Maximising Multiphase Production From Offshore · PDF fileMaximising Multiphase Production...
Transcript of Maximising Multiphase Production From Offshore · PDF fileMaximising Multiphase Production...
Maximising Multiphase Production From Offshore Pipelines
Presented at the European Mediterranean Oil & Gas Production Summit Conference
(September 2012- Cyprus).
Dr. Kashmir JohalDirector- FIM
www.fluidsinmotion.comwww.fluidsinmotion.com
Agenda
• Introduction.
• Flow Assurance Challenges.
• Flow Assurance Solution Options.
• Technologies- GTLA.
• Design Process Through an Integrated System Approach.
• Summary
Maximisin Multiphase Flow Basically Simple
PRes
PHost
Production (Q) = function of (Pres – PHost. - Losses) is always positive
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
• 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
Gas Hydrates: Formation & Structure
• 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
What Problems Can Hydrates Cause?What Problems Can Hydrates Cause?
• 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
Courtesy of Petrobras
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)
Cool Down at Pipeline Inlet
C ooldow n at P ipe In let
0
1 0
2 0
3 0
4 0
5 0
6 0
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
T im e (H rs)
Te
mp
. (C
)
24788
30709
36491
42131
47632
52991
58210
63289
H ydrate T em p
R eservo ir Com position
Shut in C om position
(b opd)
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 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
Liquid Hold-up Profiles.
• Horizontal: Increase. • 30deg. Up: Increase.• 45deg.Up: Constant.• Vertical: Lowest.• 45deg. Down: Increase.• 30deg.Down: Increase.• Vertical Down: Increase.
Horrizontal30deg.Up
45deg.UpVerticle Riser
45deg. Down30deg.Down
Verticle Down
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
7800 16069 24195 32180 40023 47724 55283 62700 69975
Liquid Holdup Fraction
Liquid Hold-Up Predictions (6" pipe)Using Beggs & Brill Horizontal Correction
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
Asphaltenes• 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
S.L&B.E-2000
Wax Characteristcs
S.L&B.E-2000
PARAFFIN STRUCTURE TYPE
STRUCTURE.
Strait Chain- Normal Paraffin.
Branched Chain- Iso-Paraffin.
Cyclo Chain- Naphthene
• Component in crude at C20+• Solubility measured by Wax
Appearance Temperature (WAT) or Cloud Point (CP)
• Wax appearance and deposition requires integrated wax phase behaviour with thermo-hydraulic analysis.
Wax Deposition Prediction
0
0 .0 1
0.0 2
0 .0 3
0 .0 4
0.0 5
0.0 6
0.0 7
0.0 8
-4 796 1596 2396 2796 3596 4396 5196 5996 6796 7596 8396 9196 9996 10796 11596 12396 13196 13996 14796 15596 16396 17196 17996 18796 19596 20098.4 20303.2 20508 20712.8
Wax Thickness (mm/d)
P ip e le n g th (m )
W a x D e p o s it io n
7 ,0 6 9 .1
13,6 10.2
19,3 48.4
24 ,2 83 .6
28 ,4 15 .9
31 ,7 45 .3
34,2 71.8
35 ,9 95 .3
36,9 15.9
37 ,0 33 .6
10 ,4 40 .0
� �� �= �� �. �� �. ሺ�� �−�� �ሺ
where,M = Wax mass transfer rate per unit time.
mtr = Wax mass transfer coefficient and is a
function of the Reynolds and Schmidt numbers.
PSA = Pipe surface area of consideration.
WFC = Concentration of wax content in the
fluid.WPW = Concentration of wax content at the
pipe wall.
Emulsions Consequences
OPERATING: •Tight emulsion between water and oil causes inversion viscosity• High pressure drop in pipelines• Separation efficiency impairedSHUT DOWN: •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
FA – Sand Erosion
Consequences:
• Material Loss
•Pipeline leaks
• Separator Efficiency
• Erosion Velocity Limits
• Requirement for CRA materials / Q Reduction.
