Eubank Field (Kansas) - A Formation Evaluation and Secondary

Recovery Study

Dominique Dexheimer

Dr. Thomas A. BlasingameAssociate Professor/Assistant Department Head

Department of Petroleum EngineeringTexas A&M University

12 August 1999

2

Location of Eubank Field

ARIZONAARIZONA

UTAHUTAH

MISSISSIMISSISSIPPIPPI

OKLAHOMAOKLAHOMA

MISSOURIMISSOURI

ILLINOISILLINOIS

IOWAIOWANEBRASKANEBRASKA

WYOMINGWYOMING

COLORADOCOLORADO KANSASKANSAS

NEW MEXICONEW MEXICO

TEXASTEXASLOUISIANALOUISIANA

ARKANSASARKANSAS

Eubank Field

3

Issues to be Addressed* Primary recovery of old and new wells Remaining oil-in-place/movable oil Reservoir continuity/reservoir quality Waterflood feasibility

Reservoir heterogeneity issues Locations/patterns of water injection wells Interwell communication via fractures

* Terms of Reference—Anadarko Petroleum (April 1998)

4

Key Findings Oil-in-place (OIP)

Contacted: 13 million BBL Movable: 5 million BBL Remaining: 3 million BBL

Waterflood potential 3 independent regions: North, South, West The North region is best in terms of

remaining reserves and reservoir quality Locations/patterns of water injection wells

5

OIP Results

Moody A-3

Moody A-1

Gregg 2 OIP computed using

production data Radius of bubble proportional

to the value of the variable shown

Wells with no "bubble" indicate that no production data are available

Contacted OIP distribution North — 10 million BBL South — 3 million BBL West — 300,000 BBL

Permeability Barrier

Permeability Barrier

North Region

South Region

West Region

6

EUR/N computed using production data

Note uniformity of EUR/N trends (average of 24 %)

EUR/N Results

Permeability Barrier

Permeability Barrier

North Region

South Region

West Region

7

Waterflood Potential

Leslie 2-33Leslie 2-33

Doerksen A1-27Doerksen A1-27

Owens A-3Owens A-3

Leathers Land 1-10Leathers Land 1-10

Patterns developed using IQI, as well as natural flow barriers IQI=(kh)x(EUR/N)

Predict recovery of 2 to 3 million BBL by waterflood Almost certainly a low

estimate Repressuring will

increase recovery

(kh, EUR/N)kh, EUR/N)

Permeability Barrier

Permeability Barrier

(kh, EUR/N, location)

(kh, EUR/N, location)

(kh, EUR/N)

8

Follow-Up (Anadarko) Economics and Strategy

Must have Section 34 (T28S–R34W) Water source/water quality Assess risk involved in initiating and

