Effects of Salinity and Salt Species on Hydrate Anti-Agglomeration in

Gas/Oil/Brine Systems

Reservoir Engineering Research Institute

Minwei Sun Abbas Firoozabadi

Nov 5th 2013, AICHE Annual Meeting

A research and educational organization, founded in 1990.

Located in Palo Alto (CA), and a laboratory in Mountain View (CA)

Evolved as a world leader in the areas of

Thermodynamics of hydrocarbon reservoirs and production

Gas injection processes

Fractured and layered reservoirs

Flow assurance

gas hydrate and wax

17 member companies

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About RERI (Reservoir Engineering Research Institute)

Offshore crude oil production

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Source: US Energy Information Administration 2011

Shallow < 1000 ft

Deep 1000~4999 ft

Flowlines in deepwater Oil capture in deepwater

Crud

e Pr

oduc

tion

Mill

ion

barr

el /

yea

r

Sub-cooling and hydrate inhibitors

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Also low dosage (< 1 wt%)

Form slurry instead of plug

Effective at high sub-coolings

Methane hydrate When operating @ 4 ºC

Pressure Sub-cooling

50 bar 11 ºC

100 bar 16 ºC

150 bar 18 ºC

200 bar 20 ºC

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 ºC)

Anti-agglomerants (AAs)

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Anti-agglomeration

Anti-agglomerant (AA)

Hydrate particles are formed from water-in-oil emulsions

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Previous work (Sun and Firoozabadi, JCIS, 2013)

Aqueous phase

Hydrate formation

Hydrate High P, low T

Aqueous phase

Nonionic AA effective over entire watercut range No water-in-oil emulsions @ 100% watercut

– Investigation of the effectiveness of our AA in brines

of different salt species and concentrations.

– Understanding of key mechanisms.

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Objectives

Thermodynamic bulk effect (inhibition similar to alcohols).

Salts affect the adsorption of surfactant molecules onto the hydrate particle surface.

Ionic surfactants (generally enhance adsorption)

Nonionic surfactant (unclear)

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Salt effects

• Methane hydrates – NaCl brine

– KCl brine

– Foaming and solution

• Sizing measurement – In an autoclave setup by FBRM

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Outline

• Instrument: – Rocking sapphire cells, pressure to 200 bar

• Surfactants: – A special AA (Sun and Firoozabadi, JCIS, 2013)

• Systems: – 10 ml liquid + 10 ml gas in sapphire cells, closed system

– Methane/n-octane/brine

– Natural gas/n-octane/water or brine

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Methane hydrate tests in model oil

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Setup – RCS-2

Bath temperature, cell pressure and ball running time are recorded. Effectiveness is determined by visual observation and ball running time.

Temp:

1~30 ºC

Pressure:

up to 200 bar

Cooling rate:

up to 22 ºC

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Effective dosage in freshwater & brine Watercut Effective AA dosage (wt%)

in freshwater

Effective AA dosage (wt%) in

4.0wt% NaCl brine

20% 0.2 0.4

30% 0.2 0.4

50% 0.2 0.4

70% 0.2 0.3

80% 0.2 0.3

95% 0.2 0.3

100% 0.2 0.2

Table 1: Effective AA dosage in methane/n-octane/water (and brine) at different cooling rates. Table 1: Effective AA dosage in methane/n-octane/water (and brine) at different cooling rates.

Higher dosage is required in brine, possibly due to the competition of adsorption between ions and surfactant molecules onto the hydrate particles.

Manuscript in preparation

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Effect of salinity (NaCl, 100% watercut)

60

70

80

90

100

110

120

130

140

50 150 250 350 450

Cell

pres

sure

(bar

)

Time (min)

11% NaCl

7% NaCl

4% NaCl

14 vol% Hydrate

21 vol% Hydrate

27 vol% Hydrate

5 ºC 7 ºC 9 ºC

Closed cell, P ~ 135 bar (methane), T from 20 ºC, -4 ºC/hr to 1 ºC, kept @ 1 ºC for 2 hr before ramping to 20 ºC @ rate of 8 ºC/hr, AA 0.2 wt%.

When salinity ≥ 7%, we need only 0.1 wt% AA.

Thermodynamic inhibiting effect

Manuscript in preparation

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Foam Formation In KCl and MgCl2 brines, foam is formed @ 100% watercut! Agglomeration is then observed. A very small amount of oil prevents foaming.

Effect of salinity (KCl)

Hydrate formation in methane/brine systems with 0.5 vol% n-octane. Initial pressure is 125 bar at 20 ºC. The temperature decreases from 20 ºC to 1 ºC at the rate of -4 ºC/hr, then kept at 1 ºC for 4 hours before ramping back to 20 ºC. The concentration of AA in brine is 0.2 wt%.

50

70

90

110

130

0 2 4 6 8 10 12

Cell

Pres

sure

(bar

)

Time (hour)

4% KCl

7% KCl

Thermodynamic inhibiting effect

Similar results in MgCl2. Manuscript in preparation 15

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Effective volume fraction and agglomeration

E. Colombel; P. Gateau; L. Barre; F. Gruy; T. Palermo, Oil & Gas Science and Technology-Revue de l'IFP 2009, 64, (5), 629-636.

Manuscript in preparation

Porous aggregates (180 μm)

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Sizing measurement

Collaboration with Prof Chen & Prof Sun in Chinese University of Petroleum, Beijing

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FBRM (Focus Beam Reflectance Measurement )

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before in freshwater

after in freshwater

before in brine

after in brine

Mean (sqrt weighted, um) 46 48 26 191

Counts <10 um 22650 26448 35513 18902

Counts 10~50 um 5474 8919 9575 5169

Counts 50~150 um 607 383 186 1193

Counts 150~300 um 0.10 3.25 0 262

Chord length distribution

AA concentration: 0.2 wt% Brine: 4 wt% NaCl

Manuscript in preparation

• Our AA is effective in brine systems at concentration as low as 0.1 wt%.

• Salts have two different effects:

– Reduce surfactant adsorption onto hydrate particle surfaces.

– Thermodynamic inhibiting effect.

• In some brines, due to foaming, anti-agglomeration may not realize. A small amount of an oil can avoid foaming.

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Summary of salt effects

Next …

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Develop our anti-agglomeration theory

Molecular simulation

Optimize AA formulation

Perform flow loop tests

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)