bluuebunny/crossref_metadata_2025 huggingface dataset:
Liquid Nitrogen Developments and Applications in Drilling and Completion Operations
Authors: Shouldice S.P.
Published: March 2010

Nitrogen is not a cure-all, but the results of field and laboratory workthat have evolved during recent years support its use as a valuable aid indrilling and completion operations. The advanced liquid nitrogen techniquespioneered in the Gulf Coast of the United States in 1959 have experiencedsignificant growth in the past four years. Such techniques are not confined tojust one or a few applications but have become intertwined with every aspect ofwell development and have made obsolete many oilfield practices previouslyemployed throughout North America. Liquid nitrogen, pumped at pressures of upto 10,000 psi, is forced through a gasifying heater and the colourless, odourless inert gas is injected into the well to perform a variety of valuable, safe and time-saving functions. These techniques have been field-proven inthousands of jobs and are supported by research results.

Industry has developed nitrogen procedures to:Provide uncontaminated drill stem test samples, reduce misruns and setpackers.Bring in wells without swabbing and its inherent hazards - day ornight.Enhance the benefits of stimulation treatments and force spent acid andfrac fluids out of the formation quickly and more efficiently, thus reducingwell bore damage and increasing productivity.Boost hydraulic perforating stream penetration up to 300 per cent, andsimplify "dry" gun perforating.Quickly droll mud weights to combat lost circulation while drilling andcementing.Combat paraffin and corrosion and increase inhibitor treatmenteffectiveness.Prevent downhole explosions when air drilling, and reduce formationcontamination by using nitrogen as a drilling fluid.

Introduction

Today, thanks to the missile age, the oil industry is served by liquidnitrogen units that are equipped with positive displacement "cryogenic" pumps.The cryogenic (super-cold) pumps were developed to handle fluids as cold as-350°F, which are common in the missile industry. With the introduction of thefirst liquid nitrogen unit in December, 1959, in Texas, and the use of thecryogenic pump, the versatility of nitrogen for oilfield uses has greatlyincreased.
Application of Advanced Well Treatment Knowledge
Authors: Hurst R.E.
Published: March 2010

Most well stimulation treatments involve the injection of some type ofliquid into subsurface formations. Rates of injection may be such that either amatrix treatment or fracture treatment will result. Improper application ofeither type of treatment may result in increased completion costs and damage toa well from the standpoint of ultimate recovery or future use as a storage orinjection well.

Well stimulation technology has advanced so rapidly during the past decadethat most production and engineering personnel have not had enough time toproperly analyze and apply all the new data, materials and techniques. Thispaper reviews new developments and shows how the various data may be collected, combined and applied for better treatment results and higher well profits.

Introduction

At some time in the producing life of most oil and gas wells, the need forstimulation arises. To make stimulation treatments more successful, a greatnumber of organizations and individuals have devoted large sums of money andtime to the development of improved engineering data materials and techniques.More technical information on well stimulation has been developed in the lastdecade than in the entire previous life of our industry. Because of this rapiddevelopment from many sources, most individuals have not had enough time toanalyze and apply much of this new data, and thus may not be receiving theavailable benefit. The purpose of this paper will be to show how, throughcollecting, combining and applying various data, the treatment of wells can bemore clearly understood and the results improved.

Stimulation by Injection

Most stimulation treatments in use today involve the injection of some typeof liquid into the formation. The stimulation effect of this injection dependslargely on what pattern the liquid follows in flowing from the well bore intothe formation.

If injection is started at a sufficiently low rate into a permeableformation and then increased, an injection- pressure profile can be drawn asshown in Figure 1.
Computer Analysis of Gas Field Deliverability and Development Economics
Authors: Winter C.R. , Edgington A.N.
Published: March 2010

Long-term forecasts of gas field deliverabi Iity are necessary for both transmission and producing companies in order to permit orderly planning of facilities and the development of reserves. A digital computer program has been developed and is described here in. It is used to predict the availability of pipeline gas over the producing life of a field or pool, to forecast the numberof wells required to deplete the reserves efficiently, and to schedule the drilling requirements. The program also computes the amount of compression asit is required.

Included in the output data are the average reservoir pressure and shut-in and flowing wellhead pressures for each year. Maximum daily per well allowable sand average well deliverabilities are calculated. These results are derived using the linear relationship between reseryoir withdrawals and P/Z forvolumetric reservoirs and using the wellhead deliverability curve. The latter function is empirical in derivation and makes use of the exponential relationship between rate of flow from a well and the difference of squares ofthe static and flowing wellhead pressures.

