bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mining at Athabasca - A New Approach to Oil Production
Authors: Spragins F.K. 
Published: December 2007

Abstract
The first large-scale commercial extraction plant in the Athabasca tar sands region of Canada begins operating in late 1967. The start of this plant hails the beginning of the use of mining technology in the production of crude oil on this continent. This article reports on two basically different mining approaches that could be used in a commercial tar sands, plant, and details economics and types of equipment to be used.

Introduction
Geological studies, including results from approximately 2,000 test holes, outlined the deposit and established the reserves in the Athabasca region.' The total in-place reserve of bitumen is calculated to be approximately 625 billion bbl. Of this amount, it is estimated that about 45 percent can be recovered by known techniques and transformed into a marketable synthetic crude oil. Hence, proved reserves in the tar sands total about 285 billion bbl of recoverable synthetic crude oil. Compare these reserves with two other major sources of oil in North America: conventional oil and potentially producible Colorado oil shales. Proved reserves of conventional oil are currently placed at 49 billion bbl. Total in-place reserves of shale oil are estimated at over 2 trillion bbl; but, on the basis of current technology, only 80 billion reserves of tar sand oil are more than twice the combined total of conventional oil and shale oil proved reserves.

Description of Ore Body
Though extremely variable in nature, good quality ore body in the Athabasca tar sands covers about 10,000 sq miles. The average thickness is 150 ft and the ore body reaches a maximum thickness of about 400 ft. The deposit is covered by overburden that varies in depth from a few feet to as much as 2,000 ft. Oil saturation varies from trace amounts to as much as 18 percent by weight. In a so-called good, average, potentially commercial area, the average saturation ranges from 10 to 15 weight percent. On this basis, at an average thickness of 150 ft, 1 sq mile of tar sand contains over 100 million bbl of bitumen in place - the equivalent of a major oil field. The extent of the overburden thickness determines how the bitumen might be recovered from the ore body. As a result, the main Athabasca oil deposit (Fig. 1) is generally divided into two principal areas: one where oil is recoverable by mining methods and the other where oil is considered recoverable only by in situ methods. Proved reserves of recoverable synthetic crude oil in these two areas are estimated at approximately 85 billion and 200 billion bbl, respectively. Division of the two areas has been roughly determined by the amount of overburden as related to the thickness of corresponding tar sand beds. However, this relationship is continually changing to allow for greater recoveries in the mineable area as operational techniques are improved.
JPT
P. 1337ˆ
Simulation of Big Muddy Surfactant Pilot
Authors: Saad Naji , Pope Gary A. , Sepehrnoori Kamy 
Published: December 2007

SummaryAn improved compositional chemical-flood simulator has been used for the study of the low-tension pilot project at the Big Muddy field near Casper, WY. Both the tracer injection conducted before injection of the chemical slug and the chemical-flooding stages of the pilot project were analyzed. Using a compositional simulator, we successfully matched not only the oil recovery but also the tracers, polymer, alcohol, and chloride histories.Simulation results indicate that for this freshwater reservoir, the salinity gradient during preflush and the resulting calcium pickup by the surfactant slug played a major role in project success. In addition, the analysis of the effects of crossflow on the performance of the pilot project indicate that for the well spacing of the pilot, crossflow does not play as important a role as it might for a large-scale project.
Professional Contemporizing: A Personal Challenge
Authors: Stockman F.D. , Dempsey J.R. , Preston F.W. 
Published: December 2007

Abstract
This article outlines one major company's method of insuring that its engineers keep up with the increased expansion of technical knowledge. The continuing education program developed for personnel of one division is presented and evaluated as to methods of presentation and impact upon participants. Stressed in the article is the unique industry-university cooperation exhibited in the program.

Introduction
The problem of technological obsolescence has been recognized for many years. Practically every journal devoted to engineering or technology and many outside this area have published editorials calling attention to the accelerating rate at which knowledge is increasing. These editorials also point out the serious problem facing scientists, engineers and even managers because of their own decreasing familiarity with principles once learned and because of the growing store of human knowledge.

