bluuebunny/crossref_metadata_2025_split huggingface dataset:
FDA Drug Approval Summary: Lapatinib in Combination with Capecitabine for Previously Treated Metastatic Breast Cancer That Overexpresses HER-2
Authors: Ryan Qin , Ibrahim Amna , Cohen Martin H. , Johnson John , Ko Chia-wen , Sridhara Rajeshwari , Justice Robert , Pazdur Richard 
Published: October 2008

Abstract

Learning Objectives
After completing this course, the reader should be able to: Describe the clinical trial that led to the approval of lapatinib in combination with capecitabine for the treatment of previously treated patients with HER-2–overexpressing metastatic breast cancer.Determine appropriate patients to receive lapatinib plus capecitabine treatment.Assess and manage the toxicities of lapatinib plus capecitabine treatment.
CME This article is available for continuing medical education credit at CME.TheOncologist.com
On March 13, 2007, the U.S. Food and Drug Administration approved lapatinib (Tykerb® tablets; GlaxoSmithKline, Philadelphia), an oral, small molecule, dual tyrosine kinase inhibitor of ErbB-2 and ErbB-1, for use in combination with capecitabine for the treatment of patients with human epidermal growth factor receptor (HER)-2–overexpressing metastatic breast cancer who had received prior therapy including an anthracycline, a taxane, and trastuzumab.
One multicenter, open-label, randomized trial was submitted. Eligible patients had stage IIIb or IV breast cancer, ErbB-2 overexpression (immunohistochemistry 3+ or 2+ with fluorescence in situ hybridization confirmation), measurable disease, a 0 or 1 Eastern Cooperative Oncology Group performance status score, a cardiac ejection fraction within the institutional normal range, and adequate laboratory function.
Patients received either lapatinib (1,250 mg once daily on days 1–21) plus capecitabine (1,000 mg/m2 every 12 hours on days 1–14) every 21 days or capecitabine alone (1,250 mg/m2 every 12 hours on days 1–14) every 21 days.
The primary endpoint was time to progression (TTP) determined by a blinded independent review panel. After TTP results of a prespecified interim analysis were made available, study enrollment was discontinued (399 patients enrolled).
The median TTP was 27.1 versus 18.6 weeks (hazard ratio, 0.57; p = .00013) favoring the lapatinib plus capecitabine arm. Response rates were 23.7% (lapatinib plus capecitabine) versus 13.9% (capecitabine alone). Survival data were not mature.
Although the toxicities observed in the lapatinib and capecitabine combination arm were generally similar to those in the capecitabine alone arm, a higher incidence of diarrhea and rash was noted with the combination. Grade 3 or 4 adverse reactions that occurred with a frequency of &gt;5% in patients on the combination arm were diarrhea (13%) and palmar–plantar erythrodysesthesia (12%). There was a 2% incidence of reversible decreased left ventricular function in the combination arm.
A New Regression-Based Method for Accurate Measurement of Coal and Shale Gas Content
Authors: Shtepani E. , Noll L. A. , Elrod L. W. , Jacobs P. M. 
Published: October 2008

Abstract
Gas content and storage capacity are the key parameters for determination of the gas resources and reserves in unconventional reservoirs. These parameters must be obtained from laboratory experiments in the core samples such as desorption canister tests and adsorption isotherm experiments. Desorption canister testing is performed to determine the total adsorbed gas content, gas composition and the total desorption time. Adsorption isotherm experiments are conducted to determine the gas storage capacity with pressure and for CO2 sequestration purposes. Other analyses of coals include proximate analysis and bulk density measurements of all samples. Shales are commonly analyzed for total organic carbon in lieu of proximate analysis.
The gas content is estimated by placing selected freshly cut reservoir samples in air tight sealed canisters and measuring desorbed gas volume as a function of time at atmospheric conditions. Total gas content is the summation of three components: "lost gas", desorbed gas, and "residual gas". "Lost gas" is the volume of the gas that desorbs from the sample during the recovery process at wellsite, before the core sample can be sealed in a desorption canister. "Residual gas" is the gas that remains sorbed on the sample at the completion of the canister desorption test.
A disadvantage of this procedure is the estimation of "lost gas". The volume of the "lost gas" is usually estimated by extrapolation of desorbed data to time zero using linear and/or polynomial curve-fit to the plot of cumulative desorbed gas versus square root of time. The differences between both methods can become more pronounced especially in high gas content reservoirs.
In this paper a new method, which is based on nonlinear regression of measured gas content, is presented. This technique offers an accurate estimation of lost gas which coupled with sorption isotherm impacts the calculation of gas in place, the recoverable reserve and production profiles.
Improvements in Measuring Sorption-Induced Strain and Permeability in Coal
Authors: Robertson E. P. 
Published: October 2008

