bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Fireflood in a Very Viscous Oil-Unconsolidated Sand Reservoir, S.E. Pauls Valley Field, Oklahoma
Authors: Elkins Lincoln F. , Morton Dick , Blackwell William A. 
Published: December 2007

Abstract
This field produces 8000 cp 100 API oil by natural water drive from an unconsolidated sand reservoir about 100 feet thick. Nearly all wells produced 10–50% sand initially, declining later to 0.1–2%, regardless of completion method. Apparently this production of sand created inter-connecting "worm hole" porosity extending at least between wells on porosity extending at least between wells on 10-acre spacing. Some of the evidence for this during primary production was:
1 near-gauge caliper surveys of open hole sections after production of large volumes of sand;
2 rapid movement of injected water and tracers between wells; and
3 production of Jelflake lost circulation material from two wells following its use in workover and deepening of a third well.
Air was injected below the oil-water contact in an edge well as a partial test for spontaneous ignition in a peripheral fireflood. In about four months some offset wells were converted to flowing after breakthrough of "air" devoid of oxygen but also containing very little carbon dioxide. When produced "air" reached high oxygen containing test was stopped. Later a structurally high 'Well was ignited. Extremely rapid travel of carbon dioxide to 2 offset wells was also indicative of inter-connected "worm hole" porosity created by production of sand.
The fireflood stimulated two offset wells such that total field production increased from 100- to 170 BOPD previously to a maximum 400 BOPD six months later and averaged 310 BOPD for the 16 months of air injection. Cumulative average air-oil ratio was 6 Mcf/bbl. Although the test was physically successful, abnormally high physically successful, abnormally high producing well operating expense precluded producing well operating expense precluded continuing operation and expansion of the project.

Introduction
The Southeast Pauls Valley Field, Garvin County, Oklahoma, producing from the oil Creek Sand at a depth of 4300 feet, 'Was discovered in March, 1955. Since it produces very viscous oil from unconsolidated sand, operating problems have been severe.
Log Derived Rock Properties For Use In Well Stimulation Design
Authors: Anderson Terry , Walker Terry 
Published: December 2007

Abstract
Well logs which present the full wave train of the acoustic signal show variations in both the compressive and shear wave arrivals with lithological changes. This information, along with elastic constants, which can be derived from the logs, can be used in the design techniques available for well stimulation planning.
This information has been successfully applied in one area of California to select completion intervals that could be successfully stimulated at pressures below wellhead limitations. Additionally, pressures below wellhead limitations. Additionally, this data could be applied to the prediction of fracture height and of the fracture closure or sand embedment problem where productivity increases from well stimulation are only temporary.

Introduction
Optimization of well treatment over recent years has necessitated more exact input data regarding the formation characteristics. Design techniques have been developed which require specific rock properties; however, many of the properties used properties; however, many of the properties used are assumptions or average values obtained from limited core samples. Variations of geological factors under downhole conditions are readily observed on many types of logs; however, many of these variations are seldom taken into account in treatment design. Their influence on vertical fracture height is an important consideration for which there has been nothing very consistent in the method of prediction.
Potential Underground Storage of Hydrocarbons Along the Eastern Seaboard
Authors: Langill Richard F. , Heckard John M. 
Published: December 2007

This paper was prepared for the Eastern Regional Meeting to be held in Columbus, Ohio, November 8–9, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Many areas of the United States are suitable for the underground storage of hydrocarbons from both a geologic and an economic viewpoint. This potential for underground storage has not been explored or developed to any great extent along the eastern seaboard, although the need for underground storage continues to increase.
A growth in demand for clean fuels and changes in the availability of domestic natural gas supply for the eastern seaboard point to a present need for evaluating the potential for underground storage of gas supplies from other sources. Specifically, aquifer storage facilities for natural gas derived from domestic or imported sources and from increasing imports of liquefied natural gas, should be developed for both curve-shaping and peak-shaving requirements. This aquifer storage could be used to meet increasing gas demands resulting from population growth, particularly in inland areas excluded particularly in inland areas excluded from ready deliverability provided by LNG vaporization facilities. In addition, the same aquifer storage facilities could find a future use in handling supplies of gas from domestic synthetic natural gas.
Cavern storage of LPG or reformed products for the northeast should also products for the northeast should also be developed. Cavern storage would handle increased demands for products such as propane, butane, naptha, fuel, oil and propane, butane, naptha, fuel, oil and crude. The total potential for cavern storage has not been adequately assessed in terms of future needs.
The technical feasibility of both aquifer and cavern underground storage depends largely upon geologic conditions. The economic feasibility can readily be estimated by comparison with other storage operations. An analysis is made of existing geologic conditions (on a regional basis) and specific recommendations are made relative to the development of underground storage facilities along the eastern seaboard.
Through Flow Line Tools for Remote Downhole Well Operations
Authors: Seligman P.R. , Reeds C.B. 
Published: December 2007

