bluuebunny/crossref_metadata_2025 huggingface dataset:
A Rapid Approximate Method for the Estimation of Hydrocarbon Dew Points of Clean Pipeline Natural Gases
Authors: Aziz K. , Govier G.W.
Published: March 2010

A "theoretical" correlation of the effect of pressure on the hydrocarbon dewpoint temperature of clean pipeline gases is presented. The correlation wasdeveloped from calculated dew point data on thirteen gas analyses from ten gasfields in Alberta. The dew points were calculated by conventional trial anderror method and NGAA equilibrium ratio charts. The data are correlated bymeans of a wetness parameter based on the amounts of propane and heaviercomponents in the gas and equilibrium ratios for those components atarbitrarily selected conditions.

The correlation allows the quick estimation of the hydrocarbon dew points ofclean pipeline gases without the usual trial and error procedure. For moreaccurate results the dew points calculated from this correlation may be used asthe first estimate in the conventional trial and error calculations. Thecalculated dew points are usually within +4°F of the results from conventionalcalculations over the normal range of pipeline operating pressure and, forpipeline natural gases free of contaminants, such as glycol or compressor oil, are within about the same limits when compared with measured dew points.

The correlation does not apply to the prediction of dew point temperaturesfor pipeline gases containing even small quantities of alcohol, glycol orcompressor oil.

Introduction

Pipeline natural gases, which are composed mainly of a mixture of paraffinhydrocarbon gases, nitrogen, carbon dioxide and water vapor, normally exhibittwo kinds of dew points. These are hydrocarbon dew points and water dewpoints.

The dew point is the temperature, at a certain pressure, at which the firstdrop of liquid is formed or is just about to form. In the case of water dewpoints, the liquid formed is water and in the case of hydrocarbon dew pointsthe liquid formed is a mixture of the hydrocarbons contained in the gas. If apipeline gas, as a result of processing, contains contaminants such as glycol, a third type of dew points may also be observed. The liquid formed in this casewill be a mixture of hydrocarbons and the contaminant. Because of the higherboiling point of the contaminant, the presence of this component in the gaswould raise the dew point temperature. Small amounts of nitrogen, carbondioxide and other non-hydrocarbon constituents may also be present in the dewformed, depending upon the concentration of these components.
Petrogas Processing Calgary Plant
Authors: Manley H.W. , Lewis G.H.
Published: March 2010

Thirty Corporate Oil &Gas Working Owners in the Calgary Gas Fieldsbecame shareholders of Petrogas Processing Ltd. for the purpose of establishinggas plant processing facilities to process their combined gas reserves of inexcess of 1500 billion cu. ft. Jefferson Lake Petrochemicals has been appointedthe Operator of the Petrogas Plant Facilities.

This $13,000,000 Plant facility consists of some 135 miles of field pipeline systems; a gas purification section design for 150 million cu. ft./daycapacity utilizing the Hot Potassium and Conventional Amine treating processes;a modified Claus process to produce 875 long tons/day of elemental sulphur; aconventional refrigeration unit for 125 million cu. ft./day of pipe line gasdelivery to meet water and hydrocarbon dewpoint specification; and, a 2200bbl./day liquid condensate stabilization unit.

The combined plant inlet gas streams have approximately 24% acid gas, or 16%hydrogen sulphide and 8% carbon dioxide. The use of the Hot Potassium gaspurification section is proving very satisfactory for extracting a large partof the acid gas having this ratio of acid gas volumes. The plant design hasresulted in lower capital costs, less gas fuel consumption and comparativelylittle chemical losses as compared to other gas processing plant designs in Canada.

Glycol pipe line delivery and gathering systems to and from each wellheadfor gas dehydration in the fields is used whereby central plant regeneration ofthe glycol can be obtained. This type of functional design will reducecorrosion in the gas gathering systems and prevents excessive gas hydratesoccurring at the 1200 psia gas gathering pressures. With the Crossfield gasfield now having proved 81.4 square miles and the Elkton gas field havingproved 47.7 square miles of productive area, the field gas dehydration designcapital cost has proved to be comparatively low for the five Elkton gas wellsand eight Crossfield wells now connected to the Plant. As additional gasproducing wells are completed in these large fields, the unit cost/wellheaddehydration will continue to be reduced.
Prediction of Miscibility
Authors: Adamson J.A. , Flock D.L.
Published: March 2010

Recent studies of the mechanisms involved when a reservoir fluid isdisplaced miscibly by a light hydrocarbon mixture have resulted in thedevelopment of theoretical methods to predict the approximate conditionsnecessary in order that miscibility may occur. One of these methods employs theuse of a pseudo-ternary diagram and requires the calculations of the criticaltemperature and pressure of both the displacing and displaced phases.

Preliminary and theoretical studies have been conducted in an attempt toverify the theoretical considerations involved in this particular method aswell as to modify the procedure by employing newer means of calculatingcritical conditions.

In conjunction with this study a unique method of recording pressureprofiles as a function of time during an actual miscible displacement has beendevised. This paper presents and discusses some of the results obtained in thisproject.

