bluuebunny/crossref_metadata_2025_split huggingface dataset:
Calculating Recovery by Cycling a Retrograde Condensate Reservoir
Authors: Sheldon W.C. 
Published: December 2007

Abstract
The theory and principles covering cycling a retrograde condensate reservoir have been presented by some excellent papers. Methods for calculating recovery have also been discussed. However, calculating rate of dry gas invasion or dilution when cycling a thick reservoir presents some problems. The vertical sweeping depends upon the permeability range or distribution of permeabilities in reservoirs where thickness of the productive zone approaches the distances between wells. This paper discusses the concept of permeability variation, or V factor, and presents curves to relate sweeping efficiency with pore volumes of dry gas injected for various permeability variations. From these considerations a "dilution factor" has been developed for various permeability variations.

Introduction
Many cycling operations have been initiated to obtain a greater recovery of liquids otherwise lost by retrograde condensation within the reservoir. One of the problems which confronts those concerned with such a project is to determine anticipated recovery for any proposed plan of cycling operation. After a project has been started it is important to be able to determine whether it is operating satisfactorily at any given time. The subject has been covered by some outstanding papers.
The purpose of this paper is to clarify some concepts previously presented. Some curves have been developed which have been useful in following the cycling performance of reservoirs with thick sections.

Method
In cycling a reservoir that is relatively thin, one in which sand thickness is small compared to distance between wells, transition from producing reservoir wet gas to driving dry gas is sharp. In such cases there is little dilution of reservoir gas by injected dry gas. A producing well changes rapidly from wet gas production to dry gas shortly after the first dry gas is produced. In these cases the permeability variation concept, as discussed by Law and by Standing, et al. is valid but less apparent.
Case History of Steam Soaking in the Kern River Field, California
Authors: Long Robert J. 
Published: December 2007

Abstract
Crestmont Oil Co.'s 42-acre May Fee property is located in the Kern River field, and consists of eight wells in the China Grade zone and seven wells in the Kern River zone. The average well declined from an initial production of 70 to 4 BOPD in seven years, while recovering only 9 per cent of the oil in place. A thermal recovery program was initiated using the steam soak method of injecting, soaking, and then producing. After injecting an average of 10,000 bbl of water as 80 per cent quality steam in six of the 15 wells, production increased from 1,635 to 13,374 bbl/month. The eightfold increase in production can be accounted for by the fact that these zones are ideally responsive to steam stimulation, due to the large decrease in viscosity realized by small increases in temperature and the large amount of 12.5 deg. gravity oil remaining at relatively shallow depths.
Introduction
Primary production from the seven- and 15-year-old wells on the 42-acre property had declined to 2 to 6 BOPD/well, even though only 9 per cent of the original oil in place had been produced. Late in 1962 Crestmont Oil Co. decided to investigate various methods of thermal recovery to see if the remaining oil could be economically recovered. The purpose of this paper is to
present the reservoir conditions prior to steam injection, describe equipment used and the method of injection, tabulate the results before and after the wells were steamed, and tabulate techniques and conclusions regarding steam injection.
Geological Description
The Kern River zone contains 190 net ft of oil sand from 700 to 1,000 ft. There are several strata of shale throughout the zone, with a 60-ft interval occurring at 850 ft. The formation has 35 per cent porosity, 20 per cent connate water, and a 1.05 formation volume factor. The viscosity of the oil at the ambient reservoir temperature of 80F is 7,000 Saybolt-seconds. The gravity averages 12.6 at 60F. The Kern River zone contains approximately 1,900 bbl of oil/acre-ft. A zone of fresh water, identical to the produced water, exists from just below the surface to the top of the Kern River zone. Fig. 1 shows a composite log of the Kern River and China Grade zones. The China Grade zone contains 20 ft of oil sand in Te 35 ft from 1,200 to 1,235 ft. The China Grade zone exhibits a more uniform vertical homogeneity than the Kern River zone. The ambient temperature, viscosity and gravity are closely related to the Kern River zone.
JPT
Acid Stimulation of a Fractured Shale Zone
Authors: Dewar R.M. 
Published: December 2007

Abstract
Honolulu Oil Corp., operator for the Antelope Shale Zone Unit, Buena Vista Hills, initiated a program for oil well acid treatment for the purpose of removing precipitated carbonate scales from production equipment and for well stimulation, Oct. 23, 1956. This program was active through Feb., 1958. In this period 35 wells were acid treated yielding a net increase in oil of 1,390 B/D and gas increase of 3,265 Mcf/D. The total cost of acidizing the 35 wells was $80,000.

