use of geology and petrophysics in the characterization of

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Use of Geology and Petrophysics in the Characterization of St. Use of Geology and Petrophysics in the Characterization of St.

Peter Sandstone Reservoirs Peter Sandstone Reservoirs

Rusli Bin Adam

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USE OF GEOLOGY AND PETROPHYSICS IN THE CHARACTERIZATION OF ST. PETER SANDSTONE RESERVOIRS

by

Rusli Bin Adam

A Thesis Submitted to the

Faculty of The Graduate College in partial fulfillment of the

requirements for the Degree of Master of Science

Department of Geology

Western Michigan University Kalamazoo, Michigan

December 1992

Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

USE OF GEOLOGY AND PETROPHYSICS IN THE CHARACTERIZATION OF ST. PETER SANDSTONE RESERVOIRS

Rusli Bin Adam, M.S.

Western Michigan University, 1992

Core samples and petrophysical data from three reservoir intervals within the

Middle Ordovician St. Peter Sandstone in the Michigan basin were utilized to assess

the reservoir performance. Each reservoir interval coincides with major sedimentary

facies which are in gradational contact with one another vertically and laterally

throughout the basin. Reservoirs in the lower portions of the formation (reservoir

type 1) are dominated by meso-intercrystalline porosity. This predominantly quartz

cemented reservoir rock type is characterized by low porosity with high permeability,

moderate pore apertures, and moderate irreducible water saturation. Reservoirs at the

top of the formation (reservoir type 3) are dominated by clay-rich, well sorted, fine-

to medium-grained sandstone. The abundance of micropores with small pore

apertures is responsible for the typically moderate porosity, low permeability, and

high irreducible water saturation. Reservoirs below reservoir type 3 (reservoir type

2) consist of well sorted, uncemented, medium-grained sandstone. Macro

intergranular pores with macro pore throats produce relatively high porosity and

permeability, and low irreducible water saturation.


ACKNOWLEDGEMENTS

I w ish to express special acknow ledgem ent and sincere

appreciation to my advisor and committee chairman, Dr. David A.

Barnes, for his insight and guidance throughout the course of my study.

I would like also to acknowledge my other thesis committee members,

Dr. William B. Harrison III and Dr. John D. Grace, for their critical

reviews of the manuscript. Appreciation is also extended to my

colleagues at WMU Core Research Laboratory for their assistance.

I would like to appreciate and thank rny parents, Adam Haji Abas

and Sharifah Abdul Rahman, for their love and support, and Public

Service Departm ent of M alaysia for its sponsorship program that

enabled me to pursue my study. Lastly, I would like to thank Almighty

God (Allah), the Most Compassionate Most Merciful, for His enormous

bounty.

Rusli Bin Adam


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U se of geology and petrophysics in the characterization of St. Peter Sandstone reservoirs

Adam, Rusli Bin, M.S.

W e s t e r n M ic h ig a n U n iv e r s i t y , 1 9 9 2

U M I300 N. Zeeb Rd.Ann Arbor, MI 48106


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TABLE OF CONTENTS

ACKNOWLEDGEMENTS......................................................................................... ii

LIST OF TABLES.................................................................................................... vii

LIST OF FIGURES.................................................................................................... viii

INTRODUCTION...................................................................................................... 1

Production H istory...................................................................................... 1

Purpose of Study......................................................................................... 2

Methods of Study........................................................................................ 2

GEOLOGIC FRAMEWORK FOR THE ST. PETER SANDSTONE....................... 8

Regional Geology.......................................................................................... 8

Stratigraphy....................................................................................................... 1 2

Structural Studies.............................................................................................. 1 5

Depositional Environment............................................................................... 1 7

Petrologic Studies........................................................................................ 19

PORE CLASSIFICATION TECHNIQUES AND PETROPHYSICS..................... 2 1

Pore Classification....................................................................................... 2 1

P e tro p h y sic s ................................................................................................. 26

P orosity ................................................................................................. 2 6

P e rm eab ility ........................................................................................ 27

Relative Perm eability....................................................................... 2 8


Table of Contents— Continued

Internal Surface Area....................................................................... 28

W ettab ility ........................................................................................... 28

Capillarity and Irreducible Saturation....................................... 29

Breakthrough Pressure.................................................................... 3 1

Hydrocarbon Column and Water Saturation.................................. 3 3

DESCRIPTION OF RESERVOIR ROCK SAMPLES.............................................. 3 6

Anger 1-20 Upper Cores (Reservoir Type 3 ) ........................... 3 6

Sample Description........................................................................... 3 6

In te rp re ta tio n ..................................................................................... 42

Patrick & St. Norwich 2-28 Cores (Reservoir Type 2).................... 43

Sample Description............................................................................ 43

In te rp re ta tio n ..................................................................................... 47

Anger 1-20 Lower Cores (Reservoir Type 1)............................ 48

Sample Description........................................................................... 48

In te rp re ta tio n ..................................................................................... 5 1

PORE TYPES WITHIN THE ST. PETER SANDSTONE RESERVOIRS 5 2

Porosity in Quartz Cemented Sandstone: Pore Type 1................... 5 2

Porosity in Uncemented Sandstone: Pore Type 2 ........................... 57

Porosity in Argillaceous Sandstone: Pore Type 3................................ 5 9

Port Size............................................................................................................ 6 4

Port Size in Reservoir Type 1............................................................... 64

iv


Table o f Contents— Continued

Port Size in Reservoir Type 2............................................................... 6 8

Port Size in Reservoir Type 3............................................................... 69

PETROPHYSICS OF THE ST. PETER SANDSTONE RESERVOIRS..................... 7 0

Porosity................................................................................................................ 7 0

Permeability and Relative Permeability............................................. 72

Internal Surface Area.......................................................................................... 7 3

W ettab ility ....................................................................................................... 74

Breakthrough Pressure................................................................................ 74

CAPILLARITY PROFILES AND HYDROCARBON COLUMN HEIGHT 7 6

Capillary Profiles............................................................................................ 7 6

Capillarity Profile of Reservoir Type 1................................................ 7 6



Hydrocarbon Column Height............................................................................. 8 1

Hydrocarbon Column in Reservoir Type 1 ....................... 8 1

Hydrocarbon Column in Reservoir Type 2 ...................... 8 3

Hydrocarbon Column in Reservoir Type 3 ...................... 8 5

SUMMARY AND CONCLUSIONS 8 6

APPENDICES

A. All Time Oil and Natural Gas Production inMichigan "Deep" Play.................................................................................... 92

B. Core Descriptions............................................................................................ 97

v


Table of Contents— Continued

APPENDICES

C Point Count Data............................................................................................... 104

D. Core Analysis, Port Size, and Buckles Number Data....................... 115

BIBLIOGRAPHY...................................................................................................... 123

vi


LIST OF TABLES

1. Consolidation Classification for Silicate-Rich Clastic Rocks............... 37

2. Statistics for Port Size....................................................................................... 6 7

3. Statistics for Porosity.................................................................................. 71

4. Statistics for Permeability......................................................................... 7 3

5. Statistics for Buckles Number......................................................................... 87

vii


LIST OF FIGURES

1. Stratigraphic Location of Reservoir Samples Used in the Study... 4

2. A Type Mercury Injection Capillary Pressure Curve and ItsImportant Components....................................................................................... 6

3. Generalized Isopach Map of the St. Peter Sandstone in the North American Midcontinent and the AssociatedPaleozoic Structural Features 1 0

4. Generalized Lower Paleozoic Stratigraphic Column for theMichigan Basin 1 1

5. Cycles of Sedimentation in Upper Midwest During Paleozoic 13

6. Lithology and Wireline Log Response of the Middle Ordovician Sandstone and Associated Strata in a Key Well From theCentral Michigan Basin................................................................................ 14

7. Stratigraphic Nomenclature and Correlations for the Lower andMiddle Ordovician in the Michigan Basin.............................................. 1 6

8. General Characteristics of Major Lithofacies in the St. PeterSandstone, Michigan Basin......................................................................... 18

9. Generalized Paragenetic Sequence of the St. Peter Sandstonein the Michigan Basin.................................................................................. 20

10. Pore Type Classification.................................................................................... 22

11. Interpretation of Pore and Rock Types Using Porosity-Perm eability C rossplot.............................................................. 24

12. Illustration of Pore-to-throat Size Ratio and CoordinationNumber and Their Effects on Recovery Efficiency.............................. 25

13. Relationship Between Capillarity, Saturation Profile, andPore Size............................................................................................................. 3 0

viii


List of Figures— Continued

14. Breakthrough Pressure Determination From Mercury Injection Capillary Pressure Curve............................................................................ 3 2

15. Hydrocarbon Column................................................................................... 34

16. Photographs of Sandstone Samples From Anger 1-20Upper Cores......................................................................................................... 3 8

17. Quartz-Feldspar-Lithic (Q-F-L) Ternary Plots for Anger 1-20Upper Cores......................................................................................................... 40

18. Photographs of Sandstone Samples From Patrick & St. Norwich2-28 W ell......................................................................................................... 43

19. Quartz-Feldspar-Lithic (Q-F-L) Ternary Plots for Patrick &St. Norwich 2-28 Cores................................................................................ 45

20. Photographs of Sandstone Samples From Anger 1-20Lower Cores.................................................................................................... 4 8

21. Quartz-Feldspar-Lithic (Q-F-L) Ternary Plots for Anger 1-20 Lower Cores..................................................................................................... 49

22. Photomicrographs of Quartz Cemented Sandstone............................ 5 2

23. Scanning Electron Micrographs of Quartz Cemented Sandstone.... 5 3

24. Interpretation of Rock and Pore Types of the St. Peter Sandstone Reservoirs Using Porosity-Permeability Crossplot............................ 54

25. Schematic Representation of the Generalized Paragenesis ofModel Pore Types Within the St. Peter Sandstone Reservoirs 5 5

26. Scanning Electron Micrographs of Uncemented Sandstone............... 5 7

27. Photomicrographs of Uncemented Sandstone.................................... 5 9

28. Photomicrograph of Clay-Rich Sandstone.................................................... 60

29. Scanning Electron Micrograph of Clay-Rich (Argillaceous)Sandstone 6 1

ix


List of Figures— Continued

30. Graphic Solution of Winland's Equation Plotted on Porosity- Permeability Crossplot for Determination of Port Sizes................... 64

31. Mercury Injection Capillary Pressure Curve of QuartzCemented Sandstone (Anger 1-20 8991’) ............................................ 7 6

32. Mercury Injection Capillary Pressure Curve of Uncemented Sandstone (Patrick & St. Norwich 2-28 7943’)......................................... 77

33. Mercury Injection Capillary Pressure Curve of Clay-RichSandstone (Anger 1-20 8651’)......................................................................... 79

34. Relationship Between Water Saturation, Port Size, and theHeight of Hydrocarbon Column Above Free Water Level.................. 8 1

35. Buckles Plot for Patrick & St. Norwich 2-28 Cores........................... 87

36. Buckles Plot for Anger 1-20 Upper Cores............................................ 8 8

37. Buckles Plot for Anger 1-20 Lower Cores............................................ 89

x


INTRODUCTION

Production History

Hydrocarbon production in the Lower Ordovician St. Peter Sandstone of the

Michigan basin was established in 1981 with the discovery of natural gas in JEM-

Edward 7-36 well in Missaukee County. Since then, numerous producing wells were

discovered and the formation has become one of the most prolific hydrocarbon plays

in the basin. Within the industry, activities on the St. Peter Sandstone and deeper

formations is often called the "deep" play. The success of the deep play is revealed

by dramatic increase in the number of producing wells in recent years. As of

November 30, 1990 the total of 104 wells in 16 counties have been put into

production, with the cumulative total production of 142,771,355 Mcf natural gas and

1,215,028 barrels oil (Appendix A).

Hydrocarbon production in the Edwards 7-36 and Gilde 1-25 wells of

Falmouth field, Missaukee County, Michigan, are examples of reservoirs in the upper

portions of the St. Peter Sandstone. Efforts however continue to explore intervals

deeper in the formation. As a result, several other producing horizons were later

recognized. The discovery of natural gas and condensate in the Jansma 1-29 well in

1985 and the Patrick & St. Norwich 2-28 well in 1986 of Woodville field, Newaygo

1


County, proved that hydrocarbon production is not limited to the zones at the top of

formation. Subsequently, production was recognized in several other units in the St.

Peter Sandstone, such as in "Ruwe Gulf zone" of the Reed City field in Osceola

County.

Purpose of Study*

The objective of this study is to characterize a limited number of reservoir

rock types in the St. Peter Sandstone and interpret the geological controls on their

petrophysical attributes. The intent is to formulate a model for reservoir performance

based on recognition of different reservoir types which result from the sum of

geologic processes. Recognition of pore-scale geological and petrophysical

parameters of each reservoir type is emphasized in this study as opposed to a facies-

scale framework. The pore-scale parameters can be integrated with facies-scale

parameters such as structural and stratigraphic settings to allow the better appraisal

of reservoir quality and for the establishment of minimum characteristics required for

economic production in any zone in the formation.

Methods of Study

Representative cores from producing reservoir intervals in the St. Peter

Sandstone used in the study are from the Anger 1-20 well in Mecosta County and the

Patrick & St. Norwich 2-28 well in Newaygo County. Anger 1-20 upper cores (set


#C-1, 8603’ to 8660’ depth) were chosen to represent the reservoir types at the top

of formation, or reservoir type 3 (RT3). Cores from Patrick & St. Norwich 2-28

well (set //C-l and ttC-2, 7923’ to 8004’ depth) represent reservoir type 2 (RT2); the

reservoir interval stratigraphically below reservoir type 3. Anger 1-20 lower cores

(set ttC-2, 8979’ to 9023’ depth) represent a reservoir type in the lower portions of

the formation, or reservoir type 1 (RT1). Stratigraphic location of each reservoir

interval is shown in Figure 1. This subdivision of reservoir intervals correlates with

Lundgren’s (1991) major lithofacies (Figure 7) in the St. Peter Sandstone.

Methods used in this study include core description, standard petrographic and

scanning electron microscope analysis, and mercury injection capillary pressure curve

analysis. Conventional sample examination techniques were used in core description

but with special emphasis on the assessment of the reservoir quality. The cores were

examined based on their lithologic character, textural features, sedimentary structures,

consolidation, and amount and type of visible porosity (Appendix B). Reservoir

quality can be estimated based on the estimation of grain size and sorting, amount of

visible pores, degree of rock consolidation, and the presence of cements and pore-

filling materials (Sneider and King, 1984).

More than 100 thin sections and 10 samples for scanning electron microscope

(SEM) analysis were prepared from each set of cores. The thin sections were stained

with sodium cobaltinitrate for potassium feldspar identification and with alizarin red-S

and potassium ferricyanide solutions for


4

B

PATRICK & ST. NORWICH 2-28

WOLVERINE ANGER 1-20

HUNTMARTIN 1-15

o> ,30l° perck l50lu mGlenwoodFormation7800 Tsp8600RT3.

RT2St. Peter8000Sandstone 8800

8200 11600'RT1 9000

118!Prairie du Chien Group

12000

^ = Cored IntervalTpdc

SCALE

^ I 7 To°

Figure 1. Stratigraphic Location of Reservoir Samples Used in the Study.RT1 = Reservoir Type 1, RT2 = Reservoir Type 2, and RT3 = Reservoir Type 3. Hunt Martin 1-15 well is the reference well used by Lundgren (1991).


5

carbonate species identification. For pore type recognition, the thin sections were

impregnated with blue epoxy. The three dimensional shape of pores can be more

accurately recognized using the SEM. The high magnification and exceptional depth

of field of the SEM technique allows the three dimensional shape of the pores to be

viewed and analyzed.

Pertinent core analysis data such as porosity and permeability measurements

corresponding to the cores were supplied by Wolverine Oil & Gas Company (see

Appendix D). Other important petrophysical parameters such as wettability,

irreducible saturation, capillarity, breakthrough pressure, hydrocarbon column height

were interpreted from the core analysis data and mercury injection capillary pressure

curves. Mercury injection capillary pressure techniques, widely used within

petroleum industry, were obtained by injecting mercury under elevated pressure into

sample plugs to produce a plot of injection pressure versus percentage of mercury

saturation (Figure 2; Jennings, 1987). The resulting curve provides valuable aids for

quantitative assessment of reservoir properties from parameters such as entry pressure,

plateau, displacement pressure, and irreducible saturation.

Overall quality of each reservoir rock type at pore-scale can be estimated from

Buckles plot (Figures 35, 36, and 37). Buckles, or bulk volume water, plot is the

plot of water saturation against porosity (Hartmann, 1988). The quality of the

reservoir sample is indicated by the Buckles number and the estimated pore throat

size. If a reservoir sample has high Buckles number, the


6Irreducible Saturation, %

100400.052000

Irreducible Saturation, Swi O.IO1000

0.25 on

w.

0.5

100eoo0J Displacement

Pressure, Pd3.0

Port Sue5.0

EntryPressure, Pe

100Mercury Saturation, %

Figure 2. A Type Mercury Injection Capillary Pressure Curve and Its Important Components (Modified From Jennings, 1987).


Upp

er

Mac

ro

I M

acro

M

cso

I M

icro

product of porosity and water saturation, and relatively large pore

throat, it has excellent reservoir quality.


GEOLOGIC FRAMEWORK FOR THE ST. PETER SANDSTONE

An understanding of the geologic framework of any petroleum reservoir is

most effective in understanding the nature and quality of the reservoir (e.g., Johnson

and Steward, 1987). When thorough understanding of geologic parameters is

established, the maximum exploitation of the reservoir can be achieved. Thus, efforts

continue to reconstruct an appropriate geologic model for the St. Peter Sandstone in

the Michigan basin. A number of studies on Ordovician formations have lead to

establishment of the following framework for the St. Peter Sandstone in the basin.

Regional Geology

The St. Peter Sandstone crops out throughout much of the upper Midwest and

was expected to be present in the Michigan basin by several workers (e.g., Brady and

DeHaas, 1988; Fisher, Barratt, Droste, and Shaver, 1988; and Lilienthal, 1978).

Others believed the St. Peter Sandstone to be missing in the Michigan basin or present

only as karstic depression (e.g., Bricker, Milstein, and Reszka, 1983; Catacosinos,

1972).

Massive quartz sandstone was first encountered in Michigan in the Charley E.

Moe No. 1 well in Ottawa County in 1930, but there was no convincing evidence at

that time to prove that the sandstone was the continuation of the famous cratonic sheet

8


sandstone. The first modern deep test of this massive sandstone formation was made

in 1964 in the Brazos State Foster 1-20 well in Ogemaw County. The unit was then

classified as Upper Cambrian and was assigned to the Trempeleau and Eau Claire

Formation (Ives and Ells, 1965). Only recently has the presence the St. Peter

Sandstone in Michigan subsurface been convincingly established (e.g., Barnes,

Lundgren, and Longman, in press; Harrison, 1987a).

