bluuebunny/crossref_metadata_2025_split huggingface dataset:
Structural Repair Experiences in the Viking Gas Field
Authors: Jones Glyn R. 
Published: December 2007

Abstract
This paper discusses the problems in dealing with cracks on subsea nodes on in-service North Sea structures. Determining the cause of cracking before planning remedial action is an important aspect of guaranteeing a successful repair. Gathering information on the nature of subsea cracks to establish causes of cracking and assess crack significance is a task severely handicapped by the inadequacy of present inspection techniques. The causes of cracking can be many and various, ranging from poor steel properties to fatigue. Assessment of crack significance to the safety of a structure can make use of fracture mechanics techniques, but their inaccuracy in a complex node situation with unknown factors, such as crack profile and steel properties, has to be borne in mind. Many repair methods are available, ranging from hyperbaric welding to bracing, but the method used must be matched to the cause of cracking. Accurate measurements of the as-built geometry of structures, early repair site preparation, and attention to minor detail greatly reduce repair costs and enhance the chances of success.
Rheological Monitoring of the Formation of Polyacrylamide/Cr+3 Gels
Authors: Prud'homme Robert K. , Uhl Jonathan T. , Poinsatte John P. , Halverson Frederick 
Published: December 2007

Abstract
The formation of polyacrylamide/chromium-ion gels has been followed rheologically. The time dependence of the storage modulus has been used to analyze the kinetics of the gelation process. The kinetic theory of rubber elasticity has been used to determine the crosslink density in the gel from the measured value of the storage modulus. The effects of changing polymer, chromium ion, and reducing agent concentrations have been studied.
A New Method To Simulate the Effects of Viscous Fingering on Miscible Displacement Processes in Porous Media
Authors: Vossoughi Shapour , Smith James E. , Green Don W. , Willhite G. Paul 
Published: December 2007

Abstract
Dispersion and viscous fingering are important parameters in miscible displacement. Effects of dispersion on concentration profiles in porous media can be simulated when the viscosity ratio is favorable. The capability to simulate viscous fingering is limited.
This paper presents a new method to simulate effects of viscous fingering on miscible displacement processes in porous media. The method is based on the numerical solution of a general form of the convection-dispersion equation. In this equation the convection term is represented by a fractional flow function. The fractional flow function is derived from Darcy’s law by using a concentration-dependent average viscosity and relative flow area to each fluid at any point in the bed.
The method was extended to the description of a polymer flood by including retention and inaccessible PV. A Langmuir-type model for polymer retention in the rock was used. The resulting convection-dispersion equation for displacement by polymer was solved numerically by the use of a finite-element method with linear basis functions and Crank-Nicholson derivative approximation.
History matches were performed on four sets of laboratory data to verify the model: (1) an unfavorable viscosity ratio displacement, (2) stable displacement of glycerol by polymer solution, (3) unstable displacement of brine by a slug of polymer solution, and (4) a favorable viscosity ratio displacement. In general, computed results from the model matched laboratory data closely. Good agreement of the model with experiments over a significant range of variables lends support to the analysis.
A Review of 1960 Domestic Production
Authors: Miller Raymond W. 
Published: December 2007

The General Picture
Totaling the score on the oil Industry for 1960 gives a sobering picture. Demands for petroleum products were up 2 per cent for the year. This was on the plus side but was a lot less than industry is accustomed to when contrasted with increases of about 4 per cent for 1959 and 5 per cent per year in the earlier postwar years.
Crude-oil production was about 0.5 per cent below 1959, with an increase of about 7 per cent in the production of natural-gas liquids. Crude-oil stocks were down 9.6 per cent from the previous year, which was the lowest yearend crude-stock figure in more than a decade. On the other hand, gasoline and kerosene stocks were up substantially while distillate and residual fuel oils were a little lower than a year ago.
It is important to note that much of the so-called stocks are actually in pipelines and are working stocks rather than readily available. With the increased use of pipelines for products, a higher per cent of the products are now working stocks. Over-all, at least one-half of the total stocks are not readily available for use.
Gas Injection in Eastern Venezuela Field Increases Oil Recovery
Authors: Vowel W.R. 
Published: December 2007

