bluuebunny/crossref_metadata_2025_split huggingface dataset:
Controlled Solubility Phosphates--A Versatile Solution To Oilfield Scale Problems
Authors: Sloat Ben 
Published: December 2007

Abstract
Water flooding has focused attention on the problem of scale in producing wells. Four reasons why scale forms are discussed. A new theory which will help explain the severe scale build-up that occurs in many producing wells at the time of water breakthrough is presented.
A recently developed family of scale preventives - the controlled solubility phosphates - are described chemically and physically. Factors which influence the performance of these unique phosphates in oilfield brines are evaluated in terms of laboratory test data.
Case histories of producing wells treated with controlled solubility phosphates are summarized. The importance of bottom-hole temperature, the role of produced-fluid mineral characteristics and the value of knowing down-hole flow conditions are pointed out.
Economic considerations well known to engineers and production men are used to compare the cost of conventional treatment and the cost of the new controlled solubility phosphate scale-prevention approach.

Introduction
General acceptance of the artificial water drive as a secondary producing mechanism for the recovery of oil has made many petroleum engineers and production men extremely "water conscious" during the last few years. Scale and corrosion problems of a type seldom encountered in primary production soon become evident as leases are placed under flood. In attempting to find solutions to these newly created problems, the oil industry has learned that standard municipal and industrial water-treatment practice is going to be of little value. The reason for this is that, until the oil industry started to emphasize water flooding and the conditioning of produced fluids, no one had ever attempted to make use of water of as poor quality as that now being handled by many secondary-recovery operators. The need for processing brines saturated with corrosive gases, scale-forming minerals and insidious microbiological growths has opened up a completely new field of water-conditioning technology.
This paper deals with scale in oilfield brines. Factors which influence the formation of scale are discussed along with how petroleum engineers can get the most out of a unique family of chemicals which will effectively prevent scale.
EPT Interpretation in Carbonates Drilled With Salt Muds
Authors: Kenyon W. E. , Baker P. L. 
Published: December 2007

SummaryLaboratory measurements of rock dielectric permittivity show a dependence on water conductivity. The laboratory measurements were fitted by a model in which the rock microgeometry is represented as a collection of grains, some platy and some spherical, in water. The model can be used in a variety of log interpretation methods for the electromagnetic propagation tool (EPT), with or without microresistivity logs.
Analysis of Interference Data in a Highly Heterogeneous Naturally Fractured Geothermal Reservoir
Authors: Benson S. M. , Lai C. H. 
Published: December 2007

SummaryAn approach consisting of a combination of composite and naturally fractured reservoir models has been proposed to interpret pressure-transient data from an 11-well interference test in a highly heterogeneous geothermal reservoir. The approach leads to an integrated interpretation that accounts for all of the salient features of the data.An initial appraisal of the data indicates excellent agreement with theoretical results for double-porosity reservoirs. For some of the wells, however, the bulk storativity, calculated with the double-porosity model, differs significantly from the average value of this parameter. Furthermore, it increases systematically as the distance between the active and observation wells decreases. To explain this peculiar result, an alternative method of analyzing data from composite reservoirs is presented. The method demonstrates that local permeability variations can result in enormous variations in the apparent storativity without causing variations in the apparent permeability-thickness of the reservoir. A simple graphical technique, based on analyzing systematic variations in the apparent storativity, has been developed to determine the size of the region and the mobility contrast between different regions of the reservoir. By using this technique, we show that the observed variations in the storativity are the result of a small, high-permeability region that surrounds the pumped well and is penetrated by several of the observation wells.
Experimental Studies of Salt-Cavity Leaching by Freshwater Injection
Authors: Reda Daniel C. , Russo Anthony J. 
Published: December 2007

Summary
Salt-cavity-leaching experiments were conducted in the laboratory in support of the U.S. Strategic Petroleum Reserve (SPR) program. Cavities of an initially cylindrical geometry were created by hollowing out salt cores from one end, leaving the circular wall and bottom as an integral piece. In three experiments, a salt cavity was placed vertically in a pressure vessel and its interior was filled with saturated brine. The vessel was sealed and pressurized to actual SPR-cavern pressure. Fresh water was injected down a tube into the cavity, while brine was removed simultaneously from the cavity through a withdrawal tube.
Both direct (injection-below-withdrawal) and reverse (injection-above-withdrawal) leaching procedures were investigated for essentially the same flow rate conditions and total withdrawal time. A traversable gamma-beam densitometer was positioned between the injection and withdrawal locations in each case and was used as a nonintrusive diagnostic technique to investigate transient phenomena that occurred during the leaching and post-leaching (return-to-equilibrium) periods. Beam attenuation measurements yielded a quantitative measure of the total, time-integrated, salt-wall recession and the instantaneous, path-length-averaged, brine salinity. Final cavity shapes were measured by gamma-beam densitometry and by sectioning/micrometer techniques. Transient and steady-state measurements were compared with numerical predictions. Experimental results and numerical predictions were in good agreement.
Production Potential Changes During Sweep-Out in a Five-Spot System
Authors: Caudle B.H. , Witte M.D. 
Published: December 2007

