Influence factor research on deacidification process for high carbon content gas field by numerical simulation—a case study of the Oudeh gas field
© Lv et al. 2015
Received: 3 August 2015
Accepted: 21 October 2015
Published: 6 November 2015
High concentrations of CO2 in natural gas affect its calorific value and corrode the equipment and pipelines related to its transportation and usage. Therefore, strict control over the H2S and CO2 contents in natural gas is essential. CO2 is an important industrial gas that can bring a great deal of economic profit when it is fully utilized.
The natural gas produced at the Oudeh gas field in Syria contains high carbon content natural gas, in which the CO2 content is in the range of 17.5–18.8 %, while the H2S content is in the range of 2.8–3.2 %. However, there have been few studies conducted on treatment solutions for natural gas with high carbon contents. In this paper, several commonly used methods for deacidification of natural gas were introduced. Among these methods, the most suitable one was chosen for desulfurization and decarbonization of the natural gas produced at the Oudeh gas field based on its gas quality.
Optimization and analysis of the primary operating parameters for the desulfurization and decarbonization processes were conducted to obtain the optimized values for the input temperature of the lean solution (42 °C), reflux ratio (0.8), number of trays in the absorber unit (17) , and circulation rate of the lean solution (330 m3/h), etc. Additionally, the influence of the operating pressure of the regenerator unit on the regeneration system was also investigated. The energy consumption of the apparatus and the corrosion level of sour gas to the apparatus were reduced after optimization. Based on the investigation of the natural gas treatment for this gas field, it can serve as a reference for the purification of high carbon contents natural gas.
There is a burgeoning demand for natural gas in industry because it is a clean fuel. It has been predicted that the world will enter a “natural gas era” in the middle of the 21st century (Zhang 1997). A series of treatments is required for natural gas to be extracted from underground before it can be commercialized. Different treatments are needed for natural gases with different natures. “Acid gas” refers to natural gas containing H2S, CO2, and RSH (organic sulfur). H2S is highly toxic and burns into SO2, causing air pollution and cracking of pipes after severe corrosion. High levels of CO2 directly affect the calorific value of natural gas and corrode the system and pipelines installed for its transportation and usage. Therefore, the levels of H2S and CO2 in natural gas have to be strictly controlled. The quality of purified natural gas must meet the second standard of China’s quality specification for natural gas, in which the content of H2S must be less than 7 mg/m3 and the content of CO2 must be less than 3 %.
In 1880s, the American company Union Carbide is the pioneer company formulated the MDEA solution, Ucarsol HS, and further developed it into a series of products. Thereafter, formulated CR solutions, primarily used for CO2 removal, were also developed (Yu 1985). The Dow chemical company based in the United States also developed similar formulated solutions such as the Gas/Spec SS and CS series solutions. In the 1950s, German companies Lurgi GmbH and Linde AG jointly developed low-temperature methanol absorption technology. Owing to its excellent performance, it was widely used in urban gas as well as the oil and gas industries. Currently there are over 80 installations operating low-temperature methanol absorption technologies worldwide (Niu et al. 2003; Hoochgesand 1970). In 1965, American company Allied developed the Selexol solution (polyethylene glycol dimethyl ether) as a physical absorption method that was used for the removal of CO2 from natural gas starting in the early 1980s. Recently, the Selexol solution has been widely employed for the removal of H2S, CO2, COS, sulfides, mercaptans, and other hazardous components from natural gas, fuel gas, and syngas (Qin et al. 2008; Cheng et al. 2002). The ARI Company successfully developed the LO-CAT process used for catalytic liquid-phase oxidation–reduction desulfurization using iron-based catalysts. It is suitable for the purification of natural gas with 0.2 ~ 10 T/d sulfur content. The difference between the LO-CAT and oxyamine desulfurization processes is that the former is an oxidation–reduction process for the removal of H2S but does not remove CO2. Since the successful development of the LO-CAT desulfurization process in the 1980s, as many as 232 installations have been set up worldwide including those that have been completed and those under construction as of 1998 (Xu et al. 2004). In the early 1980s, the Monsanto Company developed membrane separation technology for the removal of CO2 from natural gas. However, the application of this technology was hindered by the high production cost of the membrane (Wang et al. 1999; Long and Long 1993).
