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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.
Virtual special issue of recent advances on gas hydrates scientific drilling in Alaska
Gas hydrate refers to a non-stoichiometric clathrate that forms spontaneously in the natural environment whenever sufficient quantities of gases of appropriate size (most commonly methane) interact with abundant water under specific conditions of temperature and pressure. (1,2) Such conditions occur wherever the shallow geothermal gradient has been suppressed by either deepwater or thick permafrost, allowing for relatively low temperatures to coexist with elevated pressures. The volume of gas hydrate on Earth is difficult to constrain, (3) but it is sufficient that gas hydrate is a meaningful potential component of (1) the long-term natural cycling of carbon, (2) the nearer term environmental changes in response to warming climates, (4) and (3) future energy supply systems. Since the initial recognition of gas hydrate as an abundant component in nature in the late 1960s, a series of scientific drilling expeditions conducted by both the Integrated Ocean Discovery Program (and successors) and national research and development programs in Canada, Japan, China, the United States, South Korea, and others (5) have explored the occurrence and nature of gas hydrates. In particular, the desire for expanded energy supply options to support the economic development and energy security for nations around the globe is currently motivating a broad range of laboratory and numerical simulation studies in support of an ongoing series of field-based scientific tests of the potential commercial viability of gas extraction from natural gas hydrate deposits. (6)
Clean coal initiatives in Indiana
Purpose - Indiana is listed among the top ten coal states in the USA and annually mines about 35 million short tons (million tons) of coal from the vast reserves of the US Midwest Illinois Coal Basin. The implementation and commercialization of clean coal technologies is important to the economy of the state and has a significant role in the state's energy plan for increasing the use of the state's natural resources. Coal is a substantial Indiana energy resource and also has stable and relatively low costs, compared with the increasing costs of other major fuels. This indigenous energy source enables the promotion of energy independence. The purpose of this paper is to outline the significance of clean coal projects for achieving this objective. Design/methodology/approach - The paper outlines the clean coal initiatives being taken in Indiana and the research carried out at the Indiana Center for Coal Technology Research. Findings - Clean coal power generation and coal for transportation fuels (coal-to-liquids - CTL) are two major topics being investigated in Indiana. Coking coal, data compilation of the bituminous coal qualities within the Indiana coal beds, reducing dependence on coal imports, and provision of an emissions free environment are important topics to state legislators. Originality/value - Lessons learnt from these projects will be of value to other states and countries.
Advanced distributed acoustic sensing vertical seismic profile imaging of an Alaska North Slope gas hydrate field
Gas hydrates are found in significant quantities on the North Slope of Alaska in subpermafrost sand units and intermixed in lower portions of permafrost within the hydrate stability window. While conventional surface seismic data and established imaging methods can indicate the presence of gas hydrate reservoirs, producing high-resolution images of (seismically) thin layers remains challenging due to the preferential attenuation of the higher-frequency data components. An alternative strategy is to use distributed acoustic sensing (DAS) involving cementing optical fibers into boreholes to measure seismic wavefield energy closer to the strata of interest using vertical seismic profiling (VSP). DAS VSP imaging takes advantage of the shorter travel paths and reduced attenuation to generate higher-resolution near-well images. We illustrate these benefits on a DAS VSP data set acquired at the Hydrate-01 stratigraphic test well located in the Prudhoe Bay Unit of Alaska where significant gas hydrate deposits have been detected in two subpermafrost sand layers that are intended for long-duration production testing. Our DAS data preprocessing workflow effectively isolates the upgoing compressional-wave (P-wave) reflections required for subsurface acoustic imaging. After applying three-dimensional (3-D) tomography to improve the quality of the 3-D migration velocity model, we use 3-D reverse-time migration (RTM) to develop high-quality images of the two target sands and minor near-well faulting. We validate our RTM images through highly accurate well-ties with previously acquired petrophysical log data. This study demonstrates that combining 3-D RTM imaging with DAS VSP data provides significant value to gas hydrate and similar projects, and it suggests that more advanced inversion approaches such as (elastic) least-squares RTM could recover higher-resolution and more quantitative estimates of subsurface reflectivity, which would be valuable for refining the understanding of gas hydrate systems.
