bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Mixing Rule Method for Calculating the Viscosity of CO2 and Low-Gravity Reservoir Oil
Authors: Emanuel A. S. 
Published: December 2007

ABSTRACT
A mixing rule correlation has been developed for predicting the viscosity of CO2-reservoir oil mixtures from composition. The method is suitable for equation-of-state based calculations and is most useful for heavy oils. The parameters of the correlation were developed from 15 different CO2-oil mixtures. Mixture viscosity ranged from 0.2 to 5000 cp. The pressure-temperature range of the experimental data was 300-7000 psi and 70-250°F. The calculation requires the viscosity of the stock tank oil at reservoir temperature and atmospheric pressure. For best accuracy, this viscosity is measured experimentally, but it can be estimated from oil gravity. The correlation generally predicts absolute viscosity of the oil-solution gas-CO2 mixture within ±30% at reservoir condition. The percentage reduction of stock tank oil viscosity to reservoir mixture conditions is predicted on an average within ±5% of the stock tank viscosity. The accuracy of this correlation will usually be better than that of other general correlations, particularly for heavy oils at reservoir conditions. The proposed correlation may be calibrated to experimental data by adjusting one parameter.
Application of Pseudotime to Estimate Average Reservoir Pressure
Authors: Aanonsen S. 
Published: December 2007

ABSTRACT
Several methods taking into account variations in compressibility and viscosity have recently been proposed to improve the estimate of average reservoir pressure from pressure buildup tests in gas reservoirs. This paper demonstrates how well-known methods developed for oil reservoirs can be applied directly if the pseudopressure transformation is combined with pseudotime. It is shown that the method is equally applicable both for gas reservoirs and oil reservoirs where substantial gas saturation has developed during production. The method may also improve the estimates of formation permeability and skin factor.
By introducing different flow regions where simplifying assumptions can be stated, it is shown that pseudotime is valid for buildup, but not for drawdown. In addition, it is shown that the use of the producing GOR at shut-in to calculate buildup pseudopressure in solution-gas-drive reservoirs also depends on these assumptions.
Numerical simulations demonstrating the validity of the method is presented for a circular as well as different rectangular geometries.
Concentration Effects on the Settling Velocities of Proppant Slurries
Authors: Dunand A. , Soucemarianadin A. 
Published: December 2007

ABSTRACT
In this paper, we study the sedimentation of single particles and of suspensions in quiescent fracturing fluids.
In the first part of the paper, measurements of the terminal fall velocities of single spheres in hydroxypropyl guar solutions are reported. Classical viscometric measurements show that the viscosity function of these fluids is well represented by the Ellis model. After correction for boundary effects, the experimentally measured velocities compare well with theoretical predictions based on the Ellis model.
In the second part of the paper, we investigate the settling behaviour of concentrated proppant suspensions (5 to 41 % by volume of solids). The solid volume fraction is determined, as a function of vertical distance and time, using gammaray attenuation measurements. Settling velocities are compared with single sphere data.
Finally, the effects of the proppant concentration are discussed in relation with several existing models for hindered settling.
A New Approach to the Characterization of Reservoir Heterogeneity Based on the Geomathematical Model and Kriging Technique
Authors: Da Costa e Silva A. J. 
Published: December 2007

ABSTRACT
One of the most significant problems of reservoir engineering is the construction of realistic mathematical models describing the nature and disposition of the heterogeneities that inevitably occur in petroliferous formations. This paper presents a new approach based on a geomathematical model resulting from the Theory of Regionalised Variables of G. Matheron and from the Kriging technique. The model is tested on a North Sea Oil Reservoir and results are remarkable.
A CO2 Injection Measurement and Control System
Authors: White J. T. , Benoit R. L. 
Published: December 2007

