bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ethical Issues in Patient–Physician Communication About Therapy for Cancer: Professional Responsibilities of the Oncologist
Authors: Wenger Neil S. , Vespa Paul M. 
Published: March 2010

Abstract
Value in cancer care from a patient-centered perspective not only requires full oncologist-to-patient communication of information about potential treatments, but also imbues in the oncologist a responsibility to evaluate the value of cancer therapies and to offer to patients only those potential therapies that are appropriate for the patient. A case is presented in which the possibility of a low-probability treatment presented without adequate context or advice led to a prolonged, unsatisfying death for a young person with advanced cancer. The professional responsibility of the oncologist includes provision of care based on wise, cost-effective management aimed at meeting the needs of the individual patient. The oncologist has the clinical knowledge, is aware of a patient's clinical details, and has the relationship with the patient that permits understanding his or her values in order to guide cancer care decisions. The oncologist must identify the spectrum of treatments that are indicated for the patient, understand patient preferences and goals in order to inform the patient about options, and advise the patient concerning choice of cancer care. Oncologists as a professional group can ensure the use of standardized outcome measures, promote communication of prognosis and goals in order to guide optimal cancer care choices, and ensure appropriate patient selection and reasonableness in the cost per benefit increment of treatments. In this way, oncologists can ensure value in cancer care.
Mainstream Options for Heavy Oil:Part I-Cold Production
Authors: Chugh S. , Baker R. , Telesford A. , Zhang E. 
Published: March 2010

Abstract
Heavy oil production has enjoyed a resurgence as both major and junior operating companies diversify their portfolios and pursue new opportunities. The key factors for the renewed interest are:Improved profitabilityTechnological advances have improved productivityEnormous reserve sizeLow geological riskLow capital investment required for non-thermal projects
In addition, immediate concerns about environmental issues such as sand disposal and gas migration appear to have been resolved to the extent that there is no immediate threat to the operating environment. The key risk factors remain oil and gas prices, land prices, and economic means of sand disposal. This paper focuses on "cold production" as one of the most attractive new technologies used to produce heavy oil in the Lloydminster area. Steam assisted gravity drainage (SAGD) will be the focus of a future paper.

Introduction
Western Canadian crude oil production is approximately 320,000 m3/d. Of this amount, 50﹪ is comprised of heavy crude and bitumen. While bitumen demand has been essentially flat since the mid- to late-1980s, heavy oil production has doubled from 56,000 m3/d to 112,000 m3/d in the last ten years(1).
Why Heavy Oil?
New Life from an Old Field-PKCU #2 Waterflood
Authors: Krasey R. 
Published: March 2010

Abstract
The Pembina Keystone Cardium Unit #2 is located on the eastern edge of the Pembina Cardium oilfield. PKCU #2 has been on primary depletion for over 40 years and was nearing the end of its economic life. In late 1995 the Pembina Exploitation Team within Canadian Oxy decided to review the area in detail one last time. The final result of the exhaustive work, which included core floods, geological review, a 3D simulation, facilities and production optimization review, and a reservoir depletion plan, was a large scale waterflood on a depleted field. It is expected that the recovery factor for the waterflood will be 20% as compared to the primary recovery factor of 11%. The over 10,000,000 BOEs of incremental reserves will be developed for &lt; $3.00/BOE. Waterflood start up was anticipated for late summer 1998.

Author's Note
Since this paper was originally written the following actions have taken place. CanadianOxy and Working Interest Owner approval was granted in the third quarter of 1997. Facilities Engineering and Operations began the process of consultation with area residents and gaining pipeline right of ways. Construction was set to begin in the Summer of 1998. Within CanadianOxy at that time a review of our properties was conducted. It was decided that all of CanadianOxy's Pembina properties would be sold. All work in the field was suspended.
PKCU #2, along with the rest of CanadianOxy's Pembina properties, were sold to Penn West Petroleum in December 1998. Penn West is currently reviewing a scaled down version of the Keystone Waterflood.

Introduction
With the discovery of the Pembina Oilfield in the mid-1950s rapid development drilling was followed by the implementation of a waterflood. Most of the Pembina Cardium was under waterflood by the mid-1960s. The main western portion of the Pembina Cardium, centered around the town of Drayton Valley, was developed using waterflood on 80-acre spacing 5-spots. The southeastern portion of the Pembina Cardium, centered around the Village of Breton, was anomalous. Most of it was developed on 160 acre spacing on primary depletion. PKCU #2 is located in the SE portion of the field.
Historically any secondary recovery scheme at PKCU #2 was deemed to be too risky for some of the following reasons:The overlying conglomerate would act as a thief zoneThe low reservoir pressureThe old geologic model of the sandstone which consisted of independent sand lenses was poor for waterfloodingThe value of the gas and liquids
The uncertainty and risk with waterflooding PKCU #2 meant that the project could never get corporate and partner approval until some of the following questions were answered:Can you successfully waterflood a reservoir with high gas saturation and low pressure?What is the true geologic model?What is the cost of implementing a waterflood?What production and recovery could be anticipated?What is the downside risk?
The 1995 Waterflood study included the following elements which were meant to answer all questions and concerns:
How Many Pseudo-Components Are Needed to Model Phase Behaviour?
Authors: Thomas F.B. , Shtepani E. , Imer D. , Bennion D.B. 
Published: March 2010