In China, the oxyamine process is the most commonly used method for the desulfurization and decarbonization of natural gas. In the 1980s, Nanjing Chemical Industry Company successfully developed an absorption solution called NHD that resembled the physical and chemical properties of Selexol, which was later developed into a NHD purification process. The NHD process is currently widely used for desulfurization and decarbonization purposes in small fertilizer plants, ammonia plants, and methanol plants (Hoochgesand 1970). Since 1993, the research institute of PetroChina Southwest Oil and Gasfield has been cooperating with Zhejiang Zhenhai Petrochemical Engineering General Plant in an effort to substitute MEA for a MDEA method in order to reduce the energy consumption of vapor by 40 %. Until now, pure MDEA or formulated solvents with a mixture of MDEA and other physical solvents and chemical additives have been used in most purification installations for natural gas and gas refineries in China (Chen 2003; He et al. 2009).
HYSYS is a simulation software developed by Hyprotech Company based in Canada that plays a dominant role in simulation techniques in the petrochemical industry around the world. It is also used in wide range of fields, including petroleum extraction, storage and transportation, petrochemical industries, natural gas processing, fine chemical industries, refining industries and pharmaceutical industries.
Balance equation of acid gas in the amine solution
The balance equation in a H2S-CO2-Am-aqueous system involves seven chemical equations, two Henry’s Law, three mass-balance equations, and one electroneutrality equation.
The composition of feed gas
The processing capacity of the installment, flow rate, pressure (absolute pressure), and temperature of the feed gas were set as 250 × 104 Nm3/d, 230 × 104, 7.5 MPa, and 25 °C, respectively.
The quality of the natural gas has to be taken into consideration when choosing the most suitable method for desulfurization and decarbonization processes. For example, the oxidation–reduction method is mainly used for the removal of H2S and is unsuitable for systems with CO2 content. The CO2 content of the purified gas does not reach the specification of being less than 3 % after undergoing the membrane separation process. In addition, it is highly unstable, and generates high production costs (Ren and An 2005). The physiochemical absorption method has only found success in small installations but it is still not stable enough to be widely used (Gupta 1986). The simulation result shows that 39.1 % of methane will be lost using the Selexol method, showing a lack of economic benefit. Compared to those methods, the chemical absorption method seems to be the most suitable desulfurization and decarbonization process to purify natural gas with high CO2 content.
During the deacidification process, monoethanolamine (MEA) in the solution degrades CO2 to produce some non-renewable substances, which results in partial loss of its desulfurization capability. Hence, this method is not being selected. Methyldiethanolamine (MDEA) is highly selective towards H2S, is less corrosive, requires low energy consumption for regeneration, and has wide applications. Although this method is applicable for H2S removal, this study primarily dealt with the removal of CO2, and hence, this method was also unsuitable (Xue 1995). In the F1exsorb PS process, the activated MDEA and sterically-hindered amines are suitable for use with natural gas with high carbon content. However, its high cost has hindered its wide applications. Compared to MEA, diethanolamine (DEA) has relatively high solubility, lower degradability, is less corrosive, and is not selective towards either H2S or CO2. It is suitable to be used in natural gas, manufactured gas, and feed gas with high contents of organic sulfides. Thus, it was selected for this system.
It is known that feed gas contains high CO2 content. Although the MDEA solution possesses a number of advantages, it has a slower reaction rate in the removal of CO2. To overcome this problem, a certain amount of DEA (MEA) was mixed with the MDEA solution to improve the absorption rate of CO2. As a result, the MDEA-DEA mixed-amines solution exhibited a faster absorption rate, higher CO2 removal efficiency, and lower circulation rate of lean solution (Li and Zhao 2009; Wang and Wang 2003). After comparing the simulations of solutions with different ratios and the DEA method, a mixed-amines solution with a ratio of 43 %(w) MDEA + 12 %(w) DEA was chosen as the absorber for the desulfurization and decarbonization processes after purification efficiency, economic benefits, and recycling issues were taken into account.
Numerical simulation method validation
Based on the field test data provided by the literature (Ma et al. 2012), a set of decarbonization device were put into production on 2009.12 at Changling gas field, with a operation capacity of 120 × 104m3/d. The mixed-amines solution is 45 %(w) MDEA + 5 %(w) Activator + 50 %(w) Water, the CO2 content in processed natural gas is 24 % on average in the test.