Introduction
Acid stimulation of California oil wells has been used to a limited extent, primarily for dissolving precipitated carbonate scales and other plugging agents within or adjacent to the wellbore.
In the Antelope Shale Zone in Buena Vista Hills, some producing wells showed evidence of rapid carbonate scale precipitation on the tubing and rods in early phases of production. Observation of this scale led to the belief that acid treatment of a well might be beneficial both to production equipment and to production rate, if liner and adjacent wellbore were suffering plugging. Initial application of acid to an oil well was made almost solely to clean up production equipment.

History of Development
The Buena Vista Hills field is located in Kern County near Taft. The field is on a large anticlinal structure including two domes and containing several productive sands from about 2,300 to 3,900 ft, and also containing the Antelope Shale Zone which is predominantly a fractured shale. The shallower sand zones were developed over a period from 1909 to the present time. The fractured shale zone has been developed in the last six years and development is still progressing to a minor degree. This report is confined to the East Dome. The upper sands have been acid treated on occasion over a period of years in a spotty manner giving spotty results. A few jobs were quite beneficial, but the majority were of moderate or no success. The predominant basis for treatment of these upper sands was also the observation of precipitated scale on production equipment.
An Efficient Fully Implicit Simulator
Authors: Ponting D. K. , Foster B. A. , Naccache P. F. , Nicholas M. O. , Pollard R. K. , Rae J. , Banks D. , Walsh S. K. 
Published: December 2007

Abstract
This paper describes Program for Oil Reservoir Simulation (pores), an efficient general-purpose black-oil simulator now in production use for modeling North Sea fields. The fully implicit finite-difference equations are solved for each timestep with a Newton-Raphson procedure. The resulting large sets of linear equations are usually solved simultaneously by a new and powerful iterative method that uses a preconditioned conjugate gradient algorithm with an enforced column-sum condition to accelerate convergence. A sequential solution option is available, and direct matrix inversion methods also are provided. Gas condensate problems are handled by a variable switching technique. Four examples are presented to illustrate the power and efficiency of the program.
Economics of a Computerized Oilfield Control System
Authors: Bowler D.L. , Queen J.A. 
Published: December 2007

Abstract
The economic aspects of the online, programmable computer for supervisory control of producing operations are discussed. The material presented reflects the performance and economics of a pilot supervisory control installation that has been supervising and controlling producing operations for one year in two widely separated fields in southeastern New Mexico. Expansion of this pilot supervisory system is necessary to obtain an actual payout, but the performance of the pilot project does provide a reliable basis for predicting the economics of full scale computer controlled producing operations.
Introduction
A pilot installation to evaluate a supervisory, monitoring and control system for properties operated in southeastern New Mexico by Continental Oil Co. was installed in Oct., 1964. The pilot project included 56 wells in two fields to be controlled from the district office in Hobbs, N. M. Results of the pilot project would serve to evaluate the economics of expanding the system to include three additional areas and 326 additional wells in a full scale operation, with possible future expansion to a total of 600 to 700 wells. The pilot installation and three additional areas to be included in the full scale project are shown in Fig. 1.This supervisory control system is similar in concept to an earlier system installed during 1962 in the Big Horn Basin of Wyoming by the Rocky Mountain Region of Conoco. The pilot project has been sufficiently complex to prove equipment capability and performance, but limited enough to keep installation costs within reason should results indicate the total project to be economically unattractive leases in the Hobbs and El Mar fields of New Mexico comprise this two-field pilot project. These areas are separated by approximately 56 air miles (Fig. 1). The Hobbs field, located two miles from the central supervisory in the city of Hobbs, consists of three leases with 14 flowing or pumping wells producing 5 1 8 BOPD into one central tank battery. The El Mar field includes three leases with 42 pumping or flowing wells producing 700 BOPD into a central tank battery. The objective of the pilot program was to determine if a significant portion of the pumper functions could be performed by the supervisory system while maintaining producing efficiency at a level equal to or greater than before. It was recognized that not all of the pumper duties could be performed by computer control but that almost all of the check-and-see type routine could be surveyed by the system. The majority of pumper time involves travel and inspection duties; therefore, it was estimated that approximately 50 per cent of his assignments could be supervised by the control system.
JPT
P. 48ˆ
One Hundred Years of Progress in Petroleum Production Engineering
Authors: Power Harry H. 
Published: December 2007