Abstract
Equation of State (EOS) modelling has become a very important part of reservoir fluid analysis. EOS modelling is used as an adjunct for experimental analysis in the capacity of quality control and quality assurance. It is also used by oilfield practitioners to assess what type of compositional trends they can expect as a function of time. Still other applications include full compositional simulation where the EOS approximates the compositions of the phases in situ.
The science of EOS modelling is well documented in the literature. There have been a number of good publications including text books and papers that outlined the basis for EOS applications and the origin of such analysis in terms of theoretical constructs. However, the art of EOS modelling has been less extensively reported in the literature and it seems that experience often means the difference between obtaining a representative EOS model and not. Indeed, the approach to obtaining a good EOS model appears to be very subjective.
This paper presents an approach to EOS modelling involving a specific protocol. This protocol can be used every time and should result in abbreviating the path to a representative EOS model. To put EOS modelling into perspective, this paper begins with a discussion of the five areas of empiricism associated with the EOS. A brief discussion of the two main types of application\ follows and then the technique proposed for practical EOS modelling is described.
The protocol suggested is:Define the use of the EOS model. Is it going to be used for volatility- or extraction-based systems?Acquire experimental data that represent the application.Determine the number of components required.De-couple the different areas of the data and associate them with their respective VLE parameters in the EOS.Tune the constitutive relations to the data that are de-coupled from the VLE computations.

Technical Background and EOS Empiricism
The equation at the heart of EOS modelling is
Equation (Available In Full Paper)
The necessary condition for the computation of phase equilibrium is equality of component fugacity, fi, phase to phase. The sufficient condition is the minimization of free energy, which can also be expressed as a molar-weighted average of the component fugacities across all phases [Equation (2)]. Equation (Available In Full Paper)
No matter what the numerical engine for the computations, the calculation of fugacity or chemical potential must occur. The great breakthrough provided by the EOS is that the integral in Equation (1) can be readily and easily computed, over and over in the iterative sequence of the solution of the nonlinear equations(1–3).
It should be remembered that Equation (1) is perfect. There are no simplifying assumptions, and if the parameters in Equation (1) are known with a high degree of accuracy, then the computation of fugacity will be accurate. Therefore, the more accurate the EOS, the better the fugacities and the more representative the phase behaviour predictions.
Trends in Tight Gas Sand Production
Authors: Wattenbarger Robert A. 
Published: March 2010

Abstract
The growth of tight gas sand production in the U.S. has been steady and fairly dramatic the last few years. The term "tight gas" is actually a misnomer that has became somewhat standard. Of course, the gas is not tight but rather the producing formation (i.e., low permeability). There is an official guideline of a tight gas sand that has been used for legislation and regulation purposes: the permeability must be less than 0.1 millidarcies. A reservoir is classified as "tight gas" if it meets this criterion.
Figure 1 shows production rates for the three categories of unconventional gas production in the U.S.: tight gas sand, coal bed methane, and gas shales. It can be seen that tight gas sands dominate unconventional gas production. Tight gas sand production has increased from 2.5 Bcf/d in 1970 to 9.2 Bcf/d (about 3,400 Bcf/year) in 1996. This represented only 4% of U.S. gas production in 1970, but a much more significant 17% in 1996. Although coal bed methane and gas shale production are increasing, they are much less significant than tight gas sand production.
Figure 2 shows where the tight gas sand regions are located. Figure 3 shows how tight gas sand production has grown in the major regions from 1970 to 1996. Except for the San Juan Basin, the production rate has continued to climb for all regions during this time. The South Texas region is near the Mexican border but is not shown in Figure 2. In general, the regions have increased production rate not only by adding wells but also by achieving more productivity per well. Improving technology has been a major factor in increasing well productivity.

