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Flow Assurance

28 November 2013

Australian ResourcesResearch Centre

Workshop

28 November 2013

The University of Western Australia

Executive Summary We are pleased to welcome you to our November 2013 Flow Assurance Workshop. This event is designed to provide you with an opportunity to examine the ongoing gas hydrates and flow assurance research within the Fluid Sciences & Resources Division of the University of Western Australia. The feedback you provide on these Workshop presentations is critical to producing research that advances both student knowledge and industrial capability. This meeting is organised around three of our 2013 Flow Assurance research themes:

• Hydrate plug formation mechanisms. Hydrate plugs were generated in water-dominant systems using a high-pressure visual stirred cell. The results illustrate that catastrophic plug formation is preceded by the formation of a moving particle bed; this bed formation depends on fluid velocity. Hydrate plugs were also studied in a once-through gas-dominant flowloop, where wall deposition and breakup/sloughing was inferred as a critical mechanism to plug formation.

• Under-dosage of thermodynamic inhibitors. The injection of hydrate thermodynamic inhibitors (e.g. methanol or MEG) represents both a significant investment and potential risk area for transient operations. In cases where complete hydrate inhibition is not achieved, the risk of plug formation is uncertain. New data from both the high-pressure visual stirred cell and single-pass flowloop have together suggested that under-dosage of MEG does not increase plugging risk in water- and gas-dominant systems under turbulent flow conditions.

• Particle interactions in oil-dominant systems. The formation of large hydrate aggregates represents a critical step in the formation of hydrate plugs in oil-dominant systems. Through the new deployment of a hydrate calorimeter, new data suggests that corrosion inhibitors may adsorb to the hydrate particle surface, minimizing the size of hydrate aggregates and effect on slurry viscosity. New data on hydrate nucleation and growth has allowed us to expand this oil-dominant model, to take the first step in quantifying the risk of hydrate plug formation.

We hope you will consider joining us again on the 17 April 2014 to discuss an update on these and other flow assurance-related research activities. Please feel free to contact us should you have any questions or feedback after the meeting. Prof. Eric May, Chevron Chair in Gas Process Engineering

([email protected]) Prof. Mike Johns, Chair of Chemical and Process Engineering

([email protected]) Dr. Zachary Aman, Research Assistant Professor, Mechanical and Chemical Engineering

([email protected])

28 November 2013

The University of Western Australia

UWA Flow Assurance Workshop Thursday 28 November 2013

8:30 AM Coffee on arrival 8:35-8:40 AM Welcome by academic leadership 8:40-9:00 AM Overview of research program and educational directions 9:00-9:30 AM Hydrate Plug Formation in Water-Dominant Systems

(Masoumeh Akhfash) 9:30-10:00 AM Hydrate Management in Under-Inhibited Conditions

(Sang Yoon Ahn) 10:00-10:30 AM Morning coffee/tea break 10:30-11:00 AM Hydrate Film Growth in a Gas-Dominant Flowloop

(Mauricio Di Lorenzo) 11:00-11:30 AM Corrosion Inhibitor-Hydrate Interactions with High-Pressure Calorimetry

(Alexandra Thornton, Kristopher Pfeiffer) 11:30-12:00 PM Stand-Alone Tool to Assess Hydrate Plug Formation Risk

(Bruce Norris, Zach Aman) 12:00-1:00 PM Lunch in meeting room and informal discussion 1:00-2:00 PM Formal feedback from attendees 2:00-2:30 PM Optional tour of laboratory and flowloop facilities

Fluid Science & Resources Division

Winthrop Professor Michael Johns Chair of Chemical and Process Engineering

Winthrop Professor Eric May Chevron Chair in Gas Process Engineering

Fluid Science & Resources

Colors: Gradient Light Blue #2992ce Gradient Dark Blue #1163b7 (also used for text of logo)

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Academic & Research Staff

2

Brendan Graham Tom Hughes Ken Marsh Mike Johns Eric May

Einar Fridjonsson

Paul Stanwix

Kevin Li Zachary Aman Agnes Haber

• 2 Technicians• 16 PhD Students including 2 based in CSIRO labs

Clayton Locke Sarah Vogt



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Research Themes

• Oilfield Emulsions

• Oil and Gas Field Water Management

• CO2 Research

• Advanced Gas Thermodynamics

• Gas Separations & Adsorption

• Hydrates and Flow Assurance

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Collaborators

4 4



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Funding From …

5 5



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Flow Assurance Teaching

6

New (3+2) UWA Engineering Undergraduate/Masters Degree Structure

Transport Phenomena Gas Processing 1 - Flow Assurance and Gathering

Gas Processing 2 – Treatment and LNG Production OLGA Training



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Growth in Chemical Engineering

7

Year! Student #!2006 75 2007 160 2008 221 2009 302 2010 403 2011 441 2012 483 2013 482

Gas Hydrates and Flow Assurance Research Program

Zachary M. Aman 28 November 2013

UWA Flow Assurance Workshop



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Research Team Academics and Fellows

Doctoral Students

Visiting Scholar: Sang Yoon Ahn (Hyundai)

M.S. Students • Alexandra Thornton• Bruce Norris • Evgeny Bespalov • Alexander MacAdie• Chris Sinclair



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Laboratory Tools Enable Broad Lengthscale of Study

Fundamental inquiry of hydrate behaviour • Nucleation, growth, deposition, particle behavior

