bluuebunny/crossref_metadata_2025_split huggingface dataset:
Calculation Methods for Linear and Radial Steam Flow in Oil Reservoirs
Authors: van Lookeren J. 
Published: December 2007

AbstractThe flow of oil and water in a reservoir as a result of steam injection is related to the shape of the growing steam zone. Analytical formulas describing the approximate shape of this zone have been derived both for linear flow in horizontal and dipping formations and for radial flow around injection wells in a horizontal formation.The theory is based on segregated-flow principles such as those previously used by Dupuit,1 Dietz,2 and others. The formulas take into account gravity overlay of steam zones and have been checked against results of scaled laboratory experiments, steam-injection projects in the field, and calculations with a numerical reservoir simulator. From the good agreement with the new calculation method it would seem that the shape of a steam zone is controlled mainly by one group of parameters including steam-injection rate, pressure, and effective formation permeability to steam.The equations can be used to analyze and explain field observations, such as the position of steam/liquid contacts in injection wells, estimates of effective permeability to steam in steam zones, and steam-zone thickness as noticed in observation wells. This paper shows, for example, how a cumulative oil/steam ratio for oil displaced from a steam zone depends on steam-zone pressure, injection rate, and time.With increasing oil viscosity, more bypassing of oil by steam owing to viscous forces will occur, leading to more overlay of steam zones and eventually to narrow tonguing in a lateral direction.The calculation methods provide an evaluation tool for steamdrive and steam-soak processes to reservoir engineers engaged in field operations, project design, and research.
An Empirical Model for Three-Phase Relative Permeability
Authors: Blunt M. J. 
Published: December 2007

SummaryWe present an empirical model for three-phase relative permeability. We allow for changes in hydrocarbon composition, different saturation paths, and the trapping of oil, water, and gas. The model is based on saturation-weighted interpolation between the two-phase relative permeabilities. By writing the relative permeabilities as unique functions of a flowing saturation, the model predicts the behavior for any sequence of saturation changes and accounts for trapping. Layer drainage allows the oil relative permeability to be extrapolated to low saturation. The formulation for water-wet media, including layer drainage and trapping, is tested against experimental three-phase data.
Gravitational Potential Variations of the Sun and Moon for Estimation of Reservoir Compressibility
Authors: Chang Eric , Firoozabadi Abbas 
Published: December 2007

Summary
Total compressibility in a fractured reservoir is estimated using the pressure response due to gravitational potential variations. Both the lunar and the solar gravitational potentials are fully accounted for by inclusion of longer-period components. The semidiurnal and diurnal pressure data show substantial long-term variations. The gravitational potential also contains the same variation trend: the ratio between the potential and pressure has a fairly uniform value over successive cycles. The computed total compressibility is also fairly constant and independent of the cycle.
Conditioning 3D Stochastic Channels to Pressure Data
Authors: Bi Zhuoxin , Oliver D. S. , Reynolds A. C. 
Published: December 2007

SummaryThis work discusses the development and implementation of a procedure to condition a stochastic channel to well-test pressure data and well observations of the channel thickness and the depth of the top of the channel. The stochastic channel is defined by a set of geometric random variables (referred to as geometric model parameters) that describe the location, size, and shape. Channel and nonchannel permeability and porosity are treated as random variables. These four random variables plus the geometric parameters comprise the complete set of model parameters. Multiple conditional realizations of the geometric parameters and rock properties are generated to evaluate the uncertainty in model parameters and the reduction in uncertainty obtained by conditioning to well-test pressure data.
Hydrate Control During Deepwater Drilling: Overview and New Drilling-Fluids Formulations
Authors: Ebeltoft Hege , Majeed Yousif , Sœrgärd Eirik 
Published: December 2007

Summary
Gas-hydrate formation during deepwater offshore drilling is a well-recognized operational hazard. Plugging the blowout preventer (BOP) stack, choke, and kill lines with hydrates can cause a serious well-control problem. We conducted an up-to-date review of the drilling practices and mud formulations applied in deepwater drilling as related to gas-hydrate control and mitigation. The review indicated that salt/polymer mud systems are the most commonly used mud formulations in the Gulf of Mexico, North Sea, and offshore Brazil. Successful drilling with these systems has been achieved to water depths of up to 7,500 ft.
In the second part of this work, we measured the hydrate-phase equilibrium of 25 drilling-fluid formulations. Testing also included two new spotting-fluid formulations. Testing results indicated that, on weight basis, NaCl is the best thermodynamic inhibitor among the salts tested in this work, which are NaBr, Na-formate, KCl, and CaCl2. Although the high solubility of the Na-formate makes it possible to increase hydrate suppression beyond that of NaCl, the former is less effective on weight basis than NaCl. The glycols are considerably less effective inhibitors, on weight basis, than the salts. However, a greater degree of suppression can be achieved by using mixtures of salts and glycols. Among the tested glycols, ethylene glycol showed the best performance compared to Aqua-Col™S, Geo-Meo™ D207, and HP-100N™.
Integration of NMR With Other Openhole Logs for Improved Formation Evaluation
Authors: Minh Chanh Cao , Freedman Robert , Crary Steve , Cannon Darrel 
Published: December 2007

