Overview of Gas Displacement EOR

Mark Holtz RECS 2012 7 June 2012

Overview of Gas Displacement Enhanced Oil Recovery

Praxair At A Glance

TEXAS LOUISIANA

Hydrogen

Air Separation Plants

NitrogenOxygen

Industrial Area

GALVESTONBAY

GULF OFMEXICO

BAYTOWN

MONTBELVIEU

CHANNELVIEW

LAPORTE

HOUSTON

GALVESTONTEXAS CITY

PORTARTHUR

PASADENADEERPARK

BAYPORT

SULPHUR

LAKECHARLES

NEDERLAND

SABINELAKE

NEWORLEANS

GEISMAR

BATON ROUGE

245 miles of pipeline serving50 major customers

BEAUMONT

Praxair’s 600 MMCFD H2 System Capacity

Packaged Gases Liquid Supply

Pipline

Onsite

Upstream Oil and Gas Business

l Enhanced Oil Recovery – Over 30 years experience with Gas

Displacement Recovery (GDR) l Nitrogen l Carbon Dioxide

– More than 25 projects

l Well Stimulation Services

l CO2/N2 EOR Services –  Pilots and huff-n-puffs

l CO2 Capture & Purification Exxon Hawkins Field, Injects 80 MMscf/d of N2 at 2,000 psi

Outline

1.  The Petrophysics of Residual Saturation 2.  General Applications of Gas

Displacement Recovery (GDR) 3.  CO2 EOR Pilot Approach

Rock-Fluid Property Models

•  Wettability •  End point fluid characteristics

–  Residual oil and gas saturation –  End point water saturations

•  Oil-water relative permeability •  Oil-gas relative permeability •  Gas-water relative permeability •  Capillary pressure character

Wettability

•  Is defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids.

Wettability Contact Angle

•  Water wet

Grain surface

Water

Oil

•  Oil wet

Water

αc αc

Pore-Scale Trapping results in residual saturation.

Wetting phase

Nonwetting phase trapped

Wettability Effects on Water Displacing Oil

Time and water encroachment increasing

Water Water Water

Oil Oil Oil

Water wet system

Wettability Effects on Water Displacing Oil

Water Water Water

Oil Oil

Oil

Time and water encroachment increasing

Oil Wet System

Wettability and Relative Permeability R

elat

ive

perm

eabi

lity

(%)

Water saturation (%)

100

80

60

40

20

0 0 20 40 60 80 100

Water

Water

Oil Wet Water Wet

Oil

Oil

48

40

32

Capillary Pressure Curves: Water-Wet and Oil-Wet

24

16

8

0 0 20 40 60 80 100

Water Saturation, %

Cap

illar

y Pr

essu

re, c

m o

f Hg

2 1

48

40

32

24

16

8

0 0 20 40 60 80 100

Water Saturation, % C

apill

ary

Pres

sure

, cm

of H

g

Water-wet Rock (Vernango Core)

After Killins et al. 1953, Dullien 1992

Oil-wet Rock (Tensleep sandstone)

2

1

Residual Saturation as a Function of Porosity

y = -0.3136Ln(x) - 0.1334 R 2 = 0.8536

0

0.2

0.4

0.6

0.8

1

0 0.1 0.2 0.3 0.4 0.5 0.6 Porosity (fraction)

Res

idua

l Non

wet

ting

phas

e sa

tura

tion

(frac

tion)

Gas Residual saturation to water (fraction) Frio Barrier bar Log. (Gas Residual saturation to water (fraction)) Poly. (Gas Residual saturation to water (fraction)) Log. (Gas Residual saturation to water (fraction))

N = 143

Gas Displacement Recovery Reserve Growth Applications

•  Pressure Maintenance –  Oil reservoirs –  Pressure maintenance condensate and retrograde

condensate reservoirs •  Miscible Displacement •  Immiscible Displacement

Ø Patterns Ø Huff n Puff

•  Mixed gas Applications Ø Driving agent for slug/buffer Ø Mixed gases for density control

•  Gas Assisted Gravity Drainage

Gas Cap Injection

l Mechanisms –  CO2/N2 displacing

methane –  Pressure

maintenance for the oil saturated zone.

Oil

CH4 CO2/N2

Prax

air

Generalized Retrograde Condensate-Gas Phase Diagram

Pres

sure

Cric

onde

nthe

rm

Temperature Reservoir Temperature

Modified from McCain (1973)

Gas

Liquid

Dew point pressure

100

75

50

25

10

0

Pressure depletion

Initial conditions

Surface conditions

Gas Condensate Pressure Maintenance

l  Pressure depletion causes; –  Reduction in gas permeability and well productivity –  Lower ultimate hydrocarbon recovery 10 to 40 % –  Aquifer encroachment

l  Screening criteria: 1)   Dew point pressure is near the original reservoir pressure, under

saturated by 150 to 300 psi,

2) High condensate yield of 175 bbl/MMSCF produced, 3) High liquid dropout rate with liquid condensation from 20 to 40 %

of the hydrocarbon pore space.

