What Is Natural Gas Processing?

The natural gas produced by the natural gas gathering and processing of the gas collection pipe network centralized gas wells is separated and measured and sent to the natural gas processing plant for desulfurization, dehydration, recovery of sulfur and liquid hydrocarbons, and the process of obtaining natural gas that meets the standards.

Natural gas gathering and processing

Right!

The natural gas produced by the natural gas gathering and processing of the gas collection pipe network centralized gas wells is separated and measured and sent to the natural gas processing plant for desulfurization, dehydration, recovery of sulfur and liquid hydrocarbons, and the process of obtaining natural gas that meets the standards.

Chinese name

Natural gas gathering and processing

Technology Type

Physical Chemistry

Technical goals

Obtaining qualified natural gas

Main process

Gas collection, desulfurization, dehydration, recovery

The natural gas produced by the gas wells is collected by the gas collection pipe network, and after separation and measurement, it is sent to the natural gas processing plant for desulfurization, dehydration, recovery of sulfur and liquid hydrocarbons, and the process of obtaining natural gas that meets the standards.
It is important to consider issues such as layout, delivery method, and gas pressure. The layout of the gas collection network depends on:

Gas field area and shape;

terrain and features;

Expected development of gas fields.

There are three basic ways of gas distribution network layout: radial, branched, and annular.

Natural gas gathering and processing

Can also be used in combination (Figure 1). According to the liquid content in the fluid being transported, the gas collecting pipe network can adopt single casing network gas and liquid mixed transmission within the allowable pressure drop range, and can also separate gas and liquid in advance at the well site, using two casing networks Gas and liquid transfer. If the gas field has more than two gas reservoirs to be exploited at the same time, a multi-casing network should be set up according to the gas quality and pressure of different production layers. The pressure of the gas collection pipe network is determined according to factors such as formation pressure, gas-liquid separation process and pressure requirements of the gas transmission system.
In the later stage of gas field production, the production and pressure of gas wells are reduced at the same time. Compressors can be used to collect gas when natural gas cannot enter the gas collection network by its own pressure and cannot be used locally. Mine gas collection generally uses a reciprocating compressor unit driven by a dedicated gas engine to adapt to the continuous changes in both the exhaust volume and the compression ratio. The unit can be installed at a well site or a gas gathering station. If a large amount of high-pressure natural gas can be obtained nearby without other constraints, an ejector with high-pressure gas and low-pressure gas can be used to collect low-pressure natural gas to enter the gas collection pipe network.
For the gas collection network of sulfur-containing gas fields, low-carbon steel or sulfur-resistant low-alloy steel pipes are often used to prevent stress corrosion caused by sulfides (see carbon steel, alloy steel, stress corrosion fracture and hydrogen embrittlement).
Formation gas, condensate, condensate, and a small amount of sand from the gas well are separated from the natural gas. In the main stage of the gas field development process, the wellhead pressure of the gas well is generally much higher than the pressure of the gas gathering network. When the pressure is throttled and reduced, the Joule-Thomson effect will occur, which will reduce the temperature of the natural gas. Even above 0 ° C, certain components in natural gas can still form ice-snow-like hydrates with existing free water under certain temperature and pressure conditions, blocking pipelines and equipment. The separation process of the mine is divided into normal temperature separation and low temperature separation according to different methods to prevent the formation of hydrates.
Separation at room temperature

Hydrate formation is prevented by heating. The natural gas from the wellhead is first heated, then throttled and decompressed before entering the separator. After gas-liquid separation should be measured separately (Figure 2). The degree of heating and pressure reduction stages depend on wellhead temperature and wellhead pressure. Separation at room temperature is generally used for dry gas (the content of pentane and above fractions is less than 10ml / m), which can be carried out at a well site or a gas gathering station.

Natural gas gathering and processing

Cryogenic separation

Inject antifreeze such as glycol (ethylene glycol, diethylene glycol), methanol, etc. into the air stream to prevent the formation of hydrates. See Figure 3 for the low temperature separation process using glycol as antifreeze.
The natural gas from the wellhead is first separated by the free water carried in the free water separator. The pressure of the separator is controlled above the natural gas reverse condensing pressure to prevent hydrocarbon condensation. Then antifreeze, such as glycol, is injected into the natural gas stream, and the pressure is throttled and reduced, and the condensed oil that enters enters the cryogenic separator. The natural gas is output after being cooled, and the dilute glycol after the condensate absorbs water enters the stabilization tower, and then is separated in an oil-glycol separator, and the former is sent to a storage tank; the latter is reused after being concentrated. Low-temperature separation is generally used for moisture (pentane and above fractions are higher than 10ml / m). It is usually carried out centrally at the gas gathering station. No antifreeze can be added when the water content is low.

