bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Minimum Miscibility Pressure: A Correlation for Impure CO2 Streams and Live Oil Systems
Authors: Alston R. B. , Kokolis G. P. , James C. F. 
Published: December 2007

Abstract
This paper presents an empirically derived correlation for estimating the minimum pressure required for multicontact miscible (MCM) displacement of live oil systems by pure or impure CO2 streams. Minimum miseibility pressure (MMP) has been correlated with temperature, oil C5+ molecular weight, volatile oil fraction, intermediate oil fraction, and composition of the CO2 stream.
The effects of temperature and oil C5+ molecular weight on pure CO2 MMP have been well documented. However, CO2 sources are rarely pure, and solution gas usually is present in reservoir oils. The correlation presented in this paper accounts for the additional effects on MMP caused by the presence of volatile components (methane, C1; and N2) and intermediate components (ethane, C2; propane, C3; butane, C4; hydrogen sulfide, H2S; and CO2) in the reservoir oil. This correlation also is capable of estimating MMP for a contaminated or enriched CO2 stream on the basis of the pure CO2 MMP.
Multicomponent CO2/Water/Hydrocarbon Phase Behavior Modeling: A Comparative Study
Authors: Kuan D. Y. , Kilpatrick P. K. , Sahimi M. , Scriven L. E. , Davis H. T. 
Published: December 2007

Summary
Phase behavior predictions of the Peng-Robinson (PR) equation and the Kleintjens-Koningsveld (KK) equation, a lattice-gas model, are compared for pure CO2, water, methane, n-butane, n-octane, n-decane, and several binary and ternary mixtures of these components. The KK equation is more accurate than the PR equation for predicting the saturated liquid densities of pure fluids. The two equations are comparable in predictions of binary pressure/composition phase diagrams and ternary-composition phase diagrams. Thus for these properties, the PR equation is preferred because it is a simpler equation, has fewer adjustable parameters, and has parameters available for more systems than the KK equation.
Eight-Well Interference Test in the Anschutz Ranch East Field
Authors: Pollock C. B. , Curtis Bennett 
Published: December 2007

Summary
In many new fields, it is necessary to plan for secondary recovery methods before the field is fully developed or extensive reservoir data have been obtained. Shortly after discovery of the Anschutz Ranch East field, the working-interest owners recognized that planning for an improved recovery program should begin as soon as possible. Knowledge regarding the degree of communication in the reservoir, the magnitude of any directional permeability trend, and the interwell reservoir properties would be needed to select a suitable reservoir management method. A large-scale interference test was chosen as a way to provide part of this information during the early stages of development.
This paper describes how the test was planned and executed and includes some of the problems that were encountered during the test performance and interpretation. The results obtained from the test confirmed the geological interpretation of a directional formation flow capacity and indicated that the Nugget formation is at least partially anisotropic.
Estimation of Formation Pressures From Electrical Surveys-Offshore Louisiana
Authors: Foster J.B. 
Published: December 2007

Discussion

Background Theory
Origin of Abnormal PressuresThe origin of abnormal pressures has been discussed by numerous researchers and several theories, well summarized by Watts in 1948, have been advanced to explain such pressures. The generally accepted theory explaining the occurrence of abnormally high pressures in the offshore area is paraphrased below. Consider a layer of sediments deposited at the bottom of the sea in a fluid environment. As more and more sediments are added above this layer, the grains of the sediments will pack closer together and accept the added weight of the overburden. Some of the water within the pore spaces will be squeezed out by the compaction. Since the water is continuous with (or in communication with) the water in the sediments and sea above, the pressure with-in the water is hydrostatic. As long as this process continues through geologic time so that water in the pore spaces is free to move out with the addition of overburden weight, the pressure of the fluid in the pores will remain hydrostatic or normal. As reported by Cannon and Craze in 1938, the normal pressure gradient in the Gulf Coast region approximates 0.465 psi/ ft, or the weight of a column of water with 80,000 ppm salt.
JPT
P. 165ˆ
Low-Temperature-Oxidation Kinetic Parameters for In-Situ Combustion: Numerical Simulation
Authors: Adegbesan K. O. , Donnelly J. K. , Moore R. G. , Bennien D. W. 
Published: December 2007

