chimagwu enyi presentation 2009

8/14/2019 Chimagwu Enyi Presentation 2009

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DEFINITIONDEFINITION

Natural Gas is a naturally occurring gaseous mixtureNatural Gas is a naturally occurring gaseous mixture

of hydrocarbon and non hydrocarbon gases found inof hydrocarbon and non hydrocarbon gases found in

underground rock reservoirs either on its own as freeunderground rock reservoirs either on its own as free

gas or in association with crude oil.gas or in association with crude oil.

** Hydrocarbon Components: CHydrocarbon Components: C11 C C77++

** Non Hydrocarbon ComponentsNon Hydrocarbon Components

- Nitrogen (N- Nitrogen (N22))

- Hydrogen Sulphide (H- Hydrogen Sulphide (H22S)S)

- Carbon Dioxide (Co2)- Carbon Dioxide (Co2)

- Water Vapour (H- Water Vapour (H220)0)

o


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TYPES OF NATURAL GAS DEPOSITTYPES OF NATURAL GAS DEPOSIT

Associated GasAssociated Gas: Gas Co-exists in reservoir with Crude Oil.: Gas Co-exists in reservoir with Crude Oil.

Non-Associated GasNon-Associated Gas: Gas exists without oil in the Reservoir.: Gas exists without oil in the Reservoir. Gas Condensates:Gas Condensates: Gases exists in gaseous form in the reservoir but liquefy onGases exists in gaseous form in the reservoir but liquefy on

production due to reduction in pressure. Gas condensates are of higher qualityproduction due to reduction in pressure. Gas condensates are of higher quality

and are therefore of more economic value.and are therefore of more economic value.

Gases containing HGases containing H22S and CoS and Co22 are called acid gases because they form acids orare called acid gases because they form acids or

acidic solution in the presence of water.acidic solution in the presence of water.

A gas is called sour if it contains HA gas is called sour if it contains H22S in amounts above 4ppmS in amounts above 4ppm


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Methane CH4 LNG

Ethane C2H6

Propane C3H8

Butanes C4H10

Pentanes and Heavier C5H12

Non-Hydrocarbons

NGLLPG

NG

LPG: Liquefied Petroleum Gas

NGL: Natural Gas Liquids

LNG: Liquefied Natural Gas


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GAS PRODUCTION SCHEMATICGAS PRODUCTION SCHEMATIC

Market

Pipeline

Compression

Processing

Production Tubing

Inflow PerformanceReservoir


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USES OF NATURAL GASUSES OF NATURAL GAS

Current Use of Natural Gas and Future Options


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PROPERTIES OF NATURAL GASPROPERTIES OF NATURAL GAS- Ideal Gases : the Ideal Gas LawIdeal Gases : the Ideal Gas Law

PV = nRTPV = nRT

Where:Where:

P = Absolute Pressure (psia)P = Absolute Pressure (psia)

V = Volume (ftV = Volume (ft33))

n = No. of Moles of gasn = No. of Moles of gas

R = Universal Gas ConstantR = Universal Gas Constant

T = Absolute Temperature (T = Absolute Temperature (00

R)R)If M = Mass of gas (Ib)If M = Mass of gas (Ib)

And M = Molecular wt of the gas (Ibm/Ib-mol)And M = Molecular wt of the gas (Ibm/Ib-mol)

M

mn =

M

mn =

RTMmPv =

RTV

mPM = = pRT

gastheofdensity

RT

PMP ==


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Gas Gravity (yGas Gravity (ygg): the specific gravity of a gas is defined as the ratio of): the specific gravity of a gas is defined as the ratio of

the density of the gas to the density of dry air, at stp.the density of the gas to the density of dry air, at stp.

29

gg

g

M

pair

p

y ==

Apparent molecular weight: a gas mixture behaves as if were a

pure gas with a definite molecular weight. This molecular weight isknown as an apparent molecular weight. It is defined as

Where

Ma = Apparent Molecular weight of Mixture

yi = Mole fraction of component

Mi = Molecular weight of component i

Ma = yiMi


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REAL GASESREAL GASES

The assumption for ideal gas law do not hold for gases at pressures andThe assumption for ideal gas law do not hold for gases at pressures and

temperatures that deviate from the ideal or standard conditions must be madetemperatures that deviate from the ideal or standard conditions must be made

to account for the deviation from ideal behaviour.to account for the deviation from ideal behaviour.

The most widely used correction method is the gas compressibility factor orThe most widely used correction method is the gas compressibility factor or

the gas deviation factor or the Z-factor.the gas deviation factor or the Z-factor.