Abstract
In predicting the performance of a pattern injection operation, the engineer needs to know both the amount of oil to be recovered and the rate at which the recovery will take place. This paper describes fluid flow model studies on the effect of mobility ratio on the rate of oil recovery in a five-spot. The results show the change in fluid conductivity (total flow rate/ pressure drop) as the sweep-out pattern increases for mobility ratios between 0.1 and 10. These data, when combined with a knowledge of reservoir permeabilities and sweepout pattern efficiencies, can be used to predict the cumulative oil production as a function of time for homogeneous five-spot injection systems.

Introduction
The flow potential in a pattern flood element is a function of the mobility ratio and how far the injected flood front has gone. For a waterflood project having a mobility ratio of one, the conductance - which is the flow rate per unit pressure drop (q/ Δp) - will remain the same throughout the life of the flood. If the mobility ratio is favorable &lt; 1), the conductance of the project will drop continuously throughout the operation. If, on the other hand, the mobility ratio is unfavorable, the conductance ratio will increase continuously. Therefore, if the reservoir engineer wishes to predict either the rate at a specified pressure or the pressure at some rate for a secondary recovery project, he must know how the conductance will vary during the flood.
Other investigators have studied this problem using potentiometric models or analytical solution. The method described in this paper uses fluid flow models to study the variation in conductance with mobility ratio and flood front advance. Fluid flow models are more directly analogous to the reservoir and the resulting data can be directly applied to secondary recovery projects. This method was developed to yield reservoir engineering data which can be applied directly from graphs to the reservoir problem.
Analysis of Natural Hydraulic Fracturing of Shales During Sedimentation
Authors: Ozkaya I. 
Published: December 2007

Summary
An approximate mathematical model of the time variation of excess head at the middle of a shale layer during burial is obtained and used in the analysis of natural hydraulic fracturing by excess pore pressure. The fundamental variables that control fracturing are critical stress intensity factor, hydraulic conductivity, specific storage, Poisson's ratio, sedimentation rate, and shale-layer thickness. A simple fracture criterion is derived that shows that for usual values of the above variables, natural hydraulic fracturing is not possible. Fractures form only if the shale is excessively thick and has a low hydraulic conductivity. Depth bracket of fracture generation and closure is shallow. However, porosity may restrict the depth of fracture initiation. An abrupt increase in the sedimentation rate may cause fracture reopening at great depths.
An Approach to the Evaluation of Oil - Production Capital Investment Risks
Authors: Wansbrough R.S. 
Published: December 2007

Abstract
Methods of analyzing the profitability of proposed capital investments have received considerable attention in recent literature. The discounted-cash-flow rate of return, particularly, has been advocated as a means for discriminating among new investment opportunities. Examination of the characteristics of this rate of return led to the conclusion that such rate is seriously misleading at rates of return which are higher than an appropriate interest rate used to determine the present value of future income. Such relatively high rates of return are ordinarily encountered in the oil and gas production industry and are commensurate with the high risk of normal industry ventures.
The difficulty inherent in this use of the discounted-cash-flow rate of return stems from the fact that the relative value of each future year's income from a project is weighted according to the discount-factor characteristic of the rate of return determined from the project. If this rate of return is higher than the realistic present-value interest rate, income from the later years in the life of the project is penalized at a rate which is higher than is needed to compensate for the deferment of this income.
A method of evaluating new capital investments of unequal risk on a commensurable basis is suggested. This method provides a rational framework into which an estimate of the probabilities of success or failure of each facet of a given project may be fitted.

General
The objective of investment evaluation is to provide a measure of the ability of an investment to generate profits. If a quantitative measure of this ability is available, all opportunities for investment can be measured, and an optimum disposition of the funds available for investment can be made.
In the opinion of the writer, the most serious obstacles to be overcome in providing such a measure are encountered, first, in adequately measuring the value today of cash to be received at some future date and, second, in measuring (on a commensurable basis) investments which involve different degrees of risk. These problems are of particular importance in the petroleum production field. This industry provides investment opportunities which yield patterns of cash flow vs. time which vary over a wide range. Individual risks to which investors are exposed cover a continuous spectrum from rank wildcat to interior development well.
Case History of the Development Drilling of the Southwest Sabine Tram and West Devil's Pocket Fields
Authors: Penny R. C. , Eustes A. W. , York D. W. 
Published: December 2007

