bluuebunny/crossref_metadata_2025_split huggingface dataset:
Two Tracer Test Method for Quantification of Residual Oil in Fractured Porous Media
Authors: Grigorievich B. P. , Archer J. S. 
Published: December 2007

Abstract
The method for identification of residual oil from the data of flow of two tracers with different solubility in oil is developed for fractured-porous reservoirs.
The solubility of tracer in the immobile phase (oil, retrograde condensate) leads the lag of the tracer front propagation behind the displacement front. The ratio of the tracer front velocity and the velocity of total flux is determined by the saturation of immobile phase. It allows us to determine the saturation of the residual hydrocarbon phase from the data of flow of two tracers with the different magnitude of the constant of tracer distribution between the water (gas) and oil (condensate).
A new equations for flow of two tracers in fractured-porous media are derived. Both diffusive and convective mechanisms of the tracer mass transfer between blocks and fractures are taken into account. The hydraulic interaction between fluxes in cracks and in matrix is described as well. Problem of one-dimensional flow leads to the linear system of hyperbolic equations. Analytical solution for ID problem of injection of water (gas) with the two tracers is obtained. Results of theoretical prediction of tracers wave propagation are in a good agreement with the data of laboratory experiments.
Exact explicit formulae for propagation of the concentration wave of two tracers allows us to solve an inverse problem. Method for improved characterization of fractured-porous media from data of two tracers concentrations on the exit of reservoir is developed. Measurement of the first tracer concentration allows us to determine the following properties of fractured-porous media: fractional flow function (fraction of the flux via fractures in the total flux); fraction of porous space of cracks in the total space of fractured-porous media; coefficient of mass transfer between fractures and matrix. Information about the concentration of the second tracer permits us to determine the saturation of the immobile phase separately in fractures and in blocks.
Ion Exchange Between Hydrogen and Homoionic Brines Related to Permeability Reduction
Authors: Souto Esperanza , Bazin Brigitte , Sardin Michel 
Published: December 2007

Abstract
Formation damage due to clay migration may be observed when the injected brine replaces the connate water during operations such as waterflooding, chemical flooding including alkaline, surfactant and polymer processes.
This work deals with the effects of physico-chemical changes induced by brine replacement on the permeability behavior of consolidated argillaceous sandstones.
The experimental investigation is made up of: –core flow experiments in clayey sandstones. Effluent pH and ionic concentration are measured at the outlet of the porous medium and permeability variations are simultaneously monitored when the injected salinity is abruptly decreased.–batch coagulation tests giving both critical salt concentration and pH in a salinity-pH diagram.
Brines are prepared with sodium and potassium salts.
A physico-chemical flow model is also developped based on cationic exchange with the proton when the salinity decreases. The model allows: –the interpretation of the experimental observations (pH and concentration)–the knowledge of the transition compositions–the effect of the major parameters like the clay content through the cation exchange capacity.
The model gives pH and salinity profiles. The comparison of these values with the salinity-pH diagram critical ones leads to the prediction of the effect of the fluid composition on the damage process.
Remedial Treatment for Polymeric Damage Removal Provides Improved Well Productivity
Authors: Tjon-Joe-Pin Robert , Brannon H. D. , Rickards A. R. 
Published: December 2007

Abstract
Recent advances in biotechnology have led to the identification and isolation of polymer-specific enzymes. This new technology has been incorporated in the development of improved damage removal systems. The polymer specific reactivity of the new systems provides environmentally safe polymer degradation without causing damage to the formation or tubular goods.
Polymer specific systems have been developed for removal of damage caused by polymers such as cellulose, guar, and starch. The treatments can be applied over a wide range of downhole conditions to polymeric damage resulting from fracturing, gravel packing, or workover operations.
Fracture conductivity and core flow evaluations have shown that multi-fold improvements in permeability are achieved with the new systems. Damaged wells treated with the new systems have experienced up to three-fold improvement in well productivity. A detailed study and analysis of laboratory and field data are presented.
Moncrief (Pittsburgh) Unit Waterflood A Case History of High Pressure and Wide Spacing
Authors: Gaskill Robert A. 
Published: December 2007

Introduction
The Moncrief field is located approximately 6 miles north of the city of Winnsboro, Franklin County, Tex. The field is productive in two reservoirs—the Smackover Lime at 12,200 ft, which is gas productive, and the Pittsburgh oil sand at 8,250 ft. As originally developed, after discovery in March, 1964, the Moncrief field Pittsburgh sand produced from ten 160-acre spaced wells which proved approximately 1,562 acres of reservoir areal extent.
Early observation of performance indicated that the Pittsburgh sand reservoir was producing under a primarily rock and fluid compressibility mechanism, and that the pressure and well capacities were depleting rapidly. With the realization that the supplementary solution gas energy available would be deficient for efficient exploitation of the field, efforts were begun to unitize the reservoir for pressure maintenance. The Pittsburgh reservoir was unitized for a flooding operation effective March 1, 1967.

