Immiscible Gas Displacement

Recovery

Reserve Growth for

Higher Recovery

Efficiency

Miscibility

• Miscibility reduces the interfacial tension

between gas and oil to zero Modified from zain et al., 2005, SPE # 97613

Miscible - capable of

mixing in any ratio

without separation of

two phases

Slim Tube Test Example

Immiscible CO2 Flooding

Recovery Mechanisms

• Oil Swelling

• Viscosity Reduction

• 3 Phase Flow Oil Mobilization (Kr effects)

– Accelerated oil recovery, higher core flood recovery (Olsen et. al., 1992, Dale & Skauge, 2005)

• Improved Volumetric Sweep Efficiency

Modified from Fernandez and Pascual. 2007 Spe # 108031

Gas Displacement Recovery

Reserve Growth Applications

• Miscible Displacement

• Pressure Maintenance – Pressure maintenance condensate and retrograde

condensate reservoirs

– oil reservoirs

• Gas Assisted Gravity Drainage

• Immiscible Displacement Gas cap gas

Oil reservoir IWAG

• Mixed Gas Applications Driving agent for slug/buffer

Mixed gases for density control

Morrow N2 Pressure Maintenance

Colorado Kansas

Oil Lease Pressure Maintenance

Response

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 20 40 60 80 100 120 140 160

Months

Mo

nth

ly p

rod

uc

tio

n (

ST

B)

Monthly Oil Production (STB)

Monthly Water Production (STB)

N2 System Installed

April 2007 June 2010

Morrow Immsicible Pressure Maintenance

• Simple On site N2 Application

• N2 Pressure Maintenance is Resulting in Reserve

Growth of 385,000 STB

• Over lease life N2/primary production ratio is 0.63

• Extends production over 6 years

Gas Displacement Recovery

Reserve Growth Applications

• Miscible Displacement

• Pressure Maintenance – Pressure maintenance condensate and retrograde

condensate reservoirs

– oil reservoirs

• Gas Assisted Gravity Drainage

• Immiscible Displacement Gas cap gas

Oil reservoir IWAG

• Mixed Gas Applications Driving agent for slug/buffer

Mixed gases for density control

Gravity Drainage Double Displacement Process

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)

Up-dip Gas Injection into a Dipping Reservoir is one of the Most Efficient Recovery Methods.

– Recovery efficiencies of 85 % to 95 %

Increases Sweep Efficiency SoDDP decrease of 35% ( Hawkins field)

Increases Displacement Efficiency

– Oil film flow is an important recovery mechanism

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)

Oil Spreading and Film Flow

• Spreading Coefficient is a Function interfacial tension.

• Positive Spreading Coefficient is a Function of Interfacial Tension Between Fluids

• High Spreading Coefficient and N2 Injection Reduced So by Half.

Gravity Drainage - General Design

Critical velocity analytical model

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)

Dr is density difference

k is permeability (darcies)

q is dip angle

is porosity (fraction)

Dm is viscosity difference

m

qr

D

D

sin741.2 kVc

Where

(Hill 1952)

Hawkins Field Reservoir Characteristics

• Porosity 28 %, Permeability 3,396 md Swi 9.6 %

(Dexter sands)

• Average formation dip 6 degrees

• Oil gravity 12 – 30

• Oil viscosity 2-80 cp, 3.7 cp average

• Boi 1.2225 bbl/STB, Original GOR 370 scf/STB

• Pi = 1,985 psi, Ti 168 F

• DDP Sorg < 10%

Hawkins Field Double Displacement Process

Lawrence et al., 2003

Double Displacement Process Schematic

Tests of Water vs Gas-Liquid Drainage

• Hawkins

Example,

Woodbine

Dexter ss.

Gas Assisted Gravity Drainage

(GAGD) Field Examples • Mauddud Field, Bahrain, GAGD Obtained reserve growth from

25% to 41 % of OOIP “16%” increase (Kantzas et al., 1993)

• Oseberg Field, gas injection w/o water flood

• Coulummes-Vancouriois field, France (Denoyelle et al., 1986)

– N2 after CO2, well in pattern displayed a 4 fold production increase

– 14 Mscf/STB Utilization was recorded

• Alberta Pinnacle Reef Floods (Wizard Lake, Westpem Nisku D), Reserve Growth of 15-40% OOIP. (Howes, B. J., 1988)

• West Hackberry, LA, Reported 30% OOIP Reserve Growth

• Others include; Weeks Island, Bay St Elaine, Intisar Libia, Handil, Borneo, Samaria Field Mexico, Cantarell

• Hawkins, Tx, Exxon

Gas Displacement Recovery

Reserve Growth Applications

• Miscible Displacement

• Pressure Maintenance – Pressure maintenance condensate and retrograde

condensate reservoirs

– oil reservoirs

• Gas Assisted Gravity Drainage

• Immiscible Displacement Gas cap gas

Oil reservoir IWAG

• Mixed Gas Applications Driving agent for slug/buffer

Mixed gases for density control

Immiscible Water Alternating Gas

(IWAG)

• “a successful IWAG can potentially show a faster response that a miscible flood with less cost”

• Significant tertiary oil recovery efficiencies have been observed as a result of immiscible WAG displacements.

