bluuebunny/crossref_metadata_2025_split huggingface dataset:
Control and Telemetering of Gas Producing Wells
Authors: Schwartz J.H. 
Published: March 2010

Abstract
Pressure gas wells present unique operating problems requiring constantclose supervision. When these wells are located in inaccessible areas, or wherea saving in manpower is desirable, remote central control and data collectingare advantageous.
Vessel pressure and temperature, wellhead temperature and pressure, dehydrator dew point, and high H2S content are but a few of thepossible trouble points that should be continuously monitored for safety ofboth personnel and equipment. Regular logging of flow rates, temperatures, analog variables and other critical functions serve the dual purpose ofefficiency of operation and elimination of wellhead charts.
Central control of wellhead flow rate and shut-down provides for a safe andreadily adjustable gas gathering system. Remote units should be designed sothat alarms are "fail safe," and automatic shutdown from critical failuresshould operate independently of the central unit. In areas where a corrosiveatmosphere is present, care should be taken to protect all electrical contactsfrom contamination.
A properly designed system will operate on a minimum number ofinter-connecting channels and for this purpose some method of coding isrequired. Since equipment in the field must operate under adverse conditionseven the most sophisticated equipment must be rugged and reliable. Centralcontrol systems are economically justifiable by savings in personnel, vehicles, accounting, and by the elimination of some costly pneumatic controls.

Introduction
The technique of central control and telemetering has been successfully usedfor many years by the petroleum refiner. In recent years, oil production hasalso benefitted by the use of remote supervisory systems. With the developmentof Western Canada's vast reserves of relatively inaccessible high pressure sournatural gas, a clear need has arisen for the application of complete automationto gas production. By the use of a combination of local alarm monitors, processcontrollers, telemetering, remote data logging, and control, a safer moreefficient operation can be obtained together with lower operating costs.
Turner Valley Limestone Oilfield Past, Present, Future
Authors: Paulson M.P. , Wahl J. 
Published: March 2010

Abstract
A review of the history of development of the field is presented along withthe production history over a 26-year period. The performance of the reservoirindicates that the major recovery mechanism has been a gas in solution driveaided to a small extent by down dip water intrusion and gravity drainage.Waterflood performance predictions, based on detailed study of the north end ofthe Turner Valley field will be presented. Water injection on the down dip edgeof the total field is in progress. Current results are difficult to evaluatebecause of relatively short period of injection and change in operatingconditions. The injection pattern and facilities are described. Potentialresponse areas are dealt with.
History

Introduction
The Turner Valley Limestone Oilfield is located 30 miles southwest of the City of Calgary, Alberta. It extends in a north-northwest direction from Lsd.16. Section 5, Township 18, Range 2, W.5M in the south to Lsd. 8, Section 24, Township 21, Range 3, W.5M in the north. The oil reservoir is 23 miles long andvaries in width from a half to one and one half miles. Production is obtainedfrom the Madison Paleozoic limestone. There is a gas cap associated with theoil reservoir.
Development and Production
The discovery well for the crude oil zone came into production on June 16,1936, almost 26 years ago. This well, "Turner Valley Royalties No. 1", wasdrilled in the southeast quarter of Lsd. 13, Section 26, Township 18, Range 2,W.5M, which was downdip from gas production in the limestone. Initialproduction was 960 barrels in 24 hours.
The development of the field progressed at a fairly constant rate over thenext ten-year period, during which 293 wells were drilled primarily on 40-acrespacing. The maximum number of completions in any one year was 42. A total of317 oil wells have been completed in the pool to date.
Voidage Calculations for Water Flood Schemes
Authors: Agnew G.H. 
Published: March 2010

Abstract
The calculation of several distinct physical quantities are sometimeslumped, and not without confusion, under the term "voidage calculations." Eachtype of voidage calculation, such as withdrawals at constant pressure or gasfilled volume, has its place in evaluating the performance of water floods. Thebasis of each is the material balance. The physical significance of the variousvoidage concepts and the application of the material balance in the estimationof reservoir pressure are examined in this paper.
It is shown that the common method of determining withdrawals, based on thesimple concept of a two-phase volume factor, while useful for demonstratingwhether or not reservoir pressure is being maintained, has limited value indetermining the overall status of a water flood. A new equation for determiningthe gas filled volume in a reservoir is presented. From it, a simple definitionof cumulative voidage is proposed. Suggestions are made regarding the use ofconventional reservoir fluid analyses. The estimation of reservoir pressure andcalculation of voidage are illustrated by examples.