Summary
The principal objective of this study was to provide low-temperature-oxidation (LTO) reaction models that are suitable for use in numerical simulators of in-situ combustion for bitumen and heavy-oil reservoirs. A systematic study investigated the LTO reactions of the liquid-phase components of bitumen and heavy oils. Athabasca bitumen, free of water and minerals, was oxidized by use of a laboratory-stirred semiflow batch reactor. Kinetic studies were carried out in the 333 to 423 K [140 to 300°F] temperature range and at an oxygen partial pressure of 50 to 2233 kPa [7.3 to 324 psi]. The total pressures applied in the reactor ranged from 2190 to 4415 kPa [318 to 640 psi]. Experimental data were collected in the kinetic subregime. Reactor product gas was analyzed with a gas Chromatograph, and the liquid-phase oxidation product was separated into six main components (lumped or pseudocomponents): saturates, aromatics, Resins 1, Resins 2, asphaltenes, and coke (SARA).
Kinetic models are established for the liquid-phase LTO reactions. The models involve further lumping of the pseudocomponents. Saturates and aromatics are lumped to form the maltenes, Resins 1 and 2 to form the resins, and asphaltenes and coke to form asphaltenes/coke components.
On the basis of experimental kinetic data, two main types of reaction models are proposed: (1) a non-steady-state kinetic model representing the overall rate of oxygen consumption and (2) four non-steady-state multiresponse kinetic models representing the oxidation reactions of the liquid-phase components. Proposed models were found statistically adequate and suitable for use in numerical simulators.
Petroleum's Place in the Future Energy Requirements of the United States
Authors: Phelps Thomas W. 
Published: December 2007

Introduction
Although we expect the total energy requirements to rise from an equivalent of 20.0 million BOPD in 1957 to 28.5 million BOPD in 1968, we predict oil's actual contribution to decline from 44 per cent in 1957 to 43 per cent by 1968. Obviously, this is an important assumption to which everyone will not agree. This prediction is shown in Fig. 1, which also shows actual United States consumption in 1957, 1948 and 1928. The year 1957 was selected as a benchmark because the recession in 1958 will distort comparisons based on that year. Viewing oil and gas as a whole, we expect our industry's share of the energy market to increase at least up to 1968. To see why, let's turn to natural gas, the tail that is increasingly wagging the petroleum dog. In Fig. 1 the figure beside the natural gas segment and the oil segment of each bar represents the consumption for that year. For natural gas this is shown in millions of barrels a day oil equivalent, computed on the basis that 5,500 cu ft of gas equals 1 bbl of oil.

Analysis of Energy Sources Competitive to Petroleum
Now let's look at the contribution of coal, hydroelectric power, and, in 1968, atomic energy. As can be seen it is estimated that coal's share of the total market will decline to 24 per cent by 1968 from 27 per cent in 1957 and 67 per cent in 1928, but we believe the decline in tonnage of coal consumed each year is ending. We estimate consumption of coal in 1968 at the equivalent of 6.9 million BOPD compared with 5.5 million BOPD in 1957 and 7.1 million BOPD in 1928. The last small strip in Fig. 1 at the top of the 1928, 1948 and 1957 bars represents hydroelectric power. This hydro segment at the top of the 1968 bar is capped by a thin strip representing our estimate of U. S. consumption of nuclear energy in that year. Awed as we are by the longer-range potentialities of atomic power, we estimate its contribution to our 1968 total energy picture to be 10 million kw, the equivalent of a mere 300,000 BOPD.
Displacement of Viscous Oil From Consolidated Cores by Caustic at Temperatures Above 257°F
Authors: Medizade Mason M. , Handy Lyman L. 
Published: December 2007

Summary
Laboratory data were obtained to investigate the use of alkaline material with or without a small amount of surfactant as an additive to steam to enhance oil recovery from that portion of a reservoir subjected to a hot waterflood in a conventional steamflood. A series of hot alkaline floods (some containing surfactant) was performed on fired cores previously subjected to a hot waterflood in an isothermal flooding apparatus with temperatures as high as 356°F [180°C]. Floods with no previous waterflood were also tested. In addition to temperature, salt content of the injected solution, tertiary flood rate, pH of the injected solution, oil saturation, and surfactant concentration were investigated with respect to their effects on recovery mechanism and efficiency, alkaline consumption, and surfactant loss.
Results show that tertiary recovery increases with increasing temperature, increasing flood rate, increasing salt concentration in the injected caustic, and the addition of surfactant. The ultimate recoveries for the floods with no previous waterflood are comparable to those for the tertiary floods. Alkaline consumption in the presence of oil is less than that reported in the absence of oil, but still increases with increasing temperature and with decreasing flood rate. Results also show that oil is recovered with the chemical additive and that no significant oil bank is formed ahead of the chemical.
Litho-Density Tool Calibration
Authors: Ellis D. , Flaum C. , Marienbach E. , Roulet C. , Seeman B. 
Published: December 2007

