Geology topics

Catherine B. Enomoto

Publications and source records attributed to Catherine B. Enomoto.

29 records · Page 2Linked to original sources

USGS2015

Geochemical and mineralogical sampling of the Devonian shales in the Broadtop synclinorium, Appalachian basin, in Virginia, West Virginia, Maryland, and Pennsylvania

Reconnaissance field mapping and outcrop sampling for geochemical and mineralogical analyses indicate that the Middle Devonian Marcellus Shale in the Broadtop synclinorium and nearby areas from southeastern West Virginia to south-central Pennsylvania has an organic content sufficiently high and a thermal maturity sufficiently moderate to be considered for a shale gas play. The organic matter-rich Marcellus Shale is present throughout most of the synclinorium, being absent only where it has been eroded from the crest of anticlines. Geochemical analyses of outcrop and well drill-cuttings samples indicate that variable levels of hydrocarbons have been generated and expelled from the kerogen originally in place in the mudstone. The mineralogical characteristics of the Marcellus Shale samples from the study area are conducive to a continuous resource play, but the Middle Devonian strata are folded, faulted, and moderately to heavily sheared in the Broadtop synclinorium. The presence of conventional anticlinal gas fields in the study area that are productive from the underlying Lower Devonian Oriskany Sandstone suggests that an unconventional (or continuous) shale gas system may be in place within the Marcellus Shale in the study area. Results of this study indicate that the Marcellus Shale in the Broadtop synclinorium generally is similar in organic geochemical nature throughout its extent, and based on the sample analyses, there are no clearly identifiable high potential areas (or “sweet spots”) in the study area. This report contains analyses of 132 outcrop and well drill-cuttings samples.

Maryland, Pennsylvania, Virginia, West Virginia↗

USGS2014

Organic petrology of the Aptian-age section in the downdip Mississippi Interior Salt Basin, Mississippi, USA: Observations and preliminary implications for thermal maturation history

This study identifies a thermal maturity anomaly within the downdip Mississippi Interior Salt Basin (MISB) of southern Mississippi, USA, through examination of bitumen reflectance data from Aptian-age strata (Sligo Formation, Pine Island Shale, James Limestone, and Rodessa Formation). U.S. Geological Survey (USGS) reconnaissance investigations conducted in 2011–2012 examined Aptian-age thermal maturity trends across the onshore northern Gulf of Mexico region and indicated that the section in the downdip MISB is approaching the wet gas/condensate window (R o ~1.2%). A focused study in 2012–2013 used 6 whole core, one sidewall core, and 49 high-graded cutting samples (depth range of 13,000–16,500 ft [3962.4–5029.2 m] below surface) collected from 15 downdip MISB wells for mineralogy, fluid inclusion, organic geochemistry, and organic petrographic analysis. Based on native solid bitumen reflectance (R o generally > 0.8%; interpreted to be post-oil indigenous bitumens matured in situ), R o values increase regionally across the MISB from the southeast to the northwest. Thermal maturity in the eastern half of the basin (R o range 1.0 to 1.25%) appears to be related to present-day burial depth and shows a gradual increase with respect to depth. To the west, thermal maturity continues to increase even as the Aptian section shallows structurally on the Adams County High (R o range 1.4 to > 1.8%). After evaluating the possible thermal agents responsible for increasing maturity at shallower depths (i.e., igneous activity, proximity to salt, variations in regional heat flux, and uplift), we tentatively propose that either greater paleoheat flow or deeper burial coupled with uplift in the western part of the MISB could be responsible for the thermal maturity anomaly. Further research and additional data are needed to determine the cause(s) of the thermal anomaly.

International Journal of Coal Geology↗

USGS2014

The Devonian Marcellus Shale and Millboro Shale

The recent development of unconventional oil and natural gas resources in the United States builds upon many decades of research, which included resource assessment and the development of well completion and extraction technology. The Eastern Gas Shales Project, funded by the U.S. Department of Energy in the 1980s, investigated the gas potential of organic-rich, Devonian black shales in the Appalachian, Michigan, and Illinois basins. One of these eastern shales is the Middle Devonian Marcellus Shale, which has been extensively developed for natural gas and natural gas liquids since 2007. The Marcellus is one of the basal units in a thick Devonian shale sedimentary sequence in the Appalachian basin. The Marcellus rests on the Onondaga Limestone throughout most of the basin, or on the time-equivalent Needmore Shale in the southeastern parts of the basin. Another basal unit, the Huntersville Chert, underlies the Marcellus in the southern part of the basin. The Devonian section is compressed to the south, and the Marcellus Shale, along with several overlying units, grades into the age-equivalent Millboro Shale in Virginia. The Marcellus-Millboro interval is far from a uniform slab of black rock. This field trip will examine a number of natural and engineered exposures in the vicinity of the West Virginia–Virginia state line, where participants will have the opportunity to view a variety of sedimentary facies within the shale itself, sedimentary structures, tectonic structures, fossils, overlying and underlying formations, volcaniclastic ash beds, and to view a basaltic intrusion.