Introduction
The word "voidage" or the phrase "voidage calculation" are rather looselydefined terms frequently used by engineers in connection with water-floodperformance. In one commonly used context, "voidage" is the volume that theproduced fluid occupies at reservoir conditions. An almost equally commonconcept of "voidage" is the amount of void or gas-filled space in a reservoir.In fact, these concepts are so intimately associated that it is sometimesincorrectly assumed that the production of one reservoir barrel of fluid, be itoil, gas or water, will result in a like increase in the void space in areservoir. Similar confusion can result from the misinterpretation of the term"net fill-up" which is in effect the opposite of "voidage."
The purpose of this paper is to examine the various concepts of voidage andto describe their application to the evaluation of flood performance. Emphasisis laid on material balance principles for development of the equations. A newequation for the calculation of the gas-filled volume in a reservoir ispresented and a voidage concept based on this equation is proposed.
A Method For Transporting Wet Natural Gas Utilizing Hot Water Tracing
Authors: Noyes H.D. , Towie N.R. 
Published: March 2010

Abstract
To transport wet natural gas through gathering or transmission systemsrequires either the removal of the free water phase, the use of hydrateinhibitors or alternatively the maintenance of the temperature throughout thesystem above the hydrate equilibrium temperature.
This paper describes an unique method of preventing hydrate formation usinghot water tracing of buried gas pipelines. The decision to utilize such asystem was made in consideration of circumstances peculiar to a particular gastransmission problem. The gathering system was to be installed in which theultimate design capacity would be one hundred million cubic feet per day of wetsour gas and yet, in the first one to two years of operation, the throughputwould be at forty percent of capacity. The use of heat rather than dehydrationappeared to be an economical method of preventing hydrate blockage, however theuse of conventional line heaters posed certain problems in a non-unitizedfield. The principal problem was that there were to be four wells connected toa thirteen mile trunk line and the competitive operation of the wells would notpermit cascaded operation. Consequently a situation existed where heat transferareas would be large and that mass transfer rates would be low. Preliminarydesign calculations indicated that as many as twenty-five conventional lineheaters would be required in a thirteen mile system in order to offset thisproblem.
A hot water tracing system was installed in the Wildcat Hills gas fieldduring the last three months of 1961. The system was placed into operation andat the time of preparation of this paper, it has been operated four months.While the initial performance of the system was exceedingly satisfactory, it isnot yet possible to compare design calculations with field observations for allranges of weather and soil moisture conditions. It is generally accepted thatany system using heat for hydrate prevention faces its crucial test during the Spring break-up period.
Some Practical Aspects of Interference Attenuation in Routine Seismic Exploration
Authors: Evans H. 
Published: March 2010

