bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Fracturing - A Method of Oil Recovery From Extremely Low Permeability Formations
Authors: Wilsey L.E. , Bearden W.G. 
Published: December 2007

Abstract
This paper presents results of analysis of the effect of fracturing on initial flow rates and on ultimate recoveries from low capacity oil formations. This analysis shows that even in formations of permeability as low as 0.1 md, large fracture treatments can yield oil recoveries and production rates approaching those of high permeability formations. Field production information is shown which supports the analytical work.

Introduction
Often hydrocarbon bearing formations are discovered which, while they are known to contain large quantities of oil, will not produce at commercially attractive rates without special well stimulation. Attempts to solve this problem led to the development of such techniques as underreaming, shooting, acidizing, and recently hydraulic fracturing. These methods of stimulation have been highly successful in many fields. All of these treatments, however, affect only the pay section near the well bore and therefore owe their success to circumventing and overcoming local permeability reduction about the well bore.
It has been the belief that in treating wells to stimulate production in which there is no permeability reduction near the well, the maximum possible production rate increase would be of the order of two or fourfold. Hence, it has been concluded that fracture treatment of uniformly low capacity (permeability times thickness) formations could meet with but limited success.
It is the purpose of this paper to show that the use of fracture treatments much larger than usually used can yield commercially attractive producing rates and high recoveries even in formations of permeability less than 0.1 of a md.

Procedure
In order to illustrate the effects of fracturing, an analytical study of some hypothetical systems was made in which one factor at a time was varied to show what is important in recovering oil from fractured wells.
Clarifying Oilfield and Refinery Waste Waters by Gas Flotation
Authors: Ellis M.M. , Fischer P.W. 
Published: December 2007

Gas flotation is a method of removing residual oil and suspended solids from oilfield and refinery waste waters. Because the system has a history of generally effective performance and because the equipment involved requires little space, it appears that flotation could be a desirable way of handling some very big problems.

Introduction
For more than 20 years the Union Oil Co. of California has used gas flotation as an effective means of removing residual oil and solids from many waste waters before disposing of them. Proper selection of equipment, flotation gas, demulsifiers, coagulants, and other factors makes it possible to tailor the flotation process for optimum treatment of most waste waters. Relatively small space requirements and minimum retention times are important - sometimes essential - features of gas flotation equipment.
Increasingly stringent waste-disposal requirements dictate a new look at the advantages and practical limitations of this method.
Waste waters can be clarified in many ways, each method having its own advantages and limitations. Surge vessels, skim ponds, API separators, and lagoons are adequate if the oil is not emulsified, if few entrained solids are present, and if there is adequate space or retention time. Coalescing filters can often improve the performance of these simple systems by helping to break emulsions and by trapping oily solids and slimes. Often, chemical demulsifiers or coagulants are also effective. Combinations of these systems have been used for many years with varying degrees of success. For example, a random sampling of coalescing tanks produced the varying results shown in Table 1. The quality of treated waters depends less on coalescer capacity and throughput than upon the presence of emulsions and the type of solids in the water.
However, there are many locations where adequate space is not available for conventional equipment, and others where clarification must exceed the levels obtainable by the older methods. In these locations, gas flotation should be considered.
Principle of Flotation Principle of Flotation Gas flotation speeds tip the gravity separation of oil droplets and dispersed solids from waste water. According to Stokes' law, the vertical movement of a particle through a fluid is expressed as particle through a fluid is expressed as
where
V = rate of rise or fall of the particleg = gravity constantpf = density of the fluidpp = density of the particleD = deiameter of the particlemu = viscosity of the fluid
Gas flotation modifies two of the variables listed above: particle density and particle diameter.
JPT
P. 426
The Role of Gravity in Capillary Pressure Measurements
Authors: Szabo Miklos T. 
Published: December 2007