The overall distribution of the St. Peter Sandstone in North American

midcontinent is shown Figure 3. The sandstone thickens to 1,200 feet (365 meters)

in central Michigan basin. The St. Peter Sandstone is much thicker in the basin

compared to the surrounding craton. This relationship may be related to the

availability of clastic sediment discharged from adjacent Precambrian crystalline rock

exposures and reworked Cambrian sandstone formations surrounding the Michigan

basin (Lundgren and Harrison, 1989) and to the local subsidence and eustatic sea level

fluctuation (Barnes, Harrison, Lundgren and Wieczorek, 1988).

Transgression northward of an epeiric sea from Late Cambrian to Middle

Ordovician deposited marine depositional packages in the Michigan basin (Ells,

1969). The Mt. Simon-Eau Claire-Galesville-Franconia-Trempeleau-Prairie du Chien

package was deposited during Sauk sequence, while the St. Peter Sandstone-

Glenwood package was deposited during Tippecanoe sequence (Figure 4). This

depositional package is comparable to the recorded history of regional regression and

transgression at various scales during Paleozoic (Figure 5).


10

v .

WISCONSIN ARCH /

. ----------------------j . ._

KAKEE ARCHTV-

0 1 0 0 m ile s| -------- 4 t 1 \

100 200 kilometersC O N T O U R INTERVAL 100 ft

Figure 3. Generalized Isopach Map of the St. Peter Sandstone in the North American Midcontinent and the Associated Paleozoic Structural Features (From Barnes et al., in press).


11

ROCK UNITS

MICHIGANco n o r t h e r nINDIANAuCO

l o w e r p e n in s u l aUPPER PENINSULA

ST. IQNACE SALINAGROUP

0 UNIT THROUGH

A UNIT

WABASHPOINT AUX CHENES

PLEASANT MILLS

MANISTIQUESALAUONIENIAGARA

BURNT BLUFFCLINTONCO

CATARACTCABOT HEADCABOT HEAD CAT

GRPCAT.GRP. MANITOULIN

UNOIFFERENTIATED

FT ATKINSON

BILL'S CREEK UTICA

GROOS QUARRYTRENTONTRENTON

CHANOLER FALLS m8 R QRP_BLACK RIVER

BONY FALLS ANCfLlGRP.

OLENWOOO

AU TRAIN P4CGRP

FOSTERONEOTA

POTOSITREMPEALEAU

FRANCONIA

IRONTON

o a l c s v il l eCALCSVILLE

MOUNT SIMONMOUNT SIMON

523 -

Figure 4. Generalized Lower Paleozoic Stratigraphic Column for the Michigan Basin (From Fisher, Barratt, Drostee, and Shaver, 1988).


Stratigraphy

Detailed stratigraphic and sedimentologic relationships were determined for

Ordovician strata in the Michigan basin (Barnes et al., in press) as a result of the

conventional core and wireline logs made available by recent deep exploration

drilling. Barnes et al. (in press) conclude that the St. Peter Sandstone of the

Michigan basin stratigraphically overlies the Brazos Shale member of the Lower

Ordovician Prairie du Chien Group, and is overlain by Glenwood Formation (Figure

6).

The St. Peter Sandstone-Prairie du Chien contact is purportedly marked by the

sub-Tippecanoe surface of unconformity in the Michigan basin. The stratigraphic

magnitude of the disconformity apparently decreases toward the basin center where

the contact may be gradational (Barnes et al., in press). Outside the Michigan basin

this interregional disconformity truncates carbonate rocks of Prairie du Chien Group.

The St. Peter Sandstone-Prairie du Chien contact in the Michigan basin was picked

by Lundgren (1991) and Barnes et al. (in press) at a point where the gamma ray (GR)

and the photoelectric effect (PEF) log signatures drastically increase (Figures 1 and

6).

The Glenwood-St. Peter Sandstone contact in most places appears gradational.

The contact consists of admixture of sandstone, siltstone, carbonate and shale (Barnes

et al., 1988). Preliminary conodont biostratigraphic studies by Barnes, Harrison and

Shaw (in review) suggests a Middle Whiterockian age for the St. Peter-Glenwood


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RELATIVE SEA LEVEL

HIGHER I LOWES

Q U A T E R N A R Y

T E R T I A R YT E J A S

CRETACEOUS

Z U N i ::*• 1—_ C R E T A C E O U S

J U R A S S I C

T R I A S S I C

P E R M I A NA B S A R O K A

P E N N S Y L V A N I A N

k a s k a s k i aKISSISSIPP1AN M I S S I S S I P P I A N

DEVONIAN D E V O N I A N

S I L U R I A NT I P P E C A N O E

O R D O V I C I A N

. S A U K • ■ v X v " : 'C A M B R I A N

♦400a *200ai I 1

2 n d O R D E R C Y C L E S O F G L O B A L S E A L E V E L V A IL A N D O T H E R S , ' 7 7

NO RTH AMERICAN CRATONIC S E Q U E N C E S . S L O S S , 6 3

Figure 5. Cycles of Sedimentation in Upper Midwest During Paleozoic (Modified From Lundgren, 1991).

Dark areas represent craton and light areas represent trangression of sea.

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UJ

U J

oOQ

CHU J

LU □

DEPTH „GAMMA R A Y „„ +

11000—

P E F

1 1 5 0 0 —

12000

12500 —

13000 —

13500

14000 - , -

BLACK RIVER FORMATION

G L EN W 00D FORMATION

ST. PETER SANDSTONE

BRAZOS s h a le "

FOSTER

FORMATION

s u b —TIPPECANOE

SURFACE

PRAIRIEdu

CHIEN

GROUP

l i m e s t o n e p u ~ r | ~ r | i s i l t s a n d

s h a l e d o l o m i t e - 7 . /~7"

Figure 6. Lithology and Wireline Log Response of the Middle Ordovician Sandstone and Associated Strata in A Key Well From Central Michigan Basin (From Barnes et al., in press).

15

contact. At the edge of the basin, where the St. Peter Sandstone pinches out, the

Glenwood lithofacies directly overlie the Prairie du Chien carbonates (Barnes et al.,

1988).

Controversy still exists regarding the actual stratigraphic correlation of the St.

Peter Sandstone. Various terminologies have been used to describe Ordovician

formations in Michigan (Figure 7). Fisher and Barratt (1985) believe the actual age

for this clastic formation to be Middle Ordovician and prefer the name Bruggers

Formation. Catacosinos (1972) gives the name Jordan Sandstone to the formation.

Other frequently used terminologies include Prairie du Chien, New Richmond and

Massive Sandstone (e.g., Bricker, Milstein and Reszka, 1983; Lilienthal, 1978).

Since the sandstone is descriptively the same as the St. Peter Sandstone that crops out

in many areas of the midwestem United States (Harrison, 1987b), the name St. Peter

Sandstone is used in this study.

Structural Studies

The structural trap for the St. Peter Sandstone is believed to be related to the

same SE-NW trending anticlines that are responsible for the production in Devonian

fields (Fisher and Barratt, 1985). The structural settings have been Most of the

studies on the St. Peter Sandstone in the upper midwest describe identified to be the

result of basement block movement (Caldwell, 1991; Versical, 1990). According to

Versical (1990), the hydrocarbon bearing structures in Paleozoic section possess


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Catacosinos1972

Bricker et al. 1983

Rohr1985

Fisher and Barrat 1985 central basin sw nich

Brady and Dehaas 1988

Harrison et al. 1989

Trenton Trenton Trenton Trenton Trenton Trenton Trentoni - iG JO -

Black River Black River Black River Black River Black River Black River Black Riverr o

U>O

= 5 Glenvood Glenvood Glenvood Glenvood Glenvood Glenvood Glenvoodt - i

o

Jordan s tT " '" '^ 7 ~

Peter Lower Glenvood Lover Glenvood St. Peter Goodvell St. PeterBruggers St. PeterLodi

Lower

St. Lawrence

Prairie du Chien Group

Prairie du Chien Group Foster Prairie du Chien

GroupPrairie du Chien

GroupPrairie du Chien

Group

CaobrLan Uppe

r Treapealeau Treapealeau Treapealeau Treapealeau Treapealeau - ...........................

Treapealeau...

Figure 7. Stratigraphic Nomenclature and Correlations for the Lower and Middle Ordovician in the Michigan Basin (From Lundgren, 1991).

O n

17

different styles and orientations due to the variation in their tectonic origin. Caldwell

(1991) establishes the timing of structural growth relative to hydrocarbon generation

and migration.

Depositional Environment

the sandstone as a transgressive sheet sand comprising a complex mosaic of

shoreface, sublittoral sheet sands, and barrier island deposits (e.g., Amaral and Pryor,

1977; Dapples, 1955; Dott and Roshardt, 1972; Fraser, 1976). Dott and Byers

(1980), on contrary, describe non-marine eolian and alluvial valley deposits.

Lorenzen (1989) describes the upper sequence of his "Massive Sand" as very

bioturbated representing low energy environment, while the middle and lower sections

as well laminated with minor or no bioturbation representing higher energy

deposition.

Based on the examination of more than 24 conventional cores, Lundgren (1991)

subdivided the St. Peter Sandstone in the Michigan basin into several facies ranging

from coastal to outer marine shelf depositional environments (Figure 8). Lundgren

(1991) related depositional facies to diagenesis within the St. Peter Sandstone.

Petrologic Studies

The St. Peter Sandstone is characterized by a highly quartz-rich framework

grain mineralogy similar to other Paleozoic sandstones in the North American


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FACIES SEDIMENTARY STRUCTURES QUARTZ DOLOHITE K-FELDSPAR CLAY

IA Med. scale crossbedding Bidirectional crossbedding Planar stratification

HIGH LOW LOW LOWScour surface (possible

CL3

eCL. IB reactivation surface) Clay drapes HIGH HOD LOW LOW

• Rip-up clastsCO

53CQ II Algal laminations Wavy bedding

Facies II consists of interbedded doloaierite and shale

Tidally influenced coastal Rip-up clastsdepositional environment

o c

E-*COCL. IIIPlanar stratificationLow angle cross stratification

eA (possible hu n n o c k y ) HIGH LOW LOW to HOD LOW to HODscour surfaces

Oo Lower ahoreface to upper skolithos ichnofacies

ac shoreface depositional environnent

Intense bloturbatlon

sE

IV Skolithos Ichnofacies HOD HOD HOD to HIGH HIGHCL. and

S3 Cruziana ichnofacies

SCL.g>

Outer narine shelfdepositional environnent

Figure 8. General Characteristics of Major Lithofacies in the St. Peter Sandstone, Michigan Basin (Modified From Lundgren, 1991).

19

midcontinent with minor occurrence of k-t'eldspar and lithic fragments (e.g., Dott and

Byers, 1980; Odom, Doe and Dott, 1976). Dapples (1955) describes the St. Peter

Sandstone in upper Mississippi Valley as uniformly well-sorted, pure quartz arenite.

Fisher and Barratt (1985) describe the variation in the petrology of their "Bruggers

Formation" and described illite/chlorite clay minerals. In recent studies, more

petrologic variations are realized within the St. Peter Sandstone in the Michigan

basin. Lundgren (1991) observes up to 10% polycrystalline quartz and up to 40%

detrital k-feldspar in many samples. This variation is in agreement with Odom (1975)

who suggested that feldsphatic arenites are predominant in lower energy shelfal facies

while quartz arenites are predominant in high energy littoral sandstone facies.

Lundgren (1991) describes modification of primary mineralogy and textural features

in the St. Peter Sandstone, and establishes the relationship between diagenetic

sequence and depositional facies and the variation in primary mineralogy. His overall

diagenetic sequence consists of early marine cement, syndepositional dolomite, quartz

overgrowth cement, pervasive dolomite replacement of precursor carbonate,

dissolution of framework grains and carbonate cements and late formation of

authigenic chlorite and illite (Figure 9).


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PARAGENESIS OF ST. PETER SANDSTONE MICHIGAN BASIN

EARLY RELATIVE TIMING LATE

E A R L Y C A R B O N A T E M A R IN E C E M E N T

Q U A R T Z O V E R G R O W T H C E M E N T

E A R L Y R E P L A C E M E N T A N D P O R E F IL L IN G

D O L O M IT E ____________

C O M P A C T IO NAND

PRESSURE SOLUTION

B U R IA L O O L O M IT E ( S A D D L E )

M IN E R A L L E A C H IN G A N D

S E C O N D A R Y P O R O S I T Y

A U T H IG E N IC C L A Y C H L O R IT E A N D ILLITE

Figure 9. Generalized Paragenetic Sequence of the St. Peter Sandstone in the Michigan Basin (From Lundgren, 1991).

too

PORE CLASSIFICATION TECHNIQUES AND PETROPHYSICS

Maximum exploitation of hydrocarbon accumulations requires an

understanding of the pore types within the reservoir interval.

Inference can be made on petrophysical properties and reservoir

performance based on the characterization of pore types in a given

reservoir container. For the St. Peter Sandstone in the Michigan basin,

primary pores were initiated by the texture of detrital grains which in

part was controlled by depositional settings. Then the pores were

considerably modified by deep burial and extensive diagenesis (Barnes

et al., in press). Different paragenetic sequences responsible for pore

geometry modification have been proposed for the St. Peter Sandstone

(e.g., Barnes et al, in press; Lundgren, 1991; Odom et al., 1976). This

study attempts to recognize the variation of pore geometry in each

reservoir rock type, to identify its paragenetic sequences, and to

appraise its reservoir quality. The main objective is to relate the pore

type encountered in the study with reservoir performance.

Pore Classification

Rock porosity is classified using numerous schemes (e.g.,

Choquette and Pray, 1970; Hartmann, 1988). In most classification

procedures, shape and size of the pores are the two major parameters

21


22

BASIC A S P E C T S OF PO R E S

P O R E S H A P E C A T E G O R I E S

i n t e r g r a n u l a r • i n t e r c r y s t a l h n e • v u g g y / m o l d l c * I r a c t u r a

P O R E - S I Z E C L A S S E S

m a cr o p or o s i t y ( > l S p ) • m e s o p o r o s i t y ( 15'5 p ) * m l c r o p o r o s l t y ( i S p )

P O R E THROAT SIZE CL ASSES

m a c r o >2p m c s o .5 -2 V m i c r o .2-.5P s u b m i c r o <,2m

V u ggy/so ld lc P o ro s ity (p oorly connected)I n terg ra m ilsr P o ro sity

Irosobile w ater ^hydrocarbon

v u ggy/fractu ra P o r o s ity (w e ll connected)I n te r c r y s ta l l in e P o ro sity

Figure 10. Pore Type Classification (From Hartmann, 1989).


23

identified (Figure 10). Suitable modifiers are then added. Since the goal

of this study is to characterize reservoir attributes o f the St. Peter

Sandstone, besides the recognition of pore size and shape, the size and

distribution of pore throats, the constrictions connecting one large pore

to another, are emphasized. Thin section and scanning electron

photographs are used for pore type recognition.

In the absence of visual aid for pore shape identification, porosity

and permeability data can be used for pore type prediction (Hartmann,

1988). According to Hartmann (1988), porosity-permeability crossplots

show consistent values for four common clastic rock types (Figure 11).

The pore type can often by directly interpreted from these rock types.

Uncem ented clean sandstones, for exam ple, define a field for

intergranular porosity. Quartz and carbonate-cem ented sandstones

define intercrystalline porosity field, and shaly sandstones define a field

for microporosity.

Wardlaw and Cassan (1978) recognized the strong affect of pore

geometry on recovery efficiency and introduced the aspects of pore-to-

throat size ratio and throat to pore coordination number (Figure 12).

Although no attempt is made in this study to make quantitative

measurements of these attributes, the impact of these parameters on

reservoir quality of the St. Peter Sandstone are noted.


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C l a s t i c s

io

awoo

<I

^ Ca

CL

P o ro s i ty “ ^ * ( l in e a r s c a le )

Figure 11. Interpretation of Pore and Rock Types Using Porosity-PermeabilityCrossplot (From Hartmann, 1988). ^

25

R E C O V E R Y E F F I C I E N C Y

L O W H I G H

pOT0 p o r et h r o a t

L A R G E P O R E R A T I O T H R O A T

S M A L L

C O O R D I N A T I O NN U M B E R

_ ®

Figure 12. Illustration of Pore-to-Throat Size Ratio and Coordination Number and Their Effects on Recovery Efficiency (From Wardlaw and Cassan, 1978)


26

Petrophysics

Petrophysics can be defined as the physical properties of a rock or a sample

which are related to the distribution of pore space and the saturation of fluid. The

eight most important petrophysical properties of rocks that are commonly used in

formation evaluation were explained by Hartmann (1988). Those properties are

porosity, permeability, internal surface area, wettability, capillarity, irreducible

saturation, breakthrough pressure and relative permeability. Subsequent chapters

attempt to evaluate those properties in the three selected reservoir intervals.

Porosity

Porosity is the volume percentage of non-rock space in a rock or sample

regardless of the size, shape, or state of saturation. The more open space a rock

contains, the more water, oil or gas it can hold. The total porosity in a sample

should include the small pores found in shaly formations between clay crystals and

also the large unconnected pores.

Primary porosity is the porosity that is built into the rock during original

deposition and is reduced by subsequent compaction and cementation. Primary

porosity is affected more by the sorting of the grains. The better sorted the

framework grains, the higher the porosity (Baharlou, 1985).


27

Secondary porosity is that porosity which is developed subsequent to original

deposition, compaction and cementation. Secondary porosity includes fracture

porosity, solution porosity and porosity caused by dolomitization (Baharlou, 1985).

P-grmeability

Permeability is the property that permits the flow of fluid through the

interconnected pores of the rock sample when entirely saturated with that fluid. This

property is important because oil and gas must flow through reservoir rock to the well

bore in order to be recovered. The unit of permeability measurement of "darcy" can

be visualized as the permeability of a rock sample that is one centimeter long, with

one square centimeter cross-sectional area, and that is capable of flowing one cubic

centimeter per second of a one centipoise fluid (Hartmann, 1988).

Permeability is affected by grain size and sorting. The finer the grain size and

the poorer the sorting, the lower permeability. Other parameters that affect

permeability include packing of framework grains, cementation and sedimentary

structures (Pettijohn, Porter, and Siever, 1987).

Absolute permeability is the ability of a rock to transmit a single fluid when

it is entirely saturated with that fluid. Effective permeability is the permeability with

more than one fluid present in the rock. If oil, gas and water are all present in the

pores o f reservoir rock, as water saturation increases, the effective permeability to oil

and gas decreases.


28

Relative Permeability

Two phase relative permeability is defined by Hartmann (1988) as the

permeability of a pore system to gas, oil, or water when the pores are saturated with

two of those fluids. Relative permeability is the ratio of effective permeability of a

fluid to absolute permeability (Baharlou, 1985). In a reservoir container, relative

permeability to oil and gas must be higher than relative permeability to water for an

economic oil and gas recovery.

Internal Surface Area

Internal surface area is the total of all exposed mineral surfaces in a rock

sample. It includes all the surface area of pores and pore throats. That is, if the

walls of the pore spaces were to be unfolded and the area totalled, the result would

be internal surface area. Internal surface area is rather more commonly used as an

explanatory concept than as an actual petrophysical measurement. It affects most of

the petrophysical properties examined in this study.

Wettability

Wettability is a measure of the tendency of a rock surface to adsorb water in

the presence of oil and gas (Hartmann, 1988). It is largely a function of the type of


29

minerals lining the pore and pore throats and the chemical composition of the

hydrocarbon.

