bluuebunny/crossref_metadata_2025_split huggingface dataset:
Miscible Drive - Its Theory and Application
Authors: Clark Norman J. , Shearin H.M. , Schultz W.P. , Garms Kenneth , Moore J.L. 
Published: December 2007

Abstract
Petroleum industry research organizations have for a number of years placed considerable emphasis on investigations regarding various techniques of recovering more oil from reservoirs. Out of this effort has emerged the miscible-drive process which to date shows great promise for future oil recovery operations. The process can actually be subdivided into several kinds of operations; however, the basic principle of all is that hydrocarbon materials such as propane, LPG, or gas are injected into a reservoir under such conditions that fluid capillary forces are reduced to zero and resultant displacement of oil is essentially complete in those pore spaces through which injected materials move. Consideration is given in this technique to subsequent recovery of valuable injected materials and to leaving the reservoir essentially filled with dry gas at abandonment. Success in application of these techniques will depend almost entirely on proper engineering and geological evaluation. The engineer must not only understand the basic principles involved in miscible-drive techniques, but also must recognize where various techniques are applicable and be able to cope with the many factors that require careful consideration to assure proper design and conduct of complicated operations such as these. This paper discusses the various miscible-drive techniques, their place in present day oil and gas operations, factors that require detailed consideration in determining their applicability and feasibility with regard to given reservoirs, and the approach to the application of these techniques to production operations.

Introduction
It has been recognized for a number of years that oil does not produce itself, but instead requires energy from some other source to cause the movement of oil to the wellbore where it is produced. The type and availability of energy will to a great degree determine the general magnitude of the percentage of the initial oil that can be produced through means inherent in the reservoir producing mechanism itself. Depending upon the source of energy, only a small or a large percentage of the oil may be produced. Average recovery expectancy of oil from all reservoirs in the U. S. by primary means has been placed in the order of about 35 per cent of initial oil in place. An enormous amount of oil is thus left in the reservoirs awaiting only the development of new methods of extraction before the petroleum industry can realize the recovery of a part of this residual oil left underground.
Miscible Drive Field Applications in the Seeligson Field
Authors: Wright H.T. , Die R.R. 
Published: December 2007

Introduction
Substantial research has been devoted to the possibilities of greatly increasing oil recovery by injecting into reservoirs a gas known to be soluble in the crude. Various requirements, advantages, and disadvantages of such a displacement have been theorized or indicated by laboratory work. In the final analysis, however, extensive field data are required to evaluate satisfactorily the requirements and merits of a recovery mechanism. In this connection an experimental enriched gas-drive pilot project of full reservoir size was initiated in Zone 20-B of the Seeligson field during March, 1957.
The Zone 20-B reservoir was selected as an injection project for several reasons. A supply of propane for enriching the gas was available from two gasoline plants in the immediate area. Unitization was not required because the zone has only one operator and one royalty interest. The reservoir has a reasonable configuration, the sand is comparatively uniform, and development is adequate. Another major reason for selecting Zone 20-B is that the saturated crude from this reservoir is similar to substantial reserves in the immediate area so that the data obtained will be useful in the evaluation of other projects.

Geologic and Reservoir Data
The Seeligson field is located in Jim Wells and Kleberg counties of Southwest Texas. The field is on a large anticlinal structure and contains numerous productive sands varying from 4,500 to 7,500 ft in depth in the Frio and Vicksburg formations. Zone 20-B, the reservoir selected for enriched gas injection, is a sand development lying at a depth of 6,000 ft in the basal portion of the Frio formation. Fig. 1, a cross section through three wells in the field, illustrates Zone 20-B and other sand sections. The reservoir has an average sand thickness of 14 ft and a productive area of 585 acres.
Miscible Drive Field Applications in the Parks Field
Authors: Marrs Doyle G. 
Published: December 2007

Introduction
A review of the field-wide miscible displacement program being utilized in the Parks field unit is presented to assist others in the oil industry in evaluating the application of the miscible displacement process.

