bluuebunny/crossref_metadata_2025_split huggingface dataset:
In-Situ Production Cost Model for Uranium
Authors: Toth G. W. , Larson W. C. 
Published: December 2007

Abstract
In a recently completed research project for the U.S. Bureau of Mines -Twin Cities Research Center, a computerized costing procedure for uranium in situ leach mining was developed by the NUS Corporation. This costing procedure, termed a cost model, employs a process engineering approach for estimating total project costs as well as equipment and manpower requirements for uranium in situ leaching operations in either Texas or Wyoming. The Bureau recently added the capability to apply the model for New Mexico deposits. NUS also provided consulting support for this modification. Both capital and operating costs are generated by the model along with the overall production cost/pound U3O8 subject to a known rate of return. Conversely, rate of return on equity can be solved for, subject to a given price of yellowcake.
During the course of the research effort, sensitivity tests were conducted for numerous key parameters to determine the cost influence attributable to incremental changes in parameter values. The results of these sensitivity tests along with a description of the in situ leaching cost model have been documented as Bureau of Mines, Mineral Research Contract Report No. J019912, "Cost and Sensitivities Analysis for Uranium In Situ Leach Mining," dated March 1981. An update of this report was subsequently prepared by the Bureau entitled "Improved Solution Mining Production Cost Model," dated September 30, 1982. This update contains the modifications required for application of the model for New Mexico deposits.
In the remainder of this paper, the various features and capabilities of the cost model will be highlighted, along with a review of the sensitivity analysis findings.
Computerized Well Planning for Directional Wells
Authors: Hodgson Harry , Varnado S. G. 
Published: December 2007

ABSTRACT
This paper describes the use of computers for planning the trajectories of deviated wellbores and for monitoring the position of the well during the drilling operation. The model can be implemented on a small (64 Kb) mini-computer. The equations for the model are presented, along with the plots generated. Available plots include vertical and horizontal sections of the wellbore, traveling cylinder plots for anti-collision analysis, and plots that compare the planned wellbore trajectory with the actual surveyed trajectory. In addition, a new directional drilling simulator is described that allows the simulated drilling of a directional well. The simulator is currently in use as a training aid. However, it can also be used for engineering applications. The simulator is interactive and some sample results from the simulator are presented.
A Laboratory Study of the Effects of Hydraulics on Hole Erosion
Authors: Gaylord E. W. 
Published: December 2007

ABSTRACT
Laboratory studies were made with fluids containing bentonite and microcellulose fibers to determine the relationship of Theological variables to borehole erosion. The primary objective of the study was to observe hole erosion that results from purely hydraulic effects. The study was made by circulating fluid through a hole in a specimen made of compacted ground shale. The results of the investigation show a relationship between erosion, fluid wall shear stress, and plastic Reynolds number.
The Use of Weight on Bit, Torque, and Temperature to Enhance Drilling Efficiency
Authors: Guillen G. E. , Lesso W. G. 
Published: December 2007

ABSTRACT
Today, most drilling efficiency decisions are based on models describing downhole drilling conditions. The inputs to these models have in the past been a collection of surface measurements. Measurements While Drilling (MWD) provides realtime information from near the bit and allows for a more comprehensive understanding of downhole drilling conditions. Downhole measurements can help eliminate uncertainties in the behavior of the drilling system, and provide a more scientific approach to improving drilling efficiency.
The downhole drilling measurements include: weight on bit and torque measured by strain gauges set in a drill collar; temperature measured by a sensor on the outside of the collar; and mud flow rate interpreted from the MWD alternator output. Comparison of these measurements with surface data reveals previously unexpected trends that can help diagnose problems. The interrelationships among these measurements lead to a better understanding of the drilling process, and can help make immediate decisions concerning drillstring washouts, bit balling, packed off drilling assemblies, severe dog legs, the overloading of polycrystalline diamond compact bits, and the pulling of worn bits, resulting in direct savings of rig time.
From Geopressured Aquifer Test Well to Commercial Gas Producer: A Case Study
Authors: Doherty M. G. , Randolph P. L. , Poonawala N. A. 
Published: December 2007