Abstract
An economic and a rather simplified scientific approach to the solution ofmore proper spacing of pattern holes and geophone arrays in the field isdiscussed. A method of recording and calculating the surface or apparent wavelength of interference waves is outlined. Several examples of actual fieldseismograms are included to illustrate the degree of interference attenuationthat can be obtained with a minimum amount of recording experimentation.
This paper is designed primarily to point out an economic and rathersimplified scientific approach to the solution of more proper spacing ofpattern holes and multiple geophone arrays in the field. The proceduresoutlined are not proposed as a "cure-all," but merely are intended to depict alogical sequence of steps which, in many instances, will yield at least apartial solution to the enhancement of the quality of seismic reflectionsignals.
Initially a few of the fundamental concepts of wave propagation should bereviewed. The word interference is defined as any unwanted signal generated atthe shot hole whereas noise is defined as any unwanted signal generated by someextraneous source such as wind, power lines, well pump, etc.
There are numerous types of interference such as Rayleigh waves, Love waves, ground roll, reflected refractions. Both the primary and the harmonic form ofthese various waves are frequently detected on or are suspected to be on thefield seismogram. This paper is primarily concerned with the attenuation of thetype of interference wave that travels from the shot through the weathered andsub-weathered near surface materials at velocities of 1000 to 8000/second andpossesses frequencies from 10 cps to 40 cps. The primary or fundamental lowfrequency wave can usually be cancelled by electrical filtering or, as in thecase of a strong low velocity surface wave, the employment of an in-line offsetspread removed sufficiently in distance to allow all reflection data to berecorded before the interference wave is recorded. However, in areas where thenear surface material possesses exceptional acoustic transmission properties(i.e. the ability to readily transmit most types of sound waves), the first, and even second harmonics of the low frequency interference waves aretransmitted through the near surface and are sufficiently strong in amplitudeto mask, or at least in part distort, the desired reflection signals.
Digital Computer Solution and Automatic Plotting of Acoustic Log Interpretations
Authors: Taylor W.H. , Kernahan G.M. 
Published: March 2010

Abstract
Defining the problem of reconciling or adjusting sonic derived velocities tothose velocities derived from seismic methods and programming the problem foran electronic digital computer is described. Prior to programming the sonic, preliminary planning to program and print-out the geophone survey results wascarried out. The use of stored computed geophone data, to assist in makingsonic computations manipulated by the sonic program, is explained.
An attempt has been made to illustrate the large quantity of data andcomputations handled while maintaining high quality of results andpresentation. The paper intends to be a guide to approaching problems ofsimilar complexity and traces out the stops and the solution of this particularproblem. It is not intended to explain in any way how the computer operates, except in very general terms, since this is a special field of study initself.
Since original presentation, the paper has been up-dated to present newtechniques now available through utilization of the Calcomp Incremental Digital Plotter.

Introduction
The handling of thousands of calculations involved in making severalinterpretations which may be derived from the acoustic log in conjunction witha geophone survey may be handled economic• ally and presented graphicallyutilizing the electronic digital computer and the incremental digital plotterrespectively. The calculations and interpretations may now be presented in anycombination of the following:
The presentations as outlined above in the seven separate processes may nowbe presented in a single continuous computer-plotter operation.
Coal vs. Natural Gas at Wabamun
Authors: Thompson G.H. 
Published: March 2010

Abstract
A brief history is given of Calgary Power Limited since the company startedsupplying power and energy in 1911 from its Horseshoe Falls Hydro Electric Plant. This paper deals primarily with the company's thermal plant on Lake Wabamun, which was designed to burn coal as fuel. However, while the Wabamun Steam Plant was still in the planning stage, the company was offered gasdelivery at 10½ c per million BTU's and in sufficient quantity to satisfygrowing requirements,.This gas supply was exhausted in 1961. The plant's thirdunit of 150,000 KW capacity will use coal for fuel. Comparative costs of usinggas and coal are outlined.
This paper deals with the use of natural gas and coal at the Wabamun Steam Plant of Calgary Power Ltd. The plant is located some 45 miles west of Edmontonon the Canadian National Railway main line.
First the manner in which the Company has been providing its power andenergy requirements over the years should be reviewed, since this has animportant bearing on the whole subject. The term "power" is used to denote therate of generation or use of electricity and is expressed in kilowatts (KW).The term "energy" is used to denote the quantity of electricity generated orused in any given period of time and is expressed in kilowatt hours (KWH)."Load factor" (L.F.) is an important term and is defined as the ratio of the KWH actually generated in a certain period of time to the KWH that could havebeen generated in the same period, had the units been operating continuously atfull load. Thus a 10,000 KW generator operating at full load, that is at 100%load factor, for one hour, will generate 10,000 KWH, but at 50% L.F. willgenerate only 5,000 KWH.
Imperial's Steelman Unit Ia and II Waterflood System
Authors: Stevenson D.W. 
Published: March 2010

