BASIC PROCESS ENGINEERING MANUAL
DESIGN TEAM PROCESS DESIGN SECTION
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BASIC PROCESS ENGINEERING MANUAL CONTENTS 1.0
INTRODUCTION
2.0
TYPICAL GC CONFIGURATION & DESCRIPTION
3.0
FLUID FLOW
3.1
SINGLE PHASE FLOW LIQUIDS GASES
3.2
MULTIPHASE FLOW
4.0
SEPARATORS
4.1 4.2
SEPARATORS –2 PHASE SEPARATORS --3 PHASE
4.3
TANKS
5.0
PUMPS CENTRIFUGAL OTHER TYPES
6.0
COMPRESSORS CENTRIFUGAL OTHER TYPES
7.0
FLARE STACKS
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1.0 INTRODUCTION This Manual is intended primarily to help design engineers and others to understand KOC's operations and connected process engineering work that they will be called upon to perform during the course of their work. Description of theoretical background is kept to minimum. The presentation is oriented towards topics relevant to KOC. Calculation methods and equations are presented directly. Interested readers are requested to refer to the appropriate books to gain understanding of the theoretical basis of the equations. Primary sources from where the equations are taken are listed in the References list included at the end. Readers are encouraged to refer to the same. A flow schematic of a typical GC is given in the next page. It is hoped that the manual will be useful in day to day work.
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{ SHAPE \* MERGEFORMAT }
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2.0 DESCRIPTION The description provided here is that of a typical Gathering Center (GC). This provides a simple introduction to the GC for the purpose of familiarization. The GC facilities include: Incoming flowlines, headers manifolds High Pressure (HP) /Low Pressure (LP) Separators Wet, Dry and Test Tanks Desalter /Dehydration Trains Condensate Recovery Units (CRU) Transit Pumps Gas Scrubbers High Pressure / Low pressure gas and Tank Vapor systems Chemical Injection system Instrument Air System Fire water system Brackish Water system Flares Electrical System Instrumentation and Control Systems With reference to the typical configuration the following main processing steps take place in the GC. The incoming crude is flashed in the HP Separators at about 260 psig and in LP Separators at 60 psig and then the crude is routed to the Tanks. The gases from the HP / LP Separators are sent to Booster Stations (BS) for further compression. Tank Vapors are compressed in the CRU to produce condensate and CRU off gas. Condensate is dispatched to the refineries. CRU off gas is routed to the HP system. The HP/LP gas systems are provided with pressure control valves to route the excess gases to the HP/LP Flares when Booster Stations are shutdown or partially available. The wet crude from the Wet Tank is fed by pumps to the Desalter/ Dehydration trains to produce crude of quality of less than 0.10% Basic Sediment & Water (BS&W) and 10 Pounds per Thousand Barrels (PTB) of salt. (In newer GCs the requirement is 5 PTB). The Desalter/ Dehydration trains achieve the product quality by removing salt and water through application of the following: Heating Electrostatic field-2 Stages Mixing with fresh Brackish water (Wash water) Demulsifier Chemicals Settling time A typical Desalter Train consists of crude / crude heat exchanger, crude preheater, Desalter 1 and 2 stages and the wash water circuit- which includes wash water pumps and wash water heat exchangers. The train has its own chemical injection systems for injecting demulsifier, scale inhibitor, corrosion inhibitor in to crude oil and oxygen scavenger and biocide in to wash water.
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The product crude (Dry Crude) from the Desalter/ Dehydration trains is then sent to dry tanks. The dry crude from dry separator train is routed directly to dry tank. Transit Pumps dispatch dry crude to tank farms through the crude transit network. The wet tank provides a large settling time for the oil water separation. Effluent water from the wet tank is disposed off in the water disposal wells by injection or send to disposal pits for natural evaporation.
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3.0 FLUID FLOW 3.1 SINGLE PHASE FLOW-LIQUIDS All flows take place due to pressure difference between the starting point and end point i.e. without pressure difference there cannot be any flow. Basic flow equations are derived from equation of continuity and Bernouli’s equation. BASIC EQUATIONS Flow through closed pipes are classified as laminar, transition and turbulent depending on the dimensionless Reynolds Number denoted as NRe. NRe < 2300 Laminar Flow NRe > 2300 but less than 4000 Transition Flow NRe > 4000 Turbulent Flow D=pipe id V=Fluid velocity ρ=Fluid density µ=Fluid viscosity
---------------3.1
NRe = dVρ µ
In consistent units!
