bluuebunny/crossref_metadata_2025_split huggingface dataset:
Circulating Epithelial Cells in Patients with Benign Colon Diseases
Authors: Pantel Klaus , Denève Eric , Nocca David , Coffy Amandine , Vendrell Jean-Pierre , Maudelonde Thierry , Riethdorf Sabine , Alix-Panabières Catherine 
Published: December 2011

Abstract

BACKGROUND
Detection of circulating tumor cells (CTCs) in the peripheral blood is a rapidly developing research field with clear clinical implications for the staging and monitoring of cancer patients. Current CTC assays, including the US Food and Drug Administration–cleared CellSearch® system, typically use markers [e.g., cytokeratins (CKs), the transmembrane protein EpCAM (epithelial cell adhesion molecule)] that are expressed on normal and malignant epithelial cells but not on the surrounding normal leukocytes.

METHODS
We enrolled 53 patients with benign colon diseases (e.g., diverticulosis, benign polyps, Crohn disease, ulcerative rectocolitis, colonic endometriosis) and analyzed their peripheral blood with 2 previously validated CTC assays: the epithelial immunospot (EPISPOT) assay and the CellSearch system. The EPISPOT assay detects only viable, CK19-releasing CTCs that were enriched by depletion of CD45+ leukocytes, whereas the CellSearch system detects CK-positive CTCs after positive EpCAM-based immunomagnetic enrichment.

RESULTS
In patients with benign colon diseases, positive events that met the criteria for “tumor cells” were detected with both the CellSearch system (11.3%) and the CK19-EPISPOT assay (18.9%), whereas no positive events were detected in samples from healthy volunteers. Positive events were detected most frequently in patients with diverticulosis and Crohn disease. All positive events lacked expression of CD45, a common leukocyte antigen.

CONCLUSIONS
These results indicate that patients with benign inflammatory colon diseases in particular can harbor viable circulating epithelial cells that are detectable with current CTC assays. This finding points to the need for further molecular characterization of circulating epithelial cells and has important implications for the use of CTC testing.
Phase Stability and Inhibition of Calcium Sulfate in the System NaCl/Monoethylene Glycol/H2O
Authors: Lu Haiping , Amy T Kan , Zhang Ping , Yu Jie , Fan Chunfang , Work Sarah , Tomson Mason B. 
Published: December 2011

Summary
Calcium sulfate is one of the major mineral scales in oil and gas production. Hemihydrate (CaSO4·0.5H2O) and anhydrite (CaSO4) are the predominant sulfate scales formed at high temperature, while gypsum (CaSO4·2H2O) scale may form at low temperatures (&lt;~45°C). However, it has been shown in this study that anhydrite can form at low temperature in the presence of excess amounts of monoethylene glycol (MEG), and this may occur during offshore production with long tie-backs. The prediction and prevention of calcium sulfate scales requires knowledge of the phase behavior of the three major phases of calcium sulfate.
The phase behavior of different calcium sulfate phases is related to the supersaturation state, temperature, and fugacity of water. In this study, the effect of a common hydrate inhibitor, MEG, on calcium sulfate solubility and phase behavior was investigated. This study was run with NaCl/CaSO4/MEG/H2O solutions at 0–6 molality (M) NaCl and 0–95 wt% MEG at 4–70°C. Three approaches were taken to determine the kinetics of calcium sulfate phase transition at various temperatures, ionic strengths, and MEG concentrations: (1) dissolution of gypsum, (2) dissolution of anhydrite, and (3) nucleation and precipitation of calcium sulfate by mixing calcium- and sulfate-containing solutions. The effect of scale inhibitors on phase transition was also evaluated. Phase transition of gypsum to anhydrite was observed in the presence of high concentrations of NaCl and MEG, regardless of the experimental approach. The transition boundary of temperature and concentrations of NaCl and MEG can be estimated from solubility of calcium sulfate and the fugacity of water. The inhibition mechanism of hexamethylene diamine tetra (methylene phosphonic acid) (HDTMP), one of the most effective inhibitors for calcium sulfate scale, was also tested by investigating the kinetics of precipitation and inhibition of calcium sulfate.
Preselection of Reservoir Models From a Geostatistics-Based Petrophysical Seismic Inversion
Authors: Le Ravalec-Dupin M.. , Enchery G.. , Baroni A.. , Da Veiga S.. 
Published: December 2011

