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Richard M. Pollastro

Publications and source records attributed to Richard M. Pollastro.

68 records · Page 4Linked to original sources
USGS1999

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman. One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/?Q??Haushi(!) Total Petroleum System (201401) and Ghaba- Makarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014). In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: (1) the North Oman Huqf?Shu?aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and (2) the middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201). The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon-producing reservoirs within the petroleum system. In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply buried source rocks within the Infracambrian Huqf Supergroup. One general ?North Oman Huqf? type oil is dominant in the Fahud Salt Basin. Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant ?questionable unidentified source? or ?Q?-type Huqf oil source. These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout northcentral Oman. Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces. Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (middle Carboniferous to Lower Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/?Q??Haushi(!) TPS. In contrast, the Lower Cretaceous Shu?aiba and middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin?s production from porous, fractured Shu?aiba limestones in Yibal field, thus the name North Oman Huqf? Shu?aiba(!) TPS. Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup. Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more 3 mechanisms. These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and late Tertiary. Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled. Oman?s recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems. New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next 30 years. Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near future. The middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin. Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu?aiba limestone is documented along fault-dip structures. Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains. Future targets of the Natih TPS will be less obvious

Bulletin↗
USGS1998

Maps showing geology, oil and gas fields and geologic provinces of the Arabian Peninsula

Introduction This digital map compilation, which includes geology, geologic provinces, and oil and gas fields of the Arabian Peninsula, is part of a map series of the world produced by the U.S. Geological Survey World Energy Project. The goal of the project is to produce a worldwide assessment of the undiscovered, technically recoverable oil and gas resources and report these results by the year 2000. To assess the world's petroleum, a sequence of steps is being undertaken proceeding from defining geologic provinces of the world at a comparable scale, allocating oil and gas fields to these provinces, defining petroleum systems within these provinces, and ultimately assessing the undiscovered petroleum potential of selected provinces of the world. A more in-depth discussion of the geologic provinces and their relative ranking in terms of total known petroleum volume is given in USGS Open File Report 97-463 (see Klett and others, 1997).

Open-File Report↗
USGS1989

Mineralogic and textural relations in deeply buried rocks of the Simpson Group (Middle Ordovician)--implications in diagenesis and petroleum geology

The mineral composition and petrography of sandstones, shales, carbonates, and intermediate lithologies were determined on 112 core samples of the Middle Ordovician Simpson Group in the Sunray DX Parker No. 1 Mazur well, Grady County, Oklahoma. Core was recovered from present depths of about 15,900-17,200 ft and included all or parts of the Bromide, Tulip Creek, McLish, Oil Creek, and Joins Formations. The bulk-rock mineral composition of Simpson Group rocks is diverse. The mean weighted composition of 50 sandstone samples is 66% quartz, 14% clay, and 18% carbonate, as determined by X-ray powder diffraction (XRD). Some sandstones from the Oil Creek and Tulip Creek Formations contain as much as 96% quartz. These quartz-rich sandstones were cemented early by silica. Feldspar averages 2%; some sandstones from the McLish Formation contain as much as 15% feldspar. Potassium feldspar is commonly more abundant than plagioclase; potassium feldspar overgrowths are found in some of the sandstones. Most of the shales are clay-rich and quartz-poor, averaging about 85% clay minerals, 7% quartz, and 3% feldspar, by weight, as determined by XRD. Carbonate, fluorapatite, and pyrite are present in variable amounts. Such high clay/quartz ratios are not characteristic of shales and suggest that silica has been expelled by diagenetic processes during burial. The main clay mineral in the Simpson Group at these depths is illite, although iron-rich chlorite is locally concentrated in sandstones. Illite typically makes up >90 wt. % of the clay minerals in sandstones and >95 wt. % of those in shale and carbonate. Total clay content, determined from XRD, correlates closely with total gamma-ray intensity from geophysical logs, because illite is the primary potassium-bearing phase in these deeply buried rocks. Therefore, the gamma-ray log is a good indicator of "shaliness" in potential Simpson reservoirs at similar depths. Much of the carbonate was introduced into the sandstones during burial as calcite, dolomite, or ankerite cement. Early iron-free calcite is commonly replaced by iron-bearing calcite, dolomite, or ankerite. Sandstones and carbonate rocks also contain rhombic dolomite. Many of the dolomite rhombs contain overgrowths of ferroan dolomite or ankerite, as evidenced by staining. Ankerite cementation is later and less selective than earlier dolomite and commonly replaces earlier carbonate or silica cements. Dolomite commonly replaces detrital clay and calcite. Spatial and textural relations suggest that the conversion of smectite to illite contributed, in part, to the formation of dolomite and ankerite cements. Scanning electron miscroscopy reveals that much of the diagenetic illite occurs as tabular fibers in pores or as pseudomorphic intergrowths after smectite. Most chlorite in sandstones is authigenic and occurs as a pore-lining cement or as a pseudomorphic replacement after kaolinite. Secondary porosity, formed mainly from the dissolution of intergranular carbonate cements, is best developed in sandstones from the Oil Creek and Tulip Creek Formations.

