Gas Condensate vs Oil Wax Deposition Lauchie Duff Olga Users Group 11 November, 2009
OUTLINE q
Recap from Previous Olga Users Presentation
q
Gas Condensate Misconceptions
q
Fluid Characterisation Introduction Using Oil M
q
Fluid Characterisation Using A & B Gas Condensates
q
Wax Introduction
q
Wax Precipitation vs Wax Deposition
q
Waxy Condensates vs Waxy Oils Deposition
q
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 Effects Oil Cooldowns : SCDP vs CCDP
Apparent Viscosity (mPas) 4500 4000
S 1.20 BT 90C: 2kppm PPD, SCDP
3500 83% Delta at Final T
3000
S 1.20 BT 90C: 2kpp PPD, CCDP
2500 2000 1500 1000 500 0 20
22
24
26
28
30
32
34
Temperature (oC)
36
Recap: Non Newtonian Flow: Restarts Shear & Thermal History Affects on Restarts Shear Stress (Pa)
Restarts Ramps after Shut Down at 16oC: Shear History Effects
80 70 60 50 No ramping
40
after cooldown ramping
30 20 10 0 0
10
20
30
40
50
60
70
80
90
100 -1
Shear Rate (s )
WAX / Condensate Misconceptions q q q q q q q q q q
Condensate colour determines “contamination” Subsurface hydrocarbons are homogeneous fluids with no spatial variation, unlike petrophysical variations. Waxes are n alkanes only Measured WATs and wax contents are more accurate than simulated Wax Precipitation equals Wax Deposition Reported GC / HTGC compositions must be right. The lab has surely integrated the areas and mass %s correctly? Condensate compositions terminate around C30-C40 Long compositional heavy tails (of condensates), if they exist, are very insignificant (compared to oils) Reported compositions and associated EOSs are matched to measured dew points by regression of critical properties 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: 1MComposition Measurements Oil HTGC vs GC Wt%
16.0
C30+ = 15.047 % 14.0
HTGC
12.0
GC 10.0 8.0 6.0 4.0
C52+ = 1.828%
2.0 0.0 0
10
20
30 SCN
40
50
60
M Oil Composition Lets take the HTGC and extend power and exponential laws
q
M Oil HTGC & Manual Extrapolations
Wt%
Measured HTGC
10.0000
HTGC: Manual Extrapolations Exponential
C52+ = 1.828%
Power
1.0000
Power (HTGC: Manual Extrapolations)
y = 29992290.385621x
0.1000
-4.827528
2
R = 0.974967
y = 78.1118e-0.1220x R2 = 0.9583 C52+ = 1.525%
C52+ = 2.189%
0.0100
0.0010
0.0001 5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
SCN
85
90
95 100 105 110 115 120 125 130 135 140 145 150
M Oil Composition q
Lets take the HTGC and extend using PVTSim Characterisationsie Log Wt% vs Molec Wt is Linear M Oil HTGC & Manual Extrapolations
Wt%
Measured HTGC
10.0000
HTGC: Basis for Manual Extrapolations Exponential Extrapolation
C52+ = 1.828%
Power Extrapolation
1.0000
PVTSim C100+ Characterisation 0.1000
C100+= 0.0785%
y = 78.1118e-0.1220x R2 = 0.9583 C52+ = 1.525% 0.0100
y = 29992290.385621x-4.827528
0.0010
R2 = 0.974967 C52+ = 2.189%
0.0001 5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
SCN
85
90
95 100 105 110 115 120 125 130 135 140 145 150
WAX: Composition incl n Alkanes qDoes the n alkane a/c for all the wax? M Oil HTGC
Wt% 6.0000
5.0000
HTGC: PVTSim Characterised C100+
4.0000
n alkanes 3.0000
2.0000
1.0000
0.0785
0.0000 5
10
15
20
25
30
35
40
45
50
55
SCN
60
65
70
75
80
85
90
95
100
M Oil Composition incl n Alkanes Wt%
Wax% ?
