bluuebunny/crossref_metadata_2025_split huggingface dataset:
Silverdale Combination Thermal Drive Project
Authors: Cady G. V. , Hoffman S. J. , Scarborough R. M. 
Published: December 2007

ABSTRACT
In eastern Alberta, the Lloydminster Field extends from Township 48 north to Township 51 and west from the Alberta border to Range 3. A total area of more than 120,000 acres under which pools of heavy oil vital to our world energy needs, remain well saturated after years of production by conventional methods. General Crude Oil Company has acquired interest in the Sparky Q pool in the Lloydminster Field four miles south of the town of Lloydminster, Alberta. In 1975, General Crude Oil initiated a combination thermal drive project in an effect to increase the pool's recovery from 226,400 barrels to 6,854,000 barrels. This would be an increase in oil recovery from 1.2% to 37.1% of the original oil in place.
The proposed project's requirements were to drill 33 development wells, install flowline and surface facilities, and operate the combination thermal project for sixteen years. The wells were drilled and completed by December, 1975, along with the networks of flowlines, circulating water lines and electrical cables that were buried from the individual well-head to a central tank battery. The field was placed on production in early 1976 and produced by primary means until March, 1977. General Crude ignited four 30 acre inverted seven-spot patterns with a gas igniter. Air was injected down the four injection wells from an Ingersoll-Rand 4 RDS balanced opposed four stage compressor. Through 1978, five more patterns were ignited to bring the burn area to 270 acres; which contains some 4,000 acre feet of oil and sand and 8 million barrels of oil.
General Crude Oil engineers have worked since the 1977 ignition to produce 336,000 barrels of oil after injecting 1,200,000,000 cubic feet of air and 149,781 barrels of water in the combination thermal drive combustion process, They are recovering 84% of the injected gas and sustaining a 3.5 MSCF/Bbl air injected oil produced ratio. Optimistically, these factors point to a successful project, based on General Crude's past ten year experience with the combustion process.
Foam as a Mobility Control Agent in Steam Injection Processes
Authors: Chiang Jin C. , Sawyal Subir K. , Castanier Louis M. , Brigham William E. , Sufi Arshad 
Published: December 2007

ABSTRACT
Although our primary interest in studying the technique of mobility control by foaming agents was for steam injection processes, this method seems to offer excellent prospects of improving oil recovery efficiency in any type of gas drive process.
Laboratory studies showed that gravity override of injected gases in gas drive processes can be strikingly reduced and hence recovery increased by in-situ generation of foam. A two-dimensional, vertical plexiglas model holding a 4' × 1' × 0.25″ sandpack was used to investigate this phenomenon. Saturation of the sandpack by a surfactant solution instead of pure water sharply increased liquid recovery and breakthrough time in nitrogen flooding process. The improvement in production was shown to be due to a reduction of gravity override caused by in-situ generation of foam at the gas-liquid interface.
A large range of surfactant solutions of various concentrations with different amounts of monovalent and bivalent salts and alcohols has been studied as to their effectiveness as foamers. Surface tension, rate of drainage, bubble size and shape of the foams were measured in each case.
In-situ foaming in the model increased generally with surfactant concentration until the critical micelle concentration (CMC) was reached; above CMC additional amounts of surfactant had very little effect on the phenomenon.
Similar increase of recovery and delay in breakthrough time was observed in oil flooding processes. A slug of surfactant solution was injected into the pack saturated with oil, and water at irreducible water saturation, and then nitrogen was injected. Gravity override was much less than in the case when no surfactant was present.
The Need and Urgency for Unconventional Gas
Authors: Kuuskraa Vello A. 
Published: December 2007

