bluuebunny/crossref_metadata_2025_split huggingface dataset:
Progress Report of LPG Injection in the Meadow Creek Unit, Lakota B Reservoir
Authors: Harbert L.L. , Reed P.W. , Bray R.K. , Dew J.N. 
Published: December 2007

Abstract
Results of a field test of oil displacement by liquid propane and butane are presented. Since March, 1956, an LPG miscible flood project has been in operation in the Lakota B reservoir, a small reservoir of nine wells located in the Sussex area, Johnson County, Wyo. The Lakota in this reservoir consists of two zones separated by a shale break of 10 to 12 ft. Injection has been into the upper zone only. The average producing depth is 7,350 ft and as of July, 1958, the average bottom-hole pressure at datum (–2,120 ft) was 589 psig. Data on GOR, injected volumes and individual well performance are discussed. During the 28-month period the flood was in operation, 275,000 bbl of propane and butane were injected into two wells, and 72,000 bbl of oil were recovered over normal decline. The reservoir was shut-in July, 1958, to build up pressure to obtain miscibility between LPG and gas.

Introduction
LPG injection has been carried out in the Meadow Creek Unit, Lakota B upper zone since March, 1956. From March 29, 1956, to July 15, 1958, 275,000 bbl of LPG were injected into the reservoir to recover approximately 72,000 bbl of secondary oil. The purpose was to initiate a field test of miscible displacement, a process which promises to increase oil recovery beyond that obtainable by conventional methods of water flooding and gas injection. The basic process involves the injection of LPG followed by the injection of a gas. A preferred method of operation maintains the pressure in the reservoir above that required for miscibility between the LPG and gas. Operations at a lower pressure, where the oil and LPG are still miscible but the LPG and gas are not, are also possible; however, recoveries comparable to the completely miscible operation require the injection of larger quantities of LPG and gas. In either case, essentially 100 per cent of the oil in place can be recovered in that portion of the reservoir swept by the LPG, although the high pressure operation more efficiently utilizes the relatively expensive LPG.
A Mathematical Model for the Solvent Leaching of Tar Sand
Authors: Oguztoreli M. , Ali S. M. Farouq 
Published: December 2007

Summary
Solvent flooding is the basis for a wide range of EOR methods and has been shown to be a possible method of creating initial steam injectivity in tar sands. This paper presents a unique model of the dissolution of a semisolid bitumen, resulting from the injection of a solvent. The solution of the mathematical equations describing this phenomenon is discussed. Results, including a series of two-dimensional (2D) problems, are presented. Numerical aspects are addressed.
The mathematical treatment is based on a pore model that contains bitumen particles dissolving in an interstitial solution. Macroscopic transport mechanisms, based on the microscopic phenomenon, trace the course of diffusing species in a dynamically interactive solid/liquid network. The bitumen particles are given a spherical symmetry such that a radial dissolution integro-differential equation accounts for the volume changes from solvent transfer into an initially immobile bitumen.
An overall numerical approach to the nonlinear system of equations determines the state vector of pressure, saturation, and concentration of the leaching solution. We show that three dimensionless groups control the bitumen-leaching process. The Damköhler and solvent capacity numbers govern the dissolution process, while the Peclet number governs miscible displacement.
A New Pseudosteady-State Model for Dual-Porosity/Dual-Permeability Aquifers and Two Interconnected Single-Porosity Aquifers
Authors: Leung Woon F. 
Published: December 2007

Summary
A new pseudosteady-state (PSS) aquifer model for simulation of the interaction of reservoirs with finite-extent aquifers in dual-porosity/dual-permeability formations has been developed. The fast convolution method,1 which does not require lengthy data manipulation as with the superposition method, is used to implement the analytical solution of the model for time-dependent reservoir/aquifer boundary pressure. The model does not require a table lookup of the rate or pressure function; thus it is computationally efficient and lends itself readily to hand calculations or numerical reservoir simulations. A numerical example on water influx from a naturally fractured aquifer is used to show the utility of the model. The example shows the correct behavior of fractured aquifers quantitatively. The model is also applicable to a system of two interconnected single-porosity aquifers. An example demonstrates that the complex behavior associated with an interconnected aquifer system can be studied with the current model.
Quantitative Evaluation of the Density Log in the Rocky Mountain Area
Authors: Edwards J.M. 
Published: December 2007

