bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Fluids Accurately Sampled with New Wireline Tool
Authors: Kisling J.W. , Greer Larry P.
Published: March 2010

A new sampler, which is run on solid wireline, collects downhole samples offluid under closely controlled conditions. The sample can be used for PVTstudies to determine the physical and chemical properties of reservoirfluids.

The tool has very unusual design features that ensure that the propertiesand the volume of fluids and gases at the point of sampling are not altered inany way during the collection process. The integrity of this tool has beenproven by excellent results in field use.

Introduction

The object of bottom-hole sampling is to obtain a quantity of oil and gaswhich can be used to determine the physical and chemical properties of thefluids contained in the underground reservoir. These properties are, in turn, used to predict the production performance of the formation and also to determine the oil and gas reserves.

Basically, this process expands a very small quantity of fluid to manymillions of times its original size. Any discrepancies that exist in theoriginal sampling process will be magnified accordingly when the final resultsare calculated. This establishes the real need for a bottom-hole samplingdevice that collects and preserves a true sample of thesubsurface fluid.

The accuracy and integrity of the sample determine how valid the predictionscan be for the production performance of the well. The efficiency over theproducing life of the well will, in many cases, be dependent on the sepredictions and can drastically affect the total recovery to be achieved. Thesame qualities of accuracy and integrity of the sample will also determine the accuracy of the calculations of total reserves.
The Solid State Pipeline Gauger
Authors: Hinchliffe R.A.
Published: March 2010

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

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

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

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

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

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

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

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

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.
Lateral Water Encroachment In the Pincher Creek Field
Authors: Hnatiuk John
Published: March 2010

Unusual water production performance has occurred in a portion of the Pincher Creek Gas Field. This fingering or ‘lateral water encroachment’ from the downdip aquifer has been insufficient to significantly affect pressure performance, but has severely restricted the productivity of some wells and will reduce the recovery of gas in place. Water encroached into one structurally high drilling spacing unit even before the well was drilled and placed on production. The mechanics of this water movement have been confirmed during two reconditioning operations and by the production performance of wells. It has been found that a watered-out well can be made to produce water-free gas by recompleting LOWER in the same continuously porous interval. Relief from water production after reconditioning may be short-lived. The various factors to which water fingering could be attributed have been examined and are discussed. Lithofacies studies indicate two ‘shoals’ which form one continuous gas reservoir. Premature water encroachment at individual wells could be related to interfingering of rock types and lack of vertical permeability. This water encroachment phenomenon could be effective to varying degrees in other deep, fractured reservoirs in Alberta.

INTRODUCTION

The Pincher Creek Rundle Gas Pool, located in the extreme southwestern corner of Alberta, as shown on Fig.1, was discovered at a depth of 11,700 feet by the drilling of Pincher Creek No.1 in 1947. Subsequent drilling resulted in twenty-four gas wells and three dry holes. Figure 2 is a structure map which shows the locations of the wells.

Commencing early in 1957, the pool was cycled at a raw gas rate of 60 MMcf/D for two years to recover sulphur and condensate. In late 1958, gas sales to Trans-Canada commenced.

Water production problems have adversely affected the deliverabilities of wells in the northern half of the field, some occurring very early in the blowdown operation. The primary purpose of this paper is to discuss the unusual water production performance and remedial measures.

RESERVOIR CHARACTERISTICS

Geology

The Pincher Creek sour gas – condensate reservoir consists of a fractured thrust block of Rundle strata striking N3 °W and dipping 4 to 8 degrees to the southwest. The areal extent of the pool is determined by the down-dip aquifer on the west and by faults that bound the eastern edge of the structure, as shown schematically on Figure 4. Two wells appear to have encountered separate fault blocks which are in pressure communication with the main reservoir. The productive portion of the Rundle can be subdivided into five zones, the Upper Dense, Upper Porous. Middle Hard, Crystalline and Lower Porous, each differing in lithology, thickness, porosity and permeability. The five zones form a continuously porous reservoir which is normally 550 feet thick when the entire section is above water and not faulted. In general, the lithology of the pay section is one of dolomite above the Crystalline Zone and of variable amounts of limestone and dolomite through the remainder.
Education Needs of the Oil Industry's Engineering Staff
Authors: Smith Charles R.
Published: March 2010

From the humble beginning of the oil industry at Titusville, Pennsylvania in 1859 to the giant that it is today, the use of the professionally educated individual has been a mainstay of the energy business - be this in companies, in governmental agencies, in consulting groups or in the universities. The dominant role of the engineer dictates that he lie current and he capable of adjusting to the evolving technology. Responsibility of continuing and renewal education lies with the individual, with needed support from the employer, from the professional societies, from the universities and from the various entities that provide educational services. There is reason to believe that an arbitrary two-week re-education period per year, with a sabbatical leave of six months (minimum) every five years, should be the goal of the aggressive engineer, the requirement of each and every employer, and the personal goal of each self-employed engineer. Additional regional continuing education centers need to be established - similar to the Kellogg Center at the University of Oklahoma.

