Western Michigan University ScholarWorks at WMU
Master's Theses Graduate College
12-1991
Structural, Depositional, and Diagenetic Controls on Reservoir Development: St. Peter Sandstone, Newaygo County, Michigan
Mark S. Caldwell
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Recommended Citation Caldwell, Mark S., "Structural, Depositional, and Diagenetic Controls on Reservoir Development: St. Peter Sandstone, Newaygo County, Michigan" (1991). Master's Theses. 938. https://scholarworks.wmich.edu/masters_theses/938
This Masters Thesis-Open Access is brought to you for free and open access by the Graduate College at ScholarWorks at WMU. It has been accepted for inclusion in Master's Theses by an authorized administrator of ScholarWorks at WMU. For more information, please contact [email protected]. STRUCTURAL, DEPOSITIONAL, AND DIAGENETIC CONTROLS RESERVOIR DEVELOPMENT: ST. PETER SANDSTONE, NEWAYGO COUNTY, MICHIGAN
by
Mark S. Caldwell
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 1991
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. STRUCTURAL, DEPOSITIONAL, AND DIAGENETIC CONTROLS ON RESERVOIR DEVELOPMENT: ST. PETER SANDSTONE, NEWAYGO COUNTY, MICHIGAN
Mark S. Caldwell, M.S.
Western Michigan University,1991
Enhanced reservoir quality in the Middle Ordovician
St. Peter Sandstone is observed in gas bearing zones in
wells located on domal structures. Geometry and degree of
this enhanced porosity development is the result of the
interplay of structural, depositional, and diagenetic
controls. An integrated subsurface study of the Wood-
ville/Goodwell field area was performed in order to doc
ument controls on hydrocarbon accumulation.
Recurrent structural growth of domal features
throughout the Paleozoic is well documented by isopach
mapping. Burial and thermal history studies indicate that
hydrocarbons were generated in Ordovician aged source rocks during late Devonian to early Mississippian time,
and accumulated in Ordovician to Silurian aged paleo-
structural traps. These paleostructural hydrocarbon
accumulations were then modified by a post late Pennsyl
vanian period of structural growth.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. ACKNOWLEDGEMENTS
I am extremely grateful to my wife, Nancy, and my
daughters, Emily and Natalie, for their support and en
couragement during my work on this project.
I would like to thank my parents, John and Julia, for
their patience and support throughout my somewhat tumult
uous experience of higher education.
I appreciate the constructive criticism and advice of
my thesis advisor, Dr. William B. Harrison III, and com
mittee members Dr. Christopher J. Schmidt and Dr. W.
Thomas Straw.
I am extremely grateful to my employers, Klabzuba Oil
and Gas, Fort Worth, Texas, for allowing me access to
data, as well as considerable latitude vital to the com
pletion of this project.
My understanding of the petroleum geology of the
Woodville area benefitted from many discussions with geol
ogists working the Michigan basin including: Charlie
Stewart, Paul Basinski, Jim Hughes, Kevin Sullivan, John
Esch, and John Vrona.
Mark S. Caldwell
ii
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Structural, depositional, and diagenetic controls on reservoir development: St. Peter Sandstone, N-sv/aygo County, Michigan
Caldwell, Mark Sutton, M.S.
Western Michigan University, 1991
UMI 300 N. Zeeb Rd. Ann Arbor, MI 48106
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. TABLE OF CONTENTS
ACKNOWLEDGEMENTS...... ii
LIST OF FIGURES...... v
INTRODUCTION AND STUDY OBJECTIVES...... 1
METHODS...... 5
HISTORY AND GENERAL GEOLOGIC SETTING...... 8
STRATIGRAPHY...... 12
STRUCTURAL DEVELOPMENT...... 14
Structure...... 14
Woodville Anticline...... 14
Goodwell Dome...... 20
Hungerford Dome...... 20
Goodwell East Nose...... 21
Thinning of Isopachs...... 22
Cause of Thinning...... 32
Fault Control of Structural Growth...... 35
LITHOFACIES AND DEPOSITIONAL ENVIRONMENT...... 37
Lithofacies...... 37
Burrowed, Rippled Sandstone Lithofacies 37
Planar-Laminated Sandstone Lithofacies..... 40
Argillaceous Sandy-Dolomite Lithofacies 41
Depositional Environment...... 42
Discussion...... 44
iii
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Table of Contents— Continued
RESERVOIR CHARACTERISTICS...... 47
Core Porosity and Permeability...... 47
Reservoir Facies A ...... 49
Reservoir Facies B ...... 49
Nonreservoir Rock...... 50
Sealing Facies...... 50
Petrophysical Log Analysis...... 51
Neutron-Density Crossplot Porosity...... 51
Water and Hydrocarbon Saturation...... 52
ORIGIN AND MODIFICATION OF POROSITY...... 61
Depositional Control of Porosity...... 61
Diagenetic Modification of Porosity...... 62
Discussion...... 69
TIMING OF HYDROCARBON ACCUMULATION...... 75
Timing of Trap Formation...... 75
Timing of Hydrocarbon Generation and Migration...... 77
Discussion...... 80
MODEL FOR RESERVOIR DEVELOPMENT...... 82
PRODUCTION HISTORY AND RECOVERY EFFICIENCY...... 89
CONCLUSIONS...... 90
BIBLIOGRAPHY...... 92
iv
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. LIST OF FIGURES
1. St.Peter Producing Gas Fields and Regional Structure of the West Central Michigan Basin...... 3
2. St. Peter Gas Fields of the Study Area...... 4
3. Type St. Peter Sandstone Log for Study Area.... 7
4. Precambrian Structure of the Michigan Basin.... 9
5. Generalized Stratigraphy of the Michigan Basin...... 10
6. Structure Contours on the Top of the St. Peter Sandstone...... 15
7. North-South St. Peter Structural Cross Section...... 16
8. East-West St. Peter Structural Cross Section...... 17
9. Structure Contours on the Top of the Traverse Limestone (Devonian)...... 18
10. Structure Contours on the Top of the Michigan Stray Sandstone (Mississippian)...... 19
11. Top of Glenwood to Top of St. Peter Isopach.... 23
12. Top of Trenton to Top of Glenwood Isopach. 24
13. Top of Niagaran to Top of Trenton Isopach. 25
14. Top of Salina A2 Carbonate to Top of Niagaran Isopach...... 26
15. Top of Salina F Unit to Top of A2 Carbonate Isopach...... 27
16. Top of Dundee to Top of Salina F Unit Isopach.. 28
17. Top of Sunbury shale to Top of Dundee Isopach...... 29
v
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. List of Figures— Continued
18. Base of Jurassic Red Beds to the Top of the Parma Sandstone Isopach...... 30
19. Jurassic to Mississippian Gamma-Ray Log Stratigraphic Cross Section...... 33
20. Core Description, Patrick and St. Norwich #2-28...... 38
21. Core Description, Jansma #1-29...... 39
22. Core Porosity vs. Permeability Crossplot...... 48
23. Core Porosity and Neutron-Density Log Crossplot Porosity for Both Cored Wells...... 53
24. Average Neutron-Density Crossplot Porosity for Foreshore/Upper Shoreface Facies...... '54
25. Average Neutron-Density Crossplot Porosity vs. Structural Position...... 55
26. Water Saturation Equation...... 57
27. Computer Processed Log: Patrick 2-28...... 59
28. Photomicrograph of Secondary Porosity Developed in Foreshore/Upper Shoreface Facies ...... 64
29. Photomicrograph of Well Developed Secondary Porosity in Foreshore Facies...... 65
30. Photomicrograph of Tightly Dolomite Cemented Sandstone...... 66
31. Photomicrograph of Dissolution Front...... 67
32. Photomicrograph of Clay Filled Sandstone....'... 70
33. Photomicrograph of Supermature Quartzarenite of Foreshore/Upper Shoreface facies...... 71
34. Generalized Sequence of Diagenetic Events..... 72
35. Percentage Isopachous Thinning Histograms..... 76
vi
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. List of Figures— Continued
36. Michigan Basin Burial History Curve...... 79
37. Top of St. Peter Paleostructure in Late Devonian (Traverse Limestone) Time...... 81
38. Model for Leaching and Precipitation in a Folded Sandstone...... 83
39. Neutron-Density Crossplot of Average Values for Foreshore/Upper Shoreface Facies...... 85
40. Betts Creek Field Model for Reservoir Development...... 86
vii
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. INTRODUCTION AND STUDY OBJECTIVES
Deep drilling in the Michigan basin has led to the
discovery of significant reserves of natural gas from
Middle Ordovician-aged sandstone reservoirs. Through the
end of 1990, 59 fields had been discovered within the
Michigan Basin from sandstones of the Glenwood, St. Peter
Sandstone, and Prairie du Chien Formations. Although sev
eral recent publications (Barnes, 1988; Brady and DeHaas,
1988; Bricker, Milstein, and Reszka, 1983; Catacosinos,
Daniels, and Harrison, 1991; Fisher and Barratt, 1985;
Harrison, 1987; Nadon, Simo, Byers, and Dott, 1991; and
Syrjamaki, 1977) have addressed the stratigraphy, dep
ositional history, and diagenesis of the Middle Ordovician
sequence in the Michigan Basin, no detailed studies des
cribing the petroleum geology of St. Peter Sandstone
fields have been published. The relative timing of struc
tural growth, porosity development, and hydrocarbon accum
ulation in St. Peter Sandstone reservoirs is poorly doc
umented in the literature. By integrating structural and
isopach mapping, petrophysical analysis, petrography,
burial history, and production history, the controls on
St. Peter Sandstone reservoir development and hydrocarbon
accumulation may begin to be understood.
1
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 2
The study area (Figure 1) covers portions of Goodwell
and Norwich Townships (T14N-T15N;R11W) in eastern Newaygo
County, Michigan. The study area encompasses five prod
ucing St. Peter fields (Figure 2). Goodwell and Woodville
fields have proven reserves of 22 and 60 Bcfg (billion
cubic feet of gas), respectively, in the upper St. Peter
Sandstone. Other St. Peter fields within the study area
include Betts Creek, Bissel Lake, and Hungerford fields.
The study area was selected because preliminary work in
dicated that: (a) dramatic porosity variation is present
in the uppermost St. Peter Sandstone; (b) porosity var-\
iation appeared related to structural position and hydro
carbon accumulation; and (c) a variety of structures that
had undergone differing structural histories were repre
sented .
The objectives of this study are as follows: (a) to
establish the timing of structural growth relative to hy
drocarbon generation and migration; (b) to determine the
depositional environment of the St. Peter Sandstone study
interval and the depositional control on reservoir qual
ity; (c) to examine the role of diagenesis in reservoir
development; and (d) to determine reservoir geometry,
fluid saturation, and reservoir characteristics of the St.
