Geology topics

Robert A. Burruss

Publications and source records attributed to Robert A. Burruss.

At least 19 recordsLinked to original sources

USGS2015

Depositional conditions for the Kuna Formation, Red Dog Zn-PB-Ag-Barite District, Alaska, inferred from isotopic and chemical proxies

Water column redox conditions, degree of restriction of the depositional basin, and other paleoenvironmental parameters have been determined for the Mississippian Kuna Formation of northwestern Alaska from stratigraphic profiles of Mo, Fe/Al, and S isotopes in pyrite, C isotopes in organic matter, and N isotopes in bulk rock. This unit is important because it hosts the Red Dog and Anarraaq Zn-Pb-Ag ± barite deposits, which together constitute one of the largest zinc resources in the world. The isotopic and chemical proxies record a deep basin environment that became isolated from the open ocean, became increasingly reducing, and ultimately became euxinic. The basin was ventilated briefly and then became isolated again just prior to its demise as a discrete depocenter with the transition to the overlying Siksikpuk Formation. Ventilation corresponded approximately to the initiation of bedded barite deposition in the district, whereas the demise of the basin corresponded approximately to the formation of the massive sulfide deposits. The changes in basin circulation during deposition of the upper Kuna Formation may have had multiple immediate causes, but the underlying driver was probably extensional tectonic activity that also facilitated fluid flow beneath the basin floor. Although the formation of sediment-hosted sulfide deposits is generally favored by highly reducing conditions, the Zn-Pb deposits of the Red Dog district are not found in the major euxinic facies of the Kuna basin, nor did they form during the main period of euxinia. Rather, the deposits occur where strata were permeable to migrating fluids and where excess H 2 S was available beyond what was produced in situ by decomposition of local sedimentary organic matter. The known deposits formed mainly by replacement of calcareous strata that gained H 2 S from nearby highly carbonaceous beds (Anarraaq deposit) or by fracturing and vein formation in strata that produced excess H 2 S by reductive dissolution of preexisting barite (Red Dog deposits).

Alaska↗

USGS2014

The use of solvent extractions and solubility theory to discern hydrocarbon associations in coal, with application to the coal-supercritical CO 2 system

Samples of three high volatile bituminous coals were subjected to parallel sets of extractions involving solvents dichloromethane (DCM), carbon disulfide (CS 2 ), and supercritical carbon dioxide (CO 2 ) (40 °C, 100 bar) to study processes affecting coal–solvent interactions. Recoveries of perdeuterated surrogate compounds, n-hexadecane-d34 and four polycyclic aromatic hydrocarbons (PAHs), added as a spike prior to extraction, provided further insight into these processes. Soxhlet-DCM and Soxhlet-CS 2 extractions yielded similar amounts of extractable organic matter (EOM) and distributions of individual hydrocarbons. Supercritical CO 2 extractions (40 °C, 100 bar) yielded approximately an order of magnitude less EOM. Hydrocarbon distributions in supercritical CO 2 extracts generally mimicked distributions from the other solvent extracts, albeit at lower concentrations. This disparity increased with increasing molecular weight of target hydrocarbons. Five- and six-ring ring PAHs generally were not detected and no asphaltenes were recovered in supercritical CO 2 extractions conducted at 40 °C and 100 bar. Supercritical CO 2 extraction at elevated temperature (115 °C) enhanced recovery of four-ring and five-ring PAHs, dibenzothiophene (DBT), and perdeuterated PAH surrogate compounds. These results are only partially explained through comparison with previous measurements of hydrocarbon solubility in supercritical CO 2 . Similarly, an evaluation of extraction results in conjunction with solubility theory (Hildebrand and Hansen solubility parameters) does not fully account for the hydrocarbon distributions observed among the solvent extracts. Coal composition (maceral content) did not appear to affect surrogate recovery during CS 2 and DCM extractions but might affect supercritical CO 2 extractions, which revealed substantive uptake (partitioning) of PAH surrogates into the coal samples. This uptake was greatest in the sample (IN-1) with the highest vitrinite content. These findings indicate that hydrocarbon solubility does not exert a strong influence on hydrocarbon behavior in the systems studied. Other factors such as coal composition and maceral content, surface processes (physisorption), or other molecular interactions appear to affect the partitioning of hydrocarbons within the coal–supercritical CO 2 system. Resolving the extent to which these factors might affect hydrocarbon behavior under different geological settings is important to efforts seeking to model petroleum generation, fractionation and expulsion from coal beds and to delineate potential hydrocarbon fate and transport in geologic CO 2 sequestration settings.

