bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Dual Solvent Slug Technique for Improving the Injectivity of Waterfloods
Authors: Relf J.A. , Sears J.R. 
Published: March 2010

Abstract
In recent years, secondary recovery of oil by water flooding has becomeincreasingly popular in Western Canada. In most cases, water injection wellsare completed by converting wells that were formerly used for oil production;common practice is to place these wells on injection after some form oftreatment to remove wax and other deposits from the well bore.
It has been known for some time that the presence of residual oil impedesthe flow of water, and this is particularly significant in the area immediately surrounding the well bore. It has also been demonstrated in the past that theuse of a miscible displacing fluid leaves lower residual oil saturations thatdoes the use of an immiscible displacing medium such as water. There have been several methods proposed to achieve a reduction in residual oil saturation around water injection wells. These have mainly dealt with the use of surfactants or the injection of low-viscosity hydrocarbon solvents.
Recently, several articles have appeared in the literature concerning increased recovery of crude oil from formations through the use of large solvent slugs that are mutually miscible with oil and Water. These articles, based on laboratory studies on a variety of solvents, indicate that this method of recovery is technically feasible but does not appear to be economical.
This paper covers an adaptation of the miscible solvent slug technique to increasing injectivity of conventional waterfloods by a reduction of the residual oil saturation around the well bore. Reduction is accomplished by injecting an oil-soluble solvent slug followed by a mutually miscible water-soluble solvent slug. Two alternate types of treatment are discussed, one for newly converted injection wells and the other for wells that have been performing poorly on water injection. The theory behind these treatments is discussed as well as actual case histories of successful field trials on several Alberta wells.

Introduction
Several articles have been written recently on the subject of secondary recovery by waterflooding in Western Canada. It has been stated that known recoverable oil reserves will increase by approximately 50 per cent when all secondary recovery projects now in operation or planned are completed.
Thermal Cracking of Athabasca Oil-Sands Oil Part 3. - A Study of Asphaltic Components of Alberta Petroleum Oils and Asphalts
Authors: Pasternack D.S. 
Published: March 2010

Abstract
Many naturally occurring petroleum oils in Alberta are shown to produce carbon residues that exhibit a high degree of cohesiveness, a feature which should permit the production from these oils of asphalt binders exhibiting superior cohesive properties. Also shown is the presence of varying percentages of diluent-insolubles in commercial asphalts produced from several of the oils, and the formation of honeycomb-like structures (representing volume expansionsof up to 300 times) from some of these insolubles when determining the Ramsbottom carbon residue. In conjunction with the data available from the usual asphalt tests, these solubility and carbon residue tests may prove useful in permitting a better assessment of an asphalt with respect to properties and performance characteristics.

Introduction
A study of the fluidized coker distillate from Athabasca oil-sands oil showed that the high-boiling ends of the distillate provide Ramsbottom carbonresidues which exhibit excellent cohesiveness (1). One purpose of the present investigation was to determine to what extent the Ramsbottom carbon residues of naturally-occurring petroleum oils in Alberta exhibit this feature.
Furthermore, the filtrates (2) obtained from the residues following partialthermal cracking of Athabasca oil contain varsol- and kerosene-insolubles and, in many instances, the Ramsbottom carbon residues of these insolubles are inthe form of honeycomb-like structures which represent volume expansions of upto 300 times (3). Consequently, a second purpose of the present investigationwas to determine whether commercial asphalts, on dilution with varsol orkerosene, yield insolubles similar to those obtained, as described above, fromthe Athabasca oil filtrates, and also if the Ramsbottom carbon residues ofthese insolubles show volume expansions.
Exploration for and Testing of Groundwater Supplies for Secondary Recovery
Authors: Lennox D.H. 
Published: March 2010

Abstract
The methods employed in the exploration for and testing of groundwatersupplies are largely independent of the purpose for which the water is to beused. The quantity or quality of water desired, however, may eliminate someaquifers from consideration or make possible the utilization of others notusually considered and, in this respect, eventual use may influence explorationand testing. The aquifers of primary importance in supplying groundwater forsecondary-recovery purposes are the present-day and preglacial alluvialdeposits and the sandstone beds of various Upper Cretaceous and Tertiaryformations. At the present time, the present-day alluvial deposits and the Paskapoo sandstones are the most commonly used.
Once an aquifer has been selected, it is generally advisable to carry out acarefully controlled pump test, preferably with one or more observation wellsin addition to the pumping well, in order to determine all the hydrologicfactors that may combine to give rise to depletion of the aquifer during theproduction period. These include: the hydrologic characteristics of theaquifer, namely its coefficients of transmissibility and storage; the magnitudeof any leakage from overlying or underlying strata; and the location and natureof any lateral boundary. With this information, it is possible to predict, withsome degree of confidence, the safe production rate for a single well or acombination of wells for any desired production period.

