Moving from Secondary to Tertiary Recovery Stages

9TH ANNUAL WYOMING EORCO2 CONFERENCE

JULY 14-16, 2015 – Casper, WY

By Jim Mack

MTech Ventures LLC

1

Outline

• Reservoir Data

• Geologic Data

• Formation Data

• Fluid Data

• Primary & Secondary Performance

• EOR Development

• Closing

2

This is a Workshop open for Discussion

3

Reservoir Data

• Total Surface Area, AC: no. of wells, pattern

• Well Spacing, AC: < 80 acre spacing

• Average Net Pay: thin vs. thick

• Type Primary Producing Drive: solution gas drive, fluid expansion, waterdrive

• Depth: Injection Pressure

• Temperature

4

Geologic Data

• Formation:

• Type (Sandstone/Carbonate): clean vs dirty sandstone, fractured carbonate; dual porosity

• Reservoir Structure

• Reservoir Isopach

• Faults, Compartmentalization, Unconformities

5

Formation Data

• Porosity, % (Avg. & Range):

• Permeability Average md:

• Permeability Range, md:

• Permeability Variation, Kv:

• Wettability

• Clays

• Fractures (Y/N)

6

Dykstra-Parsons Permeability Variation

Kv = kavg - kσ

kavg

Kv = 230 - 70230

Kv = 0.710

100

1000

10000

2 2% 20% 50% 80% 98%

Percent Greater Than

Sam

ple

Per

mea

bilit

y (m

d)

Log-Normal Permeability Variation

Waterflood Oil Recovery

Early in Drive Midway in Drive Flood-out

Early in Drive Midway in Drive Economic Limit

Fluid Distribution During Waterflood of Water-Wet Rock

Fluid Distribution During Waterflood of Oil-Wet Rock

Displacement EfficiencyOil Displacement by Water, Oil-wet Sand

Oil Displacement by Water, Water-wet Sand

9

• Kf / Ki

- Final permeability / initial permeability

• (Kf / Ki) t

- Treatment-induced permeability damage

• (Kf / Ki) s

- Fresh water sensitivity after treatment

• (Kf / Ki) c

- Fresh water sensitivity for a comparable

untreated plug

Core Treatment Parameters

10

Crude

0.2

0.4

0.6

1.2

Kf

/ K

i

Prod. Water

1.0

0.8

0.0

Core Results

185° F – Oligocene Aged Sandstone

t s c

11

Fluid Data

• Oil Properties

• Gravity

• Viscosity

• Formation Volume Factor

• Relative Permeability

• Water Properties

• Salinity

• Connate Water Saturation

• Hardness

• Relative Permeability

• Mobility Ratio

12

0.00

0.20

0.40

0.60

0.80

1.00

0 20 40 60 80 100

Water Saturation (% PV)

Rel

ativ

e Pe

rmea

bili

ty (

Frac

tio

n) Oil

Water

Typical Water-Oil Relative Permeability Characteristics

Strongly Water-Wet Rock

Strongly Oil-Wet Rock

0.00

0.20

0.40

0.60

0.80

1.00

0 20 40 60 80 100

Water Saturation (% PV)

Rel

ativ

e Pe

rmea

bili

ty (

Frac

tio

n) Oil

Water

13

Fractional Flow Curves

Strongly Water-Wet Rockμo = 1 cp, μw = 0.5 cp

Strongly Oil-Wet Rockμo = 1 cp, μw = 0.5 cp

1.00

0.8

0.6

0.4

0.2

00 20 40 60 80 100

Frac

tio

nal

Flo

w o

f W

ater

(fw

)

Water Saturation (%Pv)

1.00

0.8

0.6

0.4

0.2

00 20 40 60 80 100

Frac

tio

nal

Flo

w o

f W

ater

(fw

)

Water Saturation (%Pv)

14

Mobility Ratio (M)

• A ratio of the water mobility in the “water bank” to the oil mobility in the “oil bank”

• M = (Krw/μw) / (Kro / μo)