Macroscopic validation of conceptual models • Formation (autoclave and flowloop) • Dissociation (plug cells)

Rheology (1 mm)

Interfacial Tension (1 µm)

Visual Autoclave

(5 cm)

Flowloop (100 m)

Plug Cells (1 m)

Hydrate Calorimeter

(50 µm)



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Hydrate Projects Focus on Plug Formation and Remediation Risk Assessment • Formation probability • Plugging mechanics

Plug Formation • Particle interactions • Nucleation and growth rate• Aggregation• Slurry behaviour • Deposition and sloughing

Plug Dissociation • High-pressure confined cell• Live fluid

injection• Heating

Chemical Control • Chemical interactions • Emulsion, dispersion

stability • Chemical

adsorption



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Oil-Dominant Conceptual Model: Viscous Hydrate Slurry

Particle interactions represent critical step • Plug formation through jamming-type failure

Deposition requires future consideration

Turner et al., Chem. Eng. Sci, 2009



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Water-Dominant Conceptual Model: Hydrate Bed Formation

Hydrate particles form moving bed (Φtransition vol%) • Detected by increase in resistance to flow• Critical stage observed before plug formation

Bed decreases velocity, enables deposition • May accelerate hydrate growth rate

Joshi et al., Chem. Eng. Sci, 2013



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Gas-Dominant Conceptual Model: Hydrate Film Growth on Wall

Hydrate growth from wetted gas on cold wall • Buildup increases shear stress from moving fluid• Large deposits may fracture (slough) at high stress

Plugging may arise from jamming-type failure • Interaction between fractured deposits

Lingelem et al., Annals NYAS., 1994



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2013 Research Themes 1) Plug formation mechanisms

• Particle bed represents critical step in water systems • Hydrate film growth inferred in gas-dominant flowloop

2) Under-dosage of thermodynamic inhibitors• Hydrate was able to grow in water, gas systems • MEG enhanced hydrate transportability

3) Particle interactions in oil systems• Corrosion inhibitors may behave as hydrate dispersant • Large particle interactions increase risk profile

Next Meeting: 17 April 2014



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UWA Flow Assurance Workshop 9:00 AM Hydrate plug formation in water-dominant systems

9:30 AM Hydrate management in under-inhibited conditions

10:00 AM Morning coffee/tea

10:30 AM Hydrate film growth in a gas-dominant flowloop

11:00 AM Corrosion inhibitor-hydrate interactions with high-pressure calorimetry

11:30 AM Stand-alone tool to assess hydrate plug formation risk

12:30 PM Lunch and informal discussion

1:00 PM Attendee feedback on presentations

2:00 PM Optional tour of laboratory and flowloop facilities

Hydrate Plug Formation in Water-Dominant Systems

Masoumeh Akhfash 28 November 2013




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2

B.Sc. (‘04), M.Sc. (‘08) Chemical Engineering, Iran • Thesis on “Fabrication and performance of PEBAX hybrid

membranes with application to gas sweetening”

Process Engineer, 2009-2012, TACE Company, Iran

PhD student, April 2012

Introduction: Masoumeh Akhfash



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Conclusions

Hydrate plugging risk factors identified in autoclave geometry

• Similar behavior to ExxonMobil flowloop results • Repeatable hydrate growth rates and

resistance-to-flow behavior Plugging-type behaviour above 15 vol% hydrate

• Bed formation and wall depositionenhanced hydrate growth

• May indicate onset to plug formation

Maximum resistance to flow at 1500 Re • Higher stirring velocity minimizes wall deposition

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Increase methane-water surface area

Faster hydrate growth

o  Potential build-up/deposition

Hydrate plug models focused on oil

o  Mechanics require validation in water systems

Motivation: Hydrate Plug Risk in High Watercut Systems

J.G. Gluyas, H.M. Hichens, The United Kingdom Oil and Gas Fields-commemorative Millennium Volume: No.20: Memoir, 2003



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Hydrate particle collection from density difference

Enables particle interactions and wall deposition •  Heterogeneous particle distribution (Φtransition) is a critical

path to bed and plug formation (Joshi et al., 2013) •  Bedding studied by Dr. Oris Hernandez (U. Tulsa, BP)

Conceptual Picture: Hydrate Bed Formation Leads to Plugging

Φtransition



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Hydrate Plug Formation Studied with High-Pressure Visual Autoclave Cell Single-pass flowloopVisual autoclaveHydrate plug cellsRaman spectroscopyLow-field NMRHP RheometerHP interfacial tensiometryMicromechanical forces

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Hydrate Plug Formation Studied with HP Visual Autoclave Cell

Single-pass flow loop Visual autoclave Hydrate plug cells Raman spectroscopy Low field NMR HP Rheometer Hp interfacial tensiometry Micromechanical forces

Specifications: •  1” sapphire cell •  High pressure cell •  Vane-blade mixing geometry •  200-1500 RPM (up to 5000 Re) •  Constant pressure or volume Basic Procedure: 1.  Fill cell with liquids (water/oil) 2.  Pressurize with stirring 3.  Cool below hydrate equilibrium 4.  Record pressure, temperature

and motor current/torque High -pressure sapphire cell



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DI WaterMethane800 RPM

100

120

140

160

180

200

220

240

0

10

20

30

40

50

60

70

0 5 10 15 20

Mot

or C

urre

nt (m

A)

