AndreaBozzo/ceres-open-data-index huggingface dataset:
Task 6.7.2 - Improved Corrosion Resistance of Alumina Refractories

In order to increase the efficiency of advanced coal-fired power systems, higher working, fluid temperatures must be reached. To protect some system surfaces, they are covered with corrosion-resistant refractories. Corrosion is the degradation of material surfaces or grain boundaries by chemical reactions with melts, liquids, or gases, causing loss of material and, consequently, a decrease in strength of the structure. In order to develop methods of reducing corrosion, the microstructure that is attacked must be identified along with the mechanism and rates of the attack. Once identified, methods for reducing corrosion rates can be developed.    In order to determine the reactivity of a refractory to a slag, several tests have been developed. The most common are the cup slag test, drip slag test American Society for Testing and Materials ([ASTM] C768), gradient slag test, rotary slag test (ASTM C874)and the dip-and- spin test. Among these tests, the cup slag test is the only static test method and the most commonly used. Previous static testing at the University of North Dakota Energy & Environmental Research Center (EERC) has shown that alumina-based castable refractories are among the least expensive and most corrosion-resistant materials for the highest-temperature coal-fired power system applications.

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Task 6.5/6.7.1 - Materials for Gas Separation and Hydrogen Separation Membranes

Catalytic gasification of coal to produce H2- and CH4-rich gases for consumption in molten carbonate fhel cells is currently under development; however, to optimize the fiel cell performance and extend its operating life, it is desired to separate as much of the inerts as possible from the fuel gas before they enter the fiel cell. In addition, the economics of the integrated gasification combined cycle (IGCC) can be improved by separating as much of the hydrogen as possible from the fuel, since hydrogen is a high-value product. One process currently under development by the Energy& Environmental Research Center (EERC) for accomplishing this gas separation and hot-gas cleanup involves gas separation membranes. These membranes are operated at temperatures as high as 800 `C and pressures up to 300 psig. Some of these membranes can have very small pores (30-50 ~), which inefllciently separate the undesired gases by operating in the Knudsen diffision region of mass transport. Other membranes with smaller pore sizes (<5 ~) operate in the molecular sieving region of mass transport phenomena. Dissolution of atomic hydrogen into thin metallic membranes made of platinum and palladium alloys is also being developed.    Technological and economic issues that must be resolved before gas separation membranes are commercially viable include improved gas separation efficiency, membrane optimization, sealing of membranes in pressure vessels, high burst strength of the ceramic material, pore thermal stability, and material chemical stability. Hydrogen separation is dependent on the temperature, pressure, pressure ratio across the membrane, and ratio of permeate flow to total flow.

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P-100 Los Alamos National Laboratory Formation Logging Tools for Microholes (Partnership)

The objectives of this project are to lay the requisite groundwork, in collaboration with industry, for the rapid development of a commercial microhole logging capability once the feasibility of deep microhole drilling is firmly established. The following technical approaches were adopted by Los Alamos to achieve the technical objectives: -Review and select from existing conventional technologies, or modest modifications thereof, geophysical logs for which the microhole environment offers the most advantage, -Examine the technological feasibility of miniaturizing these logging tools for use in microholes and document the technology challenges in doing so, and -Assess the operational feasibility of microhole logging through the fabrication and deployment of simplified prototypes of selected logging tools.

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Development of Single-Well Seismic Imaging Technology

Single well seismic imaging (SWSI) has been identified in the petroleum industry as an exciting new technology with significant economic potential, particularly in the Gulf of Mexico. Deploying a seismic energy source and receiver string in a single well will allow imaging with higher resolution than can now be achieved with 3D surface seismic or the crosswell seismic techniques as well as providing the economics of single well (as opposed to crosswell) surveys. In a salt basin environment, such images would guide targeted, low-risk drilling for oil and gas trapped against salt dome flanks, overhangs, and fault surfaces (see above example of the Choctaw salt dome). The technology would also yield valuable data in subsalt environment where surface data are often uninterpretable. In this project, the Lawrence Berkeley National Laboratory along with two other national laboratories and the industry (consisting of members of the salt imaging consortium) have pooled their resources in a cooperative venture to develop the SWSI technology. An important objective of this project is to leverage DOE and industry resources in the expeditious development of this useful tool that will address areas of research most beneficial to the industry as a whole.