Introduction

Miscible displacement of reservoir oil depends upon the formation of agraded saturation bank between the original oil in place and the injecteddisplacing fluid. This bank is all in a single phase with no interfaces presentand therefore they are no capillary forces to cause the oil to be retained inpore channels as residual oil. This situation can be achieved by employing oneor more different methods; namely solvent flooding, LPG slug process, highpressure gas drive or condensing gas drive.

Three of the factors which influence the efficiency of miscible drives arethe reservoir temperature and pressure and the composition of the injectedfluid. A certain pressure for a given temperature must prevail to maintainmiscible conditions between oil and injected fluid. Proper requirements forpressure control of the reservoir must therefore be known in advance ofcommencement of a project for properly controlled miscible drive operations.The intermediate composition of the injected gas must also be controlled suchthat the composition will be a critical one and miscible drive can beachieved.
Water Analysis Data: Interpretation and Applications
Authors: Noad D.F.
Published: March 2010

The value of water analysis data in petroleum exploration and production iswidely recognized. Water analyses have proven useful in water productionproblems, in the correlation of stratigraphic units and of the aquifers withinthese units, and in the study of the movement of subsurface waters.

A large volume of water analysis data is available for the Western Canada Sedimentary Basin. Maximum benefits may be derived from these data through thecareful selection of analyses that represent most accurately the chemicalcomposition of the subsurface waters.

Various graphical methods have been devised for presenting the chemicalanalysis of a water. Graphical diagrams are particularly useful in comparingwater analyses.

Isoconcentration maps provide information essential for the study of thechemical and physical behaviour of formation waters. Furthermore, these mapsprovide information that can be converted readily to water resistivitydata.

Studies of the chemistry of formation waters, carried out in conjunctionwith studies of the geologic framework wherein the waters reside, can be mosteffective in the solution of local and regional problems.

Introduction

Subsurface water is a generally unwanted commodity found during the searchfor, and exploitation of, oil and gas reserves. Because subsurface water oftencontains a large amount of dissolved salts, it is unsuitable for domesticpurposes. By virtue of the dissolved salts and of certain gases held insolution, this water is a powerful chemical agent capable of corroding themetal in well equipment. Yet the very presence of these salts and gases makeswater analysis useful in certain exploration and production problems.

In addition to discussing the interpretation and applications of wateranalysis data, this paper discusses sampling procedure and analyticaltechniques. Proper campling and analytical methods are requisites to obtainingmaximum information on subsurface waters. This means ensuring that the samplesclosely represent the formation waters and that the chemical analyses provideadequate data for both present and future requirements.
Summary of a Report on Gas Flow Measurement
Authors: - -
Published: March 2010

A study group was formed in February, 1961 by the CIM-AIME, Edmonton Section, to consider gas measurement problems encountered by the oil and gasproduction industry in Alberta. The prime purpose of the group was toco-ordinate the efforts of all those working on the problem and to provide aforum for the exchange of opinions, ideas and field results.

Sixteen organizations were represented at the inaugural meeting. Theseorganizations included oil and gas producers, gas transmission and gas utilityoperators, the University of Alberta and the Oil and Gas ConservationBoard.

The objectives of the group were:To review all methods of gas flow measurement suitable for use in the oiland gas industry.To evaluate the instruments employing these methods.To determine who has tested and/or accepted these instruments.To determine the accuracy and dependability of these instruments underspecified conditions.To determine the relative economies of the use of these instruments.To draw up a list of criteria which could be used for determining thesuitability of methods and instruments for gas flow measurement.

To achieve these objectives, four committees were formed to investigate thefollowing:Orifice metersPositive displacement metersMass flow metersOther methods of gas flow measurement.

The material prepared by these committees forms the basis of thisreport.

After a general introduction to the basic theory and principles of gasmeasurement, the report details all of the methods which may be applied to gasmeasurement. There are twenty-six different methods considered under thefollowing six general headings:Differential head metersVariable area metersVelocity flow metersMass flow metersPositive displacement metersMiscellaneous meters
Well-Bore Notching and Hydraulic Fracturing
Authors: Strain H.J.
Published: March 2010

Several advanced procedures for planning hydraulic fracturing treatmentswere introduced by research engineers during 1957 and 1958. Fracturing with thesingle-plane entry technique was one promising new concept. With this techniquethe well-bore is prepared at a selected point using a hydraulic or a mechanicalnotching tool. The well is then fractured with a treatment designed to generatea single, large-areal-extent fracture. A partial monolayer of large-sizepropping agent is distributed in the fracture to give high-flow capacity afterthe treatment. An experimental program was conducted in the Pincher Creek, Steelman and Pembina fields during 1959 and 1960 to evaluate single-plane-entryfracturing. It was found that the technique could not be indiscriminantlyapplied to every reservoir. Interference from natural vertical fracture systemswas a problem. However, when reservoir conditions were favorable, the resultsindicated that wells fractured with the single- plane entry technique havehigher and more sustained productivity than those fractured by conventionalmethods.