Geological Description
The structure is a long, gently sloping, deep-seated anticline trending north and south. The anticline is traversed, in a northwest-southeast direction, by a major fault which has divided the structure into two segments. This discussion is confined to the larger east segment. No significant oil accumulation was found on the west side of the fault. The productive area on the east side of the fault has an average net pay thickness of 21 ft (see Fig. 1). The Bend section of the Pennsylvanian formation in the Parks area is composed of tan, finely crystalline limestone, interspersed throughout with shale stringers varying from mere shale partings to shale beds several feet in thickness. Porosity of the Bend limestone is described as fossiliferous, with voids having been created as the result of leaching of microfossil shells. Intercrystalline porosity is negligible.

Production History and Data
The primary producing mechanism was solution gas drive. Cumulative production to Jan. 1, 1958, was 3.5 million bbl of oil, 21,000 MMcf of gas, and 35,000 bbl of water. The bottom-hole pressure declined from an original 4,567 to 1,760 psig in July, 1957, and the produced gas-oil ratio increased from 1,800 to 16,000 cu ft/bbl. Primary production and shrinkage of the reservoir oil has created a present gas saturation of approximately 25 per cent.
The average porosity for the net pay is 6 to 8 per cent; the average interstitial water saturation is 30 to 35 per cent; and the average permeability is 3 md.
The reservoir oil was undersaturated at the original reservoir pressure, 4,567 psig. The bubble point pressure is 3,508 psig. The original dissolved gas-oil ratio was 1,817 cu ft/bbl, and the initial formation volume factor was 2.014 reservoir bbl/STB. The reservoir temperature is 174°F. The oil gravity is 45°API, and the initial reservoir oil viscosity was 0.22 cp.
Miscible Drive Field Applications in the Panhandle Field
Authors: Relph J.L. 
Published: December 2007

Introduction
The Hughey B lease, the north one-half Section 129, Block 3, T&GN RR Survey, Gray County, Tex., is the location of a pilot project of slug LPG injection to improve the existing gas drive. The Hughey B lease is one of the leases in the West Pampa Repressuring Assn. that has been returning produced gas to the Brown Dolomite reservoir since 1946.
The pilot project consists of two input wells that were gas injection wells and the 12 producing wells that are direct or diagonal offsets to the input wells. Table 1 contains information on the pilot area.
The LPG slug was taken from the Cities Service gasoline plant approximately 1 mile west of the Hughey B lease. In the spring of 1957, it was apparent that there would be products produced at the plant in excess of market demand and storage facilities. Plans were made to utilize this otherwise wasted material to test the recovery possibilities of LPG injection in this type reservoir. Laboratory research on samples of LPG and Brown Dolomite crude found no adverse effects on mixing the two liquids. Displacement tests on a core are being run to aid in the operation of the pilot project.

LPG - Gas Injection
It was determined that slug LPG injection would be the most advantageous mechanism and in July, 1957, liquid butane injection started in Hughey B No. 10. LPG injection continued until a slug consisting of 76,076 bbl of butane and 53,074 bbl of propane had been injected.
On Nov. 13, LPG injection ceased in Hughey B No. 10 and gas injection resumed at approximately 500 Mcf/D. LPG injection in Hughey B–23 was started immediately and a volume of 50,412 bbl of butane and 50,433 bbl of propane was injected to Jan. 22, 1958. Gas injection was then resumed and the LPG injection in the pilot area was completed. To April 1, 1958, 230,625 bbl of LPG and 100 MMcf of gas have been injected into the pilot area since project initiation.
The daily production performance from the Hughey B lease has always been erratic and well tests vary considerably. The best method of detecting stimulation of the producing wells in the pilot area has been by fluid-level surveys. Static fluid-level surveys on two producing wells, Hughey B–4, the north offset, and Hughey B–11, the west offset to Hughey B–10, indicated approximately 800 ft more fluid than was present before the project started. Production tests on these wells gave Hughey B–4 82 BOPD, up 71 BOPD from the normal rate, and Hughey B–11, 96 BOPD, up 61 BOPD. Testing continues on the lease and at latest report, three more wells are producing some increased oil. Further testing will show how much these wells are stimulated. Increased oil production to April 1, 1958, is estimated at 8,930 bbl.
The stimulation of producing wells is believed to be justification for assuming that this project will recover oil that would not be produced by continuing the previous recovery mechanism. The volume of this oil cannot be estimated at this time and for this reason, no economic evaluation can be made.
Experience in Gravel Packing Long, Perforated Intervals in Deviated Holes (includes associated papers 12886 and 13309 )
Authors: van Ballegooyen J. , Giap Kiat Tan , Seng Kong Tan 
Published: December 2007

