bluuebunny/crossref_metadata_2025_split huggingface dataset:
Compositional Multiphase Hydrodynamic Modeling off Gas/Gas-Condensate Dispersed Flow in Gas Pipelines
Authors: Adewuml Michael A. , Mucharam Leksono 
Published: December 2007

SummaryA nonisothermal 1D steady-state compositional two-phase hydrodynamic model describes the formation and flow dynamics of gas condensate in horizontal natural gas pipelines. The two major constituents of the model, hydrodynamics and phase behavior, are coupled through the phase-generation/disappearance-related terms in the continuity and momentum equations. The model is demonstrably capable of predicting the amount, quantity, and distribution of condensate in the pipeline, in addition to the other commonly sought engineering design variables. Parametric studies show that the model is capable of predicting the phenomena associated with gas condensation in pipelines.
Gas Storage and Transport in Devonian Shales
Authors: Schettler P. D. , Parmely C. R. , Lee W. J. 
Published: December 2007

Summary
Natural gas storage in Devonian shales occurs in part because of the adsorption of methane onto internal pore surfaces. Methane is released during production and is a significant fraction of the total gas produced. Thus, porosity, as a measure of gas storage capacity, must be supplemented with a term that will account for the condensed-phase methane. There are additional implications for gas transport in shale. These factors must be considered, for example, in the application of numerical simulators to production from shale wells.
Subsea Blowout-Preventer Systems: Reliability and Testing
Authors: Holand Per 
Published: December 2007

Summary
A comprehensive study of subsea blowout-preventer (BOP) performance in the North Sea during 1978–89 was conducted to identify BOP reliability problems. Evaluations of the BOP as a barrier to blowouts, together with rig downtime caused by BOP failures and malfunctions, showed that BOP reliability has improved significantly during the last few years.
A Proposed Technique for Simulation of Viscous Fingering in One-Dimensional Immiscible Flow
Authors: Odeh Aziz S. 
Published: December 2007

Summary
One-dimensional (1D) oil/water displacement data for a very wide range of unfavorable mobility ratios obtained on three sandpacks show that for these sandpacks, the macroscopic effect of viscous fingering may be captured when its behavior is modeled with a reservoir simulator and one set of relative permeability values. This set may be calculated directly from the experimental data where viscous fingering occurred, or alternatively, it may be generated from relative permeability values obtained on systems with no frontal instabilities.
Physical Properties of Drilling Fluids at High Temperatures and Pressures
Authors: Fisk J. V. , Jamison D. E. 
Published: December 2007

Summary
Rheological and dynamic filtration properties are presented for water- and oil-based drilling fluids. The physical properties were obtained by use of the DYNAMIC HPHT® test system at test temperatures to 400°F [478 K], system pressures to 15,000 psi [103 MPa], and differential pressures to 600 psi [4.1 MPa]. The data indicated that the de Guzman-Andrade law can be used to describe the temperature effects on the viscosity of oil muds. We also observed that dynamic filtration rates of drilling fluids are greatly affected by solids plugging the pore space in the formation. Temperature and pressure affect dynamic, filtration by changing the dispersion of the solids in the fluid.
Transient Stresses and Displacement Around a Wellbore Due to Fluid Flow in Transversely Isotropic, Porous Media: II. Finite Reservoirs
Authors: Seth M.S. , Gray K.E. 
Published: December 2007