Pres

sure

(bar

) \ T

empe

ratu

re (°

C)

Time After Cooling Begins (hours)

Pressure

Temperature

Motor Current

Hydrate Nucleation Model Region

Hydrate Growth Quantified by a Decrease in Cell Pressure



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Video Speed: 1250×

Heterogeneous Particle Distribution Detected Visually

Vane-and-baffle geometry impeller



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Skovborg Model: Diffusion-limited Hydrate Growth

Physical requirements to grow hydrate in water:

1.  Gas dissolution (bubbleentrainment) in water

2.  Gas diffusion in the aqueous phase (limiting step)

3.  Reaction between water and dissolved gas to form hydrate

Model over-prediction of growth rate may indicate dissolution-limited regions

• Kinetic reaction 500× faster than other steps

Skovborg et al., Chem. Eng. Sci., 1994.



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Bed Formation Detected in Both Pressure and Motor Current Signals

Four comparative ‘regions’ identified after nucleation in pressure and motor current signals

A. Growth from methane-saturated water B. Growth limited by re-saturation of methane C. Bed formation generates water-gas interfacial area D. Catastrophic hydrate growth



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Hydrate Bed Formation Identified from ExxonMobil Flowloop Tests

• Bed formation resulted in initial pressure drop increase• Hydrate plugging behaviour (red) followed Φtransition

Joshi et al., Chem. Eng. Sci., 2013



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Critical Hydrate Fraction (Φtransition) Also Observed in Autoclave Measurements

• Three repeat trials at 400 RPM • Regional boundaries (A-D) identified from pressure data • Region C onset may correspond to Φtransition in autoclave

Joshi et al., Chem. Eng. Sci., 2013



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Φtransition Observed From Three Independent Measurements

1. Pressureconsumption

• Slope change2. Motor current / torque

• First increase abovenoise level

• Most valid method3. Visual observation

• Heterogeneity in hydratedistribution

• Deposition on wall



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Hypothesis of Mixing Deficiency Tested at 50, 800 RPM

Excellent Agreement (800 RPM)

Greater Mixing Deficiency (50 RPM)



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Excellent Repeatability in Motor Current Achieved with Autoclave

Maximum motor current may indicate plugging risk



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Φtransition Increases with Velocity Up to 4,000 Re

Similar observation to Joshi et al. (2013)

• First visualconfirmation of Φtransition

• Observe deposition as critical parameter

Further tests required above 4,500 Re

• Φtransition decrease may be geometry artefact

Curve to guide the eye


Peak motor current observed at 1,500

2

Re

Re 1000

N D

turbulent

ρµ

•

=

〉



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Shut-in and Restart Trials Show Similar Φtransition Behavior

Initial 1 vol% hydrate formed without stirring

• System inside hydrateregion before mixing

• Impeller started after initial growth (constant velocity)

• May simulate “coldrestart” effect

Average deviation in Φtransition is 4.5 vol% hydrate




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Conclusions

Hydrate plugging risk factors identified in autoclave geometry

• Similar behavior to ExxonMobil flowloop results • Repeatable hydrate growth rates and

resistance-to-flow behavior Plugging-type behaviour above 15 vol% hydrate

• Bed formation and wall depositionenhanced hydrate growth

• May indicate onset to plug formation

Maximum resistance to flow at 1500 Re • Higher stirring velocity minimizes wall deposition



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Way Forward

Hydrate formation in oil-phase systems

• Beginning with low water cut (e.g. 10 vol%)

• Full dispersion of water / hydrate

• Particles and aggregates captured by high-

speed camera

Hydrate Management in Under-Inhibited Conditions

S.Y. Ahn 28 November 2013




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Introduction

Name : Sang Yoon, AHN (Hyundai Heavy Industries)

Experience – 11 years in process engineering

• FLNG : Hyundai FLNG • FPSO : USAN, MOHO BILONDO • Fixed P/F : USGIF, Rong-Doi

– Stayed at Abu Dhabi Offshore for one (1) year to support start-up

Work at UWA – Subject : Prediction of hydrate formation and control– Period : July 2013 ~ June 2014

2



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Conclusions

MEG increased hydrate growth rate at least 75%

MEG decreased resistance to flow in turbulent systems

MEG delayed hydrate bed formation (ɸtransition)

3



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Motivation: Hydrate Prevention and Remediation in Deep Water

22°C

5°C

Cost of hydrate prevention increases with depth

• Pipeline insulation thickness increases • MEG regeneration package is larger • Canyon Express (2,200 m, GoM)

o 1 US Mil $/16 days, without methanol recovery 4

Deep water increases the chance of hydrate formation

• More severe PT conditions • Longer retention time



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Pressure&

Temperature&

Pressure&

Temperature&

Pressure&

Temperature&

Pressure&

Temperature&

Motivation: Effect of Under-Inhibition on Hydrate Growth and Transportability

Hydrate under-inhibited condition

• Insufficient amount of hydrate inhibitor (THI)

• Monoethylene glycol(MEG) used here

• Malfunction of equipment, or transient operations

Unknown effect on plug formation

• Hydrate growth rate• Transportability • Plant operating range

Hydrate Free Region

Hydrate Forming Region

5% 15% MEG 0%

5



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Previous study on hydrate under-inhibited system • Performed by Xiaoyun Li (Statoil, 2008, 2011) • Oil dominant system (Water+MEG at 20 vol% of oil volume) • Plugging potential increases to max at 10~15 wt% MEG

MEG Suggested to Increase Hydrate Risk

Will water dominant systems show

similar behavior?

