The SPE Foundation through member donations and a ... · PDF fileThe SPE Foundation through...
Transcript of The SPE Foundation through member donations and a ... · PDF fileThe SPE Foundation through...
Primary funding is provided by
The SPE Foundation through member donations
and a contribution from Offshore Europe
The Society is grateful to those companies that allow their
professionals to serve as lecturers
Additional support provided by AIME
Society of Petroleum Engineers
Distinguished Lecturer Programwww.spe.org/dl
Society of Petroleum Engineers
Distinguished Lecturer Programwww.spe.org/dl
Mack Shippen
The Science and Economics of
Multiphase Flow
Outline
– Introduction
– The Science of Multiphase Flow
– The Economics of Multiphase Flow
– Concluding Remarks
3 3
A Broad View of Fluid Mechanics
milliseconds
1m
1s
Detonation
Reservoir
Pipelines
Terrain Slugs
Molecular Diffusion
Chemical Reactions
Cavitation
Severe Riser Slugging
Hyd. Slugs
Bubbly Flow
Formation
Damage
Wax
Corrosion
Hydrates
ScaleErosion &
Shut-in
4
Focus of this talk
Total Production System
Completion
Choke
Safety Valve
Tubing
Flowline
Pump
Compressor
Separator
Export lines
Riser
Reservoir
gas
oil
Artificial Lift
5
Pressure Changes
Separator
gas
oil
DP Safety Valve
DP Reservoir Drawdown
DP Completion
DP Wellhead Choke
DP Flowline
DP Compressor
DP Oil Export
DP Gas Export
DP Tubing
DP Riser
DP Pump
• Flow in porous media
• Artificial Lift
• Multiphase Flow in pipes
• Chokes/restrictions
• Pumps/Compressors
6
Nodal Analysis
gas
oil
Pwf
Pwf
Flow rate
OutflowInflow
PR
PR
Psep
Psep
Hydraulic Fracture
ESP
7
Temperature Changes
Separator
gas
oil
DT Safety Valve
DT Completion
DT Wellhead Choke
DT Flowline
DT Compressor
DT Oil Export
DT Gas Export
DT Tubing
DT Riser
DT Pump
• Convection (free, forced)
• Conduction
• Elevation
• JT Cooling/Heating
• Frictional Heating
8
Flow Assurance
gas
oil
ReservoirBottomhole
Topsides
Riserbase
Reservoir
Bottomhole
WellheadRiserbase
Topsides
Wellhead
89
Outline
– Introduction
– The Science of Multiphase Flow
– The Economics of Multiphase Flow
– Concluding Remarks
3 10
Liquid Holdup
• Function of the degree of gas-phase slippage
• Gas travels faster because of lower density and viscosity
• Higher mixture velocity less slip
3
Qg = VgAg
QL = VLAL
Vg Ag
VL AL
AL
AG
No slip slip
Holdup = 0 All gas flowHoldup = 1 All liquid flow
𝐻𝐿 =𝐴𝐿
𝐴𝑃𝐼𝑃𝐸11
Pressure Losses
Terrain effects are important! pressure losses uphill are only partially recovered going downhill
12
∝ velocity∝ viscosity
~ zero∝ density12
Evolution of 1D Steady-State Multiphase ModelsM
ore
Ph
ysic
s
2000 2010199019801970196019501800
Single-Phase
Homogeneous (Mixture Reynolds No.)
