bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Completions for Waterflood Operations
Authors: Watson Marsh S. , Ward Ted G. , Buckles George L. 
Published: December 2007

Abstract
Reservoir conditions in Permian sand fields of West Texas present problems in waterflood operations unique to that area. These are caused by upper water-bearing formations; a series of sand lenses in the producing zone separated by shale, sandy shale and dolomite stringers and gas sands above the producing oil zones. In some fields bottom-hole water is present in the down dip area in the principal oil-producing oil zones. pointed out that the most satisfactory methods used to overcome these problems could apply to any area where an open hole completion would be possible.
The paper presents a discussion of current completion practices for injection and producing wells. The methods by which properly completed wells help to solve the problems of thief zones, injection rates, maintaining properly treated water, and isolation of the sands to be flooded are presented.
A method for completion of cable tool holes, where the operator may chip core and shoot the producing zone before running casing is discussed in detail.

Introduction
The essence of water flooding is to inject water continuously into the pore spaces of an oil reservoir at a rate that will result in the production of the maximum amount of commercially recoverable oil. Any mechanical, chemical, or biological processes that assist or detract from this endeavor are of vital importance.
In its simplest aspect the problem then resolves itself into injecting the most suitable water available into an oil bearing formation at the right pressure. This involves spacing, pattern, water treating and well completions. Pore spaces refer to any openings through which fluid could pass. The scope of this paper concerns itself with well completions.
Injection well completion is the most critical factor to waterflooding success. This for the simple reason that the injection well is the sole medium for directing the water to its function. In like manner producing wells must be completed so that all waterflood oil can be produced. It is an economic waste to continually attempt to work over a completed injection well, and it is a hazard to try to solve all problems by increasing injection pressures.
Linear Fluid-Barrier Detection by Well Pressure Measurements (includes associated discussion and reply)
Authors: Davis E. Grady , Hawkins M.F. 
Published: December 2007

Abstract
In recent years considerable attention has been given to the use of unsteady-state pressure measurements in wells as a means of investigating thenature of petroleum reservoirs both near to and away from wells. These methodsare based on sound theory; for, theoretically at least, pressure build-up anddrawdown curves reflect the nature of the reservoirs from which the data aretaken. One of the more common and prominent features of reservoirs which can bedetected in some instances by pressure measurements is the linearfluid-barrier, e.g., a linear sealing fault. There has been some misuse of thistechnique in engineering practice, and it was therefore thought worthwhile todiscuss the criteria for valid pressure tests which indicate the presence andlocation of linear fluid-barriers.

Introduction
The present discussion will be concerned with the detection of linear fluid-barriers in ideal reservoirs, thus establishing optimum conditions fortheir detection in real reservoirs. The ideal reservoir considered is ahomogeneous, isotropic, porous bed of uniform thickness saturated with aslightly compressible fluid. Bounded on one side by a reasonably extensivelinear fluid barrier, the reservoir is assumed to be of such extent thatdiscontinuities other than the linear barrier have no appreciable affect on themeasured well pressures within the duration of the test. it is further assumedthat there are no appreciable pressure transients at the test well as caused byflow rate changes in other wells tapping the reservoir. A skin effect, ifpresent in the test well, is assumed to be invariant with flow rate, pressureand time.

Discussion
The theory of linear barrier detection using well pressure measurements has been treated by Horner, Jones, Dolan, Einarsen and Hill and Davis. For thepressure drawdown case in an ideal reservoir with constant rate of fluid entryinto the wellbore, this theory predicts pressure decline curves such as shownin Fig. 1. Here the dimensionless pressure drop p, assuming no skin effect, isplotted vs the natural logarithm of dimensionless time t for several values ofdimensionless distance d between the test well and the linear fluid-pressurebarrier. These dimensionless groups are defined in the Nomenclature. The plotsof Fig. 1 show a curved section which covers approximately a 25-fold timerange, i.e., the ratio of the time at the end of the curved section to that atthe beginning. Stated otherwise, the curved section covers about three naturallog cycles on the time scale or about 1.4 common log cycles, beginning at 0.35and ending at 9.
JPT
P. 1077^
Decline Curve Analysis Using Type Curves
Authors: Fetkovich M.J. 
Published: December 2007

This paper demonstrates that decline curve analysis not only has a solid fundamental base but also provides a tool with more diagnostic power than has been suspected previously. The type curve approach provides unique solutions on which engineers can agree or shows when a unique solution is not possible with a type curve only.