INTRODUCTION

MUCH HAS BEEN SAID about the state of the engineering profession - especially after the launching of the first Sputnik. Since this historic date in 1957, the applied sciences received much attention and considerable federal funding, although not necessarily in areas directly benefiting the oil industry, However, the United States' emphasis on space technology did culminate in the landing of two men on the moon in July of 1969. With less journalistic impact, but with more direct benefit to the man on the street, the oil industry has managed to provide the world with all economical energy source that has primary changed lives for the better. Of the problems that have been created, pollution is now receiving the most attention. Much of the solving will be done by engineers of all ages, but mainly by those who have remained mentally flexible and who have kept on top of, or at least current with, advancing technology. Where did it all begin?

BACKGROUND

It may be speculated that education began with the drilling of the Drake well in Titusville, Pennsylvania, or possibly before this date. A sizeable patent literature existed prior to 1900. Uhl(1) points out that by the early 1900's, engineers and geologists were transmitting to their apprentices, through articles and through informal courses and study groups, the knowledge gleaned from the actual drilling for and the production of oil and gas. Early AIME and USGS publications became the main recorders of such activities. In 1910, the University of Pittsburgh established the first formal curriculum to satisfy, in part, the growing technical needs of the oil industry. The first petroleum engineering degrees were granted in 1915. By, June of 1970, approximately 15,000 petroleum engineers will have graduated from the 27 universities and colleges with petroleum programs in the United States. These graduates have come from and returned to serve most of the oil-producing countries of the world.
Unit Equity Determination
Authors: Tetreau E.M. , Roberts L.E.
Published: March 2010

Where unitization takes place early in a pool's life, it is considered critical that the evaluations determining participating equity be carried out quickly and accurately, Comprehensive study of the inter-relationship of all of the known variables, or commonly called unitization parameters, for a large number of land tracts with a wide variance of parameters has in the past been unwieldy and impractical. In order to assess accurately- the impact of these unitization parameters, a computer program was developed to calculate future performance and tract value. The example used in this illustration happens to the for a unit project in the Province of Alberta, but the principle and procedures can be adapted to any project where contributory values of the tracts involved need to be assessed. The pro-gram includes the following features:Pool allowable forecast as a time function.Distribution of pool allowables on an acreage basis, together with redistribution of individual tract's incapability to the remaining capable wells.Crude oil price as a function of time.Present worth at several discount rates.Individual tract's reserves and allowable acreage.Individual tract's initial producing capacity start of decline, type of decline (constant percentage harmonic or hyperbolic) and abandonment rate.Operating costs and expenditure scheduling.Complete print-out of tract performance over 50 years.Each company's participation equity at each discount rate.

The adaptability of the program has been demonstrated by the virtual fieldwide unitization of the Nipisi Gilwood pool in Alberta. Here, twenty of the twenty-one operators with both wholly owned and joint interests in various parts of the pool, and under a system which grants equal allowables to all productive acreage, were able to agree despite major variances in their parameters.

It is no longer necessary then to rely on previously established unitization weighting patterns of various parameters to establish unit equities.

INTRODUCTION

IMPLEMENTATION of Alberta's reserve proration system in May, 1968 necessitated a review of both the parameters and their proper weighting in unitization studies. Where in the past each pool was typically developed to the same density, the regulations now in force permit spacing to range from 160 to 1,440 acres. Although the allowable within a pool remains distributed on validated acreage the proration system is now designed to transfer individual well in capabilities back to the pool's remaining capable wells. The situation is further complicated in that owners of tracts with wide spacing have the opportunity of infill drilling for productivity to a density of IGO acres/well.

Shortly after the new system was announced, it became evident that the earlier practice of arbitrarily weighting allowable rate and reserves wasn't answering such fundamental questions as:What is the effective impact of allowable redistribution within the pool?What effective weighting should be given to rate under the new proration system?Who should be responsible for infill drilling investments?
Stimulation of Thick Mississippian Carbonate Sections In Foothill Wells
Authors: Nielson G.W.
Published: March 2010

This paper will review the development of the Quirk Creek gas field and the techniques used to drill, complete and stimulate the comparatively thick heterogeneous Mississippian sections found in the earlier wells. It will discuss the disappointing results obtained from these conventional stimulation treatments, and describe in detail the systematic efforts subsequently made to improve the deliverabilities of individual wells by selective and largeyo1ume acid-fracturing treatments.

