bluuebunny/crossref_metadata_2025 huggingface dataset:
Heat Transfer During Hot Fluid Injection Into an Oil Reservoir
Authors: Spillette Arthur G.
Published: March 2010

The engineering evaluation of thermal recovery processes depends on the ability to predict their behaviour in the field. Such a prediction, whetherbased on physical or mathematical models, requires an accurate accounting of the thermal energy utilized by the process. This paper presents a criticalreview of the important contributions to the literature concerning heattransfer during hot fluid injection into an oil reservoir. The heat transfer mechanisms, the resulting energy balance equation and the restrictive assumptions necessary to obtain analytical solutions of the energy balanceequation are discussed. These solutions yield information relative to the thermal efficiency of the process and the temperature distributions within the reservoir and the surrounding impermeable media. However, to date, the published techniques have been limited to injection into a linear or radial homogeneous sand with constant physical properties and have not considered multidimensional heat transfer completely. We have applied a recently published numerical technique to the solution of the energy balance equation in order to remove these limitations. The accuracy of the numerical method for the case of one-dimensional fluid flow is demonstrated in the paper by comparing the calculated thermal efficiency for hot water injection into a water sand to the corresponding analytical solution. A comparison with published experimenta lresults demonstrates the utility of the method and confirms our understanding and analysis of the heat transfer mechanisms.

Introduction

Predictions of the field behaviour of thermal recovery processes require anaccurate accounting of the energy that is injected into (or generated within)the reservoir. Numerous heat transfer models of the basic thermal processeshave been formulated and solved analytically (c.f. ref. 6, 7, 8, 14, 16, 19).Although limited in scope because of necessary restrictive assumptions, these solutions have proved useful in the development of interpretative mathematical models of the processes (12, 20, 21). For heat transfer during the forward underground combustion process, numerical (3, 4) as well as analytical solutions have been obtained.

The following sections discuss the heat transfer mechanisms that take placeduring the injection of hot fluid into an oil reservoir, the energy balance equation and the assumptions necessary to obtain analytical solutions of the energy balance equation. All of the analytical solutions that have appeared inthe literature are limited to a consideration of one-dimensional incompressible fluid flow in a homogeneous sand with constant physical properties. This paper presents a numerical solution of the energy balance that is not hampered bysuch assumptions, and compares it with published experimental results.
Improving Waterflood Recovery of Viscous Crude Oils by Chemical Control
Authors: Scott G.R. , Collins H.N. , Flock D.L.
Published: March 2010

A model study was carried out to determine the influence of rate, viscosity, ratio and interfacial tension on the waterflood recovery efficiency of viscouscrude oil from sands native to the Lloydminster area. Displacement tests on along sand pack showed that scaling and viscous fingering were important factorswhen comparing test recoveries. Above a certain critical displacement rate, dependent upon the viscosity ratio, breakthrough recoveries decreased withincreasing rate.

Laboratory studies of brine – crude oil interfacial tension were made on anumber of acid and alkaline solutions to determine their suitability forwaterflooding. As a result of these studies, displacement tests were run usingweak sodium hydroxide solutions to displace natural crude oil from sand packs.The tests indicated that sodium hydroxide may be added to injected brine toincrease oil recovery above that obtained by natural brine flooding.

Part A

Model Tests of Viscous Crude Recovery Using Native Brine

Introduction

The waterflooding of high-viscosity oil reservoirs has been looked uponskeptically in the past because of expected low recoveries. This may explainthe dearth of fundamental studies of the influence of viscosity ratio onwaterflood recoveries at ratios greater than 100 to 1. Viscosity ratio, as usedherein, is the ratio of the viscosity of the displaced to the displacing fluid.

A purpose of this work was to examine the influence of viscosity ratio onrecovery by waterflooding. Preliminary measurement of dead Lloydminster crudeviscosities at reservoir temperature indicated that viscosity ratios of up to 1,500 to 1 would be within the range of interest.

The scaling of a model to a reservoir requires attention to the propersimulation of the relative roles of capillary and viscous forces. Thefundamental work of Rapoport and Leas (24) and later Kyte and Rapoport (19) have detailed the theoretical and experimental basis for conducting laboratorydisplacement tests at a rate sufficient to minimize misleading capillaryeffects. Such phenomena are not usually considered to be significant in thereservoir because of the much greater length of the system.
Pressure Maintenance by Waterflooding North Virden Scallion Field, Manitoba
Authors: Park R.A.
Published: March 2010

The North Virden Scallion field is located on the northeast flank of the Williston Basin and produces from the Virden and Scallion members of the Lodgepole formation of Mississippian age. The reservoir was highlyundersaturated initially. The sources of energy for primary production werecombinations of oil expansion, partial edgewater drive and limited bottom-waterdrive. Laboratory flooding tests and engineering calculations indicated thatwaterflooding could more than double the anticipated primary recovery andsignificantly increase the rapidly declining production rates. It was estimatedthat the ultimate primary recovery of 25,000,000 barrels could be increased to 55,000,000 barrels.

