Reservoir Growth from CO2 EOR

CO2 Enhanced Oil Recovery

Reservoir GrowthFrom CO2 Enhanced Oil

RecoveryThe Fundamentals

Mark H. Holtz


US CO2 driven EOR Projects and Infrastructure-Today and

Tomorrow

Source: Denbury Resources, Inc., 2004


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


Classifying Solvent Displacements...

Minimum Miscibility Pressure (MMP)

Minimum Miscible Enrichment (MME)


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


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


Ways to Estimate MMP...• Experimental….

Slim tube experiments

Rising bubble method

Vanishing interfacial tension

• Calculation…Mixing cell method

Method of characteristics

• Correlation….


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)


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)


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)


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)


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


Effect of Impurities in CO2

• MMP decreases if the impurity has a greater critical temperature than CO2

Increasing MMP Decreasing MMP


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


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


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


Outline

••• Fluid CharacteristicsFluid CharacteristicsFluid Characteristics• Rock – fluid interaction••• Flooding methodsFlooding methodsFlooding methods••• Flooding project designFlooding project designFlooding project design


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


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


Formation of Residual Saturation

• Moore and Slobod, 1956– Pore Doublet model

Capillary force holds nonwetting phase in larger pore


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


Geologic Effects on Residual Saturation

Modified from Stegemeier, 1976


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)


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 ( % )


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)


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


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


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

--


Flooding Methods

• Huff-n- Puff • Water after gas (WAG)• Gravity stable• Continuous injection


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


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.


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)


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


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


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.


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


Relative Cost For a CO2 EOR WAG Project

68%22%

10%

CO2 Cost

Field equipment

Recyclingplant


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.


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


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


Project Design

Injection facilities Well DesignProductionfacilities

WellheadTubingCorrosion inhibitorsStainless steel gravel pack

StorageCompression Separation

Storage

CO2 recycle systemSuction scrubberFilter separatorDehydrator

CO2 recycling

Oil


CO2 Injection Well Design

Example from Bay St. Elaine Field

Palmer et al., 1984)


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


Methods to Reduce Corrosion Problems

• Use of corrosion inhibitors• Separate CO2 injection lines• Stainless steel wellheads• Fiber glass gathering systems

Documents

Reservoir Growth from CO2 EOR