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Flow Assurance Technology Options & Pipe Sizing for Deep-Water & Long Distance Oil & Gas Transport.
• Introduction• Flow Assurance Challenges.• Flow Assurance Solution Options.• Technologies- GTLA.• Design Process Through an
Integrated System Approach.• Multiphase Pipe sizing Charts• Summary
Agenda
Flow Assurance
“The ability to produce fluids economically from the reservoir to a production facility, over the life of field in any environment “ Deepstar.
“The term Garantia de Fluxo” Coined by Petrobras in the early 1990’s, and translates literally as Guarantee the Flow.
Flow Assurance ?
• To produce and transport fluids from the pore throat of reservoir to the host facility
– Throughout life cycle of field
– Under all operating conditions
– In a cost-effective way
“ A structural engineering analysis process that utilizes the in-depth knowledge of fluid properties and thermal hydraulic analysis of the system to develop strategies for control of solids such as hydrates, waxes, asphaltenes and scale”
OTC #13123
• Keep the flow path open!
• Goals:
– Reduce risk of lost or reduced production
– Enhance production rate
• FA strategies must be integrated into overall systems design and field operations
SL-Shell
• The broadest link throughout the production system
• Cross-Functional, Cross-Team Discipline• From Project Conception to Operations
• Forget flow assurance• Industry needs performance assurance
• Costly and conservative • FA Engineers – Trouble makers
Typical Subsea Engineer
FlowAssurance
GasHydratesParaffin /
Ashphaltenes
Scales
Liquid SluggingLow
Temperatures
Sand / Erosion
Corrosion
Emulsion/ Foam
Flow Assurance Challenges
Blockages
Inte
grity
Operational
• Solid Ice-like crystal• Hydrocarbon molecules trapped inside water
“cages”• Hydrate Formation occurs when
– Water + light HC• Formation temperature (higher than freezing)
depends on pressure, can form > 15 °C• Approximately 85% water, 15% HC • Gas volume – 150-200 scf/ft3 hydrates
Gas Hydrates: Formation & Structure
• Blockage of pipeline and flowline– Block line completely– Plugs up to 6 miles– Plugs in up to 40” pipe
• Production downtime• Time and cost of remediation• Serious safety issues• During drilling or completion
– Plug blow out preventers– Collapse tubing and casing
• Worsens as water depth increases• Spans life cycle of field
What Problems Can Hydrates What Problems Can Hydrates Cause?Cause?
Courtesy of Petrobras
Compositional Tracking
• Normally Based on Hydrate Dissociation Curve
• Reservoir Composition is usually used.
• However the composition varies with Shut Down
• Compositional Tracking of Benefit• Increased cool down time• Reduced Insulation Requirements• Precious additional time prior to hydrates
Pipeline / Riser System during Shut Down
Oil/Wat
Gas
Case Example
Hydrate Curves for Pipeline Shut Down (GOR=3000scf/stb)
0
20
40
60
80
100
120
140
160
180
0 5 10 15 20 25 30
Temp.(C)
Pre
ssu
re (
Bar
a)
29 Barg Shutdown
95 Barg Shutdown
95 Barg Flowing
Cool Down at Riser Mid Point
Cool down at Riser Mid Point
0
10
20
30
40
50
60
0.3
1.4
2.5
3.6
4.7
5.8
6.9
8.1
9.2
10.3
11.4
12.5
13.6
14.7
15.8
16.9
18.1
19.2
20.3
21.4
22.5
23.6
24.7
25.8
26.9
28.1
29.2
Time (Hrs)
Te
mp
.(C
)
24788
30709
36491
42131
47632
52991
58210
63289Reservoir Composition
Shut in Composition
(bopd)
Cooldow n at Pipe Inlet
0
10
20
30
40
50
60
0.3
1.4
2.5
3.6
4.7
5.8
6.9
8.1
9.2
10
.3
11
.4
12
.5
