The present invention relates to a process for removing heavy hydrocarbons and hydrogen sulfide from natural gas. More particularly, the invention relates to an efficient design to remove heavy hydrocarbons (C5+) even when hydrogen sulfide has adversely affected the ability of the standard adsorbent to remove heavy hydrocarbons from a natural gas stream.
A large fraction of the world's total natural gas reserves has the problem of being “sour” in that they contain substantial amounts of hydrogen sulfide, which is both highly toxic and tends to embrittle steel pipelines, making the transport of gases by pipeline highly dangerous and unreliable. Much of world's total natural gas reserves also has the problem of being “static,” i.e., the gas is located in remote geographic regions that make it uneconomical to transport the gas via pipeline or to refine and/or condense the gas on site and ship it to market in liquid form. The world's total natural gas reserves also include much that is poor in quality because the methane and other combustible gas components are diluted with non-combustible carbon dioxide and nitrogen gas, making the unrefined gas a relatively low Btu fuel source.
Thus, for many years, the need has existed to convert sour natural gas which may also be static and/or poor into a more valuable commercial product which could then be transported in large quantities by inexpensive means (preferably by ship or pipeline). The current state of industrial practice with sour natural gas that is also static and poor is illustrated by Exxon's development of the Natuna gas fields located in the middle of the South China Sea. Because the natural gas deposits contain high percentages of CO2 and H2S, the gas is considered both poor and sour. In that project the CO2 and H2S are removed by liquefying and fractionally distilling the gas. This approach, while technically feasible, is very expensive. The static gas problem was resolved by developing a local use for the gas on site, namely as a fuel for use in producing steam for secondary oil recovery in the same remote geographic location. The Exxon approach made good economic sense because it began with two low value natural resources (a static, poor quality sour gas field and a depleted oil field) and finished with a relatively high quality crude oil end product using secondary oil recovery techniques. The natural gas intended to be treated by means of the method according to the invention may be saturated with water. This natural gas is generally at the pressure and at the temperature of the production well or of any process used upstream.
The hydrocarbons in the natural gas can be such that at least 95% by weight of their compounds have one to seven carbon atoms. Generally, the hydrocarbons essentially contain compounds having one to two carbon atoms. About 2 to 10% by weight are considered heavier hydrocarbons, having at least five carbon atoms up to thirty or more carbon atoms. The natural gas intended to be treated contains a substantial amount of hydrogen sulfide. A substantial amount generally means between 5 and 50% by mole, preferably between 20 and 45% by mole, in particular between 30 and 40% by mole, for example, 35% by mole.
Natural gas usually contains a significant amount of carbon dioxide. The proportion of carbon dioxide can range up to 50% by mole or higher, often from 10 to 40% by mole. A typical sour natural gas can, for example, contain 50 to 70% by mole of methane, 5 to 15% by mole of ethane, 0 to 5% by mole of propane, 5 to 50% by mole of hydrogen sulfide and 0 to 30% by mole of carbon dioxide. By way of example, the natural gas to be treated can contain 56% by mole of methane, 0.5% by mole of ethane, 0.2% by mole of propane, 0.03% by mole of butane, 0.25% by mole of water, 10.6% by mole of carbon dioxide, 31.5% by mole of hydrogen sulfide and various other compounds as traces.
There are a number of different methods that have been used to treat natural gas streams. In most methods, a combination of technologies is employed to remove condensable components as well as gaseous components such as carbon dioxide. In one process, adsorbents such as silica gel are used to remove heavy hydrocarbons followed by use of an amine solvent to remove carbon dioxide and hydrogen sulfide. Another particularly useful method involves permeable membrane processes and systems that are known in the art and have been employed or considered for a wide variety of gas and liquid separations. In such operations, a feed stream is brought into contact with the surface of a membrane, and the more readily permeable component of the feed stream is recovered as a permeate stream, with the less-readily permeable component being withdrawn from the membrane system as a non-permeate stream.
Membranes are widely used to separate permeable components from gaseous feed streams. Examples of such process applications include removal of acid gases from natural gas streams, removal of water vapor from air and light hydrocarbon streams, and removal of hydrogen from heavier hydrocarbon streams. Membranes are also employed in gas processing applications to remove permeable components from a process gas stream. Natural gas as produced from a gas well presents a separations challenge. Often the natural gas is found together with other components such as sulfur compounds, water, and associated gases. The associated gases found in natural gas streams typically include carbon dioxide, hydrogen sulfide, nitrogen, helium, and argon. Generally, these other gas components are separated from the natural gas by bulk methods employing membrane systems.
Membranes for gas processing typically operate in a continuous manner, wherein a feed gas stream is introduced to the membrane gas separation module on a non-permeate side of a membrane. The feed gas is introduced at separation conditions which include a separation pressure and temperature which retains the components of the feed gas stream in the vapor phase, well above the dew point of the gas stream, or the temperature and pressure condition at which condensation of one of the components might occur. The feed gas stream fed to the gas separation membrane may contain a substantial amount of moisture and condensable hydrocarbons. These condensable components can cause problems in downstream equipment, such as condensation in the membrane elements, thereby causing membrane swelling, or coating of the membrane surface, leading to decreased permeability. In order to compensate for damage caused by condensation of the feed gas stream during the lifetime of a membrane system, such membrane systems are often oversized to compensate for the loss of membrane surface over the useful life of the membrane. However, for high volume gas treating application, this over design of membrane capacity can be very costly, adding millions of dollars to the cost of a membrane system. One approach to extend the membrane life is to pretreat the natural gas prior to sending it to the gas separation membrane. In the UOP MemGuard process thermal swing adsorption (TSA) units are used to pretreat the natural gas feed to the membrane process. These TSA units use silica gel or aluminosilicate gel adsorbents to remove heavier hydrocarbons and water from the natural gas. This pretreatment prevents condensation in the membrane process and the subsequent coating of the membrane surface with heavy hydrocarbons, thereby extending membrane life.
Another method for treating natural gas streams involves the use of an amine solvent process. It is often necessary to remove the higher hydrocarbons before the feed stream contacts the amine solvent, for example to prevent foaming problems.
U.S. Pat. No. 4,881,953 to Prasad et al. discloses an approach to the problem of preventing premature loss of membrane capacity by passing the feed gas mixture through a bed of adsorbent material, such as activated carbon to adsorb contaminants such as heavier hydrocarbon contaminants without the removal of lighter hydrocarbons. Prasad requires that a means for removing moisture from the feed gas be provided because high moisture levels generally limit the ability of activated carbon adsorbents to retain their adsorptive capacity for heavy hydrocarbons.