• Moderate IFT reduction

• Oil recovery mechanism is 3-phase and hysteretic effects

• 13% Residual oil saturation was reached in core studies.

• “Gas-oil immiscible displacement has a higher microscopic sweep efficiency that water-oil”

From Righi, et al, 2004, SPE 89360

Mechanisms For Immiscible WAG

1. Improved Volumetric Sweep with Water Following Gas – Presence of free gas causes Krw in 3-phase flow to be lower than water-oil

saturated pores, thus diverting water to unswept rock

2. Oil Viscosity Reduction – Changes mobility ratio of water-oil displacement more favorable in the case of

(initially) undersaturated oil.

3. Oil Swelling by Dissolved Gas – Residual oil contains less stock tank oil, thus increasing recovery even in the

absence of any Sor reduction.

4. Interfacial Tension (IFT) Reduction – Gas-oil IFT is lower than water-oil, allows gas to displace oil through small

pores throats not accessible by water alone (under a give pressure gradient).

5. Residual Oil Saturation Reduction Due to 3-phase and Hysteresis Effects. – In water-wet rock, trapping of gas during imbibition cycles can cause oil

mobilization at low saturations and an effective reduction in the 3-phase residual oil saturation.

Immiscible with no Solubility Effects

• Recovered 18% over waterflood

Normalized to

waterflood

recovery

IWAG Results With CH4 vs N2

• Simulation with history match of CH4 IWAG

• No Discernable difference between CH4 and N2 IWAG production prediction

CH4 IWAG

started

Simulated IWAG

From Mohiuddin et al., 2007, SPE # 105785

Mechanisms for Reduction of Waterflood

Sor in the Presence of Free Gas

• Gas Trapping – Water imbibition in the presence of a gas phase saturation

leads to free gas trapping

• Oil Mobilization and Reduction – Trapping of a gas in the presence of water-oil system residual

oil, causes a fraction of the oil to be mobilized based on 3-phase oil relative permeability.

• 3-Phase Gas and Water Mobility – In WAG cycling secondary drainage paths ( increased Sg in

the presence of water and oil), produce Krg values that decrease in each cycle rather than retracing the same drainage Krg path. This results in effective mobility control of the gas

Based on Rel perm core results Sorg about =2/3 Sorw

Immiscible WAG, Micromodel Tests

• Stable Oil Layers Were Formed Between Water and Gas Phases.

• High Sor Case, gas traveled through oil channels, moving : – Oil to production

– Oil into water flood channels

• Low Sor Case, gas traveled through oil channels and large water channels moving : – Oil to water filled pores

– Blocking some water flood channels

• Additional Oil Recovered By: – Water displaced oil that had refilled the water channels during gas injection

– Water displaced oil in other regions because of gas blocking of water channels

– Waterflood recovery 28%, Gas Flood recovered another 20.5 % of OOIP

Modified From Dong et al., 2001, JCPT

3 Phase Pore level Interaction

• Initially gas only moves into the oil bearing pores because the

threshold capillary pressure into water saturated pores is much

higher.

• Oil forms a continuous layer between gas and water.

• Film flow can allow more oil to move out of the pore.

From Dong et al., 2001, JCPT

2 Menisci

1 Menisci

Oil film

Gas Oil

Experimental Immiscible CO2 Gas

Flooding

• The Average Tertiary

oil recovery was 14.7

% of OOIP

• Injection of a Single

Slug WAG was very

efficient

• 20.6 % Reserve

Growth was Obtained

from 4 WAG cycles.

Zhang, et al., JCPT 2/2010

Kuparuk River IWAG Example

• Gas Saturation Reduces

Water Mobility

– Reduces water handling

– Increases sweep

efficiency

• Mechanism Results in

Lower residual Oil

Saturation

From Ma and Youngren,1994 SPE # 28602

From Ma and Youngren,1994 SPE # 28602

Production Results

Kuparuk River IWAG Example

32 31

29

21

%O

OIP

40

35

30

25

20

15

10

5

0

22

30

22

17

19

19

17

13

7

5

10

1

5

2

3

1

0

Number of patterns

WF IWAG

Water Injection, HCPV

0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5

Offshore India IWAG

• Laboratory Tests Generated a 14.5 % Increase In Displacement Efficiency

• Pilot Displayed: – Oil Production increase

– Water cut decrease

• Simulation Resulted in 9.5 % OOIP Reserve Growth

Ramachandran et al., 2010 SPE # 128848

Immiscible Floods and Pilots

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

• Lick Creek Field • Ss, Arkansas, after 5 years CO2 injection = 14.1 BSCF & 1 MM STB

oil produced. • 17 API, 160 cp

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

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

• Huntington Beach Field • 14 API, 177 cp oil

• Denbury Resources, Mississippi USA

Immiscible CO2 Pilots,

Forest Reserve and Oropouche Fields, Trinidad

• Implemented After Natural Gas and Water

injection

• Conducted in a Gravity Stable Mode

• Oil 17-29 API

• Reserve Growth Ranged from 2-8 % of OOIP

and Projected to be 4-9 %

• Utilization Rates Ranged from 3-11 Mscf/STB

From Mohammed-Singh & Singhal, 2005

Summary/Conclusions

• Miscibility Isn’t a “Holy Grail”

