bluuebunny/crossref_metadata_2025 huggingface dataset:
Unsteady State Gas Flow - Use of Drawdown Data in the Prediction of Gas Well Behavior
Authors: Flock D.L. , Aziz K.
Published: March 2010

The solutions on unsteady state gas flow in a radial system have beenreviewed to aid in the interpretation of drawdown data. It has been thepractice to evaluate the time and rate conversion constants directly orindirectly by using reservoir data. This paper presents a method of determiningthese constants from drawdown data.

A simplified approach to determine the time of stabilization for the variousboundary conditions is presented. An example problem illustrating the use ofthis theory appears in the Appendix.

Unsteady State Flow Equation

The solution of any unsteady-state flow problem involves -1, the continuityequation -2, the equation of state of the fluid -3, the equation of fluidmotion and -4, the boundary conditions. For Darcy flow of a gas in thehorizontal radial plane the equation is

(Equation i)

when the viscosity, compressibility and permeability to gas flow may beassumed constant and the medium is homogeneous. (Since Kg is assumedconstant subscript gwill be omitted from now on.)

By substituting in Equation (i) we may also write

(Equation ii)

Equations (i) &(ii) are non-linear differential equations and norigorous analytical solutions of these equations are available.

Equations (i) and (ii) may be normalized (made dimensionless). Equation (i)becomes

(Equation iii)

where if the pressure P, in the equation for t may be assumed constant atsome average value.

(Equation iv)

The clear distinction must be noted between Equations (iii) and (iv). Wehave reduced the non-linear differential Equation (ii) to a linear differentialEquation (iii) by defining a t which contains P assumed constant at P. Katzet al.have justified this assumption. If the assumption is justified, which at best can only result in approximate answers, then we may use all ofthe solutions obtained for liquid flow case by simply replacing P byP2. This has been done in many practical applications of the theoryof unsteady-state flow to gas reservoir problems.
Improved Primary Cementing Through Turbulent Flow Techniques
Authors: Greaves F.C.
Published: March 2010

In an effort to secure better primary cementing, the industry has beendevoting considerable time to the study of turbulent flow cementing in recentmonths.

This paper presents a review of the theoretical calculations used inpredicting flow rates necessary to obtain turbulent flow during the cementingoperation and a study of the rates necessary in various annuli using some ofthe more common cementing blends.

In addition, the effects of recently developed additives on the rheologicalproperties of cementing materials are briefly discussed. The results of somefield applications are presented, which tend to indicate superior results usingthe turbulent flow technique.

Introduction

Although the quality of the cement sheath has been important since theinception of oilwell cementing, it is becoming much more so in the light ofrecent accelerating advances in well completion technology. With completionsbecoming more complex, the cement as well as the casing is subjected to moreand more rigourous treatment, making it imperative that a reliable primarycement job be obtained. Indeed, the success of many present stimulationproduction and secondary recovery practices depends directly upon the soundnessof the cement sheath.

It is obvious that the quality of the cement sheath is highly dependent uponthe amount of drilling mud displaced in the annulus by cement slurry. This wasrecognized as early as 1948 and experimental work was performed which revealedthat mud displacement was a function of the type of flow characteristics of thecementing slurry. It is now agreed that maximum displacement efficiency isachieved when the cement column is placed at rates sufficient to createturbulent flow. Although in the early stages of investigation the necessaryrates were in most cases unattainable due to inadequate pumping equipment, thispaper attempts to show that with modern cementing equipment and recentlydeveloped cement additives, the necessary rates are, in most cases, attainablewith very little difficulty.
Case History of a Supplemental Natural Water Drive; Stettler D-2 Pool
Authors: Craig R.K. , Lozanski W.R.E.
Published: March 2010

Introduction

Development History

The Stettler D-2 (Nisku) pool is located in Township 38, Range 20, west ofthe fourth meridian, and, as shown in Figure1, lies approximately 140miles southeast of Edmonton, Alberta. The pool was discovered in 1949 by thedrilling of Canadian Gulf N.J. Ellis No.4, located in Lsd. 4–10–38–20 W/4.Deepening of this well led to the discovery of the D-3 pool, in which the wellwas initially completed. Figure2 is a plan view of the location of theD-2 reservoir relative to the D-3 reservoir.

Development of the D-2 pool since 1949 has established a productive area of5,970 acres, defined by ninety commercial wells and approximately twenty dryholes. The pool has a length of five miles, a breadth of three miles and agross pay thickness of up to 108 feet, with a pool average of 63 feet. Theaverage well depth is 5,200 feet. Figure3 is an isopach of the grossNisku oil pay. There was no evidence of a gas cap overlying the oil pool.

