bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Small-Scale Heterogeneities on the Effective Dispersivity of Porous Medium
Authors: Kelkar B. G. , Gupta S. P. 
Published: December 2007

ABSTRACT
Dispersivity affects the displacement and sweep efficiencies and the required slug size of a displacing fluid. Unfortunately, the dispersivity values estimated from field tests are a few orders of magnitude greater than the values obtained in laboratory tests. This investigation studies the effect of small scale (or core scale) heterogeneities on the effective dispersivity value in a typical gridblock size used in a reservoir simulator. The study is restricted to contact miscible displacements with unit mobility ratio. A finite element simulator is used to investigate these effects. Physical dispersion is explicitly included in the simulator.
Results show that the effective dispersivity is affected by the degree of heterogeneity, the average length of heterogeneity, the length of the system, and the manner in which the permeability values are spatially distributed. The effect of heterogeneity becomes significant if the coefficient of variance is greater than 0.4. The effect of dimensionless scale length (ratio of average length of heterogeneity to length of the system) on effective dispersivity is insignificant for dimensionless scale values less than .01; above that value dispersivity increases with an increase in the scale length. The effective dispersivity increases almost linearly with an increase in the length of the system for constant dimensionless scale length. This provides an explanation for the similar trend reported for field dispersivity data. A simple correlation is proposed to calculate the effective dispersivity of the porous medium. The effect of the way in which given permeability values are distributed across the medium on the dispersivity cannot be correlated with the parameters investigated, probably indicating that the effective dispersivity is a unique function of the manner in which permeability values are distributed. This effect was not noted previously in the literature; however, it does not affect the general trends.
Foam Flooding of Cores Under North Sea Reservoir Conditions
Authors: McPhee C. A. , Tehrani A. D. H. , Jolly R. P. S. 
Published: December 2007

ABSTRACT
Laboratory corefloods were run to explore the feasibility of foam to provide mobility and injection profile control in a stratified, heterogeneous North Sea reservoir. The objectives were to identify suitable surfactants, from over 100 commercial surfactants initially screened, which were capable of producing stable foam at North Sea reservoir conditions and, to quantify the influence of several reservoir and injection parameters upon foaming performance.
The experimental apparatus essential for the laboratory simulation of foam generation and injection into porous media at reservoir conditions is described.
The test results showed that, compared with brine injection alone, three surfactants were each capable of substantially increasing core pressure gradients in synthetic porous media, when injected with nitrogen gas at conditions of 4300 psig (29.6 MPa) and 230°F (110°C). Effective, resilient foams can also be generated within natural sandstone cores at injection velocities of 10 ft/d (3.05 m/d).
Based on the surfactants evaluated in this study, the dramatic reduction in foam pressure drop (by up to 80 times) in the presence of the North Sea crude used, effectively precludes the use of foam to restrict water or gas channelling at North Sea pressure and temperature.
A New Method for Testing of Gas-Blocking Foams
Authors: Hanssen J. E. 
Published: December 2007

ABSTRACT
A study of foams as gas-blocking agents in model porous media is reported. Foams are generated by displacing surfactant solution with gas, and tested by meas·uring gas permeability as a function of step-wise increasing differential pressure. The method gives a direct, in-situ measurement of foam gas-blocking ability which is sensitive to differences among surfactants tested. Contrary to some previous reports, no correlation is found between surfactant performance in gas-blockage, tests and in bulk foam tests. It is suggested to employ the gas-blockage method for screening purposes instead of bulk tests in studies directed at obtaining maximum gas blockage of porous media.
Integrated Geological/Engineering Model for Barrier Island Deposits in Bell Creek Field, Montana
Authors: Honarpour M. M. , Szpakiewicz M. J. , Schatzinger R. A. , Tomutsa L. , Carroll H. B. , Tillman R. W. 
Published: December 2007