Summary
Drilling and evaluating the Wilcox formation have long been challenging tasks. Lithology changes have made pore-pressure prediction difficult, while Wilcox water salinity and clays have made formation evaluation by openhole logging techniques virtually impossible. Optimization of very basic parameters—such as casing setting depths, mud properties, hydraulics, and evaluation techniques—have led to substantial reductions in time and, therefore, well cost. This paper outlines several improvements, learned from experience, that contributed to cost and time reductions in drilling and completing these Wilcox wells.
The Use of Higher-Order Differencing Techniques in Reservoir Simulation
Authors: Taggart I. J. , Pinczewski W. V. 
Published: December 2007

SummaryUniformly second- and third-order finite-difference schemes are developed for convection-dominated flows in porous media. The schemes are applied to immiscible and miscible displacements characterized by low levels of physical dispersion. The high-order schemes developed are shown to reduce significantly both dispersion of sharp fronts and sensitivity to grid orientation when compared with solutions obtained with the commonly used one-point upwind differencing schemes. Moreover, for explicit timestepping simulators, such as those based on implicit-pressure, explicit-saturation (IMPES) formulations, the improved performance of the high-order methods is obtained with only a modest increase in computational effort.
Properties and Behavior of Reservoir Oil in the Aneth Field, Utah
Authors: Zaffarano R.F. , Cupps C.Q. , Fry J. 
Published: December 2007

Abstract
Data are presented which show the PVT characteristics of the reservoir oil in the Aneth field, San Juan County, Utah. The data were obtained principally from the analysis of subsurface oil samples taken from seven wells within two years after discovery of the field. The uniformity of the oil across the large producing area is discussed and information on the development history and geology of the area is also given. The Aneth field is the first of several fields to be studied to provide data for a general investigation of the relative characteristics of Pennsylvanian reservoir oils in the Paradox basin.

Introduction
PVT characteristics of reservoir oil in the Aneth field, as reported here, were determined to provide part of the information needed for a comparative study of the characteristics of Pennsylvanian reservoir oils in the Paradox basin. The study proposes to determine if variations in oil characteristics occur in the basin which may reflect the source and migration history of the oil and also provide evidence of the effect of differential entrapment, as proposed by Gussow.
The Paradox basin appeared opportune for this study because of the recent development of several producing fields and an oil potential indicated to be of national significance. Aneth is the largest field discovered thus far and is the first field studied. Other studies are in progress of the McElmo Creek, Ratherford and White Mesa fields to the south and southeast of Aneth and will be covered in future reports.
Results of the Aneth and other field studies are being reported to inform the oil industry of the nature and behavior of reservoir oils in this new productive area and to make these data generally available for use in control of reservoir performance. A more detailed presentation of results of the Aneth field study may be obtained from a Bureau of Mines report.
An Analysis of Reservoir Chemical Treatments
Authors: Dria M. A. , Schechter R. S. , Lake L. W. 
Published: December 2007

Summary
In chemical well treatments, success or failure is often difficult or impossible to anticipate. The near-wellbore pressure drawdown and fines migration contribute to the overall well damage, but the effect of the chemical treatment alone can induce damage by reprecipitation when the spent treatment solution is produced over the treated zone. The identity, amount, and rate of return of this reprecipitation damage are discussed here.
Our procedure considers the chemical interaction of formation minerals and brine with the treatment solution in the presence of an immiscible phase. Although this analysis contains several simplifying assumptions, the results can be applied, with care, to lend insight and direction to practical problems. If relative permeabilities and mineral and injected water compositions are known, the analysis procedure will estimate the success of the treatment and indicate approximate treatment duration.
Two- and Three-Phase Relative Permeabilities of Micellar Fluids
Authors: Delshad Mojdeh , Delshad Mohammad , Pope G. A. , Lake L. W. 
Published: December 2007

SummaryTwo- and three-phase relative permeabilities have been measured for a low-interfacial-tension (IFT) brine/oil/surfactant/alcohol mixture in Berea sandstone cores. The measurements were done at steady-state conditions with a constant nominal capillary number of 10−2. These are the first three-phase micellar relative permeabilities reported to date.Continuous and slug displacements of both partitioning and nonpartitioning radioactive tracers were run for each steady-state experiment. The effluent tracer data from these experiments were analyzed by a capacitance model.Both excess phases flowing with the microemulsion showed significant capacitance effects, but the microemulsion did not. The absence of capacitance indicates that the microemulsion was probably the wetting phase in these low-IFT flows, even more wetting than the excess brine phase. The relative permeability of each phase is a function of only its own saturation during three-phase flow. Polymer dissolved in brine had little effect on the relative permeabilities of brine and microemulsion in two-phase flow.
Chemical Stability Limits of Water-Soluble Polymers Used in Oil Recovery Processes
Authors: Ryles R. G. 
Published: December 2007