Abstract
Total worldwide CBM in-place reserves estimates are between 3500 Tcf and 9500 Tcf. Unminable coal beds have been recommended as good CO2 sequestration sites as the world prepares to sequester large amounts of greenhouse gases. In the U.S., these coal seams have the capacity to adsorb and sequester roughly 50 years of CO2 emissions from all the U.S. coal-fired power plants at today's output rates. The amount and type of gas adsorbed in coal has a strong impact on the permeability of the coal seam. An improved mixed gas adsorption isotherm model based on the extended-Langmuir theory is discussed and is applied to mixed gas sorption-induced strain based on pure gas strain data and a parameter accounting for gas-gas interactions that is independent of the coal substrate. Advantages and disadvantages of using freestanding versus constrained samples for sorption-induced strain measurements are also discussed. A permeability equation used to model laboratory was found to be very accurate when sorption-induced strain was small, but less accurate with higher strain gases.
Solving Completion Options for Underground Gas Storage Through Geomechanics
Authors: Surej Subbiah , Burgstaller C. , Fuller J. , Wielemaker E. , Jilg W. 
Published: October 2008

Abstract
Varition of gas demand yearly, weekly, at different tine in a day and seosonly is the main driving factor for gas storage. Ideally the gas needs to be stored at the comsumption points and the demand fluctuations need to be met by supply. Thus the underground gas strorage operators need to maximize the storage capacity and minimize the cost of storage. Furthermore the operations need to be safe during the injection and production cylces.
During underground gas storage the reservoir is exposed to large range of pressure changes i.e. injection and production cycle. The stress state acting on the reservoir rock during this cycle is very high. In addition, the rate at which gas is injected and produced can subject the reservoir rock in the near wellbore region to large stresses. Both the change in stress due to changes in the reservoir pressure and changes in stress due to injection and production rate can be sufficient to fail the rock in this near wellbore region and cause sand production. Any sand production is likely to damage wellbore and surface equipment, and ultimately may render the gas storage operation unviable.
An understanding of the state of stress in the reservoir created by these gas storage operations is critical to avoid unwanted sand production. A geomechanical review of the potential for sand production in the Haidach Underground Storage Reservoir, Austria, illustrates the steps necessary to determine the stress state that will cause formation deformation and probable sand production. The study assists the selection of stable zones for perforating wells and sets operational limits for the gas flow to and from the wells
Pore-Pressure Prediction in Overconsolidated Shales
Authors: Nygaard R. , Karimi M. , Hareland G. , Tahmeen M. , Munro H. 
Published: October 2008

Abstract
Several of the existing pore pressure estimation methods are based on establishing a normal compaction trend curve with depth. The rationale is that as fine grained sediments are buried with depth the increase in overburden stress compact the sediments therefrom the normal compaction curve can be developed. Common methods using a normal compaction trend as the basis is the equivalent depth method, or the Eaton ratio method which uses sonic, density or resistivity logs as inputs. When fluid overpressure develops caused by other sources than mechanical compaction, such as fluid mechanical entrapment, rock molecular transformation, migration or hydrocarbon generation, Bowers method can be applied. Bowers extended the above mentioned methods to calculate over pressure where sediments are unloaded during pore pressure build up.
However, these methods require that you establish a normal compaction curve for sediments without overpressure. In many onshore basins, such as the Mid-Alberta basin, which has thick eroded sections and therefore the sediments are over-consolidated, it is not possible to establish a normal compaction curve. To be able to predict the pore pressure in overpressured Mid-Alberta shales, we developed a pore pressure prediction method based on over-consolidation theory. We tested the method with sonic logs and the method gave promising results for establishing pore pressures in the over-consolidated Alberta basin.
Prediction of Production in Oil Reservoirs by Considering Change in Number of Production Wells
Authors: Guan Yanyan , Niu Yanliang , Han Dejin , Zhou Xisheng , Li Kewen 
Published: October 2008

Abstract
Decline curve analysis (DCA) is a traditional method for production prediction, which is still being used today because of its simplicity. However, DCA methods have limitations in many cases when applied to entire reservoirs. Such cases include variation in production conditions and change in the number of injection and production wells. In this study, we focused on the latter problem, change in the number of production wells. Obviously, there would be a significant oil production boost during a specific time period if more oil wells are drilled. The traditional DCA approach cannot match the increase in oil production due to the increase in the number of oil production wells. We have developed a method to match and predict the oil production of entire reservoirs by considering the change in the number of production wells. The main idea of this new approach came from the concept of effective wells. We applied this new approach in several sandstone oil reservoirs with different permeabilities. Satisfactory results were obtained. Comparison with the existing models (exponential, hyperbolic model, and harmonic models) was made and the results showed the new approach had the best fit to the production history in the cases studied.
Impact of Water-Based Drill-In Fluids on Solids Invasion and Damage Characteristics
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Shafei M. , Bataweel M. A. 
Published: October 2008

