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Janet K. Pitman

Publications and source records attributed to Janet K. Pitman.

At least 37 records · Page 2Linked to original sources
USGS2020

Origin and geochemistry of formation waters from the lower Eagle Ford Group, Gulf Coast Basin, south central Texas

The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125-165 C), development of reservoir over-pressuring (400-800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and ⁸⁷Sr/⁸⁶Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism behind salinity greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing 18O and decreasing 2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is unknown mechanism allowing for water advection into low permeability reservoirs.

Texas↗
USGS2019

Geology and assessment of undiscovered oil and gas resources of the Lomonosov-Makarov Province, 2008

The Lomonosov-Makarov Province lies in the central Arctic Ocean and encompasses the northern part of the oceanic Amerasia Basin (Makarov and Podvodnikov Basins) and the adjoining Lomonosov Ridge and Siberian continental margins. The Amerasia Basin is thought to have been created in the Jurassic and Early Cretaceous by rotational rifting of the Alaska-Siberia margin away from the Canada margin about a pivot point in the Mackenzie Delta and an associated continental-scale transform fault along the Lomonosov Ridge. The province is bounded on the south by the Cretaceous Alpha-Mendeleev Ridge, an undersea ridge composed of plume-type volcanic rocks that obliquely crosses the Amerasia Basin, dividing it into northern and southern parts. The thickest passive-margin succession in the province lies along the Siberian margin, where sediments thin from a maximum thickness along the continental margin to less than 2 km in the basin. The northern part of the province consists of the Lomonosov Ridge, which was rifted away from the Eurasia Plate in the Paleocene during formation of the oceanic Eurasia Basin, creating an isolated, narrow, submerged, but high-standing microcontinent. This part of the province contains sediments that were shed from the Eurasia Plate in the Mesozoic and covered by pelagic and hemipelagic sediments in the Cenozoic, creating depositional successions with thicknesses ranging from about 1 to more than 5 km. This tectonic framework provides the basis for division of the province into four assessment units (AUs), including (1) Lomonosov Ridge AU, (2) Makarov Basin Margin AU, (3) Siberian Passive Margin AU, and (4) Makarov Basin AU. The Lomonosov Ridge and Makarov Basin Margin AUs compose a displaced part of the Cretaceous shelf and slope, respectively, of the Eurasia continental margin with a covering drape of pelagic Cenozoic sediments. The Siberian Passive Margin and Makarov Basin AUs represent the slope of the Siberian continental margin and adjoining basin plain deposits, respectively, deposited on oceanic crust of the northern Amerasia Basin. All of the AUs are entirely submarine and covered by the polar icecap, and consequently have not been explored for petroleum. Petroleum source rock units considered in the assessment of the province are mostly hypothetical, and include Triassic and Jurassic platformal marine shale units on the Lomonosov Ridge, and province-wide Lower Cretaceous synrift, Lower and Upper Cretaceous postrift, and Paleogene organic-rich shale intervals. The most prospective reservoirs and traps are envisioned to include base-of-slope turbidite-fan complexes, slope channels and basins, extensional and growth fault structures, and other stratigraphic, structural, and composite trap features typically present on clastic-dominated continental passive margins. Because of concerns about reservoir quality in the Makarov Basin AU and the detrimental effect of Paleocene rifting in the Lomonosov Ridge AU, these units were not quantitatively assessed, as they were judged to have less than 10 percent probability of containing at least one accumulation of hydrocarbons equal to or greater than 50 million barrels of oil equivalent (MMBOE). The mean volumes of undiscovered resources for the Makarov Basin Margin AU are estimated to be 0.12 billion barrels of oil and 0.74 trillion cubic feet of nonassociated gas, whereas the undiscovered resources for the Siberian Passive Margin AU are estimated to be ~1 billion barrels of oil and 4.7 trillion cubic feet of nonassociated gas.

Professional Paper↗
USGS2019

Geology and assessment of undiscovered oil and gas resources of the Northwest Canada Interior Basins Province, Arctic Canada

The Northwest Canada Interior Basins Province is bounded by the Mackenzie and Richardson Mountains on the southwest and west, by the Eskimo Lakes Arch on the northwest, and by the erosional limit of Paleozoic strata on the east. It lies within the far northwest part of the Paleozoic continent of Laurentia. During early Paleozoic time, it was part of a passive margin formed when the Neoproterozoic supercontinent Rodinia broke apart. A Cambrian marine transgressive sequence gave way to an evaporitic intrashelf basin, succeeded by a westward-building carbonate bank from Late Cambrian through Middle Devonian time. In Late Devonian and early Carboniferous time, the region was buried by a thick succession of south-prograding clastic strata derived from orogenic belts to the northeast and north. A subsequent period of inactivity and erosion persisted until sedimentation resumed as the opening of the Canada Basin initiated an Early Cretaceous marine transgression over much of the region. Later in Cretaceous time, clastic strata derived from Cordilleran uplifts to the southwest began to prograde north, ending with eventual Laramide uplift and deformation in latest Cretaceous and Paleogene time. Two petroleum systems are known within the province. A petroleum system in Cambrian to Middle Devonian strata, sourced by alginitic Cambrian shales and sealed by Cambrian evaporites, is proven by modest gas discoveries in the Colville Hills; generation is attributed to burial under the Upper Devonian clastic wedge. An Upper Devonian petroleum system, proven by the presence of the 250-million-barrel Norman Wells field at the southern edge of the province, was sourced by organic-rich shale of the Canol Formation. Generation is similarly inferred to have been driven by burial beneath the Devonian clastic wedge, perhaps augmented locally by additional Cretaceous burial. Potential reservoirs include Devonian reefs and sandstones stratigraphically below and laterally equivalent to the source rocks, as well as overlying sandstones in the clastic wedge. Subordinate source rocks could include organic-rich shales within the clastic wedge. Principal risks to the lower Paleozoic petroleum system include (1) inadequate reservoir volume for a field of the minimum size and (2) petroleum loss by remigration caused by Laramide deformation. One lower Paleozoic assessment unit (AU) was quantitatively assessed, with estimated resources of 0 to 117 million barrels of oil (MMBO), mean 23 MMBO; and 0 to 1,364 billion cubic feet of gas (BCFG), mean 310 BCFG. The principle risks to the Devonian petroleum system were considered to be (1) lack of preservation due to extensive erosion before the Cretaceous, and (2) inadequate reservoir volume, because the best potential reservoir strata, Devonian reefs, may be absent throughout most of the province owing to either lack of deposition or erosion. These risks were sufficiently high that the single AU defined in the Devonian petroleum system was not quantitatively assessed, because the chance of a field of the minimum size, 50 million barrels of oil equivalent, was estimated to be only 0.1.

