bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rock Rupture as Affected by Fluid Properties
Authors: Scott P.P. , Bearden William G. , Howard G.C. 
Published: April 2012

Abstract
This paper concerns the rupture or breakdown of rock formations as related to drilling, completing, and stimulating production of wells, and comprises data compiled from a study of literature and records of treatment of oil and gas wells, and from tests conducted in bores drilled into rock cores and outcrops of rock. Results of the investigation indicate that the internal pressure to rupture cylinders of rock and to break-down rock formations surrounding a bore in the earth is dependent upon the extent of intrusion of fluids, the position of bedding planes, the ratio of internal to external diameter, the tensile strength of rock, and magnitude of confining pressure, and is independent of the size of bore, degree of fluid saturation, and temperature of rock within practical limits.
It is concluded that the mathematical relationship of pressure in bores and stresses in the surrounding rock must not be limited by the simplifying assumptions of homogeneity, isotropy, and impermeability; that the incidence of lost circulation of drilling fluids to induced fractures may be reduced by preventing intrusion of fluids into the small intrinsic fractures along weak bedding planes; and that the magnitude of the breakdown pressure of wells to be treated may be lowered by removal of mud cake.

Introduction
The purpose of this paper is to present and discuss the results of tests which may serve to broaden the understanding of the phenomena of rupture or breakdown of rock and thus contribute to the improvement of the techniques for drilling and completing wells, including such operations as preventing lost circulation, stimulating production, and placing cement.
Since the early recognition of the possibility of rupturing rock adjacent to a well by fluid pressure, the distribution and magnitude of stresses around a well and the internal pressure to cause failure have been expressed mathematically by application of the principles defining the elastic and inelastic behavior of thick-walled cylinders of a homogeneous, isotropic, impermeable material. In either the elastic or plastic state, if the conditions of homogeneity, isotropy, and impermeability were the normal characteristics of rock, there would be no reason to question the validity of the above principles when applied to rock.
Properties of Linear Waterfloods
Authors: Rapoport L.A. , Leas W.J. 
Published: April 2012

Abstract
The original Buckley-Leverett theory has been extended and a more detailed formulation of the waterflood behavior in linear horizontal systems is presented. Particular consideration has been given to the evaluation of capillary pressure effects and differential equations permitting an explicit evaluation of these effects have been derived. On the basis of the developed theory it is recognized that the flooding behavior is dependent upon the length of the system and the rate of injection. At the same time it has been determined that systems of different lengths yield the same flooding behavior if the injection rates and/or the fluid viscosities are properly adjusted or "scaled." It has also been found that the sensitivity of the flooding behavior with respect to rate and length decreases as any one of these factors increases in value and that for sufficiently long systems and high rates of water injection the flooding behavior becomes independent of rate and length, or "stabilized." To such stabilized conditions the theory formulated by Buckley and Leverett is applicable. A number of laboratory flooding tests have been made and good agreement has been found between theory and experimental observations. The experimental results are discussed and it is shown that under field conditions the flooding behavior is usually stabilized. As a result of these findings a procedure is indicated for evaluating field performances either on the basis of tests performed with commonly available core samples or by means of calculations using relative permeability data.
Origin of the Electric Potential Observed in Wells
Authors: McCardell W.M. , Winsauer W.O. , Williams M. 
Published: April 2012

Abstract
The mechanism by which an electrical potential difference is developed between two salt solutions separated by shale is shown to be a consequence of the electrical double layer of the shale surfaces. A mathematical derivation is presented to show the dependence of the potential on the shale characteristics and on the concentration of the salt solutions. The equations developed describe adequately the potential-concentration behavior of a long shale core. The equations also describe the variation of potential of sand-shale mixtures with variation of clay content. Ion adsorption is an important factor in the development of the surface charge on the shale, and electrical resistivity and ion transference number data are employed to estimate the increase of surface charge with concentration. Since the potential is shown to be dependent on the characteristics of the particular system, water salinities estimated from the potential log by previously proposed methods may be low in some cases.

Introduction
That the electric well log exists today may be attributed to the ingenuity of the Schlumberger brothers, who adapted to the logging of wells techniques which were originally developed as surface prospecting methods for the location of ore bodies. Empirically, it was found that the potential curve of the electric log usually gave values for clean sands which were negative with respect to the values for shales. It was suggested that the potential was responsive to porosity. It was postulated, in explanation, that the potential was the sum of a streaming potential, which differed for sands and shales, and of an "electro-chemical" potential of undetermined origin.
Mounce and Rust in 1943 showed that the streaming potential is small in most cases and that the potential is generated by a process in which shale and a salinity difference play essential parts. Dickey, in the same year, concluded that the potential is dependent upon adsorptive properties of reservoir rock.
Calculations of Unsteady-State Gas Flow Through Porous Media
Authors: Bruce G.H. , Peaceman D.W. , Rachford H.H. , Rice J.D. 
Published: April 2012

Abstract
The problem of unsteady-state gas flow through porous media leads to a second-order non-linear partial differential equation for which no analytical solution has been found. In this paper a stable numerical procedure is developed for solving the equation for production of gas at constant rate from linear and radial systems. An electronic digital computer is used to perform the numerical integration using an implicit form of an approximating difference equation. Solutions are presented in graphical form for various values of dimensionless parameters. The solutions are compared with the laboratory study of gas depletion in a linear system.

