07 Gas Handling

Upstream Process Engineering Course 7. Gas Handling

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Gas Handling

1

Units and Standard Conditions Common Gas Units mmscf, MMSCF, MMCF - one million standard cubic feet BE CAREFUL! In English units MM means million In metric units M means “mega” or 10^6

Standard Conditions (Pressure & Temperature) English

P= 14.7 psia,

T = 60°F (15.56°C) = 520°R

Metric

P = 101.325 Kpa (1 atm),

T = 15 °C = 288 K

Normal

P = 101.325 Kpa (1 atm),

T = 0°C = 273K

Volume to Mass conversions English:

379 ft3/lb-mol

2626 lbmol/MMscf

Metric:

23.96 m3/kmol

41470 kmol/106 std m3

1 MMscfd = 110 lbmol/hr 1 x 106 std m3/d = 1739 kmol/h

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Gas Handling

2

Gas Handling •

Gas Management – – –

– – – – •

1st Stage Compression

compress to export gas to market reinject for reservoir support reinject to improve recovery • miscible/immiscible drive • WAG (Water alternating gas) reinject into separate formation compress to recover valuable NGLs use as fuel flare

Outcome is application specific

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2nd Stage Compression

Export Compression Export

Gas Lift Re-injection Gas from Separators

Lean Glycol

Dehydration Column NGLs

NGLs

NGLs

Rich Glycol

Typical Gas Handling Arrangement

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Gas Handling

3

Compressors

Axial Compressor

Centrifugal Compressor

Reciprocating Compressors

Screw Compressor Upstream Process Engineering Course

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Gas Handling

4

Centrifugal Compressor

Vertical Split

Horizontal Split

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Gas Handling

5

Flow through Centrifugal Compressor Discharge

Diffuser Minimum width of last impeller passage is ~ 4mm

suctio n

Leakage flow here opposes centrifugal force, causes turbulence

Impeller Inlet guide vane

Seal Chamber

End thrust generated by Impellers Upstream Process Engineering Course

IS

Opposed by the balance Piston

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Gas Handling

6

Compressor Comparison • Reciprocating:

• Centrifugal:

– Greater flexibility in capacity and pressure range – Higher compressor efficiency and lower power cost – Capability of delivering higher pressures – Capability of handling smaller volumes – Less sensitive to changes in gas composition and density

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– Lower maintenance expense – Greater continuity of service and dependability – Less operating attention – Greater volume capacity per unit of plot area – Adaptability to gas turbine drivers

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Gas Handling

7

Centrifugal Compressors Operation and Control – Variable speed – Constant speed • discharge throttling • suction throttling • inlet guide vanes

– Surge / Stonewall – Seal Systems • seal oil • dry gas seals

– – – – – –

Lubricating oil (Inter) cooling Blowdown Vibration Rotor dynamics Critical speed

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– Compressor Operation Characteristics: Head (adiabatic or polytropic)

•

Surge - Flow reversal - Damages machine

Lines of constant adiabatic or polytropic efficiency Surge Line Control Line A

0.65 0.70

A1

0.65 Stonewall

B

B1 C

Normal Duty Point

Constant Speed Lines

D

105% 100% 95%

Inlet Volumetric Flowrate

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Gas Handling

8

Flow Limits Two conditions associated with centrifugal compressors are surge (pumping) and stone-wall (choked flow). At some point on the compressor’s operating curve there exists a condition of minimum flow/maximum head where the developed head is insufficient to overcome the system resistance. This is the surge point. When the compressor reaches this point, the gas in the discharge piping back-flows into the compressor. Without discharge flow, discharge pressure drops until it is within the compressor’s capability, only to repeat the cycle. The repeated pressure oscillations at the surge point should be avoided since it can be detrimental to the compressor. Surging can cause the compressor to overheat to the point the maximum allowable temperature of the unit is exceeded. Also, surging can cause damage to the thrust bearing due to the rotor shifting back and forth from the active to the inactive side. “Stonewall” or choked flow occurs when sonic velocity is reached at any point in the compressor. When this point is reached for a given gas, the flow through the compressor cannot be increased further without internal modifications.

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Gas Handling

9

•

Anti-Surge Control Systems – Minimum Flow Control. Suitable for fixed speed machines only. Impractical and wasteful for variable speed. – Flow ΔP Control. Series of control points at differing speeds gives surge control line of the form y = mx + c. Recycle valve modulated to ensure operating point is not to the left of this line. Simple and robust. – CCC control. Uses two additional lines Allows more efficient (closer to surge limit line (SLL)) and responsive control

Head

Anti-Surge Control 100 95 90 85 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0

Operating Point Dev

SOL

RTL

Surge Lim it Line

0

5

10

15

20

Minim um Flow Control Line

Surge Control Line

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Flow

• Surge Control Line (SCL). Uses PI control to manage normal load changes. • Recycle Trip Line (RTL). Aggressive control, acts as flow approaches surge line. Recycle valve opened in steps by timer delay until RTL is re-crossed when PI control is reactivated. Should never be re-set. • Safety On Line (SOL). If SOL is crossed surge is assumed to have occurred. Incident is logged and the controller moves all control lines to the right. Can be re-set (after investigation into incident cause).

– CCC uses deviation (DEV) between operating point and SCL to determine compressor status. Upstream Process Engineering Course

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10

Centrifugal Compressors Lube Oil System

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11

Reciprocating Compressors Piston reciprocating compressors are the most common type of positive displacement compressors. They are available both in single and double-acting design in various configurations. Gas is drawn into the cylinder usually through a self-acting valve which is opened and closed by pressure difference. After compression, the gas leaves via a self-acting discharge valve. The valve is comprised of a seat, valve guard, plates and springs. The plate moves between the guard and seat aided by the springs which help to accelerate closure. The valve is fully open when held against the guard and fully closed when held against the seat. Some less common designs have cam-controlled or rotary slide valves. More detail on valves is given later. Reciprocating compressors can be supplied as lubricated or oil-free designs. Oil-free compressors have piston rings and wear bands fitted. Trunk type oil-free compressors have dry crank cases with permanently lubricated bearings. Crosshead types have lengthened piston rods which keep oil wetted parts away from the compression space. Other types of positive displacement compressor are oil-free labyrinth piston compressors (no piston rings are fitted, the cylinder wall to piston seal is achieved by labyrinth seals) and diaphragm compressors. Upstream Process Engineering Course

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Gas Handling

12

Reciprocating Compressors

Single-acting 1- piston

Double-acting 4- connecting rod

2- piston rod 5. crankshaft with counter-weight

Compressor valve

3- cross-head

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Gas Handling

13

Reciprocating Compressors Single-acting Compression occurs only on one side of the piston and only once per revolution of the crankshaft. These machines are normally referred to as trunk type compressors. Examples of cylinder layouts are shown on the next slide. Single-acting compressors are usually of the enclosed type where the piston is directly driven by a connecting rod working off a crankshaft, both of which are enclosed in an externally pressure-tight crankcase.

