Reservoir Growth From Co2 Eor

CO2 Enhanced Oil Recovery

Reservoir Growth From CO2 Enhanced Oil Recovery The Fundamentals Mark H. Holtz

US CO2 driven EOR Projects and Infrastructure-Today and Tomorrow

CO2 Enhanced Oil Recovery

Source: Denbury Resources, Inc., 2004

Outline CO2 Enhanced Oil Recovery

• • • •

Fluid Characteristics Rock – fluid interaction Flooding methods Flooding project design

Potential Solvents

CO2 Enhanced Oil Recovery

• Alcohols • Nitrogen • Air • Flue gas • Various petroleum gases (C3) • Methane • Carbon dioxide

Classifying Solvent Displacements...

CO2 Enhanced Oil Recovery

Minimum Miscible Enrichment (MME)

Minimum Miscibility Pressure (MMP)

CO2 Miscible Flooding Mechanisms CO2 Enhanced Oil Recovery

• • •

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. Miscibility Region (CO2 and Oil Form Single Phase)

Pure CO2

CO2 Vaporizing Oil Components

Direction of Displacement

CO2 Condensing Into Oil

Original Oil

Selection of Candidates Suitable for CO2 Miscible Flooding CO2 Enhanced Oil Recovery

Minimum Miscibility Pressure (MMP) within an achievable range CO2 Minimum Misciility Pressure

% Recovery at 1.2 HCPV of CO2 Injected

100 95

CO2 Thermodynamic MMP

90 85 80 75 70 65 60 55 50 1000

1100

1200

1300

1400

1500

Test Pressure, psia

1600

1700

1800

Ways to Estimate MMP... CO2 Enhanced Oil Recovery

• Experimental…. Slim tube experiments Rising bubble method Vanishing interfacial tension

• Calculation… Mixing cell method Method of characteristics

• Correlation….

Ways to Estimate MMP • Experimental

CO2 Enhanced Oil Recovery

Slim tube experiment: Isothermal crude displacement by carbon dioxide in the absence of water. The apparatus consists of a large aspect 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

CO2 Enhanced Oil Recovery

Rising bubble method: Visual observation experiment and photography of rising gas bubbles in the oil. An empirical pressure dependence of the rising gas bubbles is established to infer the MMP (Christiansen and Kim 1984; Hagen and Kossack 1986)

Ways to Estimate MMP • Analytical…

CO2 Enhanced Oil Recovery

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

CO2 Enhanced Oil Recovery

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 the pressure at which the critical tie line passes through the crude composition. (Wang and Orr 1984)

Ways to Estimate MMP CO2 Enhanced Oil Recovery

• Correlations Many correlations are found in the literature that are largely based on slim tube test data. Most of them are functions of API gravity, C5+ molecular weight, and temperature. Correlation for CO 2 M inimum Pressure as a Function of T emperature (M ungan, N., Carbon Dioxide Flooding Fundamentals, 1981) 6000

Molecular Weight C5+ vs. Oil gravity (Lasater, 1958) 20

Oil Gravity, oAPI

Miscibility Pressure, psi

5000 MOLE W EIGHT C 5 + =

340

300

280

260

240

220

200

4000 180 3000

2000

1000

0 0.00

100.00

200.00

300.00

Molecular Weight C5+

400.00

500.00

0 70

110

150

190 o

Te m pe rature , F

230

270

Effect of Impurities in CO2 CO2 Enhanced Oil Recovery

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

Decreasing MMP

Critical Properties of Common Elements/Compounds CO2 Enhanced Oil Recovery

Critical temperature Substance Sulfur dioxide SO2 Ammonia (NH3)

(oF)

(oC)

315.8

Critical pressure (psi) (lb/sq .in)

(atm)

1143

Boiling temperature (oF)

(oC)

14.11

266

130

1691

115

-27.4

-33

706-716

375-380

3,200

217.8

212

100

88.2

31

1132

77

-110

-79

Carbonmonoxid e (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

Oxygen (O2)

-180

-297

-183

Water (H2O) Carbondioxide (CO2)

65 -118

735

50

MMP Correction for Impurities CO2 Enhanced Oil Recovery

Pmmp = PmmpCO2(1 − (0.00213(Tpc − Tc) + (0.000251(Tpc − Tc)2 − 2.35E−7 (Tpc − Tc)3 Where: Pmmp

= MMP of mixture

PmmpCO2 = MMP of CO2 Tpc

= Psudo critical temperature of mixture

Tc

= Critical temperature of mixture

(From Sebastian et al. 1984)

Key Physical Properties CO2 Solubility in Aqueous Phase, Constant Temperature CO2 Enhanced Oil Recovery

CO2 Concentration in Aqueous Phase, mole fraction

0.1 5,800 psi

2,900 psi

Temperature = 140 F T=140°F

0.01 1,060 psi

0.001

1,400 psi

91 91 psi psi

0.0001 0

50,000

100,000

150,000

200,000

Salinity, ppm NaCl

250,000

300,000

350,000

Outline CO2 Enhanced Oil Recovery

• • • •

Fluid Characteristics Rock – fluid interaction Flooding methods Flooding project design

Residency of CO2 in An EOR Flood CO2 Enhanced Oil Recovery

CO2 dissolved in produced oil

CO2 as separate residual phase Rock Grain CO2 Rock Grain Rock Grain CO2 dissolved in water

CO2 dissolved in residual oil

Flow & Saturation Definitions CO2 Enhanced Oil Recovery

160

Capillary pressure (psi)

140 120

Drainage, wetting phase being replaced by non wetting phase

100 80

Imbibition, wetting phase replacing nonwetting phase

60 40

Swirr

20

Sor

0 0

10 20 30 40 50 60 70 80 90 100

Wetting-phase “water” saturation (percent)

