A New 3D Structural Modeling Technique Unravels Complex Structures within the Marcellus Shale: Utilizing
Borehole Image logs
Aimen Amer, Steve Collins, Daniel Hamilton, Helena Gamero, Carmen Contreras and Manish Singh
Schlumberger, aamer@slb.com
The standard practice in Marcellus Shale development is to drill a pilot well followed by a sidetrack targeting zones
with superior reservoir and completion quality. A common challenge in drilling these wells is to remain in the zone
of interest. In many instances within the Marcellus Shale, wells are drilled out of zone and the problems can be
attributed to complex structural settings. Such structural complexities can often be understood using seismic data.
In this case the horizontal well indeed encountered a complex structure, however, the available seismic at the time
of drilling the well was poor and therefore no definite interpretation could be made. In an attempt to better
understand the structure, high resolution borehole image logs were acquired within both the pilot and horizontal
wellbores. These preexisting data sets were utilized to construct a 3D structural model using a new methodology
that incorporates the handpicked dip sets for the bedding, faults and fractures as interpreted from borehole image
data to build a near wellbore structural model. Borehole image data in this example provides critical information
on sub-seismic faults present within the well section.
The resulting model reveals a complex structure composed of three elements: 1) an asymmetrical anticline, 2) a
highly tilted fault block and 3) a second gently tilted fault block. This analysis has been compared to a previous
model and major discrepancies were found. Openhole logs were utilized to assist in the model interpretation and
newly acquired 3D seismic has confirmed the new model produced using this new methodology. Finally, an
attempt to understand the fractures over the section was also conducted and relative fracture ages were
established by comparing the structure to the magnitude of the different fracture classes. The new 3D structural
model and natural fracture information is now being used to identify hydraulic re-fracturing candidate zones
within the focus wellbore and this type of study may have implications to the drilling and completion of shale
reservoirs in the future.
Variability of Thin Grainstone Units in the Trenton and Black River (Ordovician) of the Michigan Basin and the
Significance to High Resolution Cycle Stratigraphy and Reservoir Characterization
Tarek Anan and G. Michael Grammer
Western Michigan University, Michigan Geological Repository for Research and Education, Department of
Geosciences, Kalamazoo, MI 49008, atarekeg@yahoo.com
Thin packstone to grainstone beds, intercalated with open shelf deposits, have been identified in the Trenton and
Black River Groups of Michigan and Indiana. The origin of these centimeter to decimeter thick grainy beds has
been previously described by most workers as either being storm deposits (tempestites), with normal marine
skeletal debris shed from shallower water, orrepresenting localized shoal deposits. Since the majority of both
Trenton and Black River facies consist of deeper subtidal, bioturbated wackestones and packstones deposited on
an open shelf or ramp, an interpretation of these grainy units as shallow marine shoal deposits would have
significant value in the development of a high resolution cycle stratigraphic framework for these units.
The packstone and grainstones occur in thin beds, ranging from a few to several centimeters in thickness.
Compositionally these beds contain a normal marine fauna consisting primarily of trilobites, brachiopods, and
crinoids. These skeletal beds are intercalated with muddier deposits within the Trenton Black River which have
previously been interpreted as open marine, deeper shelf or ramp. Initial evaluation indicates that there is a
distinct textural variation within the skeletal beds ranging from pure skeletal grainstones to mud-rich packstones,
with at least some of the grainstones exhibiting evidence of flooding surfaces or transgressive lags along the upper
boundaries. Our preliminary hypothesis is that these grainstones represent shoal deposition while the muddier
packstones were likely deposited as storm deposits. As such, the grainstones would provide good cycle cap
markers for cyclostratigraphic correlation while developing a reservoir model. These thin beds are readily
identifiable on image logs, and could provide a means for cycle stratigraphy within the Trenton and Black River
Groups without relying on core data.
Subsurface Lithostratigraphy of the Cambro-Ordovician Knox Group in Illinois; Regional Correlation of Potential
Reservoirs and Seals for CO2 Sequestration
Zohreh Askari, Y. Lasemi, Z. Lasemi, and H. E. Leetaru
Illinois State Geological Survey, Institute of Natural Resource Sustainability, University of Illinois at UrbanaChampaign, Champaign, IL 61820, askari@isgs.illinois.edu
As part of a US DOE-funded project, detailed subsurface lithostratigraphic evaluation of the Cambro-Ordovician
strata is being conducted in the Illinois Basin to better understand the potential reservoirs and seals for CO 2
storage of the Knox Group. Deep wells penetrating the Knox Group were selected for detailed petrographic
examination of well cuttings and available cores. The preliminary results obtained from this ongoing study along
with outcrop data, have provided important information regarding the lithologic variations in the Knox Group in
the Illinois subsurface.
In the north and central part of Illinois, the Cambro-Ordovician Knox Group (300-1500 feet thick) is subdivided into
alternating carbonate-dominated and siliciclastic-dominated units. The carbonate units, from base to top, include
the Cambrian Franconia Formation, Potosi Dolomite, Eminence Formation, and the Ordovician Oneota and
Shakopee Dolomites. The siliciclastic units include the Cambrian Eau Claire Formation, Galesville and Ironton
Sandstones, Davis Member of the Franconia Formation, Momence Member of the Eminence Formation, and the
Ordovician Gunter and New Richmond Sandstones. The siliciclastics thin southward, where in the southern and
deeper part of the Illinois Basin, the Knox Group is composed dominantly of dolomite with thin shale beds. In this
area, the Knox Group thickens to over 6000 feet and the formations are not easily differentiated. The integrated
approach using detailed petrographic examination has identified lithostratigraphic and lithofacies variations within
the Knox Group that aid in determining the best reservoir and sealing units in the Knox for potential carbon
sequestration.
Chemostratigraphy of the Marcellus Shale: Insights into Depositional Environments and Implications for Play
Fairways
David R. Blood1, and Gary G. Lash2
1
EQT Production, Pittsburgh, PA, 15222, bloodr@eqt.com
2
Dept. of Geosciences, SUNY Fredonia, Fredonia, NY, 14063
Chemostratigraphic (x-ray fluorescence) elemental concentrations determined from four Middle Devonian
Marcellus Shale cores from southwestern Pennsylvania and northern West Virginia have been analyzed to
determine watermass chemistry and the chemical nature of preserved organic matter. Authigenic uranium and
molybdenum enrichment factors (U EF and Mo EF) supported by the size distribution of pyrite framboids suggests
a depositional environment characterized by a strongly suboxic to often euxinic water column through Union
Springs and locally Oatka Creek deposition. Low Degrees of Pyritization (DOPs) that would otherwise suggest a
more dysoxic water column may be explained by the rapid sedimentation rates during Marcellus time. Sediment
passing quickly through the zone of iron reduction would have limited the formation of pyrite thereby lowering the
relative DOP and uptake of hydrogen sulfide from the water column. In turn hydrogen sulfide rich bottom waters
would have favored vulcanization of organic matter and uptake of molybdenum. Indeed, a correlation can be
drawn between the occurrence of calculated organic sulfur and Mo EFs. After correction for loss of organic sulfur
via thermal maturation, organic sulfur content of the Marcellus Shale has been estimated to average 3.9% in
northern West Virginia, within the range of published results of 3.7-6.8% in the Monterey Shale. Given that
thermal conversion of sulfur-rich organic matter requires lower activation energies due to the breaking of C-S
bonds rather than C-C bonds, organic sulfur contents of the Marcellus Shale may play a role in the location of the
“Marcellus Oil” fairway, pushing the fairway outboard of significant Marcellus deposition.
Stratigraphic Completeness of Carbonate-Dominated Records from Cratonic Interiors versus Continental
Margins: Stratigraphic Thinning Occurs via Condensation and Truncation at Multiple Scales
Mara E. Brady
The University of Chicago, Department of Geophysical Sciences, 5734 South Ellis Avenue, Chicago, IL 60637,
marabrady@uchicago.edu
Over Phanerozoic time scales, stratigraphic records from the cratonic interior are generally assumed to be
relatively incomplete, with more numerous and longer-duration hiatuses, compared to records from the
continental margin. However, this assumption may not hold true for the shorter time scales (i.e. several 106 years)
over which accumulation of the preserved stratigraphic record on the craton actually takes place.
In particular, this study examines Middle-Upper Devonian carbonate-dominated deposits in Iowa (cratonic interior)
and Nevada (continental margin) that developed at equivalent paleolatitudes, preserve a comparable range of
depositional environments, and were connected via a continuous epicontinental seaway. The stratigraphic record
in Nevada is up to eight times thicker than the coeval record in Iowa. However, these two records appear to be
equally complete at the limits of any sequence stratigraphic, biostratigraphic, and chemostratigraphic resolution
(approximately 106-year resolution). This study compares the two records at finer stratigraphic scales to
determine whether, and at which scale, the record in Iowa is (1) condensed but equally complete, (2) truncated,
but comparable where preserved, or (3) truncated beyond recognition of equivalent stratigraphic elements
compared to that of Nevada.
First, the facies compositions and thicknesses were documented in the two field areas in the context of measured
stratigraphic sections. Next, I determined how these facies stack to form meter-scale cycles, defined as
gradational facies transitions interrupted by discontinuities that reflect non-deposition and/or erosion. Finally, I
compared the thicknesses and total numbers of stratigraphic elements preserved in these two records.
The results of this analysis indicate that meter-scale cycles in Iowa are on average half as thick and half as
numerous compared to Nevada. Moreover, the thinnest meter-scale cycles in both Iowa and Nevada tend to have
fewer numbers of facies preserved within them, and Iowa contains a higher proportion of those thinner, faciespoor cycles. However, the majority of the discrepancy in thickness of meter-scale cycles can be accounted for by
differences in the thickness of individual facies – facies in Nevada are on average 1.5 times thicker than those in
Iowa.
These findings demonstrate that major truncation of entire meter-scale cycles does occur in Iowa, but truncation
of facies within the preserved meter-scale cycles appears to be minimal. A major portion of the discrepancy in
overall thickness of meter-scale cycles can be accounted for by condensation, or miniaturization, of individual
facies in Iowa relative to Nevada. These results have implications for the ability of stratigraphers and
paleobiologists to compare records across distinct basins for the purpose of documenting relative sea level
changes, variations in meter-scale cycle stacking patterns, and evolutionary and paleoecological dynamics through
time. This study suggests that, where preserved, the record of carbonate-dominated systems from the cratonic
interior is qualitatively comparable, though relatively condensed, compared to that of the continental margin. The
majority of truncation of cratonic carbonate records likely occurs at major depositional sequence boundaries and
other recognizable discontinuities.
Depositional History of the Central Appalachian Region during the Cambrian—Ordovician Sauk Megasequence
David K. Brezinski1, John F. Taylor2, John E. Repetski3
1
Maryland Geological Survey, 2300 St Paul Street, Baltimore, MD 21218
2
Geoscience Department, Indiana University of Pennsylvania, Indiana PA 15705
3
U.S.Geological Survey, 926A National Center, Reston VA 20192, jrepetski@usgs.gov
In the central Appalachians, carbonate deposition of the Great American Carbonate Bank began during the Early
Cambrian with the deposition of ramp facies. Vertical stacking of bioturbated subtidal ramp deposits and
dolomitized microbial boundstone led to the initiation of platform sedimentation, a sand shoal facies, then
development of peritidal cyclicity. Initiation of peritidal deposition coincided with development of a rimmed
platform that would persist throughout much of the Cambrian and Early Ordovician. The platform became
subaerially exposed during the Hawke Bay regression, bringing the Sauk I Sequence to an end.
The basal Sauk II transgression during the early Middle Cambrian submerged the platform and reinitiated the
peritidal cyclicity that had characterized the pre-Hawke Bay strata. This thick stack of meter-scale cycles is
preserved as the Pleasant Hill and Warrior Formations of the Nittany Arch (central Pennsylvania), the Elbrook
Formation of the Great Valley (VA, MD), and the Zooks Corner Formation of the Conestoga Valley (eastern PA).
Deposition of peritidal cycles was interrupted during deposition of the Glossopleura and Bathyriscus-Elrathina
trilobite Zones by 3rd order deepening episodes that submerged the platform. Regressive facies of the Sauk II
Sequence produced platform-wide restrictions and deposition of the lower sandy member of the Gatesburg
Formation, the Big Spring Station Member of the Conococheague Formation, and the Snitz Creek Formation. Resubmergence of the platform was initiated during the late Steptoean (Elvinia Zone; medial Late Cambrian) with the
expansion of extensive, subtidal thrombolitic boundstone facies. Vertical stacking of no fewer than four of these
thrombolite-dominated intervals records 3rd order deepening episodes separated by intervening shallowing
episodes that produced peritidal ribbony and laminated, mudcracked dolostone.
The maximum deepening of the Sauk III transgression produced the Stonehenge Limestone in two 3 rd order
submergences. Subsequent circulation restriction during the Sauk III regression produced a thick stack of meterscale cycles of the Rockdale Run Formation (VA, MD) and the upper Nittany, Epler, and lower Bellefonte
formations of the Nittany Arch. This regressive phase was interrupted by a 3 rd order deepening event that
produced the “oolitic member” of the lower Rockdale Run and the Woodsboro Member of the Grove Formation in
the Frederick Valley, MD. Platform exposure and extreme circulation restrictions marked the end of the Sauk
Sequence and resulted in the Knox/Beekmantown unconformity over most of the Appalachian region. In the
central Pennsylvania/W. Maryland/N. Virginia depocenter, however, sedimentation continued, and the sequence
boundary is represented there by the “dolomite member” of the Rockdale Run and the Bellefonte Dolomite of the
Nittany Arch.
Restricted circulation continued through much of the Whiterockian in this region, with the deposition of the
uppermost Rockdale Run, the Pinesburg Station and middle and upper parts of the Bellefonte Dolomite of the
Great Valley and Nittany Arch regions. During deposition of the Tippecanoe Sequence, beginning late in the
Whiterockian, the peritidal shelf cycles were re-established during deposition of the St. Paul Group (MD) and the
Loysburg Formation (central PA).
Depositional model of the Marcellus Shale in West Virginia based on facies analysis
Kathy R. Bruner1,2,3, Margaret Walker-Milani3, and Richard Smosna1,2,3
1
National Energy Technology Laboratory, Morgantown, West Virginia 26507, rsmosna@wvu.edu
2
URS Corporation, Morgantown, West Virginia 26507
3
West Virginia University, Morgantown, West Virginia 26506
A lithologic analysis of well exposed Marcellus outcrops has identified six different facies in West Virginia and
neighboring states: (1) light gray calcareous shale, (2) fossiliferous limestone, (3) black calcareous shale, (4) black
noncalcareous shale, (5) dark gray noncalcareous shale, and (6) K-bentonite. Close interbedding of these rock
types attests to a complex, ever-changing environment on the eastern foreland ramp of the Appalachian basin.
The environmental setting was clearly not a deep trough, permanently anoxic, salinity stratified, sediment starved,
and populated exclusively by phytoplankton—the traditional depositional model. To the contrary, our
sedimentary data suggest a rather shallow water depth, intermittent anoxia, normal-marine salinity, a fluctuating
input of siliciclastic mud, and faunal communities of low and moderate diversity.
Interbedding of the shale and limestone lithofacies as well as the vertical stacking of facies associations is
explained most simply by fluctuations in water depth coupled with fluctuations in sediment supply. The sea floor
was, at times, immediately below wave base (Facies 1 and 2), around the depth of the thermocline (Facies 2 and
3), or below the thermocline (Facies 4 and 5), relative sea level changing through two sequences of lowstand,
transgression, and highstand. Simultaneously the supply of siliciclastic mud was greater at times of lowstand
(increased erosion) and highstand (prograding shoreline), and the supply smaller during transgression (sediment
stored in distant coastal plain).
Assessing Composite Storage Formations for Geologic Carbon Sequestration
Marc L. Buursink, Ernie R. Slucher, Matthew D. Merrill, Peter D. Warwick
U.S. Geological Survey, 12201 Sunrise Valley Drive, Reston, VA 20192
As part of the U.S. Geological Survey domestic geologic carbon dioxide (CO 2) sequestration assessment we have
identified composite storage formations in several basins. A composite storage formation or assessment unit
(SAU) consists of multiple reservoir rock intervals and a single regional seal. In contrast, a typical SAU consists of a
single reservoir formation and regional seal pair. If multiple reservoir rock units are deposited without an
intervening thick regionally distributed seal, these formations may be assessed as one composite SAU, and the
total gross thickness of all the reservoir rock is included. Initially, the net thickness, average porosity, and
permeability distribution are expressed separately for each formation in the composite SAU. Available literature
may provide isopach maps and reservoir properties (from core samples or pumping tests) for distinct facies in the
formations. A GIS workflow is applied to sum the net porous thickness.
To illustrate the concept of composite SAU’s we provide two examples from assessment work in Wyoming. The
first composite SAU spans the Paleozoic formations in the Southwest Wyoming Province (SWWP or Greater Green
River Basin). The reservoir formations include the Pennsylvanian Tensleep Sandstone and the Weber Sandstone,
the Mississippian Darwin Sandstone Member of Amsden Formation and the Madison Limestone, and the
Ordovician Bighorn Dolomite. The assessed regional seal is the Permian Phosphoria Formation, which is about 100
ft. thick in this basin with shale and anhydrite. For example, the Tensleep is white ledge-forming sandstone with
an average gross thickness of 600 ft. The Madison is mostly carbonate rocks with an average thickness of 250 ft.
The Bighorn is massive or thin-bedded dolomite, with a sandstone member, and exhibits 450 ft. gross average
thickness. Due to porosity and lithology variations, the assessed net porous interval for each formation is a
fraction of its gross thickness. The Cambrian Flathead Sandstone was not included, for example, due to its low netto-gross porous interval and intervening shales. By assessing multiple formations in the SWWP, we increase the
net porous thickness of a nearly five-million acre SAU. We do not find that the net thickness of the composite SAU
exceeds our predicted maximum column height for CO2 (about 2,500 ft.). A similar composite SAU consisting of
Paleozoic formations was assessed in the Wyoming Thrust Belt (WTB). Though it is smaller, at slightly over threemillion acres due to multiple thrust faults, the gross SAU thickness is greater because of repeated sections. For
example, the Madison is about 1,300 ft. thick here due to over-thrusting. Only areas where the Phosphoria
Formation (with an average thickness of 400 ft.) is present, as a regional seal, are included in the composite SAU.
Our separate net-to-gross estimates for the formations in the SWWP are applied to the correlative WTB rocks.
The Case for CCS as a Clean Development Mechanism (CDM)
Carpenter, Steven M.
Advanced Resources International, 1282 Secretariat Court, Batavia, OH 45103, scarpenter@adv-res.com
The Carbon Capture & Sequestration (CCS) marketplace is lacking standardization and therefore the ability to allow
CCS projects to be considered as Clean Development Mechanisms. There is an international push to change this
and recognize CCS. This recognition will allow for standardized and ultimately address a much needed CDM option
and international standardization.
This process is beginning with a bi-national effort between the United States and Canada. CSA Standards, a leading
developer of standards, codes and personnel certification programs, and the International Performance
Assessment Centre for Geologic Storage of Carbon Dioxide (IPAC-CO2 Research Inc.) have partnered to develop a
bi-national American-Canadian carbon capture and storage (CCS) standard for the geologic storage of carbon
dioxide (GSC).
The GSC standard will be developed by leading North American experts and, upon completion, will be the world's
first formally recognized CCS standard in this area. It is intended that the new standard will be used as a basis for
the promotion of international standards through the International Organization for Standardization. The
standard is expected to be completed by the end of 2011.
CSA Standards will manage the standards development process through the establishment of a Technical
Committee (Committee) that shall be responsible for developing and maintaining the standard. A seed document
based on existing industry guidelines, related standards, and IPAC-CO2 expertise has been prepared and will be
presented to the Committee for consideration. The Committee, with process and editorial support from CSA
Standards, will be completely responsible for the content of the final standard. Membership of the Committee
will be drawn from experts with full GSC project life cycle knowledge and experience and will represent a balance
of stakeholder needs.
The bi-national American-Canada Consensus Standard will address the full geological carbon dioxide storage
project life cycle including: site selection, operation, closure, and post-closure stewardship. It is expected that ISO
standardization and certification will follow.
Preliminary Evaluation of Offshore Transport and Storage of CO 2
Carpenter, Steven M.
Advanced Resources International, 1282 Secretariat Court, Batavia, OH 45103, scarpenter@adv-res.com
The DOE-NETL has funded the Southern States Energy Board (SSEB) who have teamed with IOGCC (and others) to
prepare a report that will have as its primary objective to conduct studies to evaluate the potential for geological
storage of CO2 utilizing existing offshore oil and natural gas fields in the Gulf of Mexico nearing the end of
productive life, and in areas that have not been subject to oil and natural gas production (other than GOM). These
offshore geologic settings, along with wells and infrastructure (where it exists), may be suitable for CO 2
sequestration with the adaptation of technical, regulatory, and business modifications. Inherent within this
objective is the consideration of:
(1) resource mapping of CO2 storage potential and infrastructure in SECARB’s offshore areas under Federal
jurisdiction in the Gulf of Mexico;
(2) resource mapping of CO2 storage potential and infrastructure in the SECARB region offshore areas under
state jurisdiction, and
(3) the current legal and regulatory structures and opportunities in applicable jurisdictions.
Research will be performed as part of a collaborative partnership between the Southern States Energy Board and
the Interstate Oil and Gas Compact Commission (IOGCC), with technical assistance from the University of Texas at
Austin, Bureau of Economic Geology (BEG) and from the Geological Survey of Alabama (GSA). The SSEB will
manage the project, under its existing SECARB Phase III agreement.
The IOGCC Carbon Capture and Geologic Storage Task Force will conduct legal and regulatory research by means of
specific subgroups created for each project. These subgroups will: 1) conduct research and analyses; and 2) draft
findings and recommendations and/or guidance documents, potentially including suggested amendments to
IOGCC’s CO2 model legislation and rules. The IOGCC will work closely with the SECARB partnership to evaluate the
legal and regulatory structures of the states involved. Research topics include an evaluation of current legal and
regulatory structures, identification of challenges stakeholders may face, and identification of legal and regulatory
opportunities.
Empirical Evaluation of Procedures to Detect Spatial Anomalies in the Devonian Antrim Shale (Michigan Basin),
and Potential Effects on Resource Assessment
Timothy C. Coburn,1 Philip A. Freeman2 and Emil D. Attanasi2
1
Department of Management Science, Abilene Christian University, ACU Box 29315, Abilene, TX 79699,
coburnt@acu.edu
2
US Geological Survey, National Center, 12201 Sunrise Valley Drive, Reston, VA 20192
During the past decade, drilling and fracturing innovations have helped to unlock vast natural gas resources in
shale. However, while the resource in unconventional shale gas plays is assumed to be ubiquitous, it is not
uniformly distributed in any geographic sense, and the locations of highly productive sites cannot be easily
differentiated from less productive ones prior to drilling. For conventional plays, it has long been recognized that
the detection of anomalies and trends can provide valuable information with which to reduce assessment
uncertainty; but this principle has not proved to be entirely applicable to unconventional plays. The difficulty lies in
the physical nature of the resource itself. Shale gas resources are continuous, but the gas is apparently unevenly
distributed in a spatial sense and may be random-like in places. This characteristic of the gas distribution, coupled
with variable drilling and completion tactics that affect recovery and producibility, renders anomalies and trends
over extended distances difficult to track, and even masks their importance. If regional trends can be discerned,
then such trends can presumably be used to aid the assessment process.
The primary objective of this study is to investigate empirical methods for establishing regional trends in
unconventional gas resources as exhibited by historical production data and to determine whether or not the
inclusion of such trends influences localized assessment results. To this end, the following two important questions
are posited: (1) Can results of past drilling (i.e., well productivity) be used to confirm trends that might be inferred
from available geological evidence, particularly with regard to naturally-occurring fractures? (2) Can information
about such trends be used to inform the estimates of recoverable gas at undrilled sites as well as the aggregate
assessments of remaining recoverable gas? These questions are addressed by using publicly available data from
the Devonian Antrim Shale gas play in the Michigan Basin. Results from bearing correlation analysis and trend
surface analysis based on cell EUR values are consistent with previous geological evaluations, and local spatial
statistics indicate the existence of clusters of cells with similar values.
Reservoir Porosity Characterization for a Carbon Sequestration Target: Citronelle Field, Alabama
Keith Coffindaffer, George Case, and Amy Weislogel
Department of Geology and Geography, West Virginia University, Morgantown, WV 26506, kcoffind@mix.wvu.edu
The Citronelle Field, located in the Mobile County area of Alabama, has been a longstanding (since 1955) oil and
gas producing basin (537MMbbl oil in place, 169MMbbl oil produced) and more recently, a carbon sequestration
target. Located overtop of a salt-cored anticline, main production in the Citronelle Field is from the Donovan Sand
of the Cretaceous Rodessa Formation. Overall, the Donovan Sand is characterized by discontinuous fine- to
medium-grained fluvial sandstone, with inclusions of pebble-sized mud rip-up clasts as well as some feldspathic
grains, interbedded with mottled to fissile mudstone. The Donovan Sand is currently being injected with
supercritical-CO2 in hopes of enhancing oil recovery as well as serving as a pilot for long-term geologic carbon
sequestration. Estimated enhancement of reserves is approximately 20%. Porosity and sedimentary lithofacies
distribution within the Donovan Sand is highly variable, ranging from ~0.5%- ~11% porosity with an average of
about 6%. Due to this heterogeneity, it becomes imperative to better understand the reservoir’s overall geology.
