bluuebunny/crossref_metadata_2025_split huggingface dataset:
Association of genetic variants in the adiponectin gene with adiponectin level and hypertension in Hong Kong Chinese
Authors: Ong Kwok Leung , Li Mingfang , Tso Annette W K , Xu Aimin , Cherny Stacey S , Sham Pak Chung , Tse Hung Fat , Lam Tai Hing , Cheung Bernard M Y , Lam Karen S L 
Published: June 2010

ObjectiveLow plasma adiponectin level can predict the development of hypertension after 5 years in our population. We therefore investigated whether single-nucleotide polymorphisms (SNPs) in the adiponectin gene influenced plasma adiponectin level and whether they were associated with hypertension.Design and methodsWe genotyped 14 tagging SNPs in 1616 subjects with persistent normotensive or hypertensive status during a 6.4-year follow-up period in the Hong Kong Cardiovascular Risk Factor Prevalence Study-2 (CRISPS-2). Plasma adiponectin level was measured in 1385 subjects using in-house sandwich ELISA.ResultsThe minor G allele of the SNP rs266729 was significantly associated with higher odds of hypertension (odds ratio (95% confidence interval)=1.49 (1.13–1.95), P=0.0044) after adjusting for covariates. In stepwise multiple logistic regression, this SNP (P=0.006) was a significant independent factor of hypertension, together with age (P<0.001), body mass index (P<0.001), triglycerides (P=0.021), and insulin resistance index (P<0.001). Among the 14 SNPs, rs266729 (β=−0.067, P=0.0037), −10677C>T (β=0.069, P=0.0027), rs182052 (β=−0.097, P<0.0001), and rs12495941 (β=0.103, P<0.0001) were significantly associated with adiponectin level after adjusting for covariates. No significant sex interaction was found for the associations of SNPs with hypertension and adiponectin level. Similar results were obtained in haplotype analysis.ConclusionIn our population, genetic variants in the adiponectin gene influenced plasma adiponectin levels, and one of them was associated with hypertension. This study has provided further evidence for a role of adiponectin in the development of hypertension.
Estimation of Dry-Rock Elastic Moduli Based on the Simulation of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs
Authors: Odumosu Tobiloluwa B. , Torres-Verdín Carlos , Salazar Jesús M. , Ma Jun , Voss Benjamin , Wang Gong Li 
Published: June 2010

Summary
Reliable estimates of dry-rock elastic properties are critical to the accurate interpretation of the seismic response of hydrocarbon reservoirs. We describe a new method for estimating elastic moduli of rocks in-situ based on the simulation of mud-filtrate invasion effects on resistivity and acoustic logs.
Simulations of mud-filtrate invasion account for the dynamic process of fluid displacement and mixing between mud-filtrate and hydrocarbons. The calculated spatial distributions of electrical resistivity are matched against resistivity logs by adjusting the underlying petrophysical properties. We then perform Biot-Gassmann fluid substitution on the 2D spatial distributions of fluid saturation with initial estimates of dry-bulk (kdry) modulus and shear rigidity (µdry) and a constraint of Poisson's ratio (?d) typical of the formation. This process generates 2D spatial distributions of compressional and shear-wave velocities and density. Subsequently, sonic waveforms are simulated to calculate shear-wave slowness. Initial estimates of the dry-bulk modulus are progressively adjusted using a modified Gregory-Pickett (1963) solution of Biot's (1956) equation to estimate a shear rigidity that converges to the well-log value of shear-wave slowness. The constraint on dynamic Poisson's ratio is then removed and a refined estimate of the dry-bulk modulus is obtained by both simulating the acoustic log (monopole) and matching the log-derived compressional-wave slowness.
This technique leads to reliable estimates of dry-bulk moduli and shear rigidity that compare well to laboratory core measurements. Resulting dry-rock elastic properties can be used to calculate seismic compressional-wave and shear-wave velocities devoid of mud-filtrate invasion effects for further seismic-driven reservoir-characterization studies.
Experimental Investigation of Emulsion Stability in Gas/Oil Separation Plants
Authors: Al-Ghamdi A. M. , Noïk C. , Dalmazzone C. , Kokal S. 
Published: June 2010