Summary
A new geostatistics-based seismic-inversion method is introduced in this paper for determining reservoir models consistent with base seismic information. The proposed methodology entails two steps, with only the second being examined in this paper. First, cubes of acoustic velocities or impedances are derived from seismic inversion. Second, these data are incorporated into a matching process to identify reservoir models leading to acoustic responses close to the reference acoustic data. The parameterization of the facies and petrophysical properties populating the reservoir models is based upon the gradual-deformation method (GDM), which relies on geostatistical concepts. This particular feature makes it possible to change the spatial distribution of the property of interest from a few parameters while preserving its spatial variability. The matching process is driven from a global optimization algorithm known as the particle-swarm optimization (PSO). Such a global approach is reasonable for the problem considered because the forward modeling is very fast. A variant of the PSO algorithm is implemented to take advantage of the GDM properties. This approach yields reservoir models that honor the seismic data better than those derived from stochastic simulation only with seismic used as a secondary variable. A numerical experiment is then presented to stress the applicability of the proposed matching methodology: The GDM-based PSO approach is used to identify facies reservoir models and water/oil contact consistent with some reference acoustic P-wave impedances.
Seismic History Matching of Nelson Using Time-Lapse Seismic Data: An Investigation of 4D Signature Normalization
Authors: Kazemi Alireza , Stephen Karl D. , Shams Asghar 
Published: December 2011

Summary
History matching of a reservoir model is always a difficult task. In some fields, we can use time-lapse (4D) seismic data to detect production-induced changes as a complement to more conventional production data. In seismic history matching, we predict these data and compare to observations. Observed time-lapse data often consist of relative measures of change, which require normalization. We investigate different normalization approaches, based on predicted 4D data, and assess their impact on history matching.
We apply the approach to the Nelson field in which four surveys are available over 9 years of production. We normalize the 4D signature in a number of ways. First, we use predictions of 4D signature from vertical wells that match production, and we derive a normalization function. As an alternative, we use crossplots of the full-field prediction against observation. Normalized observations are used in an automatic-history-matching process, in which the model is updated. We analyze the results of the two normalization approaches and compare against the case of just using production data.
The result shows that when we use 4D data normalized to wells, we obtain 49% reduced misfit along with 36% improvement in predictions. Also over the whole reservoir, 8 and 7% reduction of misfits for 4D seismic are obtained in history and prediction periods, respectively. When we use only production data, the production history match is improved to a similar degree (45%), but in predictions, the improvement is only 25% and the 4D seismic misfit is 10% worse.
Finding the unswept areas in the reservoir is always a challenge in reservoir management. By using 4D data in history matching, we can better predict reservoir behavior and identify regions of remaining oil.
Understanding the Effects of Leakoff Tests on Wellbore Strength
Authors: Wang Hong , Soliman M. Y. , Shan Zhaohui , Meng Frank , Towler Brian F. 
Published: December 2011

Summary
Leakoff tests (LOTs) are performed to test the strength or pressure containment of the shoe after a cement job to help ensure that the new hole has been securely isolated from what has been cased off. A successful LOT can also be used to calibrate the least principal stress (many times, in the case of a vertical well, the minimum horizontal stress), or for geomechanics modeling. This will require initiating a fracture at the wellbore. Because of the near-wellbore stress concentration, for the purpose of geomechanics calibration, it is preferred to take the leakoff to the far-field stress region. To perform this extended LOT (XLOT), a relatively long fracture has to be created. Though an XLOT is needed for these reasons, some engineers tend to refrain from performing this test for fear that the test may damage the wellbore and consequently cause drilling problems.
This paper addresses this issue by investigating the effect of wellbore damage on wellbore "strength" or pressure containment. Various issues are discussed to help engineers determine when it may or may not be a concern. This should give practicing engineers the necessary insight into this complex rock-mechanics issue. The discussions are supported with results from analytical and numerical simulations based on rock-mechanics principles.
Protecting the Reservoir With Surfactant Micellar Drill-In Fluids in Carbonate-Containing Formations
Authors: Huang Tianping , Crews James B. , Clark David E. 
Published: December 2011

