bluuebunny/crossref_metadata_2025_split huggingface dataset:
Three-Phase Relative Permeability of Water-Wet, Oil-Wet, and Mixed-Wet Sandpacks
Authors: DiCarlo D. A. , Sahni Akshay , Blunt M. J. 
Published: December 2007

Summary
We study three-phase flow in water-wet, oil-wet, mixed-wet, and fractionally wet sandpacks. We make the mixed-wet pack by invading a water-filled water-wet pack with crude oil and aging it for a week. This process mimics wettability changes in reservoir settings, leading to a realistic arrangement of wettability at the pore scale. We characterize the wettability of each sand pack by measuring the capillary pressure curves. We obtain the oil and water relative permeabilites during three-phase gravity drainage, by measuring the saturation in situ using computerized tomography scanning. In an analog experiment, we measure pressure gradients in the gas phase to obtain the gas relative permeability. Thus we determine all three relative permeabilities as a function of saturation for each wettability. We find that under uniform wetting, the relative permeabilities of the most-wetting phase (water in a water-wet pack, oil in an oil-wet pack) are similar. However, the relative permeabilities of the intermediate-wet phase (oil in a water-wet pack, water in a oil-wet pack) are very different at low saturations, with spreading oils showing a characteristic layer drainage regime. The mixed-wet pack also shows the layer drainage regime. We also find that the gas relative permeability is smaller in an oil-wet medium than in a water-wet medium. We explain the observations in terms of wetting, spreading, and the pore scale configurations of fluid.
Real-Time Pressure Diagnostics Used To Improve Pretreatment Frac Design: Case Studies in the Antrim Shale
Authors: Dozier G. C. , Sutton T. W. 
Published: December 2007

Summary
This paper describes simple diagnostics steps which can be used ahead of any fracturing treatment to determine fluid and reservoir properties essential to fracturing success. It outlines a logical progression of diagnostic injections and the data obtained from each process. These diagnostic injections have been performed in the Antrim Shale of Northern Michigan to improve the fracture design by allowing real-time data analysis in a user-friendly fashion for quick interpretion on location.
Over 7,000 fracture treatments have been performed in the Antrim Shale of Northern Michigan. Very few have been altered significantly based on pressure data acquired from each preceding treatment. In essence, there has been very little evolution in how operators stimulate the Antrim. Primarily, this is due to the inability to accurately model (fracture) the effect of natural fractures in the Antrim Shale. Nevertheless, it is possible to use these models to analyze pretreatment pressure responses to produce a more efficient frac design and improve the resulting frac conductivity. As the industry moves away from the "cookie cutter" frac design toward one specific design, with minimal additional time and effort, for the well, a mere 10 mcf/d/well increase in production over a period of 10 to 15 years becomes very economical.
This paper will illustrate simple diagnostic tests that can be performed prior to each fracturing treatment to give good indication of fluid efficiency localized rock stress. Under real-time circumstances, a 10 to 15 min injection test followed by a complete falloff can yield an abundance of information regarding the viability of a particular fracturing treatment.
In the Antrim Shale of Northern Michigan, these diagnostic techniques have been used successfully to determine leakoff, closure, fracture extension, and various other parameters essential in designing a fracturing treatment. In addition, pretreatment results have been linked with the success or premature screen-out of particular wells in the Antrim. Through case studies, this paper will show a logical progression of data analysis based on diagnostic results. Resulting in a fracturing treatment that can be designed or altered on location based on actual reservoir response and measured stresses. In turn, operators can regain a measure of predictability in controlling fractured behavior by tailoring a unique solution for each well without excessive time or added cost.
Assessing the Feasibility of a Time-Lapse Seismic Reservoir Monitoring Project
Authors: Blonk B. , Calvert R. W. , Koster J. K. , van der Zee G. 
Published: December 2007

Summary
We discuss a method to assess if a particular seismic survey may be suitable as a base survey for a time-lapse seismic monitoring project, and to predict if anticipated changes in the reservoir's acoustic properties could be interpreted on a repeat survey. Our approach is to generate a simulated repeat survey using a realistic noise realization estimated from the candidate base survey. This repeat survey contains seismic changes that have been modeled by integrating rock and fluid property data, as well as results from the flow simulator. The method can be used to reduce the risk of shooting a repeat survey on which meaningful seismic changes cannot be interpreted. It can also help in deciding the proper timing for an eventual reshoot. Furthermore, the method is valuable for assessing data quality before quantitative interpretation studies. We show an example from the Middle East illustrating a survey that is unfavorable as a base survey. Furthermore, we show examples from the North Sea where application of the method was key for deciding upon a repeat survey and upon the proper timing of a possible repeat survey.
Hydraulic Fracture Propagation in Layered Formations
Authors: Daneshy A.A. 
Published: December 2007