ABSTRACT
Despite the nation's preoccupation with oil, the colorful, turbulent history of coal and the controversy surrounding nuclear energy, neither oil, coal or nuclear is now the dominant U.S. energy source—since the mid-1970's the largest domestic energy source has been natural gas.
In the past year, the nation consumed nearly 80 quads (quadrillion or 1015 BTUs) of energy with domestically produced natural gas providing approximately 19 quads (19 Tcf). In comparison, domestic oil production was 18 quads (3 billion barrels), coal production was 14 quads (600 million tons) and nuclear energy in the form of electricity was 3 quads (250 million kilowatt-hours).
Natural gas is an economically preferable substitute for oil and an environmentally more acceptable source than coal or nuclear for many uses, such as industrial heating. Further, increased domestic supplies of natural gas could reduce imports, lessen the U.S. dependence on foreign energy sources, and help the balance of payments.
Gas Industry Estimates of Unconventional Gas Production 1980–2000
Authors: Lawrence G. H. , Davis O. C. , Linden H. R. , Lee B. S. , Schlesinger B. , McCormick W. T. , Kalisch R. B. 
Published: December 2007

ABSTRACT
The authors of this paper prepared a series of analyses of the supplemental supply sources of natural gas. This study was developed for the use of the Gas Supply Committee of the American Gas Association. The authors operating as a task force prepared a series of individual studies which were then integrated into a single report which will be published as the proceedings of the Gas Supply Committee workshop II. This SPE-DOE paper has been taken from the broader study. It emphasizes the unconventional or non-conventional sources of natural gas and provides sufficient summary data on other supplies of natural gas to facilitate a review of the major findings of the task force with respect to the relative importance of unconventional sources of gas.
This paper provides a review of unconventional sources of gas from western tight sands, Devonian shale, gas from coal seams, SNG from peat, SNG from oil shale, gas from geopressured aquifers, gas from urban waste and animal residues and gas from biomass. The potential gas supplies from all sources are compared for four specific scenarios to illustrate the variability of the gas supply because of different national energy policies.
Effects of Fracture Fluids on Devonian Shales
Authors: Miller James F. , Boyer J. Parke , Kent Susan J. , Snyder M. Jack , Sharer John C. 
Published: December 2007

Abstract
The gas resource locked in the thick hydrocarbon-bearing Devonian shales which underlie much of the Eastern U.S. has been estimated to be up to three times the current proven gas reserves of this country. However, the economic feasibility of producing large quantities of gas from this resource remains in question due to the dense structure and low permeability of these shales. Hydraulic fracturing which usually must be employed to stimulate the gas flow involves significant risk of formation damage by the fracture fluids and resultant plugging of gas-flow channels. Thus, basic investigation of the effects of such fluids on the shale structure and properties, having the objective of developing fracture procedures and technology that will avoid the detrimental damage, is needed.
This paper describes the methods and presents initial results of a current laboratory investigation of the effects of various fluids such as liquid carbon dioxide, aqueous carbon dioxide, water and proprietary fluids on shale under simulated down-hole conditions. The effects, are evaluated by in situ measurements of permeability, before and after treatment with the fluid, under various applied pressures and pressure differentials. The nature and extent of the "skin effect." are evaluated by examination of the microstructure of the shale.
It is expected that the results will provide additional insight into the mechanisms of formation damage and will provide guidance to the design and utilization of commercial fracture technolgoy.
Utilizing Well Interference Data in Unconventional Gas Reservoirs
Authors: Sawyer W. K. , Alam J. , Rose W. D. 
Published: December 2007

Abstract
This paper describes the use of a dual porosity radial gas flow simulator for estimating values for the key parameters controlling gas production from the Devonian shale or similar unconventional resource. Using best estimates from the literature on shale fracture and matrix properties as a starting point, the model is used to history match production decline and cumulative production data from a Devonian shale well in Meigs County, Ohio. Three sets of parameters were obtained which gave good agreement with the production data. Utilizing simulated pressures at a distance of 96 feet (29.3 m) as a third matching parameter, it was possible to distinguish between the three cases and thus obtain a "more unique" match.
From the results obtained it is concluded that interference data can provide additional information needed for determining the key parameters that control shale well deliverability.
After the Technology, What Happens?
Authors: Merrill Timothy W. 
Published: December 2007

