bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of Oil Recovery by Steam Injection From the Franklin Heavy Oil Field
Authors: Donohue David A.T. 
Published: March 2010

Abstract
The Franklin heavy oil field, Venango county, Pennsylvania was discovered inlate 1859 but is, today, virtually abandoned. Geologic data reveal that theshallow producing formation, Devonian in age, has been productive over onlyhalf of the field area but that in excess of 60 million barrels of crude oilremain in place. The gravity of this "heavy oil" (a misnomer in light of ourpresent definition) is about 31°API, and the crude is distinguished by its paraffinic base, naphthenic light ends and good market value. Recently it was announced that a steam injection pilot test was to be initiated in this field.In view of this development, a simulation of the steam injection process for anindividual pattern within this field has been made using available physical data and published mathematical models. A description of the field and details of the simulation are presented in the paper.

Introduction
The Franklin heavy oil field, located in Venango County, Pennsylvania, was discovered soon after the completion of the Drake well in 1859. The field wasdeveloped over a period of years, but for all practical purposes it is now abandoned. Recently, however, it was announced that a steam injection pilotproject was to be initiated in a segment of this field. This study, performedindependently of any request or commission, was made to characterize, in an approximate manner, the engineering parameters of this particular injection-production system.
This field received its name soon after its discovery. In light of our present concepts, however, the term "heavy oil" is a misnomer because crude oilfrom the Franklin heavy oil field has a gravity in the range of 31–32°API, anomalously low for Pennsylvania crudes. Because of the large percentage of high-grade lubricating oils contained in the crude, it commands a highmarket value. It is estimated that this field has an in-place crude oil volumein excess of 60 million barrels.
Effect of Temperature on Waterflooding
Authors: Edmondson T.A. 
Published: March 2010

Abstract
This paper describes laboratory experiments involving waterflooding atelevated temperatures using two refined oils and two crudes. The test core andinjection water were both held at test temperatures for the duration of theflood, thus eliminating the problem of thermal fronts. The findings reportedhere apply to waterflooding in general and thermal recovery in particular, asmost thermal recovery methods include a phase where "hot" water displaces "hot"oil.
Waterflood tests were conducted at 75°F, 100°F, 150° F, 200°F, 300°F, 400°Fand 500°F using two refined oils: No. 5 white oil and No. 15 white oil. Twocrude oils were used in waterflooding at 75°F, 150°F and 300°F.
The results show that residual oil saturation decreases with increasing temperature. Consequently, ultimate oil recovery increases with increasingtemperature and the relative permeability ratio is different for differenttemperatures. The magnitude of the temperature effect varies, but in most casesit is appreciable, especially for the crude oils. Crude oil waterfloodbehaviour in the laboratory tests differs significantly from refined oilbehaviour, because in crude oil waterfloods water breakthrough is earlier andsubordinate production is much higher. Consequently, predictions of field hotwaterfloods require displacement data at the actual field flood temperature, using reservoir materials.

Introduction
There is a great deal of current interest in thermal methods for recoveringcrude oil, especially the heavy viscous crudes. Many forms of thermal recoveryinclude a phase where hot water displaces oil. In such a process, two frontswill form a leading cold-water front and a hot-water front. Oil and waterviscosities decrease and the liquids swell as the temperature increases. These effects may influence fluid flow in a way not described by simple relativepermeability concepts. However, all processes involved in hot waterfloodingoccur slowly, and thermal equilibrium may be considered to prevail at everyspace-time point during the flood. Consequently, the relative flow rates of oiland water are determined by relative permeability ratios and viscosities, despite the complicating thermal effects mentioned above.
Exploration and Production - From Now to 1970
Authors: Hay Charles 
Published: March 2010