After five years of planning and negotiating, a portion of the field wasunitized and a nine-spot waterflood was installed. Water injection began in December, 1962. Results to date have been encouraging. Production has increasedfrom a pre-flood rate of 2,900 BOPD to 4,750 BOPD. Additional oil recovery dueto waterflooding is estimated to be more than 500,000 barrels to year-end 1964.To assist in predicting and controlling the advance of the flood fronts, injection profiles have been run on the injection wells and a digital computermodel to simulate the project is currently being constructed.

Introduction

The North Virden Scallion field is located in southwest Manitoba, 30 mileseast of the Saskatchewan border and due north of the town of Virden. Thisplaces the field approximately midway between Regina and Winnipeg. Productionis obtained from the Virden and Scallion members of the Lodgepole formation of Mississippian age at a depth of 2,000 feet.

The field was discovered in December, 1953, by The California Standard Company with the drilling of Calstan Scallion 3-11-11-26 W.P.M. Developmentfollowed rapidly, and by 1961 more than 300 wells had been drilled, of which274 were capable of production. All wells were drilled on 40-acre spacing andplaced on pump soon after completion.

In early 1957, the field's production rate and pressure were decliningrapidly and the need for pressure maintenance had become obvious. Engineeringand laboratory studies conducted that year showed that waterflooding was theonly economical method of secondary recovery.
Methods of Sludge Control During Acid Stimulation Treatments
Authors: Crowe C.W. , Hendrickson A.R. , Dobberthien R.F.
Published: March 2010

The formation of asphaltic sludge during acid stimulation has been a seriousproblem in many areas for several years. Such sludges have had adverse effectson the results of treatments in several Canadian reservoirs. Recent studieshave shown that sludge may also affect results in many areas where its effectshave not yet been recognized. These studies indicate that:Sludge is a precipitate of colloidal materials present in crude oils.The precipitates occur due to changes in the environmental conditions ofthe crude by the addition of materials such as acid.Once formed, sludge is insoluble in most treating chemicals.Sludge can be prevented or controlled by the use of stabilizing agents intreating fluid or by the use of certain solvents as the outer phase ofacid-in-oil emulsions.

The purpose of this paper will be to show how and why sludge is formed andhow it can be prevented or controlled. Simple laboratory tests to determine theprobability of sludge formation prior to treatment are discussed. Actual fieldresults point out some of the problem areas in Canada and show that sludgecontrol during acidizing treatments can increase productivity in theseareas.

Introduction

The formation of sludge by crude oil on contact with acid has beenrecognized as a serious problem in isolated areas for some time. The problemwas apparently first observed in certain California wells. In these wells, itwas noted that following acidizing treatments the wells were very slow to cleanup, and often a great deal of asphalt-like material was returned with thetreating fluids. In some cases, complete or partial plugging of the wellresulted from the treatment. A study of this problem revealed that the crudeoils produced from these wells actually formed solid precipitates upon contactwith acid. An analysis of these sludge-like precipitates showed them to be madeup mainly of asphaltenes, resins, paraffin waxes and otherhigh-molecular-weight hydrocarbons. These materials were apparentlyprecipitated from the crude by the reduction in pH as a result of acidcontact.
Applications of the Continuous Dipmeter in Western Canada
Authors: Goetz J.
Published: March 2010

This paper discusses the application of the continuous dip meter, an instrument which not only determines dips and tops of formations but alsoyields basic information on sedimentology and stratigraphy. After a brief description of the apparatus and the methods of plotting its readings, theauthor explains the interpretation of information for various geologic features- reefs, sands and unconformities. All of the examples are from oil wells in Western Canada, and the influence of the continuous dipmeter on petroleum exploration is stressed.

Introduction

It is a basic physical fact that oil tends to migrate to a position abovewater, and that gas tends to migrate above both oil and water. It seems, therefore, that nothing is more fundamental in oil exploration than determining which way is up. Essentially, this is the purpose of the continuous dipmeter. However, interspersed with the basic information as to which way is up is awealth of other information related to deposition. So the dipmeter becomes, inaddition, a basic tool for studies of sedimentology and stratigraphy.

The down hole equipment of the continuous dipmeter, illustrated in Figure1, features three identical sets of electrodes mounted on spring-actuated wall-contact arms. The arms are spaced 120 degrees from each other. The electrodes lie in a common plane perpendicular to the axis of the tool. As this system of electrodes passes a bed boundary, similar resistivity signals fromeach electrode are sent to the surface and recorded on film. If an anomaly onthe curves is caused by a bedding plane crossing the borehole at other than a 90-degree angle, the anomalies on the individual curves occur at slightly different depths. Figure 2 illustrates the behaviour of the three curvesat a steeply dipping bedding plane.