operating a waterflood project in this area New data acquisition

Pressure transient tests Geochemistry: source rock, migration

Additional work Further geologic description of reservoirs Reservoir simulation

9

5 Cores 130 ft cored — Owens A-3 Sidewall core data not used

in correlations

53 Well logs 1 PVT sample (Owens A-2)

39 Pressure data 12 static bottomhole pressure

tests 20 drill stem tests 5 pressure buildup tests 2 other wireline tests

25 Wellbore diagrams Drilling/Completion histories Stimulation treatments

43 Well production records 30 wells — oil allocated

(2 wells had limited data) 10 wells — gas allocated 3 wells — unallocated

Data Inventory — 55 Wells

10

Reservoir Pressure History

400400

600600

800800

10001000

12001200

14001400

16001600

1960

1960

1197 00

1980

1990

2000

Test date

Pres

sure

, psi

a

South Eubank

Field

West Eubank

Field

Legend Drill Stem Test Static Bottomhole Pressure Pressure Buildup Test

Probable Data Trend for North Eubank Fieldand 95 % Confidence Interval

MooA-1

MooA-1Greg_3

MooA-3

Do1-27 Cl2-34Clw3-9

Ko1-28Ko2-28

Su1-28

Ko_A-4

Clw1A9

Su1-28Wr1-26

GregF6Clw1A9

OwnA-1RayC-2

Data Inventory

11

Production History — Oil and GasNorth Eubank Field

Data Inventory

00

11

22

33

44

5519

60

1970

1980

1990

2000

Time, Years

Np,

MM

BB

LG

p, b

scf

00

200200

400400

600600

800800

10001000

12001200

14001400

16001600

18001800

20002000

Pres

sure

, psi

aPr

essu

re, p

sia

No production given prior to 1970

LegendOil producedGas ProducedReservoir Pressure

Pressure Data Trend

2 New Wells

7 New Wells

8 New Wells

2 New Wells

2 New Wells2 New Wells

12

0.00.0

0.20.2

0.40.4

0.60.6

0.80.8

1.01.019

9619

96

1997

1997

1998

1998

Time, YearsTime, Years

00

200200

400400

600600

800800

10001000

12001200

14001400

16001600

18001800

Np,

MM

BB

L G

p, b

scf

Pres

sure

, psi

a

Data InventoryProduction History — Oil and Gas

South Eubank Field

Pressure Data Trend

10 New Wells

7 New Wells

LegendOil producedGas ProducedReservoir Pressure

Outlying pressure data: Clawson Well 3-34

13

Enabling Technologies/Data Core Data (Owens A-3)

Core-Well Log data correlations pc/kr correlations for effective permeability

Fluid Property Report (Owens A-2) Well log analysis (53 Wells)

Field cross-section maps Data used for well performance analysis

Decline type curve analysis (28 Wells) Mapping/correlation of results

14

Estimate rock and fluid properties Estimate contacted and movable OIP Estimate reservoir continuity

Horizontal flow capacity (koh) Horizontal/Vertical flow barriers

Evaluate conditions for waterflooding Reservoir pressure Completion interval/contacted reserves

Identify potential water injection wells

Specific Objectives of this Work

15

Petrophysics Distributions of rock properties Core/Well log prediction of permeability

Well Performance Analysis Distribution of computed variables Bubble map of OIP and EUR/N Correlation of volume and flow properties

Waterflood potential Bubble map of "Injection Quality Index"

Results of this Work

16

Geologic Description Based on literature and Anadarko work

Well Log Analysis (53 wells) Performed using Petra and SAS softwares

Oil Production Data Analysis (28 Wells) WPA software

Integration of Results Confirmed geologic flow model Recommendations for waterflood

Conclusions

Outline - Work Performed by Texas A&M

17

Incised Chester Sand(from 3D seismic structure map)

3 Producing intervals Average depth: 5,500 ft 55 wells drilled 40 years of production

Np, tot = 2.4 million BBL Gp, tot = 5.3 bscf

Light oil, sweet gas, water

100<h<300 ft

9 miles9 miles

700 ft

Geologic Description

18

Sand 3Sand 3

Shale 2Shale 2

Sand 2Sand 2

Shale 1Shale 1

Sand 1Sand 1

NotchNotch

MorrowMorrow

Geologic DescriptionSchematic of Deposition in a Paleovalley

St. LouisSt. Louis

Perforations

Perforations

Perforations

Inci

sed

Che

ster

San

dIn

cise

d C

hest

er S

and

19

Paleovalley Profile—Sample Cross-Section

5300

5400

5500

5600

Owens A-3 Owens A-1 Owens A-2 Owens A-4

St. Louis

Basal Basal Chester Chester

SandSand

Notch

MorrowSP ILD SP ILDSP ILDSP ILD

Well Log Analysis

20

Cluster Analysis (Owens A-3)

SPLog, mV

-200 -100 0

ILD Log, Ohm-m

5300

5400

5500

5600

0 10 20 30 40 50

Cluster Log, no units

0 1 2 3 4 5

Reservoirsection is

represented by "Cluster" 4

Well Log Analysis

21

Porosity Distribution (from Well Logs)

0123456789

101112131415

0.05 0.06 0.07 0.08 0.09 0.1 0.11 0.12 0.13 0.14 0.15 0.16

Per-Well Average Porosity, , fraction

Freq

uenc

y

Average Porosity

Porosity Distribution Function

Porosity Statistics mean = 0.105 (fraction) std dev = 0.022

Well Log Analysis

22

Volume of Shale Distribution (from Well Logs)

Well Log Analysis

Per-Well Average Volume of Shale, VSH , fraction

0

2

4

6

8

10

12

14

16

0 0.04 0.08 0.12 0.16 0.2 0.24

Average Volume of Shale

Volume of Shale Distribution Function

Volume of Shale Statistics:mean = 0.082 (fraction)

std dev = 0.060

Freq

uenc

y

23

Net Pay Distribution (from Well Logs)

