bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Results from the Maljamar Carbon Dioxide Pilot
Authors: Lingane P. J. , McWilliams R. E. , Pittaway K. R. 
Published: December 2007

SUMMARY
Continuous carbon dioxide injection in the Grayburg/San Andres formations of the MCA unit has been completed; follow-up brine injection began in December 1983. Incremental oil production began in mid-1983 from the Grayburg zone and six months later from the San Andres.
Special features of the inverted five-spot pilot include (a) separate completions in the Grayburg and San Andres zones; (b) fiberglass-cased logging observation wells for in situ monitoring of oil, brine, and carbon dioxide movement; and (c) gamma-ray emitting tracers for improved vertical resolution of flow zones.
The a priori prediction of the flow behavior in the Grayburg reservoir, developed from core and log data from seven closely spaced wells, was not consistent with pressure interference data, nor with the arrival times of tracers at the logging and production wells. At least three different reservoir descriptions match the Grayburg data; the most likely explanation is a change in the effective location of the injection well due to a hydraulic fracture.
Cosurfactant-Enhanced Alkaline Flooding
Authors: Nelson R. C. , Lawson J. B. , Thigpen D. R. , Stegemeier G. L. 
Published: December 2007

Abstract
Many crude oil candidates for enhanced oil recovery by alkaline flooding produce their lowest interfacial tension at very low concentrations of alkali. Alkaline consumption by the rock makes propagation through the oil reservoir of such dilute alkaline solutions prohibitively slow. The dilemma of having to choose between highest displacement efficiency (lowest interfacial tension) and satisfactory displacement rate can be resolved by adding cosurfactants to the alkali. Low concentrations of properly chosen cosurfactants raise the concentration of electrolyte required for minimum interfacial tension to alkali concentrations high enough for satisfactory propagation of the alkaline bank. That is, just as in chemical flooding, a cosurfactant can be used to raise the "salinity requirement" of an alkaline flood.
Activity Maps, similar to the Salinity Requirement Diagrams of chemical flooding, are useful in formulating and understanding the results of cosurfactant-enhanced alkaline floods.
Alkaline flooding systems, formulated by the methods discussed in this paper, recover as much oil in laboratory core floods as well-formulated chemical flooding systems.
Evaluation Coring Results at a Micellar/Polymer Flood
Authors: Milton H. W. 
Published: December 2007

ABSTRACT
The results are presented for three evaluation core tests drilled at the M-1 Project in the Robinson Field of southern Illinois. The cores were taken near three logging observation wells which have been used to follow injected fluid movement through the reservoir in one-quarter of a 2-1/2 acre 5-spot.
Core oil saturation, oil displacement efficiency and vertical conformance are related to slug size, geologic characteristics and reservoir properties. The Robinson sand in the core test wells can be divided into at least three zones that show different fluid movement. These zones are also indicated by the observation well logs.
Sulfonate was detected in all selected core sample extractions. Further analysis showed that the low oil saturation samples had lost more of the water-soluble sulfonate components – that is, the sand had been flushed better by the polymer solution following the micellar slug. Where the slug has been effectively displaced, a considerable reduction in reservoir oil saturation is occurring.
The Effect of Temperature and Interfacial Tension on Water/Oil Relative Permeabilities of Consolidated Sands
Authors: Torabzadeh S. J. , Handy L. L. 
Published: December 2007

