bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pembina Unit Institutes Line-Drive Type Waterflood; Off-Creek Reservoir Provides Water Supply
Authors: Harris R.L. , Horney D.M. 
Published: March 2010

Abstract
Operators select line-drive waterflood over other pattern type injectionsystems for the Lindale area. Greater oil recovery is predicted at asubstantially lower capital investment. Problems of primary water source areovercome by off-stream reservoir. Treatment and injection facilities arecombined to reduce operation and maintenance costs. Under the line-drive typewaterflood scheme the operators expect to recover the equivalent of the primaryoil in eight years compared to a normal twenty-five years. It is anticipatedthat the ultimate oil recovery will be more than double the primary reserves.Utilization of specialized engineering services can result in substantial costsavings on projects of this nature.

Introduction
A portion of the Pembina field in the Keystone-Berrymoor area was thought tobe a good prospect for a secondary oil recovery scheme. Unitization was aprerequisite to carrying out any full-scale project because of the large numberof ownership interests.
A feasibility study by a reservoir engineering consultant outlined an areawithin Twp. 49, Rge. 5, W5M which might be successfully water-flooded. Theconsultant considered several methods and recommended a line-drive typewaterflood. Implementation of this scheme is expected to increase presentincome, more than double the oil recovery, cost considerably less than apattern type flood, and be more economical in operation. The study indicated awater requirement of 3,500 B/D.This requirement and the generalconfiguration of the area and pattern governed the design of thefacilities.
Outline of Study Area and Brief History
Immediately to the east of the recently formed Berrymoor Cardium Unit and inthe western portion of the main Keystone-Pembina area a part of the sprawlingPembina oil field was subjected to examination for waterflood. The study areawas contained mainly in Twp. 49, Rge. 5, W5M, and was designated the Lindalearea. Some additional areas to the east and south were considered unsuitablefor waterflood because of the poorer Cardium sand characteristics. A separatepilot flood was recommended for this marginal area.
The Engineering Design of Well Stimulation Treatments
Authors: Flickinger D.H. , Fast C.R. 
Published: March 2010

Abstract
Correlation of the pump rate, fluid additives, tubular goods, andperforating programme can result in appreciable cost reduction in a wellstimulation treatment. The use of a specially designed cross-over valve topermit stimulation treatments to be conducted through manifolded tubing andcasing annulus, after initial formation breakdown through the tubing can resultin greatly increased treatment efficiency and reduced costs. A technique isoutlined for analyzing treatment variables and field examples are used todemonstrate the savings that can be realized by engineering the design of wellstimulation treatments.

Introduction
The hydraulic fracturing process has been the most successful and widelyused technique to stimulate oil and gas wells. It is estimated that 400,000treatments have been conducted during the 15 years the process has beenavailable and approximately 2,400 jobs per month are now being completed in thefree world's oil and gas producing areas.
The unusually high (80%) success ratio achieved using the process isprobably the major reason that many operators devote little thought andplanning to the hydraulic and mechanical factors involved in a successfultreatment. It is the object of this paper to demonstrate the economicincentives for optimum treatment design with emphasis on correlating thetubular goods arrangement, perforating programme, pump rate and the additivesused. It will be shown that substantial cost reductions are feasible byengineering the design of well stimulation treatments while increasing theefficiency and success probability of the treatment.
Discussion
Effect of TubularGoods on Treatment Costs
The total hydraulic horsepower required to pump water into a typical 7,000ft. well with various arrangements of tubular goods is shown graphically onFigure1. It will be noted that the total hydraulic horsepower consistsof two components:the horsepower necessary to inject fluids into aformation, andthe additional horsepower to overcome friction for thevarious combinations of tubular goods.
Understanding the Muskat Method of Analysing Pressure Build-up Curves
Authors: Larson V.C. 
Published: March 2010