ABSTRACT
Advances in microcomputer technology have heralded a new era in oil field automation. A novel measurement and control system has been implemented on the carbon dioxide injection wells in the Slaughter and Wasson Fields operated by Amoco Production Company. The heart of this system is a solar powered microprocessor based Remote Telemetry Unit which senses the necessary input parameters, performs the calculations necessary to measure the rate and pressure at which carbon dioxide is being injected, controls the position of a ball valve to maintain the desired flow rate and pressure, and sends selected information to a central automation computer for alarm and reporting purposes. The purpose of this paper is to describe the electronic hardware, the end devices, control element, and software that was used to implement this function.
Enhanced Recovery of a "J" Sand Crude Oil With a Combination of Surfactant and Alkaline Chemicals
Authors: Martin F. D. , Oxley J. C. , Lim H. 
Published: December 2007

ABSTRACT
This paper presents laboratory results aimed at the enhanced recovery of a crude oil from a "J" Sand reservoir in Nebraska. The "J" Sand oil, typical of many midcontinent crudes, only contains small amounts of the organic acids that produce natural surfactants when alkali is added. As a result, the interfacial tensions between alkaline solutions and the crude oil are not low enough for efficient oil displacement. Although other mechanisms may be responsible for producing additional oil, the primary approach of this work was the addition of a surfactant to the alkaline solution in order to achieve ultralow interfacial tensions. The surfactant used was a synthetic petroleum sulfonate.
The alkaline chemicals that were considered include sodium carbonate, sodium hydroxide, sodium silicate, ammonium hydroxide, and potassium hydroxide. Using results on the effect of various alkaline chemicals on the phase behavior of the surfactant, the current paper outlines the rationale for selecting optimum formulations for this project.
For the optimum formulations of alkali and surfactant, interfacial tensions with the crude oil were measured. Alkali consumption and silica dissolution were monitored. Oil recovery tests in reservoir cores at 160°F were conducted with some of the more promising formulations.
Implications from the results of this work suggest that it is possible to select the appropriate alkaline chemical, as well as the molecular weight of the surfactant, to give optimum recovery for the conditions of water salinity and temperature in the reservoir. For example, a formulation can be chosen so that a preflush is not required for this project.
Optimum WAG Ratio vs. Rock Wettability in CO2 Flooding
Authors: Jackson D. D. , Andrews G. L. , Claridge E. L. 
Published: December 2007

ABSTRACT
Enhanced oil recovery in carbon dioxide (CO2) miscible floods can be severely reduced by gravity segregation and/or viscous fingering of the CO2. Dimensionlessly scaled experiments have been conducted in a laboratory model of a quarter five spot to investigate the effects of rock wetting state, alternate injection of water and CO2 gas (WAG), and total CO2 slug size on secondary and tertiary extra oil recovery.
Laboratory model results in the water-wet beadpack show an optimum WAG ratio of 0:1 (continuous slug process) for tertiary floods, while the same floods in oil-wet packs have optimum recoveries at WAG ratios of about 1:1. Floods in both wetting states indicate that maximum recovery is a stronger function of slug size in secondary CO2 flooding than in tertiary flooding. The wetting state was found to be a major factor affecting flood performance, with the consequence that tertiary floods in the water-wet laboratory model were dominated by gravity forces, while oil-wet tertiary floods were controlled by viscous fingering.
High Differential Pressure, Radial Flow Characteristics of Gun Perforations
Authors: Regalbuto J. A. , Riggs R. S. 
Published: December 2007

