Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data

2009 ◽  
Vol 12 (05) ◽  
pp. 793-802 ◽  
Author(s):  
P. David Ting ◽  
Birol Dindoruk ◽  
John Ratulowski
Keyword(s):  
Experimental Data ◽  
Phase Behavior ◽  
Rock Properties ◽  
Model Parameters ◽  
Fluid Composition ◽  
Bulk Fluid ◽  
Reservoir Fluid ◽  
Fluid Systems ◽  
Fluid Properties ◽  
The Impact

Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27°API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.

Predicting Reservoir Fluid Phase and Volumetric Behavior From Samples Contaminated With Oil-Based Mud

2002 ◽  
Vol 5 (03) ◽  
pp. 197-205 ◽  
Author(s):  
F. Gozalpour ◽  
A. Danesh ◽  
D.-H. Tehrani ◽  
A.C. Todd ◽  
B. Tohidi
Keyword(s):  
Phase Equilibrium ◽  
Phase Behavior ◽  
Volatile Oil ◽  
Fluid Composition ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Different Types ◽  
The Impact ◽  
Mud Filtrate ◽  
Equilibrium Calculations

Summary The impact of sample contamination with oil-based mud filtrate on phase behavior and properties of different types of reservoir fluids, including gas condensate and volatile oil, has been investigated. Two simple methods are used to determine the uncontaminated fluid composition from contaminated samples. The capability of the methods is demonstrated against highly contaminated samples. An equation-of-state (EOS)-based method also has been developed to predict the phase and volumetric properties of the retrieved composition. The method determines the required parameters of the EOS for the uncontaminated fluid using the developed phase-behavior models from contaminated-sample data. The method has been examined against experimental data of different types of reservoir fluids with successful results. Introduction Accurate reservoir fluid composition and properties are essential for reservoir management and development. Reliable reservoir fluid samples are therefore required; however, major challenges can render the fluid analysis limited in value. The reservoir fluid samples for pressure/volume/temperature (PVT) tests can be collected by bottomhole and/or surface sampling techniques as appropriate. During the drilling process, owing to overbalance pressure in the mud column, mud filtrate invades the formation. If an oil-based mud is used in the drilling, it can cause major difficulties in collecting high-quality formation fluid samples. Because the filtrate of oil-based drilling mud is miscible with the formation fluid, it could significantly alter the composition and phase behavior of the reservoir fluid. Even the presence of a small amount of oil-based filtrate in the collected sample could significantly affect the PVT properties of the formation fluid. Oil-based mud is used widely in the petroleum industry. Contamination with oil-based mud filtrate could affect reservoir fluid properties such as saturation pressure, formation volume factor, gas/liquid ratio, and stock-tank liquid density. Because collecting a reservoir fluid sample is expensive, and accurate reservoir fluid properties are needed in reservoir development, it is highly desirable to determine accurate composition and phase behavior for the reservoir fluid from contaminated samples. This study investigates the impact of sample contamination with oil-based mud filtrates on composition and phase behavior properties of different types of reservoir fluids, including volatile oil and gas condensate samples. The samples were purposely contaminated with a known amount of oil-based mud filtrates in the laboratory. The methods developed in this study were then applied to determine the original composition of the reservoir fluid from contaminated samples. The phase behavior of the contaminated samples was also investigated by performing constant composition expansion (CCE) tests at reservoir and surface conditions. The measured experimental data were used to tune EOSs by adjusting their parameters. The determined parameters of EOS tuned to the contaminated samples were used to calculate the parameters of EOS for the uncontaminated sample. EOS EOSs are used extensively to simulate the volumetric behavior and phase equilibrium of petroleum reservoir fluids. Among different types of EOSs, cubic EOSs have enjoyed considerable success in modeling because they are simple and give reliable results in phase equilibrium calculations. Two EOSs, the Valderrama1 modification of the Patel-Teja (VPT) EOS and a modified Peng-Robinson2 (mPR) EOS, were used in this study to perform phase equilibrium calculations. All binary interaction parameters (BIP) in the mixing rule were set to zero, and the temperature dependency of the attractive term was used as the tuning parameter to fit the measured data.3 Extended compositional analyses (up to C20+) of fluids were used in phase equilibrium calculations. The required critical properties of petroleum fractions to calculate parameters of EOS were determined by perturbation expansion correlations.4 The required boiling-point temperatures were calculated from the Riazi- Daubert5 correlation using the molecular weight and specific gravity of petroleum fractions. The Lee-Kesler6 correlation was used to calculate the accentric factor of compounds. Contaminated Reservoir Fluids Hydrocarbon-based fluids (natural or synthetic oils) are generally used in oil-based drilling muds. Because these fluids are soluble in the reservoir fluid, they can render the fluid analysis limited in value. Determination of the original fluid composition from the analysis of a contaminated sample is feasible, but isolating the properties of the reservoir fluid free from contamination is not easily accomplished. Despite the recent improvements in sampling reservoir fluids,7,8 obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Therefore, modeling techniques are required, along with the laboratory studies, to determine the composition and PVT properties of the uncontaminated fluid. We have demonstrated, as have other investigators,9,10 that an exponential relationship exists between the concentration of components in the C8+ portion of real reservoir fluids and the corresponding molecular weights. For example, if the molar concentration of single carbon number groups is plotted against their molecular weights, it will give a straight line on a semilogarithmic scale. Based on this feature of natural fluids, two methods have been developed in this study to retrieve the original composition of reservoir fluid from contaminated samples. The composition of the C8+ portion of contaminated sample is plotted against molecular weight on a semilogarithmic scale. The plotted data will show a departure from the line over the range affected by the contaminants (see Fig. 1). The concentrations of the contaminants are then skimmed from the semilog straight line, presumed to be valid for the uncontaminated reservoir fluid. The fitted line is used to determine the composition of the uncontaminated fluid. The above method, referred to as the Skimming method, gives a reliable composition of the uncontaminated fluid if the contaminant comprises a limited hydrocarbon range. MacMillan et al.11 developed a similar method. They fitted a gamma distribution function to the composition of the C7+ portion of contaminated oil samples, excluding the composition of contaminants from the datafitting procedure.

Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems and Their Interplay

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 2867-2880
Author(s):  
Ram R. Ratnakar ◽  
Edward J. Lewis ◽  
Birol Dindoruk
Keyword(s):  
Measurement Techniques ◽  
Saturation Pressure ◽  
Ultrasonic Pulse ◽  
Acoustic Velocity ◽  
Viscosity Data ◽  
Reservoir Fluid ◽  
Fluid Systems ◽  
Fluid Properties ◽  
Volume Measurements ◽  
Live Oil

Summary Acoustic velocity is one of the key thermodynamic properties that can supplement phase behavior or pressure/volume/temperature (PVT) measurements of pure substances and mixtures. Several important fluid properties are relatively difficult to obtain through traditional measurement techniques, correlations, or equation of state (EOS) models. Acoustic measurements offer a simpler method to obtain some of these properties. In this work, we used an experimental method based on ultrasonic pulse-echo measurements in a high-pressure/high-temperature (HP/HT) cell to estimate acoustic velocity in fluid mixtures. We used this technique to estimate related key PVT parameters (such as compressibility), thereby bridging gaps in essential data. In particular, the effect of dilution with methane (CH4) and carbon dioxide (CO2) at pressures from 15 to 62 MPa and temperatures from 313 to 344 K is studied for two reservoir fluid systems to capture the effect of the gas/oil ratio (GOR) and density variations on measured viscosity and acoustic velocity. Correlative analysis of the acoustic velocity and viscosity data were then performed to develop an empirical correlation that is a function of GOR. Such a correlation can be useful for improving the interpretation of the sonic velocity response and the calibration of viscosity changes when areal fluid properties vary with GOR, especially in disequilibrium systems. In addition, under isothermal conditions, the acoustic velocity of a live oil decreases monotonically with decreasing pressure until the saturation point where the trend is reversed. This observation can also be used as a technique to estimate the saturation pressure of a live oil or as a byproduct of the target experiments. It supplements the classical pressure/volume measurements to determine the bubblepoint pressure.

High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen

2014 ◽  
Vol 17 (03) ◽  
pp. 384-395 ◽  
Author(s):  
Odd Steve Hustad ◽  
Na Jia ◽  
Karen Schou Pedersen ◽  
Afzal Memon ◽  
Sukit Leekumjorn
Keyword(s):  
High Pressure ◽  
Gulf Of Mexico ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Positive Impact ◽  
Viscosity Reduction ◽  
Fluid Composition ◽  
Viscosity Data ◽  
Oil Viscosity ◽  
Reservoir Fluid

Summary This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include: Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations. The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen. Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.

