bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prognostic and Predictive Biomarkers in Resected Colon Cancer: Current Status and Future Perspectives for Integrating Genomics into Biomarker Discovery
Authors: Tejpar Sabine , Bertagnolli Monica , Bosman Fred , Lenz Heinz-Joseph , Garraway Levi , Waldman Frederic , Warren Robert , Bild Andrea , Collins-Brennan Denise , Hahn Hejin , Harkin D. Paul , Kennedy Richard , Ilyas Mohammad , Morreau Hans , Proutski Vitali , Swanton Charles , Tomlinson Ian , Delorenzi Mauro , Fiocca Roberto , Van Cutsem Eric , Roth Arnaud 
Published: March 2010

AbstractThe number of agents that are potentially effective in the adjuvant treatment of locally advanced resectable colon cancer is increasing. Consequently, it is important to ascertain which subgroups of patients will benefit from a specific treatment. Despite more than two decades of research into the molecular genetics of colon cancer, there is a lack of prognostic and predictive molecular biomarkers with proven utility in this setting. A secondary objective of the Pan European Trials in Adjuvant Colon Cancer-3 trial, which compared irinotecan in combination with 5-fluorouracil and leucovorin in the postoperative treatment of stage III and stage II colon cancer patients, was to undertake a translational research study to assess a panel of putative prognostic and predictive markers in a large colon cancer patient cohort. The Cancer and Leukemia Group B 89803 trial, in a similar design, also investigated the use of prognostic and predictive biomarkers in this setting. In this article, the authors, who are coinvestigators from these trials and performed similar investigations of biomarker discovery in the adjuvant treatment of colon cancer, review the current status of biomarker research in this field, drawing on their experiences and considering future strategies for biomarker discovery in the postgenomic era.
Advanced Technology To Reduce Water Cut: Case Studies From the Pemex Southern Region
Authors: Romo Gustavo A. , Leyva Héctor Hernández , Aguilar Raúl Bonifacio , Campos Carlos Caballero , Eoff Larry , Dalrymple Dwyann 
Published: March 2010

Summary
This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability would be destined for abandonment otherwise.
This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which uses hydrophobically modified water-soluble polymers, and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results of the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost prohibitive.
From Lean to Extreme-Lean Well Profile: Field Experience in the Mediterranean Sea
Authors: Calderoni A.. , Donati F.. , Ferrara P.. , Maestrami M.. , Oppelt J.. , Krüger S.. 
Published: March 2010

Summary
The main subject of this paper will be to outline the field experience achieved with a new type of well profile and directional drilling system. Reducing the cost of well construction has been a driver for many new technologies. The lean casing profile introduced by Eni SpA, the major Italian oil and gas company, about a decade ago was a successful step towards lowering the drilling and completion cost in the vertical, top-hole section. Automated vertical-drilling tools have been the technical enabler of such a concept. Recently, this oil company has moved further towards an even more radical "extreme-lean well profile." This paper gives a brief insight into the well-design concept and the enabling technology behind it. The drilling technology is based on the well-known automated vertical-drilling system, which has been enhanced by the capability to drill an enlarged hole size below a casing without compromising the verticality and hole quality. In the main part of the paper, two field applications, in the Mediterannean Sea and offshore Egypt, are described. The paper will also cover the lessons learned especially from the second of the first two field applications. The extreme-lean well profile and automated vertical-reaming technology can provide value to several drilling campaigns not only through the reduction of well-construction cost. Another major benefit is the ability to run an intermediate casing string, if required because of difficult well conditions, and still arrive at the same diameter of casing in the reservoir. The completion concept and the enabling tool technology are very unique and have not been available to the industry until recently.
Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verification Project
Authors: Norden B.. , Förster A.. , Vu-Hoang D.. , Marcelis F.. , Springer N.. , Le Nir I.. 
Published: March 2010