ABSTRACT
Geological heterogeneities controlling fluid production from the Lower Cretaceous Muddy formation in the Tertiary Incentive Project (TIP) and adjacent area in Unit ‘A’ of Bell Creek field Montana were investigated. Production and injection performance and production test data, as well as core, log, and structural data, were integrated to provide an improved geological/engineering model. The model was used to study the influence of the various scales and nature of geological heterogeneities on fluid flow and residual oil saturation distribution in the reservoir.
Information from primary production; initial production rate potential distribution; cumulative primary, secondary, and tertiary production; pressure transient test data; water injection front tracking; electrical resistivity changes due to depletion of residual oil; injectivity histories of injection wells; and areal simulations was integrated to identify fluid flow patterns and residual oil saturation distribution.
Production performance and oil saturation distribution in Unit ‘A’ of Bell Creek field were affected by critical multigenetic heterogeneities, such as stratigraphy and dimensions of facies, valley incisions into the best productive barrier island sediments, high-permeability "channels," reduction in net pay due to diagenetic clay content, faulting and structural dip. These heterogeneities result in large production/residual oil saturation contrasts over small distances. Results of the study showed that the most productive part of Unit ‘A’ is associated with regions of well-developed high-energy barrier island facies (upper shoreface and foreshore); low amounts of diagenetic clay cement; and absence of structural discontinuities. The influence of nature and the scale of geological heterogeneities varied at different stages of oil recovery.
The understanding of reservoir performance in the barrier island system was improved by integrated multidisciplinary analyses of standard data and comprehensive approach to geological and engineering interpretation.
Calculation of Multiphase Equilibrium for Water-Hydrocarbon Systems at High Temperature
Authors: Nutakki R. , Firoozabadi A. , Wong T. W. , Aziz K. 
Published: December 2007

ABSTRACT
Multiphase equilibrium calculations for binary, ternary, and quaternary hydrocarbon-water systems at high temperature were performed using the Schmidt-Wenzel equation of state. The solubility of water in the hydrocarbon-rich liquid phase and vapor phases is modelled using a constant binary interaction parameter between water and hydrocarbon, while the solubility of hydrocarbons in the aqueous phase is calculated using a temperature dependent binary interaction parameter. Two and three phase equilibrium calculations were performed using the method of successive substitution. A stability analysis using the tangent plane criterion was used to determine the correct number of phases present.
At high temperature the solubility of water in hydrocarbon liquids can be quite large. Using the procedure outlined above the solubility of water in the hydrocarbon-rich liquid phase was calculated accurately both for mixtures of water and pure hydrocarbon components, and for mixtures of water and petroleum fractions. The binary interaction parameters used in the hydrocarbon-rich liquid phase and the vapor phase were found to be dependent on the type of hydrocarbon. The interaction parameters for components in the same homologous group such as alkanes, aromatics, and alkenes were found to be almost the same.
The solubility of hydrocarbons in the aqueous phase was calculated reasonably accurately using temperature dependent interaction coefficients in the aqueous phase. Above 200 °F, the binary interaction parameters in the aqueous phase were linear functions of temperature. Binary interaction parameters from two phase binary data were found to be quite adequate to calculate three phase multicomponent equilibrium.
Correcting Oil/Water Relative Permeability Data for Capillary End Effect in Displacement Experiments
Authors: Qadeer S. , Dehghani K. , Ogbe D. O. , Ostermann R. D. 
Published: December 2007

ABSTRACT
Capillary effects in low flow rate displacement experiments cause error in relative permeability values calculated by JBN or Jones and Roszelle methods. The results from a series of displacement and capillary pressure experiments were used along with a history matching package to quantify the changes in relative permeabilities with rate. The experiments were conducted with different rates on short and long cores. The history matching procedure was developed using a one-dimensional, two phase finite difference simulator, and the Levenberg-Marquardt optimization algorithm.
Exponential form for relative permeability functions were used and the change of function parameters with rate was investigated. The results show that for the case of drainage the relative permeability parameters (i.e., end-point relative permeability and saturation exponent) have functional relationships with rate. The saturation exponent in non-wetting phase and the end-point nonwetting relative permeability increase with rate. However, the end-point relative permeability to wetting phase did not show any significant change but the saturation exponent in the wetting phase decreased with increase in rate. Regression equations of these changes were developed. In the case of imbibition, these parameters did not indicate any meaningful trend with rate.
An Overview of Formation Damage and Well Productivity in Oilfield Operations: An Update
Authors: Krueger R. F. 
Published: December 2007