The relative displacements of the three curves, in inches of borehole, arecombined with hole caliper and hole deviation data to compute the amount and direction of formation dip. This process is performed for many correlatable anomalies on the three resistivity curves.
The Retrievable Casing Liner - A New Production Tool
Authors: Bullen R.S.
Published: March 2010

A tough, synthetic rubber sleeve has been developed which may be positionedin perforated casing with great accuracy. When set in a well, the liner sealsoff all perforations it covers, permitting fracture treatment or otherstimulation work either above or below the selectively closed interval. Thetool is run, set, retrieved or repositioned by wireline, thus keeping costssubstantially lower than those of conventional tubing and packer arrangements.

Introduction

During workover operations, it is often desirable to selectively seal offone or more sets of perforations in order to facilitate the directtreatment of a specific zone. Similarly, on injection wells it is sometimesrequired to isolate a particular interval either temporarily or permanently inorder to improve the injection profile. In the past, this selective isolationhas been largely accomplished by packer-tubing arrangements. A new wirelinetool, the Select Liner® is now available for these applications.

Tool Construction and Operation

The Select Liner is composed of 5/8-inch neoprene tubing material with nylongrid reinforcement, molded on each end to a threaded steel collar. In aparticular application, a liner is selected which has an outside diameterslightly larger than the inside diameter of the casing in which it is to berun. By stretching the liner lengthwise over a setting tool, the liner diameteris reduced so that it may be run easily inside the casing. Figure 1illustrates this principle. The setting tool holds the liner in its stretchedposition while the assembly is run in the hole. An electric collar locator isattached to the top of the tool for precise location over the interval to beselectively closed. An electric device then releases the ends of the liner, which tries to snap back to its original dimensions. Having a slightly largerdiameter than the casing, it expands to conform to the inside of the casing, sealing off the formation from all internal casing pressure.
Introduction to the New Halliburton-Welex Dip Meter
Authors: Haynes J.E. , Winn R.H. , Nelner S.H.
Published: March 2010

To provide a more detailed study of the structural conditions in a well, anew continuous dip meter tool is offered to the industry. The tool provides formore correlative points by improved pad design, use of a focusing currentresistivity measure, non-linear scales and rapid response galvanometers. A newtype of drift transducer gives direct readings of hole drift, and a constantvelocity coupling suspension eliminates "projection corrections." A techniqueof calibration eliminates errors of direction of 180 degrees and multiples of60 degrees. A method of presentation and a discussion of the interpretationnecessary to recognize faults, bars and unconformities is brieflydiscussed.

Introduction

In the early days of dip meter logging, only a few isolated stations werereported on a dip survey. The inadequacies of early tools, and, moreparticularly, inadequate calculations and interpretive techniques, gave theimpression to the industry that dip meter survey information was of smallutility. The experienced dip meter computer and log analyst, however, soonrealized that a wealth of structural information could be obtained from a dipmeter survey that provided sufficient information to allow computations atnumerous stations. It was recognized that errors due to erratic galvanometerresponse, tool rotation, "floating pads" and "projection corrections" or"pseudo azimuths" had to be eliminated.

Theory

Fundamentally, the Welex tool (Figure 1) operates on the sameprinciple as all dip meter tools; i.e.. three points defining a plane. Threeresistivity curves properly correlated provide these points when the positions of the point, are oriented in azimuth. The displacement of these points, properly corrected for the geometry of the bore hole, defines the plane inspace.
The C.A.O.D.C. Its Functions
Authors: Porter John D.
Published: March 2010

The purpose of this paper is to provide basic information concerning the Canadian Association of Oilwell Drilling Contractors – by outlining its aims, objectives and accomplishments. It covers the historical background, membership composition, organizational structure and programs of the Association.

History and Objectives of the Association

Through this meeting of the Petroleum Society, I am hopeful that a broaderknowledge of the purposes of the Canadian Association of Oilwell Drilling Contractors will be provided and a deeper understanding of the contractdrilling and servicing industry will develop, improving the co-ordination andplanning of contractor-operator activities – the objective being a stronger andmore progressive Canadian petroleum industry.

With the discovery of Leduc in 1947, the exploration door was opened for amore active search for hydrocarbon reserves in Western Canada. Drillingcontractors were then faced with growth problems of a type that confront anyfledging industry – in relations with governments, operators and the public, and in the training and development of personnel – at the same time trying toadd a measure of stability to their own contracting organizations. Obviously, there was a need for the contractors to take collective action to resolve someof these difficulties, and the Canadian Association of Oilwell Drilling Contractors was formed and registered as a trade association under the Societies Act of the Province of Alberta in June, 1949. A further stimulant wasprovided by certain experienced operating companies who wished to see anefficient drilling industry established to perform a safe and reliableservice.
Analysis of MER Calculation Techniques
Authors: Havlena D. , Paxman D.S.
Published: March 2010