Abstract
The somewhat neglected Muskat method is an excellent way to obtain staticpressure from build-up curves. A re-examination of the technique, accountingmore rigorously for fluid compressibility, shows why the early part of theMuskat pressure plot actually curves upward, so that it sometimes seems to giveunsatisfactory results. A straight line, indicating a correct static - pressureguess, should be expected only for later data; however, the time at which theline stops curving can be estimated simply. The study also revealed thatreservoir transmissibility and expansibility can be obtained from the plot.Three other methods of estimating static pressure from build-up curves arecompared to the Muskat method. They are less precise because they either do notaccount adequately for compressibility or they need more accurate reservoirinformation than is usually available.

Introduction
The Muskat method of analysing build-up curves seems to have been neglectedin favour of other methods. This paper should renew confidence in the Muskatmethod in that it provides a new theoretical basis for its use, adds to itsscope, shows why and when it will sometimes fail and compares it with someother techniques.
Applied to wells in a uniform, bounded system, the Muskat method is shown togive static pressure with very good resolution and without the need for priorknowledge of any reservoir parameters; however, the plot behaves as a straightline only for the later build-up data. A modification to the method permitsdetermining drainage-area transmissibility and expansibility from the plot.
The Basic Muskat Method
In 1937 Muskat published a method for finding static pressure from abuild-up curve.
Chemical Cleaning as a Maintenance Tool
Authors: Mullin G. , Quinn H. 
Published: March 2010

Abstract
This paper will attempt to outline how chemical cleaning provides apractical method of removing fouling products which interfere with heattransfer or with flow rates.
It will discuss how the selection of the proper solvent and technique for asuccessful and economic cleaning application depends on a number of factors, such as the nature of the deposit, the metals in the equipment to be cleaned, the solvents available, temperatures and safe operating practices.
The relationship of time and frequency of cleaning to cost will be outlined, as well as the factors which should be considered in the total cost whenevaluating chemical cleaning as a maintenance tool.
The author will also discuss recent developments in new solvents andtechniques, such as EDTA formulations, foam cleaning, organic solvents, vapourcleaning and one-stage copper solvents.
Chemical cleaning provides a practical method of removing fouling productswhich interfere with heat transfer or with flow rates. In the case of newpiping or other new equipment, the chemical removal of mill scale and oils andpreservatives is frequently necessary. This is especially true in the case oflubricating oil systems, oxygen systems and high-pressure boilers.
The successful and economic application of solvent cleaning depends upon anumber of factors; namely, the deposits, the metals in the equipment to becleaned, the solvents available and safe operating practices. The removal ofany type of deposit with solvents is dependent upon the nature of thatdeposit.
In solvent cleaning, the deposits, for purposes of identification, aredivided into one of three broad classes - namely, inorganic deposits, organic deposits,or mixtures of inorganic and organic deposits.
The inorganic deposits (Table I) consist of a comparatively small number ofspecific chemical compounds (Table II). They may be designated by chemical ormineral name, and by chemical formulae.
Physiographic Controls on Development in the Queen Elizabeth Islands
Authors: Sim V.W. 
Published: March 2010

