Geology topics
Robert T. Ryder
Publications and source records attributed to Robert T. Ryder.
Thermal maturity patterns (CAI and %Ro) in the Ordovician and Devonian rocks of the Appalachian basin in New York State
The objective of this study is to enhance existing thermal maturity maps in New York State by establishing: 1) new subsurface CAI data points for the Ordovician and Devonian and 2) new %Ro and Rock Eval subsurface data points for Middle and Upper Devonian black shale units. The thermal maturity of the Ordovician and Devonian rocks is of major interest because they contain the source for most of the unconventional natural gas resources in the basin. Thermal maturity patterns of the Middle Ordovician Trenton Group are evaluated here because they closely approximate those of the overlying Ordovician Utica Shale that is believed to be the source rock for the regional oil and gas accumulation in Lower Silurian sandstones (Jenden and others, 1993; Ryder and others, 1998). Improved CAI-based thermal maturity maps of the Ordovician are important to identify areas of optimum gas generation from the Utica Shale and to provide constraints for interpreting the origin of oil and gas in the Lower Silurian regional accumulation, in particular, its basin-centered part (Ryder, 1998). Thermal maturity maps of the Devonian will better constrain burial history-petroleum generation models of the Utica Shale, as well as place limitations on the origin of regional oil and gas accumulation in Upper Devonian sandstone and Middle to Upper Devonian black shale.
Maps showing geology, oil and gas fields, and geologic provinces of the Asia Pacific region
This digitally compiled maps include geology, geologic provinces, and oil and gas fields of the Asia Pacific Region. The map is part of a worldwide series of maps on CD-ROM released by the U.S. Geological Survey's World Energy Project. The goal of the project is to assess the undiscovered, technically recoverable oil and gas resources of the world and report these results by the year 2000. For data management purposes, the world was divided into eight energy regions corresponding approximately to the economic regions of the world as defined by the U.S. Department of State. The Asia Pacific Region (Region 3) includes Australia, Brunei, Cambodia, The People's Republic of China, Fiji, Indonesia, Japan, North and South Korea, Laos, Malaysia, Mongolia, New Caledonia, New Zealand, Papua New Guinea, Philippines, Thailand, Vanuatu, and Vietnam.
Black shale source rocks and oil generation in the Cambrian and Ordovician of the central Appalachian Basin, USA
Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft 3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician black shale (Utica and Antes shales) in the Appalachian basin. Moreover, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in these same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitumen extract geochemistry identify the black shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. T max , CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network controlled by basement tectonics aided in the distribution of oil from the source to the trap. This fracture network permitted oil to move laterally and stratigraphically downsection through eastward-dipping, impermeable carbonate sequences to carrier zones such as the Middle Ordovician Knox unconformity, and to reservoirs such as porous dolomite in the Middle Ordovician Trenton Limestone in the Lima-Indiana field. Some of the oil and gas from the Utica-Antes source escaped vertically through a partially fractured, leaky Upper Ordovician shale seal into widespread Lower Silurian sandstone reservoirs.