In general, in-plant piping is designed for turbulent flow except gravity drain lines, which could be in laminar flow. Transitional flow is usually avoided. Basic design equations are: Velocity of fluid in pipe Velocity V= Fluid flow rate Cross Sectional area of Pipe For V = ft/sec, Q = Bbls/day, d = pipe id inches
V = 0.012 Q d2
-----------------3.2
Usually the requirement is to calculate pressure drop of fluid flowing in a pipe. Following are the steps to arrive at the pressure drop: Calculate friction factor Rather than try to solve this implicit Colebrooke’s equation, use the f Vs Nre graph in GPSA or use a direct equation for f, e.g. Churchill’s Calculate pressure drop For 100 feet of pipe ∆P=pressure drop in psi Q= flow rate in GPM L=Length in feet ρ=Fluid density in lb/ft3 f= friction factor d = pipe id inches
For 100 feet of pipe
----------3.3
∆P= 0.0216 f ρ Q2 d5
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Churchill’s equation for friction factor f = friction factor Nre = Reynolds number A & B = constants D = Pipe diameter in feet e= Roughness factor ft
1/12
12
f = 2.0
+
__8__ Nre
---3.4
__ 1___ (A+B)1.5
16
---3.5
0.9
A = -2.457 ln
__ 7__ Nre
+ __0.27e__ D
16
---3.6
B = 37530 Nre
Note that roughness factor for clean pipe is 0.0018 inches. Pressure loss through pipe fittings and valves There are two methods to calculate the pressure loss 1. The K factor method and 2. The equivalent length method. Since the equivalent length method is computationally simpler the same is presented. The method is to simply add an equivalent length due to the valves and fittings to the actual piping length. Refer to Table 1 at the end of section on fluid flow for the equivalent lengths. General guidelines Fluid velocities For hydrocarbon liquids keep pump suction velocities low –in the range 1 to 3 feet per second and always check suction pressure and NPSHA for the pump. The pressure should not be allowed to fall below the Vapor pressure of the pumped liquid at any point in the suction piping
Pump discharge piping velocities could be higher –in the range of 8 to 12 feet per second. Remember that at certain locations like vessel and tank inlets static electricity could up due to high velocities and splashing of liquids. For clean water velocities could still go up.
For gravity drains, velocities are in the range of 1 to 2 feet per second. Always check the head available with the pressure loss in the piping for gravity flow. {PAGE }/24
SINGLE PHASE FLOW-- GASES Pressure drop calculations for gases are complicated by the fact that gas density changes along the path of travel. For in-plant piping it can be assumed to some extent that the gas density will remain constant for about 100 ft and then the following equations can be applied: Gas velocity V= Feet /sec Q= MMSCFD T= Temperature in Rankine Z= Gas compressibility factor D= Pipe diameter inches P= Gas pressure in psia
V = 60 Q T Z d2 P
--------------3.7
Friction factor can be calculated using the methods describes under liquids. Gas flow can be adiabatic or isothermal. Short distances within plant can be taken as isothermal with out affecting the accuracy. If the gas is at a temperature that is widely different from the ambient then the temperature effect has to be considered. Pressure drop is then calculated by: Equation for Isothermal flow P1= Upstream pressure psia P2= Down stream pressure psia S = Sp. Gravity of gas Q = Gas flow rate MMSCFD Z = Compressibility factor of gas T1= Flowing temperature f = Moody friction factor L = Length in feet d = Pipe diameter inches
-------3.8
For short pipe length P12—P22 = 25.1 S Q2 Z T1 f L d5
Long distance Pipeline –Single Line The best way to understand the pressure drop and flow in a single long distance pipeline is by computer simulation. However the following equation –Panhandle B equation will give approximate but quick answer to flow versus pressure drops in a pipeline. Please note the equation is applicable to large diameter long pipeline where the flow is fully turbulent. Panhandle B equation
Q2 =737 Tb Pb
---3.9
1.02
E
P12—P22________ S0.961 Lm Tav Zav
d 0.51
P1= Upstream pressure psia P2= Down stream pressure psia S = Sp. Gravity of gas Q = Gas flow rate MMSCFD E = Pipeline Efficiency-fraction varies from 0.88 to 0.95 {PAGE }/24
