bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interfacial Light Scattering Study in Microemulsions
Authors: Kim Mahn Won , Huang John S. , Bock Jan 
Published: December 2007

Abstract
Thermally excited waves at the interface between two fluids contain information about the structure and tension at this interface. A surface light-scattering technique based on photon correlation spectroscopy has been developed to probe the dynamics of these interfacial waves for microemulsions. The interfacial tension (IFT) as measured by this nonperturbing technique is consistent with the values obtained by conventional methods.
We have studied the temperature and salinity dependence of σ (IFT) in a three-phase microemulsion system, and found that σ ~ ϵ2±0 5, where ϵ is the reduced variable |TC − T| and |Cc− C| with Tc and Cc representing the critical values of temperature and salinity, respectively. Furthermore, the correlation length, L, in the microemulsion phase has also been measured by dynamic light scattering. In the two-phase regions it was observed that σ~L−2, in accordance with the scaling law predictions. Thus, the scaled salinity and temperature parameters influence the IFT through their effect on the correlation length in the bulk microemulsion phase.
An Analysis of the Effect of CO2 Injection on the Recovery of In-Situ Methane From Bituminous Coal: An Experimental Simulation
Authors: Reznik A. A. , Singh P. K. , Foley W. L. 
Published: December 2007

Abstract
A set of experiments is described in which CO2 is injected into large cores of CH4− and water-saturated bituminous coal at elevated pressures. CO2 at pressures up to 800 psig [5516 KPa] is used to simulate the enhanced recovery of in-situ CH4 from coal beds. CO2 injection increases the recovery of CH4 by a factor of two to three times that achieved in simple desorption by pressure drawdown and atmospheric diffusion. In general, higher CO2 pressures achieve greater CH4 recovery. The presence of even small amounts of N2 in the injection gas greatly reduces the CH4 recovered. CO2 at 500 to 800 psig [3447 to 5516 kPa] is shown to be capable of completely demethanating integral coal samples. This was confirmed by tests run on crushed cores. CO2 consumption by permanent adsorption is quite high vis-à-vis the CH4 recovered and may preclude its use as an enhanced-recovery energy process. Its primary function would appear to be as a means of safely demethanating coal beds before mining.
A Critical Study of a Petroleum Engineering Computing Operation
Authors: McCarty D.G. , Welsh J.R. 
Published: December 2007

Abstract
During the last 5 to 10 years the application of automatic computing equipment in engineering work has developed into what appears to be a major technical development. In view of the widespread use of this type equipment, it is believed timely to examine the record critically for useful operating criteria and for clues to how productive the application of computers in engineering activities has been. In order to provide some data to assist in answering these questions, the operational history of a computing facility engaged exclusively in engineering analysis work on a service basis as part of an oil company petroleum engineering organization has, been reviewed. On the basis of this experience, an attempt has been made to point outthose procedures which have been effective in bringing about company-wide participation in the use of the equipment,how engineering development work and subsequent communication of new methods of analysis to field engineers can be accomplished, andwhat constitutes a workable procedure for producing the desired service work.
The accomplishments of this particular computing facility have been studied, and on the basis of the indicated volume of productive work and corresponding net cost, the use of general purpose digital computers in petroleum engineering activities is attractive economically. When broad participation in the use of the equipment is achieved, the communication problem associated withdistributing information on methods and the availability of specific calculation procedures to field installation,arranging for exploitation of new approaches, andmaintaining a free and reasonably simple flow channel for service work from and to field engineering groups is greatly simplified.

Introduction
The urge to enter into the present discussion of the use of automatic computers comes fromthe belief that the application of high-speed digital computers has reached the stage of development where the users can no longer expect the computers operation to be viewed as experimental, andthe fact that although a large volume of literature has appeared in recent years concerning digital computers and their use, very little information has appeared showing some of the more pertinent factors of computer operation such as unit costs, economic advantages, and other tangible benefits.
If a serious effort is made by those having experience in computer operations, it should be possible at the present time to make available sufficient information to enable prospective users to make a reasonably accurate appraisal of the potential benefits of using a computer in practically any application.
Waterflood Oil Recovery in Fractured Reservoirs With Directionally Drilled Wells
Authors: Bacon Jeffrey R. , Kempthorne Robert H. 
Published: December 2007