Effect of GOR on Gas Diffusivity in Reservoir-Fluid Systems

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 185-196 ◽  
Author(s):  
Ram R. Ratnakar ◽  
Birol Dindoruk
Keyword(s):  
Experimental Data ◽  
Gas Diffusion ◽  
Solubility Parameters ◽  
Einstein Relation ◽  
Liquid Density ◽  
Oil Viscosity ◽  
Data Set ◽  
Gas Diffusivity ◽  
Reservoir Fluid ◽  
Fluid Systems

Summary Molecular diffusion plays a dominant role in various reservoir processes, especially in the absence of convective mixing. In general, gas diffusion in oils depends on several factors such as pressure, temperature, oil viscosity, and gas/oil ratio (GOR). Out of these factors, the effects of GOR and live-oil-compositional changes on diffusivity are rare or not available in the literature. The current work fills this gap and presents the experimental observations on the effect of GOR on gas diffusivity in reservoir-fluid systems. Synthetic live oils were created by combining stock-tank oil (STO) and methane in various ratios. Constant-composition-expansion (CCE) experiments were performed with these oils to obtain their bubblepoints and liquid densities in relation to GOR. Methane diffusivity in these oils was obtained from pressure-decay (PD) tests at high-pressure/high-temperature (HP/HT) conditions. The diffusion and solubility parameters were estimated from PD data using the diffusion model and integral-based linear regression presented in previous work (Ratnakar and Dindoruk 2015, 2018). The experimental and modeling methodologies are presented here in sufficient detail to allow readers to replicate and evaluate the results. In this work, we experimentally investigated the effect of GOR on methane diffusivity in oils at HP/HT conditions using PD tests. In particular, We present experimental data for bubblepoints and liquid density of synthetic oils with various GOR values. For the range of GORs considered, these measurements show that the bubblepoint pressure increases linearly with GOR. Late-transient solution (LTS) of the PD model was used to obtain diffusivity parameters by regressing against experimental data. It is found that as the GOR value increases (that is, when oil becomes lighter), the diffusivity value increases, which is in accordance with the Stokes-Einstein relation. Most importantly, an empirical correlation is developed on the basis of a limited data set to describe the variation in diffusivity values with GOR. This can be important when experimental data are available for the STO but not for the live oils. It can also be extremely useful in gas-injection processes where the amount of gas dissolved in the oil varies, leading to variations in diffusivity.

Modeling and Simulation of LiFePO4 Battery for Electric Vehicle

2013 ◽  
Vol 860-863 ◽  
pp. 1134-1141
Author(s):  
Chang Qing Du ◽  
Fan Li ◽  
Xian Jun Hou ◽  
Yi Fan Zhao
Keyword(s):  
Experimental Data ◽  
Data Analysis ◽  
Equivalent Circuit Model ◽  
Model Parameters ◽  
Traditional Model ◽  
Performance Tests ◽  
Discharge Performance ◽  
The Impact ◽  
Different Order ◽  
Charge Discharge

For accurately studying the performance of LiFePO4 battery group, this paper conducted CC and HPPC cycle charge/discharge performance tests of LiFePO4 battery, and designed an improved equivalent circuit model based on the data analysis. Compared to the traditional model, the model considered the impact of the hysteresis voltage, had more accurate corresponding relationship between SOC and balance voltage, obtained a more realistic overpotential property by contrasting different order models. Estimated model parameters, modeling in Matlab / Simulink environment and simulation in the UDDS condition, verified the accuracy and feasibility of the designed model by comparing with experimental data.

Theoretical and experimental analysis for the impact response of glass fibre reinforced aluminium honeycomb sandwiches

2016 ◽  
Vol 20 (1) ◽  
pp. 42-69 ◽  
Author(s):  
Vincenzo Crupi ◽  
Emre Kara ◽  
Gabriella Epasto ◽  
Eugenio Guglielmino ◽  
Halil Aykul
Keyword(s):  
Experimental Data ◽  
Sandwich Structures ◽  
Low Velocity Impact ◽  
Balance Model ◽  
Model Parameters ◽  
Low Velocity ◽  
Internal Damage ◽  
Limit Loads ◽  
Load Carrying ◽  
The Impact