Characteristics of discrete and basin-centered parts of the Lower Silurian regional oil and gas accumulation, Appalachian basin: Preliminary results from a data set of 25 oil and gas fields
Oil and gas trapped in Lower Silurian "Clinton" sands and Medina Group sandstone constitute a regional hydrocarbon accumulation that extends 425 mi in length from Ontario, Canada to northeastern Kentucky. The 125-mi width of the accumulation extends from central Ohio eastward to western Pennsylvania and west-central New York. Lenticular and intertonguing reservoirs, a gradual eastward decrease in reservoir porosity and permeability, and poorly segregated gas, oil, and water in the reservoirs make it very difficult to recognize clear-cut geologic- and production-based subdivisions in the accumulation that are relevant to resource assessment. However, subtle variations are recognizable that permit the regional accumulation to be subdivided into three tentative parts: a western gas-bearing part having more or less discrete fields; an eastern gas-bearing part having many characteristics of a basin-centered accumulation; and a central oil- and gas-bearing part with "hybrid" fields that share characteristics of both discrete and basin-centered accumulation. A data set of 25 oil and gas fields is used in the report to compare selected attributes of the three parts of the regional accumulation. A fourth part of the regional accumulation, not discussed here, is an eastern extension of basin-centered accumulation having local commercial gas in the Tuscarora Sandstone, a proximal facies of the Lower Silurian depositional system. A basin-centered gas accumulation is a regionally extensive and commonly very thick zone of gas saturation that occurs in low-permeability rocks in the central, deeper part of a sedimentary basin. Another commonly used term for this type of accumulation is deep-basin gas accumulation. Basin-centered accumulation is a variety of continuous-type accumulation. The "Clinton" sands and Medina Group sandstone part of the basin-centered gas accumulation is characterized by: a) reservoir porosity ranging from about 5 to 10 percent; b) reservoir permeability equal to or less than 0.1 mD; c) low reservoir water saturation and an average water yield per well less than about 9 to 13 BW/MMCFG; d) a broadly defined updip water-block trap; e) underpressured reservoirs with a gradient ranging from 0.25 to 0.35 psi/ft; and f) reservoir temperature of at least 125° F (52° C). Other than for historical and location purposes, the term field has little or no meaning as an assessment unit for the regional accumulation. In practice, each designated field represents a production sweet spot having relatively high EURs per well that in turn merges with surrounding gas-productive regions that are generally larger in area but have lower EURs per well. This important feature of the Lower Silurian regional accumulation, whereby most wells drilled into it are gas productive, must be considered when assessing its potential for remaining recoverable gas resources. Most of the remaining gas resources reside in "Clinton" sands and Medina Group sandstone in the basin-centered part of the accumulation where as much as several tens of TCF of natural gas may be technically recoverable. The Tuscarora Sandstone in the eastern extension of the basin-centered part of the accumulation underlies a very large area and, although commonly characterized by very low porosity and permeability and low-Btu gas, probably contains additional gas resources. Remaining undiscovered recoverable gas and oil resources in the discrete and hybrid parts of the accumulation are primarily located beneath Lake Erie.
Stratigraphic framework of Cambrian and Ordovician rocks in the central Appalachian Basin from Campbell County Kentucky, to Tazwell County, Virginia
No abstract available.
The Areal Extent of Continuous Type Gas Accumulations in Lower Silurian Clinton Sands and Medina Group Sandstones of the Appalachian Basin and the Environments Affected by Their Development
In order to best preserve and manage our energy and natural resources we must understand the relationships between these resources and the impacts of their development. To further this understanding the U.S. Geological Survey is studying unconventional continuous-type and, to a lesser extent, conventional oil and gas accumulations and the environmental impacts associated with their development. Continuous-type gas accumulations are generally characterized by low matrix permeabilities, large areal extents, and no distinct water contacts. This basin scale map shows the overall extent of these accumulations and the general land use types that may be impacted by their development. The Appalachian Basin has the longest history of oil and gas exploration and production in the United States. Since Drake's Titusville discovery well was drilled in 1859, oil and gas has been continuously produced in the basin. While there is still a great deal of oil and gas production, new field discoveries are rare and relatively small. For most of the second half of the 20th century the Appalachian basin has been considered a mature petroleum province because most of the large plays have already been discovered and developed. One exception to this trend is the Lower Silurian Clinton Sands and Medina Group Gas play which is being developed in New York, Pennsylvania, and Ohio. This continuous-type gas play has been expanding since the early 1970's (see inset maps). In the 1980's economic incentives such as large increases in wellhead prices further stimulated continuous-type gas resource development. Continuous-type gas plays can be large in areal extent and in thickness. 'Sweetspots' (areas of greater prodcution) are hard to predict and generally associated with better than average permeabilities, and enhanced by natural fracture systems. With an overall success rate often approaching 90%, drilling most of the play with closely spaced wells is often the best way to maximize gas recovery. Some positive economic characteristics associated with the development of these continuous-type accumulations are high success rates, low drilling and development costs, and low water production, which results in low water disposal costs. Large areas within the Appalachian basin with good potential for this type of gas accumulation remain to be tested. Positive environmental characteristics include, a clean energy source, low water production, and relatively low surface impact. Some negative characteristics associated with these continuous -type accumulations are low individual well production rates and small well drainage area. Negative environmental characteristics are primarily related to the dense well spacing used to develop the resource to its full potential. Often negative environmental impacts such as surface disturbance can be greatly reduced. The number of well sites can be decreased by using a single centrally located surface location and associated facilities for several directionally or horizonatally drilled wells. This also minimizes the transportation infrastructure (access roads and pipelines) required to maintain the wells and deliver the gas. Visual impacts can be reduced by selecting well locations visible only over short distances. While the prospective area is large, potential decreases basin- ward and toward the northeast and southwest. These areas are represented by the lower potential plays 6727, 6730, and 6731. The U.S. Geological Survey landuse and landcover data was derived from USGS 1:250,000 and 1:100,000 scale maps. This information was collected between the mid 1970s to mid 1980s. The land use and land cover data was mapped and coded using the Anderson classification system (Anderson, 1975) which is a hierarchical system of general (level 1) to more specific (level 2) characterization. Level 1 characterization was used for this map; the land use and land cover designations are displayed below in the Explanation. T
Stratigraphic framework of Cambrian and Ordovician rocks in the central Appalachian basin from Fayette County, Ohio to Botetourt County, Virginia
No abstract available.