Organic Geochemistry↗

USGS2014

The geochemistry of oils and gases from the Cumberland overthrust sheet in Virginia and Tennessee

This study presents high-resolution gas chromatograms of oils and molecular and isotopic analyses of oil-associated gases from 17 wells producing in the Upper Cambrian to Lower Ordovician Knox Group, the Middle and Upper Ordovician Stones River Group, and the Upper Ordovician Trenton Limestone in the Cumberland overthrust sheet. The wells are located in the Ben Hur and Rose Hill fields in Lee County, Va., and in the Swan Creek field in Hancock and Claiborne Counties, Tenn. They produce oils typical of those from source rocks that are rich in Gloeocapsomorpha prisca ( G. prisca ) (Assemblage A-type kerogen). The Rose Hill oils appear to come from a source that contains a higher proportion of Assemblage A-type kerogen than the Ben Hur and Swan Creek oils. Extrapolation of the δ 13 C compositions of oil-associated gases to possible kerogen compositions gives estimates of -23 to -24 per mil within the range of isotopic compositions of known G. prisca source material. Gases produced from the Knox Group wells in the Swan Creek field are different from those in the Middle and Upper Ordovician reservoirs and come from a source with a broader range of isotopic values. Trends in isotopic and gasoline-range compositional parameters of the oils and associated gas isotopic and molecular compositions are most likely influenced by changes in local source depositional facies.

Kentucky, Tennessee, Virginia↗

USGS2014

Composition of natural gas and crude oil produced from 14 wells in the Lower Silurian "Clinton" Sandstone and Medina Group Sandstones, northeastern Ohio and northwestern Pennsylvania

The geochemical processes that control the distribution of hydrocarbons in the regional accumulation of natural gas and crude oil in reservoirs of Early Silurian age in the central Appalachian basin are not well understood. Gas and oil samples from 14 wells along a down-dip transect through the accumulation in northeastern Ohio and northwestern Pennsylvania were analyzed for molecular and stable isotopic compositions to look for evidence of hydrocarbon source, thermal maturation, migration, and alteration parameters. The correlation of carbon and hydrogen stable isotopic composition of methane with thermal maturation indicates that the deepest gases are more thermally mature than independent estimates of thermal maturity of the reservoir horizon based on the conodont alteration index. This correlation indicates that the natural gas charge in the deepest parts of the regional accumulation sampled in this study originated in deeper parts of the Appalachian basin and migrated into place. Other processes, including mixing and late-stage alteration of hydrocarbons, may also impact the observed compositions of natural gases and crude oils.

Ohio, Pennsylvania↗

USGS2014

Composition of natural gas and crude oil produced from 10 wells in the Lower Silurian "Clinton" Sandstone, Trumbull County, Ohio

Natural gases and associated crude oils in the “Clinton” sandstone, Medina Group sandstones, and equivalent Tuscarora Sandstone in the northern Appalachian basin are part of a regional, continuous-type or basin-centered accumulation. The origin of the hydrocarbon charge to regional continuoustype accumulations is poorly understood. We have analyzed the molecular and stable isotopic composition of gases and oils produced from 10 wells in the “Clinton” sandstone in Trumbull County, Ohio, in an initial attempt to identify the characteristics of the accumulated fluids. The analyses show that the fluids have remarkably uniform compositions that are similar to previously published analyses of oils (Cole and others, 1987) and gases (Laughrey and Baldasarre, 1998) in Early Silurian reservoirs elsewhere in Ohio; however, geochemical parameters in the oils and gases suggest that the fluids have experienced higher levels of thermal stress than the present-day burial conditions of the reservoir rocks. The crude oils have an unusual geochemical characteristic: they do not contain detectable levels of sterane and triterpane biomarkers. The origin of these absences is unknown.