Planning and operations of the Hydrate 01 Stratigraphic Test Well, Prudhoe Bay Unit, Alaska North Slope
The National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey are leading an effort to conduct an extended gas hydrate production test in northern Alaska. The proposed production test required the drilling of an initial stratigraphic test well (STW) to confirm the geologic conditions of the proposed test site. This well was completed in January 2019 in cooperation with the Prudhoe Bay Unit Working Interest Owners. The Prudhoe Bay Unit Hydrate-01 STW was spudded on 10-December-2018. Downhole data acquisition was completed on 25-December-2018, and the rig was released on 01-January-2019. The Hydrate-01 STW was drilled in two sections, including the surface hole that was drilled to a depth of 2248 ft measured depth (MD) (685 m MD) and cased, and the production hole section that was drilled to a depth of 3558 ft MD (1084 m MD) and also cased. A thermally chilled mineral-oil-based mud was used in the main (production) hole section of the well to maintain wellbore stability and quality of the wellbore acquired data. The primary wellbore data were acquired using logging-while-drilling tools. A sidewall pressure core system was also deployed to gather grain size and other data needed for the design of the future production test wells. In addition to confirming the geologic conditions at the test site, the Hydrate-01 STW was designed to serve as a monitoring well during future field operations. Therefore, two sets of fiber-optic cables, each including a bundled distributed acoustic sensor (DAS) and a distributed temperature sensor (DTS), were clamped to the outside of the production casing and cemented in place. In March 2019, the project team acquired three-dimensional (3D) DAS vertical seismic profiling data in the Hydrate-01 STW. Temperature surveys were also acquired with the DTS as deployed in the Hydrate-01 STW during the completion of the well and nearly continuously since March-2019.
Scientific results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope
The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.
Gas hydrate saturation estimates, gas hydrate occurrence, and reservoir characteristics based on well log data from the hydrate-01 stratigraphic test well, Alaska North Slope
The Hydrate-01 Stratigraphic Test Well was drilled at the Kuparuk 7-11-12 site on the Alaska North Slope in December 2018. Sonic log data provide compressional (P) and shear (S) slowness from which we determine gas hydrate saturation ( S gh ) estimates using effective medium theory. The sonic S gh estimates compare favorably with S gh estimated from resistivity and nuclear magnetic resonance (NMR) logs, showing that gas hydrate occupies up to approximately 90% of the pore space in the target reservoir sands. The informally named B1 sand (2294 feet below mean sea level) shows lower V P / V S ratios than the D1 sand (2770 feet below mean sea level), with the lower part of the B1 sand showing lower V P / V S ratios than the upper part of the B1 sand. This corresponds to a stiffer, or more “cemented”, behavior for the lower B1 sand and less cemented behavior for the D1 sand. This trend could be due to differences in the reservoirs themselves or in the gas hydrate morphology or to both factors. We observe that the presence of gas hydrate in the upper B1 sand has greater impact on hydraulic permeability (measurements suggest a greater difference between intrinsic and effective permeability) than in the D1 sand, possibly related to gas hydrate morphology but more likely due simply to higher gas hydrate saturations in the upper B1 sand. Analyses of S gh relative to porosity, shale fraction, and intrinsic permeability show that reservoir quality (as represented by these three metrics) exerts control on gas hydrate saturation. Grain size and mineralogy data show somewhat smaller grains and better sorting in the D1 reservoir relative to the upper B1 reservoir and smaller grains and greater clay fraction in the lower B1 reservoir relative to the other two reservoir zones. Together, these data suggest that reservoir characteristics play a role in the observed V P / V S patterns, but gas hydrate morphology (possibly varying with saturation) must also be considered.
New insights into the occurrence and implications of mobile water in gas hydrate systems
Gas hydrate production technologies commonly feature reservoir depressurization. Depressurization occurs when a pressure gradient is established in a well, drawing mobile water from the reservoir and reducing reservoir pressure. As such, the occurrence of mobile water is a necessary condition for effective gas production from gas hydrate reservoirs using common borehole-based methods. However, recent field programs have revealed that mobile water exists widely within the overall gas hydrate reservoir system, including within overlying and underlying units once thought of as virtually impermeable seals. Further, excess free water may also be commonly found in hydrate-free or hydrate-poor permeable strata interbedded within the larger gas hydrate reservoir system. Such internal sources of water are complex to characterize, difficult to explain, potentially highly heterogeneous, and may pose significant challenges to depressurization-based production. This report summarizes the general occurrence of water in gas hydrate systems and select technical implications.
