SPT Gas Condensate vs Oil Wax Deposition

Gas Condensate vs Oil Wax Deposition

Lauchie Duff Olga Users Group 11 November, 2009

OUTLINE

q Recap from Previous Olga Users Presentationq Gas Condensate Misconceptionsq Fluid Characterisation Introduction Using Oil Mq Fluid Characterisation Using A & B Gas Condensates qWax Introductionq Wax Precipitation vs Wax DepositionqWaxy Condensates vs Waxy Oils Depositionq References

Recap Summary: Olga Wax Attack

q Non Newtonian Rheology & How to Model in Olga

Recap: Olga Wax Attack on Non Newtonian Flow

Steady State Shear & Thermal History EffectsOil Cooldowns : SCDP vs CCDP

0

500

1000

1500

2000

2500

3000

3500

4000

4500

20 22 24 26 28 30 32 34 36Temperature (oC)

Apparent Viscosity (mPas)

S 1.20 BT 90C: 2kppm PPD, SCDP

S 1.20 BT 90C: 2kpp PPD, CCDP83% Delta atFinal T

Recap: Non Newtonian Flow: Restarts

Shear & Thermal History Affects on RestartsRestarts Ramps after Shut Down at 16oC: Shear History Effects

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 60 70 80 90 100Shear Rate (s-1)

Shear Stress (Pa)

No ramping after cooldown ramping

WAX / Condensate Misconceptionsq Condensate colour determines contaminationq Subsurface hydrocarbons are homogeneous fluids with no spatial

variation, unlike petrophysical variations.q Waxes are n alkanes only q Measured WATs and wax contents are more accurate than

simulatedq Wax Precipitation equals Wax Depositionq Reported GC / HTGC compositions must be right. The lab has

surely integrated the areas and mass %s correctly?q Condensate compositions terminate around C30-C40q Long compositional heavy tails (of condensates), if they exist, are

very insignificant (compared to oils)q Reported compositions and associated EOSs are matched to

measured dew points by regression of critical propertiesq Condensate near well bore banking of heavy ends does not occur in

high permeability formations

Fluid Characterisation is First (and very big) Step in Wax Deposition

Concepts and Wax Primer: 1 Composition MeasurementsM Oil HTGC vs GC

C52+ = 1.828%

C30+ = 15.047 %

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

0 10 20 30 40 50 60

SCN

Wt%

HTGC

GC

M Oil Compositionq Lets take the HTGC and extend power and exponential laws

M Oil HTGC & Manual Extrapolations

C52+ = 1.828%

y = 29992290.385621x-4.827528

R2 = 0.974967

C52+ = 2.189%

0.0001

0.0010

0.0100

0.1000

1.0000

10.0000

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120 125 130 135 140 145 150

SCN

Wt%

Measured HTGC

HTGC: Manual Extrapolations

Exponential

Power

Power (HTGC: Manual Extrapolations)

y = 78.1118e-0.1220xR2 = 0.9583C52+ = 1.525%

M Oil Compositionq Lets take the HTGC and extend using PVTSim Characterisations-

ie Log Wt% vs Molec Wt is LinearM Oil HTGC & Manual Extrapolations

C52+ = 1.828%

C100+= 0.0785%

y = 29992290.385621x-4.827528

R2 = 0.974967

C52+ = 2.189%

0.0001

0.0010

0.0100

0.1000

1.0000

10.0000

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120 125 130 135 140 145 150

SCN

Wt%

Measured HTGC

HTGC: Basis for Manual Extrapolations

Exponential Extrapolation

Power Extrapolation

PVTSim C100+ Characterisation

y = 78.1118e-0.1220xR2 = 0.9583C52+ = 1.525%

WAX: Composition incl n AlkanesqDoes the n alkane a/c for all the wax?

