bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Investigation of the Water-Driven Carbon Dioxide Process for Oil Recovery
Authors: Beeson D.M. , Ortloff G.D. 
Published: December 2007

Abstract
Water-propelled banks of carbon dioxide recovered both high- and low-viscosity crude oil substantially in excess of that recovered by water flood in linear flow model experiments. The increase in oil recovery is explained by oil swelling and viscosity reduction. Additional oil was recovered by solution gas drive at the end of the carbon dioxide floods when the model systems were depressured.

Introduction
This study was an investigation of the use of a water-driven carbon dioxide bank to recover crude oil. Techniques involving the injection of carbon dioxide have aroused considerable interest in recent years among methods considered for increasing oil recoveries.
A number of investigators have studied the process in the laboratory and in the field. Laboratory studies referenced indicate that carbon dioxide in conjunction with water flooding recovers more oil than does water flooding alone. These reports diverge widely, however, in stating magnitude of improvement.
We believed that a water-driven carbon dioxide bank would increase recovery of crude oils by two mechanisms: viscosity reduction and oil swelling. Due to reduction in the oil viscosity caused by solution of carbon dioxide, displacement efficiency should be improved. In addition, the residual oil should be highly swollen by the carbon dioxide held in solution. Thus, the final residual oil saturation, in terms of stock-tank oil, would be lower than in the absence of carbon dioxide.
To test this hypothesis, experiments were carried out to recover both high- and low-viscosity crude oils from linear laboratory models. Tests reported here were carried out in small-diameter models at low rates of fluid advance, where diffusion is a powerful factor in preventing fingering or channeling. The volumetric sweep efficiency of the injected fluids should, under these conditions, be close to 100 per cent. In a field operation it would be necessary to evaluate stratification effects and to consider areal sweep efficiency.
Results of Mathematical Modeling of Modified In-Situ Oil Shale Retorting
Authors: Braun R. L. , Diaz J. C , Lewis A. E. 
Published: December 2007

Abstract
Lawrence Livermore Natl. Laboratory (LLNL) has developed a one-dimensional (1D) mathematical model to simulate modified in-situ (MIS) retorting of oil shale. In this paper we discuss application of the model to commercial-scale retorting conditions. The model was tested by comparing calculated values to those measured in experimental retort runs performed at LLNL. There was generally good agreement between the calculated and observed results for oil yield, temperature profiles, and the yields of most gas species. Retorting rates were generally overestimated by as much as 10%. The model is a useful tool for design and control of retort operations and to identify and interpret observations that differ from model predictions.
The model was used to predict the results for MIS retorting on a commercial scale, focusing on larger retorts and larger shale particle sizes than could be investigated experimentally. Retort bed properties, particularly shale composition and particle size, play an important role in determining the recoverable fraction of oil. For a given shale composition, the inlet-gas properties can be selected to help control retort operations and to maximize oil yield. Extreme variations in oil shale grade that may be encountered as a function of depth can be dealt with by appropriate changes in the composition and flow rate of the inlet gas. In addition, we show that substituting oxygen diluted with steam or CO2 (for air or air diluted with steam) can make significant improvements in the heating value of the effluent gas. Finally, we demonstrate the feasibility of retorting through a substantial interval of very low-grade shale.
Two-Phase Flow in Random Network Models of Porous Media
Authors: Koplik J. , Lasseter T. J. 
Published: December 2007

Abstract
To explore how the microscopic geometry of a pore space affects the macroscopic characteristics of fluid flow in porous media, we have used approximate solutions of the Navier-Stokes equations to calculate the flow of two fluids in random networks. The model pore space consists of an array of pores of variable radius connected to a random number of nearest neighbors by throats of variable length and radius. The various size and connectedness distributions may be arbitrarily assigned, as are the wetting characteristics of the two fluids in the pore space. The fluids are assumed to be incompressible, immiscible, Newtonian, and of equal viscosity. In the calculation, we use Stokes flow results for the motion of the individual fluids and incorporate microscopic capillary force by using the Washburn approximation. At any time, the problem is mathematically identical to a random electrical network of resistors, batteries, and diodes. From the numerical solution of the latter, we compute the fluid velocities and saturation rates of change and use a discrete timestepping procedure to follow the subsequent motion. The scale of the computation has restricted us so far to networks of hundreds of pores in two dimensions (2D). Within these limitations, we discuss the dependence of residual oil saturations and interface shapes on network geometry and flow conditions.
Mineralogical Characterization of Uranium Ore To Evaluate In-Situ Leaching Prospects
Authors: Tsui T. -F. 
Published: December 2007