Darcy-Weisbach-Moody
Flow Regime
Slip
Zuber & Findlay
Drift Flux
Hagedorn
& Brown
Dukler, Eaton & Flanigan GrayEmpirical Category B
2-Phase (Gas-Liquid) 3-Phase (Gas-Oil-Water) Inclination Angle Evolutionary
Key:
Flow Regime
Slip
Lockhart &
Martinelli
Poettmann&
Carpenter
Empirical Category ABaxendell &
Thomas
Empirical Category C
Flow Regime
SlipMukherjee & BrillDuns & Ros
Beggs & Brill
SLB Drift-Flux
Orkiszewski
Mechanistic(Phenomenological) AnsariGovier,
Aziz &
Fogarasi
Taitel & Dukler Xiao TUFFP UnifiedHasan
& Kabir
OLGA-S
LedaFlow PM
4500
30
190
# lines of code
13
State of the art
State-of-the-Art
3-Phase Mechanistic Flow Models
3
BHR 2007-A2
• Based on combined force and momentum balances and best represent
the physics of multiphase flow
• Account for broad ranges of fluids and pipe geometries
• Top 3 (State-of-the-Art) include OLGAS, LedaFlow and TUFFP
Reality Model
SPE 19451
SPE 95749
14
Oil-Water Flow
6-inch pipe1500 BOPD1500 BWPD1.5 cp oil
2º up
2º down
0º
15
Oil−water flow experiments in 6-in.-diameter pipe (oil shown with red dye and water with blue dye). Each case has identical volumetric flow rates: 1500 bpd of each phase. The left-hand image shows upward flow inclined at θ = +2 ° (from the horizontal). The center image shows horizontal flow θ =0 °, while the right-hand image shows downward flow inclined at θ = −2° (from the horizontal). We observe that in the left-hand image, oil "slips" much faster over the water. In the center image, we have near-perfect stratified flow with no discernible slippage between phases, while in the right-hand image, we observe water rapidly slipping beneath the oil. These experiments clearly show how even a small inclination in pipe elevation can have a dramatic effect on slippage and associated flow regimes.
Rule of 10’s For Today’s “State of the Art”
Stable Flow < Operating Rate < Erosional Limits
Deviation angles ±10º of vertical or horizontal
Liquid volume fractions > 10%
Water or oil fraction < 10% relative to total liquid
Pipe diameters < 10 inches
Oil viscosities < 102 centipoise3
Can generally expect +/- 10% Error in Accuracy of Holdup and Pressure Predictions for conditions of:
16
Multiphase Flow Research Centers
IFE, Norway
Sintef, Norway
Cranfield University (TMF), UK
University of Tulsa (TUFFP), US
17
Top 5 R&D Challenges
3. Exotic Fluids - Heavy Oil- Foam- Slurries
5. Model Discontinuities
4. Improved Closure vv Relationships
2. Odd Angles
1. 3+ Phases
18
Outline
– Introduction
– The Science of Multiphase Flow
– The Economics of Multiphase Flow
– Concluding Remarks
3 19
Economics
“Economics is the study of the use of scarce
resources which have alternative uses”
- Lionel Robbins
20
Examples
Example Description
1 - Offshore Field Planning Offshore Oil
2 - Slug Catcher Sizing Offshore Gas Condensate
3* – Terrain Effects Onshore Shale Oil
4* – Heavy Oil Pipeline Onshore Heavy Oil
* Backup example for onshore focused audiences – see supplemental slides
21
Example 1: Offshore Field Planning
Pla
tform
Cos
t
Platform Capacity
Ultra-deep
Deep
Shallow
22
Example 1: Optimal Platform Size
132
Time
Oil
Pro
duct
ion
Rat
e
Oil Production Capacity
Net
Pre
sent
Val
ue (
NP
V)
23
Example 1: Integrated Modeling
Constraints:
Reservoir Forecast Production Network Process Facilities
Max. Liquids: 80,000 BPD
Max. Water: 25,000 BPD
Max Gas Lift: 100 MMscfd
Compressor power: 9,000 Hp.
