AndreaBozzo/ceres-open-data-index huggingface dataset:
Costs of Storing and Transporting Hydrogen

An analysis was performed to estimate the costs associated with storing and transporting hydrogen. These costs can be added to a hydrogen production cost to determine the total delivered cost of hydrogen. Storage methods analyzed included compressed gas, liquid hydrogen, metal hydride, and underground storage. Major capital and operating costs were considered over a range of production rates and storage times. In all cases, underground storage was the cheapest method; liquid hydrogen has advantages over compressed gas for longer storage times. For the transport of hydrogen, compressed gas, liquid hydrogen, metal hydride, and pipeline delivery were considered. Modes of transportation included truck and rail transport for the compressed gas and metal hydride. For liquid hydrogen, barge delivery was investigated as an option in addition to truck and rail. Transportation costs were estimated for a range of production rates and delivery distances. For large quantities of hydrogen, pipeline delivery was the cheapest option. For smaller quantities of hydrogen, liquid hydrogen had advantages over the other methods for longer delivery distances. All cost assumptions and sample calculations are included in the report along with some background information on each storage method. The appendix contains sensitivity analyses and graphs showing important trends associated with hydrogen storage and transportation.

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Green Powered Production by CO-Gasification of Biomass and Coal in Coal-Fired Oxygen-Blown Entrained-Flow Based IGCC Processes

The use of coal for large scale powered production meets a growing environmental concern. In spite of the fact that "clean" coal conversion technologies integrated with high-efficiency power production facilities, such as IGCC, are developed, the aim for sustainable development strives for a power production system based on renewable energy sources. One of the most promising renewable energy source that can be used in the Netherlands is biomass, i.e. organic waste materials and/or energy crops. To accelerate the introduction of this material, in a technical and economically acceptable way, co-gasification with fossil fuels, in particular coal, in large scale IGCC processes is considered. In this paper the technical feasibility, economic profitability, and environmentally acceptability of co-gasification of biomass in coal-fired oxygen-blown entrained-flow based IGCC process and three co-gasification concepts were defined for further consideration.

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Data Summary of Offshore Drilling Waste Disposal Practices

The U.S. Environmental Protection (EPA) announced in December 1997 that it would revise the offshore oil and gas effluent limitations guidelines to incorporate discharge requirements for synthetic-based drilling muds (SBMs). The process to be used would be an expedited ?presumptive rulemaking? process that would require cooperation between EPA, other government agencies, the regulated industry, and other interested stakeholders. To allow the process to proceed at a rate much faster than normal, industry formed several work groups to generate new data. The U.S. Department of Energy (DOE) offered to assist EPA in additional data gathering efforts. On September 2, 1998, Joseph Daly, the EPA project manager for the SBM rulemaking, wrote to Nancy Johnson, DOE?s Director of Planning and Environmental Analysis in the Office of Fossil Energy, outlining the types of information he hoped that DOE could provide.

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Identification And Evaluation Of Fluvial-dominate Deltaic (Class I Oil) Reservoirs In Oklahoma