A special aspect of the program is the well economics subroutine. This feature enables the user to predetermine the limiting conditions that a wellmust satisfy in order to be considered economic to drill. The program will calculate the present worth of future net production revenue from each additional well at any specified discount rate and, if the result is favourable, the well will be added to the system and will yield a rate of return greater than, or equal to, that specified in the input data. Producingcompanies often require a well to yield a total net production revenue which issome multiple of the capital investment in the well. This "well payout multiple" is left as a variable in the input data to accommodate individualcompany policy and to make provision for risk, amount of capital invested, expected productive life and other factors to be considered in investment decision making. Provision is also made in the program to establish a limit to the maximum number of wells to be drilled in the reservoir.
Operations Research in Petroleum Production
Authors: Raleigh J.T. , Flock D.L.
Published: March 2010

The domestic petroleum producing industry in Canada and the United States is faced with serious foreign competition due to a high differential in producing costs. The crude oil transportation factor and government restrictions provide effective barriers behind which much of this country's crude is marketed. In order to become more competitive, many United States oil companies have introduced Operations Research into their domestic planning.

The purpose of this paper is to point out briefly where Operations Research has been used in the petroleum industry, with more specific application being given to producing operations. Some background thinking on the unique problems of petroleum production is presented. An example using linear programming, taken from the literature, deals with a multi-reservoir field producing operation.

It is concluded that favourable results can be obtained by using Operations Research techniques to either maximize profits or income or to minimize operating and lifting costs in petroleum production operations.

Introduction

Energy is one of the most basic building blocks of any industrialized economy. The forms of energy most commonly used in North America are crude oil, bituminous coal, natural gas and electricity. As the natural sources of theseenergies are commonly found at a considerable distance from their end use, the transportation cost will be an important factor in total energy costs.

The international character of crude oil movements and the changes in patterns that can take place from time to time are indicated by excess supply breaking through in some areas to cause price deterioration. Despite this, the basic fact remains that the United States and Canada are still largely supplied by domestic oil and that, despite very much higher production costs, the transportation factor and government restrictions provide an effective barrier behind which much of the crude is marketed.
The Medicine Hat Gas Field
Authors: Martin Ian
Published: March 2010

This paper discusses the development and performance of Canada's largest individual accumulation of gas. The proven initial gas in place is in excess of 2 trillion cubic feet.

The first well was drilled in the Medicine Hat sand in 1904, although gaswas known to be present in the area in the 1890's. During the first 50 years, development was very slow, as there was only a small localized market, and onlyabout 100 wells were drilled. The approval of gas export from Alberta during the 1950's provided the incentive to completely develop the pool. Subsequent approval for export from the Medicine Hat field led to the drilling of about300 wells between 1958 and 1963. The field now contains about 400 wells, and development is by no means complete.

The producing horizon is a shallow, thin, shaly sand. The determination of effective pay is complicated by the presence of extremely fine layering of the shale and sand. A correlation between logs and core analyses was developed in1959 following an intensive geological study of the cores. Further drilling andthe observation of field performance has proved this correlation to be satisfactory.

The uneven development of the pool over a period of 60 years has causedconsiderable gas migration into the older producing area. Engineering studies involving the application of fluid flow principles showed that the gas reserves of many operators who were denied access to the local market were being seriously depleted by drainage. These findings were presented to the Alberta Oil and Gas Conservation Board and may have been a factor in the subsequent granting of export permits for several operators. Methods of calculating the drainage across lease lines are described.

Recent engineering studies have shown that gas drainage is, in many instances, being curtailed. The previously penalized operators are now participating in their rightful share of gas from this field. It is now morethan ever an important asset to the economy of southeast Alberta.
Solvent Placement Improvement by Pre-Injection of Water - Lobstick Cardium Unit, Pembina Field
Authors: Kloepfer C.V. , Griffith J.D.
Published: March 2010

Stratification of petroleum reservoirs plays an important role in theperformance of fluid injection pressure maintenance recovery projects. Thesignificance of this factor in miscible recovery applications is emphasizedbecause of the generally adverse mobility ratios common to this type ofproject. The initial distribution of a miscible slug among the strata of areservoir dictates the volume of the reservoir that can be miscibly swept asthe slug is subsequently driven through the reservoir. The slug volume requiredto achieve miscibility in all strata of any given reservoir generally becomesprohibitively large. Improvement in permeability contrast prior to solventplacement will effect improved solvent utilization and enhance the efficiencyof this recovery technique.

The reservoir in the Lobstick area of the Pembina Cardium pool is severelystratified. In the area of miscible application, a conglomerate member, representing about 30 per cent of the reservoir volume, has a capacity of aboutfifty times that of the underlying sand. To improve the native capacitydistribution and to afford an evaluation tool for early injection performance,a 400,000-barrel slug of water was injected ahead of the solvent slug.Theoretically, this pre-injection of water will double the effectiveness of theinjected solvent. The calculation method for determining the improvement ofsolvent placement for Lobstick is described in detail.