Comparison of petroleum production engineering practices in the United States throughout the past century shows:the profession has been represented ipso facto from the beginning, andrecognition as a separate and distinct engineering profession has occurred only during the last half of the 100-year history.
The coal-oil industry was already of sizeable extent in 1859, and industrial and domestic needs were well established for illuminating oils and lubricants.
Although commercial incentives are credited with the initiation of the petroleum industry, "Colonel" E. L. Drake has been recognized for his application of salt-well drilling techniques to the recovery of oil. Development, first confined to Pennsylvania, spread to at least four other states before the close of 1860. The demand for competent labor, trained "on the job" increased as migration proceeded to new areas of flush production.

Early Exploration
When embryo development at Bradford was found as a direct continuation of the Clarion County oil trend, transit lines served as "conclusive proof that all the lands through which that line passed were ‘on the oil belt!’". This procedure was criticized severely by John F. Carll, often recognized as the first petroleum production engineer in the United States. His vision of the real importance of geology and reservoir performance predicted present day theories and techniques with remarkable clarity.
Of importance to exploration, however, were the oil, gas and water seepages; and asphaltic, paraffinic and bituminous deposits closely associated with the oil and gas areas developed initially.
In addition to topographic features and surface indications, "creekology" prevailed for a short time, followed by a general resort to sorcery and divining rods.
However, early drilling activities served to provide considerable knowledge of geologic structures for the accumulation of oil and natural gas. The anticlinal theory, as first developed by T. Sterry Hunt in 1861, was not given credence by geologists and producers until its revival 20 years later by I. C. White. Oil found in non-anticlinal areas served to discredit the first proposed theory. Hence, few geologists were employed by the producers prior to 1900.
A Review of Foreign Oil Production in 1960
Authors: Mayhew Zeb 
Published: December 2007

The petroleum industry during 1959 was characterized by one dominant theme - overcapacity to produce. This problem continued to dominate 1960 and will undoubtedly be a sore thumb for many years to come.
In the Free Foreign area, spare capacity to produce increased only slightly, barrelwise, during 1960 and as a per cent of total capacity, it leveled off. However, this adjustment is qualified by the fact that some major investments currently being made abroad soon wilI result in the availability in the world market of substantial volumes of new crude. This can only result in another upward cycle of the over-all spare producibility curve.
Of course, a certain level of spare is necessary because the oil industry is a growing business and cannot afford simply to exist from day to day. A certain amount of extra capacity is necessary to allow for the unavoidable downtimes which occur in producing operations; and, finally, there is the need to have some spare for handling emergencies.
All these factors require that money be invested in spare capacity, but the big question is, "What level of spare is desirable and when does it become a burden?". It would be an oversimplification to make a general statement about the worldwide industry because both the location and ownership of spare capacity have a great deal to do with its effect.
Fig. 1 shows spare capacity as a per cent of total capacity for the last decade for the United States, Free Foreign, and Free World areas.
Fluid and Heat Flow In Gas-Rich Geothermal Reservoirs
Authors: O'Sullivan M. J. , Bodvarsson G. S. , Pruess K. , Blakeley M. R. 
Published: December 2007

Abstract
Numerical simulation techniques are used to study the effects of noncondensable gases (CO2) on geothermal reservoir behavior in the natural state and during exploitation. It is shown that the presence of CO2 has a large effect on the thermodynamic conditions of a reservoir in the natural state, especially on temperature distributions and phase compositions. The gas will expand two-phase zones and increase gas saturations to enable flow of CO2 through the system. During exploitation, the early pressure drop primarily results from "degassing" of the system. This process can cause a very rapid initial pressure drop, on the order of megapascals, depending on the initial partial pressure of CO2. The flowing gas content from wells can provide information on in-place gas saturations and relative permeability curves that apply at a given geothermal resource. Site-specific studies are made for the gas-rich, two-phase reservoir at the Ohaaki geothermal field in New Zealand. A simple lumped-parameter model and a vertical column model are applied to the field data. The results obtained agree well with the natural thermodynamic state of the Ohaaki field (pressure and temperature profiles) and a partial pressure of 1.5 to 2.5 MPa [217 to 363 psi] is calculated in the primary reservoirs. The models also agree reasonably well with field data obtained during exploitation of the field. The treatment of thermophysical properties of H2O/CO2 mixtures for different phase compositions is summarized.
Water/Oil Displacement Characteristics in Crossbedded Reservoir Zones
Authors: Kortekaas T. F. M. 
Published: December 2007