Northwest Canada Interior Basins Province↗
USGS2019

Geology and assessment of undiscovered oil and gas resources of the Eurasia Basin Province, 2008

The Eurasia Basin Petroleum Province comprises the younger, eastern half of the Arctic Ocean, including the Eurasia Basin and the outboard part of the continental margin of northern Europe in the Barents and Kara Seas. The province includes the slope and rise sedimentary prism of the Lena Delta, the north-facing outer shelf, slope, and rise of the European passive margin, and sedimentary accumulations in the deep Nansen and Amundsen Basins. The entire province lies north of the Arctic Circle beneath the polar ice cap and includes the North Pole. The province is divided into four assessment units (AUs). The Lena Prodelta AU in the eastern part of the province consists of the deep-marine part of the Lena Delta, which has been deposited across the Gakkel Ridge, an ultraslow spreading ridge. The Nansen Basin Margin AU in the southern part of the province comprises the Cenozoic passive margin sequence of the rift margin of the western (European) part of the Eurasian plate. This AU spans the continent-ocean boundary and includes prerift strata along the outer continental margin. The Nansen Basin and Amundsen Basin AUs encompass the deep abyssal plains of the Eurasia Basin. Lying south of the Gakkel Ridge spreading center, the sedimentary fill of Nansen Basin AU consists of the distal clinoform deposits shed from the western Eurasia passive margin. North of the Gakkel Ridge, Amundsen Basin AU consists of a nascent distal passive-margin sequence derived from the adjacent Lomonosov Ridge and overlying flat-lying deep marine strata shed from distant source areas in Siberia and Greenland after the Lomonosov Ridge subsided below sea level at about 50 Ma. The primary petroleum system thought to be present is sourced in ~50–44 Ma (early to middle Eocene) condensed pelagic deposits that could be widespread in the province. Mean estimates of undiscovered, technically recoverable petroleum resources include <1 billion barrels of oil (BBO) and about 1.4 trillion cubic feet (TCF) of nonassociated gas in Lena Prodelta AU, and < 0.4 BBO and 3.4 TCF nonassociated gas in the Nansen Basin Margin AU. Quantities of natural gas liquids and associated natural gas also are assessed in each of these AUs. The Nansen Basin and Amundsen Basin AUs were not quantitatively assessed because they were judged to have less than 10 percent probability of containing at least one accumulation of 50 MMBOE (million barrels of oil equivalent), the minimum probability required for evaluation in the U.S. Geological Survey Circum-Arctic Resource Appraisal.

Professional Paper↗
USGS2019

Geology and assessment of undiscovered oil and gas resources of the Vilkitskii Basin Province, 2008

The Vilkitskii Basin is a separate petroleum province that lies beneath the continental shelf of the East Siberian Sea east of the New Siberian Islands and northwest of Wrangel Island. It is a basin known only on the basis of gravity data and three seismic profiles. A small, southern part of the basin overlies the Brooks Range–Chukotka late Mesozoic-early Paleogene orogenic belt, but most of the basin lies north of that belt. Its regional setting suggests that it may have similarities to other post-orogenic (successor) basins on the East Siberian Shelf as well as to foreland, rift-sag, and passive margin basins lying north of the orogenic belt such as the North Slope, North Chukchi and Podvodnikov Basins. Although the basin’s petroleum potential is poorly known, extremely thick sediments, diapiric structures, and gas plumes interpreted from a seismic profile are considered favorable features for petroleum presence and imply that there may be an active petroleum system. An overall probability of about 30 percent of at least one petroleum accumulation >50 MMBOE (million barrels of oil equivalent) was determined based on estimated probabilities of the occurrence of petroleum source, adequate reservoir, trap and seal, and favorable timing. A single assessment unit (AU) was defined and assessed, resulting in mean estimates of undiscovered, technically recoverable resources that include about 100 million barrels of oil and 5,500 billion cubic feet of nonassociated gas.

Professional Paper↗
USGS2018

Assessment of undiscovered continuous oil and gas resources in the Wolfcamp Shale and Bone Spring Formation of the Delaware Basin, Permian Basin Province, New Mexico and Texas, 2018

Using a geology-based assessment methodology, the U.S. Geological Survey assessed undiscovered, technically recoverable continuous mean resources of 46.3 billion barrels of oil and 281 trillion cubic feet of gas in the Wolfcamp shale and Bone Spring Formation of the Delaware Basin in the Permian Basin Province, southeast New Mexico and west Texas.

New Mexico, Texas↗