Janet K. Pitman

Assessment of undiscovered oil and gas in the Arctic.

Arctic Energy Reserves The Arctic consists of approximately equal fractions of terrain above sea level, continental shelves with depths less than 500 meters, and deep ocean basins that have been mostly covered in ice. While the deep ocean regions probably have limited petroleum reserves, the shelf areas are likely to contain abundant ones. Based on the limited amount of exploration data available, Gautier et al. (p. 1175) have constructed a probabilistic, geology-based estimate of how much oil and gas may be found. Approximately 30% of the worlds undiscovered gas, and 13% of its undiscovered oil, may be found north of the Arctic Circle. Advances in the technology of hydrocarbon recovery, as well as vanishing ice cover around the North Pole, make the Arctic an increasingly attractive region for energy source development, although the existing reserves are probably not large enough to shift current production patterns significantly. About 30 percent of the world’s undiscovered gas and 13 percent of the world’s undiscovered oil probably exist north of the Arctic Circle. Among the greatest uncertainties in future energy supply and a subject of considerable environmental concern is the amount of oil and gas yet to be found in the Arctic. By using a probabilistic geology-based methodology, the United States Geological Survey has assessed the area north of the Arctic Circle and concluded that about 30% of the world’s undiscovered gas and 13% of the world’s undiscovered oil may be found there, mostly offshore under less than 500 meters of water. Undiscovered natural gas is three times more abundant than oil in the Arctic and is largely concentrated in Russia. Oil resources, although important to the interests of Arctic countries, are probably not sufficient to substantially shift the current geographic pattern of world oil production.

Origin of minerals in joint and cleat systems of the Pottsville Formation, Black Warrior basin, Alabama: Implications for coalbed methane generation and production

Coalbed methane is produced from naturally fractured strata in the lower Pennsylvanian Pottsville Formation in the eastern part of the Black Warrior basin, Alabama. Major fracture systems include orthogonal fractures, which consist of systematic joints in siliciclastic strata and face cleats in coal that strike northeast throughout the basin. Calcite and minor amounts of pyrite commonly fill joints in sandstone and shale and, less commonly, cleats in coal. Joint-fill calcite postdates most pyrite and is a weakly ferroan, coarse-crystalline variety that formed during a period of uplift and erosion late in the burial history. Pyrite forms fine to coarse euhedral crystals that line joint walls or are complexly intergrown with calcite.Stable-isotope data reveal large variations in the carbon isotope composition of joint- and cleat-fill calcite (10.3 to +24.3 Peedee belemnite [PDB]) but only a relatively narrow range in the oxygen-isotope composition of this calcite (16.2 to 4.1 PDB). Negative carbon values can be attributed to 13C-depleted CO2 derived from the oxidation of organic matter, and moderately to highly positive carbon values can be attributed to bacterial methanogenesis. Assuming crystallization temperatures of 2050C, most joint- and cleat-fill calcite precipitated from fluids with 18O ratios ranging from about 11 to +2 standard mean ocean water (SMOW). Uplift and unroofing since the Mesozoic led to meteoric recharge of Pottsville strata and development of freshwater plumes that were fed by meteoric recharge along the structurally upturned, southeastern margin of the basin. Influxes of fresh water into the basin via faults and coalbeds facilitated late-stage bacterial methanogenesis, which accounts for the high gas content in coal and the carbonate cementation of joints and cleats.Diagenetic and epigenetic minerals can affect the transmissivity and storage capacity of joints and cleats, and they appear to contribute significantly to interwell heterogeneity in the Pottsville Formation. In highly productive coalbed methane fields, joint- and cleat-fill calcite have strongly positive 13C values, whereas calcite fill has lower 13C values in fields that are shut in or abandoned. Petrographic analysis and stable-isotope geochemistry of joint- and cleat-fill cements provide insight into coalbed methane reservoir quality and the nature and extent of reservoir compartmentalization, which are important factors governing methane production.

