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Alaska: A twenty-first-century petroleum province
Alaska, the least explored of all United States regions, is estimated to contain approximately 40% of total U.S. undiscovered, technically recoverable oil and natural-gas resources, based on the most recent U.S. Department of the Interior (U.S. Geological Survey and Minerals Management Service) estimates. Northern Alaska, including the North Slope and adjacent Beaufort and Chukchi continental shelves, holds the lion's share of the total Alaskan endowment of more than 30 billion barrels (4.8 billion m 3 ) of oil and natural-gas liquids plus nearly 200 trillion cubic feet (5.7 trillion m 3 ) of natural gas. This geologically complex region includes prospective strata within passive-margin, rift, and foreland-basin sequences. Multiple source-rock zones have charged several regionally extensive petroleum systems. Extensional and compressional structures provide ample structural objectives. In addition, recent emphasis on stratigraphic traps has demonstrated significant resource potential in shelf and turbidite systems in Jurassic to Tertiary strata. Despite robust potential, northern Alaska remains a risky exploration frontier - a nexus of geologic complexity, harsh economic conditions, and volatile policy issues. Its role as a major petroleum province in this century will depend on continued technological innovations, not only in exploration and drilling operations, but also in development of huge, currently unmarketable natural-gas resources. Ultimately, policy decisions will determine whether exploration of arctic Alaska will proceed.
Gas shale/oil shale
The production of natural gas from shales continues to increase in North America, and shale gas exploration is on the rise in other parts of the world since the previous report by this committee was published by American Association of Petroleum Geologists, Energy Minerals Division (2009). For the United States, the volume of proved reserves of natural gas increased 11% from 2008 to 2009, the increase driven largely by shale gas development (Energy Information Administration 2010c). Furthermore, shales have increasingly become targets of exploration for oil and condensate as well as gas, which has served to greatly expand their significance as ‘‘unconventional’’ petroleum reservoirs. This report provides information about specific shales across North America and Europe from which gas (biogenic or thermogenic), oil, or natural gas liquids are produced or is actively being explored. The intent is to reflect the recently expanded mission of the Energy Minerals Division (EMD) Gas Shales Committee to serve as a single point of access to technical information on shales regardless of the type of hydrocarbon produced from them. The contents of this report were drawn largely from contributions by numerous members of the EMD Gas Shales Advisory Committee, with much of the data being available from public websites such as state or provincial geological surveys or other public institutions. Shales from which gas or oil is being produced in the United States are listed in alphabetical order by shale name. Information for Canada is presented by province, whereas for Europe, it is presented by country.
Geochemically distinct oil families in the onshore and offshore Santa Maria basins, California
The purpose of this work is to identify genetic affinities among 48 crude oil samples from the onshore and offshore Santa Maria basins. A total of 21 source-related biomarker and stable carbon isotope ratios among the samples were assessed to assure that they were unaffected by secondary processes. Chemometric analysis of these data identifies six oil families with map and stratigraphic distributions that reflect organofacies variations within the Miocene Monterey Formation source rock. The data comprise a training set that was used to create a chemometric decision tree to classify newly collected oil samples. Three onshore families originated from two synclines, which may contain one or more pods of thermally mature source rock. Multiple biomarker parameters indicate that the six oil families achieved early oil window maturity in the range of 0.6%–0.7% equivalent vitrinite reflectance. The offshore oil samples consist of one family from Point Pedernales field and two families from the “B” prospect. Geochemical characteristics of these families indicate origins under differing water column and sediment oxicity and carbonate versus siliceous and detrital input in ‘carbonate,’ ‘marl,’ and ‘shale’ organofacies like those in the lower calcareous–siliceous, carbonaceous marl, and clayey–siliceous members of the Monterey Formation elsewhere in coastal California. The corresponding lithofacies and organofacies appear to be linked to the early–middle Miocene climate optimum and subsequent paleoclimatic cooling after circa 14 Ma, a systematic up-section increase in the stable carbon isotope composition of related oil samples, decreased preservation of calcium carbonate shells from planktic foraminifera and coccoliths, and increased preservation of clay-sized siliceous shells of diatoms and radiolarians. The results show that organofacies within the Monterey source rock are responsible for many of the geochemical differences between the oil families. This paleoclimate–organofacies model for crude oil from the Monterey Formation can be used to enhance future exploration efforts in many areas of coastal California.