Ohio↗

USGS2014

Evidence for Cambrian petroleum source rocks in the Rome trough of West Virginia and Kentucky, Appalachian basin

A 130-foot-thick Cambrian black shale sampled from a core between 11,150 and 11,195 feet in the Exxon No. 1 Smith well in Wayne County, W. Va., has been identified as a good to very good source rock. The black shale is located in the Middle Cambrian Rogersville Shale of the Conasauga Group. Total organic carbon (TOC) values of four samples that range from 1.2 to 4.4 weight percent (average 2.6 weight percent) are the highest reported to date in the pre-Knox section of the Rome trough. Although the samples are probably in the zone of gas generation based on their low hydrogen index values (55 to 63) and temperature maximum of second hydrocarbon peak (S 2 ) values of about 465°C, first hydrocarbon peak (S 1 ) values of 0.81 to 2.71 indicate that they contain free extractable hydrocarbons. A bitumen sample extracted from the Rogersville Shale is characterized by (1) a broad spectrum of n -alkanes from n -C 11 through n -C 30 , (2) strong odd-carbon predominance in the n -C 13 to n -C 19 range, and (3) small but detectable amounts of isoprenoids pristane and phytane. The strong odd-carbon predominance of the n -C 15 to n -C1 9 n-alkanes is commonly attributed to the Ordovician alga Gloeocapsomorpha prisca . This occurrence of G. prisca is among the first to be reported in Cambrian rocks. Thin black shale beds collected from the Lower to Middle Cambrian Rome Formation in the Texaco No. 1 Kirby well in Garrard County, Ky., have TOC values as high as 3.2 percent, hydrogen index values as high as 417, and bitumen extract characteristics similar to the Rogersville Shale. The bitumen extract from the Rogersville Shale compares very closely with oils or condensates from Cambrian reservoirs in the Carson Associates No. 1 Kazee well, Homer gas field, Elliott County, Ky.; the Inland No. 529 White well, Boyd County, Ky.; and the Miller No. 1 well, Wolfe County, Ky. These favorable oil-source rock correlations suggest a new petroleum system in the Appalachian basin that is characterized by a Conasauga Group source rock and Rome Formation and Conasauga Group reservoirs. This petroleum system probably extends along the Rome trough from eastern Kentucky to at least central West Virginia.

Kentucky, West Virginia↗

USGS2013

Observations on the crystallization of spodumene from aqueous solutions in a hydrothermal diamond-anvil cell

Crystallization experiments were conducted in a new type of hydrothermal diamond-anvil cell (HDAC; type V) using LiAlSi 2 O 6 (S) gel and H 2 O (W) as starting materials. A total of 21 experiments were performed at temperatures up to 950°C and pressures up to 788 MPa. In the samples with relatively low W/S ratios, many small crystals formed in the melt phase during cooling. In those with high W/S ratios, only a few crystals with smooth surfaces crystallized from the aqueous fluid in the presence of melt droplets, which were gradually consumed during crystal growth, indicating rapid transfer of material from the melt to the crystals through the aqueous fluid. The nucleation of crystals started at 710 (±70)°C and 520 (±80) MPa, and crystal growth ended at 570 (±40)°C and 320 (±90) MPa, with the cooling P-T path within the stability field of spodumene + quartz in the S-W system. The observed linear crystal growth rates in the aqueous phase, calculated by dividing the maximum length of a single crystal by the duration of the entire growth step, were 4.7 × 10 −6 and 5.7 × 10 −6 cm s −1 for the cooling rates of 0.5 and 1°C min −1 , respectively. However, a rapid crystal growth rate of 3.6 × 10 −5 cm s −1 in the aqueous fluid was observed when the components were supplied by nearby melt droplets. Our results show that when crystals nucleate in the aqueous fluid instead of the melt phase, there are fewer nuclei formed, and they grow much faster due to the low viscosity of the aqueous fluid, which accelerates diffusion of components for the growth of crystals. Therefore, the large crystals in granitic pegmatite can crystallize directly from aqueous fluids rather than hydrosilicate melt.

Geofluids↗

USGS2013

Disproportionation and thermochemical sulfate reduction reactions in S-H 2 0-Ch 4 and S-D 2 O-CH 4 systems from 200 to 340 °C at elevated pressures

