bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Solid State Pipeline Gauger
Authors: Hinchliffe R.A. 
Published: March 2010

Abstract
Automatic receiving and delivery facilities have been installed by Federated Pipe Lines Ltd. at all gathering points where power is available. Thisequipment reduces the frequency of visits by operating personnel and, barringcomponent failure, provides reliable control of pipeline facilities.
The "Fieldgate" operational technique now being employed by producingcompanies requires that the pipeline provide the most efficient handlingpossible. In the past, crude from a field was received at perhaps a dozen ormore locations; now the entire production may be received at one "Fieldgate"battery. This resulting high throughput from a single location must not be heldup, and down time of pipeline facilities has to be kept to a minimum.
Remote control of pipeline facilities at these locations of high throughputpermits continuous monitoring, and equipment malfunction is indicated at theoperating control center. Remedial action can be initiated much quicker by thismonitoring than by the visual inspection of a passing operator.
The installation of remote control equipment must be considered carefully, bearing in mind that the automatic equipment at the battery is accomplishingthe over-all function of accepting, metering and shipping crude.
The essential requirements of the remote control system are to provide anindication of equipment status and equipment on-off control. Digital readout ofthe metering equipment is required to determine periodic throughput. Alarmindications are to be registered whenever a condition arises which affects theoperation of the pipeline facilities. Reset control is a requirement to rectifypower failure conditions once power has been restored.

Introduction
The gathering system installed by Federated Pipe Lines Ltd. serves variouscrude oil producers in an area some 60 miles long and, at one point, 30 mileswide. Until ten years ago, this region of Alberta was an isolated wildernessand the only surface access was over a few forestry trails. The currentproducing fields of Swan Hills, Judy Creek, Carson Creek, Virginia Hills, Morse River, Inverness, Deer Mountain and House Mountain lie within this area.
Completion of Water Source Wells - Dollard and Instow Fields
Authors: Todd M.B. 
Published: March 2010

Abstract
Waterflooding of oil fields in southwestern Saskatchewan has created ademand for huge quantities of makeup water. Marathon Oil Company, in itsoperation in the Dollard, Instow, and Rapdan fields in this part of the Province, has experimented with several aquifers and several types of wellcompletions. The development of a gravel packing technique in the extremelyfine grained, thick Belly River sands has established a reliable and economicalsource of water.
The paper discusses Marathon's experience with various aquifers and types ofwell completions. It deals with the theoretical aspects of gravel packingand discusses in detail the particular type of gravel packing technique whichproved successful in withholding the extremely fine sands of the thick Belly River formation.

Introduction
Pressure maintenance operations in Marathon Oil Company's southeastern Saskatchewan operations (Figure 1) commenced with the construction ofwaterflood facilities in the Dollard Field in 1955. Early studies indicatedthat approximately 50 million barrels of water would be required to completethis project. Subsequent development of the Instow, Rapdan and Leon Lakewaterfloods established the need for another 70 million barrels of water.
Throughout the past ten years, Marathon, as operator of the Dollard, Instowand Rapdan units in the Dollard-Instow area, has experimented with severalaquifers and with several types of water source well completions. The cost of supplying water for the various waterfloods has continually decreased astechniques improved, until at the present time an adequate, reliable and cheapsource of water has been ensured for the remaining life of the projects.
Wells have been completed in the shallow Ravenscrag sands and in the Upper Belly River, Lower Belly River, Viking and Blairmore formations, covering adepth range of from 250 to 4,400 ft. The completion technique which proved themost successful involved gravel packing between a slotted liner and openhole.
Film-Forming Compounds from Crude Oils, Interfacial Films and Paraffin Deposition
Authors: Hasiba H.H. , Jessen F.W. 
Published: March 2010

ABSTRACT
A method was developed to collect interface-active film material from theoil/water interface. The film-forming material was subjected to infrared andmass spectrometric analysis. The combined analysis data indicate that the polarorganic material consists to a large extent of aliphatic esters of aromaticacids. The existence of smaller amounts of ketones, aldehydes, naphthalene andanthrazene derivatives, carboxylic acids and organic nitro compounds was alsoindicated. Long chain aliphatic material was found incorporated within themultilayered film structures. The molecular weight range of the inter faciallyadsorbed organic molecules lies between 200 and 420, with the accent on thehigher mass values. The surface exposed groups of the multilayer films arethought to consist of a closely packed array of CH, groups. A hypothesisconcerning an interrelationship between the formation of interfacial films andparaffin deposition is given.