SummaryThe storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK (CO2 Storage by Injection into a saline aquifer at Ketzin) project is a research and development (R&D) project, mainly supported by the European Commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in-situ laboratory for CO2 storage.The preparatory phase of the project involved a baseline geological-site exploration and the drilling of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin, located near Berlin. The target saline aquifer is the lithologically heterogeneous Triassic Stuttgart formation, situated at approximately 630- to 710-m (2,070- to 2,330-ft) depth. A comprehensive borehole-logging program was performed consisting of routine well logging complemented with an enhanced logging program for one well that recorded nuclear-magnetic-resonance (NMR) and borehole-resistivity images, to characterize the storage formation better. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability, and brine permeability at different pressure conditions.The saline aquifer at Ketzin shows a variable porosity/permeability distribution, which is related to grain size, facies variation, and rock cementation with values in the range from 5 to &gt; 35% and 0.02 to &gt; 5,000 md for porosity and permeability, respectively. On the basis of core analysis and logging data, an elemental loganalysis model for the target formation was established for all three wells. In addition, permeability was estimated using the Coates equation and compared with core data and NMR log-derived permeability, which seems to provide meaningful permeability estimates for the Ketzin reservoir. On the basis of the good core control that guided the petrophysical well-log interpretation in the first two CO2SINK wells, a porosity and permeability prediction by analogy for the third well is appropriate and applicable. The availability of cores was crucial for a sophisticated formation evaluation at borehole scale that characterizes the real subsurface conditions.
Improved Prediction of Oil Recovery From Waterflooded Fractured Reservoirs Using Homogenization
Authors: Salimi Hamidreza , Bruining Johannes 
Published: March 2010

SummaryMost simulations of waterflooding in fractured media are based on the Warren and Root (WR) approach, which uses an empirical transfer function between the fracture and matrix block. We use homogenization to obtain an improved flow model in fractured media, leading to an integro-differential equation; also called the boundary-condition (BC) approach. We formulate a well-posed numerical 3D model for the BC approach. This paper derives this numerical model to solve full 3D integro-differential equations in a field reservoir simulation. We compare the results of the upscaled model with ECLIPSETM results. For the interpretation, it is useful to define three dimensionless parameters that characterize the oil production in fractured media. The most important of these parameters is a Peclet number, defined as the ratio between the time required to imbibe water into the matrix block and the travel time of water in the fracture system. The results of the WR approach and the BC approach are in good agreement when the travel time is of the same order of magnitude as the imbibition time. However, if the travel time is shorter or longer than the imbibition time, the approaches give different results. The BC approach allows the use of transfer functions based on fundamental principles (e.g., the use of a rate-dependent capillary pressure function). When implemented, it can be used to improve recovery predictions for waterflooded fractured reservoirs.
Erosion Study for a 400-MMcf/D Completion: Cannonball Field, Offshore Trinidad
Authors: Healy J.C.. C. , Martin John , McLaury Brenton , Jagroop Raynald 
Published: March 2010

Summary
The Cannonball field is a 1 Tcf gas/condensate development offshore Trinidad producing at a sustained rate in excess of 800 MMcf/D from three wells. The completion design selected was 7⅝- in. production tubing with an openhole gravel pack. The initial well (CAN01) has produced at 333 MMcf/D. These rates are higher than typically experienced, which has raised concerns about the resultant potential for metal erosion. As a result, a rigorous erosion study was initiated. The objective was to evaluate erosion quantitatively at various rates over the life cycle of the well to design the completion appropriately and select the appropriate materials.
The erosion nodes within the completion—changes in flow direction (e.g., a tee such as in the wellhead) and/or flow constric- tions—were identified as the tree, a landing-nipple profile near the surface, and a formation-isolation device (FID) positioned in the gravel-pack assembly. The key parameters were defined as particles of sharp sand, with a diameter of 50 μm, at a concentration of 0.1 lbm/MMcf. Erosion rates were calculated using the erosion model, Sand Production Pipe Saver (SPPS), developed by the Erosion/Corrosion Research Center (E/CRC) at the University of Tulsa, USA. Erosion rates were calculated over the life cycle, starting at initial rates of 280 and 400 MMcf/D. Erosion rates were also calculated with and without a liquid film (a protective layer on the pipe wall that can reduce the erosion rate). Erosion results (without a liquid film) at all nodes exceeded BP's erosion limit; however, the erosion results with a thin liquid film were mostly below the company's erosion limit. Determination of the presence and thickness of the liquid film was critical. A multiphasepipeline simulation calculated that a sufficient liquid film would exist at all critical areas. Erosion of the tree was assessed further by computation-fluid-dynamics (CFD) models, which identified several hot spots; thus, additional cladding of all flow-wetted surfaces and rounding of the outlet corner was required. The Cannonball completion design, including the tree, was determined to be capable of sustained rates up to a maximum of 400 MMcf/D. The three-well development, where initial rates have been as high as 333 MMcf/D, has been on production for several years without any erosion issues.
Pore-Pressure-Coefficient Anisotropy Measurements for Intrinsic and Induced Anisotropy in Sandstone
Authors: Al-Tahini Ashraf , Abousleiman Younane 
Published: March 2010

