11/19/2013
Flow Assurance Assurance - Mana Managing ging Flow Dynamics and Production Chemistry
Abul Jamaluddin, Ph.D. Production Technology Advisor Business Manager Manager – North America NExT – Oil & Gas Training and Career Development Development
What is the primary operating focus of your team?
Acknowledgement • SPE for organizing this Webinar • All clients who contributed to some of the field examples • Schlumberger to allow me to participate and thanks to the following sub segments for providing the contents -
– Schlumberger Research – Reservoir Sampling and Analysis sub segment – Flow Assurance Consulting group of OneSubsea – NExT – Oil and Gas Training and Competency Development of Petrotechnical Services
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Presentation Presentatio n Outline Deepwater & flow assurance Flow hindrance elements A holistic flow assurance workflow Field examples with key technology applications
• Waxy crude production management (SPE 132615)
4AJ 11/19/2013
Deepwater Flow Assurance Challenges – Colder temperatures – Greater hydrostatic head – Longer tiebacks, and hence complex thermo-hydraulic fluid behaviour Commingling of – Gas condensate production Incompatible fluids – Organic/Inorganic solids precipitations – Commingled production – complex fluid systems systems Large pressure pressure drops Cold deep water – Reservoir Complexity Complexity - shallow reservoir, HPHT, HP HT, facilitates deposition
facilitates deposition
compartmentalised, …
– Reduce uncertainties and minimize risks CAPEX versus OPEX 5AJ 11/19/2013
Flow Assurance
“Maintain flow from pore to process”” process
'ntegrated S"luti"ns
LiquidManagement
Asphaltenes
Hydrates
Wax
Scal e
PVT & Fluideha!i"ur
#"rr"si"n & $r"si"n
%peraility Assessment
Sur!eillance & %perati"n
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Flow Hindrance Elements – Especially Critical in Offshore Arena
Fluid Properties Properties - PVT
Fluid Flow & Heat Transfer
Asphaltene
Wax
Hydrate
Naphthanates Naphth anates - Soaps
Oilfield Scales
Emulsions/ Foams
Corrosions/Erosions/Sand
Heavy Oils
Understanding the fundamentals of these elements are the ke to design management strateg 7AJ 11/19/2013
Flow Assurance Domains Production Chemistry
Production Engineering
Production Surveillance
!hara"teri#ation$ %redi"tion of !hara"teri#ation$ flo& sto%%age elements
'hermal(hdrauli" design and assessment of su)sea multi%hase flo& sstems
*rodu"tion o%timi#ation and earl dete"tion of flo& sto%%ages
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What is your primary area of expertise/interest?
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Holistic Flow Assurance Workflow
Downhole Characteriza tion & SinglePhase Sampling
Laboratory Measureme nts
Modeling
Integration, Interpretatio n and Design
• Thermod ynamic – • Steady & Transient State Modeling
• PVT • Asphalten e • Wax • Hydrate
Field Implementat ion • Implement a technically sound, cost effective and environme ntal sound solution
,eed)a"k -oo%
10AJ 11/19/2013
*ressure -iuid anagement
Subsea Gas Lift
Liquid Management Subsea Natural Lift 11AJ 11/19/2013
!ourtes of .neu)sea
Production Chemistry
g n i l p m a S
Fluid sampling, analysis, characterisation, prediction of challenges Development of Asphaltene Deposition Model
*erformas%haltene "hara"teri#ation
!al"ulate as%haltene(li1uid3/-4 flash
5m%lement the%arti"le de%osition me"hanism &hi"h in"ludes %arti"le formation$ trans%ortation and adsor%tion
/ingle and t&o %hase flo&models
(1) Particles Form
(2) Particle Transport
ScalePrecipitationResult s
(3)Particles Adsorb
6.00E-04 5.00E-04
a t a D f o e u l a V
n o i t 4.00E-04 c a r F s s 3.00E-04 a M d i l o 2.00E-04 S
1.00E-04 0.00E+00 0
0. 2
0 4.
0 6.
0 8.
1
MassFractionofFormationWater
g n i l p m a S d i u l F 12AJ 11/19/2013
BaSO4 Cal. Cal. SrSO4 Cal. BaSO4 Exp. SrSO4 Exp.