Abstract
Drilling the U-formation (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf) to mechanically stabilize the shale and balance the reservoir pressure. Two fluids have been used to drill this formation: KCl/ BaSO4/ CaCO3 and potassium formate/CaCO3. Barite is added in the first fluid with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, BaSO4 is insoluble in acids and requires chelating agents (DTPA) to remove it from the formation. Formate drill-in fluids with low solid content can be used, but they are expensive and corrosive at pH values less than 7-8. A third drilling fluid was recently developed by Al-Yami et al (2007) to overcome some of the problems associated with these two systems.
The objective of this study is to determine solids invasion and damage characteristic for the three fluids. Core flood tests were conducted using reservoir cores at bottom hole conditions. Then the cores were examined by ESEM analysis to determine solids invasion, and characteristics of damage.
The three drilling fluids examined did damage the core plugs either through external, internal filter cake, or both. The ESEM images showed that the least damage and minimum solids invasion occurred when Mn3O4 water-based drill-in fluid use tested. The highest damage was observed when barite/CaCO3 mud was examined. This was followed by the potassium formate drill-in fluids. Kaolinite booklets were not attacked by the filtrate of the three drill-in-fluids examined. The damage noted with potassium formate mud was due to incompatibility of mud filtrate with the formation brine where potassium chloride crystals was noted in the core.
Coalbed Discontinuity Effects on the Production of Degasification Boreholes and on Emissions During Longwall Mining
Authors: Karacan C. Ö. , Goodman G. V. R. 
Published: October 2008

Abstract
Geological discontinues in the coalbed, such as faults, sandstone channels, permeability facies, lithotype changes, and large scale partings in the coal seam, can cause intermittent production problems or produce unexpected amounts of water or gas from degasification boreholes. These discontinuities not only can impact methane emissions into the mine workings, especially if they hinder proper and effective degasification of the coalbed but may act as conduits for methane flow from gassy strata into advancing mine workings. The effects of these discontinuities are still under debate by mining and gas production experts. This study presents a numerical investigation using reservoir simulations of the effects of partings and permeability facies and lithotype changes on the production performances of vertical and horizontal degasification boreholes, as well as the emissions during longwall operations.
In this work, the grid block was designed in a multi-layer 3-D structure which enabled spatial descriptions of the geometries and properties of the discontinuities within the coal seam. The studied coal seam discontinuities and their properties were distributed arbitrarily within the model. Production was simulated by vertical and horizontal boreholes. Degasification boreholes operated two years prior to start of the mining.
The results of this numerical study show that in coal seams with major heterogeneities and discontinuties, the geometry and location of the boreholes are important for improved gas production. These considerations are also important for controlling methane and water inflow into the working environment during longwall mining.
Water-Production Diagnosis Using Transient Test With Multiphase Flowmeter
Authors: Gasbarri S. , Basabe L. , Fariña A. , Trinidad F. , Sosa G. , Azuaje E. 
Published: October 2008

Abstract
Accurate determination of oil, water, and gas production rates is an important element of oilfield management and optimization. Multiphase flow meters (MPFM) are being accepted more and more for well testing, reservoir management, production allocation, production monitoring, and fiscal metering. In addition to common MPFM applications, this study shows how a multiphase flow meter may be used as a valuable tool to evaluate water production problems of the well by imposing transient flowing conditions to the well and tracking characteristic parameters such as flowrates, water cut and gas oil ratio with the equipment during the test.
Representative curves are shown in this study in order to identify some common wellbore problems associated with water conformance. The curves were obtained through numerical reservoir simulation using a number of cases related to the most important problems: water channeling in stratified formations, mechanical wellbore integrity, water conning, and oil-water contact advance.
The flowrate at the well should be shortened to a half of the current flowrate with a choke for several hours then, the dimensionless pattern curves of the water cut and gas oil ratio gathered in this study should be matched with the measurement of the MPFM on site in order to characterize the nature of the water problem.
This application represents a new tool used to identify the sources of water production. The tool is easy and quick to apply, and complements other analytical techniques being used like diagnostics plots based on production history, water-oil ratio performance and production logs. All of them are used to differentiate between the different mechanisms of water invasion, so that an appropriate treatment may be selected to control undesirable water production.
Acid Emulsified in Xylene: A Cost-Effective Treatment to Remove Asphaltene Deposition and Enhance Well Productivity
Authors: Fatah W. Abdel , Nasr-El-Din H. A. 
Published: October 2008

