bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Investigation of Foundation Design for Offshore Gravity Structures
Authors: Kraft L.M. , Murff J.D. 
Published: December 2007

Abstract
This paper lays the groundwork for establishing foundation safety criteria for offshore gravity structures. The concepts are explained in terms of first- and second-order uncertainty analyses. Various uncertainties associated with foundation analyses are identified and applications are illustrated with examples.

Introduction
Gravity structures play a prominent role today in North Sea oil development. These structures are not supported by piles, as are most ocean structures, but rather sit directly on the ocean bottom and depend on their foundation geometries and large weights m resist severe environmental loadings. A number of structural and foundation configurations have been proposed; however, attention is restricted here to a general configuration typical of the most prominent structures presently being constructed. prominent structures presently being constructed. An example of a gravity structure is illustrated in Fig. 1. The structure foundation consists of a large caisson placed directly on the unprepared sea-bed surface. The deck is supported by large columns extending from the caisson. Various combinations of steel and reinforced concrete have been proposed, but most structures are being constructed almost entirely of reinforced and prestressed concrete. prestressed concrete. One of the primary engineering concerns with these structures is foundation design. Because of the variability associated with the environmental forces, as well as the basic soil properties, this problem lends itself well to modem probabilistic problem lends itself well to modem probabilistic procedures. Such procedures provide a rational, procedures. Such procedures provide a rational, quantitative means for evaluating uncertainties affecting appropriate design, even though a degree of subjectivity will always remain in any such evaluation. The probabilistic method requires the engineer to formally and consistently recognize die variability of many of the important design parameters. The method gives management and parameters. The method gives management and others responsible for setting design criteria an opportunity to appraise cost/benefits of design levels required for given reliability levels. It also quantifies reliability to permit direct comparison with other options.
This paper presents a method for analyzing the reliability of gravity-structure foundations in terms of simple loading and resistance models. The sources of variability in estimating resistance to loads are discussed, with particular emphasis on the nature of soil-property variability and uncertainty. These concepts are illustrated through an analysis of a typical gravity-structure foundation.
SPEJ
P. 97
Generalization of the Maxwell Equation for Formation Resistivity Factors(includes associated papers 6556 and 6557 )
Authors: Perez-Rosales C. 
Published: December 2007

A formula relating porosity and formation resistivity factor is presented.This equation is applicable not only to consolidated and unconsolidatedmaterials, but also to dispersive systems. A comparison of calculatedvalues with experimental data shows the equation yields satisfactory results.

Introduction
The formation resistivity factor of a porous sample hasbeen defined as the ratio of the resistivity of the samplewhen completely saturated with an electrolyte to theresistivity of the saturating electrolyte. One of thetheoretical expressions relating the formation resistivityfactor, F R, to porosity, phi, is known as the Maxwellequation. Its form is
3 −F = ---------- ...........................(1)R 2
This equation can be applied to dispersive systems ofspheres, where electrical interference among theelements is negligible.
In practice, little attention has been paid to Eq. 1, mainly because its application is limited to idealizedsystems. However, contrary to other empiricalexpressions currently used, it has the virtue of having arigorous theoretical deduction.
In view of the potential importance of Eq. 1, andbecause the idealizations made in its derivation are notwell known, a theoretical development is presented inthe Appendix, according to the ideas suggested byMaxwell.