GSA Field Guides↗

USGS2014

Characterization of the Marcellus Shale based on computer-assisted correlation of wireline logs in Virginia and West Virginia

The Middle Devonian Marcellus Shale in the Appalachian basin extends from central Ohio on the west to eastern New York on the east, and from north-central New York on the north to northern Tennessee on the south. Its thickness ranges from 0 feet (ft) where it pinches out to the west to as much as 700 ft in its eastern extent. Within the Broadtop synclinorium, the thickness of the Marcellus Shale ranges from 250 to 565 ft. Although stratigraphic complexities have been documented, a significant range in thickness most likely is because of tectonic thickening from folds and thrust faults. Outcrop studies in the Valley and Ridge and Appalachian Plateaus provinces illustrate the challenges of interpreting the relation of third-order faults, folds, and “disturbed” zones to the regional tectonic framework. Recent field work within the Valley and Ridge province determined that significant faulting and intraformational deformation are present within the Marcellus Shale at the outcrop scale. In an attempt to determine if this scale of deformation is detectable with conventional wireline logs, petrophysical properties (primarily mineralogy and porosity) were measured by interpretation of gamma-ray and bulk-density logs. The results of performing a statistical correlation of wireline logs from nine wells indicated that there are discontinuities within the Millboro Shale (undifferentiated Marcellus Shale and Mahantango Formation) where there are significant thickness differences between wells. Also, some intervals likely contain mineralogy that makes these zones more prone to layer-shortening cleavage duplexes. The Correlator program proved to be a useful tool in a region of contractional deformation.

Virginia;West Virginia↗

USGS2014

Well log and 2D seismic data character of the Wilcox Group in south-central Louisiana

Well logs and 2D seismic data were used to interpret the depth and morphology of potential Paleocene and lower Eocene Wilcox Group slope and basin-floor reservoirs in south-central Louisiana. These may occur in a poorly explored area previously estimated by the U.S. Geological Survey to contain a mean undiscovered conventional resource potential of 26,398 billion cubic feet of gas and 423 million barrels of natural gas liquids. The Wilcox Group is 15,000 to 26,000 feet deep in south-central Louisiana. Previously published paleogeographic maps suggest the sediment transport direction during the Paleocene and lower Eocene was west to east, parallel to the relict Cretaceous shelf margin, and north to south due to the development of the Holly Springs delta system in Louisiana. Inclined reflectors on the 2D seismic data suggest high-energy deposition of clastic sediments. There is minimal well control downdip of currently productive areas. The Wilcox Group is productive in updip areas of Texas and Louisiana from fluvial, deltaic, and near-shore marine shelf sandstones. The reported presence of porous sandstones at 29,000 feet within the Wilcox Group containing about 200 feet of gas in the Davy Jones 1 discovery well in the offshore Louisiana South Marsh Island area illustrates a sand-rich system developed during the Paleocene and early Eocene. This study describes some of the well log and reflection seismic data characteristics of the slope and basin-floor reservoirs with gas-discovery potential that may be in the area between the producing trend onshore Louisiana and the offshore discovery.

Louisiana↗

USGS2014

U.S. Geological Survey unconventional petroleum systems research in south Mississippi: Observations on burial history and thermal maturity in the Cretaceous

Shale hydrocarbon ‘resource’ plays have revolutionized the United States energy mix over the last 5 years. These plays are diverse in lithology and age but share the common feature of occurring in ‘tight’ formations which require hydraulic (hydro-) fracturing for economic flow rates. In general, economic success requires an organic-rich reservoir with a quartz- or carbonate-rich mineralogy that responds to artificial stimulation by fracturing. The U.S. Geological Survey (USGS) is tasked with estimating the quantity and quality of undiscovered hydrocarbons reservoired in shales. In support of that mission, we began an investigation of unconventional petroleum systems in the southern part of the Mississippi Salt Basin in 2012, building on earlier reconnaissance work that identified this area as potentially prospective for ‘shale’ gas (Enomoto et al., 2012). While our recent studies (Valentine et al., 2014a; Hackley et al., 2014) have suggested poor ‘shale’ gas prospectivity (due to low organic content, low porosity, high clay content, and significant depth), at least for the Aptian section, they also have generated a wealth of new information about thermal maturity in the Cretaceous of south Mississippi. In addition, our work to-date has set the stage for future USGS evaluation of unconventional hydrocarbons reservoired in the Upper Cretaceous Tuscaloosa Marine Shale (TMS). Here, we summarize recent USGS thermal maturity studies in the south Mississippi Salt Basin.