SummaryIn this study, we determine experimentally the effect of inherent and stress-induced anisotropy on stiffness components, elastic moduli, and Biot's pore-pressure coefficients (PPCs) for Lyons outcrop Colorado sandstone, which exhibits a clear transverse isotropic rock structure. Both dynamic and quasistatic methods were used under a nonhydrostatic state of stress to perform the measurements on dry core samples. Our assumption of apparent transverse anisotropy was confirmed initially with acoustic velocity measurements and at a later stage in the loading with experimental transverse anisotropic failure analysis. The objective of this study is to identify and isolate the effect of stress-induced anisotropy from the inherent transverse anisotropy on the measured stiffness components, elastic moduli, and Biot's PPCs. The effect of stress-induced anisotropy appears to have significant control on measured stiffness components, elastic moduli, and Biot's PPCs in comparison to the inherent-transverse-anisotropy effect. Our work shows that the stiffness components, Mij and thus the computed elastic moduli, are highly influenced by the stress-induced anisotropy, especially the off-diagonal stiffness components, M12 and M13, where the increase in their magnitudes from the dynamic measurements before failure is determined to be 100 and 81%, respectively. The difference in the magnitude between the axial and lateral Biot's PPCs in line with bedding planes and perpendicular to them is measured to be 24 and 16% from the quasistatic and dynamic methods, respectively; whereas, the effect of stress-induced anisotropy reduced the dynamic average magnitude of the Biot's PPCs along the bedding planes and transverse to these planes by 63% across a stress range of 145 MPa.
Entrance Pressure of Oil-Based Mud Into Shale: Effect of Shale, Water Activity, and Mud Properties
Authors: Oleas Andres M. , Osuji Collins E. , Chenevert Martin E. , Sharma Mukul M. 
Published: March 2010

Summary
Oil-based muds (OBMs) have been developed to combat drilling problems caused by shale hydration. This paper presents experimental data that show the factors that control the movement of oil filtrate into a shale, as described by its "entrance pressure." Although the oil filtrate of the OBM does not hydrate the shale, it can penetrate the shale, increase the pore pressure, and cause wellbore failure. It is of primary interest to understand this when troublesome shales are drilled. It is also important to understand how factors such as the emulsifier concentration in the OBM and the porosity of the shale affect this entrance pressure.
The objective of this study is to determine and quantify the factors that control the oil entry pressures of shales. For this purpose, five OBMs, containing different concentrations of emulsifiers, water, and oil, were studied.
The study was also intended to determine the effect of shale porosity on entrance pressure. Data are reported for the Arco China shale samples having porosities of 1.8 (native), 3.9, and 4.9%.
It was observed that for a given OBM water content, as the emulsifier concentration increased, the required entrance pressure and the electrical stability (ES) of the mud increased. Also, for shales that had higher porosities and, therefore, larger pore throats, the oil entrance pressure decreased.
A Quantitative and Qualitative Comparison of Coarse-Grid-Generation Techniques for Modeling Fluid Displacement in Heterogeneous Porous Media
Authors: Mostaghimi P.. , Mahani H.. 
Published: March 2010

Summary
To apply upscaling techniques is an undeniable demand in reservoir simulation, when one considers the difference between the level of detail in a geological model and the level of details that can be handled by a reservoir simulator. Upscaling the reservoir model involves first constructing a coarse grid by using gridding algorithms and then computing average properties for coarse gridblocks. Although various techniques have been proposed for each of these steps, one needs to be aware of strengths and weaknesses of each technique before attempting to apply them. In this paper, we focus on different gridding methods and evaluate their performances. Three main grid-generation techniques are considered: permeability-based (PB), flow-based (FB), and vorticity-based (VB) methods. We apply all three methods to a number of 2D heterogeneous models and simulate two-phase flow on the constructed grids. Then we compare their obtained global and local results. Fluid cuts at the producer is employed as the global performance indicator and saturation-distribution error as the local indicator. We show that FB and VB gridding, which are dynamic methods, are superior to PB gridding, which is a static method. On the basis of this analysis, we then concentrate on FB and VB gridding and investigate their performance in greater detail. While FB gridding uses fluid velocity as gridblock density indicator, VB gridding combines velocity and permeability variation in gridding according to its definition and takes advantage of both. Therefore, although performance of FB and VB gridding is comparable in many cases, VB has the benefit of producing coarse gridblocks with more-uniform permeability and fluid-properties distribution. This in turn yields more-accurate global and local results and reduces application of sophisticated upscaling techniques and fulltensor permeability upscaling.
Data Assimilation of Coupled Fluid Flow and Geomechanics Using the Ensemble Kalman Filter
Authors: Chang Haibin , Chen Yan , Zhang Dongxiao 
Published: March 2010