Development drilling was essentially completed by 1956. Subsequent tounitization in May, 1957, five wells were drilled and six D-3 wells weredual-completed. Six wells in the northwest corner of the field, BASU 15–20,16–20, 13–21, 4–28, 1–29 and 2–29, were added to the unit in February,1960.

Geology

The Nisku formation is a biostromal reef structure, draped over the Leduc(D-3) bioherm. The stratigraphy is illustrated in Figures4, 5 and 6, which are geological cross sections of the field. The D-2 may be classifiedinto two components. The upper sub-member, which varies from a thickness of 30feet at the crest to 100 feet on the flanks, is an evaporitic sequence ofprimary anhydrite and dolomite and forms the caprock.
Education for the Petroleum Industry
Authors: Flock D.L.
Published: March 2010

Since 1930, petroleum engineering educators have faced the problem of theeducation of engineers for the petroleum industry. An essential balance had tobe maintained between competing and, sometimes, conflicting elements of thiseducation. The basic sciences, the fundamentals of engineering, the humanitiesand the specialized petroleum engineering courses had to be constantlyevaluated and assigned their proper proportions in the whole programme.Naturally, the design of the early curricula reflected to a large extent thedominant interests of the petroleum industry during those years; but eventuallycoherent and homogeneous petroleum engineering curricula evolved.

For about a decade after World War II these programmes were favourablyreceived, both by the students and the petroleum industry. But recent atomicdevelopment and the changing needs of industry have resulted in decreasedinterest and decreased enrollment in the petroleum discipline. Educators mustkeep up with the times. Chance and innovation must be accepted; education forpetroleum engineers must not only bring itself up to date, but must, ifpossible, prepare for a constantly changing world. The solutions discussed inthis paper primarily revolve about what might be classed as the two-degreeplan. So far these ideas have been favourably received.

Introduction

Since 1957, engineering enrollments in some Universities in North Americahave sharply decreased. The petroleum engineering student, in particular, isapparently becoming almost extinct. Can industry do without him? It appearsnot; he is still needed and will be needed needed in the future. But hisnumbers continue to dwindle, and the resulting problems of engineeringeducators and industry are still unsolved.

The purpose of this paper is to discuss the problems of educators andindustry concerning this development and suggest a solution. Many men inindustry have no firsthand knowledge of the basic content of petroleumengineering curricula. The principle objectives and historical developments ofpetroleum engineering are reviewed in an attempt to define dearly theactivities of the petroleum engineer in the industry.
Thermal Cracking of Athabasca Oil-Sands Oil Part 1. - Changes in Some Properties of the Oil and its Components
Authors: Pasternack D.S.
Published: March 2010

Partial thermal cracking of virgin Athabasca oil-sands oil at atmosphericpressure with simultaneous removal of distillate, followed by filtration, removes all extraneous mineral matter as well as the smallamounts ofcoke produced during the thermal cracking. A study was made of the filtratesand of fractions from the filtrates in order to gain an insight into some ofthe complex changes which occur in the oil during thermal cracking.

The changes which occur in molecular weight, ultimate composition, B.t.u.value, specific gravity and penetration during thermal cracking of the Athabasca oil are illustrated. In addition, it is shown that portions of theasphaltene material (designated as varsol- or kerosene-insolubles) from somefiltrates have interesting characteristics. For example, on heating at 1,022°F, these insolubles form honeycomb-like structures which represent volumeexpansions as great as 200 to 300 times. Some of these structures may be cutwith a knife without crumbling. Also, the formation of these honeycombs is, under certain conditions, sensitive to prior oxidation of the insolubles atelevated temperatures and to other factors. Furthermore, on mixing theinsolubles with dry Drumheller subbituminous B coal (a non-caking coal) in theratio of only 1 part of insolubles to 11 parts of coal, and carbonizing rapidlyat 1,022°F, a fairly hard lump is obtained which is similar in hardness to thatproduced by similarly carbonizing an unconsolidated mixture of the dry Drumheller coal and dry Crowsnest Pass caking coal in a ratio of 1:1.

Introduction

The dehydration of Virgin oil recovered from the Athabasca oil sands byeither the hot-water-washing processor the cold-water-washing processreveals the presence of relatively large amounts of clay, silt and very finesand, the actual amounts depending on the particular experimental conditions.

Consequently, interest heretofore has centred on the yields and quality of thedistillates produced from the oil.
Simulation of the Alcohol-Slug Process Using the "Cell Model"
Authors: Donohue D.A.T. , Nielsen R.F.
Published: March 2010

The similarity of the mechanism of miscible displacement to the functioning of packed columns has led to suggestions that the "theoretical plate" concept might be a useful mathematical model for the simulation of miscible displacement processes. Such a model would rest on the assumption that the porespace of a linear porous medium is equivalent to a certain number of "plates"or cells and that, in each cell, only a fraction of the fluid volume ismovable. During displacement, the movable volume from each cell moves on toeach succeeding cell, establishing equilibria with the respective stationary volumes.

