minwei_1_aa in a full watercut range
DESCRIPTION
Gas hydrate anti-agglomeration in rocking cellsTRANSCRIPT
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An effective Hydrate Anti-agglomerant at Full Range of Watercuts
May 14-15 2012 RERI Annual Workshop Reservoir Engineering Research Institute
Minwei Sun
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Gas hydrates
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Methane Molecule
Hydrate Crystal
Ice-like crystalline molecular complexes
Form from a mixtures of water and natural gas
Serious problem in most deepwater operations
A large gas hydrate plug formed in a subsea hydrocarbon pipeline. from Petrobras (Brazil)
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Sub-cooling and hydrate inhibitors
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Also low dosage (< 1 wt%)
Form slurry instead of plug
Effective at high sub-cooling
When operating @ 4 C
Pressure Sub-cooling
50 bar 11 C
100 bar 16 C
150 bar 18 C
200 bar 20 C
Thermodynamic inhibitors (THIs)
Large quantity, 10 ~ 60 wt% of water
Kinetic inhibitors (KIs)
Delay hydrate formation or decelerate hydrate growth
Low dosage (~1 wt%)
Ineffective @ high sub-coolings (>10 C)
Anti-agglomerants (AAs)
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Offshore crude oil production
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offshore-technology
Gulf of Mexico, 1984-2009
Source: US Energy Information Administration
Shallow < 1000 ft
Deep 1000~4999 ft
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High pressure (150 bar), low temperature (~4 C)
BY WEIGHT: ~20% Methane
60,000 barrels/day
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Deepwater Horizon oil spill, 2010
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Limitations of current AAs
Effective at low watercuts, but NOT at high watercuts (50%)
Toxicity (especially quaternary ammonium salts)
Cost (dosage ~ 1.0 wt% in water)
Objectives
Effective AA in a wide watercut range Flowlines in deepwater
Oil capture in deepwater
Low toxicity
Low dosage
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Motivations & objectives
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Instrument: New setup purchased from PSL (Germany), two testing rocking cells, up
to 200 bar
Surfactants: A special AA
PVP-10: Polyvinylpyrrolidone with MW ~10000, common kinetic inhibitor
Rh: rhamnolipid, bio-surfactant as AA
2C-75: a quaternary ammonium salt, suggested by Shell
Systems: 10 ml liquid + 10 ml gas in sapphire cells, closed system
Methane/n-octane/water
Methane/n-octane/brine, brine: 4 wt% NaCl
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Methane hydrate tests
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Setup RCS-2
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Setup RCS-2
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Closed cell, P ~150 bar, T from 20 C, -2 C/hr to 1 C, kept @ 1 C for 2 hr before ramping to 20 C @ rate of 4 C/hr Hydrate formation temp: ~13C . Dissociation temp: 12 C. Hydrate fraction ~50%
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Methane/n-octane/water/AA, 50% watercut, 0.2 wt% AA
Ball movement in the cell due to AA effect
Viscosity increase due to high hydrate
content
Hydrate formation
Hydrate dissociation Pressure (bar)
Temp. (C)
Ball running
Time (msec)
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Closed cell, P ~ 150 bar, T from 20 C, -2 C/hr to 1 C, kept @ 1 C for 2 hr before ramping to 20 C @ rate of 4 C/hr apparent plugging. Hydrate fraction ~75%
Methane/n-octane/water/AA, 70% watercut, 0.2 wt% AA
Pressure (bar)
Temp. (C)
Ball running
Time (msec)
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Right picture taken 15 minutes after the left picture by keeping the cell still at 1 C Red circles show the position of stainless steel ball.
No plugging
70 % watercut @ 1 C, kept still
Time = 15 minutes Time = 0
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Closed cell, 50 bar methane, raise P to 160 bar by nitrogen, T from 20 C, -2 C/hr to 1 C, kept @ 1 C for 2 hr before ramping to 20 C @ rate of 4 C/hr. Hydrate fraction: ~63%
Methane/nitrogen/n-octane/water/AA, 70% watercut, 0.2 wt% AA
Pressure (bar)
Temp. (C)
Ball running
Time (msec)
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Closed cells, P ~ 90 bar, T from 20 C, -2 C/hr to 2 C, kept @ 2 C for 2 hr before ramping to 20 C @ rate of 4 C/hr (cell 1, 0.2 wt% AA, cell 2, 0.2 wt% PVP10) Hydrate formation temp: 9 C and 7.2 C. Dissociation temp: 3 C and 10.2 C Hydrate fraction in cell 1: ~70%
Ball movement in the cell due to AA effect
Ball without movement due to plugging
Hydrate formation Hydrate dissociation
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Methane/water/AA, 100% watercut, 0.2 wt% AA
Pressure (bar)
Temp. (C)
Ball running
Time (msec)
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AA in methane/n-octane/water systems
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
20 40 60 80 100
AA
do
sage
(w
t% in
wat
er)
Watercut (%)
Other inhibitors at 50% watercut: PVP-10 1.0 wt%, kinetic inhibition to 7 C subcooling Rh 1.0 wt%, ineffective AA 2C-75 1.0 wt%, ineffective AA
(o) Stable dispersion
(x) Plugging
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Gulf of Mexico, 3.5 wt%
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Salinity distribution in various waters
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AA in methane/n-octane/brine systems
0.1
0.2
0.3
0.4
20 40 60 80 100
AA
do
sage
(w
t% in
wat
er)
Watercut (%)
Brine: 4 wt% NaCl
(o) Stable dispersion
(x) Plugging
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AA 30% watercut
0.2wt% surfactant 50% watercut
0.5wt% surfactant 70% watercut
0.5wt% surfactant
Special AA ---- 52.8 3.7 14.8 1.5
2C-75 155.2 11.0 124.2 13.6 212.7 50.6
Rh 1253.9 88.7 494.3 35.0 385.3 97.8
Emulsion size
Smaller emulsion size Higher effectiveness in AA
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CMC measurement (UV absorption)
Enolic form Stay in micelle Absorption ~ 312 nm
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
300 310 320 330 340 350 360
Ab
sorb
ance
Wavelength (nm)
100ppm
70ppm
50ppm
30ppm
15ppm
10ppm
7.5ppm
5ppm
CMC ~ 10 ppm
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Proposed mechanism
Aqueous phase
2000 ppm CMC
Hydrate formation
Dielectric constant at 273k Water ~ 88 Methane hydrate ~ 58
Aqueous phase
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Our special AA is effective at 0.2 wt% in methane/oil/water systems, outperforming PVP-10, 2C-75 and Rh.
For the hydrate fraction less than 63%, our special AA is effective in the full watercut range. To the best of our knowledge, this is the first time an AA is reported to be effective for a watercut above 50%.
Our special AA is also effective at 0.4 wt% in methane/oil/brine systems at 4 wt% salinity in the full watercut range.
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Conclusions
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Deliverables and future work
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Two reports will be delivered to members this year.
Midterm report in Q1 2012
Full report in Q3 2012
Future work
Improve the understanding of the mechanism
Investigate the effectiveness in crude oil systems
Perform the 24-hour shut-in tests
Perform flow testing
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Acknowledgements
RERI member companies
RERI colleagues
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Reservoir Engineering Research Institute (RERI) Palo Alto, CA, USA
http://www.rerinst.org thermodynamics of hydrocarbon reservoirs and production
gas injection processes fractured and layered reservoirs
flow assurance (asphaltenes and gas hydrates)