Minwei_1_AA in a Full Watercut Range

An effective Hydrate Anti-agglomerant at Full Range of Watercuts

May 14-15 2012 RERI Annual Workshop Reservoir Engineering Research Institute

Minwei Sun

Gas hydrates

2

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)

Sub-cooling and hydrate inhibitors

3

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)

Offshore crude oil production

4

offshore-technology

Gulf of Mexico, 1984-2009

Source: US Energy Information Administration

Shallow < 1000 ft

Deep 1000~4999 ft

High pressure (150 bar), low temperature (~4 C)

BY WEIGHT: ~20% Methane

60,000 barrels/day

5

Deepwater Horizon oil spill, 2010

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

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

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)

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

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

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

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

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)