Fracture patterns and their origin in the upper Devonian Antrim Shale gas reservoir of the Michigan basin: A review
INTRODUCTION: Black shale members of the Upper Devonian Antrim Shale are both the source and reservoir for a regional gas accumulation that presently extends across parts of six counties in the northern part of the Michigan basin (fig. 1). Natural fractures are considered by most petroleum geologists and oil and gas operators who work the Michigan basin to be a necessary condition for commercial gas production in the Antrim Shale. Fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which, otherwise, has a low matrix permeability. Moreover, the fractures assist in the release of gas adsorbed on mineral and(or) organic matter in the shale (Curtis, 1992). Depths to the gas-producing intervals (Norwood and Lachine Members) generally range from 1,200 to 1,800 ft (Oil and Gas Journal, 1994). Locally, wells that produce gas from the accumulation are as deep as 2,200 (Oil and Gas Journal, 1994). Even though natural fractures are an important control on Antrim Shale gas production, most wells require stimulation by hydraulic fracturing to attain commercial production rates (Kelly, 1992). In the U.S. Geological Survey's National Assessment of United States oil and gas, Dolton (1995) estimates that, at a mean value, 4.45 trillion cubic feet (TCF) of gas are recoverable as additions to already discovered quantities from the Antrim Shale in the productive area of the northern Michigan trend. Dolton (1995) also suggests that undiscovered Antrim Shale gas accumulations exist in other parts of the Michigan basin. The character, distribution, and origin of natural fractures in the Antrim Shale gas accumulation have been studied recently by academia and industry. The intent of these investigations is to: 1) predict 'sweet spots', prior to drilling, in the existing gas-producing trend, 2) improve production practices in the existing trend, 3) predict analogous fracture-controlled gas accumulations in other parts of the Michigan basin, and 4) improve estimates of the recoverable gas in the Antrim Shale gas plays (Dolton, 1995). This review of published literature on the characteristics of Antrim Shale fractures, their origin, and their controls on gas production will help to define objectives and goals in future U.S. Geological Survey studies of Antrim Shale gas resources.