ABSTRACT
A short test of a geopressured sandstone produced brine resulting in a decision to abandon the well as a dry hole. The pressure, temperature and salinity of the zone led to additional testing as a Department of Energy (DOE) sponsored geopressured-geothermal "Well of Opportunity." A series of three drawdown and two buildup tests were performed over a two week period. Accurate and continuous measurement indicated a monotonically increasing gas-water ratio (GWR) during the first 24-hour flow test. This change was accompanied by a relatively high and increasing natural gas liquid (NGL) content in the gas. After a total of 9 days of production during a 14-day period, the GWR increased from about 37, SCF/STB (6.7 m3/m3) to over 320 SCF/STB (57.6 m3/m3) with production of about 1.0 MMCE/D (28 636 m3/d) of gas containing 135 BPD (21.5 m3 /d) of NGL, 75 BPD (11.9 m /d) of 40° API (0.83) crude oil and 3150 STB/D (501 m3 /d) brine. More than 33 months after this test, the well was still a commercial hydrocarbon producer.
It appears that the well was a near miss in the context of exploration for a gas cap. Careful measurement of the variations in the produced GWR plus variations in the relative abundances of hydrocarbon species demonstrated a potentially valuable tool for the early detection of the close proximity of a gas cap to a well that produces only brine. Computer simulation with a radial coning model provided an appropriate history match when a greater sand thickness was assumed. Production projections indicated that the reservoir could produce substantial quantities of hydrocarbons over time at a constant 1000 BPD (159 m3/d) or 2000 BPD (318 m3/d) brine rate. Actual production values are in reasonable agreement with the projected figures even though a number of problems caused erratic production and a rather simplistic model interpretation was made.
A productive offset well has been drilled. It is doubtful whether this offset would exist had the initial well been a "dry hole."
Fracture Design with Time- and Temperature-Dependent Fluid Properties
Authors: Poulsen D. K. , Lee W. S. 
Published: December 2007

Abstract
The proppant transporting ability of most hydraulic fracturing fluids is both time and temperature dependent. A proppant transport model that considers this dependence and the fluid temperature variation throughout a fracturing treatment has been devised. This model provides the basis for a numerical method to aid in selecting staged gel and gel stabilizer concentrations.
Downhole Density of Heavy Brines
Authors: Krook G. W. , Boyce T. D. 
Published: December 2007

Abstract
Heavy brine completion fluids decrease in density with increasing temperature and increase in density with increasing pressure. Pressure-volume-temperature (P-V-T) analysis of various brine solutions at temperatures from 76° to 345°F and pressures of 0 to 22,000 psig has been used to examine the behavior-of brine density under bottom-hole conditions. Information obtained from these measurements allows the engineer to calculate more precisely the brine density at the surface which will provide the desired hydrostatic gradient for formation pressure control at downhole temperatures and pressures.
The Application of Depth of Formation Damage Measurements in Predicting Water Injectivity Decline
Authors: Todd A. C. , Somerville J. E. , Scott Graham 
Published: December 2007

Abstract
Pressure maintenance by sea water injection is part of many offshore field developments. Experiences gained over the last decade in the North Sea, where there is a wide variance in the systems used, appears not to have clarified design specifications.
The paper describes various approaches to analysing water quality criteria with reference to water injection schemes and presents the philosophy of the interrelated approach of laboratory experiments, theoretical models and well injectivity predictions in relation to reservoir characteristics.
Results are presented from a laboratory and modelling investigation of permeability impairment as a function of the depth of invasion. A pore network model is described which is generated from laboratory derived pore size distribution data. Predictions of permeability from the model are compared to experimental values and good agreement is demonstrated. The incorporation into the model of particle capture mechanisms enables it to be used to predict the reduction in permeability of a core arising from injection fluids. Another modelling approach is described where the contribution of pore size to permeability is demonstrated.
Water quality experimental results are presented showing permeability profiles obtained using a multiport pressure tapped core holder which demonstrate local permeability impairment as a function of particle size and rock properties.
The results of one modelling approach is applied in the paper to the prediction of well injectivities and filtration requirements.
Aqueous-Based Remedial Treatments for Reservoirs Damaged by Oil-Phase Drilling Muds
Authors: Goode D. L. , Berry S. D. , Stacy A. L. 
Published: December 2007