Introduction
Dean Hare of McGill University has recently pointed out that Canada is toocold and too big. His precise reasons for this belief do not concern us here, but I suggest that it is also an apt description of the Queen ElizabethIslands. To put it another way, climate and terrain in the Queen ElizabethIslands are seriously restrictive physical factors determining the directionand rate of economic expansion. These factors are discussed in some detail inthis paper.
Climate
In all activities in the Arctic, man's comfort is of primary importance. AsHarwood (1961, p. 1106) suggests "… in the end it is his heat loss whichdetermines whether he is cold and inefficient or warm and efficient." The firstaspect of the climate of the Queen Elizabeth Islands which needs emphasis isthe severity of the temperature and the duration of the period of extreme cold.Temperatures normally associated with winter in southern Canada occur during 10months of the year (Figure1), At Resolute, on Cornwallis Island, sub-freezing temperatures are usual between mid-October and mid-April. Onlyduring July and August can temperatures be expected to remain above freezing, and even during this period occasional sub-freezing days may occur. Most areasof the Islands share with interior Keewatin District the distinction of beingthe coldest areas in Canada in January, when the mean monthly temperature dipsbelow -30°F. Thomas points out, however, that even under these extremeconditions, daily temperature variations may range as high as 10° to15°F. (Thomas, 1961, p. 945).
Summer, as we know it in southern Canada, is not experienced in the QueenElizabeth Islands. In July, the mean monthly temperature is approximately40°F., or roughly the same as winter temperatures in Vancouver or April andOctober temperatures in Edmonton.
The Prediction of Pressure Gradients for a non-Newtonian Crude Oil Flowing in a Pipeline
Authors: McKay W.N. , Boucher W.W. , Milne J. 
Published: March 2010

Abstract
Several Western Canada crudes exhibit non-Newtonian flow characteristics.Thus, the use of the standard definition of viscosity is unreliable in pipelinesizing formulae.
A "model pipeline" viscometer was constructed, adapted from an instrumentdesigned by Coe, and based upon the theoretical aspects of the scale-up problemfor non-Newtonian flow. Using this instrument, laboratory pressure gradientswere determined and compared directly to the pressure gradients measured in atest section of pipeline carrying the crude oil. The field tests were for ayear's operation, and covered the full range of probable temperatures and flowvolumes. Laboratory pressure gradients agreed with the field values with anaverage error of less than 5 per cent.

Introduction
Fluids are classified into two main categories - Newtonian or non-Newtonian- according to their behaviour at constant temperature under various steadyshearing forces. A Newtonian fluid obeys the equation:
(Equation i)
in the laminar flow regime. Here, T is the shear stress, du/dr the shearrate, and ?the viscosity of the fluid in question. For laminar flow ina round tube, a double integration yields the classic Hagen-Poisseuilleequation
(Equation ii)
where R is the radius, P/L is the pressure gradient and Q is the throughputor rated volume flow.
Because of the identity of equation (i) with equation (ii), it has become anaccepted procedure to call RP/2L the shear stress at the wall of a tube ofradius R, and 4Q/pR3 the resultant shear rate. For reasons that willbe explained later, it is more rigorous to define these terms, in equation(ii), as the "apparent" shear stress and the "apparent" shear rate. The "real"or "true" terms should be only identified with equation (i).
A General Solution of the Equations Describing Steady State Turbulent Compressible Flow in Circular Conduits
Authors: Dranchuk P.M. , Quon D. 
Published: March 2010

Abstract
Although a number of solutions to the equations describing steady compressible flow in pipes exist, even the most rigorous of these make simplifying assumptions concerning thermal effects; i.e., either that the flowis isothermal or that the gas assumes identically the temperature of the surroundings. There are, however, instances where these assumptions may not be warranted.
This paper examines the differential equations which characterize momentum and heat transfer, rearranges them so as to make them amenable to numericalsolution and proposes a computational technique suitable for use on digital computers. The approach represents an improved and generalized method ofhandling gas well calculations as well as pipeline design problems.

Introduction
The flow of fluids, in general can be described by a set of partial differential equations – comprising the equation of continuity, aforce-momentum balance for each of the three dimensions and a total energy balance. A general solution of this set of five partial differential equations involving four independent variables – three geometric, one time – is currently beyond our capabilities. Fortunately, in many cases of gas flow, the flow ishighly turbulent, steady and occurs in circular conduits. In such cases, the system may be described by two ordinary differential equations, namely, aforce-momentum and a total energy balance. These two equations may be writtenin terms of one independent variable, length, and two dependent variables, which may be two fluid properties. Although any two independent properties willdefine the state of a fluid, temperature and pressure are the obvious choices, as they are the ones usually measured in practice.
Until recently, the solution of simultaneous nonlinear differential equations has been too time-consuming to find wide engineering acceptance. Consequently, further simplifying assumptions have been made. It has been assumed that the gas temperature is either constant or an explicit function of length, thereby reducing the number of differential equations to one, viz., theforce-momentum balance. It should be pointed out, however, that the assumption of isothermal flow is normally not defensible on physical grounds. With regardto the alternate proposed assumption, while the temperature of the surroundings may be known, the assumption that the fluid assumes identically the temperature of the surroundings implies that the overall heat transfer coefficient between the fluid and the surroundings is infinite - a questionable hypothesis.
Laboratory Displacement of Oil by Water Under Simulated Reservoir Conditions
Authors: Colpitts G.P. , Hunter D.E. 
Published: March 2010

