reservoir growth from co2 eor
DESCRIPTION
This presentation is about the role of CO2 in enhancing the production of Oil from reservoir by injecting CO2TRANSCRIPT
CO2 Enhanced Oil Recovery
Reservoir GrowthFrom CO2 Enhanced Oil
RecoveryThe Fundamentals
Mark H. Holtz
CO2 Enhanced Oil Recovery
US CO2 driven EOR Projects and Infrastructure-Today and
Tomorrow
Source: Denbury Resources, Inc., 2004
CO2 Enhanced Oil Recovery
Outline
• Fluid Characteristics• Rock – fluid interaction• Flooding methods• Flooding project design
CO2 Enhanced Oil RecoveryPotential Solvents• Alcohols
• Nitrogen
• Air
• Flue gas
• Various petroleum gases (C3)
• Methane
• Carbon dioxide
CO2 Enhanced Oil Recovery
Classifying Solvent Displacements...
Minimum Miscibility Pressure (MMP)
Minimum Miscible Enrichment (MME)
CO2 Enhanced Oil Recovery
CO2 Miscible Flooding Mechanisms
• Large density at reservoir conditions makes the CO2 a good solvent for light hydrocarbons
• The formation of a single phase diminishes the capillary forces• Miscibility with the CO2 lowers the viscosity of the oil and increases its
mobility.
Pure CO2CO2 VaporizingOil Components
CO2 CondensingInto Oil
Original Oil
Miscibility Region(CO2 and Oil Form Single Phase)
Direction of Displacement
CO2 Enhanced Oil Recovery
Selection of Candidates Suitable for CO2Miscible Flooding
Minimum Miscibility Pressure (MMP) within an achievable range
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
CO2 Enhanced Oil Recovery
Ways to Estimate MMP...• Experimental….
Slim tube experiments
Rising bubble method
Vanishing interfacial tension
• Calculation…Mixing cell method
Method of characteristics
• Correlation….
CO2 Enhanced Oil Recovery
Ways to Estimate MMP• Experimental
Slim tube experiment: Isothermal crude displacement by carbondioxide in the absence of water. The apparatus consists of a largeaspect ratio tube or spiral coil containing beads or unconsolidated sands.(Rutherford 1962, Yarborough and Smith 1970, Holm et al 1974)
CO2 Enhanced Oil Recovery
Ways to Estimate MMP• Experimental
Rising bubble method: Visual observation experiment and photography of rising gas bubbles in the oil. An empirical pressuredependence of the rising gas bubbles is established to infer theMMP (Christiansen and Kim 1984; Hagen and Kossack 1986)
CO2 Enhanced Oil Recovery
Ways to Estimate MMP• Analytical…
Mixing cell method: Simulated container in which oil and gas are mixed and equilibrium vapor and liquid phases are formed. Two versions: single-cell methods (Kuo 1985; Nouar et al. 1986) and multiple-cell methods (Metcalfe et al.1973; Pederson et al. 1986; Neau et al. 1996)
CO2 Enhanced Oil Recovery
Ways to Estimate MMP• Analytical
Tie line analysis and method of characteristics (MOC): Negative flash simulated to find the pressure when the injection tie line or the initial tie line become critical. In other words, the MMP would be thepressure at which the critical tie line passes through the crude composition. (Wang and Orr 1984)
CO2 Enhanced Oil Recovery
Ways to Estimate MMP
• CorrelationsMany correlations are found in the literature that are largely based on slimtube test data. Most of them are functions of API gravity, C5+ molecular weight,and temperature.