M Oil HTGC

0.07850.0000

1.0000

2.0000

3.0000

4.0000

5.0000

6.0000

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

SCN

Wt%

HTGC: PVTSim Characterised C100+

n alkanes

M Oil Composition incl n Alkanes

0.07850.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

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

SCN

Wt%

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

Wax% ?


n alkanes as % SCN

M Oil Properties: WAT / WDTq Pour Point = 24oCq WAT by 3 different DSCs(45->75oC) / CPM (39-48.8oC)/ Rheology /

CWDT (51oC) M Oil DSC (Heating Cycle)

2

2.5

3

3.5

4

4.5

5

0 20 40 60 80 100 120

Temperature (oC)

WDT1 = 67OCWDT 2 = 55OC

WDT 2 = 44OC

Heat Capacity

J/gOC

Still Melting at >100oC

M OIL WAX: WDT vs WATq Note endothermic melting curve vs exothermic xlln curve. Ie end of

melting approx at beginning of Xlln. This is a very significant result as it reveals the effect of kinetics on WDT / WAT ie WDT-WAT almost zero

M WAT SIMULATION BASED ON HTGC

Simulated M WAT: 52oC

0

5

10

15

20

25

-30 -20 -10 0 10 20 30 40 50 60

Temperature (oC)

Wax Wt%

Tulsa WAT to C52+

M OIL WAX: Conclusion

qWe have simulated WAT of 52oC vs DSC measured WAT of 63oC & WDT of >100oC. Is this Robust and we can now characterise to these measurements?

WAX: M Oil Composition incl n AlkanesqDoes wax content go down as SCN increases?

0.07850.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

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

SCN

Wt%

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

Wax% ?


n alkanes as % SCN

M OIL : PVTSim CharactersationqPVTSim characterises zero wax after last measured plus

fraction-but is this correct?PVTSims PARAW Characterised Fractions

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 10 20 30 40 50 60 70 80 90 100

SCN

Fraction

Paraffins

Napthenes (Branched & Cyclics)

Aromatics

Waxes

Asphaltenes

WAX: Composition incl n AlkanesqPVTSim characterises zero wax after last measured plus fraction

0.07850.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

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

SCN

Wt%

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

Wax% ?


n alkanes as % SCN

PVTSims Heavy Characterised Wax %

My favourite PhD on WDT vs WAT

Audrey Taggart 1995, Univ Strathclyde Nucleation, Growth and Habit Modification of n Alkanes etc Ref [3]

qTerminology: Meta stable zone width = WDT-WAT

q WDT approaches WAT in the limit of slow cooling

My favourite PhD : WDT vs WAT

MSZW Associated with Crystallite Dissolution & Precipitation from

C18H38 Melt

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

25 26 27 28 29 30

Temperature

Cooling Rate (oC/min)

WAT WDT

MSZW

Tsat (at b =0oC /min)

WDT / WAT and Wax Xtal Effects

MSZWs vs Carbon Chain Lengths

0

0.5

1

1.5

2

2.5

3

12 14 16 18 20 22 24 26 28 30 32

Carbon Chain Length

Meta Stable Zone Width (oC)

MONOCLINIC

TRICLINIC

ORTHORHOMBIC

My favourite PhD on this subject

WATs for Normal Alkanes (Measured at 5oC /min)

-5

5

15

25

35

45

55

65

75

85

95

105

10 15 20 25 30 35 40 45 50 55 60Carbon Number

Temperature (oC)

0

30

60

90

120

150

180

210

240

Enthalpy of Crystallisation (J/g)

WATEnthalpy of Crystallisation

TRICLINIC

MONOCLINICORTHORHOMBIC

WAX PRIMERq Wax is not just n alkanes but many other species. eg Ref [2] determined

microxlline waxes (mpts>60C) to be 20-40% n alkanes,15-40% iso alkanes and approx 35% cycloalkanes.

q Macro and microXlline waxes. Microxlline waxes average 1-2 microns.q MicroXlline waxes MWts from 300 to 2500 (C21-C179).q Relatively poorly measured and limitations of measurements not widely

understood. For example UOP 46 measures wax content at 30C after filtering cold extract through GF filters that retain 1.5 microns (at best) in liquid. CPM measures down to 2 microns at best. Kinetics of cooling affects WAT measurement.

q WAT is defined as 2 ppm most insoluble (highest MWt) species. No lab measurements capable of measuring to this level.

q Recent project: Oil. CPM WAT 39-48oC. DSC WAT at least 63oC.q GC / HTGC Measurements. Lack of resolution as Mwt increases and

Xllinity changes from macro to microXlline.q Recommend best GC / HTGC merged to provide overall fluid

composition.