Abstract
Intuitively, preserved core waterfloods at reservoir conditions give resultswhich most closely represent the displacement that occurs in the reservoir. More elaborate equipment and more involved procedures are required to performsuch tests than for conventional waterfloods. The equipment and proceduresrequired are described in detail. An experimental program to determine the effects of test environment and core condition is described. Typical results are presented which show that both test environment and core condition should be as representative of the reservoir as possible, that their separate effects are not independent, and that each reservoir is liable to be different. For each reservoir, the decision has to be made whether the benefit of more representative data outweighs the additional cost involved in testing preserved cores at reservoir conditions.

Introduction
The use of laboratory waterflood results to assist in the prediction of reservoir performance is common practice in reservoir engineering. Thetheoretical validity of such use is well established. Commonly, waterflood tests are carried out on extracted cores using refined oil at room temperature and atmospheric pressure. In recent years, some investigators have been studying the question of how closely tests of this sort really represent displacement in the reservoir. Of special concern are the test environment and the core condition. Wilson, Ruhl et al., Delcloud, and Savelli and Kytehave been concerned primarily with environment. Do pressure or temperatureaffect the results? Does refined oil behave the same as reservoir oil? Bobek et al., Burkhardt et al., and Denekas et al. havebeen concerned with core condition. Are the surface characteristics of extracted core representation of the characteristics of in situ reservoir material?
We are engaged in an experimental program to study the individual effects and the combined effects of both test environment and core condition. Control of these factors requires careful and elaborate experimental work. It is the primary purpose of this paper to present, in some detail. the procedures, equipment and test materials necessary to achieve this control. In addition some experimental results from this program are presented.
Gas Transportation Cost Dividends From Internally Coated Pipe and Station Automation
Authors: Hurd L.G. 
Published: March 2010

Abstract
The Alberta-California gas pipeline is coated internally throughout most ofits length with a thin film of epoxy resin, the purpose of which was primarilyto provide a smooth internal surface and reduce compressor station horsepower requirements.
Three of the compressor stations installed on the line are automated and arecontrolled remotely by a single "set point" signal from the central dispatch office.
This paper evaluates the benefits that have been realized from these two factors. Pipeline flow efficiency factors are reported and compared with thosefor uncoated portions of the line, and compressor station operating and maintenance costs on the line are compared with costs usually experienced insimilar manned stations. Both of these effects are then related to costs of transportation, and the net effect of each is reported.

Introduction
The Alberta – California pipeline system extends from gas fields in theeastern foothills region of Alberta through the southeast corner of British Columbia across the international border in Idaho, and through Washington, Oregon and northern California to Antioch on San Francisco Bay – a total ofsome 1,600 miles, including gathering laterals. It carries gas purchased in Alberta by Alberta and Southern Gas Co. Ltd. to markets served by the Pacific Gas & Electric Co. throughout northern California, and to the Canadian Montana Pipeline Co. at the Alberta-Montana border. In addition, gas purchasedby the Westcoast Transmission Company Limited from fields in Alberta is carriedby the line and delivered to the El Paso Natural Gas Co. near Spokane, Washington, as well as to local utility companies along the route of the linein British Columbia, Idaho, Washington and Oregon.
The main line is 36 inches in diameter throughout its length and, with thefour compressor stations installed at the time the line was built, the systemis capable of delivering some 460 MMcf/D to the San Francisco Bay area, about160 MMcf/D to El Paso at Spokane and about 36 MMcf/D to Canadian Montana.
The Use of Salt Cement Blends as an Aid to Better Cementing in Formations Containing Fresh Water Sensitive Clays
Authors: Longson W.B. 
Published: March 2010