Introduction

Significant technological advances in the science of hydraulic fracturingwere made by research engineers during 1957 and 1958. These were received withconsiderable interest by the Canadian oil and gas industry. In particular, theconcept of a single, high-flow-capacity fracture held promise for many areas.An experimental program was carried out by The British American Oil Company Limited during 1959 and 1960 to evaluate some of the new fracturing theories.Fracturing with the single-plane entry technique was first attempted in Canadaat a gas well in the Pincher Creek field.

Another proving ground for this type of fracturing were poor-productivitywells along the north side of the Steelman field. Rapid decline in productionrate after normal acid completion treatment was characteristic of wells in thisarea. Conventional sandfracturing had been tried with no success. In an effortto overcome the problem and work out a superior completion method, single-plane-entry fracturing treatments were performed on nine edge wellsduring the latter part of 1959 and in early 1960. An abrasive jetting tool anda mechanical under-reamer were evaluated as a means of notching the well-bore.Partial-monolayer and multilayer fracturing treatments were tried inconjunction with the single entry. Production data from these nine experimentalwells and from offsetting conventionally completed wells are compared toevaluate the usefulness of the single-plane entry technique and thepartial-monolayer propping theory.
Allowables and Allowances
Authors: Lee C.S.
Published: March 2010

Introduction

The problem of proration to market demand has always been highlycontroversial. Because another hearing is to be held on November 5th, 1963 -the last one of importance was in 1961 - this review is an attempt to compile arepresentative bibliography and to present the issues for debate which havearisen in the past and those which can be anticipated in the future. From thispoint of view, it is hoped that it will provide some background and avoid someduplication of research for those who propose to take an interest in thesecoming hearings. Whether from the standpoint of equity or of economics orfurther development and investment, these hearings will be vital to the futureof the oil industry in Alberta. No recent hearing has been more important.

This paper does notrepresent the views of any group and does notpurport to offer any solution. The writer reserves the right to advocate orjoin in advocating such solutions as may be considered appropriate at the timeof the hearing.

Historical

The competence and jurisdiction of the Oil and Gas Conservation Board of theGovernment of the Province of Alberta in the matter of proration of crude oilto market demand does not call for any lengthy discussion. It is contained inSection 36 (1) of the Oil and Gas Conservation Act, which, amongst otherthings, states that each owner should have an opportunity of obtaining his justand equitable share of the production of any pool.

Until 1949 the Oil and Gas Conservation Board set certain standards, in anattempt to preserve good engineering practices, of so-called "maximumproduction" (2). However, following the discovery of Redwater, the provincialproducing potential on this "maximum production" basis grew to a figure which, by 1950, exceeded the available demand by a wide margin. Nearly all the demandat that time was in Alberta.
How to Keep Tubing Sealed in Packers
Authors: Logan J.L.
Published: March 2010

In many oil, gas, and injection wells. a string of tubing, sealed at itslower end in a packer, is used to isolate tubing pressures and fluids from thecasing. In multiple completions, two or more tubing strings are used to isolatezones. This paper presents a means of determining the best way to initiallyland the tubing in the packer to compensate for future anticipated wellconditions.

The equations in this paper were developed in a previous publication andhave been successfully applied to over fifty critical wells in the UnitedStates, Canada, and Europe. Many of these were deep, high-pressure, high-temperature, high-cost wells in which it was imperative that atubing-to-packer seal be maintained during all completion, remedial. andproducing operations. In some of these wells, it was important to keep thetubing as straight as possible to facilitate future wire line work.

The conditions of these wells have been grouped and tabulated so the readercan see some of the practical applications of the paper.

Introduction

The bottom of a string of unanchored tubing in a rod-pumped well moves up onthe upstroke and down on the downstroke. In addition, the tubing graduallyelongates until the well reaches pumping equilibrium. Disregardingrod-to-tubing friction, vertical movement is caused by pressure and temperaturechanges acting on the entire tubing string. Knowing tubing and casing size, initial and final fluid densities and levels, and initial and final tubingtemperature, it is possible to calculate the extent of these verticalmovements.

Rod-pumped wells are generally familiar to the reader and are mentioned herebecause the freely hanging tubing string reacts in exactly the same manner tochanges in well conditions as does a string of tubing sealed, at its lower end, in a packer which permits free seal movement. A packer, however, may be setmuch deeper than a pump, and not only is a longer string of tubing exposed tothese changes but the changes may also be much more severe. Consequently, theamount of vertical movement is usually much greater.
Geochemical Studies of Natural Gas Part I. Hydrocarbons in Western Canadian Natural Gases
Authors: Hitchon Brian
Published: March 2010

Natural gases in Western Canada are found in sediments ranging in age fromCambrian to Tertiary. The hydrocarbons in these gases are described andevaluated in terms of their geochemistry, origin, migration andaccumulation.