Introduction

In miscible fluid displacement projects, reservoir stratification maysignificantly affect recovery because of the adverse mobility ratios common tosuch schemes. Solvent injection into a stratified reservoir will generallyresult in more permeable strata receiving a solvent volume in excess of thatrequired to effect complete miscible displacement before the less permeablezones have received the required minimum. The initial distribution of solventamong the reservoir strata governs the portion of the reservoir that can bemiscibly swept by the driving of this slug through the reservoir.
A Stable, Explicit, Computationally Efficient Method for Solving Two-Dimensional Mathematical Models of Petroleum Reservoirs
Authors: Quon D. , Dranchuk P.M. , Allada S.R. , Leung P.K.
Published: March 2010

There has been a growing interest in the use of two-dimensional mathematicalmodels to simulate the transient behaviour of oil and gas fields. Until very recently, the standard numerical technique used the alternating direction implicit procedure (ADIP) to integrate the basic partial differential equation describing flow through porous media. However, the computational problem, evenon high-speed computers, remained a form idable one. A new method for solving the conduction equations, first suggested by Saul'ev and later extended by Larkin, makes ingenious use of the known boundary conditions to permit an explicit point-by-point sequential evaluation of all interior grid points. A reverse sweep is used to minimize the over-all errors. The method, which may becalled an alternating direction explicit procedure (ADEP), combines thestability of the implicit methods with the computational ease of the explicit methods. By examining the structure of the computational models and noting their physical significance, it is shown that ADEP is a logical extension of ADIP and should have about the same accuracy. The new method is applied to anexample problem involving a volumetric under saturated oil reservoir, mathematically represented by several hundred grid points. The results indicatea possible order of magnitude saving in computer time for problems of this typeas compared to an ADIP solution. This suggests that three-dimensional models might now very well be practicable.

Introduction

The present paper is a preliminary report on a new numerical method, firstproposed by Saul'ev (1) and later extended by Larkin (2), for solving the basicpartial differential equation describing the flow of a slightly compressiblefluid through porous media. As it involves an alternating direction explicitprocedure, it may be referred to as ADEP.

Because of limitations of computational machinery and costs, existingmethods have been largely limited to the two-dimensional case. The mostefficient of these methods is the alternating direction implicit procedure, or ADIP, developed by Peaceman and Rachford (3). By examining the proposed methodin the mathematical context of earlier computational models, we can drawcertain, hopefully valid conclusions about its accuracy, its stability and itscalculational requirements. No attempt will be made here to give formalmathematical proofs of stability or to present a detailed error analysis -important considerations which have been examined elsewhere (4).
Application of Electrical Current for Increasing the Flow Rate of Oil and Water in a Porous Medium
Authors: Anbah Saleh A. , Chilingar George V. , Beeson Carrol M.
Published: March 2010

Part II of their paper already published in the Journal of Canadian Petroleum Technology, Vol. 3, No. 1, pages 9–14, Spring, 1964: "Use of Direct Electrical Current for Increasing the Flow Rate of Reservoir Fluids During Petroleum Recovery."

The possible use of direct electrical current for increasing the flow rate of reservoir fluids during petroleum recovery was recently investigated by Ambah et al. [1964] (29). As pointed out by the writers, however, thestudy of the application of electrokinetic phenomena in oil production was notcomplete, and many other problems remain to be solved.

The possibility of using electric current for enhancing the injectivity ofwater in waterflood systems or simply increasing the rate of production intight formations was further investigated in the present study. In all cases, the volumetric rate of flow increased on increasing the electrical potential imposed. Additional theoretical analysis is also presented here.

Theoretical Analysis

Reuss [1808] (2) was the first to notice that if two electrodes were placedin a liquid on opposite sides of a porous diaphragm, on application of an electromotive force the liquid would flow from one compartment to the other. An equilibrium will be reached when the hydraulic head, due to the difference influid level, is balanced by the driving force caused by the imposed e.m.f.

Wiedemann's [1852] (3) first and second laws stated that:

When an electrical field is applied to a liquid in capillaries, the flowis proportional to the electric current or the applied potential. If, instead, this flow is prevented, the electroosmotic pressure is likewise proportional tothe current.

Quincke [1860] (4) recognized electroosmosis and streaming potential as inverse phenomena and explained them by assuming the existence ofan electric double layer at the boundary surface between the liquid and thesolid wall. It can be assumed that the solid surface is negatively charged andthe positively charged part of the double layer is present in the liquid phase.Thus, upon the application of an external electrical field, the positivelycharged liquid layer will move toward the cathode, drawing with it watermolecules in the free liquid stream because of the viscous drag. Conversely, ifa liquid is forced through capillaries, a streaming potential or a streamingcurrent, depending on which is measured, is produced which is proportional tothe pressure differential applied.
Gas Cycling in the Lookout Butte Rundle Pool
Authors: Hnatiuk J.
Published: March 2010

