Abstract:
A methodology that performs fluid sampling within a wellbore traversing a reservoir and fluid analysis on the fluid sample(s) to determine properties (including asphaltene concentration) of the fluid sample(s). At least one model is used to predict asphaltene concentration as a function of location in the reservoir. The predicted asphaltene concentrations are compared with corresponding concentrations measured by the fluid analysis to identify if the asphaltene of the fluid sample(s) corresponds to a particular asphaltene type (e.g., asphaltene clusters common in heavy oil). If so, a viscosity model is used to derive viscosity of the reservoir fluids as a function of location in the reservoir. The viscosity model allows for gradients in the viscosity of the reservoir fluids as a function of depth. The results of the viscosity model (and/or parts thereof) can be used in reservoir understanding workflows and in reservoir simulation.
Abstract:
Systems and methods for identifying a likelihood that a reservoir of a geological formation received a secondary charge of hydrocarbons of relatively very different thermal maturity of composition are provided. One method includes positioning a downhole acquisition tool in a wellbore in a geological formation and testing one or more fluid properties of the formation fluid. Data processing circuitry may identify whether a relationship of the one or more fluid properties exceeds a first threshold that indicates likely asphaltene instability. When this is the case, data processing circuitry may be used to model the geological formation using a realization scenario in which multiple charges of hydrocarbons of substantially different thermal maturity or substantially different composition, or both, filled a reservoir of the geological formation over geologic time.
Abstract:
Embodiments herein include a system and method for modeling and interpreting an evolution of fluids in an oilfield using artificial intelligence. Embodiments may include identifying, using at least one processor, one or more reservoir fluid dynamics processes or properties and generating a model for the one or more reservoir fluid dynamics processes or properties. Embodiments may include receiving, at the model, one or more parameter values corresponding to the one or more reservoir fluid dynamics processes or properties and displaying, at a graphical user interface, one or more results, based upon, at least in part, the model and the one or more parameter values.
Abstract:
Methods and systems are provided for conducting formation analysis. Data from borehole logging tools is used to conduct a petrophysical analysis of the formation in order to determine (quantify) total porosity and formation matrix permittivity for an interval of the formation. Noninvaded zone water saturation and flushed zone water saturation for the interval of the formation is determined using a saturation model of the interval. The noninvaded zone water saturation is compared to the flushed zone water saturation, and the results of the comparison are used to determine that the interval of the formation contains movable hydrocarbon, immobile hydrocarbon or movable formation water.
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:
Various implementations directed to analyzing a reservoir using fluid analysis are provided. In one implementation, a method may include determining mud gas logging (MGL) data based on drilling mud associated with a wellbore traversing a reservoir of interest. The method may also include determining first downhole fluid analysis (DFA) data based on a first reservoir fluid sample obtained at a first measurement station in the wellbore. The method may further include determining predicted DFA data for the wellbore based on the first DFA data. The method may additionally include determining second DFA data based on a second reservoir fluid sample obtained at a second measurement station in the wellbore. The method may further include analyzing the reservoir based on a comparison of the MGL data and a comparison of the second DFA data to the predicted DFA data.
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:
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:
A method is disclosed for assessing connectivity between sections in a hydrocarbon reservoir. Samples of hydrocarbons are collected over different depths in at least one wellbore. Fluorescence intensity determines the actual heavy end concentrations of hydrocarbons for the corresponding different depths. Estimated heavy end concentrations of hydrocarbons for corresponding different depths are determined and the actual heavy end concentrations of hydrocarbons are compared with the estimated heavy end concentrations to assess connectivity between sections of the hydrocarbon reservoir.
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.