As you know, the subject I have been asked to cover is "exploration andproduction, from now to 1970." I should perhaps begin by pointing out that manyof the exploration and development programs designed to meet the demands of1970 are already well underway. As a significant contributor to the supply ofenergy on this continent, the Canadian oil and gas industry is already lookingpast 1970 and trying to get a focus on the situation ten and even twenty yearsfrom now.
First a little background on the industry, to bring us up to date: Accordingto statistics published by the Canadian Petroleum Association, industry expenditures for the exploration, development and production of oil and naturalgas in Western Canada, from 1947 to 1964, inclusive, amounted to 8.3 billiondollars, exclusive of pipeline construction.
Except for the last three years, the continuous expansion of the industryhas resulted in annual expenditures greater than income. The cumulative excess of expenditures over income amounted to 1.8 billion dollars during this eighteen-year period. This amount does not reflect any interest on money, thecost of high-risk capital needed for this type of investment nor income taxes.However, the industry has discovered substantial reserves of oil, gas and gasproducts which will more than offset this deficit.
Figure 1 shows how the production of crude oil rose from 21,000barrels per day in 1947 to a peak of nearly 500,000 barrels per day during the Suez crisis in 1957, then dropped back to about 450,000 barrels per day. Underthe National Oil Policy, which began in 1961, production increased steadily toan average of 750,000 barrels per day last year, with natural gas liquidsaccounting for an additional 102,000 barrels per day. In 1970, we estimatecrude oil production at 960,000 barrels per day, with liquids bringing thetotal of 1,100,000 B/D. Figure 2 shows the development of domestic andexport markets for crude oil and pentanes plus.
Review of Waterflood Performance in the Fosterton Main Unit
Authors: Tutt D.W. 
Published: March 2010

Abstract
The Main Roseray sand pool is one of three pools comprising the Fostertonfield in southwestern Saskatchewan. The pool was discovered in January, 1952, by Mobil Oil Canada, Ltd. Drilling continued until the middle of 1955, whendevelopment was considered complete. The pool was unitized on July 1, 1958, with Mobil Oil Canada, Ltd. as the operator. Pressure maintenance by means ofwater injection commenced during March, 1959. This paper presents basic dataand a review of reservoir performance under pressure maintenance bywaterflooding in the Fosterton Main Unit.

Introduction
The Main Roseray sand pool (Fosterton Main Unit) is one of three poolscomprising the Fosterton field. The Fosterton field is located in Township 17, Range 18, west of the Third Meridian in southwestern Saskatchewan (Figure1).
The pool was discovered in January, 1952, by Mobil Oil Canada, Ltd., by thedrilling of Socony-Western Prairie Fosterton No. 1 in Lsd. 2 of Section 10, Township 17, Range 18, west of the Third Meridian. The pool produces from astratigraphic trap in the Roseray sand created by an erosional unconformitybetween it and the overlying Blairmore formation. Drilling continued until themiddle of 1955, when development was considered complete. Production from thispool is obtained from the Roseray I sand and the Roseray II sand. Table 1presents the reservoir properties for the pool. Figure 2 is an isopachmap of the Roseray I sand, which is the lower of the two producing sands. Thissand extends from the western edge of the pool and gradually thins out to theeast about midway through Section 11. It is underlain by water in the northwestcorner and along the southern portion. There are approximately 36 MMSTB oforiginal oil-in-place in this sand. Figure 3 is an isopach map of the Roseray II sand. This sand extends from the western to the eastern edge of thepool. Approximately one-third of the oil-in-place in this sand is underlain bywater in the eastern portion of the pool, as shown by the shaded area.
A Western Canadian Co-Operative Education Program In Engineering
Authors: Blachford C.W. , Mantle J.B. 
Published: March 2010

Abstract
The Co-operative Education Program developed at the University of Saskatchewan, Regina Campus, is the first in Canada west of the Great Lakes. It is a program in which industry and the university co-operate to develop a mature. self-confident engineer capable of fulfilling his potential The scheme is one in which the student alternates between one semester of studying and one semester working in industry.
Many advantages for industry, the student and the university arising from the program are presented. Briefly, for industry, a few of these advantages are: they obtain a more mature engineering employee, who is less likely to move during the early years of employment; an orientation program is possible while the student is an undergraduate; an effective recruiting program is established: and student help is available the year round.