The Lookout Butte condensate-bearing gas accumulation is contained in afractured thrust block of Rundle strata at a depth of 12,200 feet. Themoderately sour gas initially contained 106 barrels of pentanes plus permillion cubic feet of well effluent. As studies indicated that only 27.5 percent of the original pentanes plus in place were recoverable by normal pressuredepletion, a gas cycling scheme was initiated in 1963 to increase condensate recovery. Gas is produced from four wells, condensate is removed and stabilized, and sour, relatively dry gas is injected into a single well at the north end of the pool. It is anticipated that 33.7 per cent of the originalpentanes plus in place will be ultimately recovered if the pool is cycled at 40MMcf/D prior to pressure depletion. The prediction methods and performance todate are discussed. The effect of fractures on cycling performance isimportant. Performance in Lookout Butte during 18 months generally confirms assumptions regarding the effectiveness of the fractures. The elongated shapeof the reservoir is expected to result in a favourable areal sweep. This configuration also permits flexibility in the event that a second injection well is required in the future.

Introduction

The Lookout Butte Rundle gas pool is located in the extreme southwestern corner of Alberta between the Pincher Creek Rundle gas pool and the International Boundary, as shown on Figure 1. The pool was discovered in1959 by the drilling of B.A. Lookout Butte 11–31, in Lsd. 11-31-1-28 W/4, which encountered gas-bearing Rundle at approximately 12,000 feet. Seven wells were subsequently drilled, which resulted in four producing gas wells, two marginal gas wells and one abandonment. The Lookout Butte Rundle Unit No.1 became effective in August, 1963, at which time gas cycling commenced.

Reservoir Characteristics

I. Geology

The Lookout Butte reservoir is a thrust block of Rundle strata, strikingnorth-northwest, dipping west and plunging gradually northward. Maximum elevation of the thrust block above the regional elevation of the Rundle is approximately 1,500 feet.
The Chemical Treatment of Water Used in Steam Injection Systems
Authors: Walker Charles L.
Published: March 2010

The chemical treatment of waters used in steam injection involves the control of the following problems:the removal of oxygen from the process waters;the prevention of mineral deposition due to hardness leakage by the ionexchangers;the control of corrosion in the steam injection lines; andthe prevention of biological growths in the source water.

This paper deals with the fundamentals of water chemistry involved insolving the above-mentioned problems and the chemicals necessary to bring aboutthe control. The author will also discuss the divergence of opinions on thenecessity to treat waters used for steam injection systems. The treatment problems involved in the production of steam-treated crudes will also be considered.

Introduction

Everyone knows that the chemical symbol for water is H2O; butwhat few people realize is that, unlike other symbols for chemicals, the(H2O) symbol tells us very little about what water is. Water is only H2O at the first instant of its formation. From the time water fallsthrough the atmosphere until it reaches its final resting place, waterdissolves the various gases and minerals with which it comes into contact. Therefore, water as we know it is actually a solution of minerals and gases. Itis, therefore, this aqueous solution of minerals and gases that we deal with inthe everyday use of water; and the types of these components in water governthe use to which it can be put. In no place is this fact more strikingly revealed than in the examination of waters used for the generation of steam.The presence of certain minerals and dissolved gases is directly related to many of the operational problems involved in the production of oil by steam injection.
Advances in Estimating Gas Well Deliverability
Authors: Winestock A.G. , Colpitts G.P.
Published: March 2010

In the past, drawdown tests to estimate well deliverability and diagnose wellbore damage, although simple in themselves, have been of limited value, often because it is inconvenient or costly to obtain the constant flow rate required to analyze them reliably. This paper presents a new drawdown analysis technique developed with the aid of a digital gas-well simulator. The new method does not require a constant rate, is as simple to analyze as the conventional method and is considerably more accurate. It can thus heused in gas wells to analyze the early time data from a back-pressure test when the rate has not yet "stabilized" to a constant value. The new technique takes into account turbulent flow in gas-well systems - a prerequisite to calculatinga gas well's current and potential deliverability. These calculations areeasier if at least two drawdown tests, and preferably, more, can be conducted on the gas well. Fortunately, the practice of running a multiplicity of drawdown tests is already embodied in the four-point isochronal AOF test, where each flow test is separated from the others by a sufficiently long period of shut-in. This type of test lends itself to reliable drawdown analysis. However, in the four-point flow-after flow test, where the flows at each rate are consecutive, the deliverability estimates often are not reliable. The new drawdown technique is not limited to use in gas wells. It can also be used toestimate well productivity and diagnose wellbore damage in oil or water systems.

Introduction

Gas flow in a porous medium is different from oil or water flow in that itdoes not obey the Darcy Law. In the gas-reservoir-engineering literature (1), this difference is now commonly called "turbulence." Turbulence occurs becausethe low viscosity of gas (compared to that of oil or water) results incorrespondingly higher gas velocities under a given pressure gradient. At these higher velocities, the gas suffers inertial energy losses as well as the usualviscous energy (Darcy) loss.
Understanding Surface Casing Waiting-on-Cement Time
Authors: Maier L.F.
Published: March 2010

The waiting-on-cement time in low-temperature surface casing cementing canvery often be reduced to less than what is common practice today through abetter understanding of cementing conditions. Two major factors in the earlydevelopment of the compressive strength of cement are the water-cement ratioand the curing temperature. The latter is partially dependent upon theformer.

