Sulfur-containing natural gas contains impurities such as hydrogen sulfide, organic sulfur (mercaptan), carbon dioxide, saturated water, etc. In order to meet the requirements of factory production and the use of civil commercial gas, it is necessary to remove the harmful components. The standards of commercial natural gas vary from country to country, mainly including hydrocarbon dew point and water dew point. The contents of hydrogen sulfide, mercaptan and carbon dioxide in natural gas are the highest and the combustion value is low. The composition of raw natural gas is different from that of commercial natural gas, and the technical scheme of natural gas purification is also different. In this paper, the selection method of desulfurization and dehydration technology scheme for sour natural gas will be put forward based on the composition of treated natural gas in an oil and gas treatment plant in Kazakhstan and the requirements of international pipelines for natural gas export.

2 feed gas conditions

The main conditions of associated natural gas in an oil and gas treatment plant in Kazakhstan are as follows:

1) the processing capacity is 600× 104m3/d (the standard state is 0℃, 10 1.325kPa, the same below);

2) The pressure is 0.7MPa. In order to meet the needs of pipeline transportation pressure and purification process, the device pressure is 6.8MPa after being boosted by the booster station;

3) Main components

ingredient

Composition (mol%)

C 1

75. 17

C2

9.44

C3

7.2 1

Complement fourth component deficiency

3.35

C5+

1.06

carbon dioxide

0.7 1

H2O

0.5 1

H2S

36 g/m3

Thiol sulfur

500 mg/m3

3 technical indicators of commercial natural gas

The commercial natural gas from this plant will be exported to international pipelines and must meet the requirements of ос109051.40-93 standard. The main technical indicators to be achieved are:

1) factory pressure 6.3MPa；;

2) water dew point ≤-20℃;

3) hydrocarbon dew point ≤-10℃;

4) Hydrogen sulfide (H2S) ≤ 7 mg/m3;

5) Thiol sulfur (calculated as sulfur) ≤16 mg/m3;

6) Low combustion calorific value ≥32.5MJ/m3.

4 Preliminary selection of process route

According to the conditions of raw natural gas and the technical indicators of commercial natural gas, the general process flow chart of the factory is shown in figure 1.

After the associated natural gas in the oil field is supercharged by the booster station, it enters the natural gas desulfurization and dehydration unit for treatment, and most of H2S and RSH in the natural gas need to be removed to meet the technical indicators of H2S and mercaptan sulfur content in the product natural gas. At the same time, most of the water in natural gas needs to be removed to meet the technical index of natural gas water dew point. At the same time, in order to recover more liquefied gas and light oil products, the dehydration depth needs to meet the requirement of water dew point ≤-35℃ required by subsequent light hydrocarbon recovery devices. However, the CO2 content in the feed gas is low, which is 0.7 1%(mol), and the low combustion calorific value of commercial natural gas is ≥32.5MJ/m3, so the removal can be ignored.

Clean natural gas treated by natural gas desulfurization and dehydration unit recovers light hydrocarbons (above C3) in natural gas through light hydrocarbon recovery unit to produce liquefied gas and light oil products, so that commercial natural gas can reach the technical index of hydrocarbon dew point ≤-10℃.

The acid gas removed by desulfurization unit is mainly composed of H2S, RSH, CO2, H2O, etc. , transported to sulfur recovery unit to recover sulfur, and sulfur products are produced by sulfur molding facilities. The tail gas of sulfur recovery unit is treated by tail gas treatment unit, and then burned and discharged into the atmosphere.

The following part of this paper mainly discusses how to choose a reasonable process scheme for the desulfurization and dehydration unit, so that the content of hydrogen sulfide and mercaptan in the product gas of the desulfurization and dehydration unit is qualified, and the water dew point meets the requirements of commercial natural gas and subsequent light hydrocarbon recovery units.

5 Preliminary selection of dehydration process scheme

Commonly used dehydration processes include solvent dehydration and solid desiccant adsorption. Solvent absorption method has the advantages of low equipment investment and operating cost, and is more suitable for dehydration of high-pressure natural gas with large flow. The triethylene glycol solution dehydration method is the most widely used, but its dehydration depth is limited, and the dew point drop is generally less than 45℃. The dew point of dry gas dehydrated by solid desiccant adsorption method can be lower than -50℃.

Because the dew point of natural gas in the dehydration unit in this scheme is ≤-35℃, it is difficult to realize solvent dehydration, so it is necessary to adopt solid desiccant dehydration process, such as molecular sieve dehydration process.