Hydrocarbons are the chief components in the majority of the nearly 3,000analyses of natural gases from Western Canada. Most gases contain more than 90per cent hydrocarbons, but as little as 0.26 per cent is present in some. Thepreferred order of abundance of the individual hydrocarbons is methane >ethane > propane >n- butane >isobutene >isopentane > n-pentane > hexanes > heptanes. A decreasingn-butane:isobutane ratio is accompanied by an approach to unity of theisopentane :n-pentane ratio. Study of the C4 andC5 isomers indicates that no reservoirs are in thermodynamicequilibrium. Variations in the C4 and C5isomer ratiosare attributed to catalysis by the sediments.

Methane probably originates due to direct synthesis by bacteria, although itis also a by-product of biochemical reactions that are able to generatehydrocarbons with from two to ten carbon atoms. These reactions includelow-temperature decarboxylation and reductive deamination of amino acids anddecarboxylation of fatty acids. The part played by bacteria in these reactionsis probably important, although the mechanism is not known with any degree ofcertainty.

Natural gases with relatively low contents of methane and high contents ofheavy hydrocarbons are found in sediments deposited in basinal environments. Insediments deposited in shelf environments the natural gases have highercontents of methane and lower contents of the heavy hydrocarbons. Forpre-Cretaceous strata in Western Canada, the depositional basins approximatelycoincide with the present structural basin, and fluid flow is updip. ForCretaceous strata, sediments in the structural basin contain natural gases withrelatively low contents of methane except where modification due to downdipfluid-flow has occurred. Possible mechanisms inducing modification of theregional variations include undersaturation of the formation water with naturalgas at present reservoir temperatures and pressures, and variations in thesolubilities of the hydrocarbons due to changes in flow direction and movementinto regions with formation waters of different salinites.
A Reservoir Study of the Sturgeon Lake South D-3 Pool
Authors: McKibbon J.H. , Paxman D.S. , Havlena D.
Published: March 2010

This study illustrates the use of the expanded material balance to determinethe volume of oil originally in place and to define the aquifer system.

The expanded material balance, which incorporates an unsteady-state waterinflux term, contains two explicit and several implicit unknowns. The solutionof such a material balance is accomplished by algebraically rearranging theterms to define the equation of a straight line. Such a straight-line conceptis then used to define the various unknowns. Both linear and radial aquiferconfigurations are considered and the acceptability of the results arestatistically tested.

Due to the installation and subsequent extension of a gas gathering systemin the field, there have been two major changes in the field separatorpressure. These variations in separator pressure are accounted for in thecalculations.

The study concludes that the performance of the Sturgeon Lake South D-3pool, to date, has been consistent with a radial aquifer system which has notyet felt boundary effects. The volume of oil originally in place as determinedin this paper is in excellent agreement with the volumetric estimate.

Introduction

The Sturgeon Lake South field is situated some 160 miles northwest of theCity of Edmonton. Alberta. The D-3 pool the only productive horizon of anyconsequence in the field, was discovered in early 1953 with the drilling of thewell Amerada HB Union Crown "R" 5–19 (Lsd 5–19–69–22 W5). While sporadicdrilling in the field is continuing, development was substantially completed bythe end of 1957 when some 100 producing oil wells had been completed. There arecurrently 112 wells capable of oil production from this reservoir.

Several calculations have been performed in the past to establish avolumetric estimate of the original oil in place; however, due to limited wellcontrol in the southwestern part of the pool (see the attachedstructure-isopach map of Figure1), and a controversy concerning theconnate water saturation, the volumetric estimates for this reservoir haveshown a wide variation in values. These differences in the volumetric estimatesprompted the present detailed investigation.
Geochemical Studies of Natural Gas Part II. Acid Gases in Western Canadian Natural Gases
Authors: Hitchon Brian
Published: March 2010

Hydrogen sulphide is of interest as an economic source of sulphur, fromconsideration of corrosion problems, as a health hazard, and as a geochemicalguide. It forms an essential link in the cycle of sulphur, it occurs widely innature, and, with carbon dioxide, is a byproduct of the bacterial reduction ofsulphates. The close association with low contents of dissolved sulphate information waters, and with the presence of sulphate-reducing bacteria in someoil-field waters, is consistent with a biogenic origin for these two componentsin the bulk of natural gases. The few exceptions (natural gases with commonlyless than five per cent hydrocarbons, no hydrogen sulphide and consistingpredominantly of carbon dioxide) probably owe their origin to metamorphism ofbituminous carbonates.

The contents of both hydrogen sulphide and carbon dioxide in natural gasesfrom Western Canada vary regionally, although the trend patterns are not alwayssimilar. In some stratigraphic units hydrogen sulphide probably has beenremoved from the aqueous system through reaction with iron in solution and thesubsequent precipitation of pyrite. In other units, oxidation of crude oils mayhave relatively increased the content of carbon dioxide in the natural gases.In spite of the probable operation of these phenomena, the major factorcontrolling the content of hydrogen sulphide and carbon dioxide in naturalgases is the environment of deposition of the sediments, a view that is inaccord with a biogenic origin for both acid gases.

