bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solving Engineering Problems With PC-Based Relational Databases
Authors: Bastian P. A. , Pietsch C. L. , Voneiff G. W. 
Published: December 2007

Summary
Information management and instant access to information is increasingly important in the day-to-day operation of oil and gas fields, and the data are only as valuable as our ability to use them to solve problems. This paper presents an example of a project-driven approach to engineering information management of large engineering projects, such as integrated reservoir studies. By project-driven, we mean that the design and content of the database are project-specific and custom-built to fit the needs of the project. This approach has the advantage of addressing the specific requirements of a particular project and providing the end users of that database with a customized interface to access the data. We used a PC-based relational database management system (RDBMS) to custom build a database from existing engineering data as part of a larger integrated study. The data were originally in a variety of formats. The RDBMS allowed us to construct rapidly a database specific to the needs of the project. The database includes forms and reports for data entry and review and graphics for displaying data. In addition, the database is very flexible, allowing changes to be made quickly and easily as the project progresses or if the objectives of the project change along the way. Finally, the database can import a wide variety of raw-data formats and export data to other engineering analysis applications.
Development of a Modified Pressure Interference Equation
Authors: Prasad Raj K. 
Published: December 2007

The equations presented in previous literature on well interference are adequate when there has been no pressure interference at the observation well prior to pressure interference at the observation well prior to shut-in. However, tests made during the later stages of the development of a reservoir frequently reveal that this interference has occurred. A modified equation is developed here to account for it. Pressure at a closed-in observation well, due to continued oil production at off set wells, is given by:
.........(1)
where
aj = distance from jth well to the observationwell ftPws = pressure at the observation well at t hoursof shut-in, psiapi = initial pressure of the reservoir, psiaq = production rate at the observation well priorto shut-in, RB/Dqj = production rate at the jth interfering well, RB/Dtj = total production time elapsed at jth wellprior to shut-in of the observation well, hourstj = producing time of the jth well at the time ofpressure observation after shut-in of theobservation well, hoursNw = total number of interfering wells. CC = ----------0.00105k162.6qm = -----------kh
When t is very small compared with tj,
,........(2)
or when tj + tj is very small,
,.....(3)
Eq. 1 can be written as
...........(4)
A plot of pws vs on semilogarythmic paper for small t should yield a straight line of slope m =
162.6 and an intercept defined by
...........(5)
Substituting the value of pi from Eq. 5 into Eq. 1 yields.
P. 149
The Use of Source and Green's Functions in Solving Unsteady-Flow Problems in Reservoirs
Authors: Gringarten Alain C. , Ramey Henry J. 
Published: December 2007

Abstract
Although it is an old method, the use of Green's functions to solve unsteady flow problems in reservoir engineering is not widely practiced. The reason is that it is difficult to find the appropriate Green's junction. In this study, tables of instantaneous Green's and source functions were prepared that can be used with the Newman's prepared that can be used with the Newman's product method to generate solutions for a wide product method to generate solutions for a wide variety of reservoir flow problems. New solutions for infinite conductivity sources were also prepared.

Introduction
The transient flow of a slightly compressible fluid in a homogeneous and anisotropic porous medium D, bounded by a surface Se (Fig. 1), is described by the diffusivity equational derived from the continuity equation and Darcy's law? Assuming constant permeabilities, porosity, and fluid viscosity and small pressure gradients everywhere, and neglecting the effect of gravity, the diffusivity equation can be written as
Equation (1)
where x, y and z are the principal axes of permeability, and the coefficients Nx, Ny, Nz are permeability, and the coefficients Nx, Ny, Nz are the principal diffusivities. When Nx = Ny = Nr (cylindrical systems), the diffusivity equation can be written as
Equation (2)
The diffusivity constants are given by
Equation (3)
Many techniques have been used for solving Eqs. 1 and 2. Most of these were first used for solving heat conduction problems and have since been applied by different authors to petroleum engineering. In the literature, most problems were solved either with Laplace transforms or Fourier transforms. One useful method employs Lord Kelvin's instantaneous point source solution. Another method that is of value although very rarely used is the Green's function method. This study presents the point source solution as part of a more general theory of Green's functions. part of a more general theory of Green's functions. This theory is applied in combination with other techniques to yield immediate solutions to difficult flow problems, some of which either have not been published or have been solved by long analytical published or have been solved by long analytical methods or sophisticated numerical techniques only.
A Tertiary COFCAW Pilot Test In the Sloss Field, Nebraska
Authors: Parrish David R. , Pollock Charles B. , Ness N.L. , Craig F.F. 
Published: December 2007

The operability of COFCAW in previously waterflooded reservoirs was demonstrated by the production of 80,000 barrels of oil from a 40-acre five-spot. This thermal recovery pilot was unusual in several respects. The pay was thin and deep, the oil was light, and the viscosity was low.