ABSTRACT
Almost every field operation is a potential source of damage to well productivity. This paper provides a broad overview of the nature of formation damage problems, how they occur during various oilfield operations, and their effects on well productivity.
Diagnosis of numerous formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging of fine solids or chemical reactions and thermodynamic considerations. The fine solids may be introduced from well bore fluids or generated in situ by the interaction of invading fluids with rock minerals or formation fluids.
Control of formation damage requires proper design of treating fluids for chemical compatibility and strict quality control of fluid physical and chemical properties during treatment. The use of treating fluid filtration, clean work strings (pipe), and inhibited fluids has been shown to be important in the control of formation damage during well treatment.
Mechanisms of Capillary Displacement of Residual Oil by Gravity-Assisted Inert Gas Injection
Authors: Kantzas A. , Chatzis I. , Dullien F. A. L. 
Published: December 2007

ABSTRACT
Very high oil recoveries are achieved when an inert gas displaces continuous oil or residual oil downwards in water wet columns of glass beads and in sandstone cores, provided that a semipermeable membrane is used at the production end to prevent gas breakthrough. In this paper, pore level mechanisms that control this displacement process are elucidated, as revealed by experiments in 2-dimensional pore network micromodels and unconsolidated columns of glass beads. Visualizations of the displacement mechanisms are presented and their effect on oil production is discussed. By applying principles of capillarity and by using well defined pore geometries, equations have been developed for predicting both water and oil distributions at the pore level.
Installation of Retrievable Liners
Authors: Manley D. D. 
Published: December 2007

Abstract
In today's oil and gas economic environment, oil and gas wellbores must remain competent for long-term production and injection use. Secondary recovery, waterflooding, and tertiary recovery methods of polymer and carbon dioxide injection have given new life to old wells, requiring even
longer use of existing wellbores. Wellbore integrity tests required by state and federal regulations, are designed to protect fresh water zones, prevent hydrocarbon migration into unwanted zones of porosity and insure that wellbores are not in communication with the strata behind the pipe. These integrity tests and the longer more demanding use of wellbores have contributed to oil and gas operators discovering that lengthy sections of the original casing string have disintegrated. Contributing factors of casing failures are external corrosion, electrolysis, and internal metal loss, due to hydrogen sulfide and carbon dioxide. "Retrievable" liner installations provide a method of ameliorating the casing problems, and restoring the old wellbore to service. Through the use of a gelatinous, thixotropic oil-base packer grease, instead of cement, placed in the annular area between the newly installed liner and the original casing string the liner become retrievable. When initially mixed the oil-base packer fluid is liquescent enough to be pumped into the annulus. In a quiescent state it develops the consistency of a stiff grease. Upon agitation, the packer fluid will alter to a consistency capable of being pumped, thus allowing the liner to be recovered.
The retrievable liner provides an alternative to squeeze cementing where the deteriorated casing length is too long to provide for adequate cement fill. The liner offers a method to protect the active production or injection zone from foreign fluid invasion and when needed, allows the installation of special alloy liner equipment to protect against hydrogen sulfide and carbon dioxide environments.
The Water Quality Control Station: A New Monitoring Tool for Injection Water
Authors: Meyer D. R. 
Published: December 2007