Introduction

This paper is the second of a series concerned with the geochemistry ofnatural gas in Western Canada. It discusses the acid gases hydrogen sulphideand carbon dioxide. The first paper dealt with the hydrocarbons and the thirdpart will treat the inert gases.
Developments in Oil and Natural Gas Production Southwestern Ontario
Authors: Oakley K.A.
Published: March 2010

Southwestern Ontario's oil and gas industry has had its fluctuations overthe past 100 years. At present oil production is in an extended maximum cycleand gas production is trending downward from a maximum cycle. Trends forecastinclude secondary-recovery and pressure-maintenance projects in Devonian andSilurian reservoirs, declining gas production through depletion of pinnaclereefs, and a stepped-up Cambrian exploration programme to find more fields likeClearville and Gobles.

Introduction

The history of the oil and gas industry in southwestern Ontario stretchesback over more than 100 years. During this time, the production of both oil andgas has passed through several very severe cycles, until today oil productionis enjoying an extended maximum cycle while gas production appears to betrending downward from a maximum cycle. This paper presents a brief look at thepast, a review of present conditions and a forecast of possible futuretrends.

It was in 1857 that James Miller Williams found petroleum in quantitiessufficient to warrant setting up refining equipment at Ennis-killen. Thecommercial production of oil has been going on ever since. Gas production datesback to the discovery of the Kingsville, Haldimand and Welland fields in thelate 1880's. After all this time - 100 years since the first crude was producedand 75 years since the first gas- one might well ask what there couldbe left to say about such a long-established industry that would bear on thesituation today. Nevertheless, a brief survey of developments in southwesternOntario since the beginning may help to place recent events in their properperspective.
Athabasca's Place in the Future
Authors: Spragins F.K.
Published: March 2010

A general survey of Western Canada's oil industry from 1778 to the presentsuggests that development of the Athabasca oil sands will play a prominent partin sustaining Alberta's key position in the national energy picture.

The First Oil Men

Oil development in Western Canada has had a long and sometimes weirdhistory. Many events from the past are now all but forgotten, but there areothers which stand out as milestones in our struggle for world recognition as asignificant oil-producing area. Although the experiences and happenings thateach of us remembers may vary, every one of them has its place in ourindustry's colourful background.

Looking back in time, we must recognize that Canada's first oil men were theIndians who lived along the Athabasca river in 1778. Even then, nearly twohundred years ago, they realized the importance of this product that was allaround them, having found that a mixture of Athabasca bitumen and spruce-treegum made a fine compound for waterproofing canoes. History does not relatePeter Pond's experiences with Athabasca oil but, by the time AlexanderMackenzie relieved him in 1787, the oil men were ready for business. For asuitable amount of whisky, the Indian chief would provide Mackenzie with thebitumen he needed to caulk his canoes. I have often wondered how the Scotsmanreacted when he found the stuff he had been forced to buy was literally runningout of the banks in many places for over 100 miles along the Athabasca river!These spots he later described as "fountains of bitumen."

Early Beginnings

Despite this early "commercialization" however, Athabasca oil remainedrelatively unheeded until recent years. Instead, other major fields in manyareas were discovered and developed until Western Canada became established asone of the leading oil-and-gas-producing areas of the world. Let us take a lookat how this came about.
A Practical Approach to Gas Deliverability Predictions with the Use of an Electronic Digital Computer
Authors: Chernoff G.M.
Published: March 2010

This paper presents a method of estimating the physical deliverability ofgas at the wellhead from depletion-type gas reservoirs, prior and subsequent tothe years of declining production. A prediction programme suitable for amedium-sized digital computer is given. It utilizes measured wellhead pressuredeliverability and absolute open flow potential curves for a field-averagewell. The predictions show the length of time a field is capable of deliveringa specified constant daily volume of gas. In addition, for each predictionperiod, the average reservoir and wellhead pressures, the average maximumproduction capacity, the QMax as determined by the Alberta Oil and GasConservation Board formula, and the cumulative gas volumes produced arecalculated. The programme also takes into account field compression and/or thedrilling of additional wells when required.

Introduction

Reliable gas deliverability predictions are essential for economic forecastsof gas field performance. The calculation basically involves an adaption of thefamiliar equation in U.S.B.M. Monograph7, relating flow rate toreservoir pressure. The equation only indicates a well's capacity to producegas at the reservoir sand-face. In actual practice, it is desirable to know thegas volumes a well is capable of delivering against a back pressure oftransmission lines, processing plants and field gathering lines. When the openflow equation is used for pipeline or wellhead deliverability calculations, itis necessary to calculate a relationship of Q versus flowing sand-facepressures for a constant-flowing wellhead pressure. As wellhead pressures areusually measured during back-pressure tests, these are used directly inplotting a wellhead deliverability curve, as described by Crawford (1).

For maximum reliability, the predictions for any field frequently must berevised as additional information and production history become available. Toperform the calculations by hand is an arduous task requiring considerable timespent on routine work. A medium-sized electronic computer is ideally suited forthis application, and, after the programme is written, long-rangedeliverability forecasts at various rates may be made in a matter ofminutes.
Development of Judy Creek - A Case Study
Authors: Bradshaw A.D.
Published: March 2010

This paper reviews engineering considerations associated with thedevelopment of the Judy Creek Beaverhill Lake oil pool. The orderly developmentof the pool was facilitated by early studies of drilling and completionprogrammes, production practices and reservoir problems. The reservoir studyhas served as a basis for unitization and pressure maintenance, which becameeffective less than four years after discovery.

