Measurement Of Fluid Properties Research Articles

Model discovery approach enables noninvasive measurement of intra-tumoral fluid transport in dynamic MRI.

Dynamic contrast-enhanced magnetic resonance imaging (DCE-MRI) is a routine method to noninvasively quantify perfusion dynamics in tissues. The standard practice for analyzing DCE-MRI data is to fit an ordinary differential equation to each voxel. Recent advances in data science provide an opportunity to move beyond existing methods to obtain more accurate measurements of fluid properties. Here, we developed a localized convolutional function regression that enables simultaneous measurement of interstitial fluid velocity, diffusion, and perfusion in 3D. We validated the method computationally and experimentally, demonstrating accurate measurement of fluid dynamics in situ and in vivo. Applying the method to human MRIs, we observed tissue-specific differences in fluid dynamics, with an increased fluid velocity in breast cancer as compared to brain cancer. Overall, our method represents an improved strategy for studying interstitial flows and interstitial transport in tumors and patients. We expect that our method will contribute to the better understanding of cancer progression and therapeutic response.

Optimizing Sensitivity in a Fluid-Structure Interaction-Based Microfluidic Viscometer: A Multiphysics Simulation Study.

Fluid-structure interactions (FSI) are used in a variety of sensors based on micro- and nanotechnology to detect and measure changes in pressure, flow, and viscosity of fluids. These sensors typically consist of a flexible structure that deforms in response to the fluid flow and generates an electrical, optical, or mechanical signal that can be measured. FSI-based sensors have recently been utilized in applications such as biomedical devices, environmental monitoring, and aerospace engineering, where the accurate measurement of fluid properties is critical to ensure performance and safety. In this work, multiphysics models are employed to identify and study parameters that affect the performance of an FSI-based microfluidic viscometer that measures the viscosity of Newtonian and non-Newtonian fluids using the deflection of flexible micropillars. Specifically, we studied the impact of geometric parameters such as pillar diameter and height, aspect ratio of the pillars, pillar spacing, and the distance between the pillars and the channel walls. Our study provides design guidelines to adjust the sensitivity of the viscometer toward specific applications. Overall, this highly sensitive microfluidic sensor can be integrated into complex systems and provide real-time monitoring of fluid viscosity.

Pipe Viscometer for Continuous Viscosity and Density Measurement of Oil Well Barrier Materials

Summary The barrier material is a crucial component for wells, as it provides mechanical support to the casing and prevents the uncontrolled flow of formation fluids, ensuring zonal isolation. One of the essential prerequisites for the success of cementing an oil and gas well is the efficient removal of in-situ fluids and their adequate replacement by the barrier material. The quality of the mud displacement is affected by both the density and the viscosity hierarchy among subsequent fluids. Consequently, accurate and reliable measurement of fluid properties can help ensure consistent large-scale mixing of cementing fluids and verification that the properties of the mixed fluid are according to plan. In this paper, we investigate the implementation of a pipe viscometer for future automated measurements of density and viscosity of materials for zonal isolation and perform a sequential validation of the viscometer that starts with small-scale batch mixing and characterization of particle-free calibration liquids, followed by conventional Class G cement and selected new barrier materials. Finally, a larger-scale validation of the pipe viscometer was performed by integrating it into a yard-scale batch mixer for in-line characterization of expanding Class G oilwell cement mixing. In all cases, flow curves derived from pipe viscosity measurements were compared with offline measurements using a rheometer and a conventional oilfield viscometer. After a series of measurements and comparisons, the investigated in-line measurement system proved adequate for viscosity estimation. The flow curve of the barrier materials showed results similar to measurements using a conventional viscometer, validating the proposed test configuration to continuously measure the rheological behavior of the barrier material. The pipe viscometer flow curves are generally found to be in good quantitative agreement with independent viscometer characterization of the fluids, although some of the pipe viscometer measurements likely exhibited entrance length effects. Future improvements to the pipe viscometer design involve the assessment of even longer pipe sections to allow full flow development at the highest shear rate range and possibly different pipe diameters to improve the measurement resolution of low-shear rate viscosity.