Peter Sandstone.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
TUN TUN T13M T15H T16N T18M T17N T12N \ \ 9 X CCLFAX’M % 'CALI* fCSEJ^'17 \ \, ?E0LA eevecLME'c > OSTA \ N NT" . MFC © \ ® < V . \M0N" 1& S C 1 1 \ \ j \ \ v ------aocc*aL'« ' &a£Y**7 & \ V i , 'V tGO i N \ LAKE \ AflEA-^ NEWA \ \ \ \ \ \ R13W R13W R12W R11W R10W R9W STUDY \ \
6 MILES CJ^500FT. Michigan Basin. STRUCTURE ST. PETER QAS FEDS Figure 1. Figure 1. St. Peter Producing Gas Fields and Regional Structure of the West Central
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. GEBFQBD 1.1 E (CFG
.WQQ
k E K 8 6
S I'. PETER FELDS AM} YEA R OF DJSC aMfHoaTo^wi DvyBJLEAS • OL ST. P£T£ft TESTS UPPtfl ST. PcTfcfi « CAS g a s well 25 ♦ DAY HOLE I Mt£
Figure 2. St. Peter Gas Fields of the Study Area. Field name, year of discovery, and cumulative production to 1-1-91 are indicated.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. METHODS
Documenting the structural history of the study area
was accomplished by basic subsurface geologic methods.
Twenty-five correlated tops were picked from petrophysical
logs for each of the 34 Ordovician wells drilled in the
study area. Up to ten tops were picked where logs were
available from approximately 85 Devonian and Mississippian
wells drilled. All wells were located on 1:24,000 scale
base maps. From the data base of well tops, a series of
eight isopach maps and four structure maps were created
and contoured honoring regional trends as defined by pre
vious proprietary work done by the writer.
Conventional four inch cores from the Wolverine Pat
rick and St. Norwich #2-28 (SWSE, Sec. 28-T15N-R11W) and
the Wolverine Jansma #1-29 (NENE, Sec. 29-T15N-Rllw) were
examined and described for this study. Lithology, sedi
mentary structures, trace fossils, porosity, grain size,
sorting, rounding, diagenetic fabrics, and oil stain were
recorded on a standard core analysis form. Horizontal air
permeability and Boyle's Law porosity measurements were
performed by Core Laboratories (Mt. Pleasant) in one foot increments on the entire cored intervals for the above two
wells. Vertical air permeability was also measured for the
Jansma #1-29.
5
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Thirty-eight thin sections, six from the Patrick and
St. Norwich #2-28 and 32 from the Jansma #1-29 were exam
ined with a petrographic microscope in order to charact
erize the petrography, diagenesis, and microscopic reser
voir quality of the St. Peter Sandstone within the study
area. All thin sections were impregnated with blue stained
epoxy to aid in defining porosity, and stained with aliz
arin red to distinguish calcite from dolomite cement.
Wireline log curves for 30 St. Peter Sandstone tests
in the study area were digitized in one foot increments
and analyzed using the TERRASCIENCES workstation at West
ern Michigan University, Kalamazoo. Curves digitized in
cluded gamma-ray (GR), bulk density (RHOB), neutron poros
ity (NPHI), deep laterolog (LLD), shallow laterolog (LLS),
and micro laterolog (MLL). These log curves were analyzed
over a study interval spanning roughly 110 feet (Figure 3,
type log) of the lower Glenwood Formation and upper St.
Peter Sandstone. Neutron-density crossplot porosity, true
resistivity, and water saturation were then calculated and
plotted using the workstation.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. WOLVERINE. PATRICK AND ST. NORWICH #2-28 NW SW SE SEC. 28 TI5N-R1IW
7900 ST. PETER SANDSTONE
PERFS UMdnPoy pp*r Si. P«t«r Zon* SS STUDY INTERVAL
8100
8200
8300
PRAHEDU CHBN
8500
0 150 2 3 GR RHOB (g/cc)
Figure 3. Type St. Peter Sandstone Log for Study Area.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. HISTORY AND GENERAL GEOLOGIC SETTING
The study area is located on the southwest flank of
the Michigan intracratonic basin (Figures 1 and 4). Reg
ional northeast dip increases from about 25 feet/mile for
Mississippian-aged rocks to about 75 feet/mile for Ordo
vician-aged rocks. This regional pattern of gentle basin-
ward slope is punctuated by subtle anticlinal closures,
terraces, and basinward plunging noses of structure con
tours. Over 10,000 feet of Cambrian through Jurassic rocks
are present in the study area (Figure 5). Studies pert
inent to the stratigraphy and geologic history of the
Michigan basin include: Dorr and Eschman (1971), Ells
(1967), Gardner (1974), Hinze, Kellogg, and O'Hara (1975),
Lillienthal (1978), Mesolella, Robinson, McCormick, and
Ormiston (1974), and Newcombe (1933).
In 1983, Jennings Petroleum discovered Michigan's
second St. Peter Sandstone gas field beneath Goodwell Dev
onian field. The Anderson #1-8A (BHLrNENESE, sec. 8, T14n-
R11W) discovery well produced ten million cubic feet gas
per day (Mmcfgd), and 36 barrels of condensate per day
(Bcpd) through perforations in the upper St. Peter Sand
stone on production test. This was followed by deep gas
discoveries at Woodville (1985), Betts Creek (1987) and
Hungerford (1988) fields.
8
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 9
(\ oti **ii
^I*tc
Figure 4. Precambrian Structure of the Michigan Basin. Keeweenawan-aged rift zone is shaded. Modified from Catacosinos and Daniels (1991).
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. SERIES/STAGES ROCK UNITS WIKONSINAN 1.8 0AJOCIAN 201 2M OtSMOINCJIAN VISCAN O KIMDtAHOOKIAN 110 CKAUTAUQUAN >74 CHIAN • O f f ALANC rrm ThltogON0 UNIT A UNlI NIAOAAA CLINTON CAJ I CAIQF HlAD QW». | man HOUL hT LLANOOVCNIAN ALCKANONIAN UMDlff (M lM llAf ID MiCllMONOIAN ASHOILLIAN UTICA MAVtVILLIAN R lA tff i f LOIAN CANAOOCIAN •LACK AIVIA •CACKAIVCAIAM CHAITAN LLAMVIANIAK WHItCAOCKIAN '4T1- nT l *>.«« C H lt * CANAOIAN TACMAOOCIAH iRSUPIALtAU TACNKALCAUAN 870* Figure 5 Generalized Stratigraphy of the Michigan Basin Modified from Fisher et al . (1988). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Prior to the St. Peter Sandstone discovery, the pet roleum history of the area was dominated by development of oil and gas in Devonian and Mississippian reservoirs. In 1943, discoveries were made on structural closures at Goodwell and Woodville fields, and through 1986 cumulative production of 1,145,293 barrels of oil from the Traverse Limestone (Devonian) was reported for Goodwell field from 31 wells. Goodwell and Woodville Stray Sandstone (Mississ ippian) reservoirs have been converted to gas storage fields with working storage capacity of 19 Bcfg and 5 Bcfg, respectively. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. STRATIGRAPHY Considerable disagreement exists among geologists as to the proper stratigraphic nomenclature for the Middle Ordovician sequence found in the Michigan basin. The mas sive sandstone underlying the Glenwood Formation has been referred to as Prairie du Chien (Bricker et al., 1983; Lillienthal, 1978; Wheeler, 1987), Bruggers (Fisher and Barratt, 1985), and New Richmond (Ells, 1967). A growing number of geologists (Barnes, 1988; Catacosinos et al., 1991; Harrison, 1987; Lundgren, 1991; Nadon et al., 1991) have argued that the massive sandstone is stratigraph- ically equivalent to the St. Peter Sandstone of widespread occurrence in the mid-continent (Dapples, 1955; Ostrom, 1978). The confusion over stratigraphic nomenclature re sulted from miscorrelation of the thin St. Peter Sandstone outcrop in Wisconsin and Illinois to the thick massive sandstone of the Michigan basin subsurface. The Michigan basin was undergoing rapid subsidence during St. Peter time (Catacosinos et al., 1991; Fisher and Barratt, 1985) that accounts for the variation in thickness from tens of feet thick on the Wisconsin arch, to over 1000 ft. thick in the central Michigan basin. Harrison (1987) has suggested that the Glenwood should properly be assigned formation status as opposed to 12 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 13 being the lowermost member of the Black River Formation (Bricker et al., 1983; Lillienthal, 1978). Direct appli cation of existing stratigraphic nomenclature outside the Michigan basin, primarily in Wisconsin and Illinois, dic tates that the interbedded dolomite, siltstone, anhydrite, and sandstones occurring beneath the St. Peter Sandstone (variously called Foster, Brazos, or Trempealeau) are pro perly referred to as the Prairie du Chien Formation. For the purposes of this paper, the terms Glenwood, St. Peter Sandstone, and Prairie du Chien (Figure 3) will be applied as shown in a reference section for the Patrick and St. Norwich #2-28 well. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. STRUCTURAL DEVELOPMENT Structure Woodville Anticline Structural mapping on the top of the St. Peter Sand stone (Figures 6-8) shows that the most prominent feature present in the study area is a northwest-southeast trend ing anticline roughly six miles long by one mile wide. This anticline is doubly plunging from a culmination loc ated in the Nl/2 section 33 and the Sl/2 section 28, T15N- R11W. Woodville, Bissel Lake, and Betts Creek St. Peter fields are located along this anticline (Figure 6). Wood ville field actually consists of two domal features sep arated by a saddle (Figure 6). Maximum St. Peter Sandstone structural closure at Woodville field is 90 feet. The Bis sel Lake and Betts Creek domes are separate features with maximum closure of 40 feet. Structural mapping on the top of the Traverse Limestone (Figure 9) and Mississippian Stray Sandstone (Figure 10) shows a well defined closure of about 40 feet shifted slightly north of the Woodville St. Peter dome. The deeper Bissel Lake and Betts Creek structures have little shallow expression other than a slight nosing of structure contours to the southeast (Fig ures 9 and 10). 14 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. r6943 -6932 -6914 6978V69I ST. PETER SS STRUCTURE C.I.- 50 FT. DAY HOLE ST. PETER TESTS & GAS M IL UPPER S T . PETER C A S WELL Figure 6. Structure Contours on the Top of the St. Peter Sandstone. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. HUNGERFORD WOODVILLE NORWICH 1-22 PATRICK 1-28 PATRICK & ST. NORWICH 2-28 WEI # ^ # # A NORTH -6700 BILK DENSITY -6800- -6900- P : 3 5 M M C F D 70BCPD 0H2O CUM. FROD. 645 BCFQ 102,675 BC WATER CUM PROD. 302 BCR3 DST: 3522 FT. PM. H20 55,732 BC 5BCPD P: 10 W .C FD FROM LOWS? ST. PETER SS Figure 7. North-South St. Peter Structural Cross Section. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. WOODVILLE GOODWELL 28 PATRICK & ST. NORWICH 2-28 WENSTROM1-33 ANDERSON 1-8 ANDERSON 1-8A PRMARK1-17 + # # + # # A' SOUTH W ATER V -6700 FflONMCFD I 56BCPD r5* jf BULK DENSITY C U A PROD. 76 BCFG -6S00 T i 5^5TBC ST.FETERDRV h OLE" SL.B. BLUFF SAS WELL DST: 5235 FT. FM. H 20 P :3 5 M M 3 = D 70BCPD 0H 2O CUM. FROD. 645 BCR3 102,675 BC ST. PETER STRUCTURAL CROSS SECTION CUM. PROD. 3 0 2 6CFG PRODUCTION TOTALS T 0 1-1-91 HORIZONTAL NOT TO SCALE 55,732 BC | PERFORATED INTERVAL BULK DENSITY <25 G/CC -POROSITY >10% J ■ DST INTERVAL f s Section. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. WOODVILLE BISEL L ALTMAN 1-20 PATRICK & St, NORWICH 2-28 MYERS 1-34 HUDSON WEST % % g a m m a r a y v b u l k d e n s it y ------\ - -I ------6800 ■ -6900 P : 3 5 K/MCFD GLENWOOD FM. £ 70BCPD C H 2 0 2 CUM. PROD. 6 4 5 BCFG 102,875 BC STPETERSS -7000 P:3M M C FD 70BCPD CH20 CUM. FROD. 3.16 BCFG 56079 BC NO CORES OR TESTS D S T .3 5 M l| P: 3 1 WELL AB\D- WATERED OUT 10BCI ST. PETER STRUCTURAL CROSS SECTION CUM. PROD. 0 | PRODUCTION TOTALS T 0 1-1-91 HORIZONTAL NOT TO SCALE PERFORATED INTERVAL 'BULK DENSITY <25 G/CC ^POROSITY > 10% 7 DST NTERVAL Figure 8 East-West St. Peter Structural Cross Section. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. BISEL LAKE BETTS CREEK MYERS 1-34 HUDSON 1-35 C O X O N 1-2 DANELS 1-1A DANELS 1-1 + % $ EAST -6800 -6900 GUENWOODFM. fl»<3AS\. WATBT STPETERSS _ _-7000 NO TESTS DST 7B MMCFD P: 33 MMCFD ES OR TESTS DST. 35 MMCFD 3 BC NO TESTS P : 3 MMCFD 120BBLH2O 10 BC CUM. PROD. 0 0 7 BCFG RJRAL CROSS SECTION CUM. PROD. 033 BCFG ZONEABND. HORIZONTAL NOT TO SCALE / BULK DENSITY <25 G /C C -POROSITY > 10% Section. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 18 -(800 33 »• 22 TRAVERSE LIME STRUCTURE LOW • O L » CAS ♦ DRY HOLE Figure 9. Structure Contours on the Top of the Traverse Limestone (Devonian). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 23 -150 3 3 3 6 1 -200;---- 23 Figure 10. Structure Contours on the Top of the Michigan Stray Sandstone (Mississippian). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission 20 Goodwell Dome Well control indicates a minimum of 60 feet of clos ure on the top of the St. Peter Sandstone at Goodwell (Figure 6). However, based on proprietary seismic data reviewed by the writer (C.J. Stewart III, personal com munication), closure of 160 feet is likely with a down-to- the-southwest fault indicated south of Goodwell Dome. Fur ther evidence for this fault interpretation is observed on the Michigan Stray Sandstone structure map (Figure 10). Based on relatively abrupt south structure contour dip (150 ft./mi.), a northwest-southeast trending, down-to- the-southwest fault is inferred at depth to the south of Goodwell Dome (Figure 10). It is inferred that this fault dies out up section above the St. Peter Sandstone, as wellbore evidence of a fault (i.e. missing section) is not observed. The Goodwell dome has a structural closure on the Michigan Stray Sandstone in excess of 100 feet (Figure 10), in comparison to closure of 40 feet at Woodville. The Goodwell dome has a structural closure on the Michigan Stray Sandstone in excess of 100 feet (Figure 10), in com parison to closure of 40 feet at Woodville. Hunqerford Dome In December of 1988, Petrostar Energy, Traverse City, Michigan, completed the St. Norwich #1-22 (T15N-R11W) for Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 10 Mmcfd and 144 Bcpd from a lower St. Peter Sandstone reservoir after drill-stem testing five Mmcfd from the uppermost St. Peter Sandstone. This discovery is located nearly two miles north, and over 150 feet lower, at the St. Peter Sandstone level to the Woodville crestal dome (Figure 6). It is evident that this well is located on an entirely separate structure from Woodville Anticline. The size of this feature remains undefined by drilling, how ever, seismic data presented by Petrostar to the State of Michigan for a field spacing hearing indicates that it is a dome shaped feature which covers about 500 acres. Goodwell East Nose Goodwell East field (section 23 and 26; T14N-R11W) produces oil and gas from the Traverse Limestone and Mich igan Stray Sandstone. Structure mapping (Figures 9 and 10) shows that production occurs from closure of 30 feet or less, located on a north-south trending basinward plunging nose of structure contours, which extends to the south well beyond the study area. Two wells drilled on this fea ture were completed as dry holes at the Ordovician level. Both wells were completed as moderate gas producers in the Silurian Burnt Bluff dolomite. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 22 Thinning of Isopachs Domal structures mapped at the St. Peter Sandstone level are associated with thinning of overlying formations (Figures 11-18). Mappable isopachous thinning over deep structures are well defined in most intervals between the Salina A2 Carbonate and the top of the St. Peter Sandstone (Figures 11-14). The oldest mappable thinning of isopachs over domal structures is present in the Glenwood isopach (Figure 11). This isopach thins from 140 feet off structure to 110 feet on structure at Woodville dome. No obvious gross litho- logic facies changes associated with the isopach thinning are observed by wireline log correlation, rather a gradual and systematic thinning of the entire interval. Similarly, the Trenton to Glenwood (Figure 12) and Niagaran to Tren ton (Figure 13) isopachs indicate subtle yet mappable thinning over the deep structures with no obvious discon- fomities present. The most dramatic thinning of isopachs is in the Sal ina A1 and A2 Salts, represented by the A2 Carbonate to Niagaran isopach (Figure 14). This pattern of isopach thinning very closely corresponds to deeper structure. The A2 and A1 Carbonates respectively overlie the A2 and A1 Salts, and show no appreciable thickness variation across the study area. However, the A1 Salt, regionally 370 feet Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. MO 24 20 2 3 125 122 2 6 2 9 25 32 3 6 '121 106 115 105 134 120 131 135 126 110 106 124 GLENWOOD TO STPETB? ISOPAO CJ.- 10 FT. M r HOLE ST. PETER TESTS c as v * u IPPER ST. PETER ______CAS WELL I M U © Figure 11. Top of Glenwood to Top of St. Peter Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. R 11 W TRENTON TO GLBWOOD ISOPACH C4.-IO FT. DRY HOLE ST. PETER TESTS C a s w e u . UPPER ST. PETER CAS I m j l £ Figure 12. Top of Trenton to Top of Glenwood Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. v06 26 B72i MAGARAN TO TRENTON ISOPACH 672 Figure 13.Top of Niagaran to Top of Trenton Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. THICK 882. 900 20 Figure 14. Top of Salina A2 Carbonate to Top of Niagaran Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. .7 9 5 7 7 2 780 27 7 4 9 7 7 5 j 751 7 8 9 1 7 8 ij ( g k ^ 6 7\t> 7 4 0 '00 7 6 6 20 22 7 0 9 ■P UMT TO A2 CARB. ISOPACH C.I.- 10 FT. ^ DRYH0C£ ST. PETER TESTS c a Sv* l i / & & u p p e r s t. p e t e r — ____ . n w CA5 WOJ. I MLE Figure 15. Top of Salina F Unit to Top of A2 Carbonate Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 1 4 7 9 ' 1 4 8 4 1 4 9 0 1466* [4 6 3 1464 146U1501 1507| 1473 1 4 7 / U B 9 148V 150 1454 1 4 4 6 , 1439 1 4 7 5 2? Figure 16. Top of Dundee to Top of Salina F Unit Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 29 H4 SUNBURY TO DUNDEE LSISOPAO — Figure 17. Top of Sunbury shale to Top of Dundee Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. iTHIN 29 2 8 THIN 92k 33 35 3 6 20 22 23 BASE JURASSIC - PARMA SS ISOPACH C J.-20 FT. ^ ST. PETER TESTS • Oft. UPPER ST. PETER * GAS GAS YELL ♦ DRY HOLE t M L £ Figure 18- Base of Jurassic Red Beds to the Top of the Parma Sandstone Isopach. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 31 thick, thins to a minimum of 288 feet at Betts Creek field. Similar thinning is mappable over the other St. Peter fields, yet no thinning whatsoever is present at Goodwell East field. Upper Silurian through upper Mississippian isopachs exhibit gradual basinward thickening and indicate no sys tematic thinning of isopachs associated with known deeper structures (Figures 15-17). A widespread post-Bass Islands (Late Silurian) unconformity is documented across the Michigan Basin (Fisher et al., 1988); however, no discern ible thickness variations indicative of structural growth and subsequent planation by an erosion surface are evi dent. Another widespread unconformity of regional extent, between the Mississippian Marshall Formation and the over- lying Michigan Formation is well documented in the Mich igan Basin (Lillienthal, 1978; Newcombe 1933). Evidence of structural growth and subsequent erosional planation at this unconformity surface is not present in the study area. Rather, the lithologic sequence below the top of the Michigan Formation is remarkably uniform and laterally consistent across the study area. Dramatic thinning is again mappable in an interval between the upper Pennsylvanian and the base of the Jur assic (Figures 18 and 19). The basal Pennsylvanian Parma Sandstone (Saginaw Formation) lies unconformably on the Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 32 Upper Mississippian Bayport Limestone (Michigan Formation) (Lilienthal, 1978). The interbedded sandstones and shales of the Saginaw Formation are in turn overlain unconform- ably by Jurassic (Kimmeridgian) Red Beds. The Parma Sand stone varies in thickness from 40 to 130 feet across the study area with no apparent relation between thickness and structural position. However, an isopach map of the int erval between the base of the Jurassic Red Beds and the top of the Parma Sandstone (Figures 18-19) defines a sys tematic and mappable thinning of isopachs in close corres pondence to Parma Sandstone structural closures. This iso pach (Figure 18) defines mappable thinning over Woodville, Goodwell, and Goodwell East fields while no thinning is present at Bissel Lake or Betts Creek fields. Cause of Thinning The close correspondence in map view of isopachous thinning and positive structure is highly indicative of structural uplift as the cause of thinning. The present sites of St. Peter structural highs were intermittently positive areas for a long span of geologic time. Landes (1959) recognized this recurrent structural style as very common across U.S. mid-continent oilfields: Whatever the cause for folding, it must be, in most instances, an activity subject to repeat perform ances, for recurrent folding is the rule rather than Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. u> OJ MICHIGAN FM. MICHIGAN U. U. MISSISSIPPI U. U. PENNSYLVANIAN 1 JURASSIC JURASSIC RED BEDS A I I -o- NE NE SE 2-HN-I1W * PARMA :SS PARMA 'TRIPLE 'TRIPLE GYP' MICHIGAN STRAY' i I - o BASEJURASSICJREDBEDS OF. i i -O of post-Late Pennsylvanian structural growth. A Datum baseis of Jurassic. This demonstrates dramatic thinning indicative SE NE 20-15K-11W . SW NW 28-15NUW SW SE 28-15N-11W Figure 19. Jurassic to Mississippian Gamma-Ray Log Stratigraphic Cross Section. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. the exception in the mid-continent and similar areas. Subsurface isopach mapping has shown that most struc tures are the result of several periods of folding. "Once an anticline, always an anticline is a maxim with wide applicability." (Landes, 1959, p. 289) The amount of thinning undergone is the result of the interplay of structural uplift, sedimentation rate, eros ion, compaction, and plastic flow. Gay (1989) has suggest ed that "syndepositional compaction structures" are a much more common feature of sedimentary basins than is present ly recognized. Syndepositional compaction structures form as a result of gravitational compaction over positive top ographic features (Gay, 1989). The remarkably close correspondence of deeper struct ure and thinning in the A1 and A2 salt, coupled with the fact that the salts are stratigraphically the lowest rel atively incompetent structural units, suggests that the salt isopach thins are the result of plastic flow of salt in response to "late" (i.e., Pennsylvanian or later) structural growth. However, isopach mapping (Figure 18) indicates that Goodwell East field experienced Pennsyl vanian (or later) structural growth yet exhibits no thin ning of the A1 or A2 Salts (Figure 14). If the thinning of the A1 and A2 Salts were solely due to plastic flow in response to structural uplift, the greatest thinning of salt would correspond in map view with the most pronounced folding (i.e. Woodville Dome). This is not the case. The oretical studies of the mechanical behavior of salt masses Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 35 (Jackson and Talbot, 1986) indicate that salt should ex perience plastic behavior at relatively shallow burial depths (less than 1000ft). Fault Control of Structural Growth Although unequivocable evidence for faulting is lack ing, the presence of a deeply buried fault system control ling the patterns of structural uplift is by far the sim plest and most workable hypothesis. The most compelling evidence for fault control is the repeated occurence throughout the Paleozoic of localized thinning over pos itive structures. It is well documented that the Paleozoic Michigan basin is underlain by a buried segment of the Mid-continent rift system (Dickas, 1986; Fowler and Kuen- zi, 1978; Hinze et al., 1975;) of Proteozoic (1.1 Ga) age (Figure 4). Rift related structures are superimposed on older structural grains in the igneous and metamorphic rock complex inherited from the Penokean and other Archean or Proterozoic orogenic events (Hinze et al., 1975). Ob served structures in the Minnesota-Wisconsin segment of the mid-continent rift are dominated by normal faulting, which parallels the main trend of the gravity and magnetic anomaly (Dickas, 1986). The dominant northwest trend of structures in the Michigan basin largely parallels the trend of the mid-Michigan gravity anomaly. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. The simplest and most obvious conclusion is that the structures observed in Paleozoic rocks in the central Michigan basin were largely controlled by a buried fault system in Precambrian rocks that was initially formed dur ing the Keeweenawan rifting event, and were, subsequently, , reactivated intermittently during the Paleozoic. Struct ures of similar proposed origin overlying the Mid-cont inent Rift System have been recognized in Kansas (Ber- i endsen, Blair, Watney, Newell, and Steeples, 1989), Neb raska (Carlson, 1989), and the Illinois basin (Kolata, 1990). Versical (1990) has suggested that many of the an ticlines in Michigan formed as "tulip structures" in res ponse to strike-slip movement on basement faults. These "deep-seated" faults do not appear to propagate upward and through the Paleozoic cover rocks. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. LITHOFACIES AND DEPOSITIONAL ENVIRONMENT Lithofacies Of the 30 wells drilled that penetrated the St. Peter Sandstone within the study area, only two cores of the uppermost St. Peter Sandstone were taken. Conventional four inch cores from the Wolverine Patrick and St. Norwich #2-28 (SWSE, Sec. 28-T15N-R11W) and the Wolverine Jansma #1-29 (NENE, Sec. 29-T15N-R11W) were examined and des cribed for this study. As observed in core, the upper St. Peter Sandstone and lower Glenwood Formation study in terval (Figures 20-21) may be divided into three general lithofacies. In ascending order these are: (1) burrowed, rippled sandstone lithofacies, (2) planar-laminated sand stone lithofacies, and (3) argillaceous, sandy-dolomite lithofacies. Burrowed, Rippled Sandstone Lithofacies This lithofacies consists of fine to medium grained, sorted to well-sorted, rounded to well-rounded, buff to dark grey or white sandstone. Represented in the interval of 7959-8003 feet in the Patrick and St. Norwich #2-28 well (Figure 20), this lithofacies is generally bioturb- 37 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. CO ('/.) 10 .1 20 rvaslve cement Tight Tight dol Oil filled 10 \ CORE PERM. (MD.) (MD.) PERM. CORE POROSITY CORE f 100 CT a X«STJUT. to wK. massive &URR 8SDQI*© C^TT &URR 8SDQI*© CRCATKKAL CdH’ACT LEGEND KM . GRAZDC TRACES C.AT LAMINAE. STYtCUTES n * l £ HOR. TO HOR. SUSHO*. LAM PUUWJt VEIT. 8'JMOVS gry. M ------ SS, SS, buff, to A gry., ebnd styT and dk. dk. g ry abna to stul. wh, hvy b lonrb« abnd clay by erosional bases and clay drape lamina Mixed Utholgu, ss to sdy. do\, gry to SS, SS, buFf to A ripple x. strat. and hor. plr. lam def. Massive mottled red ss. appears w / 'weathered*,clau. wh. lam.. 'reduction* 4* th. c~u spots, dol. sm. rent zrtQ 7937.5. v.tt. tltely qtz. ant'd ss, 1/2' to 2* beds of SS, SS, red, v. •clean*, sub. hor. to hop. sm. sm. rent hor. plr, 797V78 lam., Is wh. plr. lam., no blcturb.. no clay or sfyL lam. skollthos birr, and wave rippled facies def. due to Urrow mottling, sm. ram. hor. scour sirf., Q 80027 w / cly rip up clasts Red Red to blU otl sm.) ss, bedding poorly v. plr. lam., no ripple x strat. but sm. rem. hor. plr. lam., hor. bar. well def. that define trough x beds on slip feces slay lam., abnd matrix clay, hvy burr. In pert GR. SIZEGR. MEAN/MAX. t FT. MISSWG t < FT. MISSWG 7950 8000 LOG LOG DEPTH Figure 20. Core Description, Patrick and St. Norwich #2-28. BURROWED. BURROWED. RIPPLED PLANAR PLANAR LAMINATED .SANDSTONE LITHOFACIES , SANDSTONE LITHOFACIES GLENWOOD ST. ST. PETER GAMMA RAY GAMMA Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 10 .1 20 Tight Tight dol' 10 CORE CORE PERM. (MD.) CORE POROSITY (%) t> 100 ______plr lam p hor CT a CJXT TRACES ARP JSARP C N C CONTACT m C R*5An>O L S LEGEND KA CUT U*CHA£. STTI.XITES RJPflE <*STR*T. K * . 73 5LSH0R. V£*T. SWCWS ------bloturb, more arg Than above SS, SS, buff, frl„ mssv, dol. cmt. SS, SS, bu ff to ly gry, frl, sm fling hor lam and obvious sm burrows oil stn esp.679,81,83,96 • friable, no sed. struct, app. ft dol Q 7974 dol ft app. struct, no sed. friable, mnr mnr bloturb., zones of wh. qtz cmt / SS, red to It gry, mssv., hvy blk oil stn Ip stn oil hvy blk mssv., gry, It red to SS, SS, SS, red, frl., clean, sm hor plr lam Dolomite, dk to It gry, erg, styl, sdy lp. mod. mod. bloturb. l-10cm bddng def. by arg. >0oJ,_dk_oru^arq^^churned" sdy, 'SSj^lt_ tp_dk_gryt hyy_bJ.otur£.t_ _ tp_dk_gryt hyy_bJ.otur£.t_ 'SSj^lt_ . sfylo'ltes anc* $' 1 • • ZZZZZIZj 7 -Af £ T(J—7 u 7950 8000 s an dy Figure 21. Figure 21. Core Description, Jansma #1-29. lithofacies a r g i l l LITHOFACIES d o l LITHOFACIES PLANAR LPLANAR A MSS S BURR. RIPPL'D SS RIPPL'D BURR. £ ray c gamma GLENWOOD ST, ST, PETER Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. ated, with horizontal grazing traces observed toward the base and vertical skolithos burrows prevalent toward the top. Current induced sedimentary structures include ripple cross stratification, possible hummocky cross stratifi cation (Harms, Southard, Spearing, and Walker, 1979) and some remnant horizontal planar lamination. Bedding geom etry is defined by erosional bases, clay laminations and abundant mud chip rip-up clasts that define cross laminae slip faces. Stylolites and scour surfaces are common. Many of the primary sedimentary structures are obscured by bio- turbation and/or diagenetic fabrics such as pervasive quartz overgrowth cementation, pressure solution, or styl- olitization. The burrowed, rippled sandstone lithofacies is gradational upward into the overlying planar-laminated sandstone lithofacies. In thin section, this lithofacies consists of quartz- arenites with minor (5% or less) amounts of K-feldspar grains. The principle intergranular materials are clays, quartz overgrowths, and dolomite cement. Planar-laminated Sandstone Lithofacies This lithofacies, present in both cored wells, (Fig ures 20 and 21) consists of a fine to medium-grained, well-sorted, well-rounded, red to brown sandstone. This lithofacies generally is not bioturbated and exhibits sub Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. horizontal to horizontal-planar lamination (Harms et al., 1975). This lithofacies has a noticeably lower percentage of clay-sized material (either true mineralogical clay or micritic carbonate) than the underlying burrowed, rippled sandstone lithofacies. Stylolites, mud chip rip-up clasts, and clay laminations are rare or absent. This lithofacies is somewhat striking in core because of its sometimes bright red color and its massive homogenous appearance. This lithofacies is oil-stained to varying degree in both cored wells. The planar-laminated sandstone lithofacies is the main gas producing zone in the study area and exhibits marked changes in porosity on and off structure. In thin section, this lithofacies consists of quartz- arenite with minor amounts of K-feldspar grains. This lithofacies has a noticeably lower interstitial clay con tent than the underlying burrowed, rippled sandstone lith ofacies. In addition to clay, which in places lines pores, quartz overgrowths, dolomite, and bitumen (dead oil), are the primary intergranular materials. Minor interstitial material includes feldspar overgrowths and anhydrite ce ment. Argillaceous, Sandy-Dolomite Lithofacies Ten feet of this lithofacies, typical of the Glen- wood Formation, is present in the Jansma #1-29 from 7950- Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 7964 feet (Figure 21). This lithofacies consists of inter bedded dark to light grey argillaceous dolomite, and bio- turbated buff to white dolomitic argillaceous sandstones. The gradational Glenwood-St. Peter Sandstone contact is picked at 7964 feet in the Jansma #1-29 well. Any evidence of current-formed sedimentary structures in the sandstones has been completely obliterated by extensive bioturbation. Depositional Environment The burrowed, rippled sandstone lithofacies repre sents deposition in middle to lower shoreface environments (Dickinson, Berryhill, and Holmes, 1972; Harms et al., 1975; Moslow, 1984; Scholle and Spearing, 1982). Seaward, and in deeper water than the foreshore and upper shoreface zone, normal, relatively quiet water deposition alternates with turbulent conditions experienced during periodic storms. Storm events produce abundant scour surfaces and "hummocky cross stratification" (Harms et al., 1975, p. 23). Under fair weather conditions, clays and mud will settle from suspension on the lower shoreface. These fine grained sediments are then mixed into underlying sands by burrowing organisms. Burrowing intensity generally in creases with water depth in the shoreface zone (Moslow, 1984). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 43 The planar-laminated sandstone lithofacies was de posited in high energy foreshore to upper shoreface en vironments (Dickinson et al., 1972; Harms et al., 1975; Moslow, 1984; Scholle and Spearing, 1982). As defined by Harms et al. (1975) the foreshore includes the swash, surf, and breaker zones. Typical foreshore to upper shoreface deposits are described as mineralogically and texturally mature sandstones, with low angle to planar "swash cross stratification" (Harms et al., 1975). These high energy deposits have little clay sized material due to winnowing and the lack of burrowing (Dickinson et al., 1972; Harms et al., 1975; Moslow, 1984; Scholle and Spear ing, 1982). The inferred depositional environment for the arg illaceous, sandy-dolomite lithofacies is restricted marine shelf, seaward and in deeper water than the shore zone. Beginning in Glenwood time, sand transport into the basin was cut off as a result of regional transgression. Carb onate deposition commenced in response to higher sea lev el, as evidenced by the 15 to 20 foot thick bed of shaly- dolomite in the lower Glenwood Formation. Sands observed in the lower Glenwood Formation probably represent rework ing of upper St. Peter Sandstone deposits. The extensive bioturbation and high clay content of these sediments in dicate sediment starved conditions that reflect deeper Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 44 water depths than interpreted for the underlying St. Peter Sandstone. Discussion Based on the vertical succession of lithologies and sedimentary structures described above, the St. Peter Sandstone study interval represents a shoaling upward se quence deposited by lateral progradation of a sandy shore line (Dickinson