Summary
Conventional water-based drill-in fluids (DIFs) contain high-molecular-weight polymers and different-size-distribution solid particles to reduce fluid loss and carry drilling debris back to surface during the drilling process. The polymers and solid particles in the drill-in fluids usually generate near-wellbore formation damage.
This paper introduces a new polymer-free and solids-free surfactant micellar-based drill-in-fluid system to drill a carbonate-containing reservoir. This new fluid system contains relatively low-reactivity acids mixed with surfactants and internal breakers. The drill-in fluid is designed to have low viscosities in the drillpipe. After the fluid flows out of the drill bit, the acids will react with carbonates in the formation and thereby increase the pH of the drill-in fluid. The higher fluid pH combined with the presence of dissolved divalent ions will cause the surfactants to form elongated micelle structures that will significantly increase fluid viscosity at the bottom of the hole and in the downhole annulus between the drillpipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry nondissolved drilling debris to the surface. After drilling through the targeted formation, the internal breakers in the viscosified drill-in fluid will break down the fluid viscosity to improve ease of removal, and the drill-in fluid should leave very little or no near-wellbore damage.
Boosting Energy Efficiency Using Waste-Heat-Powered Absorption Chillers
Authors: Popli Sahil , Rodgers Peter , Eveloy Valerie , Al Hashimi Saleh , Radermacher Reinhard , Hwang Yunho 
Published: December 2011

Summary
The oil and gas industry is under increasing pressure to improve the efficiency of its energy-intensive oil- and gas-processing operations through improved energy use and waste-heat recovery. This paper explores the use of waste-heat-powered absorption cooling to boost the efficiency of natural-gas (NG) processing, enhance hydrocarbon recovery, and reduce utility cost in an NG plant. A thermodynamic analysis of a gas turbine waste-heat-powered double-effect water/lithium bromide (H2O/LiBr) absorption chiller in an integrated NG plant is presented. It is found that waste heat recovered from turbine exhaust gases could be used to provide enhanced process cooling capacity to the NG plant through absorption cooling. The results suggest that a double-effect LiBr absorption chiller utilizing 34.6 MW of gas-turbine exhaust heat could provide 45 MW of cooling at 5°C. This could save approximately 9 MW of electric energy required by a typical compression chiller, while providing an equivalent amount of cooling. The associated annual savings are estimated to be approximately USD 7.8 million/yr, with a payback period of 2 years.
Review of Electrical-Submersible-Pump Surging Correlation and Models
Authors: Gamboa Jose , Prado Mauricio 
Published: December 2011

Summary
Head deterioration observed in electrical submersible pumps (ESPs) under two-phase flow is mild until a sudden performance breakdown is observed in the pump head curve at a certain volumetric gas fraction. This critical condition is termed surging. Consequently, the head that the pump generates with two-phase flow depends on whether the stages operate under conditions before (mild performance deterioration) or after (severe performance deterioration) the surging point.
The surging, for engineering purposes, can be predicted by published correlations, but the lack of a theoretical basis is a limiting factor for their application. Mechanistic models seem to be the proper alternative. However, the poor understanding of the physical mechanism that causes the surging hinders the development of such mechanistic models. This paper reviews some of these correlations and mechanistic models by comparing the correlation predictions against experimental data acquired in a closed loop with water and air using a commercial 24-stage ESP. The data cover a wide range of volumetric gas fractions, rotational speeds, and intake pressures. As a consequence of this analysis, a new correlation has been formulated. This correlation predicts the initiation of the surging as a function of rotational speed and fluid properties.
A Proposed Method for Planning the Best Response to Kicks Taken During Managed Pressure Drilling Operations
Authors: Smith J. R. , Patel B. M. 
Published: December 2011