Abstract
A second-generation density logging tool has been developed that uses a gamma-ray source and two Nal scintillator detectors for borehole measurement of electron density, pe, and a quantity Fpe that is related to the lithology of the formation. An active stabilization system controls the gains of the two detectors, which permits selective gamma-ray detection. Spectral analysis is performed in the near detector (two energy windows) and in the detector farther away from the source (three energy windows). This paper describes the results of laboratory measurements undertaken to define the basic tool response. The tool is shown to provide reliable measurements of formation density and lithology under a variety of environmental conditions.
Thermal Effects of Reinjection in Geothermal Reservoirs With Major Vertical Fractures
Authors: Pruess K. , Bodvarsson G.S. 
Published: December 2007

Introduction
Reinjection of spent geothermal brines is the most attractive method for their disposal. Field experience and theoretical work have shown that properly designed injection systems can avoid premature thermal interference at production wells and may serve additional purposes, such as maintenance of reservoir pressures and enhancement of ultimate energy recovery. There has been some controversy in the literature regarding benefits and drawbacks of reinjection. At the present time it seems clear that the issues are largely site-specific, and that reservoir response to reinjection is strongly dependent on formation properties and the thermodynamic state of the reservoir fluids. Whether or not reinjection at a given site is deemed desirable from the standpoint of reservoir management, it appears that for environmental reasons most future geothermal projects will require full reinjection as a method of waste disposal. There is a need for methods of designing and testing reinjection systems to avoid premature breakthrough of colder fluids at the production wells. production wells. An advisory panel convened by the U.S. DOE identified the development of techniques for monitoring, prediction, and control of the migration of injected prediction, and control of the migration of injected waters as an urgent priority. Depending on the geological characteristics of a geothermal reservoir, this can be a rather difficult task. For reservoirs approaching the idealization of a porous medium of uniform thickness, porosity, and permeability, analytical solutions are available for estimating the migration of thermal (cold) fronts away from injection wells. However, most high-temperature geothermal reservoirs are situated in fractured volcanic rocks. There is plenty of field evidence showing that in fractured reservoirs injected water can migrate rather rapidly to production wells. The possibility of rapid thermal breakthrough along preferential pathways is of obvious concern to field developers.
In the next section we review some field evidence for fast paths, and discuss possibilities and limitations for determining the thermal characteristics of fast paths by nonthermal means. We present idealized models of fast paths, and examine their applicability to field situations. paths, and examine their applicability to field situations. It is emphasized that tracer tests and pressure transient tests can provide only incomplete and ambiguous information on the thermal characteristics of fast paths. More reliable predictions of thermal interference are possible from nonisothermal injection tests. Numerical simulations incorporating approximate analytical solutions then are used to examine thermal breakthrough and recovery in vertical fractures.
JPT
p. 1567
Effect of Temperature on Oil/Water Relative Permeabilities of Unconsolidated and Consolidated Sands
Authors: Miller Mark A. , Ramey H. J. 
Published: December 2007

Abstract
Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures.
Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300°F [149°C].
Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances.
Prediction of Approximate Time of Interference Between Adjacent Wells
Authors: Stevens William F. , Thodos George 
Published: December 2007

Abstract
The point-source function introduced by Horner as a solution to the general unsteady-state equation for the flow of fluids through porous media has been utilized to calculate pressure profiles for adjacent wells as a function of time. By trial and error, the time at which the pressure waves meet to cause interference can then be calculated. For this calculation, the time of interference is arbitrarily defined as that time when both pressure waves exhibit a pressure decrease of 25 psi at the same point within the formation. To illustrate the method, an example involving two adjacent wells producing at different rates has been worked out and is presented in detail.

Introduction
The initiation of production of a new well is usually accompanied by pressure drawdown measurements in order to establish the extent and characteristics of the formation. The interpretation of such pressure drawdown data is based on mathematical developments involving a single well in an infinite reservoir. If more than one well is present in a reservoir, the possibility of interaction between wells exists. Therefore, care must be taken in interpreting the pressure drawdown data. It becomes important to be able to determine when this interaction, or interference, becomes significant. This paper presents a method for the prediction of the approximate time of interference between two such adjacent wells. The basic differential equation describing the pressure distribution existing during unsteady-state flow of a slightly compressible fluid has been solved by Horner, for a constant production rate from a circular homogeneous reservoir of infinite extent. The solution utilizes the point-source function to define the pressure at various points within the formation as a function of time.
Cation Exchange in Porous Media With Broad-Equivalent-Weight Sulfonate Micellar Fluids
Authors: Chan A. F. , Kremesec V. J. 
Published: December 2007