Theory
Outstanding among the attempts to generalize theMaxwell equation is the work of Fricke, whotheoretically demonstrated that for dispersive systems of oblate and prolate spheroids
(x + 1) −F = -------------,.........................(2)R x
where x is a geometric parameter that is a function ofthe axial ratio of the spheroids, and whose value is lessthan 2. When x = 2, Eq. 2 reduces to Eq. 1.
Fricke confirmed Eq. 2 by using experimental dataon the conductivity of blood. For this purpose, hetreated the red corpuscles as oblate spheroids. Furthermore, he made use of the fact that the redcorpuscles behave as perfect insulators for director low-frequency current; this behavior results frompolarization effects.
It is interesting to note that Maxwell's formula forspheres and Fricke's equation for spheroids areequilateral hyperbolas that can be written as
P(1−) F = 1 + -----------,.......................(3)R
where P takes on the values of 1.5 and (1 + x)/x, respectively. Furthermore, P is a geometric parameterwhose value becomes larger as the sphericity becomessmaller. Similarly, it has been found that, in the caseof two-dimensional dispersive systems, a relationship ofthe form of Eq. 3 is also satisfied. However, it shouldbe noted that idealizations have been made in itsderivation that, in principle, do not allow its applicationto those cases where the elements are in contact or neareach other, or when they have irregular shapes. Therefore, Eq. 3 should be modified if it is to be applied to real cases.
For this purpose, consider a system of spheres, whether disperse or in contact. Fig. 1 shows some ofthe flowlines in the neighborhood of two spheres incontact.
JPT
P. 819^
Sand Jet Perforating Revisited
Authors: Cobbett J. S. 
Published: December 2007

Summary
Though sand jet perforating is not a new technique, it is one that has been almost forgotten, the last SPE paper on the subject being published in 1972. Unlike explosive perforating, which is literally a "one shot" process, sand jet perforating uses a high velocity jet of abrasive fluid to cut through the casing, cement and deep into the formation, enabling pressure, pumping time and other parameters to be varied to maximize penetration. Sand jets can penetrate much deeper than explosives, and offer a cost-efficient, safer and better-targeted alternative to hydraulic fracturing to bypassing deep near-wellbore damage.
This paper is based mainly on experience in Lithuania, where, in 1995, joint venture oil companies first started field operations to complete development of small oil fields found in the west of the country (see Fig. 1) during the Soviet era, but which had been considered as too small to develop for the Soviet Union, with giant oil fields to the east. Wells, some of which had produced on test at over one thousand barrels per day, had been left with heavy mud across open perforations, often for more than a decade. When it proved impossible to get these wells to flow again using (western) tubing conveyed explosive perforators (TCPs), sand jetting was used, as has been the almost universal practice in Lithuania. The first well sand jet perforated by a joint venture company, which had yielded less than one barrel per day with (western) TCPs, gave over 900 barrels per day when perforated with sand jets.
Subsequently, one of the best producers in Lithuania, which had already been sand jetted once, was reperforated using more advanced techniques. Coiled tubing was run through the xmas tree and completion to enable the well to be sand jet perforated, with oil as the carrier fluid, underbalanced, with the well flowing throughout, resulting in a doubling of production to 800 BOPD.
Though sand jet perforating is, at least theoretically, available from the main pumping contractors, it is almost unknown outside North America and the former Soviet Union, the main technical references (Refs. 1–5) being over 30 yr old. Sand jet perforating does, however, provide a cost-effective means of passing deep formation damage and should form part of the armory of any practicing petroleum engineer. This paper aims to remind engineers of this, review the technology and suggest appropriate applications.
Use of Analytical Solutions To Improve Simulator Accuracy
Authors: Jasti J. K. , Penmatcha V. R. , Babu D. K. 
Published: December 2007

Summary
Analytical solutions previously developed for wellbore design and scoping analysis were utilized in this study to benchmark and modify the existing wellbore models in the reservoir simulator. The analytical solutions were developed for single phase oil or gas flow problems, and they are currently being used for well performance studies covering a wide range of well configurations: vertical, horizontal, deviated, and arbitrary well geometry, and fractured completions in single or multilayered reservoirs. In this paper, some of the analytical solutions are utilized for benchmarking the existing well models in the reservoir simulator. Alternative well models are proposed for improving the accuracy of simulator predictions. Two methods of calculating gridblock-wellbore-connection factors are described. Results show that the new methods impact the simulator accuracy significantly for three-dimensional flow cases and for highly deviated wells.
Surfactant Aging: A Possible Detriment to Tertiary Oil Recovery
Authors: Cash R.L. , Cayias J.L. , Hayes M. , McAllister D.J. , Schares T. , Schechter R.S. , Wade W.H. 
Published: December 2007