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FIELD DEMONSTRATION OF CARBON DIOXIDE MISCIBLE FLOODING IN THE LANSING-KANSAS CITY FORMATION, CENTRAL KANSAS

Progress is reported for the period from July 1, 2001 to September 30, 2001. Technical design and budget for a larger (60-acre) CO2 demonstration project are being reviewed by the US DOE for approval. While this review process is being conducted, work is proceeding on well testing to obtain reservoir properties and on the VIP reservoir simulation model to improve model prediction and better understand the controls that certain parameters exert on predicted performance.

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High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs

This report outlines progress in the fourth quarter of the first year of the DOE project High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs?. A new approach for qualitative evaluation of the impact of numerical ispersion in compositional finite difference simulation is described. The approach, based on solutions to one-dimensional (1D) flow equations obtained by the method of  characteristics (MOC), results from current research on automatic generation of analytical solutions for 1D-gas injection problems. The  assessment of the effects of numerical dispersion is demonstrated in a 2D case study of a miscible flooding using multicomponent fluid descriptions. The case study demonstrates the utility of combining streamtube methods with the analytical theory of 1D-gas injection processes.

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Greater Green River Basin Production Improvement Project

It has been estimated that the Greater Green River Basin of southwestern Wyoming may contain as much as 5,000 TCF of gas trapped within unconventional, overpressured, very tight, basin-centered gas reservoirs Among the many potentially productive horizons in the Greater Green River Basin (GGRB) is the mid-Cretaceous Frontier Formation, estimated to contain at least 300 TCF of natural gas The Frontier Formation has been recognized as a very large gas resource for over three decades, and all of the wells penetrating the deep, basin-centered Frontier Formation in the GGRB have encountered gas However, none of these deep wells that drilled through the overpressured Frontier prior to this project had proven to be economic This has been due to the very low average permeability within the reservoir (as low as 0 0001 md in situ permeability)

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Task 3.14 - Demonstration of Technologies for Remote Power Generation in Alaska

In over 165 villages in Alaska, the use of fossil fuel supplies or renewable energy resources could greatly reduce the cost of electricity and space heating. Currently, diesel generators are the most commonly used electrical generating systems; however, high fuel costs result in extremely high electrical power costs reIative to the lower 48 states. The reduction of fuel costs associated with the use of indigenous, locally available fuels running modular, high-efficiency power- generating systems would be extremely beneficial.

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The Influence of Fold and Fracture Development on Reservoir Behavior of the Lisburne Group of Northern Alaska/Fundamental Geoscience Award

The Lisburne Group has deformed into detachment folds evolved to different degrees, and thus provides a series of natural experiments in which to observe those structures and to develop predictive models for their formation and for the resulting patterns of enhancement and reduction of porosity and permeability. The results of these field-based observations and models can then be used to develop quantitative models for characterization of Lisburne reservoirs and the fluid flow within them for a spectrum of traps, from relatively underformed to highly folded and thrust faulted. This research will enable the understanding of the relationship between fracturing, normal faulting and asymmetric folding in the Lisburne carbonates in order to develop predictive models. The fracture system of Lisburne Group of carbonates has been recognized as being critical to optimal reservoir management. A number of problems with reservoirs, including difficulty in establishing an oil-water contact location, highly variable well productivity, disappointing waterflood performance and reserves estimates have been associated with difficulties in the fracture description and characterization.

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Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

Injection at the CO2 Pilot was re-started in late April, 2002. Due to producer sanding problems in the past, we decided to utilize a different operating injection strategy this time around. All four injection wells shall be on CO2 injection for 2 weeks, and then switched to water injection for 2 weeks. These ?Water Alternating with Gas (WAG)? cycles have been ongoing since the pilot was re-started in April 2002. To date, very minimal sanding has been observed in the pilot producing wells.

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ROME TROUGH CONSORTIUM

This report contains the results of research conducted by the Rome Trough Consortium, a partnership of three state geological surveys, several energy industry companies and the U.S. Department of Energy. The Consortium was headed by the Kentucky Geological Survey, University of Kentucky, Lexington, KY. Research was also conducted by the Ohio Department of Natural Resources, Division of Geological Survey in Columbus, Ohio and the West Virginia Geological and Economic Survey in Morgantown, WV. Members of the consortium are listed in Table 1-1. This consortium was formed to gain a better understanding of the geology and deep hydrocarbon potential of the Rome Trough, a Cambrian-age depositional basin located in eastern Kentucky, northern West Virginia, and southeastern-most Ohio. The Consortium was initiated in January 1999, and research lasted 2 years, with a final project review and core workshop on January 24, 2001 at the Kentucky Geological Survey in Lexington, KY. At this meeting members decided to continue research on core material that arrived near the end of the project. This report documents all research done through mid-2002. Significant new research resulted from the extra time allowed to continue this work.