ABSTRACT
The success or failure of secondary and tertiary recovery operations can depend in large measure on maintaining the quality of the water chosen to carry the EOR chemicals and to displace and move the oil through the formation matrix toward the producing wells.
Some commonly accepted indicators of poor water quality include the presence of corrosion and its by-products, carbonate and sulfate scale formation and deposition, oxygen and elevated dissolved acid gas levels, high bacterial populations, heavy suspended solids load and oil carryover.
At present, engineers and operators typically rely on periodic, yet relatively infrequent, monitoring of the injection water in order to obtain the data necessary for good water management. Periodic monitoring however may allow occasional but potentially damaging system upsets to occur without detection.
The relative uncertainty of intermittent sampling can be greatly reduced by combining the benefits of continuous in-line filtration with controlled flow rates, accumulated volume, and monitoring of scale and corrosion tendencies. Changes in water quality can therefore be quickly recognized and appropriate, timely measures initiated.
This paper discusses the installation of a Water Quality Control Station, the individual components, and the contribution of each to the definition of water quality problems. A key field case history is presented to show how the concept is applied.
Horizontal Drilling of Eolian Nugget Sandstone in the Overthrust Belt
Authors: Greener J. M , Sauvageau K. A. , Pasternack I. 
Published: December 2007

ABSTRACT
The horizontal recompletion of the Ryckman Creek Well #21 was the first to be attempted in a Thrust Belt Nugget field. The horizontal completion is significant because of the potential to substantially increase oil reserves over what can be produced with conventional methods. A horizontal wellbore has the ability to penetrate long intervals of an oil zone and expand the well's drainage area. The greater open productive interval permits lower drawdown pressures, alleviating the stratigraphic gas/water coning tendencies that have plagued many Nugget fields.
To recomplete the Ryckman Creek #21 as a horizontal wellbore, a directional program was designed to incorporate industry proven tools and techniques. A section was milled in the 7 in (17.7 cm) production casing at a predetermined elevation above the desired horizontal target zone. Medium radius of curvature (20 degrees/100 ft [30.5 m]) tools were utilized to drill the curved portion of the wellbore. A total of 534 ft (162.8 m) of lateral hole was drilled with a steerable bottomhole assembly. The amount of open productive interval was a five-fold increase over the vertical completion originally performed in the Ryckman Creek #21 well.
Permeability Damage to Natural Fractures Caused by Fracturing Fluid Polymers
Authors: Gall B. L. , Sattler A. R. , Maloney D. R. , Raible C. J. 
Published: December 2007

ABSTRACT
Formation damage studies using artifically fractured, low-permeability sandstone cores indicate that viscosified fracturing fluids can severely restrict gas flow through these types of narrow fractures. These studies were performed in support of the Department of Energy's Multiwell Experiment (MWX). The MWX program was a coordinated research effort to study methods to evaluate and enhance gas production from low-permeability lenticular reservoirs of the Western United States.
Extensive geological and production evaluations at the MWX site indicate that the presence of a natural fracture system is largely responsible for unstimulated gas production. The laboratory formation damage studies were designed to examine changes in cracked core permeability to gas caused by fracturing fluid residues introduced into such narrow fractures during fluid leakoff.
Polysaccharide polymers caused significant reduction (up to 95%) to gas flow through cracked cores. Polymer fracturing fluid gels used in this study included hydroxypropyl guar, hydroxyethyl cellulose, and xanthan gum. In contrast, polyacrylamide gels caused little or no reduction in gas flow through cracked cores after liquid cleanup. Other components of fracturing fluids (surfactants, breakers, etc.) caused less damage to gas flows.
The results of fluid leakoff tests indicated that polysaccharide polymers caused a filter cake buildup at or near the crack entrance while polyacrylamide polymers did not cause a filtercake buildup within the time period of the tests. For xanthan gum gels filtercake buildup was reduced for gels containing polymer breakers. For gels containing polymer breakers, 100 mesh sand was an effective fluid-loss control agent for narrow fractures.
Other factors affecting gas flow through cracked cores were investigated, including the effects of net confining stress and non-Darcy flow parameters.
Results are related to some of the problems observed during the stimulation program conducted for the MWX.
Use of Wet Gas Flow for Long-Term Fracture Conductivity Measurements in the Presence of Gel Filter Cakes
Authors: McDaniel B. W. 
Published: December 2007