ABSTRACT
An underlying premise to the Unconventional Gas Recovery (UGR) Program seems to be: given adequate technological solutions and proper economic incentive, the marketplace can accommodate any and all volumes of produced gas. My paper explores this hypothesis by examining the gas industry infrastructure as it exists today in the Appalachian Basin.
The UGR Program as structured by the Department of Energy (DOE) identifies four unconventional gas sources methane recovery from coal beds, eastern gas shales, western gas sands, and geopressurized acquifiers. The third category - western gas sands - may have evolved from a category which had been called "tight gas basins in a report written by Lewin and Associates, Inc. (published in summary form in The Oil and Gas Journal, June 12, 1978, under the title "Vast Potential Held by Four ‘Unconventional’ Gas Sources.)" On August 29, 1979 (Docket No. RM79-76) the Federal Energy Regulatory Commission (FERC) issued its Notice of Proposed Rulemaking in which it proposed to implement Section 107(b) and (c)(5) of the Natural Gas Policy Act (NGPA). Those sections of the NGPA charged FERC with setting incentive prices for gas produced under such conditions which present extraordinary risks or costs. The FERC has identified that gas produced from tight formations may indeed present such extraordinary risks and costs. Although the initial proposed rulemaking identified only western sand formations as qualifying for a tight sands definition, the tight sand definition guidelines would encompass - in some peoples’ minds - certain Appalachian sands.
Thus, it might be argued that three of the UGR programs (methane recovery from coal beds, eastern gas shales, and "tight sand formations") have particular relevance for the Appalachian gas producing, transmission, distribution, and gas usage industries. To proceed with the technology of UGR without a thorough knowledge of these industries may constitute a major oversight. Why invent a perfect mousetrap if no one wants it? It is conceivable that the technology to produce Devonian shales will be established someday and the price "right," but the gas not be produced for lack of a market. If such a conclusion seems incredible, I suggest that such a condition exists today. Conventional gas drilling programs in the Appalachian Basin are currently being either stabilized or reduced. Gas purchasers are not paying NGPA ceiling prices though we are all well aware that better than ceiling prices are being paid for other "commercial" sources of gas (Canadian, Mexican, LNG). The reason for such an apparent inconsistency lies not in any conspiracy theory or monopolistic domination, but in the history of Appalachian gas production and in its current industry infrastructure.
Utilization and Recovery Economics for Vertical Wells in Coalbed Methane
Authors: Gillies Alexander , Snygg Arnold J. , Dickehuth Debra 
Published: December 2007

Abstract
Previous economic studies of the recovery and utilization of methane from coalbeds using vertical wells were based on drainage in advance of mining where a single seam is drained with well spacing designed for rapid predrainage. A production economics study has been conducted which shows that the lower overall investment costs for wider spacing and increased production from multiple seams result in gas recovery at costs well below current prices for new gas imports. When applied to some of the thicker, deeper Western coals, the method also results in a favorable ROI.
Earth Stress Relationships in the Applachian Basin
Authors: McKetta Steven F. 
Published: December 2007

Abstract
This paper presents a derived stress ratio which permits the identification of the extent of the regional tectonic forces acting upon a formation. Once identified, these tectonic forces allow certain inferences to be made about the maximum potential of natural fracturing present in a formation. Investigation of three gas producing formations in the Appalachian Basin shows that the Berea sandstone, the Clinton sandstone and the Devonian Shale all display a similar tectonic relationship. This leads to the conclusion that much of the Basin can be categorized into different stress regions with each region relating the degree of natural fracturing present.
Unconventional Exploration for Natural Fractures
Authors: Hennington W. M. 
Published: December 2007