Summary
This paper presents an experimental study performed to characterize the stability of emulsion samples collected from different Gas/Oil Separation Plants (GOSPs). The first part of the study (Al-Ghamdi et al. 2007) focused on the analyses of separated phases. Many techniques (differential scanning calorimetry, Karl Fischer titration, rheology, optical microscopy, and cryo-scanning electron microscopy) were applied to analyze and characterize the separated phases: crude oil, emulsion, and free water. In the second part of this study, the stability of residual emulsions was investigated against several chemical demulsifiers by using bottle tests and an automated vertical-scan macroscopic analyzer (Turbiscan; Formulaction; Toulouse, France). This instrument is used to obtain kinetics of separation of concentrated and opaque dispersed systems such as emulsions, suspensions, and foams. Interfacial tension measurements were also made to obtain information about the interfacial behavior of samples including viscoelasticity properties of the film. The results of transient emulsion-separation experiments provide some useful insights into their behavior, stability, and tightness. The study highlights the main physicochemical parameters responsible for the varying tightness of these emulsions and should help provide recommendations to optimize their treatment costs and resolve emulsion issues in the GOSPs.
Temperature Effects on Surfactant-Aided Imbibition Into Fractured Carbonates
Authors: Gupta R. , Mohanty K. 
Published: June 2010

Summary
Little oil is recovered from fractured oil-wet carbonate rocks by waterflooding. Surfactant treatments are being developed to enhance oil recovery from such formations. This paper investigates the effect of temperature on such surfactant treatments. Anionic and nonionic surfactants have been identified for oil recovery from fractured low-permeability carbonate rocks at high temperatures. For most of the surfactants studied, optimal salinity decreases slightly or remains unchanged with an increase in temperature. Contact angles on initially oil-wet calcite plates decrease on addition of most of the surfactants; the final contact angle decreases with increase in temperature for all the surfactants in the current study. Oil-recovery rate from surfactant solution imbibition increases with temperature for all surfactants. At 90°C, high recovery [approximately 60% original oil in place (OOIP) in 30 days] was obtained for many surfactants at very low surfactant concentrations (&lt; 0.1 wt%) in tight (approximately 15 md) carbonate cores. Surfactant/brine imbibition was found to be a gravity-driven process for these surfactants. Increase in temperature leads to reductions in viscosity and contact angle, which, in turn, increases oil relative permeability, which enhances the oil-recovery rate.
The Effect of Including Tracer Data in the Ensemble-Kalman-Filter Approach
Authors: Valestrand Randi , Sagen Jan , Nævdal Geir , Huseby Olaf 
Published: June 2010

SummaryTracers are widely used to increase the understanding of fluid flow; they can be used to label injection fluids, hence, well connections and fluid patterns can be established when the tracer appears in production wells. Tracer data contain valuable information but are often underexploited.This paper presents methodology for assimilation of tracer data for reservoir model updating using the ensemble Kalman filter (EnKF). The presented assimilation methodology is generally applicable for all types of tracers, but the example used for demonstration focuses on gas tracers. Contrary to water tracers, which can be either nonpartitioning or partition between (oil and water) phases, gas tracers always partition between the oil and gas phases. This oil/gas partitioning is accounted for in the presented tracer transport modeling. The EnKF has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty.The value of tracer data in the EnKF approach is demonstrated on a North-Sea-based example. The permeability and fault transmissibility multiplier of a reservoir are estimated by EnKF. This example shows that tracer data can be used successfully in an EnKF-based automatic updating scheme. Potential misinterpretations of gas tracer data if their partitioning is neglected is highlighted by comparing results from simulation cases where partitioning is neglected to simulation results where partitioning is accounted for.
The Importance of Wax-Deposition Measurements in the Simulation and Design of Subsea Pipelines
Authors: Akbarzadeh Kamran , Ratulowski John , Eskin Dmitry , Davies Tara 
Published: June 2010

Summary
Conventional practices for estimating the amount of deposited wax in pipelines are usually based on predictions made with simulation packages using limited stock-tank-oil (STO) deposition data collected under laminar-flow conditions in bench-scale flow loops. Such practices are conservative and often lead to nonoptimal designs of pipelines and surface facilities. For optimized designs, laboratory-scale deposition measurements made under realistic conditions are required to calibrate flowline models. In this work, a high-pressure deposition cell that operates on the Taylor-Couette (TC) flow principle is used to generate more deposition data with live reservoir fluids under turbulent flow similar to the conditions encountered in many flowlines. The analogy between TC flow and pipe flow is explained, and a scalability flow chart for linking the laboratory-scale deposition data from TC configuration to pipe configuration is presented. Through a case study, the scaled-deposition data are then used to tune a wax-deposition model in the OLGA®5 simulation package. Next, the tuned model is applied to predict wax deposition under actual production and transportation conditions. The importance of tuning the deposition models with live fluid data under turbulent-flow conditions is also shown by comparing results obtained from conventional dead-oil low-shear data.
A New Regression-Based Method for Accurate Measurement of Coal and Shale Gas Content
Authors: Shtepani E.. , Noll L.A.. A. , Elrod L.W.. W. , Jacobs P.M.. M. 
Published: June 2010

