Method of determining saturates, aromatics, resins, and asphaltene (SARA) fractions of reservoir fluid during downhole fluid analysis

A method for estimating saturates, aromatics, resins, and asphaltenes (“SARA”) fractions of reservoir fluid, comprising:

• receiving, at a processing system, a first dataset of measurements based on a plurality of data samples of reservoir fluid retrieved from a plurality of wellbores, wherein each data sample of the plurality of data samples is associated with a wellbore of the plurality of wellbores, wherein each data sample is collected by a respective downhole fluid analyzer (DFA) tool disposed within a respective wellbore, and wherein the first dataset of measurements comprises an indication of pressure (“P”) exerted by the reservoir fluid in a respective wellbore on flowbore housing of a respective DFA tool, a temperature (“Tres”) of the reservoir fluid within the flowbore housing in the respective DFA tool, an indication of methane (“C1”) in the reservoir fluid, an indication of ethane (“C2”) in the reservoir fluid, an indication of propane (“C3”) in the reservoir fluid, an indication of butane (“C4”) in the reservoir fluid, an indication of pentane (“C5”) in the reservoir fluid, an indication of one or more hexanes (“C6+”) in the reservoir fluid, an indication of nitrogen (“N2”) in the reservoir fluid, and an indication of carbon dioxide (“CO2”) in the reservoir fluid;
• training, by the processing system, a regression model to predict SARA fractions using a first subset of the first dataset of measurements;
• tuning, by the processing system, the trained regression model using a second subset of the first dataset of measurements, wherein the processing system is configured to tune the regression model until a prediction performance of the regression model is greater than or equal to a prediction accuracy threshold;
• instructing, by the processing system, a pump disposed within an additional wellbore to pump additional reservoir fluid from the additional wellbore into an additional DFA tool disposed within the additional wellbore;
• receiving, by the processing system, a second dataset of measurements from the additional DFA tool based on the additional reservoir fluid within the additional wellbore;
• providing, by the processing system, the second dataset of measurements as input to the trained regression model;
• and
• generating, by the processing system, an estimate of SARA fraction levels for the additional reservoir fluid within the additional wellbore based on the second dataset and the trained regression model.

A system for estimating saturates, aromatics, resins, and asphaltenes (“SARA”) fractions in reservoir fluid, comprising:

• a downhole fluid analyzer (DFA) tool configured to receive a sample of reservoir fluid from a wellbore and collect a plurality of data samples associated with the reservoir fluid, the DFA tool, comprising:
• a flowbore housing;
• an isolation valve coupled to the flowbore housing;
• a filter array spectrometer coupled to the flowbore housing;
• a fluorescence detector coupled to the flowbore housing;
• a grating spectrometer coupled to the flowbore housing;
• a pressure and temperature gauge coupled to the flowbore housing;
• a resistivity sensor coupled to the flowbore housing;
• and
• a viscosity sensor coupled to the flowbore housing;
• a pump disposed within the wellbore and coupled to the isolation valve of the DFA tool via tubing, wherein the pump is configured to pump the reservoir fluid from the wellbore into the DFA tool;
• and
• a computing system configured to perform operations comprising:
• causing the pump to pump the reservoir fluid to the isolation valve of the DFA tool;
• causing the DFA tool to collect the plurality of the data samples;
• receiving the plurality of data samples from the DFA tool;
• generating a dataset of reservoir characteristics based on the plurality of data samples, wherein the dataset of reservoir characteristics comprises an indication of pressure (“P”) exerted by the reservoir fluid on the flowbore housing, a temperature (“Tres”) of the reservoir fluid within the flowbore housing, an indication of methane (“C1”) in the reservoir fluid, an indication of ethane (“C2”) in the reservoir fluid, an indication of propane (“C3”) in the reservoir fluid, an indication of butane (“C4”) in the reservoir fluid, an indication of pentane (“C5”) in the reservoir fluid, an indication of one or more hexanes (“C6+”) in the reservoir fluid, an indication of nitrogen (“N2”) in the reservoir fluid, and an indication of carbon dioxide (“CO2”) in the reservoir fluid;
• and
• determining, using a trained regression model, a predicted asphaltene stability in the reservoir fluid by generating a prediction of the SARA fractions in the reservoir fluid based on the dataset of reservoir characteristics.