According to Hartmann (1988) most elastics oil and gas reservoirs are water-

wet. Many carbonate reservoirs, on the other hand, are probably oil-wet (Chilinger

and Yen, 1983; Wardlaw, 1976). Although all three reservoir types in the study

appear to be water-wet, the magnitude of the wettability varies with different pore

apertures. In a reservoir with larger pores, wettability to water is reduced because

the non-wetting phase such as oil can break through the thin skin of water on pore

wall easily.

Capillarity and Irreducible Saturation

Capillarity is closely related to wettability. It is actually the wetting force that

acts along mineral surfaces. Capillarity is more the function of the size of pores and

pore throats in the pore system than mineralogy. The smaller the pores, the greater

internal surface area, and the more wetting fluid being held in the pore system.

Therefore, the sample with smaller pores usually has greater capillarity pressure than

the sample with larger pores.

Irreducible water saturation is the percentage of reservoir porosity occupied by

water that will not move under producing condition because the water is adsorbed

onto mineral surfaces or trapped in small pores with high capillarity. The sample

with high irreducible water saturation has poor reservoir quality because greater


30

glaaa tubas blotter (C <• n

air

60 80 1000 20

WATER SATURATIONwater

Figure 13. Relationship Between Capillarity, Saturation Profile, and Pore Size (From Coalson, Hartmann, and Thomas, 1985).


31

pressure is needed to overcome capillary pressure before non-wetting phase can be

introduced into the pore system.

Relationship between capillarity, irreducible saturation, and pore size is

explained in Figure 13. The large tube represents the sample with large pore

apertures and the small tubes represent the sample with smaller pore apertures. The

larger tube has low capillarity and capable of drawing only a short column of water

into the tube. The smaller tube, on the other hand, has greater capillarity and draw

a taller column of water. At reservoir condition, the greater outside pressure is

needed in the reservoir with smaller pores in order to overcome the higher capillary

pressure. If the reservoir has very fine pore system such as in the blotter, the water

column will be extremely tall and it cannot be displaced with any easily achievable

pressure.

Breakthrough Pressure

Breakthrough pressure was defined by Hartmann (1988) as the pressure

required for initial migration of non-wetting fluid through a pore system. It is the

pressure at which seals start to leak or at which secondary migration of hydrocarbons

into the pore system can occur. Following the achievement of breakthrough pressure,

a filament of continuos hydrocarbon migration from source rock into reservoir

container is established.


32

Irreducible Saturation, %

100 0.052000

0.101000

0.25

U<v

cz<v

Cl .a

Jennings (1987) •Displaceient Pressure’Scbowalter (1989)

•Displaceient Pressure’ 20 Katz andTboipson (1987) "Threshold Pressure

100 Mercury Saturation,

Figure 14. Breakthrough Pressure Determination From Mercury Injection Capillary Pressure Curve.


33

Different cut-off for breakthrough pressure has been proposed by

different workers (Figure 14). Schowalter (1979) interprets his

"displacement pressure" as the pressure at 10% mercury saturation on

mercury injection capillary pressure curve. Katz and Thompson (1987)

indicate their "threshold pressure" graphically to the inflection point on

mercury injection plot. Jennings (1987) estimated his "displacement

pressure" by extending the slope of plateau to the right side of the

graph.

Hydrocarbon Column and Water Saturation

A hydrocarbon column is the hypothetical vertical dimension of

continuous hydrocarbon accumulation, with its bottom located at the

free water level and extending to the top of the trap. The column

comprises three zones: 100% hydrocarbon production zone, oil-water

transition zone, and 100% water production zone (Figure 15). For the

hydrocarbon in a reservoir container to be recovered, buoyancy

pressure created by hydrocarbon column must be great enough to

overcome capillary resistance of the wetting fluid on the pore wall. For

a reservoir with small pore and pore throat sizes, the greater buoyancy

pressure, or the taller hydrocarbon column, is needed to overcome

capillarity for initial migration of hydrocarbon into reservoir container.

Water saturation is the percentage of pore volume in a rock filled


34

O ILTop o f Trap

Free-Oil Level

Econ. o/w Contact

Prod, o/w Contact

100% Water Level

Free-Water Level

C O L U M N

T<U<DU

8 0 %

& > 70 %

5 0 %

Figure 15. Hydrocarbon Column (From Jennings, 1987).


35

with water. This percentage includes not only the free and mobile

water in large pores that can be displaced by hydrocarbon but also the

immobile water trapped within small pores. The percentage of water

saturation is at 100% in the free-water zone and it decreases to 0% in

the free-hydrocarbon zone (Figure 15). Water saturation in a reservoir

is related by Hartmann (1989) to the pore type of the reservoir

container being evaluated and to the height of the hydrocarbon column

height above the free water level. If the type of pores and the amount

water saturation a reservoir are known, the height of hydrocarbon

column can be predicted.


DESCRIPTION OF RESERVOIR ROCK SAMPLES

Conventional sample description techniques were used in the description of

reservoir rock samples with special emphasis on the assessment of reservoir quality.

Grain texture, sedimentary structures, type of cements, degree of rock consolidation

(Table 1), and amount and type of visible porosity (see Appendix B) were catalogued

in addition to lithology (Sneider and King, 1984). The description of each set of

cores is presented in Appendix B.

Anger 1-20 Upper Cores (Reservoir Type 3)

Sample Description (Appendix B)

Hydrocarbon reservoir sandstones in the Anger 1-20 well, cores #C-1, boxes

1 through 7, from 8603’ to 8660’ depth, consist of primarily subrounded to rounded,

bimodal to well-sorted, fine- to medium-grained argillaceous (clay-rich) sandstones.

In core samples, the clay-rich portions of the sandstone are distinguishable from the

clay-poor portions by their green color. Clay matrix appears to be the major

intergranular material in the cores, but significant amount of quartz and carbonate

cements are also present.

36


37

Table 1

Consolidation Classification for Silicate-Rich Clastic Rocks

Descriptive Term Sample Description

Unconsolidated Sample disaggregates into individual particles before and after hydrocarbons are removed.

Slightly Consolidated Sample easily disaggregates or crumbles into individual particles when nibbed between fingers.

Moderately Consolidated Sample disaggregates only after rubbed vigorously between fingers.

Moderately-Well Sample will not disaggregate when rubbedConsolidated vigorously between fingers. Forceps or steel probe will

disaggregate this sample into individual particles and smaller pieces containing several particles.

Well Consolidated Sample disaggregates with great difficulty, using forceps or steel probe, into smaller pieces containing several particles.

Very Well Consolidated Sample will not disaggregate with forceps or probe. A hammer disaggregates the sample into small pieces; pieces break into particles.

(From Sneider and King, 1984)


38

The consolidation for these cores ranges from slightly consolidated in clay-rich

sandstone to well consolidated in quartz and dolomite cemented

sandstones (see Table 1 for consolidation classification). Visible porosity is

dominated by intergranular pores that range from trace to excellent (see Appendix B

for visible porosity classification). Poor visible porosity is usually found in quartz

and dolomite cemented sandstone, while good to excellent visible porosity is found

in clay-rich samples.

Sedimentary structures within this set of cores are dominated by massive

structureless beds and planar laminations (Figure 16). Small-scale crossbeddings are

also present in some places. Most primary sedimentary structures are destroyed by

extensive burrowing. The completely bioturbated zones exhibit mottled structure

(Figure 16c). Other structures such of scour surfaces and stylolites, although, are

also present within the cores.

Petrographic point counts indicate that the detrital composition in these cores

is dominated by monocrystalline quartz with minor k-feldspar (Appendix C). Quartz-

feldspar-lithic (Q-F-L) ternary plots indicate that the majority of samples are quartz

arenites with minor less common subfeldsarenites (Figure 17). Authigenic mineral

cements and replacements in the cores range from 1.2% to 81.0% according to point

count data with the average of 11.9% (Appendix C). Both clay and quartz

overgrowths are widely distributed, while dolomite is only found locally.


39

(v J -2 G

Figure 16. Photographs of Sandstone Samples From Anger 1-20 Upper Cores.

A. Structureless sandstone. Clay-rich (argillaceous) sandstone (cl) has better visible porosity than clay-poor (primarily quartz-cemented) sandstone (qc) (8637.0’-8638.8’). B. Planar laminated (pi) sandstone with small-scale crossbedding (xb) (8612.2’-8614.0’). C. Heavily bioturbated sandstone with mottled texture (mott) (8603.0’-8604.4’). D. Sandstone with extensive burrowings (arrows) that destroy primary sedimentary structures (8644.0’- 8645.6’).


40

Figure 16--Continued

C. Heavily bioturbated sandstone with mottled texture (mott) (8603.0’-8604.4’).D. Sandstone with extensive burrowings (arrows) that destoy primary sedimentary structures (8644.0’-8645.6’)-


41

100% QUARTZ

Sublith-arenite

Subfelds-arenite

LithicFeldsarenite

FeldphaticLitharenite

Feldsarenite Litharenite

50% FELDSPAR 50% LITHIC

Figure 17. Quartz-Feldspaf-Lithic (Q-F-L) Ternary Plots for Anger 1-20 Uppeir Cores.


42

Interpretation

The dominantly fine- to medium-grained and moderate to good sorting of most

sandstones in the Anger 1-20 upper cores exhibit good reservoir potential.

However, the cores are heavily cemented and the reservoir quality has been reduced.

Point count data (Appendix C) indicate the average authigenic cements within the

samples is greater than average porosity (7.9% to 15.9% cements and 4.5% to 10.5%

porosity if ninety-five percent confidence limit is used for the average cement and

porosity of 11.9% and 7.5% respectively; Pettijohn et al., 1987, p. 520-22).

The reservoir container within the Anger 1-20 upper cores is probably the

loosely consolidated portions of the succession with excellent visible porosity. Clay-

rich sandstone beds and laminae usually have good visible porosity and less

consolidated, and are probably the best reservoir rock. Quartz and dolomite cemented

beds, on the other hand, have poor visible porosity and well consolidated, and

therefore are poorer reservoirs.

Abundant vertical burrows and massive and planar laminated beddings suggest

the close correlation between upper cores in the Anger 1-20 and outer marine facies

of Lundgren (1991) (Figure 8). The coarser-grained sand layers that comprise

laminated bedding and the scour surfaces in places could be related to the episodic

storm events. Mottled structures (Figure 16c) in argillaceous sandstone at the top of


43

the cores suggest the gradational contact between the upper St. Peter Sandstone and

the overlying Glenwood Formation.

Patrick & St. Norwich 2-28 Cores (Reservoir Type 2)


The Patrick & St. Norwich 2-28 well, cores tfC-\ and #C-2, 7924’ to 8004’

depth, is dominated by well sorted, well rounded, medium-grained uncemented

sandstones with minor poor to moderately sorted argillaceous sandstone at the top of

the cored interval (Figure 18). This succession is dominated by moderately

consolidated sandstone with fair to excellent visible porosity. Sandstone between

7931’ to 7955’ has the best visible porosity (Figure 18a; see core description in

Appendix B). The same depth interval is also the least consolidated portion of the

cores.

Primary sedimentary structures within this interval are dominated by planar

laminations with few examples of low angle cross stratification. Like the Anger 1-20

cores ffC-1, vertical burrows (Skolitus ichnofacies) obscure primary sedimentary

structures (Figure 18b). Scour surfaces with associated rip-up clasts are more

abundant in these cores than the Anger 1-20 upper cores (Figure 18c). Point count

data indicate that the detrital mineralogy of sandstones in this portion of the St. Peter

Sandstone is more quartzose than in the Anger 1-20 cores (Figure 19). In accordance

with fair to excellent visible porosity observed in the cores, the point count porosity


AB

Figure 18. Photographs of Sandstone Samples From Patrick & St. Norwich 2-28 Well.

A. Uncemented, friable sandstone (uc) with excellent visible porosity is the most common reservoir rock type for this set of cores. Dolomite cemented zone (dol) with trace visible porosity is also present (7937.0’-7939.4’). B. Vertical burrows (arrows) obscure primary sedimentary structures (7965.6’- 7966.5’). C. Scour surface (arrow) with associated rip-up clasts indicates sudden change of energy condition during storm events in shoreface environment (8002.0’-8003.0’). D. Argillaceous sandstone at the top of cores (7924.0’- 7925.2’)


45

j y V v k 1 4 / . , i ' • * *

u \ ■ ^ **' **

Figure 18--Continued

C. Scour surface (arrow) with associated rip-up clasts indicates sudden change of energy condition during storm events in shoreface environment (8002.0’- 8003.0’). D. Argillaceous sandstone at the top of cores (7924.0’-7925.2’).


46

100% QUARTZ

Sublith-arenite

Subfelds-arenite

Feldphatic\ \Litharenite\ Litharenite'

Felds- Lithic arenite Feldsarenite


Figure 19. Quartz-Feldspar-Lithic (Q-F-L) Ternary Plots for Patrick & St. Norwich 2-28 Cores.


47

is relatively high (see Appendix C). Except for the dolomitic and argillaceous

sandstones at the top of cored interval, very little intergranular cements and matrix

are present in the thin sections.

Interpretation

The well-sorted, well-rounded, medium-grained sandstone in cores from the

Patrick & St. Norwich 2-28 well has excellent reservoir quality. The lack of

intergranular materials in most of the cores, has resulted in better reservoir quality

than sandstone in the Anger 1-20 cores ffC-2. The best reservoir rock within the

cores is the moderately consolidated with excellent visible porosity interval (from

7931’ to 7955’ depth). This is supported by the high porosities and permeabilities

encountered within the sample (see Appendix D).

Abundant planar laminations, vertical burrows and scour surfaces correlate this

set of cores with lower shoreface to the upper shoreface depositional environment of

Lundgren (1991) (Figure 8). Extensive burrowings suggest intermittent low energy

conditions. Scour surfaces and low angle cross-stratification in several places suggest

the episodic storm dominated depositional facies (Dott, Byers, Fielder, Stenzel, and

Winffee, 1986).


48

Anger 1-20 Lower Cores (Reservoir Type 1)


Sandstones in the Wolverine Anger 1-20 well, cores #C-2, from 8978.0’-

9024.5’ depth, consist mostly of rounded, moderate- to very well-sorted, quartz

cemented sandstone. Relatively thin dolomitic quartz sandstone is also present

locally. Dolomitic sandstone is recognizable in the cores by its dark-gray color.

Consolidation in these cores ranges from moderately consolidated to very well

consolidated. Consolidation tends to vary with the type and amount of cementing

materials. Dolomitized sandstones are usually very well consolidated while the quartz

cemented sandstone are generally moderately-well consolidated. Visible porosity

ranges from trace in dolomitic sandstone to relatively good in quartz cemented

sandstone (see Appendix B for visible porosity classification).

Stylolites are common chemical compaction features in quartz sandstone and

they obscure sedimentary structures in many places (Figure 20). However, current-

induced sedimentary structures such as planar lamination and cross strata still can be

recognized (Figure 20b).

Point count data indicate the detrital composition of this set of cores is

dominated by quartz arenite with minor subfeldsarenite (Appendix C; Figure 21).

The primary authigenic mineral in the cores is quartz overgrowth cements. Although

dolomite and clay minerals are also present they are not abundant.


49

Figure 20. Photographs of Sandstone Samples From Anger 1-20 Lower Cores.

A. Stylolites (arrows) obscure primary textures and structures in many places (9020.0’-9021.8’). B. Current-induced sedimentary structures such as planar lamination (pi) and tabular cross-bedding (txb) are present throughout the cores (8981.5’-8983.2’).


50

100% QUARTZ

Subfelds-arenite

Sublith-^arenite

Feldphatic\ \Litharenite \ Litharenite

Felds- Lithic arenite Feldsarenite


Figure 21. Quartz-Feldspar-Lithic (Q-F-L) Ternary Plots for Anger 1-20 Lower Cores.


51

Interpretation

The rounded, well-sorted, fine- to medium-grained sandstones encountered in

the Anger 1-20 cores ffC-2 contain excellent intergranular porosity. But quartz

cementation is extensive enough to consolidate the framework grains and to reduce

the porosity in places. Although the cores are primarily well consolidated, the

interval in the middle of the cores (8989.0’ to 9011.0’) exhibits good to excellent

visible porosity. Core analysis data indicate probably the main reservoir container in

the well.

The cores with current-induced sedimentary structures and the lack of

bioturbation suggest that this is relatively high energy tidally influenced coastal

environment (see Figure 8). The cores with massive beds and planar lamination

indicate the lower energy lagoonal deposits (Barnes et al., in press).


PORE TYPES WITHIN THE ST. PETER SANDSTONE RESERVOIRS

Porosity in Quartz Cemented Sandstone: Pore Type 1

Porosity in primarily quartz cemented sandstones of the Anger 1-20 well,

cores #C-2, is generally surrounded by quartz overgrowth crystals, and is classified

as intercrystalline porosity. Thin section and scanning electron micrographs (Figures

22 and 23) reveal that the secondary quartz tends to grow in the central pore, not in

the pore throat. The result is a decrease in the ratio of pore-to-throat size which

improves quality and recovery efficiency of these reservoir rocks (see Figure 12).

The throat to pore coordination number in this pore type is not greatly affected by

secondary quartz overgrowth. Scanning electron micrographs of polished surfaces of

a quartz-cemented sample (Figure 23b) reveals the presence of macro intercrystalline

porosity connected by smooth, macro pore throats.

Pore type 1 samples are represented by relatively low porosity with moderate

permeability (Figure 24). Porosity and permeability ranges encountered for this

reservoir type are closely related to quartz cemented zone of Figure 11. The samples

should contain intercrystalline porosity.

Quartz overgrowth cement was probably the first diagenetic cement in most

of the lower facies of the St. Peter Sandstone (Lundgren, 1991; Figure 25a). Quartz

52


100 microns |

200 microns

Figure 22. Photomicrographs of Quartz Cemented Sandstone (Anger 1-20 8982’-83’).

A. Quartz overgrowth (qov) occupies part of intergranular space. Boundary between detrital quartz and overgrowth is represented by "dust rim" (arrows). P = pore space, Q = detrital quartz, and qov = quartz overgrowth. B. Suture and concavo-convex grain to grain contact (arrows) are the evident of chemical compaction which results in a loss of porosity. Crossed nicols.


S i « r

Figure 23. Scanning Electron Micrographs of Quartz Cemented Sandstone.

Euhedral quartz overgrowth crystals (arrows) create smooth surface area. A. SEM of a naturally broken surface (Anger 1-20, 9006.0’). B. SEM of a polished section indicates pores are well-connected (Gingrich 1-31 A, 9975.0’).


55

1000 n

100 -

•oB

'JE,sBL-<D

CL

2u

io -

00

N 0

Anger 1-20 - Upper Cores (PT3) 'Doooc Patrick & St. Norwich 2-28 (PT2)

Anger 1-20 - Lower Cores (PTl)

0T

4i > r

8 12 16 Core Porosity (%)

20 24

Figure 24. Interpretation of Rock and Pore Types of the St. Peter Sandstone Reservoirs Using Porosity-Permeability Crossplot.

Only samples with permeabilities greater than 5 md were plotted.


