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MODELING AND SIMULATION OF HYDROGEN SULFIDE REMOVAL FROM PETROLEUM PRODUCTION LINES BY CHEMICAL SCAVENGERS a
b
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Krishnaswamy Rajagopal , Rogério Lacerda , Ivan Slobodcicov & Eugenio Campagnolo
c
a
Laboratório de Termodinâmica e Cinética Aplicada (LATCA), Escola de Química, Universidade Federal do Rio de Janeiro , Rio de Janeiro, Brazil b
Departamento de Engenharia Química e do Petróleo , Escola de Engenharia, Universidade Federal Fluminense , Niterói, Brazil c
Centro de Pesquisa e Desenvolvimento (CENPES), Tecnologia de Recuperação e Análises de Reservatórios e de Elevação e Escoamento, PETROBRAS , Rio de Janeiro, Brazil Published online: 12 May 2009.
To cite this article: Krishnaswamy Rajagopal , Rogério Lacerda , Ivan Slobodcicov & Eugenio Campagnolo (2009) MODELING AND SIMULATION OF HYDROGEN SULFIDE REMOVAL FROM PETROLEUM PRODUCTION LINES BY CHEMICAL SCAVENGERS, Chemical Engineering Communications, 196:10, 1237-1248, DOI: 10.1080/00986440902832100 To link to this article: http://dx.doi.org/10.1080/00986440902832100
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Chem. Eng. Comm., 196:1237–1248, 2009 Copyright # Taylor & Francis Group, LLC ISSN: 0098-6445 print=1563-5201 online DOI: 10.1080/00986440902832100
Modeling and Simulation of Hydrogen Sulfide Removal from Petroleum Production Lines by Chemical Scavengers KRISHNASWAMY RAJAGOPAL,1 ROGE´RIO LACERDA,2 IVAN SLOBODCICOV,3 AND EUGENIO CAMPAGNOLO3
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1
Laborat orio de Termodinaˆmica e Cine´tica Aplicada (LATCA), Escola de Quı´mica, Universidade Federal do Rio de Janeiro, Rio de Janeiro, Brazil 2 Departamento de Engenharia Quı´mica e do Petr oleo, Escola de Engenharia, Universidade Federal Fluminense, Niter oi, Brazil 3 Centro de Pesquisa e Desenvolvimento (CENPES), Tecnologia de Recuperac¸a˜o e An alises de Reservat orios e de Elevac¸a˜o e Escoamento, PETROBRAS, Rio de Janeiro, Brazil The in-line scavenging of hydrogen sulfide is the preferred method for minimizing the corrosion and operational risks in offshore oil production. We model hydrogen sulfide removal from multiphase produced fluids prior to phase separation and processing by injection of triazine solution into their gas phase. Using a kinetic model and multiphase simulator, the flow regimes, amounts, and composition of three phases are determined along the horizontal and vertical flow path from subsea well to separator tank. The flow regimes were found to be slug flow or intermittent flow. The highly reactive triazine is destroyed on contact with water phase flowing near the wall. We have simulated the hydrogen sulfide concentration profiles for different amounts of gas injection. The results are compatible with the available field data from an offshore oil well and are useful in determining the injection rates of expensive chemical scavengers and optimal gas injection rates. Keywords Hydrogen sulfide removal; Gas lift injection; Multiphase flow reactor; Sour oil production; Triazine scavenger solution
Introduction In several petroleum reservoirs, the concentration of hydrogen sulfide (H2S) has been observed to increase unexpectedly in gaseous, oil, and aqueous phases of produced fluids. This concentration is typically measured in parts per million by volume (ppmv) in the gas phase relative to a partition from oil and an aqueous phase with a pH equal to or less than 5 at standard temperature and pressure (STP), of 20 C and 1 atm absolute pressure. When the concentration of H2S exceeds 3 ppmv in the gas Address correspondence to Krishnaswamy Rajagopal, Laborat orio de Termodinaˆmica e Cine´tica Aplicada (LATCA), Escola de Quı´mica, Universidade Federal do Rio de Janeiro, Av. Horacio Macedo, 2030. Ed. do Centro de Tecnologia, Bloco E – sala 209, C.P. 68502, Cidade Universitaria, CEP 21949-900, Rio de Janeiro – RJ, Brazil. E-mail:
[email protected]