GEOLOGY AND RESERVOIR CHARACTERISTICS
The Moncrief field is geologically part of an elongated anticlinal system which trends into the New Hope field structural trend to the northeast. The Pittsburgh reservoir, as developed on the crest of the structure, exhibits approximately 70 ft of closure and reaches a maximum thickness of 23 ft in the Unit Well 1-1. The lithology is described as that of a fine grained sandstone by core analysis and sample descriptions. Fig. 1 is a contour map indicating the structural attitude of the Pittsburgh zone.
The reservoir is bounded by an acquifer to the north and south at a subsea depth at about -7,780 ft. However, the effect of the aquifer is largely nullified by the thinning nature of the sand and the adverse permeability development along these flanks. Fig. 2 is an isopachous of the Pittsburgh net sand interval. A permeability pinchout is evidenced on the western permeability pinchout is evidenced on the western end of the reservoir trend by the distinctive difference in the crude gravity in the westerly direction. A test in the Humble-Winnsboro Fish and Hunt Club No. 1, located about three-quarters of a mile west of the unit boundary, yielded a 40 degrees API gravity crude. The Moncrief Pittsburgh sand produces 32 degrees API gravity crude. The Pittsburgh reservoir permeability is believed to Pittsburgh reservoir permeability is believed to discontinue at its eastern extremity somewhere within the west half of the M. Oliphant Survey. Again, the differential in the crude gravities lends support to this conclusion along with the apparent general thinning in sand development in the easterly direction. Further, the Moncrief Pittsburg field demonstrated no evidence of Pittsburg field demonstrated no evidence of pressure depletion when discovered in March, 1964, pressure depletion when discovered in March, 1964, with a reservoir pressure of 3,703 psig.
Chemistry of Interstitial Solutions in Shales Versus that in Associated Sandstones
Authors: Chilingar George V. , Rieke Herman H. , Sawabini Stan T. 
Published: December 2007

Abstract
Experimental results obtained by the writers show that the salinity of squeezed-out solutions from muds progressively changes with increasing overburden pressure. Both marine muds and clays plus sea water mixtures were used. Experimental results also show that the salinity of water remaining in shales should be considerably lower than that in associated sandstones. Yet, log analysts in their calculations assume that salinity of interstitial waters in shales and in sands is the same. This may result in erroneous interpretations.
Field data show a typical pattern of decreasing salinity of produced water with time in zones which receive most of their water from associated shales. This supports the above-mentioned conclusion based on laboratory data.
Introduction
Large amounts of water are squeezed out of the continental and marine sediments during compaction and lithification. The overburden pressures on these sediments may reach pressures on these sediments may reach magnitudes of 14,000 to 36,000 psi in geosynclinal basins. Most of the salts present in the waters, which are trapped during sedimentation,, are squeezed out during the initial stages of compaction. The laboratory results obtained by Buneeva et al. Kryukov and Komarova, Kryukov and Zhuchkova, Rieke et al. and Chilingarian and Rieke showed that mineralization of squeezed-out solutions progressively decreases with increasing overburden pressure.
Very little is known of the actual porosity of shale and the actual salinity of the contained water. It seems that if one could be determined the other probably could be calculated. The actual salinity of formation waters of the sands usually ranges from three times the salinity of sea water to one-fourth times the salinity of sea water [average salinity of sea water = 35 degrees/oo], and may range from greater than 10 times salinity of sea water to virtually fresh water. Recently, Foster and Whalen presented a technique for estimating formation pressures from electrical logs. This technique has been found especially applicable in the offshore Louisiana area in detecting abnormally high reservoir pressures. These authors, however, assumed that pressures. These authors, however, assumed that the water resistivity values in shales are equal to, or of the same magnitude, as that calculated for nearby sands. Consequently, solution Of this problem [chemistry of interstitial waters in shales vs chemistry of waters in associated sandstones] is of great practical importance.
A Method of Predicting Saturation Exponents in Logging
Authors: Von Gonten W.D. , Osoba J.S. 
Published: December 2007