INTRODUCTION
THE EXISTENCE OF FILMFORMING COMPOUNDS in crude oils and the possibleimplication to some problems of concern to the petroleum industry has beenrecognized for a number of years. It has been found that the surface exposedgroups of polar-non-polar molecules, adsorbed on a solid or a liquid surface, will completely determine the subsequent wettability characteristics of thelatter (1). The relevancy of this fact to problems such as relativepermeability measurements, secondary recovery methods and paraffin depositionhas been mentioned by several researchers (2, 3, 4). Attempts have been made inthe past to isolate film forming compounds from crude oils and to define theirchemical nature. Metalporphyrins complexes (5, 6), free naphthenic acids, acidanions and their salts (7), and highly oxygenated low molecular weightfractions of the resin and asphalt fractions of crude oils (2) have been listedas interface-active compounds. A severe crystal growth modification in waxslovent mixtures, induced by asphaltic material, has been reported by Birdwell(8), Chichakli (9) and others (10). Patton (11) found, during paraffindeposition studies, that the presence of a high boiling point crude oilfraction, both in the wax solvent system and as a pre-adsorbed film, inhibitedthe formation of paraffin deposits. A film balance study of the physicalcharacteristics of films formed by benzene solutions of crude oils, includingtheir distillation and chromatographic fractions at the oil/water interface, was described earlier (12, 13). The indication was that the 700°F+ distillationresidual and, in turn, their asphaltic sub fractions are the major contributorsof interface-active material to the films formed by the original crude oils.Hence, without trying to adopt any specific model for the structure of acolloidal " asphaltene particle," it seemed that either the asphaltic fractionscontained free polar molecules a priori or the benzene as a solvent played arole in " activating" polar molecules through destruction of a number ofasphaltene particles.
Optimum Fracturing Treatment Design Helps Reach Maximum Profit
Authors: Williams J.R. , Tinsley J.M. , Malone W.T. 
Published: March 2010

ABSTRACT
A method to help determine the proper fracturing treatment for optimum profitability has been developed to evaluate the many variables encountered. This method utilized a digital computer for rapid analysis. Many plans for fracturing treatments have followed various logical theories and procedures. Such plans reflect, in general, the results of research into new materials and techniques involved. These design methods have not considered a true optimum evaluation. They have shown, however, that formation properties, treatment fluid characteristics, proppants, injection rates, treatment volumes and other factors are important to the success of a proposed treatment. The relative emphasis on each of the above variables depends, to a considerable extent, onthe design method in question. This method provides a means to inter-relate these variables, allowing a more complete analysis of how they may affect treatment results. The question of "What is the best combination of all these variables?" is very important and the answer is the goal of this method. The optimum treatment selected is based on maximum profitability, where profit isthe gain in value of the producing well due to a specific fracturing treatment. Profit is determined from the value of the increased production rate due to fracturing less the cost of obtaining that rate of production. This paper willdiscuss the design procedures employed, show computer input and output data and give the results of some treatments.

