bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Field Testing of a Core Barrel for Recovering Unconsolidated Oil Sands
Authors: Hildebrandt A.B. , Bridwell H.C. , Kellner J.M. 
Published: December 2007

Abstract
The rubber-sleeve core barrel was developed to improve core recovery from unconsolidated sands, where it is most difficult to obtain cores with conventional barrels. The use of a rubber-sleeve core retainer, together with other departures from usual design, has required a considerable amount of testing to prove its operability. Tests run in shallow experimental holes and in drilling wells in the U.S. and Venezuela have, to a large extent, proved the operation of the barrel. Internal mechanism troubles, such as sandbinding of the sleeve, have been largely overcome. Cores have been recovered from completely unconsolidated sands where conventional coring has almost been abandoned because of poor recovery. In addition to retaining the core until brought to the surface, the barrel gives a "packaged-as-cut" core, which is convenient for handling and transportation. In the initial work, drag blade cutters, roller cutters, and tungsten carbide insert cutters were used for cutting unconsolidated sands.
Further bit head development is presently being conducted using diamond heads in unconsolidated sands where shales, hard sands, and limestones are encountered in adjacent formations. This work should render the barrel capable of cutting and recovering most types of formations, possibly including broken and fractured formations. This development is being carried on in cooperation with a diamond bit manufacturer.

Introduction
For many years the oil industry has needed greater recovery of cores from unconsolidated formations. Conventional equipment has been used to core unconsolidated sands with little success. Specifically, a core barrel was needed which would recover unconsolidated sands in a condition that would give useful reservoir information.

Development of the Rubber-Sleeve Core Barrel

Basic Requirements of Unconsolidated Sand Coring
The basic need was defined as a core barrel that would obtain a continuous unconsolidated core with sand grains in place as deposited in the formation. A preliminary survey of coring equipment and search of the literature pointed out the weaknesses of conventional core barrels. Laboratory tests using unconsolidated sand in a metal tube simulated actual sand movement into the care barrel during conventional coring. In conventional barrels the core sometimes crumbles and bridges, or fails under compressive column action, becomes oversize, and wedges against the walls of the inner barrel.
The Salinity-Requirement Diagram–A Useful Tool in Chemical Flooding Research and Development
Authors: Nelson Richard C. 
Published: December 2007

Abstract
Optimal salinity, the level of brine salinity at which a chemical flooding surfactant displaces oil most efficiently, is related to midpoint salinity and to the range of salinity over which the phase environment is Type III. These three conditions are functions of surfactant concentration—usually decreasing as surfactant concentration decreases, particularly if the brine contains multivalent cations. A salinity-requirement diagram, constructed from phase equilibrium data, expresses quantitatively the dependency of midpoint salinity and the Type III range on surfactant concentration. Because surfactant coneentration decreases as a flood with a small-pore-volume chemical slug proceeds, a salinity-requirement diagram can provide insight into the performance of chemical floods. Examples are presented that support the proposal that chemical flooding is most efficient when conducted in a salinity gradient. A phenomenon in which a "wedge" of oil is left on the bottom of the core by a chemical flood is related to the salinity-requirement diagram for the system, and the effect of ion exchange on such diagrams is discussed.
Estimating Air Emissions for BP's Permian Basin Gas Plants and Oil and Gas Properties
Authors: Johnstone James E. , Stobbe Alan 
Published: December 2007

Summary
A system to estimate emissions from large numbers of oil and gas producing properties and gas plants was developed by BP's Permian asset environmental group. The system estimates air emissions on a quarterly basis for both internal and external reporting requirements. An additional benefit has been increased lease revenues from improved operating efficiencies identified by the system.
The results of the emissions-reporting system enabled BP to accurately estimate the emissions from each property. Emissions for the Permian asset were quantified. Internal and external reporting requirements were integrated. Lease-gas use was reduced by optimizing fuel burned and the use of bleed-gas-operated equipment. The study also helped prioritize additional engineering work to look at fuel consumption in fired equipment.
Identified Models for Gas Storage Dynamics
Authors: Chierici G. L. , Gottardi G. A. , Guidorzi R. P. 
Published: December 2007

AbstractThe classical approach to forecasting hydrocarbon reservoir behavior is through modeling. Traditional models are based on equations describing the physical behavior of the reservoir-plus-aquifer system; usually the parameters describing aquifer behavior are not known beforehand and are evaluated by a trial-and-error procedure based on the best fit of past reservoir performance. This approach leads to models that are intrinsically realistic, as they reflect the physical nature of the phenomena involved.A completely different approach, based on system theory techniques, is presented in this paper. This technique, called identification, consists of the determination of a mathematical model equivalent to the process under test, the word "equivalent" meaning that the process and the model show the same input/output behavior. As a consequence, an identified model of this type can be used to predict the response of an actual reservoir-plus-aquifer system to different inputs – i.e., to different production schedules.Case histories of the application of the identification technique to actual gas storage reservoirs are presented.
Application of the Time-Dependent Overall Heat-Transfer Coefficient Concept to Heat-Transfer Problems in Porous Media
Authors: Satman Abdurrahman , Zolotukhin Anatoly B. , Soliman Mohamed Y. 
Published: December 2007