Abstract
This is a progress report on the evaluation of a new unconventional exploration technique for locating the natural fracture reservoirs in the Devonian - Ohio Shale. Five PHASE I tests have been drilled, cored, logged, cased and are currently being tested. Findings to date indicate that the technique has been successful in predicting the presence of natural fractures. In the six well PHASE II program, scheduled for later this year, the technique will be used to define the limits of these fracture systems. If PHASE II is successful, the project will have demonstrated that natural fracture reservoirs can be selectively located with a high degree of certainty.
Preliminary Results of the Wells-of-Opportunity Geopressured-Geothermal Testing Program
Authors: McCoy Rayford L. , Hartsock James H. , Dobson Richard J. 
Published: December 2007

Abstract
The Fairfax Foster Sutter No. 2 well located in the East Franklin area of St. Mary Parish and the Beulah Simon No. 2 well located in the Kaplan area of Vermilion Parish, Louisiana were the first successful tests of geopressured-geotherman (Geo2) aquifers under the Well of Opportunity (WOO) program. Gruy Federal assumed the Fairfax Foster Sutter operation on March 8, 1979 when the operator abandoned attempts to discover conventional hydrocarbons at a total depth of 16,340 ft. The Simon No. 2 well was acquired under similar circumstances approximately one month later at a total depth of 15,265 ft.
In both tests, the objectives were all accomplished and data were obtained which will contribute to the overall assessment of the geopressured-geothermal resource of the upper Gulf of Mexico basin. In both instances, the gas solubilities (22.8 and 24.0 scf/bbl) indicated that the waters were saturated with gas at reservoir conditions. The produced water was more saline than expected (190,000 mg/1 in one instance, 104,000 mg/1 in the other). {The high concentrations of dissolved solids in these waters created a scaling problem that required significant attention and will have to be addressed in future tests.1}
Test Results of Stimulated Wells in Devonian Shales
Authors: Kumar Raj M. , Hartsock James H. , Frohne K. H. 
Published: December 2007

ABSTRACT
The long test times required to attain radial flow in stimulated Devonian shale gas wells are impractical. However, experience shows that a short test period (about two weeks) is sufficient to evaluate reservoir and fracture properties using conventional techniques followed by mathematical simulation of the observed pressures. History matches, whether unique or not (insufficient production data are available at present to establish uniqueness), give clear insight into reservoir properties, the effectiveness of frac treatment, and well deliverability.
Determining the Feasibility of Using Vertical Boreholes to Drain Gas from the Pocahontas No. 3 Coalbed, Buchanan County, Va
Authors: Trevits Michael A. , Richards Walter L. , Von Schonfeldt Hilmar A. 
Published: December 2007

ABSTRACT
In July 1979, a project was established to determine the feasibility of using vertical boreholes to degasify the Pocahontas No. 3 coalbed in advance of mining. To date, three methane gas drainage boreholes have been completed near the Virginia Pocahontas No. 5 mine in Buchanan County, Va. Various coalbed reservoir tests and in-situ stress determinations have been performed. Hydraulic stimulation treatments were designed and implemented at two boreholes, followed by preliminary gas and water production testing.
Prediction Of CaCO3 Scale Under Downhole Conditions
Authors: Vetter O. J. , Kandarpa V. 
Published: December 2007

ABSTRACT
CaCO3 is one of the most common scales in oilfield and geothermal operations. Various thermodynamic models have been reported in the literature to predict the precipitation of CaCO3. Each of these existing models has its limitation when applied to the real situations of the field operations. Some models (e.g., Stiff-Davis method) ignore many conditions leading to CaCO3 precipitation.
In the present paper, we describe a model to predict the CaCO3 scale formation at any location within the field as a function of water composition, temperature and pressure. This model is based on equilibrium thermodynamics, but uses only the experimentally measured parameters. The input data for the model are (1) one water analysis, (2) one pH measurement at any location in the field, (3) the temperature at which the only field pH measurement is made, (4) the CO2 concentration of the gases (if a gas phase exists upstream or at the point where the liquid sample is taken and the pH is measured), and (5) the amount of flash (if a gas phase exists upstream or at the point of sample collection). The model then takes these measured data and calculates the equilibrium brine composition (including pH) in the reservoir.
The calculated brine composition data can then be used either to predict the CaCO3 precipitation for any set of prescribed conditions or to predict the CaCO3 precipitation at various locations within an oilfield or geothermal operation. For a set of temperature and pressure, the model goes through a decision to determine whether a single phase or two phase condition exists for the brine.
For the case of the existence of the single phase brine, the model calculates the amount of CaCO3 precipitate taking into account the pertinent chemical reactions involving the various carbonate species.
For the case of the existence of two phase brine, the model first computes the CO3 emission and its effect on the pertinent reactions Involving the various carbonate species and, hence, calculates the amount of CaCO3 precipitate.
Successful Stimulation in the Rocky Mountain Area Using a New Acid Base Gel System
Authors: Coulter Gerald R. , Harris Larry E. , Klebenow Don E. 
Published: December 2007

