Natural gas is one of the world’s major supply of energy. It exists underground as a combustible mixture of hydrocarbons gases. Its main constituent is methane and also includes ethane, propane and other heavier hydrocarbons; and other gases such as nitrogen, helium, carbon dioxide, hydrogen sulphide and water vapour. The composition of natural gas can vary widely depending where it is found.
Natural gas itself is colourless, odorless and shapeless. Despite such an uninteresting appearance, it gives off a huge amount of energy when it is burned. It is a fuel for domestic; commercial as well as industrial.
The natural gas that comes through the pipelines to our homes is not exactly quite the same as those brought from underground. This is because the natural gas transported through pipelines must meet gas specifications to be allowed in. In Great Britain, the gas specification is stated in the Gas Safety (Management) Regulations 1996.
When natural gas is brought out of the well, it contains water vapour, hydrogen sulphide and carbon dioxide. This is known as sour gas. A process called sweetening removes these acid gases. This will prevent pipeline corrosion.
The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex,and usually involves four main processes to remove the various impurities:
1. Sulfur and Carbon Dioxide Removal Sweetening Process
2. Water Removal Dehydration Process
3. Gas Liquefaction
4. Separation of Natural Gas Liquids
In this paper, I will focus on sweetening process. Commercially available acid gas removal processes may be broadly classified into four main categories: absorption by regenerable solvent; adsorption on solid bed, membrane separation, and direct conversion to sulphur.
The process that I present here is very much based on the work that I have done during my third year undergraduate design project: Natural Gas processing. The gas specification given in this project required a low concentration of hydrogen sulphide (not more than 10 ppm ).
I have chosen the sweetening process using absorption by regenerable solvent. This method of absorption was established nearly 70 years ago for applications in the petroleum and chemical processing industries. The fundamental engineering concepts developed in the 1930s through early 1950s are still quite applicable to today’s designs and continue to be used.
The solvent used is methyl-di-ethanol-amine (MDEA). It is a tertiary amine and is more selective for hydrogen sulphide than conventional amines such as mono-ethanol-amine (MEA), dimethyl-ethanol-amine (DEA) and di-glycol-amine (DGA). This selectivity arises because MDEA completely substituted ammonia molecules with no hydrogen atoms attached to the nitrogen, cannot react directly with carbon dioxide to form carbamate. However, it reacts directly with hydrogen sulphide via the same instantaneous proton transfer mechanism that occurs when hydrogen sulphide reacts with primary and secondary amines.
Research shows that MDEA concentrations of up to 60wt% can be used without any evaporation losses. MDEA at this concentration is sparingly miscible with hydrocarbons. (I modelled and developed the process flow sheet using the computer simulation program ChemCad. It is a circulation process.
Initially, the feed sour gas enters the bottom of an absorber at 70 bar and 50 degree celsius. It flows at the rate of about 700 tonnes per hour. Simultaneously, the cooled lean amine enters the top of the absorber column at the rate of approximately 1000 tonnes per hour.
The sour gas flows upward counter-current to the lean solvent. Almost all the carbon dioxide and hydrogen sulphide in the sour gas are absorbed by the solvent in the absorber. There is only 2 percent hydrogen sulphide left in the sweet gas.
The sweet gas, after absorption of hydrogen sulphide by the solvent, flows overhead from the absorber. An acid gas rich amine solution leaves the bottom of the column at an elevated temperature. This is because of the exothermic absorption reaction. This rich amine solution is then fed to a regenerator also known as Stripper usually by application of heat.
The stripper has a reboiler which supplies the heat to strip-off’ the hydrogen sulphide and carbon dioxide from the rich amine to regenerate the lean amine solution. It is further cooled by a heat exchanger and re-circulated to the top of the absorber, thus completing the cycle.
During the process, there was a loss of MDEA and water together with acid gas. Make up water and MDEA have therefore been added to make up for the loss.
The energy consumed is directly related to amine circulation rate. Increasing the amine concentration and acid gas loading in the rich solution will allow a decrease in the circulation rate and energy costs. When the acid gas content in the inlet gas is reduced or when the feed gas flow rate is reduced, energy can be saved by reducing the amine circulation rate.
This effect is not usually as great as expected. The principal reason is because the acid gas vapour pressure is higher over more concentrated solutions at equivalent acid/amine mole ratios. When an attempt is made to absorb the same quantity of acid gas in a smaller volume of solution, the heat of reaction results in a greater increase in temperature and also an increase in acid gas vapour pressure over the solution. The effect of increasing the MDEA concentration is almost nullified by the decreasing net acid gas absorption per mole of MDEA. (Hovels and Van De Venne, 1981).
The power recovery attainable was also taken into account. When the absorber operates at a sufficient pressure, a hydraulic turbine can be used to recover the energy from the high pressure liquid leaving the absorber. A hydraulic turbine converts the high pressure liquid to mechanical energy which can be used to drive the lean amine pumps. If a hydraulic turbine is not used, the high pressure energy of the liquid is wasted when it is reduced from the absorber pressure to the stripper pressure.
One of the by-products of the sweetening process is hydrogen sulphide. It can be sold and used if reduced to its elemental form, sulphur. It is a bright yellow powder, and can often be seen in large piles near gas treatment plants. In order to recover elemental sulfur from the gas processing plant, the sulfur containing discharge from a gas sweetening process must be further treated. The process used to recover sulfur is known as the Claus process, and involves using thermal and catalytic reactions to extract the elemental sulfur from the hydrogen sulphide solution.