Mississippi↗

USGS2013

Geologic model for the assessment of undiscovered hydrocarbons in Lower to Upper Cretaceous carbonate rocks of the Fredericksburg and Washita groups, U.S. Gulf Coast Region

As part of the assessment of undiscovered oil and gas resources in Jurassic and Cretaceous strata of the U.S. Gulf Coast in 2010, the U.S. Geological Survey assessed carbonate rocks of the Fredericksburg and Washita groups and their equivalent units underlying onshore lands and State waters. One conventional assessment unit extending from south Texas to the Florida panhandle was defined: the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil assessment unit. Assessed strata range in age from Early Cretaceous Albian to Late Cretaceous Cenomanian. The assessment was based on a geologic model that incorporated the Upper Jurassic–Cretaceous–Tertiary Composite Total Petroleum System of the Gulf of Mexico Basin. The following factors were evaluated to define the assessment unit and estimate undiscovered oil and gas resources: potential source rocks, hydrocarbon migration, reservoir porosity and permeability, traps and seals, structural features, depositional framework, and potential for water washing of hydrocarbons near outcrop areas. Analysis of the production history of discovered reservoirs and well data within the assessment unit was also essential for estimating the numbers and sizes of undiscovered oil and gas reservoirs within the assessment unit. The downdip boundary of the assessment unit was drawn as an arbitrary line 10 miles downdip of the Lower Cretaceous shelf margin, to include potential reef-talus reservoirs, a facies described in the geologic model developed for the assessment. Updip boundaries of the assessment unit were drawn based on the updip extent of assessment unit carbonate reservoir rocks, basin margin fault zones, and (or) the presence of producing wells within the assessed interval. Using the U.S. Geological Survey methodology, mean undiscovered resources of 40 million barrels of oil, 622 billion cubic feet of gas, and 14 million barrels of natural gas liquids were estimated for the assessment unit.

U.S. Gulf Coast↗

USGS2012

Scientific basis for safely shutting in the Macondo Well after the April 20, 2010 Deepwater Horizon blowout

As part of the government response to the Deepwater Horizon blowout, a Well Integrity Team evaluated the geologic hazards of shutting in the Macondo Well at the seafloor and determined the conditions under which it could safely be undertaken. Of particular concern was the possibility that, under the anticipated high shut-in pressures, oil could leak out of the well casing below the seafloor. Such a leak could lead to new geologic pathways for hydrocarbon release to the Gulf of Mexico. Evaluating this hazard required analyses of 2D and 3D seismic surveys, seafloor bathymetry, sediment properties, geophysical well logs, and drilling data to assess the geological, hydrological, and geomechanical conditions around the Macondo Well. After the well was successfully capped and shut in on July 15, 2010, a variety of monitoring activities were used to assess subsurface well integrity. These activities included acquisition of wellhead pressure data, marine multichannel seismic profiles, seafloor and water-column sonar surveys, and wellhead visual/acoustic monitoring. These data showed that the Macondo Well was not leaking after shut in, and therefore, it could remain safely shut until reservoir pressures were suppressed (killed) with heavy drilling mud and the well was sealed with cement.

Gulf of Mexico↗

USGS2012

Geology of the Devonian Marcellus Shale--Valley and Ridge province, Virginia and West Virginia--a field trip guidebook for the American Association of Petroleum Geologists Eastern Section Meeting, September 28-29, 2011

Detailed and reconnaissance field mapping and the results of geochemical and mineralogical analyses of outcrop samples indicate that the Devonian shales of the 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 it has been eroded from the crests of anticlines. Geochemical analyses of outcrop and well samples indicate that hydrocarbons have been generated and expelled from the kerogen originally in place in the shale. The mineralogical characteristics of the Marcellus Shale samples from the Broadtop Synclinorium are slightly different from the averages of samples from New York, Pennsylvania, northeast Ohio, and northern West Virginia. The Middle Devonian shale interval is moderately to heavily fractured in all areas, but in some areas substantial fault shearing has removed a regular "cleat" system of fractures. Conventional anticlinal gas fields in the study area that are productive from the Lower Devonian Oriskany Sandstone suggest that a continuous shale gas system may be in place within the Marcellus Shale interval at least in a portion of the synclinorium. Third-order intraformational deformation is evident within the Marcellus shale exposures. Correlations between outcrops and geophysical logs from exploration wells nearby will be examined by field trip attendees.