Abstract
Prediction of temperature distribution behavior during thermal recovery processes is necessary for engineering evaluation of field operations. Such a prediction can be used in the case of hot- and cold-water injection into a reservoir and also applies in some other thermal recovery processes, such as in-situ combustion and steam-flooding.
The mathematical formulas discussed involve the concept of a time-dependent overall heat-transfer coefficient. In the first portion of the paper, we discuss two new analytical solutions that describe the temperature distribution in linear and radial reservoirs in the case of hot- and cold-water injection. A comparison with published laboratory hot-water injection data demonstrates the validity of the solution for linear geometry. Since the new analytical model considers the heat conduction in addition to convection and heat loss, it describes the thermal behavior in a more general form than does Lauwerier’s model. These two models are compared also.
The application of the time-dependent overall heat-transfer coefficient concept to the thermal behavior of the steam plateau portion of the in-situ combustion process is discussed in the second part of the paper. The result is fairly satisfactory.
Natural Gas Potential of the New Albany Shale Group (Devonian-Mississippian) in Southeastern Illinois
Authors: Cluff Robert M. , Dickerson Donald R. 
Published: December 2007

Abstract
Data from geologic and geochemical studies of the New Albany shale group indicate that a 19-county area of southeastern Illinois is a favorable area to explore for gas in Devonian shale. Although gas shows in the shales have been encountered in several wells drilled in this area, no attempts were made to complete or evaluate a shale gas well until 1979.
In 1979, core samples from two Wayne County wells were obtained, permitting the first quantitative assessment of gas content of the shales in this area. Seventy core samples from the two wells were sealed in airtight canisters at the drilling site for off-gas analysis. The quantities of shale gas released from the core samples in a 34-day period ranged from 0.16 to 2.40 cu ft HC/cu ft (0.16 to 2.40 m3 HC/m3)* of shale. This gas is richer in heavy hydrocarbons than is the average "pipeline gas." It has a calculated average BTU value of 1,240 Btu/cu ft (46 200 kJ/m3). Because the proportion of nonhydro-carbon gases is unknown, the calorific content of produced gas would necessarily be slightly lower. The gas-bearing intervals generally correspond with high radioactivity intervals on gamma-ray logs. The quantities of shale gas in core samples from these wells are similar to those in gas-producing areas of Devonian shale in the Appalachian basin. However, because the New Albany shale is much thinner than its Appalachian basin equivalents, the total gas resource is probably much smaller.
Conventional rotary drilling with mud base drilling fluids likely causes extensive formation damage and may account for the paucity of gas shows and completion attempts in the Devonian shales; therefore, commercial production of shale gas in Illinois probably will require novel drilling and completion techniques not commonly used by local operators.
The Effect of Hydrotropic Salts on Phase Relationships Involving Hydrocarbons, Water, and Alcohols
Authors: Ho Patience C. , Kraus Kurt A. 
Published: December 2007

Abstract
Hydrotropic salts, which can increase the solubility of organic materials in aqueous solutions, are of interest in a variety of industries including those related to tertiary oil recovery. We have examined effects on solubility of hydrocarbons in water (with and without alcohols) by adding inorganic hydrotropic salts such as Perchlorates, thiocyanates, and iodides (high in the usual Hofmeister series), organic salts such as short chain alkyl benzene sulfonates, and other salts based on substituted benzene derivatives. Although the inorganic salts are relatively ineffective in increasing solubility of hydrocarbons in water, many of the organic salts are excellent hydrotropic agents for hydrocarbons.
We have examined the phase relationships for several series of aromatic salts such as sulfonates, carboxylates, and hydrocarboxylates as a function of alkyl-carbon substitution in three-component (hydrocarbon, salt, water) and in four-component (hydrocarbon, salt, alcohol, water) systems. We also have examined miscibility relationships for a given hydrotropic salt as the chain length of alkanes and alkyl benzenes is varied systematically.
While miscibilities decrease with increase in chain length of the hydrocarbon, the hydrotropic properties in these systems increase rapidly with the number of alkyl carbons on the benzene ring of the salts, and they arc relatively insensitive to the type of charged group (sulfonate vs. carboxylate) attached to the benzene ring. However, there are significant increases in hydrotropy as one goes from equally substituted sulfonates or carboxylates to salicylates. A number of salts have been identified that have much greater hydrotropic properties for hydrocarbons than well-known hydrotropic materials such as toluene and xylene sulfonates.
Divalent Ion Exchange With Alkali
Authors: Bunge A. L. , Radke C. J. 
Published: December 2007

