Donald L. Gautier

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.

Circum-Arctic petroleum systems identified using decision-tree chemometrics

Source- and age-related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55N latitude. A unique, multitiered chemometric (multivariate statistical) decision tree was created that allowed automated classification of 31 genetically distinct circum-Arctic oil families based on a training set of 622 oil samples. The method, which we call decision-tree chemometrics, uses principal components analysis and multiple tiers of K-nearest neighbor and SIMCA (soft independent modeling of class analogy) models to classify and assign confidence limits for newly acquired oil samples and source rock extracts. Geochemical data for each oil sample were also used to infer the age, lithology, organic matter input, depositional environment, and identity of its source rock. These results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation.

Arctic petroleum geology

The vast Arctic region contains nine proven petroleum provinces with giant resources but over half of the sedimentary basins are completely undrilled, making the region the last major frontier for conventional oil and gas exploration. This book provides a comprehensive overview of the geology and the petroleum potential of the Arctic. Nine papers offer a circum-Arctic perspective on the Phanerozoic tectonic and palaeogeographic evolution, the currently recognized sedimentary basins, the gravity and magnetic fields and, perhaps most importantly, the petroleum resources and yet-to-find potential of the basins. The remaining 41 papers provide data-rich, geological and geophysical analyses and individual oil and gas assessments of specific basins throughout the Arctic. These detailed and well illustrated studies cover the continental areas of Laurentia, Baltica and Siberia and the Arctic Ocean. Of special interest are the 13 papers providing new data and interpretations on the extensive, little known, but promising, basins of Russia. A DVD is provided inside the back of the book, that contains PDFs of all papers plus all related Supplementary Publications.

Sandstone porosity as a function of thermal maturity

Sandstone porosity decreases in the subsurface as a power function of thermal maturity: {phi} = A(M){sup B}, where {phi} is porosity and M is a measure of thermal maturity representing integrated time-temperature history; A and B are constants for a given sandstone of homogeneous properties but vary between data sets. The commonly observed exponential dependence of sandstone porosity upon depth follows as a special case from this power-function relation when temperature increases linearly with depth. The consideration of sandstone porosity in terms of time-temperature exposure offers advantages in the comparison of porosity data from diverse geologic settings, the recognition of unusual porosity within a sandstone sequence, and the prediction of porosity ahead of the drill and at times in the geologic past.

Cretaceous shales from the western interior of North America: Sulfur/carbon ratios and sulfur-isotope composition

Carbon and sulfur abundance and δ 34 S of pyrite sulfur were studied in cores of selected Cretaceous marine shales from the western interior of North America. Sulfur/carbon ratios average 0.67, a value greater than that observed in recent marine sediments and much higher than global values calculated for the Cretaceous. Increased S/C ratios probably result from generally low levels of bioturbation and enhanced efficiency of sulfate reduction due to low oxygen levels in the Cretaceous seaway. Isotopic compositions of pyrite sulfur vary systematically with the level of oxygenation of the depositional environment and therefore with organic carbon abundance and type of organic matter. Samples with organic carbon in excess of 4 wt% contain disseminated pyrite that is extremely depleted in 34 S (mean δ 34 S = −31‰); these samples are laminated clay shales that contain hydrogen-rich (type II) organic matter. Samples containing less than 1.5% organic carbon display relatively “heavy” but wide ranging δ 34 S values (δ 34 S = −34.6‰ to +16.8‰; mean δ 34 S = −12.4‰); these samples are highly bioturbated and contain only type III, hydrogen-poor organic matter. Samples containing intermediate amounts of organic carbon contain pyrite with δ 34 S values averaging −25.9‰ and contain mixed type II and type III organic matter. The higher organic carbon content and the preservation of hydrogen-rich organic matter generally correlate with slow sedimentation. Samples rich in organic carbon and containing isotopically “light” sulfide sulfur accumulated beneath anoxic and perhaps sulfidic bottom waters. Samples with intermediate organic matter content and intermediate sulfur isotopic compositions accumulated under mainly dysaerobic bottom waters. Samples with relatively low amounts of organic carbon and wide-ranging but less negative sulfur isotopic values were deposited beneath oxygenated bottom waters. Sulfur-isotope data are apparently a sensitive indicator of diagenetic or depositional facies of fine-grained Cretaceous rocks in the western interior.