The Knowledge Gap
Fig. 1 dramatically illustrates the growing gap between knowledge that is available to the technical world and the individual's knowledge that is eroded through infrequent use and a fallible memory. The number of publications in the technical literature is a measure of the increase in human knowledge. In 1963 Kriegel estimated that the total volume of technical literature would double in the period from 1960 through 1967. This prediction is already a fact and corresponds to a rate of increase of about 10 percent per year compounded annually. In a like manner, Thomas Stelson, head of the Civil Engineering Dept. of the Carnegie Institute of Technology, estimated that the decay of an engineer's knowledge without renewal is approximately 10 percent per year compounded annually. The difference between these two effects, called the knowledge gap (KG), can be reduced to the following generalized equation, KG = (1 + i)n - 1/(1 + d)n, where i = fraction increase per year in man's knowledge, d = fractional decrease per year in an engineer's remembered knowledge if no subsequent training is undertaken and n = number of years since graduation.
This equation is not the most plausible or best mathematical model of obsolescence. However, it does have gross qualitative significance. If, using the criteria cited above, i = d = 0.10, then within 5 years after graduation, a person's KG can be as large as his original store of knowledge.
A much more disturbing aspect of this obsolescence is that the changes in technology within the past decade have been so extensive that the entire mission of engineering has changed.
Gravel Packing in an Abnormally Pressured Chalk Reservoirs A Valhall Field Case Study
Authors: Attard Marcel , Mathes Robert A. , Mower Lawrence N. 
Published: December 2007

Summary
Gravel-packing operations in the Valhall field, offshore Norway, are performed under pressure with diesel as the work fluid and with a snubbing unit, because of the sensitivity of the reservoir rock to aqueous completion fluids. The methods used for wellbore preparation, wellbore cleanout, and gravel packing are described. These completion techniques have allowed wellhead pressures to be drawn down to much lower levels than before, resulting in significantly increased production rates.
Semianalytical Productivity Models for Perforated Completions
Authors: Karakas Metin , Tarlq S. M. 
Published: December 2007

Summary
This paper discusses the effects of various perforation and reservoir parameters on the productivity (or injectivity) of perforated completions. Because of the complex, 3D flow into a spiral system of perforations, productivity analysis of perforated completions is not easily amenable to analytical treatment. This paper presents a semianalytical solution for the estimation of skin in perforated completions. Results are presented for two separate cases: the 2D-plane-flow problem, which is essentially valid at small dimensionless perforation spacings (large perforation penetrations or high perforation shot densities) and the general 3D problem, where the vertical convergent flow into perforations is significant. In these analyses, the wellbore and vertical-flow effects are quantified in terms of pseu-doskins obtained by accurate finite-element simulations. The effects of perforation damage and formation anisotropy are also included. The results provide a better understanding of the relative role of various perforation parameters in affecting well productivity. Because they are based on theoretical considerations, the correlations allow reliable estimates of the skin in perforated completions.
New relations are provided for estimating productivity of perforated completions with formation permeability damage. Results indicate the importance of angular phasing, in addition to perforation penetration, in overcoming the effects of formation damage on well productivity.
Case Study of a Stimulation Experiment in a Fluvial, Tight-Sandstone Gas Reservoir
Authors: Warpinski Norman R. , Branagan Paul T. , Sattler Allan R. , Cipolla Craig L. , Lorenz John C. , Thorne B. J. 
Published: December 2007

SummaryA successful stimulation experiment was conducted in a fluvial sandstone of the Mesaverde formation at the U.S. DOE's Multiwell Experiment (MWX) Site in the Piceance basin of Colorado. The stimulation experiment consisted of stress tests, a three-well prefracture interference test, step-rate/flowback tests, a minifracture, a full stimulation treatment, borehole geophone diagnostics during fracturing, and a postfracture interference test.
Boundary-Dominated Flow in Solutions-Gas-Drive Reservoirs
Authors: Camacho-V. Rodolfo G. , Raghavan Rajagopal 
Published: December 2007

SummaryThe performance of wells in solution-gas-drive reservoirs during the boundary-dominated flow period is examined. Both constant-wellbore-pressure and constant-oil-rate production modes in closed systems are considered. For the constant-wellbore-pressure production mode, Arps' performance-prediction equations are examined, and predictions of future performance are shown to be strong functions of well spacing, well condition, and fluid properties. The parameters b (the decline exponent) and di (the initial decline rate) in the Arps equations are expressed in terms of physical properties. The conditions under which these equations can be used are specified. An empirical procedure to predict production rates is also presented. In the case of constant-oil-rate production, an expression to correlate the pressure distribution in the reservoir is presented. The correlating function permits us to extend the definition of pseudosteady-state flow to solution-gas-drive systems. Its use also allows the simultaneous computation of average properties (pressure and saturation) during boundary-dominated flow from wellbore information.
Planning Engineering Careers Staff and Line
Authors: Matthews C.S. 
Published: December 2007

Abstract
The basic aim of engineering career planning should be to provide the optimum opportunity for self-development. Planning for the early years should encourage development of technical proficiency. Later planning can then be directed either toward development of a highly qualified specialist or toward development of an administrator.