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
During the period 1969–71 a number of Through Flow Line (TFL) tools were tested in two wells: one a 3500' deep non-producing well; the other a 9330' deep well on gas lift production.
This work was conducted in connection with the development of a new subsea well completion system.' Test results, however, demonstrated that TFL tools and techniques have great potential for application in wells on land as well as offshore.
Initial costs for equipping a well for TFL work are greater than for wire line operations. In many cases, however, operating costs will be significantly less. TFL tools are equally efficient in straight and highly deviated wells and are effective for a wide variety of downhole jobs including fishing problems. Numerous workover type jobs such as sand washing, perforating and cementing can be performed perforating and cementing can be performed without pulling tubing, and TFL procedures permit large differential procedures permit large differential forces to be applied downhole when necessary.
Many existing TFL tools are operational. In some cases, improvements in design or prerun inspection are warranted to improve reliability. Certain other tools are still in the development stage, and both shop and field tests are indicated to uncover design faults and to establish operating characteristics.

Introduction
In recent years, quite a bit of experimental and developmental work has been performed on oil well tools designed to be pumped hydraulically down a tubing string. Originally, anticipated application was for two types of wells:Offshore platform wells that were directionally drilled at such high angles that wire line tools simply would not fall to bottom satisfactorily.Ocean floor completions producing through submarine flow lines to platforms some distance away.
Sand Stabilization with Hydroxy Aluminum Solutions
Authors: Reed M.G. , Coppel Claude P. 
Published: December 2007

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
In many oil producing reservoirs, sand and other fine-grained rock materials migrate into wells. This influx may decrease oil production by plugging gravel packs, production by plugging gravel packs, eroding well equipment or completely sanding up wells. In many such problem formations, the principal problem formations, the principal natural cementing agents are clay minerals, which are relatively weak and may be further weakened by changes in formation fluid chemistry. When these clay minerals expand and disperse, the coarser silt and sand in the formation rock may also move in with flowing fluids and damage the well. This paper describes a procedure for treating such formations with hydroxy-aluminum to stabilize clay minerals and thereby prevent sand and silt production. production. Hydroxy-aluminum is a relatively inexpensive and commercially available chemical that very effectively inhibits clay damage in normally water sensitive formations. An aqueous solution of hydroxy-aluminum is injected and is desirably followed by an aqueous overflush and a short shut-in period. Hydroxy-aluminum cations adsorb very tightly on clay mineral surfaces and stabilize them by decreasing dispersive forces and eliminating structural expansion.
Laboratory flow studies show that after treatment many selected friable natural formation sands can withstand considerably higher flow rates without sand production. The effectiveness of the chemical treatment is related to the clay mineral content and cation exchange capacity of the rock. The process has been applied successfully in California and Gulf Coast fields.

Introduction
Movement of formation materials into wells is a serious problem in many oil-production areas around the world.
Information Services - An International Technology for Petroleum Engineers
Authors: Wexler P.L. 
Published: December 2007

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Good afternoon ladies and gentlemen. It is my pleasure to meet with you today and discuss Information Services, an International Technology for Petroleum Engineers.
My talk will cover three main aspects:
. An overview of Information Services and its technology.
A review of some current petrochemical applications which utilize the Network.
A projection of future Information Services trends.
Information Services can be viewed in three specific phases and time periods.
The first phase began in the mid-sixties and was commonly referred to as Time-Sharing. As you all know, this involved a fairly standard computer with some telecommunications capability and specialized interactive software.
During the next four to five years, this industry grew tremendously and systems and their capabilities progressed on a very fast scale. This type of service was primarily oriented toward engineering and primarily oriented toward engineering and scientific applications and Time-Sharing systems generally served a customer on a regional basis.
In the late sixties, a new phase of the industry was entered… Networking. This development was the merging of computers and telecommunications on a grand scale. Systems developed large networks providing common file access from many diverse locations. Applications began to become more business oriented… inventory management… order processing are a few prime examples. Service vendors today offer Networking capability on widely varying ranges….. from regional to national to international.
Let me now divert for a few minutes and discuss one specific network with which I am slightly familiar….. GE's International Information Services Network.
First, let me discuss the Network's Technology. This can be addressed in two respects - one from an overall system basis and the other with reference to hardware and software.
Numerical Simulation Of Compositional Phenomena In Petroleum Reservoirs
Authors: Nolen J.S. 
Published: December 2007

Nolen, J.S., Member AIME INTERCOMP Resource Development and Engineering, Inc.