20
s i s y l a n A s e l p m a S
g n i l e d o M d i u l F
n o i t a r b i l a c l e d o M
45 1 month 6 months 1year
18 16
n o i t a t e r p r e t n I
40 35
) m 14 m ( s s12 e n k10 c i h t t 8 i s o p e 6 D
30 )
C (
e 25 r u t a r
20 e p Temperatureprof iles
m e
15 T
4
10
2
5
0 0
3 00 0
600 9 00 0 1 20 00 Distance(m)
1 50 00
0 1 80 00
Time
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Production Engineering Importance of Dynamics from Reserv oir to Process Facilities Slug Catcher
tead tate .ut"omes *eak %rodu"tion rates !om%letions design *i%eline si#ing 8ui%ment si#ing Process !acilities
6eseroir
nami" .ut"omes *rodu"tion %rofiles :ell "lean(u% / start(u% %ro"edures !ooldo&n / insulation reuirements -iuid surge management / slug "at"her
ECLPSE 13AJ 11/19/2013
Production Operations Production surveillance and optimization, operational well and pipeline remediation, prevention and mitigation techniques in order to optimize production
onitor ensors and * meters ata a"uisition ata alidation and storage
Distributed temperature Production Intervention sensors DTS
Process !acilities
6eseroir
Multiphase meter
Alarm .%timise ntegrated asset management :ell interention ,lo&line remediation
ECLPSE 14AJ 11/19/2013
Asphaltenes in the Reservoir
Reservoir Architecture – Aerial Compositional Grading
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Compartments, sealing barriers, baffles Different Fault Blocks Different GOR (colors)
!ourtes of .! ullins
Hibernia Areal Map
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Impact Completions Vertical Compositional Compositional Grading (Heavy Ends ! )
Reservoir Fluids are often highly graded and often NOT in equilibrium May have compatibility issues
l n i O m u e l n o O C
!ourtes of .! ullins
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Production Chemistry
Athabasca Bitumen ρ>1
Mercury
Asphaltene Wax
Diamondoids
Gas Hydrate 17 AJ 11/19/2013
Organic Scale
Asphaltenes Asphaltenes
Operationally defined as a portion of crude oil insoluble in nalkanes such as heptane but soluble in aromatics such as toluene or dichloromethane. Source specific. They are the heaviest and the most polar components in crude oil composed of : • Poly Polyarom aromatics atics carry carrying ing aliph aliphatic atic rings rings or or chains chains • H/C ato atomi mic c ratio ratio = 1.01.0-1.2 1.2 • Hete Heteroato roatoms: ms: nitro nitrogen, gen, oxyge oxygen, n, sulfur sulfur • Meta Metals: ls: nick nickel, el, vanad vanadium ium,, iron. iron.
S
N H
Causes of Asphaltene Asphaltene Precipit Precipitation ation
Change in Oil Composition
Pressure Depletion Above Psat
Change in Temperature
Others (pH, Water Cut, Electro-kinetic Effects etc…)
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Key properties of waxy crudes
Waxes are high molecular weight saturated carbons (>C20) mainly from normal paraffins CnH2n+2
Tend to precipitate when temperatures are reduced.
Precipitates as crystalline waxy solids.
y t i s o c Highly Non s Newtonian i V
Mildly Non-Newtonian
Newtonian
15-25 oC
Pour Point 19AJ 11/19/2013
Temperature
Cloud Point Wax Appearance Temperature (WAT)
Hydrates – Ice – Ice That Burns
Crystalline solid consisting of gas molecules each surrounded by a cage of water molecules. Hydrate usually forms at high P & low T One volume hydrate can carry 160-180 volumes of methane Hydrate Formers: C1 n-C4 O2 others
C2 N2 Ar
C3 i-C4 CO2 H2S cyclo-C3
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Common Inorganic Scales • Calc Calcit ite e (C (CaC aCO O3) – acid solub soluble le carbonates – Formed due to the pr esence of calcium ions and bicarbonate ions in the produced water – Pressure changes may caus e precipitation
•
Barite (BaSO4) – acid insolub insoluble le sulphates – Generally formed when t here is coproduction of formation water (Ba2+) and
injection water (SO4-) Barite Anhydrite
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What is your major flow assurance concern?