INTRODUCTION
HYDRAULIC FORMATION FRACTURING for production improvement has been a routine stimulation treatment for many years. The size of the treatments and thequantity of proppant used have changed markedly since the beginning. In theearly 1950's, treatments of 800 or 1,600 gallons with 10 to 20 sacks of 20–40s and were common place. Today, treatments of 800 to 1000 barrels are not unusual and quantities of sand or other proppants have increased to hundreds or thousands of sacks. This has, of course, greatly increased the cost of fracture treatments, but it has also increased their success. The injection rates also have increased as larger pumping equipment has become available and aschemicals, such as friction reducers, have allowed for better utilization of horse power. Since the advent of fracturing as a stimulation technique, a greatmany different types of fracturing fluids have become available. These fluidshave properties, such as viscosity and friction reduction, that may be adjusted to suit particular needs.
Brittle Failure and Low-Temperature Welding
Authors: Winterton K. 
Published: March 2010

ABSTRACT
The causes of brittle failure are explained, and the aspects of crackpropagation and crack initiation treated separately. The selection of steelsfor service at low temperatures is considered, and some instances are given ofspecial code requirements. General advice is presented for the minimization ofthe problems of brittle failure. Welding in cold weather affects personnel, materials and equipment. Metallurgical factors are also involved, as revealedby experimentation and practical experience. Code requirements are explained.Practical advice is given for overcoming the problems that may be en-countered.

INTRODUCTION
THERE ARE ALL KINDS OF TROUBLES that can develop in equipment innorthern climates. These may result from improper selection of materials, unsuitable over-all design, inappropriate design or choice of particularcomponents, manufacturing defects with special significance for operation atlow temperatures, etc.
It is not surprising that suitable equipment and materials could in mosteases be provided, but that this would entail unwelcome increases in costs.Moreover, in
Canada at least, the problems have been attacked piecemeal, and there is nosystematic approach available to those who are not immediately deterred by theprospect of paying more for what they need. At the University of Alaska, theengineering faculty places emphasis on special training of students in theunique aspects of work in the North in the U.S.S.R.., a more unified approachto northern problems has been developing, and they considered the establishmentof a Research Institute for Technical Problems of the North
The present paper is limited to the consideration of two aspects of theproblem; firstly, brittle fracture, which is certainly, the most importantsingle material problem, and secondly, the effect of low temperatures inwelding.
Recovery Sensitivities of High-Relief Reservoirs
Authors: Beveridge S.B. , Spivak A. , Bertrand J.P. 
Published: March 2010

ABSTRACT
Of the mechanisms for oil recovery, the greatest challenge to reservoir engineering is a reliable determination of the expected performance of areservoir subject to gravity control. With the increasing number of high relief reservoirs recently developed in the Rainbow-Zama area, in addition to theolder but important D-3 reef reservoirs, it is increasingly important to the Alberta oil industry to gain a better understanding of the factors affecting the efficiency of gravity drainage. This paper presents the results of asensitivity study to determine the effects of rate, permeability and relative permeability on the recovery performance for such high-relief reservoirs. Theuse of a mathematical reservoir simulator has permitted the quantitative assessment of each of these factors and the study has shown that relative permeability is by far the most important. In fact, under gravity-controlledconditions, conventional relative permeability data obtained by the Welge method do not cover the low oil saturation range needed for accurate recovery predictions. Relative permeability curves may be extrapolated in this range, but a better method would be a steady-state determination of relative permeability at the low oil saturations.

INTRODUCTION
OIL PRODUCTION FROM HIGH-RELIEF RESERVOIRS forms an appreciable part of thetotal oil production in Alberta. The recovery mechanism in these reservoirs isprimarily one of gravity drainage. Gravity forces in these reservoirs tend tosegregate the fluids according to their densities, causing the oil to move vertically ahead of the displacing gas or water. Although the general influence of rate, permeability and relative permeability on gravity is intuitively obvious, there is little quantitative data available to show the magnitude andrelative effects of these factors. This paper presents a study of the sensitivity of oil recovery to these factors. The study was carried out using aone-dimensional, three-phase reservoir simulation mathematical model of a typical Rainbow reservoir. Although it used only the description of one reef, the conclusions of this study are generally applicable to most reef reservoirs which are being produced by gravity drainage; for example, the Rainbow-Zamareservoirs or D-3 reefs in Alberta. The problem was simplified by assumingone-dimensional (vertical) flow; however, the work done by McCulloch et al.shows that the results from one-dimensional simulation of high-relief reservoirs are in good agreement with three-dimensional simulation results.
Potential Energy Resources of Alberta and Their Strategic Position Within the Circular Mosaic
Authors: Menneer Jack 
Published: March 2010

