Hydrogen Sulfide (H2S) is a colorless gas that causes tremendous issues in three categories: human safety, regulatory compliance, and infrastructure integrity (corrosion). If you’ve ever smelled that rotten egg odor around wastewater treatment plants or oil & gas refineries, you’ve experienced H2S. At a molecular level, an H2S molecule is 2 Hydrogen atoms and 1 Sulfur atom. Sometimes called “sour gas” due to its sulfur smell, it is most often measured in Parts per Million (PPM). One (1) Part per Million is equal to 1 mg/l (milligram per liter). For those of us that are not fluent in metric units of measurement, 1 mg/l is equivalent to .001335 ounces (oz) per 1 gallon. To get a better visual, this is 3 tablespoons to a regular sized swimming pool.
Doesn’t seem like a very large amount, right? It’s an invisible gas, that would eventually be burned or dissipated into the air. The problem is that treating H2S out of Natural Gas often has secondary impacts. The most common means of treating H2S is to utilize a chemical scavenger (Triazene) to turn the sulfur into liquid chemical waste. Another chemical (Amine) can also be used to strip H2S out of Natural Gas, concentrate it, and most commonly incinerate it in a flare. The scavenger creates a hazardous, toxic waste byproduct that has high disposal costs. The stripping and flaring of the H2S creates SO2, the basic ingredient of Acid Rain.
Looking at the oil & gas industry in Texas, there are more than 77,000 active producing wells. About 30% of these wells produce some level of H2S along with their production, and the average H2S concentration in oil & gas wells in Texas is 9,249 ppm. This average is weighted heavily but a subset of very sour gas wells. Oil & gas production companies have two basic options: 1) sell their gas with H2S in it for a discount and let the midstream company (pipeline company) take care of it, or 2) treat it out of the gas and sell it “sweet” (oilfield vernacular – opposite of sour). Because of the dangers and integrity issues associated with H2S, midstream companies limit Natural Gas in pipelines to below 4 ppm, which is a tight specification for gas treating.
What’s the big deal? It’s a colorless gas that is measured in parts per million. Let’s look at math. The general equation for quantifying the sulfur is as follows:
Gas Production (MMSCFD) x H2S Concentration (PPM) x .083 = Pounds of Sulfur
If we apply the average daily production of natural gas in Texas x the average concentration of H2S (9,249), we get 2,738,260 lbs per day of sulfur produced in Texas from natural gas production alone. This equates to more than 340,000 Tons of sulfur/year from natural gas production in Texas. If all of this was emitted into the atmosphere, we would have a serious problem.
Fortunately, the majority of H2S that is removed from natural gas is converted to elemental sulfur through a Sulfur Recovery Unit (SRU) and sold for many commercial uses including fertilizer, making rubber tires or as a base compound for sulfuric acid production. However, this leaves a tremendous amount of H2S that is simply flared, converted to SO2 and emitted into our atmosphere. With the average Texas well only producing 36 lbs of sulfur per day, moving the treating upstream to the well-head creates tremendous value financially and environmentally.
This is where Streamline can help…
Streamline has developed the Next Generation of liquid REDOX (Reduction-Oxidation) H2S removal technology. REDOX technology (the process of chemically converting H2S into Elemental Sulfur) has been around since the 1930’s, but Streamline has pioneered a step-function improvement to the technology by reducing the footprint, capital cost, and operating cost. Streamline provides the opportunity for operators to move H2S treating upstream to the production facility and eliminate the need for Operators to convert the H2S to a toxic liquid waste or flare it creating SO2.
If you are interested in learning more about how Streamline is revolutionizing the H2S treating business, shoot us an email at email@example.com.