Abstract
In January, 1962, full-scale water flooding began in the Steelman field ofsoutheastern Saskatchewan. The field has been developed on 80-acre spacing andthe injection pattern is an inverted nine-spot. The main requirements of theflood are a high quality water and flexibility in injection rates andpressures. To accomplish these ends water from the high capacity Blairmore sandis distributed to the injection plants, where it is filtered andinhibitor-treated, before injection into high pressure lines radiating to theinjection wells. The pressure and rate of injection to each well is controlledat the injection plant. Plant operation is semi-automatic and source wellpumps, filters, engines and injection pumps are protected by safety controls.Corrosion throughout the injection system is controlled through coatings andinhibitor and bacteriacide injection.
The design of the injection system was influenced by the results of a pilotoperation which commenced in 1958. The use of dry gas engines and diatomaceousearth filters are some of the design improvements derived from pilotexperience. This presentation discusses the design of surface facilities forthe water floods in Steelman Units IA and II, which were installed by ImperialOil Limited in 1961.

Introduction
The Steelman field is on the northern rim of the Williston Basin insoutheast Saskatchewan, approximately 15 miles north of the InternationalBoundary (Figure 1).The reservoir, at an average depth of 4,700 ft., isa stratigraphic trap of Mississippian limestone known locally as the MidaleBeds. The zone is thin and heterogeneous with low permeability. To date, 760wells have been drilled on 80-acre spacing. Recovery has been estimated at 16per cent under natural depletion and 35 per cent under water flooding.
The Demand for Canadian Crude and Natural Gas Liquids, 1962-1967
Authors: Lounsbury J.P. 
Published: March 2010

Abstract
Since 1956 a high degree of correlation has been evident between thecyclical growth of the Canadian economy and the total demand for petroleumproducts in Canada. The author develops assumptions as to the rates of growthwhich can be expected for the Canadian economy over the next five years and, onthe basis of these assumptions, forecasts a demand for petroleum products in Canada for 1967 of about 1,175 Mb/d (thousand barrels per day). Thiscorresponds to a rate of growth in product demand of about 4.5 percentcompounded annually. Since some three-fifths of this product market fallswithin that area west of the Ottawa Valley which has been reserved to Canadiancrude and natural gas liquids under the terms of the National Oil Policy, Canadian producers can expect to market nearly 675 Mb/d in Canada by 1967. Theexport market, now beginning to be influenced by slower growth rates in thePacific Northwest and by informal quotas in U.S. markets east of the Rockies, should nevertheless provide outlets for about 325 Mb/d in 1967. Thus totalCanadian production of crude oil and natural gas liquids five years henceshould reach close to 1,000 Mb/d, a gain of 35 per cent over estimated outputin 1962. Alberta's production, influenced in the short run by developments inBritish Columbia should by 1967 still account for about two-thirds of totalCanadian output. If Alberta's production is to grow at rates faster than thosedetermined by the now relatively mature Canadian energy market, it must do soas a result of greatly enlarged export markets. Even if export markets developat no faster rates than those forecast by the author, larger new additions toreserves will have to be developed over the next five years than have beendeveloped over the last five.
The Windfall Field Cycling Project
Authors: Wichert E. 
Published: March 2010

Abstract
Gas and condensate are produced from the Windfall reservoir and delivered tothe Windfall Gas Plant. The gas, containing 14% hydrogen sulphide and 5% carbondioxide, is sweetened and sold to the Alberta and Southern Gas Company, withthe hydrogen sulphide being converted to elemental sulphur. The condensate isstabilized and delivered into the Peace River Pipeline Company pipeline goingfrom Fox Creek to Edmonton. Gas is also produced from the Pine
Creek field, dehydrated and delivered through a 14-inch transmission line tothe Windfall Gas Plant. Here the Pine Creek gas is compressed and injectedthrough four wells into the Windfall reservoir to maintain the reservoirpressure. The Pine Creek gas contains 26% hydrogen sulphide and 6% carbondioxide. By means of this pressure maintenance cycling scheme, maximum liquidhydrocarbon recovery will be achieved and the processing of the Pine Creek gaswith its larger hydrogen sulphide content will be delayed by several years.