The Oklahoma Geological Survey (OGS), the Geo Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma have engaged in a five-year program to identify and address Oklahoma's oil recovery opportunities in fluvial dominated deltaic (FDD) reservoirs. This program included a systematic and comprehensive collection and evaluation of information on all FDD oil reservoirs in Oklahoma and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. The execution of this project was approached in phases. The first phase began in January, 1993 and consisted of planning, play identification and analysis, data acquisition, database development, and computer systems design. By the middle of 1994, many of these tasks were completed or nearly finished including the identification of all FDD reservoirs in Oklahoma, data collection, and defining play boundaries. By early 1995, a preliminary workshop schedule had been developed for project implementation and technology transfer activities. Later in 1995, the play workshop and publication series was initiated with the Morrow and the Booch plays. Concurrent with the initiation of the workshop series was the opening of a computer user lab that was developed for use by the petroleum industry. Industry response to the facility initially was slow, but after the first year lab usage began to increase and is sustaining. The remaining six play workshops were completed through 1996 and 1997, with the project ending on December 31, 1997. The play workshop and publication listing (in order of production) was as follows: Morrow, Booch, Layton and Osage-Layton, Prue and Skinner, Cleveland and Peru, Red Fork, Tonkawa, and Bartlesville. This program has been described by numerous industry representatives as the most valuable program that the Oklahoma Geological Survey has ever implemented. Since there is no direct way to measure the impact that this program has had on the volumes of FDD oil production in Oklahoma, the success of the program must be measured in terms of the accomplishments and the industry valuations of those accomplishments. Eight highly successful workshops and accompanying publications were completed on eleven FDD horizons. A computer user laboratory was established and continues to be a resource to the industry. lndustry relationships with the project participants have shown vast improvements. lndustry feedback to the program has been overwhelmingly positive. The development of this FDD program and the support of the U.S. Department of Energy have set the stage for a strong technology transfer foundation for Oklahoma's petroleum industry. Oklahoma Geological Survey University of Oklahoma

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Economic Recovery Of Oil Trapped At Fan Margins Using High Angle Wells And Multiple Hydraulic Fractures

This project attempts to demonstrate the effectiveness of exploiting thin-layered, low energy deposits at the distal margin of a prograding turbidite complex through the use of hydraulically fractured horizontal or high-angle wells. The combination of a horizontal or high-angle well and hydraulic fracturing will allow greater pay exposure than can be achieved with conventional vertical wells while maintaining vertical communication between thin interbedded layers and the wellbore. A high-angle well will be drilled in the fan-margin portion of a slope-basin clastic reservoir and will be completed with multiple hydraulic-fracture treatments. Geologic modeling, reservoir characterization, and fine-grid reservoir simulation will be used to select the well location and orientation. Design parameters for the hydraulic-fracture treatments will be determined, in part, by fracturing an existing test well. Fracture azimuth will be predicted by passive seismic monitoring of a fracture-stimulation treatment in the test well using logging tools in an offset well.

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Improved Efficiency of Miscible CO2 Floods and Enhanced Prospects for CO2 Flooding Heterogeneous Reservoirs

The goal of this project is to improve the efficiency of miscible C02 floods and enhance the prospects for flooding heterogeneous reservoirs. This report provides results of the first year of the three-year project that will be exploring three principle areas: Fluid and matrix interactions (understanding the problems): interfacial tension (IFT), phase behavior, miscibility, capillary number, injectivity, wettability, and gravity drainage. Conformance control/sweep efficiency (solving the problems): reduction of mobility using foam, diversion by selective mobility reduction (SMR) using foam, improved injectivity, alternating water and gas injection, and using horizontal wells. Reservoir simulation for improved oil recovery (predicting results): gravity drainage, SMR, C02-foam flooding, IFT, injectivity profile, horizontal wells, and naturally fractured reservoirs.

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FRACTURED RESERVOIR DISCRETE FEATURE NETWORK

This report describes research and technology development for the project, "Fractured Reservoir Discrete Feature Network Technologies," a project of Fundamental Geoscience Research and development sponsored by the U.S. Department of Energy National Oil and Related Programs through BDM-OK/NIPER. This project was carried out by Golder Associates (Seattle, WA) together with Marathon Oil Company (Midland, Texas) and the Massachusetts Institute of Technology (Cambridge, Massachusetts). Golder Associates was the project lead, and carried out the primary research, technology development, management, and technology transfer activities. Marathon Oil Company (Midland, Texas) carried out field tests and contributed project data for the project study at the Yates Field in Iran, TX (Tracts 17 and 49). Marathon also participated in the research applications. Marathon's participation was contributed to the project. Theoretical development of the Hierarchical Fracture Model (HFM) and implementation of the HFM model for Tracts 17 and 49 were carried out by the Massachusetts Institute of Technology.