Introduction
New processes for achieving improved oil recovery have been under development in the petroleum industry for many years. One such process, termed surfactant flooding uses surfactants to minimize oil/water capillary forces. The petroleum sulfonates are of interest as surfactants by virtue of their low cost. However, there are problems. Foster has shown that the low interfacial tensions required for efficient displacement are sensitive functions of surfactant concentration and salinity.
Aqueous solutions of petroleum sulfonates appear to change with time. This tension aging has been found to occur in both the presence and absence of certain cosurfactants. Also visually striking are the metamorphic changes that slowly occur when the surfactant is carefully contacted with an aromatic hydrocarbon without mixing the two phases. The aging processes described here evolve through nonequilibrium states, some of which may be detrimental to oil-recovery processes. These nonequilibrium aging states develop slowly (over a period of months, perhaps even years) and would not influence model displacements lasting only a few days or weeks; but they would be significant in the time frame over which a tertiary oil-recovery program is conducted.

Experimental Procedure
All the pure hydrocarbon oils studied were spectroscopic grade. Further purification had no effect on their interfacial tensions and, therefore, they were used as received from the manufacturer, Chem Samples. The hydrocarbon mixture designated as pseudocrude is described elsewhere. Witco Chemical Co. supplied the petroleum sulfonate designated as TRS 10-80, and Shell Development Co. provided the Martinez 380 and Martinez 470.
The aqueous surfactant/salt solutions were prepared using the surfactant as received, always adding the sodium chloride last.
All the interfacial tension measurements were made without pre-equilibrating the two phases. The values of the tensions for these systems were obtained at 25 deg. C using a spinning-drop interfacial tensiometer.

Results and Discussions

Low Tensions and Surfactant Aging
A substantial difference in some interfacial tensions was discovered when two surfactant solutions of differing ages were used to measure the interfacial tensions of three homologous hydrocarbon series. These three hydrocarbon series were (1) n-alkanes from pentane to heptadecane, (2) n-alkylbenzenes or 1-phenylalkanes from benzene to heptadecylbenzene, and (3) n-alkylcyclohexanes or 1-cyclohexylalkanes from cyclohexane to n-tridecylcyclohexane. Both aqueous phases conMined 0.2-percent surfactant/1.0-percent salt and were prepared using the same technique. prepared using the same technique. JPT
P. 985
Effect of Coiled-Tubing Initial Configuration on Buckling Behavior in a Constant-Curvature Hole
Authors: Qiu Weiyong , Miska S. Z. , Volk L. J. 
Published: December 2007

Summary
In practical coiled tubing drilling and completion operations, minor curvature always exists in coiled tubing (CT). The authors ("Effect of Coiled Tubing Initial Configuration on Buckling/ Bending Behavior in Straight Deviated Wells," paper SPE 39003 Presented at the 1997 Fifth Latin American and Caribbean Petroleum Engineering Conference and Exhibition held in Rio de Janeiro, Brazil, 30 August-3 September) previously published that the initial CT configuration results in the reduction of the axial compression force required to produce helical configuration in a deviated well. In this paper, the authors emphasize the effect of initial CT configuration, or residual bending, on buckling behavior in a hole of constant curvature. By utilizing the conservation of energy and the principle of virtual work, new equations are derived to predict the axial compression force for a stable sinusoidal configuration and the axial compression force required to produce a helical configuration. These new equations reduce to those previously published when CT has not been initially bent. Practical examples are presented to demonstrate the effect of the initial amplitude on both sinusoidal and helical buckling behavior of CT in curved wells. The results indicate that the radius of curvature of a borehole is a governing parameter that influences CT buckling behavior. The effect of the initial CT configuration on sinusoidal configuration can be neglected, whereas the effect of the initial CT configuration on helical configuration is substantial. The results will help field engineer to understand CT buckling behavior, and consequently, to select the proper CT to avoid lockup and to improve the prediction of the axial force transmission in horizontal and extended reach drilling.
The Material Balance as an Equation of a Straight Line
Authors: Havlena D. , Odeh A.S. 
Published: December 2007