Elemental sulfur, as a transient intermediate compound, by-product, or catalyst, plays significant roles in thermochemical sulfate reduction (TSR) reactions. However, the mechanisms of the reactions in S-H 2 O-hydrocarbons systems are not clear. To improve our understanding of reaction mechanisms, we conducted a series of experiments between 200 and 340 °C for S-H 2 O-CH 4 , S-D 2 O-CH 4 , and S-CH 4 -1m ZnBr 2 systems in fused silica capillary capsules (FSCC). After a heating period ranging from 24 to 2160 hours (hrs), the quenched samples were analyzed by Raman spectroscopy. Combined with the in situ Raman spectra collected at high temperatures and pressures in the S-H 2 O and S-H 2 O-CH 4 systems, our results showed that (1) the disproportionation of sulfur in the S-H 2 O-CH 4 system occurred at temperatures above 200 °C and produced H 2 S, SO 4 2- , and possibly trace amount of HSO 4- ; (2) sulfate (and bisulfate), in the presence of sulfur, can be reduced by methane between 250 and 340 °C to produce CO 2 and H 2 S, and these TSR temperatures are much closer to those of the natural system (<200 °C) than those of any previous experiments; (3) the disproportionation and TSR reactions in the S-H 2 O-CH 4 system may take place simultaneously, with TSR being favored at higher temperatures; and (4) in the system S-D 2 O-CH 4 , both TSR and the competitive disproportionation reactions occurred simultaneously at temperatures above 300 °C, but these reactions were very slow at lower temperatures. Our observation of methane reaction at 250 °C in a laboratory time scale suggests that, in a geologic time scale, methane may be destroyed by TSR reactions at temperatures > 200 °C that can be reached by deep drilling for hydrocarbon resources.

Geochimica et Cosmochimica Acta↗

USGS2013

Lithofacies, age, depositional setting, and geochemistry of the Otuk Formation in the Red Dog District, northwestern Alaska

Complete penetration of the Otuk Formation in a continuous drill core (diamond-drill hole, DDH 927) from the Red Dog District illuminates the facies, age, depositional environment, source rock potential, and isotope stratigraphy of this unit in northwestern Alaska. The section, in the Wolverine Creek plate of the Endicott Mountains Allochthon (EMA), is ~82 meters (m) thick and appears structurally uncomplicated. Bedding dips are generally low and thicknesses recorded are close to true thicknesses. Preliminary synthesis of sedimentologic, paleontologic, and isotopic data suggests that the Otuk succession in DDH 927 is a largely complete, albeit condensed, marine Triassic section in conformable contact with marine Permian and Jurassic strata. The Otuk Formation in DDH 927 gradationally overlies gray siliceous mudstone of the Siksikpuk Formation (Permian, based on regional correlations) and underlies black organic-rich mudstone of the Kingak(?) Shale (Jurassic?, based on regional correlations). The informal shale, chert, and limestone members of the Otuk are recognized in DDH 927, but the Jurassic Blankenship Member is absent. The lower (shale) member consists of 28 m of black to light gray, silty shale with as much as 6.9 weight percent total organic carbon (TOC). Thin limy layers near the base of this member contain bivalve fragments (Claraia sp.?) consistent with an Early Triassic (Griesbachian-early Smithian) age. Gray radiolarian chert dominates the middle member (25 m thick) and yields radiolarians of Middle Triassic (Anisian and Ladinian) and Late Triassic (Carnian-late middle Norian) ages. Black to light gray silty shale, like that in the lower member, forms interbeds that range from a few millimeters to 7 centimeters in thickness through much of the middle member. A distinctive, 2.4-m-thick interval of black shale and calcareous radiolarite ~17 m above the base of the member has as much as 9.8 weight percent TOC, and a 1.9-m-thick interval of limy to cherty mudstone immediately above this contains radiolarians, foraminifers, conodonts, and halobiid bivalve fragments. The upper (limestone) member (29 m thick) is lime mudstone with monotid bivalves and late Norian radiolarians, overlain by gray chert that contains Rhaetian (latest Triassic) radiolarians; Rhaetian strata have not previously been documented in the Otuk. Rare gray to black shale interbeds in the upper member have as much as 3.4 weight percent TOC. At least 35 m of black mudstone overlies the limestone member; these strata lack interbeds of oil shale and chert that are characteristic of the Blankenship, and instead they resemble the Kingak Shale. Vitrinite reflectance values (2.45 and 2.47 percent Ro) from two samples of black shale in the chert member indicate that these rocks reached a high level of thermal maturity within the dry gas window. Regional correlations indicate that lithofacies in the Otuk Formation vary with both structural and geographic position. For example, the shale member of the Otuk in the Wolverine Creek plate includes more limy layers and less barite (as blades, nodules, and lenses) than equivalent strata in the structurally higher Red Dog plate of the EMA, but it has fewer limy layers than the shale member in the EMA ~450 kilometers (km) to the east at Tiglukpuk Creek. The limestone member of the Otuk is thicker in the Wolverine Creek plate than in the Red Dog plate and differs from this member in EMA sections to the east in containing an upper cherty interval that lacks monotids; a similar interval is seen at the top of the Otuk Formation ~125 km to the west (Lisburne Peninsula). Our observations are consistent with the interpretations of previous researchers that Otuk facies become more distal in higher structural positions and that within a given structural level more distal facies occur to the west. Recent paleogeographic reconstructions indicate that the Otuk accumulated at a relatively high paleolatitude with a bivalve fauna typical of the Boreal realm. A suite of δ 13 C org (carbon isotopic composition of carbon) data (n=38) from the upper Siksikpuk Formation through the Otuk Formation and into the Kingak(?) Shale in DDH 927 shows a pattern of positive and negative excursions similar to those reported elsewhere in Triassic strata. In particular, a distinct negative excursion at the base of the Otuk (from ‒23.8 to ‒31.3‰ (permil, or parts per thousand)) likely correlates with a pronounced excursion that marks the Permian-Triassic boundary at many localities worldwide. Another feature of the Otuk δ 13 C org record that may correlate globally is a series of negative and positive excursions in the lower member. At the top of the Otuk in DDH 927, the δ 13 C org values are extremely low and may correlate with a negative excursion that is widely observed at the Triassic-Jurassic boundary.