Videal

VactualZ=

Z

VactualVideal=

For a certain quantity of gas, we write

22

22

11

11

TZ

VP

TV

VP

=

Where: Z1 = Gas deviation factor at condition 1

Z2

= Gas deviation factor at condition 2


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Density of Real GasDensity of Real Gas

RTM

MZPV =

ZRT

PMP=

At standard conditions (P = 14.73psia, T = 520R)

ZT

PyP

g7.2=

THE THEOREM OF CORRESPONDING STATES

Reduced Temperature

Reduced Pressure

Reduced Volume

Tc

TTr=

Pc

P=Pr

Vc

VVr=

Where:

T = actual temperatureP = actual pressureV = critical temperatureTc = critical temperaturePc = critical pressure

Vc = critical volume


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DETERMINATION OF Z - FACTORDETERMINATION OF Z - FACTOR

Using Standing and Kate CorrelationUsing Standing and Kate Correlation

If Gas composition is givenIf Gas composition is given- Pseudo critical pressure: PPseudo critical pressure: Ppcpc == yy iiPPcici- Pseudo critical temperature: TPseudo critical temperature: Tpcpc == yy iiTTcici If Gas composition is not given but gas gravity is given:If Gas composition is not given but gas gravity is given:

PPpcpc = 709.604 58.718y= 709.604 58.718ygg

TTpcpc = 170.491 + 307.344 y= 170.491 + 307.344 ygg

For a gaseous mixtureFor a gaseous mixture

pc

rp T

TT =

pcrp P

PP =

The interception of pseudo reduced pressure and pseudo reducedThe interception of pseudo reduced pressure and pseudo reduced

temperature on standing and Katz chart gives the z factortemperature on standing and Katz chart gives the z factor


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GAS FORMATION VOLUME FACTOR (BGAS FORMATION VOLUME FACTOR (Bg)g)

Where:Where: V = volume at reservoir conditionV = volume at reservoir condition

Vsc = volume at standard conditionVsc = volume at standard condition

From the equation of stateFrom the equation of state

sc

g

V

VB =

( )VolStd

vol

PTZ

PZT

nRTZ

Px

P

ZnRTB

scsc

sc

scsc

scg

.=

=

At standard conditions: PAt standard conditions: Pscsc = 14.7psia and T= 14.7psia and Tscsc =520=52000R, ZR, Zscsc = 1= 1

scfftP

ZTBg /0283.0

3=


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VISCOSITY OF NATURAL GASVISCOSITY OF NATURAL GAS

This is defined as a measure of resistance to flow exerted by the gas. The unit of viscosity is the centipaise.This is defined as a measure of resistance to flow exerted by the gas. The unit of viscosity is the centipaise.

There are two ways of estimating viscosityThere are two ways of estimating viscosity Laboratory methodLaboratory method CorrelationsCorrelations

By Lab MethodBy Lab MethodIf analysis of the gas mixture is known and the viscosities of the components are known, thenIf analysis of the gas mixture is known and the viscosities of the components are known, then

( )( )

=ii

ii

My

Myi

2

2

By Correlations

( ) ( )rrTPfandTMf ==

12 ,

(a) Compute AMW of the gas yiMi

(b) Determine the of the gas mixture at 1 atmosphere using chart. If the pressure of

the mixture is above 1 atm then

3. Calculate pseudo critical temperature/pressure

4. Calculate reduced temperature/pressure

5. Determine the viscosity ratio ( g/ gi ) from chart

6. Calculate g

7. If the gas contains non-HC components, then the should be corrected using chart.

ig


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ESTIMATION OF GAS RESERVESESTIMATION OF GAS RESERVES

Three methods are availableThree methods are available

1.1.Volumetric MethodVolumetric Method

2.2.Material Balance MethodMaterial Balance Method3.3.Pressure Decline MethodPressure Decline Method

Volumetric MethodVolumetric Method

This is applied in a new field for rough estimates. No production history isThis is applied in a new field for rough estimates. No production history is

required. We need only geological data like porosity, water saturation etc.required. We need only geological data like porosity, water saturation etc.

( )gi

wi

B

SAhG 143560

Where: A = Area of the reservoir (Acres)

h = Formation thickness (ft)

= PorositySwi = Water Saturation

Bgi = Initial gas formation vol factor

G = Gas initial in plae


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Gas produced at any given condition (Gp) isGas produced at any given condition (Gp) is

( )

=

ggi

wipBB

SAhG11

143560

Recovery FactorRecovery Factor

g

gip

gB

B

G

GE == 1

MATERIAL BALANCE METHODMATERIAL BALANCE METHOD

This is used for reservoir that has produced long enough.This is used for reservoir that has produced long enough.