Introduction

IN JUNE 1967, the first Quirk Creek well was spudded by Columbian Northland on a farm-in from Imperial Oil. In August 1967, the Missippian reef was penetrated and proved to be gas-bearing. Seven of the next eight wells also produced gas. This paper describes the original completions of the first four wells, and the remedial stimulation treatments subsequently used to increase their deliverabilities.

Description Of The Field

Quirk Creek is located 25 miles southwest of Calgary, near the north end of the Turner Valley Pool (Figure 1).

The current pool size is illustrated in Figure 2, which shows the eight potential gas wells and the one dry hole. The field boundaries are defined by a fault to the northeast and a gas/water contact to the southwest. This forms a banana-shaped structural trap, the ends of which are limited by both a gas/water contact and a tightening of the formation. The better wells are located near the center of the field, where the gas plant will be built.

The Mississippian reef is 600 feet thick and consists of massive limestone beds interspersed with dolomites. The porosity, ranging from that caused by very small vugs to minute inter crystalline porosity, is generally found in the dolomite. Some vertical fracturing has been noted in the cores.

The net pay varies in thickness between 125 and 175 feet, and is scattered throughout the reservoir in isolated stringers as shown in Figure S. These stringers range in thickness from 2 to 50 feet, with porosities of up to 19 per cent and an over-all average of 8 per cent over the productive intervals.

Low permeabilities characterize the reservoir. The average is 1.25 md, although individual streaks may reach as high as 100 md, The bottom-hole temperature at 120 °F is abnormally low the bottom-hole pressure is 2,200 psi. The average depth of the wells is 6,550 feet.

The gas is moderately rich in condensate, ranging from 9 to 11 barrels per MMcf of gas. The hydrogen sulpbide content ranges from 8 to 10 percent.

Original Completion And Stimulation Techniques

The completion techniques used in the first four wells – 6–5, 11–33, 10–28 and 11–11 – followed recognized gas-well completion practices and are summarized on Table 1. In most cases, the well bore was evacuated with nitrogen, then perforated with one or two holes in each permeable internal as determined from micrologs and core analyses. The total number of perforations per well varied from 36 to 88, depending on the total thickness of the pay and the number of porous stringers.
A Current Review of Forward Combustion
Authors: Flock D.L. , Dranchuk P.M.
Published: March 2010

In-situ combustion methods of oil recovery generally involve heat transfer with phase change and chemical reaction coupled with the hydrodynamics of multi-phase flow through porous media. To date, a vast amount of work has been carried out in this area and a. number of successful projects have been reported.

This paper examines only a portion of this field. It presents an over-all view of the forward combustion process by reviewing the results of some of the key experimental and theoretical studies and field tests.

Introduction

ALTHOUGH THE FORWARD COMBUSTION PROCESS may be described by means of an intricate ensemble of a number of individual physical and chemical processes, the over-all mechanism has been initially described simply as follows. The process is initiated by injecting air for a short period, so as to establish a continuous gas phase between the injecting- and producing wells. Once this is accomplished, heat is introduced into the injecting well so as to raise the temperature of the formation in the vicinity of the wellbore. When the formation temperature has been raised sufficiently, the formation oil, in vicinity of the wellbore, is ignited. As air injection continues, the burning gradually progresses from the injecting to the producing well When burning stabilizes, the process may be described by means of a series of zones, as is shown in Figure, 1. In short, this series consists of a? burned zone, a combustion front, a hot water zone, a light hydrocarbon zone, an oil bank and an original or unaltered zone.

At the Fifth World Petroleum Congress, Tadema(1). using the results of recent investigations(2), (3), (4) proposed a more detailed representation of the over-all mechanism, as is shown in Figure 2. In his representation, the series of zones consists of a burned zone, a combustion zone, a multiphase zone, a three-phase zone, an oil bank zone and an original zone. These zones contain air, coke, (steam, gases, hot water and light hydrocarbons). (gases, oil and water), (oil and gas) and original oil, respectively.

According to this model, the temperature distribution assume the shape of a heat wave and is characterized by a peak temperature in the combustion zone, a steep front followed by a steam plateau downstream, and a graduate decline upstream. In general, the heat-wave propagation velocity does not appear to be influenced b:v oil or rock type hut is directly related to air flux and oxygen content. That is as air flux and oxygen content are decreased the temperature profile tends to elongate.

The Combustion Zone

In the multiphase zone, crude oil is vaporized and cracked or carbonized to produce a residuum or coke deposit on the sand surface. This deposit serves as fuel in the combustion zone. Heat is then carried forward by convection by the water resulting from combustion, vaporized formation water hot gases and combustion products.