Core studies, thin section analyses, and a fluid saturation index test from the Donovan Sand have been completed,
allowing for higher resolution reservoir characterization. The lower porosity portions of the reservoir are areas of
concern for pore space filling and degradation of EOR and sequestration capacity due to mineral precipitation from
supersaturated supercritical-CO2. However, there is also potential for creation of secondary pore space by
dissolution of minerals within the sandstone. This would hypothetically increase carbon storage capacity within the
reservoir as well as allow greater mobility of the fluid through the rock, enhancing EOR production. The exact
dynamics of these reactions are not yet known, however we are able to postulate that there is some possible
clogging of the reservoir, as evidenced by a decrease in the rate of fluid injection.
Investigations into the Oil and Natural Gas Resource Potential of North Carolina State Waters
James L. Coleman, Jr.
U. S. Geological Survey, Reston, VA 20192
The state waters area of eastern North Carolina consists of the large, shallow brackish waters of Pamlico and
Albemarle Sounds and their smaller bays, sounds, and drowned river valleys, plus a three-mile wide coastal zone,
which is seaward of the Outer Banks and landard of the Outer Continental Shelf (OCS) management area of the U.
S. Bureau of Ocean Energy Management, Regulation and Enforcement (formerly Minerals Management Service,
MMS). These state water areas have seen sparse seismic profiling and deep drilling since 1925. Of the 116 wells
drilled in eastern North Carolina, only six wells reported some type of show of oil or natural gas. Of these six, only
one was drilled within a state water body; the remaining five wells were drilled onshore, but near the marshlines
of Pamlico and Albemarle Sounds.
The geology of the state waters area is dominated by an unknown thickness of Precambrian and Paleozoic high
grade metamorphic and igneous rocks overlain by an eastward dipping wedge of Mesozoic and Cenozoic
sedimentary rocks. Based on well data, regional gravity and aeromagnetic maps, and limited seismic profiles, the
swarm of Triassic – Jurassic rift basins that extend from Georgia to offshore Maine (and their accompanying
petroleum system) appear to bypass the Pamlico – Albemarle Sound area. This condition raises questions as to the
potential source rock interval for the hydrocarbon shows reported in the six wells. The data reported in these six
wells will be reviewed, and sources for the reported hydrocarbon shows will be speculated.
Examination of the shale gas potential of Devonian shales in the Broadtop Synclinorium, Appalachian Basin
(Virginia, West Virginia, Maryland, and southern Pennsylvania)
J. L. Coleman, Jr.1, C. B. Enomoto1, P. W. Niemeyer1, 2, F. T. Dulong1, C. S. Swezey1, and G. W. Van Swearingen3
1
U. S. Geological Survey, 12201 Sunrise Valley Drive, MS 956, Reston, VA 20192
2
University of Mississippi, Department of Geology and Geological Engineering, University, MS 38677
3
HighMount Exploration and Production, LLC, 16945 Northchase Drive, Suite 1750, Houston, TX 77060.
Within the central Appalachian fold and thrust belt, organically-rich shales of Middle Devonian age crop out within
and extend into the subsurface of the Broadtop Synclinorium. Within the synclinorium, the organically rich
Devonian shale formations are primarily the Marcellus and Needmore Shales; other shales included in the study
are the Mahantango Formation and possibly the Harrell Shale and Mandata Formation. Where the Mahantango
cannot be differentiated from the Marcellus, the interval is termed the Millboro Shale. The presence of gas
reservoirs within the underlying Lower Devonian Oriskany Sandstone, plus isolated gas production from Devonian
shales within the Broadtop Synclinorium, suggest that the Devonian shales may have economic gas shale
development potential.
Outcrops within the 16-county study area that occupies the Broadtop Synclinorium in northern West Virginia,
northwestern Virginia, western Maryland and the southern tier of counties in Pennsylvania were examined,
described, sampled, and analyzed for total organic carbon (TOC) content, thermal stress levels (vitrinite
reflectance, VR), and mineralogical content. One hundred and nine samples were analyzed for TOC and VR; 106 of
these samples were examined for mineralogical content using x-ray diffraction. Of the 109 samples examined for
TOC and VR, the Marcellus shale samples have a TOC range of 0.17% to 7.22% (n=92) and a VR range of 0.74% to
3.43% (n=95). With few exceptions, the range of TOC and VR of all other sampled shales fall within these intervals.
In the Marcellus Shale samples, the quartz content ranges from 24% to 77%, the carbonate content ranges from
0% to 43%, and the clay content (illite + kaolinite + chlorite) ranges from 16% to 60%.
Reconnaissance field mapping and outcrop sampling for geochemical analysis indicate that the Devonian shales in
Broadtop Synclinorium from central Virginia to southern Pennsylvania have an organic content sufficiently high
and a thermal maturity sufficiently moderate to be considered for a shale gas play. The organically rich Middle
Devonian Marcellus Shale is present throughout most of the synclinorium, being absent only where anticlinal
structures bring older rocks to the surface, causing the Marcellus to be eroded from the crests of these structures.
Geochemical analyses of outcrop and four well samples indicate that most if not all of the hydrocarbons have been
generated and expelled from the kerogen originally in place in the shale. Although the Middle Devonian shale
interval is moderately to heavily fractured in all part of the Synclinorium, in some areas substantial fault shearing
has destroyed a regular “cleat” system of fractures. Results of this study indicate that the Marcellus Shale within
the Broadtop Synclinorium is generally similar in organic geochemical nature throughout its extent, and there are
no clearly identifiable high potential areas (or “sweetspots”) based on one or more characteristics observed in the
field.
USGS Re-assessment of the Undiscovered, Technically-recoverable Oil and Gas Resources of the Marcellus Shale,
Appalachian Basin, USA
J. L. Coleman, Jr.1, R. C. Milici1, T. A. Cook2, R. R. Charpentier2, M. A. Kirschbaum2, T. R. Klett2, R. M. Pollastro2, and
C. J. Schenk2
1
U. S. Geological Survey, Reston VA
2
U. S. Geological Survey, Denver CO
The US Geological Survey has recently completed a re-assessment of the undiscovered, technically-recoverable oil
and gas resources of the Middle Devonian Marcellus Shale in the Appalachian Basin of the eastern United States.
This work re-examined the 2002 assessment, and using the USGS geology-based assessment methodology for
continuous petroleum resources, developed a revised estimate for this emerging new trend. The assessment was
based on geologic elements of the Marcellus Shale within the Devonian Shale-Middle and Upper Paleozoic Total
Petroleum System, recent production histories within the trend, and potential for the Marcellus Shale to respond
effectively to multi-stage hydraulic fracture stimulation completions in horizontal wells.
The Marcellus Shale was divided into three assessment units (AUs) within its extent in the Appalachian Basin: (1)
Western Margin, in the western extents of the Marcellus where it is less than 50 feet thick and west of the
Appalachian Structural Front (ASF), (2) Interior Marcellus, in the eastern extents of the trend, where it is greater
than 50 feet thick and west of the ASF, and (3) Fold Belt Marcellus, where it is present east of the ASF. These three
AUs extend from southern New York to southwestern Virginia and northeastern Tennessee and from central Ohio
to western Virginia and Maryland. The geology and resource assessments of these three AUs will be reviewed and
discussed.
Shark Bay Carbonates after the Pioneers: some Current Research
Lindsay B. Collins, and Ricardo Jahnert
Department of Applied Geology, Curtin University, Kent Street, Bentley, WA, 6102, Australia. L.,
Collins@curtin.edu.au
Since the initial sedimentological studies of Shark Bay in the 1960s to 70s (by Logan et al, Read, Hagan, Hoffman,
Davies and others) on hypersaline stromatolites and microbial tidal flats, seagrass banks, calcrete, and hypersaline
basin evolution the area was established as a World Heritage precinct with high conservation status and remains
an important asset for all with an interest in carbonate sediments and diagenesis. Ongoing research has included
studies by astrobiologists, ecologists and geologists (eg. Walter, Burns,., Goh, Allen, & Neilan , McNamara).
Sedimentological research has centred on a number of separate studies, notably by Playford, 1976, 1979, 1990;
Burne, & Moore, 1987; Kennard & James, 1986; Awrick & Riding, 1988; Reid et al, 2003 and several others.
The recognition of the reservoir significance of coquinas and microbialites in recently discovered fields (eg.Santos
and Campos Basins, Brazil) has renewed interest in the analogue potential of similar facies in Shark Bay, with the
development of current and new research themes including:
 Microbial mat facies and fabrics, chemistry, organic composition and microbial communities,
 Subtidal microbial structures: origin, occurrence, distribution and growth history,
 Coquina ridge morphology, facies, structures, chronologic record and evolution.
The subtidal study has allowed a re-evaluation of the Shark Bay stromatolite model. Based on the improved
knowledge of the nature and distribution of Shark Bay microbial deposits a revised facies model has been
constructed and is characterized by relatively extensive and prolific activity of bacteria, during the last 2000 years,
producing microbialites that are exposed in the supratidal zone and are progressively colonizing the subtidal zone
as a consequence of sea level fall, although evidence of recolonization observed on the intertidal zone points to a
recent short marine transgression.
With the discovery of widespread subtidal microbialites the Shark Bay intertidal stromatolite model was reevaluated after initial reporting of mainly intertidal forms. Establishing the widespread nature and distribution of
subtidal microbialites enhances Shark Bay’s applicability as an analogue for ancient systems.
A forty year climate drying in southwest Australia and interaction with the cyclone (hurricane) regime which
impacts the semi-arid Shark Bay region has raised questions for marine park managers concerning potential future
climate trends and their impact on World Heritage assets. Maintenance of the hypersaline system in areas such as
Hamelin Pool is dependent upon evaporation (currently 10x precipitation), runoff input (dependent on low winter
rains but also cyclone intensity and frequency) and tidal exchange across the northern Faure barrier channel-bank
complex, such that hydrodynamic circulation is also dependent on future sea levels, and a research team is
evaluating potential future change from a management viewpoint. Additionally, an arid delta juxtaposed with the
channel-bank complex provides a facies association of potential analogue significance for regional hydrocarbon
explorers.
Predicting Total Dissolved Solid Concentrations in Appalachian Basin Formation Waters from Spontaneous
Potential Logs
Colin Doolan
U.S. Geological Survey, 12201 Sunrise Valley Dr., MS 956, Reston, VA 20192, cdoolan@usgs.gov
A preliminary methodology is presented for predicting total dissolved solid (TDS) concentrations in formation
waters within the Appalachian basin using spontaneous potential (SP) log responses. The methodology draws
from previous studies that have determined the areal distribution of formation water salinity values in the offshore
U.S. Gulf of Mexico and the onshore North Slope of Alaska. A series of wells within the Appalachian basin were
selected for the study based on the availability of relevant header information, such as bottom-hole temperatures
and mud filtrate information, and quality of the SP traces. The wells used in this study form a northwest to
southeast transect across the strike of the Appalachian basin through parts of Ohio, West Virginia and
Pennsylvania. TDS concentrations based on SP logs from the wells are expected to show the lateral variation of
formation water salinities for specific formations from the basin margin to the basin center.
TDS concentrations are first calculated for wells that have associated produced water samples from the target
formations. The measured TDS values from the produced water samples are used for quality control of the values
calculated from SP response. Once quality assurance of the methods is established, calculations of TDS values are
made using logs from areas where there are no corresponding water chemistry data. For this technique, the
calculations are dependent on accurate borehole temperature measurements and the availability of mud filtrate
resistivity values for individual wells.
Ultimately, TDS concentrations will be calculated for wells forming a grid across the entire basin. Contour maps
based on the well grid will show the spatial and vertical extent of formation water TDS concentrations for specific
formations within the basin. These studies will aid in predicting the salinity of produced waters in the Appalachian
basin and will serve as a base for identifying and mapping paleoflow regimes.
The Role of Matrix and Fractures on Appalachian Basin Upper Devonian Gas Production
Ashley S.B. Douds
EQT Production, 625 Liberty Ave, Pittsburgh, PA 15222, adouds@eqt.com
Long-standing debates have surrounded the relative contribution of natural fractures and matrix to the prolific
production of very low permeability, low pressure reservoirs such as the Upper Devonian Shales of the
Appalachian Basin. The Upper Devonian Shales are composed of several black shale intervals that have been
exploited for hydrocarbons for over 100 years, including the Dunkirk and Rhinestreet shales. Gas storage efficiency
and movement of gas through these shales needs to be viewed in three different time frames and conditions:
geologic via hydrocarbon migration, formation connectivity via natural wellbore production, long-term production
via artificial fractures connecting a larger area.
The notion that gas-filled fractures abound in the subsurface at a lateral spacing often missed during coring and
logging operations is not supported by the characteristics of most shale gas producing wells. Shale wells typically
do not produce without stimulation unless a set of tectonically-related faults and fractures are intersected along
the wellbore. Observations from four wells drilled in southern West Virginia where data was collected on four
different lithologies highlight the importance of matrix versus fracture abundance in creating economically-viable
reservoirs. The following reservoirs were analyzed for matrix versus fracture contribution during geologic time,
natural wellbore production time, and long-term production post stimulation: porous and permeable (millidarcy
scale) sandstone, porous and impermeable (nanodarcy scale) siltstone, organic rich shale, and organic lean shale.
Well Site Techniques for the Study of Unconventional Reservoirs
Jerad Dudley and Ken Bohnert
Geosearch Logging, Inc., 23541 Rt. 220, Ulster, PA 18850, jdudley@geosearchlogging.com
This is an ongoing study in which we examine different analytical techniques that can be used on the
unconventional Marcellus Shale reservoir. We will be looking at the blender gas technique and how it can be
improved to provide better data on gas contained within the cuttings. We will also look at the calcimetry tests and
how they can be used to help identify zones of natural fractures. From these techniques, the surface logger on
location can gain a better understanding of the Marcellus Shale. A better understanding can help the client
geologist more accurately identify areas to induce the artificial hydraulic fracturing.
Shifts in Depocenter Locations during the Mississippian in the Michigan Basin (USA, Canada)
J.A. East and C.S. Swezey
U.S. Geological Survey, 12201 Sunrise Valley Drive, Reston, VA 20192, jeast@usgs.gov
Very few comprehensive studies have been published on the structural geology of the Michigan Basin, which spans
the USA-Canada border. One study by C.E. Prouty (1988) postulated that during the Mississippian Subperiod the
primary depocenter of the Michigan Basin shifted approximately 30 miles west-southwest from the vicinity of
Saginaw Bay towards the geographic center of the basin. This postulated shift in depocenter is coincident with an
unconformity between the Osagian Marshall Sandstone and the overlying Meramecian Michigan Formation. Using
modern international stratigraphic terminology, this unconformity is within the Middle Mississippian Visean Stage.
Detailed GIS analysis of isopach maps suggests that the Kinderhookian Sunbury Shale is less than 30 ft thick
throughout most of the basin, although thicknesses greater than 140 ft are present on the eastern side. The
Sunbury Shale depocenter (point of greatest isopach thickness) is located in eastern Michigan at 43.38659 degrees
latitude and -82.59214 degrees longitude. The Sunbury Shale is overlain by the Kinderhookian Coldwater Shale,
which attains a maximum thickness of 1,300 ft. The Coldwater Shale depocenter is located at 43.30404 degrees
latitude and -84.88010 degrees longitude. The Coldwater Shale is overlain by the Osagian Marshall Sandstone,
which attains a maximum thickness of 350 ft. The Marshall Sandstone depocenter is located at 43.46626 degrees
latitude and -84.33664 degrees longitude. The Marshall Sandstone is capped by an unconformity, above which
lies the Meramecian Michigan Formation. The lower part of the Michigan Formation is a sandstone that is
informally named the Michigan Stray sandstone, which ranges in thickness from 250 to 600 ft in the central part of
the basin. The depocenter of the Michigan Stray sandstone is located in central Michigan at 43.99952 degrees
latitude and -85.01863 degrees longitude. In summary, the Coldwater Shale depocenter is located approximately
110 miles west of the Sunbury Shale depocenter. The Marshall Sandstone depocenter is located approximately 30
miles east-northeast of the Coldwater Shale depocenter. The Michigan Stray sandstone depocenter is located
approximately 110 miles northwest of the Marshall Sandstone depocenter. This westward shift from the Marshall
Sandstone depocenter to the overlying Michigan Stray sandstone depocenter occurred just after or during the
latter part of the Acadian Orogeny. Possible explanations for this depocenter shift include sediment loading and
(or) tectonic processes associated with the Acadian Orogeny. However, the isopach maps do not reveal a
unidirectional major shift in depocenter location from the Sunbury Shale to the Michigan Formation, suggesting
that the unconformity beneath the Michigan Formation and the shift in depocenter location is more likely a result
of sediment loading rather than tectonic processes.
Forensic Petroleum System Analysis of Drilling Results and Hydrocarbon Potential of Georges Bank Basin
Erin T. Elliott and Paul J. Post
U.S. Dept. of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico
Region, New Orleans, LA 70123, Erin.Elliott@boemre.gov
The Georges Bank basin (GBB), offshore Massachusetts, USA, experienced a brief period of exploratory drilling
during 1981 and 1982. During this time, eight new field wildcat (NFW) wells were drilled to evaluate the
hydrocarbon potential of interpreted prospective structural, structural-stratigraphic stratigraphic traps, and reefs.
Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) staff utilized recently reprocessed
seismic data, which more clearly images and provides a better interpretation of the prospects drilled, industry
NFW well data and modern exploration concepts in their forensic petroleum system analysis of this single phase of
GBB exploration.
Final well results showed pre-drill interpretations to be inaccurate. Although interpreted structures, structuralstratigraphic, and stratigraphic traps were still mappable, lack of hydrocarbon charge and reservoirs resulted in dry
holes for all 8 exploration wells. Interpreted reefs were either “tite” micritic limestone, dolomite overlying salt and
anhydrite, or volcanics. Results from this project will be available as a well folio providing pre- and post-drilling
analysis of each well.
Examination of Inferred Third-Order Structural Features of the Marcellus Shale Using Wireline Logs in the
Broadtop Synclinorium, Virginia and West Virginia
Catherine B. Enomoto, Ricardo A. Olea, and James L. Coleman, Jr.
1
U. S. Geological Survey, 12201 Sunrise Valley Drive, MS 956, Reston, VA 20192, cenomoto@usgs.gov
The Middle Devonian Marcellus Shale extends from central Ohio in the west to eastern Pennsylvania in the east,
and central New York in the north to southwest Virginia in the south. Its thickness varies from zero along its
western pinchout to perhaps as much as 900 feet (275 m) thick in its eastern extents. The thickness of the
Marcellus Shale varies from 350 to 570 feet (100 to 175 m) thick within the Broadtop Synclinorium in Virginia and
West Virginia. Thickness variations in the eastern portion of the Appalachian Basin appear to be caused by thirdorder features, specifically apparent thickening related to folds and thrust faults within the formation. Published
studies in the Valley and Ridge Province illustrated a direct relationship of third-order faults, folds, and “disturbed
zones” to the regional tectonic framework. During recent field work within the Valley and Ridge Province, we
observed intraformational deformation in the Marcellus Shale. In an attempt to determine if this outcrop-scale
deformation is discernible in the subsurface, we examined conventional gamma-ray and density logs from nine
wells in a 30-mile by 30-mile (50-km by 50-km) area in eastern West Virginia and western Virginia.
We used the Correlator 5.2 computer program designed to correlate geophysical well logs in extensional regimes
such as the U.S. Gulf Coast. This represents the initial use of the Correlator program in a contractional tectonic
regime. We used this program to statistically evaluate the continuity of the Marcellus Shale and, in turn, to
interpret discontinuities in the subsurface that may be the roots of the “disturbed zones” evident in outcrop.
Using formation top depths submitted by well operators as a starting point, we used visual pattern recognition to
correlate digital logs from nine wells. The tops of the Marcellus Shale, the Needmore Shale, and the Oriskany
Sandstone were entered into the Correlator 5.2 program to initiate this study. Using an iterative process of
measuring the similarity in shale content between two wells within user-defined correlation and search windows,
then measuring the similarity in bulk density between the same two wells, the program calculates a weighted
correlation within the search window. We subdivided the Marcellus Shale into three intervals based on correlation
strength and gamma-ray log character. We calculated average gamma-ray and average bulk density values for
each of these intervals.
Our analysis of all of these calculations suggests that some zones within the Marcellus Shale are more prone to
disharmonic folding and small-scale thrust faulting than others. Recent presentations by natural gas producers
have suggested that faults and fractures in the Marcellus Shale have a negative impact on completion operations
in horizontal wells. The ability to delineate these features in the subsurface will aid in designing completion
techniques and enhancing natural gas production from the Marcellus Shale.
Evaluating the Effects of Lithofacies and Thin Shales on the Lateral Distribution of Hydrothermal
Dolomite Reservoirs, Albion-Scipio and Stoney Point Rields, Michigan Basin
Peter J. Feutz and G. Michael Grammer
Western Michigan University
Albion-Scipio and Stoney Point Fields are hydrothermal dolomite hydrocarbon reservoirs in the southern Michigan
Basin. Both Albion-Scipio Field (approximately 1 mile wide, 35 miles long) and Stoney Point Field (approximately
.75 mile wide, 7 miles long) encompass narrow zones of faulting and fracturing which have been altered from a
tight host limestone into a more porous and permeable dolomite by upward-moving hydrothermal fluids. Previous
authors have noted that development of reservoir rock laterally away from the faults may be the result of the
preferential migration of hydrothermal fluids through certain primary depositional facies. Additionally, thin beds of
shales (millimeter to centimeter thick) within these Ordovician-aged Trenton and Black River reservoirs may have
acted as baffles or barriers to the vertical flow of the hydrothermal fluids, thus dolomitizing the limestone beneath
the shales and again creating more predictable porous and permeable zones for hydrocarbon storage. Detailed
core analysis and petrographic research in the Albion-Scipio-Stoney Point region is utilized to test the hypothesis
that primary depositional facies and thin shales may have influenced fluid flow in these reservoirs.
The goal of this project is to observe the lateral spread of the hydrothermal dolomite away from the vertical to
sub-vertical faults and note any relationship with the primary depositional facies and thin shales, and help predict
how far laterally the reservoir producing dolomitization is spread. This will ultimately lead drillers to more
accurately pinpoint producing zones of hydrocarbons and avoid the close, step-out dry holes that are commonly
encountered along the perimeter of these elongate trends.
Preparing for and Handling Common Complaints by Private Water Well Owners Related to Coal Bed Methane,
Shale Gas and Other Unconventional Development Programs
John V. Fontana and David M. Seneshen
Vista Geoscience, 130 Capital Drive, Suite C, Golden, Colorado, USA, JFontana@VistaGeoScience.com
A major public concern with unconventional oil and gas development occurring today is the potential impact to
ground water or private well owners. When development occurs in a populated rural area, it’s not long before the
operators and regulators are hit with complaints from private water well owners suspecting that their water well is
impacted from nearby development activities. The current public fear about hydrofracturing practices is
unwarranted and should be easily defended.
While a few complaints can be linked to real issues such as poor cement jobs, leaky pits and other conventional
releases and accidents, the vast majority turn out to be due to poor quality water well design, construction and
lack of maintenance that can mimic issues cause by oil and gas releases. While the actual releases and spills must
be acknowledged along with their true impacts to ground water, public education is required to demonstrate that
these are rare and many of the issues with private water wells are related to naturally occurring conditions, poor
construction and maintenance practices, or other historical activities such as mining exploration, early oil and gas
exploration, agricultural impacts or other industrial impacts. Water wells can also become non-productive and the
quality of water degraded due to regional draw-down from over use of the aquifer, drought, well system fouling,
or just the limited life span of water wells. Methane in a water well occurs naturally from bacteria present in or
introduced into the well, natural gas seeps, or the result of adsorbed methane in the coals or shales present in
some aquifers. Even though methane occurs naturally in many ground water aquifers, it is not toxic and therefore
not routinely checked for as part of water quality tests in private wells, until gas development occurs in the area
when it then becomes “discovered” as a problem. Done prior to development, a proactive baseline testing
program can head off these problems with stakeholders. If not done prior to development, forensic geochemical
methods can typically distinguish the source as natural or anthropogenic, but this is more costly than having the
baseline data as proof of pre-existing conditions.
Some states are have or are currently proposing new regulations to conduct baseline studies before drilling occurs
and routinely after. Baseline testing procedures and results are presented that help protect operators from
complaints and potential law suits. Industry and others will need to sponsor significant public education efforts to
alleviate unfounded fears about hydrofracturing, drilling and affordable energy. The authors recently assisted in
creating an educational brochure, website and presentation for Raton Basin water well owners to educate the well
owners on the most common water well problems, including naturally occurring methane, how to distinguish
these issues from gas development releases or other forms of natural or anthropogenic contamination, and how to
resolve the issues with routine testing and maintenance. The baseline methods presented assist developers in
locating pre-existing conditions and potential problem areas and allow them to quickly dismiss unfounded
complaints.
Natural Fracture Characterization in Shale-Gas Reservoirs: Spatial Organization and Fracture Sealing
Julia F.W. Gale, L. Pommer, X. Ouyang and S. E. Laubach
Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin, J.J. Pickle Research
Campus, Building 130, 10100 Burnet Road, Austin, TX 78758-4445, julia.gale@beg.utexas.edu
Natural fracture systems are important for production in shale-gas reservoirs in two ways. They may reactivate
during hydraulic fracture treatments or they may be partly open, contributing to permeability without reactivation.
Degree of openness and fracture plane strength are related in part to the specific structural-diagenetic history of
each fracture set and shale host rock. Several possible mechanisms control fracture formation. A key variable is the
depth of burial, and thereby the temperature, pore-fluid pressure and effective stress at the time of fracture
development. Examples exist across the spectrum; from veins developing before host-rock compaction is
complete, to veins forming at maximum burial due to hydrocarbon generation or other mineral reactions, to late,
shallow veins of gypsum formed due to pyrite oxidation in the weathering zone. We present examples that
illustrate these mechanisms from several US shales, including the Devonian New Albany Shale in the Illinois Basin,
the Mississippian Barnett Shale from the Delaware Basin, west Texas, and the Marcellus Shale from SW
Pennsylvania.