Introduction
The availability of water that is adequate in quantity and of suitablequality is vital for the preservation and improvement of our current highstandard of living. Not only is there a large per-capita home consumption ofwater, but vast and ever- increasing quantities are required for the productionand processing of agricultural and industrial products. The injection of waterinto an oil-bearing deposit in order to maintain the pressure as oil isremoved, and thus effect a greater percentage recovery, is an importantindustrial use of water and, because the injection site is, as a rule, distantfrom municipal supply lines, the operator must assume the responsibility forthe location and exploitation of a suitable water source.
Gas Cycling the Carson Creek Field
Authors: Derbowka G.C.M. 
Published: March 2010

Abstract
The Carson Creek - Beaverhill Lake field comprises two retrogradegas-condensate reservoirs being produced under full-scale gas cycling.Production consists of rich gas from which liquids are stripped, the residuegas being injected back into the reservoirs. Make-up gas from the adjacent Carson Creek North oil field is injected to maintain the original reservoirpressure, thereby minimizing condensation of liquid in the reservoirs. Theengineering aspects of this scheme involve a choice of well patterns andlocations, and of producing and injection rates, the prediction of rates andrecoveries, and the design of facilities. A potentiometric model study was usedas the basis of the reservoir study. The main features of the scheme are:only one injector and one large irregular cycling pattern are used for eachreservoir, utilizing widely spaced wells;the installation of thefull-scale scheme was based mainly on theoretical calculations, with noproduction history or pilot test data available.
It is estimated that 76 percent of the pentanes plus will be recovered under cycling, as compared with 45per cent under primary pressure depletion.

Introduction
The Carson Creek field is a retrograde gas condensate field located 105miles northwest of the city of Edmonton and 8 miles north of the town of Whitecourt. It is the most southerly hydrocarbon accumulation found to date inthe Swan Hills Beaverhill Lake reef trend. As presently delineated, the fieldencompasses approximately 18,000 acres in Townships 60 and 61, Ranges 11, 12and 13 W5M (Figure1). The original raw gas-in-place was approximately330 Bcf. The discovery well, Mobil Whitecourt Carson 13-12-61-12, was cased asa potential producer from the Upper Devonian Beaverhill Lake reef in March of1957. Since that time, eleven additional wells have been drilled. In March of1962, an application was made to the Conservation Board to cycle this field.The plant was built and cycling began in December, 1962. (This means that, attime of writing, the field had a production history of approximately one year.)The field has now been unitized, with Socony Mobil Oil of Canada, Ltd., as theoperator.
The Chemical Retardation of Acid and How it can be Utilized
Authors: Knox John A. , Pollock R.W. , Beecroft W.H. 
Published: March 2010

Abstract
Five years of research and development went into the technique for evaluating the reaction of acid on calcareous materials. With this technique, improvements in several of the standard acidizing solutions were discovered aswell as a new method for chemically retarding acid.
The new chemically retarded acid has properties which allow it to beutilized for a wide variety of well problems which no other single acid systemis versatile enough to handle.
Actual field results are presented to support its utility.

Introduction
Acidizing has been known as a method of well stimulation for almost seventyyears. (1). It has been widely used for thirty years, but there has been, andstill is, a great deal of mystery associated with its use. One of thefactors obscuring the technique of acidizing is that little is actually knownabout what goes on downhole during a treatment.
It has been the general belief that regardless of the type of formation or permeability of that formation, any kind of acid solution, viscous or thin, slow reading or fast, can be pumped into the existing permeability or down afracture at will and do what is desired of it. This, of course, is not true.
With the advent of fracturing about fifteen years ago, a method for stimulating sandstone as well as calcareous formations became available. Along with the technique also came a more scientific and engineered approach to stimulation. Soon, sand and water or oil had almost replaced acid, even incalcareous formations, and acidizing, as such, went into a severely depressed period.
There were still many things which acid could do that were not possible witha straight fracturing treatment, and therefore acid began a comeback withbetter retarded systems and other innovations (2) but still perhaps with less science than art.
One of the greatest problems facing the science of acidizing has been the development of reasonably simple testing procedures which would allow evaluation, on a comparative basis, of the reaction rates of different types of acid on actual formation cores.
The Facies Front of the Devonian Slave Point-Elk Point Sequence in Northeastern British Columbia and the Northwest Territories
Authors: Griffin D.L. 
Published: March 2010