Summary
The recently introduced measurement of total porosity from nuclear magnetic resonance (NMR) tools can help to identify the hydrocarbon type and to improve the determination of formation total porosity (ϕt) and water saturation (Swt) in combination with other openhole logs. In shaly formations, porosities are difficult to estimate in the presence of hydrocarbons, especially those for gas and light oils. Water saturations are even more difficult to estimate because critical parameters such as clay cation exchange capacities/unit pore volume (QV), the formation factor (F) and formation water resistivity (Rw) might not be known. The latter quantities are essential inputs into the Waxman-Smits and dualwater model saturation equations.
In the typical case of shaly gas-bearing formations, both the total porosity corrected for the gas effect and the gas saturation (Sxgas) in the flushed zone can be derived by combining total NMR porosity (ϕNMR) and density porosity (ϕdensity). Adding resistivity logs such as Rxo and Rt helps to differentiate between gas and oil. Furthermore, the flushed zone water saturation (Sxot) computed from 1 − Sxgas can be used in many ways. One procedure uses Sxot in conjunction with the Rxo saturation equation to determine QV or F. Another technique uses Sxot in conjunction with the saturation point (SP) to estimate QV when Rw is known. Yet, another method estimates QV directly from the NMR short relaxation time part of the T2 distribution and use Sxot in conjunction with SP to estimate Rw. The new interpretation procedure follows the sequential shaly sands approach: first, determine porosity, second, determine shaliness, and, third, determine saturation. The new procedure improves on the classical method by offering new ways to compute QV, F and Rw. The methodology is applied to a number of field examples.
Examination of Seismic Repeatability as a Key Element of Time-Lapse Seismic Monitoring
Authors: Hughes J. K. 
Published: December 2007

Summary
The propagation of elastic waves in rocks is determined by the bulk modulus, shear modulus, and bulk density of the rock. In porous rocks all these properties are affected by the distribution of pore space, the geometry and interconnectivity of the pores, and the nature of the fluid occupying the pore space. In addition, the bulk and shear moduli are also affected by the effective pressure, which is equivalent to the difference between the confining (or lithostatic) pressure and pore pressure.
During production of hydrocarbons from a reservoir, the movement of fluids and changes in pore pressure may contribute to a significant change in the elastic moduli and bulk density of the reservoir rocks. This phenomenon is the basis for reservoir monitoring by repeated seismic (or time-lapse) surveys whereby the difference in seismic response during the lifetime of the field can be directly related to changes in the pore fluids and/or pore pressure. Under suitable conditions, these changes in the reservoir during production can be quantitatively estimated by appropriate repeat three-dimensional (3D) seismic surveys which can contribute to understanding of the reservoir model away from the wells. The benefit to reservoir management is a better flow model which incorporates the information derived from the seismic data.
What are suitable conditions? There are two primary factors which determine whether the reservoir changes we wish to observe will be detectable in the seismic data:
the magnitude of the change in the elastic moduli (and bulk density) of the reservoir rocks as a result of fluid displacement, pressure changes, etc.; the magnitude of the repeatability errors between time-lapse seismic surveys. This includes errors associated with seismic data collection, ambient noise and data processing.
The first is the signal component and the second the noise component. Previous reviews of seismic monitoring suggest that for 3D seismic surveys a signal-to-noise (S/N) ratio of 1.0 is sufficient for qualitative estimation of reservoir changes. Higher S/N ratios may allow quantitative estimates.
After a brief examination of the rock physics affecting the seismic signal, we examine the second factor, repeatability errors, and use a synthetic seismic model to illustrate some of the factors which contribute to repeatability error. We also use two land 3D surveys over a Middle East carbonate reservoir to illustrate seismic repeatability. The study finds that repeatability errors, while always larger than desired, are generally within limits which will allow production-induced changes in seismic reflectivity to be confidently detected.
An Analysis of High-Velocity Gas Flow Through Porous Media
Authors: Firoozabadi Abbas , Katz Donald L. 
Published: December 2007

Darcy's law is inadequate for representing high-velocity gas flow in porous media, such as near the wellbore. An analysis of pressure lost during flow through conduits of alternating cross sections suggests more appropriate words for describing the mechanism for energy loss and terms in the flow equation. Updated correlations are presented for the coefficient of the velocity-squared term.