5.00
0.5
4.50
0.45
4.00
0.4 HTGC: PVTSim Characterised C100+
3.50
0.35
n alkanes as % SCN
3.00
0.3
2.50
0.25
2.00
0.2
1.50
0.15
1.00
0.1
0.50
0.05 0.0785
0.00 5
10
15
20
25
30
35
40
45
50
55
SCN
60
65
70
75
80
85
90
0
95 100
M Oil Properties: WAT / WDT q q
Pour Point = 24oC WAT by 3 different DSCs(45->75oC) / CPM (39-48.8oC)/ Rheology / oC) CWDT (51Heat M Oil DSC (Heating Cycle) Capacity O
J/g C 5
o
4.5
Still Melting at >100 C
WDT 2 = 44OC
4
O
WDT 2 = 55 C
O
WDT1 = 67 C
3.5
3
2.5
2 0
20
40
60
80 o
Temperature ( C)
100
120
M OIL WAX: WDT vs WAT q
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 o
Simulated M WAT: 52 C
Wax Wt% 25
Tulsa WAT to C52+
20
15
10
5
0 -30
-20
-10
0
10
20
Temperature (oC)
30
40
50
60
M OIL WAX: Conclusion
q We
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 Alkanes qDoes wax content go down as SCN increases? Wt%
Wax% ?
5.00
0.5
4.50
0.45
4.00
0.4 HTGC: PVTSim Characterised C100+
3.50
0.35
n alkanes as % SCN
3.00
0.3
2.50
0.25
2.00
0.2
1.50
0.15
1.00
0.1
0.50
0.05 0.0785
0.00 5
10
15
20
25
30
35
40
45
50
55
SCN
60
65
70
75
80
85
90
0
95 100
M OIL : PVTSim Charactersation qPVTSim characterises zero wax after last measured plus fraction-but is this correct? PVTSims PARAW Characterised Fractions
Fraction 0.7 0.6 0.5
Paraffins Napthenes (Branched & Cyclics) Aromatics
0.4
Waxes Asphaltenes
0.3 0.2 0.1 0 0
10
20
30
40
50 SCN
60
70
80
90
100
WAX: Composition incl n Alkanes qPVTSim characterises zero wax after last measured plus fraction Wt%
Wax% ?
5.00
0.5
4.50
0.45
4.00
0.4 HTGC: PVTSim Characterised C100+
3.50
0.35
n alkanes as % SCN PVTSims Heavy Characterised Wax %
3.00
0.3
2.50
0.25
2.00
0.2
1.50
0.15
1.00
0.1
0.50
0.05 0.0785
0.00 5
10
15
20
25
30
35
40
45
50
55
SCN
60
65
70
75
80
85
90
0
95 100
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 Cooling Rate C18H38 Melt o
( C/min) 0.8
WAT
0.7
WDT
0.6 MSZW 0.5 0.4 0.3 0.2 0.1
T sat (at b =0oC /min)
0 25
26
27
28
29 Temperature
30
WDT / WAT and Wax Xtal Effects MSZWs vs Carbon Chain Lengths
Meta Stable Zone o
Width ( C) 3 TRICLINIC 2.5 2 1.5 1 MONOCLINIC 0.5 ORTHORHOMBIC
0 12
14
16
18
20
22
24
26
28
30
Carbon Chain Length
32
My favourite PhD on this subject WATs for Normal Alkanes (Measured at 5oC /min) Enthalpy of Crystallisation (J/g)
o
Temperature ( C) 105
240
TRICLINIC
95 85
210
75
180
65 150
55
MONOCLINIC ORTHORHOMBIC
45
120
35
90
25
WAT Enthalpy of Crystallisation
15
60 30
5 -5
0 10
15
20
25
30
35
40
45
50
55
Carbon Number
60
WAX PRIMER q
q q q
q q q q
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. Macro and microXlline waxes. Microxlline waxes average 1-2 microns. MicroXlline waxes MWts from 300 to 2500 (C21-C179). 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. WAT is defined as 2 ppm most insoluble (highest MWt) species. No lab measurements capable of measuring to this level. Recent project: Oil. CPM WAT 39-48oC. DSC WAT at least 63oC. GC / HTGC Measurements. Lack of resolution as Mwt increases and Xllinity changes from macro to microXlline. Recommend best GC / HTGC merged to provide overall fluid composition.
