FEED GAS OPTIMIZATION IN MOBILE UNIT FOR HIGH QUALITY NATURAL GAS LIQUIDS

Abstract

Optimized surface processing equipments based on the physical properties of natural gas mixtures. Designed an advanced correlation for separator based on terminal velocity on inlet and exit acid gas loadings that possibly improved the vapor quality and resident time for gas treating operations. Reduced BTEX emission based on acid gas loadings on the principle of vapor – liquid equilibrium which possibly allowed small percentage of acid gases to vent on the overhead column of flash tank. In pursuance of characterizing the natural gas mixtures based on their physical properties a new correlation for solubility and dynamic viscosities were developed. Additional stages of separation in surge tank might possibly improve the concentration and viscosity of circulated solvent which likely improve vapor pressure and prevent cavitation. The developed correlation improved the phase separation of dissolved hydrocarbons. RHV of natural gas mixture was improved in terms of quality (93-99%) under the pipeline specifications. FIG. 1

Specification

Description:FIELD OF INVENTION
Embodiments of the present disclosure relate to the field of natural gas processing and more particularly to a system and method to optimize feed composition of a natural gas. Based on the solid and liquids entrainment designed a new correlation for separator. Analyzed Recovered Heating Value based on the quality of natural gas liquids. Characterized natural gas mixtures based on the developed solubility & dynamic viscosity model.
BRIEF DESCRIPTION
[2] In accordance with an embodiment of the present disclosure, a system to optimize feed composition of a natural gas is provided. The system includes a vertical separator and principle separation of gas and liquids is achieved through mass flow, molecular weight and viscosity of natural gas liquids. The next phase of natural gas treating is to remove contaminants in saturated stream likely H2S, CO2 through continuous process to avoid corrosion and plugging problems in the cryogenic unit. Inlet composition in the sweetening unit has medium to higher fractions of acid gases loadings were processed through the continuous amine systems. Regardless of liquid rate, feed gas [100] entering the sweetening unit passed through the vertical separator for initial separation and enters to the absorber were mass transfer occurs from liquid phase to vapor phase and leaves the unit as sweet gas.The dehydrated gas stream is precooled in the refrigeration unit which comprised series of heat exchangers and mixers by maintaining hydrocarbon vapors at dew point temperature.
[3] To further clarify the advantages and features of the present disclosure, a more explicit description of the disclosure will follow by reference to specific embodiments thereof, which are illustrated in the appended figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[4] The feed composition [100] of natural gas is a mixture of hydrocarbons and non-hydrocarbon gases in which characterization depends on the physical properties such as specific gravity, density, viscosity, solubility, and compressibility factor.
[5] Fig: 1 Feed gas [100] optimization in the mobile unit.
[6] Fig.2 Dynamic viscosities of the natural gas mixtures.
[7] Fig. 3 Dynamic viscosities as a function of mole fractions based on inlet composition of the natural gas mixtures.
[8] Fig 4 Dynamic viscosities based on inlet compositions for cryogenic systems.
[9] Fig.5 Gas solubility as a function of mole fractions.
[10] Fig 6 Terminal settling velocity based on inlet and exit gas fractions.
[11] Fig 7 Recovered heating value based on natural gas compositions.
Detailed Description
3 Phase Separator (Mobile Unit) [200]
In order to improve the vapor quality and the residence time inlet composition (100) to the mobile unit of the designed 3 phase vertical separator based on terminal settling velocity is the function of drag force and inlet compositions.
Absorber [205]
The driving force on the absorber column is achieved by mass transfer between the lean amine and sour gas through countercurrent flow. The more volatile component based on the mole fractions of H2S, and CO2 mass transfer occurs from liquid phase to vapor phase and leaves the unit as sweet gas. The less volatile component in the contactor column from vapor to liquid leads in carryover of liquid reflux results in increase in liquid handling capacity in the flash tank.
Flash tank [210]