There are two cases:There are two cases:

- Without water production/influxWithout water production/influx

- With water production/influxWith water production/influx

Without water production/influxWithout water production/influx

( )g

gig

pB

BBGG =

With water production/influxWith water production/influx

( )

g

wpe

g

gig

pB

BWW

B

BBGG

+

=


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PRESSURE DECLINE METHODPRESSURE DECLINE METHOD

i

i

ibb

pb

Z

P

VTZ

TGP

Z

P+=

COMPRESSION OF NATURAL GASCOMPRESSION OF NATURAL GAS

Add energy to the gasAdd energy to the gas

TYPES

(1)Positive Displacement Compressors

- Reciprocating Compressors

- Rotary Blowers

(2)Continuous flow compressors- Centrifugal Compressors

- Ejectors

Reciprocating compressors are the most commonly used in

gas industry


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COMPONENTSCOMPONENTS

- PistonPiston

- CylinderCylinder

- Suction/Discharge ValvesSuction/Discharge Valves

- Connecting RodConnecting Rod

- ImpellerImpeller

- ShaftShaft

- DiffuserDiffuser- VoluteVolute

COMPRESSION CYCLECOMPRESSION CYCLE

- Ideal CycleIdeal Cycle- Actual CycleActual Cycle


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MULTISTAGE COMPRESSOR ARRANGEMENTMULTISTAGE COMPRESSOR ARRANGEMENT

Compressor Ratio r =Compressor Ratio r =s

d

PP

1 2 3Ps Pd

For design purposesFor design purposes r < 6r < 6

For practical purposesFor practical purposes rr 44

- Optimum Number of stages is given by- Optimum Number of stages is given by

n

s

d

PP

r

1

=

Where:Where:

Pd = discharge pressure (psia)Pd = discharge pressure (psia)

Ps = suction pressure (psia)Ps = suction pressure (psia)

n = No of stages requiredn = No of stages required


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COMPRSSOR DESIGNCOMPRSSOR DESIGN

This involvesThis involves

1.1. The determination of compressor capacityThe determination of compressor capacity

2.2. The determination of power requirementsThe determination of power requirements

-- Determination of compressor capacityDetermination of compressor capacity

4

2

vLSEdq

=WhereWhere

q = Flow capacity (scfd)q = Flow capacity (scfd)

d = Piston diameter (ft)d = Piston diameter (ft)

L = Stroke length (ft)L = Stroke length (ft)

S = Compressor speed (rpm)S = Compressor speed (rpm)

Ev = Volumetric efficiencyEv = Volumetric efficiency


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The volumetric efficiency is calculated fromThe volumetric efficiency is calculated from

ZZ11 = gas derivation factor at suction condition= gas derivation factor at suction condition

ZZ22 = gas derivation factor at discharge condition= gas derivation factor at discharge condition

K = Cp/Cv = Isentropic exponentK = Cp/Cv = Isentropic exponent

= 11

1

2

1 kv r

Z

ZCAE

DETERMINATION OF COMPRESSOR HORSEPOWERDETERMINATION OF COMPRESSOR HORSEPOWERTheoretical HP is determined by 3 waysTheoretical HP is determined by 3 ways

- Analytical methodAnalytical method

- Mollier diagramMollier diagram

- Quickie estimateQuickie estimate

ANALYTICAL METHOD:ANALYTICAL METHOD:

( )( )

= 11

1

027.31

K

KZr

K

KT

T

PW s

b

b


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Where:Where:

W = Power required HP/MNscfW = Power required HP/MNscf

PPbb = Pressure at standard condition (psia)= Pressure at standard condition (psia)

TTbb = Temperature standard condition (oR)= Temperature standard condition (oR)TT11 = Suction Temperature (oR)= Suction Temperature (oR)

ZZ22 = Gas deviation factor at suction condition= Gas deviation factor at suction condition

Mollier DiagramMollier Diagram

W = 0.0432W = 0.0432 HH

wherewhereW = Power required (HP/MNSIFD)W = Power required (HP/MNSIFD)

H = Enthalpy change (BTU/Ib-mol)H = Enthalpy change (BTU/Ib-mol)


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Quickie ChartsQuickie ChartsUsed for making quick estimates. They give higher values than otherUsed for making quick estimates. They give higher values than othermethods. Should not replace accurate methods.methods. Should not replace accurate methods.

(Copy charts on Page 140).(Copy charts on Page 140).

( )MMcfdbHpT

TVP

b

b /4.14

1

bHp =

OR

bHp =

( )

( )MMcfdbHpT

TqP

b

b /

104

1

Where

V = Inlet capacity of compressor (mmcfd)

q = Inlet capacity of compressor (cfm)

Pb = Standard pressure (Psia)

Tb = Standard temperature (oR)

T1 = Inlet temperature of compressor (oR)

(bHp/MMcfd) = Factor determined from chart

bHp = Power requirement (HP)


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GAS METERINGGAS METERING

To determine volumetric flow ratesTo determine volumetric flow rates To determine pressure loss for a particular flow rateTo determine pressure loss for a particular flow rate

EQUIPMENT USEDEQUIPMENT USED Orifice meterOrifice meter Turbine meterTurbine meter Pilot tubePilot tube

Critical flow proverCritical flow prover

ORIFICE METERINGORIFICE METERING Means of measuring the PD caused by a change in velocity of the gas as itMeans of measuring the PD caused by a change in velocity of the gas as it

passes through a restriction placed in the pipe.passes through a restriction placed in the pipe. Gas flow rate in scf/hr is given asGas flow rate in scf/hr is given as

fhwpCqsc =

Where: qsc = gas flowrate scf/hr

C = Orifice constants

hw = differential press across the orifice (inches H2O)

pf= flowing pressure (Psia)


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C = FC = Fbb FFpbpb FFtbtb FFgg FFtftf FFrr FFpvpv**

YFm

Basic Orifice Factor (Fb): Dependends on the location of the differential taps and theDependends on the location of the differential taps and the

internal pipe diameter and orifice diameter value is obtained from table.internal pipe diameter and orifice diameter value is obtained from table.

