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: Accurate, real-time formation fluids analysis can be accomplished using the systems and techniques described herein. A fluid analyzer includes a first mode of analysis, such as an optical analyzer, configured to determine a physical (optical) property of a fluid sample. The fluid analyzer also includes another mode of analysis, such as a composition analyzer, such as a gas chromatograph, configured to determine a component composition of the fluid sample. A data processor is configured to determine a quantity, such as a weight percentage, of a target component of the fluid sample in response results obtained from the first and second modes of analysis. Beneficially, the results are obtained at least in near real-time, allowing for interim results, such as results from the first analyzer to be used for one or more of tuning the compositional analyzer and for implementing quality control.

Abstract: A methodology performs downhole fluid analysis at multiple measurement stations within a wellbore traversing a reservoir to determine gradients of compositional components and other fluid properties. A model is used to predict concentrations of a plurality of high molecular weight solute part class-types at varying reservoir locations. Such predictions are compared against downhole measurements to identify the best matching solute part class-type. If the best-matching class type corresponds to at least one predetermined asphaltene component, phase stability of asphaltene in the reservoir fluid at a given depth is evaluated using equilibrium criteria involving an oil rich phase and an asphaltene rich phase of respective components of the reservoir fluid at the given depth. The result of the evaluation of asphaltene rich phase stability is used for reservoir analysis.

Abstract: A methodology for reservoir understanding that performs investigation of asphaltene instability as a function of location in a reservoir of interest. In the preferred embodiment, results derived as part of the investigation of asphaltene instability are used as a workflow decision point for selectively performing additional analysis of reservoir fluids. The additional analysis of reservoir fluids can verify the presence of asphaltene flocculation onset conditions and/or determine the presence and location of phase-separated bitumen in the reservoir of interest.

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: A methodology for reservoir understanding that performs investigation of asphaltene instability as a function of location in a reservoir of interest. In the preferred embodiment, results derived as part of the investigation of asphaltene instability are used as a workflow decision point for selectively performing additional analysis of reservoir fluids. The additional analysis of reservoir fluids can verify the presence of asphaltene flocculation onset conditions and/or determine the presence and location of phase-separated bitumen in the reservoir of interest.

Abstract: Accurate, real-time formation fluids analysis can be accomplished using the systems and techniques described herein. A fluid analyzer includes a first mode of analysis, such as an optical analyzer, configured to determine a physical (optical) property of a fluid sample. The fluid analyzer also includes another mode of analysis, such as a composition analyzer, such as a gas chromatographer, configured to determine an elemental composition of the fluid sample. A data processor is configured to determine a quantity, such as a weight percentage, of a target component of the fluid sample in response results obtained from the first and second modes of analysis. Beneficially, the results are obtained at least in near real-time, allowing for interim results, such as results from the first analyzer to be used for one or more of tuning the compositional analyzer and for implementing quality control.