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Sizing Gelant Treatments in Hydraulically Fractured Production Wells

Often, when production wells are stimulated by hydraulic fracturing, the fracture unintentionally breaks into water zones, causing substantially increased water production. To correct this problem, we developed an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. In these treatments, gelant penetrates a short distance from the fracture face into the porous rock associated with both water and hydrocarbon zones. Success for a given treatment requires that the gel reduce permeability to water much more than that to hydrocarbon. We present a simple 11-step procedure for sizing these gelant treatments. This procedure was incorporated in user-friendly graphical-user-interface software than can be downloaded from our web site at http://baervan/ResSweepEffic/reservoir.htm.

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VERIFICATION OF GEOLOGICAL/ENGINEERING MODEL IN WATERFLOOD AREAS

A geological/engineering model was constructed for the extended Tertiary Incentive Project (TIP) mile area of Unit A in Bell Creek field, Powder River County, Montana. The model was constructed to develop a methodology for characterizing reservoir heterogeneity for barrier island deposits. This report summarizes the status of the NIPER geological/engineering model as of September 1987. A structure map of Muddy formation sandstones and an isopach map of the reservoir were constructed to delineate the framework of the pay zones. In addition, reservoir quality was differentiated by grouping facies into three classes. Valley incisions and indications of localized faulting have been documented within the barrier-island deposit. Valley fill deposits unconformably overlie portions of the barrier island sequence in the Bell Creek field.

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ADVANCED FRACTURE MODELING IN THE UINTA BASIN (UTAH) FOR OPTIMIZED PRIMARY AND SECONDARY RECOVERY

The Uinta Basin in northeastern Utah has long been recognized as the second richest onshore basin in the contiguous United States in terms of hydrocarbons in-place. Despite the prolific abundance of hydrocarbons, recovery is impeded by the nature of the oil, the difficult behavior of these "conventional" reservoirs, and the sporadic deliverability associated with production through natural fractures. How to more intelligently extract these substantial reserves is a goal not only applicable to the Uinta Basin itself, but also to other difficult plays throughout the United States. Fracture systems throughout the United States are being recognized more commonly but are not sufficiently characterized or considered to take full advantage of their presence. In this regard, the Uinta Basin was ideal for the development of advanced, integrated methodology applicable to naturally fractured reservoirs.

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CHARACTERIZATION OF FRACTURED RESERVOIRS USING STATIC AND DYNAMIC DATA: FROM SONIC AND 3D SEISMIC TO PERMEABILITY DISTRIBUTION

In low porosity, low permeability zones, natural fractures are the primary source of permeability affecting both production and injection of fluids. The open fractures do not contribute much to porosity, but they provide an increased drainage network to existing porosity. They also may connect the borehole to remote zones of better reservoir characteristics. An important approach to characterizing the fracture orientation and permeability of reservoir formations is one based on the effects of such conditions on the propagation of acoustic and seismic waves in the rock. The project objective is to evaluate acoustic logging and surface seismic measurement techniques as well as fluid flow and transport methods for mapping permeability anisotropy and other petrophysical parameters in a fractured reservoir. We will also determine facture connectivity using multiphase production data. The work includes theoretical and numerical model studies linked with a balanced petrophysical and engineering program for the development of advanced concepts of borehole and surface seismic methods.

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Naturally Fractures Reservoirs: Optimized E&P Strategies Using a Reaction-Transport-Mechanical Simulator in an Integrated Approach

Major accomplishments of this project occurred in three primary categories: 1) Fractured Reservoir Location and Characteristics Prediction for Exploration and Production Planning, 2) Implications of Geologic Data Analysis and Synthesis for Exploration and Development Programs, and 3) Fractured Reservoir Production Modeling. The results in each category will be discussed in turn.