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phase, the oil well is deemed to be sour, and precautions are necessary in design and operation of production, transport, and storage equipment due to H2S toxicity, corrosion, plugging of reservoir formations, and increased sulfur content of produced oil. Some oil fields in the North Sea and Campos Basin (Brazil) have turned sour after a few years of injection of seawater for improved recovery of oil (Eden et al., 1993). Many studies have attributed this souring to the activity of sulfate-reducing bacteria and resultant production of biogenic H2S, except in a few cases of very high pressure reservoirs where there is evidence for a geochemcial mechanism as well (Farquhar, 1998). Many production facilities were unfortunately previously designed and built without considering the effect of these organisms on their operation and maintenance. From the experience of North Sea oil fields, we can expect about 10% of the oil wells to suffer from increased corrosion of tubing, casing, and production facilities, iron sulfide deposition, and injection and wellbore plugging, as well as safety, health, and environmental concerns during the economic production life of the field. The souring of petroleum reservoirs caused mainly by sulfate-reducing bacteria can increase the concentration of hydrogen sulfide in produced fluids to the point of making it necessary to inject expensive chemical scavengers in production pipelines so that the corrosion and operational risks can be minimized. In-line scavenging of hydrogen sulfide is the preferred method for production of crude oil containing low hydrogen sulfide levels from subsea wells, especially where the well is tied back via a flowline to a host facility at which there is no provision for H2S scavenging and=or where a H2S removal facility is too expensive and=or impractical to install (Nagl, 2001). As a result of this method, the hydrogen sulfide content of the crude oil that is delivered to the platform is reduced to safe and commercially acceptable levels and reaction by-product formation is manageable. The formation water provides a carrier phase for some of the reaction products and enhances the dispersion of some insoluble reaction products in the coproduced aqueous phase. We model this chemical process using available field data so that the cost of removal of hydrogen sulfide (H2S) can be reduced by determining optimal gas injection rates as well as the rate of injection of chemical scavengers in production lines. The proposed methodology is also useful in selecting alternative scavengers. In the literature, models have been proposed for treating single-phase natural gas with liquid scavengers (Fisher et al., 2003). There is little information about in situ removal of hydrogen sulfide from multiphase streams.
Chemical System The chemical system considered is a subsea flowline connecting a mature subsea oil well to an offshore production facility, schematically shown in Figure 1. The reservoir fluids, namely, formation water, crude oil, and its associated gas, flow into production lines at point 13. The oil phase is initially above the bubble point pressure, and the gas lift process is used to transport and lift the reservoir fluids from the well to the production platform. The widely used liquid chemical scavenger 1,3,5-tris (2-hydroxyethyl)-1,3,5-triazinane (‘‘triazine’’) is atomized into the lift gas pipeline and the mist is homogenized by flow. Then the lift gas with the scavenger mist is continuously injected into the production line through a mandrel after segment 8. The scavenger droplets disperse through the produced fluid substantially homogeneously because of the natural turbulence of the fluid flow. As the pressure
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Figure 1. Flow path and flow regimes of the chemical system.
drops below the bubble point, a gas phase containing part of the H2S is formed. The droplets of triazine injected into the gas phase decompose H2S by the nucleophilic substitution of sulfur into the triazine ring, and the droplets encountering water phase are rapidly hydrolyzed in a competing reaction. The reactions take place in the multiphase flow along the flowline. The reaction products disperse in the liquid phase. The lift gas is recovered from the oil at a separation stage and is reused. The geometry of chemical system is shown in Table I.