Introduction
RELATING LEARNING directly to society has become an increasing concern to all of us in the universities. The older concept of a university located in isolation from its Surroundings is no longer good enough for today's youth. They have grown up exposed by the media and modern transportation to life in the world in all its splendor and ugliness, Students in general have become much more aware of the great disparity between the ideals of freedom, liberty and justice and the way they are carried out in society. A dissatisfaction has developed to such an extent that the desire is now to get into the action and help to build a better world; that is to say, students realize that society has become too complex to gain an understanding of life through books alone - through the environment of the university alone.
Although we intend to discuss business, industry and engineering students here, the above remarks are not unrelated. The world of business and industry has become so complex and huge that it is no longer as easy to do an adequate or job of educating an engineering student for his future career entirely within the university. The student is curious and wishes to know more about his future in the world and how his ideal career objectives mesh with real life. We belief that the Co-operative Education Program presented here will expose the student to both the theoretical world and real-life experiences and thus provide a broader and richer preparation for life than conventional programs.

Co-Operative Program
Last year, we began the first Co-operative Education Program west of southern Ontario at the University of Saskatchewan, Regina Campus. We have participating firms in Manitoba and Saskatchewan, from Thompson to Winnipeg and from Lac La Ronge to Regina. We would like to extend the program in the next year to Alberta and B.C.
"Co-operative education" derives its name from the partnership between the university and industry, who co-operate to guide a young man through his four years of formal education. The scheme has other names; e.g. ‘thick sandwich course’, or ‘thin sandwich course’.
Vertical Immiscible Displacement Experiments In a Non-Homogeneous Flow Cell
Authors: Brandner C.F. , Slotboom R.A. 
Published: March 2010

Abstract
Vertical two-phase displacement studies were conducted using a non-homogeneous flow cell in order to determine the reversibility of water-oil displacements in the heterogeneous Rainbow Keg River pools and to provide a better definition of the residual oil under waterflood and gas flood in these reservoirs. The non-homogeneous flow cell was constructed of fused glass beads. The maximum to minimum permeability ratio was approximately 270.
The results of a waterflood upward followed by an oil flood downward over field rates of 4 to 700 fr/yr show that:displacements are stable over the velocity range studied;complete resaturation of the matrix porosity by oil will occur when the cell is connected in a manner representative of field behaviour (matrix-connected);the apparent capillary height of rise is velocity dependent; andthe oil recovery from the vugs during water displacement is a function of velocity, with more oil recovered at the higher velocities.
The downward displacement of oil by gas indicates that the displacement process is essentially independent of velocity over the velocity range of 2 to 150 jt/yr.
Time-lapse motion picture films were made of the displacement Experiments＿

Introduction
THE RAINBOW FIELD, discovered in northwestern Alberta in 1965, now comprises some 50 separate reef reservoirs. Production is mainly from the Middle Devonian Keg River Formation, which lies at a depth of about 6000 feet. The larger reefs have high-vertical- relief (up to 600 feet) oil-bearing zones that are usually underlain by an aquifer and sometimes overlain by an initial gas cap. The production mechanisms in these reservoirs, whether it be primary depletion or pressure maintenance by gas, solvent or water inj ection, will therefore be gravity controlled, and drainage will be predominantly in a vertical direction under effective segregation of the phases in the reservoirs. Volumetric efficiencies are consequently very high, and ultimate recoveries are mainly determined by the residual oil saturation left behind by the displacing fluid.
Of the various depletion methods, solvent flooding is the most efficient recovery mechanism, with a residual oil saturation of zero to a few per cent＿ Waterflooding, gas flooding and primary depletion are less efficient. Some 30 per cent of the 1150 million STB of original oil-in-place of the Rainbow Keg River reef is currently under solvent flood, and 60 per cent is being waterflooded. The remaining 10 per cent is under primary depletion. The amount of oil under solvent flood is limited by solvent and gas availability. Solvent is separated from the crude oil, and solution gas may be supplemented with gas from other sources. In each of the solvent flood pools, a solvent bank is injected to cover the oil When this solvent bank becomes large enough to provide miscibility for the lifetime of the project, it is then pushed down to displace the oil by injecting lean gas into the crest of the reef.
Determination of the "Gas-Free" Liquid Level And the Annular Gas Flow Rate For a Pumping Well
Authors: Alexander L.G. 
Published: March 2010