56

TJu T) r

t VibA

B

QUARTZ GRAIN

QUARTZOVERGROWTH

CARBONATEC EM EN T

o K-FELDSPAR ®GRAIN

A U TH IG EN IC ^ CLAY

Figure 25. Schematic Representation of the Generalized Paragenesis o f Model Pore Types Within the St. Peter Sandstone Reservoirs (From Barnes, 1990).

A. Paragenesis of pore type 1. B. Paragenesis of pore type 2. C. Paragenesis of pore type 3.


57

overgrowth cementation, however, was terminated before complete pore occlusion

by late burial dolomite. The subsequent leaching of this dolomite cement produced

the secondary intercrystalline pores. In the absent of burial dolomite, the pore space

would have been completely occluded by the overgrowth or reduced by subsequent

compaction (Lundgren, 1991; Figure 22b).

Porosity in Uncemented Sandstone: Pore Type 2

The description of conventional core in the Patrick & St. Norwich 2-28 well

indicates excellent visible porosity in predominantly clean uncemented sandstone.

Point count data confirm porosity to 28.4% (see Appendix C). These data are in

agreement with typical clean sandstone reservoir properties described in the middle

facies of the St. Peter Sandstone (Barnes et al., in press; Lundgren, 1991).

Scanning electron micrographs of a polished section from Patrick & St.

Norwich 2-28 well (Figure 26a) show the variation in size of intergranular pores.

The majority of porosity is macro intergranular to 100 microns in size. Scanning

electron micrographs of a broken surface of clean uncemented sandstone (Figure 26b)

display the excellent connectivity of the pore system. The predominantly macro

intergranular pores in the sample are well connected by macro pore throats. The

presence of this well-connected pore system is clearly responsible for the good

production in the Patrick & St. Norwich 2-28 well (see Appendix A for all-time

cumulative production).


Figure 26. Scanning Electron Micrographs of Uncemented Sandstone.

A. SEM of a polished section showing two dimensional shape of pores (Patrick & St. Norwich 2-28, 7940’). B. SEM of a naturally broken surface showing three dimensional shape of pores. The interconnection between pores by relatively large pore throats is more apparent in this sample (Martin 1-15, 11356’).


59

Sandstones in this interval are characterized by high porosity and permeability

(Figure 24). These values are in accordance with the clean uncemented sandstone

envelope of Hartmann (1988) (Figure 11).

Intergranular pores observed in reservoir type 2 were secondary in origin

following the dissolution of intergranular dolomite cement (Figures 25b and 27). The

scarcity of authigenic clay in the reservoir is believed to be related to the lesser

amounts of k-feldspar in most part of the middle St. Peter Sandstone (Lundgren,

1991). Quartz overgrowth in this reservoir facies was believed to has been precluded

by early carbonate matrix (Lundgren, 1991).

Porosity in Argillaceous Sandstone: Pore Type 3

Point count data in the Anger 1-20 well, cores #C-1, indicate an abundance

of clay minerals in this portion of the St. Peter Sandstone (see Appendix C). This

relatively high percentage of clays is in accord with the abundance of pore-filling and

pore-lining authigenic clays in the upper portions of the St. Peter Sandstone (Barnes

et al., in press; Lundgren, 1991).

There are two dominant pore types present within the argillaceous facies of the

St. Peter Sandstone: meso to macro intergranular pores in relatively clay-poor

medium-grained sandstone, and microporosity within clay crystals in clay-rich

sandstone (Figures 28 and 29). Although a significant amount of intergranular

porosity is preserved in the clay-rich reservoir type 3, the reservoir quality is not


60

200 microns

200 microns

Figure 27. Photomicrographs of Uncemented Sandstone.

Q = detrital quartz, P - pores, and D = dolomite. A. Secondary intergranular porosity is abundant due to the dissolution of pore-filling minerals (Patrick & St. Norwich 2-28 , 7943.0’). B. Trace of dolomite and authigenic clays (arrows) occupy part of intergranular space in this sample (Patrick & St. Norwich 2-28, 7931.5’).


61

100 microns

Figure 28. Photomicrograph of Clay-Rich Sandstone (Anger 1-20 8631-32’).

P = pore space, Q = detrital quartz grain, F = k-feldspar, and cl = authigenic clays. Authigenic clays occupy part to most of intergranular space. Corroded feldspar grain indicates mineral dissolution process which creates secondary porosity.


I'*. ’

p 1 ) 0 p | v ^

jr . ■■ -')‘ar •■ -' ‘V '^ tv T T r "^:' - vI , . Vy* "'<'•■'■ y •aL; gffgsg Vais®

H ,"M

Figure 29. Scanning Electron Micrographs of Clay-Rich (Argillaceous) Sandstone.

CL = pore-filling authigenic clays, and Q = detrital quartz grain.A. Micropores are the dominant pore type in a clay-rich sample (Martin 1- 15 well, 11410’). B. Meso to macro intergranular pores are the dominant pore type in a clay-coated sample (Gilde 1-25, 10595’).


63

clearly improved. Scanning electron micrographs of samples with relatively small

amounts of clay show the sand grains to be clay coated and to have rough surface

area (Figure 29b). This rough surface increases the total internal surface area and the

wettability of the samples toward wetting-fluid. Beside surface roughness, reservoir

quality for the clay-rich sandstone reservoir is also reduced by the heterogeneity of

its pore system.

Individual clay particle within the clay-rich reservoirs usually occur as platelet

of less than 10 microns in size and occupy not only the central pores but also the pore

throats (Figure 29a). The result is the reduction of the pore throat size and the

subsequent increase of pore-to-throat size ratio which lowers reservoir quality. In few

cases the pore throats are totally blocked resulting in a poorly connected pore system.

Porosity-permeability crossplots (Figure 24) indicate that the samples from the

Anger 1-20 well, cores //C-1, are represented by moderate porosity with relatively

low permeability. A comparison of the porosity-permeability plots with Hartmann’s

(1988) interpretation (Figure 11), the Anger 1-20 well, cores #C-1, would fall into

the shaly sandstone group. Low permeability and moderate porosity is directly related

to the abundance of microporosity as a result of abundant pore-filling clays.

X-ray diffraction analysis performed by Lundgren (1991) on selected samples

indicates illite and chlorite are the primary clay minerals in the St. Peter Sandstone.

The origin of those clays and associated microporosity is believed to be strongly

controlled by the dissolution of unstable precursor minerals (Barnes et al., in press).


64

Evidence of mineral dissolution is proved by the patchy dolomite remnants and

corroded k-feldspar grains (Figures 25c, 27b and 28).

Port Size

The concept of port size was introduced by Hartmann and Coalson (1990) as

a good measure of the largest connected pore throats in a sample. According to

Hartmann and Coalson (1990), rocks with intergranular and intercrystalline pore

systems of similar port size share similar irreducible saturation, relative permeability,

and production performance ranges.

Port size is indicated by the pore throat size at 35% non-wetting fluid

saturation on mercury injection capillary pressure curve (Figure 2). Port size is

usually calculated using Winland’s equation (log port size = 0.732 + 0.588 log

permeability - 0.864 log porosity) (Kolodzie, 1980). For samples from the Anger 1-

20 and Patrick & St. Norwich 2-28 wells, their port sizes were calculated and are

presented in Appendix D. Winland’s equation for port size can be also solved

graphically on porosity-permeability crossplot (Figure 30).

Port Size in Reservoir Type 1

For the reservoir type 1 samples from the lower cores in the Anger 1-20 well

(8978.0’-9023.5’), the port size ranges from 0.15 to 9.84 microns with the mean 2.58


65R 3 5 = 1 6 / i

100 = R 3 5 = 4 u

R 3 5 - 2 / i

R 3 5 = 1 / i

LL t).1 M ea n P o r t S i z ecr

10 20 P O R O S IT Y

5.61 [A 1.86

3 0

B 1000, R 3 5 = 1 6 / i

R 3 5 - 8 / 1

R 3 5 = 4 / 1

R 3 5 = 2 / i

R 3 5 -1 /1

Q - 0 .1 ,

10 20

POROSITY

Figure 30. Graphical Solution of Winland’s Equation Plotted on Porosity- Permeability Crossplot for Determination of Port Sizes.

Only data with permeability 5 md or greater are used in the crossplots. A. Crossplot for Anger 1-20 lower cores. B. Crossplot of Patrick & St. Norwich 2-28 cores. C. Crossplot of Anger 1-20 upper cores.


P °ftO S /JY 30

p igurte 30- Continued

CrosspIot o f Ant'g er l 20 iovv.er cores.

M ission.

67

Table 2

Statistics for Port Size (microns)

A. Entire Samples

Anger 1-20 Patrick & St. Anger 1-20Lower Cores Norwich 2-28 Upper Cores(RT1) (RT2) (RT3)

No. of Samples, N 46 81 57

Range 0.15 - 9.84 0.11 - 14.03 0.23 - 5.54

Mean 2.58 4.25 2.04

Std. Dev. 2.11 4.09 1.60

B. Samples With Permeability Greater Than 5 md

Anger 1-20 Patrick & St. Anger 1-20Lower Cores Norwich 2-28 Upper Cores(RT1) (RT2) (RT3)

No. of Samples, N 13 45 14

Range 2.88 - 9.84 1.68 - 14.03 2.96 - 5.54

Mean 5.61 6.67 4.31

Std. Dev. 1.86 4.21 1.04


68

microns and standard deviation of 2.11 (Table 2; Appendix D). For the samples with

permeability greater than 5 md, the mean is at 5.61 microns with standard deviation

of 1.86.

A representative mercury injection capillary pressure curve of a quartz

cemented reservoir sample (see Chapter 6, Capillarity Profiles and Hydrocarbon

Column Height, Figure 31) indicates a port size of 5 microns for that sample.

Although the port size of this typical reservoir rock type is not as large as a typical

Patrick & St. Norwich 2-28 sample, the overall pore throats are well sorted according

to the long and flat plateau of the capillary curve (Figure 31). Performance of this

reservoir type is probably much better than its port size indicates.


Port size for samples from the Wolverine Gas & Oil Patrick & St. Norwich

2-28 well ranges from 0.11 to 14.03 microns, with the mean of 4.25 microns

(Appendix D; Table 2). These relatively large port sizes are consistent with the high

porosity and permeability values in the Patrick & St. Norwich 2-28 cores.

For samples with permeability greater than 5 md, the port size ranges from

1.68 to 14.03 microns with the mean of 6.67 microns (Figure 30b). These greater

port sizes compared to Anger 1-20, cores #C-1 and //C-2, are directly related to the

scarcity of intergranular materials and to the relative abundance of macro

intergranular pores and pore throats in reservoir type 2.


69

A representative mercury injection capillary pressure curve of a high porosity

and permeability, clean, uncemented sample from Patrick & St. Norwich 2-28 well

(see Chapter 6, Capillarity Profiles and Hydrocarbon Column Height, Figure 32)

shows the port size of nearly 20 microns. The plateau of this curve appears to be flat

which indicates relatively well sorted pore throats. The relatively large port size and

well sorted pore throats provide an excellent medium for fluid recovery.


The port size for Wolverine Gas & Oil’s Anger 1-20 cores #C-1 ranges from

0.23 to 5.54 microns, with the mean of 2.04 microns (Appendix D; Table 2). These

relatively small port sizes are consistent with the low permeabilities and moderate

porosities within the cores. For the samples with permeability greater than 5 md,

which are considered the main contributor to reservoir performance, the port size

ranges from 2.96 to 5.54 microns with the mean of 4.31 microns (Table 2; Figure

29).

Capillary pressure curve of a clay-rich reservoir sample (Anger 1-20 8651’)

indicates the port size of 4.0 microns (see Chapter 6, Capillarity Profiles and

Hydrocarbon Column Height, Figure 33). This small port size is directly related to

the reduction of overall pore throats by pore-filling authigenic clays. The relatively

small port size tends to produce a poor reservoir.


PETROPHYSICS OF THE ST. PETER SANDSTONE RESERVOIRS

Porosity

A comparison of the three reservoir types indicate that reservoir type 2,

represented by Patrick & St. Norwich 2-28 well in this study, tends to have the

highest percentage of pore space. Core porosities for Patrick & St. Norwich 2-28

range from 1.7 to 21.1 % with the mean of 11.5% and standard deviation of 4.42

(Table 3; Appendix D). The mean point counted porosity is at 11.0% with standard

deviation of 6.99 (Table 3; Appendix C). This relatively high porosity is in

accordance with abundant visible, macro intergranular pores in the sample.

Core porosity ranges from 1.1 to 14.4% with the mean of 8.1 % in reservoir

type 3 from the argillaceous Anger 1-20 cores tiC-l. Point count porosity ranges

from 0 to 14.8% with mean the of 7.6%. Reservoir type 1 in the Anger 1-20 cores

#C-2, on the other hand, has the mean of 6.8% and 6.3% respectively for core and

point count porosity. These values are lower than the mean porosities for reservoir

type 3. The best explanation for this relationship is the presence of microporosity due

to abundant clay particles in reservoir type 3 as opposed to the present of quartz

overgrowth cement in reservoir facies 1. Although most of the Anger 1-20 cores

70


71

Table 3

Statistics for Porosity

A. Data From Conventional Core Analysis (Appendix D)

Anger 1-20 Lower Cores (RT1)

Patrick & St. Norwich 2-28

(RT2)

Anger 1-20 Upper Cores

(RT3)

No. of Data, N 46 81 57

Range 1.3 - 13.7% 1.7-21.1% 1.1 - 14.4%

Mean 6.8% 11.5% 8.1%

Std. Dev. 3.70 4.42 2.82

B. Data From Point Count (Appendix C)



(RT2)


(RT3)

N 46 37 57

Range 0 - 14.9% 0 - 23.2% 0 - 14.8%

Mean 6.3% 11.0% 7.6%

Std. Dev. 4.80 6.99 3.73


72

#C-\ samples areclay-cemented, the loss of porosity in the samples is not as great as

porosity loss in quartz cemented samples in reservoir type 1 because micropores are

preserved within the clay crystals.

Permeability and Relative Permeability

The range of permeability in the three reservoir types indicates that reservoir

type 2 in the Patrick & St. Norwich 2-28 well, has the best permeability range (Table

4). An average permeability of 59.40 md for the Patrick 2-28 well sample set

coincides with the abundance of macro and well-connected pores. Although both

upper and lower cores in the Anger 1-20 well contain abundant clay and quartz

cement respectively, the lower cores (cores #C-2) have better permeabilities. The

mean permeability for the lower cores is 12.61 md, while the mean for the upper

cores is 6.67 md. Higher permeabilities in the lower cores are apparently due to the

dominantly well-connected porosity and relatively well sorted pore throats, indicated

by the flat and long plateau on the mercury injection capillary pressure curve (Figure

31). The pore throats in a clay-rich reservoir type 3 are not only smaller but the size

sorting is poor (Figure 33). The result is the poor reservoir quality of reservoir type

3.

Relative permeability is closely related to water saturation in the sample and

therefore related to pore-size distributions and wettability. For reservoir


73

Table 4

Statistics for Permeability



(RT2)


(RT3)

No. of Samples N 46 81 57

Range 0.01 - 130 md 0.04 - 427 md 0.02 - 35md

Mean 12.61md 59.40md 6.67md

type 3, relative permeability to oil and gas would be low because of theabundance of

micropores in its pore system. The high irreducible water saturation inherent in

micropores and throats inhibits oil and gas flow. The larger-pored reservoir types 1

and 2, on the other hand, should have relatively good permeability to oil and gas.

The actual relative permeability ranges for the reservoir samples can only be

interpreted from relative permeability curves which were not available for this study.

Internal Surface Area

In comparison of the three reservoir types, it appears that the argillaceous

sandstones from reservoir type 3 have the greatest internal surface area especially if


74

all the irregular surfaces of the clay-rich samples were unfolded. The uncemented

sandstones from reservoir type 2, on the other hand, would have the least amount of

internal surface area. The quartz cemented sandstones from reservoir type 1 have

moderate internal surface area but the smooth pore walls provide an excellent medium

for fluid flow in the pore system. This fact is supported by the moderate permeability

and the relatively low porosity for sandstones from Anger 1-20 cores ttC-2.

Wettability

For reservoir samples examined in this study, the most water-wet reservoir

type is the reservoir type 3. In the presence of numerous micropores and micro pore

throats, wetting' fluid is tightly held. This situation is supported by the higher

formation water resistivity measurements and the higher percentage of irreducible

water saturation in Anger 1-20 lower cores. In contrast, the presence of macropores

in reservoir type 2 would reduce the wettability toward wetting fluid. With larger

pores, hydrocarbon can break through the thin skin of water protecting the pore wall.

As a result, the percentage irreducible water saturation in reservoir type 2 such as in

Patrick & St. Norwich 2-28 well is generally low (Figure 32).

Breakthrough Pressure

Of the three mercury injection capillary pressure "type" curves (Figures 31,

32, and 33), the curves for Anger 1-20 upper and lower cores (#C-1 and #C-2)


75

require greater breakthrough pressure than Patrick & St. Norwich 2-28 well. If

Jenninngs (1987) displacement pressure determination technique is used, the

breakthrough pressures for both Anger 1-20 upper and lower cores are at 14 psi

(Figures 31 and 33). These high breakthrough pressures are directly related to the

small pore throats encountered in both samples. Breakthrough pressure for Patrick

& St. Norwich 2-28 well (Figure 32) sample, on the other hand, is at 3 psi. This low

displacement pressure indicates the hydrocarbon can be introduced into the sample at

relatively low pressure because of the presence of large pore apertures.


CAPILLARITY PROFILES AND HYDROCARBON COLUMN HEIGHT

Capillarity Profiles

Capillarity Profile of Reservoir Type 1

Capillarity of quartz cemented reservoir samples with intercrystalline porosity

is represented by mercury injection capillary pressure analysis of Anger 1-20 8991’

(Figure 31). The capillary pressure curve for this reservoir sample has an entry

pressure of about 10 psi. Once the entry pressure is achieved, the sample tends to

require only little incremental pressure in order to saturate mercury into the pore

system. The long and flat plateau indicates the pore throats are relatively well-sorted

and the reservoir readily accepts mercury at low pressure.

The irreducible saturation for this reservoir sample is at 8%, which is

surprising low for the relatively small-pored sample. At reservoir conditions, only

small amounts of wetting phase are trapped in the pores, and the reservoir rock

should have good recovery.


Capillarity of clean uncemented reservoir samples are represented by a sample

from Patrick & St. Norwich 2-28 well (Figure 32). This capillary pressure curve is

76


77

Operator: Wolv. Gas & Oil Depth: 89 91 'Wel l : Anger 1 - 2 0 Perm, md: 62.00County: Mecosta Poro, %: 13.3

Wetting P h a s e Satu rat ion ( %)

1008040

0.11000

0l_D cn (n 0v_

" Port “ Size

CL - 1 0

10080 60 40 20100 0

Mercury S a tu r a t io n (&)

Figure 31. Mercury Injection Capillary Pressure Curve of Quartz Cemented Sandstone (Anger 1-20, 8991’).