Honeycomb sandwich structures are increasingly used in the automotive, aerospace and shipbuilding industries where fuel savings, increase in load carrying capacity, vehicle safety and decrease in gas emissions are very important aspects. The aim of this study was to develop the theoretical methods, initially proposed by the authors and by other researchers for the prediction of low-velocity impact responses of sandwich structures. The developed methods were applied to sandwich structures with aluminium honeycomb cores and glass-epoxy facings for the assessment of impact parameters and for the prediction of limit loads. The values of model parameters were compared with data reported in literature and the predictions of the limit loads were validated by means of the experimental data. Good achievement was obtained between the results of the theoretical models and the experimental data. The failure mode and the internal damage of the sandwich panels have been investigated using 3D computed tomography, which allowed the evaluation of parameters of energy balance model, and infrared thermography, which allowed the detection of the temperature evolution of the specimens during the tests. The experimental and theoretical results demonstrated that the use of glass-epoxy reinforcement on aluminium honeycomb sandwiches enhances the energy absorption and load carrying capacities.

REAL-TIME AND ON-SITE RESERVOIR FLUID CHARACTERISATION USING SPECTRAL ANALYSIS AND PVT EXPRESS

2004 ◽  
Vol 44 (1) ◽  
pp. 605
Author(s):  
A.K.M. Jamaluddin ◽  
C. Dong ◽  
P. Hermans ◽  
I.A. Khan ◽  
A. Carnegie ◽  
...  
Keyword(s):  
Real Time ◽  
Carbon Number ◽  
Saturation Pressure ◽  
Fluid Composition ◽  
Reservoir Fluid ◽  
Basic Fluid ◽  
Development Cycle ◽  
Surface Analysis Techniques ◽  
Fluid Properties ◽  
Open Hole

Obtaining an adequate fluid characterisation early in the life of a reservoir is becoming a key requirement for successful hydrocarbon development. This work presents and discusses a number of new fluid sampling and fluid characterisation technologies that can be deployed either down hole or at surface in the early stages of the exploration and development cycle to achieve this objective. Techniques discussed include methods to monitor and quantify oil-based mud contamination, gas-liquid-ratio (GLR) and basic fluid composition in real time during open-hole formation testing operations. In addition, we demonstrate the applicability of new surface analysis techniques that allow for rapid, accurate, and reliable measurements of key fluid properties, such as saturation pressure, gas-oil ratio, extended carbon number composition, viscosity, and density, on-site within a few hours of retrieving reservoir fluid samples at surface. Finally, prediction tools used to extend these limited measurements to a traditional PVT fluid characterisation are presented along with example measurements from all the techniques described. In conclusion, it is shown that the implementation of these techniques in a complementary program can reduce the risk associated with making key development decisions that are based on an understanding of reservoir fluid properties.

Accuracy and Precision of Reservoir Fluid Characterization Tests Through Blind Round-Robin Testing

2021 ◽  
Author(s):  
Arwa Mawlod ◽  
Afzal Memon ◽  
John Nighswander
Keyword(s):  
Molar Mass ◽  
Sensitivity Study ◽  
Round Robin ◽  
Fluid Composition ◽  
Mass Measurements ◽  
Reservoir Fluid ◽  
Stock Tank ◽  
Fluid Characterization ◽  
Plus Fraction ◽  
The Impact