Production-Logging Technologies Enhance Inflow Profiling in Deepwater Gulf of Mexico

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196188, “Third-Generation Production-Logging Technologies Enhance Inflow Profiling in Deepwater Gulf of Mexico Reservoirs,” by Glenn Donovan, SPE, Sagar Kamath, and Elizabeth Tanis, SPE, Shell, et al., prepared for the 2019 SPE Annual Technology Conference and Exhibition, Calgary, 30 September–2 October. The paper has not been peer reviewed. This paper discusses the effectiveness of third-generation (Gen3) production-logging-tool (PLT) technology, which uses co-located digital sensors for simultaneous acquisition of flow data to provide the most accurate characterization of the flow condition at each depth surveyed. The resulting data allow for much-improved processing. The probabilistic interpretive model used in the processing has been updated to incorporate this and future developments in PLT architecture. Introduction The first generation of PLT provided a single, discrete measurement for each sensor along the tool assembly’s length, resulting in long tool assemblies and measurements taken at different points along the flow path. This approach had several drawbacks: long toolstrings, point sensors that only provided a measurement at a single point in the cross section of the flow, and measurements that were not acquired simultaneously at each depth logged. Second- generation PLTs represented an improvement because sensors were arranged as an array, enabling multiple measurements to be made at a single depth. However, the toolstrings were still long and not all were arranged optimally to capture data in the flow path. The Gen3 PLT is one-tenth the length of the first-generation versions and roughly one-third that of the shortest second-generation tools. Digitalization allows for direct measurement of flow conditions and rapid interpretation of results. In multiphase flow and deviated wells, co-locating sensors in a spatial geometry provides the optimal information with which to create a fully accurate picture of the downhole flow. Description of Gen3 PLT The PLT described in the paper exemplifies how miniaturization and digitalization are enabling transformational improvements over traditional systems in terms of efficiency and capability. The tool encompasses, within a 3-ft length, up to 24 sensors that collect multiple measurements of fluid properties and fluid movements in a wellbore. These include oil, gas, and water holdup and bubble count, fluid conductivity, phase velocities, pressure, temperature, inclination, rotation, and depth correlation, plus power and communication. The fluid characteristics are locally screened by an array of 8 to 16 tube-shaped probe sensors that are interchangeable, depending on the targeted measurements (Fig. 1). The tool relies on a refractive index needle-shaped probe with a triphasic sensor to identify and quantify the oil, gas, and water holdups and bubble counts at each point of the array. The geometric design of the sensitive tip, along with the optoelectronics of the sensor, are optimized to discriminate oil, water, and gas with high confidence, overcoming the fact that the refractive indexes of oil and water are close to each other.

Electrowetting based local sensing of liquid properties using relaxation dynamics of stretched liquid interface

HypothesisMonitoring progression of biochemical processes is required for medical and industrial applications. Spatiotemporal changes in fluid properties can be measured to determine progress of biochemical processes like blood coagulation. Localised electrowetting-on-dielectric (EWOD) actuates a part of droplet contact line, allowing local measurement of fluid properties without inducing bulk fluid motion, which is unlike full droplet oscillation-based techniques. ExperimentsIn this work, narrow electrodes (50–450 μm) were used to actuate a portion of drop interface. Dynamics of interface actuation and relaxation was used to estimate the local visco-elastic properties of the droplet. FindingsFor local interface motion, theory predicts a generic dispersion relation ω=cqn. In agreement with theory, decay time was found to be proportional to viscosity and inversely proportional to surface tension. Interface displacement remained almost constant for different viscosities, but it decreased with increase in surface tension. Capability to measure spatiotemporal dynamics of chemical process was demonstrated for sugar dissolution in a droplet of water. For full droplet oscillation-based techniques, the induced bulk flows adversely affect the monitored process. Localised EWOD reduces bulk flows in the sample. So, this technique was applied to study blood coagulation dynamics, enlightening the future prospect of developing biomedical sensors.