WAX PRIMER q q
Investigation of n alkane content of macro & microXlline waxes: AW 034 AND AW050 were microxlline and OFM/CFA macroxlline
Must Understand that Micro / Macro Relationship
WAX: Simulated WAT of Oil M Simulated WATs 52oC-85oC
q
o
Simulated M WATS: 52-85 C
Wax Wt% 25
PVTSim WAT to C52+
20
Tulsa WAT to C98+ PVTSim (Heavy) WAT
15
10
5
0 -30
-20
-10
0
10
20
30
40
Temperature (oC)
50
60
70
80
90
PVTSim: Melting (WDT) vs SCN PVTSim SCN vs Melting Points of n Alkanes
o
TM ( C) 140 120 100 80
If sample contains no more than
60
C52, then require heating sample
40
o
to 90 C in order to melt.
20
If sample contains C100, then
0
require heating sample to 125oC
-20
in order to melt.
-40
Equally, if sample contains C100,
-60
WDT - WAT = 125-96= 30 C
-80
If sample only contains C52:
o
WDT-WAT = 90- 52 = 38oC
-100
10 0
97
C
C
91
88
94 C
C
C
85 C
82 C
79 C
76 C
73 C
70 C
67 C
61
58
64 C
C
C
55 C
52 C
49 C
46 C
43 C
40 C
37 C
31
28
34 C
C
C
25 C
22 C
19 C
16 C
13
C
10 C
C
7
-120
GAS CONDENSATE FLUID CHARACTERISATION
Reasons why your gas condensate fluid characterisation is probably wrong. q q q q q
q
Sampling below dew point if MDT, sample contamination Compositional gradients DST-well conditioning / poor separator control = gas / liquid entrainment Subsampling losing fractions Laboratory GC vs HTGC Measurements-improper measurement heavy fractions: condensate PVT very sensitive to the small amounts heavy fractions EOS characterisation issues: Heavy fraction extension
GAS CONDENSATE FLUID CHARACTERISATION
Choosing Representative Samples q
Is there such a thing? ie how do reservoir compositional gradients affect sample colour for example? Ref [4]
GAS CONDENSATE FLUID CHARACTERISATION
Condensate colour q 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 CHARACTERISATION
1. Condensate A GC vs HTGC
n n n
Company A HTGC C100+ = 3.5 wt% Company B GC C36+ = 0.384 wt% Company C GC C35+ = 0.03 wt%
GAS CONDENSATE FLUID CHARACTERISATION 1.
2. PVT Consequences of Gas Condensate A GC / HTGC Measurements n
n
GC based EOS underpredicted two measured dew points by 344 and 690 psi HTGC based EOS exactly matched one and underpredicted the other by 190 psi
P Condensate Case History
P Condensate Properties n
API 46.7 (0.794 g/cc)
n
Pour point 21oC
Cloud Point 41oC by AMS 259 (CPM cooling at 0.2oC /min (= WAT?)
n
n
CWDT 45oC
n
Wax content ?
P Condensate Case History: PVT P Gas Condensate VLE (Company X) PSIG 8000 7000 6000 5000 4000
Measured Dew Point
3000
Co X Characterisation
2000
PVTSim C20+ Characterisation
1000 0 0
50
100
150
200 o
Temperature C
250
300
350
P: Reservoir Fluid & TBP Given Wt%
Reported Compositions: Reservor Fluid P & TBP P
100.00
Condensate TBP Reservoir Fluid
C20+ = 6.055 %
10.00
1.00
C38+ = 0.36% 0.10
N 2 C O 2 C 1 C 2 C 3 iC 4 nC 4 iC 5 nC 5 C 6 C 7 C 8 C 9 C 10 C 11 C 12 C 13 C 14 C 15 C 16 C 17 C 18 C 19 C 21 C 24 C 28 C 3 C 2 38 +
0.01
SCN
Flash P Reservoir Fluid to STP n
Why stop at C59+?