Isotopic composition of pyrite: Relationship to organic matter type and iron availability in some North American cretaceous shales

The S isotope composition of pyrite in Cretaceous shales from the Western Interior of North America is related to organic C abundance, kerogen type and Fe availability. Both calcareous and noncalcareous rocks show a correlation between S and C, but noncalcareous rocks are relatively enriched in S with a higher S/C ratio. This higher ratio probably shows that pyrite formation was Fe limited in the calcareous rocks. Organic-carbon-rich noncalcareous shales accumulated slowly beneath anoxic bottom waters. The anoxic bottom waters allowed hydrogen-rich organic matter to be preserved. Such shales have a narrow range of 34S-depleted sulfide and have Fe/S ratios like stoichiometric pyrite, suggesting that pyrite formation in organic-rich shales was also limited by Fe availability. Conversely, organic-poor shales commonly accumulated at comparatively high rates, contain hydrogen-poor and refractory organic matter, and have a wide range of pyrite-S isotopic compositions. These organic-poor shales contain post-sulfidic authigenic minerals such as siderite and have excess reactive Fe rather than pyrite stoichiometry. Evidently Fe played a large role in early diagenesis and determined the course of post-sulfidic diagenesis. Fe availability was, however, mainly controlled by provenance, by the rates of sediment accumulation, and by the oxygen content of the depositional environment.

An evaluation of the U.S. Geological Survey World Petroleum Assessment 2000

This study compares the additions to conventional crude oil and natural gas reserves as reported from January 1996 to December 2003 with the estimated undiscovered and reserve-growth volumes assessed in the U.S. Geological Survey World Petroleum Assessment 2000, which used data current through 1995. Approximately 28% of the estimated additions to oil reserves by reserve growth and approximately 11% of the estimated undiscovered oil volumes were realized in the 8 yr since the assessment (27% of the time frame for the assessment). Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10% of the estimated undiscovered gas volumes were realized. Between 1995 and 2003, growth of oil reserves in previously discovered fields exceeded new-field discoveries as a source of global additions to reserves of conventional oil by a ratio of 3:1. The greatest amount of reserve growth for crude oil occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in sub-Saharan Africa. The greatest amount of reserve growth for natural gas occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas-field discoveries exceeded new oil-field discoveries.

Chapter 1 An overview of the petroleum geology of the Arctic

Abstract Nine main petroleum provinces containing recoverable resources totalling 61 Bbbl liquids+269 Bbbloe of gas are known in the Arctic. The three best known major provinces are: West Siberia–South Kara, Arctic Alaska and Timan–Pechora. They have been sourced principally from, respectively, Upper Jurassic, Triassic and Devonian marine source rocks and their hydrocarbons are reservoired principally in Cretaceous sandstones, Triassic sandstones and Palaeozoic carbonates. The remaining six provinces except for the Upper Cretaceous–Palaeogene petroleum system in the Mackenzie Delta have predominantly Mesozoic sources and Jurassic reservoirs. There are discoveries in 15% of the total area of sedimentary basins (c. 8×106 km2), dry wells in 10% of the area, seismic but no wells in 50% and no seismic in 25%. The United States Geological Survey estimate yet-to-find resources to total 90 Bbbl liquids+279 Bbbloe gas, with four regions – South Kara Sea, Alaska, East Barents Sea, East Greenland – dominating. Russian estimates of South Kara Sea and East Barents Sea are equally positive. The large potential reflects primarily the large undrilled areas, thick basins and widespread source rocks.