Abstract
Wells drilled with oil-phase muds are subject to severe damage due to loss of mud filtrate or whole mud to the reservoir matrix or hairline fractures. It is essential that this mud be removed prior to well production in order to gain maximum productivity. A system of aqueous-based remedial treatments has been employed to remove oil-phase drilling muds from damaged reservoirs. Mud solids are suspended and viscosity is permanently lowered by the aqueous-based system so that the mud can be flowed to the surface. Special surfactants restore the affected reservoir to a water-wet state and clay stabilizers prevent formation damage. The new system represents an improvement over conventional hydrocarbon/mutual solvent treatments. The conventional treatments do not effectively suspend mud solids and only temporarily reduce mud viscosity, while leaving the treated reservoir in an oil-wet condition. The aqueous-based system also lowers surface injection pressure below that required by hydrocarbon/mutual solvent systems.
Laboratory data are presented showing the relative effects of the aqueous-based system and a hydrocarbon/mutual solvent treatment on the degree and permanence of oil-phase mud viscosity reduction. The aqueous-based system more effectively and irreversibly lowers mud viscosity as compared to the hydrocarbon/mutual solvent treatment. Cores damaged by oil-phase mud filtrate or whole mud were treated with either hydrocarbon/mutual solvent or the aqueous-based system. Regained core permeabilities following the treatments indicate that the aqueous-based system yields significantly higher recoveries than the hydrocarbon/mutual solvent treatment.
The aqueous-based system has been widely used in wells drilled with oil-phase muds to effect significant production increases. The aqueous-based remedial treatments have more effectively removed damaging oil-phase mud filtrate and solids than conventional hydrocarbon/mutual solvent treatments. In the process, problems associated with the use of hydrocarbon/mutual solvent treatments have been alleviated. These problems include high pumping pressures, "regelling" of the mud, oil-wetting of the formation, and incomplete removal of mud solids.
Dewatering a Deep Gas Well With a Gas Lift System—A Case History
Authors: Green R. E. , Korzekwa C. R. 
Published: December 2007

ABSTRACT
A characteristic of Fusselman gas wells in the Permian Basin is that they begin to produce connate water early in the life of the well. Eventually the water entering the wellbore cannot be unloaded because the hydraulic pressure of liquid fall back becomes greater than the reservoir pressure and the well ceases to flow. At this watered out and nonflow state, considerable gas may remain in the formation. This case study deals with the development of a closed loop gas lift system designed to unload water.
The gas lift system consists of: a predetermined number of gas lift valves externally mounted on mandrels and installed in the tubing string, surface processing equipment, and a gas compressor. Dewatering of the well is accomplished by injecting gas down the tubing-casing annulus and through the gas lift valves. The injection and dewatering process continues until the reservoir pressure overcomes the hydrostatic head. At this point the well will kick-off and flow. To maintain this flowing condition, a portion of the well stream is diverted and reinjected into the well to maintain high velocities in the tubing. The high tubing flow rate lifts the water and reduces the dynamic pressure gradient in the tubing.
The well in this study is currently producing in the above manner. Restoration of gas flow in this well required thirty days due to the uniqueness of the project and modifications through trial and error. Since then, the well has stabilized with a sales volume of 1,100 Mcf/D (31,500 m3/d) and gas lifts 350 barrels of water daily (55 m3/d). An injection volume of 400 Mcf/D (11,455 m3/d) maintains high tubing velocities and prevents the well from loading with water. An increase in reserves has resulted from gas lifting this nonproductive well.
System Survey for Improving Injection Efficiency
Authors: Crow C. L. , Keeling R. E. 
Published: December 2007

ABSTRACT
Injection water quality is a primary factor affecting the ease with which water can be injected into a reservoir and the overall success of a waterflood operation. Proper water quality can also keep waterflood maintenance costs low by reducing the amount of remedial work normally required on injection wells. Most injection systems if properly designed minimize oil carryover and solids content. Water conditioning prevents scale deposition, reduces solids, and allows recovery of carryover oil, resulting in minimum injection pressures. The type of water conditioning process necessary is determined by equipment evaluation and water analyses (including compatibility predictions and membrane filter testing).
Equipment evaluations, such as retention time studies that determine vessel residence time, describe the current mechanical operation of the system. Water analyses and compatibility studies predict the probability of scaling, corrosion, and solids formation occurring within the system. Membrane filter tests are performed to determine the type and amount of suspended solids contained in the water. From these tests, proper water conditioning techniques are implemented. All data should be gathered throughout the system to detect changes occurring between the water source(s) and the injection wells. Changes in such factors as pressure, temperature, and dissolved solids influence problem development.
Graphic representation of data, such as oil concentration (ppm) versus time (days) of a particular vessel's influent and effluent, assists in setting and meeting objectives for injection water quality. Special analyses, such as core flow tests and filtration studies, also define cost-effective solutions to problems.
Principles of Squeeze Cementing
Authors: Goodwin K. J. 
Published: December 2007