Technology Update: Magnetic Resonance-While-Drilling System Improves Understanding of Complex Reservoirs

Technology Update Reservoirs consisting of heterogeneous carbonates and shaly sands pose formation evaluation challenges for conventional logging-while-drilling (LWD) measurements. Widely used resistivity, density, neutron porosity, and sonic measurements are all sensitive to both the formation matrix and the fluids, which may create ambiguities in the evaluation of reservoir fluids. The Schlumberger proVision Plus magnetic resonance-while-drilling (MRWD) technology offers enhanced evaluation capabilities. By manipulating the hydrogen atoms in the fluids, nuclear magnetic resonance (NMR) methods provide a focused measurement of fluid properties and their interactions with the surrounding matrix at a fundamental level. The technology provides a more complete, real-time assessment of producibility in complex reservoirs. Evolution of the Technology The industry has used NMR technology for formation evaluation for more than 25 years, during which significant technical and operational developments have greatly enhanced its capabilities and applications. In porous media, NMR techniques reveal pore and fluid properties by exciting the nuclear states of hydrogen-containing molecules in the formation fluids and measuring the relaxation times for the induced excited energy states. The relaxation time for a molecule near a pore wall surface tends to be much faster than that for a molecule in the bulk fluid volume. A distribution of all the relaxation times, known as a T2 distribution, can be used to derive both irreducible and producible fluid volumes, and an improved estimation of permeability. These measurements are also important for identifying bypassed pay zones and estimating production rates. The first NMR tools were deployed on wireline after the hole had been drilled, which added rig time and cost to the operation and did not allow for real-time changes to the wellbore’s trajectory. Schlumberger shifted the service from wireline to a while-drilling application in 2002. This early work focused on redesigning the sensor array to make it more robust and capable of withstanding dynamic drilling environments. The design effort culminated with the introduction of the company’s latest MRWD system in 2012. Its new sensor makes reliable measurements under rapidly changing downhole temperatures and pressures and withstands the vibrations and drillstring shocks that are common during drilling. Further design enhancements allow the tool to be placed anywhere within the bottomhole assembly (BHA). A sleeve stabilizer minimizes tool motion without affecting the steerability of the BHA. Powered by a downhole electrical turbine, the tool does not need to be tripped to replace batteries.

Liquid characterization and measurement of fluid properties for reduced uncertainty in multiphase flow area fraction measurements

Meters measuring multiphase flows use one or more physical properties of the fluids to estimate flow area fractions of phases and components. Most common in the oil and gas industry are meters based on measurement of gamma ray attenuation and permittivity. Uncertainty about the actual values of attenuation coefficients and permittivity will lead to systematic errors which we analyze and exemplify. To counter these errors it is desirable to monitor the properties of the fluids on-line with the flow measurement. Subsequently we present measurements of liquid phase properties since these are found to impact flow area fraction measurements more significantly. Dual-modality densitometry, which is based on measurements of gamma attenuation coefficients, is used to characterize liquid components in terms of density and composition. This technique is demonstrated to be well suited for the task, albeit the compositional results are less accurate, and do not allow for precise interferences regarding the permittivity.

Microfluidics and Their Macro Applications for the Oil and Gas Industry

Academia Pore-scale transport phenomena in reservoirs is of critical importance to the oil and gas industry, and the study of fluid transport at small scales has a long history that predates the term “microfluidics.” The term is predominantly associated with microfluidic chip-based technology that emerged in the 1990s and grew in response to health and life science applications. Oil and gas professionals are realizing the potential of this technology and tapping into various sectors. For example, OndaVia, founded in 2009, has patented microfluidics-based analysis and separation tools for applications in the chemical industry. There are exciting opportunities for industry giants not only to improve their business but also to encourage research at academic institutions. Researchers and entrepreneurs can collaborate in order to make microfluidics applications more accessible and soon become the go-to solutions to inform operations and perform fluid analysis. There are also tremendous opportunities through startup companies and technology acquisitions to provide faster and better fluid property measurements as well as screening and assessment of reservoir processes at the pore scale. The biggest challenges here are investment capital and standardization, both of which need to be addressed with more awareness among the industry pioneers. Microfluidics for oil and gas startups can grow in response to revenue and may be acquired by an established service company to reach global markets. The central advantages that motivated the microfluidic approach in life sciences were rapid analysis; low reagent volumes; low cost; excellent control of conditions, particularly on the scale of biological cells; and opportunities for separations and multiplexing. Several of these advantages can translate directly to oil and gas applications, both above and below ground, as highlighted in Fig. 1. In addition, suitably fabricated glass and silicon microfluidic chips can readily accommodate reservoir pressures. For instance, in contrast to conventional large pressure/volume/temperature cells, high pressures are easily handled with microfluidics owing to the very small volumes (and small areas) involved. The challenge is leveraging our unique microfluidic tools to maximize the contribution to the energy sector. We need to find challenges that are both important and uniquely well-suited to a microfluidic approach. Outlined below are two such approaches: microfluidics for oil and gas fluid analysis, and microfluidics/micromodels to understand pore-scale processes in reservoirs.