Zav = Compressibility factor of gas-Average Tb = Base absolute temperature 520 OR Pb = Base absolute pressure 14.7 psia Tav = Average temperature of gas Lm = Length in miles d = Pipe diameter inches
There are several other equations, but only the Panhandle B is considered here. Gas Density varies with the gas molecular weight, absolute gas pressure and gas temperature. The relationship is expressed as the formula Gas Density ρ = Density of gas in lb/ft3 MW = Molecular weight P = Pressure in psia T = Temperature in OR
ρ = MW P 10.72 T
-----3.10
MULTI PHASE FLOW For multi phase flow computer simulation is the best since hand calculations are very tedious. It is important to understand the flow regime in multi phase flow namely, Bubble, Stratified, Wavy, Annular Mist and Slug flow. Multi phase flow can exist in the following areas in a Gathering Center & Booster station: Flow-lines and inlet headers to Separators Liquid outlet (oil) from separators Downstream of condensate level control valves in CRUs and Booster stations Computer simulations can reveal the flow regimes. In multi phase flow practical thumb rule is to size the pipe just right i.e. not to oversize. Slug flow is to be avoided. It is important to note that the pipe orientation (horizontal, vertical up or down) will affect the flow regimes. A simple check on the multiphase liquid velocity can give some idea of the design limitations. Maximum allowable velocity in a relatively short multiphase fluid pipe is usually the erosion velocity. It can be calculated as follows: First calculate the mixture density SG = Sp. Gr. of the liquid Mixture Density P = Operating pressure psia ---3.11 R = Gas / Liquid ratio ft3/bbl S = Sp. Gr of Gas at std. conditions ρm = 12409 (SG) P + 2.7 R S P 198.7 P + RTZ {PAGE }/24
T Z
= Operating temperature OR = Gas Compressibility factor
Then calculate the Vmax. as Vmax = Maximum allowable velocity ρm = Mixture density C = Constant, 100 for continuous service 120 for discontinuous service
Maximum allowable velocity Vmax = _ C__ √ρm2
----3.12
Table –1 Friction loss of water in pipe fittings in terms of equivalent length-L-feet of straight pipe. Nominal Pipe Size
Gate Valv e-full open
90 O Elbo w
6 8 10 12 16 20 24 30 36
4.04 5.32 6.68 7.96 10.0 12.5 15.1 18.7 22.7
15.2 20.0 25.1 29.8 37.5 47 56.6 70 85
Long Radius O 90 or 45O elbow 8.09 10.6 13.4 15.9 20.0 25.1 30.2 37.3 45.3
Std Tee thru’ flow
Std Tee branch flow
10.1 13.3 16.7 19.9 25 31.4 37.7 46.7 56.7
30.3 39.9 50.1 59.7 75 94.1 113 140 170
Swing Check valve – full open 50.5 33.3 41.8 49.7 62.5 78.4 94.3
Globe valvesfull open
Butt erfly valve -
90O weld elbow r/d=1
172 226 284 338 425 533 641
22.7 29.9 29.2 34.8 31.3 39.2 47.1
10.1 13.3 16.7 19.9 25.0 31.4 37.7 46.7 56.7
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4.0 SEPARATORS Oil and Gas Production separators—2 Phase A quick but approximate size of the Oil and Gas Production separators can be ascertained by use of the following methods Using K factor method Horizontal Separators with mist extractors can be sized by the K factor method and the Souders & Brown equation. Following conditions apply: Horizontal Separators greater than 10 ft in length with mist extractors are sized using the following equations: Maximum allowable velocity ---4.1 L 0.56 Vt = K ρl—ρg ρl 10
Vt = Maximum allowable velocity of gas in the vessel (Terminal Velocity) ft/sec K = Constant-Values to be taken from the table below ρl = Liquid density lb/ft3 ρg = Gas Density lb/ft3 L = Seam to Seam length of Vessel ft
Horizontal Separators less than 10 ft in length with mist extractors are sized using the following equation Vt = Maximum allowable velocity of gas in the vessel (Terminal Velocity) ft/sec K = Constant-Values to be taken from the table below ρl = Liquid density lb/ft3 ρg = Gas Density lb/ft3
Maximum allowable velocity -- -4.2 Vt = K ρl—ρg ρl
Typical K Factors for sizing Woven Wire Demisters Separator type
K-factor
Horizontal Vertical Spherical
0.40 to 0.50 0.18 to 0.35 0.20 to 0.35
Adjustment of K factor for pressure-% of design value: Atmospheric 150 psi 300 psi 600 psi
100 90 85 80
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Note: Typically use one half of the above values for approximate sizing of vertical separators without wire demisters
For compressor suction scrubbers inlet separators multiply K by 0.70 to 0.80
The droplet size assumed in the above equations is 150 microns.