Introduction

The Judy Creek Beaverhill Lake oil pool was discovered by Imperial OilLimited in February, 1959, two years after the Home-Regent discovery of SwanHills, several miles to the north. Judy Creek is located about 100 milesnorthwest of the city of Edmonton in the heavily wooded Swan Hills area(Figure1). Other Beaverhill Lake reef pools in the area are: Deer Mountain, Swan Hills, Virginia Hills, Judy Creek West, Carson Creek North, Carson Creek (gas), Kaybob and Snipe Lake. These pools all produce from the Swan Hills member of the Beaverhill Lake formation of Middle Devonian age.

Judy Creek has provided an excellent proving ground for technical advancesduring the past decade. The purpose of this paper is to review briefly some ofthe advanced techniques that were applied in the development of the pool.

Initial Operations

Figure2 is a detailed map of the Judy Creek area. The discoverywell, 16–31–63–10, located on a Crown drilling reservation, struck oil at adepth of 8,600 feet. Immediately, an exploratory effort was launched, with sixstepouts begun simultaneously to help define the reservoir extent. Four of thesix were subsequently abandoned; two found Beaverhill Lake oil.

At the time of discovery, access to Judy Creek consisted only of a wintertrail, with spring break-up expected in three to four weeks time. It wasnecessary to stockpile equipment and prepare lease sites for the plannedstepouts. Within one month, 550 truck-loads of material, including fivedrilling rigs, Cat equipment, camps, mud, cement, tubular goods, diesel oil, and gasoline, were assembled at the prepared locations. In anticipation ofproduction, 24 miles of temporary pipeline were strung north from Judy Creek tojoin Federated Pipeline's main line north of the Freeman river.
Thermal Cracking of Athabasca Oil-Sands Oil Part 2. - Cohesiveness of Carbon Residue from Fluidized Coker Distillate
Authors: Pasternack D.S.
Published: March 2010

A continuation of the study of the partial thermal cracking of Athabascaoil-sands oil shows that maximum production of Ramsbottom carbon residue fromthe virgin oil and from its fluidized coker distillate occurs when the oil ordistillate is given an initial heating at about 800 to 825°F prior to carbonization. Residues representing the high-boiling ends of the fluidizedcoker distillate provide carbon residues which show excellent cohesiveness andpermit the production of hard low-temperature coke from non-caking Drumhellercoal and of very hard pellets (briquets) from hematite and non-caking Drumheller coal. It is possible that the coke and briquets may be strong enough to be fired directly into a metallurgical furnace.

Introduction

The work reported herein represents a continuation of the study of the partial thermal cracking of Athabasca oil-sands oil and of the usefulness ofthe derived products. It deals with "gum" formation during the storage ofsolutions of the Athabasca oil, the maximum production of carbon residuematerial from the oil and its fluidized coker distillate, and the usefulness of the residue from the fluidized coker distillate as a briquetting binder. Aportion of the earlier work has been reported.

Results and Discussion

Gum Formation on Dilution of Toluene Extract of Virgin Athabasca Oil

Dehydrated virgin Athabasca oil was diluted with toluene and filtered toremove extraneous mineral matter. Following removal of the toluene by heating, the toluene extract was diluted with 30 parts of kerosene at 280°F, filtered through medium-porosity fritted-disk glass filters and the precipitate washed.Table I shows that room-temperature storage of the combined filtrate and washings results in substantial amounts of precipitate, which may be consideredas "gum" formation.

This stability test was continued for 246 days, by which time 54 percent ofthe asphaltenes in the virgin oil had become insoluble in kerosene and hadprecipitated out. Cognizance of this feature is important in the storage of solutions of the virgin Athabasca oil.
Tight Hole and Closed Chamber Testing - A New Technique for Formation Evaluation
Authors: McAllister J.A. , Jensen L.I.
Published: March 2010

The closed chamber and tight hole methods of well testing described in this paper are designed to overcome some special drill stem test problems existingat the surface. The primary purpose for conducting this type of drill stem testis to utilize a system that offers maximum secrecy and/or maximum control of fluid recovery; therefore, maximum safety.

The problem of secrecy commonly occurs in Canada, and the tight hole technique was developed so that only authorized personnel would be able to determine the type of recovery and the pressure involved.

The closed chamber method has application wherever a high degree of controlof the recovery is desired, such as in townsite and night-time testing, neither of which can be accomplished safely by the conventional drill stem test method.This method also permits a high degree of safety when testing high-pressure gassands.

Experience with closed chamber testing has indicated that the fluid recovery data may be applicable for empirical analysis to determine reservoir fluid properties provided that certain problems are recognized.