Abstract
Water saturation is calculated from resistivity logs by using the relationship
where n is the saturation exponent. From this equation, it is evident that in order to calculate accurate water saturations from logs, the value of n must be known.
In this research project, saturation exponents and electrical formation factors were measured using three different salinity waters on 63 core samples from two wells in the same field. Porosity and permeability were also determined on each of the cores. The log readings from the SP Log, Density Log, Gamma Ray. Log, and Sidewall Neutron Log were read to coincide with each core sample. The lithology of samples ranged from clean to shaly fine grained sandstone.
Both the saturation exponent and formation factor were found to be greatly affected by the saturating water resistivity. The three waters used had resistivities of 0.06, 0.2, and 2.0 Ohm-Meters. As the water resistivity increased, the saturation exponent and formation factor decreased. The saturation exponent averaged about 2.03 for the 0.06 Ohm-Meter water but decreased to an average of about 1.21 for the resistive 2.0 Ohm-Meter water.
All of the core analysis and well log data was used in a regression analysis computer program to predict saturation exponent. Saturation exponent was predicted with the computer program to an average error of about 9 percent. Water resistivity was by far the most percent. Water resistivity was by far the most important independent variable in the prediction equation and permeability was second. By using water resistivity by itself, the saturation exponent was predicted with an average error of 15 percent.
This research shows that in either shaly sand or formation with high water resistivity large errors in determining water saturation can be made by assuming that the saturation exponent is equal to 2. This work further shows that saturation exponent can be predicted from routine core analysis and well log data.
The Goals of Engineering Education Report in Retrospect
Authors: Higdon Archie 
Published: December 2007

Background
The Goals report was the fifth national evaluation and in-depth study of engineering education in the current century. The Mann Report 1907–18, the Wickenden Report 1923–30, the Hammond Report of 1940, updated in 1944, and the Grinter Report 1952–55, preceded the Goals Report 1962–68.
No other academic discipline or field of study has subjected itself to such intensive study. Furthermore, no other undergraduate educational program of this age requires its students to study such a broad spectrum of subject matter. Engineering education combines an understanding of this technological age in which we live as a key part of a broad liberal education and yet still finds time for specialization in a branch of engineering.
A four-year undergraduate program in any of the engineering disciplines today includes approximately one year (one-fourth of the program) in mathematics and basic sciences, program) in mathematics and basic sciences, one year in the engineering sciences, onehalf year in the social sciences and humanities, one-half year in analysis, synthesis, and design, plus another half year in courses in the specific engineering specialty, with the remaining half year for miscellaneous courses including composition, speech, graphics, and physical education. Please understand that these are very general averages and that some programs vary quite a bit from these data.

The Goals Report
The Preliminary Goals Report was published in October, 1965, and immediately published in October, 1965, and immediately became an extremely controversial document. In retrospect, this was very fortunate because engineering educators as well as practicing engineers everywhere became keenly practicing engineers everywhere became keenly aware of engineering educational problems and aspirations. In order to debate the issues effectively, engineers were forced to study the pros and the cons of each recommendation. The Preliminary Report contained fourteen specific recommendations. Even today, there is more heat than light in some discussions of some of those fourteen issues but the study and the dialogue alone made the time, effort, and money used to prepare the report well worth it.
After regional meetings across the nation on the Preliminary Report, followed by much study by the Goals staff and the Boards of Analysts, the Interim Goals Report was published in April, 1967. Much of the furor published in April, 1967. Much of the furor had subsided by this time and the Interim Report was rather generally accepted. Naturally, some people continued to oppose some aspects of the modified report.
Progressive Cavity Pumps Deliver Highest Mechanical Efficiency/Lowest Operating Cost in Mature Permian Basin Waterflood
Authors: Wright D. W. , Adair R. L. 
Published: December 2007

ABSTRACT
Results of a field test study proved that progressive Cavity (PC) pumping systems provide greater mechanical efficiency and less electrical usage than beam and electrical submersible pumping (esp) systems in mature waterflood producing wells. These systems were evaluated in Permian Basin wells ranging from 3800 feet to 5000 feet in depth and production rates ranging from 500 barrels per day to 1000 barrel per day.
Operating facilities were used to monitor production, fluid shots were used to monitor fluid levels, and inline mechanical kw-hr meters were used to measure electrical usages before and after PC pump system installations. Mechanical efficiencies were calculated based upon this data. Production tests indicate that total well productivity was increased and an incremental oil increase was realized where PC pumping systems replaced beam lift systems previously thought to be optimum.
Increased water production due to waterflooding has necessitated lift revisions and beam pump optimization. When a beam lift system has reached maximum potential, a larger lift system becomes necessary. Esp systems provide increased lift capability, but at a much lower efficiency. The criteria used for selecting the test wells was maximized beam lift and economically marginal esp producing systems. The purpose for the field test was to determine if PC pumping systems were an economic alternative to lift these high WOR wells when compared to beam and esp systems.
A field test study was began in 1991 to evaluate mechanical and electrical efficiencies of PC pumping systems in the environment stated above. A comparative analysis to beam and esp lift systems was then performed. This paper presents the results of that analysis and confirms that PC pumping systems are the most cost effective artificial lift systems in mature Permian Basin waterlood producing wells.
Enhancing Performance of Submersibles Operating in Miscible Flood Conditions
Authors: Durham M. O. , Miller Gerald 
Published: December 2007