In calculating the gas capacity of horizontal separators, the cross-sectional area of that portion of the vessel occupied by liquid (at maximum level) is subtracted from the total vessel cross sectional area. Separators can be any length, but the preferred ratio of seam to seam length to the diameter of the vessel, L/D is usually in the range of 2:1 to 4: 1 The maximum allowable velocity has to be translated into the diameter of the vessel and appropriate length. This would require trial and error computation. Retention time for the oil water liquid is to checked to see if it is comparable to the general engineering practice as given in the API 12J –Specification for Oil and Gas separators. Typical values from the above are given below: Oil Gravities
Minutes (typical)
Above 35 OAPI 20---30 OAPI 10—20 OAPI
1 1 to 2 2 to 4
An alternate method of sizing is the method given in API RP 521. This method utilizes a force balance on the liquid droplet and predicts the settling velocity using a Drag coefficient. Details of the calculation are available in API RP 521. The above calculations will give only an approximate size for preliminary assessment, generally the manufacturer does actual sizing using proprietary design methods. Vertical knock out drums with mist extractors The sizing equations are the same as given above. Oil and Gas Production separators—3 Phase Design of 3 phase separator involves consideration of 2 separations, one for gas and liquid and the second, between lighter and denser liquids. The liquid- liquid separation involves providing sufficient retention time that is providing adequate vessel volume so that there is time for oil droplets to travel up and reach the oil water interface and for water droplets to travels down. The usual approach is to provide equal residence time for oil and water. API 12J –Specification for Oil and Gas separators gives certain typical values as: {PAGE }/24
Above 35 O API Below 35 O API 100 OF + 80 OF + 60 OF +
3 to 5 5 to 10 10 to 20 20 to 30
Appropriate allowances have to be given while designing oil-water separation for oil that is highly viscous. Tanks KOC operations usually use two types of tanks, fixed roof and floating roof tanks to store crude oil. Fixed roof tanks are used as store wet crude and or dry crude inside the GC. Floating roof tanks are used in tank farms. Fixed Roof Tanks at the GCs serve the purpose of separation of formation water from crude by providing adequate retention time. Finalizing the size of a fixed roof or floating roof tank starts with the requirement of the volume of liquid to be stored that is, the operational capacity of the tank. Once this is available, the diameter can be fixed and the nearest height of the tank that would satisfy the capacity required can be looked up from the table available in API 650. It is t o be noted that the cross sectional area provided (or effectively the diameter) plays an important role in the oil water separation. The separation of the oil droplets from water and vice versa can be checked by the following equations: There are two cases to be considered: Case 1-Oil continuous, water dispersed. In this case the downward velocity of water droplets have to be greater than the upward velocity of bulk oil stream to enable the water droplets to settle to the bottom. Downward velocity of water droplets can be calculated by the following equation: U= Droplet velocity ft/sec g= acceleration due to gravity ft/sec2 d= droplet diameter-ft ρw=water density lb/ft3 ρo= Oil density lb/ft3 µo = Viscosity of oil lb/ft.sec
---4.3 2
Uw = gd (ρw—ρo) 18µo
Upward Bulk Oil Velocity can be calculated by the equation Voil=Upward Bulk oil velocity ft/sec Foil= Oil flow rate in to the tank ft3/sec AT= Area of cross section of the tank ft2
Voil = Foil AT
---4.4
