Abstract: Upper and lower asphaltene weight fractions of fluid proximate ends of an oil column are obtained based on measured OD. Upper and lower maltene partial densities are obtained based on the asphaltene weight fractions. A maltene partial density distribution is obtained utilizing the maltene partial densities and a predetermined diffusion model. An asphaltene partial density distribution is obtained based on the maltene partial density distribution and an estimated mass density gradient. An asphaltene weight percentage is obtained based on the asphaltene partial density distribution and the mass density gradient. The asphaltene weight percentage distribution is converted to an OD distribution utilizing a predetermined correlation. An optimization then reduces differences between the OD distribution and the measured OD data to within a predetermined range to refine a biodegradation time of the predetermined diffusion model. A viscosity distribution may be obtained based on the optimized OD distribution.

Abstract: A method for performing contamination monitoring through estimation wherein measured data for optical density, gas to oil ratio, mass density and composition of fluid components are used to obtain plotting data and the plotting data is extrapolated to obtain contamination levels.

Abstract: A method includes identifying linearly behaving data within obtained data associated with fluid obtained from a subterranean formation. Shrinkage factor is determined based on the linearly behaving data. A function relating GOR data of the obtained fluid with the determined shrinkage factor is determined. A first linear relationship between optical density (OD) data of the obtained fluid and the function is determined. A second linear relationship between density data of the obtained fluid and the function is determined. An oil-based mud (OBM) filtrate contamination property of OBM filtrate within the obtained fluid based on the first linear relationship is determined. A native formation property of native formation fluid within the obtained fluid based on the second linear relationship is determined. A volume fraction of OBM filtrate contamination within the obtained fluid based on the OBM filtrate contamination property and the native formation property is estimated.

Abstract: A method for contamination monitoring includes measuring water based mud filtrate density and resistivity at downhole conditions, logging properties of a downhole fluid to find at least a resistivity and a density of a fluid sample at the downhole conditions, establishing a linear relationship between a water based mud filtrate conductivity at downhole conditions and the water based mud filtrate density at the downhole conditions, determining a density and a resistivity for native formation water, estimating a density for water based mud filtrate using the linear relationship between conductivity and density, and estimating a water based mud filtrate contamination.

Abstract: Methods and apparatus for operating a downhole tool within a wellbore adjacent a subterranean formation to pump contaminated fluid from the formation into the downhole tool while measuring first and second fluid properties of the contaminated fluid. The contaminated fluid comprises native fluid from the formation and a contaminant. The downhole tool is in communication with surface equipment located at surface. The downhole tool and/or surface equipment is operated to estimate a formation volume factor of the contaminated fluid based on at least one of the first and second fluid properties of the contaminated fluid. A linear relationship is then estimated between the first fluid property and a function that relates the first fluid property to the second fluid property and the estimated formation volume factor of the contaminated fluid. A fluid property of the contaminant is then estimated based on the estimated linear relationship.

Abstract: Disclosed are methods and apparatus obtaining in-situ, real-time data associated with a sample stream obtained by a downhole sampling apparatus disposed in a borehole that extends into a subterranean formation. The obtained data includes multiple fluid properties of the sample stream. The sample stream includes native formation fluid from the subterranean formation and filtrate contamination resulting from formation of the borehole in the subterranean formation. The obtained data is filtered to remove outliers. The filtered data is fit to each of a plurality of models each characterizing a corresponding one of the fluid properties as a function of a pumpout volume or time of the sample stream. Based on the fitted data, a start of a developed flow regime of the native formation fluid within the subterranean formation surrounding the borehole is identified.

Abstract: A method includes operating a downhole acquisition tool including a guard probe and a sample probe in a wellbore that contains a fluid that includes a native reservoir fluid and a contaminant. The method also includes receiving a first portion of fluid into the guard probe and a second portion of fluid into the sample probe, estimating a contamination level of the first or second portions based on a fluid property of the respective first and second portions, determining an initial guard flow rate of the first portion, determining an initial sample flow rate of the second portion, using a processor to adjust a guard flow rate of the second portion over pump time after the contamination level of the first portion is at or below a contamination level threshold, and adjust a sample flow rate of the first portion based on the adjusted guard flow rate and total flowrate.

Abstract: The present disclosure relates to a downhole fluid analysis method that includes withdrawing formation fluid into a downhole tool at a plurality of stations within a wellbore, analyzing the formation fluid within a fluid analyzer of a downhole tool to determine properties of the formation fluid for the plurality of stations, and developing, based on the determined properties of the formation fluid, a relationship for predicting viscosity from a measured optical density.

Abstract: First piston position data of a piston in a displacement unit is obtained based on an output signal from a sensor associated with the displacement unit, the output signal being dependent upon a physical position of the piston in the displacement unit. Second piston position data of the piston in the displacement unit is obtained based on data indicative of a number of revolutions of a hydraulic motor in a hydraulic system, the hydraulic system being operable to drive the piston of the displacement unit. Based on the second piston position data, a flow rate of a fluid pumped by the displacement unit is estimated. A system correction factor is generated based on the first piston position data and the second piston position data. The estimated flow rate is adjusted based on the system correction factor.

Abstract: A downhole tool, surface equipment, and/or remote equipment are utilized to obtain data associated with a subterranean hydrocarbon reservoir, fluid contained therein, and/or fluid obtained therefrom. At least one condition indicating that a density inversion exists in the fluid contained in the reservoir is identified from the data. Molecular sizes of fluid components contained within the reservoir are estimated from the data. A model of the density inversion is generated based on the data and molecular sizes. The density inversion model is utilized to estimate the density inversion amount and depth and time elapsed since the density inversion began to form within the reservoir. A model of a gravity-induced current of the density inversion is generated based on the data and the density inversion amount, depth, and elapsed time.

