bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mixing During Two-Phase, Steady-State Laboratory Displacements in Sandstone Cores
Authors: Bretz R. E. , Welch S. L. , Morrow N. R. , Orr F. M. 
Published: December 2007

ABSTRACT
This paper examines the changes in fluid distributions and the mixing that occurs in immiscible phases flowing in a porous medium with changes in phase saturations and flow rates. We report experimental results for steady-state displacements with saturations established by secondary drainage, for one outcrop and one reservoir sandstone. Displacements were performed using immiscible liquids of matched density and viscosity at six saturations ranging from residual oil to low initial water saturation. Flow rates at a given saturation were usually varied by more than an order of magnitude.
Trapped, dendritic and flowing fractions were determined for each phase by fitting effluent composition data to the Coats-Smith model as modified by Salter and Mohanty. The oil phase and, contrary to previous investigations, the brine phase both exhibited trapped saturations. That for the brine phase was found to be independent of flow rate for both core samples. The volume of trapped oil phase was also independent of flow rate for the reservoir sample, but the outcrop sample showed velocity dependence at the higher values of oil saturation. The stagnant volume fraction at a given saturation was essentially independent of velocity. Thus, in cases where trapped oil saturation changed with velocity, there was an equal but opposite change in the flowing fraction.
The fits of displacement results to the modified Coats-Smith model were also used to investigate changes in mixing as phase saturations and flow velocities changed. The parameters of that model represent mixing in terms of dispersion and mass transfer coefficients. Those parameters were determined as functions of displacement velocity at each saturation. Dispersion coefficients in both phases were linear functions of velocity at any given saturation. Brine dispersion coefficients were indistinguishable from those obtained in stable, single-phase displacements on the same core. Oil phase dispersion coefficients were, in general, greater than those for the brine phase, but decreased as oil saturation increased, and at low water saturation were the same or less than those for the brine phase. Mass transfer coefficients were also linear functions of displacement velocity and had similar values for both phases.
The differences in displacement results between the two core samples are interpreted in terms of pore structure and changes in fluid distribution with changes in saturation and flow rate. Finally, we discuss the implications of the mixing results for the performance of EOR processes.
Scaling Laws for Immiscible Displacements with Capillary and Viscous Fingering
Authors: Lenormand R. 
Published: December 2007

ABSTRACT
Multiphase reservoir properties are generally extrapolated from laboratory measurements, and scaling laws are based on dimensionless numbers obtained from macroscopic flow equations. This approach is not valid when fingering occurs on the macroscopic scale because of an unfavorable viscosity ratio or capillary effects. We describe a more general scaling technique taking this fingering into account.
Phase Behavior Calculations Near the Critical Point
Authors: Kossack C. A. , Hagen S. , Munkerud P. K. 
Published: December 2007

Abstract
Phase behavior studies have been performed using three component, six component and twenty-two component mixtures. These studies have been performed in such a way that the critical points for the mixtures are approached, either by increasing the temperature while keeping the composition constant or by changing the composition while keeping the temperature constant. It has been shown that regression on the data from these types of experiments gives a better Equation of State (EOS) match, and thus will allow a better simulation of slim tube displacements.
The phase behavior has been calculated using the Peng-Robinson EOS and a comparison between the calculated and experimental results is shown. A comparison of the quality of the phase match, especially the pressure – temperature behavior, is made as a function of the number of regression variables. In all cases substantial improvement, in the EOS's ability to simulate PT-x data was seen as the number of regression variables increased. As a result of the fact that a system with more components has more regression variables available, the twenty-two component system had the best match and the three component system the poorest match. The conclusion was that the two parameter EOS as it is normally used lacks flexibility to calculate phase behavior in the entire, phase space. The phase matches were used to predict additional data at different temperatures and compositions to evaluate the ability of the EOS to extrapolate the phase match. The result was that the EOS did surprisingly well in some cases and very poor in other cases.
On-Site Completion/Workover Fluid Analysis Using a Portable Laser Particle Size Counter
Authors: Underdown D. R. , Newhouse D. P. , Fisher C. B. 
Published: December 2007