The strengths of cements required for drill-out are discussed, and the curing times required to achieve the necessary strengths are presentedgraphically. API Class A, B and C cements are considered, and the advantages of using the densified systems are illustrated.

Data from field studies concluded over the past several years, including temperature measurements on well fluids and temperature surveys followingcement jobs, illustrate the curing temperature behaviours of typical western Canadian surface casing cement jobs. The effects caused by heat of hydrationand by cement mixing water and displacement fluids which are warmer than formation temperatures, can be rather significant, producing average curing temperatures which are higher than the surrounding formation temperatures by asmuch as 5°F to 30°F or more.

A laboratory study was made to determine the comparative effects of the heatof hydration of cement slurries under different conditions. The heat evolved isincreased when (1) the slurry is placed at a higher starting temperature, (2)the volume of slurry is increased and (3) the slurry is mixed at a higherdensity.

Cementing practices are discussed and recommendations made. With a more thorough knowledge of the basic factors involved, it should be possible in manycases, to more accurately correlate the required waiting-on-cement time withthe conditions as they exist rather than adopt a policy of fixed time which satisfies all probable conditions of cementing materials, temperatures and techniques.

Introduction

The phrase "waiting-on-cement," or "WOC," has long been a misnomer in mostinstances. The nonproductive and expensive time spent waiting has usually notbeen necessary, because, in fact, the cement was firmly set and was actuallywaiting on us. Increasing concern is being expressed by the industry over thiscostly waste, and continual attempts are being made to reduce WOC time to asafe minimum. The area of greatest interest appears to be that of surfacecasing cementing; this is due to the difficulties caused by the lowertemperature curing conditions.
Northern Oil Prospect Re-Examined
Authors: Quirin G. David
Published: March 2010

This paper updates a study made five years ago, reviewing the main points and noting how changed conditions may affect the economies of oil production inthe Arctic Islands and the northern mainland. Wellhead prices and possiblemarkets are estimated; offshore development is a new factor. The paper concludes with a consideration of the effects on Prairie production and possible government controls to regulate oil production in the North.

Introduction

I have dealt at length, in a monograph, with the basic factors affecting the feasibility of oil and gas development in northern Canada (1). That study was prepared five years ago, and conditions have changed. The purpose of this paperis to review the main points made in my earlier study, and to see how changed conditions may have affected the prospects for northern oil development. The development of any natural resource industry in a given geographic setting isthe result of a partly fortuitous, partly controllable combination of factors physical, technological, political and economic - which together make possible the profitable exploitation of the underlying resource. Emphasis must be placedon the word profitable, for development which is not profitable is sheer waste, puts more into the ground than will ever come out, benefits no one, and is unlikely to be viable in the long run. I propose to review these factors briefly as they apply in this case.

Physical Factor

As the underlying basis for the development of any natural resource industryis the resource itself, I will examine the physical factor first. Compared withthe state of our knowledge five years ago, our knowledge of the intimatepetroleum geology of the Canadian North has increased enormously, thanks to thedrilling programs carried out in the intervening period. However, it would bemore accurate to say that what has been achieved is a slight reduction in ourenormous ignorance. We've had a few surprises, and perhaps found a few placeswhere the oil isn't, and we can expect to find a few more of these before wefind out where the oil is.
General Geology of Lower Cretaceous Heavy Oil Accumulations in Western Canada
Authors: Vigrass L.W.
Published: March 2010

Lower Cretaceous sand reservoirs contain about 750 billion barrels ofviscous, heavy oil along a broad arcuate belt that extends from northwestern Alberta into west-central Saskatchewan. The heavy oil is pooled in the Mannville Group and, in a gross sense, occurs in a marine-continentaltransition facies. The accumulation at Peace River is in a regional onlapfeature. The accumulations in the Athabasca-Lloydminster region occur acrossthe crest and on the southwest flank of a regional anticlinal feature associated with the solution of salt from Middle Devonian beds. These regional features had already formed by the end of Early Cretaceous time.

Chemical and physical properties of oils from different accumulations show that they belong to a single oil system and suggest a common mode of origin.The Athabasca oil is young and immature and not evaporated, altered orpolymerized. The oil is not escaped and re-deposited Devonian oil. The mosttenable working hypothesis is that hydrocarbons moved out of sediments in thedeep basin in micellar solution in compaction waters. The hydrocarbons weredeposited as heavy asphaltic oil where physical-chemical conditions weresuitable. Early formed stratigraphic and structural "traps" served as loci of deposition for the heavy oil. Since deposition, and governed by buoyancy and capillarity, there has been some adjustment in position of the oil inthe traps.