Upper Cretaceous Ferron Sandstone: Major coalbed methane play in central Utah
Recent drilling for coalbed gas in the Upper Cretaceous Ferron Sandstone Member of central Utah has resulted in one of the most successful plays of this kind. Exploration to date has resulted in three fields and a potential fairway 6-10 mi (10-16 km) wide and 20-60 mi (32-96 km) long, corresponding to shallow coal occurrence at depths of about 1800-3500 ft (545-1060 m) in the Ferron, a sequence of interbedded fluvial-deltaic sandstone, shale, and coal in the lower part of the Cretaceous Mancos Shale. Coalbed methane (CBM) reservoirs in this interval consist of thin to moderately thick (3-10 ft [1-3 m]) coal beds of relatively low rank (high-volatile B bituminous) and variable gas content, ranging from 100 scf/ton or less in the south to as high as 500-600 scf/ton in the north. Productive wells have averaged more than 500 mcf/day and, after several years, continue to typically show negative production declines. In the major productive area, Drunkards Wash unit, the first 33 producers averaged 974 mcf and 85 bbl of water per day after five years of continuous production. Estimated ultimate recoverable reserves for individual wells in this unit range from 1.5 to 4 bcf. Based on several criteria, including gas content, thermal maturity, and chronostratigraphy, the play is divided into northern and southern parts. The northern part is characterized by coals that have the following characteristics: (1) high gas contents; (2) moderate thermal maturity (e.g., vitrinite reflectance [R o ] values of 0.6-0.8%); (3) good permeabilities (5-20 md); (4) lack of exposure; and (5) overpressuring, due to artesian conditions. Southern coals have much lower average gas contents (<100 scf/ton) and lower thermal maturity (R o = 0.4-0.6%), and they are exposed along an extensive, 35 mi (56 km) outcrop belt that may have allowed a degree of flushing. These coals, however, are also thicker and more extensive than those to the north and thus may retain significant potential. Northern coals appear to contain a mixture of gas from three sources: in-situ thermogenic methane, migrated thermogenic methane from more mature sources, and late-stage biogenic gas. Current development is focused on the northern part of the stated fairway, where well control and an existing infrastructure are present. Indications are that CBM exploration in the Ferron will expand considerably in the near future.
Permeability of methane hydrate-bearing sandy silts in the deep-water Gulf of Mexico (Green Canyon Block 955)
Permeability is one of the most crucial properties governing fluid flow in methane hydrate reservoirs. This paper presents a comprehensive permeability analysis of hydrate-bearing sandy silt pressure-cored from Green Canyon Block 955 (GC 955) in the deep-water Gulf of Mexico. We developed an experimental protocol to systematically characterize the transport and petrophysical properties in pressure cores. The in situ effective permeability ranges from 0.1 md (1.0 × 10 −16 m 2 ) to 2.4 md (2.4 × 10 −15 m 2 ) in these natural sandy silts cores with hydrate occupying 83%–93% of the pore space. When hydrate dissociates from these cores, the measured intrinsic permeability ( k 0 ) is 0.3 md (3.0 × 10 −16 m 2 ) to 9.3 md (9.3 × 10 −15 m 2 ); these results are affected by fines migration during hydrate dissociation. We analyzed samples reconstituted from these sandy silts and found k 0 to range from ∼12 md (∼1.2 × 10 −14 m 2 ) to ∼41 md (∼4.1 × 10 −14 m 2 ). The water relative permeabilities ( k rw ) of GC 955 pressure cores are large relative to other natural pressure cores from offshore Japan, offshore India, and onshore Alaska. These k rw values are also higher than predicted by current conceptual relative permeability models where hydrate fills the pores or coats the grains of the sediments. This fundamental conundrum requires further study. Our work provides essential parameters to reservoir simulation models seeking to predict hydrate formation in geological systems, evaluate the gas production potential, and explore the best way to produce this energy resource in sandy silt reservoirs.
Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment
Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C–360°C) on shale and coal samples show that solid-bitumen reflectance ( BR o ) in shales is less responsive to thermal stress than vitrinite reflectance ( R o ) in coal. This effect is most pronounced at lower experimental temperatures (300°C–320°C), whereas reflectance changes are more similar at higher temperatures (340°C–360°C). Neither a “vitrinite-like” maceral nor “suppressed vitrinite” was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of “ R o suppression,” particularly at lower thermal maturity ( R o ≤ 1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that R o and BR o are more similar at higher maturities ( R o > 1.0%). It is suggested that R o suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.
Controls on the deposition and preservation of the Cretaceous Mowry Shale and Frontier Formation and equivalents, Rocky Mountain region, Colorado, Utah, and Wyoming
Regional variations in thickness and facies of clastic sediments are controlled by geographic location within a foreland basin. Preservation of facies is dependent on the original accommodation space available during deposition and ultimately by tectonic modification of the foreland in its postthrusting stages. The preservation of facies within the foreland basin and during the modification stage affects the kinds of hydrocarbon reservoirs that are present. This is the case for the Cretaceous Mowry Shale and Frontier Formation and equivalent strata in the Rocky Mountain region of Colorado, Utah, and Wyoming. Biostratigraphically constrained isopach maps of three intervals within these formations provide a control on eustatic variations in sea level, which allow depositional patterns across dip and along strike to be interpreted in terms of relationship to thrust progression and depositional topography. The most highly subsiding parts of the Rocky Mountain foreland basin, near the fold and thrust belt to the west, typically contain a low number of coarse-grained sandstone channels but limited sandstone reservoirs. However, where subsidence is greater than sediment supply, the foredeep contains stacked deltaic sandstones, coal, and preserved transgressive marine shales in mainly conformable successions. The main exploration play in this area is currently coalbed gas, but the enhanced coal thickness combined with a Mowry marine shale source rock indicates that a low-permeability, basin-centered play may exist somewhere along strike in a deep part of the basin. In the slower subsiding parts of the foreland basin, marginal marine and fluvial sandstones are amalgamated and compartmentalized by unconformities, providing conditions for the development of stratigraphic and combination traps, especially in areas of repeated reactivation. Areas of medium accommodation in the most distal parts of the foreland contain isolated marginal marine shoreface and deltaic sandstones that were deposited at or near sea level lowstand and were reworked landward by ravinement and longshore currents by storms creating stratigraphic or combination traps enclosed with marine shale seals. Paleogeographic reconstructions are used to show exploration fairways of the different play types present in the Laramide-modified, Cretaceous foreland basin. Existing oil and gas fields from these plays show a relatively consistent volume of hydrocarbons, which results from the partitioning of facies within the different parts of the foreland basin.
Global prediction of continuous hydrocarbon accumulations in self-sourced reservoirs
This report was first presented as an abstract in poster format at the American Association of Petroleum Geologists (AAPG) 2012 Annual Convention and Exhibition, April 22-25, Long Beach, Calif., as Search and Discovery Article no. 90142. Shale resource plays occur in predictable tectonic settings within similar orders of magnitude of eustatic events. A conceptual model for predicting the presence of resource-quality shales is essential for evaluating components of continuous petroleum systems. Basin geometry often distinguishes self-sourced resource plays from conventional plays. Intracratonic or intrashelf foreland basins at active margins are the predominant depositional settings among those explored for the development of self-sourced continuous accumulations, whereas source rocks associated with conventional accumulations typically were deposited in rifted passive margin settings (or other cratonic environments). Generally, the former are associated with the assembly of supercontinents, and the latter often resulted during or subsequent to the breakup of landmasses. Spreading rates, climate, and eustasy are influenced by these global tectonic events, such that deposition of self-sourced reservoirs occurred during periods characterized by rapid plate reconfiguration, predominantly greenhouse climate conditions, and in areas adjacent to extensive carbonate sedimentation. Combined tectonic histories, eustatic curves, and paleogeographic reconstructions may be useful in global predictions of organic-rich shale accumulations suitable for continuous resource development. Accumulation of marine organic material is attributed to upwellings that enhance productivity and oxygen-minimum bottom waters that prevent destruction of organic matter. The accumulation of potential self-sourced resources can be attributed to slow sedimentation rates in rapidly subsiding (incipient, flexural) foreland basins, while flooding of adjacent carbonate platforms and other cratonic highs occurred. In contrast, deposition of this resource type on rifted passive margins was likely the result of reactivation of long-lived cratonic features or salt tectonic regimes that created semi-confined basins. Commonly, loading by thick sections of clastic material, following thermal relaxation after plate collision or rift phases, advances kerogen maturation. With few exceptions, North American self-sourced reservoirs appear to be associated with calcitic seas and predominantly greenhouse or transitional ("warm" to "cool") global climatic conditions. Significant changes to the global carbon budget may also be a contributing factor in the stratigraphic distribution of continuous resource plays, requiring additional evaluation.