Pressure sensitivity of low permeability sandstones

Abstract Detailed core analysis has been carried out on 32 tight sandstones with permeabilities ranging over four orders of magnitude (0.0002 to 4.8 mD at 5000 psi confining pressure). Relationships between gas permeability and net confining pressure were measured for cycles of loading and unloading. For some samples, permeabilities were measured both along and across bedding planes. Large variations in stress sensitivity of permeability were observed from one sample to another. The ratio of permeability at a nominal confining pressure of 500 psi to that at 5000 psi was used to define a stress sensitivity ratio. For a given sample, confining pressure vs permeability followed a linear log-log relationship, the slope of which provided an index of pressure sensitivity. This index, as obtained for first unloading data, was used in testing relationships between stress sensitivity and other measured rock properties. Pressure sensitivity tended to increase with increase in carbonate content and depth, and with decrease in porosity, permeability and sodium feldspar. However, scatter in these relationships increased as permeability decreased. Tests for correlations between pressure sensitivity and various linear combinations of variables are reported. Details of pore structure related to diagenetic changes appears to be of much greater significance to pressure sensitivity than mineral composition.

Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin

The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrous-pyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.

Concentration and mineralogical residence of elements in rich oil shales of the Green River Formation, Piceance Creek basin, Colorado, and the Uinta Basin, Utah — A preliminary report

Abstract Ten samples from drillcore of two rich oil-shale beds from the Parachute Creek Member of the Eocene Green River Formation, Piceance Creek basin, Colorado, and Uinta Basin, Utah, were analyzed for 37 major, minor, and trace elements. For 23 of these elements, principal mineralogical residence is established or suggested and such studies may provide data which are useful for predicting the kinds and amounts of elements and compounds that might be released into the environment by oil-shale mining operations.

Depositional Setting and Diagenetic Evolution of Some Tertiary Unconventional Reservoir Rocks, Uinta Basin, Utah

The Douglas Creek Member of the Tertiary Green River Formation underlies much of the Uinta basin, Utah, and contains large volumes of oil and gas trapped in a complex of fractured low-permeability sandstone reservoirs. In the southeastern part of the basin at Pariette Bench, the Eocene Douglas Creek Member is a thick sequence of fine-grained alluvial sandstone complexly intercalated with lacustrine claystone and carbonate rock. Sediments were deposited in a subsiding intermontane basin along the shallow fluctuating margin of ancient Lake Uinta. Although the Uinta basin has undergone postdepositional uplift and erosion, the deepest cored rocks at Pariette Bench have never been buried more than 9,800 ft (3,000 m). The sandstones, dominantly lithic arkoses and feldspathic litharenites, were derived from source terranes south of the Uinta basin. Secondary silica and several generations of authigenic calcite [Ca1.8-1.9(Mg0.02-0.06Fe0.02-0.06)(CO3)2], dolomite [Ca1.3-1.4(Mg0.6-0.7Fe0.02-0.04)(CO3)2], and ankerite [Ca1.2-1.3(Mg0.2-0.3Fe0.4-0.6)(CO3)2] form a replacive cement in the sandstones. Commonly, syntaxial overgrowths of late iron-bearing carbonate occur on detrital grains and preexisting relicts of iron-free carbonate cement. In sandstone where carbonate has been partly dissolved, abundant authigenic illite, partly ordered mixed- ayer illite-smectite, and small amounts of chlorite partly to completely fill secondary pores. Isotopic composition of carbonate cement and grain-supported rock range from -0.39 to -6.18 ^pmil for ^dgr13C and -7.80 to -13.98 ^pmil for ^dgr18O, indicating that authigenic carbonate formed at low temperatures in the presence of meteoric waters by a process of solution-precipitation. Enrichment of carbon and oxygen in early diagenetic calcite and fossiliferous rock relative to late diagenetic ankerite indicates a trend toward lighter isotopic carbonate compositions with increasing diagenesis. Kerogenous rocks at Pariette Bench are thermochemically immature and therefore are not the source of oil produced in the field. Hydrocarbons are compositionally similar to some of the oils produced from the Green River Formation in the Bluebell-Altamont field and are interpreted to have migrated from mature Green River source rocks through a network of open fractures. The occurrence of small amounts of hydrocarbon in secondary pores indicates that its emplacement postdated carbonate dissolution.