"Normal Characterisation" Options: Reservoir STP Flash to C59+ with 55 C7+ Pcs
Wt% 100.00
10.00
STP Condensate Reservoir Fluid
6.055
C62+ = 1.2324% 1.00
0.10
62
60
-C
57
54
C
51
C
48
C
45
C
42
C
39
36
C
C C
SCN
C
33
C
30
C
27
C
24
C
21
C
18
C
15
C
12
C
9 C
6 C
4
nC
2 C
N
2
0.01
STP P Condensate Composition n
Lets go to C80 being Max PVTSims “Normal Characterisation” " Normal Characterisation" Options: Reservoir STP Flash with 74 C7+ Pcs to C80
Wt% 100.00000
STP Condy Characterised to C80 STP Condy Characterised to C59+
10.00000
Reservoir Fluid
1.2324%
1.00000
0.39% 0.10000
C80+ = 0.0339%
0.01000
0.00100
0.00010
N
2 C 1 C 3 nC 4 nC 5 C 7 C 9 C 11 C 13 C 15 C 17 C 19 C 21 C 23 C 25 C 27 C 29 C 31 C 33 C 35 C 37 C 39 C 41 C 43 C 45 C 47 C 49 C 51 C 53 C 55 C 57 C 59 C 61 C 63 C 65 C 67 C 69 C 71 C 73 C 75 C 77 C 79
0.00001
SCN
STP P Condensate Composition
n Why
stop at C80? C80+ is still 339 ppm n We want to go to 1-2 ppm. n Why?
P Condensate Composition n We
now need to use PVTSim Heavy Characterisation to go beyond C80. n But this condensate is not heavy. API = 46.7 n Problem # 1 with PVTSim: Many normal waxy fluids have carbon numbers in excess of C100 n We continue with Heavy Characterisation
STP P Condensate Composition n
Lets go to C200 being Max PVTSims “Heavy Characterisation” " Heavy Characterisation" Options: Reservoir STP Flash with 74 C7+ Pcs to C80
Wt% 100.0000
STP Condy Characterised to C200 STP Condy Characterised to C80 10.0000
STP Condy Characterised to C59+ Reservoir Fluid
C61+= 1.2324%
1.0000
C100+= 0.0874%
0.1000
0.0100
N
2 C 1 C nC3 nC4 5 C 7 C C 9 1 C 1 1 C 3 1 C 5 1 C 7 1 C 9 2 C 1 2 C 3 2 C 5 2 C 7 2 C 9 3 C 1 3 C 3 3 C 5 3 C 7 3 C 9 4 C 1 4 C 3 4 C 5 4 C 7 4 C 9 5 C 1 5 C 3 5 C 5 5 C 7 5 C 9 6 C 1 6 C 3 6 C 5 6 C 7 6 C 9 7 C 1 7 C 3 7 C 5 7 C 7 7 C 9 8 C 1 8 C 3 8 C 5 8 C 7 8 C 9 9 C 1 9 C 3 9 C 5 9 C 7 99
0.0010
SCN
P Condensate Heavy vs Normal Charact n
Normal
Heavy vs Normal Characterisation P Condensate 20 C7+ PCs
Wt % 14.00 12.00 10.00
Normal Characterisation Heavy Characterisation
8.00 6.00 4.00 2.00
N 2 C O 2 C 1 C 2 C 3 iC 4 nC 4 iC 5 nC 5 C 6 C 7 C 8 C 9 C 10 C 11 C 12 C 13 C 14 C 15 C 16 C 17 C 18 C C1 20 9 C C2 22 1 C -C2 25 4 C C2 29 8 C -C3 34 3 C -C3 40 9 C -C4 49 8 -C 80
0.00
P Condensate Heavy vs Normal Charact n
Heavy
Heavy vs Normal Characterisation P Condensate 20 C7+ PCs
Wt % 14.00 12.00 10.00
Heavy Characterisation Normal Characterisation
8.00 6.00 4.00 2.00
N 2 C O 2 C 1 C 2 C 3 iC 4 nC 4 iC 5 nC 5 C 6 C 7 C 8 C 9 C 10 C 11 C 12 C 13 C 14 C 15 C 16 C 17 C 18 C C1 20 9 C -C2 22 1 C -C2 25 4 C -C2 29 8 C -C3 33 2 C -C3 4 9 C 0 -C 50 4 -C 9 20 0
0.00
P Condensate Characterisation Summary
Characterisation Summary Fluid Characterisation C7+ PCs C20+ C38+ C59+ TBP1 None None 10.96 0.36 TBP2 None None 20.8 GC Normal 20 26.23 GC Heavy 20 24.65 GC Normal 55 26.227 8.771 1.779 GC Normal 74 26.231 8.776 1.784 GC Heavy 94 24.644 8.164 1.875
C80+
C100+
0.000 0.034 0.390