13
.6
14
.7
15
.8
16
.9
18
.1
19
.2
20
.3
21
.4
22
.5
23
.6
24
.7
25
.8
26
.9
28
.1
29
.2
30
.3
31
.4
32
.5
33
.6
34
.7
35
.8
36
.9
38
.1
39
.2
40
.3
Tim e (Hrs)
Te
mp
. (C
)
24788
30709
36491
42131
47632
52991
58210
63289
Hydrate Temp
Reservoir Composition
Shut in Composition
(bopd)
Cool Down at Pipeline Inlet
Pipeline & Riser Slugging
Insufficient gas velocity in riser
Liquids accumulate at bottom of riser
Liquid accumulation at riser base seals off gas flow Flow out of riser stops
Liquid continues to accumulate at the riser base
Riser begins to fill with liquid Pressure builds upstream of the blockage
Upstream pressure builds sufficiently to overcome hydrostatic head in riser Slug of liquid is expelled, followed by gas which has packed behind blockage
Slugging Types:•Hydro-dynamic•Terrain•Riser induced
Slug Characteristics
0
100
200
300
400
500
600
700
6067
1249
8
1881
9
2502
9
3112
9
3711
9
4299
8
4876
7
5442
5
5997
3
6541
1
Flow Rate (bbl/d)
Frequency (1/Hr)
Length (m)
Volume (m3)
FA – Consequences of Slugging
• Safety to personnel and equipment• Unstable production • Equipment trips • Total field shutdown• Loss of revenue• e.g. 100mbpd field shutdown: loss of $5m /day @ $50/bbl & $10m @ $100/bbl
• Polar components in crude oil
• Stable in presence of resins
• Resins diluted by gas release and injection
• Flocculate in wells and topside equipment
• Prediction via SARA analysis
• Saturates, Aromatics, Resins and Asphaltene fluid property analysis.
• Asphaltene content: amount of material insoluble in n-heptane (or n-pentane) but soluble in toluene
• Precipitation is induced by pressure decrease and/or changes in the solvency of crude oil (by low MW n-paraffins, CO2, acids, etc)
• Minimum solubility at bubble point
Asphaltenes
S.L&B.E-2000
Emulsions Consequences
• Tight emulsion between water and oil causes inversion viscosity• High pressure drop in pipelines• Separation efficiency impaired• Shut-in conditions can cause rheology change to Non-Newtonian behaviour• High yield stress at low shear rates require very high pressure to start up pipeline.
Viscosity at Low Shear Rate (cPoise)
0 10 20
5
100
10,000
S-1Newtonian
Non-NewtonianShear Stress
Shear Rate
Sand Erosion (Pipeline Outlet)
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5
60
67
12
49
8
18
81
9
25
02
9
31
12
9
37
11
9
42
99
8
48
76
7
54
42
5
59
97
3
65
41
1
Flow Rate (bbl/d)
Err
os
ion
(m
m/y
r)
1
5
10
15
20
50
100
200
300
400
500
1000
Sand Ratekg/month
FA – Sand Erosion
Consequences:
• Material Loss
•Pipeline leaks
• Separator Efficiency
• Erosion Velocity Limits
• Requirement for CRA materials
Pipeline Corrosion
0.01.02.03.04.05.06.0
1 3 5 7 9
11 13 15 17 19
Time (Yrs)
Cor
rosi
on (m
m)
Corrosion Rate (mm/year)Corrosion (including fugacity)Corosion (fug+pH)Corrosion (Wcut >5%)Corrosion (90%inhib.eff)Commulative Corrosion
FA – Corrosion
Issues:
• Development of Anti-CorrosionStrategies
• Integrating Multi-Phase Flow
• De-WardMilliums
-25
-20
-15
-10
-5
00
0
50 100 150 200 250 300 350 400
Time (s)
Temp. (C)Outlet-InsulatedMiddle-Insulated
Uninsulated
Inlet-Insulated
Low Temperatures – Well Start-Up
Issues:
• Prod. Hydrates S/U• Material Integrity• Prod. Loss• System S/D• Safety
Mitigation:• Flowline Insulation• Operational
FA Consequences
• Incorrect System designs• Un-necessary Operating Problems • Potential Flow Path Blockage• Resulting Production Shut down• Consequential Revenue Loss• In the extreme: Loss of Asset.
