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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
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
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Academic & Research Staff
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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
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Funding From …
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Flow Assurance Teaching
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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
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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
UWA Flow Assurance Workshop
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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
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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
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
Curve to guide the eye
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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
UWA Flow Assurance Workshop
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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
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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)
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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%
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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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ar)
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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
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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
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Initial Growth Rate Increased with Turbulence and MEG
0.00
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1,000 3,000 5,000
Initial0Growth0Rate0(m
ol/hr)
Reynolds0Number
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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%
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Re = N•
ρmixtureD2
µmixture
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0 5 10 15
HydrateV
olum
e4Fractio
n4(%
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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
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0 20 40 60
Torque
-(Ncm
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Hydrate-Volume-Fraction-(%)
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10%
15%
NO ɸtransition
10.5 %
18.6 %
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Max(Torqu
e((Ncm
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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
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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)
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Hydrate Film Growth in a Gas-Dominant Flowloop
Mauricio Di Lorenzo 28 November 2013
UWA Flow Assurance Workshop
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Mauricio Di Lorenzo
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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
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Focus on Australian Offshore Gas
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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
5
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
6
(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
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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
13
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
14
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
16
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
18
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
UWA Flow Assurance Workshop
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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
2
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Summary
3
• 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
4
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?
5
Turner et al. (2009) in collaboration with J. Abrahamson
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6
+
+
+
+
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
7
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DSC Thermograms Quantify Power Required for Hydrate Dissociation
8
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
9
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
10
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Experimental Droplet Diameters Approximately 2-10 Microns
11
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
12
25/11/2013'
5'
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Baseline Dispersion Breaks with Repeated Dissociation Cycles
13
• 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
14
0"
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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
15
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!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
16
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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
17
• 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
18
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
19
• 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
21
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!
2
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!
3
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!
7
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
8
Version 1.0: Single Control Volume
Model Considers Dynamic Aggregation!
9
1! Droplet Size!
2! Surface Area!
3! Formation Kinetics!
4! Mass Balance!
5! Dynamic Force!
6! Aggregate Size!
7! Relative Viscosity!
8! Pressure Drop!
10
1! Droplet Size!
2! Surface Area!
3! Formation Kinetics!
4! Mass Balance!
5! Dynamic Force!
6! Aggregate Size!
7! Relative Viscosity!
8! Pressure Drop!
Model Considers Dynamic Aggregation!
11
1! Droplet Size!
2! Surface Area!
3! Formation Kinetics!
4! Mass Balance!
5! Dynamic Force!
6! Aggregate Size!
7! Relative Viscosity!
8! Pressure Drop!
Model Considers Dynamic Aggregation!
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!
13
Condensate + Methane + Water (75 vol% LL, 15 vol% WC, 1.75 m/s)!
14
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
18
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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
19
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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)
20
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Example Case Flowline Geometry
21
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
22
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Risk Profile Changes with Watercut
23
Turning point due to shear increase
Sev
erity
of p
lug
form
atio
n
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AAs Reduce Slurry Viscosity
24
Sev
erity
of p
lug
form
atio
n
Uninhibited
Anti-Agglomerant
25/11/2013
9
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First Step Toward Quantitative Risk Assessment
25
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"
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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
27
0"
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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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