0.000 0.000 0.087
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
Wt% 10.00000
1.00000
0.10000
0.01000
0.00100
STP Condy Characterised to C80 0.00010
HTGC (n alkanes) of Condy
SCN
C 80
C 78
C 76
C 74
C 72
C 70
C 68
C 66
C 64
C 62
C 60
C 58
C 56
C 54
C 52
C 50
C 48
C 46
C 44
C 42
C 40
C 38
C 36
C 34
C 32
C 30
C 28
C 26
C 24
C 22
C 20
0.00001
Simulated P WAT v1 based on HTGC n
V1 Simulated WAT =36oC vs CPM 41oC or CWDT 45oC? o
P Condensate Simulated WAT v1 = 36 C Wax Content % 100
10
1
0.1 v1 WAT
0.01
0.001
0.0001 -30
-25
-20
-15
-10
-5
0
5
10
Temperature oC
15
20
25
30
35
40
P Condensate Distillates Properties n
49.2 % Wax for C22+
Boiling Range
°C
Yield Range
wgt %
84.1 - 100
Yield
wgt %
15.9
g/ml cSt cSt °C
31.8 0.866 8.697 4.736 21
Conradson Carbon Residue Ash
wgt %
0.48
wgt %
0.045
Asphaltenes Wax Content
wgt % wgt %
<0.05 49.2
API Gravity Density 15°C Viscosity 70°C Viscosity 100°C Pour Point
360+ = C22+
P Condensate Distillate Properties UOP 46 C22+ = 49.2% Wax HTGC C22+ = 6.6 % Wax (n alkane = 13% UOP46) HTGC vs UOP Wax Fraction n
n Wax Fraction 0.700 0.600 0.500 0.400 0.300 0.200 0.100
68
C
66
C
64
C
62
C
60
C
58
C
56
C
54
C
52
C
50
C
48
C
46
C
44
C
42
C
40
C
38
C
36
C
34
C
32
C
30
C
28
C
26
C
24
C
22
C
C
20
0.000
Simulated P WAT v2 q We need to resimulate reflecting 49% wax content for C22+ P Condensate Simulated WAT v2 = 74.7oC Wax Content % 100
10
1
0.1
0.01 v1 WAT
v2 WAT
0.001
0.0001 -30 -25 -20 -15 -10
-5
0
5
10
15
20
25
30
Temperature oC
35
40
45
50
55
60
65
70
75
80
C80+ = 0.034 Wt% We need to keep going down the SCNs because WAT is down to 1-2 ppm.
P Condensate WAT v3 o
P Condensate Simulated WAT v2 = 85 C Wax Content % 100
10
1
0.1
0.01
0.001
v1 WAT v2 WAT v3 Heavy Characterised WAT
0.0001 -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
Simulated v2 P WAT vs CPM / CWDT 75oC vs CPM 41oC and CWDT 45oC q So Simulation Must be Wrong?
q
Lets look at some other Information: Melting Points of C80 using PVTSim q C80 MPt (Tf) = 112oC (WAT driven by C80 of 0.034 wt% = 75oC) q WDT – WAT = 37oC. Is this reasonable? Conservative? q WDT approaches WAT in the limit of slow cooling
PVTSim Melting (WDT) vs SCN PVTSim SCN vs Melting Points of n Alkanes
o
TM ( C) 140 120 100 80
If sample contains no more than
60
C52, then require heating sample
40
o
to 90 C in order to melt.
20
If sample contains C100, then
0
require heating sample to 125oC
-20
in order to melt.
-40
Equally, if sample contains C100,
-60
WDT - WAT = 125-96= 30 C
-80
If sample only contains C52:
o
WDT-WAT = 90- 52 = 38oC
-100
10 0
97
C
C
91
88
94 C
C
C
85 C
82 C
79 C
76 C
73 C
70 C
67 C
61
58
64 C
C
C
55 C
52 C
49 C
46 C
43 C
40 C
37 C
31
28
34 C
C
C
25 C
22 C
19 C
16 C
13
C
10 C
C
7
-120
Are we ready to make P Wax File? Still need viscosity tuned data P Condensate Cooldown Viscosity at 60s-1
Viscosity (s-1) 60
50
40
30
20
10
0 5
10
15
20
25
30
35 o
Temperature C
40
45
50
55
Are we ready to make P Wax File? Whats happening here?