Pressure Base Factor (Fpb ): for pressure correction if the pressure base used is notfor pressure correction if the pressure base used is not

14.73psia.14.73psia.

bpb PF 73.14=

Temperature Base Factor (Ftb): for temperature correction if the base temperature is

not 520R.

520

b

tb

TT

=Specific Gravity Factor (Fg): For SG correlation if the gas SG is other than 1.00

5.0

=gYFg


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5.0

520

=fT

Ftf

Reynolds Number Factor (Fr): It accounts for variation of the discharge

coefficient with Reynolds number. Value obtained from chart

Supercompressibility factor (Fpv ): It corrects the variation from the ideal

gas law:

( ) 5.01

=pvF

Expansion Factor (Y): It accounts for change in gas density as the

pressure changes across the orifice. The change is usually small and

therefore ignored

Manometer Factor (Fm): For correction when mercury-type manometer

is used. It accounts for different heads of gas above the two legs of the

manometer. Usually small value and therefore insignificant.

Flowing Temperature Factor (Ftf): For flowing temperature correction

if the flowing temperature of gas is other than 600F


28/63

Turbine MeterTurbine Meter

A velocity responsive meter that is connected in the pipeline such thatA velocity responsive meter that is connected in the pipeline such that

the entire gas stream passes through the meter.the entire gas stream passes through the meter.

A propeller in the meter turns at a velocity which is proportional to theA propeller in the meter turns at a velocity which is proportional to the

velocity of the fluid flowing through itvelocity of the fluid flowing through it A secondary element to sense and totalize the revolutions of theA secondary element to sense and totalize the revolutions of the

propeller is connected.propeller is connected.

Flow in WellsFlow in Wells

Several methods are available for calculating static and flowing pressureSeveral methods are available for calculating static and flowing pressuredrop in gas wells. The most widely used method is that of cullender anddrop in gas wells. The most widely used method is that of cullender and

smith.smith.

The pressure gradient equation applicable to any fluid at any pipeThe pressure gradient equation applicable to any fluid at any pipe

inclination angle is give asinclination angle is give as

)1..(..........2

2

dLg

vdv

dg

vfSing

g

dL

dp

ccc

++=

)2..(..........accfel dL

d

dL

d

dL

d

dL

dp

+

+

=

OR


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Static Bottom Hole PressureStatic Bottom Hole Pressure

For a vertical (For a vertical ( = 90= 9000, Sin, Sin = 1), shut in (v = 0) gas well, equation 1 becomes= 1), shut in (v = 0) gas well, equation 1 becomes

=

=

=

=

H

c

ws

ts

c

g

c

g

dhTZRg

gMd

RZTg

gMdhd

ZRT

PM

g

g

dh

dp

0

)3.......(..........


30/63

In oilfield unitIn oilfield unit

( )( )

=

TZ

Hytsws

g01875.0exp

WhereWhere

Pws = Static or shut in BHP (psia)Pws = Static or shut in BHP (psia)

Pts = Static tubing pressure (psia)Pts = Static tubing pressure (psia)

yg = Gas gravityyg = Gas gravity

H = Well depth (ft)H = Well depth (ft)

factorilitycompressibGasZ

ORtubingtheinetemperaturAverageT

==


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Cullender and Smith MethodCullender and Smith Method

From equation (3), we can writeFrom equation (3), we can write

HyR

MHdhR

Md

TZg

Hws

ts 01875.00 ===

This integral is written in short notation asThis integral is written in short notation as

HyIddTZ

g

ws

ts

ws

ts 01875.0==

Using a series expansionUsing a series expansion

( ) ( ) ( )( )mswsmswstsMStsMS IIIIId ++= 2


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Where

ms = Pressure at mid point of well (H/s)

Ims

= I evaluated at ms

, T

Its = I evaluated at ts, Ts

Iws = I evaluated at ws , Tf

ssms

gmsws

tsms

g

tsms

IIHy

II

Hy

++=

++=

01875.0

01875.0


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FLOWING BOTTOM HOLE PRESUREFLOWING BOTTOM HOLE PRESURE

( )( ) ( )( )

5

2 1exp25exp

2

Sd

SMDfZTqyS

g

wf tf

+=

Where

Pwf = Flowing bottom hole pressure (psia)

S = 0.0375yg (TVD)/TZ

MD = Measure depth (ft)

TVD = True vertical depth (ft)