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14

Reciprocating Compressors

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Reciprocating Compressors Double-acting Compression occurs alternately on both sides of the piston, twice during each revolution of the crankshaft. These machines are normally referred to as crosshead type compressors. Examples of cylinder layouts are shown on the next slide.

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Gas Handling

16

Reciprocating Compressors

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Gas Handling

17

Reciprocating Compressors •

Compressor Construction • • •

•

Number of cylinders ranges from 1 – 16 Where 4 or more cylinders are used a V, W or radial arrangement is used. Compressor cylinders are normally cast in close-grained iron. Larger compressors will usually be fitted with a replaceable cylinder liner. Two types of piston are commonly used, automotive and double-trunk. Automotive type pistons are used where the suction valves are located on the cylinder head and double-trunk where the suction gas enters through ports in the cylinder walls.

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The three most common suction and discharge valves in reciprocating compressors are –

– –

The poppet valve, a cage serves as both a valve seat, stem guide and spring retainer. A spring, dashpot or bleeder arrangement is used to limit and damp valve travel. These are slow response valves and only used on slow speed compressors. The ring plate valve was described earlier. Flexing valves vary in design but typically would consist of a seat, ribbon strips and a valve guard. This type of valve is the feather valve. The ribbon strips or reeds flex under pressure and as for the ring plate Valve operates under pressure difference

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Gas Handling

18

Reciprocating Compressors •

•

•

Crankshafts in larger compressors are of the crank-throw type. These are mainly fabricated from forged steel or alloy cast iron. Smaller compressors tend to use an eccentric shaft. Bearing journals are highly polished and case hardened where aluminium or brass bearings are used. Usually plain bearings are found on crankshafts, however, main bearings can be of the roller or ball anti-friction type. In order to prevent leakage of gas (and oil) from the crankcase or air into the crankcase it is common to fit a self adjusting seal. The spring loaded seal nose is held hard against the polished seal plate. An oil film between the two provides a gas-tight seal. The nose is sealed to the crankshaft by the rubber gasket

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Gas Handling

19

Reciprocating Compressors Compressor capacity control

• •

• • • •

There are a number of means of controlling compressor capacity Variable speed shaft drive. Suction valve regulation, a claw mechanism holds the valve plates open when gas demand is low (see adjacent). Clearance pocket control Inlet throttling. Bypass control Cylinder unloading by bypassing the discharge from one or more cylinders back to suction line. 10. gas to and from unloading device

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Gas Handling

20

Reciprocating Compressors Compressor Performance

• • • • • • • •

In order to understand how a reciprocating compressor performs. A few key concepts must be understood The compression cycle Volumetric efficiency The clearance volume and the effects of clearance Wiredrawing Cylinder heating Piston and valve leakage Isothermal versus isentropic compression Water-jacketing the cylinder

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Gas Handling

21

Reciprocating Compressors The compression cycle The compression cycle is shown in the adjacent figure. a) b) c)

d)

The piston is at top dead centre with suction and discharge valves closed. The piston has travelled down the cylinder and the suction valves open. The piston is at bottom dead centre with suction and discharge valves closed. The piston has travelled back up the cylinder and the discharge valves open.

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Gas Handling

22

Reciprocating Compressors The cycle is shown on the theoretical time-pressure diagram. At point A the piston is at top dead centre. The pressure is maintained by the gas in the clearance space holding the valves closed. On the suction stroke from A-B the pressure is reduced as the gas expands to point B. Here, the gas in the suction line is at a higher pressure than the cylinder and the suction valves open. From B-C the cylinder is filled with gas at suction pressure until point C when the suction valves close usually under spring action. Compression takes place from C-D. At point D the pressure in the cylinder is higher than the gas in the head of the compressor and the discharge valves open. Gas flows until the piston reaches point A again and the cycle is complete with the crankshaft having completed one full revolution Upstream Process Engineering Course

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23

Reciprocating Compressors

A typical compression cycle is shown here on a pressure-volume diagram. The points A,B,C and D depict the piston at the same position as on the time-pressure diagram above.

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Gas Handling

24

Reciprocating Compressors Volumetric efficiency

ηv=

The actual volume of gas transferred from the suction line is the actual displacement of the cylinder. The ratio of this actual displacement to piston displacement is known as the total volumetric efficiency of the compressor

Volumetric efficiency (%)

Vact = actual volume of suction gas compressed per unit time Vp = compressor piston displacement

Vact V  x 100 Vp Upstream Process Engineering Course

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Gas Handling

25

Reciprocating Compressors Effects of clearance When the piston has reached the end of the compression stroke, some gas is retained in the clearance space in the cylinder after the discharge valves have closed. When the compression cycle restarts, there is already a volume of gas in the cylinder which reexpands and reduces the available volume for suction gas. Referring back to the pressurevolume diagram, the clearance volume and re-expanded gas volume are shown as Va and Vb respectively. Obviously, as the clearance volume increases, the volumetric efficiency reduces.

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26

Reciprocating Compressors Wiredrawing Wiredrawing is defined as a restriction of area for a flowing fluid, causing a loss in pressure by (internal; and external) friction without loss of heat or performance of work; throttling. As gas passes through the suction valves a mild throttling takes place which means that the cylinder is at a slightly lower pressure than the suction line and thus less volume of suction gas is transferred than if the gas was at suction line pressure. This reduces the volumetric efficiency of the compressor as the actual volume of suction vapour transferred is reduced. Wiredrawing is independent of compression ratio being a function of gas velocity through the valves and passages of the compressor. As velocity increase the effects of wiredrawing increase. The gas velocity is dependent upon valve characteristics, the gas and the speed of the compressor. As the compressor rpm increases so does the piston displacement and velocity of the gas passing through the valves. This in turn amplifies the effects of wiredrawing.