Abstract: Systems and methods for obtaining in-situ measurements of mixed formation fluids are provided. A downhole acquisition tool may move to a first station in a wellbore in a geological formation to collect a sample of first formation fluid from the first station. The downhole acquisition tool may move to a second station in the wellbore and a sample of second formation fluid may be collected. A proportion of the first formation fluid and the second formation fluid may be mixed within the downhole acquisition tool in-situ while the downhole acquisition tool is within the wellbore to obtain a formation fluid mixture. The formation fluid mixture may be passed into a fluid testing component of the downhole acquisition tool while the downhole acquisition tool is in the wellbore to measure fluid properties of the formation fluid mixture in-situ.

Abstract: The present disclosure relates to a method for characterizing a hydrocarbon reservoir of interest traversed by at least one wellbore that includes (a) using a numerical model to simulate over geological time a non-equilibrium concentration of an asphaltene component as a function of location within the wellbore, (b) analyzing fluid samples acquired from at least one wellbore that traverses the reservoir of interest to measure concentration of the asphaltene component as a function of location within the wellbore, (c) comparing the non-equilibrium concentration of the asphaltene component as a function of location within the wellbore resulting from the simulation of (a) to the concentration of the asphaltene component as a function of location within the wellbore as measured in (b), and characterizing the reservoir of interest based upon the comparing of (c).

Abstract: Various implementations described herein are directed to a method for assessing risks of compartmentalization. In one implementation, the method may include receiving seismic data for a formation of interest; identifying areas in the formation having a dip angle greater than about 30 degrees; performing a plurality of downhole fluid analysis (DFA) within a wellbore around the formation having the dip angle greater than about 30 degrees to identify areas experiencing mass density inversion; and determining the areas experiencing mass density inversion by DFA as having one or more risks of compartmentalization.

Abstract: A method includes placing a downhole acquisition tool in a wellbore in a geological formation within a hydrocarbon reservoir. The wellbore or the geological formation, or both, contain a reservoir fluid. The method also includes performing downhole fluid analysis using the downhole acquisition tool in the wellbore to determine at least one measurement associated with the reservoir fluid and using a processor to: estimate at least one fluid component property by using an equation of state based at least in part on at least one measurement associated with the reservoir fluid and simulate a diffusion process using a diffusive model that takes into account the at least one estimated fluid property. The diffusive model accounts for gravitational diffusion of at least one or more components in the reservoir fluid.

Abstract: The present disclosure relates to systems and methods for determining an integrity of a sample chamber. In certain embodiments, formation fluid is collected from a subterranean formation within a sample chamber disposed in a downhole tool, the downhole tool is withdrawn from a wellbore, an estimated surface pressure of the collected formation fluid is determined, the estimated surface pressure of the collected formation fluid is compared with an actual surface pressure of the sample chamber, and the integrity of the sample chamber is determined based on the comparison of the estimated surface pressure and the actual surface pressure.

Abstract: Methods are provided for reservoir analysis. In some embodiments, a reservoir may be analyzed by obtaining abundance ratios at a first measurement station and a second measurement station and determining an abundance ratio trend. Abundance ratios at a third measurement station may be obtained and plotted versus depth with the previously obtained abundance ratios. A change in the abundance ratio trend may be identified and result in further investigation of the reservoir. If the abundance ratio is unchanged, additional abundance ratios may be obtained and plotted versus depth to further evaluate the abundance ratio trend. Methods for reservoir analysis using fluid predictions with and without offset well information are also provided.

Abstract: A downhole tool is conveyed within a borehole extending into a subterranean formation. Fluid is drawn from the subterranean formation into the downhole tool, wherein the fluid comprises heavy oil. Fluorescence intensity of the drawn fluid is measured via a sensor of the downhole tool, and asphaltene content of the drawn fluid is estimated based on the measured fluorescence intensity.

Abstract: Apparatus and methods for obtaining initial settings of station-specific parameters descriptive of wellbore/formation properties specific to downhole pressure test stations, and obtaining initial settings of station-shared parameters descriptive of petrophysical properties of petrophysically unique formation zones. A pressure transient model of the zones is obtained by regression utilizing the pressure data of each station and the initial settings of the station-specific and station-shared parameters. The regression analytically determines a model value of at least one of the station-specific parameters and the station-shared parameters.

Abstract: The present disclosure relates to methods and apparatus for determining a viscosity-pressure profile of downhole fluid by measuring the viscosity at several different pressures during a sampling operation. According to certain embodiments, the viscosity may be measured at different times during a sampling operation and used to generate the viscosity-pressure profile. For example, the viscosity may be measured at the beginning of pumping, during filling of a sample chamber, during a pressure-build up period, and while retracting the probe. The measured viscosities may then be employed to determine a profile that represents the change in viscosity that occurs with pressure.

Abstract: A method includes placing a downhole acquisition tool in a wellbore in a geological formation containing a reservoir fluid. The method includes performing downhole fluid analysis using the downhole acquisition tool to determine at least one measurement of the reservoir fluid. The method includes using a processor to estimate at least one fluid component property by using an equation of state based at least in part on the at least one measurement of the reservoir fluid and to simulate a diffusion process using a diffusion model that takes into account the at least one estimated fluid property to generate a composition path. The method includes using a processor to estimate one or more phase envelopes based in part on the at least one fluid property and compare the one or more phase envelopes with the composition path. The method includes outputting a visualization identify potential areas of asphaltene instability.