ABSTRACT
Relative permeability data for high- and low-tension systems were obtained experimentally at temperatures ranging from 22°C to 175°C. No other data have been reported for high temperatures and low interfacial tensions. Results for high-tension systems at elevated temperatures and for low-tension systems at room temperature are compared with other published data. The results of this study can be used to predict the performance and efficiency of enhanced oil recovery methods in which chemicals are considered for use with hot waterfloods or as steamflood additives. They are of particular interest with respect to steamfloods in viscous oil reservoirs.
Equipment was designed and constructed to measure water-oil relative permeabilities at elevated temperatures and pressures. It can be used for both steady-state and unsteady-state dynamic displacement measurements. The apparatus permits very accurate measurement of fluid saturations volumetrically by monitoring the oil content of the total system using a high pressure, high temperature water-oil separator. Experiments were conducted on fired Berea sandstone cores using n-dodecane and 1% NaCl brine. Aqueous low-concentration surfactant solutions were used to change interfacial tension levels. For the experiments reported here, the fluid pressure was kept constant at 300 psig and the overburden pressure at 650 psig.
The experimental results indicate that relative permeability curves are affected by temperature, especially at low IFT's. For the high-tension system, relative permeability to oil increased and relative permeability to water decreased at a given saturation while residual oil saturation decreased and irreducible water saturation increased with increasing temperature. Water/oil relative permeability ratio decreased with temperature at a given water saturation. These results suggest an increase in the preferential water wettability of sandstone with temperature.
Temperature effects were found to be more pronounced for low-tension than for high-tension systems. Residual oil saturation decreased significantly at higher temperatures, but only a small change in irreducible water saturation was observed. At any given temperature, irreducible water saturation for the low-tension system was lower than that observed for the high-tension system. Relative permeability to oil and water both increased with increasing temperature up to 100°C for the low-tension system. At higher temperatures, a decrease in relative permeability to water was observed, probably due to wettability alteration.
The steady-state technique showed a hysteresis effect in relative permeability curves which tended to diminish at high temperatures and low IFT's. Rate effect was not significant for the rates used in this study. The change in wettability of the rock and reduction of IFT with increasing temperature were important factors affecting the observed relative permeability curves.
Frontal Structure and Stability in Immiscible Displacement
Authors: Jerauld G. R. , Nitsche L. C. , Teletzke G. F. , Davis H. T. , Scriven L. E. 
Published: December 2007

Abstract
A theory of the stability or instability of plane saturation fronts in immiscible displacements is presented which is more realistic than earlier theories. For given two-phase relative permeability functions, capillary pressure function, viscosity ratio, saturation ahead of the front, and allowable front-propagation speed, the displacement-front saturation profile of permanent form is calculated from Rizhik et al.'s (1961) solution by quadrature of the nonlinear convective diffusion equations for two-phase flow with significant capillary effect. Stability of the saturation profile of permanent form with respect to small disturbances in pressure and saturation (as may be caused by minor heterogeneities in a reservoir) is found by solving the generalized eigenproblem to which linear stability theory and finite differencing lead.
The results show that when the front is unstable there is a fastest growing wavelength of disturbance transverse to the flow. Shorter wavelengths are slowed or stabilized by capillary-pressure-gradient-driven flow; longer wavelengths grow more slowly because the transverse pressure gradients driving them are weaker. If the displacing fluid is viscous enough the front is stable, but the larger the scale of disturbance the more nearly it is marginally stable. An earlier theory that approximates the front as a discontinuity agrees roughly but differs in important details, among them the mildly stabilizing effect associated with the saturation profile in the frontal zone.
A Study of the Relationship Between Surfactant/Oil/Brine System Phase Behavior and Chemical Flood Recovery in Short Cores
Authors: Ashrawi S. S. 
Published: December 2007