Introduction
Rate-time decline curve extrapolation is one of the oldest and most often used tools of the petroleum engineer. The various methods used always have been regarded as strictly empirical and generally not scientific. Results obtained for a well or lease are subject to a wide range of alternate interpretations, mostly as a function of the experience and objectives of the evaluator. Recent efforts in the area of decline curve analysis have been directed toward a purely computerieed statistical approach, its basic objective being to arrive at a unique "unbiased" interpretation. As pointed out in a comprehensive review of the literature by Ramsay,1 "In the period from 1964 to date (1968), several additional papers were published which contribute to the understanding of decline curves but add little new technology."
A new direction for decline curve analysis was given by Slider2 with his development of an overlay method to analyze rate-time data. Because his method was rapid and easily applied, it was used extensively by Ramsay in his evaluation of some 200 wells to determine the distribution of the decline curve exponent b. Gentry's3 Fig. 1 displaying the Arps4 exponential, hypbolic, and harmonic solutions all on one curve also could be used as an overlay to match all of a well's decline data. However, he did not illustrate this in his example application of the curve.
The overlay method of Slider is similar in principle to the log-log type curve matching procedure presently being employed to analyze constant-rate pressure buildup and drawdown data.5–9 The exponential decline, often used in decline curve analysis, readily can be shown to be a long-time solution of the constant-pressure.10–13 It followed then that a log-log type curve matching procedure could be developed to analyze decline curve data.
A Result of SP Log Interpretation
Authors: De Andrade Paulo Varjao 
Published: December 2007

Introduction
Since 1949, attention has been directed in this laboratory to the interpretation of SP logs. It has been the aim of the work to get connate water resistivities to use in quantitative interpretation of the resistivity curves. Wyllie's theory was taken as the fundamental working hypothesis as it would provide a correct theoretical background to support the results. In order to have an idea of the precision of the method, it was decided to make a series of interpretations in wells which produced only water and to compare the calculated results with resistivities obtained from chemical analysis of water samples.
Several water analyses and electrical logs were available from wells in the Sergi sands in several fields of the Bahian Reconcavo. The Sergi sands are the highest member of the Brotas formation, presumably of Lower Cretaceous age, and were deposited all over the basin. They constitute a homogeneous body and can be correlated over distances of tens of miles with only minor changes in lithology. The upper part of the Sergi known as "C zone," is a medium to fine grained sandstone, medium consolidated to friable, with finely disseminated clay, 15 to 30 ft thick, good porosity and permeability. Fig. 1 shows a log of part of the upper Sergi with the shale section overlying it.
Water samples came from formation tests, being collected in the lower part of the column. In case of mud contamination, they were discarded. Analysis comprised routine determinations of chloride, sulfate, bicarbonate and carbonate, calcium and magnesium. Sodium was calculated by difference. Resistivities of water and mud were obtained using either the Schlumberger salinity-resistivity chart or a combination of the said chart with Dunlap's method (the low sulfate content of the brines made this method very simple and accurate). Bottom-hole temperatures were available either from log headings or from direct measurements made with a maximum thermometer. In order to avoid the influence of resistivity on the amplitude of the SP "peak," only water wells were used in this study. Corrections for bed thickness were unnecessary in the wells studied. All wells were rotary drilled.
Comparison of Liquid-Holdup and Friction-Factor Correlations for Gas-Liquid Flow
Authors: Vohra I.R. , Hernandez F. , Marcano N. , Brill J.P. 
Published: December 2007

Predicting expected pressure drop during two-phase, gas-liquid flow in pipes is highly significant to the petroleum industry. The relative accuracies of four published correlations are determined in terms of the constitutent liquid holdup and friction-factor prediction schemes. Liquid-holdup values predicted from two other correlations and from no-slip considerations are included in the comparisons.

