bluuebunny/crossref_metadata_2025 huggingface dataset:
The Prediction of Pressure Gradients for a non-Newtonian Crude Oil Flowing in a Pipeline
Authors: McKay W.N. , Boucher W.W. , Milne J.
Published: March 2010

Several Western Canada crudes exhibit non-Newtonian flow characteristics.Thus, the use of the standard definition of viscosity is unreliable in pipelinesizing formulae.

A "model pipeline" viscometer was constructed, adapted from an instrumentdesigned by Coe, and based upon the theoretical aspects of the scale-up problemfor non-Newtonian flow. Using this instrument, laboratory pressure gradientswere determined and compared directly to the pressure gradients measured in atest section of pipeline carrying the crude oil. The field tests were for ayear's operation, and covered the full range of probable temperatures and flowvolumes. Laboratory pressure gradients agreed with the field values with anaverage error of less than 5 per cent.

Introduction

Fluids are classified into two main categories - Newtonian or non-Newtonian- according to their behaviour at constant temperature under various steadyshearing forces. A Newtonian fluid obeys the equation:

(Equation i)

in the laminar flow regime. Here, T is the shear stress, du/dr the shearrate, and ?the viscosity of the fluid in question. For laminar flow ina round tube, a double integration yields the classic Hagen-Poisseuilleequation

(Equation ii)

where R is the radius, P/L is the pressure gradient and Q is the throughputor rated volume flow.

Because of the identity of equation (i) with equation (ii), it has become anaccepted procedure to call RP/2L the shear stress at the wall of a tube ofradius R, and 4Q/pR3 the resultant shear rate. For reasons that willbe explained later, it is more rigorous to define these terms, in equation(ii), as the "apparent" shear stress and the "apparent" shear rate. The "real"or "true" terms should be only identified with equation (i).
A General Solution of the Equations Describing Steady State Turbulent Compressible Flow in Circular Conduits
Authors: Dranchuk P.M. , Quon D.
Published: March 2010

Although a number of solutions to the equations describing steady compressible flow in pipes exist, even the most rigorous of these make simplifying assumptions concerning thermal effects; i.e., either that the flowis isothermal or that the gas assumes identically the temperature of the surroundings. There are, however, instances where these assumptions may not be warranted.

This paper examines the differential equations which characterize momentum and heat transfer, rearranges them so as to make them amenable to numericalsolution and proposes a computational technique suitable for use on digital computers. The approach represents an improved and generalized method ofhandling gas well calculations as well as pipeline design problems.

Introduction

The flow of fluids, in general can be described by a set of partial differential equations – comprising the equation of continuity, aforce-momentum balance for each of the three dimensions and a total energy balance. A general solution of this set of five partial differential equations involving four independent variables – three geometric, one time – is currently beyond our capabilities. Fortunately, in many cases of gas flow, the flow ishighly turbulent, steady and occurs in circular conduits. In such cases, the system may be described by two ordinary differential equations, namely, aforce-momentum and a total energy balance. These two equations may be writtenin terms of one independent variable, length, and two dependent variables, which may be two fluid properties. Although any two independent properties willdefine the state of a fluid, temperature and pressure are the obvious choices, as they are the ones usually measured in practice.

Until recently, the solution of simultaneous nonlinear differential equations has been too time-consuming to find wide engineering acceptance. Consequently, further simplifying assumptions have been made. It has been assumed that the gas temperature is either constant or an explicit function of length, thereby reducing the number of differential equations to one, viz., theforce-momentum balance. It should be pointed out, however, that the assumption of isothermal flow is normally not defensible on physical grounds. With regardto the alternate proposed assumption, while the temperature of the surroundings may be known, the assumption that the fluid assumes identically the temperature of the surroundings implies that the overall heat transfer coefficient between the fluid and the surroundings is infinite - a questionable hypothesis.
Laboratory Displacement of Oil by Water Under Simulated Reservoir Conditions
Authors: Colpitts G.P. , Hunter D.E.
Published: March 2010

Intuitively, preserved core waterfloods at reservoir conditions give resultswhich most closely represent the displacement that occurs in the reservoir. More elaborate equipment and more involved procedures are required to performsuch tests than for conventional waterfloods. The equipment and proceduresrequired are described in detail. An experimental program to determine the effects of test environment and core condition is described. Typical results are presented which show that both test environment and core condition should be as representative of the reservoir as possible, that their separate effects are not independent, and that each reservoir is liable to be different. For each reservoir, the decision has to be made whether the benefit of more representative data outweighs the additional cost involved in testing preserved cores at reservoir conditions.