Well Log Analysis

0

2

4

6

8

10

12

14

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95

Freq

uenc

y

Per-Well Net Pay, h , ft

Per-well Net Pay

Net Pay Distribution Function

Net Pay Statistics:mean = 20.00 ftstd dev = 21.83 ft

24

Core Porosity—Core Permeability Relationship(Owens A-3)

k = 0.2777exp(37.75) R2= 0.82

Core Porosity, , fraction

Cor

e P

erm

eabi

lity,

k, m

d

104

0.00 0.05 0.10 0.15 0.20 0.25

Data Trend and 95 %

confidence interval

103

102

101

100

10 -1

Well Log Analysis

25

Core Permeability-Well Log Data Correlation

kobsobs

kkcalcal

Legend

Tried several models 3 to 5 well log variables

SP, GR ILD NPHI, DPHI, PHIDN

Owens A-353805380

54005400

54205420

54405440

54605460

54805480

55005500

55205520

554055401010-1 10100 10101 10102 10103

Permeability, md

True

Ver

tical

Dep

th, f

t

Valid for 10<k<200 md 4 variables (GR, ILD, NPHI, DPHI) Stable predictor for 45 cases

"Best" permeability model

Well Log Analysis

26

Well Performance Analysis Data Required:

Time, pressure, rate (TPR) data Initial reservoir pressure Reservoir and fluid properties

How used: Data edit plot (remove off-trend values) Decline type curve match EUR plot

Results: Flow parameters (kh, s, xf) Volumetric parameters (N, A)

27

Well Performance Analysis Production Data Plot (Moody A-3)

Reservoir Pressure Reservoir Pressure 1000 psia (1986)1000 psia (1986)

1985

1988

1991

1994

1997

GasGas

OilOil

WaterWater

Production Time, Years

Flow

Rat

es, B

BL/

D, M

scf/D

103

102

101

100

28

Well Performance Analysis

10-2

10-1

100

102 103 104 105

Np/qo, Days

q o/

p, B

BL/

D/p

sia

"Data Edit" Plot Moody A- 3

Only oil cases are relevant for this field

"Data Edit" Plot used to Remove Off-Trend Data

29

"WPA" Plot (Used to Perform Type Curve Analysis)Moody A-3

Well Performance Analysis

qDd

qDdi

qDdid

10-2

10-1

100

101

-3 10-2 10-1 100 101 10210

Dim

ensi

onle

ss R

ate

Func

tions

(qD

d, q D

di, q

Ddi

d)

Dimensionless Material Balance Time, tDd, days

800

16080 48 28 18 12 7 4

4712

1218

80160

1x104

47

2848

800

30

Estimated Ultimate Recovery (EUR) Plot Moody A-3

Well Performance Analysis

Estimated Primary Movable Oil:520,000 BBL

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0 100,000 200,000 300,000 400,000 500,000 600,000

Np, BBL

q/p

, BB

L/D

/psi

a

31

Well Performance Analysis Production Data Plot

Owens A-219

96

1997

1998

Flow

rate

s, B

BL/

D, M

scf/D

Production Time, Months

Reservoir Pressure Reservoir Pressure 770 psia (1995)770 psia (1995)GasGas

OilOil

103

102

101

100

32

Well Performance Analysis

10-2

100

Np/q, Days

q/p

, BB

L/D

/psi

a

101 102 103 104

10-1

"Data Edit" Plot Owens A-2

A unique trend is identified on the plot

Approach tolerates incomplete data

33

"WPA" Plot (Used to Perform Type Curve Analysis)Owens A-2

Well Performance Analysis

qDd

qDdi

qDdid

10-2

10-1

100

101

-3 10-2 10-1 100 101 10210

Dim

ensi

onle

ss R

ate

Func

tions

(qD

d, q D

di, q

Ddi

d)

Dimensionless Total Material Balance Time, tDd, days

800

16080 48 28 18 12 7 4

4712

1218

80160

1x104

47

2848

800

34

Estimated Ultimate Recovery (EUR) Plot Owens A-2

Well Performance Analysis

Estimated Primary Movable Oil :51,500 BBL

0.000

0.050

0.100

0.150

0.200

0.250

0 10,000 20,000 30,000 40,000 50,000 60,000

Np, BBL

q/p

, BB

L/D

/psi

a

35

Well Performance Analysis

0

1

2

3

4

5

6

7

8

9

-7 -6 -5 -4 -3 -2 -1 0 1 2Skin Factor, s, Dimensionless

Freq

uenc

y

Skin Factor DataSkin Factor Distribution Function

Skin Factor Statistics:Mean = -2.5Std. Dev. = 1.4

Skin Factor Distribution(from Well Performance Analysis)

36

Well Performance AnalysisFlow Capacity (koh) Distribution

(from Well Performance Analysis)

0

1

2

3

4

5

6

7

0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 400

koh Datakoh Distribution Function

koh distribution Statistics:Mean = 50 md-ft

Flow Capacity, koh, md-ft

Freq

uenc

y

37

Well Performance Analysis

0

1

2

3

4

5

6

7

81.