et al., 1972; Harms et al., 1975; Moslow, 1984; Scholle and Spearing, 1982). This sandstone sequence was subsequently "drowned" by a relatively rapid rise in sea level and overlain by restricted marine argillaceous carbonates and reworked sandstones of the lower Glenwood Formation. From the top of the St. Peter Sandstone to the base of the study interval (Figure 20) an overall upward decrease in clay-sized material is observed. Mud chip rip- up clasts, clay laminations, and stylolites generally de crease upward. This trend is well represented by gamma-ray log profiles (Figure 20), which display a general "clean ing" upward trend. The average and maximum grain size of the framework grains exhibits an overall coarsening upward profile, however grain size variations are subtle. If the volume of clay-sized matrix material were quantified, and averaged with framework grain size, a more pronounced up- Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 45 i ward coarsening sequence, typical of a prograding shore line, would be apparent. In general, the degree of bioturbation increases with depth in the study interval. The planar-laminated, sand stone lithofacies is completely devoid of trace fossils. Burrowing organisms are not observed in modern beach en vironments (Blatt ,Middleton, and Murray, 1980; Moslow, 1984) but are more abundant further offshore in middle to lower shoreface environments. Core is unavailable outside of Woodville field, how ever, based on log cross sections (Figures 7 and 8), it is likely that the overall vertical succession described ab ove is present in all wells in the study interval. Based on log correlation the foreshore to upper shoreface dep osits have consistently lower gamma-ray log response in the vicinity of Woodville field (Figures 7 and 8). Given the generally shallow water setting of St. Peter Sandstone deposition and the evidence for "early" structural growth (see following section on structural development and Nadon et al., 1991), it is likely that subtle facies changes due to shoaling over sea-floor highs occurred. Barnes (1988), Harrison (1987), and Lundgren (1991) have documented that in many other areas of the Michigan basin, a generally deepening upward sequence is observed in the upper St. Peter Sandstone, that is gradational into Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. the overlying Glenwood Formation. Perhaps the "anomalous" shallowing upward sequence described above is the result of shoreline progradation during rising relative sea lev el. The prograding shoreline built upward and kept pace with rising sea level, and was subsequently "drowned" as sand supply was cut off by inundation of the source area. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. RESERVOIR CHARACTERISTICS Core Porosity and Permeability Air permeability and Boyle's Law porosity measure ments were performed by CORE LABORATORIES INC., Mt. Pleas ant, Michigan, in one foot increments on the entire int ervals described above for the two wells. Vertical air permeability was also measured for the Jansma #1-29. The results of core analysis indicate (Figure 22) that the highest porosity and permeability is found in the fore shore to upper shoreface, planar-laminated sandstone lithofacies. The underlying middle to lower shoreface burrowed, rippled sandstone lithofacies has lower porosity and permeability (Figure 22). The argillaceous, sandy- dolomite lithofacies has the lowest porosity and permea bility of all lithofacies. Based on the porosity vs. perm eability crossplot (Figure 22), three reservoir facies and a reservoir seal are recognized that generally correspond to the lithofacies described above. It should be noted that the close correspondence of reservoir facies to lith ofacies is observed only in structurally high wells, such as the two cored. Reservoir Facies A (see below) is not present in off structure wells. 47 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. KEY V PLANAR LAMNATED SANDSTONE LITHOFACIES O BURROWED, RPPLED SANDSTONE UTHOFACES 1000- a AHULLACEOUS, SANDY DOLOMITE LITHOFACES RESERVOIR FACIES 'A' 100 - Q 10 - CD < RESERVOIR FACIES "B* LLI z: Od LLI Q_ 1.0 - NONRESERVOIR AND SEALING FACIES .1 ~aa r —— —i------1------1------1— 4.0 8.0 12.0 16.0 20.0 24.0 POROSITY (%) Figure 22. Core Porosity vs. Permeability Crossplot. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 49 Reservoir Facies A Reservoir Facies A has average porosity of 16% (range 11 to 21.1%) and average permeability of 160 millidarcies (md) (range 20 to 427 md) (Figure 22). In thin section, Reservoir Facies A rocks are generally very low in clay content and have well developed secondary porosity. Poros ity can be described as intergranular macroporosity (ie. pores >.015 mm [Coalson, Hartman, and Thomas, 1985]) with a large open pore geometry, and well connected open pore throats. In 25% of the samples of Reservoir Facies A in the Jansma #1-29, vertical permeability was higher than horizontal permeability. This may be caused in part by leached vertical burrows that appear in core as vertical vuggy porosity. All producing gas wells in the study area are perforated in Reservoir Facies A. Reservoir Facies B Reservoir Facies B has average porosity of 10% (range 5 to 15%) and average permeability of 6 md (range 2 to 30 md)(Figure 22). Reservoir Facies B rocks contain a higher percentage of interstitial clay which lines pores and bridges pore throats. This pore system is classified as intergranular macroporosity with considerable intercryst alline microporosity (Coalson et al., 1985). Although mea Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. sured porosity is not much lower than Reservoir Facies A, permeability is an order of magnitude lower. Nonreservoir Rock A third grouping of samples of the lowest porosity and permeability includes rocks with average porosity of less than 12% (range 1 to 11.8%) and permeabilities of less than 2 md (range less than .02 to 2 md)(Figure 22). Pervasively clay-cemented sandstones and tightly quartz overgrowth-cemented sandstones comprise the common nonres ervoir rock in the St. Peter Sandstone. Bitumen-plugged sandstone and extremely tightly dolomite-cemented sand stone are found interbedded with Reservoir Facies A rocks. All of the above rock types have low effective porosity and permeability, and do not contribute significantly to the storage capacity or the deliverabilty of the reser voir. Thus, they are characterized as nonreservoir rocks. Sealing Facies The reservoir seal consists of an impermeable dolo mite cap rock of the Glenwood Formation. Measured perm eabilities over a ten foot section of this interval in the Jansma #1-29 (7950-7960 ft.) average less than .02 md. Based on wireline log interpretation and correlation the dolomite beds maintain a thickness of about sixteen feet Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 51 across the study area, and form the seal to structural hydrocarbon accumulations. Petrophysical Log Analysis The results of core description and analysis indic ates significant vertical variation in reservoir quality. Defining the horizontal porosity distribution and quant ifying the relationship between porosity, structural pos ition, and hydrocarbon saturation requires correlation and analysis of petrophysical logs. By integrating core data with log analysis and structural history the controls bn reservoir development may be established. Neutron-Density Crossplot Porosity A common method (Asquith, 1982) of determining the porosity of rocks in the subsurface is by crossplotting neutron porosity and density porosity. This method gives reliable true porosity values regardless of lithology. Neutron-density crossplot porosities were calculated in one foot increments for 30 St. Peter Sandstone wells in the study area. The very close fit between measured core porosity and neutron-density crossplot porosity (Figure 23) attests to the accuracy and utility of this method. Average neutron-density crossplot porosities were calculated for all wells in the uppermost St. Peter Sand Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. stone correlative to the interval of 7924 to 7958 ft. in the Patrick and St. Norwich #2-28. This interval, which comprises the main pay zone (Reservoir Facies A) in all study area fields, varies from 32 to 37 feet thick across the study area and is readily correlated. The results of this analysis (Figure 24) documents dramatic variation in porosity in map view. A "background" or regional porosity average of 10-11% is fairly constant in off structure wells across the study area while porosity systematically increases with increasing structural position above closure to nearly 17% at Woodville and 18% at Goodwell^ Enhanced porosity is also observed to a lesser extent at Hungerford, Bissel Lake, and Betts Creek fields. In gen eral, porosity increases linearly at a rate of 5-6% por osity per 100 feet of structural height above closure (Figure 25). Water and Hydrocarbon Saturation A close relationship between porosity enhancement and structure is evident. Much of the pore space in areas of enhanced porosity is occupied by hydrocarbons in these structurally controlled accumulations. One of the object ives of this study is to determine the role of hydrocar bons in the evolution of porosity. As such, relating the distribution of hydrocarbons to structure and reservoir Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 53 VCLL NAI£: PATRICK 2-28 p in rCRK is f.d t DEPTH .30 COtiP oc JM OR 15tU t fEE! JO w a x Q( r 5 J 1 •* r \ 1 f | 1 ) 5950 r > >»•> \ \ •£ i * ( \ “ ... P. - —------— i - i • t S* 4 lOLNAtC: -WQ1A 1-29 cafe iso .orf depth at _ umi nrr flfiOfi Figure 23. Core Porosity and Neutron-Density Log Crossplot Porosity for both Cored Wells. GR=gamma ray, CORG=core ganuna ray, CORP=core porosity, PHIX and XPP=ND crossplot porosity. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. • IW^ F RODUCTIVE AREAS AVE. N -0 XPLOT POROSITY UPPER SHOtffACE/FOflgHORE FACES CJ.- IX (POROSITY) u tx if M ST. PETER TESTS ^ GAS WELL tfJ V UPPER ST. PET® ^ CASVSCU Figure 24. Average Neutron-Density Crossplot Porosity for Foreshore/Upper Shoreface Facies. See text for discussion. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 1 8 - WOODVILLE o ^ Q_ •— 1 6 - a t ' CO z o . cc M-5.0%/100 FT. LUO > a_ c 12 - -6820 -6810 -6860 -6880 -6900 -6920 -6910 1 8 - O a_ — X > _ f- i—i 16_ z' cno . cn M -6 ,6 % /100 FT. LU0>Q- ,,, H- 12 - -6610 -6660 -6680 -6700 -6720 -6710 -6760 STRUCTURAL POSITION (SUBSEA) Ufa s t . reTBt os wai - < j> - U f a ST. PETER OKY HOLE Figure 25. Average Neutron-Density Crossplot Porosity vs. Structural Position. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 56 geometry, by means of log analysis, is required. Water saturation (Sw) is the percentage of pore vol ume in a rock which is occupied by formation water (As quith, 1982). Water saturations are calculated based on empirical knowledge of the inherent resistivity of the formation, resistivity readings obtained from the later- olog tool, and neutron-density crossplot porosity (As quith, 1982). Deep laterolog values were corrected for the effects of invasion of drilling mud filtrate to obtain true formation resistivity (Rt), using tornado chart al gorithms programmed into the workstation. Water satur-' ations (Sw) were then calculated using the formula and parameters defined in Figure 26. Calculating water saturations in the St. Peter Sandstone is a complicated and often frustrating exper ience. In addition to inherent resistivity of the rocks and their contained fluids (water or hydrocarbons), res istivity log response is affected by variable depth of invasion of drilling mud filtrate into the formation, high resistivity "shoulder" bed effects, and the "Groningen" effect (Lorenzen, 1989). Cementation exponent (m) is prob ably quite variable as well because of the variable pore geometry described above in this diagenetically complex reservoir. In spite of the difficulties in calculating water saturations, the results of log analysis are streng- Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. - n Rt nn Sw n= — PhiXP Rw where: Sw = Water Saturation Rw “ Formation Water Resistivity .027 ohm-m Q BHT (H 7 deg. F) Rt = Formation Resistivity PhiXP = Crossplot porosity m = Cementation Exponent= 1.58 n = Saturation Exponent= 1.71 Figure 26. Water Saturation Equation. See text for discussion. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 58 thened by drill stem test results integrated with struct ure mapping. For example, the Patrick #1-28 (SW/4,NE/4; Sec.28, T15N-R11W) and the Anderson #1-8 (NE/4,NE/4; Sec. 8, T14N-R11W) have calculated water saturations in excess of 50% in the foreshore to upper shoreface facies. These structurally low wells (Figures 6-8) recovered 3522 and 6235 feet of formation salt water during drill-stem test ing, indicative that these wells penetrated the reservoir below the gas water contact. Productive gas wells all ex hibit calculated water saturations of 10 to 40% in the foreshore to upper shoreface facies. The results of log analysis, integrated with subsurf ace mapping, indicates that a water saturation cutoff of greater than 50% closely approximates the gas-water con tact (Figure 27). Reservoir Facies A rocks exhibit irre ducible water saturations as low as 10% and average 15% where productive across the study area. Irreducible water saturation is defined as "the water saturation at which all the water is adsorbed on the grains in a rock, or is held in the capillaries by capillary pressure" (Asquith, 1982, p. 2). A hydrocarbon zone at irreducible water sat uration will produce hydrocarbons water free. Reservoir Facies B rocks exhibit irreducible water saturations of 20-50%, as a result of clay-sized intergranular matrix with more capacity to hold water than the cleaner Reser- Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. CJ1 VO jc PEF.M . = f3 0 M rt. rop.osiTV: im ... 100.00 MLL LLD LLS _ 100.00 GAS WATER 7SD0 7S50 6000 TO? or ST. or TO? FfTFR ST. .00 .30 FEET 100.00 >ZP7H L ii >ZP7H 100.00 .00 vELL ►&*£: ►&*£: vELL £-£8 PATRICK Figure 27, Figure 27, Computer Processed Log: Patrick 2-28. See text for discussion. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. voir Facies A. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. ORIGIN AND MODIFICATION OF POROSITY Porosity varies dramatically within relatively short distances (i.e., less than 2500 ft.) within foreshore to upper shoreface facies of the uppermost St. Peter Sand stone (Figure 24). It has also been observed that porosity varies from about 10% in lower energy depositional facies to as much as 20% in higher energy facies in the same wellbore. The observed porosity distribution in the St. Peter Sandstone is the result of a sequence of geologic processes that acted upon the original sediments. These processes can be classified as either depositioi^J. or postdepositional (diagenetic). Depositional Control of Porosity The primary depositional controls on reservoir qual ity are sandstone composition, grain size, and sorting (Blatt et al., 1980; Bloch, 1991). Within the St. Peter Sandstone analyzed for this study, porosity development is closely related to depositional facies. Rock of the high est porosity occurs in sandstones deposited in high energy foreshore to upper shoreface environments. Lower energy middle to lower shoreface facies have consistently lower porosity (and permeability), largely due to interstitial 61 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. clay-sized material of depositional origin. These rocks remain of comparably low reservoir quality. Although a subtle coarsening-upward pattern is ob served in the study interval, grain size and sorting of framework grains are similar in both high and low energy facies. More than anything, this is probably a function of provenance from multicycle Early Paleozoic sandstones of the source area (Harrison, 1987; Lundgren, 1991). There simply was not a wide spectrum of grain sizes (or grain composition) supplied to the depositional basin. Deposit- ionally, the difference in porosity and permeability ob served between high and low energy facies is due to the relative abundance of fine grained (clay sized) sediment present in lower energy facies. Diagenetic Modification of Porosity The St. Peter Sandstone has undergone complex dia genesis that has resulted in sandstone porosities ranging from 0 to 22% in the study interval. Diagenetic processes can either reduce or enhance primary porosity by physical and chemical processes that "are functions of temperature, effective pressure, and time." (Bloch, 1991; p. 1147). The principle intergranular materials that occlude pore space are quartz overgrowths, clays, and dolomite cement. Minor interstitial material includes bitumen (dead oil), feld Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. spar overgrowths, and anhydrite cement. Perhaps the finest reservoir rock present in the St. Peter Sandstone of the Michigan basin is located in the study area (Reservoir Facies A), with porosities ranging up to 22% and permea bilities of over 600 millidarcies. The high reservoir quality observed is likely the result of the pervasive development of secondary porosity (Barnes, 1989; Lundgren, 1991). Within the study interval, evidence for secondary porosity (Figures 28-31) includes cement dissolution fronts, elongate and oversize pores, partial dissolution of grains, and inhomogeneity of packing (Schmidt and McDonald, 1979). A two to three foot thick, tightly dolomite cemented zone is observed in core ten feet below the top of the St. Peter Sandstone (7936-38 ft. in the Patrick and St. Nor wich #2-28)(Figures 20 and 30). This tightly dolomite ce mented sandstone is separated from excellent reservoir quality rock by a dissolution front (Figure 31) with no changes of framework grain size or sorting evident across the front. The dolomite cement is recognized as being a very early carbonate cement by the presence of "floating" sandstone grains (Erdman and Surdam, 1984). This tight zone is persistent throughout the study area in both on and off structure wells (Figures 7 and 8), which also sug gests depositional or early burial origin. This example Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 64 Figure 28. Photomicrograph of Secondary Porosity Developed in Foreshore/Upper Shoreface Facies. (Jansma #1-29, 7985 ft.). Evidence for secondary por osity includes elongate, oversize pores, par tial dissolution of grains, and general inhomo geneity of packing. Note pressure solution, quartz overgrowths, and sericitized K-feldspar grain. Magnification 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 65 Figure 29. Photomicrograph of Well Developed Secondary Porosity in Foreshore Facies. (Jansma #1-29, 7994 ft.). This sample had measured plug permeability of 609 md. and 18.2% porosity. This sample exhibits very open framework that does not appear to have undergone significant compaction, and only minor pressure solution. Open framework and notable absence of quartz overgrowth cement may result from early carbonate cement that was subsequently dissolved. Note residual oil and the absence of interstitial clay. Magnification 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Figure 30. Photomicrograph of Tightly Dolomite Cemented Sandstone. (Patrick and St. Norwich #2-28; 7937 feet). Porosity=1.7%/ permeability=.02 md. Sand grains "floating" in dolomite matrix and the lack of significant compaction or quartz over growth cementation are suggestive that this cement represents early marine carbonate ce ment, that was subsequently dolomitized. The degree of grain support increases toward the dissolution front (Fig. 31). Magnification 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 67 Figure 31. Photomicrograph of Dissolution Front. This illustrates the abrupt change in reservoir quality that occurs due to dissolution. Per vasive dolomite cement reduces porosity and permeability to nearly zero while excellent reservoir quality is present across the dis solution front. This sample is from high energy foreshore/upper shoreface facies. Magnification 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 68 presents conclusive evidence for secondary porosity form ation across a diagenetic front. It is also evident (Fig ures 30 and 31) that this zone of early carbonate cement did not experience subsequent diagenetic modification oth er than dolomitization. This interval "survived" the sec ondary porosity forming processes, and very nearly main tained its original depositional fabric. Barnes (1988), Barnes, Turmelle, and Adam (1989), Budros and Daly (1986), and Lundgren (1991) have shown that pervasive quartz overgrowth cementation commonly occludes porosity in shallow water, high energy litho- facies in the St. Peter Sandstone. The relationship of porosity to depositional facies is anomalous within the study area, in that quartz overgrowth cementation does not completely destroy porosity in foreshore to upper shore face facies. Perhaps, pervasive quartz overgrowth devel opment did not occur because primary porosity was partial ly filled with early carbonate cement. This carbonate ce ment was subsequently dissolved upon further burial, near ly restoring porosity to that of shallow burial condi tions. In summary, porosity distribution in the St. Peter Sandstone has been modified by diagenetic processes in cluding compaction, pressure solution, dissolution and cementation by calcite (now dolomite), quartz, chlorite, Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 69 illite, and other minerals (Figures 28-33). A generalized paragenetic sequence of diagenetic events (Figure 34) based on observations in this study is in general agree ment with previous work by Barnes (1988); Barnes et al. (1989); Budros and Daly (1986); and Lundgren (1991). Discussion The existence of comparatively "tight" rock (10% por osity) immediately adjacent laterally to enhanced porosity (Reservoir Facies A) within upper shoreface to foreshore facies is problematic. Based on close correlation of gam- ma-ray logs (Figures 7 and 8) and given the known lateral continuity of shoreface environments, a depositional ori gin for this pattern of porosity development is unlikely. The linear relationship (Figure 25) of porosity to struct ural position, and the correspondence of hydrocarbon ac cumulation to areas of enhanced porosity, are also sug gestive of post depositional modification of porosity. The existence of secondary porosity in rocks of mod erate to deep burial depth has become widely recognized in recent literature (McDonald and Surdam, 1984; Schmidt and McDonald, 1984). Theoretical and experimental studies show that thermal maturation of kerogen produces organic and inorganic acids with the potential to dissolve rock matrix and framework grains (Surdam, Boese, and Crossey, 1984). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. Figure 32. Photomicrograph of Clay Filled Sandstone. This sample from lower energy middle to lower shoreface facies (Jansma #1-29, 8003 ft.). Measured porosity of this sample is 15.3% but permeability was only 2.2 md. Much of the porosity is microporosity associated with 'clay minerals, which line pores and bridge pore throats. Pervasive quartz overgrowth cement ation is lacking, possibly as a result of clay coats inhibiting nucleation sites. This sample has undergone significant compaction. Note partially sericitzed K-feldspar grain. Magni fication 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 71 Figure 33. Photomicrograph of Supermature Quartzarenite of Foreshore/Upper Shoreface Facies. Measured permeability is 17 md. and porosity 11.4%. Reservoir quality is reduced by pore filling bitumen which blocks pore throats and locally completely fills pore space. Note pressure solution and relative lack of interstitial clay or quartz overgrowth cementation. Magnification 70X, plain light. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. j - to RELATIVE RELATIVE TIMING OF DIAGENETIC EVENTS EARLY LATE Figure 34. Generalized Sequence of Diagenetic Events. BURIAL DOLOMITE SOLUTION PRESSURE MECHANICAL COMPACTION EMPLACEMENT HYDROCARBON EARLY EARLY MARINE FORMATION OF FORMATION CEMENTATION DOLOMITIZATION OF DOLOMITIZATION CARBONATE CEMENT CARBONATE SECONDARY POROSITY SECONDARY QUARTZ OVERGROWTH QUARTZ PRECURSOR CARBONATE PRECURSOR Reproduced with permission of the copyright owner. Further reproduction prohibited without permission 73 BjorZykke (1984) has suggested that much secondary por osity identified in the literature may in fact be dis solution enhanced primary porosity. In well-cemented sand stones, limited pathways for dissolution fluids exist, while "maximum leaching by pore water will occur in sand stones having the highest primary porosity" Bjorlykke (1984, pg. 282). Fabric and texture of dissolution en hanced primary porosity would be indistinguishable from secondary porosity as defined by Schmidt and McDonald (1984). Possibly the tightly dolomite cemented zone de scribed above survived dissolution because it retained no porosity and permeability pathways for leaching fluids, while sandstone retaining some amount of primary porosity experienced dissolution enhancement. Although much of the porosity observed is likely the result of leaching by acidic pore waters, it is also rec ognized that the present porosity and permeability dis tribution is largely controlled by depositional facies. Rock of the highest reservoir quality was deposited in high energy foreshore to upper shoreface facies that init ially had the highest primary porosity. Lower energy mid dle to lower shoreface deposits had lower primary porosity due to a higher mud to sand ratio. These basic deposit ional differences exerted control over later diagenetic Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 74 processes by controlling the extent to which water moved through or within a given sediment package. Original poros ities and permeabilities of homogenously burrowed, fine grained, clay-rich deposits of the lower shore face were likely low because of the abundance of de- trital clay, and were further reduced at an early stage by compaction. Because of the very low perm eability, these deposits probably acted as systems which were closed or semiclosed (experiencing expul sion but not input) to migrating pore waters. The dominant diagenetic reactions in these sediments re flected rearrangement of materials in situ and in cluded processes such as clay neomorphosis and minor development of quartz overgrowths. (Stonecipher and May, 1990, p. 41). Higher energy, foreshore/upper shoreface facies sediments can be characterized as relatively open pore systems with the potential for throughflow of migrating pore waters. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. TIMING OF HYDROCARBON ACCUMULATION Timing of Trap Formation The results of isopach mapping are summarized (Fig ure 35) by a series of histograms for the five St. Peter fields and Goodwell East nose. The percentage of thinning for each structural feature was determined by dividing the minimum thickness of a stratigraphic interval by its re gional thickness. Based on the above arguments (see Structural Development section), it is concluded that pat terns of isopach thinning are a direct indicator of syn- depositional structural growth. Thus, Figure 35, in ef fect, is a graph of structural growth rate versus time. In summary, all St. Peter fields show substantial early (pre- A2 Carbonate) domal development, while Goodwell East field does not. Upper Silurian through upper Mississippian iso- pachs exhibit gradual basinward thickening and reveal no evidence of structural growth associated with known deeper structures. Marked thinning is again mappable in an inter val between the upper Pennsylvanian and the base of the Jurassic, at Goodwell, Woodville, and Goodwell East field. The timing of this period of structural growth is inferred to be post-Late Pennsylvanian pre-Jurassic. 75 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. j - o> . j .] p I .| m J dev | BETTS CREEK BETTS BISEL LAKE BISEL l'!'s i! II f f II i! l'!'s ffl 2 2 *».?.« S 3$ ffl ORa ORa SIL ?!- REGIONAL INTERVAL THICKNESS 30 > . j .! p L | d e v | s i l WOODVILLE HUNGERFORD O R a | ^ ; *! 11 i | j | ifPMF i ^ 11 *! ; %- REGIONAL INTERVAL THICKNESS 30 > thickness interval GOODWELL O R a | SIL. 1dEvJm.Ip.IJ. GOODWELL EAST GOODWELL Figure 35. Percentage Isopachous Thinning Histograms. %- %- %- regional 25 30 30 > > Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. The observation that hydrocarbons occupy secondary porosity attests to the relative timing of porosity devel opment with respect to hydrocarbon accumulation. Theoret ical and experimental studies show that thermal maturation of kerogen produces organic and inorganic acids with the potential to dissolve rock matrix and framework grains (Surdam et al., 1990). Dissolved C02, forming carbonic acid, "lowers the pH of pore fluids, thus providing an acidic solvent for carbonate and other materials, and C02 gas creates a gas-drive mechanism for the migration of hydrocarbons into reservoir rock (Porter and Weimer, 1982, p. 2556)". Much of the C02 gas generated during degrad ation of organic matter occurs early, before peak oil gen eration (Schmidt and McDonald, 1979). Thus, the develop ment of secondary dissolution porosity occurs just prior to migration and accumulation of hydrocarbons in available traps. Timing of Hydrocarbon Generation and Migration Establishing the burial and thermal history of a sedimentary basin is critical to developing an under standing of the timing of hydrocarbon generation and ac cumulation. The burial and thermal history of the Michigan basin has been a source of recent controversy among re searchers, although most agree that "almost all Paleozoic Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 78 strata in the Michigan basin display elevated levels of organic maturity that cannot be explained by present-day burial depths, geothermal gradients and heat flow" (Pol lack and Cercone, 1989). Nunn, Sleep, and Moore (1984) theorized that a deep-seated thermal event was responsible for the observed elevated levels of thermal maturity. Cer cone (1984), and Pollack and Cercone (1989), postulated that a "thermal blanket" of over 3000 feet of Pennsyl vanian rocks raised the geothermal gradient, but were sub sequently unroofed due to widespread epeirogenic uplift and erosion during Late Paleozoic and Early Mesozoic time. Detailed oil-source rock correlations for St. Peter Sandstone accumulations are unavailable in the literature. Organic-rich shales and mudstones of the uppermost Prairie du Chien group ("Foster" or "Brazos") are likely source rocks (Harrison, 1987). Based on the Lopatin (1971) meth od, Cercone (1984) concluded that during the Paleozoic, rocks entered the top of the oil window at burial depths ranging from 6200 to 7500 feet (Figure 36) in the central Michigan basin. If true, Lower and Middle Ordovician source rocks would have commenced generating hydocarbons in Early Devonian to Early Missippian time. Thus, hydro carbons generated in Early Devonian to Early Mississippian time accumulated in paleostructural traps that have been Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. j VO - km ■4 •2 U. Silurian U. L. Devonian L. L. Ordovician L. U. Ordovician U. Ordovician M. K 100 Pennsylvanian,'Mississippian M. Devonian/ll. Devonian —- Devonian Devonian/ll. M. CENTRAL MICHIGAN 200 Wyvy* rp 300 M D 400 m o d e l 2 m odel 1 \ ‘ Modified from Cercone (1984) GROWTH GROWTH ACCUMULATION REACT. STRUCTURAL BURIAL/BYDR0CAR30N STRUCTURAL STRUCT. BURIAL/BYDR0CAR30N dashed lines. dashed window shown by shown window Depth to top of oil of top to Depth Ma Figure 36. Michigan Basin Burial History Curve. St. Peter Sandstone stippled. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 80 documented to have formed during the Siluro-Ordovician. Discussion All St. Peter Sandstone fields, within the study area and beyond, exhibit evidence of pre-Devonian paleostruct- ural growth. Fundamentals of carbonate sedimentology (Wil son, 1975) dictate that, within the confines of the study area, the Devonian Traverse Limestone depositional surface was flat and at or very near sea-level. As such, a Trav erse Limestone to St. Peter Sandstone isopach should closely represent St. Peter Sandstone paleostructure (Fig ure 37) in Late Devonian time. Thus, hydrocarbons gener ated in Early Devonian to Early Mississippian time accum ulated in paleostructural traps that have been documented to have formed during the Siluro-Ordovician. During the post-Late Pennsylvanian stage of structural growth, pal eostructural closures at Goodwell and Woodville domes were accentuated by further folding. Paleostructural closures at Bissel Lake and Betts Creek domes did not experience such late domal growth, but were tilted down to the east as a result of uplift in the vicinity of Woodville dome. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 5103 5233" 22 23 -5300 5153 2 7 2 6 5076 SliS 5133 32 •5101 3 4 5116 5112 5154 5131 5163. 5103 4930 5077i 001 ■5100^ 20 PALEOSTRUCTURB TRAVERSE LS TIME CJ.- 50 FT. 2 7 Figure 37. Top of St. Peter Paleostructure in Late Devonian (Traverse Limestone) Time. See text for discussion. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. MODEL FOR RESERVOIR DEVELOPMENT Reservoir quality in the beach/upper shoreface facies is considerably lower in off structure wells. A close re lationship between structural position, hydrocarbon sat uration, ^pd porosity development is observed within this facies. Several features of interest concerning this res ervoir heterogeneity aye apparent: (a) increased poros ity/reservoir quality is observed in gas bearing inter vals; (b) the greater the amount of structural closure the higher the average porosity; (c) at Woodville, wells below the GWC show regional porosity (10-11%) while at Goodwell "wet" wells still show enhanced porosity; and (d) at Bis- sel Lake and Betts Creek areas of enhanced porosity do not coincide closely with present structural position. Given the evidence for secondary porosity, the por osity pattern observed resulted from: (a) secondary por osity forming processes (dissolution by acidic migrating pore waters) that were concentrated and more complete on the crests of domal structures (Figure 38, Bjorlykke, 1984) and/or; (b) secondary porosity forming processes affected the study area uniformly and hydrocarbons subse quently migrated into paleostructural traps. During pro gressive burial, continued cementation occluded porosity 82 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. DISSOLUTION OF .CARBONATES PRECIPITATION OF SILICATES / / / j t *.'