Introduction
Much research has been conducted to understand flow through porous media. Regarding high velocity, suitable correlations and nomenclature are the subject of controversy because of different views on the mechanism causing pressure drop.
This study tries to improve the understanding of high-velocity flow through porous media. Using available data and this research, the best correlation is sought to permit the calculation of high-velocity flow based on permeability, porosity, and character of the rock. permeability, porosity, and character of the rock. We hope that a nomenclature can be suggested that is acceptable to both reservoir engineers and fluid mechanics research scientists. The results should be useful for improving correlations of gas-well flow data and for predicting well flow from core data, fluid properties, and specified conditions. properties, and specified conditions. Early Work on High-Velocity Flow
Fancher et al. measured pressure drop during flow through a large number of unconsolidated and consolidated porous media. They correlated the data by using the porous media. They correlated the data by using the friction factor and Reynolds number, with grain diameter as a characteristic length. They showed that for flow through porous media, an increased pressure drop at high velocity is beyond that proportional to velocity. Data taken at the USBM were correlated using a quadratic equation of pressure drop with the second term of velocity to the nth power. Green and Duwez increased the understanding of high-velocity gas flow data when studying sintered metals. They adapted the equation with a velocity term squared that Forchheimer had developed:
dp v- ---- = ----- + pv 2......................(1)dL k
Comell and Katz measured the porosity, permeability, and B factors for cores, resulting in a correlation of B with permeability. The term B was called a "turbulence factor," but the expression was unacceptable to several researchers.

Language Used in Literature
Space limitations prohibit quoting completely the language used when describing the mechanism that consumes energy at more than a linear rate with velocity. The term used in flow equations (generally the in a quadratic flow equation) also has been given various names according to the author's view of the flow mechanism.
Table 1 assembles selected typical titles and statements quoted from published works. After the flow mechanism has been reviewed, a more appropriate language will be submitted to agree with the concepts developed here.
JPT
P. 211
Theoretical and Experimental Bases for the Dual-Water Model for Interpretation of Shaly Sands
Authors: Clavier C. , Coates G. , Dumanoir J. 
Published: December 2007

Abstract
A simple petrophysical model proposed by Waxman and Smits (WS)1 in 1968 and Waxman and Thomas (WT)2 in 1972 accounts for the results of an extensive experimental study on the effects of clays on the resistivity of shaly sands.
This model has been well accepted by the industry despite a few inconsistencies with experimental results. It is proposed that these inconsistencies resulted from the unaccounted presence of salt-free water at the clay/water interface. Electrochemistry indicates that this water should exist, but is there enough to influence the results? Both a theoretical study and reinterpretation of Waxman-Smits-Thomas data show that there is.
The corresponding new model starts from the Waxman and Smits concept of supplementing the water conductivity with a conductivity from the clay counterions. The crucial step, however, is equating each of these conductivity terms to a particular type of water, each occupying a representative volume of the total porosity. This approach has been named the "dual-water" (DW) model because of these two water types—the conductivity and volume fraction of each being predicted by the model.
The DW model has been tested on most of the core data reported in Refs. 1 and 2. The DW concept is also supported by log data3 and has been successfully applied to the interpretation of thousands of wells. However, the scope of this paper remains limited to the theoretical and experimental bases of the DW model.
Stochastic Reservoir Modeling Constrained to Dynamic Data: Local Calibration and Inference of Structural Parameters
Authors: Le Ravalec-Dupin Mickaële , Hu L. Y. , Nœtinger Benoît 
Published: December 2007

Summary
This paper presents a new geostatistical approach, called the general-inversion method that incorporates dynamic data (pressure transient, well production, water cut) into a reservoir model. It essentially involves two basic tools: the fast-Fourier-transform moving-average (FFT-MA) generator and the gradual-deformation method. The FFT-MA generator produces unconditional Gaussian-related fields that can be perturbed on the basis of the gradual-deformation principles. Thus, the initial structure of the realizations is preserved. Integrating these two primary algorithms within an optimization process yields the general-inversion procedure. The method has at least three significant advantages. First, unlike the traditional inverse approaches, the general-inversion method easily accounts for the constraint relative to prior geostatistical information. Second, the permeability/porosity distribution can be perturbed globally or locally. And third, the method makes it possible to condition the permeability/porosity distribution and the structural (or geostatistical) parameters (mean, variance, correlation length) at the same time. Because of these distinct capabilities, the suggested inversion scheme can qualify as a general one.
The suggested approach was applied to synthetic examples designed to address such key issues as characterization of permeability distribution, updating of a reservoir model to integrate newly obtained data, and estimation of correlation length from well data.
Interpretation of Well-Block Pressures in Numerical Reservoir Simulation(includes associated paper 6988 )
Authors: Peaceman D.W. 
Published: December 2007

