potential production enhancement methods in the bakken...

Copyright @ SRC 2015

Potential Production Enhancement Methods in the Bakken: Gas Utilization and Water Injection

Presented by Mars Luo Saskatchewan Research Council March 12, 2015

Tight Oil Optimization Conference


Outline • SRC at a glance • Tight oil reservoir characteristics • Challenges for tight oil development • Prospective EOR solutions • Conclusions

2


SRC Overview • Saskatchewan’s leading provider of

applied RD&D and technology commercialization

• Over 350 employees • $68 million in annual revenue • 68 years of RD&D experience • 2,000 clients around the world • Providing leading edge oil and gas

technologies to clients • Team of expert engineers, scientists, and

technologists

3


Research & Innovation • Advancing enhanced oil recovery

(EOR) in the WCSB • State of the art labs with custom-

designed and custom-built models – SAGD, SVX techniques

• Expertise in: – Thermal EOR – Post-cold-production EOR – Chemical waterflooding – Miscible/immiscible gas (CO2) injection – Microbial EOR – In-situ combustion – Original hybrid EOR systems such as

solvent/thermal and chemical/CO2

4


Tight Oil Reservoir Characteristics

Source: Canadian Society of Unconventional Resources Source: JuneWarren-Nickle’s Energy Group

5


Tight Oil Plays in Western Canada

6

Source: ERCB


Southeast Saskatchewan Bakken Oil Production and Producing Well Count

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Source: Saskatchewan Ministry of Economy

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

55,000

60,000

65,000

70,000

75,000

Jan-

04Ap

r-04

Jul-0

4O

ct-0

4Ja

n-05

Apr-

05Ju

l-05

Oct

-05

Jan-

06Ap

r-06

Jul-0

6O

ct-0

6Ja

n-07

Apr-

07Ju

l-07

Oct

-07

Jan-

08Ap

r-08

Jul-0

8O

ct-0

8Ja

n-09

Apr-

09Ju

l-09

Oct

-09

Jan-

10Ap

r-10

Jul-1

0O

ct-1

0Ja

n-11

Apr-

11Ju

l-11

Oct

-11

Jan-

12Ap

r-12

Jul-1

2O

ct-1

2Ja

n-13

Apr-

13Ju

l-13

Oct

-13

Jan-

14Ap

r-14

Jul-1

4O

ct-1

4

Wel

l Cou

nt

Oil

Prod

uctio

n (b

arre

ls p

er d

ay)

Oil Production (barrels per day)

Producing Well Count


8

Source: Saskatchewan Ministry of Economy

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

300

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan-

04Ap

r-04

Jul-0

4O

ct-0

4Ja

n-05

Apr-

05Ju

l-05

Oct

-05

Jan-

06Ap

r-06

Jul-0

6O

ct-0

6Ja

n-07

Apr-

07Ju

l-07

Oct

-07

Jan-

08Ap

r-08

Jul-0

8O

ct-0

8Ja

n-09

Apr-

09Ju

l-09

Oct

-09

Jan-

10Ap

r-10

Jul-1

0O

ct-1

0Ja

n-11

Apr-

11Ju

l-11

Oct

-11

Jan-

12Ap

r-12

Jul-1

2O

ct-1

2Ja

n-13

Apr-

13Ju

l-13

Oct

-13

Jan-

14Ap

r-14

Jul-1

4O

ct-1

4

Wel

l Cou

nt

Oil

Prod

uctio

n (b

arre

ls p

er d

ay)

Oil Production (barrels per day)

Producing Well Count

Southeast Saskatchewan Bakken-Torquay Oil Production and Producing Well Count


Challenges in Developing Bakken • Low permeability • Low porosity • Harsh reservoir conditions • Complex geology • Formation damage

“I think the bigger bang for our buck right now is in waterflooding to see if this pool can be waterflooded or CO2 flooded and those kinds of things.”