Concentration of MEG

Gel-like plugs

Hyd

rate

plu

ggin

g po

tent

ial 0~5% 5~20% > 20%

Deposits on wall

Hard plugs

Softer plugs

High degree of agglomeration

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50

60

70

80

90

100

110

0 2 4 6 8 10 12 14

Pressure/(b

ar)

Temperature/(Deg/C)

0%/5%/10%/15%/

Initial Temp (25 °C)

Experimental Pressure Increased to Maintain Hydrate Subcooling

Stability Point (9 °C)

Target Temp (1 °C)

Subcooling (8 °C)

Hydrate Free Region

Hydrate Forming Region MEG Pressure

0% 64 bar

5% 72.5 bar

10% 85 bar

15% 100 bar

Initial Condition

Component Methane Water MEG

RPM 200 400 600 800

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Higher MEG Concentration Causes Slush-Type Hydrate

5%

15% MEG

End (64.5%/47.8%)

0% MEG

10% 15% 20%

Hydrate Volume Fraction

8



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No MEG: Solid-Type Deposition

Particles are small and accumulate 9

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With MEG: Slush-Type Deposition

Larger hydrate particles at nucleation

15 WT% MEG IN WATER 200 RPM

10



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Initial Growth Rate Increased with Turbulence and MEG

0.00

0.01

0.02

0.03

0.04

0.05

0.06

1,000 3,000 5,000

Initial0Growth0Rate0(m

ol/hr)

Reynolds0Number

10%

15%

5%

0%

Initial growth rate increases exponentially with Re

MEG increases initial growth rate

•  Highest initial growth rate at 10% MEG

•  Similar subcooling from equilibrium

75%

11

Re = N•

ρmixtureD2

µmixture



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0

20

40

60

80

0 5 10 15

HydrateV

olum

e4Fractio

n4(%

)

MEG4Concentration4(wt%)200,4400,4600,48004RPM

Maximum Hydrate Volume Decreased with MEG

Average hydrate volume fraction decreases

Limited gas-water contact reduces hydrate growth rate

12 vol%

(Error bounds represent range)

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MEG Delayed ɸtransition and Decreased Max Torque

ɸtransition is delayed with MEG

•  Delayed onset of plug behavior

Max torque decreases with MEG

•  Slurry remains flowable •  Analogous to ΔP

MEG enhances transportability of hydrate slurry

0

2

4

6

8

10

0 20 40 60

Torque

-(Ncm

)

Hydrate-Volume-Fraction-(%)

0%

10%

15%

NO ɸtransition

10.5 %

18.6 %

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5

10

15

20

25

0 5 10 15

Max(Torqu

e((Ncm

)

MEG(Concentration((wt(%)200(RPM 400,(600,(800(RPM

Max Torque Decreased with MEG

Max torque decreases with MEG increases

•  0, 10, 15% MEG independent RPM

•  5% follow trend but with peak at 1,300 Re

(200 RPM: Laminar/Transition, 400+ RPM: Turbulent)

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MEG Improves Plugging Onset Point At Low Turbulence

Delayed ɸtransition may lower plugging risk

Below 10% MEG, less sensitive on turbulent system

•  High RPM, ɸtransition is relatively same

•  Low RPM, ɸtransition is delayed

At 15% MEG, ɸtransition is delayed more than 45%

0

5

10

15

20

25

30

0 5 10 15

ɸtran

sitio

n.(Vol.%)

MEG.Concentration.(wt.%)200,.400.RPM 600,.800.RPM

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Conclusions

MEG increased hydrate growth rate at least 75%

MEG decreased resistance to flow in turbulent systems • Laminar systems followed trend, with peak at 5 wt% MEG

MEG delayed hydrate bed formation (ɸtransition) • Turbulent systems less sensitive to MEG effect

Initial'Growth'Rate'

Reynolds'Number

10%

15%

5%0%

75% Max$Torqu

e$

MEG$Concentration$200$RPM 400,$600,$800$RPM

ɸtran

sitio

n)

MEG)Concentration)200,)400)RPM 600,)800)RPM

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Way Forward

Effect of under-inhibition on gas + water + oil systems

• Low watercut (fully emulsified water)• High watercut (separate phases)

17

Hydrate Film Growth in a Gas-Dominant Flowloop

Mauricio Di Lorenzo 28 November 2013




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Mauricio Di Lorenzo

2

Flow assurance specialist, CSIRO • Leading Oilfield Chemistry and

Engineering team

Part-time PhD student at UWA

13 years industry experience • R&D projects at PDVSA

(Venezuela) • Physical-chemistry and

hydrodynamics of production and drilling fluids



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Conclusions Hytra flowloop captured observations of hydrate deposition and sloughing • Way forward on modelling hydrate growth

Under-inhibition with MEG decreased plugging risk • Decreased rates of hydrate growth

and pressure drop increase

Anti-Agglomerants (AAs) reduced maximum pressure drop achieved during restart test

3



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Focus on Australian Offshore Gas

4

Considerations in deepwater •  Long tiebacks•  Hilly seabed•  Low temperatures•  High pressures

Relevant questions 1.  What are the mechanisms of

hydrate plug formation in gas pipelines?