Introduction
Production of fluids from porous rock reservoirs is essentially a transient process. Transient gradients develop as soon as production begins, and further withdrawals continue to cause disturbances which propagate throughout the reservoir, each adding in some way to the prior ones.
A correct mathematical analysis of this behavior is complicated by the fact that the transient or unsteady-state flow of compressible fluids must be described by difficult second-order partial differential equations. As a practical matter, three distinctly different cases arise:Flow of single-phase liquidFlow of gasesMultiphase flow
The first of these has been found to give a linear second-order equation similar to the well-known heat flow equation.
Solutions of Equation (1) for both linear and radial flow are available in several forms.
Although a number of approximate solutions have, been proposed, each is limited in value by the associated simplifying assumptions.
Inasmuch as the analysis of transient flow is limited to liquid systems, a solution of the second case is necessary if further progress is to be made in studying underground fluid movement. For this reason a solution of Equation (2) was undertaken by means of numerical integration of approximating difference equations.
Application of the Material Balance Equation to a Partial Water-Drive Reservoir
Authors: Van Everdingen A.F. , Timmerman E.H. , McMahon J.J. 
Published: April 2012

Abstract
The present paper contains a method which combines the material balance equation with the water influx equation to obtain reliable values for the active oil originally in place and a quantitative evaluation of the cumulative water influx. The method is illustrated by an application to a reservoir without original gas cap. In the absence of an original gas cap, results may be obtained using only field production and pressure data, PVT analyses, and a minimum of subsurface information.

Characteristics of Reservoir and Reservoir Fluids
Production in the field under review is obtained from the top of the Wilcox formation of Eocene age, at a depth of approximately 8,100'Ft subsea. The structural map, Fig. 1, shows that the accumulation, half elliptical in shape with the long axis in east-west direction, is trapped to the north and on the upthrown side of a normal fault. A number of east-west faults with additional minor faulting in random directions are found in the general area, and seismic information and production performance indicate in this particular case the existence of a second fault a short distance downdip, with a strike more or less parallel to the fault controlling the accumulation. It is estimated that 1,830 acres were originally underlain by oil and that the maximum thickness of the original oil column, about 37 ft, was only slightly greater than the maximum thickness of the oil-bearing sand. Maximum net sand thickness was estimated at approximately 26 ft. From logging and subsurface information the gross sand volume has been placed at 37,400 acre-ft, which reduces to about 27,500 acre-ft after probable non-productive intervals have been deducted. The following table presents laboratory analyses data for the Wilcox sand cores.
Permanent-Type Well Completion
Authors: Huber T.A. , Tausch G.H. 
Published: April 2012

Abstract
Very encouraging progress has been made in the development of the permanent-type well completion which decreases considerably the cost of completions and workovers and aids in the acquisition of reliable reservoir information at low cost. Completion and remedial operations are performed with tools which pass through the well tubing. Perforating and plug-back operations can be done with the tubing in place and do not require pipe-handling equipment.
Because of the many advantages afforded by this method, development work is going forward in anticipation of ultimately being able to use it to perform all usual well completion and work over operations. Effort is also being directed to the development of a more permanent type of lift equipment suitable for use with the permanent-type well completion.

Introduction
The permanent-type well completion is one in which the tubing and well-head are set in place only once in the life of the well and the completion or remedial work is performed through the tubing with a tubing-type perforator, a retrievable tubing extension, and other wire-line tools. This new type completion has made possible the saving of one to two days' rig time in the completion of each of several hundred wells during the past two years, and use of equipment developed for this type of completion has resulted in a 75 per cent reduction in costs of certain types of workovers. In addition, the more reliable indication of the commercial value of a reservoir and the more accurate general reservoir information made possible promise to be of even greater value in oil recovery than the reduction of costs for completions and workovers.
Recently, several wells were worked over by using the retrievable tubing extension suspended on a swab line to plug back with cement and then perforating a higher producing interval with the tubing-type perforator, thus opening the way for complete through-the-tubing workovers which may be performed without pipe-handling equipment or mud. Those items attendant to the use of pipe-handling equipment and mud, such as board matting, rig substructure, and pits, were also eliminated.
There are indications that the elimination of drilling mud during completion and workover operations will frequently give increased well productivity, as plugging of the perforations will not occur.
Bubble Formation in Supersaturated Hydrocarbon Mixtures
Authors: Kennedy Harvey T. , Olson Charles R. 
Published: April 2012