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Gas Handling

27

Reciprocating Compressors Cylinder heating

Piston and valve leakage

The compression process generates heat as work is transferred into the gas from the piston. Some of this heat is retained in the cylinder walls. Heat is conducted from the cylinder walls to the gas entering from the suction line. Heat is also generated from friction by the turbulent movement of gas in the cylinder. The net effect of this is that suction gas is heated and expands in the cylinder. This reduces the amount of gas which can be transferred from the suction line. Cylinder heating increases as the compression ratio increases. This reduction in actual volume of gas in the cylinder reduces the volumetric efficiency of the compressor

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Leakage back through suction or discharge valves or around the piston will decrease the gas transferred by the compressor. Well maintained compressors with valves and pistons in good condition will not suffer from high leakage rates. Back flow through valves is minimised by designing them to close promptly by spring assistance. However, spring tension increases wire drawing so the spring rating is critical. Back leakage is a function of compression ratio and compressor speed.

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Gas Handling

28

Reciprocating Compressors Isothermal versus isentropic compression The pressure-volume diagram attached shows the compression cycle. Noting the work done during compression is equal to the area under the curve, it can be seen that an isothermal (constant temperature) compression process requires less work input than an isentropic (constant entropy) process. The reduction in work is shown by the hatched area. Clearly this is more desirable since less work input to the compressor is required. A water jacket on the cylinder which draws heat from the gas during compression will move the process way from isentropic toward isothermal compression.

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Reciprocating Compressor Con-rod Crank

Piston

Crosshead

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Suction Valves

Distance Piece

Wiper

Packing

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Discharg e Valves

Gas Handling

30

Screw Compressors Screw compressors are positive displacement compressors. Twin screw machines compress gas between two meshing helically grooved rotors. Single screw machines have a single screw which meshes with two gate rotors. In twin screw compressors the male rotor is the driving rotor with a series of lobes, these mesh with matching flutes on the female non-driven rotor. The compression process is described below.

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31

Screw Compressors

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Screw Compressors Single screw compressors consist of a single screw with two gaterotors. Gas flows through the suction port into the exposed grooves at each end. With rotation, gaterotor teeth enter and seal the grooves in the screw sequentially trapping gas in the chambers. The gas is continually compressed until the leading edge of the screw passes the discharge port. Gas is then discharged until the gaterotor reduces the effective volume to zero. Since there are two gaterotors, the compression process occurs twice per revolution thus doubling the capacity of the machine.

1- gaterotor 2- screw rotor

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Screw Compressors Capacity Control Mechanism Capacity control is accomplished by a slide valve which moves parallel to the rotor axis and changes the area of the opening in the bottom of the rotor casing. This, in effect, lengthens or shortens the region of compression of the rotor and further acts to return gas to the suction side, while bypassing compressed gas. Variable speed drives can also control the capacity.

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Screw Compressors Compressor Performance Dynamic compressors use terms such as polytrophic head and temperature lift to describe their performance capabilities. These are not normally applied to positive displacement machines, screw compressors are usually described in terms of pressure ratio.

Basic compression characteristics are Volume ratio

Vi 

V1 Volume when compressio n begins  V2 Volume when compressio n ends

This may be a fixed ratio or a variable ratio where a slide valve is installed as described above fro capacity control. Pressure ratio

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i 

P2 Pressure at discharge  P1 Pressure at suction

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Screw Compressors The isentropic relationship between the volume and pressure ratios described in equation 2 of the section on Compression Thermodynamics. Screw compressors are normally high speed rotating machines and as such due to the short residence time of the gas during compression, the process is generally regarded as reversible adiabatic.

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36

Compressor Selection •

Recip.-multi stage: –

•

Recip.-single stage: –

•

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Gas export / reinjection

Axial: – –

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Gas pipeline boosting

Centr. Multi stage: –

•

Air (vacuum) systems

Centr. Single stage: –

•

Oil free (air) compression

Rotary compressors: –

•

Fuel gas compression

Diaphragm: –

•

Gas export / reinjection

Pilpeline boosting Air separation Gas Handling

37

Compressor Selection Is the discharge volume flow YES

greater than 300m3/h

NO Is the pressure rise

Will the mean molar mass change by more than 20%

YES

YES

greater than 7 bar

Is the pressure rise greater than 20 bar NO

NO

NO

YES Use a CENTRIFUGAL Compressor Upstream Process Engineering Course

Use a RECIPROCATING Compressor

Use a SCREW Compressor

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Use a LIQUID RING Compressor Gas Handling

38

Compression Thermodynamics •

The basic thermodynamic equation for compression is:

H   VdP  Wtheor

•

For the isentropic compression process:

P V k  const  P1 V1

•

Substitution of [2] into [1] yields:

H  P1 k V1   P 1

P2

1

k

[1]

k

 dP

[2]

[3]

P1

1

•

or (solving):

•

Equation [4] is rewritten as:

•

Substitution of the ideal gas law into [5] yields:

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k 1 P k V1  k 1 H  1   P2 k  P2 k   k 1       k  k 1       P1  V1 P2 k H       1  k  1    P1       k   k 1       m  Z1  R  T1 P2 k H       1 P  k 1      MW   1   k   Prepared by Genesis Oil and Gas Consultants Ltd

H Enthalpy change (kJ) V Gas volume (m3) P Pressure (kPa) WtheorTheoretical work done (kJ) k Ratio of specific heats (Cp/Cv) m Mass (kg) Z Compressibility factor (-) R Gas constant (=8.314 kJ/kmol.K) T Temperature (K) MW Molweight (kg/kmol)

[4]

[5]

[6]

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39

Compression Thermodynamics •

Equation [6] (previous slide) is usually written as:

k 1    Z a  R  T1   P2  k H isen       1 P  k 1      MW   1    k 

[7]

which is the basic “head” equation for compressors, in which Z a is the average compressibility ((Z1+Z2/2)) and Hisen is the isentropic head (in kJ/kg). For the isentropic head in meters: H isen meters 

1000  H isen kJ / kg  g  9.81

•

In a steady state situation the entropy change in a system is written as: S = Q/Tb + Sp [8] in which Q is the heat exchanged with surroundings, T is the absolute temperature of the system boundaries and Sp is the entropy production, reflecting the irreversibility of the process.