The techniques we employ for fracture characterization can be utilized in any shale-gas reservoir but require
specific data sets. We focus here on two aspects: fracture spatial organization and fracture sealing cements. We
use a modified two-point correlation integral method to analyze horizontal image log data, which allows us to
quantify spatial organization, and to assess the degree of fracture clustering. We compare the results of this
analysis with geomechanical models of growing fracture patterns, informed by knowledge of fracture population
size-scaling relationships. Our goal is to develop a methodology for fracture spacing prediction. Fracture sealing
cements follow similar patterns to those in fractures in tight gas sandstones and dolostones. The synkinematic
cement phase is commonly characterized by crack seal texture and mineral bridges. Scanning Electron Microscopebased cathodoluminescence, coupled with fluid inclusion analysis has allowed constraints to be placed on the
timing and during of fracture formation. Hydrocarbon inclusions are commonly observed in the fracture sealing
cements and provide insights into processes associate with cracking of kerogen to oil and oil to gas.
NEMS-CTS: A Model and Framework for Comprehensive Assessment of CCS and Infrastructure
Rodney Geisbrecht, Charles Zelek, Tim Grant
U.S Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road,
P.O. Box 10940, Pittsburgh, PA. 15236-0940
The National Energy Technology Laboratory is funding a NEMS-CTS (CO2 Transportation and Storage) model that
will provide for modeling of CO2 pipelines and pipeline networks across the lower 48 states. An integrated NEMS
based analysis used by the National Energy Technology to assess CCS retrofitting of existing coal fired power plants
was updated to factor in plant specific variations in the costs of capture and regional variations in the costs of
transmission and sequestration. Pipeline networks in the updated model are configured endogenously to be
optimally consistent with the latest capacity and cost data for the U.S. sequestration resource base. The model will
provide for analysis of various source, sink and pipeline combinations as well as different economic and policy
scenarios. This paper will present a recent application of the model to assess the role of CCS in a Clean Energy
Standard scenario. Documentation will also be presented for key parts of the model, including: (1) capture costs the original generic model based on the Conesville Study and corrections based on heat rate and emission control
configuration now include corrections for other site specific details such as capacity and location; (2) sequestration
capacity and costs - NATCARB and other data bases are used for capacity and formation properties which are
combined with drilling, monitoring, and other cost estimates in various cost models; (3) transmission costs pipeline cost data and GIS data on siting constraints are combined in various cost models in a GAMS based
optimizer that configures an evolving pipeline network ; (4) NEMS integration - the GAMS GDX utility is used to
interface NEMS and the GAMS based optimizer (CTS Module) such that the evolving pipeline network and its
associated cost adders for transmission and sequestration are consistent with the penetration of CCS in NEMS.
New ASTM Standard Test Method for Determination of the Reflectance of Vitrinite Dispersed in Sedimentary
Rocks
Paul C. Hackley1, Carla V. Araujo2, Ángeles G. Borrego3, Brian J. Cardott4, Alan C. Cook5, Mária Hámor-Vidó6, Kees
Kommeren7, João G. Mendonça Filho8, Jane Newman9, Mark Pawlewicz10, Judith Potter11, Isabel Suárez-Ruiz3
1
U.S. Geological Survey, MS 956 National Center, Reston VA 20192, USA, phackley@usgs.gov
2
Petrobras Research and Development Center, Rua Horácio Macedo No. 950, Cidade Universitária, Ilha do Fundão
21941-915 Rio de Janeiro, Brazil
3
Instituto Nacional del Carbón, CSIC Apartado 73, 33080 Oviedo, Spain
4
Oklahoma Geological Survey, University of Oklahoma Energy Center, 100 East Boyd Rm N-131, Norman OK 73019,
USA
5
Keiraville Konsultants Pty. Ltd., 7 Dallas Street, Keiraville, NSW 2500, Australia
6
Eötvös Loránd Geophysical Institute of Hungary, Kolumbusz St. 17-23, 1145 Budapest, Hungary
7
Shell International Exploration and Production BV, Research and Technical Services, Volmerlaan 8 PO Box 60, 2280
AB Rijswijk, The Netherlands
8
Palynofacies and Organic Facies Laboratory, Universidade Federal do Rio de Janeiro, Av. Athos da Silveira 274,
Cidade Universitária, 21941-916, Rio de Janeiro, Brazil
9
Newman Energy Research Ltd., 2 Rose Street, Christchurch 8002, New Zealand
10
U.S. Geological Survey, Box 25046 Denver Federal Center, MS 977, Denver CO 80225, USA
11
J.P. Petrographics, 90 Patterson Close SW, Calgary, Alberta T3H 3K2, Canada
Vitrinite is the dominant organic constituent of coal and its mean reflectance can be reproducibly determined by
different operators in different laboratories with different test equipment. Standard test methods to determine
vitrinite reflectance of coal have been long published by the American Society for Testing and Materials (ASTM)
and the International Organization for Standardization, among others, and these tests for coal have served as
guides for measurement of reflectance of vitrinite dispersed in sedimentary rocks. However, numerous published
examples indicate high inter-laboratory variability for dispersed vitrinite reflectance analysis which can be
attributed to lack of a common method.
To address this shortcoming, a new ASTM standard test method to determine the reflectance of vitrinite dispersed
in sedimentary rocks was developed by an international committee of technical experts from government
agencies, academia, industry, and consultancies. This partnership between members of ASTM, the International
Committee for Coal and Organic Petrology (ICCP), The Society for Organic Petrology, and the American Association
of Petroleum Geologists was formed to address the need for standardization in vitrinite reflectance analysis of
rocks other than coal, in particular, shale. With current oil and gas industry interest focused on unconventional
shale gas plays, it is critically important that the most commonly used thermal maturity indicator, i.e., vitrinite
reflectance, have a codified procedure for measurement.
The first step in development of the new test method was a survey of common practices used in laboratories that
routinely measure the reflectance of dispersed vitrinite. The writing committee was identified from within the
survey respondents, and the ASTM coal vitrinite reflectance standard (D2798) was used as the outline to frame the
new standard. Significant deviations from the coal standard included: 1) specialized terminology to include
recycled vitrinite, zooclasts, solid bitumens, and marine algae; 2) discussion of potential for vitrinite suppression
and retardation in certain conditions; 3) inclusion of fluorescence observation and resulting changes to equipment
description and procedure; and 4) addition of reporting requirements including type and quality of sample
preparation, observation of fluorescence, and consideration of supporting data and information.
The new standard was successfully balloted at the ASTM D05.28 coal and coke petrography subcommittee level in
November, 2010, and at the ASTM D05 coal and coke main committee level in March, 2011. It will appear in print
form later this year in the 2011 Annual Book of ASTM Standards, v. 05.06, Gaseous Fuels; Coal and Coke.
Anticipated users include government, academic, and service laboratories, and adoption as the prescribed method
for the dispersed vitrinite reflectance accreditation program of the ICCP, which currently includes approximately
forty laboratories worldwide. The test method will be most useful for those working in shale gas plays where
vitrinite reflectance is considered the most robust thermal maturity parameter. Anticipated future improvements
to the standard include the creation of quantified reproducibility and repeatability values through laboratory
round-robin exercises, and the development of a supplemental online image atlas of dispersed organic matter in
sedimentary rocks to aid in the identification of primary vitrinite.
Petrology of Stromatoporoid-Coral Framestones and Rudstones in the Upper Keyser Formation (Silurian) of the
Water Sinks Area, Highland County, Virginia
John T. Haynes1, Selina Cole1, Richard A. Lambert2, Philip C. Lucas3, Stephen A. Leslie1, Steven J. Whitmeyer1, and
Timothy Rose4
1
Dept. of Geology & Environmental Science, James Madison University, Memorial Hall MSC 6903, Harrisonburg, VA
22807, haynesjx@jmu.edu
2
Virginia Speleological Survey, P.O. Box 151, Monterey, VA 24456
3
Virginia Speleological Survey, 587 Limestone Lane, Burnsville, VA 24487
Smithsonian Institution, Department of Mineral Sciences, PO Box 37012, MRC 119, Washington, DC 20013-7012
4
The Keyser Formation in the central Appalachians spans the Silurian – Devonian boundary, and in Highland County
there are two prominent biostromal framestone and rudstone horizons in the upper 35 m comprised principally of
stromatoporoids and corals. The upper of the two is best known from a biohermal exposure near the community
of Mustoe, about 9 km to the west-northwest of our study area, but the lower horizon in this area has received
less attention. Excellent surface and subsurface exposures of these two horizons in the Keyser have turned out to
be an important part of the stratigraphic column in the Water Sinks, a complex karst feature in the Williamsville 7½
minute quadrangle in southern Highland County, which we have recently remapped in detail. The lower biostromal
horizon is exposed in the stream-washed walls of several passages of the Water Sinks Subway Cave (discovered in
November 2007) and in Aqua Cave. It is 2-3 m thick, with a stromatoporoid framestone at the base, which overlies
a cross-bedded quartzose crinoidal grainstone that itself overlies the upper beds of the Clifton Forge Sandstone.
Most of the stromatoporoids above the basal framestone appear to have been rotated or tumbled, and the few
corals in this rudstone horizon also appear to have been transported. This horizon has been extensively but
selectively dolomitized in these exposures as well, including numerous baroque dolomite crystals throughout.
The upper biostromal horizon is separated from the lower biostromal horizon by 15 m of massively bedded to
cross-bedded crinoidal grainstones, pink in places, and about 3 m of shaley and in places cherty lime mudstones at
the base. This upper biostromal horizon is exposed in the passages of two additional caves, Owl Cave and the Old
Water Sinks Cave. At about 4 m thick, it is thicker than the lower horizon, and it is a framestone throughout more
of its area of occurrence as well, with the stromatoporoids and corals being in growth position in several
exposures. Diversity in the upper horizon is higher than in the lower horizon, with corals, both rugose and tabulate,
being quite common, and some bryozoans present as well. This horizon has been less dolomitized, but there has
been more replacement by chert and chalcedony.
Stratigraphy and Petrology Of Sandstones in the Mckenzie, Williamsport, Tonoloway, and Keyser Formations
(Silurian) of the Valley and Ridge Province in Highland County, Virginia
John T. Haynes1, Aryn Hoge1, Richard A. Lambert2, Philip C. Lucas3, Steven J. Whitmeyer1, and Timothy Rose4
1
Dept. of Geology & Environmental Science, James Madison University, Memorial Hall MSC 6903, Harrisonburg, VA
22807, haynesjx@jmu.edu
2
Virginia Speleological Survey, P.O. Box 151, Monterey, VA 24456
3
Virginia Speleological Survey, 587 Limestone Lane, Burnsville, VA 24487
4
Smithsonian Institution, Department of Mineral Sciences, PO Box 37012, MRC 119, Washington, DC 20013-7012
The Silurian sequence of Highland County includes several quartz arenites that are less than 1 m to over 20 m
thick. The stratigraphy of some (Tuscarora, Keefer, Williamsport), is well known, but others, especially several
unnamed sandstones in the McKenzie and Tonoloway Formations, are only now being mapped, and their
stratigraphic relations worked out. Our mapping in the Williamsville 7½ min. quadrangle has clarified relationships
among these sandstones. The Clifton Forge Sandstone Member of the Keyser Formation is exposed in the Water
Sinks, and it is a cross-bedded calcarenaceous quartz arenite to quartzose crinoidal grainstone up to 12 m thick. It
directly and unconformably overlies the Tonoloway. The Clifton Forge and the Tonoloway are separated in one
section by a flat-pebble conglomerate up to 135 cm thick, which thins to less than 2 cm over ~ 20 meters.
The Tonoloway Formation in this region is more heterogeneous than reported, with up to 7 sandstones present.
The most prominent and continuous of these is a calcarenaceous quartz arenite that separates the lower and
middle members. It is up to 1.5 m thick along Chestnut Ridge south to Burnsville. This sandstone and another one
25 m downsection were identified locally for decades as the “lower and upper tongues of the Clifton Forge
Sandstone,” but our mapping shows them to be as-yet unnamed sandstones in the lower member of the
Tonoloway. The upper sandstone has whole and fragmental echinoderms, bryozoans, and brachiopods among
mostly monocrystalline quartz cemented by abundant quartz overgrowths, which hold the rock together even
where calcareous grains and cements have been removed. The lower sandstone is a calcareous quartz wacke to
quartz arenite. Other sandstones in the Tonoloway are less extensive, finer-grained, and dolomitic.
Three newly measured and described sections (in the Bullpasture River Gorge, at Lower Gap, and at Trimble) of
Silurian strata show more detailed facies relations of the Tonoloway, Williamsport, McKenzie, and Keefer
Formations. These 3 sections are in stratigraphically strategic positions, being between two sections (Muddy Run
and Fork of Waters) that have previously been measured and described. Our findings help constrain the
stratigraphy and areal extent of the unnamed quartz arenite in the McKenzie Formation, as well as document the
lateral continuity of the Williamsport Sandstone, and identify what is true Keefer Sandstone (with its hematitic and
oolitic “Clinton” ironstone layers) vs. the amalgamated “Keefer” Sandstone of some previous workers (which
included the McKenzie and Williamsport horizons). The unnamed McKenzie sandstone persists almost 40 km
farther north than previously known and it makes prominent ledges in the Bullpasture River. The Williamsport, a
mappable unit in this area, underlies the Tonoloway at sections where the Wills Creek Formation is very thin or
absent. In some earlier reports the Keefer was mapped as being overlain by Tonoloway, but the true Keefer is
overlain by McKenzie, thus the Keefer of those reports is more accurately characterized as the “Keefer” or even
“Eagle Rock” Sandstone. The Keefer oolitic beds are ferroan dolomites with berthierine and hematite ooids, and
they extend from the Fork of Waters section south at least to the Bullpasture River.
Sequence and Carbon Isotope Stratigraphy from the Aptian carbonate platform interior, southern Croatia
A. Husinec1, S.P. Regan2, C.A. Harman3, D.A. Mosher4 & J.F. Read 5
1
Department of Geology, St. Lawrence University, Canton, New York 13617, USA (ahusinec@stlawu.edu)
2
Department of Geosciences, University of Massachusetts, Amherst, MA 01003, USA (srega0@cns.umass.edu)
3
Department of Geological Sciences, University of Texas, Austin, TX 78713, USA (caharm05@mail.utexas.edu)
4
Department of Earth and Environmental Sciences, Rensselaer Polytechnic Institute, Troy, NY 12180, USA
(moshed4@rpi.edu)
5
Emeritus, Department of Geosciences, Virginia Tech, Blacksburg, Virginia 24061, USA (jfread@vt.edu)
Six stratigraphic sections (Korcula, Hvar, Mljet islands and the Peljesac Penninsula) of shallow, Aptian platform
interior carbonates from the southern Croatia part of Tethys, were studied to document the sequence
development, parasequence stacking, and the effects of oceanic anoxic events on the platform stratigraphy.
The vertical stacking of subtidal, intertidal-supratidal, and subaerial exposure facies generated shallowing-upward
parasequences whose architecture was controlled by 3rd-order sea level cycles with superimposed Milankovitch
sea-level fluctuations, coupled with down-to-basin differential subsidence. The parasequences make up three 3rdorder sequences separated by sequence boundary zones of breccias. The three sequences correlate with regional
sequences of the Arabian Platform and elsewhere in Tethys.
The Early Aptian Sequence 1 (16 to 51 meters thick) is characterized by poorly cyclic, subtidal amalgamated
parasequences indicative of relatively high sea levels, increased species population and diversity. Facies are poorlycyclic, thick-bedded to massive, composed of subtidal lime mudstone and skeletal-intraclastic lime mudstone and
wackestone with rare benthic foraminifera, calcareous algae, microbial encrusters, bivalve fragments, as well as
subordinate pelagic crinoids and planktic foraminifers. The Early to Late Aptian Sequence 2 (6 to 27 meters thick)
is characterized by peritidal parasequences of skeletal mudstone-wackstone overlain by peloid-intraclast-skeletal
packstone and grainstone, and barren mudstone or regional thin, microbial laminites and rare breccias updip.
Locally, it contains an early highstand 10-meter-thick unit of thin-bedded, platy laminated limestone with
petroliferous odor, the laminae being mm-to-cm alternations of lime mudstone and fine pellet packstone. This
localized deeper lagoon facies marks a major transgression coeval with drowning of numerous Tethyan carbonate
platforms (OAE-1a), and is followed by a pronounced Late Aptian regression marking a significant biological crisis in
the peri-Adriatic region. The latest Aptian Sequence 3 (9 to 19 meters thick)consists of parasequences with
subtidal to subaerial exposure facies. The overlying Aptian-Albian sequence boundary consists of 3 to 5 well
developed breccias.
Carbon isotopes were obtained from carbonate mud matrix of the Aptian mudstone-wackestone. The resulting Cisotope curve (range from -1.59 to 4.03 ‰VPDB, with mean values of 0.7 ‰) matches with Alpine Tethys trends.
The initiation of OAE-1a, defined by a negative shift to -1.6‰VPDB followed by a positive excursion to 3.4‰VPDB,
coincides with a long-term global sea-level rise; the sedimentary expression of deepening is evidenced by the
locally limited deeper lagoon platy lime mudstone overlying subaerial exposure breccia.
Seismic Signatures of Faults in the Appalachian Basin of NYS, and the Effect of These Faults on Devonian Black
Shales: An Update
Robert D. Jacobi1,2, Cheri Cruz2, Al Leaver2, Jodi Fisher2
1
Norse Energy Corp, USA, 3556 Lake Shore Road, Buffalo, NY 14219 RJacobi@norseenergy.com
2
Department of Geology, University at Buffalo, Buffalo, NY 14260
In 2002 the Appalachian Basin in NYS was proposed to be riddled by literally hundreds of faults, based primarily on
EarthSat’s (1997) Landsat lineaments integrated with gravity and magnetics and in western NYS, surface geology
and soil gas. This report summarizes advances the UB Rock Fracture Group and associated partners have made in
fault understanding since 2002, based principally on extensive 3D seismic, as well as integration with field studies
of fracture systems in the black shales.
The spider web of interconnected fault strands can be separated into fault systems with common orientations and
tectonic histories. Many of the major northerly-striking fault systems, such as the Clarendon-Linden Fault System,
are reactivated intra-Grenvillian suture systems. The northerly-trending faults influenced deposition rates (and
facies) for much of the Paleozoic rock record, and show that the faults commonly reversed motion during
orogenies. The arcuate fault pattern across PA and NY (in map view) began as Iapetan-opening related faults (IOFs)
and outlines the Laurentian margin as the Pennsylvanian Salient and NY Promontory. Cambrian inversion of the
IOF basins is common. The IOFs were reactivated with the most significant offset primarily in Taconic times, but
were reactivated in all the Appalachian orogenies. Taconic fault block interactions between the arcuate IOFs and
intersecting northerly-trending faults are typical. Taconic slip on the IOFs in the arcuate pattern was oblique, and
most likely reversed during late Taconic convergence. The arcuate fault set controlled the development of many of
the TBr fields. NNE-striking “Taconic” faults in the Mohawk Valley region may be reactivated IOFs and experienced
oblique slip consistent with E-W Laurentian convergence (present coordinates). N-striking “neo-Taconic” faults
display only down dip motion indicators in outcrop. Both fault systems controlled Utica thickness variations; they
were reactivated in the Silurian when they controlled 0-lines and facies development at the edge of the Salinic
basin. NW-striking faults in western NY and PA, and WNW-striking faults in eastern NY were transfer zones
between segments of the IOFs. They were reactivated during the Taconic as oblique slip, and reversed motion in
late Taconic, and were reactivated in later orogenies. These faults also controlled development of some TBr fields.
In the Devonian Geneseo black shale in the Finger Lakes region, N- and ENE-striking Fracture Intensification
Domains (FIDs) are coincident with similarly-striking faults proposed on the basis of stratigraphic offsets and
seismic data. Also in eastern NYS, some Marcellus outcrops exhibit anomalous fracture systems, related to
coincident fault systems, and do not display the typical J1/J2.
Steep gradients in thermal maturity (indicated by CAI contours, Weary et al., 2001) in the Utica have been shown
to coincide with fault systems such as the Keuka Lake Fault System (Jacobi, 2007). Although less compelling in the
Devonian shales, observed steep gradients between CAI of 2 to 3.5 would be an equivalent of ~5,000 m offset,
significantly more than is possible along faults in central NYS. We therefore suggest that the steep gradients are
influenced by relatively hot fluid migration along fault systems. Thus, the local thermal maturity index may not be
simply measuring a simple burial history.
CO2 Sequestration in Central New York State: Update
Robert D. Jacobi1,2, Teresa Jordan3, Matthew Becker2,4, Beata Csatho2, Louis A. Derry5, Rick Frappa6, Jason Phipps
Morgan7, Larry Brown7, Kathryn Tamulonis8, Marta Castagna2,9, Jodi Fisher2, Melissa Zelazny2, John Martin10
1
Norse Energy Corp, USA, 3556 Lake Shore Road, Buffalo, NY 14219, RJacobi@norseenergy.com,
2
Univeristy at Buffalo, 855 Natural Sciences Complex, Buffalo, NY 14260
3
Earth and Atmospheric Sciences, Cornell University, Snee Hall, Ithaca, NY 14853
4
Dept of Geology, Cal State, Long Beach, 1250 Bellflower Blvd, Long Beach, CA 90815
5
Earth & Atmospheric Sciences, Cornell University, Snee Hall, Ithaca, NY 14817
6
AMEC Geomatrix, 908 John Muir Drive, Suite 104, Amherst, NY 14228
7
Earth & Atmospheric Sciences, Cornell University, Snee Hall, Ithaca, NY 14853
8
Schlumberger Carbon Services and Cornell University, 14090 Southwest Freeway, Sugar Land, TX 77478
9
University of Trento and University at Buffalo, Department of Civil and Environmental Engineering, Trento, 12345,
Italy
10
NYSERDA, Washington Circle, Albany, NY
The UB-Cornell-NYSERDA-Geomatrix-AES-Anschutz-Norse Energy-Talisman-NYS Museum consortium was formed
in 2008 to investigate the feasibility of subsurface CO2 sequestration from coal-fired power plants in central New
York State. The targeted units included Cambrian units (e.g., Potsdam, Rose Run, Galway), Ordovician Queenston,
and Silurian Oneida and Oswego. The Phase I tasks included 1) determining characteristics of the targeted horizons
(Jordan, Frappa, NYS Museum, and Jacobi); 2) determining the spatial variability of these units from seismic
reflection data (Jordan); 3) modeling dynamic CO2 capacity and fracture flow in potential CO2 reservoirs (Becker);
4) evaluating CO2 fluid-reservoir rock interactions (Derry); 5) modeling CO2 capacity incorporating task #4 (Phipps
Morgan); 6) collecting published and new fault and fracture data (Jacobi); 7) identification of lineaments and
testing the lineaments against task #6 (Csatho and Jacobi).
The Potsdam has porosities (P) up to 10% and permeabilities (k) ranging from 0.002 to generally 1 mD. The Rose
Run locally has P over 10% and k up to 4 mD. P for the Queenston is up to 14% and k ranges from 0.1 to 20 mD.
The Oneida and Oswego sands are too thin to be viable targets. The static capacity of the Queenston is sufficient to
store in a 25 mi2 area 3-12 years of CO2 emitted from the largest of the local power plants. However, if
permeability and capillarity are considered, the dynamic CO 2 storage capacity of these units is inhibited by
permeability. Hydraulic fracturing could significantly enhance the rate of injection (e.g., by at least a factor of 4 in
the Queenston). The largest simulated dynamic storage volume after 10 years (without hydraulic fracturing) was
achieved in Cambrian units: 4 megatons of CO2 storage in the Rose Run, and 6 megatons CO2 storage in the
Avoca/Little Falls formations. Queenston has roughly comparable numbers to the Rose Run. These volumes
approach the 1 megaton per year economic threshold. In the Queenston Formation no P occlusion would result by
precipitation of new minerals over decades. Lineaments and proposed fault systems are relatively close to each of
the coal-fired power plants. In order to predict the actual fractures in the target units at the target site, and to
verify an absence of faults, 3D seismic and horizontal test wells are a necessary step in Phase II.
Factors Affecting CO2 Storage Potential in Unmineable Coal Beds
Kevin B. Jones and Margo D. Corum
U.S. Geological Survey, 12201 Sunrise Valley Drive MS 956, Reston VA 20192, kevinjones@usgs.gov
The atmospheric CO2 concentration has increased from about 280 ppm in pre-industrial time to more than 390
ppm today. This increase is expected to continue as energy demand continues to increase worldwide. Capture and
geologic storage of CO2 is one approach to reduce the atmospheric CO2 concentration and its effects on global
climate. The U.S. Geological Survey (USGS) is currently assessing the potential national geologic resources available
for geologic CO2 storage, as directed by the 2007 Energy Independence and Security Act (EISA, Public Law 110–
140). Although the current assessment will not address potential CO2 storage in unmineable coal beds, future
assessments may. For this reason, the USGS is assembling a body of knowledge on factors affecting this storage,
including aspects of coal-CO2 interactions that are not yet well understood and are the subject of active research.
Because long-term storage of CO2 in coal essentially precludes use of the coal as fuel, EISA specifies that only
unmineable coal seams will be considered for CO2 storage. The term “unmineable” is problematic, however, as its
definition changes based on economics and technology. A consensus definition of unmineable coal is needed
before its potential for CO2 storage can be estimated.