Energy resources and changing land use, Front Range of Colorado: AAPG-EMD field trip guide, in association with the 2001 AAPG-EMD annual meeting
Over the past 30 years, communities in the Northern Front Range of Colorado have experienced tremendous urban and commercial growth rivaling or surpassing that in most other parts of the United States. Much of this growth coincides with areas underlain by critically needed natural resources (such as oil, natural gas, construction aggregate (stone, sand, and gravel), and water), thus presenting serious challenges for city, county, and state planners as well as producers of these natural resources. With projections for as much as a 51 percent increase in population in Colorado over the next 25 years (Colorado Department of Local Affairs, 2001), it is likely that these challenges will increase. This field trip will blend petroleum and coal geology with discussions of urban development to highlight the interplay between growth in the Front Range and energy resource production. On the trip we will also explore the effects of past production on land use. A total of 6 stops will be made in various locations around the Front Range area.
Petrofacies Analysis - A Petrophysical Tool for Geologic/Engineering Reservoir Characterization
Petrofacies analysis is defined as the characterization and classification of pore types and fluid saturations as revealed by petrophysical measurements of a reservoir. The word "petrofacies" makes an explicit link between petroleum engineers' concerns with pore characteristics as arbiters of production performance and the facies paradigm of geologists as a methodology for genetic understanding and prediction. In petrofacies analysis, the porosity and resistivity axes of the classical Pickett plot are used to map water saturation, bulk volume water, and estimated permeability, as well as capillary pressure information where it is available. When data points are connected in order of depth within a reservoir, the characteristic patterns reflect reservoir rock character and its interplay with the hydrocarbon column. A third variable can be presented at each point on the crossplot by assigning a color scale that is based on other well logs, often gamma ray or photoelectric effect, or other derived variables. Contrasts between reservoir pore types and fluid saturations are reflected in changing patterns on the crossplot and can help discriminate and characterize reservoir heterogeneity. Many hundreds of analyses of well logs facilitated by spreadsheet and object-oriented programming have provided the means to distinguish patterns typical of certain complex pore types (size and connectedness) for sandstones and carbonate reservoirs, occurrences of irreducible water saturation, and presence of transition zones. The result has been an improved means to evaluate potential production, such as bypassed pay behind pipe and in old exploration wells, or to assess zonation and continuity of the reservoir. Petrofacies analysis in this study was applied to distinguishing flow units and including discriminating pore type as an assessment of reservoir conformance and continuity. The analysis is facilitated through the use of colorimage cross sections depicting depositional sequences, natural gamma ray, porosity, and permeability. Also, cluster analysis was applied to discriminate petrophysically similar reservoir rock.