Data comparison between the result of test and numerical simulation
CO2 content in purified gas (%)
Lean solution circulation rate (m3/h)
In numerical simulation, the process was designed as follows.
The feed gas (F1) was firstly introduced into the horizontal separation to remove impurities and water droplets (F2) that had been carried along with the feed gas (F1). The feed gas (F1) entered the bottom of the absorber unit after the filtration and separation processes. The up-flowing feed gas eventually had countercurrent contact with the down-flowing 55 % (w) mixed-amines lean solution that entered from the top of the tower. Most of the H2S and CO2 were absorbed by the lean solution here. The wet purified gas (F2) left the tower and subsequently entered the vertical separator for removal of the remaining alcohol amine droplets (F4) before leaving the installation. The wet purified gas (F5) was then transferred into the molecular sieve and dehydration unit. The H2S and CO2 contents of the wet purified gas (F5) were the contents after being purified.
The DEA-rich solution (F6) that exited from the bottom of the absorber unit was introduced into the flash drum. Hydrocarbon gasses that were dissolved in the solution were released after undergoing the flash evaporation. In the scrubbing section, the up-flowing flash gas (F7) had countercurrent contact with the down-flowing mixed-amines lean solution to remove a portion of the CO2 and H2S content from the flash gas. After its pressure was regulated, the flash gas (F7) eventually entered the fuel gas system of the purification plant.
The mixed-amines-rich solution (F8) coming from the bottom of the flash drum passed through the filtration system to purge the degradation products and mechanical impurities that had been dissolved in the rich solution. After that, the mixed-amines-rich solution (F9) entered the heat exchanger and was warmed by the lean solution (F10) coming out from the bottom of the regenerator unit. Then, the rich solution (F11) re-entered the regenerator unit from the top and had countercurrent contact with the up-flowing vapor, leading to further desorption of the H2S and CO2 gases to achieve regeneration of the solution. A reboiler at the bottom of the tower provided the heat for regeneration. After passing through the heat exchanger, the warm mixed-amines lean solution (F12) was removed from the bottom of the regenerator unit and cooled by the rich solution. It (F12) then entered the air cooler and cooler to be further chilled. Subsequently, the lean solution (F13) was transferred back to the MDEA-DEA absorber unit by means of a circulating pump to complete the cycle.
The acidic components and water vapor (F14) leaving from the top of the regenerator unit entered the condenser, and a substantial amount of water vapor was condensed. The acidic condensate (F15) being separated out was directed back to the top of the regenerator unit to recycle the alcohol amines vapor that was carried along by the acidic airflow. The acid gas (F16) was transferred to the sulfur recovery unit or incinerator.
Parameter for the absorber and regenerator units
Pressure (top) (kPa)
Pressure (bottom) (kPa)
Temperature (top) (°C)
Temperature (bottom) (°C)
Number of trays
Parameter for the apparatus used in the process
Temperature of outlet pump
Internal pressure of the apparatus (kPa)
Simulated results of the mass flow parameters of the deacidification process using the mixed-amines solution
Mass flow parameters
Lean solution entering the absorber unit
Rich solution existing the absorber unit
Lean solution existing the regenerator unit
Rich solution entering the regenerator unit
Flow rate, kmol/h
Composition mol %
Heat load of the apparatus
Inlet temperature, °C
Outlet temperature, °C
Heat load, kw
(Rich solution) 72.3
(Lean solution) 125.2
(Rich solution) 90.0
(Lean solution) 98.6
(Rich solution) 10,770 kmol/h
(Lean solution) 9974 kmol/h
During the simulated calculations for the desulfurization and decarbonisation process of natural gas, most of the parameters were derived from empirical or assumed values. Therefore, this paper investigated the input temperature of the lean solution, the reflux ratio, the number of trays in the absorber unit, the circulation rate of the lean solution, and the operating pressure of the regenerator unit and their influences on the efficiency of the purification process.
