Improved performance of the Benfield-HiPure process using process simulation
Natural gas processing plants are an essential part of the energy industry, providing clean burning fuels and valuable chemical feedstock.
R Ochieng and A S Berrouk, Department of Chemical Engineering, Petroleum Institute
J Slagle, L G Lyddon and P E Krouskop, Bryan Research & Engineering, Inc
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The importance and complexity of gas processing plants have increased over the years, leading to improvements in energy efficiency and integration with petrochemical plants. These improvements are aided by the use of computer simulation models as tools for designing, troubleshooting, and optimising gas treating plants.
This work discusses the major optimisation techniques based on the Benfield HiPure process at Abu Dhabi Gas Liquefaction Company Limited (ADGAS) and the use of a process simulation tool, ProMax. At ADGAS’ Train 3 plant in Das Island, high pressure natural gas containing 6 to 7 mole % acid gas first comes into contact with a 30 wt% Potassium Carbonate (K2CO3) solution promoted with 3 wt% Diethanolamine (DEA). The gas is then contacted with a 20 wt% DEA solution downstream.
The results from the simulations show a close match with the plant operating data. The simulation model was then used to explore the effect of changes in process parameters on ADGAS’ plant performance.
Abu Dhabi Gas Liquefaction Ltd (ADGAS) Plant
ADGAS, a part of ADNOC (Abu Dhabi National Oil Company) group, is known for the production of Liquefied Natural Gas (LNG) since 1977. ADGAS operates three LNG Trains. The first two trains, (Trains 1 & 2) have been in operation since 1977, each with a capacity of 180 tons per hour of LNG. The third train (Train 3) was commissioned in 1994 and is capable of producing 380 tons per hour of LNG1.
The Train 3 gas sweetening plant is a “Benfield HiPure” design supplied by UOP, and is a hybrid arrangement of the basic Benfield and Amine units5.
Carbon dioxide and hydrogen sulphide removal from natural gas is a key step in the liquefied natural gas (LNG) process, in particular for sour gas streams containing significant concentrations of these acid gases. This plant is seeking sweet gas which contains no more than 5 ppmv and 50 ppmv of H2S and CO2, respectively1. Higher acid gas concentrations will directly affect the quality of LNG product and/or pose serious operational problems to the cryogenic columns. Failure to remove carbon dioxide can cause freeze-out on surfaces inside heat exchangers or plug lines which may lead to safety hazards and/or reduced operation efficiency. In presence of water, CO2 and H2S also form acids which cause corrosion of process equipment2-4. Therefore, removal of these contaminants is an operational necessity in any LNG producing plant.
The Benfield HiPure Process of ADGAS
The Benfield HiPure design was described in 1974 by Benson and Parrish5. It uses two independent but compatible circulating solutions to remove acid gases (H2S & CO2) from natural gas. In the first stage, the bulk of the acid gas is removed in a carbonate absorption system, where hot potassium carbonate promoted with diethanolamine (DEA) is employed as the solvent. In the second stage, the remaining acid gases are removed in an amine absorption system using DEA as the solvent. The DEA system provides the final trim removal of the acid gases to achieve the required sweet gas specification of less than 5 ppmv H2S and 50 ppmv CO2. The integrated schematic of the Benfield HiPure process is shown in Figure 1.
The hot potassium carbonate absorption system is comprised of a split flow absorber and a regenerator with no side draws. The carbonate absorber and regenerator are both tall vertical packed bed columns. The treated gas from the carbonate absorber is fed directly into the amine absorber.
The DEA amine system is comprised of an absorber and a stripper, both tall columns using a packed bed arrangement. After absorbing the acid gases, the rich solution from the absorber is pumped to the DEA regenerator. The regenerator has no condenser, and the overhead gas is fed to the middle of the carbonate regenerator, which does have a condenser. Liquid from the carbonate regenerator condenser is fed to the top of the DEA regenerator as reflux. The exit gas from the DEA absorber (sweet gas) is passed on for further processing to produce LNG. The stripped acid gases (H2S and CO2) from both the carbonate and DEA regenerators proceed to a sulphur recovery unit (SRU), where the acid gases are processed to produce molten liquid sulphur.
The feed gas to Train 3 is high pressure gas of about 52 bar (g) with an average H2S and CO2 content of about 2.2% and 4.7%, respectively. The sweetened gas produced by this plant is about 0.4 ppmv H2S and 19 ppmv CO2, which meets the required design specifications1.
Both the hot potassium carbonate and DEA absorbers operate at a pressure of about 50 bar(g) and the regenerators operate at lower pressures of about 0.8 bar(g). The necessary heat load for the regeneration is supplied through reboilers associated with each of the regenerators. Operating data and column internals are shown in Table 1 and Table 2.
Process optimisation through process simulation
Process optimisation is the ultimate goal of process simulation.
Simulation models help illuminate the bottlenecks in the processes and identify changes to help optimise plant performance. Process simulation can be described as a logical model for a chemical process that can be used to evaluate the process response for a given set of inputs. In a typical engineering process, process simulation provides the capability for the designer to understand the consequences of new design before the actual implementation of the process. This greatly minimises the risks associated with implementation of less than optimum designs. Simulations also enable prediction of process responses to proposed changes in process parameters for proposed improvement projects6, 7
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