Introduction
The prediction of pressure drop during two-phase, gas-liquid flow in pipes is of great significance to the petroleum industry. Extensive theoretical and experimental research has been conducted on horizontal, vertical, and inclined two-phase flow, but few of the resulting correlations are valid over broad ranges of flow rates, fluid properties, and pipe sizes.
Most published pressure-loss prediction correlations require prediction of two parameters: the liquid holdup and a two phase friction factor. The reliability of any flowing pressure-drop correlation is, therefore, dependent on the relative accuracies of the constituent liquid-holdup and friction-factor predictions. The accuracy of these correlating schemes may be evaluated only for test cases for which simultaneous liquid-holdup and pressure-drop data are available.
Beggs'2 and Eaton's5 experimental data include accurately measured pressure-loss and liquid-holdup values. These data are restricted to 1-, 1.5-, 2.067-, and 4.02-in.-ID pipes. Additional data are available in the literature or from private sources, but the accuracy of measurement is unknown or questionable, so they were not considered here. Fifty-eight tests from Beggs' study and 238 tests from Eaton's study were combined in a data bank for this investigation.
Using this data bank, two separate comparison studies were pursued. The first study compared measured liquid holdup with that predicted from six commonly used correlations and a no-slip calculation for two-phase horizontal flow in pipes. The second study predicted two-phase friction factors from correlative functions of four authors and compared these factors with the friction factors calculated from their respective mechanical energy-balance equations. Some differences exist in the definition of terms used in the energy-balance equations. The four friction-factor correlations considered were developed by Beggs and Brill,3 Dukler,4 Eaton et al.,6 and Guzhov et al.7 Their liquid-holdup correlations were also compared with the correlations of Hughmark9 and Lockhart and Martinelli.10 To establish a lower bound on predicted liquid-holdup values, a no-slip holdup was also calculated.
The percent differences between measured and predicted liquid holdup and between measured and predicted friction factors were computed for each test in the data bank. The mean and standard deviation of these differences were determined to evaluate the reliability of selected correlations for predicting two phase pressure drops in horizontal pipes.
Canadian Oil at the Eighth Milestone (1947-1955)
Authors: Twaits W.O. 
Published: December 2007

Introduction
Recently Canada celebrated the eighth anniversary of a discovery which to Canadian oil men ranks with that made by Columbus. The finding of crude oil at Leduc, Alta., eight years ago on Feb. 13 had some other similarities with the experiences of Christopher Columbus. As with the discovery of America, the significance of finding oil in Canada was not immediately recognized. Today, at the comparatively advanced age of eight, and with an unprecedented rate of growth, there are few who are not aware of the size or importance of the Canadian development. It seems appropriate at this time to examine some of the factors influencing the economic behavior of thin new supply source-not in detail, but rather in terms of future growth.

Canadian Oil Today
The stature of present Canadian oil can be measured with considerable ease and a minimum of statistics. Eight years of progress has brought the industry to the point where it supplies the needs of virtually all of Canada west of Toronto on Lake Ontario. This is in marked contrast with the 1947 situation in which an area near the Arctic Circle and another around Calgary were the only sections supplied with local crude. This widening of the area supplied reflects the growth of total reserves from 72 million bbl to some 2 3/4 billion and of daily average production from a declining position at 20,000 to a position with excess maximum efficient recovery at 260,000 bbl. Potential production has risen to around 420,000 bbl. There are a great many other measurements of progress which could be enumerated, but the one which is perhaps most striking from a Canadian viewpoint is that currant production with a 1954 gross value of $245 million effects a foreign exchange saving of considerably more than that amount. This saving of foreign currency is in U. S. dollars, and it is augmented by the inflow of additional cash for investment in oil development by companies and individuals.
Effect of Clays, Limestone, and Gypsum on Soluble Oil Flooding
Authors: Bernard George G. 
Published: December 2007

Introduction
In our investigation of the soluble oil flooding process we observed that the process is less efficient in some porous rocks than in others. There are two basic porous rocks than in others. There are two basic factors that affect the oil displacing action of the soluble oil process:composition of interstitial fluids, andcomposition of reservoir rock.
The literature has much data showing that composition of interstitial water, particularly the presence of divalent ions, greatly affects the efficiency of a soluble oil flood. This study is not concerned with that aspect of the problem. problem. This study is concerned with the effect of rock minerals on soluble oil flooding. We evaluated the possibility that certain rock minerals can drastically possibility that certain rock minerals can drastically affect the efficiency of the soluble oil flood. One previous study has shown some of the possibilities in previous study has shown some of the possibilities in this regard.

Experimental Procedure
The flooding experiments were conducted in unconsolidated sandpacks (No. 16 sand) containing from 0 to 2 percent of either gypsum, montmorillonite clay, or calcium carbonate. The sand was packed in 3-ft long, 2-in. diameter plastic tubes to a porosity of about 40 percent and a permeability of about 4 darcies. In preparation for the flooding experiments, the systems were first saturated with brine or fresh water, permeability was determined, and then crude oil was permeability was determined, and then crude oil was injected to irreducible water. Next, the system was waterflooded to residual oil saturation, and, finally, a soluble oil flood was made. Oil saturations after waterflooding ranged from 28 to 32 percent PV. In each soluble oil flood, 0.03 PV of soluble oil was injected and followed by 1 PV of polyacrylamide solution that had a viscosity of about 32 cp.