Abstract
The application of salt for primary cementing in Western Canada has been restricted largely to salt cavern storage wells and to the development of potash reserves in south-central Saskatchewan. The value of salt cement blendsin cementing through fresh water sensitive formations has recently broughtabout wide usage of this technique in certain areas of the United States, andthere is good reason to believe that there are several areas in Canada wherethe success of primary cementing could be improved by the use of saltcements.
There has been considerable work done on the applicability of salt cement, with emphasis on improved cement-formation bonding and the minimization offormation deterioration by water contact. Field results have shown that saltcements have improved the success of primary and squeeze cementing jobs.
Laboratory work has been done to evaluate the change in slurry properties with the addition of varying concentrations of salt to commonly used cementing blends.

Introduction
The use of salt cements in Canada has been quite limited and, as a result, the primary purpose of the information presented here is to illustrate theadvantage of salt for primary cementing of oil and gas wells where the formations encountered contain fresh water sensitive clays and shales.
The first known use of salt cements in Western Canada occurred within thepast ten years. Initially, salt cements came into use because of the failure toset fresh water cement abandonment plugs in the salt and potash zonesencountered in potash test holes. Earlier experience in the U.S.A. proved that a good cement-formation bond through a salt section could only be achieved byusing a salt cement. Figure 1 illustrates the bonding of cement to rocksalt. The illustration shows how a fresh water slurry will dissolve a portionof the salt, with the result that there is no bond between the salt and cement, while the saturated salt slurry does not dissolve any portion of the salt, resulting in good contact and bonding between the salt and the cement.
Operators in Saskatchewan found that casing could be cemented successfully in salt cavern gas storage wells with a sodium chloride slurry; more recentwork has employed a sodium chloride and potassium chloride (potash) saturated slurry (1). Later, casing was set into the potash for a solution mining project, and again salt cements were used to obtain a good primary cement job.
Predicted vs. Measured Loads in a Sucker Rod Pumping System
Authors: Byrd J.P. 
Published: March 2010

Abstract
In order to apply an oilfield pumping unit on the most economical basis, itis often necessary to predict its torsional and structural loading in advanceof well completion. Frequently, a pumping unit is misapplied because thedetermination of these values by simple prediction formulae does not conform toeventually measured loads. An investigation of the simplified predictionformulae most commonly used in applying a sucker rod pumping unit illustrateswhy discrepancies between predicted and measured loads may exist.

Introduction
One of the numerous problems faced by the pumping unit manufacturer is topredict the torsional and structural loading that will be imposed on thesurface equipment for any given set of well conditions.
As a precise determination of these loads involves, complex formulationemploying many variables (some of which are unknown prior to well completion), it becomes necessary to develop a set of prediction equations with solutionswhich are fast and simple and require knowledge of only a few known quantitiessuch as rod and fluid weight and polished rod acceleration.
In most cases, these simple and convenient formulae, employing only a smallportion of the items which actually control torsional and structural loading, are entirely adequate to apply the surface pumping unit on a most economicalbasis – but the results obtained are admittedly only approximations and maydiffer considerably from measured loads.
In a recent study of two different types of sucker rod pumping units over anumber of applications chosen at random, the predicted peak torque determined by these simplified methods was compared to the measured peak torque. The results showed that, in both types of units, approximately one-third of the applications measured greater than predicted, one-third measured less than predicted and one-third measured about the same as predicted. (See Table I).