Abstract
In many investigations of the performance of petroleum reservoirs the assumption is made that the liquid, if below its bubble-point pressure, is at all times in equilibrium with gas. On the other hand, observations by numerous investigators have indicated that gas-liquid systems including hydrocarbon systems, may exhibit supersaturation to the extent of many hundred psi in the laboratory. Up to the present, there has been no reliable data on which to judge the actual extent of supersaturation under conditions approaching those existing in petroleum reservoirs.
The work reported here deals with observations and measurements on mixtures of methane and kerosene in the presence of silica and calcite crystals. Bubbles were observed to form on crystal-hydrocarbon surfaces in preference to the glass-hydrocarbon interface or to the body of the liquid. Statistically, it was found that the number of bubbles formed per second per square centimeter of crystal surface was a function of the supersaturation only, and the function was evaluated graphically.
Supersaturations were observed up to 770 psi, under which condition bubbles formed quickly and with considerable violence. With decreasing degrees of supersaturation, the frequency of bubble formation became less, until at 30 psi supersaturation and lower, no bubbles were observed to form, even though the observation at 30 psi was continued for 138 hours. It was found that silica and calcite crystals had identical effects, within experimental error, in accelerating the formation of bubbles, and that small amounts of water and crude oil had no effect on the results.
It is shown that the maximum supersaturation that can exist in a reservoir may be calculated from the data presented and from the area of the rock surface. It is also shown that the number of bubbles formed in the reservoir, in order of magnitude, may be calculated for any rate of pressure decline imposed on the reservoir by production. The bearing of the number and distribution of bubbles on reservoir performance is discussed.
Pressure Gradients in Natural Gas Reservoirs
Authors: Cornell David , Katz Donald L. 
Published: April 2012

Abstract
Procedures for computing turbulent flow of gas in steady state near the well bore and a graphical method for predicting unsteady state laminar flow at distances from the well have been combined to compute pressure gradients in gas reservoirs.
Methods are discussed for predicting single and multiple transients at constant flow rate in an infinite reservoir, predicting constant flow rates in a finite reservoir, reproducing and interpreting back pressure test data, and prediction of the behavior of a closed-in gas well. An example of the graphical method is given for a single transient and the results are compared to a published analytical solution. A typical calculation of the pressure gradient in a reservoir and the production of gas is made starting with data from a back pressure test.

Introduction
The calculation of pressure gradients throughout a gas reservoir at any point in its production history is a complex problem involving turbulent flow near the well bore and unsteady state flow of the gas from the reservoir. The problem is complicated further by the variety of boundary conditions that may be imposed upon the flow. Such boundary conditions include finite or infinite reservoirs, constant or variable rates of production, constant or varying bottom hole pressures, complex initial pressure distributions throughout the reservoir, and pressure maintenance through cycling.
In addition to these problems there are the practical difficulties associated with natural gas reservoir analysis. These might include:variations in the permeability and porosity throughout the formation,variations in the thickness of the formation,communication of the producing formation with other producing zones,radial variations in permeability due to influx of drilling fluid, acidizing, or the buildup of liquid in the formation around the well,partial penetration of the producing zone,water flood, and many others.
These problems will be considered eventually. In the meantime, it is necessary to present methods of handling the case of radial flow through a homogeneous, regular, producing stratum to a single well uncomplicated by other factors.
A Quantitative Analysis of the Electrochemical Component of the S.P. Curve
Authors: Wyllie M.R.J. 
Published: April 2012

Abstract
The relationship between the electromotive force (E.M.F.) across a shalebarrier and the concentrations of sodium chloride solutions on either side hasbeen investigated.
It is shown that the action of a shale barrier is analogous to a glass membraneseparating two acid solutions of different hydrogen ion concentrations. Theshale behaves as a sodium electrode and is responsive to the activities of thesodium ions in the two solutions in such a way that the potential can becalculated by means of the Nernst equation. This conclusion is confirmed bylaboratory experiments.
In a borehole the total E.M.F. of a shale cell is the algebraic sum of thepotential across the shale and a boundary potential. The relationship betweentotal E.M.F. and the resistivity ratio of two sodium chloride solutions isindicated for a number of formation temperatures. The E.M.F. thus predicted isthen compared with the self potential read from an electric log and goodagreement is demonstrated.
Based on both the self potential and resistivity curves of the electrical log.a method is given for calculating connate water content in a bed havingintergranular porosity and containing both connate water and hydrocarbons.