Virginia;West Virginia↗

USGS2012

Preliminary evaluation of the shale gas prospectivity of the Lower Cretaceous Pearsall Formation in the onshore Gulf Coast region, United States

Recent work by the U.S. Geological Survey indicated that the Lower Cretaceous Pearsall Formation contains an estimated mean undiscovered, technically recoverable unconventional gas resource of 8.8 trillion cubic ft in the Maverick Basin, South Texas. Cumulative gas production from horizontal wells in the core area of the emerging play has exceeded 5 billion cubic ft since 2008. However, very little information is available to characterize the Pearsall Formation as an unconventional gas resource beyond the Maverick Basin in the greater Gulf Coast region. Therefore, this reconnaissance study examines spatial distribution, thickness, organic richness and thermal maturity of the Pearsall Formation in the onshore U.S. Gulf states using wireline logs and drill cuttings sample analysis. Spontaneous potential and resistivity curves of approximately forty wireline logs from wells in five Gulf Coast states were correlated to ascertain the thickness of the Pearsall Formation and delineate its three members: Pine Island Shale, James Limestone or Cow Creek Limestone, and Bexar Shale, in ascending stratigraphic order. In Florida and Alabama the Pearsall Formation is up to about 300 ft thick; in Mississippi, Louisiana, Arkansas, and East Texas, thickness is up to as much as 800 ft. Drill cuttings sampled from 11 wells at depths ranging from 4600 to 19,600 feet subsurface indicate increasingly oxygenated depositional environments (predominance of red shale) towards the eastern part of the basin. Cuttings vary widely in lithology but indicate interbedded clastics and limestones throughout the Pearsall Formation, consistent with previous regional studies. Organic petrographic and geochemical analyses of 17 cutting samples in the Pearsall Formation indicate a wide range in thermal maturity, from immature (0.43% Ro [vitrinite reflectance]) in paleo-high structural locations to the peak oil window (0.99% Ro) in the eastern portion of the Gulf Coast Basin. This is in contrast to dry gas thermal maturity throughout the Pearsall Formation in the South Texas Maverick Basin. Organic carbon content is low overall, even in immature samples, with a range of 0.17 to 1.08 wt.% by Leco in 22 Pearsall Formation samples. The pyrolysis output range was 0.23 to 2.33 mg hydrocarbon/g rock. The thermal maturity and Rock-Eval pyrolysis data and organic petrologic observations from this study will be used to better focus specific areas of investigation where the Pearsall Formation may be prospective as an unconventional hydrocarbon source and reservoir.

Alabama;Arkansas;Louisiana;Mississippi;Oklahoma;Te↗

USGS2010

Geology and assessment of undiscovered oil and gas resources in Mesozoic (Jurassic and Cretaceous) rocks of the onshore and state waters of the Gulf of Mexico Region, U.S.A

The U.S. Geological Survey (USGS) is in the final phase of the most recent assessment of the undiscovered technically recoverable oil and gas resources of the U.S. Gulf of Mexico coastal plain and state waters. Ongoing geologic, geochemical, and petrophysical framework studies have defined the total petroleum systems and assessment units (AUs) in the Gulf Coast region. Current studies examine the Mesozoic (Jurassic and Cretaceous) source rocks and reservoir units, and recent studies have assessed the undiscovered resources in Tertiary and certain Jurassic and Cretaceous units. The Upper Jurassic and Lower Cretaceous Cotton Valley Group and Lower Cretaceous Hosston and Travis Peak formations, as well as the Upper Cretaceous Taylor and Navarro groups and the Tuscaloosa and Woodbine groups downdip shelf-margin deltas, were assessed in 2006. Tertiary strata were assessed in 2007. Jurassic strata presently under evaluation include the Upper Jurassic Norphlet, Smackover, Haynesville, and Bossier formations. Lower Cretaceous units to be assessed in the present study include the Knowles Limestone, Sligo Formation, Trinity Group, Fredericksburg Group, and lower part of the Washita Group. Upper Cretaceous rocks being assessed include the Buda Limestone of the Washita Group, Eagle Ford Group (Eagle Ford shale, and the updip Tuscaloosa and Woodbine groups), Austin Chalk (Group), and Tokio and Eutaw formations. For each AU, a geologic model is developed to define hydrocarbon source, charge, migration, trap, and reservoir, and to estimate technically recoverable undiscovered oil and gas resources. The USGS assessment is focused on evaluating conventional clastic and carbonate deposystems, as well as resource volumes in emerging unconventional gas, shale gas, and shale oil plays currently attracting global attention.

Texas, Louisiana, Alabama, Mississippi, Florida↗