Molecular Weight C5+ vs. Oil gravity (Lasater, 1958)
0
20
0.00 100.00 200.00 300.00 400.00 500.00
Molecular Weight C5+
Oil
Gra
vity
, oA
PI
Correlation for CO2 Minimum Pressure as a Function of Temperature (Mungan, N., Carbon Dioxide Flooding Fundamentals, 1981)
0
1000
2000
3000
4000
5000
6000
70 110 150 190 230 270
Tem perature , oF
Mis
cibi
lity
Pres
sure
, psi
MOLE W EIGHT C5+ = 340 300 280 260 240 200220
180
CO2 Enhanced Oil Recovery
Effect of Impurities in CO2
• MMP decreases if the impurity has a greater critical temperature than CO2
Increasing MMP Decreasing MMP
CO2 Enhanced Oil Recovery
Critical Properties of Common Elements/Compounds
Critical temperature Critical pressure Boiling temperature
(oF) (oC) (psi) (lb/sq.in)
(atm) (oF) (oC)
Sulfur dioxide
SO2
315.8 1143 14.11
Ammonia (NH3)
266 130 1691 115 -27.4 -33
Water (H2O) 706-716 375-380 3,200 217.8 212 100
Carbon-dioxide (CO2)
88.2 31 1132 77 -110 -79
Carbon-monoxide (CO)
-222 -141 528 35.9 -310 -190
Air -220 -140 573 39 - -
Hydrogen (H)
-402 -242 294 20 -423 -253
Nitrogen (N) -236 -149 514 35 -321 -195
Nitric Oxide (NO) -94 65
Oxygen (O2) -180 -118 735 50 -297 -183
Substance
CO2 Enhanced Oil Recovery
MMP Correction for Impurities
3)TT(7E35.22)TT(000251.0()TT(00213.0(1(P cpccpccpc2mmpCOmmpP −−−−+−−=
(From Sebastian et al. 1984)
Where: Pmmp
PmmpCO2
Tpc
Tc
= MMP of mixture
= MMP of CO2
= Psudo critical temperature of mixture
= Critical temperature of mixture
CO2 Enhanced Oil Recovery
Key Physical PropertiesCO2 Solubility in Aqueous Phase, Constant
Temperature
1,400 psi
91 psi
1,060 psi
2,900 psi5,800 psi
T=140°F
0.0001
0.001
0.01
0.1
0 50,000 100,000 150,000 200,000 250,000 300,000 350,000Salinity, ppm NaCl
CO
2C
once
ntra
tion
in A
queo
us P
hase
, mol
e fr
actio
n
Temperature = 140 F
91 psi
CO2 Enhanced Oil Recovery
Outline
••• Fluid CharacteristicsFluid CharacteristicsFluid Characteristics• Rock – fluid interaction••• Flooding methodsFlooding methodsFlooding methods••• Flooding project designFlooding project designFlooding project design
CO2 Enhanced Oil Recovery
Residency of CO2 in An EOR Flood
CO2 dissolved in water
CO2 dissolved inresidual oil
CO2 as separateresidual phase
CO2
CO2 dissolved inproduced oil
Rock Grain
Rock Grain
Rock Grain
CO2 Enhanced Oil Recovery
Flow & Saturation Definitions
0
20
40
60
80
100
120
140
160
0 10 20 30 40 50 60 70 80 90 100Wetting-phase “water” saturation
(percent)
Cap
illar
y pr
essu
re (p
si)
Drainage, wetting phase beingreplaced by non wetting phase
Imbibition, wetting phasereplacing nonwetting phase
Swirr Sor
CO2 Enhanced Oil Recovery
Formation of Residual Saturation
• Moore and Slobod, 1956– Pore Doublet model
Capillary force holds nonwetting phase in larger pore
CO2 Enhanced Oil Recovery
Formation of Residual Saturation
• Oh and Slattery, 1976– Snap-off model
Capillary force cause nonwettingphase to snap-off into pore
Aspect ratio =Pore radius
Pore throat radius
CO2 Enhanced Oil Recovery
Geologic Effects on Residual Saturation
Modified from Stegemeier, 1976
CO2 Enhanced Oil Recovery
Prediction of non-wetting phase saturation for intergranular pore space
y = -0.3136Ln(x) - 0.1334R2 = 0.8536
0
0.2
0.4
0.6
0.8
1