Evaluating Formation-Fluid Properties During Sampling-While-Drilling Operations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173152, “Evaluating Formation-Fluid Properties During Sampling- While-Drilling Operations,” by K. Indo, J. Pop, K. Hsu, and S. Ossia, Schlumberger; G.-L. Atzeni and A. Malossi, Eni; and V. Agarwal, A. Garcia-Mayans, S. Paul, J. Varughese, and S. Haq, Schlumberger, prepared for the 2015 SPE Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. Recent experience with a newly introduced sampling-while-drilling service has shown that it is possible to make reliable downhole formation-fluid-property estimates during sampling-while-drilling operations. These property and contamination estimates facilitate the management of the entire while-drilling sampling process by aiding sample-capture decisions and allowing the best possible use of the sample bottles currently available on a drilling bottomhole assembly. Moreover, the contamination estimates, together with the real-time fluid-property estimates, enable prediction of the uncontaminated-fluid properties. Introduction If performed during drilling (when filtrate invasion is not fully developed), fluid scanning—where formation fluid is pumped and analyzed within the sampling-while-drilling tool without taking a sample—affords the opportunity to characterize the formation fluid at potential sampling depths before committing sample chambers. The success of such an approach depends on how completely the in-situ fluid can be characterized and how free of contamination the assessed properties are. By use of downhole optical spectrometry, it has been shown recently that it is possible to estimate in real time at least the following formationfluid properties: fluid color and type, hydrocarbon composition at various levels, carbon dioxide (CO2) content, gas/oil ratio (GOR), formation volume factor (FVF), and asphaltene content. Other measurements such as pressure, temperature, pressure gradients, and fluid density and viscosity enhance the characterization. Although not replacing pressure/volume/temperature (PVT) laboratory measurement of fluid properties, this list allows the fluid to be characterized sufficiently well to determine the fluid type and to differentiate between fluids at different spatial locations. This capability becomes important when deciding which fluid to sample, whether to recover a fluid sample, and whether another sampling run should be undertaken. The process of differentiating between fluids becomes increasingly difficult as the level of contamination of the sampled fluid increases; the proper basis for comparison is, ideally, a contamination-free (clean) fluid. If estimates of uncontaminated-fluid properties were available during drilling operations, the allocation of samples to fluids having the highest recovery priority would be expedited.