Simulation of the Chemical System The chemical system considered corresponds to an existing offshore oil well in the Campos Basin of Brazil, which has turned sour after injection of seawater for several years. Besides design data, the available field data are flow rates of reservoir fluids: 839 m3=day of oil, 1,300 m3=day of water, and 79,000 m3=day of free gas for a lift gas injection rate of 171,552 m3=day. All flow rates cited in this work are in STP m3 per day (at standard temperature and pressure of 293.15 K and 101325 Pa) per day. The concentration of H2S in the separator reduced from 450 to 10 ppmv after injection of 2.4 STP m3=d of a commercial chemical scavenger, triazine. The system is modeled using available data along with several physical properties measured for the purpose of this study (Table IIA). The simulation is done in three steps: (1) multiphase simulation to determine the pressure, temperature, velocity of each phase, liquid holdup, and flow rates of each phase, (2) estimating the phase distribution of hydrogen sulfide from total amount or from gas phase concentration, and (3) estimating
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Subsea line
Subsea line
3
4
Well=column Well=column Well=column Well=column Lift gas injection Well=column Well=column
Well=column Well=column
Well=column
9 10
11 12
13
5 6 7 8
Subsea line Subsea line
Flow line
1 2
Segment no.
194
50 53
18.4 482.6 544 250 N.A. 222.7 358
80
1200
790 150
Length [m]
4.88
3.94 4.88
3.95 4.88 4.88 4.88 4.88 4.88 4.88
4.00
6.00
6.00 6.00
Tube diameter [inch]
8.681
8.681 8.681
8.681 8.681 8.681 8.681 8.681 8.681 8.681
0
0
0 0
Lining diameter [inch]
11.5
31.6 27.3
90 90 69.6 59.2 58.8 58.8 54.2
2.3
2.3
90 2.3
Angle= horizontal [deg]
70.0
69.1 70.0
4.7 22.1 40.5 48.2 57.7 57.7 68.2
4.0
4.0
25.0 4.0
Ambient temperature [ C]
Orkiszewski (1967) Beggs and Brill (1973); Palmer (1975) Beggs and Brill (1973); Palmer (1975)
Duns and Ros (1963) Beggs and Brill (1973); Palmer (1975) Beggs and Brill (1973); Palmer (1975) Beggs and Brill (1973); Palmer (1975) Orkiszewski (1967) Orkiszewski (1967) Orkiszewski (1967) Orkiszewski (1967) Orkiszewski (1967) Orkiszewski (1967) Orkiszewski (1967)
Correlation used
Liquid
Slug Slug Slug Slug Bubble Bubble Bubble= liquid Liquid Liquid
Intermittent
Intermittent
Slug Intermittent
Predicted flow regime for 40–600% gas lift
Table I. Segments of flow path from offshore platform to subsea well, empirical correlations used for multiphase flow, predicted flow regime in each segment for different injection rates of lift gas
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Table IIA. Measured properties of the fluids Reservoir fluids
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Property Density of formation gas Density of lift gas Density of produced gas Gas-oil ratio
Scavenger solution
Value
Surface Temperature Viscosity Density Temperature tension C cP g=cm3 C mN=m
0.710 (air ¼ 1.0)
10
160.88
1.0319
—
—
0.640 (air ¼ 1.0) 0.660 (air ¼ 1.0)
20
86.23
1.0246
19.9
30.04
30
49.41
1.0172
30.4
29.12
40
30.03
1.0097
40.8
28.34
50
19.25
1.0021
50.0
27.9
60
12.93
0.9943
60.5
27.05
70
9.03
0.9864
—
—
80
6.51
0.9782
—
—
90
4.82
0.9698
—
—
86.0 (m3=m3) 0.935 (water ¼ 1.0) 218.70 (cP)
Density of oil Viscosity of oil at 30 C Viscosity 69.36 (cP) of oil at 50 C Wax appearance 20.0 ( C) temperature Density of 1.030 formation (water ¼ 1.0) water
scavenging reaction rates and gas phase concentration of hydrogen sulfide along the flow path. The proposed methodology is described below for each of the steps. Multiphase Flow Simulation The flow in the production tubes was simulated using in-house software. The following three components of pressure drop along a flow path were considered: hydrostatic head, velocity head, and frictional loss. Frictional loss occurs both between the fluid and the pipe and between the phases. The flow rates and properties of the phases determine the physical arrangement of the fluid, and this arrangement determines the pressure drop. The conceptual model was developed according to the data available and the basic assumptions on multiphase fluid hydrodynamics outlined above. All the main features of the production line were represented in the simulator environment in order to perform the calculations. The simulation model was applied to predict the flow regime and pressure drop along the production line from the reservoir up to the platform.