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Characterization and Simulation of an Exhumed Fractured Petroleum Reservoir

An exhumed fractured reservoir located near Alligator Ridge in central Nevada provides the basis for developing and testing different approaches for simulating fractured petroleum reservoirs. The fractured analog reservoir comprises a 90 m thickness of silty limestone and shaly interbeds within the Devonian Pilot Shale. A period of regional compression followed by ongoing basin and range extension has created faults and fractures that, in turn, have controlled the migration of both oil and gold ore-forming fluids. Open pit gold mines provide access for observing oil seepage, collecting the detailed fracture data needed to map variations in fracture intensity near faults, build discrete fracture network models and create equivalent permeability structures. Fault trace patterns mapped at the ground surface provide a foundation for creating synthetic fault trace maps using a stochastic procedure conditioned by the outcrop data. Conventional simulations of petroleum production from a 900 by 900 m sub-domain within the reservoir analog illustrate the possible influence of faults and fractures on production. The consequences of incorporating the impact of different stress states are also explored. Simulating multiphase fluid flow using a discrete fracture, finite element simulator illustrated how faults acting as conduits might be poorly represented by the upscaling procedures used to assign equivalent permeability values within reservoir models. The parallelized reservoir simulators developed during this project provide a vehicle to evaluate when it might be necessary to incorporate very fine scale grid networks in conventional reservoir simulators or to use finely gridded discrete fracture reservoir simulators.

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FEASIBILITY STUDY FOR LOWERING THE MINIMUM GAS PRESSURE IN SOLUTION-MINED CAVERNS BASED ON GEOMECHANICAL ANALYSES OF CREEP-INDUCED DAMAGE AND HEALING

This report presents the results of a study to evaluate the potential of increasing the working gas volume of new and existing compressed natural gas (CNG) storage caverns by using an advanced constitutive model for rock salt in the cavern design procedure. Geomechanical finite element analyses were made to determine the minimum gas pressure allowable based on an existing stress-based criterion (the Damage Potential method) and an advanced constitutive model (the Multimechanism Deformation Coupled Fracture (MDCF) model) capable of modeling damage and healing in rock salt. The MDCF model is a constitutive model developed by Sandia National Laboratories and their subcontractors to provide a description of damage, healing, and deformation of salt for safe disposal of radioactive waste at the Waste Isolation Pilot Plant. The MDCF model has the capability to track damage development and healing and to provide a quantitative measure for the damage. Additionally, the healing behavior of the salt (included with the MDCF model) was to be analyzed to determine if complete healing of the damaged rock zone would occur during the time period when the cavern was at maximum gas pressure.

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Figure 3

Composite S-wave section for a portion of line 2: S1 and S2 sections are spliced together at the line tiepoint, and time-aligned at the TN1 (TN1) marker. Evidence of shear wave splitting (interval traveltime difference between S1 and S2 sections) is seen within the Z-TN1 and the MB-DG4 intervals. The TGR-Z and TN1-MB intervals show nearly equivalent S1 and S2 interval traveltimes (negligible S-wave anisotropy). Note also that amplitude differences between S1 and S2 within the Z-TN1 interval: The reflections are much higher in amplitude and coherency on S1 than on S2. The S1-S2 amplitude difference is most pronounced in the top 80 ms. (about 300 ft) of the Z-TN1 interval, suggesting that the upper part of the interval is more anisotropic than the lower part.

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Figure 2

P-wave AVO section: Color is CP; wiggle trace is near offset stack. (AVO Gradient   AVO Intercept)/2 display of line 1 and line 2, spliced at the line tiepoint. Azimuthal dependence of the AVO response is evident at the Z and MB markers. At the line tie, line 1, left, shows a negative AVO response (blue) at the Z and MB reflectors, while line 2, right, shows a positive response (red-yellow) for these two reflectors.

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Design and Implementation of a CO2 Flood Utilizing Advanced Reservoir Characterization and Horizontal Injection Wells in a Shallow Shelf Carbonate Approaching Waterflood Depletion

The first project objective is to utilize reservoir characterization and advanced technologies to optimize the design of a carbon dioxide (CO2) project for the South Cowden Unit (SCU) located in Ector County, Texas. The SCU is a mature, relatively small, shallow shelf carbonate unit nearing waterflood depletion. The second project objective is to demonstrate the performance and economic viability of the project in the field. All work during the fourth quarter falls within the demonstration project.