Static reservoir pressure can be determined by employing the initial shut-in-flow-period method described in the text of the paper. However, problems are encountered when attempting to utilize the pressure buildup curveto determine transmissibility and permeability with the degree of accuracy obtainable from a conventional drill stem test. Examples of pressure curves from tight hole and closed chamber systems are included and discussed.

Introduction

Tight hole testing was developed to provide maximum secrecy of drill stem test results in Canada. In order to maximize secrecy, it was necessary to provide a testing system that would not allow fluid recovery to be exposed to unauthorized personnel on or off the rig floor.

The tight hole assembly consists of a closed chamber which allows the standsof drill pipe forming the chamber to be separated, drained and set aside in the derrick without revealing any recovery, even in the tool joints, to unauthorized personnel. Secrecy requires the elimination of surface indications during the test and the bringing of the recovery to the surface in such a manner that it will not flow freely from tool joints onto the floor or into the derrick. The recovery has to be removed from the chamber with maximum controlin order to provide secrecy. The conditions required for secrecy result in an increase in the safety of testing.
Geological Significance of Sonic Logs in the Boundary Lake Field
Authors: Jeffries F. , Meneley R.A.
Published: March 2010

By comparing lithologic description with core analysis and sonic log transittimes, it is possible to break the Boundary member of the Triassic Charlieformation into two major rock types. These rock types can be correlated betweenwells by their characteristic signature on the sonic logs and can thus betraced areally.

When the depths of these marker beds are fed into an electronic computer along with digitized sonic log data it is possible to compute many of the reservoir parameters for subdivisions of the Boundary member. The engineer canthus develop an extremely detailed description of the reservoir for studies of reserves, waterflood predictions, etc.

Introduction

The Boundary Lake field is situated in northeastern British Columbia and covers an area of about 100 square miles. Oil production is from a thin (0 to40 feet) carbonate bed, the Boundary member of the Triassic Charlieformation.

Previous studies in the field have shown that the sonic logs may be reactingto changes in the lithology of the reservoir (Jeffries and Kemp,1963). Subsequently, Meneley made a detailed study of representative Boundary Lake cores. This report outlines some of the results obtained incorrelating his lithological descriptions with computer-manipulated logdata.

Method of Study

Sonic logs from all available wells in the Boundary Lake field (Figure1) were digitized by spot-reading them at 6-in. intervals over thereservoir section. This information was fed to an IBM 1410 computer, and the output correlated with core-analysis porosity data from thirty-seven wells.Using a "cumulative" calibration technique (Holgate, 1960), atransit-time-versus- porosity plot was developed (Figure 2). Thisempirical relationship was used to convert all sonic log readings toappropriate porosity values. Detailed examination of a number of cores showedthat distinctive lithological types could be associated with sonic log characteristics (Figure 3). Cores from the southern part of the fieldwere checked to identify various rock-type occurrences.

By means of sonic logs, correlation sections were constructed across the southeastern part of the field, and individual zones were followed over wide areas.
The Judy Fieldgate System and Two-Phase Gathering
Authors: Keet L.
Published: March 2010

The history of Judy Creek, since its discovery in 1959, shows what can beaccomplished with planning, and with the use of up-to-date production facilities from the start of oilfield development.

Imperial Oil Limited's advantageous acreage position undoubtedly helped the Judy Creek development, but it has become clear that planning, especiallypre-planning of unified production systems, can and should be done, regardlessof acreage distribution.

This paper deals with the Judy satellite-central battery system, and itslater consolidation into the Fieldgate System, an innovation which has eliminated separate oil and gas gathering.

Judy Creek Field and Reservoir

The Judy Creek field (Figure 1) is located some 140 miles northwestof Edmonton, just south of the Swan Hills field. The country is very hilly, heavily timbered and similar to the foothills.

The field outlines of the Judy Creek and Judy West fields, with 230 wells on 160-acre spacing, are shown in Figure 2.

The reservoir lies in the Swan Hills member of the Beaverhill Lakeformation. The top of the reef is found at average depths of 8,700 feet. Thereservoir is a self-contained structure with neither gas cap nor waterdrive.

The rapid pressure decline early in its development prompted an immediateinvestigation into some form of pressure maintenance. The study indicated thata flank water injection scheme would increase recovery to 40 per cent. Asaresult, waterflood was in operation by December, 1962.

Such a pressure maintenance scheme would cause considerable interleasemigration, leading to inequities among the various land owners. This could beavoided only through unitization, and the latter became effective for the Judy Creek field in November, 1962.

Planning the Production Facilities

Several months before the Judy Creek field was actually discovered, a modelstudy was set up to determine the kind of lease facilities necessary in a newoilfield. To add realism to the study, an actual area in which Imperial hadlarge holdings was chosen for detailed examination; it was a good prospect andwas being actively explored.
The Multiple Completion Choke Assembly - A New Profit-Making Tool
Authors: Hodges J.W.
Published: March 2010

This paper describes the construction method of operation and fieldperformance of the multiple completion choke assembly developed by the Sun Oil Company.