SummaryGas 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 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 airtight 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 the 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 vs. 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, has an impact on the calculation of gas in place, the recoverable reserves, and production profiles.
Predicting Hydrate-Plug Formation in a Subsea Tieback
Authors: Davies Simon R. , Boxali John A. , Koh Carolyn A. , Sloan E. Dendy , Hemmingsen Pål V. , Kinnari Keijo J. , Xu Zheng-Gang 
Published: June 2010

Summary
Field data from StatoilHydro on hydrate-plug formation in the Tommeliten gas/condensate field are compared to predictions of the hydrate-growth model (CSMHyK-OLGA) for four typical operating scenarios: steady-state operation with failure of inhibitor injection, restart of an uninhibited line, restart of an underinhibited line, and restart of a depressurized line.
Although the CSMHyK model was designed for oil flowlines, the model is able to predict the correct time scale for hydrate-plug formation in this gas/condensate tieback. The predicted locations of the plugs are often farther upstream than observed in the field trials. This is mainly because of the assumption of a "hydrate/oil slip factor" of zero, which forces the hydrate to accumulate where it initially formed. In reality, hydrate agglomerates would be carried further downstream before eventually jamming in dips.
Predicting where and when hydrate plugs will form in subsea tiebacks is of increasing importance as the industry strives to manage the risk of plugging in oil and gas flowlines while minimizing the use of costly and environmentally harmful chemicals for hydrate inhibition. The Colorado School of Mines has been developing the CSMHyK model for the past 5 years, in collaboration with the SPT Group and several leading energy companies.
Experimental Study and Modeling of Cuttings Transport Using Foam With Drillpipe Rotation
Authors: Duan Mingqin , Miska Stefan , Yu Mengjiao , Takach Nicholas , Ahmed Ramadan , Hallman John 
Published: June 2010

Summary
Although rotary drilling is being used in most wells, the impact of drillpipe rotation on hole cleaning during foam drilling has not been investigated. There has been no single predictive tool developed to address pipe rotation effects on foam drilling. This paper presents the first study of cuttings transport using foam with pipe rotation under simulated downhole conditions.
A field-scale, high-pressure/high-temperature wellbore simulator with a 73-ft-long, 5.76×3.5-in. eccentric annular test section was used to investigate the effects of pipe rotation, foam quality and velocity, downhole pressure and temperature on cuttings transport, and pressure losses in a horizontal wellbore. Experiments were conducted with backpressures from 100 to 400 psi and temperatures from 80 to 160°F. Pipe rotary speeds were varied from 0 to 120 RPM, with foam qualities ranging from 60 to 90% and foam velocities from 2 to 5 ft/sec.
It was found that pipe rotation not only significantly decreases cuttings concentration in a horizontal annulus but also results in a considerable reduction in frictional pressure loss. The reduction in cuttings concentration is up to 40% at a medium foam velocity (3 ft/sec) when pipe is rotated up to 120 RPM. The decrease in frictional pressure loss is up to 50% at a medium foam velocity and is more than 60% at a low velocity. Using a higher foam velocity or quality also improves hole cleaning; however, pressure losses are significantly increased.
A mechanistic model and an associated computer simulator were developed for practical design and field applications. It can be used to predict cuttings concentration, bed height, and pressure drop during horizontal foam drilling with various pipe rotary speeds, eccentricities, foam qualities, and velocities under different pressure and temperature conditions. Comparisons between model predictions and experimental results show that the difference is less than 15% in most of the cases.
Estimation of Depths of Fluid Contacts and Relative Permeability Curves by History Matching Using Iterative Ensemble-Kalman Smoothers
Authors: Wang Yudou , Li Gaoming , Reynolds Albert C. 
Published: June 2010