Abstract Objectives/Scope: Oil and gas operators use a variety of reservoir engineering workflows in addition to the reservoir, production, and surface facility simulation tools to quantify reserves and complete field development planning activities. Reservoir fluid property data and models are fundamental input to all these workflows. Thus, it is important to understand the propagation of uncertainty in these various workflows arising from laboratory fluid property measured data and corresponding model uncertainty. The first step in understanding the impact of laboratory data uncertainty was to measure it, and as result, ADNOC Onshore undertook a detailed study to assess the performance of four selected reservoir fluid laboratories. The selected laboratories were evaluated using a blind round-robin study on stock tank liquid density and molar mass measurements, reservoir fluid flashed gas and flashed liquid C30+ reservoir composition gas chromatography measurements, and Constant Mass Expansion (CME) Pressure-Volume-Temperature (PVT) measurements using a variety of selected reservoir and pure components test fluids. Upon completion of the analytical study and establishing a range of measurement uncertainty, a sensitivity analysis study was completed using an equation of state (EoS) model to study the impact of reservoir fluid composition and molecular weight measurement uncertainty on EoS model predictions. Methods, Procedures, Process: A blind round test was designed and administered to assess the performance of the four laboratories. Strict confidentiality was maintained to conceal the identity of samples through blind test protocols. The round-robin tests were also witnessed by the researchers. The EoS sensitivity study was completed using the Peng Robinson EoS and a commercially available software package. Results, Observations, Conclusions: The results of the fully blind reservoir fluid laboratory tests along with the statistical analysis of uncertainties will be presented in this paper. One of the laboratories had a systemic deviation in the measured plus fraction composition on black oil reference standard samples. The plus fraction concentration is typically the largest weight percent component in black oil systems and, along with the plus fraction molar mass, plays a crucial role in establishing the mole percent overall reservoir fluid compositions. Another laboratory had systemic issues related to chromatogram component integration errors that resulted in inconsistent carbon number concentration trends for various components. All laboratories failed to produce consistent molecular weight measurements for the reference samples. Finally, one laboratory had a relative deviation for P-V measurements that were significantly outside the acceptable range. The EoS sensitivity study demonstrates that the fluid composition and stock tank oil molar mass measurements have a significant impact on EoS model predictions and hence the reservoir/production models input when all other parameters are fixed. Novel/Additive Information: To the best of our knowledge, this is the first time such an extensive and fully blind round-robin test of commercial reservoir fluid characterization laboratories has been completed and published in the open literature. The industry should greatly benefit from this first-of-its-kind blind round-robin dataset being made available to all. The study provides the basis, protocols, expectations, and recommendations for such independent round-robin testing for fluid characterization laboratories on a broader scale.

New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization

2008 ◽  
Vol 11 (06) ◽  
pp. 1107-1116 ◽  
Author(s):  
Chengli Dong ◽  
Michael D. O'Keefe ◽  
Hani Elshahawi ◽  
Mohamed Hashem ◽  
Stephen M. Williams ◽  
...  
Keyword(s):  
Real Time ◽  
Hydrocarbon Composition ◽  
Fluid Composition ◽  
Fluid Sample ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Reservoir Conditions ◽  
Fluid Properties ◽  
Fluid Characterization ◽  
Compositional Grading

Summary Downhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). For single-phase assurance, it is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore, before filling a sample bottle. In this paper, a new DFA tool is introduced that substantially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1, ethane (C2), propane to pentane (C3-5), C6+, and CO2. These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single-well to a multiwall basis. Field-based fluid characterization is now possible. In addition, a new measurement is introduced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers and measurements of fluid resistivity, pressure, temperature, and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to simulate reservoir conditions. In addition, several field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and management. Reservoir-fluid properties, such as hydrocarbon composition, GOR, CO2 content, pH, density, viscosity, and PVT behavior are key inputs for surface-facility design and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory, and it usually takes a long time (months) before the results become available. Also, miscible contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However, the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O'Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in real time, and fluid composition is derived from the spectra on the basis of C1, C2-5, C6+, and CO2; then, GOR of the fluid is estimated from the derived composition (Betancourt et al. 2004; Fujisawa et al. 2002; Dong et al. 2006; Elshahawi et al. 2004; Fujisawa et al. 2008; Mullins et al. 2001; Smits et al. 1995). Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-based mud (OBM) or water-based mud (WBM), fluid-sample contamination from the drilling fluid is estimated (Mullins et al. 2000; Fadnes et al. 2001). With the DFA technique, reservoir-fluid samples are analyzed before they are taken, and the quality of fluid samples is improved substantially. The sampling process is optimized in terms of where and when to sample and how many samples to take. Reservoir-fluid characterization from fluid-profiling methods often reveals fluid compositional grading in different zones, and it also helps to identify reservoir compartmentalization (Venkataramanan et al. 2008). A next-generation tool has been developed to improve the DFA technique. This DFA tool includes new hardware that provides more-accurate and -detailed spectra, compared to the current DFA tools, and includes new methods of deriving fluid composition and GOR from optical spectroscopy. Furthermore, the new DFA tool includes a vibrating sensor for direct measurement of fluid density and, in certain environments, viscosity. The new DFA tool provides reservoir-fluid characterization that is significantly more accurate and comprehensive compared to the current DFA technology.

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