T = 0R

q = MMScfd

d = inches

f = F(NRR,E/d) (Jain or Colebrook equation)


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FLOW IN PIPELINESFLOW IN PIPELINES

5.2

5.022

21 D

LZTfyP

CTq

gb

b

=

Value of C depends on the units used

T d L q C

Psia 0R in Mi scfd 77.54

Psia 0R in ft scfd 56.38

Psia 0R in ft MMscfd 5.638 x 10-3

Kpa 0K M m M3/d 1.149 x 106

Where

f = friction factor

D = Diameter of pipeline (inches)

L = Length of Pipeline (miles)


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Evaluation of friction factorEvaluation of friction factor

Weymouth =

Panhandle A =

Panhandle B =

3

1032.0

D

147.0Re

/085.0 Nf

183.0

Re

015.0N

Pipeline flow equation without f becomes

[ ]51

432

21

2

1

2

1 a

a

g

aa

b

b dyLZT

TEaq

=

Where the values of as are


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aa11 aa22 aa33 aa44 aa55

Weymouth:Weymouth: 433.50433.50 1.0001.000 0.50000.5000 0.50000.5000 2.6672.667

Panhandle A:Panhandle A: 435.87435.87 1.07881.0788 0.53940.5394 0.46040.4604 2.6182.618

Panhandle B:Panhandle B: 737.00737.00 1.02001.0200 0.51000.5100 0.49000.4900 2.5302.530

qq == ftft33/day/day

TT == 00RR

== psiapsiaLL == milesmiles

dd == inchesinches

Weymouth equation is used for pipeline diameter of dWeymouth equation is used for pipeline diameter of d 16 inches16 inches


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Pipeline in SeriesPipeline in Series

TT == 11 ++ 22 ++ 33

=N

i i

ie

dLdL

1333.5

333.5

Pipeline in ParallelPipeline in Parallel

qqTT = q= q11 + q+ q22 ++qq33

==

N

i

aN

i i

iT diC

f

dCq

1

5

1

1

5.0

5.2


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WELL PERFORMANCEWELL PERFORMANCE

Two phase flow problem in flowing wells can be handled byTwo phase flow problem in flowing wells can be handled by

1.1. Fluid gravity adjustmentFluid gravity adjustment2.2. Correlations Hagedorn & BrownCorrelations Hagedorn & Brown

Gravity AdjustmentGravity Adjustment

- Adjusting gas gravity to a mixture gravity to account for the added densityAdjusting gas gravity to a mixture gravity to account for the added density

due to the liquid.due to the liquid.- The mixture gravity is given byThe mixture gravity is given by

R

Ryyy

Lg

m/11231

4591

++

=

WhereWhere yymm == adjusted fluid gravityadjusted fluid gravity

yygg == dry gas gravitydry gas gravity

yyLL == liquid specific gravityliquid specific gravity

RR == Producing gas liquid ratio (Scf/STB)Producing gas liquid ratio (Scf/STB)


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Hagedorn and Brown Method:Hagedorn and Brown Method:

Ignoring acceleration componentIgnoring acceleration component

dg

VfCos

g

g

dh

dp

c

mf

m

c 2

2

+=

mm == LLHHLL ++ gg (1 H(1 HLL))

L=L= Liquid densityLiquid density

gg = gas density= gas density

HHLL = Liquid holdup (fraction of pipe occupies by liquid)= Liquid holdup (fraction of pipe occupies by liquid)

= angle of well segment from vertical= angle of well segment from vertical

VVmm = V= VSLSL + V+ Vsgsg

VVSLSL = Superficial liquid velocity = q= Superficial liquid velocity = qLL/A/AAA = area of flowing string= area of flowing string dd22/4/4d = flow string IDd = flow string ID

ff == nn22// mm

nn ==

LL ++

(1-(1-

))

=V=V /V/V


40/63

The fraction factor is calculated Jain equation asThe fraction factor is calculated Jain equation as

+

=

9.0

25.21214.1

1

RENd

Logf

m

mnm

dVN

=Re

WhereWhere( )LH

L g

H

Lm

=

1

L = Liquid viscosity= Liquid viscosity

g = gas viscosity= gas viscosity


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To determine HTo determine HLL, we need to calculate, we need to calculate

25.0

3

5.0

25.0

25.0

0.115726.0

872.120

938.1

938.1

=

=

=

=

LLL

Ld

LsggV

LSLLV

N

dN

VN

VN


42/63

WhereWhere VVSL,SL, VVSgSg = ft/Sec= ft/Sec

LL = Ib/ft= Ib/ft33

= dynes / cm= dynes / cmd = ftd = ft

LL= centipoise= centipoise

ThenThen

1.1. Calculate NCalculate NLL

2.2. Find CNFind CNLL from figure 4.7from figure 4.7

3.3. Calculate XCalculate XHH

( ) 1.0575.01.0

agvd

LVH

NNCNLNX

=

WhereWhere aa = 14.7psia= 14.7psia

4.4. Find HFind HLL//b from figure 4.8b from figure 4.8

5.5. Calculate XCalculate X

14.2

38.0

d

Lgr

N

NNX =

6. Find from figure 4.9

7. Calculate HL =

LH


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FIELD HANDLING OF NATURAL GASFIELD HANDLING OF NATURAL GAS

A typical well stream is a high velocity, turbulent and constantlyA typical well stream is a high velocity, turbulent and constantly

expanding mixture of gases, hydrocarbon liquids, water vapour,expanding mixture of gases, hydrocarbon liquids, water vapour,

free water, solids and other contaminants. Field processing offree water, solids and other contaminants. Field processing of

NG consists of four basic processes.NG consists of four basic processes.