• ' -iS^^rn^Arr.nK^i^N^*.'- • PRECIPITATION OF / PQftEWATER -.V ^ \N CARBONATES S X . s c,^TE^ A n W /''\\\ DISSOLUTION OF FLOW s i l i c a t e s . £ 7 / ' / s / sv;V;.. sNx '/ // // sv <«S£->--.:-:y THEORETICAL MODEL FOR CONVECTION CURRENTS IN A FOLDED SANDSTONE Figure 38. Model for Leaching and Precipitation in a Folded Sandstone. From Bjorlykke (1984). Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 84 below the hydrocarbon-water contact, while porosity was preserved by hydrocarbons that had accumulated in the pal- eostructural trap. Proving which of these two processes was responsible for the observed porosity distribution is impossible given the available data. However, Lundgren (1991) has demonstrated that "late" burial dolomite is common in the St. Peter and, based on neutron-density crossplots (Figure 39), it is likely that the off struct ure cement is also dolomite, as well. By comparing variations in structural development and reservoir geometry of several of the fields present in the study area an integrated model for reservoir development emerges which serves to explain the observed geology. For example, the Wolverine Daniels #1-1A (NE/4 SW/4; sec. 1- T14N,R11W) exhibited an interval of enhanced porosity that corresponds exactly to the gas filled portion of the res ervoir (Figure 40). This well was directly offset to the west by the Nomeco Coxon #1-2. This offset was struct urally level and on the same feature as the Daniels #1-1A yet was completed as a dry hole, with no porosity enhance ment present in the upper St. Peter Sandstone whatsoever. The zone of hydrocarbon accumulation (and porosity en hancement) coincides better with paleostructural closure than present structure (Figure 40). It is likely that sec- Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 85 2.3 o ~ 2.5 CO Z in Q 2.6 CD 2.8 20 NEUTRON POROSITY (%) 0 GAS WELLS T Dftr HOLES • TIGHT STREAK Figure 39. Neutron-Density Crossplot of Average Values for Foreshore/Upper Shoreface Facies. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. ON 00 T14N -6954 -5103 RllW EAST r r -6914, -5074 ■6915 -6 9 7 3 -5163 -5100 DANIELS 1-1 PALEOSTRUCTURE PRESENT PRESENT STRUCTURE % SBC 120BBLH2O ZONE A3NO. ZONE P: 33P: MMCFO TESTS NO DANIELS 1-1A DST 7flDST t^MCPD CLM PROD. 037 BCFG CLM PROD. RHOB I o COXON 1-2 NO TESTS GR GAS FILLED GASENHANCED FILLED POROSITY Figure 40. Betts Creek Field Model for Reservoir Development. WEST Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. ondary porosity was preserved by hydrocarbons which accum ulated in a paleostructural trap. This paleostructure was later tilted up to the northwest in Pennsylvania^ or later time as Woodville Dome was further uplifted. The hydro carbon column of 20 feet or less remained "diagenetically trapped" but was not of sufficient height to generate high enough buoyancy pressure (Arps, 1950; Schowalter, 1979) to force hydrocarbons into the low reservoir quality rock in the vicinity of the Coxon #1-2 well. Areas of enhanced porosity at Woodville Field (Figure 24) closely correspond to the area of Late Devonian paleostructural closure (Figure 37). Woodville Field exhibits a gas column of 68 feet that corresponds very closely with the Traverse Limestone paleostructural relief (Figure 18). The gas column at Goodwell is only 36 feet although Late Devonian paleostructural closure is at least as great as at Woodville Field. At Goodwell wells in off structure positions exhibit enhanced porosity (Figure 24) in spite of the fact that they are water filled. If the proposed model for reservoir development described above is correct then it is likely that these "wet" wells with enhanced porosity were located above the hydrocarbon water contact during the late phase of cementation. The Goodwell dome has a structural closure on the Michigan Stray Sandstone in excess of 100 feet (Figure 10), in Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. comparison to closure of 40 feet at Woodville. A late period of structural growth of greater magnitude than ob served in any of the other fields in the study area is well documented at Goodwell. As Goodwell Dome was accen tuated during this period of growth, the flanks of the hydrocarbon bearing paleostructure were rotated below the gas water contact. Since that time little or no further cementation has occurred. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. PRODUCTION HISTORY AND RECOVERY EFFICIENCY The problem of low recovery efficiency from St. Peter Sandstone gas fields is one of grave concern to the oil and gas industry. Many wells throughout the Michigan basin are initially very impressive with high gas flow rates recorded on DST's and IP tests only to yield extremely disappointing cumulative recoveries. For example the Dan iels #1-1A (Betts Creek Field) was DST'd for 7.8 Mmcfd from the upper St. Peter Sandstone, yet only produced 64 Mmcfg from this interval prior to abandonment. This well suffered from early water production that severly lowered the permeability to gas and filled the wellbore effect ively "killing" the well. Bisel Lake field and three flank producers at Woodville Field suffered similar problems and are now plugged and abandoned. The Anderson #1-8A (Good- well Field) produced gas at a steady rate of about 100,000 Mcf/month for nearly five years, with cumulative produc tion of over 7 Bcfg through October, 1989. Subsequent to shutting in of the well for a three day bottom hole pres sure test, water production increased substantially, and gas production rate precipitously decreased (C.J. Stewart III, personal communication). Similar well histories to these are common across the Michigan basin, and have con tributed to the decrease in exploration activity. 89 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. CONCLUSIONS Significantly enhanced reservoir quality in the St. Peter Sandstone is observed in gas bearing zones in wells located on domal structures. Geometry and degree of this enhanced porosity development is the result of the inter play of structural, depositional, and diagenetic controls. Within the study interval, the St. Peter Sandstone represents a shoaling upward sequence deposited by lateral progradation of a sandy shoreline. Depositional facies exert fundamental control on reservoir quality. Sandstone of the highest reservoir quality was deposited in high energy foreshore to upper shoreface environments and ini tially had high primary porosity. Lower energy middle and lower shoreface deposits initially had lower porosity and permeability, largely due to interstitial clay of depo sitional origin. These rocks remain of comparably low res ervoir quality. Recurrent structural growth of domal features throughout the Paleozoic is well documented by isopach mapping. Burial and thermal history studies indicate that hydrocarbons were generated in Ordovician aged source rocks during late Devonian-early Mississippian time, and accumulated in Ordovician to Silurian aged paleostructural traps. These paleostructural hydrocarbon accumulations 90 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 91 were then modified by a post late Pennsylvanian period of structural growth. Enhanced reservoir quality is the result of pervasive carbonate dissolution secondary porosity development that occurred just prior to hydrocarbon emplacement. The degree of secondary porosity development is a function of depo sitional facies and structural position. Hydrocarbons may play a role in preserving secondary porosity above the hydrocarbon water contact. Alternatively, leaching may have been greater on the crests of domal structures. Proved reserves range from 3 to 60 Bcfg for the five St. Peter fields located within the study area. Recovery efficiencies of only 20-50% are demonstrated for these fields, largely because of production problems associated with water encroachment. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. BIBLIOGRAPHY Arps, J.J., 1950, Engineering concepts useful in oil finding: AAPG Bulletin, v. 48, pp. 157-165. Asquith, G.A.: 1982, Basic well log analysis for geologists: Amer. Assoc, of Petr. Geol., Tulsa, Ok. 216p Barnes, D.P., 1988, Diagenesis and reservoir quality of the St. Feter Sandstone, Michigan Basin (Abs.): Lower Paleozoic of the Michigan Basin Symposium, WMU-MBGS, Kalamazoo, Mich. Barnes, D.P., T.M. Turmelle, and R. Adam, 1989, Diagenetic controls on reservoir heterogeneity in the St. Peter Sandstone, Michigan Basin (Abs.): AAPG Bulletin, pp. 331 332. Berendsen, P., K.P. Blair, W.L. Watney, K.D. Newell, and D. 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Daly, 1986, Observations concerning porosity and permeability development within Bruggers 92 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. 93 Formation (Ordovician) in Michigan Basin subsurface (Abs.): AAPG Bulletin,, v. 70, p.1063. Carlson, M.P., 1989, Influence of mid-continent rift system on occurrence of oil in Forest City Basin, (Abs.): AAPG Bulletin, v. 73, p. 340. Catacosinos, P.A., P.A. Daniels, Jr., and W.B. Harrison III, 1991, Structure, stratigraphy, and petroleum geology of the Michigan basin: in, D.R. Kolata, ed., Interior Cratonic Basins, AAPG Memoir 31, pp.561-601. Cercone, K.R., 1984, Thermal history of Michigan Basin: AAPG Bulletin, v. 68, pp. 130-136. Coalson, E.B., D.J. Hartman, and J. Thomas, 1985, Producitve characteristics of common reservoir porosity types: South Texas Geol. Soc. Bulletin, no. 4, pp. 35-51. 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Weimer, 1982, Diagenetic sequence related to structural history and petroleum accumulation: Spindle field, Colorado: AAPG Bull., v. 66, pp.2543-2560. Schmidt, V., and D.A. McDonald, 1979, Secondary reservoir porosity in the course of sandstone diagenesis: AAPG Education Course Note Series No. 12. Scholle, P.A., and D. Spearing, 1982, Sandstone depositional environments: AAPG Mem. 31, 410 p. Schowalter, T. T., 1979, Mechanics of secondary hydrocarbon migration and entrapment: AAPG Bulletin, pp. 723-760. Sloss, L.L., 1963, Sequences in the cratonic interior of North America: GSA Bull., v. 74, pp. 93-113. Stewart, C.J., III, 1989-1990, Personal communication. Stonecipher, S.A., and J.A. May, 1990, Facies controls on early diagenesis: the Wilcox group, Texas Gulf Coast: in I.D. Meshri and P.J. Ortoleva, eds., Prediction of Reservoir Quality through Chemical Modeling: AAPG Mem. 49, pp.25-44. Surdam, R.C., S.W. Boese, and L.J. Crossey, 1984, The Chemistry of secondary porosity: in D.A. McDonald and R.C. Surdam, eds., Clastic Diagenesis: AAPG Mem. 37, pp. 127-149. Syrjamaki, R.M., 1977, The Prairie du Chien group of the Michigan Basin: Michigan State University, unpublished M.S. thesis. Versical, R.T., 1990, Basement control on the development of selected Michigan Basin structures as Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. constrained by fabric elements in Paleozoic limestones (Abs.): MBGS March Meeting, East Lansing, Mich. Wheeler, C.T., Jr., 1987, Subsurface study of lower Ordovician Prairie du Chien group and underkying Cambrian formations and their relation to pre-Glenwood unconformity in southern peninsula of Michigan (Abs.): AAPG Bull., v. 71, p. 112. Wilson, J.L., 1975, Carbonate facies in geologic history: Springer-Verlag, New York, 471 p. Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.