Abstract
This paper reports theoretical and experimental developments involving propagation of hydraulic fractures in layered formations.
Unobstructed fractures are shown experimentally to propagate with a decreasing fracturing fluid pressure. This general trend is in agreement with pressure. This general trend is in agreement with theoretical predictions. Restrictions in fracture propagation result in an increase in fluid pressure. propagation result in an increase in fluid pressure. The relative fracturability of rocks can be determined by a direct experiment, the results of which are clear, easy to interpret, and include all pertinent parameters, such as physical and pertinent parameters, such as physical and mechanical properties of rocks, as well as the reactions between formation and fracturing fluid (for example, leak-off).
Fracturing experiments with layered samples show that with strong bonding between rocks it is difficult to contain a fracture in a formation totally.
The strength of the interface between adjacent formations is shown theoretically to be an important factor in fracture containment. With a weak bonding, fracture containment is possible and is associated with slippage at the interface. The pattern of propagation then will depend on the relative propagation then will depend on the relative mechanical properties of fractured formations.

Introduction
Most industrial hydraulic fractures are created in layered formations. During propagation, these fractures encounter various formations with different physical and mechanical properties. This paper physical and mechanical properties. This paper discusses the effect of those properties on propagation of the fracture. propagation of the fracture.Most of the theoretical studies on fracture propagation have been extensions of Griffith's propagation have been extensions of Griffith's work. Based on an energy criterion, Griffith developed a relationship among fracture shape, material properties, and the external force needed for fracture propagation. The energy source in hydraulic fracturing is the fluid pressure inside the fracture. The relationship between this pressure and material properties is
(1)
(2)
in which
L = fracture extent (length of a two-dimensionalfracture or radius of a penny-shapedfracture)
E = Young's modulus of material
mu = Poisson's ratio of material
gamma = effective fracture surface energy of material
sigma = least in-situ principal stress
A similar equation for a three-dimensional fracture is derived in Appendix A in the form of
(3)
in which
hf = fracture height
E(k) = complete elliptic integral of the secondkind
K(k) = complete elliptic integral of the first kind
k = parameter of the elliptic integrals
Eqs. 1 through 3 show p to decrease with increasing L (Fig. 1) As the fracture becomes larger, it needs less pressure for propagation.
In deriving these equations, no allowance has been made for fluid leak-off into the formation.
SPEJ
P. 33
Use of Temperature Simulations in Water-Control Design
Authors: Hardy M. A. , van Batenburg D. W. , Botermans C. W. 
Published: December 2007

Summary
In this article we discuss a method to predict the temperature in the near-wellbore area during water shut-off treatments. It is essential to have a good estimate of the temperature because it greatly influences the success rate of a treatment. We present some new views on how treatment temperatures can be predicted accurately in order to design and execute a successful treatment. It explains how a production operation simulator can be used with an advanced-processes reservoir simulator to give an accurate estimate of the wellbore temperatures in the treated area. These data allow treatments to be designed on the basis of realistic temperatures rather than on bottomhole static temperatures. The results of the simulations can be used to optimize treatment placement rates, fluid composition, and shut-in times.
Two case histories of recent jobs in the North Sea area are presented where simulations were used to design water-shut-off treatments and their placement. The first case illustrates how cooldown inside the reservoir was used to place a treatment that would otherwise have gelled spontaneously at the reservoir temperature. In the second case, temperature histories for different stages of the treatments were constructed from the simulation results. These temperature histories show that several different activator compositions and concentrations were required for the early, intermediate and final treatment stages.
Capillary Pressure Correlation for Mixed-Wet Reservoirs
Authors: Skjaeveland S. M. , Siqveland L. M. , Kjosavik A. , Thomas W. L. Hammervold , Virnovsky G. A. 
Published: December 2007

Summary
For water-wet reservoirs, several expressions may be used to correlate capillary pressure, or height above the free water level, with the water saturation. These correlations all feature a vertical asymptote at the residual water saturation where the capillary pressure goes to plus infinity.
We have developed a general capillary pressure correlation that covers primary drainage, imbibition, secondary drainage, and hysteresis scanning loops. The graph exhibits an asymptote at the residual saturation of water and of oil where the capillary pressure goes to plus and minus infinity, respectively. The shape of the correlation is simple yet flexible as a sum of two terms, each with two adjustable parameters and is verified by laboratory experiments and well-log data. An associated hysteresis scheme is also verified by experimental data.
The correlation can be used to make representative capillary pressure curves for numerical simulation of reservoirs with varying wettability and to model and interpret flooding processes.
The Strategic Importance of Middle East Oil
Authors: Eller Ernest M. 
Published: December 2007

