bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Judy Creek - A Case Study
Authors: Bradshaw A.D. 
Published: March 2010

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Formation Evaluation in Heavy Oil Sands
Authors: Brown James S. 
Published: March 2010

Abstract
"Formation evaluation" comprises correlation, reservoir detection and reservoir evaluation. In the Chauvin, Wainwright and Lloydminster areas, the principal heavy oil reservoir is the Sparky sand. The oil sand pools are surrounded by halos or "channels" of shale. Correlation is more difficult inthe Lloydminster area than in the Wainwright area or the Chauvin area because the sand distribution is more complex. Reservoir detection is more difficult at Wainwright and Chauvin because the oil sands are thin and apparent resistivities are low; at Lloydminster, the oil sands are thick and apparentresistivities are high. At Wainwright and Chauvin, a resistivity log, aporosity log and often a drill stem test are necessary for a decision to setpipe; at Lloydminster, all that is required is an electrical log. Productivityvaries considerably from pool to pool, probably because of changes in sandpermeability and oil viscosity. As these changes cannot be detected by theelectrical log prior to setting pipe, the present practice is to determineproductivity by production testing after setting pipe. Transmissibility,(kh/u), as derived from drill-stem test data, may provide a means of estimating productivity prior to setting pipe.

Introduction
The techniques used for formation evaluation vary from area to area, as each area has problems which are peculiar to it. The purpose of this paper is todiscuss some of the problems peculiar to the heavy oil reservoirs of the Lloydminster, Chauvin and Wainright areas, and to mention certain techniqueswhich provide the necessary data simply and economically. In the following, the Lloydminster area will be discussed first; this will be followed by adiscussion of the Wainwright and Chauvin areas. The geology of each area willbe commented on, but only insofar as it bears on the problem of correlation andreservoir identification.
Principles of Heavy Oil Recovery
Authors: Szasz S.E. , Thomas G.W. 
Published: March 2010

Abstract
Rising exploration costs have prompted greater interest in the large knowndeposits of heavy oil on our continent. Because of high oil viscosities in suchreservoirs, recoveries are poor, fluid drives are inefficient and productionrates are uneconomical. Viscosity reduction can best be accomplished by heatingthe reservoir. The basic aspects of reservoir heating are reviewed and thoseprocesses which are of practical importance in heavy oil reservoirs arediscussed.
Wellbore heating frequently can be applied to heavy oil reservoirs toincrease production rates. It will only be effective, however, where some reservoir driving energy exists and sanding problems are not severe. Forward and reverse combustion usually require so much air in heavy oil reservoirs thatthese processes are uneconomical. In hot water flooding, the water requirementsare much higher than in an ordinary waterflood. Steam floods are more attractive, but operating costs are generally high. Fresh water condensate fromthe steam may also cause severe reservoir damage.
Conduction heating processes appear most promising. Among these we includethe cyclic steam-soak process. A simple method is presented for estimating the performance from the first cycle of steam injection into the formation, assuming gravity as the only driving energy.
An example calculation for a typical heavy oil reservoir is given. Theresults yield conservative estimates. The combustion-conduction process is attractive because of the characteristic low air-oil ratios. The productionperformance of the heated reservoir is not readily predicted, however. Fracture heating processes hold great promise, provided that we can develop means forcreating fractures with controlled orientation and direction.

Introduction
The cost of finding new oil reserves has been rising continuously over thepast two decades. The oil industry has therefore put increasing emphasis onimproving recovery from known reservoirs. Recently, attention has been directedto the large deposits of heavy oil on our continent. The U.S. Bureau of Mineshas estimated (1) that in the United States there are more than 150 billionbarrels of oil with a gravity of less than 25°API in known reservoirs. Most ofthem contain more than 1000 bbl/a.ft.; about half of them are at depths of lessthan 3000 ft. Oil recovery from these reservoirs, however, is estimated at 11per cent, compared to an estimated ultimate recovery of 30 per cent fromconventional reservoirs. This makes heavy oil reservoirs especially attractivedespite their low oil mobilities.