Abstract
The facies front of the Slave Point – Elk Point sequence is the narrow zoneof contact between the carbonate Slave Point, Sulphur Point and Pine Pointformations and the equivalent shales of the Horn River formation. The faciesfront trends approximately north-northeast in British Columbia andeast-northeast in the Northwest Territories. The shales lie to the northwest ofthe front and the carbonates to the southeast.
The facies front of the Slave Point Elk Point sequence is in the order of 1000 miles in length. It extends over a maximum known stratigraphic interval ofabout 1,300 feet. In parts of the Northwest Territories, the interval overwhich the facies front is developed is considerably less due to the influence of a positive tectonic feature known as the Tathlina High.
In most areas, the Slave Point and Sulphur Point formations pass to shalequite abruptly and tend to behave as a unit in this respect. The zone in whichthe Pine Point formation passes to shale is much broader than that in which the two overlying formations pass to shale.
Three main tectonic divisions of the facies front are recognized. It is probable that the major morphological features of the front result from structural control. Drilling has shown that, in many areas, the dolomitized Slave Point formation at the facies front contains abundant reserves of natural gas. There are sufficient grounds for believing that the underlying formations at the front also contain significant hydrocarbon reserves.

Introduction
In the eastern part of northeastern British Columbia and in northern Alberta, the Slave Point Elk Point sequence consists of a series of evaporites and carbonates, mainly Givetian in age. When traced to the northwest, the evaporites are lost from the sequence and the Slave Point – Elk Point rocksconsist of a series of limestones and dolomites with occasional interbedded shales. Beyond a relatively narrow zone of profound lithologic change whichtrends east-northeast across the southern part of the Northwest Territories and north-northeast across northeastern British Columbia, the upper three-quarters of the Slave Point – Elk Point sequence is represented by a series of shales.
Waterflood Pressure Maintenance of the Peejay Field - British Columbia
Authors: Rogan A.D. , Smith B.R. 
Published: March 2010

Abstract
The Peejay field, located approximately 50 miles north of Fort St. John, British Columbia, was unitized and placed under waterflood pressure maintenancein April, 1964. This field is unique in that it is the first oil and gas unitto be formed in British Columbia for the purpose of initiating secondary recovery.
The Peejay field contains an estimated 36,000,000 stocktank barrels of oil-in-place. The predominant primary depletion drive mechanism was internal gas expansion, which was expected to yield approximately 6,000,000 STB ofrecovery or only 16 per cent of the original oil-in-place. A line-drive waterflood in the down-dip water zone is expected to yield an additional9,000,000 bbls of recovery or a total of 42 per cent of the original oil-in-place. Reservoir characteristics are such that full replacement of the5,800-B/D field production can be achieved by water injection into one well.
Important secondary benefits of the pressure maintenance and unitization scheme are:deferment of large capital expenditures for artificial lift equipment;reduction of operating costs in a remote muskeg area;conservation of reservoir energy through flexibility of production;
and increased allowable production rates through the application of a better recovery mechanism.
The securing of a satisfactory water supply was complicated by the lack of subsurface acquifers and by the seasonally poor water quality in the adjacent Doig river. These problems were overcome by the construction of a 900,000-barrel pit for off-stream storage. Construction and the operation of supply and treating facilities were generally complicated by deep muskeg in the field area.

Introduction
The Peejay oil field is located approximately 50 miles north of the town of Fort St. John, British Columbia (Figure 1). Access to the field is by anall-weather road, constructed for exploration in the general area.
The producing zone in the field is the Halfway formation of Triassic age. Development to July, 1963, had resulted in the completion of nineteen producing oil wells and two suspended wells in the pool. The proven developed surface area is 4,300 acres (Figure 2).
Correlating and Averaging Connate Water Saturation Data
Authors: Buckles R.S. 
Published: March 2010

Abstract
The use of simple hyperbolic relationships in correlating connate water saturation data is shown to have wide application in a variety of reservoirs. This can be of considerable practical significance to the reservoir engineer because volumetrically weighted average saturations for any combination of core samples, reservoir strat a or lease areas can be obtained directly from such correlations with a knowledge of average porosity alone. Also, in systems represented by a simple equilateral hyperbola the porosity- saturation productis constant and hydrocarbon volumes are conveniently derived from the difference between the pore volume and a constant fraction of the bulk volume. Potential applications and limitations of the technique have been explored fora number of sand and carbonate reservoirs, and several examples are described.