Review of past gas Production attempts from subsurface gas hydrate deposits and necessity of long-term production testing
This paper summarizes the conditions, applied techniques, results, and lessons of major field gas production attempts from gas hydrates in the past and the necessity of longer term production testing with the scale of years to fulfill the gap between the currently available information and the knowledge required for commercial development. The temporal and spatial scales of field production test projects employing depressurization have expanded since 2002. The results from the projects have proved the applicability of these techniques in both onshore and offshore conditions. However, many technical and reservoir condition-related issues have emerged in gas production, and the gap between current status and industrial requirements is still large. Sand control, artificial lift, and related flow assurance issues are common technical issues that impact onshore and offshore production testing operations. Different reservoir responses were observed well by well, and discrepancy between model predictions and actual field measurements were seen, although reasonable matches were made for short-term behaviors. Those observations suggest that temporal change of the wellbore and near-wellbore conditions and reservoir heterogeneity that cannot be fully modeled have caused complex short-term responses to the depressurization operations. To ensure the long-term operational stability and reliability of the prediction technologies for production behaviors that are essential for commercialization of gas hydrate resources, gas hydrate production testing with comparable duration with commercial operations are necessary. Due to the locality of geological conditions in gas hydrate reservoirs, numerous gas production tests will be required to understand the factors controlling gas production.
Geological reservoir characterization of a gas hydrate prospect associated with the Hydrate-01 Stratigraphic Test Well, Alaska North Slope
Geological reservoir characterization is essential for accurate evaluation of gas production performance from gas hydrate reservoirs. Particularly, the understanding of reservoir architecture and heterogeneity is of great importance since these are considered as major controls on fluid hydrodynamic and thermodynamic conditions. This study deals with well log and three-dimensional (3-D) vertical seismic profile (VSP) data acquired from the Hydrate-01 Stratigraphic Test Well within the 7-11-12 prospect, Prudhoe Bay Unit, Alaska North Slope and reports on the results of geological/geophysical evaluation related to the geological structure and reservoir properties of the 7-11-12 prospect. The structural trends of the target reservoirs, based on well correlations, are mostly consistent with the predrill prediction using the surface seismic data, and infer the existence of subseismic faults cutting through the Hydrate-01 well. The 3-D VSP data confirm a down-to-the-east normal fault that offsets the reservoir units across the Hydrate-01 well, which is concordant with the well identification of the same fault, and indicate a northeast-dipping relay structure associated with the overstepping normal faults. The edge enhancement attribute associated with discontinuity generated from the 3-D VSP data shows small faults/fractures, possibly as part of a complex fault network within the imaged normal fault system. These results reveal that the 3-D VSP data provide detailed structural information that is not present from the surface seismic data. The Hydrate-01 well log data confirm the occurrence of gas hydrate at high saturation in the two targeted sand units (B1 and D1 sands), and the comparison to a nearby pre-existing well (7-11-12 well) shows the same general trend in gas hydrate saturation as a map of seismic impedance generated from surface seismic data. The well log data also suggest that the base of gas hydrate occurrence in the Hydrate-01 and 7-11-12 wells is almost aligned at the same depth in both of the targeted B1 and D1 sand reservoirs. Especially for the D1 sand in the Hydrate-01 well, the resistivity logs show a sharp transition from high gas hydrate saturation to fully water-saturated within the D1 sand, suggesting a common gas hydrate/water contact. The results of this study will be used to construct the geological models needed for reservoir simulation studies and they can provide important insights into the geological factors that control the occurrence of gas hydrate on the Alaska North Slope.