Abstract
This paper shows on a theoretical basis how saturation profiles are influenced by gravity during the measurement of profiles are influenced by gravity during the measurement of capillary pressures in porous samples. A precise method is suggested for calculating the realistic capillary pressure curves from the data obtained in either the "diaphragm" or the "gravity drainage of long vertical core" method. A capillary pressure curve, free of the influence of gravity, can be determined by the equations developed in this paper from measurement of the pressures applied in the nonwetting phase and from the average saturations corresponding to capillary equilibria. The same equations may also be used for the evaluation of centrifuge data, provided the increase in capillary pressures is achieved by gradual lengthening of end-effect absorbers set up under the test sample, using the same constant speed of rotation at each run.

Introduction
The disc method is usually referred to in the technical literature as a standard method for determining capillary pressure curves. This study shows that using this method a certain pressure curves. This study shows that using this method a certain saturation distribution can be observed in the samples when the viscous fluid flow has ceased. The description of this phenomenon led to equations that offer a more precise formulation of the results obtained by the disc method. In addition, this formulation simplifies the "gravity drainage of long vertical cores" method because it is now sufficient merely to determine average saturations. Thus, it is unnecessary to determine saturations by electric methods or by the weighing of sectors of the drainage column.
Solubility of Sulfur in Hydrogen Sulfide and in Carbon Disulfide at Elevated Temperature and Pressure
Authors: Roof Jack G. 
Published: December 2007

Abstract
The solubility of sulfur in hydrogen sulfide has been determined by an absolute method at 21 combinations of pressure and temperature within the range of 1,020 to 4,520 psia and 110 deg. to 230 deg. F. respectively. Results, which appear to be consistent within about 2 percent, show the solubility to increase with pressure along an isotherm but to pass through maxima along isobars. Where direct comparison can be made, our values differ drastically from published results at lower pressures and are in serious disagreement at higher pressures.
The solubility of sulfur in carbon disulfide is reported for pressures from 1,020 to 5,020 psia at 150 deg. F. No published data were found for direct comparison. Both the solubility of sulfur and the density of saturated solutions decrease with increasing pressure at this temperature.

Introduction
Difficulties in production arise when a fluid containing a high content of hydrogen sulfide occurs in a reservoir in which elemental sulfur is present Changes in pressure and temperature present Changes in pressure and temperature can cause deposition of dissolved sulfur from hydrogen sulfide-rich fluids in both the formation and the production tubing. The first step in a study of this problem is to determine the solubility of sulfur in pure hydrogen sulfide under conditions of interest in production. This report presents results of one such study. Values published in the literature generally appear to be grossly in error.
In some approaches to repairing the damage caused by sulfur plugging of formation and tubing, carbon disulfide is used as a solvent. Experiments were run at a typical temperature of 150 deg. F and elevated pressure to obtain basic data on the solubility of sulfur in carbon disulfide.
Conditioning of Water by Removal of Corrosive Gases
Authors: Weeter R.F. 
Published: December 2007

The general conclusion is that the removal of oxygen from injection water is usually worthwhile, but the removal of hydrogen sulfide is much more expensive and more difficult to justify. Only in isolated instances has it been found necessary to remove carbon dioxide where there is no hydrogen sulfide.

Introduction
During the past 15 years the oil industry has become more and more aware of the importance of corrosive gases in injection water in the economics of secondary recovery of oil.
Experience indicates that removal of hydrogen sulfide to a level of 1 to 2 ppm in the absence of oxygen reduces corrosion to acceptable rates at a neutral pH and that reduction below 1 ppm is possible with existing equipment. If oxygen is reduced to 0.1 ppm in sweet water or brine at a neutral pH, corrosion will be reduced to a negligible rate, but the oxygen must be reduced still more in a system containing small amounts of sulfide. The principal effect of carbon dioxide in water is the reduction in pH, with resultant solubilization of iron. Until recently, however, removal of such gases has not gained the interest of the industry at large. Several successful operations followed by published papers have aroused interest to the extent that a review of the means available appears to be in order.