The MER (maximum efficient rate) is defined in terms of well known physicalconcepts, and an analytical solution correctly describing them is presented.The differences of opinion regarding its definition and application as an engineering concept are briefly reviewed. The relationship of the basic theoryof water-drive reservoirs and the evolvement of the MER from theseconsiderations is discussed. The primary objective of the study is to reviewprevious work and to present a new analytical technique which is based on theapplication of two different (but acceptable) methods of solution to a partialwater-drive reservoir. The widely divergent results indicate that care must beexercised in choosing a calculation method, and that the acceptability ofresults is dependent upon the accuracy with which the analytical methodcorrectly describes the physical behaviour of the reservoir fluids. The "Fluid Inventory" method, which is a computerized technique adopted as one of theexamples used in this paper, is reviewed in detail and is shown to be the mostacceptable of the investigated methods. This technique, as well as all other MER calculations, results in solutions that require reconciliation withindividual well phenomena and as such they cannot be applied in discriminately.

Introduction

Historical Review

The term MER (maximum efficient rate), as it is currently understood by theoil industry and regulatory bodies, has undergone considerable evolution in thepast 20 years and even today there exists a controversy as to its ramificationsand final utilization. In 1947, Kraus (1) reviewed in detail the history of the MER concept and its useful engineering application as known at that time.Initially, the engineering usefulness of the MER was reflected in devising means of controlling excessive production from prolific oil pools in Texas, Oklahoma and California. It has been believed that prorationing of oilproduction and the resultant decrease in rates in many of the big pools wouldhave a favourable effect on their expected ultimate recoveries. After passingthrough a considerable number of API technical committee reviews, the industryfinally conceived an idea that there must exist an optimum rate for eachreservoir (i.e., a single and unique production rate), which would by itselfinsure optimum conservation of energy and thus result in maximum ultimaterecovery.
Design and Operation of a 160,000-BFPD Centralized Production and Injection Scheme at Weyburn
Authors: Scott W.J.
Published: March 2010

Unitization of the Weyburn Oilfield was necessary to facilitatewaterflooding the limestone producing formation. At its inception, on July 1,1963, the Unit comprised 550 wells producing through 115 tank batteries. Underunitized operation, advantage was taken of the unrestricted market for oil andthe removal of regulatory production restrictions, permitting productionpractice on a maximum- efficient-rate basis. Production facilities wereconsolidated and injection facilities installed, so that emulsion treating andinjection water pumping are concentrated at one centrally located plant.

This paper describes the design criteria and the operating experience of thecentralized production and injection scheme from March, 1964, to date. Adescription is given of the pre-unit operation and equipment, and of the designconsiderations to convert to an optimum gathering system through test and groupsatellites to a central treating plant. The reasons for the choice of one plantrather than several are outlined. The design of the emulsion flow streamthrough heat exchangers, free water knockout vessels, a flow splitter, fourhorizontal heater treaters and finally to three storage tanks is presented. Theselection of the source water supply and equipment, and the sizing ofhigh-pressure water pumps and gas engine drives are discussed, as well as thecorrosion-protected, radial water injection system. The alternatives consideredfor the large-size artificial lift equipment installed on producing wells aregiven. Comments on equipment performance and costs are made.

Introduction

The Weyburn Oilfield is located 85 miles south and east of Regina, Saskatchewan (Figure1). The producing zone is comprised of the Mississippian Midale beds, which lie at an average depth of 4,600 ft fromsurface. On July 1, 1963, 53 owners of 550 wells consolidated their operationsby unitizing 70 sq. miles of productive oil land, and appointed Central-Del Rio Oils Limited as Operator. Utilization was necessary to partially restorereservoir pressure by waterflooding. Studies indicated that waterflooding wouldincrease the recovery from 13.8 per cent to 31.7 per cent of the initialoil-in-place.
Pressure-Compensated Flow Regulation for Waterflood Projects
Authors: Castro L.F. , Oden J.H.
Published: March 2010

To fill the need for economical and efficient regulation of injection fluidin waterflood projects, a new pressure- compensating flow regulator has beendeveloped. This flow regulator provides a means of controlling injectionvolumes without the need for constant adjustments because of changes in pump orformation pressures. This paper describes the technical aspects of this methodof regulation, its surface and subsurface applications, its advantages and somecase histories.

Introduction

Accurate volumetric control of injected fluid has been proven necessary for efficient waterflooding. In the past, control has often been sacrificed becausethe methods available were both inefficient and costly.

The commonly used method for the surface control of water injection rates isthe choke valve – flow meter method. Figure 1 shows a single-well, one-source installation employing this method; Figure 2 shows amultiple-well, one source installation. The volume injected into each well is determined by the differential pressure across the choke valve and thechoke-valve setting. Once the choke valve is adjusted to a particular flowrate, it acts as a fixed orifice. In other words, the flow rate through thechoke valve is entirely dependent on the differential pressure across it. Tomaintain a constant flow rate, the choke valve must be adjusted continuously toany fluctuations in pump or formation pressures.