Carbon dioxide can be stored in coal by adsorption to coal surfaces and trapping in pore spaces. Injection of CO 2
into a coal bed for storage requires permeability in the form of pores and fractures in the coal so that the CO 2 can
infiltrate the bed. Several factors affect coal permeability. Adsorption of injected CO 2 gas causes coal to swell,
reducing its permeability and making further injection of CO2 more difficult. Coal permeability also decreases with
depth. At pressure and temperature conditions that occur below about 1000 m depth, CO2 is a supercritical fluid
rather than a gas. Supercritical CO2 is an organic solvent that can diffuse into and plasticize coal, reducing its
permeability and porosity. Research into coal strength, sorption-induced strain, and effects on permeability and
porosity is ongoing.
Many in-progress and completed field CO2 injection tests and subsequent monitoring are allowing researchers to
build on theoretical work and laboratory studies and better understand geologic and engineering factors affecting
CO2 storage in coal beds. This understanding will form the basis for a future USGS methodology for the assessment
of CO2 storage potential in unmineable coal beds.
Testing Depositional Models and Basin Geometry for the Utica Shale, Mohawk Valley, New York State
Kyle Jones1, Charles E. Mitchell1, Langhorne “Taury” Smith3, Gerald Smith2, and Robert D. Jacobi2
1
Department of Geology, University at Buffalo, SUNY, 411 Cooke Hall, Buffalo, NY 14260, kylejone@buffalo.edu,
2
Norse Energy Corp, USA, 3556 Lake Shore Road, Buffalo, NY 14219
3
New York State Museum, Room 3140 CEC, Albany, NY 12230
The Ordovician Utica Shale is a natural gas producing black shale that crops out in the Mohawk Valley of eastern
New York State. The environment of deposition has traditionally been interpreted to be deep water anoxia in the
tectonically enclosed Taconic foreland basin where accommodation space growth is thought to have initially
greatly exceeded sediment supply. Smith et al. recently suggested an alternative model, however, in which the
Utica was deposited on the western limb of the Taconic foreland in relatively shallow water (perhaps less than 50
m), where it on-laps the Trenton Group above what they interpret to be subaerial unconformities. This model
emphasizes the presence of the Thruway Disconformity in the region of Little Falls and farther westward, which
separates the upper Utica Group (Indian Castle Shale) above from the Dolgeville Limestone below, as well as an
older sub-Utica unconformity that separates the basal Flat Creek Shale from the underlying Glens Falls Limestone
east of the Little Falls region. The regional basin geometry was affected by a series of syndepositional northeastsouthwest trending normal faults that delimit grabens and correspondingly thickened Utica Group deposits.
Distinguishing the alternative depositional models using local geological data therefore, will require careful
analysis to distinguish regional and local effects on lithology and accommodation space. For instance, although
total organic carbon (TOC) in the Utica is generally low (c. 1-2%) and exhibits limited geographic variation, our
preliminary data suggest locally enhanced preservation with up to 13% TOC that is present in the Flat Creek Shale,
and that TOC distribution may be significantly influenced by local structures.
Our intent is to test these alternative models based on data from field mapping as well as subsurface data. We are
employing these data to construct cross sections of the post-Knox, Taconic foreland succession in the Mohawk
Valley. A series of basement or near basement-depth cores were drilled throughout the central and eastern
Mohawk Valley area and are housed at the New York State Museum. The stratigraphic succession of the cores will
be used to construct geologic and stratigraphic cross sections of the Utica Shale that we will compare to those
created from logged natural gas wells located farther to the south. These cross sections will allow us to
reconstruct the basin geometry and compare this geometry with that of modern basins. The succession will be
divided into a set of isochronous intervals based on correlated ash beds, biostratigraphy, and graphic correlation.
Relative water depth estimates will be based on sedimentary structures such as storm beds, grainstones, and
mineralized discontinuity surfaces as well as trace fossil assemblages. Backstripping will then be performed on unit
thicknesses derived from both well logs and measured core to constrain basin geometry and the history of
accommodation space change at the time of deposition. Backstripping will also compare local subsidence to
eustasy. The goal of this project is to predict zones of high TOC and to understand effects of basin evolution on
deposition and preservation of black shales, ultimately resulting in greater natural gas production.
Assessment of Spatial Variability in the Marcellus Shale from High Resolution Sedimentology and Stratigraphy,
Finger Lakes Region, NY
Ceren Karaca and Teresa E. Jordan
Earth and Atmospheric Sciences, Cornell University, Ithaca, NY, 14853, ck465@cornell.edu
The Devonian Marcellus Formation of the Appalachian Basin is an example of the organic rich black shales that are
hydrocarbon source rocks. For most of the 20 th century, descriptions of black shales, including the Marcellus,
emphasized their homogeneity, high organic matter content, and very fine particle size (clay size), and interpreted
them to be the result of suspension settling from the water column in the deepest part of the basin. However,
recent studies show that these black shales are not homogenous, display a high degree of variability at a small
scale, and show evidence of current-induced deposition. In this study we intend to establish the variations in
lithofacies within the Marcellus Shale in the Finger Lakes region of New York and use these as criteria with which
to understand the environmental conditions under which the Marcellus Shale was deposited. A second component
of our study is to recognize key surfaces that may be indicative of basin wide base-level changes that can be tied to
the geophysical log signals. We intend to place the rock property variations in a sequence stratigraphic framework.
Ultimately, we will estimate the magnitude and variability of those rock properties across the Finger Lakes region,
by correlating well logs (wells in the ESOGIS database) within the sequence stratigraphic framework.
By its very nature, study of fine-grained rocks needs careful examination to identify rock properties that range
from macroscopic to microscopic scale. For this reason we base our high spatial-resolution analysis of the
Marcellus Shale on sedimentological, mineralogical, petrographical and chemical features. Data begin with outcrop
observations of the Marcellus Shale in fresh, unweathered surfaces of an active rock quarry (Seneca Stone Co.) in
Seneca County. Laboratory analyses of the fresh rock include petrographic thin sections, Total Organic Carbon
(TOC), X-Ray Diffraction, Scanning Electron Microscopy and microprobe.
Results to date emphasize the variability within the lower member of Marcellus Formation, the Union Springs
member. Based on the preliminary sedimentology and geochemistry data, the Union Springs Member shows great
variability within an approximately 3-meter interval. We observe three lithofacies that differ in terms of
sedimentology and geochemistry; 1. Lower “silty shale” lithofacies, 2. Middle “finely laminated shale” lithofacies,
3. Upper “calcitic concretionary shale” lithofacies. The first one, silty shale, is dominated by mm-cm scale
intercalations of silt-sized and clay-sized grains, with hints of erosion at the bases of silt lamina; it is very low in
organic matter. The second lithofacies, finely laminated shale, has more homogeneous clay-sized particles and is
darker grey; it has the highest organic matter content. The third lithofacies, shale with calcite concretions,
although also laminated, contains abundant large calcite concretions that range from 5 cm to 30 cm in diameter.
This unit is also rich in organic matter, except in the concretionary levels. All these variations in the Union Springs
Member suggest that the depositional conditions at the time of Marcellus deposition were not steady, and that
varying depositional mechanisms played roles in creating the physical and chemical properties of this formation.
USGS Assessment of In-Place, Oil-Shale Resources of the Upper Devonian Antrim Shale in the Michigan Basin,
Eastern United States
Alex W. Karlsen1, Tracey J. Mercier2, Frank T. Dulong1, Sandra G. Neuzil1, Ronald C. Johnson2
1
U.S. Geological Survey, National Center M.S. 956, 12201 Sunrise Valley Dr., Reston, VA 20192, akarlsen@usgs.gov
2
U.S. Geological Survey, Box 25046, Denver Federal Center M.S. 939, Denver, CO 80225
The U.S. Geological Survey is assessing in-place, oil-shale resources in the immature Upper Devonian Antrim Shale
in the Michigan Basin. The Antrim Shale is a black, organic-rich shale that was deposited during the Late Devonian
Period in a large epeiric, low-energy, marine environment that covered Michigan, northern Indiana, northwestern
Ohio, and parts of Lake Michigan and Lake Huron; it was also part of the Devonian sea that covered a large area of
the eastern United States. In the western part of the Michigan Basin, the Antrim Shale grades into the
contemporaneous Ellsworth Shale, a low-organic content, gray shale. The depth of the Antrim Shale varies from
surface (outcrop at the basin margins) to approximately 2,500 feet in the basin center. Within the north-central
part of the Michigan Basin, the Antrim Shale is greater than 750 feet thick. Only a small area in the north-central
part of the basin reaches thermal maturity in the oil window (greater than 0.6% Ro).
An earlier assessment of 2.82 trillion barrels of in-place, oil-shale resources of the Michigan Basin by Leffert and
Schroeder (1980) was based on average values for thickness, Fischer assay oil yield, and shale density for the
Antrim Shale. In this USGS assessment, the assessment unit for the Michigan Basin is defined by the aerial extent
of the Antrim Shale that is greater than10 feet thick, less than 6,000 feet below the surface, and does not lie under
the Great Lakes. Leffert and Schroeder (1980) provide 841 Fischer assay oil yield records, and Hockings (1980)
provides shale density data for approximately 350 samples from Antrim Shale cuttings and core from 30 locations
in the Michigan Basin. These data are used to calculate the thickness-weighted average oil yield in gallons per ton
(GPT) at each location. Shale density at each location is based on the Fischer assay oil yield and shale density
relation for all samples. The in-place, oil-shale resource calculation uses a Voronoi (polygons) method to
interpolate and extrapolate thickness, oil yield, and shale density between data locations. Because current in-situ
retort methods are believed to impact large volumes of rock irrespective of richness grade, thin shale zones in the
middle of the Antrim Shale with lower oil yields between zones with higher oil yields near the base and top of the
Antrim Shale will be included in resource estimates. Preliminary calculations indicate a smaller in-place, oil-shale
estimate than the 1980 assessment.
A Tale of Two Shales: Time-Series Geochemistry of the Devonian Marcellus and New Albany Shale Formations
Alan J. Kaufman1, Benjamin T. Breeden, III2, and Tyler Baril3
1
University of Maryland, Department of Geology and ESSIC, College Park, MD 20742-4211, kaufman@umd.edu
2
University of Maryland, Department of Geology, College Park, MD 20742-4211
3
University of Nevada Reno, Department of Geological Sciences and Engineering, Reno, NV 89557-0172
Time-series carbon, nitrogen, and sulfur elemental and isotopic analyses of the Middle Devonian Marcellus Shale
and Late Devonian New Albany Shale reveal strong stratigraphic variations related to changes in physical and
chemical depositional environments. In the Marcellus Shale, collected from outcrop near Kistler, PA, peak
abundances of carbon (up to 8 wt.%), nitrogen, and sulfur are recorded at the maximum flooding surface near the
base of the ~120 meter thick unit, suggesting a target horizon for horizontal drilling. Carbon isotope compositions
at the base of the Marcellus up to the MFS are low (ca. -36‰), and then step up 4‰ abruptly after the MFS
followed by a gentle climb to more 13C enriched values through the rest of the succession. Sulfur isotope
compositions vary widely, but define a broad positive excursion from near -30‰ at the base to near 0‰ in the
middle and back again to -30‰ at the top. The wide variation in sulfur isotope compositions may reflect low
sulfate concentrations in Devonian seawater, while the low 13C compositions leading up to the MFS suggests the
possibility of a stratified water column and chemoautotrophic inputs of organic matter. Thereafter the more
positive 13C signatures and variable sulfur isotope systematics in the Marcellus Shale are interpreted in terms of
ventilation of the shallow marine environment. Core samples intersecting the New Albany Shale in Pike County, IN
also reveal significant variations in the abundance and isotopic composition of carbon, nitrogen, and sulfur likely
associated with strong environmental perturbations. While peaks in carbon, nitrogen, and sulfur occur near the
base of the sampled interval, significant isotope shifts are not recognized until the top of the unit where there are
coincident enrichments in 13C, 14N, and 34S, with a remarkable positive excursion in sulfur isotope values of over
20‰. Previous studies have suggested that the carbon and nitrogen isotope shifts are a result of the transition
from anoxic/stratified ocean water (where sulfate reducing bacteria could occupy the water column) to ventilated
ocean water (where the bacteria would be forced to hide in anoxic sediment pore waters). In this case sulfate in
pore water available to sulfate reducers would be diffusion limited, potentially leading to progressive 34S
enrichment.
Biomarkers in the Upper Devonian Lower Huron Shale as Indicators of Biological Source of Organic Matter,
Depositional Environment, and Thermal Maturity
John Kroon and James W. Castle
Department of Environmental Engineering & Earth Sciences, Clemson University, 340 Brackett Hall, Clemson, SC
29634, jkroon@clemson.edu
The Lower Huron Shale (Upper Devonian) is considered the largest shale gas reservoir in the Big Sandy Field in
Kentucky and West Virginia. The potential for gas shales, such as the Lower Huron, to produce natural gas is a
function of type, amount, and thermal maturation of their organic matter. Twenty-one Lower Huron Shale
samples from eight wells located in eastern Kentucky and southern West Virginia were analyzed for biomarker
content to interpret biological source of organic matter, depositional environment conditions, and thermal
maturity. The following biomarkers were identified: n-alkanes (C15 to C35), pristane (Pr), phytane (Ph), steranes
(αααR, αααS, ααβR, ααβS isomers of C27 to C30 steranes), and hopanes (C27, C29, C30 and C31 hopanes).
The TAR (terrigenous versus aquatic n-alkanes ratio), n-C17/n-C31, Pr/n-C17, Ph/n-C18, and sterane distribution
indicate the source of organic matter in the samples analyzed is predominately marine algae and bacteria. The
most source-specific biomarkers identified in the samples were the C30 steranes indicative of marine brown algae.
The Pr/Ph, Pr/n-C17, Ph/n-C18, Ts/Tm ratios and sterane distribution indicate the samples were deposited in a deep
water (>100 m) environment with alternating oxic and anoxic conditions. These results and paleogeographic
information support depositional models involving a seasonally stratified water column.
The C27-20S/(20S+20R), C28-20S/(20S+20R), C29-20S/(20S+20R), C28-αββ/(αββ+ααα), C29- αββ/(αββ+ααα),
Ts/(Ts+Tm), and 22S/(22S+22R) ratio values indicate thermal maturities within the early to peak oil generation
stages. Contour maps of the biomarker ratio values indicate increasing thermal maturities toward the southeast
within the study area, which corresponds to the direction of increasing maximum burial depth. Biomarker data
suggest that gas produced from the Lower Huron Shale in the Big Sandy Field is biogenic or that thermogenic gas
has migrated to the Big Sandy Field from more thermally mature areas to the east.
Sequence Stratigraphic Analysis of the Uppermost Cambrian and the Lowermost Ordovician Deposits in Illinois:
Implications for Recognition of the Poorly Defined Cambro-Ordovician Boundary in the Deep Part of the Illinois
Basin
Yaghoob Lasemi and Z. Askari
Illinois State Geological Survey, Institute of Natural Resource Sustainability, University of Illinois, Champaign, IL
61820, ylasemi@isgs.illinois.edu
Recognition of the Cambro-Ordovician boundary in the deep part of the Illinois Basin has been hampered due to
continuous carbonate deposition and the apparent lithofacies similarities across the boundary. The Upper
Cambrian through Lower Ordovician succession in southern Illinois (over 6000 feet thick) has long been regarded
as the undifferentiated Knox Group, which is composed chiefly of fine to coarsely crystalline dolomite. To define
this important boundary, sequence stratigraphy and vertical facies trends of the uppermost Cambrian Eminence
Formation and the lowermost Ordovician Gunter Sandstone and/or Oneota Dolomite in Illinois have been
investigated along a northwest-southeast dip directed transect using subsurface data.
In the north and central part of Illinois, the Eminence Formation (50-250 feet thick) consists of sandy, fine to
medium crystalline dolomite and thin sandstone beds. It is overlain, with a sharp contact, by up to 25 feet of the
Lower Ordovician Gunter Sandstone followed by 100-300 feet of cherty fine to coarsely crystalline Oneota
Dolomite. In the southern third of Illinois, the south-central deep area of the Illinois Basin, the Gunter is absent and
the Oneota Dolomite cannot be differentiated from the Eminence Formation. Here, the Eminence Formation and
the Oneota Dolomite are very thick and consist almost entirely of fine to coarsely crystalline dolomite with thin
shale/clay intervals deposited in a relatively deeper marine setting.
Base on this study, the Cambro-Ordovician boundary is located about 50 feet above an easily recognizable high
Gamma ray marker in the upper Eminence. This geophysical marker occurs constantly at about the same depth
below the Eminence-Gunter/Oneota contact and becomes more pronounced basinward. In addition, a diagnostic
3-kick Gamma ray signature is present below the Eminence-Oneota contact in the deeper part of the basin.
Moreover, the proposed Cambro-Ordovician boundary coincides with the most regressive surface, the sequence
boundary separating the Eminence highstand systems tract and the overlying Oneota transgressive systems tract.
Recognition of the Cambro-Ordovician boundary facilitates the subdivision of the Knox Group into lower and upper
Knox successions consisting of several depositional sequences. The results of this study indicate that regional
sequence stratigraphic correlation and recognition of stratigraphic marker horizons within the Knox Group in the
Illinois Basin can provide a unique framework in which facies distribution through time can be examined to define
potential reservoirs and seals for carbon sequestration.
Chemostratigraphic trends of the Middle Devonian Marcellus Shale, Appalachian Basin; Preliminary
Observations
Gary G. Lash1 and Randy Blood2
1
Dept. of Geosciences, SUNY Fredonia, Fredonia, NY, 14063, Lash@fredonia.edu
2
Randy Blood, EQT Production, Pittsburgh, PA, 15222
Trace element and metals abundances have been used to elucidate the hydrography of silled basins as well as
watermass chemistry and deep-water residence times. The database of our preliminary study of the Middle
Devonian Marcellus Shale comprises chemostratigraphic (X-ray fluorescence) elemental concentrations
determined from cores recovered from eastern New York, southwest Pennsylvania and northern West Virginia.
Regional covariance trends of authigenic molybdenum (Moauth) and uranium (Uauth) and their respective
enrichment factors (EFs) define a uniform (Mo/U)auth ratio of ≈ 2 - 3 times the Mo/U molar ratio of seawater.
Moauth is enriched relative to Uauth by a factor of 5:1 to 10:1 suggesting accelerated transport of Mo to the seafloor
by a particulate (Mn) transport mechanism that would have required frequent fluctuations between suboxic and
moderately sulfidic water column conditions. Indeed, the relationship of total organic carbon and Mo(ppm) in
eastern New York suggests water renewal times on the order of several hundred years. A data subset defined by
diminishing Moauth and Uauth EFs at reduced aqueous Mo/U ratios may reflect the preferential uptake of U under
largely suboxic conditions. Moreover, data from a well in northern West Virginia defines Mo auth and Uauth values
typical of bottom water depleted in Mo (Mo/U = 0.1 - 0.3 x seawater) and (Mo/U)auth ratios of ≈ 1:1. Thus, whereas
the Marcellus basin may have experienced frequent episodes of suboxic to sulfidic conditions that accelerated Mo
enrichment, local hydrographic conditions (i.e., stronger degree of water column stratification) appear to have
favored Mo drawdown in bottom water. Equally intriguing is the regional concentration of barium in the upper
part of the Marcellus, which may reflect an episode of enhanced paleoproductivity at this time. Further, chloride
and strontium are especially concentrated in transgresive systems tract deposits perhaps reflecting salinity
excursions that could have enhanced the preservation of organic matter in these intervals.
Carbon Sequestration Potential of the Cambrian and Ordovician of the Illinois Basin
Hannes E. Leetaru1, Alan L. Brown2, Donald W. Lee3, Ozgur Senel4
1
Illinois State Geological Survey, 615 E. Peabody Dr, Champaign, IL 61820, leetaru@isgs.illinois.edu
2
Schlumberger Carbon Services, 14090 SW FWY Suite 240, Sugar Land, TX 77478, ABrown11@slb.com
3
Schlumberger, 1325 South Dairy Ashford, Houston, Texas 77077, lee6@slb.com
4
Schlumberger Carbon Services, 14090 SW FWY Suite 240, Sugar Land, TX 77478, OSenel@slb.com
The Cambro-Ordovician strata of the Illinois and Michigan Basins encompass most of the states of Illinois, Indiana,
Kentucky, and Michigan. This interval underlies much of the Midwest of the United States and, for some areas,
may be the only available target for geological sequestration of CO 2. We evaluated the Cambro-Ordovician strata
above the basal Mt. Simon Sandstone reservoir for sequestration potential. The two targets were the Cambrian
carbonate intervals in the Knox Group and the Ordovician St. Peter Sandstone.
The evaluation of these two formations was accomplished using wireline logs, core data, pressure data, and
seismic data from the USDOE-funded Illinois Basin Decatur-Project being conducted by the Midwest Geological
Sequestration Consortium in Macon County, Illinois. Interpretations were completed using log analysis software, a
reservoir flow simulator, and a finite-element solver that determines rock stress and strain changes resulting from
the pressure increase associated with CO2 injection.
Results of this research suggest that both the St. Peter Sandstone and the Potosi Dolomite (a formation within the
Knox) reservoirs may be capable of storing up to 2 million tonnes of CO 2 per year for a 20-year period. Reservoir
simulation results for the St. Peter indicate good injectivity and a relatively small CO 2 plume. While a single St.
Peter well (200 feet thick) is not likely to achieve the targeted injection rate of 2 million tonnes/year, results of
this study indicate that development with three or four appropriately spaced wells may be sufficient. Reservoir
simulation of the Potosi suggest that much of the CO2 flows into and through relatively thin, high permeability
intervals, resulting in a large plume diameter compared with the St. Peter.
Data Mining Methods for Assessing Public Attitudes of CCS
Kalev H. Leetaru1 and Hannes E. Leetaru2
1
University of Illinois, 2001 S. 1st Street, Suite 207, Champaign, IL, 61820, leetaru@illinois.edu
2
Illinois State Geological Survey, 615 E. Peabody Dr, Champaign, IL 61820
This case study illustrates how data mining methods can be used to gain significant insights into the prevailing tone
and geographical patterns in the coverage of CCS and be a useful tool for energy resource managers to respond to
changes in public perception. This study examined over one million global news and social media articles to
characterize public attitudes towards Clean Coal with Carbon Capture and Storage (CCS). Analysis of the LexisNexis
database from the origin of the term Clean Coal through the present, suggests that CCS has been intimately linked
with coal-fired power plants with 50 to 75 percent of the CCS articles in any given month mentioning Clean Coal
and CCS together. The term CCS generates the highest density of front page and editorial coverage of any energyrelated technology of the last half-century. During the 2008 US presidential campaign, the terminology of Clean
Coal with CCS was launched into the public lexicon through the work of the Hawthorne Group. The data show that
the effect was limited to the news media and that the blogosphere largely did not react to this campaign-based
press initiative. Further, while the number of blogs covering Clean Coal with CCS has increased 1,200% over the
last four years, the overlap between the news and blogosphere has grown significantly, suggesting newer blogs are
simply reinforcing the same messages, while the tone of their coverage is nearly identical to the more traditional
news media. Most surprisingly, economic impact rather than threat of environmental damage appears to drive
media interest. Additionally, media coverage seems to resonate most strongly with the public in spring and fall,
rather than the summer.
Vertical and Lateral Extent and TOC Content of Middle and Upper Devonian Organic-Rich Shales, New York State
James Leone and Langhorne Smith, New York State Museum, Room 3140 CEC Albany, NY 12230,
lsmith@mail.nysed.gov
While most of the focus is on the Middle Devonian Marcellus Shale, there are numerous other organic-rich shales
in the Middle and Upper Devonian strata of New York State that might also produce gas or liquids. The purpose of
this presentation is to show in-house TOC and calcite content data, maps and cross sections of Middle and Upper
Devonian black shales in New York. These organic-rich shales include from oldest to youngest the Marcellus,
Levanna, Ledyard, Geneseo, Renwick, Middlesex, Rhinestreet, Dunkirk and Pipe Creek Shales. TOC and calcite
content measured from well cuttings will be presented along with wireline logs in the cross sections and maps of
the thickness of each organic-rich shale. All of the shales grade from thicker, organic-poor gray shales in the east
to progressively thinner and more TOC-enriched to the west. The organic rich shales commonly interbedded with
limestones while the gray, organic-poor shales are commonly interbedded with siltstone and sandstone. Most of
the organic-rich shale bearing strata appear to onlap and pinch out on unconformities to the west. The cross
sections help to develop a depositional model for the organic-rich shales that shows them forming in relatively
shallow water on the present-day western or cratonward side of the basin.
The stratigraphy is quite complex as time equivalent units grade from gray shale and siltstone to organic rich shale
and limestone and unconformities develop, especially in the west. Attempts will be made to unravel some of the
stratigraphic complexity and establish chronostratigprahic relationships. One particularly interesting interval
occurs in the far western counties where more there is an unnamed limestone unit that only occurs in the
subsurface that has mistakenly been called the Tully by previous workers. The cross sections will show that this
limestone appears to be part Tichenor and Menteth Limestones which are older than the Tully Limestone and part
Genundewa Limestone which is younger than the Tully. The Tully is represented by an unconformity in the middle
of the limestone unit. This is important as the rest of the stratigraphy makes more sense when this limestone unit
is picked correctly.
Evaluation of the Newburg Sandstone as a CO2 Storage Unit in Central West Virginia
Eric Lewis
West Virginia Geological and Economic Survey, 1 Mont Chateau Rd., Morgantown, WV 26508,
elewis@geosrv.wvnet.edu
The West Virginia Department of Energy (WVDOE) is currently evaluating several deep saline formations in the
Appalachian Basin of West Virginia, which may be potential CO2 sequestration targets. As an extensive and porous
unit, especially in the upper 3-10 ft of the interval, the Upper Silurian Newburg Sandstone is thought to possess the
necessary characteristics that would allow mineralization from the sequestration process to form over long
injection periods. Short life spans of gas wells suggest well developed porosity, permeability and connectivity in
this marine sand unit and high initial pressures imply that the overlying Salina Formation will make for a
competent seal. Although production has been limited to primarily five fields separated by salt water contacts and
dry holes, this study will focus on the unit at a regional scale. Additionally, the Newburg proximity to CO2 point
sources may make it a technically and economically viable storage formation.