Abstract
The material balance equation used by reservoir engineers is arranged algebraically, resulting in an equation of a straight line. The straight line method of analysis imposes an additional necessary condition that a successful solution of the material balance equation should meet. In addition, this algebraic arrangement attaches a dynamic meaning to the otherwise static material balance equation.
The straight line method requires the plotting of one variable group vs another variable group. The sequence of the plotted points as well as the general shape of the resulting plot is of utmost importance. Therefore, one cannot program the method entirely on a digital computer as is usually done in the routine solution of the material balance equation. If this method is applied, then plotting and analysis are essential.
Only the appropriate equations and the method of analysis and interpretation with comments and discussion are presented in this paper. Illustrative field examples for the various cases treated are deferred to a subsequent writing.

Introduction
One of the fundamental principles utilized in engineering work is the law of conservation of matter. The application of this principle to hydrocarbon reservoirs for the purpose of quantitative deductions and prediction is termed "the material balance method of reservoir analysis". While the construction of the material balance equation (MBE) and the computations that go with its application are not difficult tasks, the criteria that a successful solution of the MBE should fulfill have always been a problem facing the reservoir engineer.
True and complete criteria should embody necessary and sufficient conditions. The criteria which the reservoir engineer uses possess a few necessary but no sufficient conditions. Because of this, the answers obtained from the MBE are always open to question. However, the degree of their acceptability should increase with the increase in the number of the necessary conditions that they should satisfy.
Nonisothermal Gravitational Equilibrium Model
Authors: Pádua K. G. O. 
Published: December 2007

SummaryThis work presents a new computational model for the nonisothermal gravitational compositional equilibrium. The works of Bedrikovetsky [Mathemathical Theory of Oil and Gas Recovery, Kluwer Academic Publishers, London, (1993)] (gravity and temperature) and of Whitson and Belery ("Compositional Gradients in Petroleum Reservoirs," paper SPE 28000, presented at the 1994 University of Tulsa Centennal Petroleum Engineering Symposium, Tulsa, 29–31 August) (algorithm) are the basis of the mathematical formulation. Published data and previous simplified models validate the computational procedure. A large deep-water field in Campos Basin, Brazil, exemplifies the practical application of the model. The field has an unusual temperature gradient opposite to the Earth's thermal gradient. The results indicate the increase of oil segregation with temperature decrease. The application to field data suggests the reservoir could be partially connected. Fluid composition and property variation are extrapolated to different depths with its respective temperatures. The work is an example of the application of thermodynamic data to the evaluation of reservoir connectivity and fluid properties distribution.
Capillary-Pressure Curves for Low-Permeability Chalk Obtained by Nuclear Magnetic Resonance Imaging of Core-Saturation Profiles
Authors: Norgaard J. V. , Olsen Dan , Reffstrup Jan , Springer Niels 
Published: December 2007

SummaryA new technique for obtaining water-oil capillary pressure curves, based on nuclear magnetic resonance (NMR) imaging of the saturation distribution in flooded cores is presented.In this technique, a steady-state fluid saturation profile is developed by flooding the core at a constant flow rate. At the steady-state situation where the saturation distribution no longer changes, the local pressure difference between the wetting and nonwetting phases represents the capillary pressure.The saturation profile is measured using an NMR technique and for a drainage case, the pressure in the nonwetting phase is calculated numerically. This paper presents the NMR technique and the procedure for calculating the pressure distribution in the sample.Inhomogeneous samples produce irregular saturation profiles, which may be interpreted in terms of variation in permeability, porosity, and capillary pressure.Capillary pressure curves for North Sea chalk obtained by the new technique show good agreement with capillary pressure curves obtained by traditional techniques.
Reservoir Polymer Gel Treatments To Improve Miscible CO2 Flood
Authors: Hild G. P. , Wackowski R. K. 
Published: December 2007