Introduction
During the last decade two factors have tended to emphasize the importance of career planning for engineers. The first of these is the growing dependence of companies upon engineering and research for economic success. The second is the shortage of engineering talent. These two factors make it imperative that the talent of each engineer be developed and used in an optimum manner optimum from the standpoint of both the individual and the company. The aims and goals of both the individual and the company must be compatible. Successful career planning strives to satisfy the need and desires of both.
To develop and use staff in an optimum manner, career planning is necessary. Career planning may be thought of as the providing of an environment conducive to the growth of an individual, and with his growth, the growth of the company. Provision of this environment the challenges, training, responsibilities, recognition and reward is the duty of the career planners. Other than to provide this environment and to provide motivation through recognition and reward, there is little the career planners can do to aid the development of an individual. The responsibility for this development rests solely on that individual. He alone can provide the necessary motivation and effort for his own growth. These two aspects then, career planning and self development, go hand in hand, and each is equally important in development of a successful career.
Helpful advice in planning the career of the young engineer has been given by Sands and Brown. Danielson has given insight into how engineers view themselves and their careers in his "Characteristics of Engineers and Scientists". This insight was gained through interviews with scientists and engineers and thus is of considerable value to the career planner. Much has been written about preparing the engineer to manage. Miller has discussed the training of engineers for management and Wilson has discussed the selection of candidates for management from the engineering ranks. From the viewpoint of aiding self-development of an engineer Douma points out what management expects of an engineer and suggests methods for achieving these expectations.
Many of the thoughts given in the sections to follow can be found in these cited references. In addition, I have drawn heavily on the thoughts of colleagues in my own and in other companies. To them must go the credit for most of the ideas that will be discussed. These ideas are directed specifically toward career planning in an exploration and production organization of large to medium size. However, many of the ideas will apply to career planning in any organization.
Scaled Physical Modeling of Steam-Injection Experiments
Authors: Klmber K. D. , Farouq All S. M. 
Published: December 2007

Summary
Scaled model experiments are valuable aids to steamflood design and numerical simulation. Current scaling techniques, however, have limitations. Because the techniques require porous media and pressure conditions different from those in the field studied, pressure-dependent properties and porous media characteristics are not scaled accurately. This paper discusses scaling techniques that allow field porous media and pressure conditions to be used. The ability of scaling approaches to predict such parameters as oil production rate, temperature distribution, and pressure conditions is considered. The new approaches provide scaling options for steam processes that use additives (PVT properties must be scaled), that use pressure cycles (fluid compressibilities must be scaled), and that require use of the same porous medium as found in the field.
Some Practical Considerations in the Numerical Solution of Two-Dimensional Reservoir Problems
Authors: Briggs J.E. , Dixon T.N. 
Published: December 2007

Abstract
A study was made of numerical techniques for solving the large sets of simultaneous equations that arise in the mathematical modeling of oil reservoir behavior. It was found that noniterative techniques, such as the Alternating Direction Implicit (ADI) method, as well as some other finite difference approximations, produce oscillatory or unsmooth results for large time steps. Estimates of time step sizes sufficient to avoid such behavior are given.
A comparison was made of the Point Successive Over-Relaxation (PSOR), Two-Line Cyclic Chebyshev Semi-Iterative SOR (2LCC), and iterative ADI methods, with respect to speed of solution of a test problem. It was found that, when applicable, iterative ADI is fastest for problems involving many points, while 2LCC is preferable for smaller problems.

Introduction
With the advent of high speed, large memory, digital computers, there has been an increasing emphasis on the development of improved methods for simulating and predicting reservoir performance. Two-dimensional, three-phase reservoir models with various combinations of PVT effects, as well as gravity and capillary forces, are common throughout the industry. Such models are also available through consulting firms, to anyone desiring to use them. Three-dimensional models will probably be practical in only a few years.
Enhanced In-Situ Stress Profiling With Microfracture, Core, and Sonic-Logging Data
Authors: Ahmed Usman , Markley M. E. , Crary S. F. 
Published: December 2007

Summary
Knowledge of in-situ stress distribution, especially in the vertical direction, is vital to hydraulic-fracture geometry calculations. The microfracturing technique is recognized as the best method to measure in-situ stress directly. The technique, however, is typically limited to very few measurements and, at times, it is impractical to break down and measure in-situ stress in bounding nonproducing layers. Also, in layers with significant stress variation, microfracture measurements can be reflective of an average value of the variations and thus can be misleading. Alternative techniques like core measurements can suffer from depth discrepancies and lack of measurements at in-situ conditions. Sonic-logging methods can provide continuous in-situ measurements of rock mechanical properties; however, modeling stresses from mechanical properties have certain limitations. In this paper, we present a method that can compensate for the disadvantages of the individual techniques with the advantages of the others and thereby create relationships that can facilitate obtaining representative and continuous in-situ stress data. Data from two wells are presented to illustrate the method's application.
Shared-Time Net Oil Measurement for Commingling Operations
Authors: McDuffie John C. 
Published: December 2007

Abstract
Electrical control over the discharge sequence for emulsion dumps from several separator allows one meter. probe and computer to measure separately, under pressure. the net oil from diverse ownership sources. Volumes from a lease-shared test separator may be included. Regulatory approval was granted and field use has commenced.