Abstract
The West Guara field lies in the state of Anzoategui, Venezuela, and is one of a number of fields located in the Eastern Venezuela Sedimentary Basin. The F7 sand, largest producing sand in the field, is of Oligocene age and is found at an average depth of 6,020 ft. The sand itself is clean, very well sorted, medium grained, with permeabilities ranging from 1,000 to 20,000 md and porosities ranging from 25 to 35 per cent. The oil was originally saturated, and a small initial gas cap was found during development. Original stock-tank oil in place was estimated to be 84,710,000 bbl.
Recovery as of Jan. 1, 1958, amounted to 51 million bbl or 60 per cent of the original oil in place. Evidence of gravity segregation was noted early in the life of the field and as a result, recovery under primary depletion, estimated at 59 per cent of the oil in place, would have been very good. However, early initiation of pressure maintenance by gas injection and exercising close control of producing operations will yield an ultimate recovery of approximately 70.5 per cent of the original oil in place. The ideal nature of the reservoir and its very light oil (42 API) are conducive to such control, and accurate prediction of performance using established engineering techniques is facilitated.

Introduction
The field produces from the Oficina formation of Oligocene age which consists of 3,000 ft of interbedded sands and shales. Of the 39 oil productive sands the F7 sand is the largest oil-bearing body in the field. Accumulation is controlled on the south by the West Guara fault, and on the north by an oil-water contact at 5,265 ft. The sand was deposited as a channel trending roughly north and south; thickness in the main channel approaches 100 ft. Thinning occurs to the east and west until on these flanks the thickness is approximately 10 to 20 ft. Fig. 1 shows pertinent structural details.
Table 1 presents pertinent data concerning oil characteristics and other reservoir information used in analyzing the F7 sand reservoir. It became apparent early that reservoir recovery would be high. However, to supplement this recovery and to maintain the wells on a flowing status, it was decided to maintain pressure by gas injection. Methods used in predicting reservoir recovery without pressure maintenance and with pressure maintenance are presented. Also discussed are operating procedures used so that actual recovery will approach as nearly as possible the predicted recovery.
A Novel Pressure Maintenance Operation in a Large Stratigraphic Trap
Authors: Weyler J.R. , Sayre A.T. 
Published: December 2007

Abstract
This paper presents a discussion of a program of pressure maintenance for the Adena sand field, a shallow dipping stratigraphic trap having a large gas cap. It is concluded that a reservoir of this type be successfully water flooded by injection into a row of wells along the gas-oil contact. Reservoir and laboratory studies showed that water channeling in gas saturated streaks existing in the oil zone would not occur, and that an effective water barrier could be formed between the large gas cap and producing area. Studies indicated gas-oil contact water injection far superior to the other programs investigated. One year of field performance indicates that the pressure maintenance program is functioning satisfactorily.