Oklahoma↗
USGS1989

Relationship of clay-mineral diagenesis to temperature, age, and hydrocarbon generation–an example from the Anadarko Basin, Oklahoma

Randomly interstratified illite/smectite (I/S) is present in Springeran and Morrowan rocks (Late Mississippian and Early Pennsylvanian) of the Anadarko basin, Oklahoma, at present-day depths <2,750 m, but disappears at depths of 2,750-3,050 m. Only ordered I/S is found in samples below 3,050 m. The work reported here relates the diagenesis of I/S to burial history and oil generation in the Anadarko basin and tests the dependence of the smectite-to-illite reaction on temperature and time. Published temperature models of clay diagenesis suggest that, for Tertiary and Cretaceous rocks, the transition from randomly interstratified I/S to ordered I/S occurs at 100-110°C. Burial reconstructions for the Anadarko basin indicate that maximum temperatures of 100-110°C correspond to present-day burial depths between 2,700 and 3,100 m. These independently calculated depths for the 100-110°C isotherm match the depths at which randomly interstratified I/S is observed to disappear in Morrowan-Springeran rocks. Thus, random I/S disappears at the same temperature in rocks that differ in age by some 300 m.y. Although the extent of the smectite-to-illite reaction is controlled by kinetics, and effects of time are apparent in laboratory experiments and short-lived geologic systems, the results of this study suggest that time plays a secondary role in long-term diagenetic settings.

Oklahoma↗
USGS1985

Comparative geochemical and mineralogical studies of two cyclic transgressive pelagic limestone units, cretaceous Western Interior Basin, U.S.

Pelagic limestone units were deposited in the North American Western Interior seaway during two major Cretaceous transgressive episodes. The Bridge Creek Limestone Member of the Greenhorn Formation, deposited during the Late Cenomanian-Early Turonian transgression, and the Smoky Hill Member of the Niobrara Formation, deposited during the overall Early Coniacian-Early Campanian transgression, are both enriched in organic-carbon and exhibit smallscale carbonate cycles representing periodicities in the range 20 to 40 ky. The distinct periodicity and overall unusual depositional milieu of both units are reflected in their sedimentary structures, mineralogy, and geochemistry. The Bridge Creek Limestone at Pueblo, Colorado, averages 78% CaCO 3 and 1.75% organic carbon with ranges of 42-96% and 0.06-6.97%, respectively, across small-scale cycles. High concentrations of Al, Fe, Mg, K, Ti, Na, Cr, Ni, V; higher Sr/Ca and lower Si/Al ratios; and lighter δ 18 0 in CaCO 3 in dark-colored clay-rich beds all suggest periodic influx of terrestrial clay minerals during times of peak fresh water runoff from uplifted highlands to the west. Higher Sr/Ca ratios in marlstone beds than in limestone beds suggest that the marlstone beds have undergone less diagenetic removal of Sr. Higher concentrations of organic carbon, hydrogen, and sulfur, and preservation of some lamination in the clay-rich beds also suggest that the times of enhanced runoff may have induced stable salinity stratification in the water column, which led to gradual depletion of dissolved oxygen in the bottom waters and enhanced preservation of organic carbon in sediments. The geochemistry also suggests that a significant change in sedimentation occurred at the Cenomanian-Turonian boundary. The geochemical characteristics of the Niobrara Formation near Fort collins, Colorado, are very similar to those of the Bridge Creek Limestone at Pueblo, suggesting similar depositional conditions and source of clastic materials. However, the small scale cycles are present but more subdued in the Niobrara Formation than in the Bridge Creek Limestone, and the Niobrara Formation in the Fort Collins area has not been as altered by diagenesis.

SEPM Special Publication↗
USGS1979

Altered volcanic ash partings in Wasatch Formation coal beds of the northern Powder River basin: composition and geologic applications

In contrast to the coal-bearing rocks of the Appalachian and Eastern Interior Basins, those of the northern Powder River Basin exhibit more complex stratigraphic and facies relationships, and regional correlations of coal beds are, therefore, more difficult to establish. Recently, however, several coal beds in the Powder River Basin, as well as coal beds in several other coal basins of the Rocky Mountain region, have been found to contain thin but persist&middot;ent layers. of altered volcanic ash described as kaolinitic bentonites (Bohor, 1976, 1977, 1978, Bohor and others, 1976, 1978, Bohor and Pillmore, 1976). These layers serve as isochronous marker horizons which aid in correlating coal beds over broad areas.

Wyoming↗