ABSTRACT
For an operator to predict well production after a fracturing treatment it is necessary to estimate the conductivity of the propped fracture. The validity of these predictions rests on the accuracy of the fracture conductivity estimates. This emphasizes the need to perform laboratory conductivity measurements which effectively simulate reservoir conditions.
Major advances have recently been made in laboratory attempts to measure realistic fracture conductivity values for proppants at reservoir conditions. However, even the most realistic laboratory simulations have used 2% KC1 brines as the flowing medium instead of a gas or hydrocarbon fluid. In an attempt to better simulate fracture conditions in a gas well, the work presented here includes these nine important test parameters: (1) reservoir temperature, (2) extended test time, (3) core wafers, (4) gel residue in the proppant pack, (5) gel filter cakes from dynamic fluid loss tests, (6) frac fluid clean-up period, (7) wet gas as flowing medium, (8) varying closure stresses, (9) non-darcy flow effects.
Using these procedures, with a linear flow conductivity cell, tests have been performed with three different gel systems. These results will be compared to recent work using brine water as the flowing medium, and to other works using gas flow for proppant conductivity measurements.
PUDDLE-PACK Recompletion Propped Fracturing Techniques to Improve Productivity of Multipay Producing Wells
Authors: Darr C. D. K. , Carlton J. C. 
Published: December 2007

ABSTRACT
To increase productivity of a three zone, shot, open hole completion, a "PUDDLE-PACK" has been successfully completed and all three zones individually stimulated. MCA Unit #103, located in Southeast New Mexico, experienced a 2.75 fold production increase after "PUDDLE-PACK" completing and hydraulically fracturing two San Andres intervals and acidizing one Grayburg interval.
The first attempt to hydraulically fracture the lower San Andres zone failed. As a result of the failure to hydraulically fracture the bottom San Andres "PUDDLE-PACK" completed interval, mechanical property and perforation tests were performed on the resin fill material used in the "PUDDLE-PACK" completion process. After analyzing the test data, corrective remedial operations were designed. These remedial adjustments allowed the two San Andres "PUDDLE-PACK" completed intervals to be successfully hydraulically fractured.
This paper describes in detail, the need for selective stimulation of MCA Unit #103, one initial remedial operation, the resin coated gravel fill material mechanical properties testing results, the resin coated gravel fill test perforating results, the remedial operation changes required to hydraulically fracture a "PUDDLE-PACK" completed well, and a complete evaluation of well performance.
Well Test Analysis of Pumping Wells in Multiphase Naturally Fractured Reservoirs
Authors: Aguilera R. , Houston M. , Podio A. L. , Song S. J. 
Published: December 2007

ABSTRACT
Bottom hole buildup pressures on three Wyoming pumping wells have been determined based on liquid level in the annulus as determined from a computerized acoustic device.
These buildup data correspond to a naturally fractured reservoir which produces oil, gas and water. Basic formulations and three case histories are presented:
The case of a well with after flow effects where the buildup data are properly matched using type curves for dual-porosity systems with restricted (pseudo steady state) interporosity flow and the pressure derivative. The case of a stimulated well in a naturally fractured reservoir. In this situation a conventional log-log crossplot of delta p vs. time results in two parallel straight lines with slopes equal to 0.5. Separation between the two lines allows calculation of the storativity ratio, omega. The case of a well in a layered naturally fractured reservoir with variable afterflow effects.
In this case a log-log plot of delta p vs. time shows two parallel straight lines with slopes equal to 1.0. A good match of the data is obtained with a dual-porosity model and the pressure derivative starting at the second 1.0 slope straight line.
Acquisition of the raw data, conversion into bottom hole buildup pressures, and analysis utilizing dualporosity models are presented in detail. It is concluded that pumping wells in naturally fractured reservoirs can be properly evaluated when all phases flowing are taken into account.
The same procedure and formulations presented in this work can be utilized for analysis of conventional singleporosity reservoirs by making Warren and Root's omega equal to 1.0.