Abstract
Mineralogical studies of ore samples from Mobil uranium properties in Grants mineral belt (NM) revealed a correlation between certain mineralogical characteristics of the ore and its leaching behavior in the laboratory. Mild alkaline carbonate solutions containing dissolved oxygen gas or hydrogen peroxide were used to leach ore samples. Leaching effects of the uranium minerals and reactive gangue material were investigated by comparing the mineralogical characteristics between pre- and postleach samples. Analyses were made by using the X-ray diffraction method, petrographic microscopic, and scanning electron microscopic (SEM) examinations. In one ore trend where uraninite was the principal uranium mineral, studies showed that (1) the majority of uranium minerals was readily accessible to the leachate on a microscopic scale, (2) the predominant, 1-micron [1-µm] size uraninite crystals were dissolved rapidly during leaching, (3) the minor but locally abundant uranium vanadate species was insoluble in mild alkaline carbonate leachate, and (4) pyrite crystals, with dimensions 10 times greater than the uraninite crystallites, showed some surface etchings.
These results indicate that the solubility and microscopic occurrence of uraninite are favorable for high and rapid uranium recovery, while the fraction of uranium contained in the insoluble uranium vanadate phase cannot be recovered under mild leaching conditions. The uraninite apparently dissolved at a much faster rate than pyrite, indicating a favorable initial selectivity of leachate for uranium. Mineralogical studies of the pre-and postleach ore samples correlate well with the laboratory leach tests, which showed 80 to 90% uranium recovery as well as low vanadium and sulfate levels in the effluents.
The Mechanics of Design and Interpretation of Hydraulic Fracture Treatments
Authors: Crittendon Bob C. 
Published: December 2007

Introduction
Since formal introduction of hydraulic fracturing to the petroleum industry in 1948, the technique has increased in prominence each year until in many areas it is now the most popular method of well stimulation. In some areas it is the only technique which will effect commercial production; even some limestone formations which refuse to respond to multiple-stage acid treatments will, subsequent to hydraulic fracture treatments, make commercial wells.
Many theories have been expounded to define conditions associated with hydraulic fracturing - some based on unrealistic prototypes and others on mathematical analyses substantiated as far as practical with laboratory experimentation. However, progress made has been mainly not the result of any mathematical or physical definition of the process, but industry's willingness to spend more for larger and higher rate treatments. Service companies have met the demands of the industry for treatments of greater magnitude until in some areas, treatments of from 100,000 to 200,000 gal injected at rates approaching 100 bbl/min are not only common but are performed with minimum difficulty.
The cost of such treatments is of necessity great, and it is imperative that the manpower, equipment and materials be as effectively utilized as is technically possible. The purpose of this paper is not to clarify the turbid waters of fracturing theory, but to present the tools which we had used to make the technique more effective. Some equating will be necessary; however, development and discussion of theories will be largely confined to that necessary to justify the method of analysis.

Basic Assumptions
The following assumptions have been allowed as a basic definition of conditions:The pressure required to maintain fracture parting can be determined with fair reliability from either theoretical or empirical methods.The pressure required to maintain fracture parting is independent of fluid injection rate.For any one plane of parting, the functional variation in surface injection pressure with injection rate is the result of increased or decreased friction drop in conductor pipe and perforations.Functional variation in bottom-hole casing injection pressure with rate is the result of friction drop through perforations and is generally assumed, depending on number of perforations open, to be negligible for most wells below 3,000 ft in which ball sealers are not employed.
Numerical Simulation of Combustion Tube Experiments and the Associated Kinetics of In-Situ Combustion Processes
Authors: Lin C. Y. , Chen W. H. , Lee S. T. , Culham W. E. 
Published: December 2007

Abstract
This paper presents the results of numerical simulation of dry, forward combustion tube experiments. The kinetic aspects of in-situ combustion processes also are discussed. The goals of the study are to investigate the fuel deposition mechanism and to identify the key parameters affecting the performance of in-situ combustion processes.
The thermal simulator developed at Gulf R&D Co. was used in the study. It was modified to include the capillary outlet effects for a more realistic description of the oil and water productions. The following experimental data were matched: cumulative water and oil productions, position of the combustion front as a function of time, fuel consumption, temperature as a function of time and position, and the pressure drop across the tube. History matches were performed for two crude oils with distinctly different physical properties (gravities of 26.5 and 13°API [0.896 and 0.979 g/cm3]). The agreements between experimental data and simulation results were excellent.
Results indicate that the component equilibrium K-values and the kinetics of cracking reactions are the most important parameters affecting the fuel deposition, and that the fuel deposition mechanism, the fuel composition, and the locations and sizes of the transient zones depend on the crude oil and reservoir rock properties. Simulation results are always sensitive to the K-values of the light oil component but insensitive to the K-values of the heavy oil component. Results are sensitive to the kinetics of cracking reaction only if the cracking reaction is catalytic or the peak temperature and the fuel consumption are sufficiently high. Furthermore, the fuel available may or may not be solely in the form of coke.
Our study suggests that further investigations of the catalytic effect of reservoir rocks and reaction kinetics of the cracking reaction are needed. Also, more than two crude oil components may be required to simulate the evaporation effect of crude oil accurately.
Interpretation of Pressure-Composition Phase Diagrams for CO2/Crude-Oil Systems
Authors: Orr F. M. , Jensen C. M. 
Published: December 2007