When two phases are present in the model, relative phase mobilities, as governed by viscosities and phase saturations, will affect the movable fractionin each cell. If, in addition, there is interphase transfer of material, the equilibrium condition for each cell is governed by the amounts and mutual solubilities of the components. While the procedure is quite general, thepresent study is confined to various ternary water-hydrocarbon-alcohol systems.To expedite computations, general mathematical relations were developed for thebinodal curves and tie lines. These were necessary to obtain the phase volumes and compositions for any over-all cell composition. Expressions for phasemobility ratios as functions of saturations were also used. The validity of the model has been demonstrated by comparisons of efflux histories for alcohol displacements of oil and water as obtained from the model and from laboratory experiments.

Introduction

It has been known for some time that a sufficient volume of certain lower alcohols will effectively displace all or most of the oil and water contacted in an oil-water porous medium system. As alcohols are considerably more expensive than equal volumes of recovered oil, an economically successful process requires that only a finite volume or slug of alcohol displace the oil and water.
Sour Gas Processing - West Whitecourt Plant
Authors: Neidermayer A. , Morrow J.R.
Published: March 2010

The West Whitecourt Project represents a scheme devised to obtain production from three sour gas reservoirs, to optimize hydrocarbon condensate recoveries and to coincidently produce sulphur consistent with market demand. Considerables our gas processing experience has been obtained in two and one-half years of Windfall Pilot Cycling Plant operations and an additional two years ofoperations in the enlarged West Whitecourt Plant. The installation of over12,000 BHP for the compression of extremely sour gases has indicated the attainment of a fair degree of compressor dependability, with due consideration to compressor material selection and design, modified operating techniques, and scheduled maintenance and repair programs. Unique plant design features include refrigeration of the sour gas stream prior to sweetening, the installation of asolid desiccant adsorption unit on the residue gas stream, and dehydration ofthe stabilization units' 50 per cent H2S, 190°F overhead vapours with a solid desiccant unit. Corrosion, resulting either directly or indirectly from sour gases in the process streams, has been maintained within tolerablelimits using appropriate corrosion-resistant materials, material stress relieving, optimum operating techniques and corrosion inhibitors.

Introduction

The Windfall Field, located about 20 miles west of the town of Whitecourt, Alberta, was discovered in 1955. This was followed shortly thereafter by the discovery of the Pine Creek and Beaver Creek fields, 25 miles southwest of Windfall. Figure 1 shows the proximity of the fields to the towns of Whitecourt and Edson and other key transportation arteries of the West White court Project. All discoveries were on a million-acre block of leases held jointly by Canadian Fina Oil, Ltd., Hudson's Bay Oil & Gas Company and PanAmerican Petroleum Corporation. Early in 1958, construction of the Windfall Pilot Cycling Plant began, and this plant was started up in July of 1959. Itwas designed to process 30 MMcf/D of Windfall well effluent, stabilize there covered liquids to produce a condensate product and reinject the gases back into the reservoir.
The Use of Capsules for Solids Transmission in Pipelines
Authors: Kruyer J. , Ellis H.S.
Published: March 2010

Investigations are being carried out at the Research Council of Alberta intothe possibility of using long-distance pipelines to move commodities in theform of long trains of cylinders or spheres. One of the most interestingdiscoveries of the laboratory investigations of this type of transport is thatthese forms, called capsules, with diameters close to that of the inside of thepipe, nearly always move faster than the average liquid velocity in the pipe.The reason for this is that the capsules occupy a region in the pipe where theliquid velocities are higher than the average liquid velocity. The density ofthe capsules has surprisingly little effect on their velocity relative to theliquid. The added pressure gradient in a pipeline due to the presence of acapsule train is proportional to the volumetric concentration of the capsulesand increases with capsule density, but does not increase or decreaseappreciably with liquid velocity. One important advantage that capsuletransport has over slurry transport is that pumping power is generally lower -except for slurries with very small particle sizes. Theoretical studies havebeen made, and numerical analyses have been used to predict the behaviour ofcapsules transported by a liquid in a pipeline. The experimental results thusfar have been obtained with laboratory-scale pipelines. Scaleup experiments arein progress to enable predictions to be made about the performance of capsulesin commercial lines.