Production Network
IPTC-11594 24 24
Example 1: Dealing with thru-life constraints
IPTC-11594
Dominant Constraint: Total Liquid
Production Rate
Dominant
Constraint:
Total
Compressor
Power
Dominant
Constraint:
Water
Handling
Capacity
Dominant Constraint:
Operating Costs
25
Example 1: Gas Lift Optimization
Oil
Pro
du
ctio
n R
ate
Total Gas Lift Injection Rate
Oil Rate
Optimum
Field
Well 1
Well 2
Economic
Optimum
(Qo/Qgi)
Numerous published field studies have shown gas lift optimization to
improve production by 3-15%
SPE175785SPE 120664SPE 123799 26
Example 2: Liquids Handling for Offshore Wet Gas Export Pipeline
100-mile 32”
50-mile 24” wet gas
20-mile 12” dry gas
Onshore Slug Catcher
PSIG 0403
30-mile 16” wet gas
27
Example 2: Pigging a Flowline
Why? • Remove solids > reduce blockage risk• Remove liquids > less pressure loss
VL
VG
VM
VL
VGVM
Size of slug proportional to gas-liquid slip28
Example 2: Ramp-Up Surge
Qg initial
Qg final
Qg surge
VL
VL
VL
Size of surge proportional to difference in liquid content before and after
29
Example 2: Slug Catcher Sizing
SLIP (Pig)
SURGE (Ramp-Up)
PSIG 0403
OLG
AS
Ram
p U
p
OLG
AS
Pig
Xia
o R
amp
Xia
o P
ig
$30M $16M
Installed Cost:
30
Example 2: Slug Catcher Sizing
Uncertainties
PSIG 1603 31
Example 2: Slug Catcher Sizing
Deterministic Analysis
-30% 25% -60% 40%
PSIG 1603 32
Example 2: Slug Catcher Sizing
Probabilistic Analysis
P-10
P-50
P-90
P-50
P-90
P-10
PSIG 1603 33
Example 2: Slug Catcher Sizing Economics
PSIG 1603 34
Example 3: Simple Pressure Drop Calculation
5 mile, 4” flowlineGOR = 5000 scf/STB45° API GravityQL = 1000, 100 BPD
Your Job: Calculate the required inlet pressure!
500 psia
35
Example 3: Terrain Effects
62 feet
5 miles
Absolute difference (Net - 0.14°)Terrain effects (+/- 4°from horizontal)
36
Example 3: Results – Pressure Loss
1,000 BPD
100 BPD
Vmix ~ 2 ft/sStratified-Smooth & Slug Flow
D ZTerrain
Takeaway: Terrain Effects Critical For Low Rate Cases!
Vmix ~ 15 ft/sStratified-Wavy & Slug Flow
37
Example 3: Results – Liquid Holdup (OLGAS)
1,000 BPD
100 BPD
D ZTerrain
HL (no-slip) ~ 5%
Slug
Stratified
Slug
Stratified
38
Example 3: Results – Pigging Volumes
1,000 BPD
100 BPD
D Z
Terrain
Takeaway: Terrain Effects Critical For Low Rate Cases!
Pig
Slu
g V
olu
me (
bb
l)
0
10
20
30
40
50
60
70
80
90
100
PV(Terrain)
PV(DZ) PV(Terrain)
PV(DZ)
OLGAS TUFFP
PIG
SLU
G V
OLU
ME
(BB
L)
Pig Slug Volume
Pig
Slu
g V
olu
me (
bb
l)
39
Example 3: Just Part of the Network!