•

Isentropic Process:

•

Polytropic Process:

n 1 k 1  n k  E poly Upstream Process Engineering Course

S = 0, reversible (Sp = 0) and adiabatic process (Q = 0) S  0, irreversible (Sp  0), entropy is produced by internal friction in the system n - Polytropic coefficient (n > k) E - Polytropic efficiency Prepared by Genesis Oil and Gas Consultants Ltd

Compression Curves Gas Handling

40

Compression •

n 1 n

P  T2  T1   2   P1  n 1 k 1  n k  E poly

Centrifugal Compressors – – –

– – – –

cover a wide operating range extensive use in upstream oil & gas industry main suppliers • Dresser • Nuovo Pignone • Sulzer good reliability compared to reciprocating machines not suitable for high head low flow applications compression ratio limited by discharge temperature, in turn defined by materials Head equation: n 1

T1  Z a  R h poly   n 1     MW n  

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 P    2   P1  

n

  1  

W

 m  h poly E poly

For paraffin gases k may be estimated from:

k = 1.3 - 0.31 ( - 0.55) hpoly T Za R P n k MW W m Epoly  1/2

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Polytropic head (kJ/kg) Temperature (K) Average compressibility (Z1 + Z2)/2 Gas constant (8.314 kJ/kmol.K) Pressure (Pa) Polytropic coefficient Ratio of specific heats (Cp/Cv) Molweight (kg/kmol) Gas power (kW) Mass flow (kg/s) Polytropic efficiency - Function of volumetric inlet flow varying from approx. 0.6 to 0.8 (compressor specific) Gas relative density (-) Suction/Discharge Gas Handling

41

Calculation Example •

•

or Hpoly = 175.5 * 1000 / 9.81 = 17890 m

10 MMscfd of hydrocarbon gas (MW = 22.0 kg/kmol) is compressed from 4 bara to 15 bara. Calculate the required compressor power and discharge temperature. The polytropic efficiency of the compressor is 75%. Za = 0.98. T1 = 30oC Rule of thumb: 1 MMsm3/day = 1739 kmol/hr 10 MMscfd = 0.283 MMsm3/day = 492 kmol/hr  Mass flow: 492 * 22 / 3600 = 3.0 kg/s

W

1.331

 15  1.33 T2  303     421 K  148o C 4 • •

Specific gravity: 22.0 / 28.96 = 0.76

If the same compressor were to compress a heavier gas, e.g. MW = 30, what would be the discharge pressure? The head is unaffected, because the head is only dependent on impeller (tip) speed:

 P2    4

Ratio of specific heats (estimated): k = 1.3 - 0.31* (0.76 - 0.55) = 1.23 Polytropic coefficient:

n 1 1.23  1   0.25  n  1.33 n 1.23  0.75 1.331   303  0.98  8.314  15  1.33 h poly      1  175.5 kJ / kg    1.33  1  4    22.0    1.33  Upstream Process Engineering Course

3.0 175.5  700 kW 0.75

1.331 1.33

 1.33  1  175.5     30 1.33     1  P2  22 bara 303  0.98  8.314

•

The required power would be: 700 * (30/22) = 955 kW

•

Note that the compression ratio is usually limited to 4 (although can be higher for high MW gases). If the compression ratio is higher then 4, more stages are required (with intercooling). The number of compression stages (r) can be estimated from: 1 ln  P2   P2  r P1  or    4 r  P  1 ln 4

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Gas Handling

42

Centrifugal Compressor Design • •

•

•

Mechanical design undertaken by machine supplier Design will account for; – Thermodynamics – Aerodynamics – Rotor Dynamics – Stress/loads Process engineer will specify; – Number of stages – Flowrate – Gas Composition – Inlet Pressure and Temperature – Discharge Pressure – Range in volumetric rate – Range in molecular weights Major Design Variables – Speed – Impeller Diameter – Number of impellers – Impeller Design – Head per impeller

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•

Specific speed:

N  q 0.5 Ns  H 0.75 N q H

•

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speed (rpm) volumetric flowrate ft3/s) head (ft)

Specific diameter:

ds  d

d H 0 .5 q

0.25

impeller diameter (ft)

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43

Centrifugal Compressor Train Design 1st Stage Compression

2nd Stage Compression

Export Compression Export

Gas Lift Re-injection Gas from Separators

Lean Glycol

Dehydration Column NGLs

NGLs

NGLs

Rich Glycol

Single Shaft – what speed? Optimum Specific Speed

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44

Centrifugal Compressor Train Design Compressor

1st Stage

2nd Stage 77

Export

Suction Volume Flow (ft3/S)

307

9.1

Mol Weight

35

29.5

23.2

Suction Pressure (psia)

55

258

600

Suction Temperature (DegF)

60

80

80

Discharge Pressure (psia)

275

638

2500

Compression Ratio

5

2.5

4.2

1st Stage Compression

2nd Stage Compression

Export Compression Export

Gas Lift Re-injection Gas from Separators

Lean Glycol

Dehydration Column NGLs

NGLs

NGLs

Rich Glycol

Single Shaft – what speed?

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Centrifugal Compressor Train Design Sensitivity study at three speeds – 5000, 8000 and 14000 rpm

.

Compressor 5000 rpm

1st Stage

2nd Stage

Export

Compressor 8000 rpm

1st Stage

2nd Stage

Export

No Impellers

4

3

8

No Impellers

4

3

8

Impeller Diameter (Ft)

2.94

2.68

2.49

Impeller Diameter (Ft)

1.95

1.68

1.548

Head (Ft)

40200

25690

57729

Head (Ft)

40200

25690

57729

Specific Speed

87.3

49.3

30.1

Specific Speed

139.6

78.9

48.1

Efficiency

0.767

0.655

0.564

Efficiency

0.768

0.7723

0.641

Power (KW)

7800

5930

8700

Power (KW)

7860

4800

7550

Total Power (KW)

Total Power (KW)

22500

Compressor 14000 rpm

1st Stage

2nd Stage

No Impellers

4

3

8

Impeller Diameter (Ft)

1.62

1.33

0.997

Head (Ft)

40200

25690

57729

Specific Speed

244.4

138.0

84.3

Efficiency

0.635

0.782

0.732

Power (KW)

9620

4880

6410

20350

Export Lowest Power

Total Power (KW) Upstream Process Engineering Course

Fit gear boxes and drive stages at different speeds – Total Power 19010 KW

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Compressor Drivers •

Drivers: – Electric Motors – Gas Engines – Diesel Engines – Gas Turbines – Steam Turbines – Expansion Turbines

•

Driver selection influenced by: – Compatibility with power load – Fuel availability – Weight & Volume limitations – Reliability/Availability Requirements

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Compressor Drivers Electric motor drives Depending on the size and type of compressor, electric motor drives generally have one of the following three arrangements-

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Driver Selection Is gas fuel available on site?