Field Example: Waxy Crude Management in SPE "#$%"& Deepwater from South East Asia Field Situation Dual 5-km deepwater subsea line capability with pigging operations Half buried no insulation High pour point waxy crude production at subsea temperature of 4°C No wax deposition in early life Challenge Concerned with wax gelling during unplanned shut down. Recommendation by Chemical Vendor Continuous chemical (PAO82004) injection at 300 ppm Operating Company Perspective Independent verification of gelling characteristics & chemical requirements 23AJ 11/19/2013
Waxy Crude Flowline Unplanned Shutdown/ReStart Evaluation Workflow Fluid Sampling
• Repre Representa sentative tive Sampling ng
Phase Behavior
• Standard Standard PVT analys analysis is • (Defin (Define e ph phase ase boundari boundaries) es)
Wax Characterization
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Thermodynamic Characteristics • Com Compos positi itions ons C90+ C90+ • Wa Wax x Cont Conten entt • Clo Cloud ud Point/W Point/WAT AT@ @ Ambient/Line Condition Transport Characteristics < Am)ient/-ine !ondition • Gel Gel-St -Stren rength gth • R he he ol ol og og y
g n i l e d o 2 " i m a n d o m r e h '
g n i l e d o 2 t n e i s n a r '
Deposition Measurements (not done for this field example)
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Compositions & Wax Content Recombine separator gas and oil samples at producing GOR to make reservoir fluid 12
100000
Recombined fluid 10
) 10000 m p p ( 1000 n o i t 100 a r t n e 10 c n o C 1
8 % t 6 w
4 2 0
2 2 2 4 5 6 e 7 e O N C C n C n - C - C e i i e C z u l n o e T B
0
2 4 6 8 0 2 4 6 8 + e e 0 1 1 1 1 1 2 2 2 2 2 0 n n C C C C C C C C C C 3 e e l C z n y e X B o 2 C
0
10
20
30
40
50
60
70
80
n-alkane carbon #
UOP wax content ~ 4.3 wt% at -31 oF/-35°C HTGC wax content (n-C18+) ~ 11.16 wt%
GOR = 1058 scf/sbl API = 37.9 MW = 182.6 g/mol Psat ~ 3660 psia @169.5oF/76.4°C 25AJ 11/19/2013
Schematic Diagram of Cross Polar Microscope (CPM) Measurement of o f WAT of Stock Tank Oil CC D
Hot Stage
Top View
Analyzer 4
25
50
Hot Stage 360o Rotatable Stage Polarizer
Cooling Gas
IR Filter Light Source 2;AJ 11/19/2013
High Pressure Cross Polar Microscope (HPCPM) – Wax Precipitation Assessment (20,000 psi & 200oC; Resolution Resolution ~ 4 micron)
HPCPM
HPCPM
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Live oil W AT at 4000 psia ps ia ~ 20°C 20°C 1.4E-04
GOR = 1058 scf/stb
SDS WAT ~ 2 0°C
1.2E-04
1.0E-04
) W 8.0E-05 ( r e w o 6.0E-05 P
HPCPM WAT ~ 15 °C
4.0E-05
2.0E-05
0.0E+00 0
10
20
30
40
50
60
70
80
Temperatu re (°C)
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Wax Appearance Temperature/Cloud Points Characteristic
Value/Observation
STO WAT (°C)
26.8
Live oil WAT at 4000 psia (°C)
20
Live oil WAT at 2200 psia (°C) W AT (Ex p)
20 Pb (Exp)
Hyd
W AT (S (Sim)
Pb
5000 PX02Reservoir o!di"io!s
4500 4000 3500
i!imm se%bed Temper%"re
3000 ) a i s p ( P
2500 We##$e%d o!di"io!s
2000 1500 1000
&PS'Arriv%#
500 0 -1 00
29AJ 11/19/2013
0
100
20 0
T(#)
Gel-Strengtgh Measuremeht using Model Pipeline Test (MPT) N2 Pressure For Ungelling
HP Circulation Pump
Back-Pressure Regulator
Heated Lines
Test Coils (2) • 7.0 mm mm ID • 7.64 m long long
Fluid Sample Cylinder
• 3,000 psi psi (35 Mpa) • 1 70 70oF (75oC) Temperature Controlled Bath
Applications :
• Measure Yield Strength
• Evaluate Effectiveness Of Flow Improvers
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Gel Strength Measurement Results 90
30
80
Yieldpressure = 80.6psi
Untreated STO
70
25
60
Untreated live oil
Yield pressure = 24.3psi
20
) i s 50 p ( P 40 D
) i s p ( 15 P D
30
10
20 5
10 0
0 0
20
40
60
80
100
120
140
160
0
20
40
Time(min)
60
80
100
120
140
160
Time(min)
'est =
τ = PYD/4L = 1.988 PY PY = ungelling or yield pressure D = coil inner diameter L = coil length
. il '%e
*>%si
τ (*a 1;0?3
1
' .
+0?;
2
-i e , lui d at 2200 %sia
24?3
4+?3
3
'. @ 300%%m "hemi "al
(((
o gel
31AJ 11/19/2013
Rheometer – Viscosity Measur Measurements ements
3.0 STO at 40 °C
2.5
Shear Rate Sweep
) p 2.0 c ( y t i 1.5 s o c s i V 1.0
• STO @ 40oC ~ 1.5 cP slightly non-linear • STO @ 4oC – highly non-linear (highly viscous) • Live Oil @ 4oC - Highly non-linear non-linear (less viscous viscous
0.5 0.0 32AJ 0 11/19/2013
50
1 00 15 0 20 0 Shear rate (1/s)
25 0
300
Viscosity Modeling 'est =
.il '%e
*>%si
τ (*a 1;0?3
1
' .