An Overview of Marcellus and other Devonian Shale Production in West Virginia
Eric Lewis, Mary Behling, and Susan Pool
West Virginia Geological and Economic Survey, 1 Mont Chateau Rd., Morgantown, WV 26508,
elewis@geosrv.wvnet.edu
The Middle Devonian Marcellus Shale Play has put the Appalachian Basin at the center of a national debate
concerning America’s future energy supply. Although it has been received in the region with mixed reviews, this
highly organic shale formation has secured itself as a major contributor to the natural gas supply of West Virginia
and other states in the Basin. As production continues throughout West Virginia, areas of high production
continue to emerge; however, it appears that some of these “sweet spots” may not actually be within the
“Marcellus” per se, but rather, in other, overlying Devonian shales. Various aspects of shale production will be
explored including vertical versus horizontal completions.
The Horton Bluff Formation Gas Shale, Frontier Shale Play Fairway Analysis, Nova Scotia, Canada
Adam W.A. MacDonald
Nova Scotia Department of Energy
The Horton Bluff Formation gas shale’s are within the Carboniferous lacustrine and marginal marine Horton Group
of the Maritimes Basin. Gas in place (GIP) estimates are > 69 TCF and leading indicators of a prospective shale gas
play such as TOC at >5.5 % , Maturity (Ro) of 1.6, thickness of >500 meters and estimates of 100 Bcf per section
across an area of > 2 million acres, have generated an increased interest in the Horton Bluff Formation within this
frontier basin. Comparison of this shale play characteristics to many others (mineralogy, gas filled porosity,
pressure gradient, adsorbed gas) across North America ranks the Horton Bluff shale as among some of the most
prospective.
The Nova Scotia Department of Energy (NSDOE), working closely with industry, has recently undertaken the task of
trying to understand the resource potential. GIP or “size of the prize” is determined by the shales’ gas generating
potential and the mineralogy, which may dictate the fracturing techniques and lead into the engineering solutions
that need to be achieved through the drilling and piloting phase to reach commercial producibility. Good seismic
coverage (2-D and 3-D data) and well control is available to help define the shale’s reservoir quality or “sweetspots”. Seismic interpretation linked to well data, geochemical understanding of the formation and recent outcrop
geology study has given new understanding of the depositional system and structural evolution of the basin. This
can be linked to predicted production variability. To date five wells have been drilled and two successful wells have
shown volumes of gas to surface post completion and stimulation. The analogous shale reservoirs to the north (in
New Brunswick) are currently in the evaluation pilot phase for scalable production by Apache Corporation and
attractive tight sands within the same formation are producing at approximately 25 mmcf/day through vertical
wellbore at the McCully gas field. A frontier approach to play fairway analysis and ongoing research into outcrop
geology linked to seismic data signatures and structural interpretation on the evolution of the basins are the key to
a successful development of this resources asset in eastern Canada.
Thermal Maturity of the U. S. Atlantic Coastal Plain, Maryland to North Carolina, Based on Legacy Exploration
and Stratigraphic Test Wells
MaryAnn Love Malinconico
Dept. of Geology and Environmental Geosciences, Lafayette College, Easton, PA 18042, lovem@lafayette.edu
On the US mid-Atlantic Coastal Plain, numerous deep exploration wells were drilled from 1944 to the early 1970’s,
many prior to the advent or common use of vitrinite reflectance or other maturity indicators in the petroleum
industry. The goal of the current study is to collect downhole vitrinite reflectance data from several mid-to-late
20th -century exploration and stratigraphic test wells, in order to fill the void in maturity information on the ocean
edge of the coastal plain from New Jersey to North Carolina. The goals are to test 1) hypotheses on the coastal
plain/ Outer Continental Shelf (OCS) depth to the oil window (0.6%), 2) if thermal trends are regionally similar, 3)
whether maturity data can be useful in problems of pre-Cretaceous Mesozoic stratigraphy, and 4) provide a
background framework for regional studies, such as the Chesapeake Bay Impact Structure.
Data is available from six wells in Maryland (Standard Oil of New Jersey Maryland Esso #1 at Ocean City, SoconyVacuum J. T. Bethards #1, Ohio Oil Hammond #1), Virginia (E. G. Taylor #1-G), and North Carolina (Mobil #3,
Standard Oil of New Jersey Hatteras Light Esso #1). A similar downhole reflectance trend is found among all wells,
with 0.4%Ro at about 5000-5500 ft (1600 m), 0.45%Ro at ~7000 ft (2100 m). Hatteras Light Esso #1 is the deepest
and easternmost of all coastal plain wells and has a reflectance of 0.60% at 9805 ft (2990 m) (basement depth
9853 ft). The calculated reflectance values from equilibrated downhole temperature data through coastal plain
sediments (0-4455 ft) from the VPI Crisfield deep geothermal test hole, Maryland Delmarva peninsula, follow a
similar trend. Offshore, the Baltimore Canyon COST B-2 well, on the continental shelf edge, had measured vitrinite
reflectance of 0.57% at 9910 ft (3020 m) and 0.62% at 10660 ft (3250 m) (Smith et al., 1976), comparable to the
Hatteras #1 data, suggesting a similar regional maturity gradient on the coastal plain and continental shelf.
In four wells, Taylor (VA), Hammond (MD), Bethards (MD), and Hatteras (NC), sediments just above basement
were initially (drill site or early publications), based on lithology, assigned to the Triassic. Reflectance data from this
study through those intervals for Taylor, Bethards, and Hatteras are linearly continuous with shallower data so
cannot be used to make any determination on stratigraphic age or unconformities; no measurable vitrinite was
found in oldest sediments in Hammond. However, Malinconico and Weems (2010) concurred with a variety of
other published palynological and paleontological studies on these wells that deepest strata in the
Maryland/Virginia wells are Lowest Cretaceous or Upper Jurassic, and Upper Jurassic in Hatteras #1.
Thermal Maturity of the Early Mesozoic Richmond and Fundy Basins, in the Context of Newark and Taylorsville
Basin Thermal Histories, Eastern USA and Canada
MaryAnn Love Malinconico1, and James C. Hower2
1
Dept. of Geology and Environmental Geosciences, Lafayette College, Easton, PA 18042, lovem@lafayette.edu
2
University of Kentucky, Center for Applied Energy Research, Lexington, KY 40511
Previous vitrinite reflectance and thermal history studies (Malinconico, 2002, 2010) of the eastern USA early
Mesozoic Taylorsville (VA/MD) and Newark (NY/NJ/PA) continental rift basins have shown that basement
conductive heat flow in these basins has been modified by basin-scale advective fluid flow, pathways of which vary
among basins based on distribution of permeable fluvial versus impermeable lacustrine facies. The basal basin
heat flow is hypothesized to be a relict of position relative to the Alleghanian orogenic metamorphic/ thermal axis,
which was also the locus of post-orogenic collapse. In the Taylorsville basin, an overfilled-lake-basin type according
to Carroll and Bohacs (1999), and located along the Alleghanian thermal axis, the syn-rift background geotherm
was ~45-55˚C/km. Basin-scale groundwater flow through extensive fluvial strata and driven by gravity-driven
meteoric water downwelling at the western border fault resulted in lower syn-rift geothermal gradients in the
western basin (40˚C/km) than in the eastern basin (~55˚C/km). The Newark basin, generally a balanced-fill laketype basin and west of the Alleghanian metamorphic axis, had a calculated syn-rift background gradient of
~25˚C/km. Syn-rift steady-state groundwater flow confined to basal fluvial strata, again gravity-driven by borderfault meteoric downwelling, conductively heated overlying low-permeability lacustrine formations to ~35˚C/km.
Both basins experienced post-rift, pre-coastal-plain structural inversion and erosion.
The Richmond basin is located ~15 km southwest of the Taylorsville basin along strike with the Taylorsville western
border fault. The exposed strata are Triassic, and form a structural syncline. The pattern of new surface vitrinite
reflectance data indicates that synclinal deformation was post-rift (post-thermal maximum), consistent with
inversion processes affecting other basins. Reflectance data was also measured on cuttings from two deep industry
wells in the center of the basin: Cornell Oil Bailey #1 and Horner #1. Vitrinite reflectance of 1.7% was reached at
~6600 ft (2000 m) in Bailey and ~6000 ft (1800 m) in Horner. Calculated geotherms of > 45˚C/km are consistent
with the Richmond basin’s similar tectonic position and facies association as the Taylorsville basin.
The Fundy basin of Nova Scotia and New Brunswick (NB) is primarily an underfilled-lake-type basin with a paucity
of confirmed organic-rich sediments. Sparse industry maturity data (from the Canada-Nova Scotia Offshore
Petroleum Board) is available for the Irving Chevron et al. Cape Spencer #1 well in the Bay of Fundy, 5 km south of
the NB coast and Headlands fault (Wade et al., 1996), which is part of the border fault system that also separates
the basement Avalon and Meguma terranes. The downhole industry vitrinite reflectance data suggest a syn-rift
geothermal gradient of ~20˚C/km, reasonable for cooling of a background gradient of 25˚C/km by meteoric
downwelling processes similar to other rift basins. The Fundy basin, like the Newark basin, is located off-axis of late
Paleozoic metamorphism. New surface reflectance data from isolated rider-block exposures of Triassic (Carnian)
Wolfville Formation in the highly-faulted Avalonian footwall, coastal NB, at Melvin Beach (0.83% Ro) and 30 km
northeast at Martin Head (0.28% Ro) indicate both variable syn-rift burial depth and post-rift exhumation.
Could Gas Hydrate in Fine Grained Sediments be a Precursor for Some Shale Gas Deposits?
M.D. Max1 and A.H. Johnson1
1
Hydrate Energy International, 612 Petit Berdot Drive, Kenner, LA 70065-1126, m_max@hydrate-energy.com
Shale gas is a major energy resource whose potential continues to grow. Under-standing the paragenesis of the
gas and its concentration in the shale throughout its history of deposition as muddy sediments to its present state
is a key to exploration because gas is not equally distributed in the shale host. Presently the gas in the shale is
regarded as being produced locally from the local organic matter that constitutes up to 8-10% of the rock.
However, there is some question as to whether the indigenous organic matter could actually generate all of the
gas locally, for instance for each cubic foot by cubic foot of the shale.
It is possible that the formation of solid, mechanically strong gas hydrate in the muddy shales originally
concentrated gas by compressing it into its crystalline lattice. Modern gas hydrate concentrations of 5-10% are
common in fine-grained marine sediment sections as thick as 800 feet in continental slopes. Most of gas in the
hydrate is regarded as having been generated by both bio- and thermogenic activity in huge subjacent gas
production zones. These muddy sediments are estimated to currently hold more gas worldwide than has been
identified in conventional and other unconventional gas deposits. If pressure – temperature conditions persisted
during lithification of shale gas precursor, at least until packing of the clay minerals effectively reduced
permeability to a point that the gas released from hydrate by increasing temperature or decreasing pressure could
not migrate easily, then a very large part of this gas would have been trapped in the shales as their further
compaction proceeded. An implication for exploration is that high gas concentrations may not be confined to
organic-rich shales but may also be found in any shales that once contained substantial gas hydrates, such as lower
organic content grey shales and more siliceous shales, which respond well to fracking.
3-D Reservoir Characterization of the South Buckeye Field, Dundee Formation (Devonian), Michigan Basin, USA
Shawn M. McCloskey1 and G. Michael Grammer2
1
Michigan Geological Repository for Research and Education, Western Michigan University, Kalamazoo, Michigan,
shawn.m.mccloskey@wmich.edu
2
Michigan Geological Repository for Research and Education, Western Michigan University, Kalamazoo, Michigan
Middle Devonian Dundee carbonates are prolific hydrocarbon reservoirs throughout the Michigan Basin that have
produced in excess of 375 million barrels of oil from more than 100 fields. Carbonate systems are driven by
dynamic processes that vary in time and space at nearly all scales, from the pore network to the regional sequence
stratigraphic architecture. The internal variability and detailed facies geometry of the Dundee are not well
understood. This high resolution reservoir characterization study defines the complex internal heterogeneities of
the South Buckeye field by tying reservoir quality (i.e., porosity and permeability from whole core analyses) directly
to seven primary depositional facies.
The fundamental goal of this study is to evaluate if the geographic distribution of patch reefs can be accurately
modeled in Petrel based on core and log data without a tie to 3-D seismic by utilizing the application of
geometrical data from multiple depositional analogs. Paleotopographic highs provided nucleation sites for the
stromatoporoid patch reefs to grow, but within each of these reefs reservoir quality varies significantly. The
internal architecture of the South Buckeye field and the distribution of patch reefs were defined through the
integration of petrophysical and petrographic analyses from high density subsurface core data.
Based upon core and wireline log analysis, three end member interpretations to define the distribution and scale
of the patch reef reservoirs in South Buckeye field are possible. These end-member interpretations vary on the
size and continuity of the patch reefs, with models ranging from single well reefs below seismic scale, multiple well
reefs with horizontal/multi-lateral potential, and two large reef bodies concluded from previous research. These
end member interpretations will be modeled geostatistically in Petrel to compare 3-D visualizations of the reef
complexes with known production histories from the field. As with many carbonate reservoirs, a three-dimensional
static reservoir model is a critical step in the workflow for efficient hydrocarbon extraction, natural gas storage,
and CO2 sequestration, and will provide insight into the Michigan Basin Dundee patch reefs as well as possibly
other Devonian carbonates and patch reef trends around the world.
Dust in the Wind: Aeolian Sediment in Middle Ordovician Carbonates of North America
Ronald R. McDowell
West Virginia Geological and Economic Survey, 1 Mont Chateau Road, Morgantown, WV 26508,
mcdowell@geosrv.wvnet.edu
The Middle Ordovician Nealmont Limestone of eastern West Virginia and western Virginia is marked by the
presence of numerous specimens of the feeding trace fossil Chondrites. These ichnofossils are recognizable from a
distance because they are typically infilled with tan or light orange, quartz silt and clay and stand out in marked
contrast to the dark micritic matrix. In addition, bedding surfaces may be partially or completely covered with this
bioturbated material in millimeter-thick layers. As a result, these ichnofossils are useful in identifying the
Nealmont for field mapping purposes.
The author has previously had the opportunity to study carbonates of the Middle Ordovician Pogonip Group in the
Great Basin, USA. These extensive deposits (particularly the Kanosh Formation) from the western margin of the
North American continent are similarly marked by the presence of orange, silty laminae and silt-filled Chondrites
and other feeding traces. The author interpreted these fine-grained siliciclastic sediments as aeolian in origin
because of their presence along the seaward margin of a basin more than 100 miles from the nearest siliciclastic
sediment source. It seems likely that similar sediment in the Nealmont Limestone has a comparable origin.
Reconstruction of continents during the Middle Ordovician places eastern North America at approximately 10°
south latitude and western North America at approximately 15° north latitude, both in a zone of easterly,
equatorial wind flow. The source location for deflated sediment is unknown for this time period as the major land
masses lay to the south in a nearly polar position. The presence of deposits of aeolian sediment on opposite sides
of the Middle Ordovician North American continent suggests that it may represent a major sedimentological event
with widespread stratigraphic significance.
Geochemical and Isotopic Variations in Waters of an Area of Accelerating Shale Gas Development
Michon L. Mulder and S. Sharma
Geology and Geography, West Virginia University, Morgantown, WV 26506, shikha.sharma@mail.wvu.edu
The main concern associated with Marcellus shale gas development is that water quality of surface waters and
fresh water aquifers can be compromised during gas well drilling, stimulation and improper disposal practices.
However, in shale development areas of West Virginia, the frac flowback waters can have similar chemical
constituents found in some saline formations and coal mine waters originating from several thousand acres of
abandoned coal mines in this region. Therefore, to better assess any detrimental effect on water quality there is
need to understand the natural temporal and spatial variations in the geochemical parameters of the surface
waters and groundwaters in the area.
This study documents geochemistry of 32 USGS groundwater and surface water monitoring sites in West Virginia.
Groundwater sampling locations were chosen to represent different formation aquifers and differing well depths.
The formation aquifers include the Beekmantown Group, Conemaugh Formation, Helderberg Group, Kanawha
Formation, Mahantango Formation, Mauch Chunk Formation, Monongahela Formation, Pocahontas Formation,
Pottsville Formation, and Stonehenge Formation. Surface water sampling sites were chosen in close proximity to
the groundwater sampling location. To understand the spatial geochemical variation data has been compiled for
these groundwater and surface water monitoring sites from the USGS database. Preliminary analysis of this
geochemical data shows highly variable chemistry within surface water sites locally and statewide. Samples will be
collected from these sites during the summer and winter season of 2011 to correspond with peak and base flow
conditions. Hydrochemical data will be analyzed in conjunction with isotopes, including cations and anions, as well
as discharge, pH, dissolved oxygen, conductivity, temperature, and ORP. We hypothesize that the stable isotope
signatures of oxygen, hydrogen, carbon, and sulfur of the different water sources i.e. frac flowback waters
associated with Marcellus shale gas development, coal mine waters, surface waters, and waters in shallow and
deep fresh water/saline aquifers are likely to be very different. Hence, stable isotope variations can be used in
conjunction with the routine geochemical parameters to understand the impact of Marcellus shale gas
development on the water quality of surface and groundwater aquifers of the area.
Revising the 2006 USGS Assessment of In-Place Oil Shale Resources of Devonian-Mississippian Black Shales in
the Eastern United States
Sandra G. Neuzil1, Frank T. Dulong1, Joseph A. East1, Alexander W. Karlsen1, Michael H. Trippi1, Tracey J. Mercier2,
and Ronald C. Johnson2
1
U.S. Geological Survey, National Center M.S. 956, 12201 Sunrise Valley Dr., Reston, VA 20192, sneuzil@usgs.gov
2
U.S. Geological Survey, Box 25046, Denver Federal Center M.S. 939, Denver, CO 80225
The U.S. Geological Survey (USGS) is revising the 2006 assessment of 189 billion barrels of surface-mineable oil-inplace in the Devonian-Mississippian black shales in the eastern United States, which was published as part of a
study on world oil-shale deposits (Dyni, 2006). The 2006 USGS assessment was based on earlier work by Matthews
and others (1980) who estimated the area, average thickness, and average oil yield for the most organic-rich shales
in each of six states (Alabama, Indiana, Kentucky, Michigan, Ohio, and Tennessee) that lie near the outcrop belt
and could be surface mined.
Advances in technology since 1980 suggest that in-situ retorting processes may be applicable for oil shale
development in the eastern U.S., and thus, this new USGS assessment will examine organic-rich shale to a depth of
6,000 feet. The areal extent of the Antrim Shale in the Michigan Basin; the New Albany Shale in the Illinois Basin;
and the Sunbury Shale, Cleveland Member and Huron Member of the Ohio Shale, Rhinestreet Shale Member of
the West Falls Formation, Marcellus Shale, and Chattanooga Shale in the Appalachian Basin that has a low thermal
maturity (below the oil window and into the lower part of the oil window, i.e., vitrinite reflectance values of less
than 1.0) will be considered in this assessment.
The Fischer assay method is a standard method used to measure the potential oil yield of oil shale. Publicly
available Fischer assay oil yield and total organic carbon data, primarily from core and cuttings, will be used in this
assessment. In some cases, oil yield will be calculated from total organic carbon data. Although the highest
Fischer assay oil yield values exceed 15 gallons of oil per ton of shale (GPT) in a few shale samples in the Michigan,
Illinois, and Appalachian Basins, and thin (20-30 feet thick) rich zones may have an average oil yield of 10-12 GPT,
most shale samples have an oil yield of less than 10 GPT. In each assessed formation, zones with a low oil yield
(less than approximately 5 GPT) will be included because in-situ retort methods will probably involve large volumes
of rock and not discriminate by oil yield richness grade. Thickness, Fischer assay oil yield, and density of the shale
will be interpolated between map location data points to refine the calculations of shale volume and the estimate
of in-place oil shale resources of the Devonian-Mississippian black shales of the eastern U.S. It is possible that
some black shales in the Appalachian Basin will not be assessed either due to a small areal extent that has a low
thermal maturity or due to a paucity of data. Preliminary results suggest that the in-place oil shale resources in
this assessment will be considerably larger than the previous 2006 assessment, due largely to the increased area
and greater depths of included shales.
Fabric of Shales Relating to Sedimentary Processes and Gas Shale Characteristics
Neal R. O’Brien1 and Roger Slatt2
1
Geology Department, SUNY Potsdam, 44 Pierrepont Avenue, Potsdam, NY 13676, obriennr@potsdam.edu
2
Institute of Reservoir Characterization and School of Geology and Geophysics, University of Oklahoma, Norman,
OK 73072
The fabric of shales revealed by x-radiographic, petrographic, and scanning electron microscopic analysis provides
clues to shale sedimentary processes and properties of potential gas shales. Presented here are examples of fabric
signatures useful in recognizing the following shale forming processes: 1) flocculation – dispersion, 2) bioturbation,
3) low density bottom flowing currents, 4) suspension settling, 5) bio-sediment aggregates and fecal pellet
formation, and 6) lamination processes, esp. microbial mat formation.
In addition, microfabric analysis at the micrometer and nanometer scale using SEM, FESEM, and EDX techniques
reveals various pore types found in certain gas shales. Examples are shown of these pore types: 1) porous
floccules, 2) organo-porosity, 3) pores in fecal pellets, 4) pores in fossil fragments, 5) intraparticle pore spaces, 6)
pores related to microchannels and microfractures. Examples typical of these processes and pore types are shown
for various Devonian shales of the Appalachian Basin and the Barnett-Woodford gas shales and provide a useful
pictorial frame of reference in Eastern Shale gas analysis.
Nature and Origin of Dolomitization of the Boat Harbour Formation Carbonates in Northern Peninsula, Western
Newfoundland, Canada: Implications for Porosity Controls
Babatunde J. Olanipekun and Karem Azmy
Earth Sciences, Memorial University of Newfoundland, St John's, Canada, bjo852@mun.ca
The Boat Harbour Formation of the lower Ordovician (Tremadocian/Arenigian) St George Group Carbonate on
Northern Peninsula is about 140m thick and conformably overlain by the porous Catoche Formation.
In addition to petrographic investigations (transmitted light microscope, cathodoluminiscence and fluid inclusion
microthermometry), data from geochemical analyses (major and trace elements-Ca, Mg, Fe, Mn, and Sr-, O-, and
C- and Sr-isotopes) were utilized to investigate the origin of dolomites and the results were also compared with
their counterparts of the equivalent section in Isthmus Bay at Port au Port Peninsula (about 300km to South).
At least three 3 phases of dolomites were identified from petrographic examination. The earliest phase D1 is
dolomicrite with crystals ranging from ~3 to 35 μm. The following phase D2 consists of planar sub-to euhedral
crystals ranging from 30 to120μm. The latest phase, D3, is the coarsest and consists of curved, dominantly nonplanar crystals ranging from 300 μm to 9mm, exhibit undulose extinction. The dolomite phases generally exhibit
dull luminescence except for D3 which exhibits concentric zoning. Microthermometric measurements of the
primary two-phase fluid inclusions in D2 (homogenization temperatures up to ~170oC and salinity up to ~13% eq.
wt% NaCl) and D3 (homogenization temperatures up to ~181oC and salinity estimates up to 20.22 eq. wt% NaCl)
suggest that they formed under relatively deep burial conditions and from hot saline brine. This is supported by
the petrographic evidence and geochemical composition, especially the depleted δ 18O values (–11.1±1.2‰ VPDB)
and low Sr contents (72±8ppm).
Sr composition of the dolomites shows a decreasing trend from oldest (~228ppm-D1) to youngest (72ppm-D3).
Also, the low Sr ( 228 ± 28 ppm) and δ18O(-6.0±0.8‰ VPDB) of D1 suggest that it was likely deposited from a
relatively Sr-poor fluid such as a mixture of seawater and meteoric water while D2 and D3 were precipitated from
diagenetic fluids that were circulated into the heated basin and refluxed back through faults.
In general, the Formation is not pervasively dolomitized compared to its counterpart section on the Port au Port
Peninsula and dolomitization is more concentrated in the zones around the chemostratigraphically and
petrographically delineated lower Boat Harbour disconformity.
Petrographic exams suggest that the dominant porosity type is intercrystalline and associated with D2 while vuggy
porosity is associated with D3. Visual estimates of porosity imply that it varies from <1 to ~8% in an interval of
~3m-thick immediately below the lower Boat Harbour disconformity. Chemostratigraphic correlations with the
equivalent Boat Harbour Formation section in the Isthmus Bay (300 km to South) indicate that porous interval is
associated with fluctuations in sea-level marked by a negative δ13C profile of both sections.
Fluid Evolution in Cambrian-Ordovician Knox Group Reservoirs
Thomas (Marty) Parris1, M.W. Bradley2, D. H. Doctor3, C. Bruner4, K.G. Takacs1, and S. Webb1
1
Kentucky Geological Survey, 228 MMRB, Lexington, KY 40506, mparris@uky.edu
U.S. Geological Survey, Tennessee Water Science Center, Suite 100, 640 Grassmere Park, Nashville, Tennessee
37211
3
U.S. Geological Survey, Eastern Geology and Paleoclimate Science Center, 12201 Sunrise Valley Drive, MS 926A,
Reston, VA 20192
4
Planet Energy, LLC, 9220 Dutchtown Road, Suite 104, Knoxville, TN 37923
2
Archived formation water chemistry data (n~ 930) from Precambrian to Pennsylvanian rocks in the Appalachian
and Illinois Basins of Kentucky were used to reconstruct basin hydrostatigraphy. The analysis shows that deeper
Cambrian-Ordovician waters in the Knox Group were sometimes significantly less saline than what would be
predicted by salinity trends in shallower Silurian and younger reservoirs. The contrast in salinity trends between
younger and older reservoirs suggests the presence of an aerially extensive confining unit in Upper Ordovician
strata that separates fluid populations possibly at the basin scale. Less saline waters in the Knox also suggest
mixing with meteoric waters. The critical question, especially in deeper parts of the basins, is, are these relatively
“young” meteoric waters that infiltrated along structural highs or “old” meteoric waters that penetrated exposure
surfaces during or shortly after Knox deposition? The distinction is also important because the Knox is being
evaluated as a possible carbon sequestration reservoir at depths of -2,500 ft (reference to sea level, SL) and
deeper.