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High Temperature Measurement-While-Drilling Development Status Report

The goal was to develop and test a mud-pulse measurement-while-drilling (MWD) tool for oil and gas drilling operations that includes a gamma-ray detector for formation identification and triaxial accelerometer and magnetometer suites to provide directional data. The tool will reliably operate at downhole temperatures as high as 195?C (383?F) using conventional off-the-shelf electronic components.

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AN ADVANCED FRACTURE CHARECTERIZATION AND WELL PATH NAVIGATION SYSTEM FOR EFFECTIVE RE-DEVELOPMENT AND ENHANCEMENT OF ULTIMATE RECOVERY FROM THE COMPLEX MONTEREY RESERVOIR OF SOUTH ELLWOOD FIELD, OFFSHORE CALIFORNIA

Venoco Inc, intends to re-develop the Monterey Formation, a Class III basin reservoir, at South Ellwood Field, Offshore Santa Barbara, California. Well productivity in this field varies significantly. Cumulative Monterey production for individual wells has ranged from 260 STB to 8,700,000 STB. Productivity is primarily affected by how well the well path connects with the local fracture system and the degree of aquifer support. Cumulative oil recovery to date is a small percentage of the original oil in place. To embark upon successful redevelopment and to optimize reservoir management, Venoco intends to investigate, map and characterize field fracture patterns and the reservoir conduit system. State of the art borehole imaging technologies including FMI, dipole sonic and cross-well seismic, interference tests and production logs will be employed to characterize fractures and micro faults. These data along with the existing database will be used for construction of a novel geologic model of the fracture network. Development of an innovative fracture network reservoir simulator is proposed to monitor and manage the aquifer's role in pressure maintenance and water production. The new fracture simulation model will be used for both planning optimal paths for new wells and improving ultimate recovery.

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Dissolution of Hydrocarbon Gas Hydrates in Seawater at 1030-m; Effects of Porosity, Structure, and Compositional Variation as Determined by High-Definition Video and SEM Imaging.

We compare dissolution rates of pure, porous,  compacted, and oil-contaminated sI methane hydrate and sII methane-ethane hydrate to rates measured previously on pure, compacted, sI methane hydrate and sI carbon dioxide hydrate ({\it Rehder et al., Fall AGU 2001}). Laboratory-synthesized test specimens were used in both studies, allowing characterization of test materials prior to their transport and exposure to seawater at 1030-meter depth on the Monterey Canyon seafloor, off coastal Moss Landing, CA.

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North Hill Creek Project 3-D Seismic Survey

Wind River Resources Corporation entered into an Exploration and Development Agreement and an Option Agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation to cover the exploration of approximately thirty-one square miles of Tribal minerals for oil and gas. Wind River also obtained oil and gas leases from the State of Utah covering two additional square miles contiguous with the Tribal lands. These lands are located immediately to the south of the Flat Rock Field, largely in T15S-R20E. The structure on which the Flat Rock Field is developed appeared to cross onto some of the acreage covered by Wind River's agreements with the Ute Indian Tribe. In October of 1999, Wind River Resources, with the Ute Indian Tribe as partner, applied to the Department of Energy for a grant in the amount of $500,000 to be used toward the cost of a 3-D seismic survey to explore for oil and natural gas liquids on Tribal mineral lands. In May of 2000, Wind River was notified that its proposal had been selected for funding. Negotiations for the grant contract and work in support of a categorical exclusion from the requirements of NEPA for the conduct of the seismic survey were concluded during the summer of 2000. The contract was awarded and field work in support of the survey commenced in September of 2000. Field acquisition of the 3-D seismic data began in early October of 2000 and was completed during the first week of December. Data processing and initial interpretation were completed on May 30, 2001. The DOE-supported 3-D seismic survey covers approximately 15 square miles of Tribal minerals. The survey delineated the exact size, shape, orientation, structure and stratigraphy of the suspected Hill Creek Anticline. The Flat Rock Field is located on the north flank of this structure.