History of Development and Unitization
In May, 1953, Falcon Seaboard Drilling Co. drilled the Snodgrass No. 1 in Sec. 20, T 1 N R 57 W, as a rank wildcat approximately 14 miles south of Fort Morgan. Colo. (Fig. 1). This well encountered gas in the J sand of the Dakota series and was completed for a good gas well in what is now recognized to be the gas cap of the Adena field, the largest oil field in the Denver-Julesburg Basin. This well created only mild interest in this area of the basin and the next few wells drilled were considered to have but slightly more than wildcat prospects. The oil discovery came in Nov., 1953, when an independent operator completed the Cochran No. 1 in Sec. 12, T 1 N, R 58 W, flowing 900 bbl of 42 gravity oil from the J sand.
The Adena J sand field is approximately seven miles long and 3.5 miles wide. The oil zone has an areal extent of approximately 8,425 acres and the gas cap covers approximately 4,650 acres. Basic reservoir data is shown in Table 1. Production is primarily from the Dakota J sand of Cretaceous age, encountered at an average depth of 5,650 ft. The formation dips gently to the west at a rate of only 48 ft per mile, with minor nosing and flattening within the field proper (Fig. 2). Basically, the field is a stratigraphic trap, with local structure playing a very minor role as a trapping component. Oil accumulation is controlled by permeability barriers on the east, north and south sides of the field, and by a shale seal at the base of the first bench. The formation is a light gray, fine-to-medium grained grindstone. To date 170 oil wells and 15 gas wells have been drilled. The gas wells have been shut-in since completion to conserve reservoir energy. Wells were completed by drilling the entire sand section, running 5.5-in. casing and perforating the pay interval. It took only two weeks to drill and complete a well. Approximately 85 per cent of the wells in the field were both cored and logged.
Frictional Heating and Convective Cooling of Polycrystalline Diamond Drag Tools During Rock Cutting
Authors: Ortega Alfonso , Glowka David A. 
Published: December 2007

Abstract
A numerical-analytical model is developed to predict temperatures in stud-mounted polycrystalline diamond compact (PDC) drag tools during rock cutting. Experimental measurements of the convective heat-transfer coefficient for PDC cutters are used in the model to predict temperatures under typical drilling conditions with fluid flow. The analysis compares favorably with measurements of frictional temperatures in controlled cutting tests on Tennessee marble. An equation incorporating several drilling parameters is developed to predict the mean operating temperature across the cutter wearflat, defined as that portion of the cutter surface that wears against the rock formation. It is shown that mean wearflat temperatures can be maintained below a maximum safe value of 750°C [1,382°F] only under conditions of low friction at the cutter/rock interface, regardless of the level of convective cooling. The ability of liquid drilling fluids to reduce interface friction is thus shown to be far more important in preventing excessive temperatures than their ability to provide cutter cooling. Because of the relatively high interface friction developed under typical air drilling conditions, it is doubtful that temperatures can be kept subcritical at high rotary speeds in some formations when air is employed as the drilling fluid.
Equilibrium Calculations for Coexisting Liquid Phases
Authors: Risnes Rasmus , Dalen Vilgeir 
Published: December 2007

Abstract
Modeling of reservoir processes like gas miscible flooding may require consideration of phase equilibrium between multiple liquid phases. Under certain conditions two hydrocarbon liquid phases may form; one may also want to account for mass transfer between the hydrocarbon and the aqueous phases.
This paper describes a refined successive substitution (SS) method for calculating multiphase flash equilibrium. The phase behavior procedure proceeds in a stepwise manner, and additional phases are introduced by a special testing scheme based on phase fugacities. This is to avoid trivial solutions and to ensure continuity across phase boundaries.
The method has been tested on various three- and four-phase systems, and examples of application show that the method performs well.
A Mathematical Model of Thermal Oil Recovery in Linear Systems
Authors: Gottfried B.S. 
Published: December 2007

Gottfried, B.S., Junior Member AIME, Gulf Research and Development Co., Pittsburgh, Pa.