Abstract
In Part 1 of this work,1 equations of elasticity were formulated for transversely isotropic, axisymmetric, homogeneous, porous media exhibiting pore fluid pressure. Equations of elasticity and the thermal analogy method were used to determine transient horizontal, tangential, and vertical stresses and radial displacement in a semi-infinite cylindrical region when either a constant rate of pressure or a constant rate of flow is maintained at the wellbore.
In this paper, the approach presented earlier is extended to finite reservoirs for the cases ofsteady-state flow,constant pressures at the well bore and outer boundary andconstant pressure at the wellbore and no flow at the outer boundary.
Results of this work show that radial and tangential stress gradients are high near the wellbore but diminish rapidly away from the well; the vertical stress gradient behaves in the same way but is less severe. Radial stresses are compressive or neutral, whereas tangential and vertical stresses may be tensile, neutral or compressive, depending upon the boundary conditions, the physical properties of the system and the radial distance involved (vertical stresses are always compressive in an unbounded system1).
For constant boundary pressures, both radial and tangential stresses increase with time whereas they both decrease for a closed outer boundary and constant pressure at the wellbore. The vertical stress decreases with time for both systems.
For steady-state systems, radial displacement may be positive or negative, depending upon the dimensions of the system, the pressure differential and the porosity. Radial displacement may be positive or negative for a closed outer boundary but is positive for constant pressures at both boundaries.

INTRODUCTION
The importance, utility and complexity of a realistic appraisal of the stress state at and local to a wellbore were indicated in Part 1. In this paper the analytical approach presented earlier is extended to finite, cylindrical reservoir geometry for the cases ofsteady-state flow,constant pressures at wellbore and outer boundary andconstant pressure at the wellbore and no flow at the outer boundary.
Other than the outer boundary of the reservoir being finite, the physical system and assumptions pertinent thereto are the same as before. The reader may wish to review the mathematical development through Eq. 49 of Part 1 before proceeding here.
Use of an Insulating Fluid f or Casing Protection During Steam Injection
Authors: Willhite Paul G. , Wilson J.H. , Martin William L. 
Published: December 2007

Abstract
Laboratory and field experiments are described which define casing temperatures when high-temperature steam or hot water is injected down tubing with a particular well completion fluid in the tubing-casing annulus. Also discussed is the method used to place and contain this completion material. Field results observed following stimulation of a production well with 646F steam verified laboratory data that indicated thermal deterioration of one well completion fluid. Thermal deterioration in the 15-day field test was sufficient to destroy insulating properties of the fluid tested. By using an insulating fluid in the tubing-casing annulus casing damage can be prevented in wells not adequately completed for thermal stimulation treatments.

Introduction
High-pressure steam injection frequently causes casing failure in wells completed with J-55 short-thread casing. Failures generally are identified by joint pullout or fracture occurring as the wellbore cools after steam injection. Tensile failures are the result of casing deformation when temperature- generated compressive forces exceed the yield strength of the casing steel. Preventing casing damage in injection or production wells completed with J-55 ST and C, 8-rd casing requires reducing the casing temperature and/or the thermally induced compressive forces. There are many ways to reduce casing temperature while steam is injected down the tubing. A common method is to set injection tubing on a packer to isolate the casing from the injected fluid. This technique has been used successfully to protect casing when injection temperatures are 500F or less. Few failures have occurred under these conditions because resulting casing temperatures did not exceed the temperature at which casing steel yields when fully constrained. At tubing temperatures above 500F the low-pressure annulus is not positive protection against casing failure. This is shown in Fig. 1, which compares the relative failure risk for J-55 ST and C wells when steam at temperatures of 400 to 650F is injected down tubing set on a packer in 7-in. casing. The risk of failure is high as injection temperatures approach 650F. Several instances of casing failure have been observed under these conditions. The alternatives to a low-pressure annulus can be divided into two categories: mechanical insulation attached to the injection tubing, and an insulating fluid to fill the entire annulus between the tubing and the casing. This article discusses the use of an insulating fluid for casing protection.
Nitrogen Miscible Displacement off Light Crude Oil: A Laboratory Study
Authors: Hudgins David A. , Llave Fellciano M. , Chung Frank T. H. 
Published: December 2007