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Case 2-Water continuous, oil dispersed. In this case the upward velocity of oil droplets have to be greater than the downward velocity of the bulk water stream to enable the oil droplets to travel up to the interface. Upward velocity of Oil droplets can be calculated by the following equation Uo= Droplet velocity ft/sec g= acceleration due to gravity ft/sec2 d= droplet diameter-ft ρw=water density lb/ft3 ρo= Oil density lb/ft3 µw = Viscosity of water lb/ft.sec
---4.5 2
Uo = gd (ρo—ρw) 18µw
Note that the oil droplet velocity will come out as negative indicating that it is traveling up. Downward Bulk Oil Velocity can be calculated by the equation Vw= Downward Bulk Water velocity ft/sec Fw= Water flow rate in to the tank ft3/sec AT= Area of cross section of the tank ft2
Vw = Fw_ AT
---4.6
Note: 1 Micron = 0.00099 ft 1 cp = 0.000672 lb/ft.sec
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5.0 PUMPS Centrifugal pumps are the most common type of pumps used in KOC operations. Process design of the pump involves finalizing the following parameters: Pump discharge pressure Pump suction pressure Net Positive Suction Head Available (NPSHA) Pump differential Head An estimate of the Kilowatt (usually required by Electrical design to establish the power requirements) Pump discharge pressure is calculated using the following formula: Pump discharge pressure = Required pressure at terminal point (ft) + Total Line loss (ft) + or Elevation difference (ft) Pump suction pressure = Pressure at suction origin (tank or vessel) (ft)– Line loss (ft) + or – Elevation difference (ft) If it is a tank consider pressure at normal liquid level If it is a pressurized vessel consider normal set pressure for the vessel Pump differential head (ft) P = Pump discharge pressure—Pump suction pressure Estimate of Kilowatt for pump’s motor BHP required for pump BHP= Brake Horse Power Q = Pump rated flow rate GPM H = Pump differential head in ft Sp.Gr. = Pumped liquid Specific Gravity E = Hydraulic efficiency of Pump in fraction
Kilowatt required for Motor drive
BHP for pump
--------- 5.1
BHP = Q H Sp.Gr 3960 e
KW for Drive Motor
em = motor efficiency –fraction
--------- 5.2
Kw = 0.7457 BHP em Net positive suction head available (NPSHA) is basically the pressure margin available before the liquid at pump suction flashes into vapor. It is a function of the system and can be altered by system parameters. Vapor pressure of the pumped liquid at the maximum possible temperature has to be known to calculate the NPSHA.
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Net positive suction head required (NPSHR) is a function of the pump and is independent of the pumped system parameters. It is obtained from the pump vendor. In general the pump is selected such that NPSHA > NPSHR. The margin to be available between NPSHA & NPSHR is to be ascertained from the relevant standards. Typical examples for calculating NPSHA is given below: GAUGE PRESSURE=10 PSI
NPSH CALCULATION FOR PRESSURISED DRUM
SP.GRAVITY OF WATER =1.0 NPSHA = ABS. PRESS(FT)-VAPOR PRESS(FT)-LINE LOSS(FT) +/- ELEVATION DIFFERENCE(FT)
AIR PRESSURE
PRESS. IN FT = PRESS IN PSIA* 2.31/(SP. GR)
NPSHA = (10+14.7)*2.31 1 = 57.1-1.2-45+5 = 15.9 FT
0.5 PSIA WATER @ 80 F
5 FT
--(0.5*2.31) 1
--45+5
NPSHA (AVAILABLE) MUST BE GREATER THAN NPSHR (REQUIRED) BY THE PUMP
LINE LOSS=45 FT M
GAUGE PRESSURE= 4 INCH WG
NPSH CALCULATION FOR LIQUID AT EQUILIBRIUM (TYPICAL FOR WET & DRY TANKS) SP.GRAVITY OF CRUDE = 0.86 NPSHA = ABS. PRESS(FT)-VAPOR PRESS(FT)-LINE LOSS(FT) +/- ELEVATION DIFFERENCE(FT)
GAS PRESSURE
PRESS. IN FT = PRESS IN PSIA* 2.31/(SP. GR) PRESS. IN FT = PRESS IN INCHES/29.9
LL LEVEL
SINCE CRUDE IS AT EQILIBRIUM CONDITIONS WITH VAPOR VAPOR PRESSURE OF CRUDE = PRESS OF VAPOR IN TANK = (4/29.9)+14.7 =14.83 PSIA
14.83 PSIA CRUDE @ 80 F
20 FT NPSHA = ((4/29.9)+14.7)*2.31--(14.83*2.31) --12+20 0.86 0.86 = 39.83--39.83--12+20 = 8 FT
LINE LOSS=12 FT M
NPSHA (AVAILABLE) MUST BE GREATER THAN NPSHR (REQUIRED) BY THE PUMP