ABSTRACT
Squeeze cementing is, by historical definition, the application of differential pressure across a cement slurry to accomplish the process of cement dehydration. The primary purpose of the dehydration is to create immobility of the cement slurry until some compressive strength can be developed. Current cementing technology and additives have improved the process sufficiently that the term "squeeze" may no longer be applicable. It is felt that "Remedial Cement Placement" may be more appropriate, and may more accurately define the process.
The success of a remedial cementing operation depends on a finite definition of the existing problem and the results expected from the operation. If the purpose of the squeeze is not definable, a squeeze job may not be necessary. Significant completion dollars are wasted annually on unnecessary squeezes, poorly designed squeeze slurries, and/or improper slurry placement. Many of the various applications of squeeze cementing may be classifiable as one purpose, i.e., repairing the primary cement sheath to isolate producing intervals and protect the casing string. Proper placement of a low-water loss cement slurry, at minimal surface pressure, into the casing-open hole annulus can satisfy most requirements of squeeze cementing. Initial breakdown pressures and pump-in rates prior to squeeze operations should be conducted at less than Bottom Hole Fracturing Pressure, (surface pressure [or ISDP] + hydrostatic pressure = bottom hole frac pressure). This will insure the placement of the slurry into the annulus, not into the formation. High pressure squeezes are not required, and are in fact, discouraged.
Placement of large volumes of cement slurries into the formation via created fractures, natural fractures, vugs, or zones with worm holes seldom satisfies any squeeze performance criteria; including improvement of GOR, WOR, or isolating a zone for stimulation (block squeeze). If the initial breakdown and pump-in test cannot be performed at sub-fracturing pressure, the cement sheath is competent and the squeeze operation is not required.
Gas Well Deliverability Improved By Planned Fracturing Treatments
Authors: Waters A.B. , Tinsley John M. 
Published: December 2007

Publication Rights Reserved
This paper was to be presented at the 40th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colorado, October 3–6, 1965, and is considered to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract elsewhere after publication in the Journal of Petroleum Technology or Society of Petroleum Engineers Journal is granted on request, providing proper credit is given that publication and the original presentation of the paper.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Deliverability from thousands of gas wells has been improved materially by hydraulic fracturing. Both flowing rate and wellhead pressure frequently increased substantially. In many cases production following treatment has been several fold greater than that obtained upon initial completion. Where it has been possible to make detailed study of well data and plan treatments based thereon, results have been quite gratifying. Specific study of cores from individual wells has provided better information for selection of more appropriate fracturing techniques, procedures and chemicals.
Different factors are discussed which should be considered in pre-planning fracturing treatments and some field examples are cited.

Introduction
Estimated natural gas reserves in the U. S. A. at end of 1964 are reported to be in excess of 290.500 MMcf/D. This represents more than a two-fold increase in the reserves reported 20 years ago even though the marketable production has more than tripled in the same period of time. A large part of the increase in reserves has been in the past 16 years, since hydraulic fracturing was first introduced. Commercial success of a given well is dependent on the rate of deliverability at specified drawdown pressures and the period of time such deliverability can be maintained. Improved deliverability derived by fracturing bas made it possible for many wells and fields previously considered non-commercial to be converted into profitable ventures. Not only have production rates been increased. but frequently wellhead pressures have been increased several fold. These factors have a direct relationship with open flow potential.
Past experience has specifically indicated that planned or designed treatments for gas well formation conditions and reservoir characteristics have materially increased the success ratio. Although hit-or-miss treatments have been successful. consistently good results have not always been obtained. This paper will review and bring together many of the factors which a gas well operator should consider in planning a fracturing treatment to obtain improved deliverability.
PDC Bits Find Application in San Joaquin Valley
Authors: Fox J. P. , Wood J. E. 
Published: December 2007

ABSTRACT
Polycrystalline diamond compact (PDC) bits have been successfully and economically used to drill sand and shale sections in the oilfields of the Southern San Joaquin Valley of California. "Successful" refers to reducing the number of days to drill a well by four to six days, and "Economical" refers to reducing the cost per foot for the sand and shale intervals drilled with PDC bits.
Enhancements of design variables including variations in back rake and side rake angles, and improved selection (numbers and sizes) of nozzles have helped PDC bits be economical in the Southern San Joaquin Valley.
In addition to conventional vertical wells, PDC bits used in conjunction with mud motors and steering tools have also been successfully used to directionally drill wells in this area.
Diagnostic Tools for Mapping California EOR Processes
Authors: Leighton A. J. , Wayland J. R. 
Published: December 2007

ABSTRACT
In recent years techniques using wave properties have been developed or adapted for measuring fluid injection fronts in assisted oil recovery processes. Also, tracer and pressure transient tests are being used increasingly to track and diagnose problems in these processes. This paper, summarizing the companion paper, "Diagnostic Tools for mapping EOR Processes," briefly describes each technique and its strengths and weaknesses. Conditions for most advantageous application are given.
The chief considerations in selection of a suite of mapping and diagnostic techniques for an EOR project are discussed. The selection process is illustrated by three hypothetical examples which are typical for operations in larger California oil fields.
The techniques are most effective when used in combinations and in conjunction with all other reservoir information available.