Introduction
The first paper on electrical well logging by C. and M. Schlumberger and E.G.Leonardon in 1934 attributed the self potential curve principally to streamingpotentials, i.e. to electrokinetic effects. Almost immediately greatdifficulties were encountered in reconciling many of the curves they obtainedwith this interpretation, and a second paper by the same authors soon appeared.In this second paper self potentials were attributed to the combined effects ofstreaming potentials and electrochemical potentials, the electrochemicalpotential being considered the result mainly of the interaction of fluids ofdiffering salt concentrations, i.e. a boundary potential, and partly ofpotentials set up at the faces of impermeable materials. Some experimentsinvolving a gray clay for the impermeable material were quated.
T.P. 2511
Gulf of Mexico Floating Drilling Tender
Authors: Besse C.P. , Osborne G.W. 
Published: April 2012

Drilling operations on the Gulf of Mexico continental shelf are followingtwo general plans. The first plan placed all buildings, equipment, andmaterials on a large platform while the second copies Lake Maracaibo drillingmethods by placing a minimum of equipment on the platform and using a floatingdrilling tender or drill barge anchored adjacent to the platform in an attemptto take maximum advantage of flotation in an effort to reduce costs.
A complete power rig, mud pits, pipe racks, and small auxiliaries have beenplaced on the platform as shown in Figure 1, to assure proper handling ofdrilling operations under the most adverse weather. This has the economicadvantages of eliminating the fabrication of a large structure, a materialreduction of rigging up time on each structure, and elimination of delay timeon equipment while quarters and equipment placed on the tender are being riggedup. These factors have certainly proved their economic value in drill bargeoperations in the Louisiana and Texas coastal area.
Naturally the heart of such an operation is the anchorage. This anchorage, topermit taking advantage of maximum economies, must hold the ship in arelatively fixed position under the following weather conditions:Winter northwestersSoutheasterly galesSevere rain squalls
In hurricane weather all operations must be suspended regardless of methodof operation and the floating tender will, if possible, be moved to a protectedlocation. However, in case of an emergency the floating tender should beprepared to swing with the wind and seas on a single anchor as there is considerable doubt that either ship oranchorage could withstand the severe strains imposed by fixed anchorage inhurricane weather.
Northwesters are reported to have developed wind gust velocities as high assixty miles per hour and steady winds of approximately forty-five miles perhour. Fortunately these winds do not travel a great distance over water beforearriving at our location, and, while they can possibly develop seasapproximately eight feet high, the waves are short and if taken on the bow orstern of a ship 250'Feet or more in length they should not present a difficultproblem.
T.P. 2590
Relation Between Pressure and Recovery in Long Core Water Floods
Authors: Breston Joseph N. , Hughes Richard V. 
Published: April 2012

Abstract
Conclusions drawn by previous research workers with respect to the relationbetween pressure gradients and/or velocity and oil recovery obtained bylaboratory water flood tests have been in disagreement probably due to variableprocedures and unnatural conditions and materials. The Bradford Laboratory ofthe Pennsylvania Grade Crude Oil Association as part of its secondary recoveryresearch program has conducted nineteen water floods on two long cores ofwidely differing characteristics in an attempt to clarify this relationship andmake it an aid in predicting flooding pressures in the field. Unlike previousresearch procedures the present experiments were conducted with the aim ofduplicating field conditions as closely as possible by using long unextractedconsolidated cores, a live crude, and natural brines for both flooding andconnate water content. Also, the pressure gradients and flooding velocitieswere representative of field conditions where similar sands were being flooded.Eleven floods on one core and eight floods on the other core showed increasedrecoveries and lower residual oil saturation with increased flood pressuregradients and flood velocities. A marked decrease in recovery was obtained fromboth cores at very low flood velocities. This pressure versus recoveryrelationship is shown to hold up to the point of water breakthrough and also upto the 100 and 1 produced water to oil ratio point.

Introduction
The possibility of water flooding oil sands was suggested by Carll of thePennsylvania Geological Survey in 1880. It is not known when the practice wastried intentionally for the first time, but its beneficial effects were notedin the annual production rate of the Bradford field as early as 1907. Thepractice was illegal in Pennsylvania until 1921. Early water floods in theBradford field usually consisted of shooting or splitting the casing secretlyto permit subsurface waters to enter the producing sands under hydrostatichead. As it was noted that the benefits of water flooding seemed to beproportional to the quantity of water dumped into the well many also began toutilize surface sources after the practice became legal. It was probably duringthe middle 20's before many producers realized that the pressurehead of thewater upon the producing sand determined the rate and quantity of water thatwould enter the sand. Hence, rate and quantity of production appeared to be adirect function of input pressures.
T.P. 2591