A simple model of ice segregation using an analytic function to model heat and soil-water flow
For slowly moving freezing fronts in soil, the heat-transport equation may be approximated by the Laplacian of temperature. Consequently, potential theory may be assumed to apply and the temperature state can be approximated by an analytic function. The movement of freezing fronts may be approximated by a time-stepped solution of the phase-change problem, thus solving directly for heat flow across a freezing or thawing front. Moisture transport may approximated by using an exact solution of the moisture-transport equation assuming quasi-steady-state conditions, appropriate boundary conditions, and an exponential function relating unsaturated hydraulic conductivity (defined within the thawed zones) to pore water pressure (tension). This approach is used to develop a single model of ice segregation (frost-heave) in freezing soils. Applications to published and experimental one-dimension soil column freezing data show promising results.
Defining ecological and economical hydropoweroperations: a framework for managing dam releasesto meet multiple conflicting objectives
Hydroelectric dams are a flexible source of power, provide flood control, and contribute to the economic growth of local communities through real-estate and recreation. Yet the impoundment of rivers can alter and fragment miles of critical riverine habitat needed for other competing needs such as downstream consumptive water use, fish and wildlife population viability, or other forms of recreation. Multiple conflicting interests can compromise progressive management especially with recognized uncertainties related to whether management actions will fulfill the objectives of policy makers, resource managers and/or facility owners. Decision analytic tools were used in a stakeholder-driven process to develop and implement a template for evaluation and prediction of the effects of water resource management of multiple-use systems under the context provided by R.L. Harris Dam on the Tallapoosa River, Alabama, USA. The approach provided a transparent and structured framework for decision-making and incorporated both existing and new data to meet multiple management objectives. Success of the template has been evaluated by the stakeholder governing body in an adaptive resource management framework since 2005 and is ongoing. Consequences of management of discharge at the dam were evaluated annually relative to stakeholder satisfaction to allow for adjustment of both management scenarios and objectives. This template can be applied to attempt to resolve conflict inherent in many dam-regulated systems where management decisions impact diverse values of stakeholders.
A simple method for partitioning total solar radiation into diffuse/direct components in the United States
Solar radiation is a major sustainable and clean energy resource, and use of solar radiation is expected to increase. The utilization efficiency of solar energy varies with the relative proportions of the direct and diffuse components that compose total solar radiation and with the slope and aspect of the irradiated surface. The purpose of this paper is to develop a simple method for estimating diffuse and direct solar radiation at sites with observation of only total solar radiation. An existing model for estimating diffuse radiation, i.e., a linear relationship between the diffuse fraction (the ratio of diffuse radiation to total solar radiation) and the clearness index (the ratio of total solar radiation to extraterrestrial radiation), is applied to 7 sites across the continental United States with observations of diffuse and total radiation. The linear model shows good monthly performance. The model parameters (slope and interception) show a strong seasonal pattern that exhibits small variation across the 7 sites; therefore, the average values of the two monthly parameters may be used for estimating diffuse radiation for other locations with observations of total radiation.
Permeability measurement and prediction with nuclear magnetic resonance analysis of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well
Permeability of porous media, such as oil and gas reservoirs, is the crucial material parameter for predicting their hydraulic behavior. A nuclear magnetic resonance (NMR) analyzer is widely used as a powerful tool to predict permeability of various media. NMR T 2 (transverse or spin–spin) relaxation time distribution, which is related to pore size distribution, gives the information to allow calculation of effective (initial) permeability. In this study, we investigate effective, intrinsic (absolute), and relative water and gas permeabilities of hydrate-bearing pressure core samples. These samples were recovered from the Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well by sidewall pressure coring and then analyzed in a laboratory using both fluid flow test and NMR analyzer. The peak of the NMR T 2 distribution was measured at 10–20 ms using a laboratory NMR analyzer, which compares well with in situ measurements obtained via logging while drilling NMR data for two samples with high gas hydrate saturations ( S h = 76% and 74%). Further, comparison of laboratory NMR T 2 distribution after hydrate dissociation revealed that the hydrate existed in large pore spaces. Effective permeabilities predicted by the Timur-Coates (TC) model and the Schlumberger-Doll-Research (SDR) model, with T 2 cutoff 33 ms, were about an order of magnitude less than the laboratory measured values. Alternative TC model-based calculations with the T 2 cutoff reduced to 10 ms and a newly developed hydraulic radius model better matched the laboratory data. For the analysis of the intrinsic permeabilities, the TC model with a T 2 cutoff of 33 ms and SDR model were greater than the laboratory derived values, while the hydraulic radius model more closely matched the laboratory-derived values. In addition, permeability measurements were also made relative to gas and water under constant three-phase flow (water–gas–hydrate) conditions. After hydrate dissociation, a relative permeability curve was developed for each of the analyzed core samples based on the Corey petrophysical model. The results indicate that the gas permeability changed rapidly at high water saturation around 90%. Thus, we infer that the selection of relative reservoir parameters should focus on the higher water saturation conditions.