Introduction

The use of laboratory waterflood results to assist in the prediction of reservoir performance is common practice in reservoir engineering. Thetheoretical validity of such use is well established. Commonly, waterflood tests are carried out on extracted cores using refined oil at room temperature and atmospheric pressure. In recent years, some investigators have been studying the question of how closely tests of this sort really represent displacement in the reservoir. Of special concern are the test environment and the core condition. Wilson, Ruhl et al., Delcloud, and Savelli and Kytehave been concerned primarily with environment. Do pressure or temperatureaffect the results? Does refined oil behave the same as reservoir oil? Bobek et al., Burkhardt et al., and Denekas et al. havebeen concerned with core condition. Are the surface characteristics of extracted core representation of the characteristics of in situ reservoir material?

We are engaged in an experimental program to study the individual effects and the combined effects of both test environment and core condition. Control of these factors requires careful and elaborate experimental work. It is the primary purpose of this paper to present, in some detail. the procedures, equipment and test materials necessary to achieve this control. In addition some experimental results from this program are presented.
Gas Transportation Cost Dividends From Internally Coated Pipe and Station Automation
Authors: Hurd L.G.
Published: March 2010

The Alberta-California gas pipeline is coated internally throughout most ofits length with a thin film of epoxy resin, the purpose of which was primarilyto provide a smooth internal surface and reduce compressor station horsepower requirements.

Three of the compressor stations installed on the line are automated and arecontrolled remotely by a single "set point" signal from the central dispatch office.

This paper evaluates the benefits that have been realized from these two factors. Pipeline flow efficiency factors are reported and compared with thosefor uncoated portions of the line, and compressor station operating and maintenance costs on the line are compared with costs usually experienced insimilar manned stations. Both of these effects are then related to costs of transportation, and the net effect of each is reported.

Introduction

The Alberta – California pipeline system extends from gas fields in theeastern foothills region of Alberta through the southeast corner of British Columbia across the international border in Idaho, and through Washington, Oregon and northern California to Antioch on San Francisco Bay – a total ofsome 1,600 miles, including gathering laterals. It carries gas purchased in Alberta by Alberta and Southern Gas Co. Ltd. to markets served by the Pacific Gas & Electric Co. throughout northern California, and to the Canadian Montana Pipeline Co. at the Alberta-Montana border. In addition, gas purchasedby the Westcoast Transmission Company Limited from fields in Alberta is carriedby the line and delivered to the El Paso Natural Gas Co. near Spokane, Washington, as well as to local utility companies along the route of the linein British Columbia, Idaho, Washington and Oregon.

The main line is 36 inches in diameter throughout its length and, with thefour compressor stations installed at the time the line was built, the systemis capable of delivering some 460 MMcf/D to the San Francisco Bay area, about160 MMcf/D to El Paso at Spokane and about 36 MMcf/D to Canadian Montana.
The Use of Salt Cement Blends as an Aid to Better Cementing in Formations Containing Fresh Water Sensitive Clays
Authors: Longson W.B.
Published: March 2010

The application of salt for primary cementing in Western Canada has been restricted largely to salt cavern storage wells and to the development of potash reserves in south-central Saskatchewan. The value of salt cement blendsin cementing through fresh water sensitive formations has recently broughtabout wide usage of this technique in certain areas of the United States, andthere is good reason to believe that there are several areas in Canada wherethe success of primary cementing could be improved by the use of saltcements.