WAX PRIMER

q Investigation of n alkane content of macro & microXlline waxes:q AW 034 AND AW050 were microxlline and OFM/CFA macroxlline

Must Understand that Micro / Macro Relationship

WAX: Simulated WAT of Oil Mq Simulated WATs 52oC-85oC

Simulated M WATS: 52-85oC

0

5

10

15

20

25

-30 -20 -10 0 10 20 30 40 50 60 70 80 90

Temperature (oC)

Wax Wt%

PVTSim WAT to C52+

Tulsa WAT to C98+

PVTSim (Heavy) WAT

PVTSim: Melting (WDT) vs SCNPVTSim SCN vs Melting Points of n Alkanes

-120

-100

-80

-60

-40

-20

0

20

40

60

80

100

120

140

C7 C10

C13

C16

C19

C22

C25

C28

C31

C34

C37

C40

C43

C46

C49

C52

C55

C58

C61

C64

C67

C70

C73

C76

C79

C82

C85

C88

C91

C94

C97

C100

TM (oC)

If sample contains no more than

C52, then require heating sample

to 90oC in order to melt.

If sample contains C100, then

require heating sample to 125oC

in order to melt.

Equally, if sample contains C100,

WDT - WAT = 125-96= 30oC

If sample only contains C52:

WDT-WAT = 90- 52 = 38oC

GAS CONDENSATE FLUID CHARACTERISATION

Reasons why your gas condensate fluid characterisation is probably wrong.

q Sampling below dew point if MDT, sample contaminationq Compositional gradientsq DST-well conditioning / poor separator control = gas / liquid

entrainmentq Subsampling losing fractionsq Laboratory GC vs HTGC Measurements-improper

measurement heavy fractions: condensate PVT very sensitive to the small amounts heavy fractions

q EOS characterisation issues: Heavy fraction extension


Choosing Representative Samplesq Is there such a thing? ie how do reservoir compositional

gradients affect sample colour for example? Ref [4]


Condensate colourq Ref [6] from onshore Canada describes the asphaltene production as varying from well to well and the condensate colour varies from clear to black between wells in the same field. Ref [6] further describes the condensate discolouration changing from pale yellow at low flow to black at high flow and back to pale yellow when flow is lowered again. Serious asphaltene emulsion and asphaltene fouling occurred during high flow periods. Other wells experienced a permanent shift from clear to dark condensates after absolute open flow tests with compression.q Ref [7] from an onshore Austrian lean gas condensate field also describes the same colouration issues as above being flow related. This reservoir was dew pointed at reservoir conditions (285 bar and 78oC). Plant asphaltene deposition was an issue and the estimated asphaltene content was 5 ppm of the produced liquid phase. The produced, dark coloured condensate streams showed through production testing to have increased colouring at the higher rates, attributed to increased asphaltene uptake.


q Examples of GC vs HTGC and how GC misses heavy fractions Ref [1]


q Examples of GC vs HTGC and how GC misses waxes and other high MWt species

GAS CONDENSATE FLUID CHARACTERISATION` North Sea Gas Condensate Example Ref [5]: HTGC inset

GAS CONDENSATE FLUID CHARACTERISATION1. Condensate A GC vs HTGC

n Company A HTGC C100+ = 3.5 wt%n Company B GC C36+ = 0.384 wt%n Company C GC C35+ = 0.03 wt%

GAS CONDENSATE FLUID CHARACTERISATION1.

2. PVT Consequences of Gas Condensate A GC / HTGC Measurements

n GC based EOS underpredicted two measured dew points by 344 and 690 psi

n HTGC based EOS exactly matched one and underpredicted the other by 190 psi

P Condensate Case History

P Condensate Propertiesn API 46.7 (0.794 g/cc)n Pour point 21oCn Cloud Point 41oC by AMS 259 (CPM cooling at 0.2oC /min (= WAT?)n CWDT 45oCn Wax content ?

