O2-permeable mem-brane allows O2 molecules to enter the cell, where they react with the electrolyte, creating a voltage response to the chang-ing O2 level (FIG. 2).
This design is not without downsides. H2S and CO2, the two culprits of gas processing, also create considerable prob-lems with the electrochemical O2 sensors. Both contaminant gases continuously penetrate the sensor membrane and react with the electrolyte, causing poisoning of the O2 sensor. When
this occurs, frequent recalibration is required to correct for the zero drift caused by the poisoning of the sensor. Eventually, sensor response becomes erratic, and replacement is required.
To function properly in these applications, an electrochemi-cal sensor may require an upstream H2S scrubber that also re-quires significant investment in maintenance time and spare parts to keep the sensor functional.
A better approach to O2 measurement. An optical O2 analyzer that uses fluorescence quenching technology takes advantage of a different sensing technology to deal with the challenges of O2 measurement in natural gas. Fluorescence quenching technology provides trace ppm O2 measurement with no risk of damage to the sensor in the application.
An O2-sensitive luminophore sensor provides the mea-surement technology. A blue light source is used to excite the luminophore sensor located in the process gas. Once excited, the luminophore emits light back at a specific wavelength and intensity (FIG. 3). When O2 is present, the emitted light is quenched, causing a phase shift in the time domain and re-duced light intensity. The change in the luminophore output can be directly correlated to the partial-pressure O2 levels in both the gas and liquid phases.
+ –
O2-permeable membrane
Electrolyte
CathodeAnode
FIG. 2. An O2-permeable membrane allows O2 molecules to enter the cell, where they react with the electrolyte, creating a voltage response to the changing O2 level.
O2
Excitation spectrumEmission spectrum
Luminophore dye at tip of fiber optic
FIG. 3. An O2-sensitive luminophore sensor provides measurement.
FIG. 4. A pre-engineered sample calibration panel can be provided with connections for calibration gases, along with flow and pressure instruments.
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Hydrocarbon Processing | JANUARY 2015�53
LNG, NGL and Alternative Feedstocks
Advantages of the optical sensor design include no interfer-ence due to moisture, H2S, CO2 and other contaminant gases. The O2 measurement is independent of flowrate. The lumino-phore can withstand condensation and mild particulate build-up. The response time is extremely quick (T90 < 6 sec), as is calibration time (3–5 min).
Due to these advantages, an optical O2 analyzer simplifies the sample system design. Contaminant gases do not need to be scrubbed prior to the measurement. The end result is in-creased reliability, better accuracy and faster response in sour gas processing applications.
O2 sensor installation. There are several options for the in-stallation of an optical O2 analyzer. A basic system includes the analyzer and an optical sensor. The analyzer typically provides for a local human-machine interface and has agency approvals for non-incendive installations (i.e., explosive, Class 1, Divi-sion 2 installations in the US), and the optical sensor will have several measurement range options depending on the amount of O2 in the natural gas.
The sensor will consist of an armored fiber-optic cable con-nected to a probe with the luminophore sensing element on the tip. The sensor is available with mating flow cell in 316 stainless steel, Titanium Gr. 2, and Hastelloy C-276 for full material compatibility. Temperature compensation of the O2 measurement is provided by an external PT1000 RTD refer-ence temperature detector for quick response.
A pre-engineered sample calibration panel, or SCP (FIG. 4), can be provided with connections for calibration gases as well as flowmeters, pressure regulators and a fast loop for quick re-sponse. The O2 sensor and temperature sensor are pre-wired to the analyzer, which is mounted directly to the panel. An SCP panel can save considerable engineering and design work, es-pecially in new installations.
Takeaway. Entrained O2 in sour gas can create a wide variety of problems for the amine sweetening process. Optical O2 sensing technology, using fluorescence quenching, can provide many ad-vantages over traditional electrochemical sensors:
• Increased reliability• Reduced maintenance• Quicker calibration times• Fewer spare parts• Simplified sample systems.Reliable O2 measurement allows workers at the gas processing
plant to determine leak sources and increase uptime for the plant, while providing better pipeline-quality sales gas for customers.
STEVEN HAMMOND is the product manager for Barben Analytical, a unit of AMETEK Process and Analytical Instruments. His prior experience includes 20-plus years of product development and sales/marketing of analytical sensors and instrumentation for gas and liquid measurement. Mr. Hammond holds an engineering degree from Michigan State University in East Lansing, Michigan and an MBA degree from DePaul
University in Chicago, Illinois.
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