1.1. Separation of the gas from free liquids and entrained solidsSeparation of the gas from free liquids and entrained solids

2.2. Processing the gas to remove condensable and recoverableProcessing the gas to remove condensable and recoverablehydrocabon vapoourshydrocabon vapoours

3.3. Processing the gas to remove condensable water vapour to avoidProcessing the gas to remove condensable water vapour to avoid

hydrate formation.hydrate formation.

4.4. Processing the gas to remove other undesirable componentsProcessing the gas to remove other undesirable components

such as hydrogen sulphide and carbon dioxidesuch as hydrogen sulphide and carbon dioxide


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SEPARATORSSEPARATORS

Separation of well stream gas from free liquids/solids isSeparation of well stream gas from free liquids/solids isaccomplished in a separatoraccomplished in a separator

FUNCTIONS OF SEPARATORSFUNCTIONS OF SEPARATORS1.1. Causes of primary phase separation of the liquid hydrocarbonsCauses of primary phase separation of the liquid hydrocarbons

from these that are mostly gas.from these that are mostly gas.

2.2. Refine the primary separation by removing most of the entrainedRefine the primary separation by removing most of the entrainedliquid mist from the gas.liquid mist from the gas.

3.3. Further refine the separation by removing the entrained gas fromFurther refine the separation by removing the entrained gas fromthe liquid.the liquid.

4.4. Discharge the separated gas and liquid from vessel and ensureDischarge the separated gas and liquid from vessel and ensurethat no re-entrainment of one into the other.that no re-entrainment of one into the other.

TYPESTYPES

1.1. VerticalVertical

2.2. HorizontalHorizontal

3.3. Horizontal Double BarrelHorizontal Double Barrel


46/63

Each has specific advantages and selection is based on which one willEach has specific advantages and selection is based on which one will

accomplish the desired results at the lowest cost.accomplish the desired results at the lowest cost.

ACID GAS REMOVALACID GAS REMOVAL

-- Maximum Allowable of HMaximum Allowable of H22S is sales Gas isS is sales Gas is

(0.25gm per 100ft(0.25gm per 100ft33 or 4ppm/100ftor 4ppm/100ft33))

Hydrogen sulphide and carbon Dioxide are removed by Absorption process:Hydrogen sulphide and carbon Dioxide are removed by Absorption process:


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Chemicals used are:Chemicals used are:

MEAMEA

DEADEASulfinolSulfinol

Molecular sieveMolecular sieve

Iron SpongeIron Sponge

GAS DEHYDRATIONGAS DEHYDRATION

Removal of water vapour from natural gasRemoval of water vapour from natural gas

Maximum allowable is 7Ib of HMaximum allowable is 7Ib of H220/Mcf of gas0/Mcf of gas

Processes involvedProcesses involved1.1. AbsorptionAbsorption

2.2. AdorptionAdorption


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LIQUID HYDROCABON RECOVERYLIQUID HYDROCABON RECOVERY Products extracted from the gas in liquid recovery may include:Products extracted from the gas in liquid recovery may include:

EthaneEthane

PropanePropane

IsobutaneIsobutaneNormal butaneNormal butane

Natural GasolineNatural Gasoline


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HYDROGEN SULPHIDE TREATMENTHYDROGEN SULPHIDE TREATMENT

Clans processClans process

Two stages involvedTwo stages involved

Thermal step: HThermal step: H22S is partially oxidized in a furnance to S0S is partially oxidized in a furnance to S022

Temperature 1000 1400Temperature 1000 140000cc

Catalytic step: HCatalytic step: H22S reacts over VS reacts over V220055 catalyst with S0catalyst with S022

002

1

03

2031

31

03

103

102

13

1

222

222

2222

HSSH

HSSSH

HSSH

++

++

++

GAS CONDENSATE SYSTEMSGAS CONDENSATE SYSTEMS


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GAS CONDENSATE SYSTEMSGAS CONDENSATE SYSTEMS

Gas at initial reservoir conditions but condenses to form same liquid atGas at initial reservoir conditions but condenses to form same liquid at

some point in its path to the separator.some point in its path to the separator.

They include both wet gas and retrograde condensate reservoirs.They include both wet gas and retrograde condensate reservoirs.