Yes

No

Yes

Is dual fuel capability required?

Is power per driver > 3.5 MW ?

No

Is power per driver > 3.5 MW ? No

Yes

Is weight capacity limited?

Yes

No

Yes

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Is weight capacity limited?

Yes

No

Consider gas turbine

Is power per driver > 3.5 MW ?

Consider dual fuel engine

No

Yes

Yes

No

Consider gas turbine

Is weight capacity limited?

Consider gas engine

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No

Consider gas turbine

Consider diesel engine

Gas Handling

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Cooling / Scrubbing / Compression to next stage compression/ dehydration/sweetening

Saturated vapour

Cooler

Compressor

Scrubber • • • • •

NGLs to separation

Compression will heat the gas and therefore requires (interstage/after) cooling to reduce power and also to avoid exceeding discharge temperature limits Cooling of the saturated vapour to compressor inlet conditions causes condensation of heavier components and water Leaner gas from scrubber with reduced cricondenbar Cooler outlet temperature typically 25-30 DegC set by hydrates, cooling medium temperature, and heat of compression from upstream compressor NGL recycle can significantly affect system heat and mass balance

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BP Amoco North Sea Assets Compressor Inventory BP Amoco North Sea Assets– Compressor Inventory Asset

Service

Nos/Duty

Manufacturer

Model

Seal

Driver

Andrew

LP HP (1st stage) Export Reinjection

1 x 100% 1 x 100% 1 x 100% 1 x 100%

Sulzer Sulzer Sulzer Sulzer

RB 35-3+4 RB 35-3+4 RB28-6 (HP 2nd stage) RB28-4

D? D? D? DTR

ABB – GT35 Same shaft Same shaft EM

Bruce

LP Export Reinjection (wef 3Q98)

1 x 100% 3 x 50% 1 x 100%

Dresser Rand Cooper Nuevo Pignone

26 08 B3/3 RC5/4B

D? D? DT

EM RB211 RB211

ETAP

LP Export Reinjection

2 x 50% 2 x 70% 1 x 100%

Demag Delaval Demag Delaval Nuevo Pignone

6B26 6B26 BCL305C

DT DT DTR

EM EM EM

Forties A/D

NGL Deep Gas Lift Deep Gas Lift (kick off) NGL/Shallow Gas Lift

2 x 75% ? 1 x 100% 1 x 100% 2 x 100%

Dresser Rand Dresser Rand Dresser Rand Dresser Rand

MTGB724 2608B RECIP MTGB724

W W W W

Rustons TB4500 EM EM Rustons TB4500

Foinaven

LP (1st stage) IP (2nd stage) Reinj/Gas Lift (3rd stage)

2 x 50% 2 x 50% 2 x 50%

Dresser Rand Dresser Rand Dresser Rand

451B6 (TP28 seals) 451B7 (TP28 seals) 272B4/4 (XP seals)

D? D? DT

EM Same shaft EM

Gyda

LP HP

1 x 100% 1 x 100%

Delaval Stork Delaval Stork

6BK22 6BK22

W W

EM Same shaft

Forties C/D

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BP Amoco North Sea Assets Compressor Inventory Harding

LP (1st) HP Gas Lift/Reinj

1 x 100% Demag 1 x 100% Demag

8B22 6B22

D? D?

EM Same shaft

Kinneil Terminal

Trains 1 & 2 – Separator Separator spare Trains 1 & 2 – Flowtank Flowtank spare Train 3 – LP LP Spare Train 3 – MP/HP MP/HP Spare

2 x 25% 1 x 25% 2 x 25% 1 x 25% 1 x 50% 1 x 50% 1 x 50% 1 x 50%

Sulzer Sulzer Sulzer Sulzer Demag Delaval Demag Delaval Demag Delaval Demag Delaval

RZ 35-4+4 RZ 35-4+5 R56-6, R28-6 R56-6, R28-7 3B51 3B52 7BK38 7BK38

W W W W D D DT DT

Sulzer S1 EM (Laurence Scott J25) Sulzer S1 EM (Laurence Scott J25) EGT Tornado EM (GEC Unipack) EGT TB5000 (5400 uprate) EM (GEC Unipack)

Magnus

LP Flash HP

3 x 50% 3 x 50%

Sulzer Sulzer

R28-5 RB28-4

W W

EM Same shaft

Miller

LP Flash Gas MP flash Gas Gas Regenerator Export Reinjection (wef 6/97)

1 x 100% 1 x 100% 2 x 100% 2 x 50% 1 x 100%

Sulzer Sulzer Atlas Copco Dresser Rand Sulzer

R45-5 RB45-6 GT06T150 361 B4/4

W W W W DT

EM Same shaft EM EM EM

Schiehallion

HP1/HP2 HP3 (to gas lift & reinj compr) Reinjection

2 x 50% Howden 2 x 50% Demag 1 x 100% Demag

WCVT5510/13258 5B-26 3B-22

? DT DTR

EM EM EM

SNS (Cleeton) SNS (Easington)

Export West Sole Suction

1 x 100% Dresser Rand 2 x 100% Cooper

RC6-5B

DT ?

ABB GT35 Rolls Avon

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BP Amoco North Sea Assets Compressor Inventory Thistle

LP Gas Lift HP Gas Lift

1 x 100% Demag 1 x 100% Demag

8B26 7B26

DT DT

EM EM

Ula

LP Export Reinjection (wef 10/97)

1 x 100% Delaval Stork 1 x 100% Delaval Stork 1 x 100% Sulzer

4B22 7B22

W W DTR

EM Same shaft EM

Wytch Farm

Sales Gas Export Refrigeration LP Flash Gas HP Gas Flash Flash Gas

2 x 50% 1 x 100% 1 x 100% 1 x 100% 1 x 100%

LMC331P 8BL37/44 5B22 6B22 WBF74xHD

W W W W

EM EM EM (same shaft) EM (same shaft) EM

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Sundstrand Delaval Stork Delaval Stork Delaval Stork Superior (Leased)

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Hydrate Formation • •

•

•

Presence of water in gas transportation system may result in hydrate formation and/or corrosion Hydrate Formation – presence of free water – low temperature – high pressure – C1-C4 parrafins Corrosion – partial pressure H2S/CO2 – temperature – water pH Formation boundary estimated by; – charts (on right) – Katz K Values – equations of state • modules within most commercial simulators