— Scott Saxberg, President and CEO, Crescent Point

Typical Bakken well production profile

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Bakken EOR Strategy Sharp depletion during

primary recovery What’s next?

CO2

Gas Flooding

flue gas produced gas

natural gas

formation brine

modified brine

surfactant

Water Flooding Thermal?

10


Live Oil–Injection Gas Phase Behaviour

11

Saturation Pressure (MPa)10 15 20 25

Visc

osity

(mPa

⋅s)

0.0

0.2

0.4

0.6

0.8

1.0

Live oil-flue gasLive oil-CO2Live oil-natural gasLive oil-N2Live oil-enriched natural gas


Den

sity

(kg/

m3 )

640

660

680

700

720

740

Live oil-flue gasLive oil-CO2Live oil-natural gasLive oil-N2Live oil-enriched natural gas


Gas

/Oil

Rat

io (s

m3 /s

m3 )

100

200

300

400

500

Live oil-flue gasLive oil-CO2

Live oil-natural gasLive oil-N2

Live oil-enriched natural gas


Form

atio

n Vo

lum

e Fa

ctor

(m3 /s

m3 )

1.0

1.5

2.0

2.5

Live oil-flue gasLive oil-CO2

Live oil-natural gasLive oil-N2

Live oil-enriched natural gas

CO2 causes much higher viscosity reduction and oil swelling than other gases!


Minimum Miscibility Pressure ─ Rising Bubble Test

CO2 MMP = 13.6 MPa Flue Gas MMP > 30 MPa

12


13

PV Injected

0 2 4 6 8 10

Rec

over

y Fa

ctor

(%O

OIP

)

0

20

40

60

80

100

Pre

ssur

e D

iffer

ence

(kP

a)

0

500

1000

1500

2000

2500

IWFCO2 floodingEWFdP

Primary: 5.9% of OOIP

IWF: 37.8%

CO2: 41.9% EWF: 0.8%

Primary Recovery: 5.9% of OOIP

PV Injected

0 5 10 15 20 25

Rec

over

y Fa

ctor

(%O

OIP

)

0

20

40

60

80

100

Pre

ssur

e D

iffer

ence

(kP

a)

0

4000

8000

12000

16000

20000

IWFFlue gas floodingEWFdP

Primary Recovery: 24.9% of OOIP


IWF: 42.4%

Flue gas: 12.4%

EWF: 3.2%

PV Injected

0 2 4 6 8 10 12

Rec

over

y Fa

ctor

(%O

OIP

)

0

20

40

60

80

100

Pre

ssur

e D

iffer

ence

(kP

a)

0

3000

6000

9000

12000

15000

IWFNatural gas floodingEWFdP



Natural Gas Flooding

IWF: 31.6%

PV Injected

0 5 10 15 20

Rec

over

y Fa

ctor

(%O

OIP

)

0

20

40

60

80

100

Pre

ssur

e D

iffer

ence

(kP

a)

0

2000

4000

6000

8000

10000

IWFN2 floodingEWFdP

Flue Gas Flooding CO2 Flooding

Nitrogen Flooding

Coreflood Test Pressure depletion IWF gas flood EWF


IWF: 30.0% N2: 3.0%

EWF: 5.6%

EWF: 0.0%

Natural gas: 12.4%


Geochemistry of CO2 Flooding

Saturation of Bakken core plugs with carbonated brine @ 20 MPa and 88°C for two weeks.

Before After

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Saturation of Bakken core plugs with carbonated brine @ 20 MPa and 88°C for four months.

Before After

15

Permeability increase from carbonate dissolution can be offset by decrease due to clay/grain migration.