Natural gas gathering and processing

After removing the acid gas components such as HS and CO in natural gas, it is exported. There are roughly four types of methods:
Chemisorption

The alcohol amines or alkaline salts solutions are used as solvents to absorb acid gas components such as HS and CO in natural gas in an absorption tower to purify natural gas. Then, a reverse-direction chemical reaction occurs in the regeneration tower with higher temperature and lower pressure, and the absorbed HS and CO are released to regenerate the solvent. The process flow of various chemical absorption methods is basically the same (Figure 4). The solvent contacts the acid natural gas countercurrently in the absorption tower to absorb HS and CO. The purified natural gas flows out from the top of the absorption tower and is exported after dehydration. After the acid gas is absorbed, the solvent (rich liquid) flows out from the bottom of the absorption tower, after decompression, it exchanges heat with the regenerated solvent (lean liquid), and then enters the regeneration tower. The rich liquid is further decompressed in the regeneration tower and heated by the reboiler to release the absorbed acid gas and become a lean liquid. The acid gas is discharged from the top of the regeneration tower, cooled, separated, and sent to the sulfur recovery device. The lean liquid flows from the bottom of the regeneration tower, and after heat exchange and cooling, it is pumped to the absorption tower by the solution circulation pump for recycling. The commonly used alcohol amine solutions are ethanolamine, diethanolamine, glycolamine, diisopropanolamine, and Diethanolamine and the like. The monoethanolamine method has been gradually promoted since the 1930s. Due to mature technology, strong solvent reactivity, easy recovery and treatment of metamorphic solvents, and low price, it is still widely used in natural gas desulfurization. Since the 1960s, the diisopropanolamine method has been continuously improved and gradually promoted.
Desulfurization methods using alkaline salt solutions as solvents, such as the hot potassium-alkali method, and Catacarb method and Benfield method developed on the basis of this method are mainly used to treat CO content Higher gas.
Physical absorption method

Using polyglycol dimethyl ether,

Natural gas gathering and processing

Organic solvents such as propylene carbonate and N-methylpyrrolidone have different solubility for hydrocarbons and acid gas components such as HS and CO. They absorb acid gas components in natural gas under high pressure to purify them. During the regeneration process, the pressure decreases, the temperature rises, the absorbed acid gas component is released, and the solvent is regenerated. The above absorption and regeneration are purely physical processes, and no chemical reaction occurs between the solvent and the gas. Physical absorption method is used to process natural gas with high CO content. In addition, the sulfonamide method is also generally classified into this category. However, the sulfone amine method solvent is prepared from sulfolane diisopropanolamine and water in a certain ratio, and has both physical absorption and chemical absorption. It is suitable for purifying natural gas with high acid gas partial pressure, and can partially remove organic sulfides (such as mercaptans, thioethers, carbonyl sulfur, etc.). This method has strong competitiveness and is widely used. The process is similar to the alcohol-amine method, except that the rich hydrocarbons need to be flashed under a certain pressure to remove the dissolved hydrocarbons before regeneration.
Liquid phase direct oxidation

By adding the role of the oxygen carrier in the alkaline solution, the HS absorbed by the solvent is directly oxidized to elemental sulfur, and then the solvent is regenerated by bubbling with air. This type of method can choose to absorb the HS in acidic components, used to treat natural gas with low HS content and high ratio of CO to HS content, or used to treat the tail gas of sulfur recovery device. The more representative are: anthraquinone method, improved arsenic-alkali method, ferric-alkali method, etc.
Dry bed method

The sponge-like iron oxide, molecular sieve, zinc oxide and other fixed beds are used to remove HS from natural gas. Sponge-shaped iron oxide fixed bed desulfurization is an early method. Due to the large size of the device, defects such as sulfur can not be recovered. At present, it is only used to treat dispersed low-sulfur natural gas with small amounts.
Sulfur recovery