Abstract
A technique has been developed to estimate the potential effects of directionally drilled wellbore orientation on pattern waterflood oil recovery in anisotropically fractured reservoirs. The technique attempts to quantify the tradeoff between drilling directional wells either more vertically or better aligned with the major fracture orientation in situations where simple vertical wells are not possible. Among the incentives to deplete some reservoirs with directionally drilled wells are the ability to access reserves located beneath large bodies of water from shore or island structures and the economy of centralized surface facilities. The orientation of these directionally drilled wells in anisotropically fractured oil reservoirs may have a significant impact on recovery efficiency. The described method involves combining the directional permeability characteristics of the reservoir caused by fractures, drilling accuracy, and the proposed wellbore orientation to estimate the volume of reservoir that may be affected by a nonvertical well. The distribution of fractures in the reservoir, average fracture length, and effective vertical permeability are noted as being major factors influencing the effect of directionally drilled wells on oil recovery. When applied to the Norman Wells oil field (N.W. Ter., Canada), it was possible to identify elongated target areas within which any directionally drilled well is expected to have similar oil recovery.
Handling High Pressure Cycling Projects at Northwest Branch, Louisiana
Authors: Owens Herman , Kirk Earl , Brinkley T.W. 
Published: December 2007

Abstract
Unusually high surface injection pressures ranging from 6,500 to 6,700 psi have been required in pressure maintenance operations at Northwest Branch, Acadia Parish, La. The high injection pressures were necessary to permit cycling operations at near dew-point conditions in the condensate-bearing Nodosaria Blanpiedi No. 1 sand. Injection volumes at this high pressure have averaged 12 MMcf/D since injection started in Sept., 1955. The cycling phase of operation is approximately 65 per cent complete prior to blowdown operations. Reservoir and fluid characteristics are described and production history is presented. Performance of the cycling phase of operation is presented and is based on the original 2,100-psi separator condensate in place at start of cycling operations. Compressor operating problems are also presented.

Introduction
The Northwest Branch field, Acadia Parish, La. was discovered in Dec., 1951, and was unitized for pressure maintenance (cycling) operations on June 1, 1955. The Unit consists of the Nonion Struma No. 1 sand and the Nodosaria Blanpiedi No. 1 sand; cross faulting further defines the Unit area as Block A and Block B. Cycling operations to date include the Nodosaria Blanpiedi No. 1 sand in Block A and the Nonion Struma No. 1 in Block B. Herein is reviewed the cycling operations in the Nodosaria Blanpiedi No. 1 sand in Block A where unusually high (6,500 to 6,700 psi) surface injection pressures have been required.

Geology and Reservoir Characteristics
The condensate-bearing 11,100-ft Nodosaria Blanpiedi No. 1 sand at Northwest Branch Unit represents a productive reservoir geologically classified as closure by faulting. As illustrated in the structural interpretation (Fig. 1) the productive reservoir is bounded by faults on four sides with a limited aquifer on the structural flank.
Preliminary Report on Fracturing by Vibration - A New Method of Well Stimulation
Authors: Metzger Herbert A. 
Published: December 2007

Abstract
Vibration fracturing is a new method of well stimulation which may be used in either cased or uncased wells. In a cased well, the interval to be fractured is prepared by perforating the interval with a special-type vibro perforator. A specially designed explosive charge is run on a wire line and activated under a fluid column. The charge is designed to fracture the formation horizontally or weaken it so that it will take normal sand fracturing or acidizing at lower pressures. This fracturing is accomplished by setting up a large number of impulses or vibrating pressure waves along a horizontal plane. This preliminary report is designed to give the results of the use of this new method of well stimulation in various types of formation in the Texas and Mid-Continent area, and covers the time interval from February through June, 1958.

Introduction
The new fracturing technique was offered commercially in Feb., 1958. Prior to this time it had been under intensive development and field testing for nearly two years. During that period the equipment and techniques were successfully demonstrated numerous times. Since Feb., 1958, more than 300 wells have been treated with this process. The difficulties which have arisen have resulted in modifications which give every indication of solving the indicated problems. The fracturing by vibration process was developed to provide a fast, economical method of stimulating formations of low permeability, or with permeability blocks.

Description of Equipment
The complete assembly (see Fig. 1) consists of the standard electrical conductor wire line, measuring equipment, cable head, collar locator and sinker bar (where required). The special equipment used in the process includes the vibro perforator, a specially designed gun used to shoot a 1.5-in. disintegrating projectile. The 1.5-in. hole is usually shot in the center of the zone to be fractured by vibration.
The Mechanics of Sand Movement in Fracturing
Authors: Kern L.R. , Perkins T.K. , Wyant R.E. 
Published: December 2007

Introduction
Many factors influence the results of hydraulic fracturing to stimulate well productivity. Most of these factors have been studied and their effects discussed in the literature. However, the movement of sand through the crack during fracturing has received little consideration. Exactly where the sand goes in the fracture, how it gets there, and how this might influence results have not been studied, judging from published reports.
To get an answer to some of these questions we have studied sand movement through a simulated crack segment in the laboratory. Although the work is preliminary, we have answered some questions about sand movement in a semiquantitative sense. We are reporting our results at this time in the hope of stimulating interest and further study in this important aspect of fracturing.