Marine and Nonmarine Gas-Bearing Rocks in Upper Cretaceous Blackhawk and Neslen Formations, Eastern Uinta Basin, Utah: Sedimentology, Diagenesis, and Source Rock Potential

The Upper Cretaceous Blackhawk and Neslen Formations in the eastern Uinta basin contain large amounts of thermogenic gas that was generated from interbedded humic-rich source rocks. The geometry and distribution of hydrocarbon source and reservoir rocks are controlled by depositional environment. The Blackhawk, composed of laterally extensive sandstone and locally interbedded carbonaceous siltstone and minor coal, reflects deposition in nearshore marine and backshore environments. The Neslen contains organic-rich siltstone and mudstone with lesser amounts of carbonaceous shale, coal, and lenticular sandstone that formed in coastal and lower alluvial-plain depositional settings. Potential reservoir sandstones are composed dominantly of monocrystalline quartz grains and sedimentary lithic fragments. Mechanical compaction during early burial was followed by the precipitation of quartz, carbonate, and barite later in the burial history. Variations in porosity and permeability (2-10%; < 1 md) reflects the presence of authigenic clay, mineral cements, and dissolved lithic grains. Natural fractures, cemented with carbonate, barite, and kaolinite, occur locally. Active hydrocarbon generation occurred in the Neslen and Blackhawk during the Oligocene and Miocene when these units were near their maximum burial depth and temperature. The rate of hydrocarbon generation decreased from the late Miocene to the present, owing to widespread cooling that occurred in response to regional uplift and erosion associated with the development of the Colorado Plateau. Temporally equivalent rocks in other areas of the basin may have experienced similar diagenetic and hydrocarbon generation histories.

Chapter 49: A first look at the petroleum geology of the Lomonosov Ridge microcontinent, Arctic Ocean

Abstract The Lomonosov microcontinent is an elongated continental fragment that transects the Arctic Ocean between North America and Siberia via the North Pole. Although it lies beneath polar pack ice, the geological framework of the microcontinent is inferred from sparse seismic reflection data, a few cores, potential field data and the geology of its conjugate margin in the Barents–Kara Shelf. Petroleum systems inferred to be potentially active are comparable to those sourced by condensed Triassic and Jurassic marine shale of the Barents Platform and by condensed Jurassic and (or) Cretaceous shale probably present in the adjacent Amerasia Basin. Cenozoic deposits are known to contain rich petroleum source rocks but are too thermally immature to have generated petroleum. For the 2008 USGS Circum Arctic Resource Appraisal (CARA), the microcontinent was divided into shelf and slope assessment units (AUs) at the tectonic hinge line along the Amerasia Basin margin. A low to moderate probability of accumulation in the slope AU yielded fully risked mean estimates of 123 MMBO oil and 740 BCF gas. For the shelf AU, no quantitative assessment was made because the probability of petroleum accumulations of the 50 MMBOE minimum size was estimated to be less than 10% owing to rift-related uplift, erosion and faulting.

Preliminary Pore Structure Analysis of Tight Sandstones Using Computer-Processed Photomicrographs: ABSTRACT

The complexity of pore networks in fine-grained low-permeability sandstones makes accurate modeling of fluid-flow properties difficult owing to the lack of quantitative information concerning the pore structure. Many such sandstones in the Uinta basin, Utah, are reservoirs for large amounts of natural gas. These sandstones, most of which are Tertiary and Cretaceous in age, commonly contain pores that vary greatly in size. Variation in pore size is partly due to the dissolution of mineral grains and pore-filling cement; howwever, many of the secondary pore spaces contain authigenic clay, principally illite and kaolinite, which has served to create micropore space. We have developed a method to digitize and quantify pore networks of fine-grained rocks using the apparent pore space observed in photomicrographs of thin sections. By digitizing numerous photographs, statistical data were generated, thereby making it possible to address the problem of pore structure. Pore structure data include such parameters as the pore size and shape, anisotropy of the pore arrangement within the rock matrix, and pore connectivity. Specimens obtained from CIG Exploration, Inc., Natural Buttes 21 cores (Sec. 15, T10S, R22E) were used to determine End_Page 558------------------------------ pore anisotropies of tight sandstones. Several analysis methods were used; each indicated that little anisotropy was present in the pore structure. Statistical-shape parameters, derived from the measured perimeters and areas of the pores, suggest that most of the pores within each sample are tabular rather than tubular in shape. Knowledge of the pore structure suggests that the pores should be treated as oblate rather than prolate spheroids in modeling the electromagnetic or fluid-flow properties of these rocks. End_of_Article - Last_Page 559------------

Chapter 9: Oil and gas resource potential north of the Arctic Circle

Abstract The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.