Discussion

Oxygen Removal
For many years corrosion due to oxygen in water has been accepted as a necessary evil. It was thought that the water itself was the corrosive medium; therefore, subsurface water was permitted to come in contact with air as it was pumped to the surface and stored in open tanks.
With present knowledge, the prudent operator cements his water-supply well to the surface, seals the wellhead and tests to determine whether dissolved oxygen is native to the water. If it is not, and if oxygen-free natural gas is available, a gas blanket is placed on supply wells and tanks. Often this is the only action necessary.
If there is dissolved oxygen native to the water, however, some other action must be taken for the following reasons.Pitting-type corrosion, typical of an aerated system, can cause failures even in a fresh-water system and much more rapidly in a brine system.Iron oxides and hydroxides are serious plugging agents that will increase injection pressures and decrease injection rates. These compounds may result from corrosion or from a mixing of one water containing oxygen with another containing dissolved iron.Aerobic bacteria, algae, and slime form in the system, create plugging, and enhance pitting.If an oxygen-bearing water is mixed with a hydrogen-sulfide-bearing produced water, free sulfur will be precipitated.
Study of Undersaturation During Repressuring and Supersaturation During Flow of Oil to Wells
Authors: Higgins Ralph V. 
Published: December 2007

Abstract
This paper concerns the magnitude of the amount of supersaturation that occurs in an underground reservoir during the flow of oil and gas to wells and to the amount of undersaturation that occurs during repressuring of an oil reservoir where some effective permeability to gas exists.
The study is based on earlier laboratory findings of other investigators on the rate of diffusion of gas in oil as a function of the depth of oil. Utilizing these relationships and the principles of reservoir mechanics, a quantitative estimate of undersaturation and supersaturation was calculated. The results showed that the diffusion of the gas is rapid enough that for all practical purposes no supersaturation exists during the flow of oil to wells or undersaturation during repressuring in reservoir sands having some effective permeability to gas.
The reason diffusion of the gas virtually keeps the oil saturated is the long time required in radial flow for oil to reach the well and the slow rate at which pressure in reservoirs is increased during repressuring.

Introduction
Knowledge of the phase relationships during flow of gas and oil in an underground reservoir is essential to operating the reservoir in the most efficient manner. In material-balance calculations and in fluid-flow studies, the oil is assumed to contain all the gas that it will dissolve at given temperature and pressure. Pressure-volume-temperature relationships are normally obtained in the laboratory using "bottom-hole" or combined samples of the reservoir fluids. In such laboratory determinations equilibrium is obtained between the oil and gas in the pressure cells by mechanical agitation. During the flow of oil and gas in reservoirs, however, no comparable agitation occurs to mix thoroughly these fluids to aid in effecting equilibrium between the two phases.
Chemical Enhancement of the Biodegradation of Crude-Oil Pollutants
Authors: Robichaux T.J. , Myrick Nugent H. 
Published: December 2007

These test results establish two important processes for dealing with oil in an aquatic environment. First, the rate of biological destruction of hydrocarbon can be increased by emulsifying the oil with a suitable chemical agent. Secondly, biological destruction can be further accelerated by seeding the emulsion with microorganisms that can use hydrocarbon as a food source.