Summary
This paper presents the philosophy, criteria, and technique used in arriving at the gravel-packing method for Sabah Shell Petroleum Co. Ltd. 's(SSPC's) operations. It also analyzes and discusses problems and efforts to resolve them with the aid of an evaluation tool.

Introduction
All the gravel-packing operations were done in the South Furious field completions. The field is located offshore northwest Borneo, some 120 miles northeast of Labuan Island. The completion intervals comprise a series of inter bedded sands and shales with porosities between 20 and30% and permeabilities of 100 to 500 md. Hydrocarbon occurrences vary from 1,100 to 7,600 ft subsea (ss). Local experiences pointed out the need to gravel-pack most of the proposed completions. Previous efforts at gravel-packing intervals, typically of less than 50 ft, had been satisfactory. However, premature screen outs were noted in intervals that were initially only some 100 ft long. The difficulties increased with increasing interval length(single gross interval of 653 ft being the longest) and deviation angle(maximum of 52deg.) and also with differences in the permeabilities of the different sand layers. To understand the nature of the problem, a neutron log was used to locate the position ofthe gravel and the presence of voids.
The placement technique was modified by trial and error until an acceptable technique was achieved. This paper discusses the evolution of this technique.

Completion Philosophy
The limited areal extent of the sands, which stacked to form very long hydrocarbon columns, resulted incompletions across large groups of sands having common pressure regimes. Two-phase vertical-flow calculations indicated optimal tubing size to be 3 1/2 in. We set 9 5/8-in. casing across completion intervals with 4 1/2- and 6 1/8-in. wire-wrapped screens(WWS) across bottom and subsequent intervals. The coupling of the 3 1/2-in. tubing restrictedthe use of the 4 1/2-in. screen to the bottom interval. The internal gravel-pack technique was preferred over under reamed gravel pack because of greater flexibility, satisfactory in flow performance (local experience), and shorter installation time. To alleviate the need for future recompletions and high work over costs. all possible oil sands were included in the initial completion. To ensure seal integrity and minimize complexity, there was a maximum of only four zones per well.

Sand Failure Criteria
Experience in northwest Borneo indicated that sand control is required for zones with sonic transit times At &gt;90usec/ft. In South Furious field, this was placed at+5,000 ft ss.
JPT
P. 2079^
Drainage of Aqueous Foams: Generation-Pressure and Cell-Size Effects
Authors: Rand Peter B. , Kraynik Andrew M. 
Published: December 2007

Abstract
The physical characteristics of aqueous foams make them excellent candidates for drilling fluids in geothermal formations.1,2 A major concern in this application is the foam-forming ability of a surfactant system in the harsh geothermal environment. While investigating the stability of various foams in an autoclave, we observed a dramatic increase in drainage times with increasing generation pressure, even though the liquid volume fraction of the foam was held constant. This effect appears to result from a decrease in cell size with increasing autoclave pressure and therefore is an artifact of the foam generation technique in which the pressure path of the foam changes with autoclave pressure. A theoretical model of drainage predicts that drainage times should increase with decreasing cell size, as observed. These results emphasize that proper control of cell size can have a substantial effect on the apparent stability of a foam.
Geothermal Reservoir Simulation Using Nonequilibrium Thermodynamics
Authors: Nguyen V. V. , Pinder G. F. 
Published: December 2007