Introduction
Thermal oil recovery refers to a class of recovery processes where heat is supplied to a reservoir to provide the necessary expulsive energy. This thermal energy can be supplied externally as steam or hot water, or it can be generated in situ by forward or reverse combustion. In either case, however, thermal recovery processes are characterized by the simultaneous flow of two or three fluid phases in a variable-temperature field, accompanied by possible chemical reaction or phase-change effects. Although a physical understanding of the thermal recovery processes is far from complete, it is possible to construct mathematical models which describe approximately all of the principal physical and chemical phenomena. However, attempts to solve such models, even with high-speed computers, involve formidable mathematical difficulties. Consequently, theoretical solutions have been obtained only for idealized cases in which important physical phenomena are neglected. For example, consider the process of forward in situ combustion. All such theories which have been developed consider only certain aspects of the Process, such as heat transfer, heat transfer with phase change, heat transfer with chemical reaction, or the hydrodynamics of three-phase flow. A general theory including all of the above phenomena has not been developed to date. This paper presents a unified theory of thermal recovery processes in linear systems. A mathematical model is developed which explicitly includes conduction-convection heat transfer with convective external heat loss, chemical reaction between air and oil, aqueous phase change, and the hydrodynamics of three-phase flow. A system of equations is developed which can be solved numerically on a high-speed digital computer, resulting in predicted temperature, pressure, and saturation histories in space and time. The model allows a more detailed simulation of thermal recovery tube experiments than had previously been possible.

THEORETICAL DEVELOPMENT
Consider the linear flow of gas, water and oil in a homogeneous porous medium. Assume that the oil will react with gaseous oxygen, and that mass is transferred between the water and gas phase by evaporation or condensation.
SPEJ
P. 196ˆ
Foamlike Dispersions for Mobility Control in CO2 Floods
Authors: Heller John P. , Lien Cheng Li , Kuntamukkula Murty S. 
Published: December 2007

AbstractAt the reservoir temperature and pressure at which CO2 can displace a crude oil with high microscopic-displacement efficiency, its density and compressibility are close to those of the crude oil—and not greatly different from those of water itself. Because of this, the mechanical and chemical characteristics of a high-pressure, CO2-in-water "foam" cannot be assumed to be the same as those of an air/water foam at near-atmospheric pressure.This paper reports information on the mobility of foamlike dispersions in reservoir rock. The data come both from the recalculation of selected experimental work reported in the literature and from new experiments. An important criterion for these experiments is to eliminate or greatly reduce the influence of fluid compressibility, so as to approximate field conditions in CO2 floods more closely. The core flow experiments performed for this work meet this condition by use of the nonaqueous phase of either liquid CO2 at high pressure, or a light hydrocarbon to simulate dense CO2 in experiments performed at low pressure.We postulate that to be effective in retarding the growth of fingers or other instability patterns in CO2 floods while maintaining a high microscopic displacement efficiency, a foamlike dispersion of dense CO2 in surfactant/water should have the following characteristics.1. Its aqueous-phase content should be as low as possible, to minimize oil trapping and to permit maximum contact between CO2 and the crude oil.2. Its effective mobility in the reservoir rock should be adjustable, by some parameters accessible during its generation, to about that of the oil bank it is expected to form and to displace.
Experimental Study on the Effect of Axial Tension Load on the Collapse Strength of Oilwell Casing
Authors: Kyogoku T. , Tokimasa K. , Nakanishi H. , Okazawa T. 
Published: December 2007

Abstract
This paper discusses a newly developed collapse testing machine that permits investigation of practical performances of oilwell casings. Although a theoretical analysis has shown that "axial tension stress has no effect on collapse pressure in the elastic case,"1 this theory is not applied to the design of casing string because of lack of useful experimental data or authorized recommendation. To investigate the effect of axial tension load, full-size commercial casings have been tested under combined loading of axial tension load and external pressure. From the experimental results, the theory mentioned was proved in the case of so-called high-collapse casing, which has been used widely in recent years. Also shown is the applicable d/h range, which is wider than API's elastic collapse range. If the results of this experiment were applied to the design of a casing program, an economical and safe one could be obtained.
Performance of Domes Unit Carbonated Waterflood - First Stage
Authors: Scott J.O. , Forrester C.E. 
Published: December 2007