Introduction
Commingling untreated crude from diverse ownership sources for central treating and custody transfer commonly involves proportional allocation of central deliveries on the basis of lease net oil measurements. Equity maintenance obligation are met by using lease net oil measurement methods of equal quality, accuracy and reliability for all properties connected to the system. The difference between actual deliveries adjusted for central stock change and the sum of the lease net oil volumes for the month provides a continuing evaluation of commingling system performance.
A lease net oil measurement unit (Fig. 1) costs about $2,500 and has a capacity exceeding 2,000 B/D. Many leases produce less than 200 B/D, and many multiwell leases need facilities for well testing that involve a net oil measurement separated from the remaining lease production being handled simultaneously. High initial investments can result from inefficient applications of equipment that occur when fieldwide modernization programs are attempted with separate measuring assemblies for production and well test functions needed on all properties.
The shared-time net oil measurement method was developed to reduce both initial costs and future operating expenses required for lease measurements in commingling operations. It comprises electrical control of the sequence of discharge cycles from several emulsion source vessels that are connected to a single metering and measuring assembly. In effect, the multilease automatic custody transfer (ACT) control method is applied to the small-volume dumps under separator pressure from lease separators through a capacitance probe and meter assembly to achieve separate registration of measured net volumes by leases. The shared-time method has most of the merits and liabilities associated with its predecessor components.
A Unique Method for Perforating, Fracturing, and Completing Horizontal Wells
Authors: Damgaard A. P. , Bangert D. S. , Murray D. J. , Rubbo R. P. , Stout G. W. 
Published: December 2007

Summary
This paper describes the evolution, laboratory testing, and field installation of a completion system developed to perforate, fracture stimulate, and isolate multiple zones in North Sea horizontal wells. This system is designed to reduce overall completion time and well control problems significantly and to allow selective zone control in production and restimulation phases. The field performance of this system is compared with that of previously used methods.
Combating Gas Migration in the Michigan Basin
Authors: Bour D. L. , Wilkinson J. G. 
Published: December 2007

Summary
Gas migration has been a significant problem in cementing wells drilled in the Praire du Chien formation. Several types of gas-migration cementing systems have been used successfully during the past several years, but only recently has an analytical method been developed to help quantify the nature of gas-migration potential on an individual well basis. Once the probable limits of the gas flow have been established, it is possible to match an appropriate gas-migration-control cementing system for a specific set of well parameters. An important aspect of this process is computer analysis that establishes the probability of gas migration for a given set of well conditions and then selects an effective strategy for designing the cementing program for that particular set of conditions. This paper presents case histories illustrating applications of gas-migration-control cement systems with particular emphasis on the job design process.
Whole-Core Analysis by 13C NMR
Authors: Vinegar H. J. , Tutunjian P. N. , Edelstein W. A. , Roemer P. B. 
Published: December 2007

SummaryA whole-core nuclear magnetic resonance (NMR) system was used to obtain natural abundance 13C spectra. The system enables rapid, nondestructive measurements of bulk volume of movable oil, aliphatic/aromatic ratio, oil viscosity, and organic vs. car bonate carbon. 13C NMR can be used in cores where the ‘HNMR spectrum is too broad to resolve oil and water resonances separately.A 51/4-in. 13C/1H NMR coil was installed on a General Electric (GE) CSI-2T NMR imager/spectrometer. With a 4-in.-OD whole core, good 13C signal/noise ratio (SNR) is obtained within minutes, while 1H spectra are obtained in seconds. NMR measurements have been made of the 13C and 1H density of crude oils with a wide range of API gravities. For light- and medium-gravity oils, the 13C and 1H signal per unit volume is constant within about 3.5%. For heavy crudes, the 13C and 1H density measured by NMR is reduced by the shortening of spin-spin relaxation times. 13 C and 1H NMR spin-lattice relaxation times were measured on a suite of Cannon viscosity standards, crude oils (4 to 60°API), and alkanes (C5 through C16) with viscosities at 77°F ranging from 0.5 cp to 2.5 × 107 cp. The 13C and 1H relaxation times show a similar correlation with viscosity from which oil viscosity can be estimated accurately for viscosities up to 100 cp. The 13 C surface relaxation rate for oils on water-wet rocks is very low.Nonproton decoupled 13C NMR is shown to be insensitive to kerogen; thus, 13 C NMR measures only the movable hydrocarbon content of the cores. In carbonates, the 13C spectrum also contains a carbonate powder pattern useful in quantifying inorganic carbon and distinguishing organic from carbonate carbon.