• There are Fundamental Immiscible

Displacement Mechanisms that Produce

Reserve Growth in Watered-out Rocks

• Experimental Data Indicates why Immiscible

Gas Displacement Works

• Pilot and Field Applications Have Proven

Immiscible Displacement

Summary of EOR Reserve Growth

Future Reserve Additions in Large, Light Oil, Mature Fields will

Primarily come from GDR.

Reserve Additions Will Occur Through:

1. Pressure maintenance

2. Miscible displacement

3. Immiscible displacement

4. Gas assisted gravity drainage

5. Mixed gas applications: driving agent/density control

GDR Typically increases both Sweep and Displacement Efficiency in

Oil and Gas Reservoirs.

Reserve Growth Targets can range from 10 to 45 % of OOIP/OGIP

• Immiscible GDR has 2 components

– Instantaneous response due to gas displacing oil

– Secondary response of fluid-fluid interaction, Viscosity

reduction, swelling, relative permeability

Dong et al.,2005 jcpt

Gravity Drainage Second Contact Water Displacement

Waterflooding after a gravity drainage gas displacement recovery (GDR) project

Water displaces the thin film oil

Gas fills the trapping pore center as residual saturation

Applicable after significant gas breakthrough

Modified from Ren et al., 2000)

Gravity Drainage - General Design

Obtain piston (no gas fingering) like displacement

– Horizontal gas-oil contact

– Have gravity dominate the gas flow

Optimize the time between gas injection and oil production.

– As fast as possible without gas fingering

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

Hawkins GAGD Production Strategies

• Adjust gas injection rate

• Level fluid contact by balancing oil production

• Maintaining optimum oil-column thickness

• Wells perforated a the base of the oil column

• Perforations made 25 -30 below GOC

• Per-well arate set a 250-400 bbl/d liquid

– Drawdown 50 – 100 psi

Hawkins Production History

EFB implemented 6 injectors

ASU startup 4/1991

Injection reduced to 15 mmscf/day

Discovered in 1940 developed on 20 acre spacing

Field unitized Inert gas

injection

began

Offshore Field Nitrogen Injection - PEMEX

Cantarell, Reservoir Characteristics*

Area (Sq miles): 48

Average thickness (feet): 167-2,920

Crude Oil gravity (API): 17-22

Formation age: Paleocene, Cretaceous

and Eoccene

Reservoir rock: naturally fractured

carbonates

Permeability range (darcies): 2-4

Porosity range: 8-12%

Main drive mechanisms: gravitational

segregation, gas cap expansion and

nitrogen injection to maintain pressure

*Considers the average of the makes four Cantrell reservoirs.

Gravity Drainage In Fractured Chalk

SPE paper 113601, Karimaie & Torsaeter 2008

0 2 4 6 8 10 0

Re

co

ve

ry f

rac

tio

n o

f O

OIP

0.2

0.4

0.6

0.8

1

Water

Injection

Equ. Gas, 200 bar

IFT=0.15, N/mr

17%

0 1 2 3 4 5 0

Re

co

ve

ry f

rac

tio

n o

f O

OIP

0.2

0.4

0.6

0.8

1

Water

Injection

Equ. Gas, 220 bar

IFT=0.15 mN/m

13%

Equ. Gas, 210 bar

IFT=0.37mN/m

6%

Time (day) Time (day)

Core flood experiments

Core Flood Experiments

Comparing Applications

• Six foot Berea core flooded immiscibly

• IWAG 58% of residual oil recovered

• GAGD, 65% of residual oil recovered

From Rao et al., 2004

Under-Saturated Reservoirs

• Oil viscosity reduction is found to be the dominant mechanism in severely under-saturated reservoirs.

• Simulation of a reservoir with Pb = 1,875 psi and Pi =3,500 psi resulted in 6-9 % OOIP reserve growth

• Milne Point field data supported lab and simulation.

Ning & McGuire, 2004, SPE # 89353

Evidence of Waterflood Alteration

Immiscible Gas Injection Differential Pressure Variation

• Initial high DP, with So and Swi

• With waterflooding DP decreases with increasing Sw

• With gas injection DP decreases rapidly, from Sg increase and thus low viscosity,

• Water injection causes a sharp DP increase

• The sharp DP increase indicates that gas injection modifies the water mobility in the water swept regions. – Thus more oil is recovered. Modified From Dong et al., 2001, JCPT

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

Structure Map 8,000 ft sand