These adjustments must be made based on periodic meter readings. In aninstallation such as the one shown in Figure 2, control of injectionrates becomes more difficult to maintain because a pressure change at any wellwill change the line or manifold pressure and, therefore, change the injectionrates at all wells. Choke-valve adjustments made to compensate for pressurefluctuations at any well will make readjustment of all valves necessary.Accuracy of adjustments can be determined only after flow has been allowed tostabilize. This results in a period of time during which accurate control ofinjection rates is lost. Equipment breakdowns, either at individual wells or ata pump station, will require shutting down one or all wells and will also result in prolonged periods of loss of volumetric control.
Quantitative Log Evaluation of the Prairie Evaporite Formation in Saskatchewan
Authors: Crain E.R. , Anderson W.B.
Published: March 2010

The problem of solving for the fraction of sylvite, carnallite, halite andinsoluble material in the Prairie Evaporite formation can be performed by asuitable interpretation program based on Gamma Ray, Sonic, Neutron and Caliperlogs. Empirical relations were established between the log values and theformation parameters, the result being a set of four simultaneous equationswhich may be reduced to obtain the desired fractions. Tedious hand calculationcan be eliminated by using computer techniques and automatic log digitizingmachines. Correlation between core and log analysis is good, and the speed andefficiency of the method is valuable in initial formation studies.

Introduction

The Prairie Evaporite formation has been the object of extensive study inthe past several years (1) (2). It is the richest known potash-bearing bed inthe world, and, as such, it is important that any information gatheredconcerning the zone be accurate and immediately useful.

Electrical and radioactivity well logs have proved to be of value forformation evaluation in the oil industry. A recent paper (3) illustrates theiruse for both qualitative and quantitative interpretation in evaporite sequencesin various parts of North America. This paper will outline the theory andtechnique used for a quantitative interpretation procedure in the potash bedsof the Prairie Evaporite formation in the Province of Saskatchewan. The dataare set up so that they can be handled by an electronic computer. The equationscan also be computed by hand at the well site to supplement the data alreadyavailable. The computer program is presented as an Appendix. An extensivebibliography covering potash geology, development and logging techniques, is included.

Theory

It is well known that potassium has a radioactive isotope which emits gammaray energy. This isotope comprises a constant fraction of the total amount ofpotassium, so that a Gamma Ray Log, which measures the amount of natural radioactivity in a formation, frequently gives a measure of the potassiumcontent.
Computer Well-Data Systems: A Company Case History
Authors: Stauft D.L.
Published: March 2010

This paper presents a user's view of well-data systems and gives the history of their development within one company. In 1951, Imperial Oil Limitedestablished a punched-card system for well data. In 1958, this system was abandoned when it was decided to go ahead with the development of acomputer-based well-data system with the data stored on magnetic tape. By 1963, this system contained basic factual data and geological tops on everyone of the 37,000 wells drilled to that time in Western Canada. Since then, another 7,000 wells have been drilled. Data on these, as well as changes to existing data, are being added as they come in every month.

With regard to the design of the well-data systems, the paper makes twobasic points. First, the users of technical-data systems such as the one described must take an active part in their design, development and operation. This is more important in this type of system than in a business-data system, which does not require the same flexibility in answering requests. Second, awell-data system should be restricted at the start to basic factual data, and extreme care must be taken to ensure that only reliable and useful datacontinue to be included. Otherwise, the system will lose the confidence of itsusers and will ultimately fail.

On the subject of economics, if the evaluation of technical-data systems isconfined solely to the unit costs of storage and retrieval, these costs will probably be judged to be fairly high and therefore the system not economic.However, the value goes beyond this analysis, and the worth of technical time is considered to be a much more important and sensitive factor. Despite the difficulty of evaluation in dollars, this advantage probably makes the investment in the system worth while.
Wellbore Behaviour During Saturated Steam Injection
Authors: Holst P.H. , Flock D.L.
Published: March 2010

A mathematical model was formulated to describe the injection of saturatedsteam down oilwell tubing under constant inlet conditions.

The system was divided into three parts, consisting of the fluid, thewellbore and the formation. Each part was considered to be a separate system, with the heat flux across the boundaries acting as the coupling parameter. Thewellbore consisted of a tubing string enclosed by either one or two casingstrings. The heat transfer in the wellbore was considered as steady state. Theheat transfer in the formation was treated as unsteady-state radial conduction, and the fluid flow was described by a modified two-phase flow correlation.

The analysis resulted in three equations, two of them implicit, which weresubsequently solved simultaneously on the 7040 computer. The solution did notpresent any convergence problems. Although a complete verification of themathematical model was not possible, the calculated temperature profiles weresimilar in shape to an observed temperature profile.