Abstract
Exchange of hardness ions is important in EOR with chemical additives. In both micellar/polymer and caustic flooding processes, multivalent ions released from rock surfaces can interact with anionic surfactants, rendering them preferentially oil soluble and/or insoluble in water. Because hardness cations are sparingly soluble and precipitate in alkaline solutions, such solutions may be more efficient as surfactant-flood preflushes than are softened brines. Multivalent ion precipitation may also occur in alkaline waterflooding. To permit design of such processes, this paper presents a chromatographic theory for simultaneous ion exchange with precipitation of divalent ions.
Theoretical effluent histories and concentration profiles are presented for the cases of finite pulses and continuous injection of hydroxide ions into linear cores. Complete capture of the insoluble salt particles is assumed. Results are given for the case of instantaneous equilibration of the solution with the precipitate, as well as for the case of complete nonequilibrium, in which the solid precipitate does not redissolve. These two physical extremes predict field performance and laboratory results, respectively. Data for Berea sandstone and an argillaceous sand compare favorably with the proposed theory.
The efficiency of alkaline preflushing is shown to depend on the exchange isotherm, initial divalent loading of the rock, injected pH and salinity, the solubility product of the precipitated salt, and pulse size. The effect of pulse size on complete equilibrium removal of hardness ions is reduced efficiency with increasing size until a critical volume approximating continuous injection is reached. Increasing injected pH and salinity provides a more favorable response.
The theoretical model, when applied to field conditions, predicts redissolution zones that have not been previously recognized because solution residence times in laboratory columns are too short. Calculations show that precipitate redissolution by the low-pH solutions following alkaline pulses may introduce high concentrations of calcium behind the preflush where interference with micellar or polymer solutions is likely. These results suggest that reservoir preflush design from laboratory tests, while possible, must be made carefully.
Surfactant Flooding 1: The Effect of Alkaline Additives on IFT, Surfactant Adsorption, and Recovery Efficiency
Authors: Krumrine Paul H. , Falcone James S. , Campbell Thomas C. 
Published: December 2007

Abstract
This paper examines the effects of alkaline additives on dilute surfactant systems for improved oil recovery. The study was limited to the determination of the effects of alkaline additives on interfacial tension (IFT), surfactant adsorption or retention in Berea cores, and improvement in oil recovery. The alkaline chemicals studied were sodium silicates, sodium phosphates, sodium carbonate, and sodium hydroxide. In addition, optimal salinities and surfactant average equivalent molecular weight for the recovery of two midcontinent crude oils were determined through a combination of IFT determinations and oil displacement tests.
The laboratory results show that the alkaline chemicals have two major effects. First, IFT is reduced further by the high pH surfactant/alkali solution combinations, and second, certain alkaline species significantly reduce surfactant retention. This leads to recoveries of residual oil from 40 to 70% with surfactant solutions containing only 0.25 wt% surfactant.
A Method for Determining Optimum Second Stage Pressure in Three Stage Separation
Authors: Whinery Kenneth F. , Campbell John M. 
Published: December 2007

Introduction
This investigation was prompted by the absence of a simple, accurate method to predict optimum second stage separation pressure in three stage separation operations. Three stage separation as used here includes two separators plus the stock tank. The first stage pressure is usually fixed by gas sales conditions and the third stage is at atmospheric pressure. Thus, the second stage pressure is the only one that may be varied indiscriminate during production operations. No variations in temperature were considered in this study, even though it will vary among systems, for a change in temperature has little effect on the optimum pressure. Optimum pressures may be determined from flash calculations, but these are tedious unless a computer is available. An early attempt to develop a simpler method yielded an equation which gave the optimum pressure only as a function of initial and final pressure. Experience, however, confirms theoretical relationships which show that composition as well as pressure and temperature must be a factor.

Development of New Correlation
Wellstreams having 17 different analyses, ranging from low gravity crude to condensate, were used to determine the effect of composition. Each wellstream was flashed through three stages to determine the optimum second stage pressure for each first stage pressure. Equilibrium vaporization ratios proposed by Latham and Campbell were used throughout. The heptane plus fraction, for simplicity, was assumed to have the properties of octane.
Modeling Natural Gas Reservoirs – A Simple Model
Authors: Collier Richard S. , Monash Ellis A. , Hultquist Paul F. 
Published: December 2007

Abstract
A mathematical model is developed and tested for the production of natural gas with water encroachment and gas entrapment. The model is built on the material and volumetric balance relations, the Schilthuis water drive model, and a gas entrapment mechanism which assumes that the rate of gas entrapment is proportional to the volumetric rate of water influx. This model represents an alternative to the large grid models because of its low computer, maintenance, and manpower costs.
Performance of the Pickton Field
Authors: Barton H.B. , Dykes F.R. 
Published: December 2007