Economic Factors
The growth of tight gas production is certainly tied to the overall growth of the gas industry and is affected by the same economic factors. Some observers have been predicting for decades that natural gas would eventually become more valuable and more plentiful than oil. Fifty years ago, gas was regarded as essentially a nuisance that came with the discovery and production of oil. It was common to dispose of produced associated gas by venting it to the atmosphere because of the limited market and transportation for gas and the high cost of storing gas by reinjection.
Figure 4 shows that the relative importance of gas and oil has gradually changed over the years to favor gas. Gas production has exceeded oil production every year in the U.S. since 1969 on an energy content (BTU) basis, except for the mid-1980s, and the margin has been growing in recent years. More importantly, the wellhead revenue for gas has exceeded the wellhead revenue for oil since 1992, and the margin is becoming greater. The profit comparison is even more dramatic since gas is generally cheaper to find, develop, and produce. A number of changes have taken place over the last few decades to bring about the growth of gas production.
Overestimation of Original Gas in Place in Water-Drive Gas Reservoirs Due to a Misleading Linear p/z Plot
Authors: El-Ahmady M.H. , Wattenbarger R.A. , Pham T.T. 
Published: March 2010

Abstract
A straight-line plot of p/z vs. Gp (cumulative gas production) is widely used to estimate the original gas in place. It is known as the p/z plot technique. The linearity of that plot has been historically known to be a unique feature of a volumetric (closed) reservoir. In this paper, we show that a uniqueness problem may exist when using the p/z plot. In other words, if the reservoir is in contact with an aquifer, a straight-line may exist on that plot causing a major overestimation of original gas in place. This uniqueness problem is proved to be due solely to the unsteady state nature of aquifers.
A simulation study was performed to determine the conditions for such a misleading straight line. Several examples demonstrate that it is possible to construct a synthetic data set for a water-drive gas reservoir such that a misleading straight-line plot is obtained. This misleading straight-line is shown to be due to certain rate schedules. The conventional material balance equation is coupled with an aquifer mathematical model to obtain this schedule. In this paper, an actual field case is presented as an example of this possible overestimation of original gas in place due to a misleading linear p/z plot.

Introduction
The material balance equation is an expression of the law of the conservation of mass, which is commonly used in reservoir engineering. For reservoirs with no water influx and no water encroachment and if we neglect formation and water compressibilities, it will have the following form
(1) G B g i = G - G p B y
which can be written also as
Equation (2) Available In Full Paper.
If we include all of the forces that we previously neglected, then we will have the following equation
(3) G B g i = G - G p B g + W e - W p + G B g i 1 - R M
Equation (4) Available In Full Paper.
If we neglect the influence of the formation and water compressibility
then the Ramagost factor RM will be equal to 1, and
therefore Equation (4) will be reduced to the following
An Overview of Formation Damage Mechanisms Causing a Reduction in the Productivity and Injectivity of Oil and Gas Producing Formations
Authors: Bennion D. Brant 
Published: March 2010

Introduction
Formation damage is a hot topic these days-with justifiable reason, as more operating companies move to the exploitation of more and more challenging oil and gas reservoirs in tighter, deeper, and more depleted conditions. Disappointing production or injection results from an oil or gas well can be related to a number of factors which may be difficult to diagnose. Some of these may center about poor inherent natural reservoir quality characteristics, others about mechanical considerations surrounding the condition and type of the wellbore obtained, and still others under the nebulous catch-all of "formation damage" which often (and sometimes unjustly) absorbs the majority of the blame for the poor results of many projects.
Formation damage in oil and gas wells is difficult to quantify in many cases. This is due to the inability of the reservoir engineer to retrieve exact samples and conduct detailed measurements on the area of interest, usually represented by a volume of rock surrounding the wellbore which is generally several thousand meters below the surface of the earth. However, ongoing research over the years has allowed the development of a variety of techniques allowing the use of the available information to obtain a much better indication f the type and degree of damage which different reservoirs may be sensitive to, thereby adjusting operating practices to attempt to minimize or reduce these permeability reducing factors. This data would include information such as production and pressure data, pressure transient data, log analysis, fluid and PVT data and core, cuttings, and special core analysis data. The subject of this brief article is to provide a synopsis of some of the types of formation damage which commonly present themselves as problems for many oil and gas producing projects, and review some of the associated technology being used to overcome these problems.

How Much of a Concern is Formation Damage?
A technical definition of formation damage would be "any process that causes a reduction in the natural inherent productivity of an oil or gas producing formation, or a reduction in the injectivity of a water or gas injection well." Although the drilling process often bears the brunt of the blame, formation damage can occur at any time during the life of a well including completion, production, stimulation, kill, or workover operations. Often the problem is ignored due to a combination of ignorance and apathy with the common rationale that "We don't care about formation damage in this reservoir-we can always fracture through it." Surprisingly, this pretense may make sense in certain situations, particularly when the formation is of such low inherent quality that it is obvious the flow area and driving differential pressure available for production present in a normal cased and perforated or open hole completion are insufficient to sustain economic production rates, even with a totally "non damaged" well.
Residual Oil Saturation Inside the Steam Chamber During SAGD
Authors: Walls E. , Palmgren C. , Kisman K. 
Published: March 2010