Flow Assurance – Solution Options
• Fluids Handling• Mix Chemicals – Thermodynamic, Kinetic, THI, AA• Heat Retention – Insulation (Passive)• Provide Heating : Fluids / Circulation, Electrical, Other
Active Methods• Remove Heat – Change Rheology (Cold Pipe Slurry)• Separate Fluids• Re-Combine Fluids – Subsea GTLA• Others
Enabling Technologies
Oil
Gas
Water
Reservoir
Separator/Boosting
FPSO
Tanker
Tree
To FPSO
Multiphase Transport
Coselles
Reservoir
Reservoir
• Subsea Processing
• Separation
• Multiphase Pumping
• Metering
• Subsea Gas Compression
• Pipeline Thermal Management
• Raw Sea Water Injection
• Gas to Liquids Conversion
• Gas to Liquids Absorption
• Other Emerging Technologies
Technology- FA Cost Vs Benefit MapCost (Capex / Opex / Intervention)
Simplicity
Benefit
Risk
Low Cost Insulation
Chemicals
Chemicals
Draining Systems
Slurry Transport
Intelligent Slug Control
Slug Control
Active HeatingElectricalInductionTraceLiquid Circulation
Microbes ?
Subsea Processing
Down HoleProcessing(ESP/HSP)
SubseaG-T-L-ALiquid Boosting
MultiphasePumpingPigging
PIP
What is GTLA ?
• Gas to Liquid Absorption.
• Process of Gas Absorption of C1-C3,, CO2,H2S by high gas solubility liquids.
• Fluids Phase Equilibrium Change.
• Recovery of Oil Light End Components (C3-C8).
• Multiphase to Liquid Only Transport.• Considerable Benefits (Capex / Opex).• Innovation / Value.
What is GTLA ?
3 Components to GTLA:• Subsea Achitecture & Absorption. • Transportation.• Host Facilities Processing.• System configurations – Reservoir fluids
characteristics.
Hydrate Blockage Risks
Water
Oil
Gas
0 5 10 15
Years
ProductionRates
Conventional
GTLA
Wax Blockage Risks
Water
Oil
Gas
0 5 10 15
ProductionRates
Conventional
GTLA
Years
Marginal Field Development GTLA
Water Injection
Power/Umbilical
Floating Processing
G-T-L-AAbsorber
LiquidPump
No ManifoldNo Well to Manifold linesNo PIP / insulationSingle Production Line
Impact of GTLA Technology on Hydrate Dissociation.
Hydrate Envelopes
0
20
40
60
80
100
120
140
-60
-52
-44
-35
-27
-19
-11
-2.3
-0.1
0.01
0.32
1.54
7
10 12 14 16 18 20
Temperature (C)
Pre
ssu
re (
Bar
a)
Normal
GTLA
Water Temperature2000m - Angola
Hydrate Envelopes
0
20
40
60
80
100
120
140
-60
-52
-44
-35
-27
-19
-11
-2.3
-0.1
0.01
0.32
1.54
7
10 12 14 16 18 20
Temperature (C)
Pre
ssu
re (
Bar
a)
Normal
GTLA
Water Temperature2000m - Angola
GTLA Technology Benefits
Technical• No Slugging• No Hydrates or Wax• Reduced Corrosion • Reduced Scale• Reduced pipe wt, expansion
& stress, upheaval buckling, expansion joints and burial.
• Reduced Riser fatigue• Increased Safety,
Availability, Reliability & Recovery
• Pressure Boosting via Liquid Pumps.
Economic• One Production Pipeline• No Pipeline Insulation• No Manifold• 60% Pipeline Capex
reduction (no insulation and use of CS rather than CRA)
• Use of SCR’s• Smaller Umbilical Size• No Hydrate or Wax inhibitors• Reduced Interventions.