ABSTRACT
Tubing conveyed completion techniques are being utilized more frequently than in the past, because of the apparent advantages derived from underbalanced perforating. These advantages include cleaner perforations, reductions of additional stimulation treatments and reduced completion times. This paper presents the results of a laboratory study of gun perforations made under high differential pressure, radial flow conditions. In this study, Berea sandstone cores, modified to permit radial flow, are used to determine the relationship between perforation characteristics and the time-dependent pressure differential between pore pressure (i.e. formation pressure) and "well bore" pressure during the completion process.
The primary perforation characteristic investigated (Radial Flow Ratio) is defined as the ratio of the perforated flow rate to the flow rate of the unperforated core under identical conditions. The perforated flow rate is measured in radial flow after the perforation has been made under various time-dependent pressure differentials.
The results of three different series of perforation flow tests are presented. The tests are described as 1) No Surge: Pore pressure and "well bore" pressure are both equal to 1,200 psi at the instant of perforation, 2) Immediate Surge: Pore pressure is 1,200 psi and the "well bore" pressure is 200 psi at the instant of perforation, and 3) Delayed Surge: Pore pressure and "well bore" pressure are both equal to 1,200 psi at the instant of perforation after which a 1,000 psi underbalanced differential is applied to the core.
The Radial Flow Ratio (RFR) was affected by the application of a 1,000 psi surge pressure differential, both immediate and delayed. The immediate surge RFR was 58% greater and the delayed surge RFR was 50% greater than the no surge RFR.
Correspondingly, the hole volumes after surging increased 55% indicating that there was some elimination of the compacted zone material.
Underbalancing, either at the instant of perforation or subsequently, appears to improve the flow characteristics of shaped charge perforations.
Defining the Characteristics and Performance of Gas-Lift Plungers
Authors: Mower L. N. , Lea J. F. , Beauregard E. , Ferguson P. L. 
Published: December 2007

ABSTRACT
A laboratory investigation was conducted to provide data necessary to better predict the behavior of gas lift plungers. A test well was instrumented to provide pressure, velocity, and volumetric information during the fall and rise cycle of a variety of commercially available plungers. A substantial data bank has been compiled and behavior of 13 different plunger configurations has been characterized by gas slippage, liquid fallback, and fall velocity. Performance characteristics of the individual plungers has been incorporated in a modified Foss and Gaul2 mathematical model which provides predicted minimum casing pressure in close agreement with actual laboratory tests.
As a second part of the evaluation program, actual field data was collected from four field locations with a variety of operating conditions. The correlations developed for the laboratory tests were then adjusted to fit field data. The final correlations and equations describing plunger lift operations have been included in a computer program that can be used for design and analysis of plunger lift operations.
Risk Weighting World Energy Price Stability
Authors: Omar A. E. 
Published: December 2007

ABSTRACT
During the past fifteen years the world's economic system has suffered two shocks from massive increases in the price of oil. During this time there were conflicting forecasts of future energy developments, ranging from "no problem" to an ominous, more shocking third energy crunch. Although the former is probable in the near term, the latter view seems more likely tc prevail before the end of the next decade.
As a result of the two shocks which took place in 1973 and 1979, the world began to realize that the United States was no longer the marginal producer of the last barrel of crude oil needed to set market prices. Nor can OPEC alone, as recent events indicate, have the last word in setting market price.
The energy crisis is still with us even though the industrialized countries have succeeded in deferring it for a period of time. Therefore, a world model of the supply/demand relationships for crude oil using an econometric framework was developed. The model examines the potential for worldwide energy disruption that could result from the influence of one major area [consumer (s)/supplier(s)] or a combination of areas. The model has the potential to predict whether the potential for a third energy crunch is real or not. If that potential exists, the model will determine when that is likely to occur and will further help in projecting future relationships between supply/demand and the price of oil, thereby allowing better planning and development for producers and consumers alike.
A New Sealed Bearing Rock Bit for High-Speed Drilling
Authors: Carter M. W. , Daly J. E. , Van Nederveen H. 
Published: December 2007

ABSTRACT
This report discusses the development and testing of a new sealed bearing rock bit for use with high speed drilling tools such as downhole turbines and positive displacement mud motors. The principal feature of this rock bit is a new low friction elas-tomeric seal. Characteristics of this new seal, specific design changes incorporated into the new design to increase its bearing capacity and the results of field testing of this new design are described.
The Drilling Command and Control System
Authors: Foreman R. D. 
Published: December 2007

