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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