- Wet gas Fluid initially exists as a gas in the reservior and remains in theWet gas Fluid initially exists as a gas in the reservior and remains in thegaseous phase as pressure declines at reservoir temperature. However, ingaseous phase as pressure declines at reservoir temperature. However, in

being produced to the surface, the temperature drops, causingbeing produced to the surface, the temperature drops, causing

condensation in the piping system and separator.condensation in the piping system and separator.

- Retrograde gas fluid exists as a gas at initial reservoir conditions. AsRetrograde gas fluid exists as a gas at initial reservoir conditions. As

reservoir pressure declines at reservour temperature, the dew point line isreservoir pressure declines at reservour temperature, the dew point line is

crossed and liquid forms in the reservoir, piping system and separator.crossed and liquid forms in the reservoir, piping system and separator.


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PHASE BEHAVIOURPHASE BEHAVIOUR

The phase behaviour of a fluid can be described by determining its response toThe phase behaviour of a fluid can be described by determining its response to

pressure and temperature changes.pressure and temperature changes.

- Liquid: molecules are very close togetherLiquid: molecules are very close together

- Gas: molecules are widely separatedGas: molecules are widely separated

- Confining forces: Pressure and molecular attractionConfining forces: Pressure and molecular attraction

- Dispersing forces: Kinetic energy (temperature) and molecular repulsion.Dispersing forces: Kinetic energy (temperature) and molecular repulsion.

- The magnitudes of the confining and dispersing forces dictate whether theThe magnitudes of the confining and dispersing forces dictate whether the

fluid is a liquid or a gas.fluid is a liquid or a gas.


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For multicomponent systemFor multicomponent system

The difference in molecule size and energy has influence on the phaseThe difference in molecule size and energy has influence on the phase

change.change.

- The locus of all the points where the first bubble of gas appears inThe locus of all the points where the first bubble of gas appears in

liquid as pressure and temperature conditions are changed is calledliquid as pressure and temperature conditions are changed is called

the bubble point here.the bubble point here.

- The locus of all points where the first droplet of liquid appears in aThe locus of all points where the first droplet of liquid appears in a

gas as the conditions are changed is called dew point line.gas as the conditions are changed is called dew point line.- The highest pressure at which a gas can exist is called theThe highest pressure at which a gas can exist is called the

cricondenbar.cricondenbar.

- The highest temperature at which a liquid can exist is called theThe highest temperature at which a liquid can exist is called the

cricondenthermcricondentherm

CALCULATION OF VAPOUR LIQUID EQUILIBRIACALCULATION OF VAPOUR LIQUID EQUILIBRIA


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CALCULATION OF VAPOUR LIQUID EQUILIBRIACALCULATION OF VAPOUR LIQUID EQUILIBRIA

From the relationship:From the relationship:

iii

i

ii xKy

x

yK ==

andand

ZZiin = xn = xiiL + yL + yiiVV

VKL

nZx

i

ii +=

xxii=1 and +=1 and + yyii = 1= 1

HenceHence

1=+

=VKL

nZx

i

ii

andand

1=+

=i

ii

KLV

nZy


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WhereWhere

nn == total No. of moles V in mixturetotal No. of moles V in mixture

LL == total No. of moles V in liquidtotal No. of moles V in liquid

VV == total no of moles V in vapourtotal no of moles V in vapour

ZZii == mole fraction of component i in mixturemole fraction of component i in mixture

KKii == equilibrium ratio of componentequilibrium ratio of component

yy ii == mole fraction of component i in vapour phasemole fraction of component i in vapour phase

xx ii == mole fraction of component i in liquid phasemole fraction of component i in liquid phase

BUBBLE POINT PRESSUREBUBBLE POINT PRESSUREAt bubble pointAt bubble point

VV 00LL nn

HenceHence

=

+=

10 VkL

nZLimy

i

i

Vi

=1i

i

K

ZOR


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NOTENOTE

IfIf ZZiiKKii > 1, the assumed pressure is below> 1, the assumed pressure is below bbIfIf ZZ

ii

KKii

> 1, the assumed pressure is above> 1, the assumed pressure is above bb

1ii K

ZIf The assumed pressure is above d


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DETERMINATION OF INITIAL OIL & GAS IN PLACEDETERMINATION OF INITIAL OIL & GAS IN PLACE

Let:Let: R = Initial surface gas oil ratioR = Initial surface gas oil ratio

yy00 = Specifi gravity of the tank oil= Specifi gravity of the tank oil

MMoo = Molecular weight of the tank oil= Molecular weight of the tank oil

yygg = Specific gravity of produced gas= Specific gravity of produced gas

Standard conditions:Standard conditions: 14.7psia14.7psia

606000FF

379.4 Scf/mole379.4 Scf/mole

Ome the basis of one bbl of tank oil/R Scf of gasOme the basis of one bbl of tank oil/R Scf of gas