Finite-fault analysis of the 1979 March 14 Petatlan, Mexico, earthquake using teleseismic P waveforms
Vertical, teleseismic P waves recorded for the 1979 March 14 Petatlan, Mexico, earthquake were used to derive the distribution of coseismic slip using a linear finite-fault inversion scheme that solves for the amount of slip in each of a series of consecutive time windows. Data recorded by six stations of the Global Digital Seismograph Network were inverted in addition to digitized analogue long-period recordings available from nine Worldwide Standardized Seismograph Network stations. The digital data include four broad-band and short-period velocity waveforms reconstructed from the short- and long-period components. The time-window approach allows for a variable rise time on the fault and accounts for the source multiplicity evident in the recorded P waveforms. Synthetic tests conducted using the inversion method on the limited data set, however, reveal that the data are insufficient to identify the exact dislocation duration on the fault. The method is thus implemented by prescribing the fault rise time using five consecutive 1 s time windows. The coseismic slip inferred from the P waves shows a small 70 cm peak near the earthquake hypocentre and a large zone of dislocation (1.2 m maximum) further south-east. The slip pattern covers depths from 3 to 25 km and is located south-east of other recent large interplate ruptures on the Michoacan segment of the Mexican subduction zone. This result indicates that the 1979 Petatlan earthquake broke an independent, adjacent portion of the Cocos-North America plate boundary. The seismic moment of 1.5 × 10 27 dyn cm inferred from the P waves is approximately one-half the long-period moment estimated by other investigators from the observed surface waves. Although the discrepancy is within the uncertainty of the seismic-moment estimates, it may suggest the presence of a component of slow interplate motion that did not radiate significant P -wave energy.
Mineral facilities of Africa and the Middle East
This map displays over 1,500 mineral facilities in Africa and the Middle East. The mineral facilities include mines, plants, mills, or refineries of aluminum, cement, coal, copper, diamond, gold, iron and steel, nickel, platinum-group metals, salt, and silver, among others. The data used in this poster were compiled from multiple sources, including the 2004 USGS Minerals Yearbook (Africa and Middle East volume), Minerals Statistics and Information from the USGS Web site (http://minerals.usgs.gov/minerals/), and data collected by USGS minerals information country specialists. Data reflect the most recent published table of industry structure for each country. Other sources include statistical publications of individual countries, annual reports and press releases of operating companies, and trade journals. Due to the sensitivity of some energy commodity data, the quality of these data should be evaluated on a country-by-country basis. Additional information and explanation is available from the country specialists. See Table 1 for general information about each mineral facility site including country, location and facility name, facility type, latitude, longitude, mineral commodity, mining method, main operating company, status, capacity, and units.
Mineral Facilities of Latin America and Canada
This data set consists of records for over 900 mineral facilities in Latin America and Canada. The mineral facilities include mines, plants, smelters, or refineries of aluminum, cement, coal, copper, diamond, gold, iron and steel, nickel, platinum-group metals, salt, and silver, among others. Records include attributes such as commodity, country, location, company name, facility type and capacity if applicable, and generalized coordinates. The data were compiled from multiple sources, including the 2003 and 2004 USGS Minerals Yearbooks (Latin America and Candada volume), data to be published in the 2005 Minerals Yearbook Latin America and Canada Volume, minerals statistics and information from the USGS minerals information Web site (minerals.usgs.gov/minerals), and data collected by USGS minerals information country specialists. Data reflect the most recent published table of industry structure for each country. Other sources include statistical publications of individual countries, annual reports and press releases of operating companies,and trade journals. Due to the sensitivity of some energy commodity data, the quality of these data should be evaluated on a country-by-country basis. Additional information and explanation is available from the country specialists.