ABSTRACT
The best-Laid plans in drilling are often defeated by at least three major problems: (1) information scarcity – poor communication between rig and office hinders attempts to make good decisions; voluminous historical files yield little practical information, (2) data saturation – nobody can digest all of the real time data now available at the rig site, and (3) technology lag – the gap widens between what is technically feasible and what is routinely achieved. The Drilling Command and Control (DCC) system has been developed to mitigate these problems. Drilling Command and Control combines the best available computer, video, and satellite technologies to provide quality communications, reduce large volumes of data to practical use, and actively tracks all phases of the drilling operation. Its foremost feature is ease of use, as demonstrated by contract personnel who learn to perform at full capabilities within two weeks of DCC experience. This paper describes both the unique Drilling Command and Control system and its novel applications to drilling.
Fracture Evaluation Using Borehole Sonic Velocity Measurements
Authors: Liu O. Y. 
Published: December 2007

ABSTRACT
Using waveforms acquired by multitransmitter and/or multireceiver borehole sonic tools, acoustic velocity (or slowness) was computed for compressional, shear, and Stoneley waves using direct phase determination (DPD),1 the slowness time coherence (STC) method,2 and multiple shot processing (MSP).3 It was found that values of Δt (or slowness) computed using the receiver locations, referred to as the receiver Δt, were different from those computed using the transmitter locations, referred to as the transmitter Δt, when the sonic tool was in the vicinity of fractures. The amount of differences in compressional, shear, and Stoneley Δt depends on the size and nature of the fractures. It is possible to determine the height, width, and dip angle of the fracture when these differences are used in conjunction with Dual Dipmeter* tool data.
Determination of Permeability Variation Factor V From Log Analysis
Authors: Kapadia S. P. , Menzie D. E. 
Published: December 2007

ABSTRACT
The paper presents a technique for the determination of the coefficient of permeability variation, V, from quantitative well log analysis without the requirement of expensive coring programs or extensive laboratory effort. The method is an application of the improved empirical relationships proposed by Coats and Dumanoir (1973) in which the permeability index is derived as a function of porosity, resistivity at irreducible water saturation, hydrocarbon density and rock type.
Field examples illustrate the application of this new approach and the results obtained for a wide variety of lithologies.
Meren Field Offshore Treating Facilities for Seawater Injection
Authors: Adetoba A. L. 
Published: December 2007

ABSTRACT
The need for pressure maintenance by water flooding of seven reservoirs in the Meren field to enhance oil recovery was established. Treating facilities have been designed to remove suspended solids and dissolved gases. Chemical treatment is used to control scale, corrosion and microorganisms. All these have solved the problems associated with sea water injection.
A Laboratory Evaluation of Barium Sulfate Scale Inhibitors at Low pH for Use in Carbon Dioxide EOR Floods
Authors: Ramsey J. E. , Cenegy L. M. 
Published: December 2007

ABSTRACT
During a carbon dioxide flood, the floodwater pH can drop significantly causing scaling problems. An evaluation was therefore made of the efficacy of five barium sulfate scale inhibitors and of their cost-performance as the system pH was incrementally lowered from 7.0 to 4.0. A theory is presented linking a scale inhibitor's effectiveness at low pH to its dissociation constant.
East Painter Reservoir: An Example of a Compositional Gradient From a Gravitational Field
Authors: Creek J. L. , Schrader M. L. 
Published: December 2007

ABSTRACT
The effects of gravity on composition in a static hydrocarbon fluid column has been studied since Sage and Lacey's (1) pioneering work in 1939. Recent investigators (2, 3, 4) have pointed out that the effects of gravity become more significant as a critical point is approached. Therefore, a reservoir with a large closure containing a rich condensate and volatile oil should have measurable contributions from gravity affecting the distribution of hydrocarbons in the reservoirs.
Several examples of reservoirs with large closures containing both a volatile oil and rich condensate exist in the Nugget Sandstone portion of the Wyoming Overthrust Belt. We show that the hydrocarbons present in these sandstone reservoirs have physical properties which may be correlated with depth. We further show that for one reservoir, East Painter Reservoir Field, that the variation in hydrocarbon composition with depth may be predicted with some accuracy by including the gravitational correction term to the equations governing equilibrium, i.e., migdh for each component. These results are important with regard to compositional simulation of the performance of these fields and in equity determination.
Role of Cement Fluid Loss in Wellbore Completion
Authors: Bannister C. E. , Lawson V. M. 
Published: December 2007

