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