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Methane Hydrate Production from Alaskan Permafrost

Natural gas hydrates beneath the permafrost have been encountered as a nuisance by the oil and gas industry for years. Numerous drilling problems, including kicks and uncontrolled gas releases, have been documented in arctic regions by engineers working in Russia, Canada and the U.S. Information has been generated in laboratory studies pertaining to the extent, volume, chemistry and phase behavior of gas hydrates. The scientists that have studied hydrate potential agree that the potential is great -- on the North Slope of Alaska alone, it has been estimated at 590 TCF. However, little information has been obtained on physical samples taken from actual rock containing hydrates. This project is in the first year of a three-year endeavor being sponsored by Maurer Technology, Noble Drilling, and Anadarko Petroleum, in partnership with the DOE. The purpose of the project is to build on previous & ongoing R&D in the area of onshore hydrate deposition. Plans are to identify, quantify and predict production potential for hydrates located on the North Slope of Alaska. Plans to design and implement a program to safely and economically drill, core and produce gas from arctic hydrates. The current work scope is to drill and core up to 3 wells on Anadarko leases in FY 2003 during the winter drilling season. We are also going to utilize an on-site core analysis laboratory to determine some of the physical characteristics of the hydrates and surrounding rock. We hope to tie together geology, geophysics, logs, and drilling and production data to allow reservoir models to be calibrated. Ultimately, the goal is to form an objective technical and economic evaluation of reservoir potential of Alaska hydrates.

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U. S. Geological Survey Gas Hydrate Studies in the Northern Gulf Of Mexico

Gas hydrates in continental margin sediments are known or inferred worldwide, but are only well-studied and characterized in a few locations. In the Gulf of Mexico, gas hydrates have been identified as abundant surface mounds in much of the north-central Gulf, but evidence is essentially lacking for their existence deeper in the uppermost few hundred meters of sediment where they are expected to be stable. Much of the current interest in the Gulf of Mexico comes from the economic reality that conventional hydrocarbon exploration is moving into frontier deep-water areas, i.e., in regions where drilling will in all likelihood encounter and penetrate potential gas hydrate accumulations. Federal,  academic, and industry efforts are converging in the Gulf to make it one of the best studied and characterized sites of hydrate occurrence. The US Geological Survey (USGS) program in the Gulf of Mexico has dual purposes: (1) to understand the relationships among gas hydrate occurrence, geologic framework, and active geologic processes; and (2) to integrate project results with extensive research that is being conducted by academic institutions and the exploration industry to find the answers to these fundamental questions regarding natural gas hydrate occurrence in the Gulf of Mexico. The initial phase of the USGS project has focused on three areas of the north-central Gulf where gas hydrates and active gas venting are well-known sea-floor features: the Mississippi Canyon, Green Canyon, and Garden Banks. These locations contain diverse geologic features (such as salt domes, deep faults, buried channels, and turbidite deposits) and evidence for active geologic processes (such as mass wasting, slumps, shallow-water flows, young faults, and fluid/gas venting). These settings offer a representative sampling of the complex environments in which to compare and understand gas hydrate occurrence.

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High-Resolution Studies of Hydrates on Blake Ridge

Deep-tow multichannel seismic data are used to obtain significantly improved images and physical property estimates of marine sediments within the upper 1 km of the sediment column. The technology that supports this effort is based on a Helmholtz resonator source (220Hz ? 1kHz frequency band, 200 dB // 1 ?Pa @ 1 m source level) that operates at any ocean depth. The source and 48 independent hydrophones are deployed approximately 300 meters above the seafloor. This system has proven to be optimal for studies of marine hydrates as it provides high-resolution data through the hydrate stability zone (HSZ), including the strong seismic signal from the bottom simulating reflector (BSR) that is related to the temperature-pressure driven phase change from solid hydrate to gas and water.

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The Curiosity of Gas Hydrates

Gas hydrate is an ice-like material consisting of a structure of water molecules, like ice, but having an expanded crystal lattice that encages a gas molecule, generally methane. It occurs naturally within ocean sediments in a layer commonly several hundred meters thick, just below the sea floor at temperatures and pressures existing below about 500 meters water depth. Gas hydrate also is stable in conjunction with permafrost in the Arctic. Most marine gas hydrate is formed of microbially-generated gas. It binds huge amounts of methane into the sediments. Worldwide, gas hydrate is estimated to hold about 1019 grams of organic carbon in the form of methane (Kvenvolden, 1993). This represents an amount of organic carbon that is twice as much as in all other fossil fuels on earth (conventional natural gas, oil, and coal) and an amount of methane that is about 3,000 times as much as exists in the atmosphere. Gas hydrate is important primarily because it contains huge amounts of methane in a concentrated form and because it influences the physical properties of sedimentary deposits, particularly sediment strength.

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