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For the purpose of simulation, the flowline from surface to reservoir was divided into 13 segments based on the inclination and location, whether the line is located under the seabed or not. Suitable empirical correlations were used to determine the flow regime and pressure drop along the tubes. The pressure drop due to fittings and valves was included by manufacturer’s specifications. Each segment was divided in to sub-segments for calculating pressure drop and heat transfer more precisely. Table I also shows the empirical multiphase correlation used and the predicted flow regime in different segments for a range of injected lift gases. Figure 1 shows the evolution of the flow regimes along the line. Between the reservoir and the point of the gas lift injection the flow regime goes from liquid phase to bubbling flow, and after the gas lift injection up to the platform the flow regime is slug. The heavier water phase flows generally as an annulus near the wall. The temperature, pressure, and flow rates of oil, water, and gas phases were determined along the flow path by this simulation for different gas lift rates, ranging from 40% to 600% of field flow rate. Estimation of Phase Distribution of H2S From the available literature data (Eden et al., 1993) we developed a correlation to estimate the equilibrium constant of hydrogen sulfide between oil and water phases (K oil=water) from temperature, pressure, and gas-oil ratio. The equilibrium Henry’s constant KH2S for the gas=oil phases and for gas=water phases was correlated with temperature at low pressures. The correlation is shown in Figure 2. In this condition, the equilibrium constants are independent of composition and pressure and the distribution coefficient K oil=water is calculated at each temperature (Figure 3). The salt concentration of the particular case under study was similar to that in the literature data used. If the compositions of the phases are very different from the literature case, it is advisable to determine the equilibrium constant by experiment. The thermodynamic equilibrium of oil, water, and gas phases was calculated using the Sour Peng-Robinson (Sour PR) model. This model combines the Peng-Robinson equation of state and Wilson’s API-Sour Model for handling sour water systems and can be applied to sour water processes containing hydrocarbons, acid gases, and H2O. The method uses Wilson’s model to account for the ionization of the H2S,
Figure 2. Linear correlations for equilibrium constants of oil and formation water.
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CO2, and NH3 in the aqueous water phase. The fugacities of the vapor and liquid hydrocarbon phases as well as the enthalpy for all three phases were calculated using this equation of state. The K-values for the aqueous phase were calculated using Wilson’s API-Sour method (American Petroleum Institute, 1978). The Pressure-Volume-Temperature (PVT) tests were done to determine the reservoir fluid composition and physical properties like dissolved gas content and residual oil density. The liberated gas and residual oil compositions were obtained by gas chromatography. The H2S concentration was determined by spectroscopy. The oil phase is considered as a semi-continuous mixture with components and fractions based on normal boiling point. The fractions and the residue are considered as pseudo-components. The binary interaction parameters are obtained by tuning with PVT tests. Table IIB shows the reservoir fluid composition and physical properties obtained from the PVT analysis. The pressure variation along the tube was calculated using the Peng-Robinson equation of state, considering the composition of the fluids without hydrogen sulfide. Estimation of Reaction Rates Buhaug (2002) reported the kinetics of triazine liquid reacting with gaseous hydrogen sulfide and buffered water solution. In the scavenging reaction, the concentration variation of triazine in contact with hydrogen sulfide gas was determined by isotopic nuclear magnetic resonance (NMR) studies and the rate was determined to be first order in hydrogen sulfide concentration: d½T=dt ¼ ka ½THþ½HS
ð1Þ
for pH > 10
with ka ¼ 9.1 107 Ka [mol 2 * s] where Ka is the acid constant of triazine in solution. The author has also concluded that the reaction will be first order and fast for pH < 10. The reported kinetic constants may, however, have large errors, Table IIB. Reservoir fluid composition Component H 2S Methane CO2 Nitrogen Ethane Propane i-Butane n-Butane i-Pentane n-Pentane