There has been considerable work done on the applicability of salt cement, with emphasis on improved cement-formation bonding and the minimization offormation deterioration by water contact. Field results have shown that saltcements have improved the success of primary and squeeze cementing jobs.

Laboratory work has been done to evaluate the change in slurry properties with the addition of varying concentrations of salt to commonly used cementing blends.

Introduction

The use of salt cements in Canada has been quite limited and, as a result, the primary purpose of the information presented here is to illustrate theadvantage of salt for primary cementing of oil and gas wells where the formations encountered contain fresh water sensitive clays and shales.

The first known use of salt cements in Western Canada occurred within thepast ten years. Initially, salt cements came into use because of the failure toset fresh water cement abandonment plugs in the salt and potash zonesencountered in potash test holes. Earlier experience in the U.S.A. proved that a good cement-formation bond through a salt section could only be achieved byusing a salt cement. Figure 1 illustrates the bonding of cement to rocksalt. The illustration shows how a fresh water slurry will dissolve a portionof the salt, with the result that there is no bond between the salt and cement, while the saturated salt slurry does not dissolve any portion of the salt, resulting in good contact and bonding between the salt and the cement.

Operators in Saskatchewan found that casing could be cemented successfully in salt cavern gas storage wells with a sodium chloride slurry; more recentwork has employed a sodium chloride and potassium chloride (potash) saturated slurry (1). Later, casing was set into the potash for a solution mining project, and again salt cements were used to obtain a good primary cement job.
Predicted vs. Measured Loads in a Sucker Rod Pumping System
Authors: Byrd J.P.
Published: March 2010

In order to apply an oilfield pumping unit on the most economical basis, itis often necessary to predict its torsional and structural loading in advanceof well completion. Frequently, a pumping unit is misapplied because thedetermination of these values by simple prediction formulae does not conform toeventually measured loads. An investigation of the simplified predictionformulae most commonly used in applying a sucker rod pumping unit illustrateswhy discrepancies between predicted and measured loads may exist.

Introduction

One of the numerous problems faced by the pumping unit manufacturer is topredict the torsional and structural loading that will be imposed on thesurface equipment for any given set of well conditions.

As a precise determination of these loads involves, complex formulationemploying many variables (some of which are unknown prior to well completion), it becomes necessary to develop a set of prediction equations with solutionswhich are fast and simple and require knowledge of only a few known quantitiessuch as rod and fluid weight and polished rod acceleration.

In most cases, these simple and convenient formulae, employing only a smallportion of the items which actually control torsional and structural loading, are entirely adequate to apply the surface pumping unit on a most economicalbasis – but the results obtained are admittedly only approximations and maydiffer considerably from measured loads.

In a recent study of two different types of sucker rod pumping units over anumber of applications chosen at random, the predicted peak torque determined by these simplified methods was compared to the measured peak torque. The results showed that, in both types of units, approximately one-third of the applications measured greater than predicted, one-third measured less than predicted and one-third measured about the same as predicted. (See Table I).
The Dual Solvent Slug Technique for Improving the Injectivity of Waterfloods
Authors: Relf J.A. , Sears J.R.
Published: March 2010

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

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

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

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

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

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

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

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

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

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.
The Shortage of Engineers - Are We Working on the Solution or Are We Part of the Problem?
Authors: Dranchuk P.M.
Published: March 2010

During the past decade, the mineral industries have been faced with an increasing shortage of engineers. The point has now been reached where the shortage may be termed critical. This shortage may be attributed directly to declining enrollment in the mineral science programs offered by the universities on this continent.

Although the reasons for declining enrollment are undoubtedly many, twomajor hypotheses may be postulated. The first is that high-school graduates are either unaware of the mineral industries and the opportunities in them or thatthey are aware of them but have somehow obtained a false image of their truenature. The second is that they are aware of the true nature of these industries and the opportunities they offer but find them exceedingly unattractive.

The problem of dwindling enrollments has, in recent years, been subjected toa concerted attack by the industries and professions concerned. However, theirefforts to date have been based essentially on the first hypothesis. Sufficient results are now available to suggest that either the methods of attack are inappropriate or that the first hypothesis is false. As all of the known methods of attack have been examined and exhausted, current authorities contend that the problem must yield to the pressure of intensified reapplication ofthese methods. The wiser move might well be to swallow our pride and seriously consider the second hypothesis.