Abstract
The only fundamental difference between compositional reservoir simulators and simulators of the black-oil type lies in their treatment of fluid properties and phase behavior. Since properties and phase behavior. Since compositional simulation, the only justification for a compositional study is the increased accuracy that can be obtained by a more realistic description of the fluid.
This paper focuses on the consistent and accurate treatment of fluid properties in describing a three dimensional properties in describing a three dimensional compositional simulator. It describes the methods used to calculate densities, viscosities, and equilibrium K-values, presenting comparisons between calculated values and experimental data.
Another subject of discussion in the paper is the problem of numerical dispersion. An example simulation illustrates the magnitude of the problem and demonstrates that the method-of-characteristics provides a practical means of eliminating numerical provides a practical means of eliminating numerical dispersion in multicomponent miscible displacement problems.

Introduction
Most numerical simulations of petroleum reservoirs are performed with petroleum reservoirs are performed with "black-oil" type simulators. The validity of these black-oil models rests on the assumption that the reservoir fluid consists of only two components, denoted oil and gas.
Numerical Simulation of Naturally Fractured Reservoirs
Authors: Asfari Ardeshir , Witherspoon Paul A. 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The finite element method has been used to investigate mathematical models of idealized systems of vertical fractures in an effort to extend our understanding of the behavior of naturally fractured reservoirs. Regular systems of fractures have been chosen in such a way that the length of the fracture can be characterized in terms of the dimensions of a representative elemental area associated with that fracture. By changing the permeability of the fracture relate to the matrix, steady state solutions demonstrate how the effective permeability of the fractured system depends on both fracture conductivity and dimensionless parameters representing fracture density. Horizontal shale lenses, scattered through a reservoir can be modelled in the same way using finite elements of very low conductivity. Comparison of our results with those from a recent analytic solution for fractured systems indicate excellent agreement.

Introduction
There are a significant number of petroleum reservoirs where discontinuities such as fractures or joints in the porous rock matrix are the main path transmitting fluids to the producing well. These naturally fractured systems producing well. These naturally fractured systems characteristically have a low matrix permeability and one or more well developed fracture systems.
The published reports on naturally fractured reservoirs show that vertical joint planes are a dominant feature. Daniel studied three fractured limestone reservoirs of the Middle East. He reports that in all three cases, vertical and near vertical fractures were widespread, and for the most part, there was a complete absence of low dipping fracture planes. Wilkinson's work on the Spraberry reservoir in Texas revealed that vertical joints are the largest, both in extent and width, and by far the most abundant type of fractures. This dominance of vertical fractures has also been reported by other authors.
Investigations of non-reservoir rocks have also revealed the same conclusions. Kelly and Clinton, Parker, and Hodgson have made extensive regional investigations on fractures and joints. They report that vertical joints constitute the most dominant mode of fracture systems. Furthermore, they report that in the areas studied, the fractures are not randomly oriented but are systematically arranged in sets. The same finding has also recently been reported by Louis and Perrot and Mahtab et al.
In all of these investigations more than one fracture system may be found. The area of an individual fracture plane may vary from a few square inches to several hundred square feet.
The Isochronal Testing of Oil Wells
Authors: Fetkovich M.J. 
Published: December 2007

Abstract
This paper presents the results and methods of analyzing isochronal and flow after flow multipoint back-pressure tests conducted on oil wells. Tests were conducted in reservoirs with permeabilities ranging from 6 MD to &gt;1000 MD. Reservoirs in which oil well multipoint back-pressure tests were obtained ranged from highly undersaturated, to saturated at initial reservoir pressure, to a partially depleted field with a gas saturation existing above the critical. Each of these three reservoir fluid states can result in different interpretation methods. Back-pressure tests were run to pseudo-steady state in the field where the saturation was above the critical gas saturation.
In all cases, oil well back-pressure tests curves were found to follow the same general form as that used to express the rate-pressure relationship of a gas well:Equation
From some 40 oil well back-pressure tests examined, the exponent n was found to lie between 0.568 and 1.000, very near the limits commonly accepted for gas well back-pressure curves. Flow point alignment to establish an oil well back-pressure curve on the customary log qo vs. log Î"(p2) plot is considered to be as good as that obtained on gas well back-pressure tests.
This paper demonstrates that gas wells and oil wells behave very similarly and should be tested and analyzed using the same basic flow equations.

Introduction
Multipoint back-pressure testing of gas wells is an accepted procedure for establishing a gas well's performance curve. Flow after flow1 and isochronal2 testing are the two basic methods commonly used. In high permeability reservoirs, either method can be employed. In low permeability reservoirs, the Isochronal method of testing eliminates the transient effects that can severely distort the results obtained from a flow after flow test. Methods for analyzing and calculating gas well performance curves have been the subject of numerous investigations. The bulk of these investigations have examined non-Darcy flow behavior, the primary reason that multipoint tests are conducted.