SPT Gas Condensate vs Oil Wax Deposition
description
Transcript of 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% ?
HTGC: PVTSim Characterised C100+
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% ?
HTGC: PVTSim Characterised C100+
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% ?
HTGC: PVTSim Characterised C100+
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
-
GAS CONDENSATE FLUID CHARACTERISATION
Choosing Representative Samplesq Is there such a thing? ie how do reservoir compositional
gradients affect sample colour for example? Ref [4]
-
GAS CONDENSATE FLUID CHARACTERISATION
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.
-
GAS CONDENSATE FLUID CHARACTERISATION
q Examples of GC vs HTGC and how GC misses heavy fractions Ref [1]
-
GAS CONDENSATE FLUID CHARACTERISATION
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 C200
STP Condy Characterised to C80
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%
STP Condy Characterised to C80
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
-
Wax Deposition in Production SystemOnshore STO Condensate Export: 20 Days:
Oil M vs Condensate P: Single Phase Onshore Pipeline
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
-
Wax Deposition in Production SystemOnshore STO Condensate Export: 20 Days:
Oil M vs Condensate P: Single Phase Onshore Pipeline
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