Research-derived insights into surface geochemical hydrocarbon exploration
Research studies based on foreland basins (mainly in eastern Colorado) examined three surface geochemical exploration (SGE) methods as possible hydrocarbon (HC) exploration techniques. The first method, microbial soil surveying, has high potential as an exploration tool, especially hi development and enhanced recovery operations. Integrative adsorption, the second technique, is not effective as a quantitative SGE method because water, carbon dioxide, nitrous oxide, unsaturated hydrocarbons, and organic compounds are collected by the adsorbent (activated charcoal) much more strongly than covalently bonded microseeping Q-Cs thermogenic HCs. Qualitative comparisons (pattern recognition) of C8+ mass spectra cannot gauge HC gas microseepage that involves only the Q-Cs HCs. The third method, soil cakite surveying, also has no potential as an exploration tool. Soil calcite concentrations had patterns with pronounced areal contrasts, but these patterns had no geometric relationship to surface traces of established or potential production, that is, the patterns were random. Microscopic examination of thousands of soils revealed that soil calcite was an uncrystallized caliche coating soil particles. During its precipitation, caliche captures or occludes any gases, elements, or compounds in its immediate vicinity. Thus, increased signal intensity of some SGE methods should depend on increasing soil calcite concentrations. Analyses substantiate this hypothesis. Because soil calcite has no utility as a surface exploration tool, any surface method that depends on soil calcite has a diminished utility as an SGE tool. Isotopic analyses of soil calcites revealed carbonate carbon ??13C values of -4.0 to +2.07co (indicating a strong influence of atmospheric CO2) as opposed to expected values of-45 to -30%c if the carbonate carbon had originated from microbial oxidation of microseeping HC gases. These analyses confirm a surface origin for this soil calcite (caliche), which is not necessarily related to HC gas microseepage. This previously unappreciated pivotal role of caliche is hypothesized to contribute significantly to the poor and inconsistent results of some SGE methods.
Energy and minerals division tight oil and gas committee: Activities and commodity report for 2019-2020
In 2019, total daily tight oil and gas production increased in the United States month over month, with annualized growth of 14% for oil and 12% for gas. Those gains leveled off in the first quarter of 2020 due to aggressive price competition and increases in international production. Then came the pandemic with a substantially larger dose of economic turmoil, driving down demand due in part to shelter in place orders and safety concerns around travel. Between March and May, tight oil and gas production dropped by nearly 2 million bpd and almost 5 Bcf/day before beginning to recover. Production has continued to increase for the most part through the second half of 2020, but drilling remains subdued throughout most of the U.S. and uncertainty around long term demand along with the current price environment and general state of the economy has contributed to layoffs throughout the industry. Some shale-gas production has declined recently, but a few areas have seen expansion due to construction of LNG facilities along the East Coast of the U.S. (e.g., the Haynesville Formation). Current U.S. shale-gas production is still higher now than in 2019, with daily production of almost 71 Bcf as of October 2020 driven in large part by increased production from the Marcellus Shale in the Appalachian Basin and shales within the Permian Basin. Shale liquids production is down by around a million bpd to approximately 7.1 million (September 2020; U.S. EIA) from pre-pandemic production levels at the end of 2019 and beginning of 2020. Tight oil production remains dominated by plays in the Permian Basin as well as the Bakken and Eagle Ford Formations. On the development and production front, new enhanced oil recovery approaches for tight shale reservoirs are being more widely implemented. Natural gas or CO2 injection is currently being utilized in the Bakken Formation, Eagle Ford Formation, Anadarko Basin, and the Permian Basin to optimize injection sequences and boost recovery. Refracturing of existing wells to reduce drilling costs, improve production, and prolong well productive life has also begun to occur more widely in developed plays. International interest in exploiting hydrocarbons from unconventional reservoirs continues to develop, with active exploration projects on most continents. Europe remains relatively underexplored as compared to North America, although a total of 141 exploration and appraisal wells with a possible shale-gas exploration component have been spudded, including horizontal legs from vertical wells. Shale exploration has made a breakthrough in China with shale gas output in 2019 of 10 billion cubic meters (35.3 Bcf), 60% of which was produced from Sinopec’s Fuling Shale Gas field. Lacustrine shale oil exploration has also been successful in the Sichuan and Ordos Basins in central China, Junggar and Tarim Basins in northwest China, and Songliao Basin in north China, and Bohai Bay Basins in northeast China as of 2018. South America’s potential as an unconventional shale gas and oil province is mainly in Argentina and Brazil, where the production from Neuquen Basin’s tight shale of the Vaca Muerta Formation has been steadily increasing since 2016, but only 4% of the shale resource has been developed thus far. According to International Energy Agency’s report in 2013, Brazil holds the 9th largest unconventional gas reserves. Brazil has shale oil and gas potential in the Parana, Solimoes and Amazon Basins and is actively producing from the oil shale unit of the Irati Formation. In 2019, the Brazil energy ministry launched REATE 2020 to boost onshore investments that include the expectation of drilling an experimental unconventional well in the northeast region. For this inaugural report, the new AAPG EMD Tight Oil and Gas Committee (TO&G; formerly the Shale Gas & Liquids and Tight Gas Sands committees) has developed new commodity report requirements for contributors. This includes shorter annual reports focused on new developments, play concepts, along with the typical updates on production and new drilling in the play areas they cover. We are also asking contributors to collect background geologic and production related information into a document that summarizes important features of the plays they cover that will be stored on the TO&G webpage along with our commodity reports. TO&G is currently working to expand the number of contributors to cover more play areas and replace committee and advisory board members that have recently stepped down. Changes to committee leadership occurred in October as recent chairs transition to EMD elected positions.