ABSTRACT
The frequent use of clear brines as completion/workover fluids has increased the need for improved methods of solids removal during these operations. Studies in recent years, relating formation damage with particle size distribution in completion/workover fluids, magnify the need to make the brines as solids-free as possible (1–8). This fact has led the industry to re-examine the filtration process on completions.
Presently, there are no methods commonly used to determine the particle size distribution in fluids at the rig site. On-site measurements of solids generally involve centrifuging a sample of fluid to determine the percent by volume of solids or monitoring solids content by turbimetric methods. The volume percent of solids is important; however, knowledge of the particle size distribution and population density is important in order to minimize formation damage. Tests can be run in the laboratory on several types of instruments to determine particle size distribution, but these represent "after the fact" data.
In other industries, a small laser particle counter is being used to determine size distribution and actual particles per cubic centimeter in clear fluids. The instrument is interfaced with a PC computer or hand-held calculator to compute the size distribution and the population density of the particles. The instrument is portable, precise, and practical for use in the oilfield. It gives field personnel an opportunity to check the solids distribution of the fluid going into the well and the efficiency of the filtration equipment on-site. The data obtained using the laser particle counter together with the reservoir data is a good means of detecting potential formation damage associated with the solids found in the completion/workover fluids.
Results of lab tests, yard tests, and field data have shown applicability of the laser particle counter to analyze clear brines on-site. Scanning electron microscopy was used to determine the type of material passing through the filters. Comparison of the field and lab tests has given a better understanding of the limitations of the currently available filtration equipment.
Reducing Formation Damage through Two-Stage Polymer Filtration
Authors: Houchin L. R. , Hudson L. M. , Caothien S. , Daddazio G. , Hashemi R. 
Published: December 2007

ABSTRACT
Formation damage resulting from the use of unfiltered polymers during gravel pack completion operations has been addressed as it relates to НЕС completion fluids.1–5 However, other filtered polymer systems exhibit properties which, in specific applications, may out perform НЕС systems. Thus, the performance characteristics of six commonly used polymer systems, hydroxyethyl cellulose (НЕС), clarified xanthan gum (XC), HEC/XC blends, crosslinked carboxymethyl hydroxyethyl cellulose (CMHEC), hydroxypropyl guar (HPG), and standard xanthan gum (XCD), required additional evaluation. Fluid modelling was employed using a new two-stage filtration process (gel filtration) in which the viscosified fluids were optimally sheared and fine-filtered to improve sand placement efficiency and reduce formation damage. The data obtained from this study establishes mixing and filtration design criteria for optimizing completion techniques such as gravel packing, sand washing, polymer diverting, and lost circulation control.
Development of a Gravity-Assisted Gravel Pack System
Authors: Stiles R. F. , Colomb G. T. , Farley D. L. 
Published: December 2007

ABSTRACT
This paper describes the development of a new gravel pack system that is designed to produce higher quality gravel packs in deviated wells. In deviated wells, gravel pack sand deposition is not uniform and a "duning" effect is observed. This duning phenomena has been identified in several studies and results in an incomplete pack of the screen-casing annulus.
In conventional gravel packs, the sand is pumped from the top of the interval to the bottom. This new technique, termed Bottom-Up, reverses this flow and the gravel pack sand is pumped from the bottom of the interval to the top. This changes the way in which gravity acts on the sand particles and prevents "dunes" from forming. This allows for uniform placement of the sand in the screen-casing annulus.
This new concept has been tested extensively in a full scale model to study the flow characteristics and packing efficiency. Several field jobs have recently been completed with deviations ranging from 0 to 67 degrees and intervals lengths from 20′ to 100′. In all cases the gravel pack evaluation log has shown 100% annular packing from the sump packer to directly below the top packer. These wells have also demonstrated high productivities during testing and production.
Rheology of Oil-Base Muds
Authors: Houwen O. H. , Geehan T. 
Published: December 2007

ABSTRACT
The rheological behaviour of invert emulsion muds has been studied at pressures up to 1000 bar and temperatures up to 140° C, Rheological parameters were calculated for the Bingham, Herschel-Bulkley and Casson rheological models. The Herschel-Bulkley and Casson models both give good fits to the experimental rheograms. The Casson model is more reliable for extrapolation purposes than the Herschel-Bulkley model. A pair of two similar exponential expressions were found to be able to model the pressure and temperature behaviour of the two parameters of the Casson model. The expressions, which are based on the relation for pure liquids derived theoretically by Eyring, contain temperature dependent pressure coefficients. The simplifications inherent in the temperature and pressure model are discussed in the light of the temperature and pressure behaviour of the viscosity of common base oils and their constituent hydrocarbons. Field application of the model requires measurement of the rheology of the mud at two or more temperatures and knowledge of the pressure coefficients relating the behaviour of the plastic viscosity to that of the yield point, or the Casson high shear viscosity to that of the Casson yield stress. Pressure measurements or other information are then not required. Applications can be based on Casson or Bingham rheological measurements. The relationships between the parameters of the Casson and Bingham models are disussed.
Pressure Transient Analysis in Finite Linear Reservoirs Using Derivative and Conventional Techniques: Field Examples
Authors: Wong D. W. , Mothersele C. D. , Harrington A. G. , Cinco-Ley H. 
Published: December 2007