Introduction
The Middle East is an area of decision for the United States in the critical years ahead. Few Americans realize this; they neither know how much nor care about the lands east of the Mediterranean. This lack of interest and understanding has spawned grave errors in our foreign policy that promise sorrows and dangers for the future. This is tragic, for the destiny of civilization has been decided there often in the past; and it may be again in our own lifetime. Many reasons will bring this about, but large among them looms oil.
We live in an age of oil. Oil means power for peace or war as the Communists press on relentlessly to rule the world. We, of course, get energy from many sources, and coal that made our industrial age possible is still a basic one. Someday we may be able to get all we need from the atom and the sun direct. But the energy that drives man over the earth, carries him across the sea, and hurls him through the air comes from oil. Without oil our machines, many of our factories, our way of life would come to a halt. Without oil we could not hold the sea, which permits us to hold together the far-flung fragments of the Free World and thereby keep an uneasy peace.
Without oil we could not fight a war with any hope of winning - if we could fight at all. Oil is a key to our survival. And the Middle East means oil for there lie most of the world's resources.
This Middle East oil will help shape our destiny through this second half of the 20th century. At the moment we in the West have uneasy control of it, without realizing its almost priceless value. Most of us accept this great blessing with a casual carelessness that is frightening.
Slug-Tracking Model for Hilly Terrain Pipelines
Authors: Taitel Yehuda , Barnea Dvora 
Published: December 2007

Summary
Slug flow is a very common occurrence in gas-liquid two-phase flow. Usually, it is an unfavorable flow pattern due to its unsteady nature, intermittency, and high-pressure drop.
A hilly terrain pipeline consists of horizontal, uphill, and downhill sections. While slug flow is relatively well understood for any of the three configurations, there is a lack of understanding of how flow characteristics change when these configurations are interconnected, as in a hilly terrain pipeline.
Almost all-previous slug flow studies assume a constant slug length once a slug is formed and developed into a stable slug. In reality, a slug can grow or shrink as it travels through a pipeline as a consequence of the hilly terrain configuration. In addition, slugs can be generated at low "elbows" and dissipate at top "elbows." An experimental study conducted by Zheng et al.1 and Zheng2 clearly demonstrates the effect of hilly terrain pipeline configuration on slug characteristics.
In the present work slug behavior in low and top elbows is simulated and studied. The effect of compressibility is included.
Computer Log Analysis Plus Core Analysis Equals Improved Formation Evaluation in West Howard-Glasscock Unit
Authors: Wilson D.A. , Hensel W.M. 
Published: December 2007

This paper describes an orderly and systematic approach to the solution of a parameter identification problem in a West Texas carbonate reservoir. A well-planned coring program and subsequent conventional and special core analysis provide a sound basis for computer log analysis of the complex lithology of the San Andres formation.

Introduction
The Howard-Glasscock field is located south of Big Spring, Tex., in Howard and Glasscock counties, and has produced oil from the Lower Grayburg and San Andres formations since 1929. Sun Oil Co. began pilot waterflooding on the Hart-Phillips lease in 1964. The West Howard-Glasscock Unit was formed Jan. 1, 1972. During 1973, 40 wells were drilled for waterflood expansion. Ten wells were cored extensively and 38 wells were logged with suites designed for computer analysis. Fig. 1 shows the distribution of the cored and logged wells. Approximately 80 wells existed before this project and are not shown.

Coring Program
Because of the complex lithology associated with the producing formations, an extensive coring program was conducted to aid in log interpretation, geological mapping, and injection-well planning. The 10-well coring program is summarized in Table 1. The over-all recovery efficiency was 98.2 percent, with a core loss of only 73 ft occurring during the 4,118-ft coring. Of the unrecovered 73 ft, 52 ft were lost on one well, which increased the core recovery efficiency of nine wells to 99.4 percent. Recovery efficiency contributed immeasureably to the log interpretation program because core-analysis values could be correlated directly with log-derived values without the usual large gaps in core footage.

Basic Core Analysis
The cores were transported to a service company laboratory and analyzed by "whole-core" techniques. The whole-core technique1 analyzes various lengths of full diameter core for fluid saturations, porosity, and two-directional horizontal permeability (kmax and k90°). Whole-core analysis was selected because the heterogeneous nature of the San Andres precludes representative sampling by plug-type core-analysis techniques. Selection of samples for plug-type core-analysis techniques will be discussed later. A total of 1,516 whole-core sections were analyzed. Based on a total recovery of 4,045 ft, approximately two-thirds of the cores were nonreservoir rock, such as shale and anhydrite.
The Marsh Funnel and Drilling Fluid Viscosity: A New Equation for Field Use
Authors: Pitt M. J. 
Published: December 2007