Pressure-Temperature Curves For Predicting Hydrate Formation

Note that this figure should only be used for first approximations of hydrate formation conditions Upstream Process Engineering Course

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Hydrate Curves 120

100

Pressure (bara)

80

60

40

20

0 -50

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-40

-30

-20 -10 0 Temperature (deg C)

0% Methanol

10% Methanol

30% Methanol

40% Methanol

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10

20

30

20% Methanol

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Hydrate Inhibition •

– – –

•

•

•

Formation boundary suppression methanol glycol threshold hydrate inhibitors

– –

Empirical Hammerschmidt equation for prediction of the necessary inhibitor d  Mi concentration: X  100  Ki  d  M i X d Mi

Weight percent of inhibitor in the liquid water phase (wt%) Depression of hydrate point (oC) Molweight of inhibitor

Ki

Constant: 1297 for methanol 2220 for glycols

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Hammerschmidt gives good results at low inhibitor concentrations (but errs on the conservative side):

•

MeOH MEG

< 25 wt% < 15 wt%

The total inhibitor injection rate is found from:

 XR   mI  mW    XL  XR  mI mW XR XL

mass of inhibitor solution (kg) mass of liquid water (kg) rich inhibitor concentration (out) (wt%) lean inhibitor concentration (in) (wt%)

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Equilibrium Charts Vapour-Liquid Equilibrium of Methanol over Water

Water Content of Sweet Lean Natural Gas

• Losses to vapour phase: y/x (= K-value) Upstream Process Engineering Course

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Inhibition Worked Example •

•

•

10 MMscfd (2.83*105 stm3/d) of natural gas ( = 0.65) having a hydrate formation temperature of 21.1oC cools to 4.4oC in a buried pipeline (pressure is 6.2 MPa). How much methanol ( = 800 kg/m3, MW = 32) must be added if the gas enters the line saturated at 32.2oC and what is the rate of injection ? Calculate hydrate point depression: d = 21.1 - 4.4 = 16.7oC

Calculate the required mass of methanol in water:  29.2  mMeOH  181   75 kg / day 100  29.2 

•

Calculate the methanol loss to the vapour phase using the vapour-liquid equilibrium chart (4.4oC, 6.2 MPa):

Vaporisation losses  17 

Use chart for water content of lean natural gas and calculate the amount of liquid water: Water content @ 32.2oC = 800 kg/106 stm3 Water content @ 4.4oC = 160 kg/106 stm3 640 kg/106 stm3 640kg 0.283 106 stm3 Total liquid H 2O  6   181 kg / day 10 stm3 day

•

•

mMeOH 

kg MeOH / 106 stm3 wt % MeOH in water phase

17 kg MeOH 0.283 106 stm3   29.2 wt % MeOH 106 stm3 day

= 140 kg/day Total injection rate = 75 + 140 = 215 kg/day or

Use Hammerschmidt equation: X MeOH  100 

16.7  32  29.2 wt % 1297  16.7  32

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215 / 0.8 = 269 liter/day

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Hydrate Inhibition Comparison of Inhibitors for Hydrate Suppression Inhibitor

Min. Temp oC

Remarks

Methanol

Minus 95 Possibly to minus 106

Can be regenerated and recovered from liquid hydrocarbons. Significant vapour losses above minus 25oC

Minus 40

Can be regenerated. Lower vapour losses and less solubility in liquid hydrocarbons than methanol. Significant vapour loss above minus 1oC

Minus 10

Use only in warmer, low pressure systems where glycol losses are high or where glycol dehydration is used in conjunction with glycol injection

Ethylene Glycol (MEG)

Diethylene Glycol (DEG)

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Gas Dehydration Technologies Dehydration Method

Glycol Injection Glycol Absorption Glycol Absorption (with stripping gas) DRIZO Adsorption Membranes

IFPEX-1

Vortex Tubes

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Dewpoint Depression o C 35 – 40 35 – 55 55 – 78 70 – 85 50 – 90 80 – 90

90

BP Amoco Assets

Cleeton

Typical Equipment Cost (not installed) $k/MMscfd 3.2

Forties Bravo, Gyda, Magnus

5.8

Bruce Ula, Miller, Clyde, Wytch Farm Endicott (small unit) Easington (test rig) East Gilby Gas Plant (Petro-Canada), Markham Gas Plant (Marathon)

25 – 60

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8.4 cheaper than DRIZO; ETAP study; 30% cost & weight savings ETAP-study; cost savings of over 60% over conventional gas processing (glycol, turboexpander) Erskine-study; 10-20% overall topsides cost saving over conventional processes Gas Handling

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Gas Dehydration • •

•

Glycol/Methanol Injection Glycol Contacting – simple – Cold Finger – OPC DRIZO Solid Dessicants – Molecular Sieves – Silica Gels

Comparison of Dehydration Methods Method

Gas Specification (ppm v/v)

Gas Specification (lb/MMscf)

TEG Contacting

20

1

5

0.25

2

0.1

1 2

0.05 0.1

10 20

0.5 1

Solid Desiccants

Membranes

Remarks Atmospheric regeneration Min. contact temp 15-26oC Vacuum regeneration and gas stripping Regeneration by azeotropic distillation (OPC Drizo) Molecular sieves Alumina Silica gel (high capital/operating costs) "Permea"

• Membranes – new technology Membrane Separator for Natural Gas Dehydration Upstream Process Engineering Course

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Glycol Injection Glycol injection (usually MEG) can be used either to protect against hydrate formation in transmission lines from offshore facilities or upstream of gas refrigeration systems on onshore treatment plants. Glycol injection is possibly the simplest method of dehydrating natural gas, as in its simplest format it consists of an injection pump and injection point(s). If required, the injected glycol can be recovered in a glycol still where the absorbed water is driven off from the glycol. It is always economic to recover glycol from a continuous process. The glycol can be injected into the pipeline or into various sections of the unit upstream of the chilling facilities. Spray nozzles are used to ensure good dispersion into the gas the chilling facilities. Spray nozzles are used to ensure good dispersion into the gas phase. As the gas is cooled and water condenses, the glycol dissolves in the water phase. The gas and liquid phases are separated downstream in one or more separators as the gas is processed further. The glycol water mixture is drawn off and sent to the glycol regeneration unit. The flow description and facilities are very similar to the glycol regeneration unit described in the conventional glycol absorption system. Upstream Process Engineering Course

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Glycol Injection

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TEG Dehydration/Regeneration PC

Stripping Gas

Water Vapour (+ some HC, BTX)