ABSTRACT
In this paper, we present a new type curve to be used in the pressure transient analysis of rectangular reservoirs penetrated by a well with skin. The type curve uses the pressure derivative behaviour to aid in behaviour recognition and match confidence and reduces all the wellbore pressure reductions caused by skin and "pseudo-skin" during linear flow to one unique case. Cartesian plot techniques complement the type curve match calculations and ensure reservoir parameter and dimension correctness. The new techniques are applied to two field cases; both a gas and an oil well. The paper concludes that the type curve and cartesian plot techniques can be used to methodically investigate all possible rectangular reservoir configurations and well positions.
The Effect of Trace Quantities of Surfactant on Nitrogen/Water Relative Permeabilities
Authors: Sanchez J. M. , Schlechter R. S. , Monsalve A. 
Published: December 2007

ABSTRACT
This paper proposes a single capillary model incorporating the mechanisms of foam generation, propagation, and rupture. It includes new features not heretofore noted and results in predictions for the influence of variables such as the gas rate, pore geometry, liquid rate, and surfactant concentration on the relative permeability to gas. Since the model is a simple one, only qualitative trends are predicted. Nevertheless apparently contradictory results can be understood in terms of the qualitative trends and new phenomena associated with the behavior of foams generated in situ are predicted.
The model is a steady-state one. The generation rate of lamellae which are subsequently displaced and move along the capillary tube is a constant. To conduct experiments which are intended to confirm the model predictions one must ensure that these experiments yield truly steady-state results. This is not simple and a protocol for achieving steady state is tested. It is recommended as one approach for performing meaningful steady-state experiments.
Systematic steady-state experiments are reported to demonstrate two important model predictions. The first shows the remarkable effect of even very small surfactant concentrations on the relative permeability to gas and the second set of experiments is designed to verify the model prediction that the relative permeability to gas at a fixed liquid saturation may increase or decrease with increasing liquid rates. Both trends have been reported in the literature.1,2
The correspondence between the predicted trends and those observed confirms the value of the single capillary model in understanding the complexities of mobility control using foams which are generated in situ.
Production Operations Forum
Authors: Kleckner J. J. , Dickerson R. C. , Snider P. M. , Zublin J. A. , Sphan R. L. , Menne P. F. , Van Der Lichte J. H. , Ter Horst B. H. , Akkerman N. H. , Rorden L. H. , More H. S. , Kattner J. E. , Samuels A. , Wendt R. A. , Hoh T. , Beauregard E. , Ferguson P. L. , Carnell P. J. H. , Clark H. H. 
Published: December 2007

Abstract
The Production Operations Forum is designed to allow the discussion of and dissemination of information about technical innovations and solutions in production engineering that are of immediate practical use but do not warrant a full-scale paper. Each subject is presented in a five to eight minute period with a discussion period of seven to ten minutes. A wide range of subjects is encompassed in the session. Abstracts of the presentations follow.
The presence of liquids in a gas flow stream, whether the liquids are condensate or formation water, requires energy to be lifted to the surface. If sufficient energy is not present, liquids will accumulate in the well bore and exert additional back pressure on the formation. This results in erratic production, poor compressor performance, and inaccurate data in multi-rate back pressure testing. In the case of low reservoir pressure, the accumulation of liquid may kill the well.
Several methods including plunger systems, sucker rod lift, liquid diverters and gas lift installations are used to successfully move liquids from the well bore. This discussion will address specifically the use of 1.25" concentric pipe (coiled tubing) as a production string to reduce cross-sectional area of flow, thereby increasing the stream velocity and continuously unloading liquids from the wellbore. In many cases the wells requiring liquid lift are low pressure gas wells sensitive to remedial work and kill fluids. Use of a custom machined spool and slip assembly in conjunction with a pump out plug and coil tubing unit injection head allows for the installation of the coil tubing without killing the well. Installation is accomplished by shutting in the well at the bottom master valve and removing the tree above the shut in valve. The spool and slip assembly is installed and a coil tubing unit with injection head is rigged up on the spool. The tubing is run to the desired depth, the slips are set, and the tubing is packed off. The tubing is cut above the injection head and the BOP's and injection head are removed. The tubing is dressed off 2-3 inches above the bowl and slip assembly and the tree is installed. The coil tubing is pressured up with N2 or gas to release the plug and the well is flowed to sales. This "no kill" method has alleviated past problems of returning low pressure gas wells to production following workovers.
New Methods for Controlled Injection of Steam Into Multiple Sands
Authors: Hong K. C. , Griston S. 
Published: December 2007