2.  Can hydrate plug formation risk be predicted?

3.  What tools are available to prevent or delay plug formation?

Morgan, J.E.P. - OTC 19706 (2008)

Hydrate region



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Field trials • 1994 Tommeliten Gamma Field (gas-condensate pipe, 6”, 11.5 km) • 1997 Werner Bolley Field (gas-condensate pipe, 4”, 5.3 km) • 2012 ExxonMobil (oil pipe, 4”, 3.2 km)

Gas-Dominated

Liquid-Dominated

Multiphase flow simulators• 1996 OLGA-CSM Hydrate Kinetics

module• 1998 Flowasta Hydrate Kinetics module

Liquid-Dominated

Knowledge Gap in Gas Systems

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Flow Loops • 1992 Univ. of Calgary (2” dia.) • 1994 ExxonMobil (4” dia.) • 1994 IFP (Lyre loop) (2” dia.) • 1994 SINTEF wheels (2”-5” dia.) • 1996 Texaco (2” dia.) • 1999 Marathon-Tulsa Univ. (3”)

Liquid-Dominated



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Gas Pipelines Emphasise Deposition

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(E.D. Sloan et. al – Natural Gas Hydrates in Flow Assurance, 2011)

Hydrate blockage in oil pipelines

• Gas + condensate + water

• Above 90 vol% gas

• Deposition and wallsloughing

(based on M.N. Lingelem et al. 1994)

• Gas + oil + water • Above 70 vol% liquid

• Agglomeration andjamming

Hydrate blockage in gas pipelines



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Test%sec'on%

U+bend%

Hytra: Gas-Dominant Single-Pass Loop • Simulate deep-water gas field conditions• Liquid loading below 10 vol%• High gas velocity, wavy-annular flow regimes• Steady-state flow and transient-flow tests

7

TECHNICAL SPECIFICATIONS Test'sec.on' 1'inch'SS'360'pipe,'40'm'long'

Pipe<in<pipe'temperature'control'

Condi.ons' Pressure:'<1750'psig'Temperature:'17'to'86'°F'

Fluids' Aqueous'solu.ons,'light'oils,'natural'gas'

Flow'rates' Liquid:'1'to'8'L/min'(0.05'<'VL'<'0.4'm/s)'Gas:'500'to'1000'scfm'(4'<'Vg'<'9'm/s)'

Instruments' 7'pressure'transducers,'7'RTD'sensors'Gas'and'liquid'flow'meters'Viewing'windows,'high'speed'camera'



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Constant-flow Test Procedure 1.  Flow loop pressurized with domestic gas (P=1000 to 1500 psig) 2.  Flow loop walls cooled down (T=39 to 68 °F) 3.  Domestic gas circulated at high velocity (8.5 m/s) 4.  Data logging started (pressure, temperature, flow rates) 5.  DI-water injected at constant flow rate (liquid load 5%) 6.  Fluid circulation stopped when full loop pressure drop > 200 psid

8



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sect%1% sect%2%

sect%3%sect%4%

No hydrates

Low subcooling

High subcooling

Gradual ΔP Increase at Low Subcooling

P=1000 psig, T=54 °F: TSUB=7 °F

Full-loop

Sect. 4

Sect. 2

9

P=1250 psig, T=66 °F: No hydrates

Beggs and Brill



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Primary Hydrate Restriction Moves Downstream at High Subcooling

10

P= 1500 psig, T=39 °F: TSUB=26 °F sect%1% sect%2%

sect%3%sect%4%

Pressure%drop%(psid)%

Time%(min)%%

Sect. 2

Sect. 3

Sect. 4

Full loop

ΔP behaviour depends on subcooling

15.4 °F

4.6 °F



Font: Lato LightInhibitor concentration less than required to fully suppress hydrates (under-inhibited)

Economic incentives to reduce/optimize MEG dosage

Research directions on hydrate management •  Under-inhibition•  Hybrid inhibition: THIs + AAs

Hydrate Risk Management with Under-Dosed Thermodynamic Inhibitor

Gas field producing 1000 MM scfd

11

5 stbw/MMscf

1 stbw/MMscf

20 wt% MEG in Water (P = 1500 psi)



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Under-Inhibition Improves ΔP Profile

Formation rate estimated from gas consumption

Plugging risk may decrease with increasing MEG: • Lower rates of ΔP increase• Lower rates of hydrate

formation12

MEG + water at P=1500 psig, T=49 °F

20%'MEG'

30%'MEG'

10%'MEG' Uninhibited'



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←15 m

39 m →

Visual Observation of Hydrate Buildup

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VW 1

0 MEG

VW 4

0 MEG

VW 1

20% MEG

TSUB=26 °F

TSUB=7 °F



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LDHIs Investigated in Transient Cases

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Experimental procedure

1.  U-bend is charged with liquids and flow loop pressurized (P=1500 psig)

2.   Shut-in: Test section cooled down to T=36 °F for 6 hours

3.   Restart: Gas flow throughthe U-bend at 8.0 m/s

4.  T, P readings logged

5.  High speed video recordedat viewing window VW 3

Gas flow path after restart

P-T 1 P-T 2 P-T 3

P-T 4

P-T 5

VW 2

VW 4

VW 1

VW 3

P-T 6

compressor

P7

80 L separator

T7



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AAs Decrease Plug Severity on Restart

15

Proposed conceptual picture

A

B

C

Materials Brine: Distilled water + 1000 ppm NaCl Oil: decane Hydrate inhibitor: LDHI-AA: 3% w conc.