New LWD Service Integrates Formation Fluid Analysis and Sampling

Young Technology Showcase Determining the fluid properties of a reservoir by using pressure/volume/ temperature (PVT) analysis is essential to petroleum reservoir studies, production equipment design, and reservoir recovery efficiency estimation. The properties of the formation fluid are used to determine reserves and to predict reservoir performance and economics. PVT properties such as bubblepoint pressure, gas/oil ratio, viscosity, oil formation volume factor, and detailed composition are important to well performance analysis, material balance calculations, reservoir simulation, and production engineering calculations. Once the reservoir information is available, the well team makes the critical field development decisions. Conventional post-well wireline formation testing operations can delay decision making for days, sometimes months, depending upon the logistics involved in transporting a sample from the wellsite to a PVT laboratory. Additionally, wireline deployment is expensive in horizontal and highly deviated wells because of the extra time and equipment required to convey the tools to the test intervals. Integration Benefits The latest logging-while-drilling (LWD) technology integrates downhole fluid analysis and sampling with formation pressure while drilling (FPWD), thereby providing environmental, economic, time-saving, and data quality benefits over traditional methods of reservoir characterization. The integration enables three distinct services: real-time formation pressure tests, real-time in-situ measurements of fluid properties, and downhole capture and retrieval to the surface of fluid samples. The real-time formation pressure testing provides important information on fluid dynamics within the reservoir, mobility measurements, and zone productivity predictions. It is also important for accurate gradient analysis. Measuring multiple formation pressures at different depths delivers a formation fluid gradient that makes it possible to find contact points between different formation fluids such as water, gas, and oil. Pressure testing in an LWD environment also provides important information for safety and drilling optimization, including data that are valuable for controlling hydraulic overbalance and equivalent circulating density. Representative fluid samples provide information on the production potential of the reservoir. LWD fluid analysis and sampling enables fluids samples to be collected closer to in-situ conditions for a more accurate determination of fluid composition. Additionally, sample integrity can be monitored continually from the first time the sample enters the LWD tool until it is transferred to the laboratory for detailed analysis. Greater accuracy improves project cycle times and reduces development risks. Although the vital information provided by the integrated LWD service is useful throughout the life cycle of a reservoir, it is particularly valuable during the initial assessment to determine the commercial potential of a project. The assessment includes estimates for producibility, fluid type and composition, fluid phase behavior, production facility design, and flow assurance.

Temperature Controlled Viscosity and Density Measurements on a Microchip with High Resolution and Low Cost

A chip-based viscosity and density sensor which requires a sample volume of less than 10 colonl is presented. A resistive heater and a temperature sensor are provided for accurate and fast temperature dependent measurements. An inductive readout of the resonance frequency and the damping further facilitates the measurement procedure. Thereby high resolution measurements of fluid properties are easily made in view of their analysis in the context of thermorheologically simple materials.

Measurement of fluid properties using an acoustically excited atomic force microscope micro-cantilever

In this study, we develop a technique that can be used for extracting the properties of high viscosity Newtonian liquids at the microliter scale using an atomic force microscope. We obtained the responses of two different cantilevers in solutions of glycerin and water using thermal and acoustic frequency sweep excitations. The thermal excitation method cannot be used for liquids with viscosity substantially higher than 1 mPa s because of the existence of a noise floor which obscures the cantilever response. The acoustic frequency sweep excitation can overcome this limitation. The fluid properties were extracted by combining a theoretical model with the experimentally obtained results for the frequency sweep excitation. By using the cantilever phase response, errors of less than 14% in viscosity and density were achieved. This error can be explained by a local increase in fluid temperature of 3 °C due to the laser energy.

Impact of Uncertainty of Heavy Oil Fluid Property Measurements

Abstract Heavy oil is particularly known for the difficulty it presents in obtaining accurate fluid property measurements. The uncertainty of heavy oil fluid property measurements affects the quality of fluid property data which in turn affecting the accuracy of production forecast. In our investigation, we included the impact from certain heavy oil fluid property uncertainties, including live oil viscosity and saturation pressure [or the initial gas-oil ratio (GOR)]. The reservoir simulations were performed for case studies with a 9°API reservoir fluid and geology similar to those typically found in the Faja region in Venezuela. Two base cases and the underlying process mechanisms were established, one assuming primary production process and one assuming steam-assisted gravity drainage process (SAGD). We then performed sensitivity studies of the different fluid property variations to determine the effect on the process performances. We found that the process mechanism dictated the magnitude of the sensitivity to different fluid properties. The uncertainties of the recovery prediction obtained from a reservoir simulator confirmed importance of selecting accurate fluid property data on the dynamic simulation prediction. Introduction In upfront reservoir engineering study, the reservoir and fluid properties are very important input data for the dynamic reservoir simulation as they dictate the accuracy of the simulation prediction. The uncertainties of the reservoir properties, such as the geologic and petrophysic data, are often given more attention than the uncertainties of the fluid properties, such as oil viscosity and initial GOR. It is well known that there are uncertainties in fluid property data, especially for heavy oil, because accurate measurements of heavy oil properties are quite difficult to obtain. For example, it has been observed that a large variation exists in the heavy oil viscosity measured from different laboratories using different measuring techniques. In addition to the inconsistency from the measurements, fluid sampling is another main source contributing to the accuracy of fluid property data. Therefore, it is essential to study the effect of the variation in fluid properties, such as oil viscosity and oil saturated pressure (or initial GOR), to predict the heavy oil recovery performance by means of dynamic reservoir simulation.

Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination

Summary A new generation of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels of filtrate contamination that are, in many cases, below measurable limits. Also, the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling methods. Formation-fluid sampling has always been adversely affected by mud-filtrate contamination, which introduces errors into the laboratory measurements of fluid properties and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance that provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves. The application of this new focused sampling technology is presented in four case studies from wells drilled on the Norwegian continental shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate and explores the different factors that affect performance of the focused sampling technique. An important consequence of achieving negligible contamination is the ability to accurately measure fluid properties in-situ. Reduced cleanup time allows for efficient reservoir fluid profiling, whereby multiple zones can be scanned sequentially in real time to quantify the fluid properties at a much higher resolution than traditional sampling methods. Downhole fluid analysis (DFA) can thus provide an additional source of information in the process of revealing complex reservoir architectures.

Rheological behavior probed by vibrating microcantilevers

The aim of this paper is to demonstrate that vibrating microcantilevers can be used to quantify fluid properties such as density and viscosity. Contrary to classical rheological measurements using microcantilevers, the development of the proposed microrheometer is based on the measurement of fluid properties over a range of vibration frequencies, without necessarily being restricted to resonant phenomena. To this end, an analytical model is implemented and, when combined with measurements, allows the determination of the viscosity as a function of frequency. The preliminary results are encouraging for the development of a useful microrheometer on a silicon chip for microfluidic applications.

MEMS sensors for density–viscosity sensing in a low-flow microfluidic environment

Technologies based on micro electro mechanical systems (MEMS) present advantages for downhole oilfield applications since they enable the fabrication of small sensors with fast response times. Furthermore, by incorporating MEMS sensors in a microfluidic environment it would be possible to make representative measurements of fluid properties with a sample volume of no more than 1 μL and flow rates on the order of 1 μL per minute. Here, we fabricate a set of resonating beams with millimetre-scale lengths and micron-scale cross-sections to demonstrate the feasibility of resonance measurements with three different techniques. In addition, we demonstrate how the quality factor and resonance frequency can be measured to calculate the fluid viscosity and density. The effect of flow rate on the sensor is shown to be minimal in microfluidic channels, presumably due to the small cross-sectional area of the beams. These sensors are compatible with the high pressure environments found downhole.

Measurement of Vacuum Residue and Asphaltene Fluid Properties at Process Conditions

The fluid properties of interfacial tension and viscosity, and the fluid-solid interactions embodied in the contact angle, are important in a wide range of phenomena that affect the processing of the vacuum residue fractions of petroleum and oilsand bitumens. Direct measurements of these fluid properties at representative processing conditions can give important insight into a variety of design and operating challenges, from gas holdup in hydroconversion to fouling of furnace tubes. This review summarizes the efforts to measure fluid properties of vacuum residue materials at high temperature and pressure. Significant progress has been made in measuring surface tension and viscosity of vacuum residues at temperatures to 530°C at low pressures. Further work is needed to develop methods for measurement of contact angle, and for measurements at high pressure.

On the dynamic tilt of a microplate under interfacial microwave load and surface tension

An analytical model has been developed to investigate the tilt dynamics of a microbeam-supported rigid microplate which is positioned across a microchannel partially filled with an isotropic liquid. Physical phenomena included in this work are those associated with surface tension, buoyancy, hydrodynamics, interfacial microwaves and torsional stiffness of the microbeam supports. Consideration of surface tension results in nonlinear terms for the righting moment and for the forcing function terms of the ordinary differential equation of rotational motion. Response characteristics are investigated for varying microwave amplitudes and frequencies, as well as microplate and microbeam principal dimensions. Results show that the analysis presented in this work can be used in designing microdevices for measurement of fluid properties, microwave features and pulsating pressures.