Laboratory Experiments
Fig. 1 is a schematic diagram of equipment used in this study. A segment of a vertical crack 0.25-in. wide was formed between two Plexiglas plates, and movement of sand in fluid through the crack was observed under various conditions.
Sand and fluid were injected into the crack at constant rates. The top and bottom of the crack were closed so that the fluid flowed horizontally. Because of gravity most of the sand settled to the bottom before moving very far through the crack. If the fluid velocity exceeded a certain critical value, then all the sand injected was washed on through the crack even though it had settled to the bottom.
When the fluid velocity was less than this value when sand injection was started, most of the sand which settled in the crack remained in place until enough of the area open to fluid flow was blocked by the settled sand to increase the fluid velocity to the critical value. At this point all injected sand moved on through the crack even though it settled to the lower portion of the moving fluid section. All sand previously settled remained in place.
The Effect of Formation Flow on the Integrity of Perforated Casing
Authors: Pattillo Phillip D. , Smith Michael B. 
Published: December 2007

Abstract
This paper summarizes an analysis of formation/casing deformations in a chalk reservoir. The study is linked to the development of a poroelastic-plastic model of ductile rocks. Applications of the model include an analysis of chalk production into perforated casing and a discussion of the effects of such production on collapse integrity of the casing.
A Comparison of Theoretical Pressure Build-Up Curves with Field Curves Obtained from Bottom-Hole Shut-In Tests
Authors: Pitzer Sidney C. , Rice John D. , Thomas Clifford E. 
Published: December 2007

Abstract
Interpretation of pressure build-up data obtained in the conventional manner has often been difficult because of the deviation from theoretical behavior. Major causes of this deviation have been attributed to damage and afterflow, and to fluid redistribution in the wellbore which, in extreme cases, can result in a pressure hump in the early portion of the build-up curve.
Theoretical investigations show that bottomhole pressure is definitely influenced by phase redistribution in the tubing column during surface shut-in tests, and that the magnitude of the effect is sensitive to the producing gas-oil ratio and stabilized rate of flow in the well.
For field experiments a wire-line tubing packer, which can be run in the tubing against a stabilized flow rate, was developed for bottom-hole shut-in tests. By use of this bottom-hole shut-in method, pressure humps previously observed in surface shut-in tests were completely eliminated and the effects of afterflow minimized.
Analog and digital computer studies have been made to obtain theoretical curves for comparison with field curves, and remarkable agreement between the results of bottom-hole shut-in tests and theoretical curves has been obtained.

Introduction
Pressure build-up data from shut-in wells have been used by the petroleum industry to determine the permeability of the formation, to estimate wellbore damage, to evaluate the static reservoir pressure and to speculate reservoir volume. Calculation of these factors is based on methods of analysis developed for theoretical systems whose build-up curves have a characteristic shape when the wells are shut-in at the sand face. However, field curves obtained by conventional surface shut-in methods do not always exhibit this characteristic. Such factors as stratification, rock heterogeneities and irregular reservoir geometry can cause the character of a buildup curve to deviate from that predicted by theory for a simple system. In addition, all field build-up data are affected by the methods utilized in obtaining the measurements.
Effect of C7+ Properties on Equation-of-State Predictions
Authors: Whitson Curtis H. 
Published: December 2007

Abstract
This work studies the effect of heptanes-plus (C7+) characterization on equation-of-state (EOS) predictions. Both the Peng-Robinson EOS (PREOS) and a modified Redlich-Kwong EOS are used. Several characterization schemes found in the literature are used in the study. Six reservoir fluids with extended C7+ analysis have been chosen, representing a broad range of compositions and PVT data.
First, the study deals with methods for estimating specific gravities and boiling points of petroleum fractions, two properties usually required by critical property correlations. EOS predictions arc made by using critical properties based on specific gravities and boiling points measured experimentally and estimated with correlations.
Next, a review of critical-property correlations is given, including a review of commonly used correlations. Four correlations are chosen to study the effect of critical properties on EOS predictions. Results indicate that relatively small differences in critical properties and acentric factor can result in significant differences in EOS predictions.
Finally, a study is made of the effect that adjustments in C7+ critical properties Have on EOS predictions; adjustments of EOS constants (Ωa and Ωb) and binary interaction coefficients also are studied. The influence of individual and combined adjustments to C7+ properties are illustrated graphically. They provide qualitative guidelines that can be used when matching experimental PVT data with an EOS.
Case Histories Show Value of Corrosion Inhibitor Squeeze Treatment
Authors: Poetker Rupert H. 
Published: December 2007

Introduction
The inefficiency of batch treatment down the annulus to prevent corrosion in gas-lift wells led to a search for a better method. Squeezing inhibitor into the formation was attempted and appeared to be an improvement over other methods of treatment. With these other methods it was difficult to get the chemical where it was needed because a high fluid leg would cause a major portion of the chemical to enter the tubing string at the working valve, which was too high to give complete protection.
A low fluid leg would cause the chemical to dehydrate and leave a gummy substance on the outside of the tubing and on the inside of the casing. This tendency could be partially overcome by using large amounts of diluent (5 to 10 bbl) with the chemical, but such treatment was time-consuming and expensive. Sticks and pellets were tried with poor results.