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
606
7
124
98
18
819
250
29
311
29
37
119
429
98
48
767
544
25
59
973
654
11
Flow Rate (bbl/d)
Err
osi
on
(mm
/yr)
1
5
10
15
20
50
100
200
300
400
500
1000
Sand Ratekg/month
Pipeline Corrosion
0.01.02.03.04.05.06.0
1 3 5 7 9
11 13 15 17 19
Tim e (Yrs)
Cor
rosi
on (m
m)
Corros ion Rate (m m /year)Corros ion (inc luding fugac ity)Corosion (fug+pH)Corros ion (W cut >5% )Corros ion (90%inhib.eff)Com m ulative Corros ion
FA – Corrosion
Issues:
• Development of Anti-CorrosionStrategies
• Integrating Multi-Phase Flow
• De-WardMilliums
-2 5
-2 0
-1 5
-1 0
-5
00
0
5 0 1 0 0 1 5 0 2 0 0 2 5 0 3 0 0 3 5 0 4 0 0
T im e (s )
T e m p . (C )O u t le t - In s u la te dM id d le - In s u la te d
U n in s u la te d
In le t - In s u la te d
Low Temperatures – Well Start-Up
Issues:
• Prod. Hydrates S/U• Material Integrity• Prod. Loss• System S/D• Safety
Mitigation:• Flowline Insulation• Operational
Operational Limits.
Hydraulic Limit
Erosion Limit
Slugging Limit
Operating
Region
GOR/Wcut
Multi - Phase Production Operating Limits
Production
Hydrate & Wax Boundaries
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
Consequences of Ignoring FA
• Incorrect designs• Operating Problems • Flow Path Blockages• Production Shut down• Revenue Loss• Loss of Asset.
Enabling Technologies
Oil
Gas
Water
Reservoir
Separator/Boosting
FPSO Tanker
Tree
To FPSO
Multiphase Transport
Coselles
ReservoirReservoir
• 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 Map
Cost (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.
Water Injection
Power/Umbilical
Floating Processing
G-T-L-AAbsorber
LiquidPump
No ManifoldNo Well to Manifold linesNo PIP / insulationSingle Production Line
Marginal Field Development GTLA
Hydrate Risks
Water
Oil
Gas
0 5 10 15
Years
ProductionRates
Conventional
GTLA
Water
Oil
Gas
0 5 10 15
ProductionRates
Conventional
GTLA
Wax Risks
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
0.0
1
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
0.0
1
0.3
2
1.5
4 7
10 12 14 16 18 20
Temperature (C)
Pre
ssu
re (
Bar
a)
Normal
GTLA
Water Temperature2000m - Angola
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.
GTLA Technology Benefits
Integrated System
Integrated System
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 API = 15, 20 & 30 degrees.• Water Depth =100-2000m• Tie-back Distance = 10-50km.
Constraints:• Erosion Limit = C factor of 150 carbon steel pipe.• Hydraulic Limit = Based on max Well Head pressure (150bara)
Integated System
0
10
20
30
40
50
60
70WD=100m
D=10km D=20km D=30km D=40km D=50km
WD=500m
D=10km D=20km D=30km D=40km D=50km
WD=1000m
D=10km D=20km D=30km D=40km D=50km
WD=1500m
D=10km D=20km D=30km D=40km D=50km
WD=2000m
D=10km D=20km D=30km D=40km D=50km
mbopd
Tie-Back Distance (km)
8"Multiphase Production -100-2000m Water Depth GOR=100 API=30
GOR=100 API=20
GOR=100 API=15
GOR=500 API=30
GOR=500 API=20
GOR=500 API=15
GOR=1000 API=30
GOR=1000 API=20
GOR=1000 API=15
GOR=1500 API=30
GOR=1500 API=20
GOR=1500 API=15
GOR=2000 API=30
GOR=2000 API=20
GOR=2000 API=15
GOR=2000 API=15
Integated System
0102030405060708090
100
WD=100m
D=10km D=20km D=30km D=40km D=50km
WD=500m
D=10km D=20km D=30km D=40km D=50km
WD=1000m
D=10km D=20km D=30km D=40km D=50km
WD=1500m
D=10km D=20km D=30km D=40km D=50km
WD=2000m
D=10km D=20km D=30km D=40km D=50km
mbopd
Tie-Back Distance (m)
10" Multiphase Production -100-2000m Water Depth
GOR=100 API=30
GOR=100 API=20
GOR=100 API=15
GOR=500 API=30
GOR=500 API=20
GOR=500 API=15
GOR=1000 API=30
GOR=1000 API=20
GOR=1000 API=15
GOR=1500 API=30
GOR=1500 API=20
GOR=1500 API=15
GOR=2000 API=30
GOR=2000 API=20
GOR=2000 API=15
Integrated System
Exploration Appraisal / FEEDDetailedDesign Operations
Cost of Change
Opportunity to Change
• 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.
Maximising Multiphase Production & Flow Assurance Requires:
Further Information
New Flow Assurance Book
Exploration Appraisal / FEEDDetailedDesign Operations
Cost of Change
Opportunity to Change
Thank YouI would be happy to answer
questions