0

1.5

2.1

3.1

4.5

6.6

9.7

14.1

20.6

30.1

44.0

64.3

93.8

137.

0

200.

0

Fracture Half-Length DataFracture Half-Length Distribution Function

Fracture Half-Length Statistics:Mean = 26 ft

Fracture Half Length, xf, ft

Freq

uenc

yFracture Half-Length Distribution

(from Well Performance Analysis)

38

Integration of Results: Outline Petrophysical Data

Geologic structure and continuity Prediction of effective permeability

Well Performance Analysis Pressure history (used to initialize analysis) Correlation of koh and N (consistency) Correlation of EUR and N (primary recovery)

Evaluation for Waterflood Injection criteria (reservoir properties) Locations of candidate wells for injection

39

3 independent regions North, main region South and dry Southeast

tributary West, minor region

Origin of permeability barriers Depositional sequences Block faulting Morphology of channel Fluid migration

Geologic Structure/ContinuityIntegration of Results

Permeability Barrier

Permeability Barrier

North Region

South Region

West Region

40

Comparison of Effective PermeabilitiesIntegration of Results

LTHA-3RAYC-2

RAYC-4MURD-4

KO_A-4 DO1-27TILA-1OWNA-1TILA-2COLA-3GREGF6

LS2-33OWNA-4

LTHA-2MURD-3

koh (Production Data Analysis), md-ft

k oh

(Cor

e-W

ell L

ogs

Cor

rela

tion)

, md-

ft

Data trend?

10100 10101 10102 1010310100

10101

10102

10103

Additional Input for koh from well log correlation: Capillary pressure data Gas-Oil ratio (3 month avg.)

Comparison on available data (15 Wells) Reasonable agreement Divergence due to different

depths of investigation Data shift by a factor of 10

41

Integration of Results

Moody A-3

Moody A-1

Gregg 2

Contacted OIP distribution North — 10 million BBL South — 3 million BBL West — 300,000 BBL

Remaining movable oil North — 2 million BBL South — 625,000 BBL West — 50,000 BBL

3 major wells (Np) Moody A-1 — 235,000 BBL Moody A-3 — 370,000 BBL Gregg 2 — 235,000

BBL

Permeability Barrier

Permeability Barrier

North Region

South Region

West Region

42

Reservoir Pressure History

400400

600600

800800

10001000

12001200

14001400

16001600

1960

1960

1197 00

1980

1990

2000

Test date

Pres

sure

, psi

a

South Eubank

Field

West Eubank

Field

Legend Drill Stem Tests Static Bottom Hole Pressure Pressure Buildup Tests

Probable Data Trend for North Eubank Fieldand 95 % Confidence Interval

MooA-1

MooA-1Greg_3

MooA-3

Do1-27 Cl2-34Clw3-9

Ko1-28Ko2-28

Su1-28

Ko_A-4

Clw1A9

Su1-28Wr1-26

GregF6Clw1A9

OwnA-1RayC-2

Integration of Results

43

KO_A-4

GREGF6

1995TILA-2

OWNA-31990

LS1-33

COLA-3

1996

DO1-27

GREG_2

19591996

1996

1996

LS2-33

1996

LTHA-2

1996

LTHA-3

1996MOOA-1

1961MOOA-3

1985

MU1-34

1985

MURD-3

1997

MURD-4

1997

OWNA-1

1995

OWNA-2

1995 1995

OWNA-4

1996RAYC-2

1996

RAYC-3

1996

RAYC-4

1996

RAYC-5

1996

RMRC-1

1964

RMRC-2

1964

SU2-28

1997

TILA-1

1995

WR1-26

1991

103

Contacted Oil-in-Place, N, STB

Flow

Cap

acity

, koh

, md-

ft

Legend North Eubank Field West Eubank Field South Eubank Field

kh 5 10-5N

kh 6 10-4N

Note Format:

Well Code

Completion Date

Incomplete Data

"Old Wells"

"New Wells"

Integration of Results The range of kh-values is

uniform, but the spread of N-values has a disconti-nuity caused by differen-tial depletion

Differential depletion is accentuated by pressure declining well below the bubblepoint pressure

The difference between estimated volumes of contacted oil (new and old wells) suggests significant waterflood potential

Flow Capacity (kh) versus Contacted Oil-in-Place, N

102

101

100

107106105104

44

COLA-3SU2-28

RAYC-4

Integration of Results Excellent agreement in

the computed N and EUR-values

Primary recovery of 24 percent (average for the entire field)

Note that the "old" wells clearly have higher N and EUR—which also vali-dates the "differential depletion" concept

Contacted Oil-in-Place (N) versusEstimated Ultimate Recovery (EUR)

OWNA-2

GREG_2MOOA-3

1959

1996MU1-341996

TILA-1TILA-2

1996

1996

DO1-27

1990

GREGF6

1996

KO_A-4

1996

LS1-33

1996

LS2-33

LTHA-2

1996

LTHA-3

1996

MOOA-1

1961

1985

1985

MURD-3

1997

MURD-4

1997

OWNA-1

19951995

OWNA-3

1995

OWNA-4

RAYC-2

1996

RAYC-3

1996

1996

RAYC-5

RMRC-1

1964

RMRC-2

1964

1997

19951995

WR1-26

1991

Estimated Ultimate Recovery, EUR, STB

Con

tact

ed O

il-in

-Pla

ce,

Con

tact

ed O

il-in

-Pla

ce, N

, STB

, S

TB Legend

North Eubank Field West Eubank Field South Eubank Field

Incomplete Data

"New Wells"

"Old Wells"

NN = 4.2 = 4.2 EUREUR

Note Format:Well Code

Completion Date

106105104103

107

106

105

104

45

Injection Well CriteriaIntegration of Results

OWNA-1

North Region

RAYC-4RAYC-5

DO1-27MOOA-3OWNA-2

OWNA-4

WR1-26

RAYC-2OWNA-3

COLA-3

TILA-2

TILA-1

GREG_2

MOOA-1

RAYC-3

RMRC-1

RMRC-2

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

Flow capacity, koh, md-ft

EUR

/N, f

ract

ion

103102101100

Potential injectors must simultaneously maximize Access to flow capacity, koh Primary recovery, EUR/N

Candidates appear on the top right corner of the plot

Criteria to be combined with well locations taken from field maps

46

Injection Well CriteriaIntegration of Results South and west regions

have fewer injection wells based on reservoir quality and movable oil

Alternative injection well locations (green oval) are taken from field maps and the IQI criteria

South and West Regions

KO_A-4

GREGF6

MURD-3

LS2-33

LTHA-2

MURD-4

LTHA-3

SU2-28

LS1-33MU1-34

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

Flow capacity, koh, md-ft

EUR

/N, f

ract

ion

103102101100

47

Integration of Results

Leslie 2-33Leslie 2-33

Doerksen A1-27Doerksen A1-27

Owens A-3Owens A-3

Leathers Land 1-10Leathers Land 1-10

Patterns developed using IQI, as well as natural flow barriers

Predict recovery of 2 to 3 million BBL by waterflood—from Anadarko study (esti-mate of total recovery)

Flow barriers are well-defined by pressure data

Repressuring should increase recovery

(kh, EUR/N)kh, EUR/N)

Permeability Barrier

Permeability Barrier

(kh, EUR/N, location)

(kh, EUR/N, location)

(kh, EUR/N)

48

Integration of Results: Closure Injection Quality Index, khEUR/N

Limited to available well performance data Criteria focuses on flow capacity (koh), as well as

regions that were well swept (high EUR/N) Criteria provides optimal sweep of oil to production

wells Well completions

Efficiency of hydraulic fracture is an issue Interwell communication (fractures, high k zones)

49

Conclusions Well log analysis provides comprehensive

description of the reservoir Porosity, shale content, net pay Approach of core-log permeability correlation

Type curve analysis is a robust tool Volumetric estimates Flow parameters

Waterflood potential based on IQI criteria Injectors location/pattern Sweep efficiency

50

Conclusions Three independent regions (contacted OIP)