P Condensate Cooldown Viscosity from 50 to 25oC
Viscosity (s-1) 7
6
5
4
3
2
1
0 25
30
35
40
Temperature oC
45
50
55
Its all Upside Down!
Visco Tuning Using P WAT v 3 P Condensate Cooldown Viscosity at 60s-1 : PVTSim Viscosity Tuning Viscosity (s-1) 60 Raw Experimental Filtered Experimental
50
Simulated 40
Tuned
30
20
10
0 5
10
15
20
25
30
Temperature oC
35
40
45
50
55
Wax Deposition in Production System Export of Stabilised Condensate through onshore pipeline-15oC Ground Temperature
Wax Deposition in Production System Onshore STO Condensate Export: 20 Days: Oil M vs Condensate P: Single Phase Onshore Pipeline o
WAT ( C)
DXWX (mm) 2
87 86.5
1.8
86
1.6 M Oil WAT
85.5
1.4
P Condensate WAT
85
1.2
M Oil DXWX
84.5
1
P Condensate DXWX
84
0.8
83.5
0.6
83
0.4
82.5
0.2 0
82 0
5000
10000
15000
20000
Distance (m)
25000
30000
35000
Wax Deposition in Production System Onshore STO Condensate Export: 20 Days: Oil M vs Condensate P: Single Phase Onshore Pipeline QOST bbl/d
T (oC) / Viscosity (cp) 90
16000
80
14000
70
12000
M Oil T P Condensate T M Oil Viscosity P Condensate Viscosity M Oil QOST P Condensate QOST
60 50 40
10000
8000
6000
30
4000
20
2000
10 0
0
0
5000
10000
15000
20000
Distance (m)
25000
30000
35000
Wax Deposition in Production System Onshore STO Condensate Export: 20 Days: Oil M vs Condensate P: Single Phase Onshore Pipeline -1
Viscosity (cp)
Shear Rate (s ) 900
80
M Oil Viscosity 70
800
P Condensate Viscosity
700
M Oil Shear Rate
60
P Condensate SR
600
50
500 40
400 30
300
20
200
10
100 0
0 0
5000
10000
15000
20000
Distance (m)
25000
30000
35000
CONCLUSIONS 1.
2. n n n
3. 4.
Do not confuse science and the engineering implications of the science. Get the science right first before figuring the engineering consequences Differences between Reservoir and DST compositions could be due to: analysis techniques employed heavy end depletion in the near well bore region (condensate banking) deposition in the production system (downstream WH choke)
Wax precipitation is a precursor to deposition but should not be confused with deposition. Gas condensate deposition as simulated by Olga requires Reynolds number modification.
CONCLUSIONS: Condensate Banking Ref [8]
CONCLUSIONS: Condensate Banking
n n
n n
Core 1 had a permeability of 256 Md and 17.5% porosity. Core 2 had a permeability of 39 Md and 18.5% porosity Core 1 had a 10x Reduction in KG due to liquid banking Core 2 had a 25% reduction in KG due to liquid banking
1.
2.
3.
4. 5.
6. 7. 8.
References
Zhou, Li et al 2005 “Distribution and Properties of High Molecular Weight Hydrocarbons in Crude Oils and Oil Reservoir of Shengli Oil Field, China” J. Pet Science & Eng 2005 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 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. Mullins et al 2009 “ The Impact of Reservoir Fluid Compositional Variation on Flow Assurance Evaluation” OTC 20204 Heath et al 1995 “ Quantification of the C30+ Fraction of North Sea Gas Condensates by HTGC” Analytical Proceedings Incl Analytical Comms 1995,32,485 Cosman, F “Controlling Asphaltenes in Gas Condensate Systems” NL Treating Chemicals Internal Case History from Alberta, Canada. 1970s Thou, Ruthhammer et al 2002 “ Detection Asphaltenes Flocculation Onset in a Gas Condensate System” SPE 78321 Thomas B 2003 “Gas Condensate Reservoirs” SPE 101514