Recent measurements in two wells away from structural highs illustrate efforts to characterize the evolution of
deeper Knox formation water chemistry. The KGS-Blan #1, located in Hancock County, Kentucky approximately 115
miles west of the Cincinnati arch crest, sampled waters from two Knox zones at -3,165 to -3,189 and -4,485 to 4,505 ft (SL) in the Beekmantown Dolomite and Gunter Sandstone, respectively. Salinities equaled 56,775 and
97,192 mg/L, respectively, and, were less than would be predicted for this depth relative to the shallower
Paleozoic salinity trends. Farther south in the Planet Energy-West #1 in Hickman County, Tennessee, Knox waters
sampled from the Chepultepec Dolomite at –1,569 to -2,299 ft (SL) contained 452 mg/L total dissolved solids. The
low salinities are notable given the depth and location 60 miles west-southwest of the center of the Nashville
Dome. In the absence of bedded salts, dilution and evaporation proportionately influence the concentration of
chloride (Cl) and bromide (Br). Their respective concentrations in the West well (Cl= 88 mg/L, Br= 0.3 mg/L) suggest
that marine waters were diluted with meteoric water, whereas those for the Beekmantown (Cl= 41,300 mg/L; Br=
174 mg/L) and Gunter (Cl= 60,700 mg/L; Br= 293 mg/L) in the Blan well suggest evaporated marine waters.
Notwithstanding the apparent different water evolution histories in the two wells, a meteoric influence in both is
suggested by the delta18O and deltaD measurements. Values for the West (delta18O= -6.35 per mil, deltaD= -38.3
per mil) and Blan (delta18O= -5.1 to -5.5 per mil, deltaD= -40 to -41.5 per mil) wells are close to the meteoric water
line. The next important step in our investigation is to address the “young” versus “old” question, by estimating
the age of Knox waters in the West well using tritium and chlorine-36 isotope analyses.
Norfolk Basin Pseudo Well Modeling: Lessons Applicable to Triassic–Jurassic Syn-rift Prospectivity
Paul J. Post1, Stephen L. Palmes1, and MaryAnn L. Malinconico2
1
U.S. Dept. of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico
Region, New Orleans, LA 70123, paul.post@boemre.gov
2
Lafayette College, Easton, PA.
The seismically defined, undrilled Norfolk basin on the Virginia continental shelf is a Triassic–Jurassic(?) rift basin
that formed during Pangea breakup through reactivation of an Iapetus closure structural element.
Using reprocessed time-migrated seismic data, syn-rift lithologies, thicknesses and age from wells in the onshore
Taylorsville rift basin, a 1D geohistory model at a pseudo well location in the Norfolk basin was constructed. At this
location, the thickness of syn-rift sediment deposited and subsequently eroded during Norfolk basin reactivation
was consistent with that calculated for the deepest wells in the Taylorsville basin.
A “base case” model used the present-day post-rift thermal gradient of 1.44°F/100’ and ~9,900’ of syn-rift section
eroded prior to the post-rift sedimentation. Other models used different thermal histories and thicknesses of
missing syn-rift section.
The most geologically reasonable model indicates Triassic-sourced hydrocarbons were expelled primarily prior to
the onset of the post-rift/breakup unconformity and either trapped in units subsequently inverted and eroded, or
lost to paleo surface.
Applying this methodology to other eastern U.S. offshore syn-rift basins suggests that basins with less inversion
and subsequent erosion of Triassic–Jurassic syn-rift may provide valid exploration opportunities.
Central Atlantic Conjugate Margin Development: Paleoreconstructions, Basin Evolution, and Implications for
Hydrocarbon Exploration
Paul J. Post1, Erin T. Elliott1, William G. Dickson2, and Mark E. Odegard3
1
U.S. Dept. of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico
Region, New Orleans, LA 70123, paul.post@boemre.gov
2
Dickson International Geosciences, Houston, TX
3
Grizzly Geosciences, Inc., Missouri City, TX
Paleoreconstructions provide a basis for interpreting the opening history of Central Atlantic and its associated
conjugate basins. They also constrain modeling and understanding known, projected and postulated petroleum
systems along the conjugate margins.
Newly processed, integrated, and enhanced magnetic, gravity and other data at kilometric-scale spatial resolutions
were used for the paleoreconstructions made at five key paleoages, three of which are shown.
“Paired” conjugate margin basins do not appear to have originally been a single basin: a structural/topographic
high seems to have separated them. However, proximity of conjugate margin basins resulted in remarkably similar
stress regimes and depositional environments. Implications of shared geologic history are that when a new play or
source rock is found in one basin, data must be evaluated for its broader regional value in assessing plays and
resources in all the similar basins.
Examples of hydrocarbon prospectivity in conjugate basins and for plays in similar tectonic settings are discussed.
Although hydrocarbon exploration potential is determined by regional scale margin development and conjugate
margin basin setting, local factors; e.g., sediment provenance, kerogen type, source rock geohistory, etc. also have
an influence.
Atlantic OCS Geology and Resource Potential
Paul Post, Erin Elliott, Thierry DeCort, Ralph Klazynski, Elizabeth Klocek, Kun Li, and Thomas Riches
U.S. Dept. of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico
Region, New Orleans, LA 70123, paul.post@boemre.gov
Bureau of Ocean Energy Management, Regulation and Enforcement staff recently completed an inventory of the
potential undiscovered, technically recoverable oil and gas resources in the U.S. Atlantic Outer Continental Shelf
(OCS).
In addition to evaluating the appropriateness of older analogs and plays, modern exploration concepts and key
new learnings from northeast-adjacent offshore Nova Scotia, conjugate northwest Africa and the African
Transform Margin were evaluated and incorporated.
Methodology changes involved less subjective risk assessment methods resulting in “risk binning” and better data
mining of analogs to provide a series of parameters applicable to U.S. Atlantic OCS plays. The results represent the
first systematic petroleum system analysis of the U.S. Atlantic OCS applying industry-standard techniques.
Resources were assessed in nine conceptual plays and one established high-risk play. All play areas are seismically
delineated, and their petroleum system elements and processes clearly identified. Five of the plays contain ~75%
of the estimated resources.
The similarity in early shelf exploration results for the U.S. Central Atlantic Margin and African conjugate margins
may indicate that the best prospectivity exists in deep water areas.
North Carolina Shale Gas: Dan River Basin – Stokes and Rockingham Counties
Jeffrey C. Reid, Kenneth B. Taylor, and James D. Simons
N.C. Geological Survey, 1612 Mail Service Center, Raleigh, 27699-1612, jeff.reid@ncdenr.gov
The Dan River Basin is a ~93-mile-long northeast-trending half-graben Triassic rift basin with a steeply dipping
western border fault in north-central North Carolina (NC) and Virginia. The basin is filled with ~6,600 feet of
Triassic strata that dip at about 30o west toward the border fault. The Triassic are divided into the following three
formations in descending stratigraphic order: (1) Stoneville Formation (red and gray siltstone and shale); (2) Cow
Branch Formation (black shale, with some beds of gray shale, sandstone and very thin coal); and (3) Pine Hall
Formation (gray sandstone and shale).
The Cow Branch Formation (CBF), the source rock in the Dan River Basin, is correlative to the Cumnock Formation
in the Sanford sub-basin, and likely, to organic strata in the Wadesboro sub-basin, Deep River Basin, NC.
The CBF shale was deposited in fresh water, shallow lakes similar to African rift valley lakes in a paleo-equatorial
geographic location. The formation extends across ~65,000 acres in Stokes and Rockingham counties, North
Carolina, and then northeastward into Virginia.
The CBF has been informally divided into lower unnamed- and upper unnamed members. The lower member is
late middle Carnian and is up to 540 feet thick. The upper member is early upper Carnian and is up to 1,050 feet
thick near the state line in a quarry. Reconnaissance organic geochemistry and thermal maturation analyses
indicate that the black shale in the lower member of the Cow Branch Formation is gas-prone, and that total organic
carbon (TOC) average 3.68% from two core holes (n = 43, min. = 0.17, max. = 27.68; std. dev. = 5.15). Sparse
vitrinite reflectance data from these same two drill holes averages 2.07%Ro (n = 4). Additional vitrinite reflectance
and TOC analyses are pending. Sparse TOC data reported in the literature are higher in the southern part of the
basin than in the northern part of the basin. Temperatures in the northern part have been interpreted in the
literature to be higher from either deeper burial or a paleo hotspot.
The Dan River Basin contains systematic fractures that are observable in outcrop, and on regional geologic maps
superimposed on LiDAR data. The primary fractures trend north-west, whereas the conjugate fractures trend
northeast. The Dan River Basin is an untested basin with only three shallow core drill holes in the lower member of
the Cow Branch Formation. No seismic lines are known. The gray shale of upper member of the Cow Branch
Formation is mined for expanded- and lightweight aggregate where 1,500 feet of section are continuously exposed
in a mine quarry. Additional organic geochemical sampling is in progress.
The Davie Basin, located in Davie and Yadkin counties, NC, was once connected to the Dan River Basin. Post
depositional faulting and erosion account for the present configuration of the two basins. The Davie Basin has no
known organic lake facies and is probably very shallow.
Staff have identified several aspects of the North Carolina Oil and Gas Law (adopted in 1945) that should be
reviewed for updating, including horizontal drilling and hydraulic fracturing. Given the current interest in state
shale gas exploration, the North Carolina General Assembly has indicated interest in reviewing the state statutes
for possible legislation.
Silurian “Clinton” Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton
Oil Field, Ohio
Ronald A. Riley1, John Wicks2, and Christopher J. Perry1
1
Ohio Division of Geological Survey, Columbus, OH 43229, ron.riley@dnr.state.oh.us
2
J L Wicks Exploration, Wooster, OH 44691
The Ohio Division of Geological Survey conducted a detailed reservoir characterization of the Silurian “Clinton”
sandstone in the East Canton oil field to evaluate the potential for CO 2-EOR (enhanced oil recovery). This
investigation, in cooperation with private industry, included an 80 ton CO 2 cyclic test (“huff n puff”) in Stark
County. The East Canton oil field has produced approximately 95 million barrels of oil through primary recovery
since 1947 from approximately 3,100 wells within 175,000 acres. With an estimated 1.5 billion barrels of original
oil-in-place, there remains significant “stranded” oil in this nearly depleted but economically promising oil field.
There have been no secondary recovery efforts in this mature field because of the tight, heterogeneous nature of
this reservoir.
Regional stratigraphic cross sections were generated across and surrounding the East Canton oil field and
correlated to full-diameter cores and published reports to establish the regional “Clinton” sequence stratigraphy
and depositional setting. The stratigraphic framework developed by these cross sections established regionally
consistent formation/interval boundaries that were used for construction of regional structure and isopach maps.
Detailed reservoir maps of up to five sandstone units and surrounding impermeable shale units within the
“Clinton” interval were mapped and related to production in a 16 square mile area around the CO 2 cyclic test. The
geologic model was used as input into a reservoir simulation to estimate behavior of reservoir fluids from CO 2
injection.
Heterogeneity in the “Clinton” sandstone is largely controlled by deposition and geometry of tidal/fluvialdominated deltaic deposits. Regionally, the “Clinton” interval has an average gross thickness of 110 feet, and net
sandstone thickness ranges from less than 10 feet in the offshore marine environment and interchannel areas to
over 60 feet in the thicker, tidal/fluvial channel sands. Detailed mapping of these depositional units and fracture
systems is necessary to better understand reservoir compartmentalization, fluid flow, unswept oil and for planning
any future EOR development.
Integrating Depositional Facies and Stratigraphy in Characterizing Hydrothermal Dolomite Reservoirs: Trenton
Group of the Albion-Scipio Trend, Michigan Basin
Marcel R. Robinson and G. Michael Grammer
Michigan Geological Repository for Research and Education Department of Geosciences, Western Michigan
University, Kalamazoo, MI 49008, marcel.r.robinson@wmich.edu
Late Middle Ordovician Trenton-Black River carbonates are prolific hydrocarbon producers in the Michigan Basin,
and the Albion-Scipio trend/Stoney Point Field are considered classic examples of production from hydrothermally
dolomitized intervals. The current reservoir model for these two trends suggests that magnesium-rich
hydrothermal fluids flowed vertically along basement seated wrench faults and developed reservoirs through
emplacement of hydrothermal dolomite (HTD) along the faults. Structural HTD emplacement models address
linear, reservoir scale dolomite distribution coincident with left-lateral en echelon faults, but are inadequate in
modeling tens/hundreds of meter-scale variability in dolomitization laterally away from primary fractures/faults.
Renewed exploration for these reservoirs in the Michigan Basin suggests the need for a better understanding of
the controlling mechanisms and resulting distribution of reservoir HTD laterally away from the main fault-zones.
Recently completed research on the Black River Group has shown that primary depositional facies control the
development of secondary HTD reservoirs laterally from primary fault-zones, with Cruziana-type (Thalassinoides)
burrowed facies within high-frequency (4th order) sequences correlating with higher reservoir quality. These
burrow facies provided higher permeability relative to adjacent depositional facies and afforded pathways for
lateral fluid migration away from main faults, resulting in reservoir quality development away from seismically
resolvable structures.
The primary goal of this investigation is to create a sub-regional depositional model, quantitatively delineate
preferentially dolomitized facies, and to geostatistically model the three-dimensional distribution of reservoir
facies within the Trenton Group of the Albion-Scipio trend area. Subsurface core description, analysis, and wireline log data establish depositional facies, a sequence stratigraphic framework, and reservoir facies when
compared with whole core analysis, well engineering, and production data. Regionally continuous volcanic ash
beds provide markers for construction of temporally constrained depositional facies models, and when combined
with depositional facies analysis and cyclic sedimentation patterns, provide the basis of Trenton group depositional
modeling. Facies relationships and geometrical attributes are further constrained by modern depositional analogs.
Model validity will be tested by direct comparison with recently drilled Albion-Scipio Trend control-well data. The
resulting model aims to improve visualization and understanding of reservoir geometries and distributions to
reduce close step-out dry holes when targeting secondary burrow-facies reservoirs. Methods of identifying,
evaluating, and modeling relationships between depositional and reservoir facies distributions and geometries will
likely provide enhanced insight into controls on HTD reservoir formation mechanisms in the Southern Michigan
Basin, as well as to aid in exploration and reservoir development and management strategies in globally
distributed HTD reservoirs.
Geological Controls on Geological Carbon Storage Capacity, Efficiency, and Security in the Middle Devonian
Sylvania-Bois Blanc Saline Aquifer, Central Lower Michigan, USA
Farsheed Rock1, Katherine Pollard2, and David A. Barnes2
1
Chesapeake Energy, Oklahoma City, OK; farsheed.rock@gmail.com
2
Geosciences/MGRRE, Western Michigan Un., 1903 W. Michigan Ave, Kalamazoo, MI, 49008
The Middle Devonian Sylvania Sandstone is a proven brine reservoir in the Michigan basin, USA. Preliminary study
of the Sylvania by the US DOE-NETL Regional Carbon Sequestration Partnership Program estimated as much as 1.5
to 3.8 billion metric tons (GT) of Geological Carbon Storage (GCS) capacity. The objectives of this study are to
evaluate the geological controls on reservoir properties and more confidently assess regional storage capacity,
efficiency, and security in this lithologically and stratigraphically complex saline aquifer target.
Quantitative petrophysical analysis of the Sylvania–Bois Blanc sequestration system from 355 modern wire-line log
suites and conventional core analysis data from 53 wells indicate saline aquifer reservoir facies are present in a
complex lithofacies assemblage including sandstone, dolomite to dolomitic limestone, chert and tripolotic chert to
cherty carbonates in a southeast to northwest trending “fairway” in central Lower Michigan. Little conventional
core sample material for unequivocal calibration of reservoir properties to wire-line log facies has been available
for this study to date although an important set of samples was recently acquired.
Diverse lithofacies in the Sylvania-Bois Blanc may have been deposited in a SW to NE oriented mixed clastics and
carbonate sabhka to off-shore marine ramp environment. Quartz sand was derived by long shore transport from a
source to the southeast of the present distribution of the Sylvania and Bois Blanc formations in the Michigan basin.
Chert and tripolotic chert are more common in the northwest, while sandstone dominated lithofacies are more
common to the southeast. Dolomitic carbonate and cherty dolomitic carbonate dominate to the east and
northeast in more open marine portions of the basin.
Three, distinctive, end member reservoir facies are identified in the Sylvania-Bois Blanc interval: 1) moderate
porosity - moderate to high permeability sandstone, with good injectivity potential, 2) high porosity – moderate to
high permeability sandy-grainy-sucrosic and dolomitic carbonate with very good injectivity potential, and 3) very
high porosity – generally low to moderate permeability, calcareous to tripolotic chert with low to moderate
injectivity potential but high potential storage efficiency and storage security. Complex stratigraphic and lateral
facies transitions indicate short spatial scale variation in reservoir properties and the presence of internal confining
layers. Depending on assumptions of injectivity and storage efficiency, regional GCS capacity estimates calculated
in this study range from a conservative estimate of 1.85 GT to over 7 GT. Consideration of complex reservoir facies
architecture and distinctive petrophysical properties of prospective reservoir facies could result in higher GCS
capacity estimates and significant enhancement of storage efficiency and security due to enhanced capillary
entrapment in the Sylvania-Bois Blanc zone.
Reservoir Characterization and Facies Architecture of the Chesterian Clore Formation (Upper Mississippian) at
Mumford Hills Field, Southwestern Indiana
Polly Root1, M. Parke2, M. Khadhrawi1, L. Pratt1
1
Indiana University, Department of Geological Sciences, 1001 East Tenth Street, Bloomington, IN 47405
2
Layne Hydro, 320 West Eighth Street, Showers Plaza Suite 201, Bloomington, IN 47404
Chesterian sands are the primary petroleum reservoirs undergoing line-drive water and CO2 injections at Mumford
Hills Field in Southwestern Indiana. Refinement of facies correlation and a new petrophysical model of the Clore
has resulted in improved characterization and understanding of the reservoir. The mixed carbonate-siliciclastic
Clore Formation was deposited along the shallow marine shoreline of the Illinois Basin with fluvial influence from
the ancient Michigan River during the Upper Mississippian. Vertically, the Clore is comprised of three subunits
(basal packstone and wackestone, middle fine to very-fine grained sandstone with interbedded shales, and upper
wackestone and packstone with shaly interbeds), reflecting one of several high-frequency transgressive-regressive
intervals. The central Mount Pleasant Sandstone member is composed of tidally-dominated elongated ribbons
with occasional lenticular channel beds, as observed in outcrops in Southern Illinois and confirmed in wireline log
correlations. Stratigraphic closure is defined by gradual interval thinning and decreased sand content, with sand
pinching out into low-porosity mudstones to the eastern and western edges of the field. Fifteen wells within the
Mumford Hills Field provided wireline geophysical logs (SP, resistivity, and some gamma ray), and core data
(porosity, permeability, water saturation, and oil saturation). Porosity and permeability were measured from
complete core, with values ranging from 3.1-26.6% (average 19.7%) and 0.8-750 mD (average 157 mD). New
geologic and petrophysical models have correlated the subsurface porosity and permeability with depositional
environments to better understand the sand distribution and reservoir quality for the Clore Formation in Indiana.
These petroleum reservoir calculations may provide a more comprehensive inventory for accurate estimations of
CO2 sequestration potential and increased oil production at Mumford Hills.
A High-Resolution Regional Sequence Stratigraphic Framework for the Lower Pennsylvanian Breathitt Group:
Insights from Coal-Bed Methane Fields in the Pocahontas Basin
William A. Rouse1, Ryan P. Grimm2, and Kenneth A. Eriksson3
1
U.S. Geological Survey, Reston, VA 20192, wrouse@usgs.gov
2
Chevron Energy Technology Company, Houston, TX 77002
3
Department of Geosciences, Virginia Polytechnic Institute and State University, Blacksburg, VA 24061
Coal-bed methane development in the central Appalachian Basin during the past decade has generated an
extensive, high-resolution subsurface dataset that can be used to develop a sequence stratigraphic framework for
Pennsylvanian strata. The Lower Pennsylvanian, coal-bearing, siliciclastic strata of the Breathitt Group within the
Pocahontas Basin of southwestern Virginia and southern West Virginia define a southeasterly thickening clastic
wedge deposited in continental to marginal marine environments and influenced by high-frequency, highmagnitude relative sea-level fluctuations and low-frequency changes in tectonic loading. Using over 1600
geophysical wire-line well logs in conjunction with five continuous cores and numerous outcrops, a unified
sequence stratigraphic model was developed based on the interpreted facies architecture, regional flooding
surfaces and bounding discontinuities at both the coal-bed methane field and basin-wide scales.
The Lower Pennsylvanian Breathitt Group displays a stratal architecture interpreted as a back-stepping succession
of four depositional sequences that include more proximal facies at the base and more distal facies at the top. At
the base, the Pocahontas Formation is a dominantly non-marine sequence consisting of incised-valley-fill and
estuarine deposits, with limited preservation of highstand deltaic deposits. The overlying Bottom Creek and Alvy
Creek formations (sequences) include fluvial sandstones deposited in both longitudinal and transverse sediment
dispersal systems, with an upward-increasing proportion of estuarine and deltaic deposits. The Alvy Creek
Formation also includes an abrupt appearance of marine ichnofabrics, a decrease in sandstone to mudstone ratio,
and increases in facies-association rhythmicity and estuarine facies thickness. At the top of the Breathitt Group,
only a partially preserved depositional sequence is present in the Grundy Formation, with facies similar to those in
the Alvy Creek Formation.
The observed stratigraphic architecture can be explained by the interplay of glacioeustatic and tectonic
mechanisms. Glacioeustatic control on stratigraphic architecture is supported by an approximately 80 kyr average
sequence duration, within the short eccentricity period of the Milankovitch band. High-frequency eustatic
sequences are nested within four asymmetric composite sequences, attributed to low-frequency variations in
tectonic accommodation. Evidence for tectonic loading on foreland basin accommodation is based on abrupt
shifts in sandstone facies composition, angular stratal terminations and wedge-shaped composite sequence
geometries.
Major and Minor Element and Radium Geochemistry of Produced Water Samples from the Marcellus Shale in
New York, Pennsylvania, and West Virginia
Rowan, E.L.1, Engle, M.A. 1, Kraemer, T.F. 1, and Kirby, C.S.2
1
U.S. Geological Survey, 12201 Sunrise Valley Dr., Reston, VA 20192, erowan@usgs.gov
2
Bucknell University, Geology Department, Lewisburg, PA 17837
The inorganic geochemistry of produced water from the Marcellus Shale has been compared with analyses of
waters produced from adjacent Devonian strata, including sandstone in the overlying Bradford Group, and the
underlying Onondaga Limestone and Oriskany Sandstone using published data combined with a limited number of
new analyses. Total dissolved solids values in waters produced from the Marcellus are similar to those produced
from adjacent formations, and most commonly range from 100,000 to 300,000 mg/L. The waters produced from
these formations are Na-Ca-Cl dominant, with low bicarbonate and sulfate concentrations. Low sulfate is
consistent with the minimal barite precipitated from the produced waters, but only partially accounts for the high
concentrations of dissolved barium (hundreds to thousands of mg/L), whose solubility remains poorly understood.
Na/Br and Cl/Br ratios indicate mixtures of brines, with a major component of salinity derived from evaporatively
concentrated seawater.
The Marcellus Shale is known to be enriched in uranium, based in part on its high gamma-ray response on
geophysical logs. Radiochemical analyses of produced water from the Marcellus Shale show elevated radium-226,
and lesser amounts of radium-228, the decay products of uranium-238 and thorium-232, respectively, with total
radium activities of 100s to 10,000s of picocuries/liter. Produced waters from the overlying and underlying strata
generally have lower radium activities than the Marcellus. The virtual absence of dissolved uranium in the
produced waters reflects its low solubility in the reducing environments at depth that characterize most oil and gas
reservoirs. Uranium thus remains predominantly as a solid phase while the more soluble element, radium, is
brought to the surface with produced water.
A Regional Perspective of the Devonian Shale and Ordovician Utica Shale Total Petroleum Systems of the
Appalachian Basin
Robert T. Ryder, Michael H. Trippi, Christopher S. Swezey, Robert C. Milici, John E. Repetski, Leslie F. Ruppert, and
Elisabeth L. Rowan
U.S. Geological Survey, Reston, VA 20192, rryder@usgs.gov
The Devonian Shale-Middle and Upper Paleozoic and the Utica-Lower Paleozoic Total Petroleum Systems (TPS) are
the prominent Appalachian basin TPSs defined by the USGS. They have known petroleum volumes (cumulative
production + proved reserves), through 2008, of about 2.6 BBO/59.1 TCFG and 0.9 BBO/10.7 TCFG, respectively. A
mean recoverable undiscovered gas resource of 61.3 TCFG (USGS 2002 assessment) from tight sandstone and
black shale in both TPSs is conservative because it did not account for the full potential of the Devonian Marcellus
Shale and did not include an assessment of the Ordovician Utica Shale.