Introduction
This study was conducted to determine the effects of chemical dispersants on the microbial decomposition of crude oil in aquatic environments. Lin and Townsley reported that lignosulfates increase the rate of fermentation of hydrocarbons in water. They attributed the increased rate to the large surface area and to the efficiency of cell-to-oil contact provided by the emulsifier. Not all dispersing agents promote bacterial growth. Some agents are quite toxic and will retard the rate of oil decomposition. Other agents form loose, unstable emulsions and have little effect on the reaction.
Biological oxidation of any organic matter is basically the utilization of the substance as a food source. The organic matter is synthesized by bacterial oxidation to new cells and converted to energy and metabolism end products such as CO2 and water. The growth of the microorganism is dependent upon the individual metabolic requirements of the organism, the chemical nature of the organic matter and the physicochemical environment. The growth process is physicochemical environment. The growth process is related to surface area, as the interfacial area increases, the growth rate increases. Thus dispersing oil through a water phase increases both the availability of the organic matter and the surface area. The rate of microbial utilization should also increase.
The response of microorganisms to dosage with anionic or nonionic surfactants is highly variable. The structure of the surfactant molecule, its concentration, and the type of solvent used as a carrier influence the toxicity to microorganisms. The surfactants, by their effects on cell membranes, have a marked influence on the uptake of other chemical substances.

Experimental Data
In the laboratory work for this study, a preliminary evaluation was made to select a suitable method for observing the effects of several chemical formulations on microbial activity in a water-and-oil environment Methods for following oxygen uptake were compared and the Warburg technique was chosen. This technique, using 125-ml reaction flasks and aqueous manometers, provided the required sensitivity and allowed the samples to be large enough to he prepared accurately. prepared accurately. A sample of crude petroleum was used as a "standard" oil throughout the work. The standard was a sweet, paraffin-base oil, weathered to approximate oil stored for several days at atmospheric pressure and ambient temperature. The sample was stored for the duration of the investigation under conditions that prevented further change in composition.
Both fresh- and sea-water conditions were studied.
JPT
P. 16
Development of a Sea-Ice Penetrometer
Authors: McIntosh J.A. , Young Wayne C. , Welsh J.P. 
Published: December 2007

Introduction
For the past several years the U. S. Coast Guard has pursued a research and development program intended pursued a research and development program intended to lead to the ability to reconnoiter large expanses of sea ice by fixed-wing aircraft without hindrance by weather or darkness. This capability is necessary if our country is to exploit the natural resources of our northern regions. A key requirement for our reconnaissance capability is the ability to measure the thickness of the sea ice from the air, since the thickness is a major determinant of its trafficability.
Sea ice is a complex medium that is virtually impossible to duplicate in the laboratory. In addition, its properties conspire to frustrate most techniques for the remote measurement of its thickness. Numerous techniques have been investigated for remotely measuring sea-ice thickness, most without success. Sonic sounding has been tried by numerous investigators, but the high signal attenuation, poor signal-to-noise ratio, and indistinct ice-water boundary has defeated almost all experiments of which we are aware. Likewise, most methods involving electromagnetic radiation have been unsuccessful, although one or two ideas have begun to show some promise. (It should be pointed out that fresh ice, such as forms on the Great Lakes, while possessing certain complexities of its own, is more amenable to remote measurement than sea ice.)
Considering the above, the Coast Guard's Office of Research and Development decided to fund the development of some approach radically different from the sonic and electromagnetic techniques we have mentioned.
Since drilling is the only technique for measuring the thickness of sea ice that is accepted without reservation by the community, the first thought was "lets drop something on the ice, have it drill a hole, measure the thickness, and radio it up to us in the aircraft."
JPT
P. 249
Gas Well Stimulation with a Viscous Water-Base Fracturing Fluid
Authors: Seidel W.R. , Stahl E.J. 
Published: December 2007

Field experience with high-viscosity fracturing fluids shows that they are highly effective, particularly in stimulating wells with bottom-hole temperatures of 200 degrees to 400 degrees F. The propped-fracture length and fracture conductivity are greater than with low-viscosity fluids; consequently, productivity is greater. Also, abandonment pressures can be lowered, which means additional reserves.