Abstract
Carbonated water has been injected as a slug, followed by non-carbonated water, in the Bartlesville sand formation of the Domes unit in northeastern Oklahoma. Initial results are shown for the first stage of the flood, consisting of nine enclosed five-spots comprising 132 acres. Production history indicates the carbon dioxide have been transferred to the residual oil and has mostly been retained in the reservoir. A large portion of the formation is apparently being bypassed due to stratification and reservoir fracturing. Results of pressure shut-in tests are shown to indicate vertical fractures being opened by injection pressures. The tests have been used to help balance the flood and increase oil recovery from poorly swept areas.
Introduction
The Domes unit is composed of 13 quarter-sections located in Sections 34 and 35 of T-27N, R-10E; and Sections 2 and 3 of T-26N, R-10E in Osage County, Okla., 15 miles west of Bartlesville (Fig. 1).The unit is jointly owned by Cities Service Oil Co. and Oil Recovery Corp. The unit was organized March 1, 1961, with Cities Service as the operator owning a 63.52 per cent working interest, and Oil Recovery Corp. owning 36.48 per cent. Initial operations of the unit have been to conduct a carbonated waterflood of the Bartlesville formation.
Primary Development and Recovery
Development of this area began in 1910 with gas production from the Mississippi Chat at a depth of 1,950 ft. In 1914, development of the Bartlesville sand began and continued through the early 1920's. About 60 wells were drilled during this period but were all plugged when waterflooding was started. Only minor drilling was done for the next 30 years until the advent of hydraulic fracturing. when extensive redrilling of the area occurred. Wells drilled during 1952 and 1953 were completed for potentials of 50 to 100 BOPD after fracturing. This redrilling resulted in an additional 30 wells. Primary oil recovery from the Bartlesville sand in the developed unit area averaged 80 bbl/acre-ft. The NE/4, Section 34 and SW/4, Section 34, due to extensive fracture treatments, have recovered 115 bbl/acre-ft. Primary oil production is estimated to have been 1,255,000 bbl from the total unit area at the start of secondary development. Reservoir properties are shown in Table 1.
Secondary Development-First Stage
Secondary development started in Section 34 in the summer of 1961. Most of the wells used had been drilled in 1952 and 1953. Thirteen producing wells were converted to injection and three additional injection wells were drilled to complete nine five-spot patterns (Fig. 1). The patterns range from 12 to 20 acres, comprising a total of 132 acres. Besides the enclosed producing wells, four outside producing wells existed at the beginning of the flood. Additional producing wells surrounding the enclosed area were added early in 1962.
JPT
Optimal Injection Policies for Enhanced Oil Recovery: Part 1— Theory and Computational Strategies
Authors: Ramirez W. Fred , Fathi Zohreh , Cagnol Jean Luc 
Published: December 2007

Abstract
The theory of optimal control of distributed-parameter systems is presented for determining the best possible injection policies for EOR processes. The optimization criterion is to maximize the amount of oil recovered at minimum injection costs. Necessary conditions for op-timality are obtained through application of the calculus of variations and Pontryagin’s weak minimum principle. A gradient method is proposed for the computation of optimal injection policies.
Linear Oil Displacement by the Emulsion Entrapment Process
Authors: Schmidt D. P. , Soo H. , Radke C. J. 
Published: December 2007

Abstract
Lack of mobility control is a major impediment to successful EOR, especially for high-viscosity oils. This paper presents experimental and theoretical results for continuous, linear, secondary oil displacement using dilute, stable suspensions of oil drops. The major hypothesis is that the oil/water (O/W) emulsion provides microscopic mobility control through entrapment or local permeability reduction not through viscosity-ratio improvement. To describe the displacement process, previous emulsion filtration theory is extended to longer cores and to two-phase flow. Agreement between theory and experiment is satisfactory for continuous secondary oil displacement with 1- to 2-μm [1- to 2-micron] diameter drops of volume concentrations up to 5 % in unconsolidated sandpacks with permeabilities ranging from 1 to 3 μm2 [1 to 3 darcies].
Dilute suspensions of stable oil drops in water also are successful in diverting flow in parallel-coreflooding to the lower-permeability core; therefore, they provide macroscopic mobility control.