Search

In recent years, the Flory-Huggins-Zuo Equation of State (FHZ EoS) has been utilized to treat asphaltene gradient data in many oilfield reservoirs. The FHZ EoS employs asphaltene species from the Yen-Mullins model consisting of molecules, nanoaggregates and clusters of nanoaggregates; the specific species used depends primarily on the concentration of asphaltenes but also on the asphaltene stability. Reservoirs with equilibrated asphaltenes are repeatedly found to produce oil as a single flow unit addressing a key reservoir property. For crude oils with moderate concentrations of asphaltenes (a few%), asphaltenes are typically dispersed as nanoaggregates. In crude oils with high concentrations of asphaltenes (∼10%), asphaltenes are typically dispersed as clusters of nanoaggregates. This paper examines a reservoir with a crude oil of moderate concentration of asphaltenes where a secondary charge of methane created some limited instability of asphaltenes. Many pressure and fluid measurements are made to determine that indeed the fluid column is equilibrated. The FHZ EoS and the Yen-Mullins model in this equilibrated oil column are then compared with the asphaltene gradient; excellent agreement is obtained extending the use of this thermodynamic modeling to crude oils with limited asphaltene instability. Downhole fluid analysis (DFA) is used to delineate the asphaltene gradient, and both DFA and lab data are used for determination of solution gas content of oil samples. Conventional gas chromatography, two-dimensional gas chromatography (GC × GC) and gas isotope analysis are performed to analyze the oils, all with a focus to test and ensure thermodynamic equilibrium of the oil column. The mixed charge of an oil and a secondary gas is confirmed identifying the source of asphaltene instability. The result of the asphaltene instability is to create a fraction of crude oil at the base of the oil column with asphaltenes dispersed as clusters of asphaltenes, thus exhibiting a larger asphaltene gradient there. Fluid inclusion measurements are useful to indicate the sequence of events in gas and oil charging into the reservoirs in geologic time. The Flory-Huggins-Zuo EoS and the Yen-Mullins model continue to be confirmed in oilfield studies as well as in the laboratory, even in cases of limited asphaltene instability observed here.

Accurate quantification of oil-based drilling mud (OBM) filtrate contamination of hydrocarbon samples is still one of the biggest challenges in formation fluid sampling with formation testers. There exist contamination quantification techniques, but they can be technique sensitive, lack a confident level of quality control and apply only to a limited combination of probe types and formation fluid types. In particular, current techniques rely on an assumed absence of mud filtrate coloration at relevant optical channels and on sufficient optical density contrast between mud filtrate and virgin fluids. Such assumed fluid properties may not materialize when, for example, drilling muds are reused in multiple wells or when virgin fluids exhibit little color due to the absence of asphaltenes. In this paper, new mixing rules have been developed for mass density and shrinkage factor and for the newly defined “ f -function” and “ q -function”. The f -function, also referred to as the modified gas/oil ratio, is essentially a combination of gas/oil ratio with shrinkage factor. Similarly, the q -function is referred to as modified composition and is a combination of composition with mass density. OBM filtrate contamination in volume fraction, optical density, f -function, mass density, shrinkage factor, and q -function at a specified downhole sampling station have been found to be mutually linearly related as predicted by the mixing rules. The mutually linear relations are further confirmed by laboratory data for different mixtures of mud filtrate and formation fluids. Application of these mixing rules enables accurate OBM filtrate contamination in hydrocarbon samples if the filtrate properties and virgin fluid properties can be determined. A new methodology has been developed to determine the properties of the virgin formation fluid and mud filtrate, which are referred to as endpoints. The mud filtrate properties are obtained by extrapolating the mutually linear relations established from the cleanup data to zero gas/oil ratio or other known filtrate values such as zero methane composition, and/or zero optical density at specified wavelengths. The virgin fluid properties are determined by the power-law fitting of cleanup data coupled with the flow regime identification which is confirmed by large number of downhole fluid analysis datasets from wireline formation testers and numerical simulation. This novel methodology enables accurate quantification of the OBM filtrate and pure virgin formation fluid. Furthermore, the self-consistency of using multiple independent sensors provides confidence and greatly improves the robustness and quality control of OBM filtrate contamination monitoring downhole. Finally, contamination results can be expressed in volume or weight percent and as live fluid or stock-tank liquid fraction for easy comparison to laboratory results. A latest generation downhole fluid analysis (DFA) tool was employed to measure fluid properties downhole in real time on more than 30 DFA stations acquired with either conventional probes or 3D radial probes. The new methodology was applied to each of the acquired datasets. All the results from the new method are in good agreement with the results of the laboratory analysis.