Introduction

This paper concerns the geology of the main belt of Lower Cretaceous heavyoil accumulations in Western Canada. It is hoped that the regional approach that is used will improve our understanding of the individual accumulations and will aid in their exploitation.

The main Lower Cretaceous heavy oil belt extends as a 600-mile arc from Peace River in northwestern Alberta to Lloydminster in western Saskatchewan(Figure 1). The total amount of heavy oil reservoired in the sandstonesof the belt is immense, totalling at least 750 billion barrels of oil-in-place.About 95 percent of the known oil occurs in the Athabasca, Peace River, Wabasca and Cold Lake deposits.
Economic Considerations Concerning the Use of Salt Caverns for Natural Gas Storage by an Integrated Natural Gas Transmission and Distribution System
Authors: Clipsham W.B. , Olafson D.G. , Pratt B.G. , Steuart B.A.
Published: March 2010

The system under discussion, that of the Saskatchewan Power Corporation, transmits and distributes natural gas to customers whose numbers are small inrelation to the transmission distances involved. The severe continental climate coupled with the long transmission distances make the expense of meeting the peak demands imposed on the system particularly onerous. Although the systemhas available depleted gas fields that are satisfactory for storage, both in adeveloped and in a potential state, none of these reservoirs are close enoughto the load centers to alleviate the demand on major transmission systems.

Much of southern Saskatchewan is underlain by the Prairie Evaporite formation, which consists mainly of potassium and sodium chlorides. This formation occurs in thicknesses of up to 600 feet, and at depths ranging from 2,500 to 7,000 feet.

The Corporation has undertaken to develop natural gas storage in caverns that have been washed from the Prairie Evaporite formation by a solution mining process. Two of these caverns are presently in operation, and a third is in theprocess of being washed out. The economic considerations for developing these caverns are quite different from the considerations governing the development of a conventional storage field. The differences in these considerations arise, first, from the fact that the size of the reservoir is controllable and, secondly, because this type of reservoir has a relatively limited total volume compared to its delivery capability. This paper will outline the techniques bywhich the Corporation has attempted to analyse the relationship between pipe-line capacity arid cavern storage volume in order to fulfill the system requirements at minimum cost.

The Corporation's System

The Saskatchewan Power Corporation's natural gas transmission system extends throughout the populated area of Saskatchewan. With service to all of Saskatchewan's cities and most towns, the total number of customers served at year-end 1964 was 105,251.
Helium Prospects for Canada
Authors: Reed G.A.D.
Published: March 2010

Helium is a space-age engineering material used for: the refrigeration ofcommunications equipment (telestar); welding space-age metals such as titaniumand magnesium, as well as aluminum; and as a heat transfer medium inexperimental atomic reactors. It is also used in shock-tube tests, leakdetectors, as a carrier gas in chromatographs, in space simulators, inmeteorological balloons and in upper air research. Canadian helium is marketedon a world-wide basis. It is produced in Saskatchewan by the liquefaction of agas mixture which is principally nitrogen. Shipping helium in liquid form may provide sufficient savings in handling costs to reduce the cost to theconsumer.

Introduction

Canadian helium prospects are related particularly to the sole Canadianproducer, in fact the sole helium producer in the Western World outside the United States. Canadian Helium Limited, with a recovery plant located near Swift Current, Saskatchewan.

Helium is an inert rare gas, and the second lightest element known. Prof.H.J. Lockyer, the astronomer, discovered it 97 years ago in the spectrum of thesun, and in 1905 researchers at the University of Kansas identified it innatural gas. The era of the space age and the demands for atomic energy, however, have elevated helium from a role as simply a balloon-filling gas tothat of an exotic engineering material.

Markets

There is a market for helium in nearly every industrialized country of theworld. Russia supplies the needs of the communist world. Until the Canadianplant went onstream in late 1963, all of the free world's supply of helium wasprovided by the United States. Since the first world war, helium has been astrategic war material and the United States has restricted its export. Infact, export licences approved by the Secretary of State are required. As lateas 1962, the amount exported from the U.S. for approved scientific and medicaluses was approximately 9 million standard cubic feet, with more than 3.0 million cubic feet going to Canada.
The Offset Obligation in the Oil and Gas Lease
Authors: Nelles R.B.
Published: March 2010

This paper includes an analysis of the offset clause contained in most oiland gas leases, with particular emphasis upon the implications of the newproduction spacing units.

The Need for an Offset Clause

Petroleum and natural gas are of a fugacious nature, and, being lighter thanthe water that is present in porous strata, migrate up dip and accumulate whenentrapped by a permeability barrier. If there is static pressure in thereservoir, there will be no migration of the hydrocarbons. However, if there isa pressure change, such as a well piercing the reservoir, there will bemigration to an extent which would depend on the porosity and permeability ofthe reservoir rock as well as on the degree of the pressure change. Thehydrocarbons will move toward the point of low pressure. Under thesecircumstances, it is conceivable that if production is taken from a well onland owned by lessor A, hydrocarbons underlying land owned by lessor B couldmove to a position under A's land and be brought into A's possession, there by diminishing the quantity of petroleum and natural gas under B's land.