Test conditions • P=1500 psig, T=36 °F (TSUB: 30 °F) • 70 vol% liquid (96% water cut) • Gas velocity: 8 m/s

AA%

Blank%Pressure%drop%across%the%U+bend%

Di'Lorenzo,'M.'et'al.''7th$Int.$Conf.$on$Gas$Hydrates$(2011)'



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Visual Observation of Hydrate Slurry

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Videos at 1500 frames/sec from VW 3 Uninhibited – TSUB=30 °F

brine

decane

hydrates

gas

Inhibited – TSUB=30 °F

brine+AA

decane

gas



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Conclusions Hytra flowloop captured observations of hydrate deposition and sloughing • Way forward on modelling hydrate growth

Under-inhibition with MEG decreased plugging risk • Decreased rates of hydrate growth

and pressure drop increase

Anti-Agglomerants (AAs) reduced maximum pressure drop achieved during restart test

17



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Way Forward

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Investigate hydrate formation from water condensation (wet gas systems) • Continuous flow experiments in water saturated and

undersaturated conditions (stenosis build-up & sloughing) • Models for scaling-up to field pipelines

Investigate the effect of AAs in underinhibited systems • Continuous injection of MEG-AAs hybrid inhibitors

QUESTIONS Thank You

This research has been funded by the CSIRO

Corrosion Inhibitor-Hydrate Interactions with High-Pressure Calorimetry

Alexandra Thornton, Kristopher Pfeiffer 28 November 2013




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Introduction: Alex Thornton

5th year student at UWA

Bachelor of Engineering (Chemical & Process) and Bachelor of Arts (Italian)

Graduating in November 2014

Final Year Project in hydrate calorimetry

Avid explorer, sailor, foodie and bookworm

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Summary

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• Corrosion inhibitors may behave as dispersants inhydrate systems

• Water phase salinity activates natural oil surfactantsto stabilise the hydrate dispersion

• Calorimetry can quantify hydrate dispersion stability



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Hydrate Growth Mechanics for Emulsified Water Droplets

• Formation at water-hydrocarbon interface• Inward growth by diffusion of guest/water across

crystal• Four-step mechanism for hydrate conversion

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Water droplet

Hydrate film develops

Thin hydrate shell

Shell thickens

Fully converted hydrate

Requires hydrate-forming conditions

Diffusion-limited steps

Rapid hydrate growth

Adapted from Sloan, Koh & Sum, 2011



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Aggregating Hydrate Particles May Lead to Complete Blockage

• Particle-particle interactions represent a critical step• Anti-agglomerants (AAs) and kinetic hydrate inhibitors

(KHIs) adsorb to the hydrate crystal• Do Corrosion Inhibitors share similar properties?

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Turner et al. (2009) in collaboration with J. Abrahamson



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+

+

+

+

Water droplets coalesce: emulsion is unstable

Less hydrate forms

Heating

Artificial surfactants prevent droplets coalescing

-

+ -

+ - +

- + - + Charge in saline water

activates less hydrophilic natural surfactants

No change in droplet size: emulsion is stable

Minimal change in hydrate volume formed

Minimal change in hydrate volume formed

Emulsified water droplets

Thin hydrate shell forms

Hydrate

freezing

Hydrate freezing

Hydrate freezing

Hydrate freezing

Hydra

te tha

wing

Hydrate thawing

Hydrate thawing

Strong Surfactants May Stabilise the Dispersion, Affecting Hydrate Formation



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Calorimetry Used to Capture Hydrate Formation/Growth • Water-in-oil emulsion placed in DSC cells

• Cell temperature changed, and the energy required tomaintain set-point temperature is recorded

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DSC Thermograms Quantify Power Required for Hydrate Dissociation

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Signal indicates total amount of hydrate

Constant heat of fusion assumed

Large water droplets form hydrate “shell”

• Decreases signal

Thermogram integrated to estimate hydrate volume

A!∝!Vhydrate

(µW

)



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Experimental Procedure for Hydrate Formation in DSC

• Cells slowly pressurised with 6.2 MPa methane• Temperature program started (7-10 cycles)

• Resultant power curves integrated numerically todetermine amount of hydrate formed in each trial

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DSC temperature settings for single formation/dissociation trial.

Step! Direction! TLower (°C)! TUpper (°C)! Rate (°C/min)! Duration (hr)!