Possible continuous-type (unconventional) gas accumulation in the Lower Silurian "Clinton" sands, Medina Group and Tuscarora Sandstone in the Appalachian Basin; a progress report of the 1995 project activities
INTRODUCTION: In the U.S. Geological Survey's (USGS) 1995 National Assessment of United States oil and gas resources (Gautier and others, 1995), the Appalachian basin was estimated to have, at a mean value, about 61 trillion cubic feet (TCF) of recoverable gas in sandstone and shale reservoirs of Paleozoic age. Approximately one-half of this gas resource is estimated to reside in a regionally extensive, continuous-type gas accumulation whose reservoirs consist of low-permeability sandstone of the Lower Silurian 'Clinton' sands and Medina Group (Gautier and others, 1995; Ryder, 1995). Recognizing the importance of this large regional gas accumulation for future energy considerations, the USGS initiated in January 1995 a multi-year study to evaluate the nature, distribution, and origin of natural gas in the 'Clinton' sands, Medina Group sandstones, and equivalent Tuscarora Sandstone. The project is part of a larger natural gas project, Continuous Gas Accumulations in Sandstones and Carbonates, coordinated in FY1995 by Ben E. Law and Jennie L. Ridgley, USGS, Denver. Approximately 2.6 man years were devoted to the Clinton/Medina project in FY1995. A continuous-type gas accumulation, referred to in the project, is a new term introduced by Schmoker (1995a) to identify those natural gas accumulations whose reservoirs are charged throughout with gas over a large area and whose entrapment does not involve a downdip gas-water contact. Gas in these accumulations is located downdip of the water column and, thus, is the reverse of conventional-type hydrocarbon accumulations. Commonly used industry terms that are more or less synonymous with continuous-type gas accumulations include basin- centered gas accumulation (Rose and others, 1984; Law and Spencer, 1993), tight (low-permeability) gas reservoir (Spencer, 1989; Law and others, 1989; Perry, 1994), and deep basin gas (Masters, 1979, 1984). The realization that undiscovered gas in Lower Silurian sandstone reservoirs of the Appalachian basin probably occurs in a continuous accumulation rather than in conventionally trapped, discrete accumulations represents a significant departure from the 1989 National Assessment (Mast and others, 1989; deWitt, 1993). In 1989, a direct assessment (field-size distributions required for play analysis were unavailable) of the Lower Silurian sandstone play gave, at a mean value, about 1.7 TCF of gas. The 1995 estimate (~30 TCF of gas) is so much greater than the 1989 estimate (~1.7 TCF of gas) because of the interpreted continuous nature of the accumulation and the assessment methodology applied. The methodology for continuous hydrocarbon accumulations assumes that the reservoirs in the accumulation are gas-saturated and takes into account: 1) estimated ultimate recovery (EUR) per well probability distributions, 2) optimum area that a well can drain (spacing), 3) number of untested drill sites having the appropriate spacing area, 4) success ratio of previously drilled holes, and 5) risk (Schmoker, 1995b). Davis (1984), Zagorski (1988, 1991), and Law and Spencer (1993) were among the first petroleum geologists to suggest that gas in the 'Clinton' sands and Medina Group sandstones was trapped in a basin-centered/deep basin accumulation. They recognized many of the earmarks of a basin-centered/deep basin accumulation such as low-permeability reservoirs, abnormally low formation pressure, coalesced gas fields, gas shows or production in most holes drilled, low water yields, and a general lack of structural control on entrapment. Ryder (1995) adopted this interpretation by defining four continuous-type gas plays (6728-6731) in the 'Clinton' sands-Medina Group interval (fig.1). Play 6728 (Clinton/Medina sandstone gas high potential) covers a 17,000 sq mi region of western New York, northwestern Pennsylvania, eastern Ohio, and a small part of westernmost West Virginia that is very favorable for future gas resources (fig.1). Also, this play includes a l
Selected bibliography of Appalachian coalbed methane
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Stratigraphic framework of Cambrian and Ordovician rocks in the central Appalachian basin from Morrow County, Ohio, to Pendleton County, West Virginia
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Stratigraphic framework of Cambrian and Ordovician rocks in the central Appalachian Basin from Medina County, Ohio, through southwestern and south-central Pennsylvania to Hampshire County, West Virginia
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Geochemistry of selected oil and source rock samples from Cambrian and Ordovician strata, Ohio-West Virginia-Tennessee part of the Appalachian Basin
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Mineral resources of the McCullough Peaks Wilderness Study Area, Park County, Wyoming
No abstract available.
Patrick Draw field, Wyoming - 1 seismic expression of subtle strat trap in Upper Cretaceous Almond
The east flank of the Rock Springs uplift and the adjacent Wamsutter arch contain several large hydrocarbon accumulations. Among these accumulations are Patrick Draw field, which produces oil and gas from a stratigraphic trap in the Upper Cretaceous Almond formation, and Table Rock field, a faulted anticlinal trap that produces gas from multiple Tertiary, Mesozoic, and Paleozoic reservoirs. The principal petroleum reservoir in Patrick Draw field is a sandstone at the top of the Almond formation. This sandstone attains a maximum thickness of 35ft and piches out westward into relatively impervious silt-stone and shale that constitute the trapping facies. The objective of this investigation is to determine whether or not the stratigraphic trap at Patrick Draw can be detected on a 12 fold, common depth point seismic profile acquired by Forest Oil Corp. and its partners. The seismic line is 18.5 miles long and crosses Patrick Draw and Table Rock fields.