Abstract
The neutron log has been accepted as a standard means of porosity determination for a number of years. The presence of clay or silt in sandstone or carbonate reservoirs has an adverse effect on the quantitative use of the present neutron log. A system responsive to the physical properties of the formation and not to its chemical properties overcomes this limitation. A properly collimated logging tool will accurately measure bulk density of a formation. The intensity of gamma rays (from the source) that have undergone Compton scattering in the formation can be recorded and related to the density of the particular medium.
Grain densities of major minerals are known. Fluid density can be considered unity unless gas is the saturating medium. Bulk density from the density log completes the solution of the equation and provides the formation porosity. Success has been obtained with the density log in the Paradox, San Juan and Green River basins of the Rocky Mountain area.

Introduction
Porosity determination in Cretaceous and Paleozic sand sections of the Rocky Mountain area, as well as Paleozoic carbonate sections of the Paradox basin, has with conventional logging methods been difficult. The radioactive density log has been utilized in a number of wells in the Paradox, San Juan and Green River basins and has given extremely accurate results in a large majority of cases.
Since experience is always necessary in order to properly evaluate any new logging device, an attempt has been made to run the radioactive density log through sections representative of typical conditions throughout the area with as many varying conditions of lithology, borehole conditions and drilling methods as possible. This paper dwells predominantly on results obtained in the Paradox zone of Pennsylvanian age in southwestern Utah, the Mesa Verde formation of the San Juan basin and the Frontier sands and Dakota sandstones of the Green River basin of southwestern Wyoming.
EOR With Penn State Surfactants
Authors: Art T. G. , LaBelle G. , Klaus E. E. , Duda J. L. , Nagarajan R. , Biterge M. B. , Ertekin T. 
Published: December 2007

Summary
Petroleum sulfonate surfactants were synthesized from C19, C22, and C26 feedstocks and evaluated in core tests for their ability to enhance oil recovery. All three feedstocks are composed predominantly of saturated paraffinic and naphthenic hydrocarbons. The C19 feedstock includes about 12% aromatics. The hydrocarbons were vapor-phase oxidized at low temperatures to provide cyclic ethers, which subsequently were sulfonated to form a product mixture of mono-, di-, and trisulfonates.
Corefloods were conducted with both sulfonates developed at Pennsylvania State U. and commercial sulfonates in Berea sandstone cores. Production performances have been related to recovery and interfacial activity of the sulfonates. The core tests show that the optimum use of Penn State sulfonates for oil recovery is in the form of dilute slugs. High oil recovery efficiencies are realized when the Penn State sulfonates are used without cosurfactants to form dilute chemical slugs. Specifically, the enhanced oil recoveries obtained with C22 sulfonates are significantly larger than those obtained with the C19 and C26 sulfonates. This is consistent with the oil/water interfacial tension (IFT) and phase behavior of the three types of sulfonates. Furthermore, EOR results and core-effluent analysis studies indicate that sodium carbonate (Na2CO3) in low concentrations is an effective sacrificial agent for Penn State sulfonates.
Paraffin Control in the Northern Michigan Niagaran Reef Trend
Authors: Newberry M. E. , Addison G. E. , Barker K. M. 
Published: December 2007

Summary
Wax deposition on downhole equipment and in chokes, flowlines, separators, dehydration and storage equipment is a costly problem in the northern Michigan area called the Niagaran Reef trend. A number of mechanical removal techniques have been used to treat for paraffin. Among these are paraffin cutters, plunger lift, rod scrapers, hot oil or water, plastic coatings, and flowline pigging. Improvements in chemical formulation, testing, and applications have resulted in a number of economically successful chemical programs for paraffin control. Examples of field problems and solutions are presented.
A New Look at Gravel-Pack Carrier Fluid
Authors: Scheuerman R. F. 
Published: December 2007