Pore

T

hroa

t R

adii

(m

icro

n)

78Operator: Wolv. Gas <Sc Oil Depth: 7940'Well: Pat. & St. N. 2 - 2 8 Core Plug # : 17AField: Woodville Perm, md: 1030County: Newaygo Poro, %: 22 .3

Wetting P h a s e Saturat ion (%)

0 100

1000

1 0 0 t

(DD</)CO<p

CLPortSize

20 0100 80 60 40

Mercury Saturation ( %)

Figure 32. Mercury Injection Capillary Pressure Curve of Uncemented Sandstone (Patrick & St. Norwich 2-28, 7940’).

Reproduced with permission of the copyright owner. Further reproduction prohibited without permission

Pore

T

hroa

t R

adii

(m

icro

n)

79

characterized by a low entry pressure (about 1.5 psi). Once the entry pressure has

been exceeded, only little pressure is needed to saturate mercury into the rest of the

pore space within the sample. The relatively flat and long plateau of this curve

indicates an excellent pore throat sorting that enables mercury to be introduced

smoothly.

The irreducible saturation of this reservoir type is relatively low at 6%. This

is the percentage of wetting phase adsorbed onto mineral surfaces that cannot be

removed at maximum pressure o f 2000 psi. The rest of the pore volume (about 94%)

is saturated with mercuiy at 2000 psi. At reservoir conditions, this type of pore

system will accept oil and gas readily at low breakthrough pressure.


Capillarity of a clay-rich reservoir sample is represented by mercury injection

capillary pressure analysis of Anger 1-20 8651’ (Figure 33). The capillary pressure

curve for this sample is characterized by high entry pressure (about 14 psi) which is

due primarily to the small pore throats. Once the entry pressure has been exceeded,

relatively high pressure is still needed to saturate most of the pores. Even when the

maximum pressure of 2000 psi is achieved, only 67 % of the total porosity in the

sample can be occupied by mercury.

The irreducible water saturation for Anger 1-20 8651’ sample is extremely

high at 33 % because significant amount of water is trapped within small pores and


80

Operator: Wolv. Gas 6c Oil Depth: 8651 'Well: Anger 1 - 2 0 Perm, md: 70 .00County: M ecosta Poro, %: 15.8

Wetting P h a s e S a tu ra t io n (%)

1 0 080

1000

<UD cn cn d)

PortSize

Q.

10080 20 060 40100

Mercury S a tu r a t io n (ss)

Figure 33. Mercury Injection Capillary Pressure Curve of Clay-Rich Sandstone (Anger 1-20, 8651’).


Pore

T

hroa

t R

adii

(m

icro

n)

81

pore throats. At reservoir conditions, even if extremely high buoyancy

pressure due to a thick hydrocarbon column are introduced to displace

water, significant porosity will be still occupied by irreducible water

saturation .

Hydrocarbon Column Height

The hydrocarbon column in all three reservoir types examined in

the study must be tall enough to provide buoyancy pressure to

overcome capillary pressure and to displace water in the pore system.

As the hydrocarbon column height above the free water level is

controlled by water saturation and pore type according to Hartmann

(1989), with the availability of water saturation and port size data for

Anger 1-20 and Patrick & St. Norwich 2-28 wells (Appendix D), the

height of hydrocarbon column in each reservoir type can be predicted.

Hydrocarbon Column in Reservoir Type 1

Water saturation for reservoir type 1, represented by Anger 1-20

lower cores, ranges from 21.3 to 91.7% with the mean of 44.8% (see

Appendix D). For the samples with permeability greater than 5 md,

which are the main contributor to reservoir performance, the average

water saturation is at 29.2% (Figure 34). Compared to the higher

average water saturation in the other reservoir types, water saturation


Average Wat. Sat.

Average Port Size

Calculated Hydr. Height 82

All k>5sd All k>5«dSaiple Saaple Saaple Saaple

X Anger 1-20Upper Cores (RT3)

O PSH 2-28 Cores (RT2)

A Anger 1-20

63.8% (58.2%) 2.04 Bicrons (4.30) 2 - 3 ft.

46.lt (38.7%) 4.25 nicrons (6.67) 6 - 7 ft.

44.8% (29.2%) 2.58 Bicrons (5.61) 9 - 2 0 ft.Lower Cores (RT1)

7

204 06C 5 0

Water Saturation (%)8 09 0IOC

Figure 34. Relationship Between Water Saturation, Port Size, and Height of Hydrocarbon Column Above Free Water Level (Modified From Hartmann and Coalson, 1990).


83

in reservoir type 1 is relatively low. This situation is due primarily to

the low irreducible water saturation encountered in reservoir type 1

(see Figure 31). Although the mean port size for reservoir type 1 is only

slightly larger than the mean port size for reservoir type 3 (see Table 2),

the well connected pore system and the smooth pore walls found in

intercrystalline porosity provide excellent medium for fluid movement.

The capillarity is relatively low for this reservoir type.

With the mean water saturation of 44.8% and mean port size of

2.58 microns, hydrocarbon column height between 9 to 20 feet is

calculated for reservoir type 1 from Anger 1-20 lower cores (Figure 34).

This tall hydrocarbon column provides more than sufficient buoyancy

pressure to overcom e capillary pressure for in itia l hydrocarbon

migration. Compared to the shorter hydrocarbon column calculated in

reservoir type 3 which has higher capillarity and irreducible water

saturation, reservoir type 1 does not require the hydrocarbon column as

tall as it currently has. The excess buoyancy pressure, however, can be

used to displace mobile water in the pores. This reservoir rock type has

an excellent reservoir quality because the high buoyancy pressure will

mobilize a large amount of oil and gas into the reservoir.


Water saturation for reservoir type 2, represented Patrick & St.

tReproduced with permission of the copyright owner. Further reproduction prohibited without permission.

Norwich 2-28 cores, ranges from 15.9 to 94.7% with the mean of 46.0%

(see Appendix D). For the samples with permeability greater than 5 md,

the average water saturation is at 38.7% (Figure 34). Although the

average water saturation in this reservoir type is slightly higher than

the average water saturation in reservoir type 1, this reservoir type has

the lowest percentage of irreducible water saturation (see Figure 32).

The majority of saturated water in this reservoir type is therefore

mobile and can be displaced easily at low pressure. The low irreducible

water saturation encountered in reservoir type 2 is directly related to

the presence of the bigger port size (see Appendix D). The mean port

size for Patrick & St. Norwich 2-28 cores is at 4.25 microns.

With an average water saturation of 46.0% and port size of 4.25

microns, the calculated hydrocarbon column is between 6 to 7 feet in

the Patrick & St. Norwich 2-28 well (Figure 34). This moderate

hydrocarbon column height provides lesser buoyancy pressure than

reservoir type 1. However, the capillarity pressure in reservoir type 2

is low due to the abundance of macro intergranular pores and the low

irreducible water. This reservoir type needs only little pressure to

overcome capillary pressure and to introduce hydrocarbon into the

reservoir container. This reservoir type has excellent reservoir quality

because hydrocarbon can be introduced at relatively low buoyancy

p ressu re .


85


Water saturation for reservoir type 3, represented by Anger 1-20

upper cores, ranges from 29.8 to 94.3% (Appendix D) with the mean of

63.8%. For the samples with permeability greater than 5 md, the mean

water saturation is at 58.2% (Figure 34). The high water saturation in

this reservoir type is due both to the abundance of irreducible water

trapped within small pores (see Figure 33) and to the mobile water in

larger pores. The mean port size of 2.04 microns for this reservoir type

is the smallest among the three reservoir types. This is primarily due to

the occlusion of pore throat by authigenic clays.

With an average water saturation of 63.8% and port size of 2.04

microns, the calculated hydrocarbon column is between 3 to 4 feet in

Anger 1-20 upper cores (Figure 34). This short hydrocarbon column

provides a low buoyancy pressure. The capillary pressure in this

reservoir type, on the other hand, is relatively high with the presence of

small pores and higher irreducible water. In order for oil and gas in this

reservoir type to be recovered, the buoyancy pressure must be high

enough to overcome capillary pressure. Otherwise, hydrocarbon cannot

be introduced into the pore system to displace water.


SUMMARY AND CONCLUSIONS

Of the three reservoir rock types examined in the study, the well sorted,

uncemented medium-grained sandstone of reservoir type 2 has the best reservoir

quality. This fact is supported by the excellent oil and natural gas production from

wells in the Woodville field, Missaukee County (Appendix A). Recovery factors for

the weakly cemented sandstone reservoir have been estimated at approximately 80%

by Barnes et al. (in press). At pore-scale, the excellent quality of reservoir type 2 is

indicated by the relatively high Buckles number and the large pore throat at 35%

mercury saturation (Table 5; Figure 35). High recovery efficiency and good

production histories in the Woodville field are due to the primarily macro

intergranular pore system, low irreducible saturation, high porosity and permeability,

and small internal surface area in reservoir rocks of reservoir type 2.

The clay-rich sandstones of reservoir type 3 have the poorest reservoir quality.

Production from Gilde 1-25 and Edwards 7-36 wells of Falmouth field in Missaukee

County can be characterized as reservoir type 3 and have proven low recovery

efficiency and hydrocarbon production. The recovery factors for this reservoir type

have been determined at 55% (Barnes et al., in press). Buckles number for this

reservoir type is surprisingly high (Table 5, Figure 36), but it is primarily due to

the high percentage of irreducible water. The approximated pore throat size is

86


87

Table 5

Statistics for Buckles Number



(RT2)


(RT3)

No. of Samples N 46 81 57

Range 5 1 .0 - 505.7 59.8 - 950.4 62.6 - 964.92

Mean 260.9 492.5 513.3

Std. Dev. 123.94 184.06 229.89

relatively small for this reservoir type (Figure 36). The poor reservoir quality for

reservoir type 3 is indicated by the high irreducible water saturation, moderate

porosity, low permeability, and high internal surface area.

The quartz cemented sandstones of reservoir type 1 have intermediate reservoir

quality. The cumulative production from the Reed City field, representing reservoir

type 1, is not as high as the Woodville field. Although the recovery factors for this

reservoir type have not yet determined, Barnes et al. (in press) predict them to be

comparable to reservoir type 2. Buckles plot for Anger 1-20 lower cores indicates

the Buckles number to be relatively low, but the approximated pore throat size


Wate

r Sa

tura

tion

(%)

88

Swxf i )100 -

90 -

80 -

70

60 -

50

40 -

30

20

10

00 5 10 15 20 25 30

Porosity (%)

Figure 35. Buckles Plot for Patrick & St. Norwich 2-28 Cores.

/ A

2 8 0 0

2 4 0 0

2000

1 6 0 0

1 3 0 0

1000

7 0 0

5 0 0

3 0 0100


Wate

r Sa

tura

tion

(%)

89

S w x0100

20009 0 -

8 0 - 2 4 0 0

7 0 -2000

6 0 -

50 1 6 0 0

1 3 0 04 0 - 6 o o 0° H ./"v >11 10003 0 -

7 0 0

5 0 0

3 0 0100

20 -

10 -

0 6 (Appro*.)

Porosity (%)

Figure 36. Buckles Plot for Anger 1-20 Upper Cores.


90

S w x f t

aomt-Pww

00

<Dco

1002 8 0 090 -

80 - 2 4 0 0

200060 -

1 6 0 0

40 - 1 3 0 0

lO O O

700

5 0 0

3 0 0100

20 -

,o‘

50 15

Porosity ( % )

Figure 37. Buckles Plot for Anger 1-20 Lower Cores.


91

is large (Figure 37; Table 5). The intermediate reservoir quality of this primarily

quartz cemented reservoir is explained by the well connected intercrystalline porosity,

moderate permeability with relatively high porosity, low irreducible water saturation,

and low internal surface area.

The pore-scale characterization techniques used in this study can be integrated

with facies-scale framework for the better appraisal of reservoir performance.

Geologic processes that create and modify porosity such as depositional setting and

diagenesis must be fully understood for a better prediction of pore-scale parameters.

The techniques, however, should be applied on a broader regional basis as opposed

to the limited number of samples used in the study.


Appendix A

All Time Oil and Natural Gas Production in Michigan "Deep" Play

92


93

ALL-TIME MICHIGAN DEEP NATURAL GAS PRODUCTION(Annual and Cumulative Production In Met Q 14.73 pala)

COUNTY/FIELO

LEASE NAME/NUMBER (MPSC I)

Monthof first Cumulative

Production thru 1W0 1969Jan. thru Nov. 1990

Cumulative thoi

Nov. 30,1990

ALPENA Fletcher Pond Snowplow 5-9 (2598)Snowplow 6-9 (2599)Snowplow 7-5 (2600)Snowplow 10-1 (2602) Snowplow 11-8A (3036)Tyred 1-36(3267)

ARENACAuGretAuGres 2-12 (ONR)

Clayton (b)BfiQQS 1*12 (ONR)Callotto Unit 1-31 (ONR) Donahue 1-32 (ONR)Frank Unit 1-2 (DNR) Haroulunlan Unit 14 (ONR) Mansfield Unit 1-36 (ONR) Seignlous Unit 1-10 (ONR)

BAYKawkawtlnSheppard 1-2(3109)

CLARECranberry Lake Lease Management 1-12 (2391) State Winterlield 1-12 (2451) Winterfield 1-2 (3120) Winterfield 2-12(3119) Summerfield 2-10 (3121) Summerliotd 1-18 (3412)

W lnledW dState Winterfield 1-31 (3117) Marlon 1-36 (2943)State Winterfield 2-31 (3380) Mahon 2-36 (3382)

GLADWIN South Buckeye Letts Unit 2-36(2260) Ballentine Unit 1A-35 (2402) Wineman Unit **0" 2-9 (2510)

GRATIOT Jooealield Frost 1-1 (3377)

IOSCORenoReno 1-27 (2497)

KALKASKA Beaver Creek (d|Geo. Garden "A" 1-12 (3409) Stale Joseph 1-7 (3674)

MECOSTAAustinSchuberQ 1-33A(2725)

Sevens LakeFenstermacher 1-14 (2527) Fry 1-19(3337)

Big Raplda Hudson 1-19(2656)Anger 1-20 (2741)

CatoDeerfield 1-36A(3146)

11/6011/801/89

11/8010/8910/89

12/80

9/882/892/893/892/892/899/80

3/878/876/089/06

10/865/90

11/886/89

12/892/90

7/858/867/88

753.66754.003

5/908/90

1/893/89

75.143 746,519 387.607 1.209.34974.690 399.890 549.731 1.024.311

135.737 53.397 189.13450.606 1.108.432 806,475 1.965.515

129.989 394.648 524.637_ _ 93.074 874,664 967.738

FIELD TOTAL 5.880.684

15.746 156,255 78,534 250.535FIEUD TOTAL 250.535

21.949 256.079 92.725 371,553673.971 656.974 1,332,945

__ 223,964 133.987 357.951__ 316.554 291.774 606.328_ 698.639 673.847 1,372,686_ 159.252 34.006 103.258

. _ 526.096 434.766 - ( b) 960.864FIELD TOTAL 5.197.585 (b)

153.470 434.324 587.602FIELD TOTAL 587.802

13.625 105(C) _ _ 13.7304CC.41C 909.359 820.539 571.828 2.708.144

268.714 324.662 178.302 771.678— 139.709 357.720 479.039 976.468

5.869 390.832 271.219 667.920_ — 380.402 380.402


64.882 975.706 685,244 1.725.832264.947 716.426 981.373

_ 4.347 493.478 497.825_ _ _ 120.726 120.726


250.204 232.095 320.138 280.604 1.836.90661.601 54.594 19.801 44.060 234.059

105.848 201.897 239.262 547.007FIELD TOTAL 2,617.974

_ - 141.156 141.156

FIELD TOTAL 141.156

626.345 1,006,172 341.784 1.974.301FIELD TOTAL 1.974.301

85.381 85,301__ _ 24.380 24.380

FIELD TOTAL 109.761(d)

213.530 94.192 307.722FIELD TOTAL 307.722

35.518 118.782 16.912 171212— 419.418 419.418

FIELD TOTAL 590.630

1.465.499 589.116 2.054.615_ _ 1.312.111 638.359 1.950.470

FIELD TOTAL 4,005.085

_ — 250.935 356.223 607.158607.158


ALL-TIME MICHIGAN DEEP NATURAL GAS PRODUCTION(A nnual a n d C um ula tive P ro d u c tio n In M cl ® 14.73 p a la )

COUNTY/FIELD/LEASE NAME/NUMBER (MPSC 1)

Month ol first

ProductionCumulativethru 1966 1967 1988 1989

Jan. thru Nov. 1900

Cumulative thru

Nov. X , 1900

H*nfy Oam Armstrong 1*8 (2388) Armstrong 1-8A (2692)

12/869/88

2,374 225,792 17571,783

- (a) 672,269 523,324

FIELD TOTAL

220,3411.287.3761,495,717

Stanwood Albof 1*23 (2450) 12/87 - 12.359 1.498.148 789.439 538.952

FIELD TOTAL2.829.8962.829.896

MISSAUKEEFalmouthEdwards 7-36(2138) Gild© 1-25(2139)

10/8211/82

3.270.0191.844.368

97.14580,738

7,58079.530

94.30476,356

103.066 57.481

FIELD TOTAL

3.572,1142.138.4735.710.507

ForwardClam Union 1*31 (3230) Clam Union 1*30 (3381)

10/882/90

- - 11,177 656.964 699.624 352229

FIELD TOTAL

1.367.765352229

1,720,094

FUvarsldaRiverside 1*15(3116) B/90 - - - - 106,585

FIELD TOTAL186.585186.585

NEWAYGO Balts Creak (0 Daniels 1*1 A (2457) 2/88 - - 62,196 2,407


Blaal Lika (0Hudson 1-35 (2301) Johnson 1-35A (2352)

10/852/87

260,197 45.241168.078 16,755

11,830 2.054 (0

14.917

FIELD TOTAL

332,185186.887519,072

Croton (d)Bird 1*3(3500) B/90 - - - “ 115.726


EntleyButler & Highland 1*7

(PDC 2448/GLN 2500) (g) GoodwallAnderson 1*8A (2211)Mich Con 1-8(2234) Primark 1*17(2418)Mich Con 2-8 (3076)

12/87

3/8410/849/871/90

3.590.340 713.407

59,286

1,286.523377,891

77.047

1,327,424

1,315,512278.379277.646

1.940.573

1,185.482187,460281,806

1,525,139 FIELD TOTAL

243,829 160.093 184,799 331.090

FIELD TOTAL

4.852.4224.852.422

7,621,6861,717,230

621299331.090

10.491204

HubarVandedey-Millis 1*SA (2679) 1/89 - - - 152,123 (h)


Hungarford Norwich 1-22 (2790) 5/89 - - - 484.639 431,147


Woodvtlla Jam sm a 1-29 (2294)Allman 1*20 PDC (2323)Allman 1*20 Gleenwood (2324) Patrick A Stale Norwich 2-28 (2338) Cross 1*29 (2378)Bulmer 1*33(2379)Wenstrom 1-33 (2403)Woirol 1*32 (2459)

10/853/863/867/862/872/874/872/88

1,632,144 1.026.690

15,185 (i) 618,395

1,392.6571,021.838

1,530,5171,028,0911,133.480

629.549

1,547,723781,661

1,680.728971.915

1.653.296848,116472.439

1,366,123 333.495 (i)