Introduction

With the cost of finding and developing high-grade crude reservescontinually increasing, more attention is being focused on the development ofhigh-viscosity or "heavy" oil reserves. As the oil viscosity is highlydependent on temperature, a small increase in reservoir temperature decreasesthe oil viscosity markedly, facilitating increased production rates andultimate recoveries. One of the more popular means of increasing the reservoirtemperature is steam injection. To evaluate the feasibility of a thermalproject, a reasonably accurate estimate of the heat losses from the well bore, the sandface pressure and the sandface quality of the steam would be desirable, if not necessary. As the injection times are generally quite small, steady-state solutions would not be very representative and unsteady-statesolutions are required.
Scale Inhibition by the Squeeze Technique
Authors: Kerver J.K. , Heilhecker J.K.
Published: March 2010

The productivity of many wells has been seriously reduced in the pastbecause of scale deposition. In some fields, the produced water is saturatedwith gyp (calcium sulphate) that precipitates in the pores of the reservoirformation sand near the wellbore. Chemical treatments have successfullyrestored productivity for short periods, but deposition of gyp continues tooccur, resulting in a rapid decline in productivity following treatment. In thepast, chemical scale inhibitors were pumped down the annulus to prevent gypscale deposition on the rods and tubing. However, gyp precipitation in theformation and resultant productivity reduction were not prevented.

To effectively prevent gyp from precipitating in a reservoir formation, theinhibitor must be present within the pores of the formation rock. To accomplishthis, an absorbable inhibitor is injected into the formation, where it isadsorbed On the Sand or rock surface. When the well is produced, the inhibitorslowly desorbs into the produced fluids and prevents deposition of gyp in theformation or on the rods or tubing. On the basis of extensive laboratory tests, two chemicals were chosen for field testing. Of ninety wells squeezed one ormore times with these chemicals, only one has become "gypped up" in theformation. The life of the chemical treatment has varied from 2 to 17 months, with an average life of 9 months. Repeated treatments have successfullyprevented gyp deposition for more than 30 months.

INTRODUCTION

PRODUCTIVITIES OF A LARGE NUMBER OF WELLS in a West Texas waterflood wereseriously impaired by gyp (hydrous calcium sulphate) scale deposition in theformation and on the downhole mechanical equipment. The field productiondistrict has been investigating ways of combating gyp scale plugging forseveral years. Although early attempts to remove scale damage were successful, the increasing frequency of treatments and the declining effectiveness led tothe present research investigation. Scale problems are widespread in thepetroleum industry, and the literature discusses the deposition of gyp, calciumcarbonate and other scales as well as

Various methods for treating the problem. This paper presents the results ofboth laboratory and field tests that have been conducted in the development ofmore effective treatments to combat gyp scale plugging Methods for restoringwell productivity were investigated and improved. Preventing the continuedprecipitation of gyp in the pores of the formation sand was a serious problem.A scale inhibitor squeeze technique for preventing gyp precipitation was developed and successfully applied.
Temperature Distribution Ahead of an Advancing Steam Zone
Authors: Durie R.W.
Published: March 2010

This paper describes a solution to the diffusivity equation, assuming boundary conditions for a reservoir during steam injection. It should be considerable value for the evaluation of steam drive projects, particularly inview of the growing importance of thermal recovery processes in Canada,

INTRODUCTION

IN THE THEORETICAL TREATMENT of steam drive processes for the recovery ofheavy oils, one of the problems encountered is the determination of thetemperature distribution ahead of the expanding steam zone. A knowledge of the temperature distribution is of value in predicting the location and rate ofadvance of a steam zone when a temperature build-up is observed at a production or observation well, or to assess the temperature development ahead of a steamzone when its location and rate of advance are known. This paper attempts toassist the resolution of the above problem by extending the theoretical work by Lauwerier which describes the temperature distribution in a line drive model with hot water injection. In this case, the boundary conditions are altered torepresent the situation with steam injection. The Laplace transformation isused to obtain an analytical solution to the equations that ai-e developed. Representative isotherms calculated from this solution are presented ingraphical form.

THEORY

A plane condensation front is considered to be advancing through permeablestrata bounded by an impermeable cap rock and base rock. The idealized verticalcross section is shown on Figure 1.

The problem is formulated as an idealized model by including the following assumptions:The reservoir is homogeneous, isotropic and of constant thickness.The condensation front remains vertical within the sand layer, and thehot condensate flows uniformly through the oil sand ahead of the condensation front.Thermal equilibrium between the fluid and the sand grains is instantaneous.The thermal conductivities of the cap rock, base rock and oil sand are equal.The heat capacities and thermal conductivities are independent of temperatures and pressure.The heat conduction in the horizontal direction is neglected.

