Study of Novel Alkalis for Chemical

Enhanced Oil Recovery

Himanshu Sharma

Dr. Kishore Mohanty

Research Showcase in Petroleum and Geosystems

Engineering

September 8, 2015

Research Showcase Sponsored by

Introduction: Why EOR?

• More than 50% of OOIP is left unrecovered after secondary floods

(Austad et al., 1998) due to

Low macroscopic sweep efficiency due to reservoir

heterogeneity (layering, fractures, vuggs) and viscous fingering

Low microscopic efficiency due to capillary forces

Research Showcase Sponsored by

Chemical EOR

• Involves addition of chemicals to modify fluid or interfacial

properties

Alkali: Generates in-situ soap (with acidic oils) and reduces

surfactant adsorption

Surfactants: Improves microscopic sweep efficiency by

reducing interfacial tension between oil and water

Polymers: Improves macroscopic sweep efficiency by

increasing water viscosity

Challenges for Chemical EOR• Surfactants:

Stability at high temperature/salinity/hardness: New anionic

surfactants developed at UT perform well at these conditions

(SPE 154261-PA, SPE-154256-MS) Handling produced fluids

• Polymers:

Some success at high temperature/salinity/hardness

• Alkalis:

Conventional alkalis cannot be used in presence of gypsum

Limited knowledge of geochemical interactions of alkalis,

especially in carbonate reservoir, and their effect of ASP floods

• Reservoir uncertainty

Limitations of conventional alkalis

• Conventional alkalis: Na2CO3

High reactivity towards gypsum, a common reservoir mineral (example: Wyoming, West Texas, Middle east)

Permeability damage, pH propagation delay

• We studied:

Sodium metaborate and Ammonia

Alkali-rock interactions under equilibrium conditions

Effect of geochemistry on ASP floods

• Sodium metaborate study: SPE-170825-MS

Ammonia

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• Gas but very soluble in water

• Dissociates very little (1% of the amount added)

• pH of samples ~ 11 (pKa=9.25)

• Low molecular weight (0.5 wt% NH3 is equivalent to 3 wt%

Na2CO3)

• Nelson (1984), Martin (1985), Southwick (2014), Sharma

(2014)

3 2 4NH H O NH OH

Ammonia experiments

• Alkali transport experiments

Cores with gypsum: Sandstone and carbonate

• Surfactant phase behavior experiments

• Surfactant adsorption

Berea and Bandera brown sandstone

Cores with gypsum

• Oil Recovery experiments

Berea sandstone

Cores with gypsum

• Ammonia with acidic crude oil oils and hard brines

• Geochemical modeling in UTCHEM

Alkali transport: Na2CO3

• Carbonate core containing gypsum (CaSO4.2H2O)

• CaCO3 precipitation

inside the core

• Core plugging

observed

• pH propagation

delays observed0

50

100

150

200

250

300

0 1 2 3

Effl

ue

nt

con

c (m

M)

Pore volumes injected

Effluent

calcium

Effluent

sulfate

Alkali transport: Ammonia

• Carbonate core containing gypsum (CaSO4.2H2O)

• Moles Ca=Moles SO4:

No precipitation inside

the core

• pH at 1 PV=9.5

0

10

20

30

40

50

60

70

0 0.3 0.6 0.9 1.2 1.5 1.8

Eff

luen

t co

nc.(

mM

)

Pore volume injected

Effluent

calcium

Effluent

sulfate

Formation

brine: 8% NaCl

Injection brine: 0.3%

NH3 + 1% NaCl

Surfactant phase behavior

• Ammonia fixed to 0.5 wt%

• Surfactants: C28-25PO-45EO-

carboxylate; C15-18-IOS; C19-23-IOS

• Solubilization at optimum>10

• Ultralow IFT in presence of up to

1,000 ppm Ca

• Optimal salinity decreases by

10,000 ppm on addition of 1,000

ppm calcium ions

• Aqueous stable even in presence

of calcium ions

0

10

20

30

55000 65000 75000 85000

Solu

bili

zation R

atio (

cc/c

c)

NaCl (ppm)

Aqueous Limit > 90,000 ppm TDS

Temp= 59 ⁰C

Oil= 30%

σ*=12.5

Oil Water

Oil recovery in Berea Sandstone

• 0.9 wt% NH3

• 1.5 inch x 1 ft Berea

sandstone (no gypsum)

• Temperature = 59 ºC

• Recovery: 81% ROIP

• pH (1.0 PV): 10.5

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0.00 0.50 1.00 1.50 2.00Tert

iary

Reco

very

/ O

il C

ut/

Resid

ual

Oil s

atu

rati

on

PV Injected

Oil cut Tertiary recovery Sorc

Cum Oil

Oil cut

Sor

Formation Brine

Initially in the core0.4 PV ASP

1.5 PV Polymer drive 1

Oil recovery results: Carbonate with gypsum

• 0.5 wt% NH3

• Recovery: 81% ROIP

• Maximum oil cut: 40%

• Oil saturation reduced from 29% to 5.5%

• pH (1.0 PV)~ 10

• Surfactant retention: 0.24 mg/g

Formation Brine

Initially in the core0.4 PV ASP

0.5 PV Polymer drive 1

1.2 PV Polymer drive 2

0

1

2

3

4

5

6

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

0.0 0.5 1.0 1.5 2.0

Pre

ssu

re d

rop

(p

si)

Oil r

eco

very

/Oil c

ut/

Resid

ual

oil

satu

rati

on

Pore volumes injected

Tertiary recovery

Oil cutSor

Pressure drop

Ammonia with acidic crude oils

• Ammonia reacts with acidic to form soap

• Gives ultralow IFT formulations with sufficiently active oils

Conclusion

• Studied ammonia for chemical EOR

• Observed no calcium precipitation with ammonia in presence of gypsum

• Observed high pH propagation and good oil recovery in Berea sandstone and cores with gypsum

• Performed surfactant adsorption study with ammonia

• Ammonia gave low IFT formulations with sufficiently acidic oil similar to sodium carbonate

Acknowledgement

Research Showcase Sponsored by

• CPGE research showcase sponsors

• Chemical EOR JIP

• Dr. Pope, Dr. Upali and Dr. Sepehrnoori

• Chemical EOR research group at UT