This down-hole commingling tool has been in operation since March, 1960. Ithas been used in approximately 75 wells located in Louisiana, Texas, Mississippi, Oklahoma, Mexico, Kuwait and India.

Sun Oil Company's Gulf Coast Division, through the use of this tool duringthe past four years, has saved approximately $289,000 in tubular goods, andproduced approximately $282,750 worth of hydrocarbons not otherwiserecoverable.

The paper reports the results of Sun Oil Company's installations anddiscusses the various applications and limitations of the tool.

The method of allocating production to each zone is explained and theadvantages and disadvantages in the simultaneous production of two separatereservoirs through a single tubing string are enumerated.

Construction and Operation

Figure 1 shows a well equipped to receive a multiple completion chokeassembly. A retainer-type packer separates the two producing zones. The upperpacker is optional. A side-door choke landing nipple hookup is located in thetubing string above the lower packer. The multiple completion choke assemblywill be locked in this landing nipple. Normally located a joint or two abovethe upper zone, the position of the landing nipple hookup can be varied to suitwell conditions. For example, where the two zones are widely separated, itmight be placed just above the lower packer to facilitate bottom-hole pressuretests of the lower zone.

The tool consists of two separate assemblies, as shown in Figure 2.The outer assembly, which is run on a wire line and locked in the landingnipple, contains the check valves and packing seals which prevent flow from onezone to the other.

The orifice-head assembly, which carries the tungsten carbide choke beans, is run separately and is seated and locked in the outer assembly. The method ofrunning each section is illustrated in Figure 3.
Development and Transmission to Market of British Columbia Natural Gas Reserves
Authors: Kutney Peter R. , Tyler Alton T.
Published: March 2010

The discovery of huge natural gas reserves in British Columbia, strategically located with respect to almost unlimited markets for this premiumfuel along the entire Pacific Coast and in the Far East, has led to the rapid development of the Westcoast Transmission Company's pipeline system during theperiod from 1957 to date. Deliveries of gas, presently in the magnitude of 500million cubic feet per day in the wintertime, are expected to increase to thevicinity of a billion cubic feet per day in the next similar period as a resultof recent reserve developments in the Fort Nelson area and the anticipatedcontinual growth of markets in Canada and the Western States, and off-shoreshipments of LMG as far as Japan. To bring these large volumes of gas tomarket, Westcoast presently operates 1,000 miles of gathering lines and 30-in.mainline. This is being expanded this year by a $57,000,000 construction program into the Fort Nelson area close to the border of the Northwest Territories.

A review of the development of natural gas reserves in the Fort St. John and Northwestern Alberta fields has been followed by similar material covering thenew Fort Nelson area.

The transmission of British Columbia gas reserves to market requires acomplex pipeline system involving the handling of gas from the various fields, both sweet and sour, wet and dry, at high and low pressures, all under an extreme range of weather conditions. Briefly described are the Company' swellhead dehydration and gathering systems, treating plants, measurementstations, compressor stations and mainline facilities.

History of Development

The first exploration for petroleum substances in northeastern British Columbia was initiated by the Provincial Government during 1921 and 1922 when six shallow wells were drilled north of Hudson Hope. These wells, drilled to depths of between 1,000 and 2,500 feet, were unsuccessful.
The Use of Spearheads for Improved Acid Treatments
Authors: Melnyk J.D. , Mancillas G. , Davis J.J.
Published: March 2010

A common method used to design acid treatments on acid-soluble formations isbased upon the use of "reaction times" and fracture calculations. Two of thedifficulties involved in utilizing this technique are the variable reactionrates of acid under different well conditions and the problem of determiningleak-off coefficients.

One approach to controlling these factors is to prevent reaction with theformation and restrict leak-off until all the acid is in place. This can be accomplished by plating the formation fractures with a dispersible film priorto the introduction of acid to the fracture system. Laboratory data and field results using this approach have indicated favourable results.

Laboratory tests were made on several types of spearhead fluids and additives. This test information is shown and discussed in the way it pertains to the particular spearhead and acid chosen for use in the field.

Also discussed are the advantages and use of the spearhead film technique inthe placement of acid in a formation. It is expected that this approach will, in many cases, provide more reliable fracture calculation for more effective treatment design.

Introduction

Hydrochloric acid has long been one of the prime materials used instimulating limestone and dolomite reservoirs. Of the many acid treatmentsdone, most can be conveniently divided into two basic classifications:matrix acidizing, in which the acid flow is confined to the naturalpermeability and porosity of the formation; andfracture acidizing, in which the primary avenue of acid travel is through natural or induced formationfractures.

This paper is concerned with the aspects of fracture acidizing.

In a well, a zone of local wellbore damage can be responsible for a severeloss of productivity. Once this is removed or by-passed, substantial penetration of the acid is required to give a productivity increase of two tothreefold over that obtainable from the untreated formation. Radial permeability improvement, as obtained with matrix acidizing, would require prohibitive quantities of treating fluids to reach such a distance from the well bore. It has long been recognized that more reasonable volumes are required if the acid is used to create and etch a highly conductive fracture to the desired depth in the formation.