ABSTRACT
The fluid-loss behavior of cement slurries against permeable formations and its relationship to interzonal fluid migration have been investigated. Static fluid-loss testing, designed to simulate cement placed in a wellbore, has shown that the cement fluid-loss rate through a deposited mud filter cake decreases with time. This decrease in fluid-loss rate is dependent upon the designed fluid-loss properties of the cement slurry, and significantly influences the loss of hydrostatic pressure required to control formation fluids. Once the pressure starts to decay, formation fluids can potentially enter the wellbore causing ineffective zonal isolation and, in some cases, gas migration to the surface.
The mechanism described indicates that hydrostatic pressure is initially transmitted after cement placement. During this period, fluid loss to the surrounding formation is compensated for by an equal decrease in slurry volume. The resulting changes in the solid-to-water ratio and gelation properties coupled with the growth of the cement filter cake cause the pressure against the formation to eventually decrease. The rate of pressure decrease is dependent upon the fluid-loss rate and the slurry's compressibility. Once the pressure approaches the formation pressure, interzonal fluid flow through the cement slurry occurs with its rate initially governed by the cement fluid-loss rate.
Several correlations have been made relating fluid loss to the pressure profile after wellbore completion. The results suggest that an API fluid-loss requirement of 100 mL/30 min, which may be sufficient during cement placement, is actually too high when consideration is given to the fluid loss that occurs after cement placement. Sufficient delays in the loss of pressure are obtained for an API fluid-loss requirement in the range of 10 to 30 mL/30 min with the actual value dependent upon wellbore geometry, overbalance pressure, mud fluid-loss properties and cement slurry design.
Practical Onsite Inspection and Testing Improves Fracture Treatment Quality
Authors: Robinson J. C. 
Published: December 2007

ABSTRACT
A hydraulic fracture treatment quality control program was implemented in the Oregon Basin Field, Park County, Wyoming to ensure consistently high quality stimulation treatments on polymer augmented waterflood injection wells. The quality of the materials used was checked on location in addition to performing a comprehensive job review prior to each treatment. As a result of the quality control program, significant changes and improvements were made in the quality and performance of the fracture treatments.
Microcomputer Gas Reservoir Simulation Using Finite Element Methods
Authors: Logan R. W. , Lee R. L. , Tek M. R. 
Published: December 2007

ABSTRACT
Two-dimensional finite element (FEM) gas reservoir simulators are developed for the IBM-XT microcomputer. A wide range of gas migration and deliverability problems are solved, in spite of the size and speed limitations of the microcomputer.
Using pseudopressure or p2 as the dependent variable, a radial cylindrical depth simulator was developed, verified and used to investigate several deliverability problems related to unsteady state, turbulence, and stratification. The quadratic finite element is shown to be a particularly attractive choice for problems involving skin and turbulence. The results, compared with previously published analytical work, indicate close agreement in characterizing gas deliverability performance. It is observed that for cylindrical reservoirs, the end-infinite-acting time and pseudosteadystate times are quite different. This phenomenon becomes more pronounced under turbulent conditions.
A relatively new concept of Inverse Productivity Index (IPI) has been used for the deliverability analyses, as an alternative to the classical back pressure plots. The analytical and numerical solutions presented reinforce the concept that solutions to gas deliverability problems are more naturally suited to the IPI-plot analysis.
An efficient single phase areal FEM reservoir simulator is also developed, with a pseudopressure formulation and boundary water-drive capabilities. This simulator is used to study gas migration, demonstrating good agreement with previously published work. In addition, it is shown that this areal FEM simulator is particularly effective in studies related to migration between adjacent communicating reservoirs with multiple wells, complex boundaries, and specified production/injection schedules.