1,435.837940,259

1.470,801834,211503,024

864.289

1,094,356 233,078

1,472,328 505.769

36,168 FIELD TOTAL

6.002.9363,163.684

15,1856,359,63332333435.735.9073,017.6451,011,631

29,340.164

OGEMAW floa t CityStale Foster 1-20(2412) Slate Foster 1-21 (2427) Stale Foster 2-28 (2452) Slate Rose et al 2-27 (2932) Foster 1*19(2791)

9/879/872/88

10/8910/90

-

250.280408.914

238.0563,316,151

751,156

100.0973.012.8451243.353

101.859

568.885 1.420.579

671.193 570.561 50.632

FIELO TOTAL

1,157.3108.158,4892.665.702

672.42050.632

12.704.561

Waal Branch V. Nelson 1-26 ( - ) ( j)V. Nelson 1*26A (3672) (j) Meir 2-21 ( -)U )Meir 2-21A (3673) (j)Trout 3-18(3694)N. Seeley 1*27 (3379) V.arren 1-20 (3329) Robinson M 3 (3330)

6/862/903/87

11/8911/872/886/88

12/88

20.474 21,102

31,050

39.286

95.406

245.771

657.62888.677

418.30533.147

51,700

77671.467

391.897168.436497.874182.447

53.303

312.326 285.888 177.202 372.964 125.757

FIELO TOTAL

188.69053303

277.597383.793

1.374.699434J15

1289.143341.351

4.342.891

OSCEOLABurdallBoyce 1-19(2355) Boyce 2-19(2377)

12/861/87

57.003 1.819.721221.630

657.777144,586

194.112 27 (k)

177.912

FIELD TOTAL

2.906.525366243

3272.768


95ALL-TIME MICHIGAN DEEP NATURAL GAS PRODUCTION

(Annual and Cumulative Production In Met <& 14.73 psta)

COUNTY/ Month CumulativeFIELD/ of first Cumulative Jan. thru thruLEASE NAME/NUMBER (MPSC 1) Production thru 1966 1907 1066 1909 Nov. 1900 Nov. 30, 1000

Burdall. Sac. 5Stale Burdetl 1 5 (2655) 12/88 21.666 649.754 (I)


LeroyLowe 1-27 (2724) 11/88 273.790 2.062.917 938,612

FIELD TOTAL3.275.5193.275.519

Mineral SpringsSherman 1-20 (2621) 2/89 180.499 3.410


Reed CityRuwe-Gul! 1-19A (2308) 3/86 1.623.562 942.086 1.068.130 1.529.142 1.000,324 6.191.246Baderschneider 1-30 (2354) 12/86 68 (m) — — — — 66Coney 1-5 (2341) 1/87 — 857.327 765.953 1.179.626 427.023 3.229.929Gingrich 1*31 A (2393) 3/87 — 246.014 527.022 596,296 325,430 1.694.764Jew ell 1-32(2496) 6/88 507,326 421.060 148.154

FIELO TOTAL1.076,540

12.192.547Reed City. EaatGreenwald 1-27 (2900) 9/89 — — — 310.540 415.956 726.498Glese 1-34 (2899) 9/89 312.468 490.173

FIELD TOTAL602.641

1,529.139Rose LakeH. Zinger 1-1 (2605) 12/68 — — 2.631 789.901 460.963 1.253.495Wanner 1-32 (2604) 1/89 — — — 124,139 11.827 135.966Leon Parmelee 1-7A (3147) 7/89 165.410 204,502

FIELD TOTAL369.912

1.759,373OSCODA

MloU S A Mentor “C” 1-29 (2340) 10/86 178,782 910,935 1.126,678 1,302.930 931.605 4.453.130U S A Mentor "C" 1-32 (2712) 7/87 — 203.661 499.539 771,953 627,955 2,103.308U S A Mentor MCM 1-33 (2S53) 1/88 — — 545.528 171,731 549,563 1,266,822U .S A Mentor MC" 1-30 (2552) 2/88 — — 693.107 517,729 624,196 1.835.034U S A Mentor ••C” 2-32 (3228) 1/89 ~ — 131.193 151.773

FIELD TOTAL282.966

9.941.260Wagner LakeU S A 8io Creek *,DM 1-23 (3156) 4/89 — — — 555.013 666.709 1.221.722U S A Big Creek “CT 1-14 (3155) 5/89 — — — 419.456 792,793 1,212.249Big Creek t-15 (3378) 6/90 — — — — 194.792 194.792U S A Big Creek 1-24 ( - ) 10/90 “ — 60,921

F/ELD TOTAL60.921

2,689.684OTSEGOCharlton, Sec. 16Johannesburg M/g e t al 3-16 (—) 1983 46,684 - (n)


TUSCOLAAkronHarrington 1-30 (2863) 4/89 — — — 333.485 236.473 569.958Downing 1-32(3168} 11/89 — — — 6,207 36.019 42.226Ruppert 1-25 (3124) 3/90 2.730

FIELO TOTAL2.730

614,9)4AJmerSouth Aimer Land Co. 1-10 (2671) 1/89 — - - 37.714 (o) - 37.714

FIELD TOTAL 37.714

ANNUAL/CUMULATIVE TOTALS 1S.707.5W 10.050,200 20,000,607 45,740.730 30,403,802 142.771.355

On/7 product/on from h o r izo n s b e lo w th e (o p o f tb s O rdovician B lack R lrar G ro u p 's G le n w o o d M em b e r Is In c lu d e d In a b o v e s ta t is t ic s , S a ta ra l o f (ha walla a n d H a ld t lla tad a /so produce fro m ahatlow ar h orizo n s, particu larly tha S ilurian B urnt B lu tt or C//nfon She/a, b u t tha ah a tlo w a r p ro d u c tio n Is n o t In c lu d a d bars.

FOOTNOTES:(a) Last ta co rd a d pas product/on for Se/gn/ous U nit MO wall

In M ay IM S .(b) 1990 a n d c u m u la tiv e p r o d u c tio n Is th ro u g h S e p te m b e r 1990

on ly , la taa t d a ta available.(c) Laaaa M a n a g e m e n t 1-12 w a ll (23911 la s t p r o d u c e d g a s In

1908, State W ln ta rlla ld M 2 (2451) Is ra p la ca m a n t wall.(d) 1990 a n d c u m u la tiv e p ro d u c tio n Is th ro u g h O c to b e r 1990

on ly , la ta a t d a ta available.(a) A rm stro n g 1-9 w all (2508) la s t p r o d u c e d gaa In F ebruary

1988, A rm s tro n g 1-8A w ell (2892) drilled a s re p la c e m e n t In 1988.

(f) D an iels M A w e lt (2457) re -c la es lfle d a s d isc o v e r y wall o f B e tte C reek F ield , n o p ro d u c tio n re c o rd e d fro m Pralrfa d u C ttien a tta r A p r il 1989; J o h n s o n 1-85A w e ll (2852) la s t pro . d u c e d g a s In A pril 1989.

(g) B u tler 8 H igh la n d 1 7 w all (244$ re c o m p le te d In early 1988 to r p ro d u c tio n fro m G le n w o o d Z o n e (n ew P SC I250OJL

(h) V andotley M llllt 1 5 A w all's (2879) Prairie d u C h ia n In terval shu t-in , la s t p r o d u c e d g a s In O ctober IMS.

(!) A ltm a n 1-20 w ell la s t p r o d u c e d g a s from G le n w o o d Z o n e (2824) In S e p te m b e r 1985, Prairie d u Chian Z o n e h a s n o t p ro d u c e d g a s s in c e M ay 1989.

(J) V. N e lso n 1-25 a n d Matr 2-21 w e lls d lrec tlo n a lly redrllled In 1989 a n d 1990, r ep la ced b y th e V. N e lso n 1-26A a n d M eir 2-214.

(k) B o y c e 2-10 w ell (2877) la s t p r o d u c e d gas In J a n u a ry 1989.(I) S ta te B urde tl 1*5 w ell (2655) c u rre n tly s h u t ln, la s t p ro d u c e d

In D e c e m b e r 1989.(m) B a d a rsch n eld a r 1-30 wall (2854) s h u t ln sh o r tly a fte r h o o k e d

up for c o m m e rc ia l p ro d u c tio n In 1986.(n) J o h a n n e sb u rg M fg. a t a l 8 1 6 w e ll (— ) la s t p r o d u c e d g a s In

1988.(o) S o u th A im e r L a n d C o m p a n y 1-10 wall (2671) h a s n o t p ro

d u c e d g a s s in c e 1990,

with permission of the copyright owner. Further reproduction prohibited without permission.

96

ALL-TIME MICHIGAN DEEP OIL AND LEASE CONDENSATE PRODUCTION T h ro u g h M arch 1 9 8 9 in 4 2 -g a l lo n b a r re ls

COUNTY/FIELD LEASE NAME i NUMBER OHM TermM 0

Caawtatta ett produced DroM*tk mi COUNTY/HELD LEASE NAM 4 HUVSCft (OMR Pero* 0

Cewrtadu efl oM k M tkv Mart* f t t t

ALPENA/FUtcner PondSnowplow 5-9 (39200) 27.189Snowplow 6-9 (39966) 20.503Snowplow 7-5 (39990) 4.241

ALPENA/Hardwood PointState Sanborn & Wade 1-20 (40935) 433

ARENAC/AuGreaAuGres 1-12 (40*03) 44.751

ARENAC/CtaytonBriggs Unit 1-12(39689) 2.962Caiiotio Unit 1-31 (40G69) 4.166Donahue 1-32 (39954) 2.275Haroutunian Unit 1-4 (39249) 1.536Mansfield Unit 1-36 (40559) 1.376Seigmous Unit 1-10(40336) 3.008Frank Unit 1-2 (40663) 1.247

BAY/E see avtlleVarmee&ch 1-21 (39558) 2.404

BAY/FraserMeU 1-15(39976) 90LaHar 1-7 (40516) 2.551P ro sse ta l 1-12 (40916) 3.072

BAY/KawkawllnDobson et a ll-6 (40526) 630Prevost 1-11 (37779) 15.932Walcaek 1-7 (39203) 2.070Frank & Eisenman 1-3A (40090) 410Whyte 1-33(40925) 180

CLARE/Cronberry LakeState Winterfield l-!2 (40044) 1S.879State Winterfield 1-2 (40419) 6.814Stale Summorfield 2-18 (40577) 531SUte Winterfield 2-12 (40933) 2.969

CLARE/WlrtferfleldSUte Winterfield 1-31 (40987) 778

GLADWIN/South BuckeyeBallentine Unit 1A-35 (39600) 3.913Letts Unit 2-36 (37562) Wmeman Unit “ B'' 2-9 (40967)

26.3342.111

(OSCO/RenoReno 1-27 (40267) 19.074Reno 1-26 (411 tQ) 1.519

MECOSTA/Bevena LakeFenstermacher 1-14 (40242) 270

MECOSTA/BIg RapldaHudson 1-19 (41116) 4.509Anger 1-20 (41137) 997

MECOSTA/CatoDeerfield 1-36A (41328) 19

MECOSTA/Hardy DamArmstrong 1-6(39713) 1,659Armstrong 1-8A (41299) 6.501

MECOSTA/SUnwoodAJber 1-23 (40215) 391

MtSSAUKEE/ForwardCUm Umon t-31 (41179) 3,510

MONTMORENCY/FUtcher Pond. WestSnowplow 10-1 (40231) 31,533

* — West Branch Praino du Chien production reported is through June 19

NEWAYGO/Detti Croek Oamets 1-1A (40203)

NEWAYGO/Blael u * eHudson el K 1-35 (30G01)Johnson 1-35A (40002)

NEWAYGO/trialey Butler & Highland 1-7

NEWAYGO/Goodwefl A nderson 1-6A (36622)Michigan Consolidated Gas 1-6 (37469) Pnmark 1-17 (40030)

NEWAYGO/Huber Vandertey-MiUis 1-5A

NEWAYGO/Woodv1lt«A/tman t-20 (39166) (Glenwood)Art man 1-20 (39166) (PdQ Wonstrom et all-33 (40053)Cross 1-29 (39901)Jansma 1-29 (36567)Patrick-State Norvnch 2 28 (396S6) Bulmer 1-33 (39916)Wcwroi 1-32 (40361)

OGEMAW/Roee CfTy Hogoman 1-27 (40067)Stale Foster 1-20(38624)Slate Foster 1-21 (40133)State Foster 2-26 (40372)State Foster 1-19 (40676)

OGEMAW/Weel Brooch*Meir 2-21 (40068)N Seeley 1-27 (40676)Trout 3-10 (40546)V. Nelson 1-26(39749)

OSCEOLA/Burdeti Boyce 1-19 (39106)Boyce 2-19(39654)

OSCEOLA/Reed CJty BaderschnexSor 1-30(39750)Corvey 1-5 (39752)Gmgnch 1-31A (40063)Jew ett 1-32 (40491)Ruwe-Gutt 1-19A (39157)

OSCODA/M lo USA Mentor "C” 1-29 (36833)USA Mentor "C" 1-32 (39996)USA Montor •,C" 1-30 (40445)USA Mentor "C" 1-33 (40446)USA Mentor “C" 2-32 (41401)

OSCOOA/Wegner Lake USA Big Croek "D" 1-23 (40691)

OTSEGO/Chartton, Sec. 16 Johannesburg Mfg. et al 3-16 (3S113)

TUSCOLA/Akron Harrington 1-30(40136)Ruppen 1-25 (40667)

Tu sc o la /Aimer South AJmer Land Company 1-10 (40656)

TOTAL

more tecent data not available at press time.

4.1312.125

105.36612.1613.846

3754.27143.56051.86685.23488.35257.1539.896

4557.8342.6562.396

191

17.7058.405

70.7245.012

10.74915

32S8,902

42.8114.690

54.695

77.27830.80429.89816.185

277

205

1.126

2.443319

1.215,028

(From Michigan’s Oil and Gas News, v. 96, no. 35, p. 12-15, and v. 97, no. 13, p. 18-20)


Appendix B

Core Descriptions

97


KEY TO CORE DESCRIPTION

Litbolooies Sandstone

~ \ 1 r Shaley/Clay-rich SandstoneZ DoloaiteT V - T Doloaitic Sandstone

Ceaents ^ j Quartz overgrowthx I Doloaite

Clay

Sortinq Roundness

XW Extreaely well 0 Angular

VW Very well < Sub angular

W W e U 0 Subrounded

H Hoderately P Poorly

VP Very poorly

0 Rounded

Sediaentarv Structures

- s = - Planar stratification (laainated bedding) A Horizontal burrows

Cross-strata / cross-laainae I T Vertical burrows

Wavy beddings Clasts

Cross beds - v Hud cracks

Graded bedding Fractures

Hassive (structureless) bedding Mottled features

Scour surface StylolitesHicrostylolites


Key to Core Description - - Continued

Bioturbation -0^ Slight ~0- Hoderate

■0* WellVery well (churned)

Oil Stain • Poor oil stain

«• Good to excellent oil stain

Consolidation UC Gnconsolidated SC Slightly Consolidated HC Moderately Consolidated

Visible Porosity• T r ace

i P o o r (1-5%)

II Fair i5 - t 0 % i

l i ! G o o d (10-15%)

I l l l E x c e l l e n t i > 15°t>i

V T r a c e

.1 P o o r (1-5%)

i t Fair i 5 - ) 0 % i

i l l G o o d (10-15%)

1111 E x c e l l e n t (> 1 5%i

H Visibly i n t e r c o n n e c t e d

P o o r (1-5%)

< 8 * Fair (5-10%i

G o o d (10-1 5%)

E x c e l le n t (> 15%)

HWC Hoderately-Well Consolidated WC Well Consolidated

VWC Very Well Consolidated

4-&LC

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Appendix C

Point Count Data

104


RAW P O I N T COUNT DATA 105

ANGER 1-20 WELL -- UPPER CORES

DeDth Qtz Fid Lith Pol QOvq Clay Poro Total

8603-04 130 5 0 112 5 0 0 252

8604-05 190 3 0 40 9 4 8 254

8605-06 202 18 1 9 0 10 17 257

8606-07 120 10 1 31 0 0 0 252

8607-08 183 6 0 4 16 17 25 251

8608-09 191 5 1 1 24 0 31 251

8609-10 222 4 0 1 4 2 20 253

8610-11 218 8 0 2 18 2 19 267

8611-12 201 10 0 0 14 0 25 250

8612-13 219 6 1 0 3 0 23 253

8613-14 201 9 0 0 12 0 31 253

8614-15 207 7 0 0 17 0 19 250

8615-16 204 8 0 0 15 0 23 250

8616-17 207 7 0 0 17 0 30 250

8617-18 203 3 0 1 23 0 27 257

8618-19 207 3 0 0 19 1 25 255

8619-20 206 5 0 0 3 23 18 255

8620-21 211 3 0 0 5 11 15 245

8621-22 205 9 0 0 5 9 28 245

8622-23 225 3 0 0 4 1 14 247

8623-24 206 6 1 0 17 2 22 254

8624-25 190 5 0 0 39 0 16 250

8625-26 220 11 0 6 6 4 6 253

8626-27 194 6 0 0 34 0 20 254

8627-28 197 10 0 0 18 0 26 251

8628-29 192 8 0 0 17 2 29 248

8629-30 192 6 0 0 10 5 37 250

8630-31 198 5 1 0 9 3 36 253

8631-32 203 1 0 0 2 23 25 252

8632-33 188 1 1 0 8 27 25 250

8633-34 205 1 0 0 4 22 19 251

8634-35 224 2 0 2 2 13 10 253

8635-36 46 2 0 205 0 0 0 253

8636-37 198 0 0 2 30 5 15 248


RAW POINT COUNT DATA

ANGER 1-20 -- UPPER CORES

Depth Qtz Fid Lith Dolo QOvg Clay Poro Total

8637-38 183 1 0 7 50 2 7 2508638-39 211 0 0 0 5 30 4 2508639-40 186 2 0 3 3 2 4 2508640-41 198 7 0 0 31 0 20 2568641-42 194 2 0 9 13 1 34 2538642-43 207 0 0 0 23 4 16 2508643-44 198 4 0 2 3 23 24 2548644-45 196 3 0 0 6 31 17 2538645-46 205 4 0 0 4 32 10 2558646-47 193 2 0 1 3 30 23 2528647-48 198 4 0 2 3 28 15 2508648-49 185 7 0 0 10 20 28 2508649-50 187 15 0 2 3 18 30 2558650-51 192 3 0 0 11 12 20 2488651-52 188 3 0 6 4 26 24 2518652-53 203 1 0 1 2 18 26 2518653-54 190 1 0 4 7 20 25 2478654-55 193 9 0 2 16 10 24 2548655-56 200 5 0 0 4 27 15 2518656-57 205 8 0 3 11 16 10 2538657-58 215 1 0 0 33 0 2 2518658-59 202 1 0 7 7 17 17 2518659-60 217 6 0 0 0 21 9 253