Abstract
A phenomenological interpretation of the evolution of a steam/water system is proposed from a nonequilibrium mixture perspective. This type of thermodynamic behavior is structurally stable on the basis of catastrophe theory and therefore offers an unorthodox alternative approach to the simulation of geothermal reservoirs. Use of this approach in a one-dimensional (ID) finite-difference simulator yields results that can be compared with a traditional numerical scheme.
The Rheological Properties of Prudhoe Bay Oil and the Effects of a Prolonged Flow Interruption on its Flow Behavior
Authors: Economides Michael J. , Chaney George T. 
Published: December 2007

Abstract
The rheological properties of Prudhoe Bay oil, as with any other mixture of hydrocarbons, are markedly affected by the lowering of temperature. The Trans Alaska pipeline traversing the state in a north-south direction is subjected to severe ambient temperatures during the winter months. A prolonged flow interruption would result in inevitable heat losses from the trapped crude oil. The temperature decline would cause a significant alteration of the flow behavior. A fundamental heat-transfer study and laboratory measurements were combined to forecast the rheological response and subsequent start-up requirements of Prudhoe Bay oil in gathering lines and in the Trans Alaska pipeline.
Dielectric Log-A Logging Method for Determining Oil Saturation
Authors: Geng Xiuwen , Yong Yinzu , Lu Da , Zhao Shufang 
Published: December 2007

Summary
This paper presents the principles of dielectric logging by describing measurement of phase shift. laboratory experiments, theoretical calculations for determining the vertical resolution and depth of investigation, and results of application in field practice.

Introduction
Measurement of oil saturation is an important pan of well logging in the development of- an oil field. It is an important basis for evaluating watered-out reservoirs, estimating the residual oil, and redividing and combining the productive zones. In the development of an oil field by water injection, the salinity of injected water always differs greatly from that of original formation water. For example, the salinity of original formation water in Daqing oil field is about 6,000 to 8,000 ppm, and the salinity of the injected water is as low as 500 to 800 ppm. Thus, the formation water gradually becomes less saline as the amount of injected water is increased. However, the resistivity log and the Neutron Lifetime Log- cannot be used to measure oil saturation in such strata. To solve this problem, it is necessary to introduce other logging methods for measuring oil saturation that are less influenced by the salinity of formation water. Dielectric constant logging is one method to solve this problem and has been described in U. S. and Soviet literature.
In the late 1960's, the study of dielectrologs was launched in Daqing oil field. Both theoretical and experimental studies on dielectrologs were carried out. Since 1974, the dielectrolog tool has been used in the field and has been run in more than 100 downhole operations. Field practice has proved that the accuracy for interpreting water saturation of formation and watered-out zones with dielectrolog is +/-8. 8% and +/-5. 7%, respectively.

Laboratory Experiment For Determining Dielectric Constant of Rocks
The dielectric constants for crude oil and minerals of sedimentary rocks are small (2 to 8), and that for water is very high (80). Therefore, the dielectric constant for water-bearing rocks depends mainly on its water volume. To verify the fundamental principle of this logging method, a laboratory study of main factors affecting the dielectric constant of rocks was performed with core samples from different oil-beefing zones in Daqing oil field. The frequency used here is 60 MHz. Fig. 1 gives the relationship between the dielectric constant and formation water volume of sandstone samples from different regions of Daqing oil field. Air saturation is used instead of oil saturation in these experiments. In Fig. 1 the dielectric constants of rocks correspond very well with the water volume. The dielectric constants of dry samples range from 4 to 7; those of rock matrix, oil, and air are rather small because they depend on shift polarization.
JPT
P. 1797^
A Comparative Study of the Characteristics and Susceptibility of Pattern-Type Water-Injection Well Networks From the Viewpoint of Balanced Waterfloods
Authors: Xian-zhang Tong 
Published: December 2007