0 0.1 0.2 0.3 0.4 0.5 0.6Porosity (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))
N = 143
Frio (Port Neches field)
CO2 Enhanced Oil Recovery
Reported Residual Oil SaturationFrio Fluvial Deltaic Sandstone Play
0-19 19-24 24-2929-34 34-3939-4444-4949-54 54-5959-640
2
4
6
8
10
12
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Residual oil saturation ( % )
Freq
uenc
y
Cum
ulat
ive
freq
uenc
y
15 24 34 43 53 62
Input data
Lognormal function(28.76, 8.34)
0.0
0.5
1.0Sor Distribution Representative Probability Function
Residual oil saturation ( % )
CO2 Enhanced Oil Recovery
Residual oil saturation characteristics of carbonate enhanced oil recovery projects
Restricted toopen platform
Reefs
Karst modified
Deep water cherts
QAc4240c
0
1
2
3
15 20 25 30 35 40 45
4
5
6
7
50 55
Freq
uenc
y
Average reservoir residual oil saturation (percent)
CO2 Enhanced Oil Recovery
Port Neches Water-Oil Relative Permeability Curves
0
0.2
0.4
0.6
0.8
1
0 0.2 0.4 0.6 0.8 1
Sw
kr
krwkrow
From Davis, 1994, SPE paper # 27758
Sor = 0.34
Cross over 0.53
Swi = 0.18
CO2 Enhanced Oil Recovery
Reported Residual oil Saturation in Gulf Coast CO2 EOR Pilots
Reservoir Quarantine Bay
Timbalier Bay
Weeks Island
Port Neches
Little Creek
Bay St. Elaine
Paradis
Residual oil to water (fraction)0.380.290.22
0.30.21
0.1 to 0.40.26
CO2 Enhanced Oil Recovery
St Elaine Bay Field Residual Oil Saturation Measurements
Measurement type Pressure cores
Sidewall cores
Log-inject-log waterflood
Conventional logs
Partitioning tracer test
“Sor” (fraction)
0.137
0.208
0.207
0.079
0.35
Porosity (fraction)
0.277
0.279
--
0.299
--
CO2 Enhanced Oil Recovery
Flooding Methods
• Huff-n- Puff • Water after gas (WAG)• Gravity stable• Continuous injection
CO2 Enhanced Oil Recovery
Single Well Cyclic or Huff ‘n’ Puff CO2 EOR Method
• Definition– A method by which CO2 is injected into a single well, the
well is shut-in, and then CO2 is produced back from the same well along with oil.
• General procedure1) Measure reservoir temperature and pressure2) Pressure test the tubing the make sure that the CO2 will go
where it is interned 3) Inject designed CO2 slug size4) Shut in the well for designated soaking period5) Produce the well and monitor oil, gas, water, and CO2
production6) Analyze data for utilization factor (Mscf/STB), CO2
sequestered, oil production rate change, Incremental oil recovery, cost to benefit analysis
7) Repeat procedure if successful
CO2 Enhanced Oil Recovery
Huff ‘n’ Puff CO2 Recovery Methods
• Swelling of oil– CO2 dissolves in the oil causing the oil to swell. This
increased both oil saturation and relative permeability.• Viscosity reduction
– When CO2 dissolves in the oil, oil viscosity is reduced increasing oil mobility.
• Water blocking– Oil and gas saturation are increased around the effected well
area which decreased water relative permeability.– This gives the added benefit of reducing lifting and water
disposal costs.
CO2 Enhanced Oil Recovery
Huff ‘n’ Puff CO2 Design
• Set up wellhead to connect to CO2 tanks.• Consider per wellhead CO2 heater to keep CO2 from
flashing to gas in well tubing.• Bottom-hole injection pressure
– Design below frac pressure but high so reservoir pressure gets near initial pressure.
