Natural gas can frequently contain a large number of different types of impurities. Sour gas is a type of natural gas that contains large amounts of hydrogen sulfide. Also known as H2S, hydrogen sulfide is dissolvable in water, which can lead to a number of problems. Such problems can include the formation of a type of acid that can be corrosive to meters, valves, pipes, and other equipment.
Typically, gas is considered to be sour if it contains more than 5.7 milligrams of hydrogen sulfide per cubic meter of natural gas. This is equivalent to about 4 ppm by volume. When natural gas does not contain any significant amount of H2S, it is known as sweet gas.
Therefore, H2S removal techniques are known as sweetening methods. Amine treatment processes are commonly used for such purposes. Once H2S is removed, it is typically converted to a by-product in a Claus process. In some instances, it may also be treated in a WSA Process unit in order to produce a sulfuric acid by-product. While sour gas can be problematic, proper sweetening processes can eliminate this impurity and make it easier and more profitable to bring natural gas to market.
In recent years, there has been a significant increase regarding the discussion and potential for Liquefied natural gas or LNG. This pure form of natural gas is not toxic or carcinogenic. In order to make the most of the potential for natural gas to be liquefied; however, it is imperative that all impurities be removed from it. Among the top impurities contained in natural gas are carbon dioxide, sulfur, and mercury. All three of these impurities can be highly corrosive and damaging to LNG equipment and require experienced removal techniques.
Water is also commonly present in natural gas. While water, on its own, is not necessarily damaging, the potential for it to freeze and result in equipment blockage is a very real concern. Additionally, natural gas also frequently contains levels of heavier hydrocarbons that have the potential for freezing in the same manner as water. H2S and carbon dioxide removal allows LNG, when re-gasified once it has reached its final terminal, a very reliable as well as clean natural gas source that can provide power, heating, and cooling.
Each treatment situation is entirely different and unique, requiring the implementation of a gas treatment plan that is tailored to suit the individual characteristics of a specific site. We take great care to work one-on-one with clients to design a gas treating process that will meet that client’s specific needs. Oftentimes, the first step in that process is to determine the type of acid contaminants that are present in the gas stream. After determining whether you have a need for H2S removal, carbon dioxide removal, or oxygen removal from gas, we then take a look at the concentrations of each contaminant as well as the degree of removal needed for those contaminants.
We also ascertain the gas volume, pressure, and temperature as part of the gas treatment plan design process. At Blue Sky Midstream, we are also highly committed to effectively treating gas in a way that is not only cost-efficient, but also in a way that will have the least impact possible on the environment. As part of that responsibility, we carefully consider the environmental conditions required at your plant site. Although each site may require a completely different treatment process, a custom designed treatment plan can result in gas streams that are both marketable and profitable.
During the last ten years, the world has witnessed an exponential growth in the supply of natural gas from Shales. Today, shale gas accounts for approximately one-third of the total production in the United States. It is anticipated that within 20 years, the supply of Shale gas will account for more than 50 percent of domestic production. There is no doubt that shale presents a valuable source for natural gas liquids and natural gas. While the potential of Shales is undeniable, some fields result in the production of gas contaminated with hydrogen sulfide and carbon dioxide.
Such contamination levels require unique treating strategies. H2S and CO2 levels can vary significantly from one play to another. In some instances, those levels can vary among different wells located within the same play. Furthermore, while the focus of some plays may be on recovering a specific type of hydrocarbon, such as NGL, residual hydrocarbons can still present a significant energy source. When this is the case, effective carbon dioxide removal and H2S removal strategies are necessary to treat shale gas in order to achieve pipeline specifications. The latest techniques make it possible to recover marketable hydrocarbons to the greatest degree.
It is not uncommon for many natural gas fields to contain higher levels of CO2 than H2S. With H2S and carbon dioxide removal, the final acid gas stream may still contain low concentrations of H2S. This can make the stream unsuitable for sulfur recovery through the traditional Claus process. The goal of Acid Gas Enrichment (AGE) is to minimize H2S leak while maximizing CO2 slip. Through this process, it is now more economically feasible to produce natural gas reserves.
The most common method for acid gas enrichment is to utilize a separate absorber in order to treat low-grade acid gas streams. The design and operation of an acid gas enrichment plant relies on a number of parameters, such as lean solvent temperature, the ratio of feed gas H2S to CO2, and solvent selection. An AGE unit is responsible for enriching the H2S content of acid gas streams. This type of technology can also be utilized for minimizing the volume of acid gas for re-injection purposes. It can also be successfully used when it is necessary to address bottleneck situations in existing facilities during the development of newer, sourer fields.