Summary
A comprehensive laboratory study of N2 miscible flooding for enhanced recovery of light crude oil was performed. The minimum miscibility pressure (MMP) of N2 is a major constraint to its EOR application, so an empirical correlation for MMP estimation was developed and found to be reliable. Supporting work included many in-house slim-tube displacement determinations of MMP and the compilation and analysis of previously published data. The reservoir fluid composition, especially the amounts of the methane and ethane-through-pentane fractions, was found to be the major determining factor for miscibility. High-pressure core flooding tests with sandstone cores were performed to evaluate the effects of gravity stability and injection mode on the N2 miscible process. N2-gas miscible flooding successfully recovered most of the oil from laboratory cores. Gravity-stable and gravity-unstable displacements gave different oil recoveries, as did secondary and tertiary N2 displacements.
An Evaluation of Field Projects of Steam With Additives
Authors: Castanier L. M. , Brigham W. E. 
Published: December 2007

SummaryThe use of additives to improve both steamdrive and cyclic steam injection in field projects has been tested under a variety of conditions. This technique attempts to reduce gravity override and channeling of the steam by foam generation. Another mechanism appears to be "detergent" cleaning near wellbores by surface-active agents. When successful, this technology seems to be economic even at a low oil price. The results, however, have ranged from excellent to negative. In this paper, we attempt to evaluate the field projects published to date. The results of this study show that the use of additives with steam can provide significant benefits over the use of steam alone. Indeed, addition of surfactant to the steam has proved to be both technically and economically successful when the proper products and procedures were used. Caustics have given mixed results but seem to have been effective in at least one cyclic-steam project.
Evaluation of Jet-Bit Pressure Losses
Authors: Warren Tommy M. 
Published: December 2007

Summary
An experimental and theoretical study was conducted to resolve discrepancies between observed and calculated pressure losses for fluids flowing through the nozzles of jet bits. The use of a nozzle discharge coefficient of 0.95, which is commonly used for roller-cone bits, results in the calculated pressure drop being up to 30% more than actually occurs, with the average error being 14.7% for 770 data points measured with nine different fluids. A relationship is presented to calculate the discharge coefficient as a function of borehole pressure, nozzle size, and mud density, which reduces the mean absolute error to 3% for these data points. Simply increasing the discharge coefficient to a constant value of 1.02 results in reducing the error to 4.1 % without using the more complicated relationship.
Organic Deposition During CO2 and Rich-Gas Flooding
Authors: Monger T. G. , Trujlllo D. E. 
Published: December 2007

SummaryThis paper provides a 17-stock-tank oil (STO) experimental data base on the effect of oil composition on CO2-induced organic deposition. This paper also compares CO2 to precipitating agents that are paraffinic and presents information on the topography of deposition. The results offer insights on evaluating organic deposition during CO2 and rich-gas flooding.
Depletion Performance of Layered Reservoirs Without Crossflow
Authors: Fetkovlch Michael J. , Bradley Mark D. , Works Adonna M. , Thrasher Thomas S. 
Published: December 2007

Summary
This paper presents a study of the rate/time and pressure/cumulative-production depletion performance of a two-layered gas reservoir producing without crossflow. The gas reservoir has produced for more than 20 years at an effectively constant wellbore pressure, thus giving continuously declining rate/time and pressure/cumulative-production data for analysis. The field data demonstrate that Arps depletion-decline exponents between 0.5 and 1 can be obtained with a no-crossflow, layered reservoir description. Rate-vs.-time and pressure-vs.-cumulative-production predictions were developed from both 2D numerical and simplified tank models of a two-layered, no-crossflow system. These results demonstrate the effects of changes in reservoir layer volumes, permeability, and skin on the depletion performance.
Measurement and Modeling of Asphaltene Precipitation (includes associated paper 23831 )
Authors: Burke Nancy E. , Hobbs Ronald E. , Kashou Samir F. 
Published: December 2007

Summary.
Experimental asphaltene precipitation data on several live-oil/solvent mixtures at reservoir conditions were measured to study the effects of temperature, pressure, and composition on precipitate formation and the relationships between critical properties, PVT phase behavior, and precipitate formation. Data generated by the model can be used to identify operating conditions conducive to precipitate formation.