Abstract
The Pickton field, located in Hopkins County, Tex., produces from the Bacon lime reservoir of the Lower Glen Rose formation. The discovery well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cu ft/bbl, and subsurface samples of the reservoir fluid obtained soon after completion showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Reservoir studies indicated a recovery of only 19.4 per cent of the oil originally in place during primary depletion by dissolved-gas drive. It was also estimated that pressure maintenance recovery by gas displacement would total 36 per cent of the oil originally in place. Pressure maintenance by injection of dry Pickton field gas and extraneous gas from the Yantis field has increased the reservoir pressure to 90 per cent of the original pressure, and a satisfactory gas-sweep pattern has been maintained. Current recovery is 35 per cent of the oil in place. In this high-pressure gas injection pressure maintenance project, it is believed that vaporization of reservoir oil by dry gas injection has contributed substantially to the total ultimate recovery.

Introduction
The Pickton field history has been sufficiently short so that the predictions obtained by extensive engineering studies have been evaluated. Analysis of the results indicates, that by maximum use of advanced engineering technology and present day conservation measures, the Pickton field operations have been converted from an unprofitable to a profitable enterprise.
In Nov., 1944, with the completion of Humble's C. D. Nichols 1, initial production was obtained from the Pickton field in the East Texas basin, which is situated in the northeast corner of the state as shown at the top of this page. A large scale man of the central area of this basin. Fig. 1, locates the Pickton field in Hopkins and Franklin counties, 28 miles southwest of the Talco field and 28 miles northwest of the Hawkins field. The field is 16 miles southeast of Sulphur Springs, Tex.
Comparison of the Inhibitory Action of KCl and Guanidine Hydrochloride Solutions on Montmorillonite Swelling
Authors: Iltis M. , Didier G. , Laréal P. 
Published: December 2007

Abstract
This study compares the effectiveness of potassium chloride with guanidine chlorhydrate in the prevention of clay swelling. The results given on various swelling tests on calcic montmorillonite led to the conclusions that (1) guanidine chlorhydrate is more effective than potassium chloride, especially in low concentrations, and (2) water immersion of samples treated by both solutions shows the permanent feature of the inhibitive action of guanidine chlorhydrate in swelling on one hand and the important increase in swelling of immersed samples treated by potassium chloride on the other. The viscosity measure of montmorillonite suspensions, before and after solution ion elimination by dialysis, confirms these observations.
A Novel Dynamic Measurement of Permeability
Authors: Moran J. H. , Papaconstantinou C. M. 
Published: December 2007

Abstract
A method is proposed for the laboratory determination of permeability; a water-saturated core is shaken and the electrokinetic electromotive forces (cmf's) generated thereby are measured as an indication of water movement within the core. This method also can provide a determination of the zeta potential. It is of special interest because of its possible extension to use as a well logging measurement.
Tubing Movement, Forces, and Stresses in Dual-Flow Assembly Installations
Authors: Durham Kenneth S. 
Published: December 2007

AbstractTubing movement, forces, and fiber stresses in single completions have been discussed thoroughly by Lubinski et al.1 Subsequent papers have expanded this discussion to combination tubing strings2 and fixed intermediate packers.3 This paper presents the theory and solution of tubing movement, forces, and fiber stresses for dual-flow assembly installations—that is, situations in which the intermediate packer is free to move within a seal bore.
Decline Curve Analysis Using Type Curves for Two-Porosity Systems
Authors: Prat Giovanni Da , Cinco-Ley Heber , Ramey Henry J. 
Published: December 2007

Abstract
Constant producing pressure solutions that define declining production rates with time for a naturally fractured reservoir are presented. The solutions for the dimensionless flow rate are based on a model presented by Warren and Root.1 The model was extended to include constant producing pressure in both infinite and finite systems. The results obtained for a finite no-flow outer boundary are new and surprising. It was found that the flow rate shows a rapid decline initially, becomes nearly constant for a period, and then a final decline in rate takes place.
A striking result of the present study is that ignoring the presence of a constant flow rate period in a type-curve match can lead to erroneous estimates of the dimensionless outer radius of a reservoir. An example is presented to illustrate the method of type-curve matching for a naturally fractured system.
Influence of Microgels in Polysaccharide Solutions on Their Flow Behavior Through Porous Media
Authors: Chauveteau Guy , Kohler Norbert 
Published: December 2007

Abstract
Microgels existing in xanthan solutions, which are partly responsible for the poor injectability of such solutions, are retained around the injection wells. Therefore, most of the oil is swept by microgel-free solutions. This paper shows that even a few microgels can strongly modify flow behavior in porous media. Consequently, their careful elimination is required in laboratory tests for proper design of a polymer flood.