It becomes apparent that the lessor must ensure that the lessee doeverything he can to prevent hydrocarbons from being drained by others fromunder the lessor's land, and the most effective way a lessor can protect hisinterest is to have the lessee drill a well on his own land and produce thehydrocarbons before they have been produced through the well on the adjoiningpremises. This need to protect against drainage has given rise to a drillingcommitment, often incorporated in oil and gas leases, known as the "offsetobligation." This requires the lessee to commence drilling within a specifiedtime from the time that production in commercial quantities is obtained on theadjoining lands.
Engineering for the Petroleum Industry in the Arctic
Authors: Hemstock R.A.
Published: March 2010

Experience in Western Canada has shown that we can work effectively in themost severe climate, and so the question is no longer can the Arctic bedeveloped - but rather, how can it best be done. Transportation, logistics, communications and planning are key words in describing successful Arcticdevelopment.

Transportation is probably the most costly single factor in northern work.This is due partly to the lack of modern transport means in the north, andpartly to the seasonal nature of some methods of transport, e.g., inlandwaterways, but it is mostly due to the great distances involved.

Geological work is being done very well by helicopter and small fixed-wingaircraft. Geophysical work is being carried out using tracked equipment eitheryear-round or on a seasonal basis, with trucks being used in the winter.Wildcat drilling has been quite comparable to that in other areas of Western Canada, except for the high cost of transportation.

Permafrost, which underlies the Arctic and most of the sub-Arctic, resultsin special engineering problems for foundations, water supply, road building, etc. Methods are available for handling these, although we have much to learnin optimizing the engineering solutions.

Modern oilfield technology can be applied in the Arctic, and suchdevelopments as automation will be essential in the economic development ofnorthern oil.

Introduction

This paper will outline and suggest possible solutions for some of theengineering problems that affect the development of oil reserves in an Arcticor sub-Arctic environment. The theme might well be summarized by quoting Dr.John C. Reed, director of the Arctic Institute of North America, who says: "Thelimitations of northern development are largely the limitations of knowledgeand experience and not limitations of environment." There is much to be learnedbefore we can be sure we have the best engineering answers.
Alberta Proration - A Year of Transition
Authors: Strom N.A.
Published: March 2010

This paper outlines the Alberta Oil and Gas Conservation Board's new planfor prorating crude oil production in Alberta. A review of the objectives ofthe new plan, the deficiencies of the old plan and the changes adopted is firstpresented, and then the implementation and effects of the plan are discussed.Sections of the paper are devoted to well spacing changes, maximum ratelimitations and recovery efficiency, and the achievements noted in the earlystages of the plan are listed.

Introduction

Pursuant to its report concerning proration issued in July, 1964, the Alberta Oil and Gas Conservation Board took steps to implement a new plan ofprorating crude oil production in Alberta commencing on May 1, 1965. Theprocedure of conversion to the new plan provided for a four-year transitionperiod culminating on April 30, 1969. Nearly one-quarter of the transitionperiod has passed, and this paper reviews, at least in part, the effects of themeasures adopted in the new plan.

Review

The following is a brief review of the objectives aimed for in the new plan, the deficiencies of the old plan, and the actual changes adopted to foster theobjective and overcome the previous deficiencies. In addition to the explicitstatutory objectives, which need not be repeated here, the objectives sought inthe new proration plan include the following:the encouragement of efforts to enhance recovery from pools;the deferment of the abandonment of wells until all apparently economicallyrecoverable oil has been produced;provision for the production of low-reserve-per- acre discoveries whichappear to contain economically recoverable oil;to provide a system which is relatively simple to administer;to provide a method of allocation operable over a wide range of marketconditions, both as to supply and demand, and allow continuity in theproduction from and development of pools;to encourage exploration and not deter any party interested from exploringfor new reserves;to maintain the participation in the industry by anyone interested;andto encourage the economic optimum development within pools, and minimizethe cost of drilling and producing oil.
A Theoretical Comparison of Heat Transfer into Porous Media by the Injection of Steam or Hot Water
Authors: Sarem A.M. , Hawthorne R.G.
Published: March 2010

A comparison of the heat-carrying capacity of hot water and steam indicatesthat hot water can impart considerably more heat to a formation than does steamat relatively low pressures. This results from the greater density of hot waterand its corresponding greater mass flow rate at a given injection pressure. Athigher pressures, this advantage of hot water becomes smaller, and itdisappears completely at the critical pressure of water.

The relative heat-carrying capacities of hot water and steam are influencedby the presence of residual oil in the formation. Greater oil saturations leadto lower heat-carrying capacities of hot water relative to steam. Thesedifferences are a reflection of differences in relative permeabilities of theflowing fluids.