Effect of Calcium Sulfate On the Soluble Oil Process
Gypsum (CASO4 2H2O) is a slightly water-soluble mineral present in some oil reservoirs. Its maximum solubility is about 2,000 ppm in fresh water, and about 7,000 ppm in NaCl brine. We ran several flood tests to determine whether this slightly soluble mineral would affect the soluble oil flooding process. The data in Fig. 1 show that 0.5 percent or more gypsum in the sand reduces oil recovery by the soluble oil-polymer flood. With no CASO4 present, oil recovery was 96 percent, while with 2 percent CASO4 in the sand, oil recovery was 55 percent. The most probable mechanism by which gypsum reduces the oil-displacing effectiveness of the soluble oil-polymer process is related to the dissolution of solid gypsum by flooding solutions and the consequent reaction of dissolved Ca++ with flooding chemicals. Dissolved Ca++ can affect the soluble oil flooding process in two ways:it can precipitate some process in two ways:it can precipitate some of the petroleum sulfonates, andit can reduce the viscosity of polyacrylamide solution.
JPT
P. 179
Engineers as Managers
Authors: Donnell J.C. 
Published: December 2007

New Emphasis on Management Training
Hardly a week passes in which an invitation does not come from some university or management consultant firm to send some of our prospective management personnel for exposure to the newest concepts in the arts of administration. Seldom do we pick up a periodical, even of the popular variety, that does not contain an article about some company's program for management development. Your bookcases, like mine, surely have received more than their share of books on how to become a more effective administrator, a better manager, or an executive that gets the job done.
This unprecedented emphasis on managerial development has been prevalent since the close of World War II, and has long since passed the fad stage. Why is this? American industry has always managed to develop its leaders in the past; what is it that's different today?
Probably it stems from the increasing size and complexity of industry. Great technological developments, for which the engineers are partly responsible, have contributed to this complexity and growth. We have also inherited some factors from the past, the depression of the 30's and war in the 40's with their respective unemployment and shortage of workers played their part in disrupting the transition of American industry to its present status. The fact that in the past 25 years government has come to play an ever increasing role in American industry, exercising much greater regulation and control, has also had its effect. Now with the return to a highly competitive era, we are all concerned with the problem of getting more people to manage capably and to perpetuate our enterprises.

No Stereotype for Successful Managers
In all the discussion that bas developed over the past few years, it is obvious that many people think a manager or an executive has certain specific traits easily recognized which can be developed by education, training, and experience. This is not true, for there is no stereotype of successful managers. Managers vary just like other people do. Certainly there is no reason why all the characteristics of managers at different levels should be similar, and why shouldn't they vary from company to company and industry to industry and from time to time? American industry, and the oil industry in particular, must depend on all its professional and highly skilled employees as a reservoir of managers today and increasingly so in the future.
On this basis, undoubtedly the engineering profession will provide its share of these managers. In searching for managers, our criterion should not be any arbitrary traits or qualifications, but rather "what can a man accomplish."
The Application of Electrical Transients to Well Logging
Authors: Karplus Walter J. , Smith Otto J.M. 
Published: December 2007

Abstract
The transient response of earth formations may be determined by means of four electrodes mounted colinearly on a sonde. Exponentially decaying current pulses are applied to one pair of electrodes and the resulting voltage transient at the other pair is recorded. It is shown by theoretical analysis and verified by laboratory experiments that this arrangement readily yields the direct resistivity of the formation and provides valuable additional information as well.

Introduction
Although electrical transients have been employed with moderate success in geophysical prospecting, their application to well logging has received virtually no attention in technical literature. In the conventional direct resistivity logging methods only the zero frequency impedance of the formation under study is measured, and no information is obtained regarding its reactive characteristics. Since the use of certain transients appears to offer some advantages in this respect, experiments were performed on a laboratory scale to investigate this possibility. This investigation was limited to a study of a four-electrode array where both the receiving and transmitting electrode pairs are mounted on a logging sonde, and decaying exponential pulses are applied to the transmitting electrodes.