North — 75 % of the field reserves (10 MM BBL) South — 23 % of the field reserves (3 MM BBL) West — 2 % of the field reserves (300,000 BBL)

Target OIP is 5 million BBL Primary — 3 MM BBL (24 percent) Secondary — 2 MM BBL (16 percent)

51

Follow-Up (Anadarko) Economics and Strategy

Must have Section 34 (T28S–R34W) Water source/water quality Risk assessment must be performed

New data acquisition Pressure transient tests Geochemistry: source rock, migration

Additional work Further geologic description of reservoirs Reservoir simulation

52

53

Stratigraphic Timetable — Southwest Kansas

Age(Ma)

Depth(ft) System Series Stratigraphic Unit Show

245 2400

Permian Wolfcampian

Chase Group

(Hugoton Field Reservoir)

Wabaunsee Shawnee Virgilian

Lansing Group Missourian

Marmaton Group Desmoinesian

Atokan Atokan Group

290 2700

Pennsyl-vanian

Morrowan Morrow Group 310 5300

Chesterian

Chester Group(Eubank Field

Reservoir)

Sainte Genevieve Saint LouisMeramecian

335 5500

360 5700

Missi-

ssippian

Geologic Description

54

Well Log AnalysisWater Saturation Distribution

(from Well Logs)

0

2

4

6

8

10

12

0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75

Per-Well Average Water Saturation, Sw , fraction

Freq

uenc

y

Average Water Saturation

Water Saturation Distribution Function

Water Saturation Statistics:Mean = 0.367 (fraction)Std dev = 0.116

55

Net Pay Distribution (from Well Logs)

0

1

2

3

4

5

6

6 7 9 11 14 17 20 25 30 37 45 55 67 82 100

Per-Well Net Pay, h , ft

Freq

uenc

y

Per-well Net Pay

Net Pay Distribution Function

Net Pay Statistics:mean = 20.00 ftstd dev = 21.83 ft

Well Log Analysis

56

Volume of Shale Distribution (from Well Logs)

0

1

2

3

4

5

6

7

8

9

0.010 0.014 0.020 0.029 0.042 0.060 0.085 0.122 0.175 0.250

Per-Well Average Volume of Shale, VSH , fraction

Freq

uenc

y

Average Volume of Shale

Volume of Shale Distribution Function

Volume of Shale Statistics:mean = 0.082 (fraction)std dev = 0.060

Well Log Analysis

57

Well Performance AnalysisFlow Capacity (koh) Distribution

(from Well Performance Analysis)

0

1

2

3

4

5

6

7

8

1 2 4 7 14 28 54 106 206 400 800

koh distribution Statistics:Mean = 50 md-ft

Flow Capacity, koh, md-ft

Freq

uenc

y

koh Datakoh Distribution Function

58

Core Permeability-Well Log

Data Correlation

Owens Well A-3

53805380

54005400

54205420

54405440

54605460

54805480

55005500

55205520

55405540

Permeability, md

True

Ver

tical

Dep

th, f

t

kkobsobs

kkcal_3cal_3

kkcal_2cal_2

kkcal_1cal_1

LegendLegend

Geologic Description

1010-1 10100 10101 10102 10103

Best three models 3 to 5 well log variables

SP, GR ILD NPHI, DPHI, PHIDN

Various bounds tested No bounds kobs > 0.5 md 10 md < kobs < 200 md

Accuracy varies little in the reservoir rock, a lot more in the shaly zones

59

Flow Capacity versus Initial GOR

OWNA-1OWNA-4

WR1-26

COLA-3

MOOA-1

LS1-33GREGF6

OWNA-3

LTHA-3KO_A-4MOOA-3

MURD-4

LS2-33

LTHA-2

MURD-3

TILA-2TILA-1

DO1-27

MU1-34

RAYC-2

RAYC-4

Initial Gas-Oil Ratio, scf/STB(3 month average)

k oh

from

Pro

duct

ion

Dat

a A

naly

sis,

md-

ftProbable data trends forEubank Field, main area

SouthSouthRegionRegion

Probable datatrends for Owensand Ray Wells

10102 10103 10104 10105

10100

10101

10102

10103

Reasonable agreement of koh and GOR values High GOR corresponds to

low permeability to oil Trend for main area

Deviant data trends Owens and Ray Wells may

have a secondary gas cap South Eubank Field has

much more scatter

Integration of Results