ABSTRACT
This study correlates the phase behavior of surfactant/oil/brine systems with their chemical flood performance in short cores. The study focuses on the influence of two important system composition variables: viz. the brine salinity and the nominal equivalent weight of a petroleum sulfonate blend. Furthermore, it investigates the influence of the addition of an alkylether sulfate in terms of optimal salinities, increased salinity tolerance and tertiary recovery efficiency.
The oil displacement experiments employ a very fast, near-continuous, constant salinity flooding process in 3-inch long Berea cores, using a microwave instrument to determine the oil saturations. A typical turn-around time for a flooding experiment was seven hours.
Tertiary oil recovery contours are developed in a brine salinity-surfactant equivalent weight space. The region of highest tertiary oil recovery in that space closely matched the region in which equilibrium three-phase systems existed. Optimal salinities and equivalent weights, as defined by the chemical flood with the lowest final oil saturation, were obtained with excellent resolution. More significantly, they closely matched those optimal values obtained under equilibrium conditions from time-consuming solubilization parameter measurements.
The addition of the alkylether sulfate solubilizer had the effects of increasing the optimal salinity, and significantly broadening the three-phase region as well as the region of high tertiary oil recovery. This broadening effect caused a lower resolution in the determination of optimal system variables. In the presence of the solubilizer, a close correspondence between the three-phase region and the region of optimum oil recovery was also observed.
This study introduces a rapid and meaningful technique to determine the EOR potential of surfactants and surfactant formulations. Applications of the results of this work include: the rapid screening of surfactants for enhanced oil recovery processes in specific rock matrices, the design and optimization of surfactant formulations and the quality control of plant-manufactured surfactants and field-blended surfactant formulations.
CO2 Minitest, Little Knife Field, ND: A Case History
Authors: Thakur G. C. , Lin C. J. , Patel Y. R. 
Published: December 2007

SUMMARY
A joint DOE-Gulf Oil Corporation Minitest of CO2 miscible flooding was conducted in the Mission Canyon formation of the Little Knife Field, North Dakota. In the five-acre minitest area, a central injection and three observation wells were drilled to form a non-producing, inverted four-spot pattern. A 1:1 CO2 WAG injection sequence (preflush water injection, five alternate slugs of CO2 and water, and drive water injection) was implemented. Prior to the CO2 minitest, a detailed reservoir description of the test area was developed through logging, pulse testing and core analysis. Extensive laboratory work had been performed to determine miscibility pressure, swelling and viscosity reduction effects.
The minitest included continuous bottom-hole pressure measurement in all test wells and time-lapse logging to monitor saturation changes as alternate slugs of water and CO2 passed the observation wells. Fluid samples from the observation wells were collected periodically to check for tracers and fluid composition. At the conclusion of drive water injection, a fifth well was drilled behind the CO2 front and pressure-cored to measure the residual oil saturation to the CO2 flood. A Compositional Simulator was used to history match the minitest performance and to evaluate the displacement and sweep efficiency in the project area.
Reservoir simulation models were used at various stages of the minitest: (a) to determine the volume and rate of water injection required to raise the reservoir pressure above the minimum miscibility pressure, (b) to calculate CO2 slug size, WAG ratio and project life, (c) to select the location of the fourth observation well behind the CO2 front, (d) to predict breakthrough times and concentrations of CO2 and water to decide when to log wells and collect fluid samples, (e) to scale the minitest reservoir description to a typical 160-acre, five-spot pattern for predicting recoveries for a waterflood and the CO2 WAG process, and (f) to perform sensitivity studies for studying the effects of layering, vertical communication and other process parameters.
Kinetics of the Chromium(VI)/Thiourea Reaction in the Presence of Polyacrylamide
Authors: Southard M. Z. , Green D. W. , Willhite G. P. 
Published: December 2007

ABSTRACT
The formation of chromium(III)-polyacrylamide gels was followed kinetically using spectrophotometric methods. The rate of chromium(VI) species conversion by thiourea and bisulfite was monitored to find a kinetic model for the oxidation/reduction reaction. The third order model found here shows first-order dependence on chromium(VI) concentration on thiourea and on pH. Additional results of the thiourea study show that a constant amount of chromium(VI) is consumed at gelation regardless of the initial concentration of that species, indicating that the Cr(VI) reduction reaction may be the rate-determining step in gelation. No such model or constant conversion for the bisulfite-reduced reaction could be determined.
The Multiwell Experiment Core Program, II
Authors: Sattler A. R. 
Published: December 2007

