Training systems for and methods of simulating locate operations are provided for training and/or skills evaluation. Facility locating equipment, such as on-site computers and/or locate receivers, may include modules for electronically simulating locate operations. Locating equipment including simulation modules may be used, for example, in locate technician training processes and/or for updating and/or evaluating the skills of locate technicians, hi particular, a simulation module is provided for electronically generating "virtual" facilities, the presence and/or absence of which may be indicated to a locate technician during, for example, a training exercise. The actions of the locate technicians with respect to dispensing marking material that corresponds to the presence and/or absence of the virtual facilities are electronically captured, stored, and evaluated.

Locating equipment for and methods of simulating locate operations for training and/or skills evaluation

There is provided a method for modeling a hydrocarbon reservoir that includes generating a reservoir model that has a plurality of coarse grid cells. A plurality of fine grid models is generated, wherein each fine grid model corresponds to one of the plurality of coarse grid cells that surround a flux interface. The method also includes simulating the plurality of fine grid models using a training simulation to obtain a set of training parameters, including a potential at each coarse grid cell surrounding the flux interface and a flux across the flux interface. A machine learning algorithm is used to generate a constitutive relationship that provides a solution to fluid flow through the flux interface. The method also includes simulating the hydrocarbon reservoir using the constitutive relationship and generating a data representation of a physical hydrocarbon reservoir in a non-transitory, computer-readable medium based on the results of the simulation.

Methods and systems for machine-learning based simulation of flow

An improved method and system for characterizing the compositional components of a hydrocarbon reservoir of interest and analyzing fluid properties of the reservoir of interest based upon its compositional components.

Methods and apparatus for characterization of petroleum fluid and applications thereof

A method of real-time processing and monitoring comprises the steps Of blending a material of interest (e.g., an active pharmceutical material), with a secondary material, (e.g., an excipient), illuminating the blended materials with light, reflecting light carrying information about the blended materials through at least one multivariate optical element (148) and detecting said light with a first detector (152), detecting a deflected portion of the information carrying light with a second detector (156), and determining in real-time at least one selected property of the blended materials based on the detector outputs.

Optical analysis system for dynamic real-time detection and measurement

A method of arranging and utilizing a multivariate optical computing and analysis system includes transmitting a first light from a light source; generating a second light by reflecting the first light from the sample; directing a portion of the second light with a beamsplitter; and arranging an optical filter mechanism in a normal incidence orientation to receive the portion of the second light, the optical filter mechanism being configured to optically filter data carried by the portion of the second light.

Optical analysis system and methods for operating multivariate optical elements in a normal incidence orientation

A technique is described for interpretation of IPTT tests. In one implementation, the technique may be configured or designed to standardize the complete interpretation procedure of IPTT in a heterogeneous reservoir, using if available, modern wireline logs (such as, for example, nuclear magnetic resonance and imaging), dynamic data from wireline formation testers and/or any other relevant information (such as, for example, geological description, core data and local knowledge) as constraints on the interpretation. Additionally, an iterative method may be used to define formation layering. An advanced regression technology may also be used to obtain optimized horizontal and vertical permeabilities of reservoir layers. Further a graphical user interface (GUI) based IPTT workflow technique of the present invention provides an integrated user-friendly interpretation platform for analyzing formation testing pressures and flow rate measurements in order to estimate the values and associated uncertainties of local characteristics of a hydrocarbon reservoir such as, for example, local permeability, local reservoir pressure, local compressibility, etc.

System and methods of characterizing a hydrocarbon reservoir

Formation fluid data based on measurements taken downhole under natural conditions is utilized to help identify reservoir compartments. A geological model of the reservoir including expected pressure and temperature conditions is integrated with a predicted fluid model fitted to measured composition and PVT data on reservoir fluid samples or representative analog. Synthetic downhole fluid analysis (DFA) logs created from the predictive fluid model can be displayed along the proposed borehole trajectory by geological modeling software prior to data acquisition. During a downhole fluid sampling operation, actual measurements can be displayed next to the predicted logs. If agreement exists between the predicted and measured fluid samples, the geologic and fluid models are validated. However, if there is a discrepancy between the predicted and measured fluid samples, the geological model and the fluid model need to be re-analyzed, e.g., to identify reservoir fluid compartments. A quantitative comparative analysis of the sampled fluids can be performed against other samples in the same borehole or in different boreholes in the field or region to calculate the statistical similarity of the fluids, and thus the possible connectivity between two or more reservoir regions.

Facilitating oilfield development with downhole fluid analysis

This relates to methods and apparatus for analyzing samples by fluorescence spectroscopy. In one embodiment, the methods and apparatus use a fluorescence detection unit (FDU) of a composition fluid analyzer (CFA™) module to detect variations in fluid properties (gradients) within an oil bearing column. Some embodiments enable efficient downhole fluid analysis in heavy oils where water/oil emulsions are present (water in dispersed phase and oil in the continuous phase). The principles described herein may also be applied when there are fine particles in the oil such as from unconsolidated sands.

Methods and apparatus for analyzing fluid properties of emulsions using fluorescence spectroscopy

A method for determining properties of a formation fluid is provided and includes: obtaining fluid data related to Carbon-Hydrogen molecular bonds in C6+ from a fluid analyzer; and considering the fluid data to calculate mass fractions of hydrocarbon flowing through the fluid analyzer. The method further includes computing gas-oil-ratio of hydrocarbon based on the mass fractions of hydrocarbon. Another method for determining a gas-oil-ratio of a formation fluid includes: obtaining fluid data related to Carbon-Hydrogen molecular bonds in C6+ from a fluid analyzer; considering the fluid data to derive mass fractions of gas and oil; and computing gas-oil-ratio of hydrocarbon based on the derived mass fractions.

Methods and apparatus for oil composition determination

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. The computational analysis that evaluates asphaltene rich phase stability can also be used in other reservoir understanding workflows and in reservoir simulation.

Chenggang Xian

Papers

System and methods of characterizing a hydrocarbon reservoir

Facilitating oilfield development with downhole fluid analysis

Methods and apparatus for analyzing fluid properties of emulsions using fluorescence spectroscopy

Methods and apparatus for oil composition determination

Methods and apparatus for characterization of hydrocarbon reservoirs