P Condensate Case History: PVT

P Gas Condensate VLE (Company X)

0

1000

2000

3000

4000

5000

6000

7000

8000

0 50 100 150 200 250 300 350

Temperature oC

PSIG

Measured Dew Point

Co X Characterisation

PVTSim C20+ Characterisation

P: Reservoir Fluid & TBP GivenReported Compositions: Reservor Fluid P & TBP P

C38+ = 0.36%

C20+ = 6.055 %

0.01

0.10

1.00

10.00

100.00

N2 CO2 C1 C2 C3 iC

4nC

4iC

5nC

5 C6 C7 C8 C9 C10

C11

C12

C13

C14

C15

C16

C17

C18

C19

C21

C24

C28

C32

C38+

SCN

Wt%

Condensate TBP

Reservoir Fluid

Flash P Reservoir Fluid to STPn Why stop at C59+?

"Normal Characterisation" Options: Reservoir STP Flash to C59+

with 55 C7+ Pcs

C62+ = 1.2324%

6.055

0.01

0.10

1.00

10.00

100.00

N2 C2 nC

4 C6 C9 C12

C15

C18

C21

C24

C27

C30

C33

C36

C39

C42

C45

C48

C51

C54

C57

C60-

C62

SCN

Wt%

STP Condensate

Reservoir Fluid

STP P Condensate Compositionn Lets go to C80 being Max PVTSims Normal Characterisation

" Normal Characterisation" Options: Reservoir STP Flash with 74

C7+ Pcs to C80

C80+ = 0.0339%

1.2324%

0.39%

0.00001

0.00010

0.00100

0.01000

0.10000

1.00000

10.00000

100.00000

N2 C1 C3 nC

4nC

5 C7 C9 C11

C13

C15

C17

C19

C21

C23

C25

C27

C29

C31

C33

C35

C37

C39

C41

C43

C45

C47

C49

C51

C53

C55

C57

C59

C61

C63

C65

C67

C69

C71

C73

C75

C77

C79

SCN

Wt%

STP Condy Characterised to C80

STP Condy Characterised to C59+

Reservoir Fluid

STP P Condensate Composition

nWhy stop at C80? C80+ is still 339 ppmnWe want to go to 1-2 ppm. nWhy?

P Condensate Composition

nWe now need to use PVTSim Heavy Characterisation to go beyond C80.nBut this condensate is not heavy. API =

46.7nProblem # 1 with PVTSim: Many normal

waxy fluids have carbon numbers in excess of C100nWe continue with Heavy Characterisation

STP P Condensate Compositionn Lets go to C200 being Max PVTSims Heavy Characterisation

" Heavy Characterisation" Options: Reservoir STP Flash with 74

C7+ Pcs to C80

C100+= 0.0874%

C61+= 1.2324%

0.0010

0.0100

0.1000

1.0000

10.0000

100.0000

N2 C1 C3nC

4nC

5 C7 C9C11C1

3C1

5C1

7C1

9C2

1C2

3C2

5C2

7C2

9C3

1C3

3C3

5C3

7C3

9C4

1C4

3C4

5C4

7C4

9C5

1C5

3C5

5C5

7C5

9C6

1C6

3C6

5C6

7C6

9C7

1C7

3C7

5C7

7C7

9C8

1C8

3C8

5C8

7C8

9C9

1C9

3C9

5C9

7C9

9

SCN

Wt%



STP Condy Characterised to C59+

Reservoir Fluid

P Condensate Heavy vs Normal Charactn Normal

Heavy vs Normal Characterisation P Condensate 20 C7+ PCs

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

N2

CO2 C1 C2 C3 iC

4nC

4iC

5nC

5 C6 C7 C8 C9 C10

C11

C12

C13

C14

C15

C16

C17

C18

C19

C20-

C21

C22-

C24

C25-

C28

C29-

C33

C34-

C39

C40-

C48

C49-

C80

Wt %

Normal Characterisation

Heavy Characterisation

P Condensate Heavy vs Normal Charactn Heavy

Heavy vs Normal Characterisation P Condensate 20 C7+ PCs

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

N2

CO2 C1 C2 C3 iC

4nC

4iC

5nC

5 C6 C7 C8 C9 C10

C11

C12

C13

C14

C15

C16

C17

C18

C19

C20-

C21

C22-

C24

C25-

C28

C29-

C32

C33-

C39

C40-

C49

C50-

C200

Wt %

Heavy Characterisation

Normal Characterisation

P Condensate Characterisation Summary

Fluid CharacterisationC7+ PCs C20+ C38+ C59+ C80+ C100+TBP1 None None 10.96 0.36TBP2 None None 20.8GC Normal 20 26.23GC Heavy 20 24.65GC Normal 55 26.227 8.771 1.779 0.000 0.000GC Normal 74 26.231 8.776 1.784 0.034 0.000GC Heavy 94 24.644 8.164 1.875 0.390 0.087

Characterisation Summary

P Condensate HTGC : What is this saying?n Wax content decreasing as SCN increases?