Alaska↗

USGS2010

A probabilistic assessment methodology for the evaluation of geologic carbon dioxide storage

In 2007, the Energy Independence and Security Act (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of potential geologic storage resources for carbon dioxide (CO 2 ) in cooperation with the U.S. Environmental Protection Agency and the U.S. Department of Energy. The first year of that activity was specified for development of a methodology to estimate storage potential that could be applied uniformly to geologic formations across the United States. After its release, the methodology was to receive public comment and external expert review. An initial methodology was developed and published in March 2009 (Burruss and others, 2009), and public comments were received. The report was then sent to a panel of experts for external review. The external review report was received by the USGS in December 2009. This report is in response to those external comments and reviews and describes how the previous assessment methodology (Burruss and others, 2009) was revised. The resource that is assessed is the technically accessible storage resource, which is defined as the mass of CO 2 that can be stored in the pore volume of a storage formation. The methodology that is presented in this report is intended to be used for assessments at scales ranging from regional to subbasinal in which storage assessment units are defined on the basis of common geologic and hydrologic characteristics. The methodology does not apply to site-specific evaluation of storage resources or capacity.

Open-File Report↗

USGS2009

Development of a probabilistic assessment methodology for evaluation of carbon dioxide storage

This report describes a probabilistic assessment methodology developed by the U.S. Geological Survey (USGS) for evaluation of the resource potential for storage of carbon dioxide (CO 2 ) in the subsurface of the United States as authorized by the Energy Independence and Security Act (Public Law 110-140, 2007). The methodology is based on USGS assessment methodologies for oil and gas resources created and refined over the last 30 years. The resource that is evaluated is the volume of pore space in the subsurface in the depth range of 3,000 to 13,000 feet that can be described within a geologically defined storage assessment unit consisting of a storage formation and an enclosing seal formation. Storage assessment units are divided into physical traps (PTs), which in most cases are oil and gas reservoirs, and the surrounding saline formation (SF), which encompasses the remainder of the storage formation. The storage resource is determined separately for these two types of storage. Monte Carlo simulation methods are used to calculate a distribution of the potential storage size for individual PTs and the SF. To estimate the aggregate storage resource of all PTs, a second Monte Carlo simulation step is used to sample the size and number of PTs. The probability of successful storage for individual PTs or the entire SF, defined in this methodology by the likelihood that the amount of CO 2 stored will be greater than a prescribed minimum, is based on an estimate of the probability of containment using present-day geologic knowledge. The report concludes with a brief discussion of needed research data that could be used to refine assessment methodologies for CO 2 sequestration.

Open-File Report↗

USGS2008

Bedrock, Borehole, and Water-Quality Characterization of a Methane-Producing Water Well in Wolfeboro, New Hampshire