Introduction
A viscous, water-base, non-Newtonian fracturing fluid has been used successfully to stimulate seven Wilcox (Upper Eocene) and two Vicksburg (Lower Oligocene) gas wells. The bottom-hole temperatures of the completions ranged from 240 degrees to 330 degrees F. The average gas production increase was 2.8 MMcf/D, compared with 0.7 MMcf/D for treatments performed on similar wells treated with low-viscosity performed on similar wells treated with low-viscosity fluids.
The principal application of this high-viscosity fluid is in the stimulation of reservoirs with bottom-hole temperatures ranging from 200 degrees to 400 degrees F. Use of the fluid results in wider fractures, placement of proppant at higher concentrations, and better proppant distribution than is achieved with low-viscosity fluids. The improvement in response has been attributed to greater fracture conductivity and greater propped-fracture length.

Treatment Results
The total daily production of nine wells treated with the viscous fluid was increased from 16.6 to 40.6 MMcf, with the average Q/Qo being 3.2. (Q/Qo is the ratio of production rates after fracturing to production rates before treating.) In determining Q/Qo, increased tubing pressure and tubular friction were neglected. Depths of the completion intervals ranged from 8,000 to 12,000 ft. All of the treatments were performed on wells that were greater than 50 percent pressure depleted. Calculated closure stresses on the propped fractures ranged from 5,000 to 9,000 psi. Other pertinent well and treatment data are given in Table 1. pertinent well and treatment data are given in Table 1. Stimulation results previously obtained on comparable completions using low-viscosity fluids had been discouraging. Data on five such treatments performed on Wilcox gas wells are presented in Table 2. In the table below the average well data and results of these stimulations are compared with results of seven treatments on Wilcox completions using the viscous fluid.
High-Viscosity Low-ViscosityFluid (7 wells) Fluids (5 wells) Net pay, ft 49 38 Bottom-holePressure, psi 1,390 1,550 Original bottom-holepressure, psi 3,900 3,900 Average productionincrease, MMcf/D 2.8 0.7 Average Q/Qo 3.6 2.2 Profitable operations 7 2 Profitable operations 7 2 Uneconomicaloperations 0 3
Stimulation treatments using the high-viscosity fluid have yielded greater response under similar well conditions than have treatments with low-viscosity fluids. Improved stimulation response is attributed to longer propped fractures and higher fracture conductivity than could be obtained with low-viscosity fluids.
JPT
P. 1385
Measuring the Quality of a Reservoir Management Program
Authors: Holstein E. D. , Berger A. R. 
Published: December 2007

Abstract
Good reservoir management is key to successful exploitation of hydrocarbon resources. Sustaining quality reservoir management programs can be a challenge in view of cross functional, cross group requirements plus personnel and priority changes. Reservoir management processes have been defined and a set of questionnaires has been designed to comprehensively review reservoir management practices, assess its strengths, identify areas for improvement, and provide a method to measure improvements over time.
SACROC Unit CO2 Flood: Multidisciplinary Team Improves Reservoir Management and Decreases Operating Costs
Authors: Hawkins J. T. , Benvegnu A. J. , Wingate T. P. , McKamie J. D. , Pickard C. D. , Altum J. T. 
Published: December 2007

AbstractIn 1992, the economic viability of the SACROC Unit was somewhat uncertain. At that time, a multidisciplinary team was formed to improve operational efficiencies and reservoir performance. Better understanding of reservoir geology from detailed biostratigraphic analysis provided the framework to make effective changes. This paper discusses operational efficiency and reservoir exploitation projects implemented by the team.
Characterization of Mixed-Wettability States in Oil Reservoirs by Atomic Force Microscopy
Authors: Basu Subhayu , Sharma Mukul M. 
Published: December 2007

Summary
A new technique is described for directly measuring the capillary pressure required to rupture brine films on mineral surfaces. These measurements provide direct evidence for the creation of mixed-wettability states in oil reservoirs. In addition, the measurement of the critical disjoining pressure allows us to observe systematic variations in wettability as the capillary pressure is increased. The effect of brine salinity, pH, surface charge, and surface curvature have been quantified. Results for two reservoirs, one from Texas (Moutray) and another from Alaska (Prudhoe Bay), are presented.