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Most important three items that are to be kept in mind while developing pumps requirements are the rated capacity, NPSHA and the differential head. These have to realistic to match with system requirements for current and reasonable future. Other types of pumps used mainly in KOC are reciprocating types and progressive cavity types. Reciprocating pumps are mainly used in Chemical Injection skids. They are low volume high head pumps. Most important parameters to note are the suction piping length (should be as short as possible) and the suction velocity (should be less than 3 feet per second). Acceleration head has to be included in the calculations for NPSHA. Air operated Progressive cavity pumps are installed in Pits for Drain vessel, where they are used to pump out liquid accumulating in the pit. Minimum process requirements for these pumps are the flow rate and differential head, which can be calculated from the system design.
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6.0 COMPRESSORS Centrifugal Compressors For capacity and performance calculations of the compressor, the following equations apply: Capacity of the compressor is usually expressed at inlet conditions. Compressor Capacity Q=Volume of gas-Cubic ft per min at Inlet conditions icfm SCFM= Volume at gas at std. Conditions T1= Temperature at inlet OR P1= Pressure at inlet psia Z1=Compressibility factor at inlet conditions ZL=Compressibility factor at std. conditions
ICFM Q = SCFM 14.7 T1 Z1 520 P1 ZL
----6.1
Poly-tropic efficiency
----6.2
Compressor Head Poly-tropic calculation Poly-tropic Efficiency n= Poly-tropic exponent k= isentropic exponent Cp/Cv Ep= Poly-tropic efficiency
n = (n-1)
k___ Ep k-1
Poly –tropic Head Zav = Average Gas compressibility MW = Molecular wt. of gas n = Poly-tropic exponent P2 = Discharge pressure psia P1 = Suction pressure psia T1 = Inlet temperature OR
Hp = 1545 Zavg T1 MW (n-1)/n
P2 P1
(n-1)/n
__ 1
--6.3
Poly-tropic Head and Isentropic Head are related by Hisen = Isentropic Head Eisen = Isentropic Efficiency Ep = Polytropic Efficiency
Gas Horse Power
---6.4
Hp = Hisen Ep____ Eisen
Gas Horse Power GHP W = Mass Flow rate lbs/hr Ep= Poly-tropic efficiency
Gas Horse Power
---6.5
GHP = W Hp____ Ep 33000 {PAGE }/24
Isentropic calculation Isentropic Head Zav = Average Gas compressibility MW = Molecular wt. of gas k = Isentropic exponent-Cp/Cv P2 = Discharge pressure psia P1 = Suction pressure psia T1 = Inlet temperature OR
Hp = 1545 Zavg T1 MW (k-1)/k
Gas Horse Power GHP
P2 P1
(k-1)/k
__ 1
Gas Horse Power
W = Mass Flow rate lbs/hr Eis= Isentropic efficiency
--6.6
---6.7
GHP = W Hp____ Eis 33000
Mechanical losses in the Compressor can be calculated by Scheel’s equation MLoss = Mechanical Losses in compressor GHP = Gas Horse Power
Mechanical Losses
---6.9
MLoss = (GHP)0.4
Compressor Brake Horse Power BHP
Brake Horse Power BHP
--6.10
BHP = GHP + MLoss Approximate theoretical discharge temperature T2 can be calculated from ∆T ideal = temperature rise in OR T1 = Inlet temperature OR k = Isentropic exponent-Cp/Cv P2 = Discharge pressure psia P1 = Suction pressure psia
--6.11
∆T ideal = T1
P2 P1
(k-1)/k
T2= T1+ ∆T ideal
__ 1
--6.12
Other types Other types of Compressors mainly used in KOC are reciprocating compressors. Most of the Condensate Recovery Units are having reciprocating type machines. Instrument Air compressors are also reciprocating type. Detailed equations for calculating operational parameters for reciprocating machines are not presented here. The same are available in GPSA. However the {PAGE }/24