• Choose soak time. Note that soaks times greater than 4 weeks has not been found to have a strong impact on recovery.
• Set up separator system to capture CO2 for reuse. ( may choose to reuse the CH4 + CO2 gas stream)
CO2 Enhanced Oil Recovery
Single Well Cyclic or Huff ‘n’ Puff CO2 EOR Method
• Huff ‘n’ Puff– Example 28 Texas projects (Haskin &Alston,
1989), 106 LA and Kentucky wells (Thomas & Monger, 1991)
– Results 3,233 to 29,830 stb/well– Design 8 MMscf CO2 injected, 2-3 week soak
times– CO2 utilization 0.71 – 2.73 Mscf/stb, Average 1.3
Mscf/stb
CO2 Enhanced Oil Recovery
Incremental Oil Recovery as a function of Slug Size
10
100
1000
10000
100000
10 100 1000 10000
CO2 Slig Size, ton
Incr
emen
tal O
il Pr
oduc
tion,
ST
B
Johns edt., 2000
Huff ‘n’ Puff Oil Recovery
CO2 Enhanced Oil Recovery
Water After Gas
• The Water after gas method is used to reduce the fingering of CO2 between injector and producer to obtain better sweep efficiency.
• WAG ratio – the ratio of the amount of water injected to the amount of CO2 injected
• Water Cycle length – Typically in the units of hydrocarbon pore volume.
CO2 Enhanced Oil Recovery
WAG Injection Rule of Thumb
• Let pre CO2 water injection rate be X• Average water-cycle injection rate =
0.5X (based on West Texas WAG)• CO2 injection rate = 2 to 3)X
CO2 Enhanced Oil Recovery
Relative Cost For a CO2 EOR WAG Project
68%22%
10%
CO2 Cost
Field equipment
Recyclingplant
CO2 Enhanced Oil Recovery
Gravity Stable Design
• CO2 Miscible• Critical Velocity ( velocity at which CO2 will
finger)– Reservoir dip– Permeability– Fluid viscosities– Fluid densities
• Additional solvents can be added to optimize density
• Determine injection rate and bottom hole pressure.
CO2 Enhanced Oil Recovery
Continuous injectionCO2 EOR Processes Tested on the Gulf
Coast
• Continuous injection– Example little Creek– Results 17 % of OOIP recovered– Design continuous injection, recycling total gas stream– CO2 Utilization ? Mscf/stb, ? Average Mscf/stb
CO2 Enhanced Oil Recovery
Denbury as a Corporate Model
• Added CO2 flood proved reserves of 35.3 MMBOE ( 12/31/03)– West Mallalieu field (2001) $ 4 million investment
10.4 MMBOE proved reserves “$2.60/bbl cost”– McComb Field (2002) $ 2.3 million investment 8.4
MM BOE proved reserves “$3.57/bbl cost”• Little Creek, Ms 17% recovery
– 1974 pilot– 1985 2 phase project implemented
CO2 Enhanced Oil Recovery
Project Design
Injection facilities Well DesignProductionfacilities
WellheadTubingCorrosion inhibitorsStainless steel gravel pack
StorageCompression Separation
Storage
CO2 recycle systemSuction scrubberFilter separatorDehydrator
CO2 recycling
Oil
CO2 Enhanced Oil Recovery
CO2 Injection Well Design
Example from Bay St. Elaine Field
Palmer et al., 1984)
CO2 Enhanced Oil Recovery
CO2 Production Well Design
Perforations
Casing
Check valve
Catcher Sub
Production tubing
Hydraulic packer
Inhibitor packer fluid
Gas lift valve mandrel
Inhibitor string strap
Inhibitor string
Inhibitor
CO2 Enhanced Oil Recovery
Methods to Reduce Corrosion Problems
• Use of corrosion inhibitors• Separate CO2 injection lines• Stainless steel wellheads• Fiber glass gathering systems