Summary
For gravel-pack carrier fluids, less viscosity is needed downhole than for suspending and pumping high gravel loadings on the surface. To achieve this dual viscosity, breakers are added to degrade the viscosifying polymers. Unfortunately, viscosity breakback criteria are not well-defined. In addition to the type and concentration of breaker and temperature, the apparent viscosity breakback time of a polymer solution also depends on the shear rate at which the viscosity is measured. As a result, industry breakback data generally disagree because of the variety of instruments and shear rates used to measure viscosity.
This paper discusses new viscosity breakback criteria for polymer-viscosified gravel-packing carrier fluids that are based on gravel settling. Because settled, noncompacted gravel remains fluid, the time required for gravel compaction to begin is a useful criterion for maximum slurry placement time. Similarly, the time for the entire settled gravel column to become compacted is useful as a minimum shut-in time to ensure a stable pack. These criteria correlate well with fluid performance and apply to slurries with different initial viscosities (including crosslinked gels), brine densities, and gravel sizes. These times also can be correlated with low-shear-rate (0.03 second−1) Brookfield carrier-fluid viscosities when it is more convenient to take viscosity rather than gravel-settling data. Data useful for formulating gravel-pack carrier fluids are also presented.
Although this paper does not define optimum downhole carrier-fluid properties, the new criteria reflect downhole conditions better than most previous criteria. They should give better correlation with model studies and field experience and, in turn, should lead to a better understanding of the requirements for optimum downhole performance.
Economic Evaluations
Authors: Watkins P.B. 
Published: December 2007

Abstract
Formulas are developed and presented graphically which permit the rapid evaluation of projects, with the minimum of data and calculation. Methods for more detailed appraisals are discussed with particular reference to the Canadian income taxes, but U.S. taxes are also treated. "Rate of return", or "profitability index", is related to payout times and "profit ratio" for 100 per cent working interest cases.

Introduction
Many arguments can be put forth both for and against the inclusion of a tax factor in economic analyses. No attempt is made in this paper to resolve this particular controversy, other than to suggest that the payment of income taxes is inevitable, sooner or later, and in one form or another, for any company that is to survive beyond an initial expansion stage.
In the first part of this paper, the formulas and arguments are developed both for those who (for policy or other reasons) ignore income taxes, as well as for those who face the prospect of reaching a taxable position in the near future. For the latter cases, it is assumed that the project under consideration is subject to various income tax rates from zero upwards. This, of course, can lead to a conservative estimate, and further, it allows a consistent series of analyses to be made in line with any given tax policy which will be directly comparable as to profitability.
N2 and CO2 in the Oil Field: Stimulation and Completion Applications
Authors: Ward Victor L. 
Published: December 2007

SummaryThe use of both N2 and CO2 in oilfield stimulation treatments dates back more than 20 years.1 Early use was limited, but the past few years have brought about an increase in the use of both, as well as new, unconventional applications of these products.
Simulation of Compositional Processes: The Use of Pseudocomponents in Equation-of-State Calculations
Authors: Schlijper A. G. 
Published: December 2007

Summary
A new method is presented for performing equation-of-state (EOS) calculations with pseudocomponents that are obtained by lumping pure components of a multicomponent reservoir fluid description. The method recognizes that a pseudocomponent represents a mixture of components and thus has the thermodynamic behavior of a mixture, rather than that of a single component. The standard expression for the chemical potential is replaced by an adapted pseudopotential. The method also yields convenient procedures for obtaining phase densities and viscosities.
The accuracy of the method is demonstrated by comparing phase splits, lumped mole fractions in liquid and vapor phases, and phase densities and phase viscosities obtained from a lumped fluid description with the same data as those obtained from a fully compositional description of hydrocarbon systems. Generally, deviations are not more than a few percent. The method enables the use of a reduced compositional fluid representation in numerical simulation studies without any essential loss in modeling accuracy.
An Experimental Study of the In-Situ Gelation of Chromium(+ 3)/Polyacrylamide Polymer in Porous Media
Authors: Huang Chyi-Gang , Green Don W. , Willhite G. Paul 
Published: December 2007