Reserve growth in oil fields of the North Sea

The assessment of petroleum resources of the North Sea, as well as other areas of the world, requires a viable means to forecast the amount of growth of reserve estimates (reserve growth) for discovered fields and to predict the potential fully developed sizes of undiscovered fields. This study investigates the utility of North Sea oil field data to construct reserve-growth models. Oil fields of the North Sea provide an excellent dataset in which to examine the mechanisms, characteristics, rates and quantities of reserve growth because of the high level of capital investments, implementation of sophisticated technologies and careful data collection. Additionally, these field data are well reported and available publicly. Increases in successive annual estimates of recoverable crude oil volumes indicate that oil fields in the North Sea, collectively and in each country, experience reserve growth. Specific patterns of reserve growth are observed among countries and primary producing reservoir-rock types. Since 1985, Norwegian oil fields had the greatest volume increase; Danish oil fields increased by the greatest percentage relative to 1985 estimates; and British oil fields experienced an increase in recoverable oil estimates for the first ten years since 1985, followed by a slight reduction. Fields producing primarily from clastic reservoirs account for the majority of the estimated recoverable oil and, therefore, these fields had the largest volumetric increase. Fields producing primarily from chalk (limestone) reservoirs increased by a greater percentage relative to 1985 estimates than did fields producing primarily from clastic reservoirs. Additionally, the largest oil fields had the greatest volumetric increases. Although different reserve-growth patterns are observed among oil fields located in different countries, the small number of fields in Denmark precludes construction of reserve-growth models for that country. However, differences in reserve-growth patterns among oil fields that produce from primarily clastic and primarily chalk reservoirs, in addition to a greater number of fields in each of the two categories, allow separate reserve-growth models to be constructed based on reservoir-rock type. Reserve-growth models referenced to the date of discovery and to the date of first production may be constructed from North Sea field data. Years since discovery or years since first production are used as surrogates for, or measures of, field-development effort that is applied to promote reserve growth. Better estimates of recoverable oil are made as fields are developed. Because much of the field development occurs some time later than the field discovery date, reserve-growth models referenced to the date of first production may provide a more appropriate measure of development than does date of discovery.

Lithology, Reservoir Properties, and Burial History of Portion of Gammon Shale (Cretaceous), Southwestern North Dakota

In the northern Great Plains, large quantities of biogenic methane are contained at shallow depths in Cretaceous marine mudstones. The Gammon Shale and equivalents of the Milk River Formation in Canada, which comprise most sediments deposited offshore during the Eagle-Telegraph Creek regression, are typical of such gas-bearing rocks. At Little Missouri field, southwestern North Dakota, Gammon reservoirs consist of discontinuous lenses and laminae of siltstone, less than 10 mm thick, enclosed by silty clay shale. Large amounts of allogenic clay, including highly expansible mixed-layer illite-smectite cause great water sensitivity and high measured and calculated water-saturation values. Reconstructed burial depths, clay mineralogy, and organic matter maturation studies show that the Gammon has not undergone thermal conditions sufficient for oil or thermal gas generation. Scarce authigenic minerals such as pyrite, siderite, and calcite probably formed as a result of bacterial metabolism early in the burial history. The scarcity of authigenic silicates suggests that diagenesis has been inhibited during much of the burial history by the presence of free methane. Shale layers are practically impermeable whereas siltstone microlenses are porous (30 to 40%) and have permeabilities on the order of 3 to 30 md. Reservoir continuity between siltstone layers is poor and, overall, reservoir permeability is probably less than 0.4 md. Connecting passageways between siltstone lenses are 0.1 µm or less in diameter. Organic matter in the low-permeability reservoirs served as the source of biogenic methane, and capillary forces acted as the trapping mechanism for gas accumulation. At Little Missouri field, reservoirs and non-reservoirs cannot be distinguished on the basis of lithology, and much of the Gammon interval is potentially economic. Future research should be directed toward determining the physical basis of log response in the low-permeability reservoirs and toward the development or application of water-free recovery technology.