Introduction
The purpose of this paper is to describe a pilot test of COFCAW in a previously waterflooded portion of the Sloss Field, Nebraska.The Sloss pilot was one of a series of COFCAW field tests conducted in several reservoirs of differing types. This field test program is the subject of a separate paper.The COFCAW pilot at Sloss was not carried to completion but was replaced by a full-scale project. The expanded COFCAW project is the subject of another separate paper.The decision to expand COFCAW operations at Sloss was based partly on the encouraging results of the pilot and largely on an urgent need for a full-scale evaluation of this tertiary oil recovery method.

The Sloss Field
The Sloss field, with about 38 million bbl of oil originally in place is one of the larger fields in the Denver basin. It is near the city of Kimball, in Kimball County, Nebr.The field was discovered in Nov. 1954. By mid-1958, when primary operations ended, there were 89 wells in the field, most of them on 40-acre spacing. Additional wells completed later brought the total number to slightly more than 100.The field produces a light (38.8 deg. API) paraffinic oil from a stratigraphic trap in well consolidated Muddy "J" sandstone. There are two main reservoirs -- the J1 at a depth of about 6,200 ft and the slightly deeper J2. In some areas, the two reservoirs are separated by only a few feet of shale. Much of our discussion will be confined to the J1 reservoir (Fig. 1), since only that reservoir was involved in the COFCAW operations.
Production History Production History Early performance was typical of volumetric reservoirs. Peak production of 9,600 BOPD occurred in mid-1957, about 21/2 years after discovery. By 1958 the reservoir pressure had declined from the original pressure of 1,328 psia to less than 400 psia, well pressure of 1,328 psia to less than 400 psia, well below the bubble-point pressure of 689 psia. About 11 percent of the original oil in place was recovered percent of the original oil in place was recovered during pressure depletion operations.The field was unitized with Amoco Production Co. as operator and a waterflood was started in mid 1958. Response to the waterflood was good, and a maximum incremental oil producing rate of about 3,000 BOPD over the estimated primary rate was obtained. By the start of the COFCAW pilot project in mid-1963, most of the reservoir had been waterflooded. (For a description of the COFCAW process, see Ref. 1 and its references.)
JPT
P. 667
Pore Level Modeling of the Effects of Wettability
Authors: Blunt Martin J. 
Published: December 2007

AbstractWe describe a network model to study the effects of wettability which is based on the pore level scenario of Kovscek et al.1 The network model simulates primary drainage, water injection and oil re-injection. The portions of the rock surface contacted by oil after primary drainage can become oil-wet. Water remains in the corners of the pore space and these sections remain water-wet. During forced water injection, oil layers can become sandwiched between water in the corners and water in the center of the pore space. These layers maintain continuity of the oil phase and allow low oil saturations to be achieved during forced water injection. However, the flow rates through them are very low.We investigate models with different fractions of oil-wet pores, contact angles and initial water saturations. We present relative permeabilities, recovery curves and capillary pressures and interpret the results in terms of the behavior at the pore scale. The residual oil saturation, Sor, shows a non-monotonic dependence on wettability. In many cases weakly water-wet and moderately oil-wet systems have a lower Sor than either strongly water-wet or strongly oil-wet systems. Weakly oil-wet media may have a high Sor, and low relative permeabilities to both oil and water.
A Low Cost Method of Production Stimulation
Authors: Garst A.W. 
Published: December 2007

Abstract
A simple treatment has been developed by which water-block is removed from oil wells by lowering oil-water interfacial tension to a very low value.
The treatment is made by injecting a crude oil solution of a carefully selected surface-active agent into the water-blocked formation. From 1,000 to 4,000 gals. of crude oil containing 1 per cent surface active agent is used. Shut-in time following treatment is usually from 12 to 24 hours.
The treatment has been used in 90 wells with successful results obtained in 39 wells representing seven formations in nine fields. The successful treatments have resulted in added productivity of 1,217 BOPD. Treatment cost is unusually low, compared with other types of well treatments and workovers normally done for improvement of productivity.

Introduction

The Problem
Although water-block removal has received considerable attention in the past, there has remained a need for an inexpensive, effective remedial treatment for water-blocked wells. This paper discusses the development of a remedial treatment utilizing a surface active agent which has shown considerable ability to increase production rates from wells in which some water-blocking was known or suspected to exist.
The need for a remedial treatment to remove waterblock has been most clearly observed when established producing wells have shown marked productivity loss following exposure of the producing formations to water during workover operations involving water-base muds and cement. The need for such a treatment has not been so clearly evident in acidized wells. Partial water-block in such wells may occur undetected because of the complexity of operations and particularly when such wells are capable of making a maximum allowable after workover. Field tests reported in this paper show that the incidence of such water-blocking may be fairly high in at least one formation previously subjected to acidization.
High-Pressure Drilling
Authors: Maurer William C. , Heilhecker Joe K. , Love William W. 
Published: December 2007

A series of full-scale field drilling tests has shown that high-pressure bits operating at pressures of 10,000 to 15,000 psi can drill many formations two to three times faster than can conventional bits. High-pressure drills can effect significant savings where drilling costs are high, such as in deep land wells, in arctic areas, and offshore.