The above assumptions allow the problem to be formulated by considering only the positive quadrant of Figure 1. because there is symmetry about themid- point of the oil sand. The temperature distribution is therefore described by the set of partial differential equations shown below. (See full paperfor equations)
Oil Company Involvement in Canadian Mineral Exploration
Authors: Schiller E.A.
Published: March 2010

Oil company involvement in Canadian mineral exploration in 1968 will bereviewed, based on a 35-company questionnaire. Evidence of increases in companyinvolvement in 1967 and 1968 to more direct participation in 1969 will bepresented and shown by data on expenditures for those years and other pertinentinformation. Increases in the number of companies and amounts of spendingreflect a significant movement of oil and gas companies into the mineralsfield. Philosophical and economical aspects of oil company thinking will bediscussed as they pertain to prospecting. The conclusion is drawn that the moveof oil companies to mineral exploration is a logical transfer of men and ideasgeared to changing times and the need for diversification of interests. Oilcompany activity in Canada will be reviewed; special reference will be made tonorthern Saskatchewan, and the implications of the Gulf Minerals uraniumoccurrence will be assessed.

INTRODUCTION

A REVIEW of oil company involvement in Canadian mineral exploration in 1968is presented in this paper, and comparisons are made to activity in 1967 and1969. The word "involvement" rather than "participation" is used because, forthe most part, oil companies have been involved in exploration by way ofindirect participation through joint ventures and syndicates that areprincipally conducted by contractors, consultants or mining companies. Thiswill change in 1969 and succeeding years; based on the level of activity andintensity of pursual in 1967 and 1968, oil companies will move from involvementto direct participation. Data to support this conclusion is presented, asderived from a questionnaire from thirty-five responding oil companies workingin Canada. To begin with, an oil company for the purposes of thisdiscussion is an organization that derives most, if not all, of its income fromsome form of oil and gas operation; this would even include pipeline ortransmission companies, because they are now mineral explorers. The ultimatesources of oil company money is not considered, only the fact that it is spentin Canada. Monies expended 1967, 1968 and 1969 To illustrate oil companyactivity, Figure 1 shows expenditures for the years 1967, 1968 and 1969, and itcan be seen that in the number of companies spending $500,000 on exploration istwice that for the year 1967. Total spending for the same years is estimated at$7 million (1967), $13 million (1968) and $20 million (1969). Due to recentpermit acquisition in Keewatin, mostly by oil companies, a figure closer to $21million maybe more accurate.
Evaluation of New Techniques of Acidizing in Western Canada
Authors: Cruikshank C.G.
Published: March 2010

During the period from 1960 to 1968, stimulation with acid has gainedprominence through the development and introduction of new acidizing techniquesin Western Canada. The benefits derived from these innovations are many andvaried. When put to proper use, these new acidizing techniques can producesubstantial returns on dollars invested in stimulation and may in certain casesmake the difference between a well being a commercial or noncommercial producer. Many new products and ideas havebeen tried, but only a limited number have gained a permanent place in thestimulation field. Acidizing with mixtures of acid and alcohol has beenaccepted because of better post-treatment cleanup of the formation. Use of thegases, nitrogen and carbon dioxide, in conjunction with acid treatments to givedeep acid penetration and fast cleanup with savings in rig costs has provedsuccessful. Treatments with high-strength hydrochloric acid provide a veryeconomical means to get deep acid penetration.

Additional benefits are inherent in the use of each of these acidizingmodifications. Basic treatment costs are certainly a consideration whenchoosing a treatment, however they should not be emphasized to a degree whereobvious benefits are lost. Combining treatment technology, laboratoryevaluations, and well and reservoir information with past history, whenavailable, is an essential ingredient for good treatment design.

INTRODUCTION

THE USE OF AUXILIARY AIDS with acid treatments has steadily increased withthe expansion of this service. Many products and techniques have enjoyed ashort period of success in this field, only to be replaced as technicaladvances are made. Acetic acid is an example of a product that was used on manytreatments over a period of several years.

This acid offers low corrosion rates and very slow reaction rates, but itscost is high when the reactive power of acetic acid is compared to HCI. Atpresent, it is being used on very few jobs. This does not mean that operatorshave gone back to using straight 15% HCI in place of acetic acid. The morelogical explanation appears to be that other auxiliary products have gainedincreased usage. The products briefly reviewed in this paper have gamed apermanent place in acidizing and their usage appears to be increasing. Athorough knowledge of available products for acidizing will assist operators inmaking the proper choice of treating solution for a particular well and candefinitely improve the return on dollars invested for this service.
Information Transfer in The Petroleum Industry
Authors: Dolan Frank T.
Published: March 2010

This paper enumerates some of the causes behind the present revolution ininformation technology. It offers a pragmatic definition of information and asimplified model of information transfer. The principles of coordinate indexingand retrieval, which are pre-requisite to an understanding of computerizedreference-retrieval systems, are reviewed. Some of the relevant agencies(Information Utilities) concerned with the design, implementation and operationof such systems are cited. One of these, Petroleum Abstracts, which isrepresentative of the others and extremely important to the petroleum engineer, is described in considerable detail. The importance of such services to theengineering community is stressed.