Mole fraction
Pseudo-component
Mole fraction
70 ppm 0.449 0.000 0.003 0.031 0.018 0.005 0.025 0.004 0.005
C6 fraction C7 fraction C8 fraction C9 fraction C10 fraction C11 fraction C12 fraction C13 fraction C14 fraction C15 fraction C16 fraction C17 fraction C18 fraction C19þ residue
0.015 0.022 0.041 0.043 0.040 0.039 0.037 0.045 0.038 0.040 0.031 0.027 0.025 0.018
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especially if extrapolated to low pH values. The triazine is rapidly hydrolyzed on contact with water with reported kinetics of
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d½T=dt ¼ kH ½T½H for pH < 10
ð2Þ
with kH ¼ 1.42 106 s1 at 22 C and 3.40 108 s1 at 60 C. The hydrolysis will be almost instantaneous for pH values of 5 or below. We model the kinetics of hydrogen sulfide removal by triazine injection with the following considerations. The triazine solution is atomized into gas stream in nearly uniform droplets about 10 mm diameter. The smaller and larger droplets have small survival times. A computational fluid dynamics (CFD) simulation of the flow supports this consideration. The highly reactive triazine in the droplets will be destroyed almost instantly on contact with water phase flowing near the wall. The rate of removal of hydrogen sulfide is limited by the rate of mass transfer of H2S from the gas phase to scavenger solution droplets. The oil, water, and gas phases are in thermodynamic equilibrium along the flow path. The rate of removal of H2S is estimated using a model that combines mass transfer resistance and reaction. Fisher et al. (2003) have used this model for natural gas treatment. The amount transferred is estimated using the rate equation: dyH2 S KG aPyH2 S ¼ dz G
ð3Þ
where yH2S is mole fraction of H2S in the gas phase; G is molar gas velocity, mol=m2s; Z is tube length, m; KG is overall mass transfer coefficient, mol=m2 s bar; a is interfacial area, m2=m3; and P is pressure, bar. The pressure and molar gas velocity will vary along the path. We have estimated the rate constant (KGa) using the field data of H2S concentration with and without injection of scavenger solution for same rate of lift gas injection and flow rates in the
Figure 3. Equilibrium constant K oil=water for hydrogen sulfide at low pressures (unassociated hydrogen sulfide and formation water with pH ¼ 5).
Modeling H2S Removal by Scavengers
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offshore oil well under study. The H2S concentration at the entrance was obtained by mass balance at steady-state operation of the well without injecting triazine. KGa was determined from the measured operational concentration of H2S while injecting a known rate of triazine solution with known lift gas rate.
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Results and Conclusions The chemical system was simulated using the above methodology for different lift gas injection rates with and without scavenger solution. For the case of normal gas lift operation injecting 171,552 STP m3=day (100% gas lift) without scavenger solution, the temperature and pressure profiles are shown in Figure 4. The flow rates of different phases are shown in Figure 5. The flow regimes were found to be generally slug flow or intermittent flow. The amounts and concentration of hydrogen sulfide are shown in Figures 6 and 7. The simulated value of 448 ppmv compares well with the measured value of 450 ppmv in the separator. The hydrogen sulfide concentration profile for the case of production without lift gas and without scavenger solution is shown in Figure 8. The simulated concentration is 1635 ppmv. The production was shut down in the field when the concentration exceeded 1000 ppmv. Figure 8 also shows the hydrogen sulfide concentration profile for the case of injection of 1 million STP m3=day (582.9% gas lift). The simulated value is 108 ppmv in the separator compared to the expected value of about 100 ppmv. The normal gas lift operation (100% gas lift) with injection of 2.4 m3=day of liquid triazine was simulated. The hydrogen sulfide concentration profile is shown in Figure 8. The methodology effectively correlates the measured concentration of 10 ppmv at the separator. The rate constants were re-estimated considering that the rate
Figure 4. Pressure and temperature profile along the flow path (gas lift of 171,552 STP m3=day without scavenger solution).