Introduction
Asphaltene precipitation in the reservoir has proved to be a difficult problem to define and study. Field conditions conducive to precipitation include normal depletion, acid stimulation, gas-lift operations, and miscible flooding. Asphaltene precipitation is generally believed to be an irreversible process, which is the main reason it can have a profound impact on production operations. Investigations into asphaltene precipitation have been impeded by a shortage of experimental data and information on precipitation mechanisms. Our investigation included performance of experimental tests to induce and measure precipitation, selection of a thermodynamic model to describe and predict precipitate formation, and performance testing of the model with a variety of reservoir fluids. This paper summarizes the experimental testing, the theory behind the model, and applications of the model to field operations. Relationships observed between the reservoir-fluid phase behavior and the performance of the model are also discussed.

Theoretical Basis
Several theories have been proposed to explain why asphaltenes precipitate. For our work, we defined asphaltenes as the portion of the crude oil that is insoluble in heptane yet soluble in benzene or toluene. We selected a model that describes the precipitation mechanism by polymer solution theory. The large asphaltene molecules are similar in structure and behavior to polymer molecules. The remaining components in the rude oil act as a solvent in which the asphaltenes are dissolved or suspended. Hirschberg et al. used this approach in studies conducted by Koninklijke Shell E and P.
The overall model depends on two types of fluid equilibria: a vapor/liquid equilibriim (VLE) of the total reservoir fluid and liquid/liquid equilibrium(LLE) between he liquid oil and pseudoliquid asphaltene phases. The VLE of the reservoir fluid is modeled first to obtain the composition and fluid properties of the liquid phase. In the LLE segment of the model, the oil is considered to consist of two liquid phases-an oil-rich phase that acts as the solvent and an asphaltene-rich phase that behaves as the polymer. The term "asphaltenes" actually defines a solubility class of components within the crude oil. Precipitates from a crude oil are classified by the solvent used to induce precipitate formation. For this work, n-heptane was used as the precipitating solvent for asphaltene measurements performed on stock-tank oils.
Productivity of a Horizontal Well
Authors: Babu D. K. , Odeh Aziz S. 
Published: December 2007

SummaryAn equation for calculating the pseudosteady-state flow—i.e., the productivity—of a horizontal well is presented that is easy to use and identical in form to the well-known productivity equation for a vertical well. The equation was extracted from a very complex general solution. Application of the equation requires the determination of two parameters: (1) a geometric factor that accounts for the effect of permeability anisotropy, well location, and the relative dimensions of the drainage volume and (2) the skin caused by restricted entry, which accounts for the effect of well length. The paper gives simple equations for calculating these two parameters. The equation is used to study the effects on well productivity of well length, location, and degree of penetration; vertical and horizontal permeabilities; and the horizontal dimensions of the drainage volume. It is concluded that, though each of these variables has a significant effect, the well length and degree of penetration have the strongest.
A Parametric Comparison of Horizontal and Vertical Well Performance
Authors: Mukherjee Hemanta , Economides Michael J. 
Published: December 2007

Summary
This paper presents screening criteria for vertical and horizontal wells with or without induced fractures. The parametric basis of such screening makes the decision on either type of well more objective. A simple procedure to calculate the optimum number of orthogonal transverse fractures in horizontal wells and their sizes is also presented. Two important comparisons have not appeared in the literature: (1) the performance of a fully completed horizontal well with that of a hydraulically fractured well and (2) the performance of a hydraulically fractured horizontal well with that of a hydraulically fractured vertical well. In addition, previous work does not take into account the effect of the plumbing system on well performance. This paper is intended to fill these gaps.
Transient Flow Characteristics of Low Permeability Gas Reservoirs and Improvement of Deliverability by Nuclear Explosion
Authors: Eilerts C. Kenneth , Sumner Eudora F. 
Published: December 2007

