bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Retrievable Casing Liner - A New Production Tool
Authors: Bullen R.S. 
Published: March 2010

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

ABSTRACT
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

ABSTRACT
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)