ABSTRACT
Landlocked Alberta, which is flanked on its western side by the majestic Rockies, bounded to the south by the international border and is the gateway tothe north, has vast hydrocarbon resources. In this regard, it is the presentcentroid of Canada's oil and gas industry.
Despite a continuing upward mobility, it is observed that the province issurrounded – even up into the Arctic and as far south as Texas and Louisiana -by potential or new sources of oil supply.
Subjectively speaking, Alberta is described as a high- value energy areawhich is geographically encircled. It is, indeed, within the circular mosaic ofa highly competitive energy environment. Objectively, the province will becomean energy supplier of strategic significance by assisting to meet anever-increasing U.S. oil deficiency situation. Three particular aspects of Alberta are considered:Pattern of the liquids supply, namely, thecircular mosaic, in 1968, and the achievement of fluidity through optimizationof supply between the U.S. and Canada before the 1980's.Ultimate marketable reserves andproduction rates of the hydrocarbons by means of the logistic-curveapproach.Distribution of the alreadydiscovered oil reserves according to reservoir classification.

INTRODUCTION
EVEN IN THE JET AGE, or the atomic era, if so preferred, or the globalvillage psychedelic concept of Marshall McLuhan, the enormous expanse of Canadais bewildering. Our national emblem emblazons the subscript "A mari usque admare," and so it is, from sea to sea from Halifax on the Atlantic to Vancouveron the Pacific land distance of 3,000 longitudinal miles; and from the Canada-U.S.A. border to the most northerly of the Arctic Islands on the105-degree meridian -2,200 miles of latitude
Alberta holds a predominating position in the known accumulation ofhydrocarbons in Canada at the present time. Transportation of the products tomarkets across Canada and into the U.S.A. becomes an important economic factor.This is particularly so for the liquids, as Alberta has no seaboard which mightpermit a lower cost of movement. Net imports into Eastern Canada amount to200,000 bbls of liquids per day, which is equivalent to 26 per cent of Alberta's daily crude oil and pentane production. Alberta could easily producethis net imports volume without any difficulty whatsoever. The absoluteprovincial oil deliverability is now around 2 million barrels per day.Allowing, say, a 70 per cent efficiency factor, the daily production could be1.4 million barrels, or a doubling of the prevailing rate. The projection ofthe logistic curve shows that oil production lags the discovery cycle by 14years; similarly, for natural gas the lag is 16 years.
The Long-Term Cost of Alberta Conventional Crude Oil
Authors: Watkins G.C. , Watkins Karen Sharp 
Published: March 2010

Abstract
This paper, through the development of a cost model, estimates the long-run supply price of oil from existing reserves in Alberta. Proration, payments to mineral owners and taxes are considered, and wellhead costs are computed under various assumed conditions.

INTRODUCTION
THIS ARTICLE concerns the estimation of the long-term cost of oil recovered from existing reservoirs in Alberta. The long-term nature of the cost defined must be emphasized. The cost does not reflect the incremental economics of an additional ban-el produced from discovered and developed oil reservoirs. This analysis considers the long term when all expenditures are flexible. Hence, long-term cost embraces expenditures incurred in all sectors of the producing segment of the petroleum industry: exploration, development and production. The method of analysis employed in this article is general in the sense that it may be applied to any area for which data exist. However, the specific characteristics of the model developed are conditioned and limited by the nature of the data available in Alberta. Section II below discusses some definitional problems. Section III relates to the cost ‘model’. The results are tabulated and reviewed in Section IV. Section V concludes the analysis. Throughout the article, the past existence of proration is recognized and its future continuation assumed.