Summary
In reservoir history matching or data assimilation, dynamic data, such as production rates and pressures, are used to constrain reservoir models and to update model parameters. As such, even if under certain conceptualization the model parameters do not vary with time, the estimate of such parameters may change with the available observations and, thus, with time. In reality, the production process may lead to changes in both the flow and geomechanics fields, which are dynamically coupled. For example, the variations in the stress/strain field lead to changes in porosity and permeability of the reservoir and, hence, in the flow field. In weak formations, such as the Lost Hills oil field, fluid extraction may cause a large compaction to the reservoir rock and a significant subsidence at the land surface, resulting in huge economic losses and detrimental environmental consequences. The strong nonlinear coupling between reservoir flow and geomechanics poses a challenge to constructing a reliable model for predicting oil recovery in such reservoirs. On the other hand, the subsidence and other geomechanics observations can provide additional insight into the nature of the reservoir rock and help constrain the reservoir model if used wisely. In this study, the ensemble-Kalman-filter (EnKF) approach is used to estimate reservoir flow and material properties by jointly assimilating dynamic flow and geomechanics observations. The resulting model can be used for managing and optimizing production operations and for mitigating the land subsidence. The use of surface displacement observations improves the match to both production and displacement data. Localization is used to facilitate the assimilation of a large amount of data and to mitigate the effect of spurious correlations resulting from small ensembles. Because the stress, strain, and displacement fields are updated together with the material properties in the EnKF, the issue of consistency at the analysis step of the EnKF is investigated. A 3D problem with reservoir fluid-flow and mechanical parameters close to those of the Lost Hills oil field is used to test the applicability.
Experimental Study of MSE of a Single PDC Cutter Interacting With Rock Under Simulated Pressurized Conditions
Authors: Rafatian Navid , Miska Stefan , Ledgerwood L.W.. W. , Ahmed Ramadan , Yu Mengjiao , Takach Nicholas 
Published: March 2010

Summary
The downhole pressure environment is one of the most important factors affecting the rate of penetration (ROP). It is believed that impermeable rocks experience high differential pressures because of shear dilatancy and become stronger and, thus, more difficult to drill. However, recently performed atmospheric and pressurized single-cutter experiments show that contrary to this belief, even at low pressures (100-200 psig) and even with permeable rocks, significant increase in mechanical specific energy (MSE) is observed compared to atmospheric tests.
The experiments were carried out in a single-cutter high-pressure testing facility refurbished with high-precision sensors and a data acquisition system. In the experiments, a 13-mm polycrystalline-diamond-compact (PDC) cutter was used to cut Carthage marble and Indiana limestone samples with depths of cut ranging from 0.025 to 0.050 in. More than 70 high-precision tests were performed on these two rock types under confining pressures ranging from 0 to 1000 psig. The confining fluids were either water or mineral oil.
Unexpectedly, analysis of the MSE consistently showed that increases in the confining pressure as small as 150 psig can increase the MSE of the cutting process significantly and reduce the cutting efficiency by half. These reductions in the cutting efficiency that were even more dramatic in the permeable and saturated Indiana limestone could not be explained by the strengthening of the rock under confining pressures.
Upon analysis of the results of experiments (cutting forces, volume of cuts, and visual inspections of cuttings), a new theory was proposed to explain this unexpected behavior. This new theory, based on the frictional forces and the cutting mechanism under pressure, gives useful insights into the physics of cutter-rock interaction. Such insights are invaluable to the improvements of drilling practices selection [weight on bit (WOB), type of drilling fluid, and its properties] and the ROPs.