A Cooling! -30.0 20.0! -1 --B Isothermal -30.0 -- -- 1.00!C Heating! -30.0 0.0! +1 --D Heating! 0.0! 20.0! +0.1 --



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Local Crudes Blended for Baseline Stable Emulsion

Emulsion blend of local crude oils: • 40:60 blend of heavy:light oils • Blended oil density = 0.85g/cc (room temp, press) • Blended oil viscosity (@20°C) = 4.7cP

Emulsion prepared with 30% watercut • CIs added to oil blend before emulsifying• Salt added to water phase

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Experimental Droplet Diameters Approximately 2-10 Microns

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Log-normal distribution confirms representative emulsion



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Goal: Quantify Corrosion Inhibitor-Hydrate Interactions

Model corrosion inhibitor chemistries (CPC, CTAC):

Similar ionic characteristics to anti-agglomerants • Corrosion inhibitors may adsorb to hydrate-oil interface

DSC dispersion stability tests deployed

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25/11/2013'

5'



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Baseline Dispersion Breaks with Repeated Dissociation Cycles

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•  Numerically integrate dissociation thermograms

•  Estimated relative hydrate volumes

•  Normalise data to cycle 2 for repeat trials (live oil)

0"

0.05"

0.1"

0.15"

0.2"

0.25"

0.3"

0.35"

1" 2" 3" 4" 5" 6" 7" 8" 9" 10"

Hydrate(Form

ed((m

g)(

Cycle(

Absolute(Volume(Hydrate(Formed(



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•  Repeatability within 10-20% dispersion stability

•  Minimal stability increase above 10-5 mass fraction

CPC May Adsorb Strongly to Hydrate-Oil Interface Above 10-5 Mass Fraction

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0"

0.1"

0.2"

0.3"

0.4"

0.5"

0.6"

0.7"

0.8"

0.9"

1"

2" 3" 4" 5" 6" 7"

!Rela&

ve!Dispe

rsion!Stab

ility!

Cycle!number!

Dispersion!Stability!with!CPC!in!Blend!

0

3x10-6

10-5 2x10-2



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•  No meaningful improvement above 10-5 mass fraction

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0"

0.1"

0.2"

0.3"

0.4"

0.5"

0.6"

0.7"

0.8"

0.9"

1"

2" 3" 4" 5" 6" 7"

!Rela&

ve!Dispe

rsion!Stab

ility!

Cycle!number!

Dispersion!Stability!with!CTAC!in!Blend!

0

10-6

10-5

2x10-2

CTAC Shows Similar Adsorption-Type Behaviour Above 10-5 Mass Fraction



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Natural Surfactants may Stabilise Hydrate Dispersion

Crude oils contain less-hydrophilic natural surfactants • Similar function to injection chemicals?

Salinity may activate natural surfactants

• Allow adsorption to hydrate-oil interface?

At high salinity, brine emulsion may become stable

DSC stability tests again deployed

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0"

0.2"

0.4"

0.6"

0.8"

1"

1.2"

2" 3" 4" 5" 6" 7" 8" 9" 10"

Rela%v

e'Hy

drate'Vo

lume'

Cycle'

3.5%'Salt'Rela%ve'Hydrate'Volume'

!200$

0$

200$

400$

600$

800$

1000$

1200$

2$ 6$ 10$ 14$

Power&(μ

W)&

Temperature&(°C)&

Dissocia7on&Thermogram&for&10&Cycles&

Emulsions with Brine Exhibit the Same Trends as those with Corrosion Inhibitor

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• Hydrate volume decreases with cycle count

• Baseline is consistent between cycles

• Same trends as in trials with corrosion inhibitors

Cycle Count



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Salt Increases Dispersion Stability

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Stable dispersion ≥ 80% hydrate after 7 cycles

Stabilizing effect at 0.1 wt% salt

• Insufficient stabilisation

Brines of ≥ 5 wt% show stable behaviour

0"

0.2"

0.4"

0.6"

0.8"

1"

1.2"

0" 0.1" 0.5" 1" 3.5" 5" 10"

Rela%v

e'Hy

drate'Vo

lume'

Weight'Percent'Salt'in'Brine'

Rela%ve'Hydrate'Volume'at'Cycle'7'



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Conclusions

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• Corrosion inhibitors may behave as dispersants inhydrate systems above 10-5 mass fraction

• Water phase salinity activates natural oil surfactantsto stabilise the hydrate dispersion

• Calorimetry can quantify hydrate dispersion stability



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The Way Forward

• Exploration of competitive adsorption betweenartificial surfactants and natural oil surfactants

• Comparison with established performance testingmethods including autoclave cells

• Exploration of surfactants’ structure-activityrelationships

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Stand-Alone Tool to Assess Hydrate Plug Formation Risk!

Bruce Norris, Zachary M. Aman 28 November 2013

UWA Flow Assurance Workshop!

Tool to Unite Laboratory Studies!

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Rheology (1 mm)

Interfacial Tension (1 µm)

Visual Autoclave

(5 cm)

Flowloop (100 m)

Plug Cells (1 m)

Hydrate Calorimeter

(50 µm)

Hydrate Growth - Conditions - Rate

Transportability - Velocity / slip - Particle slurry - Deposition - Fluid properties - Pressure drop

Hydrodynamics - Flow regime - Momentum + +

Three primary roles of laboratory and field models:

Hydrate Flow Assurance Simulation Tool (HyFAST)

• International collaborationwith the Colorado School of Mines

• Unites the most advanced hydrate models • Each equation / model is well characterized• 5-10 second runtime per case• Uses simple hydrodynamic relationships

Screening tool to select critical cases • Identify high-risk cases for OLGA/Leda follow-up• Appropriate for subset of operating conditions • Working to expand validation!

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Creating an Open, Accessible Model

HyFAST: A User-Friendly Hydrate Tool!

HyFAST: A User-Friendly Hydrate Tool

Advanced Options • Newest models used by

default • Easily customise droplet

size, formation rate, and aggregation type

• Multiple pressure dropmodels

• Simulation step sizegoverns convergence time

HyFAST: A User-Friendly Hydrate Tool

Transport Properties • Populated with example

values • Constant heat transfer to

environment • 0-30 mol% CH4, C2H6

• Constant pressure withSRK equation of state (e.g. gas accumulator)

Version 1.0: Single Control Volume!