Shale Oil Network: Eagleford Field, Texas
40
Example 4: Inspiration The El Morro Araguaney Pipeline
41
Example 4: Heavy Oil Pipeline
Pin = 800 psia
16◦ API
30 % watercut
Pout = 800 psiaCalculate Liquid Rate
42
Example 4: Diluent Injection – 5.7” pipe
pump
No pump
~ 7000 BPD OIL
~ 5000 BPD
DILUENT
~ 3500 BPD OIL
~ 3600 BPD
DILUENT
~10,000 cp ~ 300 cp 43
Example 4: Diluent Injection – 7” pipe
pump
No pump
~ 7000 BPD OIL
~ 3500 BPD OIL
~ 2700 BPD
DILUENT
~ 1800 BPD
DILUENT
44
Example 4: Pipeline Economics
Method Effect Constraints OPEX CAPEX
Pump↑ pressure↔ friction loss
MAOPPower
↔ Med ↑ High
Diluent↓ viscosity↓ friction loss
DiluentavailabilityPower
↑ High ↔ Med
Larger Pipe size
↓ velocity↓ friction loss
Phase of development
↓Low ↑ High
DRA↓ turbulence↓ friction loss
↔ Med ↓Low
Maximum Allowable Operating PressureDrag Reducing AgentsOperating CostUpfront Capital Cost
MAOP =
DRA =OPEX =CAPEX =
45
Outline
– Introduction
– The Science of Multiphase Flow
– The Economics of Multiphase Flow
– Concluding Remarks
3 46
Concluding Remarks
• Good technology in multiphase flow modeling has emerged from years of research and development
• Challenges still remain flow assurance is not a certainty
• Economics justify the Science!
• Ultimate goal is to maximize production while minimizing flow assurance risks and operational costs
47
An Integrated View of Fluid Mechanics
Pipelines
Wellbores
Reservoir
Process
Equipment
48
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Distinguished Lecturer Programwww.spe.org/dl
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Supplemental Slides
Flow Assurance – Getting it Right
• Deepwater development ~ $3-10B
• Subsea infrastructure ~ $1-3B
• Slugcatcher ~ $30M
• Subsea booster ~ $250M
• Offshore downtime costs ~ $8M/dayOnshore Slugcatcher
Subsea BoosterS1
Example 1: ESP Optimization
Oil
Pro
du
ctio
n R
ate
Total ESP Power
Oil Rate
Optimum
Field
Well 1
Well 2
Economic
Optimum
(Qo/Qgi)
S2
Flow Assurance - Solids Problems
Asphaltene Wax
Scale Hydrate
S3
Multiphase Flow Design Tasks
Time
Pro
du
ctio
n R
ate Target Rate
50% Turndown
Natural flow Artificial Lift Decline Line Sizing
2
2
Arrival Temperature
Equipment Selection & Sizing
Erosion constraints
1
1
3 Backpressure effects3
4 Wellbore Artificial Lift5
4 5
Multiphase Boosting
Liquids Management
7
7
Hydrodynamic Slugs6 Pigging
6
Watercut
GOR
Shut-in & Start-up Operations
8 Ramp-up
8
10 Solids Formation
10
11 Gelling (kick-off pressure)
11
Steady-State
Dynamic
Terrain Slugging9
9
S4
Common Flow Assurance Workflows
Basic DetectionGood ApproximationRigorous
Key:
Full Transient
Steady- State (SS)
Liquids Handling
Ramp-up Surge (Cunliffe’s Method)
Ramp-up Surge
Pigging volumesHydrodynamic Slugs
Terrain Slugs
Severe Riser Slugs
Pigging volumes
Hydrodynamic Slugs
Terrain Slugs
Severe Riser Slugs
Slugtracking
Pipe Integrity
CO2 Corrosion
CO2 Corrosion (SS)
Erosion
Erosion (SS)
Leak/Blockage Detection
Leak/Blockage Detection
Solids
Wax Prediction
Scale Prediction
Wax Deposition
Hydrate Prediction
Hydrate Prediction
Wax Prediction
Hydrate Kinetics/ plugging
Wax Deposition
Asphaltene Prediction
Well-Specific
Liquid Loading
Liquid Loading
Nodal Analysis
Gas Lift Unloading
Artificial Lift Diagnostics
Gas Lift Unloading
Well Testing
Wellbore Cleanup
Worst Case Discharge (Blowout)
Worst Case Discharge (Blowout)
Artificial Lift Diagnostics
ApplicationShut-down/ Start-up
Shut-in (Cooldown)
System Start-up
Depressureization
S5