Summary
With the ensemble Kalman filter (EnKF) or smoother (EnKS), it is easy to adjust a wide variety of model parameters by assimilation of dynamic data. We focus first on the case where realizations and estimates of the depths of the initial fluid contacts, as well as grid- block rock-property fields, are generated by matching production data with the EnKS. Then we add the parameters defining power law relative permeability curves to the set of parameters estimated by assimilating production data with EnKS. The efficiency of EnKF and EnKS arises because data are assimilated sequentially in time and so "history matching data" requires only one forward run of the reservoir simulator for each ensemble member. For EnKS and EnKF to yield reliable characterizations of the uncertainty in model parameters and future performance predictions, the updated reservoir-simulation variables (e.g., saturations and pressures) must be statistically consistent with the realizations of these variables that would be obtained by rerunning the simulator from time zero using the updated model parameters. This statistical consistency can be established only under assumptions of Gaussi- anity and linearity that do not normally hold. Here, we use iterative EnKS methods that are statistically consistent, and show that, for the problems considered here, iteration significantly improves the performance of EnKS.
Confidence Limits Associated With Values of the Earth's Magnetic Field Used for Directional Drilling
Authors: Macmillan Susan , Grindrod Steve 
Published: June 2010

Summary
This paper describes updated uncertainties for use with predicted geomagnetic parameters within magnetic measurement-whiledrilling (MWD) survey-tool-error models. These models are used to define positional-error ellipsoids along the wellbore, which assist in hitting geological targets and avoiding collisions with existing wellbores.
The declination, dip angle, and total field strength of the Earth's magnetic field are used with magnetic-survey tools for surveying the wellbore. These values are often obtained from mathematical models such as the British Geological Survey (BGS) global-geomagnetic model (BGGM). As the Earth's magnetic field is continually varying with time, the BGGM is updated annually to maintain accuracy. However, a global predictive model cannot capture all sources of the Earth's magnetic field, which results in uncertainties of the predicted parameters. The Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA) published an MWD-error model in 2000 (Williamson 2000). The geomagnetic-field uncertainties that are part of this model were derived from work conducted by the BGS in the early 1990s. Since then, more-accurate data from magnetic-survey satellites have been introduced into the BGGM, and the uncertainty of the predicted geomagnetic-field parameters has been reduced.
The original approach to deriving the uncertainties involved separating the various error sources in the magnetic field and assessing them individually. This paper uses a simpler approach where clean orientated magnetic downhole data are simulated using geomagnetic-observatory data. Spot absolute measurements of the magnetic field made at observatories around the world are adjusted for the crustal magnetic field to make them more representative of hydrocarbon geology. The adjusted observatory data are then compared with the predicted values from the BGGM to assess the uncertainty. The uncertainties do not fit a normal distribution, so they are expressed as limits for various confidence levels. They vary with location and, in their derivation, do not assume any underlying empirical error distribution. While they also vary with time, we provide time-averaged look-up tables that should be valid for as long as there are good-quality satellite data on which to base global magnetic-field models. Options to reduce the uncertainties further using data from local magnetic surveys [in-field referencing (IFR)] and observatories (interpolation IFR) are also described.
The use of the revised geomagnetic uncertainty values in the MWD-error model will reduce wellbore-position uncertainty to reflect the increased accuracy from recent improvements in geomagnetic modeling. This is demonstrated using results for the ellipsoids of uncertainty output by an MWD error model for three standard ISCWSA well profiles.
Medium-Scale Experiments on Stabilizing Riser-Slug Flow
Authors: Sivertsen Heidi , Alstad Vidar , Skogestad Sigurd 
Published: June 2010

Summary
This is the second of two papers describing control experiments on a medium-scale slug rig. The first paper (Sivertsen et al. 2009) describes experiments performed on a small-scale laboratory rig built at the Norwegian University of Science and Technology (NTNU) Department of Chemical Engineering. These experiments showed that, despite noisy measurements, it is possible, with feedback control, to "stabilize the flow" (i.e., to achieve reasonably smooth flow in the normally riser-induced severe slug-flow region) using only topside measurements. The question to be answered is whether these results also apply for larger riser systems.
In the present paper, we look at some results obtained from a 10-m-high, 3-in.-diameter medium-scale test rig located at the Statoil Research Centre in Porsgrunn, Norway. Several cascade control structures are tested and compared, both with each other and with the results obtained from the small-scale NTNU loop. The rig was also modeled and analyzed using a simple three-state dynamic model.
The new experiments were successful and confirm the results of Sivertsen et al. (2009) from the small-scale rig. The valve opening with nonslug flow operation could be increased from approximately 12% with no control to almost 24% with control using topside measurements only. This makes it possible to produce with a larger production rate and increase the total recovery from the producing oil field. The valve opening with control could be further increased to approximately 28% using measurements from the bottom of the riser, but such measurements may not be available in many cases.