" Normal Characterisation" Options: Reservoir STP Flash with 74

C7+ Pcs to C80

0.00001

0.00010

0.00100

0.01000

0.10000

1.00000

10.00000

C20

C22

C24

C26

C28

C30

C32

C34

C36

C38

C40

C42

C44

C46

C48

C50

C52

C54

C56

C58

C60

C62

C64

C66

C68

C70

C72

C74

C76

C78

C80

SCN

Wt%


HTGC (n alkanes) of Condy

Simulated P WAT v1 based on HTGCn V1 Simulated WAT =36oC vs CPM 41oC or CWDT 45oC?

P Condensate Simulated WAT v1 = 36oC

0.0001

0.001

0.01

0.1

1

10

100

-30 -25 -20 -15 -10 -5 0 5 10 15 20 25 30 35 40

Temperature oC

Wax Content %

v1 WAT

P Condensate Distillates Propertiesn 49.2 % Wax for C22+

API Gravity 31.8Density 15C g/ml 0.866Viscosity 70C cSt 8.697Viscosity 100C cSt 4.736Pour Point C 21Conradson Carbon Residue

wgt % 0.48

Ash wgt % 0.045Asphaltenes wgt %

P Condensate Distillate Propertiesn UOP 46 C22+ = 49.2% Wax

n HTGC C22+ = 6.6 % Wax (n alkane = 13% UOP46)HTGC vs UOP Wax Fraction

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.700

C20

C22

C24

C26

C28

C30

C32

C34

C36

C38

C40

C42

C44

C46

C48

C50

C52

C54

C56

C58

C60

C62

C64

C66

C68

Wax Fraction

Simulated P WAT v2q We need to resimulate reflecting 49% wax content for C22+

P Condensate Simulated WAT v2 = 74.7oC

0.0001

0.001

0.01

0.1

1

10

100

-30 -25 -20 -15 -10 -5 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80

Temperature oC

Wax Content %

v1 WAT v2 WAT

C80+ = 0.034 Wt%We need to keep going down the

SCNs because WAT is down to 1-2 ppm.

P Condensate WAT v3P Condensate Simulated WAT v2 = 85oC

0.0001

0.001

0.01

0.1

1

10

100

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

Temperature oC

Wax Content %

v1 WAT

v2 WAT

v3 Heavy Characterised WAT

Simulated v2 P WAT vs CPM / CWDT

q 75oC vs CPM 41oC and CWDT 45oCq So Simulation Must be Wrong?

Lets look at some other Information: Melting Points of C80 using PVTSimq C80 MPt (Tf) = 112oC (WAT driven by C80 of

0.034 wt% = 75oC)q WDT WAT = 37oC. Is this reasonable?

Conservative?qWDT approaches WAT in the limit of slow cooling

PVTSim Melting (WDT) vs SCNPVTSim SCN vs Melting Points of n Alkanes

-120

-100

-80

-60

-40

-20

0

20

40

60

80

100

120

140

C7 C10

C13

C16

C19

C22

C25

C28

C31

C34

C37

C40

C43

C46

C49

C52

C55

C58

C61

C64

C67

C70

C73

C76

C79

C82

C85

C88

C91

C94

C97

C100

TM (oC)

If sample contains no more than

C52, then require heating sample

to 90oC in order to melt.

If sample contains C100, then

require heating sample to 125oC

in order to melt.

Equally, if sample contains C100,

WDT - WAT = 125-96= 30oC

If sample only contains C52:

WDT-WAT = 90- 52 = 38oC

Are we ready to make P Wax File?Still need viscosity tuned data

P Condensate Cooldown Viscosity at 60s-1

0

10

20

30

40

50

60

5 10 15 20 25 30 35 40 45 50 55

Temperature oC

Viscosity (s-1)

Are we ready to make P Wax File?Whats happening here?