The acid gas removed by two types of desulfurization devices, chemical absorption method and physical absorption method, must be sent to a sulfur recovery device to recover sulfur by the Claus method. The principle is to burn one third of the HS in the acid gas into SO, and then react with the remaining HS under the action of a catalyst (active bauxite, etc.) to obtain elemental sulfur: 2HS + SO 3S + 2HO. Most industrial units use two-stage catalytic reactions, and the conversion rate of sulfur can reach 90 to 96%.
To prevent environmental pollution caused by residual HS and SO in the exhaust gas of the sulfur recovery unit, exhaust gas treatment must also be performed. There are many methods for tail gas treatment, which are selected according to the sulfur output of the factory and the requirements of local environmental protection. In large factories located in densely populated areas, the commonly used method is to reduce the residual SO in the exhaust gas to HS by catalytic hydrogenation; then use the diisopropanolamine method or direct oxidation method to selectively remove HS, such as Scott method and Beavon method; the removed HS is returned to the sulfur recovery device; the treated exhaust gas is discharged into the atmosphere after burning. With such a tail gas treatment plant, the total recovery rate of sulfur can be as high as 99.9% or more, and the content of SO in the tail gas discharged does not exceed 300 ppm.
For Claus units that have low sulfur output and exhaust after two-stage catalytic reactions that do not meet environmental protection requirements, a three-stage catalytic reaction or additional low-temperature Claus units such as Sulfreen (Sulfreen ) And Clauspol installations, so that the exhaust emissions meet environmental protection requirements.
Natural gas that comes directly from a gas well or after desulfurization generally contains saturated water vapor. During the pipeline transportation process, with the change of pressure and temperature, condensed water may be precipitated, and even ice or solid hydrates may be formed, blocking the pipeline and affecting natural gas transportation. Condensate will also cause acidic gas components in natural gas to electrochemically corrode steel. Therefore, the natural gas must be dehydrated before entering the gas transmission system, so that its dew point is lower than the lowest ambient temperature during the gas transmission by more than 5 ° C.
Mine natural gas dehydration mainly uses triethylene glycol (or diethylene glycol) as a hygroscopic agent.

Natural gas gathering and processing

Glycol comes into contact with natural gas from top to bottom in a dehydration tower. Absorb the moisture in it to reduce the dew point of the natural gas to meet the gas transmission requirements and send it to the gas transmission system or the next process. The water-absorbed alcohol flows out from the bottom of the tower. After heat exchange and heating, the dry natural gas is stripped. After the concentration is increased, it is pumped to the dehydration tower for recycling. The flow is shown in Figure 5.
The dew point drop of the triethylene glycol dehydration method can generally reach 50-70 ° C. For natural gas with higher dew point drop or higher HS content, molecular sieves, alumina, silica gel, calcium chloride, etc. can be used as adsorbents for fixed bed. Adsorption dehydration.
The purpose of recovering hydrocarbons above ethane in natural gas is twofold:

Control the hydrocarbon dew point so that no liquid hydrocarbons will be precipitated during the gas transmission process, which will affect the gas transmission efficiency;

Recover ethane, liquefied gas (liquid propane, butane, or a mixture of both) and natural gasoline as chemical raw materials or liquid fuel. At present, the recovered liquid hydrocarbons mainly adopt the low-temperature condensing method. According to the refrigeration method, they are divided into:

Natural gas gathering and processing

Throttle expansion method or turbo expander method using natural gas's "pressure energy" and external cold source method. The condensing temperature is generally as low as -45 ° C or lower, depending on the product plan, economic benefits, and especially the degree of ethane recovery (Figure 6). For oilfield gas rich in ethane and hydrocarbons above propane, if the purpose is to recover liquid hydrocarbons above propane, generally an external cold source method with a condensation temperature of -20 to -25 ° C can be used to reasonably recover liquid hydrocarbons. Before the 1970s, normal temperature or low temperature oil absorption methods, which had been widely used, have been rarely used because of their lack of economic competitiveness.
Whether the desulfurization, dehydration, liquid hydrocarbon recovery and other treatment processes need to be carried out in full should be determined according to the quality requirements of natural gas components and externally transported gas, and should be considered uniformly with the gas collection system. If natural gas contains higher-grade helium and other components, extraction should also be considered.