Abstract
Festoon crossbedding is a typical sedimentary structure in sandstone reservoirs. It is especially common in fluvial deposits. The important elements are the foreset laminae, which vary in permeability, and the bottomsets of lower permeability.
To understand the complex, direction-dependent displacement characteristics of a crossbedded reservoir zone, we first conducted numerical simulations on a centimeter scale in a small part of a water-wet crossbedded reservoir zone. The simulations indicate that, during water/oil displacement, considerable amounts of movable oil initially are left behind in the higher-permeability foreset laminae with fluid flow perpendicular to the foreset laminae, while with flow parallel to the foreset laminae the displacement efficiency is good.
To describe the displacement characteristics on a reservoir scale, we developed a procedure for calculating direction-dependent pseudo relative-permeability and capillary-pressure curves to be used as input for the simulations of water/oil displacement in a crossbedded reservoir zone. On a reservoir scale, the displacement characteristics in a water-wet crossbedded reservoir zone are slightly more favorable with the main fluid flow perpendicular to the foreset laminae.
In addition, the sensitivity of the displacement characteristics to moderate reductions in interfacial tensions (IFT's) and to increases in water viscosity was investigated, both on a centimeter scale and on a reservoir scale. The simulations indicate the potential for substantial improvement in recovery from crossbedded reservoir zones if diluted surfactant or polymer is added to the drive water.
Analytical and Numerical Modeling of Immiscible Gravity-Stable Gas Injection Into Stratified Reservoirs
Authors: Ypma J. G. J. 
Published: December 2007

Abstract
A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model.
Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil.
A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids.
Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process.
How Oil Wells Are Completed in the Paradox Basin
Authors: MacAlister R.S. 
Published: December 2007

Abstract
This paper covers the common completion practices for oil wells in the Paradox Basin fields near the Four Corners. The nature of the producing formations is described and the pertinent drilling problems are discussed. Since the pay consists of carbonate rocks, stimulation by acidizing is the principal ingredient of completions. These methods of acidizing which have been tailored to the reservoir characteristics are described.

Introduction
As in any other geologic province, the Paradox Basin requires its own combination of the myriad of drilling and completion techniques if optimum productivity is to be obtained at minimum cost. With the boom in development activity since the oil pipelines from this basin were constructed the process of making an oil well has undergone considerable refinement so that today better wells are being completed for less money. This treatise describes how this is done. To facilitate an understanding of the problems peculiar to this area and the reasons for the methods used to cope with them, a complete but generalized description of the reservoirs is presented.

Pertinent Drilling Information
The proved commercial productive horizons in the Paradox Basin are, for all practical purposes, the porous carbonates of the Pennsylvanian Hermosa formation and those of the Paradox member. In the area of greatest exploration and development, this formation is generally between 5,000 and 6,000 ft deep. Drilling times in the Aneth and Ratherford fields are approximately 25 days, and generally somewhat more in wildcats and outlying fields. Most operators drill 9-in. hole and set 7-in. production casing or drill 7 ⅞-in. hole and set 5 ½-in. production casing. Reservoir pressure of the productive zone is less than hydrostatic, and mud weights of 9.2–10.4 lb/gal have been found to be satisfactory after setting surface casing. The mud weight depends on the weight that is necessary to control the water flow from the De Chelly, which lies some 2,000 ft below the surface. For development wells it is frequent practice to emulsify some oil into the mud before reaching the objective zone which improves drilling characteristics, reduces mud costs, and probably reduces contamination of the pay section.
Modification of Welge's Method of Shock Front Location in the Buckley-Leverett Problem for Nonzero Initial Condition
Authors: Mohsen M. F. N. 
Published: December 2007

Abstract
In the analytical solution of the Buckley-Leverett problem, Welge1 recommends that to locate a front, one should draw a tangent to the fractional saturation curve from the origin. In this paper I establish that this procedure will be correct only for the case of a zero initial condition. For a nonzero initial condition, a mass-conserving front will be located farther down the flow direction. The implications of this finding for error analysis in comparing numerical solutions to the analytical one are discussed.