ABSTRACTAn unprecedented core analysis program is under way as part of DOE's Multi-Well Experiment (MWX). MWX is a research-oriented field laboratory whose objectives are to thoroughly characterize lenticular tight gas sands and to develop technology for their production. Over 4100 ft (1250 m) of core were taken from three wells separated by only about 115–215 ft (35–66 m) at depth. All major categories of core analysis are reviewed and results through December 1983 are included. Those include routine core analysis, restored state reservoir parameter measurements, electrical measurements, mechanical rock property data, mineralogy, organic maturation, natural fractures, and geochemistry. This paper also describes the laboratory work on core and formation invasion and the development of instruments that were used in the field processing of the core.
Simulation of Real Gas Flow Through Finite-Conductivity Fractures
Authors: Hossain Mehedi , Cady G. V. , Honarpour M. M. 
Published: December 2007

ABSTRACTHydraulic fracturing stands as one of the most effective stimulation techniques that were developed to increase the productivity of either damaged wells or wells producing from low permeability reservoirs. The evaluation of fracturing treatment and performance prediction of such wells are, therefore, very important for petroleum engineers. Although various analytical, semi-analytical and numerical solutions to the fluid flow in fractures have been proposed, reliable results are not obtained because of several simplifying assumptions.The development of a mathematical model to simulate the entire pressure test history of a hydraul-ically fractured gas well is presented. A two-dimensional reservoir model was combined with an one-dimensional fracture model to study the well performance under a variety of operating conditions. In this paper the effects of non-Darcy flow in the reservoir and in the fracture, wellbore and fracture storage, fracture damage, closure stress, gas slippage, and frictional pressure drop in the tubing are investigated. Test results of the model illustrating the effects of each of these factors are also presented.
Reduce Completion Costs by Using Optimum Number of Perforations
Authors: Bucy B.J. 
Published: December 2007

Abstract
There has been a recent trend toward reducing the number of perforations in oil wells that are to be hydraulically fractured. Two benefits of this practice are better control of the fracture treatment and reduced completion costs. This paper presents a method of mathematically calculating the number of performations to be used to obtain the greatest reduction in completion costs. This optimum number of perforations is obtained by equating the perforating cost and the perforation friction cost during the fracture treatment. By reducing the number of perforations to this optimum point the completion costs are reduced. In the case of hydraulically fractured oil wells, the reduction of the number of perforations to this optimum point will have negligible effect on the production capacity of the well.

Introduction
Ever since the introduction of the practice of setting casing through the pay zones and then perforating, there has been the problem of determining the number of perforations that should be used. An early mathematical study was made by Muskat wherein the perforations were considered to be point sinks. The study made a comparison of the theoretical productivity possible through perforations as compared to the theoretical productivity possible in an open-hole completion. Later studies were made using electric analog models wherein the effect of penetration into the formation was considered. These studies indicated that pay zones should be perforated from top to bottom with a density of 8 to 16 shots per foot in order to not seriously restrict production.
The above theoretical studies were made assuming ideal conditions and radial flow drainage with the results expressed as ratios. In actual practice many factors in addition to the number of perforations, such as proration, formation permeability, tubing choke, etc., determine the resultant productivity of a perforated well. Due to these factors, plus other things, such as perforating gun mechanical strength and interference between jet charges, the normal field practice became: perforate pay zones from top to bottom with a reduced density of four shots per foot. Statistical data comparing open-hole completions and perforated completions in one field indicated there were no recognizable differences in performance between the two groups.
Recent articles have advocated the further reduction of the number of perforations in wells that are to be hydraulically fractured. This reduction in the number of perforations results in better control of the fracture treatment, and reduction in completion costs. It appears that there is a present trend in the industry to follow the suggestions in these articles.
A Multi-Level Well Management Program for Modelling Offshore Fields
Authors: Fenter D. J. 
Published: December 2007