RAW POINT COUNT DATA

ANGER 1-20 -- LOWER CORES

Depth Qtz Fid Lith Dolo OOvq Clay Poro Total

8978-79 135 14 1 102 6 0 0 2588979-80 226 3 0 0 12 1 8 2508980-81 202 8 0 0 17 4 20 2558981-82 232 6 1 0 16 0 2 2578982-83 191 0 0 0 54 1 4 2508983-84 205 10 0 1 22 2 17 2578984-85 213 11 0 0 11 1 18 2538985-86 210 7 0 0 3 12 16 2488986-87 135 11 0 125 0 0 0 2718987-88 210 7 0 1 0 29 9 2568988-89 188 7 0 59 0 0 0 2548989-90 207 11 0 0 21 0 17 2568990-91 198 10 0 0 21 1 29 2598991-92 200 12 0 0 6 1 36 2558992-93 210 16 0 0 3 1 29 2598993-94 190 12 0 0 14 0 34 2508994-95 196 4 0 0 22 0 31 2538995-96 199 9 0 0 7 0 34 2588996-97 212 7 0 0 5 0 26 2508997-98 197 11 0 0 21 0 25 2548998-99 198 10 0 0 32 0 25 2658999-00 195 7 0 0 15 0 38 2559000-01 216 9 0 0 3 0 22 2509001-02 180 7 0 0 61 0 8 2569002-03 216 13 0 0 1 15 11 2569003-04 205 5 0 0 50 0 0 2609004-05 184 7 0 0 45 0 19 2559005-06 209 12 0 0 7 1 32 2619006-07 192 10 0 0 18 0 34 2549007-00 200 10 0 0 33 0 12 2559008-09 198 11 0 2 11 0 27 2509009-10 192 14 0 0 17 0 28 2519010-11 200 6 0 0 17 0 26 249


RAW P O I N T COUNT DATA

ANGER 1-20 - - LOWER CORES

DeDth Qtz Fid Lith Pol Qovq Clay Poro Total

9011-12 180 16 0 1 34 0 28 2599012-13 208 6 0 1 1 0 24 2509013-14 193 4 0 0 48 0 5 250

9014-15 212 10 0 0 1 1 20 2539015-16 208 5 0 0 24 0 15 2529016-17 235 11 0 8 0 4 0 2589017-18 214 11 0 0 25 0 6 256

9018-19 200 18 1 15 21 0 2 257

9019-20 176 28 0 50 7 3 1 2659020-21 220 14 0 16 7 0 1 258

9021-22 218 2 0 11 13 0 6 2509022-23 210 3 0 16 11 0 10 2509023-24 188 0 0 36 26 0 0 250


RAW P O I N T COUNT DATA 1 0 9

PATRICK & ST. NORWICH 2-28 WELL

Depth Qtz Feld Lith Dolo Qovq Cla_y Poro Tota l

7924.5 196 2 0 6 1 37 16 251

7925.5 147 3 0 80 0 10 10 250

7926.5 120 4 2 116 0 8 0 250

7927.5 160 1 0 73 1 3 12 250

7929.5 202 0 0 6 8 8 26 250

7930.5 198 1 0 0 5 4 28 250

7931.5 191 0 0 3 0 3 53 2507932.5 205 0 0 5 1 0 39 2507933.5 212 0 0 1 0 3 34 2507934.5 196 0 0 5 1 6 42 2507935.5 202 0 0 4 1 11 33 2507936.5 156 0 0 73 3 0 18 2507937.5 83 1 0 166 0 0 0 2507938.5 184 2 0 0 2 0 63 2507939,5 198 0 0 0 1 0 51 2507940.5 212 0 0 0 1 0 37 2507942.5 194 2 3 0 1 0 50 2507943.5 198 1 0 0 0 0 51 2507944.5 204 1 0 0 1 0 44 2507945.5 183 2 0 0 5 0 60 2507946.5 186 2 0 0 1 0 61 2507947.5 189 1 0 1 7 0 52 2507948.5 195 1 0 0 4 0 50 2507955.5 211 1 0 0 2 3 33 2507959.5 218 1 1 0 0 5 25 2507962.5 209 0 2 0 2 0 37 2507967.5 210 1 0 0 4 5 35 2507972.5 195 1 0 0 3 1 50 2507978.5 210 1 0 0 6 12 22 2507983.5 214 0 0 0 16 3 17 2507986.5 204 1 0 0 3 0 42 2507987.5 210 0 0 10 0 5 25 2507992.5 206 0 0 0 4 21 29 2507994.5 191 0 0 1 6 22 30 2507999.5 191 0 0 0 19 15 25 2508000.5 197 0 0 0 30 0 17 2508003.5 220 0 0 0 23 0 7 250


PERCENTAGE POINT COUNT DATA

ANGER 1-20 - UPPER CORESpepth Otz Feld Lith (Q/F/L) Polo OOvq Clay Tot Cat Poro Cut+Poro8603-04 51.6 2.0 0 (96.3/3.7/0) 44.4 2.0 0 (46.4) 0 (46.4)8604-05 74.8 1.2 0 (98.4/1.6/0) 15.7 3.5 1.6 (20.8) 3.1 (23.9)8605-06 78.6 7.0 0.4 (91.4/8.2/0.4) 3.5 0 3.9 (7.4) 6.6 (14.0)8606-07 47.6 4.0 0.4 (91.6/7.6/0.8) 12.3 0 0 (12.3) 0 (12.3)8607-08 72.9 2.4 0 (96.8/3.2/0) 1.6 6.4 6.8 (14.8) 10.0 (24.8)8608-09 76.1 2.0 0.4 (97/2.5/0.5) 0.4 9.6 0 (9.5) 13.5 (22.5)8609-10 87.7 1.6 0 (98.2/1.8/0) 0.4 1.6 0.8 (2.8) 7.9 (10.7)8610-11 81.6 3.0 0 (96.5/3.5/0) 0.8 6.7 0.8 (8.3) 7.1 (15.4)8611-12 80.4 4.0 0 (95.3/4.7/0) 0 5.6 0 (5.6) 10.0 (15.6)8612-13 86.6 2.4 0.4 (96.9/2.7/0.4) 0 1.2 0 (1.2) 9.1 (10.3)8613-14 79.4 3.6 0 (95.7/4.3/0) 0 4.7 0 (4.7) 12.2 (16.9)8614-15 82.8 2.8 0 (96.7/3.3/0) 0 6.8 0 (6.8) 7.6 (14.4)8615-16 81.6 3.2 0 (96.2/3.8/0) 0 6.0 0 (6.0) 9.2 (15.2)8616-17 82.8 2.8 0 (96.7/3.3/0) 0 6.8 0 (6.8) 12.0 (18.8)8617-18 79.0 1.2 0 (98.5/1.5/0) 0.4 8.9 0 (9.3) 10.5 (19.8)8618-19 81.2 1.2 0 (98.6/1.4/0) 0 7.4 0.4 (7.8) 9.8 (17.6)8619-20 80.8 2.0 0 (97.6/2.4/0) 0 1.2 9.0 (10.2) 7.1 (17.3)8620-21 86.1 1.2 0 (98.6/1.4/0) 0 2.0 4.5 (6.5) 6.1 (12.6)8621-22 83.7 3.7 0 (95.8/4.2/0) 0 2.0 3.7 (5.7) 11.4 (17.1)8622-23 91.1 1.2 0 (98.7/1.3/0) 0 1.6 0.4 (2.0) 5.7 (7.7)8623-24 81.1 2.4 0.4 (96.7/2.8/0.5) 0 6.7 0.8 (7.5) 8.7 (16.2)8624-25 76.0 2.0 0 (97.4/2.6/0) 0 15.6 0 (15.6) 6.4 (22.0)8625-26 87.0 4.3 0 (95.2/4.8/0) 2.4 2.4 1.6 (6.2) 2.4 (8.6)8626-27 76.4 2.4 0 (97.0/3.0/0) 0 13.4 0 (13.4) 7.9 (21.3)8627-28 78.5 4.0 0 (95.2/4.8/0) 0 7.2 0 (7.2) 10.4 (17.6)8628-29 77.4 3.2 0 (96.0/4.0/0) 0 6.9 0.8 (7.7) 11.7 (19.4)8629-30 76.8 2.4 0 (97.0/3.0/0) 0 4.0 2.0 (6.0) 14.8 (20.8)8630-31 78.3 2.0 0.4 (97.1/2.4/0) 0 3.6 1.2 (4.8) 14.2 (19.0)8631-32 80.6 0.4 0 (100/0/0) 0 0.8 9.1 (9.9) 9.9 (19.8)8632-33 75.2 0.4 0.4 (99/0.5/0.5) 0 3.2 10.8 (14.0) 10.0 (24.0)8633-34 81.7 0.4 0 (99.5/0.5/0) 0 1.6 8.8 (10.4) 7.6 (18.0)8634-35 88.5 0.8 0 (99.1/0.9/0) 0.8 0.8 5.1 (6.7) 4.0 (10.7)8635-36 18.2 0.8 0 (95.8/4.2/0) 81.0 0 0 (81.0) 0 (81.0)8636-37 79.8 0 0 (100/0/0) 0.8 12.1 2.0 (14.9) 6.0 (20.9)



ANGER 1-20 UPPER CORES

Depth Otz Feld Lith ( Q / F / L )

8637-38 73.2 0.4 0 (99.4/0.6/0)8638-39 84.4 0 0 (100/0/0)8639-40 74.4 0.8 0 (98.9/1.1/0)8640-41 77.3 2.7 0 (96.6/3.4/0)8641-42 76.7 0.8 0 (99.0/1.0/0)8642-43 82.8 0 0 (100/0/0)8643-44 78.0 1.6 0 (98.0/2.0/0)8644-45 77.5 1.2 0 (98.5/1.5/0)8645-46 80.4 1.6 0 (98.1/1.9/0)8646-47 76.6 0.8 0 (99.0/1.0/0)8647-48 79.2 1.6 0 (98.0/2.0/0)8648-49 73.0 2.8 0 (96.4/3.6/0)8649-50 73.3 5.9 0 (92.6/7.4/0)8650-51 77.4 1.2 0 (98.5/1.5/0)8651-52 74.9 1.2 0 (98.2/1.8/0)8652-53 80.9 0.4 0 (99.5/0.5/0)8653-54 76.9 0.4 0 (99.5/0.5/0)8654-55 76.0 3.5 0 (95.5/4.5/0)8655-56 79.7 2.0 0 (97.6/2.4/0)8656-57 81.0 3.2 0 (96.2/3.8/0)8657-58 85.7 0.4 0 (99.5/0.5/0)8658-59 80.5 0.4 0 (99.5/0.5/0)8659-60 85.8 2.4 0 (97.3/2.7/0)

Polo OOvq Clay Tot Cat Poro Cnt+Poro

2.8 20.0 2.8 (26.4)0 2.0 1.6 (15.6)1.2 1.2 1.6 (4.8)0 12.1 7.8 (19.9)3.6 5.1 13.4 (22.5)0 9.2 6.4 (17.2)0.8 1.2 9.4 (20.5)0 2.4 6.7 (21.3)0 1.6 3.9 (18.1)0.4 1.2 9.1 (22.6)0.8 1.2 6.0 (19.2)0 4.0 11.2 (23.2)0.8 1.2 11.8 (20.9)0 4.4 8.0 (17.3)2.4 1 6 9.6 (24.0)0.4 0.8 10.4 (18.8)1.6 2.8 10.1 (22.6)0.8 6.3 9.4 (20.4)0 1.6 6.0 (18.4)1.2 4.3 4.0 (15.8)0 13.2 0.8 (14.0)2.8 2.8 6.8 (19.2)0 0 3.6 (11.9)

Averaqe 7.5 (19.4)

/t



ANGER 1-20 - LOWER CORES

Depth Qtz Feld Lith (Q/F/L) Polo OOvq Clay Tot Cat Poro Cat+Pori

8978-79 52.7 5.4 0.4 (90.0/9.3/0.7) 39.5 2.4 0 (41.9) 0 (41.9)8979-80 90.4 1.2 0 (98.7/1.3/0) 0 4.8 0.4 (5.2) 3.2 (8.4)8980-81 79.2 3.1 0 (96.2/3.8/0) 0 6.7 1.6 (8.3) 2.8 (16.1)8981-82 90.3 2.3 0.4 (97.1/2.2/0.7) 0 6.2 0 (6.2) 0.8 (7.0)8982-83 76.4 0 0 (100/0/0) 0 21.6 0.4 (22.0) 1.6 (23.6)8983-84 79.8 3.9 0 (95.3/4.7/0) 0.4 8.6 0.8 (9.8) 6.6 (16.4)8984-85 84.2 4.3 0 (95.1/4.9/0) 0 4.3 0.4 (4.7) 7.1 (11.8)8985-86 8i.7 2.8 0 (96.8/3.2/0) 0 1.2 4.8 (6.0) 6.4 (12.4)8986-87 49.8 4.1 0 (92.5/7.5/0) 46.1 0 0 (46.1) 0 (46.1)8987-88 82.0 2.7 0 (96.8/3.2/0) 0.4 0 11.3 (11.7) 3.5 (15.2)8988-89 74.0 2.8 0 (96.4/3.6/0) 23.3 0 0 (23.3) 0 (23.3)8989-90 80.9 4.3 0 (95.0/5.0/0) 0 8.2 0 (8.2) 6.6 (14.8)8990-91 76.4 3.9 0 (95.2/4.8/0) 0 8.1 0.4 (7.5) 11.2 (19.7)8991-92 78.4 4.7 0 (94.3/5.7/0) 0 2.4 0.4 (2.8) 14.1 (16.9)8992-93 81.1 5.2 0 (92.9/7.1/0) 0 1.2 0.4 (1.6) 11.2 (12.8)8993-94 76.0 4.8 0 (94.0/6.0/0) 0 5.6 0 (5.6) 13.6 (19.2)8994-95 77.5 1.6 0 (98.0/2.0/0) 0 8.7 0 (8.7) 12.2 (20.9)8995-96 77.1 3.5 0 (95.7/4.3/0) 0 2.7 0 (2.7) 13.2 (15.9)8996-97 84.8 2.8 0 (96.8/3.2/0) 0 2.0 0 (2.0) 10.4 (10.6)8997-98 77.6 4.3 0 (94.7/5.3/0) 0 8.3 0 (8.3) 9.8 (18.1)8998-99 74.7 3.8 0 (95.2/4.8/0) 0 12.1 0 (12.1) 9.4 (21.5)8999-00 76.5 2.7 0 (96.5/3.5/0) 0 5.9 0 (5.9) 14.9 (20.8)9000-01 86.4 3.6 0 (96.0/4.0/0) 0 1.2 0 (1.2) 8.8 (10.0)9001-02 70.3 2.7 0 (96.2/3.8/0) 0 23.8 0 (23.8) 3.1 (26.9)9002-03 84.4 5.1 0 (94.3/5.7/0) 0 0.4 5.9 (6.3) 4.3 (10.6)9003-04 78.8 1.9 0 (97.6/2.4/0) 0 19.2 0 (19.2) 0 (19.2)9004-05 72.2 2.7 0 (96.3/3.7/0) 0 17.6 0 (17.6) 7.4 (25.0)9005-06 80.1 4.6 0 (94.6/5.4/0) 0 2.7 0.4 (3.1) 12.3 (15.4)9006-07 75.6 3.9 0 (95.0/5.0/0) 0 7.1 0 (7.1) 13.4 (20.5)9007-08 78.4 3.9 0 (95.2/4.8/0) 0 12.9 0 (12.9) 4.7 (17.6)



ANGER 1-20 - LOWER CORES

Depth fitz Feld Lrth (Q/F/L)

9008-09 79.2 4.4 0 (94.7/5.3/0)9009-10 76.5 5.6 0 (93.2/6.8/0)9010-11 80.3 2.4 0 (97.1/2.9/0)9011-12 69.5 6.2 0 (91.8/8.2/0)9012-13 83.2 2.4 0 (97.2/2.8/0)9013-14 77.2 1.6 0 (98.0/2.0/0)9014-15 83.8 4.0 0 (95.5/4.5/0)9015-16 83.5 2.0 0 (97.7/2.3/0)9016-17 91.1 4.3 0 (95.5/4.5/0)9017-18 83.6 4.3 0 (95.1/4.9/0)9018-19 77.8 7.0 0 (91.3/8.2/0.5)9019-20 66.4 10.6 0 (86.3/13.7/0)9020-21 85.3 5.2 0 (94.0/6.0/0)9021-22 87.2 0.8 0 (99.1/0.9/0)9022-23 84.0 1.2 0 (98.6/1.4/0)9023-24 75.2 0 0 (100/0/0)

Polo oovq clay Tot Cnt Poro Cat+Poro

0.8 4.4 0 (5.2) 10.8 (16.0)0 6.8 0 (6.8) 11.2 (18.0)0 6.8 0 (6.8) 10.4 (17.2)0.4 13.1 0 (13.5) 10.8 (24.3)0.4 4.4 0 (4.8) 9.6 (14.4)0 19.2 0 (19.2) 2.0 (21.2)0 4.0 0.4 (4.4) 7.9 (12.3)0 9.5 0 (9.5) 5.9 (15.4)3.1 0 1.6 (4.7) 0 (4.7)0 9.8 0 (9.8) 2.3 (12.1)5.8 8.2 0 (14.0) 0.8 (14.8)

18.9 2.6 1.1 (22.6) 0.4 (23.0)6.2 2.7 0 (8.9) 0.4 (9.3)4.4 5.2 0 (9.6) 2.4 (12.0)6.4 4.4 0 (10.8) 4.0 (14.8)

14.4 10.4 0 (24.8) 0 (24.8)Average (11.2) 6 A (17.60)



PATRICK & ST. NORWICH 2-28 CORES

Depth Qtz Fid Lith (Q/F/L) Polo

7924.5 78.8 0.8 0 (99.0/1.0/0) 2.37925.5 58.8 1.2 0 (98.0/2.0/0) 32.07926.5 48.0 1.6 0 (95.2/3.2/1.6) 46.47927.5 64.0 0.4 0 (99.4/0.6/0) 29.27929.5 80.8 0 0 (100/0/0) 2.47930.5 99.2 0.4 0 (99.5/0.5/0) 07931.5 76.4 0 0 (100/0/0) 1.27932.5 82.0 0 0 (100/0/0) 2.07933.5 84.8 0 0 (100/0/0) 0.47934.5 98-4 0 0 (100/0/0) 2.07935.5 80.8 0 0 (100/0/0) 1.67936.5 62.4 0 0 (100/0/0) 29.27937.5 33.2 0.4 0 (98.8/1.2/0) 66.47938.5 73.6 0.8 0 (98.9/1.1/0) 07939.5 79.2 0 0 (100/0/0) 07940.5 84.8 0 0 (100/0/0) 07942.5 77.6 0.8 1.2 (97.5/1.0/1.5) 07943.5 79.2 0.4 0 (99.5/0.5/0) 07944.5 81.6 0.4 0 (99.5/0.5/0) 07945.5 73.2 0.8 0 (98.9/1.1/0) 07946.5 74.4 0.8 0 (98.9/1.1/0) 07947.5 75.6 0.4 0 (99.5/0.5/0) 0.47948.5 78.0 0.4 0 (99.5/0.5/0) 07955.5 84.4 0.4 0 (99.5/0.5/0) 07959.5 87.2 0.4 0.4 (99.1/0.5/0.4) 07962.5 83.6 0 0.8 (99.1/0/0.9) 07967.5 84.0 0.4 0 (99.5/0.5/0) 07972.5 78.0 0.4 0 (99.5/0.5/0) 07978.5 84.0 0.4 0 (99.5/0.5/0) 07983.5 85.6 0 0 (100/0/0) 07986.5 81.6 0.4 0 (99.5/0.5/0) 07987.5 84.0 0 0 (100/0/0) 4.07992.5 82.4 0 0 (100/0/0) 07994.5 76.4 0 0 (100/0/0) 0.47999.5 76.4 0 0 (100/0/0) 08000.5 78.8 0 0 (100/0/0) 08003.5 88.0 0 0 (100/0/0) 0