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Figure 5. Flow rates of gas, oil, and water phases (gas lift of 171,552 STP m3=day without scavenger solution).
constant proportionately varies with the square root of absolute temperature. The effect on the profile was negligible. In all cases studied, the proposed model and methodology of simulation were found to be effective in simulating the chemical system. The simulation studies indicate the need for better atomization so that the gas phase concentration of
Figure 6. Distribution of hydrogen sulfide among the three phases (gas lift of 171,552 STP m3=day without scavenger solution).
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Figure 7. Concentration of hydrogen sulfide in the three phases (gas lift of 171,552 STP m3=day without scavenger solution).
H2S can be reduced to acceptable levels immediately after the Christmas tree, as the pipelines were of less noble material with little resistance to corrosion by H2S. The proposed methodology can be readily used for evaluating any scavenger with known kinetics. The accuracy of simulation can be improved by using measured distribution coefficients of H2S between the oil, water, and gas phases.
Figure 8. Comparison of concentration of hydrogen sulfide in the gas phase with and without injection of scavenger solution. Case 1, without injection of lift gas and scavenger solution, ~; case 2, with injection of lift gas of 171,552 STP m3=day without scavenger solution, ; case 3, with injection of lift gas of 1,000,000 STP m3=day without scavenger solution, ; case 4, with injection of lift gas of 171,552 STP m3=day and 2.4 m3=day of triazine, —.
.
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Acknowledgments The authors acknowledge the financial support of CENPES-PETROBRAS and of MCT=FINEP=CTPETRO=PETROBRAS under the project number: FBR 2528-06, ´ gua ´ leos Pesados, Gas Liberado e a A entitled, ‘‘Distribuic¸a˜o do G as Sulfı´drico entre O de Formac¸a˜o nas Condic¸o˜es de Reservat orio.’’ The authors thank CNPq for the scholarship ‘‘Bolsa de produtividade’’ to Krishnaswamy Rajagopal and FINEP= CNPq for DTI scholarships to Ian Hovell and Luis Augusto Medeiros Rutledge for making several experimental property measurements.
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References American Petroleum Institute. (1978). A New Correlation of NH3, CO2, and H2S Volatility Data from Aqueous Sour Water Systems, American Petroleum Institute, Washington, D.C. Beggs, H. D. and Brill, J. P. (1973). The study of two-phase flow in inclined pipes, J. Pet. Technol., 255, 607. Buhaug, J. B. (2002). Investigation of the chemistry of liquid H2S scavengers, Ph.D. diss., Norwegian University of Science and Technology, Faculty of Natural Sciences and Technology. Duns, H. and Ros, N. C. J. (1963). Vertical flow of gas and liquid mixtures from boreholes, paper 22–106, presented at the Sixth World Petroleum Congress, Frankfurt, 19–26 June. Eden, B., Laycock, P. J., and Fielder, M. (1993). Oil Field Souring, HSE Books, Liverpool. Farquhar, G. B. (1998). Review and update of technology related to formation souring, Corros. Prev. Contr., 45(2), 51–56. Fisher, K. S., Leppin, D., Palla, R., and Jamal, A. (2003). Process engineering for natural gas treatment using direct-injection H2S scavengers, GasTIPS, 9(2), 12–17. Nagl, G. J. (2001). Removing H2S from gas streams: Four leading technologies are compared here, Chem. Eng., 108(7), 97–100. Orkiszewski, J. (1967). Predicting two-phase flow pressure drops in vertical pipes, J. Pet. Technol., 19, 829–838. Palmer, C. M. (1975). Evaluation of inclined pipe two-phase liquid holdup correlations using experimental data, MS thesis, The University of Tulsa, Tulsa, OK, Department of Petroleum Engineering.