Introduction

In recent years, the mineral industries have been faced with an increasing shortage of technical personnel. At present the shortage in the petroleum industry may be termed serious, whereas that in the mining industry may be moreproperly described as acute. Although this shortage was predicted as early as1951, few people accepted the prediction at that time. As the passage of time showed the prediction to be sound, industry slowly accepted it, but even thenwith reluctance and only based on the assumption that it was but a temporary phenomenon. In fact, there are at this moment members of industry who, although they realize they are about to drown, still have the feeling that if they canbut survive a bit longer the waters shall recede. The majority, however, view this as wishful thinking.
Fundamentals and Applications of the Monte Carlo Method
Authors: Stoian E.
Published: March 2010

Perhaps no industry is more vitally concerned with risk than the oil and gas industry, and few professional men other than petroleum engineers are required to recommend higher investments on the basis of such uncertain and limited information. In recent years, the number of methods dealing with risk and uncertainty has grown extensively so that the classical approach, using analytical procedures and single-valued parameters, has undergone a significant transformation. The use of stochastic variables, such as those frequently encountered in the oil industry, is now economically feasible in the evaluation of an increasing number of problems by the application of Monte Carlo techniques.

This paper defines the Monte Carlo method as a subset of simulation techniques and a combination of sampling theory and numerical analysis. Briefly, the basic technique of Monte Carlo simulation involves the representation of a situation in logical terms so that, when the pertinent dataare inserted, a mathematical solution becomes possible. Using random numbers generated by an "automatic penny-tossing machine" and a cumulative frequency distribution, the behaviour pattern of the particular case can be determined bya process of statistical experimentation. In practical applications, the probabilistic data expressed in one or several distributions may pertain to geological exploration, discovery processes, oil-in-place evaluations or the productivity of heterogeneous reservoirs. The great variety of probability models used to date (e.g., normal, log-normal, skewed log-normal, linear, multi-modal, discontinuous, theoretical, experimental) confirms a broad rangeof experimental computations and a genuine interest in realistic representations of random impacts encountered in practice.

Emphasis in this paper is directed to the salient characteristics of the Monte Carlo method, with particular reference to applications in areas relatedto the oil and gas industry. Attention is focused on reservoir engineering models. Nevertheless. management facets of the oil and gas business are considered along with other applications in statistics, mathematics, physics and engineering. Sample size reducing techniques and the use of digitalcomputers are also discussed.
The Interpretation of Permeability Measurements
Authors: Dranchuk P.M. , Sadiq S.
Published: March 2010

In 1941, Klinkenberg observed that although laboratory flow tests showedporous media to have greater permeabilities to gases than to liquids, this was not due to fluid solid interaction in the usual sense.

The present study shows that currently accepted test and interpretation practices yield permeability values which are less than or equal to the truevalue. A modification is suggested which allows Klinkenberg's method to yield unique results.

Introduction

The rediscovery of Darcy's law during the early 1930's opened new vistas tothe petroleum industry. It made possible the prediction of the behaviour of oilwells, oil fields and more complicated systems. In order that this law beapplied the permeabilities of the porous media to be studied had to be known.It therefore became accepted practice to obtain samples of a porous medium, determine the permeabilities of these samples and, from these results, estimate the permeability of the entire medium.