Abstract
In"this paper, some standard geometrical flood patterns of "n-spot" are compared with each other on the basis of their respective susceptibility to the balance between total fluid injection and withdrawal rates by use of a basic parameter, Fm− the ratio between the average PI of production wells and the injectivity index of injection wells. The characteristic parameter. Fm, of a reservoir basically is dominated by the reservoir rock and fluid property as well as by completion practices.
Each pattern of well networks deserves preference under certain specific circumstances. All factors other than Fm being equal, the five-spot network offers greater total liquid deliverability when Fm lies within the range 1 to 1.5. When Fm is smaller than 0.5, the inverted nine-spot network begins to show its superiority.
Formulas and graphs showing relationships between n and Fm are presented for comparison and selection of optimal patterns for different circumstances.
A Thermodynamic Model for Low Interfacial Tensions in Alkaline Flooding
Authors: Sharma Mukul M. , Yen T. F. 
Published: December 2007

Abstract
Many experimental studies have been undertaken to measure interfacial tensions (IFT's) as a function of pH, salinity, temperature, and divalent ion concentrations. This behavior varies from one crude oil to another and is critical in determining its suitability as a candidate for caustic flooding.
A model based on a thermodynamic analysis of crude oil/caustic interfaces has been developed that predicts the IFT behavior of such systems. The model accounts for IFT variations with changes in pH, salinity, and temperature by using parameters that must be estimated from a preliminary experimental study. The model predictions compare well with earlier reported experimental results. It is shown that the application of such a model to empirical correlations for residual oil saturations and fractional flow curves enables us to predict the changes in the fractional flow and relative permeability curves for an alkaline flood with self-sharpening fronts if the injection pH and salinity are specified. The basic equations needed to extend this model to account for divalent ions and more complex flow systems are provided in the Appendices.
Stability of Aqueous Wetting Films in Athabasca Tar Sands
Authors: Hall A. C. , Collins S. H. , Melrose J. C. 
Published: December 2007

Abstract
The existence of thin films of water that completely wet the sand grains has long been regarded as an important feature of the Athabasca oil sands deposit. Direct microscopic evidence, however, cannot be relied on to establish whether such films are present, The existence and stability of such films, therefore, must be inferred from the relevant surface chemical forces for the oil/brine/rock system.
A detailed analysis of these forces shows that the stability of these thin wetting films is critically dependent on whether the zeta potentials (and charge densities) for the two electrical double layers bounding the film are of like sign. The zeta potential and charge density for the rock/brine interface will in almost all cases be negative in sign. Therefore, a requirement for the stability of a wetting film will be that these quantities are also negative at the brine/oil interface.
New measurements of the electrophoretic mobility of small particles of Athabasca bitumen suspended in an aqueous phase are reported. These data show that the zeta potential at the bitumen/water interface is strongly negative. Consequently, these results support the hypothesis that wetting films will be stable in this instance.
Effect of Groundwater and pH Modification on Quality of Leachate From Simulated In-Situ Retorted Utah Oil Shale
Authors: Bethea Robert M. , Barber Donald R. , Parker Harry W. , Guven Necip 
Published: December 2007

Abstract
Major variables reported in this study were retorting temperature, retorting atmosphere (inert, air added, air and CO2 added), and groundwater quality (source). All leaching tests were made at atmospheric pressure and most at room temperature. Leaching tests were made with groundwater to observe the ability of spent shale to remove materials from groundwater and the possible ability of those materials to plug the pore structure of the spent shale and to minimize further leaching. The factor having the greatest effect on leachate composition was retort temperature. The presence of CO2 during high-temperature retorting suppressed the amounts of base-forming materials generated. All bâchâtes were affected significantly by the groundwater used for leaching. As expected, more material was leached from the retorted Utah shale when the higher-purity groundwater was used.
The addition of 2% Wyoming bentonite for the purpose of pH modification to the groundwater used for leaching the retorted shale (780 and 1000 °C (1,436 and 1,832 °F) retort atmosphere of air with 15% CO2 added] showed that the bentonite had only a small effect on the leaching of monovalent cations and essentially no effect on the movement of the heavy, hazardous cations. The effect of retorting temperature was mixed with the exception of chromium, which increased four- to fivefold in the leachate.
The permeability of Utah shale was determined by retorting two cores from Rock 2 at 780°C (1,436 l;) for 48 hours in the presence of air alone. The differences in the Final permeability of these cores can be attributed to differences in groundwaters.