Abstract
A program for computing the transient radial flow of natural gas, taking into account significant variable properties of the fluid and of the porous medium was used in an investigation of flow characteristics of formations for which the permeability-thickness product kh is 1 to 100 md-ft. A graphic summary of the results obtained may be used with well flow-test data to estimate kh for the formation in which the well is completed.
Assuming that a nuclear explosion in a gas-containing formation would create a rubble-filled chimney with a diameter of 170 ft and fissures radiating from the chimney wall out to a distance of 255 ft, formation pressure gradients were computed for the recovery of gas with a well drilled into the chimney. These computations for 640-and 160-acre spacing indicate that diminution of the radius segment re - rf over which flow occurs in unaltered formation provides for markedly greater ultimate recovery of gas in place than is possible with conventional well completions. A formation drilled with conventional wells 1.0 mile apart must have a productivity product of kh = 197 md-ft to deliver for 20 years 1.0 MMscf/D of gas into a pipeline operated at 300 psi. Aided by nuclear stimulation, one well can meet the same performance requirements with a kh of only 49 md-ft for the native formation. With a spacing of 160 acres and nuclear stimulation, kh need be only 9 md-ft.

Introduction
Project Gasbuggy of the El Paso Natural Gas Co. and government agencies is concerned with the creation by nuclear explosion of a chimney and radiating fissures in a low-permeability formation containing natural gas. A well is to be drilled and completed in this chimney and tests will be made on this well and other wells in the vicinity to determine the economic feasibility of nuclear stimulation for recovery of the gas. Engineering studies of the Bureau of Mines pertaining to parts of this project have been in progress since 1963. Because of the complexity of the experiment, its cost, and possible economic significance, it is desirable to define the reservoir flow problem, determine by computing the relative importance of the parameters involved, and obtain a measure of the benefits that may be expected. The results should be generalized for application to other projects.
Two parts of this problem have been investigated:
- determination of average properties of the native formation from flow tests of wells, and
- evaluation of the transient flow performance of a low-permeability formation in which a relatively high-permeability area has been created to receive a recovery well.

BASIC EQUATIONS
The partial differential equation for transient radial flow of a gas phase,
(1)
was integrated in the range rd r re. With rd/re = 0.005 and 640-acre spacing rd = 14.9 ft, so that flow over most of the radius is computed by means of Eq. 1. A program previously described by the authors was used for this purpose.
The Skin Effect in Producing Wells
Authors: Hurst William , Clark J. Donald , Brauer E. Bernard 
Published: December 2007

In calculating negative skin, treating the skin as a zone of infinitesimal thickness leads to mathematical difficulties. These can be overcome by assuming an enlarged wellbore radius and using the same equations that apply for positive skin.

Introduction
Because of drilling, completion, and workover practices, the permeability around a wellbore generally is different from the permeability of the formation. The zone with the altered permeability is called "skin" and its effect on the pressure or flow behavior of the well is called "skin effect". Hawkins has shown that the radius and the permeability of this zone are related to the skin by:
(1)
If the permeability in the skin zone is less than that of the formation, the skin is positive; if it is more than that of the formation, the skin is negative. If the two permeabilities are equal, s is zero; that is, there is no skin.
Van Everdingen and Hurst, have given mathematical solutions to the case of a zone of reduced permeability around the wellbore. This skin effect is illustrated in Fig. 1. They treat the positive skin as a zone of reduced permeability of infinitesimal thickness around the wellbore. When applied to a well with negative skin, however, their solutions lead to the calculated flowing well pressure, which is smaller than the formation pressure, i.e., an injection situation. This is a physical contradiction. In this paper, it is shown that this mathematical difficulty can be overcome by assuming an effective wellbore radius larger than the actual wellbore. Existing solutions are modified to include the effect of an enlarged wellbore radius, and thus enable the engineer to deal with negative as well as positive skins.

Theoretical Development
Van Everdingen and Hurst, through the use of Laplace transformation, obtained the following expression for transient fluid influx into a wellbore:
(2)
where tD, dimensionless time, is given by:
(3)
By use of the superposition technique, Eq. 2 can be expressed as
(4)
The values for QtD, reported extensively by van Everdingen and Hurst, are obtained from the following integral:(5)
JPT
P. 1483ˆ