Updated United Nations Framework Classification for reserves and resources of extractive industries
The United Nations have studied how the oil and gas resource classification developed jointly by the SPE, the World Petroleum Congress (WPC) and the American Association of Petroleum Geologists (AAPG) could be harmonized with the United Nations Framework Classification (UNFC) for Solid Fuel and Mineral Resources (1). The United Nations has continued to build on this and other works, with support from many relevant international organizations, with the objective of updating the UNFC to apply to the extractive industries. The result is the United Nations Framework Classification for Energy and Mineral Resources (2) that this paper will present. Reserves and resources are categorized with respect to three sets of criteria: ??? Economic and commercial viability ??? Field project status and feasibility ??? The level of geologic knowledge The field project status criteria are readily recognized as the ones highlighted in the SPE/WPC/AAPG classification system of 2000. The geologic criteria absorb the rich traditions that form the primary basis for the Russian classification system, and the ones used to delimit, in part, proved reserves. Economic and commercial criteria facilitate the use of the classification in general, and reflect the commercial considerations used to delimit proved reserves in particular. The classification system will help to develop a common understanding of reserves and resources for all the extractive industries and will assist: ??? International and national resources management to secure supplies; ??? Industries' management of business processes to achieve efficiency in exploration and production; and ??? An appropriate basis for documenting the value of reserves and resources in financial statements.
Reserve Growth in Oil Fields of West Siberian Basin, Russia
Although reserve (or field) growth has proven to be an important factor contributing to new reserves in mature petroleum basins, it is still a poorly understood phenomenon. Limited studies show that the magnitude of reserve growth is controlled by several major factors, including (1) the reserve booking and reporting requirements in each country, (2) improvements in reservoir characterization and simulation, (3) application of enhanced oil recovery techniques, and (4) the discovery of new and extensions of known pools in discovered fields. Various combinations of these factors can affect the estimates of proven reserves in particular fields and may dictate repeated estimations of reserves during a field's life. This study explores the reserve growth in the 42 largest oil fields in the West Siberian Basin, which contain about 55 percent of the basin's total oil reserves. The West Siberian Basin occupies a vast swampy plain between the Ural Mountains and the Yenisey River, and extends offshore into the Kara Sea; it is the richest petroleum province in Russia. About 600 oil and gas fields with original reserves of 144 billion barrels of oil (BBO) and more than 1,200 trillion cubic feet of gas (TCFG) have been discovered. The principal oil reserves and most of the oil fields are in the southern half of the basin, whereas the northern half contains mainly gas reserves. Sedimentary strata in the basin consist of Upper Triassic through Tertiary clastic rocks. Most oil is produced from Neocomian (Lower Cretaceous) marine to deltaic sandstone reservoirs, although substantial oil reserves are also in the marine Upper Jurassic and continental to paralic Lower to Middle Jurassic sequences. The majority of oil fields are in structural traps, which are gentle, platform-type anticlines with closures ranging from several tens of meters to as much as 150 meters (490 feet). Fields producing from stratigraphic traps are generally smaller except for the giant Talin field which contains oil in Jurassic river-valley sandstones. Principal source rocks are organic-rich marine shales of the Volgian (uppermost Jurassic) Bazhenov Formation, which is 30-50 m (98- 164 feet) thick. Bazhenov-derived oils are mostly of medium gravity, and contain 0.8-1.3 percent sulfur and 2-5 percent paraffin. Oils in the Lower to Middle Jurassic clastics were sourced from lacustrine and estuarine shales of the Toarcian Togur Bed. These oils are medium to low gravity, with low sulfur (less than 0.25 percent) and high paraffin (commonly to 10 percent) contents. Among the 42 fields analyzed for reserve growth, 30 fields are located in the Middle Ob region, which includes the Samotlor field with reserves of more than 25 BBO and the Fedorov field with reserves of about 5 BBO. Data used in the study include year of discovery, year of first production, annual and cumulative production, and remaining reserves reported by Russian reserve categories (A+B+C1 and C2) in