Abstract
An industry-supported research project has investigated well control methods for managed pressure drilling (MPD) using the constant bottom hole pressure (CBHP) method. This paper proposes a method for pre-selecting the best initial response to be taken when a kick occurs during CBHP MPD based on conclusions from the research. That research (Davoudi et al 2010) concluded that the three most widely applicable initial responses to kicks during MPD were increasing casing pressure until flow out equals flow in, shutting the well in, and using an adaptation of a MPD pump shut down schedule to detect and shut in a low rate kick. Increasing pump rate until flow out equals flow in was concluded to have limited, but potentially still important applications.
The proposed method uses a decision tree to pre-select the best response to be used if an influx of formation fluid is detected. This selection is based on the desired tolerance to kicks, equipment being used, well geometry and conclusiveness of the kick warning signs. The equations necessary to calculate decision parameters, example calculations for an application of the decision tree and comparison of simulation results to application of the decision tree are included. The decision tree indicates the response that maximizes kick tolerance within the well design, gives a basis for revising equipment or well design to maximize kick tolerance, and supports calculation of the expected kick tolerance advantage of the increasing casing pressure response versus a shut in response.
MPD Makes Possible to Drill and Trip Out of the Hole in a Gas Well With a Combination of a Narrow Mud Weight Window and a Serious Ballooning Effect
Authors: Tirado G. R. , Lupo C. P. , Beltran J. C. , Duno H. , Iturrios C. O. , Gallo J. F. , Hernandez T. , Centeno M. 
Published: December 2011

Abstract
This document presents the successful application of pro-active Managed Pressure Drilling (MPD) to drill one section through three different sands; the one in the middle with a low fracture pressure, the lower sand with a formation pressure higher than the frac gradient of the weak formation. The wrong decision to apply MPD in a reactive way leads to NPT, influxes, mud losses and increased risks.
It is shown how the conventional procedures to drill and make the trips are replaced by tailored MPD procedures leading to successful results. The Client understands the high value of proactive MPD, not only to drill but also to during trips. The drilling commenced with a MW of 1.6 g/cc and after 100 m the MW was increased to 1.62 g/cc (it is a routine procedure in the field to increase the mud density prior to reaching the expected high pressure zones while drilling conventionally). Some meters after start drilling the low frac gradient sand total mud losses were observed. The MW was reduced from 1.62 to 1.52 g/cc and MPD was implemented in a proactive manner whereby the BHP was maintained constant. The big challenge was to control the well at all times avoiding a catastrophic condition.
Hybrid Parameterization of Reservoir Properties for Robust History Matching Under Geologic Uncertainty
Authors: Reza M.. , Khaninezhad M.. , Jafarpour Behnam 
Published: December 2011

Abstract
Calibrating reservoir models against production history, also known as history matching, is commonly performed to improve reservoir prediction quality. Data scarcity and over-parameterization typically lead to an ill-posed formulation of history matching inverse problems where too many unknown parameters have to be estimated from limited measurements. As a consequence, many non-unique solutions can be found to match the observed data. Parameterization of reservoir models is often used to improve problem ill-posedness and solution plausibility (i.e., geologic realism). The existing parameterization techniques can be classified as prior-dependent (specialized) and prior-independent (generic) methods. Prior dependent methods such as the principle component analysis (PCA) utilize prior knowledge about the unknown reservoir property distributions (e.g., covariance model) and construct effective parametric descriptions for history matching. These methods immediately lose their effectiveness when the prior model becomes inaccurate. Alternatively, prior-independent methods such as Wavelet or Fourier image compression techniques are more generic (robust) in that they do not assume any prior knowledge in parameterizing reservoir properties. However, because they do not use prior knowledge, these methods are less effective when a reliable prior model is available. What complicates realistic reservoir parameterization is the uncertainty in prior knowledge. Here, we propose a hybrid parameterization approach that, by combining generic and specialized parameterization methods, offers the advantages of two techniques. By combining a set of significant prior-independent generic compression basis elements with a subset of prior-dependent learned basis components we construct a robust hybrid parameterization basis is less sensitive to errors in the prior model and more effective in reproducing more specialized geologic features in the prior. Using the proposed hybrid parameterization in several history matching examples, we show that under (in)correct prior knowledge the generic portion of the hybrid basis becomes (less) more relevant. We conclude that for realistic history matching problems where accounting for geologic uncertainty is imperative, a hybrid parameterization is more appropriate.
Capturing the Effect of Fracture Heterogeneity on Multi-Phase Flow
Authors: Jonoud S. , Wennberg O. P. , Larsen J. A. , Casini G. 
Published: December 2011