Tectonically controlled fan delta and submarine fan sedimentation of late Miocene age, southern Temblor Range, California
The Santa Margarita Formation in the southern Temblor Range, composed of conglomerate and subordinate sandstone, evolved as a large complex of fan deltas and submarine fans in late Miocene time. An 80 to 90-m.y.-old granitic basement of the Salinian block and an accompanying 23.5-m.y.-old volcanic field now located in the northern Gabilan Range and the Pinnacles area, respectively, were the primary source terranes. In general, the fan deltas crop out along the west side of the southern Temblor Range, whereas the proximal parts of the submarine fans crop out along the east side of the range. The fan deltas consist of subaerial topset beds and low-angle basinward-dipping subaqueous foreset beds. Strata interpreted to be topset beds are composed largely of conglomerate with thick to very thick horizontal beds and matrix-supported clasts. Most of the thick to very thick conglomerate beds are internally massive and disorganized. Strata interpreted as foreset beds are composed of thick-bedded, large-scale, low-angle, cross-stratified conglomerate and sandstone units which commonly are internally massive. Abundant molluskan macrofossils such as Ostrea and Pecten are present in the subaqueous foreset beds; many have been displaced downslope from their original site of deposition. Conglomerate- and sandstone-filled submarine canyons, through which coarse-grained detritus was transported to the adjacent submarine fans, locally have cut into the foreset beds of the fan deltas. These submarine canyon deposits are generally better stratified than adjacent foreset-bed deposits, and they consist of thick horizontal beds, internally massive or normally graded, arranged in fining- and thinning-upward sequences. Isolated and composite conglomerate- and sandstone-filled channels, which crop out on the east flank of the southern Temblor Range, are interpreted as proximal submarine-fan channel deposits. These channel-form conglomerate and sandstone deposits are characterized by thick, horizontal beds which are internally massive or normally graded containing division T a , and locally T b , of the Bouma sequence. Sparse calcareous foraminifers collected from diatomaceous interbeds suggest that these fan channels were deposited in upper bathyal water depths. Subaerial and regenerated subaqueous debris flows probably formed the bulk of the Santa Margarita fan delta and submarine fan system. Santa Margarita debris flows ranged from the mudflow variety to the cataclysmic debris-avalanche variety. The cogenetic Republic and Williams sandstones of local usage, located on the east side of the southern Temblor Range, are slightly older and finer grained than the Santa Margarita Formation. These units, containing well-graded sandstones, fining- and thinning-upward and coarsening- and thickening-upward sandstone sequences, thick-bedded tabular and channel-shaped sandstones, a mixture of shallow- and deep-water foraminifers, and a fan-shaped geometry in the subsurface, are interpreted as submarine fan deposits. Sedimentation associated with the Santa Margarita Formation was intimately related to the growing southern Temblor Range anticlinorium and the right-laterally shifting Salinian block along the San Andreas fault. Examples of control exerted on Santa Margarita sedimentation by the southern Temblor Range anticlinorium include the preferential accumulation of sediments along the flanks of the anticlinorium, thickening of strata on the downthrown side of the Recruit Pass fault and on flanks of selected anticlines, intraformational unconformities, and possible partial blockage of the eastward-prograding fan deltas by the Recruit Pass fault. East of the growing southern Temblor Range anticlinorium, the distal ends of the Santa Margarita submarine fans were deflected northwestward by the growing Buena Vista Hills anticline. Several examples of well-defined diachronous sedimentation, where conglomerates and sandstones of the Santa Margarita Formation occupy progressively higher stratigraphic levels in a northwest direction subparallel to the trace of the San Andreas fault, strongly imply that the Salinian basement terrane was shifting in a right-lateral sense during Santa Margarita sedimentation. Regional factors of importance in focusing conglomerate sedimentation on the southern Temblor Range locale for a 2- to 3-m.y. period in the late Mohnian were right-lateral oblique slip on the San Andreas fault, formation of the "big bend" in the San Andreas fault by left-lateral slip along the Garlock and White Wolf faults, and the partial overlap of the Salinian and Franciscan assemblage basement rocks.