Plots of known oil and gas accumulations, together with associated Ordovician, Devonian, and Pennsylvanian
conodont CAI and (or) %Ro isograds and restored overburden thicknesses, on regional geologic cross sections
provide several insights regarding the evolution of Appalachian shale-gas TPSs. First, these plots suggest that in
both TPSs oil and gas migrated vertically at least 1,000 ft through relatively impermeable shale and carbonate,
probably facilitated by fractures and faults. For example, oil and gas generated and expelled from the Marcellus
Shale in N.Y., Ohio, Pa., and W.Va. probably migrated vertically through about 1,500 to 4,000 ft of overlying shale
and siltstone into Upper Devonian and Mississippian sandstone. In addition, a short time after vertical migration,
large volumes of Marcellus Shale gas (from cracked oil or kerogen conversion) were expelled a short distance into
underlying Lower Devonian sandstone and migrated either into adjoining anticlines or updip as far as 50 miles.
Furthermore, oil and gas generated and expelled from the Utica Shale in Ohio and Pa. suggest the following
migration patterns: 1) westward across-dip migration for 30 to 80 miles through about 1,000 ft of underlying
Ordovician carbonate rocks before entrapment in Cambrian reservoirs, and 2) vertical migration through about
1,500 ft of overlying Ordovician shale followed by updip migration as far as 50 miles before entrapment in Lower
Silurian sandstone. Commonly, Devonian and Ordovician oils have migrated as much as 50 miles beyond the updip
limit of oil generation. Secondly, the plots may offer clues why gas is the dominant in-place hydrocarbon in the
largely oil-prone (type II kerogen) Marcellus, Ohio, and Utica Shales. Several observations imply that oil migrated
from the shale source rocks into available reservoirs early in the maturation history leaving abundant in-place
mobile gas and immobile oil, such as in the Ohio Shale of Big Sandy gas field, the emerging Marcellus shale-gas
accumulation, and the potential Utica shale-gas (or shale-oil) accumulation. For example, in Ky., oil that was
generated from the Ohio Shale early in the maturation process was expelled a short distance into underlying
karsted Silurian-Devonian “Corniferous” strata and then migrated 30 to 50 miles updip into unconformity traps
prior to major gas generation (from cracked oil or kerogen conversion) that left abundant in-place mobile gas in
the Ohio Shale. Similar events are envisioned for the Marcellus and Utica Shales. In N.Y., Ohio, Pa., and W.Va., oil
that was generated and expelled from the Marcellus Shale migrated vertically into Upper Devonian and
Mississippian sandstone prior to major gas generation that left abundant in-place mobile gas in the Marcellus
Shale. By comparison, oil that was generated and expelled from the Utica Shale migrated westward into traps in
Cambrian dolomite in central Ohio and in Ordovician carbonates in the Lima-Indiana field in northwestern Ohio
prior to gas generation that left abundant in-place mobile gas in the Utica Shale.
Enhanced Gas Recovery and CO2 Storage in Coal Bed Methane Reservoirs: Optimized Injected Gas Composition
for Mature Basins of Various Coal Rank
Karine Schepers1, Anne Oudinot1, Nino Ripepi2
1
Advanced Resources International, Inc., 11490 Westheimer Rd, Suite 520, Houston, TX 77077
2
Virginia Center for Coal and Energy Research, Virginia Tech., Blacksburg, VA 24061
Nitrogen (N2) and carbon dioxide (CO2) injection has been a subject of enhanced coal bed methane (ECBM) and
carbon capture and storage (CCS) research during the past decade. N 2 and CO2 injection produce substantially
different recovery processes. Coal has a higher affinity for CO2 as compared to methane (CH4), making it an ideal
candidate for CCS and address environment issues related to green house gas emissions. However, preferential
adsorption of CO2, a larger molecule than CH4, onto the coal surface results in a dramatic decrease in cleat
permeability due to coal swelling. This ultimately induces a loss of injectivity creating a significant technical hurdle
for CCS operations in coal. In contrast, N2 increases cleat permeability because of its lower coal storage capacity
relative to CH4. As a result, injectivity increases during N2-ECBM. Theoretically, the injection of a mixture of CO 2
and N2 will result in ECBM and CCS without a loss of injectivity. This study presents an investigation of that
concept.
Based on the lessons learned from several actual large-scale and small-scale field demonstrations to date, this
paper will focus on the improvement of CO2 sequestration and associated ECBM by optimization of gas
composition and injection designs for different coal ranks. To characterize resources and identify key geological
and reservoir parameters driving ECBM and sequestration processes in deep unminable coal seams, a Monte Carlo
probabilistic approach was implemented for coal seams of different rank. To perform the study, a matrix of
simulation scenarios consisting of multiple coal types (taken from mature coal basins such as San Juan, Warrior,
Central Appalachian and Powder River), permeability values, pattern sizes and injected gas mixtures (from 100%
CO2 to 100% N2,) was established. First results show that, for a specific coal rank, ECBM and CCS can drastically
improve by increasing N2 content in the injected gas stream.
Sequence Stratigraphy, Reservoir Properties and Preservation of Organic Carbon in the Middle Devonian
Marcellus Shale
Roy L. Sexton and Timothy R. Carr, Department of Geology and Geography, West Virginia University, Morgantown,
WV, 26506, rsexton2@mix.wvu.edu
The Marcellus Shale of the central Appalachian basin is emerging as an important unconventional resource play
with approximate aerial extents of 34,000,000 acres and gas in place estimates as high as 500 trillion cubic feet.
The Marcellus has long been considered a probable petroleum source rock for Upper Devonian reservoirs.
However, advances in drilling and completion technology including horizontal drilling and hydraulic fracturing have
made economic production of gas from the Marcellus possible.
Despite increased exploration and production of the Marcellus there is still much that is not understood about the
depositional environment and the distribution and preservation methods of organic material within the formation.
New interpretations are beginning to challenge traditional views on organic-rich shale deposition such as water
depth, water column stratification, importance of organic production vs. preservation, presence of anoxic and
euxinic conditions, and permanent pycnocline vs. seasonal mixing. Additionally, there is a lack of understanding of
the relationship between these factors and the sequence stratigraphic framework of individual units.
This study is intended to investigate the influencing geologic parameters under which the Marcellus Shale
accumulated over a portion of the Appalachian basin, specifically, northern West Virginia and southwestern
Pennsylvania. The study incorporates characterization of the sedimentology of the cored Hamilton Group sections
including pyrite framboid size and distribution, sedimentary structures, and microfossil assemblages. This is
accompanied by geochemical analysis including identification of trace elements, programmed pyrolosis, x-ray
diffraction, degree of pyritization, total organic carbon, carbon and sulfur isotope concentrations, and redox
indicators such as manganese, vanadium, chromium, and molybdenum. This data has been placed into a sequence
stratigraphic framework of the Marcellus Shale in order to determine relationships between individual sequences
and bottom water chemistry, the distribution and preservation methods of organic material during sediment
deposition, depositional environments, and relationships between core and well logs.
Mineralogical, Microtextural and Geochemical Analysis of Subsurface Rocks in Southwestern, Southern, and
Eastern Ohio: Initial Observations for Evaluating the Suitability of Materials for Sequestering Carbon
Julia M. Sheets1, Susan A.Welch1, David R. Cole1, Jeffrey D. Daniels1, Beverly Z. Saylor2, and Michael V. Murphy1
1
School of Earth Sciences, Ohio State University, 125 S. Oval Mall, Columbus, OH 43210, sheets.2@osu.edu
Department of Geological Sciences, Case Western Reserve University, Cleveland, OH 44106
2
In order to determine the feasibility of sequestering CO 2 in the subsurface, it is important to evaluate the
suitability of rock formations for CO2 storage. Rock samples were collected from the target interval (sandstone)
and the over lying caprock of cores from Warren County, Aristech and Coshocton wells in Ohio, to evaluate their
potential for both storage (pore space, connectivity and hydraulic conductivity) and long-term geochemical
sequestration (chemical and mineralogical reactivity) of CO 2 in the subsurface. The sedimentary rocks samples are
characterized using light and scanning electron microscopy, and powder x-ray diffraction. Mineral phase
identification is facilitated by combining light and back-scattered electron imaging techniques with energy
dispersive x-ray analyses. The samples show extreme heterogeneity in geochemistry, mineralogy, and texture over
sub-millimeter to meter scale.
Two-dimensional porosity of core samples are estimated using image processing techniques applied to lowmagnification backscattered electron (BSE) images acquired from polished thin sections. Average atomic number
contrast as revealed in BSE images is used to quantify the proportions of void spaces and mineral phases present in
the specimens. One goal of this analysis is to predict the storage capacity, from a hydraulic standpoint, of specific
rock units for injected CO2-rich fluids, based on estimates of porosity and permeability. Another goal is to assess
the potential reactivity of mineral phases for long-term geochemical storage in the form of new minerals formed,
the potential for dissolution of existing minerals, or both.
In specimens sampled from a continuously-cored hole in Warren County, Ohio, the lithology of the Eau Claire
Formation includes calcareous sandstones with interbedded siltstones and shales. Within a single thin section of
the Eau Claire Formation from the Warren County core, zones rich in quartz, feldspar and intergranular glauconite
contrast with zones rich in dolomite and fine grained glauconite. Trace mineral phases of zircon, rutile, pyrite, and
apatite have also been observed. The underlying sandstone is comprised primarily of quartz, potassium feldspar, as
well as Na-rich plagioclase. Additionally, the sandstone contains regions rich in clays and iron oxide cement. These
results indicate that mineral reactivity might be important in both the caprock and sandstone.
Potential for Supercritical Carbon Sequestration in the Offshore Bedrock Formations of the Baltimore Canyon
Trough
Brian Slater, Langhorne Smith, and Alexa Stolorow
New York State Museum, Albany, NY 12230, bslater@mail.nysed.gov
Although geologists continue to find terrestrial rock formations that have the capacity to hold moderate amounts
of carbon dioxide, the greatest potential for carbon sequestration in North Eastern United States lies in the
offshore geologic formations that make up the continental shelf.
The Baltimore Canyon Trough is a portion of the continental shelf which lies approximately 100 miles south of Long
Island and over 50 miles southeast of New Jersey. It is over 7,500 square miles in size and consists of Mesozoic and
Cenozoic limestones, dolomites, sandstones, and shales. This area has been explored by a number of oil and gas
companies as well as the Continental Offshore Stratigraphic Test (COST), the Offshore Drilling Project (ODP), and
the Deep Sea Drilling Project (DSDP). A large amount of data including wireline logs, cores, and seismic surveys has
been collected and much of it is available for additional study. Previous work indicates that there are several
sandstone beds in this region having porosities greater than 25% and permeabilities over 100 md. This suggests an
extremely large capacity for potential storage of supercritical CO2.
Offshore sequestration also avoids the issues associated with individual landowers’ mineral rights and public
concerns over leaks or drinking water contamination. Offshore sequestration also offers the benefit of additional
trapping mechanisms such as density inversion and formation of hydrates.
Structural Framework of the Appalachian Plateau of Central West Virginia
Elise Swan1, Jaime Toro1, and Pete Sullivan2
West Virginia University, Morgantown, WV 26501, eswan1@mix.wvu.edu
2
Energy Corporation of America, 501 56th Street S. E. Charleston, WV 2530
1
The Appalachian basin has attracted great interest recently due to the hydrocarbon potential from the Marcellus
Shale. 2D seismic data have brought new insights to areas, particularly Webster County, WV, that were once
considered low potential due to the lack of knowledge of the deep structures in this region. It has been previously
thought that no faults were likely to exist due to the gentle dip of surficial Pennsylvanian and Mississippian units
observed in the field.
The seismic data demonstrates Pennsylvanian to Devonian age fore and back thrusts that seem to project to the
surface. This stratum overlies Ordovician to Cambrian age extensional faulting. The locations of these structures
are much farther away from the structural front than what was once thought likely. Kinematic modeling
demonstrates the deformation process of this region of the plateau at different stages. This allows for a
reinterpretation of structures. These faults may have the potential to produce small fractures and offsets within
the Marcellus Shale that will likely affect well locations and production potential. Therefore, understanding these
deep structures and how they affect shallow structures is essential to geologist working in this region.
The fore and back thrusts may be observed in the Mauch Chunk and Greenbrier Groups through 30 gas well and
200 shallow coal well correlations. Curvature maps of the shallow surface illustrate locations of discontinuities.
This increases the resolution of the structural maps generated through seismic at depths where the data is noisy.
LIDAR data visualizes the effect that the faults play on the immediate surface (for example, controlling location of
stream valleys) while removing other trees and brush that make it impossible to map small faults penetrating the
surface in the field. The combination of this new data improves the resolution of present maps along with the
understanding of the structural framework of the Appalachian Plateau of central West Virginia.
Occurrence of Uranium in Organic-Rich Black Mudstones of the Early Mesozoic Newark Basin in New Jersey and
Evidence of Secondary Enrichment Processes
Zoltan Szabo
U.S. Geological Survey, W.Trenton, NJ 08628, zszabo@usgs.gov
The nature of uranium (U) occurrence in black shales and the fate of the U when in contact with water are
important issues when developing water or energy resources from black shales. Organic-rich black mudstones of
the Mesozoic Basin in New Jersey are important aquifers locally, and on occasion waters from wells penetrating
these formations have been noted to contain U and radium-226 (Ra-226) in concentrations above drinking water
standards. Analysis of the most radioactive core samples from some of the affected wells for uranium (and
progeny of its decay series, which includes Ra-226) using gamma-ray spectrometry indicated the maximum
concentration of uranium in the mudstone was about 1700 ppm (parts per million), though more typical values
were on the order of 100 ppm. Thorium (Th) and progeny are a possible source of alpha particles as well, but the
concentration of Th were typically about 15 to 20 ppm, or about 20 percent that for U in the radioactive zones.
Alpha-autoradiographs were generated to investigate the sources of U (or other alpha-emitting radionuclides) in
core samples of organic- and U-rich black mudstone. Scanning electron microscopy (SEM) and energy dispersive xray (EDX) allowed for mapping of the occurrence of U at specific points within thin sections. The bulk organic-rich
fine-grained rocks contained abundant but dispersed U that likely is not readily mobilized to water resources
where the rock is not fractured. The dispersed nature of the U, the presence of abundant dark organic matter, and
the fine grain size made it difficult to pinpoint U sources using solely the alpha-autoradiograph and SEM/EDX
images. Many modes of U enrichment relative to the general dispersed U already present in the organic-rich fine
silts were noted and appear to be associated with diagenetic fluid mobility in zones of higher permeability (coarse
silt and fine sand layers) or within fractures. U-bearing minerals were concentrated along pressure solution fronts,
in silty or sandy zones of intense carbonate- and sulfide-mineral cementation and mineralization, and within
mineralization zones in fractures. In some fractures, multiple zones of mineralization are likely resultant from the
extensional tectonics experienced within the Mesozoic Basins. An association of alpharadioactivity (U, and
presumably Ra-226) with secondary iron minerals, typically classified as chlorite, in minimally weathered silty and
sandy samples was also noted. These minerals were, in places, weathered to iron-oxides, which coated partly
intact grains with an orange weathering rind; the weathering of these minerals was likely also a source of iron
oxide for grain and fracture coatings. The association of alpha-particle radioactivity with the iron in oxide form
remained strong. These images show zones of secondary enrichment of U in the fine-grained rock, and also show
changes in radionuclide distribution in the rock at successive stages of weathering, in particular, concentration of
alpha-emitting radionuclides on fracture faces. While it may be generally presumed that U concentration are
somewhat enriched in carbon-rich fine-grained sedimentary deposits relative to typical sedimentary deposits, the
modes of U occurrence and enrichment were variable even within this single setting. Thus, modes of U occurrence
can be expected to vary within each unique depositional basin setting on the basis of local depositional, tectonic,
diagenetic, and weathering history. Observations compiled from any one black shale deposit may serve as broad
guidance (analogue) to the possible modes of U occurrence and preferential enrichment in black shales in other
basins. Detailed studies of specific modes of U occurrence, enrichment, and potential pathways to mobility need to
be conducted from sediment from the portions of the specific basins where water and (or) energy resources are
extracted.
Effective Fracture Treatment Determination in Unconventional Reservoirs
Charles H Smith and Eli Menendez
Halliburton, 210 Park Avenue, Suite 200, Oklahoma City, OK 73102, charlie.smith@halliburton.com
Many unknowns are still involved in the production techniques and completion procedures for many
unconventional reservoirs. The single issue that seems to be the determining factor in production is surface area
created by fracture treatment technique. The data and analysis techniques used in the horizontal well need to be
focused to provide the best design parameters for this fracture treatment.
Typical unconventional reservoirs have internal complexities that are not apparent in other reservoirs. As in other
rock conditions, contrasts occur at bed boundaries, but other contrasts occur within the rock itself. These contrasts
are commonly observed as minor fracture sets and minute horizontal bedding contrasts. Either or both of these
conditions can have a significant impact on the effectiveness of the fracture treatment and may even impede the
progression of the designed treatment. A technique is needed that will adequately describe these contrasts and
predict their effect on the fracture treatment design.
Recent work with dipole sonic logs has demonstrated the ability of the log to resolve rock mechanical properties in
the traditional vertical direction along with these same properties in the horizontal dimension. This vertical and
horizontal resolution is acquired in a pilot hole and used for landing horizon definition. The same data is used to
establish expectations of fracture treatment behavior from the initiation in a horizontal wellbore. The dipole sonic
can also establish rock mechanical properties throughout the length of the horizontal section. This combined
information allows the most efficient completion for the well.
This paper demonstrates the application of these techniques to establish the best landing point for the horizontal
well and design the fracture treatment to overcome potential problems. There are specific examples of how this
technique was applied. The ability of the fracture to maintain its shape and size is maximized through this process,
thus maximizing the reservoir surface area exposed by the treatment.
Impact of Syndepositional Faulting on the Distribution of Organic-Rich Utica Shale, New York State
Langhorne Smith
New York State Geological Survey, Room 3140 CEC, Albany, NY 12230, lsmith@mail.nysed.gov
The Utica Shale is a potential drilling target in eastern North America and Canada. Total thickness of the organicrich strata ranges from zero in the west to as much as 1300 feet in the east with common TOC values of up 3.5%.
The Utica Shale was deposited during the Late Ordovician Taconic Orogeny. Thrust loading to the east led to
significant syndepositional extensional faulting in the foreland basin to the west. These faults have a major control
on the distribution and thickness of organic-rich mudrock in the Utica.
The Ordovician Utica Shale consists of a lower organic-rich calcareous shale overlain by an organic-rich shale with
low carbonate content and gray shale. The lower calcareous shale is called the Flat Creek Formation – it overlies
an unconformity and interfingers with the Trenton Limestone to the west. A major down- to the east fault system
(one part of which is called the Hoffman’s fault) was actively moving during Flat Creek time. The organic-rich shale
of the Flat Creek developed in relatively shallow water on the upthrown western side of the extensional fault
system while organic-poor gray shales and turbidites were deposited in deeper water to the east on the
downthrown side of the fault system. This fault system, which has hundreds of meters of throw, was critical to the
development of the organic-rich shales as it served as a barrier to westward flow of clay, silt and sand that would
otherwise have moved farther to the west, diluting the organic-rich Flat Creek significantly. This fault system likely
continued to move and serve as a barrier to westward siliciclastic progradation during deposition of the overlying
Dolgeville and Lower Indian Castle intervals. There may have been other more subtle extensional faults moving
farther to the west that controlled thickness trends in the Flat Creek Shale.
The Flat Creek is overlain in many places by the Dolgeville Formation which consists of rhythmic cm-scale beds of
organic-poor limestone and organic-rich shale. The Trenton and Dolgeville are capped by a widespread
disconformity with up to 3 million years missing in the west called the Thruway Disconformity that can be traced
laterally into a correlative conformity to the east. This disconformity is overlain by an organic-rich black shale that
thickens into grabens that were actively forming during deposition. There is a well-described graben in the outcrop
belt near Little Falls, NY that can be traced into the subsurface. Within the graben the organic-rich Lower Indian
Castle Formation thickens by more than 150 meters (~500 feet). Despite the higher rate of subsidence in the
graben, thickness trends suggest that the graben stayed close to full and water depths were not much deeper than
they were on the surrounding highs during deposition.
The Upper Indian Castle is an organic-poor gray shale and it may have been deposited just as the extensional
faulting ended. The termination of movement on the Hoffman’s fault may have enabled more clay, silt and sand to
migrate farther to the west.
Upper Ordovician Trenton and Black River Carbonate Reservoirs in New York State
Langhorne Smith
New York State Geological Survey, Room 3140 CEC, Albany NY, 12230, lsmith@mail.nysed.gov
The Ordovician Trenton and Black River carbonates have produced significant quantities of gas in New York State.
The Trenton Limestone immediately overlies the Black River, but the style of reservoir is very different. The Black
River has produced gas from hydrothermal dolomite reservoirs in an area south and west of the Finger Lakes while
the Trenton has produced gas from overpressured organic-rich shale interbeds in an area to the west and
southwest of Lake Ontario.
Black River hydrothermal dolomite reservoirs of New York formed when hydrothermal fluids (100-170 C) flowed
up active transtensional faults and dolomitized the formations within the first 500 meters of burial. The reservoirs
produce from unconventional traps that are structurally low en echelon grabens or “sags.” These en echelon sags
are negative flower structures associated with an underlying transtensional fault. Not all of the dolomitized sags
are gas-bearing. In an area to the north and east of the producing area, several wells have been drilled that
produced primarily water from these features. It may be that the gas is sourced from the aforementioned organicrich shale beds in the Trenton Limestone or from the overlying Utica Shale and that the reservoirs only get charged
when faults die out in the Utica and do not extend upward into potential reservoirs in the Queenston, Herkimer or
Oneida Formations or higher.
Gas has been produced from the overlying Trenton Limestone near Lake Ontario for more than 120 years. The gas
mainly comes from intervals that consist of interbedded organic-rich shale and limestone. Gas encountered during
drilling of these wells is commonly highly overpressured but rates typically fall dramatically to a few mcf per day
after a few hours or days. Our interpretation of the reservoir is that the gas is stored in horizontal bedding planes
that are propped open by the high-pressure of the gas. The near lithostatic pressures encountered during drilling
suggest that the gas may be hydraulically lifting the overburden. During drilling the gas flows at near lithostatic
pressure out of the horizontal partings until they close, thereby dropping the rate of production from millions of
cubic feet per day to a few thousand cubic feet per day. The gas may be self sourced from very thin organic rich
shale beds interbedded with the limestones.
The likely limits of the overpressured play are the 2500 or 3000 foot burial depth contour to the south, the
pinchout of the capping Steuben Limestone to the east, the outcrop belt to the north and the likely pinchout of
organic rich shale interbeds to the west. At a depth of 2500-3000 feet, the principal compressive stress changes
from horizontal to vertical and the bedding planes are no longer likely to be open. There may be greater potential
in the Trenton limestone where there are abundant vertical natural fractures or possibly if the formation is
subjected to large scale frac jobs like those being performed on shale gas reservoirs.
Vertical and Lateral Extent and TOC Content of Middle and Upper Devonian Organic-Rich Shales, New York State
Langhorne Smith and James Leone
New York State Museum, Room 3140 CEC Albany, NY 12230, lsmith@mail.nysed.gov
While most of the focus is on the Middle Devonian Marcellus Shale, there are numerous other organic-rich shales
in the Middle and Upper Devonian strata of New York State that might also produce gas or liquids. The purpose of
this presentation is to show in-house TOC and calcite content data, maps and cross sections of Middle and Upper
Devonian black shales in New York. These organic-rich shales include from oldest to youngest the Marcellus,
Levanna, Ledyard, Geneseo, Renwick, Middlesex, Rhinestreet, Dunkirk and Pipe Creek Shales. TOC and calcite
content measured from well cuttings will be presented along with wireline logs in the cross sections and maps of
the thickness of each organic-rich shale. All of the shales grade from thicker, organic-poor gray shales in the east
to progressively thinner and more TOC-enriched to the west. The organic rich shales commonly interbedded with
limestones while the gray, organic-poor shales are commonly interbedded with siltstone and sandstone. Most of
the organic-rich shale bearing strata appear to onlap and pinch out on unconformities to the west. The cross
sections help to develop a depositional model for the organic-rich shales that shows them forming in relatively
shallow water on the present-day western or cratonward side of the basin.
The stratigraphy is quite complex as time equivalent units grade from gray shale and siltstone to organic rich shale
and limestone and unconformities develop, especially in the west. Attempts will be made to unravel some of the
stratigraphic complexity and establish chronostratigprahic relationships. One particularly interesting interval
occurs in the far western counties where more there is an unnamed limestone unit that only occurs in the
subsurface that has mistakenly been called the Tully by previous workers. The cross sections will show that this
limestone appears to be part Tichenor and Menteth Limestones which are older than the Tully Limestone and part
Genundewa Limestone which is younger than the Tully. The Tully is represented by an unconformity in the middle
of the limestone unit. This is important as the rest of the stratigraphy makes more sense when this limestone unit
is picked correctly.
Development of a Pennsylvanian Fan Delta Within a Carbonate Shelf Sea
Richard Smosna and Kathy R. Bruner
West Virginia University, Morgantown, West Virginia 26506, rsmosna@wvu.edu
The Pennsylvanian Gamonedo Formation in northern Spain contains an unusual association of facies: limestones
and conglomerates. The limestones include grainstone, packstone, and mudstone, and fossil abundance and
diversity are everywhere high. Crinoids, fusulinids and other foraminifera, brachiopods, rugose corals, ramose
bryozoans, gastropods, ostracodes, scaphopods, phylloid algae, and oncolites are plentiful. Deposition occurred as
aggrading shoals of lime sand on a nearshore shelf. Water depth fluctuated from below wave base where mud
accumulated with the fossil grains (argillaceous skeletal packstone) to above wave base where fossil grains mixed
with quartz sand and limestone extraclasts (sandy skeletal grainstone). Lime mudstone formed in a tidal-flat
environment wherever deposition raised the sediment surface to sea level. In addition, dozens of thick interbeds
of limestone conglomerate occur in the Gamonedo Formation. Clasts consist mostly of limestone rock fragments
plus smaller quantities of sandstone rock fragments, quartz and chert grains, and large bioclasts. The source area
comprised older Pennsylvanian limestone formations in a newly raised tectonic highland along the basin margin.