Heat Transfer in Turbulent Rayleigh–Bénard Convection Below the Ultimate Regime

A Rayleigh-B\'enard cell has been designed to explore the Prandtl (Pr) dependence of turbulent convection in the cross-over range $0.7<Pr<21$ and for the full range of soft and hard turbulences, up to Rayleigh number $Ra\simeq 10^{11}$. The set-up benefits from the favourable characteristics of cryogenic helium-4 in fluid mechanics, in-situ fluid property measurements, and special care on thermometry and calorimetric instrumentation. The cell is cylindrical with $diameter/height=0.5$. The effective heat transfer $Nu(Ra,Pr)$ has been measured with unprecedented accuracy for cryogenic turbulent convection experiments in this range of Rayleigh numbers. Spin-off of this study include improved fits of helium thermodynamics and viscosity properties. Three main results were found. First the $Nu(Ra)$ dependence exhibits a bimodality of the flow with $4-7 %$ difference in $Nu$ for given $Ra$ and $Pr$. Second, a systematic study of the side-wall influence reveals a measurable effect on the heat transfer. Third, the $Nu(Pr)$ dependence is very small or null : the absolute value of the average logarithmic slope $(dlnNu/dlnPr)_{Ra}$ is smaller than 0.03 in our range of $Pr$, which allows to disciminate between contradictory experiments [Ashkenazi \textit{et al.}, Phys. Rev.Lett. 83:3641 (1999)][Ahlers \textit{et al.}, Phys.Rev.Lett. 86:3320 (2001)].

Integrated Oil PVT Characterization - Lessons From Four Case Histories

Abstract Oil characterization plays an important role in integrated geophysical, geological and reservoir engineering studies. From project inception, correct fluid characterization can provide useful information about reservoir description and compartmentalization as well as properly defining fluid behaviour for engineering calculations. In this paper four field examples are presented to illustrate (1) how to use equation of state (EOS) oil characterization to check the accuracy of fluid sampling procedures and laboratory fluid property measurements, and (2) how to use EOS oil characterization to check for consistency between the geological/ geophysical reservoir description and actual field performance (e.g., produced gas-oil ratio). This results in a better reservoir model and makes further engineering and simulation tasks much easier. Introduction Integrated reservoir studies are usually initiated after the reservoir in question has been on production for many years. This provides sufficient data on field performance to ensure that some matching of calculations to actual history can be done. To conduct such studies, engineers generally have to use available data including existing PVT data. In most cases the existing PVT data, which may have been collected right after completion of the initial development wells before field production or after many years of production, can show considerable inconsistency. In addition, some key data may not have been measured or some of the data may not reflect actual reservoir performance, such as gas-oil ratio (GOR). It is, therefore, important from the outset of a project to check the consistency of available PVT data with the production test data and with the geological description before using it in a reservoir simulation study. EOS models are used by engineers to identify such inconsistencies in the PVT data and to calculate data which may not have been measured or is obviously incorrect. Before an EOS can be used, one must first correctly tune its parameters(1), that is, characterize the oil. Hence oil characterization plays an important role in the integrated reservoir study. Correct fluid characterization enables accurate EOS fluid property predictions which can provide useful information about reservoir description and compartmentalization, as well as properly defining fluid behaviour for engineering calculations. In this paper we use four actual field examples to illustrate the procedures used. EOS Oil Characterization Reservoir fluids are comprised of a very complex mixture of naturally occurring compounds. These compounds are principally hydrocarbons ranging from methane to asphalt. There are no fixed rules on the distribution of hydrocarbons in reservoirs. Fluids in reservoirs can exist as either single phase (gas or liquid), two phase (gas and liquid) or multi-phase (gas, liquid, liquid) fluids depending on the reservoir conditions and the components present. The ability to predict production rates, optimize production strategies and design production facilities depends on a knowledge of the properties of the reservoir fluid, not just at the original reservoir conditions, but also at a great many conditions on the subsequent depletion and production path. It is usually impractical, due to cost, time or lack of sufficient sample, to conduct laboratory analyses for such a wide range of conditions.