Abstract
Results of single-contact phase behavior studies for CO2/crude-oil mixtures often are presented as pressurecomposition (P-X) phase diagrams. In such diagrams, regions of pressure and CO2 mole fraction for which more than one phase forms can be identified easily. Phase diagrams for CO2/crude-oil systems can be quite complex, however, since under some conditions such mixtures can form a liquid and a vapor, two liquid phases, or two liquids and a vapor in equilibrium. This paper examines P-X diagrams for two ternary systems, CO2/propane/hexadecane and CO2 /methane/hex- adecane, and describes transitions from one diagram to another that occur with changes in system temperature or changes in oil composition.
Nine experimentally determined P-X diagrams are presented for mixtures of Wasson crude oil with CO2. Three different oils, stock-tank oil, stock-tank oil plus 312 scf/bbl [560 std m3/m3] solution gas, and stocktank oil plus 602 scf/bbl [1084 std m3/m3] solution gas, were studied at three temperatures, 90, 105, and 120°F [32, 41, and 49°C]. Comparison of the resulting phase diagrams with those discussed for the simpler ternary systems indicates that the principal features of the crude oil phase diagrams are qualitatively consistent with those of the ternary systems. The results of the CO2/crude-oil experiments indicate that for low-temperature systems (below about 120°F [49°C]), the extrapolated vapor pressure (EVP) of CO2 is a good estimate of the pressure required to produce a dense, relatively incompressible CO2-rich phase that can extract hydrocarbons efficiently from a crude oil. Hence, in the absence of other experimental evidence, the EVP curve can be used as a rough estimate of the minimum miscibility pressure (MMP) for low-temperature reservoirs.
Effect of Flow Time Duration on Buildup Pattern for Reservoirs With Heterogeneous Properties
Authors: Streltsova Tatiana D. , McKinley Richard M. 
Published: December 2007

Abstract
For a heterogeneous reservoir, the shape of a buildup curve is strongly dependent on the length of the preceding flow period. Therefore, in exploration well testing, where the flow period is usually short, modification of the pressure buildup pattern caused by insufficient flow time can lead to erroneous interpretation of well behavior. Buildup pattern, as a function of flow time, is discussed here for various types of ideal heterogeneities such as linear reservoir discontinuities, natural fractures, vertical stratification, pressure support, and lateral permeability loss. A relationship is provided for the dimensionless flow time required to produce a certain buildup pattern. The effect of flow time on quantitative assessment of reservoir parameters is determined as well.
Effects of External Boundaries on the Recognition of Reservoir Pinchout Boundaries by Pressure Transient Analysis
Authors: Gerard Matthew G. , Horne Roland N. 
Published: December 2007

Abstract
Previous workers have shown that a semi-infinite reservoir with a pinchout boundary is characterized by spherical flow at long time. As a result, the presence of a pinchout should be recognizable from pressure-drawdown data by the appearance of a straight line on a graph of pressure vs. reciprocal square root of time. However, external boundaries of the system may be felt before spherical flow is established. This problem was studied by creating boundaries in the semi-infinite reservoir, using infinite-array superposition of the pinchout source function. Three partially closed systems were produced: (1) two parallel, vertical boundaries normal to the pinchout, (2) a vertical boundary opposite the pinchout, and (3) a second pinchout opposite the first. Values of pressure vs. time have been calculated for each of these cases.
It was found that the characteristic straight line begins at a time tD/dD2=5. This line would appear only if the external boundaries in the direction orthogonal to the pinchout were more than five times as distant from the well as the pinchout, and if boundaries in the direction parallel to the pinchout were more than eight times as distant.
The Introduction of the Microchanneling Phenomenon to Cyclic Steam Stimulation and Its Application to the Numerical Simulator (Sand Deformation Concept)
Authors: Ito Yoshiaki 
Published: December 2007