Introduction

Pipelines have been used for several decades to move liquids over longdistances. The low cost of long-distance transport of liquids and gases bypipeline, which approaches that of surface transport by water, has in recentyears accounted for the construction of a large number of slurry pipelines in Europe and the Americas - ref. (1) to (9) - conveying a great variety ofdifferent materials. Further development of solids pipelining is foreseen, particularly in the United States and Canada, where railway freight rates oftenfar exceed production costs and tend to exclude western producers from nationalas well as international markets (2).
The Combustion Recovery Process - Principles and Practice
Authors: Dingley A.J.
Published: March 2010

It has long been recognized that increasing the temperature of oil-in-placein a reservoir is a means of increasing the recovery obtainable from low-gravity oil accumulations. However, the combustion recovery process was notfield-tested until 1952. Since then, the process has enjoyed increasing popularity, and, to date, some hundred projects have been started.

The reservoir mechanics of a combustion drive are complex, involving, asthey do, a fluid displacement, a heat transfer and a chemical reaction. Air isinjected continuously into the oil-bearing formation, and the oil around theinjection wellbore is ignited. This ignition can be achieved spontaneously, when the oil oxidizes rapidly, or it can be induced by pre-heating the air to ahigh temperature just prior to its entering the formation. A common displacement/combustion front is then moved through the reservoir toward theproducing wells. This process is known as forward combustion. In the reverse combustion process, oil around the production wells is ignited and the combustion front is moved counter current to the air injection.

When considering the applicability of the combustion recovery process to aspecific reservoir, the first step should be the rough estimation ofperformance based on data from various correlations of reservoir and fluid properties. If this is encouraging, laboratory burning tests should then becarried out. These consist of packing a steel tube with core material containing reservoir fluids in their correct proportions. A burning front is passed through this pack. Data obtained from this experiment enable the fuel deposit and unit air requirement to be calculated.

The areal sweep efficiency likely to be achieved in the reservoir can be obtained from potentiometric model data. The fuel deposit data obtained in the laboratory enable the displacement efficiency to be calculated, and so, having estimated the invasion efficiency, it is possible to calculate the oil recovery from the swept zone. The average oil displacement rate can then be calculated by relating the unit oil recovery, the unit air requirement and the air injection rate. The injection pressure requirement for a given air injectionrate can be estimated from flow formulae. However, the best method is to run an injection test in the field.
Simulation of Oil Recovery by Steam Injection From the Franklin Heavy Oil Field
Authors: Donohue David A.T.
Published: March 2010

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

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

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

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

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

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

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

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.
Combination Foam/Fluid Fracturing
Authors: Bullen R.S.
Published: March 2010

This paper describes the newly developed combination foam/fluid fracturing technique, dealing with the objectives of the process" the equipment required, a typical sand schedule, the calculation for frac area, fluid cleanup procedures and, finally, the advantages of combination fracturing. The areal extent of a combination fracturing treatment is discussed in the Appendix, along with fracture capacity and the fluid co-efficient for foam.

Introduction

One of the most significant innovations in fracturing technology in recent years -was the development of foam as a fracturing fluid in the fall of 1973. First conceived and researched by Blauer et al.(1) as a thesis project at the Colorado School of Mines, the process was quickly recognized by the oil and gas industry as a technique with a number of advantages resulting from the unique rheological properties of foam. Foam is now widely used as a fracturing fluid, for stimulating productivity of oil and gas wells, with a high ratio of success.(2,3)

"Combination Fracturing" was first introduced in February of 1977 as a further improvement of the Blauer form frac process, incorporating the best features of both foam and conventional fluid fracturing treatments in one job. Results of jobs performed to date indicate that Combination Fracs achieve equal or higher productivity increases than either foam fracs or fluid fracs alone.

Description of the Process

A Combination Frac is actually two different fracturing operations conducted in sequence on a' well first a foam frac, followed by a fluid fracture treatment. These two fracs are continuous, with transition from one type of operation to the other effected by increasing the pumping rates of the liquid and at the same time reducing the rate of the gas volumes pumped.

The first stage of a Combination Frac is generated by treated fluids and a specific N2 ratio to develop 75% quality foam at bottom-hole conditions. The foam is injected into the well as the base fluid of the fracturing treatment, with sand being added at concentrations of 1 to 2 pounds/gallon of foam. The rheological properties of foam, including its excellent sand carrying properties and low fluid loss, are such that it develops a fracture of considerable areal extent reaching deep into the formation.

In the second stage of a Combination Frac, the aeration and the foaming agent ratios are reduced. Simultaneously, the pumping rate is increased and sand ratios are increased to concentrations as high as 8 to 10 pounds per gallon. The increased viscosity of this fluid stage, combined with the increased rate, develops a greater crack width. This widening of the fracture, as? described in the Appendix, results in a higher flow capacity over the total frac area developed by the treatment.

Objective of a Combination Frac

The productivity of a well following fracturing is proportional to both the permeability contrast (flow capacity of the fracture in md-ft divided by the flow capacity of the formation in md-ft) and the extent of the fracture area, as illustrated in Figure I.