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Produced calcium carbonates

X. Wang et al. Ind. Eng. Chem. Res., 2011, 50 (4)

CO2 reaction with brine

Coating Clay

S.G. Sayegh et al. SPE Formation Evaluation, 1990, 12

Before CO2 flood

After CO2 flood

CO2 reaction with rock Crystal Calcite



Why Chemical EOR? Lower facility and operation cost than gas flooding

Increase capillary number: Target residual oil trapped in pores

Reduce interfacial tension between residual oil and brine by possibly up to three orders of magnitude

Alter wettability to improve injectivity

2 cm3/hr brine injection into a core stack that is 31.35 (L)×3.84 (D) cm. Pressure drop reaches 3 MPa!

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Oil─Brine─Surfactant─Rock Interactions

Oil

Formation Brine Rock

Surfactant

IFT reduction alone is not enough!

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Surfactant Screening

Phase Behaviour

Surfactant Adsorption

Time (min)

0 10 20 30 40 50 60

Con

tact

Ang

le (o )

0

10

20

30

40

50

60

70

80

90Dead oil on slideDead oil on surfactant soaked slideLive oil on slideLive oil on surfactant soaked slide

Wettability Alteration

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Source: Oil Chem Technologies


High P&T Contact Angle and IFT Meter

Interfacial Phenomenon θ

θ

θ = 148°θ = 156°

Advanced Spinning Drop Tensiometer

Contact angle measurement for a light oil on rock slide

20

Bakken oil in 0.05 wt% SuperSurfTM 406 brine solution, spinning drop IFT meter rotating at 5000 RPM.


Coreflood Test ─ Recovery or Injectivity?

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• Lower interfacial tension between water and oil, recover more oil than waterflood.

• Change the rock wettability to more water-wet, thus change the capillary pressure and relative permeability.

Fluid Injected (PV)0 1 2 3 4 5 6 7 8 9 10 11 12

Pre

ssu

re D

rop

(kP

a)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Cu

mu

lativ

e o

il R

eco

very

(%

OO

IP)

0

5

10

15

20

25

30

35

40

45

50

Pressure drop IWF1st surfactant 1st EWF2nd surfactant2nd EWF


Recovery Mechanisms for Surfactant Flooding

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• Imbibition vs Drainage

• Conventional vs Tight

• Waterflood vs Surfactant


Field-Scale EOR Simulation Model Model Properties

Avg. Permeability 1 mD Avg. Porosity 0.13 Oil Gravity 40 oAPI Estimated OOIP 6.2 MMbbl Injector Num. 4 HZ Producer Num. 4 HZ

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24

2015-01-01 2020-01-01 2025-01-01 2030-01-010

20

40

60

80

100

120

140

160WaterfloodSurfactant floodImmiscible gas floodMiscible gas flood

2011-01-01 2033-01-01

Time (Date)

Oil R

ate S

C (m

3 /D)

IOR Start Point

IMGF≈22 bbl/D

SF≈125 bbl/D

MGF≈250 bbl/D

WF≈80 bbl/D

Oil Recovery Performance Prediction 20 Year Predication of Water or Gas Injection

Scenario Oil RF (%)

Water Flooding 14 Surfactant Flooding 19

Gas Immiscible Flooding 10 Gas Miscible Flooding 35


Conclusions Knowledge of reservoir geology, mineraology, facies distribution,

lithologic variations is important when considering EOR methods for Bakken.

Miscible gas flooding can significantly enhance oil recovery from tight formations.

Immiscible gas flooding can lead to higher oil production rate at the beginning of injection process but ultimately recovers less oil than water flooding.

Reservoir permeability and porosity can be enhanced by mineral dissolution/leaching, but also reduced due to mobile fines and metal carbonate precipitation during CO2 flooding.

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Conclusions (cont’d)

Water flooding can improve the oil recovery from tight formations but may be accompanied by injectivity problems.

Understanding of complex interactions between rock, brine, surfactant, and oil is key to surfactant flooding.

Surfactant flooding recovers oil through interfacial tension reduction and wettability alteration.

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Mars Luo, Manager, EOR Processes Phone: 306-787-5652 Email: [email protected]

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