Rich amine exits the absorber column forced to the throttling valve under the principle of Joule Thomson effect for further phase separation. At higher acid gas (CO2 and H2S) loadings 5 to 10% venting to the surrounding leads to fatal to environment. Pressure difference in the flash tank [210] separates aqueous amine from high molecular weight hydrocarbons (C2 -C6) on the principle of vapor - liquid equilibrium which possibly allow small percentage of acid gases to vent on the overhead column of flash tank [210].
Lean Amine Rich amine Exchanger [215]
The efficiency of lean /rich amine heat exchanger improved by maintaining sensible heat which reduced the reboiler duty and cools the lean amine before circulating into the contactor.
Lean Amine surge tank [220]
High temperature lean amine with slow degradation rate exits from the regenerator bottoms were pre- cooled through the lean/ rich amine heat exchanger that enters the lean amine mixer with lower heats of reaction. With additional stages of separation in the surge tank [220] excess dissolved hydrocarbons such as entrained liquids might possibly improve the concentration and viscosity of circulated which likely increase the vapor pressure and prevent cavitation.
Lean Amine cooler [225]
Hot lean amine from the mixer was cooled before it enters the main amine pump. Decreasing the temperature below the operating condition of the amine treating unit results in higher liquid reflux such density difference causes decrease in efficiency of the centrifugal pump which results in partial removal of acid gases to 5 % CO2 in the sweetening unit.
Cold Box[230] and Demethanizer[235]
To prevent entrainment of liquids hydrocarbons (C1+) subcooled stream from the cold box [230] passed to the cold separators (LTS) where the additional vapors on the overhead column is compressed and expanded to the turbo expander unit. Isentropic efficiency of the compressor decreased due to the discharge pressure is the function of type of refrigerant fluid. Thus, decrease in efficiency of compressor results in secondary liquid reflux. The liquid reflux with heavier hydrocarbons enters the Demethanizer column [235] were partially condensed vapors recycled to the cold box and the accumulated liquids sent to the deethanizer column [240].
Deethanizer [240]
The heavier molecular weight hydrocarbons (C2+) enters into the deethanizer column [240] is a trayed tower heated and pressure reduced for stable operating conditions. Optimum reflux ratio is achieved by increasing the temperature of the column which improved the quality of recovered ethane up-to 97.05%.
Depropanizer[245]
Optimization of natural gas liquids was improved by-passing the C3+ liquid hydrocarbons to the depropanizerr column [245] were pressure reduced which reduced the molar flow of C3+ mixtures. Further temperature in the fractionators increased which decreased the visocisty of fluids and increased the quality of recovered propane to 96.09%.

Debutanizer [250]
The end product of natural gas liquids such as C4+ liquid hydrocarbons were forced into debutanizer column [250]`. Bottom products rich in C4+ enters into the regenerator column in which quality of natural gasoline (n-butane and i -butane) recovered up to 23.77 % and 72.25%.

Methods

The feed composition [100] of natural gas is a mixture of hydrocarbons and non-hydrocarbon gases in which characterization depends on the physical properties such as specific gravity, density, viscosity, solubility, and compressibility factor.

[12] Viscosity
The viscosity of saturated gas stream is predicted based on the inlet compositions shown in Equation A to H
[13] At static conditions:
Viscosity of water (µ) at specific temperature
μ_o=φ*μ A
μ_corrected=μ-μ_o B
[14] In presence of acid gases
CO_2=WtfractionCO_2*μ_corrected C
H_2 S=WtfractionH_2 S*μ_corrected D
〖Corrected acid gas µ=μ〗_(co_2+) μH_2 s E

[15] In presence of water > 4 lbm/ MMscf
H_2 O=WtfractionH_2 O*μ_corrected F
[16] At dynamic conditions,
X=3.5+986/T+0.01M_w
Y=2.4-0.2X
K=((9.4+0.02 M_w ) T^1.5)/(209+19M_w+T)
μ_(g _Initial)={[〖 10〗^(-4) Kexp[X(ρ_g/62.4)^Y ]]}*δ G
μ_(g_Sweetening)=[μ_(g_Initial )+〖(μ〗_(〖CO〗_2 〖+H〗_2 S))]
μ_(g_Dehydration)=[μ_(g_(Sweetening Endpoint) )+μ_(H_2 O__ Staticcondition))]
μ_(g Dynamic )= μ_(g_Initial )+〖(μ〗_(〖CO〗_2 〖+H〗_2 S))+μ_(H_2 O__ Staticcondition))
〖μ_g〗_(ColdBox Dynamic Cryogenic)=〖μ_g〗_(Dynamic End Point)-〖n_1 μ〗_(g Dynamic )
〖μ_g〗_(Demethanizer Dynamic Cryogenic)=〖μ_g〗_(Dynamic End Point)- 〖n_∞ μ〗_(g Dynamic )+〖n_∞ μ_g〗_(Coldbox End point)

FIG. 2 [6] is graphical representations depicting saturated gas stream based on inlet composition of the natural gas at dynamic conditions. In accordance with an embodiment of the present disclosure the viscosity of saturated gas stream is predicted at dynamic conditions based on the inlet compositions of the natural gas.

FIG. 3 [7] illustrates the dynamic viscosity (μ, in centipoise) of different mole fractions of components at various stages in the system The Y-axis represents the dynamic viscosity values in centipoise, ranging from 0.039 to 0.035. The X-axis labels different chemical components or substances by their common chemical notation: C1, C2, iC4, nC4, iC5, nC5, C6, H2O, H2S, CO2. It is observed in FIG 3 [7] that C1 and C2 mole fractions have higher dynamic viscosity values compared to others, reaching up to around 0.039 cp. There is a sharp decrease in dynamic viscosity from C1 to C2, and then it remains low for the rest of the components. For components from iC4 onwards, the dynamic viscosity values are relatively low and consistent, ranging between therefore, it can be seen that C1 and C2 have significantly higher viscosities, indicating they contribute more to the overall viscosity of the fluid in the system. The viscosity measurements across different stages show minimal variation for most components, suggesting the process maintains a stable viscosity for these substances.