ABSTRACT
Chevron has been employing two new completion methods to control steam injection into multiple oil-bearing horizons using a single injection well. The two methods, parallel tubing injection and limited entry injection, are used to improve steam utilization and to reduce the need to drill new injection wells.
One of the methods used previously was concentric injection in which steam is injected down two concentric pipes placed inside the wellbore and thereby distributed to two separate sands. The outer pipe can be the well casing itself. This method, however, proved unsatisfactory because one of the strings became plugged due to scale buildup. As a result, injection into both sands was no longer possible. For this reason, the concentric injection method is no longer used. Instead, parallel tubing injection and limited entry injection methods are currently used.
This paper reviews the concentric injection method and presents conceptual details of the two new methods. Theoretical calculations supporting application of these methods are also presented.
Experimental Study of Non-Darcy Flow Through Perforations
Authors: Nguyen T. V. 
Published: December 2007

ABSTRACT
Results of an experimental study of non-Darcy flow through perforations are presented. Pressure drop and flow rate data are presented as functions of the perforation geometry and gravel permeability. Water and air flow data show nonlinear relations between pressure drop and flow rate. Non-Darcy flow experimental results are used to study the productivity of gas wells. Results of this study show that standard Darcy flow analysis can overpredict the productivity by as much as 100 percent.
The Use of Circumferentially Propagated Acoustic Waves in Well Logging
Authors: Guy J. O. , Fertl W. H. , Oliver D. W. 
Published: December 2007

ABSTRACT
An acoustic logging system which uses circumferentially propagated acoustic waves for measuring several parameters in a borehole has been designed and tested. The detection of one type of wave whose particle motion is perpendicular to the borehole wall is used to indicate the presence of vertical or near-vertically oriented fractures in fluid-filled boreholes.
This paper reviews the basic theoretical concepts and instrumentation design of the Circumferential Acoustilog® and presents laboratory data to illustrate the validity and applications of the measured parameters. Recent improvements over previous devices of this type will be discussed. One of the improvements is the incorporation of a direct fluid wave baffle which extends the range of formation velocities that can be accurately measured, and also provides the means for identifying the guided fluid wave. A recent significant improvement to the system is the addition of an orientation section which assists in determining the direction of fracture systems.
Field examples from the United States, Canada, and Europe demonstrate the application of the system in varying lithologies and borehole conditions.
A Microscopic Model of Fluid Flow in Porous Media
Authors: Hardy H. H. 
Published: December 2007

ABSTRACT
A model to describe microscopic fluid flow in porous media is proposed. It offers the potential to predict relative permeability curves from microscopic rock and fluid properties. Conventional descriptions of fluid flow in porous media are based on Darcy's equations which require relative permeabilities and capillary pressure curves to be measured on macroscopic porous material. Prior to 1980, these macroscopically measured parameters could not be quantitatively related to microscopic rock properties. Recently, percolation theory has been used to relate macroscopic rock properties to relative permeabilities in the limit of capillary flow. Diffusion Limited Aggregation has been shown to simulate microscopic flow in the limit of infinite mobility ratios.
The model described in this paper is a new approach to simulating flow through porous media on a microscopic scale. It is based on a variation of diffusion limited aggregation. The model can match coreflood average saturation profiles and production histories as predicted by Darcy's equations while generating saturation distributions resembling viscous fingering. The model can also simulate the limiting cases of infinite mobility ratio and zero flow rates as previously modeled by diffusion limited aggregation and percolation theory. With some simplifying assumptions, differential equations very similar to Darcy's equations can be derived from the microscopic interpretation of fluid behavior in porous media used in this model.
Economics of Fracturing: Some Methods, Examples, and Case Studies
Authors: Veatch R. W. 
Published: December 2007

Abstract
This paper addresses methods for predicting economics of hydraulic fracturing treatments. Discussions focus on maximizing potential profits from accelerated production, reduced costs, and possibly increased ultimate recovery. Pertinent economic criteria are given. Examples are presented to demonstrate analysis methodologies and the sensitivity of economics to certain fracture treatment design parameters.
Fracture Characterization of Multilayered Reservoirs
Authors: Britt L. K. , Larsen M. J. 
Published: December 2007

ABSTRACT
Fracture treatment optimization techniques have been developed using Long-Spaced-Digital-Sonic (LSDS) log, pumpin-flowback, mini-frac, and downhole treating pressure data. These analysis techniques have been successfully applied in massive hydraulic fracturing (MHF) of "tight gas" wells. Massive hydraulic fracture stimulations have been used to make many tight gas reservoirs commercially attractive. However, studies have shown that short highly conductive fractures are optimum for the successful stimulation of wells in moderate permeability reservoirs. As a result, the ability to design and place optimal fractures in these reservoirs is critical.
This paper illustrates the application of fracture analysis techniques to a moderate permeability multi-layered reservoir. These techniques were used to identify large zonal variations in rock properties and pore pressure which result from the complex geology. The inclusion of geologic factors in fracture treatment design allowed the placement of short highly conductive fractures which were used to improve injectivity and vertical sweep, and therefore, ultimate recovery.