ABSTRACT
In hydraulic fracturing of some sandstone formations, it is desirable to use a low concentration of hydrochloric acid as the base fluid. This fluid is desired in these formations due to its superior fluid-rock compatibility characteristics. However, due to the rapid degradation of most gelling agents with hydrochloric acid, it has been difficult to place large quantities of propping agents.
A new gel system has been developed with imparts greater viscosity and a more stable get than previously available to the industry. This new gel system utilizes a low residue polymer, crosslinked with a unique crosslinker, in the presence of 3 to 5 percent HCl. The temperature stability and Theological properties of this get are presented in the paper.
A large number of treatments have been carried out with this gel system in various formations. For the purpose of this paper, we will discuss the treatments conducted in the Teapot formation in Wyoming.
The Use of Viscosity Stabilizers in High Temperature Fracturing
Authors: Elbel Jack L. , Thomas Ron L. 
Published: December 2007

ABSTRACT
A new viscosity stabilizer that increases the high temperature performance of fracturing fluids has been developed. It reduces the rate of viscosity loss of the fracturing fluid during the treatment resulting in more efficient prop transport. This is especially important in massive hydraulic fracturing where the fluids are exposed to high temperatures for long periods of time.
The new stabilizer was developed as a replacement for methanol which has traditionally been used as a stabilizer in high temperature fracturing applications. Unlike methanol, the new stabilizer is nontoxic and nonflammable.
The effect of a stabilizer on the long-term rheological properties of fracturing fluids and the resulting effect on the predicted prop placement are discussed. A comparison of computer predicted fracture geometries is made for fluids containing methanol and the new stabilizer. Field treatments incorporating viscosity stabilizers are also discussed.
The Effects of Power Supply Integrity on Electric Submergible Pumping Systems
Authors: Stewart Richard E. 
Published: December 2007

ABSTRACT
Little has been written regarding the effects of electric power integrity on submergible pumping systems. The remoteness of a site and/or the economics of the distribution system can result in power which affects equipment life and efficiency. Other installed electric devices or systems can also impact the quality of supply. The purpose of this paper is not to condemn the circumstances which lead to deficient power supply situations, but rather to address their effects and discuss practical means of correcting or minimizing their effects.
A Computer-Processed Wellsite Log Computation
Authors: Best D. L. , Gardner J. S. , Dumanoir J. L. 
Published: December 2007

ABSTRACT
A new logging unit with an integrated system of surface instrumentation built around a computer allows digitally recorded logs to be merged, computed, and recorded on film at the well site.
The SCHLUMBERGER CYBERLOOK wellsite computer processing utilizes the recently introduced "Dual Water" interpretation model for reservoir analysis. This model considers a shaly, water-saturated formation to behave as if it contains two types of pore water: "clay water" near the surfaces of clay crystals and "far water" at a distance from the clay surfaces.
The processing is designed so that all required input parameters can be accurately selected from a first-pass merge. The computations, corrected for shale and light-hydrocarbon effects, are presented on film in a format that is easily interpreted, allowing decisions to be made at the wellsite.
Field experience has shown the processing to be very flexible, providing excellent results throughout North America in both sandstone and carbonate reservoirs.