SummaryThis work describes long-term thermal stability limits of water-soluble polymers under anaerobic conditions. Polymers investigated included polyacrylamide, xanthan, scleroglucan, cellulose sulfate, and a heteropolysaccharide of unknown structure. The primary mechanism of polyacrylamide degradation was found to be amide group hydrolysis. Interaction between hydrolyzed polyacrylamide and divalent metal ions present in solution caused significant losses in solution viscosity, and phase Separation ultimately occurred in extreme conditions of high degrees of hydrolysis or high concentrations of divalent ions. The rate of hydrolysis was found to depend mostly on temperature. At 50°C [122°F], the rate was quite slow and polyacrylamide solutions were stable for many months, evert in the presence of high concentrations of divalent ions. At 60 to 70°C [140 to 158°F], the rate of hydrolysis was moderate and the rate of viscosity loss depended on the precise temperature and divalent ion concentration. At 90 °C [194°F], hydrolysis was rapid and polyacrylamide solutions were stable to precipitation only when the divalent ion concentration was less than about 200 ppm. When the divalent ion concentration was zero, solution viscosity increased because of a further expansion of the polyelectrolyte coil.The stability of xanthan was determined primarily by temperature and was independent of divalent ions. Although performance varies from xanthan to xanthan, the useful limit was generally found to be &lt; 70°C [&lt; 158°F]. Viscosity retention was also found to be extremely shear-rate dependent. Other naturally occurring polymers exhibited variable performance. In alkaline brines, polyacrylamides were stable up to 90°C [194°F] for long periods of time, whereas xanthan was degraded at &gt; 50°C [&gt; 122°F].
Dissolution and Condensation Kinetics of Silica in Alkaline Solution
Authors: Thornton S. D. , Radke C. J. 
Published: December 2007

SummaryChemical loss through long-term rock reactions is a major impediment for practical application of alkaline waterflooding. This paper addresses the viability of soluble silicates reducing hydroxide consumption by siliceous rock reactions. A convenient differential rate method is used to obtain new experimental kinetic data for the dissolution/condensation rates of quartz at 23 and 70°C [73 and 158°F] and amorphous silica at 23 °C [73 °F] over the pH range from 11 to 12 and in 1 M NaCl. The role of added silicates is studied from zero solution concentration to considerably above the solubility limit.Silica dissolution rates are observed to slow as the solubility limit is reached and become negative (i.e., net precipitation occurs) above the solubility limit. The kinetic rates decrease with increasing solution silicate in a parabolic fashion. Most important, the solubility limit of quartz (amorphous silica) controls the deposition rate of quartz (amorphous silica) over the range of pH values and temperatures investigated. That is, crystalline quartz grows directly on solid quartz particles, rather than deposition of amorphous silica with subsequent alteration to the crystalline habit. This means that relatively small amounts of soluble silicates, approaching the solubility limit of quartz, can protect against hydroxide consumption by quartzitic rock reactions.A molecular dissolution/condensation reaction scheme is proposed, based on equilibrium adsorption of unionized silicic acid. With this reaction path, a mathematical model is developed that agrees quite well with the measured kinetic rate data.
Another Look at Future Demand for Petroleum Engineers: We Can Prevent the Coming Shortage
Authors: Campbell John M. 
Published: December 2007

In the past several years questions have been raised about the future status of the petroleum industry. Some of this has been triggered by rather vague notions of the probable effect Of nuclear and solar energy along with many pessimistic public pronouncements that were designed to influence legislation. Superimposed on this has been the so-called recession, or what might better be called "re-adjustment". The net result has been the development by many individuals of a rather gloomy outlook which is largely unwarranted by the facts. Regardless of how valid this pessimism might be, we must recognize that it could have a long-range deleterious effect on petroleum engineering as a profession.
This is illustrated by the results of a recent poll taken among petroleum engineering schools on enrollment and hiring trends, reported by Robert L. Whiting in the April, 1959, issue of the JOURNAL OF PETROLEUM TECHNOLOGY. The poll was as good as any can be, and Professor Whiting made a conscientious effort to present the results fairly. The article "shook up" many people, and well it should.
The conclusions presented were fine as far as they went, but they did not fully answer the basic questions of, Why the decreasing enrollment?" and "What will be the demand for petroleum engineers?". Because of the rapidly changing technology, I do not believe the latter can be answered by a mere extrapolation of data. Instead, we must try to analyze the factors involved. There is certainly no doubting that a shortage of qualified engineers exists, even though there is a plentiful supply of engineering graduates.
This is the purpose of this article. I have concentrated on the negative factors, not because they are paramount but because they are the ones we usually choose to ignore. In doing this, I am not motivated by pessimism but by the optimistic feeling that careful thought will at least minimize the two problems presented. I hope that those who might be offended by some of the following comments will accept them in the intended spirit.