Abstract
A submersible system is the most effective equipment for producing large quantities of fluid in a marginal environment. A miscible flood presents a unique set of conditions for operating submersible systems. Some of the conditions encountered include depth, small diameter well bores, high horsepower, temperature, gas production, power system disturbances, hydrogen sulfide, asphaltines, and changing conditions.
The design of equipment, selection of materials, and operating requirements require special consideration. Techniques that enhance submersible performance are identified. Although none of these may be dramatic, the combination is dynamite.
The paper gives the operating conditions and experience with each component of the submersible system. The authors describe problems with and recommendations for selecting pumps, motors, seals, gas separators, cable, and variable frequency drives. Special attention is given to metallurgy, elastomers, training, and checklists necessary for successful operation. An extensive set of curves track the performance before and after changes.
Determination of Hydraulic Fracture Direction, San Juan Basin, New Mexico
Authors: Yale D. P. , Strubhar M. K. , El Rabaa A. W. 
Published: December 2007

ABSTRACT
Reservoir management of hydraulically fractured reservoirs can be improved with knowledge of the orientation of hydraulic fractures. Fracture direction can affect where wells are placed, the design of well patterns for EOR floods, the design of fracture treatments, and the stability and fracturing of horizontal wells. This paper presents a field study of the determination of hydraulic fracture direction in the San Juan basin in northwest New Mexico. Data from six different fracture direction techniques were integrated to improve the determination of fracture direction. Integrating results from the six techniques not only improves the accuracy of the results but also allows us to compare the techniques to one another on the basis of reliability of results, operational requirements, and cost effectiveness.
The average of all the data from each of the four wells suggests a hydraulic fracture direction of 41° azimuth in this area of northwest New Mexico. The trends agree with regional in-situ stress direction for the area1. There were only small variations between wells and the fracture direction was consistent with depth over the 300 feet of formation tested. The direction of natural fractures as seen in the core and in the borehole televiewer was similar to the hydraulic fracture direction.
Based on this study and other published reports2-13 on hydraulic fracture/in-situ stress direction, we believe hydraulic fracture direction is best determined by integrating results from multiple techniques in several wells in an area. We find that the ability to determine fracture direction is most affected by the horizontal stress contrast in the area and the presence of paleo-imprints on the rocks. Fracture direction can strongly affect the recovery of hydrocarbons from hydraulically fractured fields and should be a datum that is collected routinely in the development of such fields.
Modelling Natural Gas Markets: Answering the "What It's"
Authors: Davis D. D , Harris J. M. , Bohlen P. S 
Published: December 2007

ABSTRACT
Extensive market research has shown that volatility is the only characteristic that is constant in the natural gas marketplace. Methods which simply tie natural gas prices to crude oil prices as a predictor are, at best, inadequate and dangerous.
A more useful and realistic gas market assessment can be obtained by studying the relationship among key parameters within the market. Among others, population-weighted heating degree days, amount of gas in storage, demand growth, total deliverability, seasonal volatility, and net imports all have a profound influence on price.
These factors are presented in four separate cases using a dynamic, intertemporial simulation model. To address more "What IP questions, the algorithm is perturbed with variables such as the assumption of the mildest winter on record, followed by the coldest spring on record. The four cases presented are considered to be "mainstream" conditions that will most likely exist, however, some extremes are imposed to account for the unusual.
Measurements of Effective Fracture Toughness Values for Hydraulic Fracture: Dependence on Pressure and Fluid Rheology
Authors: Holder Jon , Morita Nobuo , Kenrick A. J. , Thallak Sitharam , Gray K. E. 
Published: December 2007

Abstract
Results from a series of laboratory hydrofracture tests, in which different fracture fluids, fracture fluid injection rates, confining pressures, and test specimen mechanical and fluid transport properties were used, are presented and discussed. Fracture fluids included various simple linear viscous (Newtonian) fluids and different combinations of three types of commercial fracture fluids: linear gels, cross-linked gels, and combinations of gels with suspended solids. Systematic variations in the behavior of fracture initiation pressures, and fracture fluid pressures during stages of stable fracture propagation, are observed to depend on fluid flow resistance, leak-off rate, and fracture fluid rheology. Post-test inspections of hydrofracture surfaces indicate the presence of a dry zone near the fracture tip. The effective hydrofracture toughness parameters determined from the tests with fracture fluid gels are substantially higher than the normal Mode-I toughness values, determined for the same material. The behavior is interpreted to be the consequence of a build-up of solids at the fracture tip, from dehydration of fracture fluids containing gels and/or solids.