In August 2004, a commercial drill rig was destroyed by ignition of an explosive gas released during the drilling of a domestic well in granitic bedrock in Tyngsborough, MA. This accident prompted the Massachusetts Department of Environmental Protection (MassDEP) to sample the well water for dissolved methane - a possible explosive fuel. Water samples collected from the Tyngsborough domestic well in 2004 by the MassDEP contained low levels of methane gas (Pierce and others, 2007). When the U.S. Geological Survey (USGS) sampled this well in 2006, there was no measurable amount of methane remaining in the well water (Pierce and others, 2007). Other deep water wells in nearby south-central New Hampshire have been determined to have high concentrations of naturally occurring methane (David Wunsch, New Hampshire State Geologist, 2004, written commun.). Studying additional wells in New England crystalline bedrock aquifers that produce methane may help to understand the origin of methane in crystalline bedrock. Domestic well NH-WRW-37 was chosen for this study because it is a relatively deep well completed in crystalline bedrock, it is not affected by known anthropogenic sources of methane, and it had the highest known natural methane concentration (15.5 mg/L, U.S. Geological Survey, 2007) measured in a study described by Robinson and others (2004). This well has been in use since it was drilled in 1997, and it was originally selected for study in 2000 as part of a 30 well network, major-aquifer study by the USGS' New England Coastal Basins (NECB) study unit of the National Water-Quality Assessment (NAWQA) Program. Dissolved methane in drinking water is not considered an ingestion health hazard, although the occurrence in ground water is a concern because, as a gas, its buildup in confined spaces can cause asphyxiation, fire, or explosion hazards (Mathes and White, 2006). Methane occurrence in the fractured crystalline bedrock is not widely reported or well understood. Borehole-geophysical surveys, bedrock outcrop observations, and water-quality analyses were used to define the geologic and hydrologic characteristics of NH-WRW-37. Collection of additional information on the hydraulic and geologic characteristics of the fractured bedrock and on water quality was initiated in an attempt to understand the setting where methane gas occurs in the bedrock ground water. The origin of dissolved methane in this and other wells in New Hampshire is the subject of ongoing investigations by the State of New Hampshire, the New Hampshire Geological Survey and the USGS.

Open-File Report↗

USGS2007

Borehole Characterization of a Methane-Yielding Bedrock Well, Tyngsborough, Massachusetts

In August 2004, a domestic water well was drilled into granitoid metamorphic rocks 5.38 kilometers southwest of Tyngsborough, Massachusetts, on Scribner Hill. According to well driller Roger Skillings of Skillings and Sons, Inc. (oral commun., 2005), no water was encountered during drilling and when the borehole reached a depth of approximately 305.1 m, a blue flame exploded out of the well casing and ignited the drill rig, resulting in a total loss of the equipment (cover). Follow up water quality studies by the Massachusetts Department of Environmental Protection detected low levels of methane in the groundwater extracted from the well. Discussions with the Stephen Hallem, Massachusetts Departments of Environmental Protection and David Wunsch, the New Hampshire State Geologist, prompted the USGS to further investigate this methane occurrence in granitoid rock. Borehole characterization and water quality sampling reported here were completed in May and June 2006, in an effort to identify the potential source of the methane. Follow up samples yielded no detectable methane, and for that reason this report presents a brief summary of our preliminary findings.

Open-File Report↗

USGS2006

Timing of hydrocarbon emplacement in ozokerite andcalcite lined fractures, Teapot Dome, Wyoming

Teapot Dome, Wyoming, also known as National Petroleum Reserve 3, is a candidate for a national CO2 storage test site. The oil field in Upper Cretaceous sandstones at Teapot Dome was discovered in the 1880's based on surface occurrences of a waxy hydrocarbon, 'ozokerite', within calcite-lined fractures. The goal of this research is to determine if the hydrocarbons resulted from active (i.e. present-day) seepage of the oil reservoirs or from an older episode of local or basinscale fluid flow. Two generations of fractures and two separate calcite cementation events are recognized in outcrop, and hydrocarbon wax, likely ozokerite, post-dates both calcite generations. The calcite contains two-phase (liquid-vapor), secondary hydrocarbon fluid inclusions that fluoresce a bluewhite color in UV epi-illumination. The ozokerite also fluoresces blue-white, which suggests that petroleum inclusions and the hydrocarbon wax are related. Gas chromatograms (GCs) of ozokerite are consistent with GCs of oils from Upper Cretaceous reservoirs at Teapot Dome, indicating that a connection between the fractures and a hydrocarbon reservoir did exist. Secondary hydrocarbon inclusions are present in the calcite, which indicates that active oil migration occurred while the fractures were at higher temperatures than surface conditions. Therefore, the oil was emplaced within the fractures when they were between 600 to 1500 m deep. Furthermore, the ozokerite formed during the uplift and exhumation of the Upper Cretaceous strata at Teapot Dome. The fractures in this study have no active connection to any deeper oil-bearing strata.

Open-File Report↗

USGS2005