Drizo® (aromatic, naphtenic, paraffin mixture)

Rich TEG

Vent low HC/BTX

Cooler (Air/Water)

Dry Gas Still Column Flue gas

dehydrati on.exe

Glycol/Glycol Exchangers

Reboiler Water LC

Drizo®

Wet Gas

Coldfinger® LC

Surge Tank

Glycol Contactor

To Still Column

Filters Flash Drum LC

Lean TEG Trim Cooler Upstream Process Engineering Course

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Drizo Refit on Ekofisk Prosernat France

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Glycol Contacting •

Water is absorbed into glycol in a bubble tray or packed counter current contactor

•

Contactor design:

vmax •

•

For tray type contactors a minimum spacing of 24” is recommended to prevent the formation of stable foams between trays and to allow for a suitable liquid level in the downcomers

vmax Ks

Structured packing types:

L G

– –

Mellapak, Montzpak, Flexipak, Gempak Advantages of structured packing: • • • •

•

smaller diameter tower (cheaper) better mass transfer no leak problems on trays not very sensitive to motion

•

Number of actual trays usually between 4 - 8

•

TEG circulation rate (rule of thumb): 20-40 liter TEG / kg H20 absorbed

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   G  K s   L  G

  

0.5

Maximum allowable superficial gas velocity (m/s) Constant (m/s) 0.0488 for 24” tray spacing and 2” seal over bubble cap slots 0.1 for structured packing Density of TEG (kg/m3) Density of gas (kg/m3)

Contactor designs available form key suppliers – Natco – Robert Jenkins – BS&B – Kvaerner Paladon – Latoka – KCC – Allen Tank

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Absorption Glycol rate Water content

Glycol purity

Multiple variables Know gas rate and required outlet water content Outlet water quality sets inlet (lean) glycol purity Glycol circulation rate set by equilibrium calculations Tower diameter normally established by entrainment limits

Vessel Diameter

Packing height from packing characteristics Packing height

Reboiler duty from heat balance - latent and sensible.

..\..\Simulations\GLYCOL MODEL.HSC Gas rate

Glycol purity

Water content

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Packing Characteristics

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Trays

Conventional Trays

Vortex Trays

Vortex Tray (Sulzer®)

Chimney Tray

Bubble Caps (Sulzer®) Bubble Caps

Package Trays (Nutter®) Upstream Process Engineering Course

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Packings

Ring Packing Koch-Glitsch® Sulzer

Tower Internals Koch-Glitsch® Upstream Process Engineering Course

Random Packing Koch-Glitsch

Mellapak®

Flexigrid Koch-Glitsch®

Structured Packing Koch-Glitsch®

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Snap-Grid Nutter® Gas Handling

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Distributors / Collectors

Sulzer Distributor/Collector Type VE

Sulzer Special Design Very low liquid loads

Sulzer Type VE

Sulzer Type VK

Distributors

Collectors Sulzer Type SLR

Sulzer Type SLMT Upstream Process Engineering Course

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Upthrust Damage

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Water Dewpoint / Lean TEG Concentration •

•

•

The achievable water dewpoint from the glycol contactor depends on the inlet lean TEG concentration (equilibrium) It is normal practice to take the desired dewpoint 5-10oC below the equilibrium dewpoint (approach) as equilibrium will not be reached in a contactor.

Minimum Lean TEG Concentration

Problem: What should be the concentration of a lean TEG solution achieving an equilibrium dewpoint of -15oC in a contactor operating at 30oC ?

•

Solution: To be on the safe side, an approach of 10oC is subtracted  Equilibrium dewpoint is -25oC From the chart on the right, read the lean TEG concentration at the intersection of the dewpoint line and the contactor temperature line:  Lean TEG concentration: 99.4 wt%

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Gas Dehydration Comparison of Glycols for Dehydration Glycol DEG (Diethyleneglycol)

Advantages

Disadvantages Cheap Larger carry-over loss Less dewpoint depression Regeneration to high concentrations is more difficult Used in almost 100% of glycol dehydration systems

TEG (Triethyleneglycol) TREG Lower carry-over loss due to (Tetraethylene- lower vapour pressure glycol) Can be used on gases whose temperature exceeds about 50oC

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More expensive

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Glycol Dehydration / Regeneration •

Glycol Regeneration Methods: – Reboiler/regenerator column using stripping gas (fuel gas) – DRIZO®-process using an aromatic recycling stripping solvent • • • •

very high stripping gas rates little or no venting of hydrocarbons glycol concentrations of > 99.99 wt% can be achieved condensation and recovery of the aromatic hydrocarbons from the still column overhead

– Coldfinger® using a cooling element in the surge tank to condense water, thus reducing the water partial pressure in the vapour space and increasing the lean glycol concentration • glycol concentrations of > 99.4 wt% can be achieved without the use of a stripping gas

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Glycol System Operating Issues Hydrocarbon Content - If hydrocarbons are present, the unit may be subject to foaming and the formation of gummy or tarry deposits in the reboiler, heat exchangers, and absorber. Corrosion - A glycol pH of less than 6 indicates a potentially serious corrosion problem with the system. Foaming - Can be induced by hydrocarbons, salts and degredation products. Salt precipitation - Can cause problems with reboiler. Glycol Carryover - Poor tower design Chimney tray Design - Poor design can lead to re-entrainment. A simple visual inspection of the glycol can provide clues for identifying many glycol problems. The following conditions can indicate major problems: The presence of a finely divided black precipitate is the result of iron corrosion.

A black viscous glycol solution may be the result of heavy hydrocarbon contamination or glycol polymerization due to thermal breakdown or interaction with hydrocarbons. A sweet, aromatic odour may be an indicator of thermal degradation of the glycol. A two-phase solution indicates hydrocarbon contamination.