Solubility [17]
Phase separation of the dissolved hydrocarbons improved in the regenerator formulated on the solubility of natural gas which is the function of pressure and temperature and mol fractions of natural gas mixtures shown in equation I. Phase separation of gas stream increased until it reached the maximum saturation pressure by maintaining the proper solvent strength which prevents degradation and pressure buildup in the regenerator column. The solubility [17] of individual component of the natural gas mixtures ranges from the Absorber (Unit 1) 3.73 Scf/STB to cooler (unit 5) 1.8753 Scf/STB about 50.15% phase separation due higher molecular weight hydrocarbons and presence of acid gases in the natural gas mixtures.

(PM_w)/ZRT*δ(C_1-C_6,CO_2,H_2 S,H_2 O….) I
FIG. 5 [9] graphical representations depicting phase separation of dissolved hydrocarbons, in accordance with an embodiment of the present disclosure. The phase separation of the dissolved hydrocarbons improved in the regenerator by maintaining proper solvent strength with prevents degradation and pressure buildup in the regenerator column.
Principle of Separation [18]
In order to improve the vapor quality and the residence time this study designed the vertical separator based on terminal settling velocity and calculated from equation J to K which is the function of drag force and inlet compositions.
Vt= √(M*M_w*μ*0.02 ) J
Where, M= Mass Flow (lb/s)
Mw= Molecular Weight (lb/lbmol)
For acid gas enrichment [19]
Vt=√((M*M_w*μ*0.02)/(Inletacidgas-Exitacidgas)) K

Recovered Heating Value [20]
In order to determine the recovered heating value based on the natural gas composition and quality (93 % to 99%), low and high heating values were estimated ranges from (1006.97 (C1) to 2341.23 Btu/scf (C3) shown in figure 7 [11].Water content of wet natural gas is determined to improve the heating value and sales gas specifications.
RHV based on heating values [21]:

RHV=HHV*ϑ L
, Claims:1. Feed Gas (100) to optimize composition of a natural gas mixtures comprising:
Feed Gas [100] Optimization in mobile unit [200] for High Quality Natural Gas Liquids.
The viscosity of liquid water at static condition [13] is calculated based on the mole fraction at pre-determined temperature.
Corrected viscosity of water vapour based on deduction based on viscosity of liquid water at predetermined temperature and viscosity of liquid water at static condition.
In presence of acid gases [14] CO2 and H2S at static condition, is the product of corrected viscosity weight fraction of CO2 and weight fraction of H2S.
In addition viscosity of corrected acid gases is the summation of weight fraction CO2and weight fraction of H2S.
In presence of water [15] greater than 4 lbm / MMscf is the product of weight fraction of water and corrected viscosity.
At dynamic condition [16] initial viscosity of natural gas based on empirical correlation, gas density and mole fractions.
The viscosity of sweet natural gas is the summation of dynamic condition of initial viscosity and corrected acid gasses.
The viscosity of dehydrated natural gas is the summation of sweetening end point and viscosity of water vapor at dynamic condition.
The dynamic viscosity of natural gas mixtures is the summation of initial viscosity, corrected acid gases and viscosity of water vapour at dynamic condition.
The cryogenic viscosity [16] of cold box is the end point of dehydrated viscosity of natural gas mixtures in deduction of dynamic viscosity of natural gas mixtures.
The viscosity of demethanizer is the sum of end point of dehydrated viscosity of natural gas mixtures, cold box end point and deduction of dynamic viscosity of natural gas mixtures.
The gas solubility [17] of the natural gas calculated mixture based on ratio of pressure and molecular weight to the compressibility factor, gas constant, temperature to the product of mole fractions.
The terminal velocity [18] of the gas mixtures calculated based on empirical correlation which is square root of 0.02, mass flow and molecular weight, viscosity of natural gas mixture.
In presence of acid gases [19], H2S, CO2 the terminal velocity calculated based on empirical correlation which is ratio of square root of 0.02, mass flow and molecular weight, viscosity of natural gas mixture to the Inlet acid gas and exit acid gas, where in the presence of the acid gas causes a gradual decrease in the viscosity of the natural gas.
Recovered Heating value [21] of the natural gas mixtures calculated based on Higher Heating value to the product of recovered quality of the natural gas mixtures.
Additional stages of separation in the surge tank [220] excess dissolved hydrocarbons such as entrained liquids might possibly improve the concentration and viscosity of circulated which likely increase the vapor pressure and prevent cavitation.
At higher acid gas (CO2 and H2S) loadings 5 to 10% venting to the surrounding leads to fatal to environment.
Pressure difference in the flash tank [210] separates aqueous amine from high molecular weight hydrocarbons (C2 -C6) on the principle of vapor - liquid equilibrium which possibly allow small percentage of acid gases to vent on the overhead column of flash tank [210].


Nomenclature
ρg Gas Density (lbm/ft3)
Mw Molecular Weight (lb/lbmol)
T Temperature (֯R)
µg Gas viscosity, Cp
Rs Solubility (scf/STB)
P Pressure (psia)
Vt Terminal Settling Velocity (ft/s)
M Mass Flow lb/s
LHV Lower Heating Value (Btu/scf)
HHV Higher Heating Value. (Btu/scf)
RHV Recovered Heating Value(Btu/scf)
Dated this 15th day of November 2024
Signature

Prakriti Bhattacharya
Patent Agent (IN/PA-5178)
Agent for the Applicant

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