• Use end point relative permeability

WATER

Krw/µw

OIL

Kro/µo

Effect of Permeability Variation & M on Sweep Efficiency – WOR = 1.0

0

0.2

0.4

0.6

0.8

1.0

0.00 0.20 0.40 0.60 0.80 1.00

Oil Recovery

Per

mea

bilit

y V

aria

tion,

Kv

Primary & Secondary Performance

Primary Producing Mechanism

• Fluid Expansion

• Solution Gas Drive

• Oil Recovery % OOIP; 3-20%OOIP; Waterdrive ->30% OOIP

• Time Rate Production Curve

17

Primary Production

18

100

1000

10000

0.5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

BO

PD

Years

Primary Decline CurvesDecline 1 Decline 2 Decline 3

Total Field Production

100,000

10,000

1000

100

10

1

May

86

Aug

87

Dec

88

May

89

Aug

90

Sept

91

Jan

93

Month

ly P

roduction &

Conc

(mg/L

)

BWPM

BOPM

Primary & Secondary Performance

Secondary Recovery Performance

• Oil Response

• Water Breakthrough

• Oil Recovery % OOIP

• Injection Well Performance

• Production/Injection Issues

• Water Quality - scale, bacterial, etc.

• Production - fluid levels, total fluid changes

• Well Integrity

20

Waterflood Patterns

Two-Spot Three-Spot RegularFour-Spot

SkewedFour-Spot

Five-Spot

Seven-Spot InvertedSeven-Spot

InvertedNine-Spot

NormalNine-Spot

Direct LineDrive

StaggeredLine Drive

21

Total Field Production

100,000

10,000

1000

100

10

1Jan.

87

Month

ly P

roduction (

BB

LS

, C

on

c, m

g/L

)

Jan.

89

Jan.

91

Jan.

93

Jan.

95

Jan.

97

100

10

1

0.1

Input

/ O

utp

ut

Ratio

BOPM

BWPM

Input / Output

Water-Oil Production Case Study

100,000

10,000

1,00071 73 75 77 79 81 83 85 87 89

Oil

and

Wat

er P

rod

uct

ion Projected Start

Polymer Flood

Actual Start Polymer FloodEnd

Polymer Flood

EstimatedPolymer Flood

EstimatedWaterflood

Cumulative Oil Recovery vs. WOR

Cumulative Oil Recovery (Coverage “C”)

Pro

du

cin

g W

ater

-Oil

Rat

io

100.0

60.0

40.0

20.0

10.0

6.0

4.0

2.0

1.0

0.6

0.4

0.2

0.1

0.0 0.2 0.4 0.6 0.8 1.0

V = 0.80, M = 5V = 0.65, M = 5V = 0.50, M = 5

A’

B CA

B’

Hall Plot – Injection

Cumulative Water Injection (BBLS)

Cu

mu

lati

ve P

ress

ure

(P

SI x

Day

s/B

BL) “A”

“B”

B’

“C”

Typical Hall Slopes

Hall Plot Curve Shapes

800

0

Cumulative Injection (BBLS)

Cu

mu

lati

ve P

ress

ure

(p

si –

day

s)600

400

200

0

200 400 600 800 1000

Injectivity Loss Good

PartFormation

26

EOR Development

Address Issues Limiting Waterflood Recovery

• Water Issues

• Spacing

• Injectivity Limitations

• Sweep

• High Residual Oil Saturation

27

Waterflood Oil Recovery

NP = OOIP x ED x EAS X EVS

• NP: Waterflood oil recovery

• ED: Displacement efficiency

• EAS: Aerial sweep efficiency

• EVS: Vertical sweep efficiency

Water Quality

• Filter injection water

• Monitor, Monitor, Monitor!• Salinity changes

• Solids content

• Scale formation

• Corrosion

• Bacteria

Cambridge Field Pilot Test Results

Actual

A c tual

S im ulated

1989 1993 1997 2001 20051,000

10,000

100,000

1

Oil Productioni

His toryMatchPrimary

Forecas tS econdaryAS P F lood

Primary

Alkaline-S urfactant-Polymer F lood

30

EOR Development

Design EOR Process to Maximize Efficiency, Oil Recovery & Economics

• Waterflood Issues to Address

• Facility Design

• Personnel

31

Closing

To have a successful EOR Project, everything that is necessary for a successful waterflood is required with the integration of the EOR process in the reservoir coupled with proper surface facilities

32