+0?;
2
-i e ,l uid at 2200 %si a
24?3
4+?3
3
' . @ 300%%m "hemi"al
(((
o gel
The plastic viscosities viscosities for the STO and live live oil @ 2200 psia psia line pressure were obtained obtained from gradients of the shear stress vs shear rate plots 33AJ 11/19/2013
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Rheology Model Selection in OLGA based on Experimental Validation
•
'he non(e&tonian )ehaior of the fluid gel &as a%%roBimated ) the Cingham %lasti" model$ &ith the %lasti" is"osit and the ield stress o)tained from the rheologi"al and gel strength measurements?
34AJ 11/19/2013
Shut-Down and Re-Start Modelling Transient Simulation using OLGA Liquid filled Flowline/ RiserGeometry
-rrival pressure of %$* psig
0
-200
-400
-600 ) m ( n o i t a v e l E
-800
-1,000
Seabed temperature of , oC
-1,200
Constant mass source of"$'((( bpd ) %*+# oC
-1,400
-1,600 0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Flowline/ RiserLength(m)
Gas filled
– Only flowline/riser considered. The production tubing was not included.
– Flow-line assumed to be half buried in soil. 35AJ 11/19/2013
– Recombined reservoir fluid composition was used in simulations.
Live Oil Shut-in Pressure & Temperature – Gas Dissolution Effect STO Condition
Live Oil @2200 psia
:A' D 2;!
16 hrs
:A' D 20!
24 hrs
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Re-Start Re-S tarts s - STO / $&(( psi
/ $&(( psi
$.hour restart
%.hour restart
– Blow down after unplanned shut-in, pressures required to initiate flow in the pipeline is around 2500 psi for both ramp-ups. 37AJ 11/19/2013
Restarts Resta rts – Live oil @ 2200ps 2200psia ia / $$(( psia
/ $$(( psia
%.hour restart
$.hour restart
– For live fluid with solution gas, pressures required to initiate flow in the pipeline is 2200 psia for both ramp-ups, respectively. 3+AJ 11/19/2013
Summary Results τ = Py D /4 L Ca se se
0 LG LG - p re re di di ct ct ed ed pr pr es es su su re re 1p 1p si si a2 a2 2(hou 2(hourr rest restar artt
;(hour ;(hour rest restart art
C al al cu cu la la te te d f ro ro m f or or ce ce balances 1psia2 using gel. strength data
'.
2 5 00
25 00
210 0
-ie oil < 2200%sia
2 2 00
2 2 00
;0 0
,or"e )alan"e "al"ulations &ith an assum%tion of a "ontinuous liuid gel at the %i%eline inlet %roides "onseratie num)ers
39AJ 11/19/2013
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Field Study Conclusions – As expected, solution gas at line condition provided lower WAT, Gel-Strength and viscosity values.
– Transient simulation of shut-down scenarios with experimental validation and the choice of right viscosity model provided longer shut-in time to reach WAT of 20 deg C at line condition 24 hrs as oppose to 16 hrs design shut-in time .
– Continuous chemical injection provided no gelling at subsea temperature of 4 deg C psi for STO & 2200 – Transient simulation predicted re-st art pressures of ~2500 psi psi for live fluid after a prolonged shut-in period. Are these pressures Wellhead Pressure ~ 2200 psia bigger/smaller than theFlowing SIWHPs? Shut-in Wellhead Pressure = 2600 psia Contingency is the pig-launching pump at subsea
– Continuous chemical injection is not a requirement with current shut-in subsea wellhead conditions. 40AJ 11/19/2013
Integration & Interpretation WA T (Ex p)
P b (Ex p)
Hyd
WA T (Sim)
Pb
5000 PX02Reservoir o!di"io!s
4500 4000 3500 3000 ) a i s p (
i!imm se%bed Temper%"re
2500
P
We##$e%d o!di"io!s
2000 1500 1000
&PS'Arriv%#
500 Predi*"ed&PS'Arriv%# 0 -1 0 0
0
1 00
20 0
T (#)
41AJ 11/19/2013
Concluding Remarks
• Understanding the fundamental flow assurance issues are key to successful field development & production, especially, in deepwater subsea environment.
• Application of appropriate technology and a customized workflow process is critical.
• Based on fundamental understanding, optimized operating strategies can be designed.
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Fluid Watcher Dashboard Reservoir P&T
e r u s s e r P
e v r u C e t a r d y H
Facility
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Temperature
*Same number for Scale
Flow Assurance Assurance - Mana Managing ging Flow Dynamics and Production Chemistry
'hank >ou An EuestionsF Abul Jamaluddin, Ph.D. Production Technology Advisor Business Manager Manager – North America NExT – Oil & Gas Training Training and Career Development Development
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