Abstract
Emulsified acid (30 vol% diesel and 70 vol% HCl acid) has been used in both matrix and acid fracturing treatments. Injection the acid in this form has several advantages including: retard the reaction of the acid with rock, reduce corrosion to well tubulars and minimize acid additives. However, using this acid to treat wells with asphaltene deposition will require removing asphaltene first using a suitable aromatic-based solvent, and then using a matrix acid treatment. This additional step will increase the cost and time needed to execute acid treatments.
To remove asphaltene deposition and enhance well productivity, hydrochloric acid was emulsified in xylene. Xylene was the external phase, and was used to dissolve asphaltenes. Then the acid, present as the dispersed phase dissolved the carbonate rock, thus enhancing well productivity. Extensive lab work was performed to ensure the stability of acid-in-xylene emulsion and measure its apparent viscosity. Acid concentration was 15 wt% HCl, the acid volume fraction was 0.7 and the balance was xylene. All tests were conducted at room temperature and 160°F.
The stability and apparent viscosity of emulsified acids were found to be a function of the type of hydrocarbon phase used to prepare emulsified acid. Emulsified acids prepared with xylene had a lower apparent viscosity and were stable for relatively shorter period of times. A matrix acid treatment was that based on xylene emulsified acid was applied in four wells without encountering operational problems. Unlike previous matrix acid treatments using regular acid, the four wells responded to the new treatment, without increasing water-cut, except in one well which was wet before the treatment.
Wettability Alteration To Increase Deliverability of Gas-Storage Wells
Authors: Xie X. , Liu Y. , Sharma M. , Weiss W. W. 
Published: October 2008

Abstract
More than 17,000 gas storage wells in the U.S. annually lose about 5% of their deliverability (i.e., injectivity and productivity). A common problem is believed to be water blockage around the wellbore. For strongly water-wet gas reservoirs, capillary forces promote the retention of water in pore spaces, which in turn curtails the flow of gas in and out of the storage wells. This paper reports the use of surfactants to change the water-wetness of a gas reservoir in order to increase gas deliverability. Surfactant treatment can alter the strong water-wetness of the rock around wellbore to a neutral-wet condition, thus reducing water retention and improving gas flow. The objective of this laboratory study was to demonstrate improved gas deliverability by altering the wettability of core samples with proper chemicals from strongly water-wet to neutral-wet. Seven chemicals were screened for efficacy of changing the wettability of strongly water-wet glass capillary tubes. Following the capillary rise tests two surfactants were selected for the core sample experiments. Rock samples and water from the St. Peter formation, a sandstone aquifer gas storage reservoir, have been tested. Spontaneous imbibition tests of reservoir cores were used to evaluate the wettability before and after surfactant treatment. The cores were saturated with either initial formation water or surfactant solutions were displaced with wet nitrogen gas. Gas relative permeability was measured. A decrease in the trapped water saturation caused an increase in gas permeability. This increase indicated improved gas deliverability that resulted from wettability alteration away from very strongly water-wet conditions. Laboratory results demonstrated that reducing the water-wetness increased permeability and improved the deliverability of gas from the cores. This technique provides a cost-effective method to increase gas deliverability in fields where water blocking is a major factor in decreased gas deliverability.
Evaluation of Two-Phase Flow Correlations and Mechanistic Models for Pipelines at Inclined Downward Flow
Authors: Yuan H. , Zhou D. 
Published: October 2008

Abstract
In this study, two-phase flow pressure prediction correlations and mechanistic models for pipelines commonly used in petroleum industry are evaluated against experimental data.
Downward two-phase flow occurs in hilly terrain pipelines, in steam injection wells, as well as in offshore oil and gas production systems. During pipeline design and simulation, experimental data are usually unavailable to calibrate against correlations and models. Sometimes it is difficult to determine which correlation or model to use in predicting pressure gradient in inclined downward flow since there are very a few correlations and models were developed specifically for downward pipe flow.
Experimental data used in this study are from a published paper (Kokal and Stanislav, 1989). Experimental data were gathered from 1-inch, 2-inch and 3-inch pipes with seven inclination angles. Oil and air were used as testing fluids. During the experiment, superficial liquid velocities range from 1.2 to 10 ft/s and superficial gas velocities range from 0.76 to 85 ft/s. The experimental results were plotted as pressure gradient vs. superficial gas velocity for each superficial liquid velocity.
Beggs-Brill, Dukler-Eaton-Flanigan, Dukler-Flanigan, Dukler, Eaton, Eaton-Flanigan correlations and Xiao mechanistic model are evaluated in this study.
The results of this study can be used as guidelines in choosing two-phase flow pressure prediction correlations and models in designing and analyzing downward two-phase flow pipelines.