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Figure 5

Anisotropy at line tie. Percent S-wave animuthal anisotropy as a function of P-wave azimuthal AVO difference. The azimuthal AVO difference is taken as the absolute value of the numerical difference in AVO parameter between measurements on line 1 and line 2. AVO gradient in red; CP or [(AVO Gradient   AVO Zero-Intercept)/2] in blue. Error bars are shown by the vertical and horizontal line segments or data points.

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Predicting the Performance of Horizontal Wells

Oil producers in many areas of the country are finding that drilling horizontal wells--starting a well downward, then angling out through the length of the reservoir--can significantly increase the flow of crude oil, often restoring economic life to an aging field. But since horizontal drilling is not yet a precise science and is more expensive than vertical drilling, operators must have confidence that it will actually produce the predicted results before investing in the technology. Stanford University researchers are assessing the performance of horizontal wells through sophisticated modeling and reservoir analyses. The goal is to develop modeling and simulation techniques that will provide operators with the quantitative tools to predict horizontal well performance in a variety of reservoir types and conditions. Using Stanford's computer modeling of complex reservoir structures and large-scale flow experiments at the Marathon Research Center that simulate reservoir conditions, the University researchers hope to develop an accurate set of specifications that will allow operators to determine whether horizontal wells make technical and economic sense for their specific fields. The results could be a major step forward in the widespread acceptance of a technology that will boost the nation's oil production

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Figure 4

Full-waveform seismic data showing the effects of microcracks on velocity anisotropy and attenuation anisotropy.  The first three curves in each plot are for the two polarizations of S and for P propagating in the x direction; the next three, propagating in the y direction; and the last three in the z direction.  Subscripts on S-wave labels give the direction of polarization.  (After Yin, 1992).

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Figure 4

Cross correlation of the mismatched traces. A zero time-lag between the traces would correspond to a value of 4 s on the vertical axis. It is seen that the traces are phase shifted by as much as 30 ms. Further, there is a substantial phase shift at the shallowest geophone level (depth 1840 ft), indicating substantial contributions from shallow depths, possible in the near-surface. The phase shifts oscillate with depth indicating deep contributions to the data matrix asymmetry.

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A NEW METHODOLOGY FOR OIL AND GAS EXPLORATION USING REMOTE SENSING DATA AND SURFACE FRACTURE ANALYSIS

A systematic methodology for oil and gas exploration using remote-sensing information and surface fracture analysis has been developed.  This methodology consists of (1) acquisition of satellite images and aerial photographs, (2) photogeological interpretation of these images and photographs for mapping surface lineaments, fracture traces, drainage patterns, and circular and accurate anomalies and (3) surface fracture analysis.

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The Influence of Disjoining Pressure on Foam Stability and Flow in Porous Media

When gas and a dilute aqueous surfactant solution flow simultaneously through a porous medium to form a foam, measured pressure drops can be orders of magnitude larger than when there is no surfactant in the aqueous phase [1,2]. The large flow resistance of foam in porous media makes it a desirable mobility-control agent for improving underground oil recovery [3-5].

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Figure 4

Oblique strikes of a natural fracture (NF) and petal-centerline fracture (P) as shown in cross section of a 4-inch core.  (More commonly, fractures will be in separate pieces of core and their relationship will be unknown if the core continuity has not been preserved between them). Petal fractures commonly strike parallel to the maximum horizontal compressive stress, natural fractures, and natural-fracture permeability can be inferred

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Figure 3

Regional fractures commonly occur as bed-normal, vertical features, and most wellbores are also vertical. This figure plots the probability of fracture intersection against the diameter of the wellbore or core that is being used to interrogate the formation in order to characterize fractures. As shown, in order to have at least a 50% chance of intersecting a fracture with a 4-inch core or 8-inch wellbore, the fractures would have to be spaced a minimum of 8 or 16 inches, respectively. Few fractured reservoirs are this intensely fractured, thus it is difficult to recognize the importance of fractures or to characterize them

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