II – DEFINITIONAL PROBLEMS
The intention of exploration is the discovery of hydrocarbon deposits. Although geological and geophysical data may indicate a higher probability of occurrence for one hydrocarbon as compared to another in a given area – for instance, gas as compared to oil it is impossible to so direct exploration that its result will be confined to the discovery of a previously specified hydrocarbon. Hence, most exploration costs are joint in relation to a necessarily mixed final output – gas, oil and other products – and, in strict economic terms a specific cost of oil does not exist(1).
Thus, the attribution of cost to oil in the analysis below is artificial in the sense that it does not supply a criterion for individual investment decisions. Such decisions would continue to observe the joint-cost character of the problem.
Notwithstanding the nature of the cost of oil in an area where oil is a joint product, it is frequently necessary in the formulation of policy, to assess the cost of oil as an individual product; for instance, to compare its cost to costs in other supply areas where oil is Virtually the sole product, as in some Middle Eastern countries. It is dear that for an area such as Alberta, where significant amounts of gas and associated products have been discovered such an assessment must recognize and incorporate an adjustment to reflect this feature. To do other-wise would ignore the fact that the pattern and intensity of exploration in Alberta undoubtedly would have been different in the absence of significant discoveries of gas.
There are basically two possible methods of adjustment.
Prop-Packed Fractures- A Reality On Which Productivity Increase Can Be Predicted
Authors: Alderman E.N. , Wendorff C.L. 
Published: March 2010

Abstract
The placement of a propping agent in hydraulically created fractures is a more adequate basis for predicting the folds of increase after a job. This is based on the premise that all unpropped areas of the created fracture eventually heal. Thus, the penetration of the prop pack into the reservoir and the amount of fill-up in the fracture determine the stimulation results.

INTRODUCTION
PRESENT METHODS of predicting the results of stimulation treatments are based on the productivity index ratios developed by McGuire and Sikora(1) (Figure 1). The predicted folds of increase are in relation to the conductivity ratio before and after fracturing and the penetration of the producing formation. This assumes that the propping agent supports the entire area of the hydraulically created facture(2).
Although the industry has recognized for some time that the propping agent neither penetrates the full length of the fracture nor gives complete fill-up, the complexities of describing the placement of the prop have prevented using this feature in the treatment design.
Limited use has been made of the settling-rate method for describing the extent which the prop pack penetrates the vertical fracture. The quotient of the vertical extent of the fracture and the settling rate gives the maximum time the prop is suspended by the fluid. The product of this time and the velocity of the fluid in the fracture gives the maximum distance the prop penetrates the fracture. Stokes Law can be used to predict the settling rate in Newtonian fluids, but is not applicable for non-Newtonian or power-law fluids.
Kerns(3) et al. and Babcock(4) et al. have made studies on the transport of prop in vertical fractures, introducing the term ?equilibrium velocity' to the industry. Equilibrium velocity is the minimum linear velocity required to keep the prop moving through the fracture. A comparison of the settling-rate method and the equilibrium-velocity method is illustrated in Figure Z.
However, as is known, little has been done toward using these methods for predicting the placement of prop in the fracture. One reason for this is that most of the fluids employed in these studies have been Newtonian, and the majority of the fracturing fluids are non-Newtonian.
For this reason, a study was undertaken to expand the available information on commonly used fracturing fluids, such as gelled water. Laboratory tests were run in a plexiglas model of fixed, but variable, fracture width. The simulated vertical linear fracture was 2 ft in height by 6 ft long. Fracture widths were variable from 0.1 to 0.5 inch.
Prop-laden fluids passing through this fracture exhibited the same general phenomena. While pumping down the pipe, the prop is fairly evenly dispersed in the fracturing fluid. However, as the fluid 'turns the corner, going into the fracture, centrifugal force and gravity concentrate the prop in the fluid moving through the lower part of the fracture. The bulk of the prop moves along the bottom of the fracture, as a fluidized bed.