Abstract
This paper describes experimental and theoretical studies of cation exchange in porous media with micellar fluids formulated using a broad-equivalent-weight (BEW) sulfonate. The sulfonates can be described as composed of two pseudocomponents—a quasi-monosulfonate (the oil-moving component) and a quasi-disulfonate (the sul-fonate-solubilizing component). With this description and a mass-action model for cation exchange between the micelles, clays, and solution, a match between computer model predictions and results of laboratory single-phase flow tests in Berea sandstone was carried out. The assumptions required are reviewed and independent experimental results presented. With these assumptions and parameter values determined from the Berea history match, satisfactory predictions of divalent cation concentrations in field core experiments have been made. The good predictive capability of this model allows initial screening and development of micellar formulations for specific reservoir applications to be conducted at appropriate hardness levels.
Design and Construction of a High-Volume Flow Gas Metering Facility
Authors: Messmer J.H. , Jones E.H. 
Published: December 2007

Introduction
The need for a high volumetric rate natural gas proving facility has become more evident recently. The value of natural gas transferred has risen dramatically, and the inadequacies of the standard means of measurement have become more apparent.
Natural gas use, material, and energy balances also require more precise calibration of flowmeters. A meter proving loop facility was therefore built, and a critical flow nozzle proving capability was installed to prove meters to 40 MMSCF/D (1.1327 × 10(6) m3/D).
A description of the system and some results obtained with orifice meters and other commercial meters are shown.

SYSTEM LOCATION AND CONSTRUCTION
A proving facility must necessarily have an adequate volumetric through-put and adequate pressure to operate the critical flow nozzles.
The site chosen was the Sand Hills Plant, South and West of Odessa, Texas, operated by Warren Petroleum Company (a wholly owned subsidiary of Gulf Oil Corp.). The line chosen for flow-verification was a residue gas product line delivering a nominal 40 MMSCF/D (1.1327 × 10(6) m3/D). A criterion that had to be satisfied was that the test system will not interrupt the normal delivery of product when in use.
A simple schematic is shown in Figure 1. Though the system is folded for construction ease it is noted that it is basically a parallel loop to an existing flow system in which valves are used to transfer the added flow piping to a series connection. Additionally, since Valve 1 can be used for piping to a series connection. Additionally, since Valve 1 can be used for flow control, flow may be partially diverted to divide the flow between the two parallel loops without limiting the flow when operating the loop with critical flow nozzles for meter proving.

CRITICAL FLOW NOZZLES
Six critical flow nozzles conforming to ISO specifications (Ref. 1) for shape were purchased from Flow Measurement Systems, Longmont, CO, and calibrated for discharge coefficient by Colorado Engineering Experiment Station, Inc., Nunn, CO over the pressure and Reynold's number (Re) range of interest: 400–1000 psig (2.76–6.89 MPa) and 4 to 15 × 10(6) Re.
Some properties of the nozzles are shown in Table 1.
Table 1

Nozzle Specifications
MeanCD = A+BRe(-1/2)Re × 10–6
No. Throat D, in (mm) A B1 .4383 (11.133) .989205 -3.215 6.585
2 .6495 (16.497) .991425 -4.7 10.24
3 .851 (21.615) .994279 -3.44 13.61
4 1.0621 (26.977) .994142 1.94 17.20
5 1.180 (29.972) .993791 -7.67 19.38
6 1.4390 (36.550) .991394 6.6 22.65
CD = Discharge Coefficient Re = Reynolds No All calibrations certified traceable to NBS.
Slim Hole Drilling Decreases Carter's Development Costs
Authors: Flatt H.J. 
Published: December 2007

Abstract
Rising development costs are recognized as one of the major problems facing the oil industry today. To combat this situation, several new concepts designed to improve drilling techniques have been advanced within recent years. Among the ideas proving most effective is slim hole drilling.
Carter's slim hole experience has been in both exploration and pool development wells. In addition, slim hole practices have been successfully applied to water injection wells. In comparison with standard operations, both penetration rate and bit life decreased using slim hole methods. No difficulty was encountered in coring, logging and testing in reduced diameter holes. Actual slim hole costs indicated a significant economic advantage over conventional practices. Savings in dry hole costs ranged up to 25 per cent, primarily from reductions in footage and day work rates. Additional savings accrued in producing wells from economy in tubular goods. Slim hole methods may not always be applicable, as consideration should be given to specific drilling problems and objectives. In many cases, however, slim hole drilling provides significant economic advantages over conventional practices.

Introduction
Increasing development costs are widely recognized as one of the major problems facing the oil industry today. Inflationary effects are firmly evident in all of the principal components of drilling costs, including labor, transportation, steel products and chemicals. Furthermore, deeper drilling is necessitated to offset depletion of shallow reserves. During recent years the concept of slim hole drilling has been experimentally applied within industry to evaluate its significance as a cost reduction measure. In most cases, slim hole results are reported to be proving effective. The purpose of this discussion is to review experience of The Carter Oil Co. in drilling 108 slim holes which have resulted in estimated savings of $162,000 below the cost which would have been incurred with conventional sized holes.