INTRODUCTION

FUNDAMENTAL CHANGES are taking place in our methods of handling information. These changes are attributable to a combination of factors, namely:An increasing awareness of the importance of information and its realequivalence to manpower and dollars.The increase of volume and flow of information intra and inter-industry, government and university.The emergence of new technologies such as electronic computers, newcommunications media and systems, microform technology, etc.The appearance of a new interdisciplinary curriculum (Information Science)focused on modern information-processing sources, systems and techniques.The change from the concept of a library as: a collecting archive, preoccupied with the media, to an information center as a dynamic disseminatorconcerned with the message.The conversion of traditional indexing and abstracting services to Information Utilities capable of supplying information sciences, computer-manipulatableinformation banks and specialized software packages.The formation of information networks to expedite information transfer

There are many definitions of information. They range all the way from thephilosophical, "that precious distillate of human experience," to themathematical definition of Information Theory. The definition offered below isneither philosophical nor mathematical. It is, however, basic andworkable.
An Effective Completion and Stimulation Technique, East Crossfield D-1
Authors: Bennett E.N. , Miller D.K. , Glover R.A.
Published: March 2010

The development of a completion and stimulation technique that would achieve satisfactory well producing rates was a major problem in the East Crossfield D-1 Reservoir. Early wells were completed using an open hole or long perforated interval. Different types of acids and additives were used to stimulate the wells; however, after eleven wells had been completed, the average well deliverability was only 3 MMcf/D. Pan American Petroleum Corporation thenstarted using the limited-entry completion technique. This technique consists of perforating a well over 4 continuous feet of Montreal the most porous interval with eight shots per foot and then acidizing with 34 per cent HCI.Nine wells were completed and stimulated in this manner and deliverability averaged 8.8 MMcf/D per well. Six of these treatments consisted of 25,000gallons of 34 per cent HCI and three consisted of 4,000 gallons of 34 per cent HCI atomized with 3,800 sef of N2 per barrel. After ten months'production, the deliverability of the atomized acid-treated wells had declined by almost 50 per cent whereas the 25,000-gallon-treated wells sustained their original deliverability. One well which had originally been considered a dryhole is now maintaining its test deliverability after a limited-entry, large-volume treatment. For this reason, limited-entry, large-volume treatmentsare now being used by Pan American to re-stimulate wells in the East Crossfield D-1 Reservoir. As a result, of the reliability of this technique, the number ofwells required to meet the plant design capacity was reduced by eleven, asaving of over $2.75 million. This paper discusses the field production history of limited entry versus non-limited entry completions and large-volume versusatomized acid stimulations.
Low Fluid Residual Fracturing
Authors: Bullen R.S.
Published: March 2010

A new process of fracturing virtually eliminates the requirement for loadfluid recovery. Liquid carbon dioxide makes up 80 per cent of the total fluidvolume injected, and this fluid gasifies after a short, period of time in thereservoir. Propping agents are carried at a high concentration in a smallside-stream of gelled alcohol, and then blended with the liquid CO2 pumped into the well. After the C02 gasifies in the formation, onlythe alcohol remains for recovery as a fluid or vapor. The process is primarilydesigned for fracture stimulation of low-permeability gas wells.

INTRODUCTION

FRACTURING OF LOW-PERMEABILITY Reservoirs has always presented the problemof fluid compatibility with the formation core and formation fluids, particularly in gas wells. For example, many formations contain clays whichswell when contacted by aqueous fluids causing restricted permeability, and itis not uncommon to see reduced flow through gas-well cores tested with variousoils. In the past, the approach to the swelling problem has been the use ofchemical additives, such as salts or pH control additives, to water forfracturing water-sensitive formations. Where hydrocarbons are used, lightproducts such as gelled condensate have seen a wide degree of success, but arerestricted in use due to the inherent hazards of pumping volatile fluids. Amore recent technological improvement to the fracturing ofpermeability-sensitive reservoirs essentially eliminates contact of theformation with any fracturing fluids at all. Stimulation is effected byfracturing the well with liquid carbon dioxide as the basic fracturing fluid.Propping agents are blended in a separate stream of gelled alcohol and blendedwith the C02 in the well. The net effect is that the well isfractured with a base fluid with liquid properties. After a short period oftime in the formation, however, the CO2 gasifies, leaving only a lowfluid residual (LFR) of alcohol to recover. This alcohol, in turn, is solublein reservoir gas (methane) and is essentially returned as a vapor.

TREATMENT MECHANICS

Earlier experimentation with LFR fracturing indicated that the alcohol hadto be gelled to a viscosity of 20 centipoise or higher in order to besufficient to carry the high concentration of proppant agent through theblender and pumping equipment. Alcohol was chosen as the proppant-carryingagent in view of its compatibility with most gas reservoirs, its low freezingpoint and its potential chemical benefit to the stimulation. Alcohol is alsocompletely compatible and miscible with CO2 for immediate blendingof the two fluids.