Summary
Gelled polymers are being used increasingly as reservoir flow control agents to improve the water-to-oil ratio (WOR) in waterflooding. To date, little has been published in the literature on the in-situ gelation of polymers in porous media. This work was undertaken to study the process of in-situ gelation of a gel system consisting of a polyacrylamide polymer, sodium dichromate, and thiourea. The experiments consisted of continuous injection of gel solutions into 1-ft [0.3-m] unconsolidated sandpacks. Pressure distributions along the flow direction were used to interpret the nature of gelation in the porous media. We found that gelation occurred much earlier than anticipated from beaker tests where gel solutions were under conditions of no shear-e.g., a gel solution with a nominal 10-day gel time in a beaker gelled in 85 hours in a porous-medium run. Shear was considered one of the major factors affecting the in-situ gelation rate, and we determined that gelation times decreased with increasing in-situ shear rates. Under the same in-situ shear rate, the in-situ gelation times were approximately equal in sandpacks prepared from different grain sizes. The order in which in-situ gelation occurred along the flow direction indicated that the shear history affected gelation time. Effluents from displacements with gel solutions were analyzed to evaluate die change in the properties of a gel solution as it moved through the porous media. The chemical analysis indicated that the retention of polymer was marked after the in-situ gelation developed.
Rock Dissolution and Consumption Phenomena in an Alkaline Recovery System
Authors: Krumrine Paul H. , Falcone James S. 
Published: December 2007

Summary
Consumption of alkali in the reservoir (loss of pH value) is a major concern to engineers designing alkaline slugs for EOR. Although several attempts have been made to model and to quantify these effects, the complexity of silicate chemistry has been a major stumbling block in adequately and realistically describing the mechanisms.
The data and mechanisms presented in this paper indicate that recently proposed consumption models should be modified to incorporate lower limits on SiO2 solubility at high pH values. A simple pseudo-first-order kinetics model is presented that provides an easy method to estimate the decrease in pH value and buildup of silica vs. time for any reasonable reservoir conditions where alkaline chemicals are used. When these limits are properly applied, the past long-term trends in laboratory data can be better explained. The implications of these changes in the dissolution rate model for improved slug design are discussed.
The Role of Thermal Analysis Techniques in the ln-Situ Combustion Process
Authors: Jha Kamal N. , Verkoczy Bela 
Published: December 2007

Summary
Thermal gravimetric analysis (TGA) and differential scanning calorimetry (DSC) studies were conducted on two Lloydminster region, Canada, heavy-oil cores, extracted oil, and mineral matter. Fig. 1 is a general schematic of the thermal process, such as evaporation, distillation, thermolysis, low-temperature oxidation (LTO), thermal cracking, combustion, coking, polymerization, and thermal alteration of mineral matter.
Four core samples and their extracted oils were examined for propensity of coke formation under helium atmosphere. A two- or three-fold increase in the fuel content was observed in the cores compared with the extracted oil. This indicates a selective and significant contribution of the minerals to the coke-forming mechanism. The data from DSC and TGA experiments were used to calculate enthalpy values and ignition temperatures. These data suggest that heat generated by LTO reactions is significant during in-situ combustion.
With the exception of Sand D, the thermal alteration of the mineral matter at 600 and 900°C [1,112 and 1,652°F] was significant. In Sands A and B, the percentage of fine particles, &lt;2 μm, doubled at 600 and 900°C [1,112 and 1,652 °F] compared with that at 100°C [212 °F], Although kaolinite constituted between 15 and 75% of the fine particles in all cases, it was not detected in appreciable concentrations when the sand was heated at 600 or 900°C [1,112 or 1,652°F]. These results indicate that potential problems during oil production could arise from the migration of fine particles. The mineral-analysis data obtained from these core samples suggest that swelling of clays during wet combustion may not be sufficient to have a deleterious effect on air/water injectivity or oil production. The results from TGA/DSC experiments are complementary to those from combustion-tube tests and provide the kinetic, thermal, and mineralogical data required for numerical simulation, planning, and design of an in-situ combustion project.
Evaluation of the Wilmington Field Micellar/Polymer Project
Authors: Fanchi J. R. , Carroll H. B. 
Published: December 2007