Input temperature of the lean solution
The results shown in Fig. 2 revealed that an increase in the input temperature of the lean solution caused a slight increase in the H2S content and a continuous decrease in the CO2 content in the wet purified gas, as well as a decrease in the flow rate of the wet purified gas leaving the tower. Based on this trend, a decrease in the input temperature of the lean solution reduced the CO2 content significantly while the H2S content remained almost constant. This result demonstrated that the input temperature of the lean solution primarily affected the absorption rate of CO2, while the MDEA-DEA mixed-amines solution did not significantly affect the absorption rate of H2S when the operating temperature was lower than 47 °C.
Figure 3 shows that the content of the acid gas in the wet purified gas began to level off after the reflux ratio of the condenser reached 0.8 (acid gas load of the lean solution was 0.0029). This revelation illustrated that the influence of the reboiler load on the acid gas load in the rich solution became smaller when the desorption of the acid gas in the rich solution reached a certain level, indicating the effect of the absorption of acid gas after this point became less significant even though the reflux ratio continue to increase.
Number of trays in the absorber unit
Figure 4 shows that the content of CO2 and H2S decreased with the increasing number of trays in the absorber unit. If most of the CO2 gas and trace amounts of H2S gas were absorbed by the MDEA-DEA mixed-amines solution when the number of trays was increased to 17 trays. The selectivity of the amine solution decreased with the increasing number of trays and caused a substantial amount of CO2 to be absorbed. As a result, the flow rate of the wet purified gas dropped accordingly, causing a drop in the revenue of the apparatus and the acid gas quality in the regenerator unit. Therefore, the optimum number of trays in the absorber unit was 17 trays theoretically.
Circulation rate of the lean solution
The contents of CO2 and H2S in the wet purified gas decreased with the increasing circulation rate of the lean solution. However, the CO2 absorption rate eventually dropped when the circulation rate of the lean solution was increased beyond 320 m3/h. This was because the reaction rate between CO2 and MDEA decreased. To remove a large amount of CO2, the retention time of the lean solution on the tray had to be maximized. Thus, increasing the circulation rate inevitably shortened the retention time of the lean solution on the tray, which slowed down the CO2 absorption rate. In addition, the reboiler load increased with the increasing circulation rate. Based on the simulation results, the circulation rate of the lean solution was estimated to be 330 m3/h when the design margin of the apparatus was taken into account.
Operating pressure of the regenerator unit
As shown in Fig. 6, the CO2 content increased and the H2S content did not change much when the operating pressure of the regenerator unit increased. As a result, the quality of the acid gas degraded. Due to the operating pressure of the regenerator unit increasing almost proportionally with the reboiler load (Wen et al. 2007), the operating pressure should not be too high. Combining the simulation and experimental results, it was more appropriate to set the operating pressure of the regenerator unit at 200 kPa.
A comparison of the parameters before and after the optimization
Circulation rate of lean solution, m3/h
flow rate of the wet purified gas, 104Nm3/h
Wet purified gas
Heat load of reboiler, kW
Acid gas load of rich solution, mol/mol
Electric energy consumption, kWh/d
0.4Mpa flow rate of vapor, t/d
Recycled chilled water, t/d
Supplementary deoxygenation water, t/d
When the inlet temperature of the lean solution was less than 47 °C, the CO2 absorption rate was mainly governed by the temperature of the lean solution, while the MDEA-DEA mixed-amines solution had less effect on the H2S absorption rate.
The influence of the reboiler load on the acid gas load in the rich solution became smaller when the desorption of acid gas in the rich solution reached a certain level. For instance, after the reflux ratio of the condenser reached 0.8, absorption of acid gas became less significant, even though the reflux ratio continued to increase.
The selectivity of the amine solution decreased with the increasing number of trays and caused a substantial amount of CO2 to be absorbed. As a result, the flow rate of the wet purified gas dropped accordingly, causing a drop in the revenue of the apparatus and the sour gas quality in the regenerator unit.
The CO2 and H2S contents in the wet purified gas decreased with the increasing circulation rate of the lean solution. However, the CO2 absorption rate eventually decreased when the circulation rate of the lean solution exceeded a certain level (320 m3/h).
The CO2 content increased and the H2S content did not significantly change when the operating pressure of the regenerator unit increased. As a result, the quality of the sour gas was degraded. Therefore, the operating pressure should not be too high.
KH designed the research and gave the guideline. YTL and XHL performed the analysis and wrote the paper. CH reviewed the paper. All the authors read and approved the final manuscript.
The authors declare that they have no competing interests.
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