Summary
The flow behavior of a Marsh funnel was numerically simulated for power law fluids and was found to give good agreement with experimental measurements. As a result, the simulation provides a general picture of the meaning of the Marsh funnel time and a correlation enabling this to be converted into a value for effective viscosity of non-Newtonian fluids. For field use, the following equation relates the effective viscosity μe (cp) to the Marsh funnel (quart) time t (seconds) and the density ρ (g/cm−3) μe = ρ (t-25).
Unique ESP Completion and Perforation Method Maximizes Production in World Record Step-Out Well
Authors: Blosser W. R. , Davies J. E. , Newberry P. S. , Hardman K. A. 
Published: December 2007

Summary
In this article we describe the key planning and operational experiences gained during the perforation and completion phases of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. We present an overview of how the M-11 well was completed successfully and describe how a combination of existing and new technology was applied to achieve Wytch Farm's most prolific producer.
Well 1M-11SPy (M-11) the world record for the highest horizontal departure, 10 114 m, at any vertical depth, and a record departure to true vertical depth ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESP's).
A new technique for perforating the well was developed to maximize inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with associated operational issues.
The large departure required the ESP to be set at 8625 m, another world record, with the 1,000 HP motor requiring a new 7 kV cable system and a 1500 kVA variable speed controller (VSC) at the surface. We describe the VSC selection and the physical testing of the complete ESP/cable/VSC system, which was conducted before installation to ensure that sufficient torque could be generated at the ESP for a range of startup and operating conditions and to configure the new type of VSC used for optimal system performance. We also report the experience gained and review the lessons learned.
Optimization of Mud Cleanup for Openhole Horizontal Wells
Authors: Morgenthaler L. N. , McNeil R. I. , Faircloth R. J. , Collins A. L. , Davis C. L. 
Published: December 2007

Summary
Successful completion of openhole horizontal wells requires removal of potential impairment from the near wellbore and formation face. Impairment can reduce well productivity and lead to failure of sand control screens due to plugging and erosion. Shell has adopted the practice in the Gulf of Mexico of employing drill-in fluids with acid-soluble bridging and weighting agents for all openhole drilling and extensive displacement and acid cleanup procedures during horizontal well completions. Drill-in fluid and filtercakes are removed with specially formulated sweeps and by attainment of sufficient velocity to achieve effective displacement. Filtercakes are removed with specially formulated washes applied using washcups or coil tubing to ensure that the cleanup formulations contact the filtercake materials.
Drill-in fluids and cleanup systems must be specially formulated and evaluated for specific applications. We have adopted a suite of laboratory screening tests to evaluate formation damage and removal chemistries to ensure that each well is effectively cleaned. These tests can also be used to evaluate new fluid systems before taking them to the field. Our approach in this instance is to compare data from new fluids to results obtained with fluids with which we have a successful field track record. In this article we will review these procedures and the results with a variety of fluid systems.
Barite Sag: Measurement, Modeling, and Management
Authors: Bern P. A. , van Oort Eric , Neustadt Beatrice , Ebeltoft Hege , Zurdo Christian , Zamora Mario , Slater K. S. 
Published: December 2007

Summary
A joint industry project was established to study barite sag mechanisms and to develop field guidelines to manage the consequences. A simple empirical model was developed to compare sag potential for a wide range of fluid types. In the study, physical properties of the mud, wellbore conditions, and characteristics of the weighting material were shown to have a large influence on sag behavior. The study also included direct measurements of the properties of settled weight-material beds. These results provide new insight into the mechanisms of barite sag and how best to manage problems in the field.
Data from the tests clearly demonstrate that the parameters affecting sag are interrelated and seldom act in isolation. For all muds tested, the highest sag occurred at low annular velocities over angles from 60 to 75°. Drillpipe rotation was particularly beneficial in minimizing barite settlement. Rotation also assisted in re-distributing barite deposits formed on the low side of the hole.
The improved understanding of the mechanisms of barite sag enabled development of practical field guidelines. Case history studies presented in the paper demonstrate how the results of the work together with better field monitoring have been successfully applied to manage the effects of barite sag in high-pressure/high-temperature and extended-reach drilling operations.
Coiled-Tubing Surface Characteristics and Effects on Fatigue Behavior
Authors: Tipton S. M. 
Published: December 2007

SummaryThe manufacturing procedure for coiled tubing induces different surface morphologies on the inner and outer surfaces. Since fatigue is a surface phenomenon, this can lead to different fatigue behavior at the two locations. This has been demonstrated in full-scale bending tests and in axial tests conducted on small coupon samples in closed-loop servohydraulic strain control. Furthermore, service environments can cause localized defects on the outer and inner surfaces of coiled tubing, such as grinding marks, corrosion pits, tool marks, or injector block damage, which can have a first order effect on fatigue strength. However, it is demonstrated in this article that there is an inherent tendency for cracks to initiate on the inner surface of coiled tubing. This tendency leads to the hypothesis that a "threshold severity" for external surface defects could exist, below which the fatigue strength of the tubing is not affected. Limited data confirm this hypothesis, and suggest that the severity could depend on the grade of the material.