CC BY
16
PURiFiCATiON OF ASSOCiATED GASES UNDER
FiELD CONDiTiONS
Fikrat Seyfiyev, Sahib Abdurahimov, Irada Hajiyeva
•
Azerbaijan State Oil and Industry University [email protected] [email protected] [email protected]
Abstract
The article considers the issue of extraction of aggressive components from the associated gases produced from the oil and gas wells. The presence of hydrogen sulfide and CO2 in the gas causes corrosion of equipment and pipelines on the one hand, and pollution of the environment, the emergence of technogenic risks on the other. A 15% aqueous solution of monoethanolamine has been proposed as an absorbent for H2S and CO2 capture.
Keywords: dry gas, hydrogen sulfide, absorption, absorbent, sodium hydroxide, technogenic
risks
I. Introduction
The presence of a wide range of aggressive components, such as hydrogen sulfide (H2S) and carbon dioxide (CO2), during the transportation of associated gases produced by the Oil and Gas office can lead to corrosion of equipment and pipelines, environmental pollution, deteriorating gas quality and thus lead to technogenic risks. The combustion of these gases produces sulfur dioxide, which is a major threat to wildlife.
In addition, hydrogen sulfide is a valuable raw material for the production of elementary sulfur, which is widely used in industry. CO2 is considered a ballast in the gas and increases its transportation costs. The presence of CO2 in the gases in some cases complicates its processing. Thus, the formation of hydrate compounds during the processes of deep cooling of the gas causes certain problems. Therefore, both from economic and environmental points of view, the extraction of aggressive components from the gases in the mining environment is of great importance and, as a result, serves to reduce technogenic risks.
II. Methods
Thus, during the preparation of associated gases for transportation, physical absorption, combined processes, i.e. chemical and physical absorbents, oxidation and adsorption processes are used to remove aggressive components.
The choice of process for the purification of associated gases from aggressive components depends mainly on the composition of the raw gas and the parameters of energy resources. In world practice, absorption processes are mainly used to purify large volumes of hydrocarbon gases before transportation. Other purification methods, such as oxidation and adsorption, are commonly used to purify small amounts of associated gas streams. The following requirements are set for absorbents used in industry: high absorbency, low vapor pressure, chemical and thermal stability under operating conditions, low viscosity, low heat capacity, non-corrosive, selective and non-toxic properties. Absorption capacity and viscosity determine the cost of
electricity consumed for the circulation of the absorbent. The more stable the absorbent and the lower the saturated vapor pressure, the lower its loss. Based on the corrosion properties, the requirements for the materials of the gas treatment plant equipment are determined.
In the world practice, amine processes take the leading place in the field of purification of gases from aggressive components. In this process, ethanolamines, monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), diglicolamine (DGA), etc. are used as absorbents to purify gases from H2S and CO2. The most commonly used of these amines are mono- and diethanolamines. Triethanolamine is not widely used due to its low absorption properties. Other amines are used for selective removal of aggressive components. [1,2]. Pure amines are highly viscous liquids with a high freezing point. However, their aqueous solutions have low viscosity and low freezing point (below - 100C). Therefore, in industry, aqueous solutions of ethanolamines are used as absorbents in the process of purification of gases from aggressive components by absorption [3,4]. The concentration of amines in solution can vary widely. Thus, this value is selected based on the results of research and in terms of corrosion control. One of the important indicators of gas treatment plants is the consumption of amines. Thus, the cost of absorbents is very high, and the absorbent expenses are the majority of operating costs.
In some cases, very small amounts of hydrogen sulfide and other sulfur compounds are found in the gases produced in some oil and gas fields of the country. However, some oil and gas companies have high levels of hydrogen sulfide in their gases. The presence of hydrogen sulfide causes corrosion of equipment and pipelines during the preparation of gases for transportation on one hand, pollution and poisoning of the environment on the other hand. The component composition of the gas is shown in Table 1.
III. Results
Concentrations of CO2 and H2S up to 10.1308 g/m3 in the associated gases lead to corrosion of the transport system and process equipment and reduce the efficiency of transport processes and the quality of transported products.
Table 1: The component composition of the gas
№ Components %, weight
1 2 3
1 Methan 96,57
2 Ethan 1,59
3 Propane 0,21
4 n-butane 0,06
5 i-butane 0,08
6 n-pentane 0,03
7 i-pentane 0,05
8 hexane 0,03
9 N2 0,21
10 CO2 1,16
11 O2 0,01
Total: 100
Density 0,700kg/m3
H2S 10,1308g/m3
Therefore, the extraction of CO2 and H2S from these gases is of great importance. The process of purification of gases from hydrogen sulfide by the absorption method consists of 2 blocks -absorption and regeneration (desorption) blocks of saturated 15% aqueous solution. A 15% aqueous solution of monoethanolamine is used as an absorbent. Some properties of a 15% aqueous solution of monoethanolamine are given below.
- Thickness, kmol/m3 2,5
- Boiling point, 0C 118
- Freezing temperature, 0C - 50
- Viscosity, at 400C, 103 Pa-S 1,0 -Vapor pressure at 400C, kPa 7,4
The basic technological scheme of the proposed device for purification of gases by absorption method is given in Figure 1. Dry gas containing H2S, obtained in the absorption and gas fractionation section, enters the absorber 1 with pressure P = 1.1 + 1.4MPa, temperature t = 400C through line I for purification from hydrogen sulfide. To remove H2S from the gas, a 15% aqueous solution of monoethanolamine from capacity 3 is supplied to the upper part of the absorber by means of line N-1 / 1,2 pump. The purified gas in the absorber passes through 2 separators and is released from the monoethanolamine particles it carries with it and is sent to the pipeline of "Azerigaz" PU for further processing through line II. Monoethanolamine solution saturated with hydrogen sulfide from 1 absorber is supplied to line 4 with line IV. The hydrogen sulfide-saturated MEA solution is pumped through the N-2 / 1,2 pump to the inter-pipe area of 7 heaters for regeneration, where it is heated to 900C and then enters line 8 through the VII desorber.