Theory of Squeeze
It was found that some inhibitors would adsorb to sand rapidly and would desorb slowly. Laboratory work indicated that this adsorption-desorption rate was sufficient to warrant field testing. The high chemical concentration (11,000 to 1 million ppm) in contact with the steel during the squeeze is also a factor. Limited field tests to evaluate these two factors have been performed, but are inconclusive.

Squeeze Treatment
Since Nov. 1954, 60 wells have been squeeze-treated with a total of 160 squeezes. These 60 wells are located in 10 different fields and produce from 19 separate reservoirs. They vary in depth from 3,000 to 12,000 ft. Of the 60 wells, four are natural flowing wells, 47 are gas-lift wells, eight are gas condensate wells, and one is a pumping well. From the information available, it appears that about 150 wells have received this inhibitor squeeze-type treatment. Approximately 350 separate squeeze treatments have been done in these 150 wells. A breakdown of these 150 wells as to method of production is as follows: gas-lift, 85; natural flow, 15; pumping, 20; and gas condensate, 30. Production from these wells, located in Texas, Louisiana and Arkansas, is both sweet and sour. Some are producing from sand and some from lime-stone formations.
Control of Injection Gas Composition in Enriched Gas-Drive Projects
Authors: Elliott J. Kelly , Johnson Harry C. 
Published: December 2007

Introduction
One of the primary requirements for successful operation of an enriched gas-drive project is to control the composition of injection gas. This can become a serious and difficult problem, particularly in cases where the enrichment material is being furnished from a number of field-produced gas streams. It is possible to effect control of the injection gas composition through frequent or continuous sampling; however, this can be extremely costly and, in many cases, impractical due to laboratory requirements of time. Another alternative would be to provide a calculation technique which would be flexible and sufficiently accurate to predict composition of the liquid and gas streams of interest at any point in the system. The purpose of this paper is to discuss a technique that was used successfully on an operating enriched gas-drive project for developing information which could be used for controlling composition of the injected gas.

Field Operations
The particular field (hereafter called Example field) in the example operation being discussed is composed of four oil reservoirs (A, B, C and E) and one gas condensate reservoir (D). Casinghead gas from the oil reservoirs and gas from the gas condensate reservoir are gathered through a field gathering system as shown in Fig. 1 for injection into Reservoir C. The gas mixture which is recovered from the five reservoirs for injection purposes is composed of gases liberated in 19 individual separators, each operating at a separate temperature and pressure.

Proposed Calculation Technique
It is well known that vapor-liquid equilibrium calculations in general use throughout the petroleum industry can be used to predict reliably the phase behavior of hydrocarbon mixtures, particularly at pressures less than 1,000 psig. It is then a simple matter to account for the material on a component basis by making flash and material balance calculations at each separation point in a hydrocarbon system. Accordingly, it was proposed to use vapor-liquid equilibrium and material balance calculations with a medium-sized electronic digital computer as a basis for developing a control procedure for use in controlling injection gas composition in the enriched gas-drive project.
Application of a Reservoir Simulator Interfaced With a Surface Facility Network: A Case History
Authors: Breaux E. J. , Monroe S. A. , Blank L. S. , Yarberry D. W. , Al-Umran S. A. 
Published: December 2007

Summary
Management requires dependable information upon which to base decisions regarding large investments. The system discussed in this paper proves to be a viable tool for effectively managing reservoir development and provides several alternatives upon which management could base such decisions.
A three-dimensional (3D), three-phase reservoir simulator is interfaced with a surface facility network simulator. The results are used in determining an integrated field development and operating plan for producing an onshore-offshore oil reservoir at a specified rate. Various aspects of alternative development and facility installation scenarios are investigated with the interfaced system. The requirements and sizing of major surface facilities and a drilling and workover program are determined over a 25-year study period. The most efficient development plan is one that combines cost-effective drilling and facilities scheduling while at the same time providing maximum operating flexibility and balanced reservoir development.
This technique has been applied to the future development planning of existing fields but is equally applicable to planning the development of new fields in any environment by altering the producing rules controls and reservoir and network models to account for the appropriate circumstances.