OOvq Clay Tot Cat Poro Cat+Poro

0.4 14.7 (17.4) 4.0 (21.4)0 4.0 (36.0) 4.0 (40.0)0 3.2 (49.6) 0 (49.6)0.4 1.2 (30.8) 4.8 (35.6)3.2 3.2 (8.8) 10.4 (19.2)2.0 1.6 (3.6) 11.2 (14.8)0 1.2 (2.4) 21.2 (23.6)0.4 0 (2.4) 15.6 (18.0)0 1.2 (1-6) 13.6 (15.2)0.4 2.4 (4.8) 16.8 (21.6)0.4 4.4 (6.4) 13.2 (19.6)1.2 0 (30.4) 7.2 (37.6)0 0 (66.4) 0 (66.4)0.8 0 (0.8) 24.2 (26.0)0.4 4.8 (5.2) 15.6 (20.8)0.4 0 (0.4) 14.8 (15.2)0.4 0 (0.4) 20.0 (20.4)0 0 (0) 20.4 (20.4)0.4 0 (0.4) 17.6 (18.0)2.0 0 (2.0) 24.0 (26.0)0.4 0 (0.4) 24.4 (24.8)2.8 0 (3.2) 20.8 (24.0)1.6 0 (1.6) 20.0 (21.6)0.8 1.2 (2.0) 13.2 (15.2)0 2.0 (2.0) 10.0 (12.0)0.8 0 (0.8) 14.8 (15.6)1.6 2.0 (3.6) 12.0 (15.6)1.2 0.4 (1.6) 20.0 (21.6)2.4 4.8 (7.2) 8.8 (16.0)6.4 1.2 (7.6) 6.8 (14.4)1.2 0 (1.2) 16.8 (18.0)0 2.0 (6.0) 10.0 (16.0)1.6 8.4 (10.0) 11.6 (21.6)2.4 8.8 (11.6) 12.0 (23.6)7.6 6.0 (13.6) 10.0 (23.6)

12.0 0 (12.8) 6.8 (19.6)9.2 0 (9.2) 2.8 (12.0)

Averaoe (11.8) 11.0 (22.8)


Appendix D

Core Analysis, Port Size, and Buckles Number Data

115


ANGER 1 - 2 0 - - UPPER CORES 116

CoreDepth(Ft)

K,mdhorz

P h i ,%

Gr.Den.Gr/cc

SOC%

swc%

PORT SIZE micron

BUCKLES 1 Phi * SI

8603 0.02 1.1 2.702 0 65.9 0.50 72.5

8604 0.04 3.0 2.685 0 60.1 0.32 180.3

8605 0.74 8 .5 2.653 0 42.6 0.71 362.1

8606 0.02 0 .9 2.759 0 69.5 0.50 62.5

8607 29.00 10.2 2.635 0 38.6 5.30 393.7

8608 25.00 9.2 2.640 0 50.9 5.26 468.3

8609 15.00 8 .4 2.636 0 47.1 4.22 395.6

8610 0.99 5.7 2.636 0 53.3 1.19 303.8

8611 10.00 8.2 2.635 0 38.3 4.73 314.1

8612 15.00 7.3 2.637 0 38.2 4.76 278.9

8613 4.87 7.2 2.637 0 47.1 2.66 339.1

8614 14.00 8 .0 2.637 0 34.6 4.22 276.8

8615 35.00 10.9 2.635 0 29.8 5.54 324.8

8616 25.00 9.2 2.637 0 38.0 5.26 349.6

8617 2.77 7.4 2.634 0 53.7 1.74 397.4

8618 5.45 7.9 2.633 0 74.7 2.45 590.1

8619 1.51 8 .2 2.634 0 79.4 1.12 651.1

8620 1.74 9.7 2.634 0 64.5 1.04 625.6

8621 2.34 7.4 2.632 0 56.0 1.58 414.4

8622 4.35 8.0 2.635 0 41.8 2.12 334.4

8623 21.00 8 .8 2.636 0 28.8 4.94 253.4

8624 0.57 4.9 2.633 0 62.5 0.98 306.2

8625 5.66 8.2 2.632 0 94.3 2.43 773.3

8626 4.36 8 .5 2.631 0 88.2 2.02 749.7

8627 10.00 9.1 2.633 0 55.7 4.32 506.9

8628 4.84 8 .2 2.629 0 72.9 2.21 597.8

8629 3.97 9 .8 2.627 0 82.3 1.70 806.5

8630 3.40 10.2 2.628 0 86.9 1.49 886.4

8631 0 .50 9 .0 2.635 0 72.1 0.54 648.9

8632 2.96 11.8 2.629 0 47.2 1.21 556.9

8633 0.94 9.7 2.634 0 61.6 0.73 597.5

8634 0.19 5.0 2.642 0 64.9 0.51 324.5

8635 1.04 6 .6 2.658 0 58.6 1.08 386.8


ANGER 1 - 2 0 - - UPPER CORES 1 1 7

CoreDepth(Ft)

K,mdhorz

P hi ,%

Gr.Oen.Gr/cc

SOC%

swc%

PORT SIZE micron

BUCKLES Phi* SW

8636 0.23 5.3 2.637 0 76.7 0.54 406.58637 0.75 6 .5 2.638 0 52.4 0 .90 340.68638 0.08 3.3 2.645 0 82.5 0.44 272.28639 4.53 8.5 2.696 0 72.6 2.06 617.18640 8 .88 6.3 2.637 0 50.9 3.92 320.78641 7.52 7.9 2.657 0 73.6 2.96 581.48642 1.19 6 .4 2.636 0 71.5 1.20 457.68643 8.91 9 .8 2.635 0 68.4 2.71 670.38644 0.97 7.7 2.638 0 67.1 0.94 516.78645 0.12 5.3 2.643 0 84.5 0.37 447.88646 11.00 11.6 2.635 0 83.5 2.66 968.68647 4.89 10.5 2.634 0 80.0 1.78 840.08648 3.19 10.9 2.633 0 78.3 1.36 853.58649 26.00 12.5 2.632 0 73.9 4.13 923.88650 12.00 12.2 2.633 0 63.2 2.68 771.08651 26.00 14.0 2.630 0 67.8 3.75 949.28652 6.11 12.9 2.630 0 74.8 1.72 964.98653 0.97 9.3 2.641 0 73.8 0.80 686.38654 0.39 7.5 2.637 0 96.3 0.54 722.28655 0.12 5.4 2.645 0 87.8 0 .36 474.18656 0.24 7.8 2.635 0 89.3 0.40 696.58657 0.02 2.2 2.636 0 72.4 0.27 157.38658 0.36 10.4 2.641 0 56.4 0.39 586.68659 0.21 13.2 2.844 0 38.2 0.23 504.2


ANGER 1 - 2 0 - - LOWER CORES 1 1 8

CoreDepth(Ft)

K,md i horz

P h i ,%

Gr.DenGr/cc

SOC%

SWC%

PORT SIZE micron

BUCKLES 1 Phi*SWC

8978 0.03 1.5 2.694 0 34.0 0.48 51.08979 0.75 6.9 2.658 0 32.0 0.86 220.88980 0.23 7.6 2.631 0 42.5 0.39 323.08981 0.05 5.3 2.654 0 53.8 0.22 285.18982 0.20 3.1 2.618 0 91.7 0.79 284.38983 0.10 4.8 2.635 0 21.3 0.36 102.28984 0.18 6 .3 2.635 0 22.3 0.40 140.58985 0.18 6.5 2.637 0 77.8 0.39 505.78986 0.02 0 .8 2.716 0 58.3 0.45 46.68987 0.14 6 .8 2.635 0 59.2 0.32 402.68988 0.05 2.2 2.680 0 68.2 0.47 150.08989 0.09 4.7 2.638 0 54.5 0.34 256.28990 39.00 10.9 2.631 0 .9 27.5 5.90 299.88991 130.00 13.7 2.637 0 20.8 9.84 285.08992 30.00 11.1 2.633 0 .9 29.2 4.98 324.18993 60.00 11.1 2.633 0 .9 29.3 7.50 325.28994 42.00 12.2 2.631 0 .8 37.1 5.60 452.68995 57.00 11.4 2.635 0 20.0 7.09 228.08996 41.00 10.5 2.636 0 .9 22.8 6.28 239.48997 33.00 9.5 2.636 0 22.0 6.03 209.08998 2.47 5.3 2.636 3 .8 28.9 2.17 153.28999 31.00 10.4 2.637 0 .9 28.5 5.37 296.49000 8.56 8 .9 2.634 1.1 35.2 2.88 313.39001 0.01 2.7 2.635 0 46.0 0.15 124.29002 0.06 5.3 2.644 1.9 23.2 0.25 123.09003 0.03 1.9 2.638 5 .6 90.0 0.39 171.09004 14.00 7.6 2.633 0 52.2 4.42 396.79005 4.00 9.6 2.633 0 46.9 1.73 450.29006 33.00 10.0 2.635 0 38.8 5.77 388.09007 16.00 12.0 2.633 0 23.6 3.22 283.29008 29.00 13.6 2.635 0 21.8 4.10 296.59009 3.24 10.8 2.634 0 27.7 1.38 299.29010 3.68 10.6 2.633 0 39.7 1.51 420.8


ANGER 1 - 2 0 - - LOWER CORES 1 1 9

CoreDepth(Ft)

K,mdhorz

P h i ,%

Gr.Den.Gr/cc

SOC%

swc%

PORT SIZE micron

BUCKLES 1 Phi*SWC

9011 0.36 7.5 2.634 0 63.5 0 .52 476.3

9012 0.35 6.7 2.632 0 62.8 0 .56 420 .8

9013 0.02 3 .8 2.634 0 57.7 0 .17 219.3

9014 0.09 6.2 2.632 0 52.0 0 .27 322.4

9015 0.11 7.3 2.631 0 57.4 0 .26 419.0

9016 0.11 6.2 2.631 0 55.1 0 .30 341.6

9017 0.05 3.3 2.636 0 86.9 0 .33 286.8

9018 0.03 1.8 2.648 0 66.8 0.41 120.2

9019 0.05 1.9 2.660 0 55.2 0 .53 104.9

9020 0.04 1.8 2.651 0 47.6 0 .49 85.7

9021 0.03 3.1 2.644 0 39.6 0 .26 122.8

9022 0.04 4 .0 2.654 0 43.5 0 .24 174.0

9023 0.05 1.3 2.673 0 47.2 0 .74 61 .4


P ATRICK & S T . NORWICH 2 - 2 8 CORES 120

Core K,md Phi , Gr . Oe n . SOC SWC PORT SIZE BUCKLES NO.Depth( F t ) horz % Gr/cc % % micron Phi*SWC

7924 .0 -25 .0 0.29 11.8 2.657925 .0 -26 .0 0.06 5.2 2.697926 .0 -27 .0 0.31 4.0 2.687927 .0 -28 .0 0.81 4 .9 2.707928 .0 -29 .0 0.42 11.8 2.637929 .0 -30 .0 0.04 10.0 2.647930 .0 -31 .0 4.72 13.5 2.637931 .0 -32 .0 159.00 18.2 2.637932 .0 -33 .0 327.00 18.0 2.647933 .0 -34 .0 161.00 17.6 2.647934 .0 -35 .0 228.00 15.3 2.647935 .0 -36 .0 75.00 12.7 2.657 936 .0 -37 .0 14.00 11.6 2.687937 .0 -38 .0 <0.02 1.7 2.787 938 .0 -39 .0 427.00 20.4 2.647939 .0 -40 .0 61.00 14.4 2.657 940 .0 -41 .0 290.00 21.1 2.647941 .0 -42 .0 257.00 16.7 2.647942 .0 -43 .0 313.00 17.0 2.647943 .0 -44 .0 254.00 17.2 2.647944 .0 -45 .0 287.00 16.8 2.647945 .0 -46 .0 334.00 17.8 2.647946 .0 -47 .0 270.00 18.2 2.647947 .0 -48 .0 180.00 17.7 2.647948 .0 -49 .0 249.00 18.5 2.647948 .5 -49 .0 161.00 14.3 2.647949 .0 -50 .0 79.00 15.4 2.657950 .0 -51 .0 143.00 14.2 2.647951 .0 -52 .0 46.00 14.4 2.647952 .0 -53 .0 50.00 14.3 2.637953 .0 -54 .0 3.80 9 .9 2.567954 .0 -55 .0 6.60 9 . 6 2.547955 .0 -56 .0 24.00 12.2 2.62

0 41.3 0.31 487 .3

0 15.9 0.25 82 .7

0 26.1 0.82 104.4

0 67.8 1.21 333.2

0 55.6 0.38 656.1

0 57.1 0.11 571.0

0 35.0 1.42 472.5

0 35.6 8.66 647 .9

0 39.4 13.37 709.20 38.1 8 .98 670.6

0 27.8 12.44 425.3

0 49.2 7.60 624 .8

0 28.5 3.06 330.6

0 65.7 0.34 111.7

0 21.6 14.03 440.6

0 37.7 6.04 542.9

0 23.1 10.86 487.40 27.3 12.38 455.9

0 29.6 13.69 503.2

0 29.3 11.98 504.00 35.6 13.14 598.10 32.4 13.66 576.7

0 31.5 11.83 573.3

0 34.4 9.55 608.9

0 31.9 11.12 590.20 32.3 10.75 461.9

0 29.9 10.62 460.5

0 40.1 10.09 569.4

0 40.9 5.12 589.00 27.2 5.40 389.0

0 17.2 1.63 170.3

0 31.3 2.32 300.5

0 29.5 4.03 359.9


P ATRICK & S T . NORWICH 2 - 2 8 CORES 121

CoreDepth(Ft)

Ka,mdhorz

P h i ,%

Gr.Den.Gr/cc

S0C%

swc%

PORT SIZE micron

BUCKLE!Phi*SW(

7956 .0 -57 .0 41.00 14.5 2.63 0 42.1 4.75 610.4

7957 .0 -58 .0 44.00 17.1 2.63 0 26.9 4.30 460.0

7958 .0 -59 .0 31.00 14.3 2.61 0 33.6 7.56 480.5

7959 .0 -60 .0 8 .20 11.0 2.64 0 40.9 2.34 449.9

7 960 .0 -61 .0 1.20 8.1 2.64 0 46.9 0.99 379.9

7 961 .0 -62 .0 0.40 6 .9 2.65 0 65.2 0.59 449.9

7 962 .0 -63 .0 17.00 13.6 2.64 0 30.1 2.99 409.4

7 963 .0 -64 .0 29.00 15.9 2.64 0 32.1 3.58 510.4

7964 .0 -65 .0 36.00 13.9 2.63 0 44.6 4.57 619.9

7965 .0 -66 .0 5.40 9 .6 2.64 0 59.4 2.06 570.2

7966 .0 -67 .0 5.10 13.5 2.64 0 48.9 1.49 - 660.2

7967 .0 -68 .0 2.40 10.9 2.64 0 62.4 1.15 680.2

7968 .0 -69 .0 2.30 8 .9 2.64 0 56.2 1.33 500.2

7969 .0 -70 .0 22.00 13.7 2.64 0 43.8 3.46 600.1

7970 .0 -71 .0 6 .10 11.8 2.64 0 48.8 1.85 575.8

7971 .0 -72 .0 7.00 10.8 2 .64 0 30.6 2.17 330.5

7972 .0 -73 .0 16.00 13.1 2.64 0 32.0 2.98 419.2

7973 .0 -74 .0 8.40 11.4 2.64 0 45.6 2.30 519.8

7974 .0 -75 .0 0.10 5.4 2.59 0 81.5 0.32 440.1

7975 .0 -76 .0 0 .40 10.8 2.59 0 50.0 0.40 540.0

7976 .0 -77 .0 <0.10 5 .5 2.60 0 32.7 0.32 179.8

7977 .0 -78 .0 0 .70 3 .9 2.65 0 69.2 1.35 269.9

7978 .0 -79 .0 6.60 7 .3 2.65 0 68.5 2.94 500.0

7979 .0 -80 .0 1.00 5.1 2.65 0 72.5 1.32 369.8

7980 .0 -81 .0 1.10 8 .1 2.58 0 55.6 1.08 450.4

7981 .0 -82 .0 1.70 9 .0 2.64 0 40.0 1.10 360.0

7982 .0 -83 .0 1.70 5.7 2.65 0 28.1 1.64 160.2

7983 .0 -84 .0 20.00 9 .0 2.64 0 27.8 4.70 250.2

7984 .0 -85 .0 2.40 9 .6 2.64 0 32.3 1.28 310.1

7985 .0 -86 .0 5.50 12.3 2.65 0 43.1 1.68 530.1

7986 .0 -87 .0 4.80 11.8 2.64 0 39.0 1.61 460.2

7987 .0 -88 .0 0.70 7.5 2.68 0 94.7 0.77 710.2

7988 .0 -89 .0 3.10 11.6 2.64 0 60.3 1.26 699.5


PATRICK & S T . NORWICH 2 - 2 8 CORES 122

CoreDepth( F t )

K,mdHorz

P h i ,%

Gr.DenGr/cc

SOC%

swc%

PORT SIZE micron

BUCKLESPhi*SW(

7989 .0 -90 .3 0.80 9 .7 2.65 0 75.3 0.66 730.47990 .0 -91 .0 2.60 10.3 2.64 0 72 .8 1.26 749 .87991 .0 -92 .0 3.50 10 .8 2.65 0 58.3 1.44 629.67992 .0 -93 .0 1.80 10.8 2.70 0 88 .0 0.98 950 .47993 .0 -94 .0 2.90 30.6 2.65 0 79.3 1.31 840 .67994 .0 -95 .0 6.10 10.9 2.65 0 70 .6 1.98 769.57995 .0 -96 .0 30.00 13.9 2.70 0 61 .9 4.10 860 .47996 .0 -97 .0 5.80 11 .8 2.64 0 62.7 1.80 739 .97997 .0 -98 .0 3.40 11.5 2.64 0 59.1 1.34 679 .67998 .0 -99 .0 1.70 7 .5 2.65 0 76 .0 1.29 570.07999 .0 -00 .0 14.00 9 .6 2.64 0 63 .5 3.62 609.68000 .0 -01 .0 0.20 4 .5 2.67 0 91.1 0.57 410 .0800 1 .0 -0 2 .0 0.30 5.1 2.61 0 35 .3 0.65 180.08002 .0 -03 .0 0.30 3 .8 2.63 0 65 .8 0.84 250.0800 3 .0 -0 4 .0 <0.10 2 .6 2.64 0 23.0 0.61 59 .8


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