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Fluid Packet (Control Vol.)

Designed for recirculating flowloop • Simulates evolution of single control volume• Validated against oil-dominant experiments

Further expansion underway • Expansion to single-pass geometry

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Version 1.0: Single Control Volume

Model Considers Dynamic Aggregation!

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1! Droplet Size!

2! Surface Area!

3! Formation Kinetics!

4! Mass Balance!

5! Dynamic Force!

6! Aggregate Size!

7! Relative Viscosity!

8! Pressure Drop!

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1! Droplet Size!

2! Surface Area!


4! Mass Balance!

5! Dynamic Force!

6! Aggregate Size!


8! Pressure Drop!


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1! Droplet Size!

2! Surface Area!


4! Mass Balance!

5! Dynamic Force!

6! Aggregate Size!


8! Pressure Drop!


FLOWLOOP VALIDATION!

HyFAST 1!

HyFAST Compared to Flowloop!

24 flowloop experiments: pressure drop and (estimated) hydrate volume fraction

Experimental variables • Hydrocarbon phase (crude oil, condensate) • Liquid loading (50-90 vol%) • Water cut (15-90 vol% of liquid phase) • Mixture velocity (1-3.5 m/s)

Goal: identify successes and limitations • HyFAST engine is well-characterised, so points of

disagreement may point to new contributions!

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Condensate + Methane + Water (75 vol% LL, 15 vol% WC, 1.75 m/s)!

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0 20 40 60 80 100 120 140

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0

2

4

6

8

10

12

14

16

Time After Nucleation (min.)

Pres

sure

Dro

p I

ncr

ease

(p

si)

Experiment

HyFAST v1.2

HyFAST Predictions Within 5 psid Below 75 vol% Watercut!

15 Complex Flow Regimes

Sepa

rate

Wat

er P

hase



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Way Forward

Validation for HyFAST 1 • Oil-dominant systems • Limited in water-cut and liquid velocity • Built for closed systems (flowloop, autoclave)

Screening Tool for Hydrate Formation • Lacks comprehensive hydrodynamics • Intended for quick hydrate calculations

HYFAST 2.0 PREVIEW Bruce Norris



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Introduction: Bruce Norris

Final year student finishing at the end of 2013.

Studying a BE/BSc in Chemical Engineering and Physics.

Working as a research assistant at UWA over the summer.

Intend to pursue graduate studies

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HyFAST 2 Preview – Due March 2014

Additional Functionality • Naturally integrated compositional tracking• Expanded to assess flowline geometry• First step toward quantifiable risk assessment

Intended Uses • Screening tool to support OLGA / Leda simulation• Education for engineers in training

International Collaboration • Colorado School of Mines

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Updates Focused to Relax Modelling Assumptions Thermodynamic Update • Hydrocarbons are consumed and flashed• Tracking phase composition is necessary

Geometric Update • Simplified fluid transport model• Retain fast solutions (5 seconds)

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Example Case Flowline Geometry

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Wellhead Conditions • Pressure: 3000 psi• Temperature: 104 °F • Liquid Loading: 70% • Water Cut: 70%

• Ambient Temperature: 39 °F • Line Length: 27 km • Line Diameter: 4 in



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Dynamic Viscosity Predictions

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Risk Profile Changes with Watercut

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Turning point due to shear increase

Sev

erity

of p

lug

form

atio

n



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AAs Reduce Slurry Viscosity

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Sev

erity

of p

lug

form

atio

n

Uninhibited

Anti-Agglomerant

25/11/2013

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First Step Toward Quantitative Risk Assessment

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Quantitative •  Experimental data on

nucleation probability

•  Link risk (viscosity) through system subcooling

*May et al., Chem. Eng. Sci., 2013

Qualitative

•  High risk: µrel > 100

•  Low risk: µrel < 10 *Zerpa et al., OTC, 2011 0

30

60

90

0 5 10 15 20

Rel

ativ

e Vi

scos

ity

sub-cooling [K]

High Risk

Low Risk

Viscosity Profile



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0"

20"

40"

60"

80"

100"

120"

0" 20" 40" 60" 80" 100"

Peak%Rela(

ve%Viscosity%

Cumula(ve%Probability%of%Observa(on%

High Risk

Low Risk

Risk Profile

First Step Toward Quantitative Risk Assessment



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Example: Liquid Loading Substantially Affects Risk Profile

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0"

20"

40"

60"

80"

100"

120"

0" 20" 40" 60" 80" 100"

Rela(v

e%Viscosity

%

Cumula(ve%Probability%of%Observa(on%

90% Liquid Loading

45% Liquid Loading

70% Liquid Loading



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HyFAST 2: A New Screening Tool

Expanding to flowline geometry • Including oil- and water-dominant models• Integrated compositional tracking• Rapid screening to identify critical casesExploration Tool • Most advanced hydrate models• Fast calculationsLimitations • Additional validation with flowloop data required• Poor performance in high water-cut cases• Tool lacks validated hydrodynamic engine

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Flow Assurance Workshop - fsr.ecm.uwa.edu.au · PDF fileGas Processing 1 - Flow Assurance and...

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