following paragraph reproduced here from GPSA will help design engineers to consider options while designing the system. “The maximum ratio of compression permissible in one stage is usually limited by the discharge temperature or by rod loading, particularly in first stage. When handling gases containing oxygen, which could support combustion, there is a possibility of fire and explosion because of the oil vapors present. To reduce carbonization of oil and danger of fires, a safe operating limit may be considered to be approximately 300 OF. Where no oxygen is present in the gas stream, temperature of 350 OF may be considered as maximum, even though mechanical or process requirements usually dictate a lower figure. Packing life may be significantly shortened by the dual requirement to seal both high [pressure and temperature gases. For this reason, at higher discharge pressures, a temperature closer to 250 OF or 275 OF may be the practical limit. In summary and for most filed applications the use of 300 OF maximum would be a good average. Recognition of the above variables is however useful.”
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7.0 FLARE STACKS KOC has mainly two types of flare stacks, Non –Smokeless and Smokeless. Since Non Smokeless type is being installed mostly a brief outline of the preliminary technical requirements of such type are given below: Flares are designed based primarily on the basis of two criteria, that is, the thermal radiation emitted from the flare and the dispersion of any toxic component in the gas in case of a flame out condition of the flare. It is to be noted that the location of the flare is fixed based on the footprint of the worst case scenario arising from thermal radiation from the flare and toxic gas dispersion. Thermal radiation Thermal radiation calculations are detailed in API RP 521- Guidelines for Pressure Relieving and Depressuring Systems and therefore not detailed here. As per API RP 521 the Recommended Design Total Radiation is as below: Recommended Design Total Radiation Permissible Design Level (K) BTU/Hr Kilowatt per /Sq. ft Square M 5000 15.77 3000
9.46
2000
6.31
1500
4.73
500
1.58
Conditions
Heat intensity on structures and in areas where operators are not likely to be performing duties and where shelter from radiant heat is available( for e.g. behind equipment) Design value for flare release at any location to which people have access (for e.g. at grade below the flare or a service platform of a nearby tower): exposure should be limited to a few seconds sufficient for escape only. Heat intensity in areas where emergency actions lasting up to1 minute may be required by personnel with out shielding but with appropriate clothing. Heat intensity in areas where emergency actions lasting several minutes may be required by personnel with out shielding but with appropriate clothing. Design value at any location where personnel with appropriate clothing may be continuously exposed.
Note that solar radiation is to be considered in the calculations. Typical value of solar radiation in Kuwait would be in the range of 300 to 500 Btu/Hr/Sq. Ft (0.948 to 1.58 Kw/sq.M) Smokeless-ness is to be specified as Ringelmann 0 (Ringelmann Smokechart) at a distance of 10 feet from the visible edge of the flare stack.
Dispersion calculations {PAGE }/24
Dispersion calculations typically are based on Gaussian Dispersion models and Pasquill-Guifford meteorology stability classes. The required complex calculations to arrive at the ground level concentrations are tedious if done manually. The simpler way would be to run the SCREEN 3 model of EPA for all stability classes to get a first approximation. Many contractors / vendors have proprietary computer programs and output from the same can be reviewed during detailed design.
{PAGE }/24
REFERENCES 1. API 12J –Specification for Oil and Gas separators 2. API RP 521-Guide for Pressure Relieving and De-pressuring Systems-4th edition 1997 3. Arnold Ken, & Stewart Maurice- Surface Production Operations Volume 1 and Volume 2 4. GPA-Engineering Data Book Volume 1 and Volume 2 5. Ingersoll-Dresser Pumps-Cameron Hydraulic Data 6. Schweitzer, Philip A- Handbook of Separation Techniques for Chemical Engineers 7. SIMSCI –Pipe Phase Manual
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