Summary
The Long Beach micellar/polymer pilot in the Wilmington field has been evaluated. Actual recovery efficiency is about two-thirds of coreflood and simulation model estimates. This relatively high recovery efficiency represents a technically successful flood. Oil recovery was less than optimal, however, because of problems associated with production from an unconsolidated formation and the presence of Desulfσvibrio bacteria.
Miscible Displacement of Crude Oil by CO2/SO2 Mixtures
Authors: Sayegh S. G. , Krause F. F. , Fosti J. E. 
Published: December 2007

Summary
Slim-tube displacement tests on a Pembina Cardium stock-tank oil using CO2, SO2, and four CO2/SO2 mixtures as the flooding agents demonstrated that the mixtures have lower minimum miscibility pressures- (MMP's) than both pure components. More oil was recovered from Berea sandstone cores when CO2 and a CO2/SO2 mixture were the flooding agents than when SO2 was used. Carbon dioxide and the CO2/SO2 mixture recovered comparable quantities of oil from Indiana limestone, while a severe loss of permeability was observed in the corresponding SO2 flood. Rock/fluid interactions characterized by mineral dissolution and precipitation were observed with all flooding agents in both rock types. New mineral phases formed abundantly in CO2/SO2 and SO2 corefloods of Indiana limestone and account for the severe loss of permeability noted in the latter corefloods.
The Impact of Oil Aromaticity on CO2 Flooding
Authors: Monger T. G. 
Published: December 2007

AbstractThis paper investigates the role of oil aromaticity in mis-cibility development and in the deposition of heavy hydrocarbons during CO2 flooding. The results of phase equilibrium measurements, compositional studies, sand-pack displacements, and consolidated corefloods are presented. Reservoir oil from the Brookhaven field and synthetic oils that model natural oil phase behavior are examined.Phase compositional analyses of CO2/synthetic-oil mixtures in static PVT tests demonstrate that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. The results of tertiary corefloods performed ,with the synthetic oils show that CO2-flood oil displacement efficiency is also improved for the oil with higher aromatic content. These oil aromaticity influences are favorable.Reservoir oil experiments show that a significant deposition of aromatic hydrocarbon material occurs when CO2 contacts highly asphaltic crude. Solid-phase formation was observed in phase equilibrium and displacement studies and led to severe plugging during linear flow through Berea cores. It is unclear how this solid phase will affect oil recovery on a reservoir scale.
An Accurate Numerical Technique for Solution of Convection-Diffusion Equations Without Numerical Dispersion
Authors: Fleming P. D. , Mansoori J. 
Published: December 2007

Summary
A technique is presented that optimizes the accuracy of numerical solutions to convection-diffusion equations while eliminating the detrimental effects of numerical dispersion. Such equations arise in the simulation of EOR processes where front smearing as a result of numerical dispersion can distort the sharp displacement fronts that are such an important part of the processes. Such front smearing can also lead to false predictions of breakthrough times. More accurate, and hence more reliable, simulation of oil recovery processes should facilitate the assessment of the economics of EOR processes. Our technique uses a parameterized, third-order-correct algorithm and Fourier analysis. The Fourier analysis allows for analytical solutions of both the differential equation and the algorithm. This enables the formulation of a concise method for requiring that the numerical solution conforms as closely as possible to the correct solution. The method is illustrated by performing the optimization on several examples with different degrees of convection and dispersion. The solutions have no numerical dispersion and little truncation error. Our method can serve as a starting point for generalization to the solution of more complicated equations that occur in multicomponent, multiphase reservoir simulators. Suggestions for such generalizations are presented.