Introduction
The Windfall field is located approximately 20 miles west of Whitecourt, Alberta, which is approximately 110 miles northwest of Edmonton. The field isin part of a large number of lease blocks owned by Hudson's Bay Oil and GasCompany, Pan American Petroleum Corporation and Canadian Fina Oil. Also locatedwithin these lease blocks are two more gas fields approximately 23 miles to thesouthwest of the Windfall field, namely the Pine Creek and Beaver Creek fields.The exploitation program of these fields is called the West Whitecourt Projectby the owners and each of the owners is an operator of a certain phase of theproject: Hudson's Bay Oil and Gas Company operates the Pine Creek and BeaverCreek fields and a transmission line from Pine Creek to Windfall; Pan AmericanPetroleum Corporation operates the Windfall Gas Processing Plant and CanadianFina Oil operates the production and injection facilities in the Windfallfield.
Economics of Marketing Small Gas Reserves
Authors: Wickens L.I. 
Published: March 2010

Abstract
One of the most difficult and frustrating situations that exists today inthe exploration for oil and gas is the marketing of small gas reserves. Inrecent years, operators in Alberta and British Columbia exploited the exportfield to market the larger established reserves. Most of the subsequentdevelopment was conducted in close proximity to these reserves leaving manyprospects undeveloped. The problem of marketing the smaller reserves must andwill remain the major deterrent to development. This will no doubt be solvedbut only if operators diligently weigh the economics of each situation andendeavour to improve their position.
During the extensive search for oil and natural gas in Western Canada, manyof the wells discovered were classified as potential gas wells. Some of thesewells have been completed and tested and others were abandoned. Theinterpretation of the information collected from these wells must be used todetermine future development. The prevailing marketing conditions will controlthe future development of each prospect and, as circumstances alter in themarket situation, the economics of the proposed development must be reviewedand adjusted.
There are several factors which contribute to the classification of a well apotential gas producer. Since each company, engineer, or geologist evaluateslogging, testing and geological information differently, the evaluation of agiven well may vary widely. The interpretation of the well data willdetermine the value of the prospect. This information must be weighed in itsproper perspective and should be supported by as much supplementary data aspossible. Frequently, the operator found it impossible to get additionalinformation as the forseeable markets make further testing uneconomical. Thismay have been the case at the time of discovery and undoubtedly would determinethe type of completion used.
Measurement Problems in Gas Plant Operations
Authors: Cullen G.R. 
Published: March 2010

Introduction
In September, 1962, the gas processing plant owned by Edmonton Liquid Gas, located on the southern outskirts of the City of Edmonton, started processinggas delivered to it by Northwestern Utilities for the removal of hydrocarbonliquids. The plant was originally designed to handle 50 MMcf/D of gas coming toEdmonton from the Pembina field and another 20 MMcf/D from the Texaco plant atBonnie Glen. These gas streams were to remain segregated, so two separateabsorption towers were required for processing. The Pembina unit was to operateat 650 psig and the Bonnie Glen at 450 psig. The residue gas was to be returnedto the Northwestern Utilities transmission line system. The reduction in gasvolume through the extraction of approximately 48,000 gal/D of liquid productswas estimated at 3.6% of the inlet gas volume. Payment was to be made for thisreduction on a therm basis.
Normally, gas plants of this nature are either subsidiaries of production ortransmission companies or part of an integrated system. As such, anydiscrepancies in a plant balance between the gas shrinkage and the extractedproducts are of no great consequence and can be taken care of in the accountingprocedures. However, in this case with separate ownership of the two companies, metering becomes a major problem to determine an accurate value of the productsextracted or used. The measurement in the reduction of gas volume cannot beused because the inherent inaccuracies in gas orifice metering are too greatfor this purpose. Measurement of the liquid products with positive displacementmeters would be the basis for billing. Gas measurement would be done only forthe purpose of obtaining plant balances.
Prior to the selection and installation of the gas measurement equipment, asurvey was made of gas plants operating under similar circumstances in bothCanada and U.S.to determine their experiences and practices.