ABSTRACT
In reservoir simulation, software referred to as a well management program is used to set well rates and/or pressures for the reservoir model. A well management program for use in modelling multiplatform, multi-reservoir North Sea fields has been developed to allow Esso engineers to investigate alternative field production plans by altering platform facility constraints and field controls. It has been used by Esso in reservoir simulation studies of the complex Brent field in the U.K. North Sea.
Initial Experience With an Underwater Manifold Centre
Authors: Osborne J. M. 
Published: December 2007

Abstract
In July 1983 comingled production from the first two completed wells of the Shell/Esso Underwater Manifold Centre (the UMC), reached the Cormorant Alpha platform. This moment was the culmination of design and development effort which had begun as early as the spring of 1975. But being both the largest subsea system to become operational in the North Sea, and the first designed to the production of several subsea wells, whilst injecting into others, how would the UMC continue to perform?
This paper details the operational experience gained to date with the UMC, tracing its brief history since it was first powered up in September 1982 to the present. This is discussed in the main body of the paper under the headings: Commissioning ExperienceOperating ExperienceReliability and Maintenance Conclusions
The UMC system is briefly described as a preliminary to the above.
Subsurface Safety Systems for TLP Completions
Authors: Calhoun M. B. , Deaton M. , Tamplen J. W. 
Published: December 2007

ABSTRACT
Well completions for tension leg platforms require special consideration in key areas. Standard downhole equipment including subsurface safety valves can be used in a conventional manner from TLP's. Special designs, however, may be required for annular safety systems or sales risers.
Reservoir Simulation of Steam Injection in the Cold Lake Tar Sand
Authors: Peake W. T. 
Published: December 2007

ABSTRACT
A reservoir simulator of steam injection in the Cold Lake Tar Sand has been validated through a history match. The history match consists of 9 steam cycles in two wells during the period June 1978 through October 1980. Block size, fracture length, oil and water relative permeabilities, and pore compressibility were found to have a significant effect upon the simulation results. The simulation results were found to be insensitive to the time step size, heat conduction from the fracture, areal grid, and well productivity index.
A proposed commercial development of the Cold Lake Tar Sand consists of 4 well, 4.13 acre (1.67 × 104 m3) rectangular well patterns. The steam injection program consists of three phases: (1) single well cyclic steaming, (2) on-trend steam drive, and (3) off-trend steam drive. The optimum number of cycles, steam injection rates, and steam slug sizes were obtained. Simulation results for the optimized oil recovery are: a steam/oil ratio of 5–6, an average oil production rate per well of 42 bbl/d (6.7 m3/d), and a recovery of 45% of the original-oil-in-place in 9.2 years.
Improved Bulk Blending Techniques for Accurate and Uniform Cement Blends
Authors: Pace R. S. , McElfresh P. M. , Cobb J. A. , Smith C. L. , Olsberg M. A. 
Published: December 2007

ABSTRACT
Two of the major factors affecting cement slurry performance are the concentration of additives and their distribution throughout the dry cement blend. Consistometer thickening time tests on one or two batches of the cement are used to monitor the cement blends. Studies conducted have proven that these tests do not necessarily reflect the uniformity or the correct concentration of additives in the blend. To improve the quality of the bulk blending of cement, researchers developed on-site methods to verify the additive concentrations of each batch blended for uniformity and accuracy. They also investigated the effects of the current dry blending procedures, transportation, and air blending on the distribution of such additives as retarders, fluid loss agents, weighting agents, and salts.
The Use of a Medical Computer Tomography (CT) System To Observe Multiphase Flow in Porous Media
Authors: Cromwell V. , Kortum D. J. , Bradley D. J. 
Published: December 2007

ABSTRACT
The value of Computed Tomography (CT) to analyze fluid flow in porous media has been verified, using a medical CT system. A series of simple displacement experiments using Danian chalk and Berea sandstone are presented to prove the feasibility of this concept. Radial and axial cross sectional views of the cores show movement of fluid fronts and changes in saturations at fixed locations. The limitations of the medical computer software provided with the first generation CT system used in this study are discussed and some possible enhancements of the equipment and software are proposed.