Introduction
Of fundamental importance in all oil and gas reserve estimates is the concept of connate water saturation. In fact, as it is one of the most basic parameters, like pay thickness or porosity, connate water must be measured orestimated in any and all types of reservoir analyses. Because water saturations may range from as little as 1 or 2 per cent up to 100 percent of the pore space within the same reservoir, it is common practice to condense the data into asingle "average" value related to some other average reservoir characteristic such as porosity or permeability. Although such an average may be applicable tothe reservoir as a whole, it can, in some cases, lead to appreciable errors ifapplied to individual wells or areas within the pool. Even when the entire poolis considered, there may be considerable difficulty in obtaining the correct average.
The use of permeability as a correlating parameter has long been popular (1,2, 3), and in some reservoirs it may be the only reasonable choice. Difficulties, however, can be encountered in applying such relationships toobtain true average saturations. Porosity-saturation correlations have beengiven somewhat less attention in the literature, although they have been widely used in Western Canada and in some areas of the United States. There are inherently fewer problems in establishing representative average values from porosity relationships, as the differences between arithmetic and geometric means, medians and modes, and the effects of sample orientation, need not be considered.
Canadian Petroleum Association - History and Organization
Authors: Doig Ian M. 
Published: March 2010

Abstract
The Canadian Petroleum Association was formed in 1952 after twenty-five years of development since its conception as the Alberta Oil Operators' Association during Turner Valley days. Its membership of 230 oil and gas exploration, development, pipeline and transportation companies which operate mostly in Western Canada represents approximately 97 percent of Canada's petroleum production. Besides having Divisions in the western provinces, the Association has an Ottawa Information Office which serves as a liaison betweenthe industry and the Federal Government. It also maintains a Statistical Economics Department.

Introduction
What is an association? I think that the answer can be summed up by sayingthat an association is "a voluntary non-profitmaking body formed by independent firms to protect and advance certain interests common to all."
Such matters as wage scales, inventories, prices, production statistics, credit and collection reports, legislative advice, economic problems, organization data, methods of finance, and operational procedures are of unique and vital concern to the members of a specific industry. It is claimed that trade associations enable their members to co-ordinate their competitive forces without relinquishing the rewards which result from personal initiative and enterprise.
In terms of function, there are two main types of trade associations:Those that confine themselves to voicing the views of their members on matters of common interest.Those that exercise some measure of control over their members.
The latter, in many countries, make extensive use of voluntary agreements for controlling prices, output and channels of distribution. In some instances, trade association arrangements go beyond price and output stabilization and take in measures designed to control production capacity.
The overwhelming majority of trade associations, including the Canadian Petroleum Association, are of the first type. They prefer self-government of industry by consent rather than by coercion. They avoid any attempts to stifle competition or to bar new entrants by means other than persuasion and presentation of facts. Thereby, they gain the advantages of good will, elasticity of operation and maximum possible membership.
Neutron Lifetime Logging in the Gulf Coast Area
Authors: Youmans A.H. , Hopkinson E.C. 
Published: March 2010

Abstract
A new type of nuclear log has been developed which responds to variations inthe lifetime of thermal neutrons in formation materials. The log is particularly sensitive to the presence of chlorine and can reliably distinguish between oil-bearing and salt-water-bearing formations. Many wells have been logged in the U.S. Gulf Coast area. Typical performance characteristics and interpretation techniques are discussed. Applicability of this new log in Canadian oil provinces is considered.

Introduction
A new nuclear logging method, recently introduced in the Gulf Coast area ofthe United States, can distinguish between brine and oil through casing. Itemploys a pulsed accelerator-type neutron source and a scintillation counter tomeasure the lifetime of thermal neutrons in formations by recording the intensity of neutron capture radiation during the interval between sourcepulses when neutrons in the borehole have died away (1). The log is called a "Neutron Lifetime Log,™" based on the fact that, in ordinary rocks, thermal neutrons have a measurable lifetime which varies with variations in reservoir fluid and rock characteristics.
Although field experience is limited, actual results in commercial wells and test pits have demonstrated that the log has important advantages over other nuclear logs. It has been found to have much better sensitivity to formation fluid salinity than any other cased hole log. As experience is gained in interpretation techniques, the new log is expected to be applicable to many formation evaluation problems where other logs are inadequate. It has been found that, in general, there is a quantitative relationship between the log response and the fluid and rock properties. This makes it possible, infavourable cases, to measure fluid saturation quantitatively. Moreover, it isfeasible to differentiate between oil and water zones even when borehole conditions are such that other logging methods would be inaccurate or inoperative.