Abstract
A typical fractured carbonate reservoir introduces a tremendous challenge to upscaling of single- and multi-phase flow. The complexity comes from both heterogeneous matrix and fracture systems where separation of scales is very difficult, if not impossible. The mathematical upscaling techniques, based on representative elementary volume, must therefore be replaced by a more realistic geology-based approach. In the case of multi-phase flow, an evaluation of the main forces acting during oil recovery must also be performed.
A matrix sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual continuum simulations. An integrated iterative workflow between the geology based static modelling and dynamic simulations is used to investigate the effect of fracture heterogeneity on multi-phase fluid flow. Heterogeneities at various scales, from diffuse fractures to sub-seismic faults, as well as fracture barriers, are considered. The diffuse fracture model is built based on facies and porosity from the matrix model together with core data, image log data and data from outcrop analogues. The sub-seismic fault model is conceptual and based on analysis of outcrop analogue data. Fluid flow simulations are run for both single-phase and multi-phase flow, gas and water injection.
Better understanding of fractured reservoirs behaviour is achieved by incorporating realistic fracture heterogeneity into the geological model and analysing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The sub-seismic faults, however, must be explicitly represented, unless the sigma factor is included in the upscaling process. A local grid refinement approach is applied to demonstrate explicit fractures in large scale simulation grid. This study provides guidelines to how to effectively upscale a heterogeneous fracture model and still capture the heterogeneous flow behaviour.
Lessons Learnt from Nine Years of Immiscible Gas Injection Performance and Sector Modeling Study of Two Pilots in a Heterogeneous Carbonate Reservoir
Authors: Konwar Lakshi , Tariq Syed , Khan Sameer , Kompanik Gary Steven , Bengherbia Mourad , Faskhoodi Majid 
Published: December 2011

Abstract
The subject reservoir is a heterogeneous carbonate formation in a giant field located offshore Abu Dhabi. Five gas injection pilots were initiated in late 2001 in the Eastern, Central and Western parts of the field both as secondary and tertiary recovery methods to evaluate the benefit of gas injection for pressure support and for recovery improvement. With less than 10% of HCPV gas injection, the pilots to date have provided valuable insight on production performance and pressure support, gravity override, swelling effect and flow assurance issues (such as asphaltene deposition) in the field. Using a 3D compositional model, a sector modeling study was carried out for comprehensive evaluation of the pilot performance to date and to predict definitive results within reasonable time frame (3-5 years) which will have ramifications on long-term full field development decisions. Additionally, the objectives of simulation efforts were to evaluate different recovery processes (gas/water/WAG) and assess key reservoir uncertainty (volumetric sweep) due to reservoir heterogeneity (high permeability streaks). Initially, the sector model was history matched with nine years of pilot performance while both reservoir heterogeneity and well spacing sensitivities were tested in the model. The history matched sector model was utilized to predict performance under different operating conditions using both gas, water and water alternating gas (WAG) injection methods.
This paper describes the pilot performance, field observations and results of a sector model study including history match, sensitivity and predictions under different injection scenarios on two of the pilots. Based on the performance and surveillance data gathered on the two pilots and sector modeling study, it was established that both pilots have met their objectives and can be concluded. Through the integration of field observations and sector modeling work, the study provided valuable insight on optimum recovery processes, well spacing and well completion requirements for long-term field development.