Summary
This paper describes the application of large volume (10,000 bbl) chromic-acetate acrylamide polymer gel treatments to improve sweep in the miscible CO2 flood at Rangely Weber Sand Unit located in northwestern Colorado. Conformance improvement has become the key operating strategy due to the maturing flood's associated natural increase in operating expense and declining oil production. Recent efforts using large volume polymer gel treatments on injection wells have been successful. The key to success has been the pairing of accurate problem characterization with a technology that can effectively impact the deep reservoir problem. The gel system has been effective because it has proven to be resistant to the low pH environment associated with CO2 flooding and has been pumped in significant quantities to improve sweep. Previous application of relatively small volume, near-wellbore treatments were not effective at preventing flow in the high permeability matrix and fracture pathways believed to be responsible for poor sweep. Results from 44 injection well treatments performed through mid-1997 are discussed. Candidate selection, treatment logistics, individual treatment examples, and full project economics are provided. Field modeling and forecasting is discussed to show the significant impact of continued treatments on field performance.
Producing Mississippi's Deep, High-Pressure Sour Gas
Authors: Hamby T.W. , Broussard L.P. 
Published: December 2007

Introduction
Shell Oil Co. has three deep, sour gas fields located about 20 miles southeast of Jackson, Miss. The wells in these fields are completed in the Smackover formation of (Jurassic age) between 19,700 and 22,250 ft; bottom-hole pressures range from 17,500 psi at the Southwest Piney Woods field. Bottom-hole temperatures range from 365 to 385F. The well fluids consists of 27 - to 16 percent H2S, 3-to 9-percent CO2, 45- to 65-percent methane, and no condensate. This gas is saturated with water at bottom-hole conditions, and each well appears to produce small amounts of salt based on the chloride content of the produced water. Water production is about 8 to 10 bbl per million cubic feet of gas. Sour gas (hydrogen sulfide) in very low aqueous concentrations can cause failure of some metals, but it can be safely contained with conventional oilfield tubulars such as C-75 and J-55 grades at moderate pressures. Likewise, high pressure (greater than pressures. Likewise, high pressure (greater than 10,000 psi) sweet gas has been safely handled with conventional P-grade tubulars. But combination of sour gas at very high pressures and temperatures cannot be safely contained with conventional tubulars; if CO2 and salt water are present the problem becomes acute. At the time of discovery of Thomasville field in 1969, sustained production of high-content H2S sour gas under conditions of very high pressure and temperature had not been proven or attempted beyond a short field test by Phillips Petroleum Co. in their Josephine "A" well in 1965. The 13,830-psi bottom-hole pressure encountered in this well was considerably below the 17,300 psi found at Thomasville. Testing of the Thomasville well revealed many technical problems that confirmed the need for high-strength tubulars resistant to stress corrosion cracking, high-pressure wellheads, environment-resistant seals, corrosion protection, and the prevention of sulfur plugging. plugging. Because of the toxicity of the produced gas, and the possibility of failure caused by stress corrosion cracking possibility of failure caused by stress corrosion cracking and weight-loss corrosion of metals, safety is the primary concern in the development of these deep, sour gas reserves. Detailed contingency plans are prepared for the entire complex and great care is taken the design, materials selection, and quality-control procedures. In preparing or executing a work plan, careful attention is preparing or executing a work plan, careful attention is given to all aspects of the operation and possible consequences are discussed in detail with all concerned, including service companies.

Well Completion Practices

20,000-psi Systems
A temporary completion was made in the Thomasville discovery well during March 1969 to permit production testing. The well tested at rates up to 10 MMcf/D of sour gas before completion-equipment failures resulted in temporary abandonment of the well.
JPT
p. 629