Reserve Growth & Higher Recovery Using Nitrogen Gas Injection Reserve Growth & Higher Recovery Using Nitrogen Gas Injection Joe Shine & Mark Holtz Praxair, Inc. 2008 Wyoming EOR/IOR Conference September 15, 2008 Joe Shine & Mark Holtz Praxair, Inc. 2008 Wyoming EOR/IOR Conference September 15, 2008
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Reserve Growth & Higher Recovery Using Nitrogen Gas Injection
Reserve Growth & Higher Recovery Using Nitrogen Gas Injection
Joe Shine & Mark Holtz Praxair, Inc. 2008 Wyoming EOR/IOR Conference September 15, 2008
Joe Shine & Mark Holtz Praxair, Inc. 2008 Wyoming EOR/IOR Conference September 15, 2008
2
Business ConfidentialBenefits from Nitrogen Gas Injection
Assist & facilitate with project development effortsReservoir engineering servicesSelection of gas injectantRecovery process simulationOptimization of gas supply system
Partner on GDR pilot projects
Provide gas injectant requirements for full scale operations
Business ConfidentialN2 Reserve Growth Applications
Pressure maintenanceCondensate and retrograde condensate reservoirs
Miscible displacement
Gravity drainage
Immiscible displacementOilGas cap gas
Driving agent for slug/buffer
19
Business ConfidentialGas Condensate Pressure Maintenance
Screening criteria:1) Dew point pressure near the original reservoir
pressure, under saturated by 150 to 300 psi, 2) High condensate yield typically >
175 bbl/MMSCF produced, 3) High liquid dropout rate with liquid
condensation from 20 to 40 % of the hydrocarbon pore space.
Pressure depletion effects cause;Reduction in gas permeability and well productivityAquifer encroachmentLower ultimate hydrocarbon recovery by 10 to 40 %
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Business ConfidentialRelative Permeability Effects in Gas Condensate Reservoirs
Near-wellbore Where saturation hysteresis is severe
Main reservoir away from wells Liquid mobility is near zeroGas flows at reduced permeability
Reservoir edge Water encroachment traps gas and condensateHydrocarbons trapped at 10- 40 % saturations
21
Business ConfidentialPermeability Reduction from Condensate Dropout
From Al-Honi and Abdulrazag, 2004
Dew point pressure
22
Business ConfidentialLaboratory and Simulation Studies
Methane used as buffer gas
Slightly greater revaporization occurred with buffer gas.
Test 12 run below dew point
Renner, et al., 1989
Test101112
TestPressure
(psia)
5,5655,565
5,565 to 4,500
Drive GasNitrogen
Buffer gasNitrogen
IrreducibleWater
Saturation(% PV)
28.127.828.0
LiquidRecovery at
1.5 HCPV Injected(% STLOIP)
87.891.964.0
99.798.699.0
MaterialBalance(vol%)
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Business ConfidentialAnschutz Ranch E. Gas Condensate Pressure Maintenance Example
From Kleinsteiber et al., 1983
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.
Nugget ss, WY
10 % porosity
3 md perm
5,600 psi injection pressure
N2 & CH4
Pi = 5,310 psi
Pdew= 5,080 psi
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Business ConfidentialAnschutz Ranch E. Gas Condensate Pressure Maintenance Example
Injection scheme1) Inject 0.1 HCPV of 35% N2
and 65% wet gas
2) Chases with pure N2
80-acre inverted 9 spot pattern
Amoco 1982, 50 MMscf/day
6,200 psi injection pressure
Wendschlag et al., 1983 From Kleinsteiber et al., 1983
9 COMP17 COMP
Cum N2 Injected, HCPV
Fig. 3-Recovery comparison from 1-D nitrogen displacement simulations
0.0 0.5 1.0 1.5 2.0
Cum
. Oil
Rec
over
y, %
OIP
0
10
20
30
40
50
60
70
80
90
100
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Business ConfidentialN2 Miscibility Displacement
There are three types of miscibility including;First-contact miscibility
Multi-contact miscibility
Vaporizing mass-transfer miscibility
Results in high displacement efficiency at the pore level
ProducerInjector
Prax
air
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Business ConfidentialMiscible N2 Flood East Binger, Oklahoma
K = 0.2 md
Phi = 0.075
Swi=0.25
60 ft net pay
Primary recovery 10.7 % of OOIP
Tr= 190 F
Pi = 5,800 psi
MMP =4,200 psi Depth 10,000 ft
42 API gravity
1.798 FVF
1,320 SCF/STB GOR
Miscibility lab results
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Business ConfidentialEast Binger Miscible N2 FloodInjection began 23 wells drilled
Plugging from combination of compressor lube oil, CO, CO2, dust.
Primary recovery 11%*
GDR reserve growth 16 % to 27% ultimate recovery *
*Cornelius, 1983
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Business ConfidentialMiscible WAG Jay Field, Florida
N2 miscible WAG 3:1 ratio
Line drive pattern
Pi = 7,850 psi, Tr = 285 F
51 API gravity oil
Phi= 0.14, K= 20 md
Reserve growth of 10 -13% OOIP (80MMSTB)
Lawrence et al., 2003
Figure 2. Jay Field wells and patterns.
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Business ConfidentialGravity Drainage
The most common Gravity drainage processes are:Gas assisted gravity drainage ( no water present)Double displacement process ( water present)
N2 injectorProducer
Double Displacement Process (DDP). The process of gas displacement of a water invaded oil column has been termed.
The double displacement process consists of injecting gas up-dip and producing oil down-dip
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Business ConfidentialGravity 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
Increases displacement efficiencyOil film flow is an important recovery mechanism– Film flow connects the isolated blobs of residual oil in the
presence of gasStrong water wetPositive spreading coefficient
Modified from Ren et al., 2000)
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Business ConfidentialGravity Drainage – General Design
Obtain piston like displacement (no gas fingering) Horizontal gas-oil contactHave 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
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Business ConfidentialGravity Drainage – General Design
Critical velocity analytical model
Simulation model dependent on 3 Phase relative permeability
Effected by film flowEffected by saturation historyTypically from 2 phase correlationsDepend on the direction of flow (i.e., be directionally anisotropic)
Vc is critical velocity rate (ft/day)Δρ
is density differencek is permeability (darcies)θ
is dip angleφ
is porosity (fraction)Δμ
is viscosity difference
μφθρ
ΔΔ
=sin741.2 kVc
Where
(Hill 1952)
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Business ConfidentialHawkins Field Double Displacement Process
Lawrence et al., 2003
Double Displacement Process Schematic
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Business ConfidentialN2 as Driving Agent for slug/buffer (chase gas)
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Business ConfidentialSt Elaine Pilot Gravity stable N2 after CO2
84.4 metric tons/D CO2 injected or 1/3 Pore volume