Solvent EOR

5 to 15 % Stability override

Reduces oil viscosity, swells oil, Miscible displacement

Miscible

10 MCF/STB oil produced

5 to 15 % Stability override

Reduces oil viscosity, swells oil

Immiscible

Typical utilization

Typical recovery (%OOIP) Issues

Recovery mechanism Process

Modified From Taber & Martin, 1983

6 MCF/STB oil produced

CO2 Minimum Misciility Pressure

50

55

60

65

70

75

80

85

90

95

100

1000 1100 1200 1300 1400 1500 1600 1700 1800

Test Pressure, psia

% R

ecov

ery

at 1

.2 H

CPV

of C

O2

Inje

cted

CO2 Thermodynamic MMP

Minimum Miscibility Pressure Estimation

Estimated MMP

CO2 Miscibility Displacement

l Results in high pore level displacement efficiency.

l Miscibility types including;

–  First-contact miscibility –  Multi-contact miscibility

l Currently applied as; –  WAG –  Continuous injection

Producer Injector

Prax

air

Oil CO2 Miscible front

The formation of a single phase diminishes the capillary forces

Immiscible Floods and Pilots

•  Dodan Field, Turkey, Turkish Pet., •  9- 15 API, 300 -1000 cp •  60 MMSCF/D ( 1998 production) •  Carbonate reservoir, at 1,500 m (4,900 ft) depth

•  Lick Creek Field •  17 API, 160 cp •  Ss, Arkansas, after 5 years CO2 injection = 14.1 BSCF & 1 MMSTB oil

produced. •  Willmington Field pilots

•  Fault block 3 tar zone •  Fault Block 5, 14 API, 180-410 CP demonstrated incremental tertiary oil recovery

•  Ritchie Field •  16 API, 195 cp •  Arkansas, CO2 utilization 6.0 Mscf/STB,

•  Huntington Beach Field •  14 API, 177 cp oil

EOR Huff-n-Puff

N2 as Driving Agent for slug/buffer (chase gas)

St Elaine Pilot Gravity stable N2 after CO2

84.4 metric tons/D CO2 injected or 1/3 Pore volume

9 month pilot

N2 slug after CO2 , CH4 & n-butane mixture

From Palmer et al., 1984,

31

N2 injection rate; 136.1 metric tons/day (2.62 MMSCF/day

Critical velocity: 2.2 ft/d

CO2 front velocity designed at 1.6 ft/d or 70% of critical

0 300 600

N

CO2 Injection Well Producer

8,000

7,800

7,600

7,400

GW

C 7,514

Structure Map 8,000 ft sand

Gravity Drainage Double Displacement Process l The process of gas

displacement of a water invaded oil column has been termed Double Displacement Process (DDP). – The DDP consists of

injecting gas up-dip and producing oil down-dip.

– DDP is efficient gravity drainage of oil with high gas saturation.

– Oil displaces water and gas displaces oil downstructure.

N2 injector Producer

Gravity Drainage Double Displacement Process (DDP)

l Up dip gas injection into a dipping reservoir is one of the most efficient recovery methods.

– Recovery efficiencies of 85 % to 95 %

l Increases sweep efficiency l SoDDP decrease of 35% ( Hawkins field)

l Increases displacement efficiency – Oil film flow is an important recovery mechanism

l  Film flow connects the isolated blobs of residual oil in the presence of gas

– Strong water wet – Positive spreading coefficient

Modified from Ren et al., 2000)

Gravity Drainage - General Design

l Obtain piston (no gas fingering) like displacement – Horizontal gas-oil contact – Have gravity dominate the gas flow

l Optimize the time between gas injection and oil production. – As fast as possible without gas fingering

l The greater the dip angle the higher the injection & production rates w/o gas fingering

– The greater the dip the more effective the gravity drainage

Gravity Drainage - General Design

l Critical velocity analytical model

l Simulation model dependent on 3 Phase relative permeability

–  Effected by film flow –  Effected by saturation history –  Typically from 2 phase correlations –  Depend on the direction of flow (i.e.,

be directionally anisotropic)

Vc is critical velocity rate (ft/day) Δρ is density difference k is permeability (darcies) θ is dip angle φ  is porosity (fraction) Δµ is viscosity difference

µφθρ

Δ

Δ=

sin741.2 kVc

Where

(Hill 1952)

Praxair GDR Pilot Approach

•  Key is proper planning –  Determine goals, objectives, and strategy

•  Important tasks include: 1)  Initial reservoir characterization

•  Test interwell connectivity (Interference tests) §  Identifying reserve growth method

2)  Monitoring program design 3)  Facilities design 4)  Proper implementation 5)  Postmortem evaluation

CO2 EOR Pumping Setup

Heater

Manifold

Pump

Control house

Typical CO2 Injection P-T Profile

Tanker

Wellhead Reservoir

MASDAR/ADCO CO2 Pilot

•  Pilot characterizes oil reservoir capacity to store CO2 and impact on EOR.

•  Started in November 2009 •  Continuous 60 TPD injection rate

@ up to 2700 psi •  Praxair employees operate site

24X7 •  2 yr duration •  Multiple CO2 Sources

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Conclusions l Future reserve additions in large light oil, mature fields will

primarily come from GDR. l Reserve additions will occur through:

– Pressure maintenance – Miscible displacement – Immiscible displacement – Mixed gas Applications – Gravity drainage

l GDR typically increases both sweep and displacement efficiency in oil and gas reservoirs.

l Reserve growth targets can range from 10 to 45 % of OOIP/OGIP

Seeper Trace

•  Detection Equipment •  Field Analysis Laboratory

• Leak Monitoring with Perfluorocarbon Tracers

Questions Tracers Can Answer

•  Identify Leaks – Abandoned wells – Well casings – Geologic features

•  Positively identify the injected gas •  Transport times and pathways •  Communication between strata

Overview of Gas Displacement EOR

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