Integated System
Integated System- General Basis
Sizing of Subsea Infrastructure:System Data:• Reservoir Pressure = 200bara & Host Pressure = 15bara.• Reservoir temperature = 60deg.C.• Well Tubing = 5” & 1500m length.• Sea bed and sea surface temps. = 5 & 15deg.C.• Oil Viscosity = 15, 20 & 30 degrees.• Water Depth =100-2000m• Tie-back Distance = 10-50km.• U = 3W/m2.K
Constraints:• Erosion Limit = C factor of 150 carbon steel pipe.• Hydraulic Limit = Based on max Well Head pressure (150bara)
Integated System Infrastructure
Seabed
Wells
Offshore Host facilities Onshore Facility
Deep Water Risers
Integated System-Charts
0
20
40
60
80
100
120
140
WD
=10
0mD
=10
kmD
=20
kmD
=30
kmD
=40
kmD
=50
km
WD
=50
0mD
=10
kmD
=20
kmD
=30
kmD
=40
kmD
=50
km
WD
=10
00m
D=
10km
D=
20km
D=
30km
D=
40km
D=
50km
WD
=15
00m
D=
10km
D=
20km
D=
30km
D=
40km
D=
50km
WD
=20
00m
D=
10km
D=
20km
D=
30km
D=
40km
D=
50km
mb
op
d
Tie-Back Distance (km)
12" Multiphase Production-100-2000m Water Depth
GOR=100 Visc=30
GOR=100 Visc=20
GOR=100 Visc=15
GOR=500 Visc=30
GOR=500 Visc=20
GOR=500 Visc=15
GOR=1000 Visc=30
GOR=1000 Visc=20
GOR=1000 Visc=15
GOR=1500 Visc=30
GOR=1500 Visc=20
GOR=1500 Visc=15
GOR=2000 Visc=30
GOR=2000 Visc=20
GOR=2000 Visc=15
10" Multiphase Production-100-2000m Water Depth
01020304050
60708090
100
WD
=100
mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
m
WD
=500
mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
m
WD
=100
0mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
m
WD
=150
0mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
m
WD
=200
0mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
mTie-Back Distance (m)
mb
op
d
GOR=100 Visc=30
GOR=100 Visc=20
GOR=100 Visc=15
GOR=500 Visc=30
GOR=500 Visc=20
GOR=500 Visc=15
GOR=1000 Visc=30
GOR=1000 Visc=20
GOR=1000 Visc=15
GOR=1500 Visc=30
GOR=1500 Visc=20
GOR=1500 Visc=15
GOR=2000 Visc=30
GOR=2000 Visc=20
GOR=2000 Visc=15
Integated System-Charts
8"Multiphase Production-100-2000m Water Depth
0
10
20
30
40
50
60
70
WD
=100
mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
mW
D=5
00m
D=1
0km
D=2
0km
D=3
0km
D=4
0km
D=5
0km
WD
=100
0mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
mW
D=1
500m
D=1
0km
D=2
0km
D=3
0km
D=4
0km
D=5
0km
WD
=200
0mD
=10k
mD
=20k
mD
=30k
mD
=40k
mD
=50k
m
Tie-Back Distance (km)
mb
op
d
GOR=100 Visc=30
GOR=100 Visc=20
GOR=100 Visc=15
GOR=500 Visc=30
GOR=500 Visc=20
GOR=500 Visc=15
GOR=1000 Visc=30
GOR=1000 Visc=20
GOR=1000 Visc=15
GOR=1500 Visc=30
GOR=1500 Visc=20
GOR=1500 Visc=15
GOR=2000 Visc=30
GOR=2000 Visc=20
GOR=2000 Visc=15
GOR=2000 Visc=15
Integated System-Charts
Integated System-3D Chart
Integated System-3D Chart
Exploration Appraisal / FEEDDetailedDesign Operations
Cost of Change
Opportunity to Change
Flow Assurance Technology Options & Pipe Sizing for Deep-Water & Long Distance Oil & Gas Transport.Transport Requires:• Innovative Flow Assurance Solutions• Better use of existing & New Technologies• Overcoming Fear to Change• Offer Value Added Benefits• Low Risks
Beware:Operators are queuing up to be 2nd or 3rd to use new technology.
Exploration Appraisal / FEEDDetailedDesign Operations
Cost of Change
Opportunity to Change
Thank YouI would be happy to answer any easy
questions