Abstract
This paper describes two methods of determining the "gas-free" fluid level and the annular gas flow rate in a pumping well without significantly disturbing the balance of tire system. The methods consist of direct or indirect measurements of the annular flow rate and observations of the pressure buildup when the annulus is closed in at the surface. These data allow the calculation of the volume of gas in the annulus and the normal annulus gas venting rate. The "gas-free" fluid level is then determined directly from the volume of the annular gas. This fluid level, in turn, allows one to derive tire bottom-hole pressure using a pressure gradient that is consistent with the temperature and pressure of the oil column.

Introduction
Knowledge of the dynamic and static bottom-hole pressures in a pumping well enables the operator to determine the optimal surface and lifting facilities for present and future operations. The bottom-hole pressure under flowing conditions is usually obtained by first determining the fluid level with an acoustic device. The height of the liquid column is calculated and an assumed pressure gradient for the fluid is then applied to the liquid column to arrive at the dynamic bottom-hole pressure. Whenever there is doubt about the fluid level or the pressure gradient, the operator often closes the annulus in order to lower the level of the liquid to the pump seating nipple. The pressure can then be determined accurately, because a known gas pressure gradient exists from the surface to the pump seating nipple.
However, the pressure data so obtained may not agree with those at the flow rate prior to the closure of the annulus valve. Therefore, a new stabilized flow rate, which corresponds to the altered pressure, must be allowed to establish itself. This procedure is time consuming and may lead to a loss of production, because flow of free gas through the pump reduces the pumping efficiency. This paper describes a single-step and a two-step method of determining the "gas-free" liquid level find the annular flow rate of gas without a significant change in the bottom-hole pressure. Knowledge of the liquid level (with the gas phase absent) allows the calculation of the bottom-hole pressure under flowing conditions using a pressure gradient of the liquid which is consistent with its pressures and temperature.

Theory
The volume of gas in the annulus can be considered as being contained in a vertical cylinder, the volume of which can vary, dependent upon the "gas-free" liquid level in the annulus which forms the base of the cylinder. Under normal operating conditions, gas is vented at the same rate as it enters and no change of mass occurs. If, however, the flow rate of gas being vented differs from the input flow rate, then the muss of the system will change according to the following mass balance equation for single-phase gas flow.
Marten Hills Gas Well Dewatering
Authors: Riley J. , Hale B. 
Published: March 2010

Abstract
Marten Hills Gas Unit No.1 has been on stream since 1969, with production from the Wabiskaw sand and Wabamun D-1 carbonate. Water influx from the underlying Wabamun D-1 aquifer became a significant problem in 1975. Production declined substantially in a large number of wells due to high wellbore fluid levels and high flowing gradients in combination with low reservoir pressure. Several methods of dewatering the wells were evaluated, with the beam pumping unit proving most effective. Currently, 18 of the 38 wells tied into the gas gathering system have beam pumping units installed.
This paper discusses the history behind the selection of bottom-hole pumps, past and present operating problems associated with this application, and current refinements to improve run lives.