Introduction
A survey has been made of more than 25 novel drills, and drilling rates were predicted for each of these drills in oil wells on the basis of available laboratory drilling data. Novel drills that thermally spall rock were found to have limited potential for drilling oil wells because most sedimentary rocks will not spall. Devices such as lasers and electron beams had extrapolated drilling rates of less than 1 ft/hr because of the high energy requirement for fusing rock. Extrapolated laboratory data indicated that high-pressure erosion bits operating at pressures of 10,000 to 20,000 psi should drill medium-strength rocks at rates of 70 to 280 ft/hr compared with 30 to 170 ft/hr for conventional roller bits. As a result of this study, research was begun to further evaluate high-pressure bits for oil-well drilling.

Earlier Work
A series of laboratory tests was conducted on high-pressure drilling before the full-scale field tests were begun. In all tests, water was used as the drilling fluid.
Pulsed-Jet Experiments Pulsed-Jet Experiments After the literature was surveyed, an An-ny surplus cannon (Fig. 1) was modified to fire water pulses at pressures up to 25,000 psi. The diameters of holes pressures up to 25,000 psi. The diameters of holes eroded using 0.2 to 1-in.-diameter nozzles were three to four times larger than the nozzle diameters (Fig. 2). At 25,000 psi, a 1.45-gal water pulse was fired through a 1.0-in.-diameter nozzle in 0.02 second. This water jet drilled a 3.9-in.-diameter X 3/4 -in. deep hole in Indiana limestone, which corresponds to an instantaneous drilling rate of 1 1,000 ft/hr and a hydraulic power output of 70,000 hp. These tests demonstrated that a threshold pressure must be exceeded before fluid jets will drill; Fig. 3 shows that this threshold pressure was about 6,200 psi for Indiana limestone. psi for Indiana limestone. The amount of energy required to remove rock was determined by measuring the amount of energy expended and the amount of rock removed during each water pulse. The data from these tests indicated that a 3,000-hp jet bit would drill an 8-in.-diameter hole in Indiana limestone at rates of 280 to 370 ft/hr.

Laboratory High-Pressure Drilling Test
After the pulsed-jet tests were completed, a fracturing truck was used to pump water through a 2-in. diameter high-pressure drill (Fig. 4) at pressures up to 13,500 psi. The first bit had two 0.15-in.-diameter nozzles (nozzle area = 0.035 sq in.) and was designed to operate at pressures up to 10,000 psi. As the pressure across this bit was increased to 10,000 psi, the flow rate increased to 133 gal/min and the power output across the bit increased to 780 hydraulic horsepower (hhp).
JPT
P. 851
Oil Displacement by Foams in Relation to Their Physical Properties in Porous Media
Authors: Minssieux L. 
Published: December 2007

An investigation was conducted on the leading properties of water-gas foams and on their circulation in porous media. Results were interpreted by using the concept of the quality, or gas content, of foams in circulation. The quality is found to correlate with the foam viscosity as determined by Darcy's law in a given section of the porous medium.

Introduction
The use of water-gas foams has been developed in recent years in the field of oil and gas production. Because of their specific properties, foams have found a variety of uses. Some examples follow:
1. The well known use of foam as an aerated drilling fluid has been extended to workover and remedial well operations. Such light fluids are especially suitable for operating in decompressed reservoirs where traditional types of mud might cause damage.
2. The technology of exploiting underground gas storage reservoirs is also involved. Foams have been used to even out the gas injection profile in the case of stratified formations. They have also been suggested as a way of preventing gas leakage through the cap rock of storage reservoirs.
3. Attempts have been made to use foams as a secondary recovery fluid, although this practice is still quite limited.
4. More recently, such fluids have been used as a means of treating wells to reduce water or gas inflow during oil production. Tests of this technique have been carried out on Soviet fields.
These divers possible uses of foams take advantage of their varied properties and also take into account their behavior in porous media. This is the point in particular that we shall deal with here. particular that we shall deal with here.
Characteristic Properties of Foams
The water foams considered here may be defined as relatively stable and homogeneous dispersions of gas in a foaming-agent solution containing 0.1 to 1.0 percent of a surfactant. percent of a surfactant.
The simple aspect of such fluids (see Fig. 1) shows that the two phases that make them up are more of less associated with one another to form a structure that becomes more and more orderly as the proportion of gas becomes higher. proportion of gas becomes higher.
Considerations in Gravel Pack Design
Authors: Saucier R.J. 
Published: December 2007

Tests with physical models have shown that sand production and pack impairment are minimized when the ratio of pack median grain size to formation median grain size is between 5 and 6. In a study of the inertia and viscosity effects of flow in gravel packed wells it was found that increasing the size and the density of the perforations should increase productivity.