Generally the peak temperature in the combustion zone varies between 700 and 1,000 °F. Combustion itself is believed to occur in two steps.
Arctic Engineering For the Petroleum Industry
Authors: Hemstock R.A.
Published: March 2010

THE ARCTIC has been defined in a variety of ways by latitude or tree line, by isotherm or permafrost. For this paper, it will be considered simply as that part of Canada lying north of the 60th parallel. Most of what is discussed here will apply specifically to the sedimentary basin, the prospective oil country bring in the Northwest Territories; other countries, however, also have very prospective arctic areas, and many of their problems will be similar (Figure 1).

Long before the current surge of interest in the north, major construction projects had been successfully undertaken in arctic Canada. One of the most outstanding was a railway from Skagway to Whitehorse: built seventy years ago, it is still hauling freight and is an important part of the transportation system supplying the Yukon Territory. In northern Manitoba, the Churchill railway was begun in 1910, through most difficult permafrost conditions. War halted construction for a time, but the line was completed in the late nineteen twenties. Since then we have had various hydropower developments, the construction of major transmission lines and, in the military field, the Early Warning system and the DEW line. The oil industry development along the Mackenzie was started over 50 years ago, and an outstanding achievement during the war years was the construction of some 660 miles of pipeline from Norman Wells to Whitehorse. These represent only a few of the major construction projects on which, over the past several decades, nearly five billion dollars has been spent.

The engineering problems discussed here will be those that are unique to the north. They include climate, permafrost, ice and snow, terrain, and remoteness. Although these problems are not new to Canadian engineers, when they have to be faced together they call for new approaches to the engineering development of large-scale oil and gas reserves. To add to the challenge, these developments are going on at a time when everyone is aware of "ecology" and "pollution" as matters of grave public concern. Development of northern Canada will go on, but every effort must be made to establish a proper balance between resource development and environmental protection. This paper will outline our present state of the art and suggest some new approaches to work that will be required.

Climate

We share our Canadian arctic climate with Russia, Alaska and the Scandinavian countries (Figure 2). In winter it features intense cold, high winds and darkness, in summer long hours of daylight and very little precipitation – so that without the permafrost, the Canadian arctic would be largely a desert. Although we have most of the know-how to be able to design equipment suitable for these conditions, very often what is available has been made for warmer climates and simply moved north for its useful life. We should not be surprised, then, if it performs badly, or fails from such causes as brittle fracture of steel.
A New Era In Supervisory Control
Authors: Niven Robert D.
Published: March 2010

Supervisory control technology has; entered a new phase of development and application. Swept along by the explosive development in integrated circuit technology, minicomputers high-speed I/O devices and long-distance data communication, supervisory control has reached a level of reliability and sophistication whereby it can perform previously unthought-of tasks. Couple this rapid development with the fact that supervisory control is about to cross over into a new domain, the inaccessible and hostile environment of the North, and it is possible to foresee almost limitless applications in the future.

Recognizing the rapid technological growth and challenge of the North, supervisory control manufacturers, including the manufacturers of communications systems, flower steams and end devices, are looking into developing system hardware and concepts to meet this challenge. Because of the extremely high operating costs of production and transmission facilities in the North, and the ever-decreasing cost of supervisory control hardware, producing companies must start considering the use of supervisory control in their operations. They must further train their staff in the acceptance of supervisory concepts and in the operation and maintenance of the hardware.

The purpose of this paper is not to show "pie in the sky Concepts which may exist ten or fifteen years from now Its purpose is to bring- the engineer up-to-date in what has transpired in supervisor control over the last three years, what is available now and how modern concepts and hardware can be applied to supervisory system of the future - and the North.

Supervisory Control Brought Up-To-Date

THE term "Supervisory Control", as it is understood by the oil and gas industry, is the capability of having complete data monitoring and control of a remote system or systems from one central point. From the inception of supervisory control in the late 1800's, many thousands of designs have evolved to achieve this end, each with its own particular advantage and specific application.

Practically all the original development 'work on supervisory systems was carried out by the telephone companies. In fact, much of the early work was based on the telephone exchange installed in Laporte, Indiana, in 1892, by the Automatic Electric Co. Development work was carried on into the early 1900's, with the dial telephone becoming the first truly digital supervisory system. By dialing a number it was possible to ring a bell at some specified remote location. The next obvious step was to replace the bell with a relay to open and close it valve or start and stop a motor. This method of digital control, and methods which evolved from it, has been used extensively up to the present day in many industrial applications. However, its relatively slow speed and susceptibility to errors make it unacceptable in most modern-day applications.

Alarm monitoring, which is a fundamental feature of all supervisory systems, was first implemented in a system developed in 1921 by J. B. Harlow.