- The mass of total well fluid (MThe mass of total well fluid (Mww) is) is

MMww = 0.07636RY= 0.07636RYgg + 350Y+ 350Y00

- The total moles of fluid in one bbl of oil and R cubic feet of gas isThe total moles of fluid in one bbl of oil and R cubic feet of gas isnn tt = 0.002636R + 350 y= 0.002636R + 350 y00/M/Moo

-- The molecular weight of the well fluid MThe molecular weight of the well fluid Mww

0

0

0

350002636.0

35007636.0

MY

R

yRy

n

MM

g

t

ww

+

+==

The specific gravity of the well fluid isThe specific gravity of the well fluid is


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- The specific gravity of the well fluid is- The specific gravity of the well fluid is

0

0

0

800,132

4584

My

R

yRyy

OR

n

My

g

w

t

ww

+

+=

=

5.131

5.141

9.56084

03.129.44

0

0

00

+=

=

=

APIy

APIyyM

nngg = No. of Mole of gas == No. of Mole of gas =

NN00 = No of mole of oil == No of mole of oil =

4.395R

0

0350M

y

Th f ti f th t t l th t i d d th f iThe fraction of the total gas that is prod ced on the s rface as gas is


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The fraction of the total gas that is produced on the surface as gas isThe fraction of the total gas that is produced on the surface as gas is

0nn

nf

g

g

g +=

The total initial gas in place per acre foot of bulk reservoir rock isThe total initial gas in place per acre foot of bulk reservoir rock is

( )( )ftacreMcf

ZRT

SG w

= /

1664,528,16

Hence:Hence:

Initial Gas In Place = fInitial Gas In Place = fggGG

Intial Oil in Place =Intial Oil in Place =R

Gfg

THERMODYNAMICS CONCEPTSTHERMODYNAMICS CONCEPTS


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THERMODYNAMICS CONCEPTSTHERMODYNAMICS CONCEPTS

Natural gas processing involves controlling the mass and energyNatural gas processing involves controlling the mass and energy

transfer within, to or from the fluid/stream under consideration.transfer within, to or from the fluid/stream under consideration.

The calculations in natural gas processing involve the prediction ofThe calculations in natural gas processing involve the prediction ofenthalpy, internal energy and entropy of the system.enthalpy, internal energy and entropy of the system.

These functions are determined usingThese functions are determined using

1.1.PVT dataPVT data

2.2.Tables of dataTables of data3.3.Generalized correlations for H and SGeneralized correlations for H and S

4.4.Figures showing H & S as functions of system PVTFigures showing H & S as functions of system PVT

2

2

MVEK =

Kinetic Energy

Potential Energy

MghE =


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Internal Energy (U) energy of system by virtue of its state.Internal Energy (U) energy of system by virtue of its state.

Enthalpy (H): H = U +Enthalpy (H): H = U + VV

Heat (Q): energy in transition across the boundary of the systemHeat (Q): energy in transition across the boundary of the system

Entropy (S):Entropy (S): S = Q/TS = Q/T

Q = MCQ = MC tt

Calculation UsingCalculation Using VT DataVT DataBoth enthalpy and entropy can be expressed in terms of otherBoth enthalpy and entropy can be expressed in terms of other

thermodynamic properties.thermodynamic properties.

ddT

dv

T

dTCdS

ddT

dvTVdTCdH

=

+=


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WhereWhere CC = S= S ht at constant pressureht at constant pressure , T = Pressure and Temperature (absolute units), T = Pressure and Temperature (absolute units)V = Corresponding volume of the systemV = Corresponding volume of the system

Calculation using Table of Thermodynamic PropertiesCalculation using Table of Thermodynamic Properties

The thermodynamic property of a two phase mixture is found fromThe thermodynamic property of a two phase mixture is found from

the saturated tables as:the saturated tables as:

t = (1 x) tg + x t f

WhereWhere t = thermodyanmical property (h, S, V) of mixturet = thermodyanmical property (h, S, V) of mixture

ttgg = thermodyanmical property of saturated vapour= thermodyanmical property of saturated vapour

ttff = thermodyanmical property of saturated liquid= thermodyanmical property of saturated liquid

X = composition of liquid in mixtureX = composition of liquid in mixture

Calculation using Charts and FiguresCalculation using Charts and Figures


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Calculation using Charts and FiguresCalculation using Charts and Figures

The four useful chaarts areThe four useful chaarts are

(1)(1) Enthalpy temperature (H.T)Enthalpy temperature (H.T)

(2)(2) Enthalpy pressure (H.P)Enthalpy pressure (H.P)(3)(3) Enthalpy Entropy (H.S) Mollier diagramEnthalpy Entropy (H.S) Mollier diagram

(4)(4) Temperature Endropy (T.S)Temperature Endropy (T.S)

GAS UTILIZATION AND CONSERVATIONGAS UTILIZATION AND CONSERVATION

- LNGLNG- GTLGTL

- POWERPOWER

- FEEDSTOCKFEEDSTOCK

(Fig required)(Fig required)

chimagwu enyi presentation 2009

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