The work reported here is considered to be preliminary in nature; severalbasic simplifying assumptions were used in it. Under conditions other thanthose assumed, the relative effectiveness of hot water and steam could besomewhat different from that reported here.

Introduction

When heat is imparted to a formation by hot water or steam injection, theoil recovery is increased due to thermal expansion of oil, reduction in oilviscosity and, in the case of steam drive, steam distillation of the crude (1).The degree to which oil recovery is increased is affected particularlyby the temperature dependence of the oil viscosity. In many cases, thereservoir oil viscosity can be reduced several hundred-fold by hot water orsteam heating to drastically increase the oil mobility. Figures 1 and2 show the relationship between temperature and viscosity for steam andwater (2). Note that water viscosity decreases with increasing temperature, butthat the steam viscosity increases with increasing temperature at pressuresbelow 1000 psi.

When a reservoir has been selected for heal treatment, it is necessary todetermine the most economical means of transferring heat into it. At firstglance, steam may seem to be a better heat carrier than hot water because itsheat content per unit mass is higher than that of water at the sametemperature.
Waterflood Behaviour of the Low-Gravity Wainwright Pool
Authors: Pawelek J. , Chorney M.
Published: March 2010

This paper outlines the development and performance of the Wainwright fieldin east-central Alberta, where the Wainwright sand produces 20–22-gravity oilfrom a depth of approximately 2,100 feet. The field was the first heavy oilpool in Alberta in which pressure maintenance by waterflooding was undertaken.Although pressure maintenance has been in progress for only three years, theperformance during this period is indicative of the project's success.

To forestall the adverse effects of rapid pressure decline and increasinggas-oil ratios in this solution gas drive reservoir unitization as aprerequisite to full-scale pressure maintenance was instituted. The field wasunitized as five separate units, with pressure maintenance conducted by two operators.

To the end of 1965, the cumulative oil production from the field wasapproximately 8,600,000 barrels. In December, 1965, oil production was 4,560barrels per day, with pressure maintenance accounting for approximately 70 percent of this. The ultimate recovery (primary plus waterflood) for the field hasbeen estimated at 31,300,000 barrels, which is more than double the recoveryanticipated by natural depletion.

Introduction

The Wainwright Sand reservoir is located on the southwestern flank of theheavy oil region of east-central Alberta. This is shown in Figure 1. Thefield was the first heavy oil pool in Alberta in which pressure maintenance bywaterflooding was undertaken. The reservoir was developed on 20-acre spacing, and the unitized areas include 202 producing wells. Reservoir characteristicsare included in Table I.

The reservoir has a gas cap and an aquifer. During primary depletion, itproduced principally as a solution gas drive reservoir with some gas capexpansion. This was evidenced by rapidly declining reservoir pressures andincreasing gas-oil ratios. Although some water was produced from down-dip wellsalong the southwest rim of the present producing limits, and there was anoticeable encroachment of water before unitized operations began, there was noappreciable recovery resulting from the water influx. Early in 1959, it wasobvious that the natural energy of the reservoir was going to produce only asmall fraction of the original oil-in-place.
Cementing Practices for Thermal Wells
Authors: Pollock R.W. , Beecroft W.H. , Carter L.G.
Published: March 2010

The introduction of steam as a means of stimulation for oil production haspresented many problems in oil well completions. Some of the difficultiesexperienced have been casing failures, pipe growth, cement failure and cementbond breakdown. Data are presented on cementing compositions and casingcementing techniques which may help build a sound steam injection well or onewhich can withstand the stresses and strains of intermittent steam injectionand production.

Introduction

Production of low-gravity, high-viscosity crude oil has been increased inrecent years by downhole electric heaters, in-situ combustion and steamstimulation (1). Of these methods, steam stimulation appears to be the mostpromising and is being used by many producers in the oil fields of Western Canada. Steam injection, by either of two systems, has become a complexproblem. The displacement or flood technique is considered to be lesstroublesome once the field has been prepared for it, but the necessary flowlines and permanent steam generating equipment makes the initial expense veryhigh. Most of the Canadian producers have utilized the second steam stimulationtechnique, that of intermittent steam injection with portable equipment - or, as it is more commonly called, "Huff and Puff." Although this second approachis less costly than the use of the permanent generating station, most of theproblems inherent with steam stimulation still exist. The most common problemsencountered are those of casing failure and/or cement failure. As long as steaminjection temperatures remain below 400°F, these problems seem to be at aminimum; however, as injection pressure increase, with the correspondingincrease in temperature, the quality of the casing, cement and cement placementbecome important factors in the success or failure of the treatment. Most ofthe Huff and Puff projects in Canada to date have been in the temperature rangeof 550° to 620°F (1,200 to 1,800 psi), although equipment is available to raisethese conditions to 670°F and 2,500 psi, respectively. Many treating failureshave been reported at the lower treating levels and many more failures areexpected to occur when the equipment is utilized to the maximum extent.