January of each year. Correlation of these Russian resource categories to U.S. categories of the Society of Petroleum Engineers classification is complex and somewhat uncertain. Reserve growth in oil fields of West Siberia was calculated using a newly developed Group Growth method, which requires that the total reserve (proven reserve plus cumulative production) of individual fields with an equal length of reserve record be added together starting with discovery year or the first production year. Then the annual growth factor (AGF), which is the ratio of total reserves of two consecutive years, is calculated for all years. Once AGFs have been calculated, the cumulative growth factor (CGF) is calculated by multiplying the AGFs of all the previous years. The CGF data are used to develop reserve growth models. The West Siberian oil fields show a 13-fold reserve growth 20 years after the discovery year and only about a 2-fold growth after the first production year. This difference is attributed to extensive exploration and field delineation activities between the discovery and the first production years. Because of uncertainty in the length of evaluation time and in reported reserves during this initial period, reserve growth based on the first production year is more reliable for model development. However, reserve growth models based both on discovery year and first production year show rapid growth in the first few years and slower growth in the following years. In contrast, the reserve growth patterns for the conterminous United States and offshore Gulf of Mexico show a steady reserve increase throughout the productive lives of the fields. The different reserve booking requirements and the lack of capital investment for improved reservoir management and production technologies in West Siberian fields relative to U.S. fields are the probable causes for the difference in growth patterns. Reserve growth models based on the first production year predict that the reserve growth potential in the 42 largest oil fields of West Siberia over a five-year period (1998-2003) ranges from 270-330 million barrels or 0.34-0.42 percent per year. For a similar five-year period (1996-2001), models for the conterminous United States predict a growth of 0.54-0.75 percent per year. This abstract presents the contents of a poster prepared for the AAPG Hedberg Research Conference on Understanding World Oil Resources, November 12-17, 2006 - Colorado Springs, Colorado. A paper 'Reserve Growth in Oil Fields of West Siberian Basin, Russia' was published in Natural Resources Research, v. 12, no. 2, June, 2003.
EMD Gas Hydrates Committee annual report
Global research on the potential commercial viability of gas extraction from gas hydrates is continuing, predominantly in Asia and in the United States, where recent efforts have focused on the exploration and characterization of gas hydrate petroleum systems and conducting controlled production tests of gas hydrate deposits hosted in mostly sand-rich reservoir systems. In 2017, gas hydrate production testing was conducted in marine settings in the offshore of Japan and China. An additional test was conducted in the Shenhu region of the South China Sea in 2020 to further evaluate the effectiveness of various well completion technologies to produce gas from gas hydrates. Late in 2018, a research partnership led by the U.S. Department of Energy National Energy Technology Laboratory and the Japan Oil, Gas and Metals National Corporation established a new Alaska North Slope test site for an extended gas hydrate production pilot with the completion of a stratigraphic test well. With the successful completion of the Prudhoe Bay Unit Hydrate-01 stratigraphic test well, planning is now underway for drilling of three additional wells at the Alaska test site, which will include a geoscience data well and two production test wells. In 2019, the Government of India released the results of one of the most comprehensive gas hydrate scientific drilling investigations ever undertaken, the leadership of the Indian National Gas Hydrate Program Expedition 02 reported on the discovery of several significant gas hydrate accumulations that were considered suitable for future gas hydrate production testing. In September of 2019, the U.S. Geological Survey released a new assessment of the technically recoverable gas hydrate resources on the Alaska North Slope. In 2018, the University of Texas at Austin released a comprehensive report describing the operational and initial technical results of the UT-GOM2-1 Hydrate Pressure Coring Expedition, which drilled and partially cored two wells in Green Canyon Block 955 in the deepwater Gulf of Mexico. The results of these recently complete gas hydrate geologic and production studies have been further reviewed in this AAPG-EMD Gas Hydrate Committee report.