Abstract
The oil saturation inside the steam chamber during steamassisted gravity drainage (SAGD) has an important impact on economics and conservation. However, the SAGD residual oil saturation is difficult to determine and model because it involves long-term thermal effects and three-phase flow. SAGD has been widely studied and piloted, but improved understanding of longterm drainage effects represents a fundamental issue that requires improved understanding.
In the first part of the paper, we represent a sensitivity test done on the shapes and the endpoints of the two-phase relative permeability curves. We find that the water relative permeability and oil relative permeability in the gas-oil system are the main factors that determine the magnitude and shape of the oil saturation curve as a function of time.
Secondly, we demonstrate how to adjust the krog relative permeability curve to match a theoretically determined residual oil saturation, which is supported by laboratory data. We propose that, during SAGD, the flow of oil can be split into two regimes. In the first regime, close to the edge of the steam chamber, oil drains quickly in a short period of time. In the second regime, oil drains slowly within the steam chamber for a longer period of time, as it is produced by "film drainage." To capture these flow regimes, the oil relative permeability curve in the gas-oil system, krog, is split into two. At higher liquid saturations, the first flow regime is represented and, at lower liquid saturations, the second regime is modelled.
Thirdly, the krog curve was adjusted so that the decrease in oil saturation with respect to time closely matched the theoretical curve while maintaining oil production rates expected for SAGD. Using this new curve at different pressures, we show that the residual oil saturation increases at lower SAGD operating pressures.

Introduction
In a steam-assisted gravity drainage (SAGD) process, bitumen drainage occurs mainly along the transition zone, which is the mobile liquid region at the boundary of the steam chamber. Bitumen drainage also continues to occur within the body of the steam chamber over a long period of time, such that the residual oil saturation gradually falls.
In this paper, the term residual oil saturation refers to the average remaining oil saturation within the steam chamber where the steam chamber includes all grid blocks in a numerical model containing any amount of steam. It is difficult to obtain residual oil saturation data as a function of time in the field so, in this study, we relied on theoretical and laboratory data. We calibrated reservoir simulation results to the theoretical and laboratory data, and then used the simulator to investigate the effects of SAGD operating pressures on the residual oil saturation.

Relative Permeability Formulation
Multiphase flow in a porous medium can be described using Darcy's Law as follows:
Pressure Transient Analysis for Wells With Variable Sandface Flow Rate
Authors: Nashawi I.S. 
Published: March 2010

Abstract
In the last two decades, with the availability of new state-of-the- art production logging devices that are capable of providing accurate downhole rate and pressure measurements, variable rate testing has been given special concern. This is mainly because it is sometimes impractical and often impossible to hold a constant flow rate long enough to perform a drawdown test. Furthermore, the use of sand face flow rate and pressure data in well test analysis has a few major advantages over conventional methods. Variable-rate tests minimize the wellbore storage effects, reduce the test duration, and provide better description of the area in the vicinity of the wellbore.
This paper presents a new technique that does not require a constant flow rate for the entire duration of the test. The technique consists of two flowing periods: a short constant flow rate period followed by a variable flow rate period. In deriving the final working equation, the variable flow rate period is approximated by a polynomial.
The new method can be also used to analyze pressure drawdown data dominated by wellbore storage and pressure buildup data pertaining to early time afterflow. Two simulated cases and two field examples are presented to illustrate the applicability of the new technique.

Introduction
The pressure drawdown test has long been recognized in the oil industry to be an excellent technique to determine reservoir characteristics. However, one of the major drawbacks in analyzing pressure draw downs is the theoretical requirement of these techniques that requires the flow rate to be held strictly constant during the entire test duration. Moreover, in most wells, the wellbore storage effects dominate the early test data and force the operator to run the test for a long period of time. This is especially true in low-productivity pumping wells and low-permeability tight reservoirs. Furthermore, in the case of small reservoirs, the boundary effects may disturb the test data even before the appearance of the semi log straight line on the test plot. Sometimes, even when the plot displays a straight line, the data analysis may not reflect the near wellbore conditions. In all of these cases, the well test fails to achieve its goals. In addition, for both oil and gas wells, the long constant-rate production condition is hard to fulfill in the field, especially during the early life of the reservoir. For all of these reasons, well test researchers tried to come up with new testing techniques that do not require a constant rate, minimize the wellbore storage effects, reflect the actual conditions in the vicinity of the wellbore, and reduce the test duration. Variable-rate tests are designed to solve most of these problems.
The idea of using afterflow data to analyze well tests is not new. As early as 1955, Gladfelter et al.(1) presented the first attempt to use approximated afterflow rate and pressure data to estimate the reservoir parameters.