Formation of Residual Saturation CO2 Enhanced Oil Recovery

• Moore and Slobod, 1956 – Pore Doublet model

Capillary force holds nonwetting phase in larger pore

Formation of Residual Saturation CO2 Enhanced Oil Recovery

• Oh and Slattery, 1976 – Snap-off model Pore radius Aspect ratio = Pore throat radius Capillary force cause nonwetting phase to snap-off into pore

Geologic Effects on Residual Saturation

CO2 Enhanced Oil Recovery

Modified from Stegemeier, 1976

Prediction of non-wetting phase saturation for intergranular pore space CO2 Enhanced Oil Recovery

1

Residual non-wetting phase saturation (fraction)

Gas Residual saturation to water (fraction) Frio Barrier bar

N = 143

Log. (Gas Residual saturation to water (fraction))

0.8

Frio (Port Neches field)

0.6

0.4

0.2

y = -0.3136Ln(x) - 0.1334 R2 = 0.8536

0 0

0.1

0.2

0.3

0.4

Porosity (fraction)

0.5

0.6

Reported Residual Oil Saturation Frio Fluvial Deltaic Sandstone Play CO2 Enhanced Oil Recovery

Representative Probability Function

Sor Distribution

1.0 12

100%

10

80% 70%

Frequency

8

60% 50%

6

40% 4

30% 20%

2

10% 0%

0 0-19 19-24 24-2929-34 34-39 39-44 44-49 49-54 54-59 59-64

Residual oil saturation ( % )

Cumulative frequency

90%

Input data 0.5

Lognormal function (28.76, 8.34) 0.0 15

24

34

43

53

Residual oil saturation ( % )

62

Residual oil saturation characteristics of carbonate enhanced oil recovery projects CO2 Enhanced Oil Recovery

7

Deep water cherts 6

Karst modified

Frequency

5

Reefs

4

Restricted to open platform

3 2 1 0 15

20

25

30

35

40

45

50

55 QAc4240c

Average reservoir residual oil saturation (percent)

Port Neches Water-Oil Relative Permeability Curves CO2 Enhanced Oil Recovery

1

0.8

0.6 kr

krw krow 0.4

Cross over 0.53 Swi = 0.18

0.2

Sor = 0.34

0 0 From Davis, 1994, SPE paper # 27758

0.2

0.4

0.6 Sw

0.8

1

Reported Residual oil Saturation in Gulf Coast CO2 EOR Pilots

CO2 Enhanced Oil Recovery

Reservoir

Residual oil to water (fraction)

Quarantine Bay

0.38

Timbalier Bay

0.29

Weeks Island

0.22

Port Neches

0.3

Little Creek

0.21

Bay St. Elaine Paradis

0.1 to 0.4 0.26

St Elaine Bay Field Residual Oil Saturation Measurements CO2 Enhanced Oil Recovery

“Sor” (fraction)

Porosity (fraction)

Pressure cores

0.137

0.277

Sidewall cores

0.208

0.279

Log-inject-log waterflood

0.207

--

Conventional logs

0.079

0.299

0.35

--

Measurement type

Partitioning tracer test

Flooding Methods CO2 Enhanced Oil Recovery

• • • •

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

Single Well Cyclic or Huff ‘n’ Puff CO2 EOR Method CO2 Enhanced Oil Recovery

•

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 procedure 1) 2) 3) 4) 5) 6) 7)

Measure reservoir temperature and pressure Pressure test the tubing the make sure that the CO2 will go where it is interned Inject designed CO2 slug size Shut in the well for designated soaking period Produce the well and monitor oil, gas, water, and CO2 production Analyze data for utilization factor (Mscf/STB), CO2 sequestered, oil production rate change, Incremental oil recovery, cost to benefit analysis Repeat procedure if successful

Huff ‘n’ Puff CO2 Recovery Methods CO2 Enhanced Oil Recovery

• 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 CO2 Enhanced Oil Recovery

• 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

CO2 Enhanced Oil Recovery

• 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

Huff ‘n’ Puff Oil Recovery CO2 Enhanced Oil Recovery

Incremental Oil Production, STB

Incremental Oil Recovery as a function of Slug Size 100000

10000

1000

100

10

10

100

1000

CO2 Slig Size, ton

10000 Johns edt., 2000

Water After Gas CO2 Enhanced Oil Recovery

• 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 CO2 Enhanced Oil Recovery

• 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 CO2 Enhanced Oil Recovery

Field equipment 10% 22% CO2 Cost

68%

Recycling plant

Gravity Stable Design CO2 Enhanced Oil Recovery

• 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 injection CO2 EOR Processes Tested on the Gulf Coast CO2 Enhanced Oil Recovery

• 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

CO2 Enhanced Oil Recovery

• 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 CO2 Enhanced Oil Recovery

Injection facilities

Storage Compression

Well Design Wellhead Tubing Corrosion inhibitors Stainless steel gravel pack

Production Oil facilities

Separation Storage CO2 recycle system Suction scrubber Filter separator Dehydrator

CO2 recycling

CO2 Injection Well Design CO2 Enhanced Oil Recovery

Example from Bay St. Elaine Field

Palmer et al., 1984)

CO2 Production Well Design CO2 Enhanced Oil Recovery

Inhibitor

Inhibitor string

Inhibitor packer fluid Gas lift valve mandrel

Inhibitor string strap

Check valve

Casing

Perforations

Hydraulic packer

Production tubing

Catcher Sub

Methods to Reduce Corrosion Problems CO2 Enhanced Oil Recovery

• • • •

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