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Adsorption - Molecular Sieves • •

Adsorption of water onto solid molecular sieve dessicant Material categories (alumino-silicates): – – – –

• • •

bauxite alumina silica gel molecular sieves

Batch process on timed cycle One bed on stream other under regeneration Key vendors: – – – – –

UOP (Alumina, Molecular Sieves) W R Grace (Silica Gel, Molecular Sieves) Rhone-Poulenc (Alumina, Molecular Sieves) Solvay (Silica Gel) Kvaerner Process Systems (Equipment)

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•

An adsorbent material should have the following characteristics: – – – – – – – – –

large surface area “activity” for components to be removed high mass transfer rate easily and economically regenerated good activity retention with time small resistance to gas flow high mechanical strength cheap, non-corrosive, non-toxic, chemically inert, high bulk density no appreciable change in volume during adsorption desorption

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Molecular Sieve System PC

Wet Gas Inlet Sequence Controller

FC

Condensate Separator Cooler

Cooling

Heater LC

Heat TC

Molecular Sieve adsorber

Regeneration

Molecular Sieve adsorber

Drain

Cool

Heat

Heating

Cooling

Drying

Cool

Dry Gas Outlet Filter Upstream Process Engineering Course

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Operating Characteristics Dry Desiccant Dehydration •

Recommended Operating Range: – –

•

Desiccant Service: –

•

Varies with water loading and gas rate: 4 - 24 hours

Regeneration: –

•

Essentially bone dry gas. Dewpoint: -75 to -125oC (Silica Gel: -60oC)

Length of Cycle: –

•

3 - 5 years in absence of poisoning. Limited by loss of capacity, dusting and breakage

Dehydration Obtained: –

•

T < 50oC T > Hydrate point

Temperature: 175 - 300oC. About 5 to 15% of the total gas stream is used for regeneration. 8 hour cycle: 6 hours heating, 2 hours cooling

•

Advantages: – – – –

–

Low exit dewpoint Effective dewpoint depression over a wide range of operating conditions Compact Relatively low initial investment for small amounts of gas (batch or semi-batch operation) Rated capacity may be increased by by-passing some wet gas

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Disadvantages: – – – – –

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High initial investment Desiccant sensitive to poisoning Rated capacity declines with pressure Pressure drop is higher than liquid desiccant systems Regeneration heat load can be high in relation to the amount of gas processed

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Molecular Sieve - Design Rules •

Preliminary sizing rules: – – – –

Maximum Superficial Velocity

Sieve bed quantity: 10 kg sieve/kg water adsorbed Bulk density (average): 722 kg/m3 The bed height is calculated from the quantity of sieve bed required (above) The bed diameter is calculated from the gas maximum superficial velocity (chart on the right)

•

Three beds are sometimes used as this allows one bed to be on-line, one bed on stand-by and the other being regenerated

•

Cycle times will be in the region of 4 to 24 hours depending on the water loading and gas rate. Optimum cycle times will vary from 4 to 8 hours

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IFPEX Gas dehydration can be achieved by chilling a gas stream to low temperatures in order to remove water down to a level which is equivalent to the specified water dewpoint. One complication of such a process is the need for a hydrate inhibitor to prevent hydrates forming at low temperatures. Institut Francais du Petrole (IFP) has developed a scheme which uses methanol for such a duty and overcomes the traditional regeneration problems associated with methanol. The novel regeneration process consists of a packed column to enable a slipstream of the wet gas stream, to be contacted with the water/methanol stream from the Low Temperature Separator. The gas effectively strips the methanol out of the water stream producing a discharge water stream containing as low as 50 ppm of methanol (suitable for offshore disposal). Methanol losses from the Low Temperature Separator to the vapour and liquid hydrocarbon streams are accounted for by means of a methanol make-up which is added to the inlet gas stream prior to chilling. The main benefits of the process are the simple, environmentally friendly regeneration (minimal losses) process, small footprint area over conventional dehydration schemes, suitability for unmanned platforms and the ability to dewpoint the gas at the same time as it is being dehydrated. The main drawbacks are the methanol losses to the hydrocarbon phases and the dual dehydration and dewpointing function. This is a drawback, as well as an advantage, as if the water specification is severe whilst the hydrocarbon dewpoint is not, IFPex-1 will essentially overtreat the gas and produce large amounts of unwanted condensate.

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Dehydration Technologies Comparison Actual Outlet Gas Specification 1.50

1.25

Calibration is 1lb/MMscf = 20ppmv

30

A

A

Glycol Absorption (A) Forties Bravo (B) Gyda (C) Frigg (Elf) (D) Magnus (E) Bruce

25

C

1.00

20

0.75

15

A

A

B

B

20ppm

Cold Finger

10

Molecular Sieve (A) Ula (B) Miller (C) Wytch Farm

10ppm

Stripping Gas

7ppm

0.25

E

5

Glycol Injection (A) Cleeton Silica Gel (A) Dimlington Terminal (B) Q8 Terminal Netherlands

D

0.50

Example Applications

Membrane (A) Easington Test Rig

Drizo

2ppm

2ppm

C

2ppm

1ppm

0

0

Ib/MMscf Pppm

Glycol Absorption

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Glycol Injection

IFPEXOL

Methanol Injection

Silica Gel

Molecular Membranes Sieve

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Gas Handling

82

Shell Twister - Dehydration Technology

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Combination of Thermo, Fluid and Aero Dynamics All in one - compact device & no moving parts – Inlet Nozzle & Vortex Tube = Turbo Expander – Supersonic Wing = Gas/Liquid Separation – Diffuser = Re-Compressor (Pressure Recovery stage)

Upstream Process Engineering Course

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Gas Handling

83

Shell Twister - Dehydration Technology Phase Envelope comparison with other dehydration technology

• Thermodynamic Process is essentially Isentropic. • Higher Isentropic Efficiency than a Turbo-Expander. • Enters the hydrate region at centre point of tube. Upstream Process Engineering Course

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Gas Handling

84

Shell Twister - Dehydration Technology

Example PFD of Twister Technology

Upstream Process Engineering Course

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Gas Handling

85

Shell Twister - Dehydration Technology Potential Space saving wrt Traditional technologies has offshore applications for Normally unattended installations

Upstream Process Engineering Course

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Gas Handling

86

Fiscal Gas Metering •

Fiscal Gas Metering: – Gas is metered for accounting and to meet the requirements of the Department of Energy (DoE) for reporting and taxation – The basis of metering is mass flow by on line density measurement – The recognised principle of measurement is use of orifice plates, with corrections for pressure, temperature, density, and relative density variations – Ultrasonic technology become more accepted

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Gas Metering Skid

Gas Handling

87

Ultrasonic Flow Metering One transducer transmits a signal downstream the flow. A second transducer transmits a signal upstream against the flow along the same path. A sound wave going with the flow travels faster than one propagated against the flow. The time the acoustic pulses take to travel across, with and against the flow, is measured very accurately. The difference in transit times is directly proportional to the medium's mean flow velocity.

The volumetric flow rate is the product of the mean velocity multiplied with the cross section of the pipe. KROHNE Meter

Upstream Process Engineering Course

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Gas Handling

88