Introduction
Gravel packs have been used extensively along the Louisiana Gulf Coast in an effort to reduce or avoid sand production from unconsolidated formations. Statistics show, however, that through 1966, gravel packs were only about 70 percent successful.*The early literature on gravel pack design is based primarily on the work of Coberly and Wagner and of Hill. Coberly's work in essence suggested that a gravel pack having granular particles of diameter 10 times the formation grain size at the 10-percent-coarse point on a cumulative sieve analysis would provide effective sand control. Numerous failures of this criterion were noted, especially in the Gulf Coast sands. Hill suggested that the ratio of 10 be reduced to 8. Failures were still noted in many applications, At least one writer suggested concentrating on the "fines" end of a cumulative sieve analysis. Winter-burn states that "actual experience in the field has shown that sand entry can virtually be eliminated by the use of gravel which is approximately 10 times the grain size of the 10 percentile of the finest sand to be screened." Clearly a finer gravel will be more effective in screening formation particles. However, it must be evaluated in the light of how the finer gravel affects permeability and reduces production.Depending upon the writer, recommended ratios of gravel to the 10-percent-coarse point may range from 4 to 13. Other suggestions appear in the literature; see, for example, the paper by Tausch and Corley for a summary of earlier gravel pack investigations.In more recent literature, Sparlin has discussed gravel placement rate and fluid viscosity in his recommendations for a "slurry pack." Schwartz recommends a size ratio of 6 at the 10-percent-coarse point and at the 40-percent point for uniform and nonuniform sands, respectively. Williams uses Schwartz's grain-size ratio of 6 and finer and discusses well productivity as a function of perforation size and density.In addition to the apparent disagreement on the geometrical basis for gravel pack design, a more subtle lack seems to exist. Few writers have explored the influence of flow parameters on the functioning of gravel packs. Sage and Lacy appear to be the first authors who attempt to take hydrodynamic (and other) factors into consideration. We supposed that under certain conditions, hydrodynamic factors could possibly outweigh geometric factors in the functioning of gravel packs. This investigation, begun in 1967, proceeds from that basic premise.

Laboratory Test and Evaluation Program
A large number of variables are involved both directly and indirectly in gravel pack behavior. Five were considered to be most significant and fundamental to the study.
JPT
P. 205^
Optimum Sand Concentrations in Well Treatments
Authors: Dehlinger Peter , Browne W.H. , Bundrant C.O. 
Published: December 2007

Abstract
Brief laboratory investigations are described which attempt to determine optimum sand concentrations in gel-sand and oil-sand well-treatments. The investigations apply to the case where sand acts as a propping agent in formation fractures. Both analytically and experimentally it is demonstrated that optimum sand concentrations can be defined. It is difficult to translate laboratory results to field treatments, however, since the relative distribution of sand and fluid in fractures may not be the same as injected. This is because fluid may penetrate the furtherest narrow portions of fractures, which would not pass sand. Optimum concentration of a monolayer of Ottawa sand in fractures of 0.025-in. width at the usual range of pressures encountered in treatments appears to be about ½ to 2 lb/ gal. of gel.
An investigation of abrasion of rock-walls by sand in treatments, described in the Appendix, shows that such abrasion is not probable in significant amounts.

Introduction
Experience in the Spraberry formation of West Texas, as well as in other formations, has shown that sand is a necessary and vital part of gel-sand and oil-sand treatments. Many observers of treatments have also concluded that there seems to be an optimum range of sand concentration for these injections. Brief laboratory investigations were made at Battelle Memorial Institute to study flow in fractures with different sand concentrations. To investigate the existence and range of optimum concentrations in the laboratory, however, necessitates knowledge of the mechanism by which the sand aids in increasing subsequent production.
The action of sand in fractures is usually thought to be either that of a propping agent, thus providing a greater effective formation permeability; that of an abrasive in eroding fill material in fractures; or that of an abrasive eroding rock-wall irregularities along fracture surfaces. Investigations described in the Appendix show that sand does not appear to erode rock-wall materials appreciably. In a subsequent paper it is reasoned, at least for the Spraberry formation of West Texas, that the primary action of sand is not in removing fill materials in fractures. In this formation, and probably others, too, the main effect of sand appears to be that of a propping agent.