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