Abstract
Historically, a vertical or horizontal fracture is believed to be a main recovery mechanism for a cyclic steam-injection process in unconsolidated oil sands. Most current computer models for the process are based on the fracture concept.
With the postulated sand deformation concept, on the other hand, the injected fluid is able to penetrate the unconsolidated oil sand by creating microchannels. When the pore pressure is reduced during production, these secondary flow channels will collapse totally or partially. Condensed steam tends to sweep fluids where the bitumen had been heated and imparts mobility as a result of the injected hot fluid.
Flow geometry of the new concept is described in this paper. The physical differences between the sand deformation zone and the no-deformation zone are also investigated. The three major differences between these two zones are porosity change, pressure level, and energy and flow characteristics resulting from the existence of microchannels.
All these modifications were incorporated successfully into a conventional numerical thermal simulator. The new model provided an excellent match for all the field observations (steam-injection pressure, oil-and-water production rates, fluid production temperature, downhole production pressure, and salinity changes) of a steam-stimulated well in an unconsolidated oil sand. The study indicates that the most important phenomenon for in-situ recovery of bitumen is the one-way-valve effect of the microchannels, which are opened during injection and closed during production.
Influence of Temperature and Pressure on Asphaltene Flocculation
Authors: Hirschberg A. , deJong L. N. J. , Schipper B. A. , Meijer J. G. 
Published: December 2007

Abstract
A thermodynamic liquid model has been developed to describe the behavior of asphalt and asphaltenes in reservoir crudes upon changes in pressure, temperature, or composition. Asphaltene solubility properties used as input to the model may be obtained from titration experiments on tank oil. High-pressure flocculation experiments confirm the potential of the model. The model appears to be well applicable to conditions at which asphaltenes are associated with resins. The model may be used to identify field conditions where asphalt or asphaltene precipitation will occur.
Behavior of Microemulsions Under Compression
Authors: Rossen W. R. , Kohn J. P. 
Published: December 2007

Abstract
Compression to reservoir pressures can alter microemulsion phase behavior, on which the success of microemulsion-based EOR processes depends. For convenience, however, phase behavior studies usually are conducted at atmospheric pressure. Extrapolating phase behavior data from atmospheric to reservoir pressures requires the volumetric properties of each phase under compression, including the isothermal compressibility as a function of pressure and composition.
Two topics are addressed here. First, compressibility data up to 16 MPa [2,300 psi] are presented for several systems of oil and water with surfactants and protosur-factants and the data are fit to simple models for pressure and composition dependence. The pressure dependence fits the Tait equation in this pressure range; selected high-pressure data indicate how the compressibility deviates at much higher pressures. To within the resolution of the data, the composition dependence is linear in volume-fraction composition; moreover, the effective compressibilities of oil and water in solution appear to be near their pure-component values. More data are needed to verify and determine the exact dependence.
Second, a simple compressibility cell is described that allows both rapid determination of compressibility and direct determination of the phase boundary in pressure. Both phase separation and coalescence of distinct phases with increasing pressure was observed in microemulsion systems, although the phase boundaries in pressure for these systems were not mapped out systematically. The effect of dissolved gases such as methane, which can affect microemulsion phase behavior at high pressures, is not addressed here.
An Integrated Design of Lease Programming and Custody Transfer Facilities
Authors: Wasicek J.J. , Kleppinger K.B. , Grovenburg W.W. 
Published: December 2007

Introduction
The Adena J sand field is the largest field to date in the Denver-Julesburg Basin (Fig. 1). This field is located in Morgan County, Colo., approximately 12 miles south of Fort Morgan. The discovery well in the Dakota J sand was drilled in Nov., 1953. By late 1954 initial development was completed with the drilling of 166 oil wells and 15 gas wells. Early in 1954 the operators recognized the advantages of unitization and committees were organized to conduct the necessary studies. On Jan. 1, 1956, a large portion of the field was unitized with The Pure Oil Co. named as Unit operator. Nine months later additional leases were brought into the Unit. All but three of the J-sand wells in the field are now participating in this Unit.
Early in Feb. 1957, plans for a pressure maintenance program were completed. In July, 1957, water injection was started into a line of wells along the gas-oil contact. This plan of water injection requires only a portion of the wells presently completed in the field to produce the reservoir. Conventional production operations under this pressure maintenance program would have required extensive tank battery relocation, and in addition would have required an elaborate produced water gathering system. An economic study of various producing operations led to the selection of automatic custody transfer equipment and well supervisory control equipment.
Studies revealed that the most desirable system should include one central treating plant and custody transfer station. Distances involved were too great to permit each well an individual lead line to a central station, or to provide supervisory well control from one point. To overcome this problem it was decided to control the wells from stations spaced through the field. Production arriving at each station could be transported to the central treating and custody transfer station through an oil-water gathering line. It became readily apparent that three major problems had to be solved in the system design.