Figure 1: Schematic diagram of the H2S gas purification plant. 1- absorber; 2,9,11- separator; 3- capacity for regenerated (pure) MEA; 4- capacity for saturated MEA solution; 5- drainage capacity; 6,12- water coolers; 7-heat exchanger; 8- desorber; 9- evaporator; 10- air cooler; 13-
capacity.
I- dry gas; II- purified gas; III- absorbent (15% aqueous solution of MEA); IV- saturated MEA solution; V-freshly prepared 15% MEA solution; VI- regenerated MEA solution; VH-steam-gas phase; VIII- desorber irrigation; IX- liquid drainage capacity in separators; X- liquid 4 capacity.
The temperature in the bottom of the desorber is 1200C, and at the top is 1100C. The heat of the lower part of the desorber 8 is provided by water vapor at a pressure of 1.0 MPa by means of an evaporator 9. Hydrogen sulfide and water vapor from the top of the column are condensed in
air condenser-coolers 10 and being cooled enter separator 11, and then additionally cooled in cooler 12 enter capacity 13. The separated gas phase (H2S) is transferred to the torch, and the liquid phase is fed to the upper part of the desorber by line X by means of the pump N-4/1,2. Monoethanolamine solution regenerated from desorber 8 is supplied to the pipeline area of heat exchangers 7 through line VIII by means of pump N-3/1,2. Here, it is cooled to 620C, enters water cooler 6 and then it is cooled to 400C. From there it is fed to capacity 3.
In order to maintain the required level of circulating MEA solution in the purification process of gases from hydrogen sulfide, fresh MEA solution is added to the system periodically along the V line. Technological reports were made to determine the performance and operating modes of the main apparatus of absorption and desorption processes. During the report, the amount of raw gas was assumed to be 11000nm3/h.
The summarized data of the technological reports are given in Tables 2, 3 and 4.
Table 2: Column type devices
Name Working conditions The height of the column, m The diameter of the column, m Number of plates, pcs. Type of plates The distance between the plates, m
Location on height t, 0C P (abs), MPa Consumption, t/h
liquid steam
Gas absorber up down 40 45 1,3 1,3 15,2 11,3 18,8 1,2 21 Valved, single-flow plate 0,6
Desorber for regeneratio n of MEA solution up down 110 120 0,2 0,2 10 0,44 18,8 1,2 21 Valved, single-flow plate 0,6
Table 3: Separators
Name The environ ment Consumptio n, t/hour Working conditions Basic dimensions Time of gas presence in the separator, min.
t, 0C P (abs), MPa Capacity, m3 Diameter, m Height, m
1 2 3 4 5 6 7 8 9
Gas separator Purified gas 11,324 40 1,3 4,0 1,2 4,4 0,22
Sour gas separator Sour gases 0,184 40 atm 6 1,2 5,2 0,22
Table 4: Heaters and refrigerators
Heat
Name The direction of flows The Consumptio Temperature Heat load transfer coefficient (K), kcal / Surface
environment n, kg / h At the At the kcal / hour area, (F), m2
inlet outlet m2hour0C
1 2 3 4 5 6 7 8 9
Heater of pipe area Regenerated 10000 120 67
saturated MEA MEA
solution solution
inter- 10182 40 90 534665 200 41x2=82
pipe area Saturated MEA solution
Water cooler of pipe area Water 29000 29 40
regenerated
MEA solution inter- Regenerated 320000 150 101x2 =202
pipe area MEA solution 10000 67 35
Water vapor pipe area Water 153,5 29 35
condensate
and H2S 921 50 3,5
mixture water inter- hydrogen 184 40 35
cooler pipe area sulfide
Air condenser Water vapor 445
cooler pipe area
110 40 150000 6,8 848
hydrogen 184,096
sulfide
The application of this device will reduce the amount of hydrogen sulfide in the gas to
0.001%.
IV. Conclusions
The presence of hydrogen sulfide in the composition of gases leads, on the one hand, to corrosion of equipment, pipelines, and on the other, to pollution and poisoning of the environment and, as a consequence, to the emergence of technogenic risks.
It was proposed to use the absorption process to remove hydrogen sulfide from the gas. A 15% aqueous solution of monoethanolamine was suggested as absorbent. Application of this device will allow to reduce the amount of H2S in the gas to the amount required by the regulatory documents.
References
[1] Miralamov H., Gurbanov R. "Technology of gas transportation in offshore oil and gas fields" Baku, Science - 2002.
[2] F.I. Afanasyev, V.M. Stryuchkov, N.N. Podlegaev and et.al., Technology of processing of natural gas: Guidebook/ under the edition. A.I. Afanasyev - M .: Nedra, 1993.- p. 152.
[3] Jou F.Y., Otto F.D., Mather A.E / Journal of Chemical Engineers.- 1994.-V.33, №1.- pp. 2002-2005.
[4] Nasteka V.N. New technologies of purification of high-core natural gases and gas condensates.-M: Nedra, 1996.- p. 108.