Initially, the determination of the permeability of a sample of a porousmedium consisted of conducting a laboratory flow test on the sample and applying Darcy's law to the resulting data. The test itself consisted of flowing the fluid of interest through the sample at various rates and recording the flow rates and appropriate pressures. As the fluids of interest were originally reservoir crude oils, such tests were difficult, if not impossible, to perform. It was reasoned that because permeability was a unique property ofthe porous medium, any laboratory fluid could serve as the flowing fluid fortest purposes. This was found to be true provided that the fluid did not interact with the solid matrix. Unfortunately, it was observed that the mostreadily available liquids often did react with naturally occurring porousmedia. Furthermore, the use of liquids as test fluids necessitated therecleaning of samples subsequent to testing. As a result, it became accepted practice to use inert gases, such as helium or nitrogen, as test fluids.
Automatic Data Gathering and Supervisory Control System for Production and Operations in the North Pembina Cardium Unit No. 1
Authors: Fryters W.A. , Harrison G.R.
Published: March 2010

A supervisory control and data gathering system has been installed in the North Pembina Cardium Unit No. 1, which is operated by Socony Mobil Oil of Canada, Ltd. This system provides, at one central location, read-out ofproduction data, logging of alarm conditions and supervisory control over thirty-five satellite production stations and two central treating stations, handling a total of 462 producing wells. The production data reported include well-test oil, water and gas volumes. The supervisory control system provides remote control of all production wells. This system was designed making use of essentially conventional electrical components. It has been in successful operation for more than eighteen months, effecting reduced maintenance and operating costs while providing increased speed and accuracy in the gathering and processing of production data.

Introduction

In the North Pembina Cardium Unit No.1, a total of 462 wells produce into thirty-five satellite well testing units. The production from the satellite units is moved through a pipeline gathering system and is processed at two treating plants. A map showing the production system field layout is given in Figure 1. The design of this production system has been described in previous publications (1, 2).

The satellite units provide individual well production test measurements of oil, water and gas volumes, and regulate and monitor oil production and testing. The treating plants accept crude-water emulsions from the satelliteunits, dehydrate and ship the oil, and treat and dispose of the water. Gas is separated and sold from the satellite units and the treating plants.

This production system requires that considerable measurement and operating status information be acquired from the satellites and the plants which aredistributed over an area of roughly 70 square miles. In addition, certaincontrol functions must be effected at these locations. For the purpose of both gathering the information and effecting the needed control, a centralized data gathering and supervisory control system is provided. This system has been inoperation for 18 months and is highly successful.
Physical Upgrading of Heavy Crude Oils by the Application of Heat
Authors: Henderson J.H. , Weber L.
Published: March 2010

Subjecting a heavy crude oil to mild thermal cracking conditions effects apermanent and significant reduction in its viscosity and specific gravity. Although all crudes are susceptible to cracking, the temperatures and timesrequired usually exceed those required to crack heavy crudes such as thosefound in the Athabasca tar sands. At temperatures below 1000°F, it has already been established that cracking of both pure hydrocarbons and petroleum can bedescribed by first-order kinetic equations. To use this fact, a reference mustbe established by which the amount of upgrading or conversion of crudeconstituents can be estimated. This was done by subjecting both the original crude and the ‘heat-treated’ oil to distillation under identical conditions.The residuum from the distillation of the treated oil was compared to that from the original crude to establish the ‘degree of upgrading.’

From such laboratory tests on a variety of crude oils, it has been possible to estimate the time-temperature history necessary to produce specific degrees of viscosity reduction for each. As a result, it is possible to estimate thefeasibility of utilizing heat in the reservoir to facilitate the production of heavy oil, or of using heat to facilitate the surface handling of oil alreadyproduced.

The permanent upgrading in physical properties occurs so slowly at 500°F that the use of temperatures below this level, as currently practiced with heated pipelines, will effect only a temporary improvement in oil fluidity. Attemperatures in excess of 700°F, coking may present serious operating problems unless residence times are kept very short.

Introduction

Crude oils of low API gravity and crude oils having a high pour point present production problems both in and out of the reservoir. To overcomesurface handling problems, the oil industry currently practices extensive and expensive blending of light oils and LPG with heavy crudes to make them easily handled in pipelines and storage facilities. An alternative remedial technique involves thermal cracking. Thermal cracking, with its attendant lowering ofpour point and viscosity, was used in Russia many years ago to facilitate the pumping of heavy crudes (1). Egloff and Morrell (2) proposed, in 1926, toseverely crack a high-pour-point oil at the wellhead to eliminate the need for pipeline heaters and diluents.