Production History
Marten Hills Gas Unit No. 1 is located approximately 145 miles (233 km) northwest of Edmonton. It is a shallow lowpressure gas field with production from the Wabiskaw sand and Wabamun D-l carbonate.
After coming on stream in late 1969, the field produced minimal amounts of water. However, by 1972 isolated instances of water production resulted in at least one well being throttled back to lower its water production. At the time, there were no water handling facilities in the field except lease flare pits and an evaporation pond. These pits were subject to strict quotas regarding quantity of produced water that could be handled each month. By early 1975, water influx from the active Wabamun D-1 acquifer became a significant problem. Figure 1 is a production graph for the Marten Hills Gas Unit No.1. The buildup of water in wellbores and surface flowline created backpressure which severely reduced well productivity. In some cases, the buildup was enough to cause wells to cease flowing.
Several methods of handling and controlling the water were evaluated before a consistent field-wide method of dewatering was determined.
The Marten Hills Field consists of two main gas-bearing formations, shown schematically in Figure 2. The lower formation (Wabamun) is a carbonate deposit of Devonian age. It varies from a dense to vuggy limestone and in the eastern portion of the field becomes a granular dolomite. Seismic data in dicate that this unconformity surface is severely channelled. The second horizon is the Wabiskaw Sandstone (Lower Cretaceous), which drapes over the D-1 unconformity. The two gas-bearing formations are separated by the "McMurray" shale layer, which is continuous over a major portion of the field. In some areas, including those where there is no apparent shale, a heavy oil or tar leg exists in the Wabiskaw sand which separates the two gas zones. The gas composition and pressures in the two zones were identical at discovery, which suggests that the shale and heavy oil do not form a continuous seal.

Initial Attempts at Dewatering
Small Tubing
Soon after water influx became a problem in 1975, a means of unloading the water using reservoir pressure was tried in three wells. The method involved installation of small-diameter production tubing as shown in Figure 3.
A Geological Explanation For the Variation In Fluid Properties Across the Pembina Cardium Field
Authors: Kerr W.E. 
Published: March 2010

Abstract
This paper examines the anomalous variations in the fluid properties across the Pembina Cardium Field in view of an extensive geological study of that area completed in 1975. Based on earlier geological concepts, it was impossible to generate a correlation between fluid properties and geology that had field-wide application. However, the recent geological study indicates that there are two separate and distinct producing zones. Further investigation showed that each zone had its own set of fluid properties. By relating the fluid properties to the appropriate producing zone, it is possible to derive a correlation which accounts for the variations in GOR's and other fluid property-related parameters in this field. A summary of the derivation and application of this correlation is discussed in this paper.

Introduction
The Pembina Cardium Field is an extensive oilfield approximately 113 km (70 miles) southwest of Edmonton, Alberta (Fig. 1). The under saturated reservoir was discovered in 1954 and was drilled out over the next several years. The pool, which covers an area of 283,000 ha (700,000 acres) and includes about 4,400 wells, is mostly under waterflood (Fig. 2).
During the first few years of production from the pool, variations were found in the fluid properties. Properties such as gas-oil ratio, bubble point, viscosity and oil gravity varied significantly across the pool. Attempts had been made to explain these variations in the fluid properties, but there were no field-wide explanations.
The purpose of this paper is to present a summary of the results of a study done on the variation of the fluid properties in the Pembina Cardium Pool in relation to a recent field-wide geological report.

Geology of the Pembina Cardium Pool
In the past, most geological studies on the Pembina Cardium Pool covered only certain areas of the field. However, in 1975, Rodgers, Klassen, Russum and Budrevics, of Amoco Canada. conducted a geological study of the whole field. Their work indicated that there were two main producing sandstone zones in the Cardium, and that these zones were not continuous across the field. Up to this time, it was generally assumed that there was only one major producing sandstone zone in the Cardium Pool.
According to the geological study completed in 1975, the Cardium was broken up into the four geological zones described below:Zone 1-Conglomerate, a broad term covering all impermeable and permeable material at the top of the Cardium Zone, bearing pebbles.Zone 2-Permeable sandstone immediately underlying and usually in contact with the conglomerate when both are present.Zone 3-Impermeable zone consisting of bioturbated shale and siltstones with minor permeable sandstones.Zone 4-A regressive phase of permeable sandstone interbedded with bioturbated material.
A diagrammatic cross-section illustrating these zones, as found in the Amoco-operated leases in the western part of the field, is shown in Figure 3.