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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



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




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




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


Uncertainties

PSIG 1603 31


Deterministic Analysis

-30% 25% -60% 40%

PSIG 1603 32


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




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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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

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