6 Preliminary selection of desulfurization and sweetening process scheme

The associated gas treated in this scheme contains 36g/m3 of H2S and 500mg/m3 of mercaptan, and the natural gas treatment capacity reaches 600× 104m3/d, which is relatively large. At present, the maximum processing capacity of a single desulfurization unit in China is only 400×104m3/d/d. ..

Commonly used desulfurization methods and alcohol desulfurization include liquid desulfurization and fixed bed desulfurization.

If a single fixed bed desulfurization method is adopted, such as molecular sieve desulfurization and dealcoholization process, according to the flow rate and sulfur content of natural gas to be treated in this scheme, the amount of hydrogen sulfide to be removed in 10 day is 2. 16× 106kg, which obviously requires about 500 molecular sieve desulfurization towers with DN3000.

At present, the mature and feasible liquid desulfurization process in China is alcohol amine method. Because mercaptan exists in sulfur-containing natural gas at the same time, sulfone amine method can be selected to remove hydrogen sulfide and mercaptan. The process is mature, and the hydrogen sulfide in natural gas can be removed to ≤7mg/m3, and the average removal rate of mercaptan in natural gas is 75%, so the mercaptan sulfur content in the product natural gas is 1.25mg/m3, which can't meet the technical index of mercaptan sulfur ≤ 1.6mg/m3. At this time, a fixed bed mercaptan removal process, such as molecular sieve mercaptan removal process, can be used to remove the remaining mercaptan in natural gas.

In this scheme, mercaptan in natural gas can also be removed by alkali elution process. In order to reduce the consumption of alkali and the amount of waste alkali produced in the production process, monoethanolamine process is needed to remove most of the hydrogen sulfide and carbon dioxide in natural gas in the previous ethanolamine desulfurization unit.

7 Comparison and Selection of Desulfurization and Dehydration Process Schemes

According to 5 and 6, there are two feasible schemes for desulfurization and dehydration process:

1) Scheme 1: Sulfonamide desulfurization+molecular sieve dehydration for sweetening.

The flow chart of this scheme is shown in Figure 2. The sulfur-containing natural gas pressurized in the booster station enters the sulfonamide desulfurization unit to remove almost all H2S and 75% mercaptan, and then enters the molecular sieve dehydration sweetening unit to remove water and residual mercaptan. The purified natural gas is recovered by light hydrocarbon recovery device to recover liquefied gas and light oil products. The molecular sieve regeneration gas in the dehydration and desulfurization unit needs to be pressurized and then returned to the sulfonamide desulfurization unit for desulfurization, which is a cyclic process.

2) Scheme 2: monoethanolamine desulfurization+alkali elution mercaptan+molecular sieve dehydration.

The flow chart of this scheme is shown in Figure 3. The sulfur-containing natural gas pressurized in the booster station enters the monoethanolamine desulfurization unit to remove almost all H2S and CO2, then enters the alkali elution mercaptan unit to remove almost all mercaptan, and the desulfurized natural gas enters the molecular sieve dehydration unit for dehydration, and the purified natural gas is transported to the light hydrocarbon recovery unit to recover liquefied gas and light oil products. The molecular sieve regeneration gas from the dehydration unit needs to be pressurized and then returned to the dehydration unit for dehydration, which is a cyclic process.

7. 1 Process Characteristics of Scheme I

1) Sulfonamide desulfurization device adopts sulfolane and methyldiethanolamine aqueous solution as desulfurizers, and the main components of the solution are methyldiethanolamine, sulfolane and water, with a weight percentage of 45:40: 15, which has both chemical absorption and physical absorption, and can also partially remove organic sulfides (the average removal rate of mercaptan is over 75%). Methyl diethanolamine in solution has a good selectivity for absorbing H2S, which reduces the absorption of CO2, greatly reduces the circulation of solution, and reduces the specifications and sizes of regeneration system equipment, such as regeneration tower, rich-poor liquid heat exchanger, solution filter, acid gas air cooler, etc. So as to reduce investment, reduce steam required for regeneration and circulating water required for solution cooling, and the energy-saving effect is more remarkable.

2) The molecular sieve dehydration and sweetening device selectively removes water and mercaptan from natural gas by using the adsorption characteristics of molecular sieve. Different from the traditional alkali washing process, molecular sieve process can selectively remove hydrogen sulfide and mercaptan, but can not remove CO2. Compared with alkali washing process, it can increase natural gas export by 2×104m3/d..

Molecular sieve dehydration and sweetening are different molecular sieves, and two different molecular sieve beds are generally arranged in the same adsorption tower.

7.2 Process Characteristics of Scheme II

1)- ethanolamine desulfurization is a typical chemical absorption process. This method can only remove trace organic sulfur, and has almost no selective absorption of H2S and CO2.