P Condensate Cooldown Viscosity from 50 to 25oC

0

1

2

3

4

5

6

7

25 30 35 40 45 50 55

Temperature oC

Viscosity (s-1)

Its all Upside Down!

Visco Tuning Using P WAT v 3

P Condensate Cooldown Viscosity at 60s-1 : PVTSim Viscosity Tuning

0

10

20

30

40

50

60

5 10 15 20 25 30 35 40 45 50 55

Temperature oC

Viscosity (s-1)

Raw Experimental

Filtered Experimental

Simulated

Tuned

Wax Deposition in Production System

Export of Stabilised Condensate through onshore pipeline-15oC Ground Temperature

Wax Deposition in Production SystemOnshore STO Condensate Export: 20 Days:

Oil M vs Condensate P: Single Phase Onshore Pipeline

82

82.5

83

83.5

84

84.5

85

85.5

86

86.5

87

0 5000 10000 15000 20000 25000 30000 35000

Distance (m)

WAT (oC)

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

DXWX (mm)

M Oil WAT

P Condensate WAT

M Oil DXWX

P Condensate DXWX



0

10

20

30

40

50

60

70

80

90

0 5000 10000 15000 20000 25000 30000 35000

Distance (m)

T (oC) / Viscosity (cp)

0

2000

4000

6000

8000

10000

12000

14000

16000

QOST bbl/d

M Oil T P Condensate TM Oil ViscosityP Condensate ViscosityM Oil QOSTP Condensate QOST



0

10

20

30

40

50

60

70

80

0 5000 10000 15000 20000 25000 30000 35000

Distance (m)

Viscosity (cp)

0

100

200

300

400

500

600

700

800

900

Shear Rate (s-1)

M Oil Viscosity

P Condensate Viscosity

M Oil Shear Rate

P Condensate SR

CONCLUSIONS

1. Do not confuse science and the engineering implications of the science. Get the science right first before figuring the engineering consequences

2. Differences between Reservoir and DST compositions could be due to:

n analysis techniques employedn heavy end depletion in the near well bore region (condensate banking) n deposition in the production system (downstream WH choke)3. Wax precipitation is a precursor to deposition but

should not be confused with deposition.4. Gas condensate deposition as simulated by Olga

requires Reynolds number modification.

CONCLUSIONS: Condensate Banking Ref [8]

CONCLUSIONS: Condensate Banking

n Core 1 had a permeability of 256 Md and 17.5% porosity.n Core 2 had a permeability of 39 Md and 18.5% porosity

n Core 1 had a 10x Reduction in KG due to liquid bankingn Core 2 had a 25% reduction in KG due to liquid banking

References1. Zhou, Li et al 2005 Distribution and Properties of High Molecular Weight Hydrocarbons in Crude Oils and Oil Reservoir of Shengli Oil Field, ChinaJ. Pet Science & Eng 2005

2. Barker et al 1995 The Chromatographic Analysis of Refined and and Synthetic Waxes. In Adlard Ed Chromatography in the Petroleum Industry Journal Chromatography Library Series, vol 56,pp 55-93

3. Taggert. A 1995 Nucleation, Growth and Habit Modification of n Alkanes and Homologous Mixtures in the Absence and Presence of Flow Improving Additives PhD, University Strathclyde.

4. Mullins et al 2009 The Impact of Reservoir Fluid Compositional Variation on Flow Assurance Evaluation OTC 20204

5. Heath et al 1995 Quantification of the C30+ Fraction of North Sea Gas Condensates by HTGC Analytical Proceedings Incl Analytical Comms 1995,32,485

6. Cosman, F Controlling Asphaltenes in Gas Condensate Systems NL Treating Chemicals Internal Case History from Alberta, Canada. 1970s

7. Thou, Ruthhammer et al 2002 Detection Asphaltenes Flocculation Onset in a Gas Condensate System SPE 78321

8. Thomas B 2003 Gas Condensate Reservoirs SPE 101514

Documents

SPT Gas Condensate vs Oil Wax Deposition