Original manuscript received in Society of Petroleum Engineers officeJune 16, 1977. Paper accepted for publication Dec. 20, 1977. Revisedmanuscript received April 3, 1978. Paper (SPE 6893) first presentedat the SPE-AIME 52nd Annual Fall Technical Conference and Exhibition, held in Denver, Oct. 9-12, 1977.

Abstract
Examination of grid pressures obtained in thenumerical simulation of single-phase flow into asingle well shows that the well-block pressure isessentially equal to the actual flowing pressure ata radius of 0.2 x. Using the equation forsteadystate radial flow then allows calculation ofthe flouring bottom-hole pressure.
The relation between pressures measured in abuildup test and the simulator well-block pressureis derived. In particular, the buildup pressure andthe well-block pressure are shown equal at ashut-in time of 67.5 ct x2/k. This is aboutone-third the shut-in time stated by previous authors, who derived their results from an erroneousassumption concerning the significance of thewell-block pressure.
When only a single buildup pressure is observedat a different shut-in time, an adjustment to theobserved pressure can be made for matching with the simulator well-block pressure.

Introduction
When modeling reservoir behavior by numericalmethods, inevitably the horizontal dimensions ofany grid block containing a well are much larger than the wellbore radius of that well. It long hasbeen recognized that the pressure calculated for awell block will be greatly different from the flowingbottom-hole pressure of the modeled well, but theliterature contains few specific guides as to how tomake the correction.
In this study, we confine our attention tosinglephase flow in two dimensions. Consider the fiveblocks abstracted from a regular grid system(Fig.1) with the center block containing a well producingat rate q. Schwabe and Brand proposed therelationship
2 kh Pe - Pwfq = ------- -----------------,..............(1)1n(r /r) + se w
where re is taken equal to x, and pe is an effectivepressure at the"drainage radius," re, obtainedfrom4Pe = Po + Fi (Pi - Po).i=1
Schwabe and Brand did not define Fi, but seemedto imply that it be taken as zero. Thus, in theabsence of a skin effect, Eq. 1 reduces to
2 kh Po - Pwfq = ------- -------------...................(2)1n (x/r) w
The most significant treatment of this subjectuntil now was that of van Poollen et al. Theystated that the calculated pressure for a well block should be tithe areal average pressure in theportion of the reservoir represented by the block.
SPEJ
P. 183^
Optimized Reservoir Development With High-Angle Wells, El Furrial Field, Venezuela
Authors: Smith Richard W. , Colmenares Rodolfo , Rosas Eulalio , Echeverria Isaura 
Published: December 2007

SummaryThe El Furrial field is one of Venezuela's major field assets and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of more than 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15,000 ft, is in its mature stages owing to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high-angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs.A reservoir model was constructed and simulated with detailed reservoir stratigraphy to determine realistic potential of high-angle wells (HAW's). Five wells had been drilled as of June 2000, and the first four wells have proved the effectiveness of the design. The philosophy, modeling technique, well design considerations, problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first HAW in the deep, challenging environment of eastern Venezuela.Results show that optimization objectives can be attained with HAW's, mainly increasing per-well production rate, maximizing per-well recovery, and extending the breakthrough time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate that the geological and simulation modeling technique is reliable and accurate. A pilot program shows that HAW technology provides major advantages to increase production rate and reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems.1The costs associated with the total project are significant, but more importantly, this program becomes very attractive because of the long-term benefits of decreased water-cut related to current water injection; decreased gas breakthrough owing to high-pressure gas injection, and fewer wells required to meet production goals.Technical contributions include the following:The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind. The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible; however, drilling problems caused by formation instability require more study and experience. This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs.
A Sand-Erosion Model for Volumetric Sand Predictions in a North Sea Reservoir
Authors: Papamichos Euripides , Malmanger Eva M. 
Published: December 2007

Summary
Volumetric sand-production data from a North Sea reservoir are interpreted with respect to the applied drawdown. Two sand rates are identified: the initial sand rate related to the increase of drawdown, and the final sand rate related to the magnitude of drawdown. A sand-erosion model is also presented and used for predicting the field data, and the results compare reasonably with the field measurements.