Conglomerate beds are frequently graded (normal, inverse-to-normal, or inverse), and the texture may be matrixor clast-supported. They formed as sediment-gravity flows on a marginal-marine fan delta when hyperpycnal
flows transported the gravel through channels incised into the carbonate shelf. Vertical changes in grain size
reflect on the timing and nature of tectonic activity. The cumulative thickness of limestone conglomerates is
greatest in eastern outcrops, which suggests that most of the coarse sediment was carried along the eastern
margin of the fan delta. From east to west, however, these sediment-gravity flows exhibit a subtle facies change—
from debris flow to turbidity current to grain flow—hinting that the fan-delta’s surface became flatter in that
direction. The cumulative thickness of fossiliferous limestones is greatest in western outcrops. The western fan
delta was less frequently disturbed by sediment-gravity flows, and after the passing of each flow, the carbonate
environment reestablished itself. Where not overwhelmed by tectonically driven sediment, the western
limestones exhibit a meter-scale cyclicity attributed to small-scale fluctuations of relative sea level.
Applied Energy Mapping at the Ohio Geological Survey
Michael P. Solis, Matthew S. Erenpreiss, and Timothy E. Leftwich
Ohio Department of Natural Resources, Division of Geological Survey, 2045 Morse Rd., Bldg. C, Columbus, OH
43229, michael.solis@dnr.state.oh.us
The Ohio Geological Survey is currently engaged in a number of projects to appraise Ohio’s geologic resources as
they apply to developing shale oil and gas, storing CO 2, and geothermal potential. This research is being conducted
with funding, in part, provided to address specific project objectives for the Ohio Coal Development Office (OCDO),
the Midwest Regional Carbon Sequestration Partnership (MRCSP) funded by the U.S. Department of Energy, and
the National Geothermal Data System (NGDS), a project funded by the U.S. Department of Energy.
New regional and state-wide isopach maps were developed for the Middle Devonian Marcellus Shale for use in
assessing Ohio’s shale gas potential. Existing stratigraphic analyses of the Devonian shale in Ohio were used as the
starting dataset. The dataset was expanded with additional geophysical logs that span the Marcellus Shale in each
county and township, where available. This allowed for an even distribution of control points. The Hamilton Group,
Marcellus Shale, and Onondaga Limestone tops were picked using USGS cross sections for reference. With this new
information and observing the Marcellus Shale’s upper and lower units, net organic thickness was calculated and
contoured. Data was also collected from the State Geological Surveys of New York, Pennsylvania, and West Virginia
to create a new regional Marcellus organic thickness map.
The initial goal for the OCDO project is to evaluate geologic conditions favorable for CO 2 storage in eastern Ohio.
This includes detailed mapping of potential CO2 sinks by creating a robust well dataset for analysis. Middle
Devonian through Middle Silurian drillers’ elevations are quickly assessed by comparing them to existing formation
tops interpreted by staff geologists for previous mapping projects. The drillers’ picks are co-kriged with existing
formation tops to create new maps with much denser well control. These new state-wide maps are then merged
with existing MRCSP data to update the regionallevel maps. New structure contour maps have been generated for
top of: Onondaga Limestone, Oriskany Sandstone, Bass Islands Dolomite, and Keefer Sandstone. As part of the
continual refinement of MRCSP maps, the Precambrian surface map was also updated using more detailed
contours provided by Kentucky and Ohio.
CO2 storage potential is temperature dependent and, globally, geothermal resources are being developed with the
aid of new technologies that produce electricity and space heat from relatively lower-temperature (≈ 100 °C) rocks,
such as those penetrated by some deep Appalachian Basin oil and gas wells. Electricity production has been
possible in conjunction with producing oil and gas wells and from coproduction associated with secondary and
enhanced oil-and-gas recovery. New techniques allow for space heating and electrical coproduction using injection
fluids, such as brine or CO2, that are usually considered waste products in the energy production cycle. The Ohio
Geological Survey began research into the state’s geothermal resources in July 2010—as part of a 47-state
coalition to develop a new NGDS—and is evaluating its very large dataset of bottom-hole temperatures (BHT) and
the AAPG corrected BHT dataset. Specifically, selected bottom-hole temperature data was corrected and used with
the AAPG dataset to construct BHT and gradient 3-D plots and maps in order to help evaluate the regional,
subsurface geothermal environment.
Strontium Isotopic Signatures of Flowback and Co-Produced Waters Associated with Marcellus Shale
Natural Gas Extraction, Pennsylvania
Brian W. Stewart1,2, Elizabeth C. Chapman1,2, Rosemary C. Capo1,2, Richard W. Hammack1, Karl T. Schroeder1,
and Harry Edenborn1
1US DOE-National Energy Technology Laboratory, 626 Cochrans Mill Rd., Pittsburgh, PA 15236
2University of Pittsburgh, Department of Geology & Planetary Science, Pittsburgh, PA 15260,
stewart@pitt.edu
A byproduct of natural gas extraction from shales of the Middle Devonian Marcellus Formation is flowback
and co-produced water from hydraulic fracturing, often with high levels of total dissolved solids (TDS) that
present a major challenge to gas producers and regulators (Blauch et al, 2009, SPE 125740). Determining the
source of these dissolved salts, whether from the shale itself or associated saline aquifers, and understanding
local and basinal variations in TDS have direct relevance to exploration methodologies and water
management and reclamation. Another important concern involves verification of the safe and
environmentally benign disposal of this high-TDS water; any increase in TDS of ground or surface waters can
potentially be attributed to Marcellus flowback leakage or improper disposal. We have initiated a strontium
(Sr) isotope study of Marcellus flowback and co-produced waters to (1) determine the source of dissolved
salts that are abundant and ubiquitous in Marcellus waters; and (2) identify unique isotope “fingerprints” of
Marcellus waters to aid in verification of safe disposal.
In order for the isotope ratio of strontium to be used successfully as a natural tracer in ground and surface
waters, the isotope ratios (87Sr/86Sr) of the potential endmembers must be distinct. Our previous work on
flowback from a series of wells in Bradford County, northern Pennsylvania, demonstrated a tight clustering of
87Sr/86Sr ratios from 0.7103 to 0.7108 (Chapman et al., 2011, NE-NC Sect. GSA Abstr. Prog 43 no.1:76).
Additional work has expanded the geographic range to southwestern Pennsylvania. Flowback and coproduced samples from the southwestern-most counties (Greene and Washington) expand the range of
values slightly to 0.7101-0.7111, while a subset from adjacent Westmoreland County cluster at distinctly
higher values (0.7120-0.7121). Other fossil-fuel-related fluids that could introduce dissolved solids into
streams include coal mine drainage, coal fly ash disposal ponds, and brines from shallow abandoned gas wells
that are common throughout the Marcellus exploration area, such as those that tap upper Devonian Venango
Group. Strontium isotope data from these sources over a wide geographic and stratigraphic range indicate
that most are isotopically distinct from Marcellus waters, and that influxes from these sources at any given
location tend to fall within a fairly restricted range. These data, when combined with the extreme
concentrations of Sr in flowback waters (up to 5,000 mg/L), demonstrate that the Sr isotope ratio is likely to
be an extremely sensitive tracer that can be used for verification of safe flowback water disposal.
The 87Sr/86Sr ratios of Marcellus waters measured here fall well above Phanerozoic seawater values (Burke et
al., 1982, Geology 10:516-519). Thus, while the Marcellus brines may have a significant seawater component,
this has clearly been augmented by a more radiogenic source, possibly originating from dissolution of
minerals within the shale itself. The bimodal clustering of flowback values so far identified in this study could
be a result of gas (and water) production from different members of the Marcellus Formation. Ongoing
leaching studies of Hamilton group core material is addressing the detailed origins of the high TDS in
flowback and co-produced waters and have potential application to exploration methodologies as well as
reduction of environmental risks.
Update on Mt. Simon Geologic Characterization Activities Associated with the FutureGen 2.0 Carbon
Sequestration Project in Illinois
E. Charlotte Sullivan and Tyler J. Gilmore
Battelle Pacific Northwest Division, 902 Battelle Blvd, Richland WA 99354 charlotte.sullivan@pnl.gov
Carbon capture and storage (CCS) offers the potential to greatly reduce carbon dioxide emissions associated with
power plants, cement plants, refineries, and other stationary industrial sources through containment in deep
geologic formations. The primary objective of the FutureGen 2.0 project is to demonstrate carbon capture and
secure storage technologies on a commercial scale, using CO2 from a power plant in Meredosia, Illinois. Upgrading
of the power plant with advanced oxy-combustion technology will allow the capture of its CO 2, which will be
transported by conventional CO2 pipeline to the storage site, which is expected to receive final approval by 2012.
Storage will be in the Mt. Simon Formation, a regionally widespread, heterogeneous Cambrian sandstone that
contains non-potable brines.
Proposed sites in four counties (Christian, Douglas, Fayette, and Morgan) were down-selected in January, 2011 and
approximately forty miles of new 2D seismic lines were shot along state and county roads to facilitate first order
evaluation of reservoir and seal thickness and structural integrity at those sites. Three of these sites are now the
subject of intensive surface and subsurface characterization to support an environmental impact statement (EIS)
conducted by DOE in compliance with the National Environmental Policy Act (NEPA). The candidate ultimately
selected for CO2 storage will be fully permitted by the Illinois Environmental Protection Agency to assure its safety
and to provide the opportunity for community input. The final site will include a visitors’ center as well as research
and training facilities in support of its mission.
The first potential site to be tested with a characterization well is in Morgan County, proximal to the Devonian
Sangamon Arch. Two-D seismic imaging integrated with regional subsurface data indicates that the Mt. Simon at
the Morgan County site is likely to be at a depth of approximately 4000 feet; with a thickness between 800 and
1000 feet thick. The Eau Clair Formation, which consists of low permeability shales, limestones and siliciclastics and
is a regional seal for natural gas storage fields, is expected to be approximately 500 feet thick, similar to observed
thicknesses at the Waverly field, 12 miles southeast of the Morgan Site. The Maquoketa and New Albany shales
form secondary seals at all of the proposed sites, and the Ironton/ Galesville and St. Peter form potential
monitoring zones. This presentation summarizes the drilling and other characterization activities to date, along
with comments on features in the newly acquired seismic data.
Structural Framework of the Appalachian Plateau of Central West Virginia
Elise Swan1, Jaime Toro1, Pete Sullivan2
1
West Virginia University, Morgantown, WV 26501, eswan1@mix.wvu.edu
2
Energy Corporation of America, 501 56th Street S. E. Charleston, WV 2530
The Appalachian basin has attracted great interest recently due to the hydrocarbon potential from the Marcellus
Shale. 2D seismic data have brought new insights to areas, particularly Webster County, WV, that were once
considered low potential due to the lack of knowledge of the deep structures in this region. It has been previously
thought that no faults were likely to exist due to the gentle dip of surficial Pennsylvanian and Mississippian units
observed in the field.
The seismic data demonstrates Pennsylvanian to Devonian age fore and back thrusts that seem to project to the
surface. This stratum overlies Ordovician to Cambrian age extensional faulting. The locations of these structures
are much farther away from the structural front than what was once thought likely. Kinematic modeling
demonstrates the deformation process of this region of the plateau at different stages. This allows for a
reinterpretation of structures. These faults may have the potential to produce small fractures and offsets within
the Marcellus Shale that will likely affect well locations and production potential. Therefore, understanding these
deep structures and how they affect shallow structures is essential to geologist working in this region.
The fore and back thrusts may be observed in the Mauch Chunk and Greenbrier Groups through 30 gas well and
200 shallow coal well correlations. Curvature maps of the shallow surface illustrate locations of discontinuities.
This increases the resolution of the structural maps generated through seismic at depths where the data is noisy.
LIDAR data visualizes the effect that the faults play on the immediate surface (for example, controlling location of
stream valleys) while removing other trees and brush that make it impossible to map small faults penetrating the
surface in the field. The combination of this new data improves the resolution of present maps along with the
understanding of the structural framework of the Appalachian Plateau of central West Virginia.
Aqueous Geochemistry of a Carbon Dioxide-Enhanced Oil Recovery Project in the Sugar Creek Oil Field, Western
Kentucky
Kathryn G. Takacs1, E.G. Beck2, T.M. Parris1, D. Wedding2, and R. Locke3
1
Kentucky Geological Survey, University of Kentucky, 228 Mining and Mineral Resources Building, Lexington, KY
40506-0107, ktakacs@uky.edu
2
Kentucky Geological Survey, University of Kentucky, 1401 Corporate Court, Henderson, KY 42420
3
Illinois State Geological Survey, University of Illinois, 615 East Peabody Drive, Champaign, IL 61820
Approximately 7,200 tons of CO2 was injected into the Mississippian Jackson Sandstone oil reservoir in the Sugar
Creek field from May 2009 to May 2010. This enhanced oil recovery (EOR) project is part of the Midwest Geological
Sequestration Consortium pilot program. Goals of this EOR project were: 1) assessment of the viability of using CO 2
for EOR in Kentucky, 2) characterization of aqueous geochemical responses to CO 2 injection, 3) estimation of the
amount of CO2 that remains sequestered, and 4) investigation of sequestration mechanisms in the reservoir.
Since its discovery in 1964, the Sugar Creek Field has produced approximately 34 percent (905,000 barrels) of the
estimated original oil in place (2,680,000 barrels). The reservoir is a stratigraphic trap in a double lobe shape that
dips down to the south of the injection well, with limited hydraulic interaction between the two lobes. Primary
recovery was by solution gas drive, and secondary recovery via waterflood has been in place since 1993.
Geochemical monitoring was performed before, during, and after CO2 injection. Aqueous geochemical changes in
the reservoir were monitored by the monthly collection of brine samples from eight production wells surrounding
a single injection well. Also, three shallow groundwater monitoring wells, two domestic water wells, and one
water-supply well were sampled quarterly to assure the quality of nearby shallow aquifers was not affected.
During sampling, field measurements of temperature, specific conductance, pH, dissolved oxygen, and oxidationreduction potential were taken for all wells. Water samples were analyzed for alkalinity, total CO 2, dissolved anions
and metals, and total dissolved solids in the laboratory. An infrared gas analyzer was used to measure the
concentrations of free-phase CO2 at production wells. Gas samples were also collected for bulk and δ13C-CO2
measurements. Reservoir pressure was monitored at the injection well, and surface pressure was monitored at the
production wells.
Free-phase CO2 was detected in five oil production wells, all on the west side of the field. Typically, after the arrival
of CO2 to the wellbore (i.e., breakthrough), pH decreased one pH unit, and chloride, calcium, strontium, and iron
concentrations increased, on average, by 200 mg/L, 115 mg/L, 45 mg/L, and 2.5 mg/L, respectively. The pH
decrease occurred very closely to the time of CO2 breakthrough. Barium concentrations, in contrast, decreased.
Aqueous geochemical changes occurred less than 1 to 4 months after CO 2 breakthrough. Since CO2 injection was
halted, pH values have generally remained below preinjection values, and most other geochemical constituents
have continued to increase in concentration. The sustained low pH values indicate that CO 2 is remaining in
aqueous solution in the reservoir. No geochemical changes have been observed in the overlying aquifers that
would indicate CO2 leakage from the deeper reservoir formation.
Prediction of Petrophysical Properties of Trenton-Black River (Ordovician) Reservoirs by Comparing Pore
Architecture and Permeability to Sonic Velocity
John E. Thornton1,2 and G. Michael Grammer1
1
Western Michigan University, Michigan Geological Repository for Research and Education, Department of
Geosciences, Kalamazoo, MI 49008
2
Current address: Shell Oil Company, 200 North Dairy Ashford Street, Houston, TX 77079,
johnedwinthornton@gmail.com
Reservoir characterization of carbonate rocks is complicated by heterogeneous pore architecture related to
primary depositional facies and subsequent diagenesis; this is especially true in diagenetically-altered and
structurally-influenced Trenton-Black River reservoirs of the Michigan Basin. Accurate and reliable prediction of
reservoir properties within hydrothermal dolomite (HTD) reservoirs through the use of acoustic properties would
significantly aid exploration and reservoir characterization efforts in HTD reservoirs both within and outside of the
Michigan Basin.
Results indicate that digital image analysis of thin sections and laboratory measures of sonic velocity both quantify
pore architecture of carbonate rocks. Integration of measures of pore architecture and physical properties into
multiple variable linear regression can accurately predict permeability of core plugs. Additionally, use of
minipermeametry and comparison of core plug and whole core measures of porosity and permeability indicate
that Trenton-Black River textures are petrophysically heterogeneous from the millimeter to meter scale. This is due
to the influence of bioturbation on primary depositional textures and their subsequent diagenetic pathways as well
as facies stacking patterns within a 1-D sequence stratigraphic framework.
Integrating modern borehole measures of physical properties and measures of pore architecture derived from
cuttings data may increase the predictability of permeability within hydrothermal dolomite reservoirs over log data
alone. Care must be taken when upscaling petrophysical measurements from core plugs to reservoir flow units in
highly-heterogeneous carbonate reservoirs.
Faunal Distribution and Relative Abundance in a Silurian (Wenlock) Pinnacle Reef Complex - Ray Reef, Macomb
County, Michigan
Jennifer L. Trout1 and G. Michael Grammer2
1
Western Michigan University, Michigan Repository for Research and Education, Kalamazoo, MI 49006,
jennifer.l.trout@wmich.edu
2
Western Michigan University, Michigan Repository for Research and Education, Kalamazoo, MI 49006
Niagaran reefs are important sources of hydrocarbons in the Michigan Basin and have been since their discovery in
southwest Ontario in the early 1900’s. In addition, some of these reservoirs have been used for gas storage and
may be potential CO2 sequestration sites.
Despite extensive research on Niagaran reefs, most studies concerning faunal abundance have been conducted by
paleontologists with an emphasis on taxonomy, paleoecology, and evolution. Relatively few studies by
sedimentologists have focused on faunal abundance as a potential indicator of reservoir characteristics.
The purpose of this study is threefold: 1) to quantitatively determine faunal abundance from subsurface cores of
Ray Reef, 2) to determine if the faunal abundance is variable or consistent on windward vs. leeward margins vs.
crest, and 3) to analyze porosity and permeability data in conjunction with faunal abundance. This will be
accomplished by scanning core slabs to electronic images, marking the identified fauna on the electronic image,
and using image analysis software to calculate faunal counts and the percentage of core surface area occupied.
Preliminary semi-quantitative observations show that the windward margin of Ray Reef is comprised mostly of low
matrix rubble with more extensive cementation than is found along the leeward margin. Windward margins also
contain a higher percentage of skeletal components, primarily stromatoporoids, tabulate corals and bryozoans
than leeward margins.
Little is known about faunal distribution and relative abundance in ancient reef complexes, especially relative to
windward/leeward orientation. If faunal distribution and relative abundance are factors that are indicative of
reservoir characteristics such as porosity and permeability, then these proxies could point to more or less
productive zones within the reef. In addition, this method may be used to investigate other reef types or reefs of
other geologic ages that have different frame-building fauna.
Using Sonic and Seismic Indications of Coastal Plain Unconformities to Suggest Missing Sediments and Downdip
Development of the Eastern Atlantic Coastal Plain and Shelf
Douglas Wyatt1and Michael Waddell2
1
University of South Carolina-Aiken, 471 University Parkway, Aiken, SC 29801, dougw@usca.edu
2
University of South Carolina, Earth Science and Resources Institute,1233 Washington Street, Suite 300, Columbia,
SC 29208, mwaddell@esri.sc.edu
High resolution geological and geophysical investigations at the USDOE Savannah River Site utilized a series of
deep boreholes plus deeper existing coastal plain wells to establish a series of regional cross-sections and
basemaps. These cross-sections were made utilizing sophisticated wireline geophysical logs, core data,
geotechnical direct push technology logs for shallow interrogation, and seismic data and were complimentary to
the many regional cross-sections and large scale maps made by historical researchers. These sections and maps
were then used in regional seismic hazard characterization and evaluation and for other environmental studies.
Additionally, both regional and higher resolution localized seismic data added to the overall efforts. The dominant
sediments evaluated were Late Eocene through Late Cretaceous from the Upper Atlantic Coastal Plain but
sediments to possible Norian age were evaluated in the lower coastal plain and shelf.
During this work it became apparent that unconformities in both the Upper, Mid and Lower Atlantic Coastal Plain
were strongly correlated to abrupt variations in sonic logs that translated from the deep to very shallow horizons.
The major published regional unconformities as well as smaller sub-regional unconformities were apparently
present in the data. Additionally, in the shallow horizons, geotechnical information was present that allowed for a
calculation of estimated overburden or burial depth. This suggested that it might be possible to estimate the
amount of sediment missing from an unconformable horizon. This was important in estimating the volume of
sediment that moved downdip. Knowing the amount of missing sediment might aide in estimating uplift, subaerial
exposure time, paleoclimate, burial depths and thermal history, and aide in the understanding of what geobodies
might be present downdip. These may be important factors in evaluating the hydrocarbon potential of the lower
submerged coastal plain and continental shelf.
For the Upper Atlantic Coastal Plain it is probable that more sediment is missing than remains. Shallow sediments,
often defined in the literature as different aged or as a different formation are possibly re-worked and mobilized
downdip. These sediments are essentially a localized regressive or transgressive expressions and have not moved
downdip. Missing sediments, eroded and mobilized down slope become reservoir bodies or compartments. As
expected the Lower Coastal Plain logs suggest that the sediment estimated from the Upper and Mid Coastal Plain
to be missing is incorporated in the Lower Coastal Plain and the number of unconformities deceases. It then
becomes possible to estimate the volume of sediment retained versus missing allowing for an estimate of available
sediment for reservoir rock.
Stratigraphic Controls on Diagenetic Pathways in the St. Peter Sandstone, Michigan Basin: An Investigation into
Reservoir Quality Prediction for Carbon Sequestration
Stephen A. Zdan
Western Michigan University, and the Michigan Geological Repository for Research and Education, 1903 West
Michigan Avenue, Kalamazoo, MI 49008, stephen.a.zdan@wmich.edu
The Middle Ordovician St. Peter Sandstone in the Michigan Basin is a target for carbon sequestration and geologic
storage. This marine sandstone ranges in thickness from regional pinch-outs to greater than 1000 feet, and has 3
distinct lithofacies. The uppermost facies contains zones of porosity and good reservoir quality. Because of the
mostly uniform detrital composition, diagenesis plays a leading role in reservoir quality development. The
distribution of diagenetic regimes is believed to result from depositional setting and related geologic processes,
including variations in sediment accumulation rate. The purpose of this study is to test stratigraphic controls on the
formation of early marine cements. These early cements preserve intergranular pore space available for late
diagenetic processes including decementation by preventing the precipitation of quartz overgrowths. This
stratigraphic/diagenetic model is evaluated using wire-line logs, for assessing regionally variable reservoir quality.
The study includes the analysis of conventional core (n=71), thin sections, and wire-line logs to better constrain an
understanding of the lateral and vertical distribution of diagenetic pathways.
Zero Discharge Water Management for Horizontal Shale Gas Well Development
Dr. Paul F. Ziemkiewicz and Jennifer Hause
West Virginia Water Research Institute, West Virginia University, PO Box 6064, Morgantown, WV 26506-6064,
Paul.ziemkiewicz@mail.wvu.edu
Shale gas production depends on the creation of permeability within an otherwise nearly impermeable rock
formation. Two technologies have been applied to produce natural gas – directional/horizontal drilling and
massive hydraulic fracturing. Fracturing uses large volumes of water to create several, long fractures in the shale
formation. Sand is pumped with the water and left to prop open the fractures, thus providing multiple, permeable
flow paths for the natural gas. The use of the large volumes of water often stresses local fresh water supplies, and
the water flowing back from the well after fracturing is a briny mixture, creating a water disposal problem. A West
Virginia University (WVU) research team is looking at methods for managing frac water withdrawals and returns
from large gas wells in the Marcellus Formation by converting the briny waste into a suitable, partial replacement
of the fresh water that is currently used as the fracturing fluid of choice. The objective of this two-year, two-phase
project is to develop and demonstrate a process for treating return frac water (RFW) from Marcellus horizontal
well development that will allow an increased recycle rate while decreasing make-up water and disposal
requirements.
Industry standards for acceptable recycle water quality standards continue to evolve with current primary needs of
high-rate filtration operations achieving solids removal well below 20 microns and a reduction in sulfates and
heavy metals. Industry also requires a treatment system with minimal operation and maintenance, occupies a
small footprint, and can easily be taken from site to site. Phase I testing and review of treatment technologies
identified a unique multi-media filter unit that met current industry needs.
This project is now well into Phase II, the design, fabrication and field deployment of a mobile treatment unit
(MTU) to an active field site. The anticipated mobilization date is July 2011 with testing to run for 3 months. The
successful development of a technology for treatment and reuse of RFW will advance shale gas development
through improved economics and resolution of environmental impacts. Improved economics will be achieved by
reducing the amount of trucking and disposal of RFW and costs associated with these activities. By reusing the
RFW for subsequent fractures, the need for fresh water will be reduced. The better you treat the RFW, the higher
the blend ratio with fresh water, the less dependence and strain on local water resources, and the less impact on
local infrastructure and surrounding environment.