Schlumberger Technology Corporation

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

Francois Xavier Dubost

Oliver Clinton Mullins

Cosan Ayan

Soraya Sofia Betancourt

Christopher Del Campo

Peter S Hegeman

Bhavani Raghuraman

Ricardo Vasques

Ronald E G Van Hal

Anthony Goodwin

Julian J Pop

Youxiang Zuo

Pierre-Yves Corre

Adriaan Gisolf

Kentaro Indo

Andrew Emil Pomerantz

Wael Abdallah

Chengli Dong

Shahnawaz Hossain Molla

Hadrien Dumont

Abdel Kharrat

Michael O'Keefe

Sylvain Wlodarczyk

Florent D'Halluin

Bertrand Claude Theuveny

Vladislav Achourov

Adriaan Gerard Gisolf

Olivier Marché

Dingan Zhang

Youxiang (Julian) Zuo

Jinglin Gao

Yannick Guyomar

Gabriela Morales German

Rafael Navarro Rosales

Soraya S Betancourt

Systems and methods presented herein generally relate to a formation testing tool configured to determine whether a formation fluid being tested is a bubble point fluid or a dew point fluid. For example, in certain embodiments, a method includes depressurizing a flowline of a formation testing tool. The flowline contains a formation fluid having a gas-to-oil ratio (GOR) within a predetermined GOR range. The method also includes determining, using a fluid analysis module of the formation testing tool, whether the formation fluid is a bubble point fluid or a dew point fluid by analyzing distribution of bubbles in the formation fluid that are caused by the depressurization of the flowline.

Systems and methods for differentiating bubble points from dew points

A method can include flowing fluid from a formation from an inlet of a tool to an annulus; flowing spacer fluid from a conduit to the annulus; flowing the fluid and the spacer fluid in the annulus to a station; and collecting the fluid.

Geologic formation characterization via fluid separation

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.

Method for characterization of hydrocarbon reservoirs

Systems, methods, and media for processing formation pressure test data are provided. The method includes determining using a processor, a plurality of regressions for measurements of the formation pressure test data, and determining that two or more of the plurality of regressions represent a fluid code. The method also includes combining the two or more of the plurality of regressions representing the fluid code to generate a first fluid-type regression, and combining two or more other ones of the plurality of regressions representing a second fluid code to generate a second fluid-type regression. The method further includes determining that the first fluid-type regression and the second fluid-type regression are in a first hydraulic zone, and calculating a location of a boundary between the first fluid-type regression and the second fluid-type regression by extrapolating the first and second fluid-type regressions to a point of intersection therebetween.

Automatic fluid coding and hydraulic zone determination

A method can include providing data for at least one shale gas formation; performing a statistical analysis on the data for each of the at least one shale gas formation; providing a simulation model; history matching the simulation model for each of the at least one shale gas formation based at least in part on the performed statistical analysis to generate a history matched model for each of the at least one shale gas formation; and forecasting production for another shale gas formation by plugging in data for the other shale gas formation into each generated history matched model. Various other apparatuses, systems, methods, etc., are also disclosed.

Shale gas production forecasting

A formation fluid sampling tool is provided with reactants which are carried downhole and which are combined in order to generate heat energy which is applied to the formation adjacent the borehole. By applying heat energy to the formation, the formation fluids are heated, thereby increasing mobility, and fluid sampling is expedited.

Formation fluid sampling tools and methods utilizing chemical heating

Methods and apparatus to form a well are disclosed. An example method involves determining a reservoir fluid map associated with at least a portion of a reservoir. The first fluid map has first fluid composition data associated therewith. The example method also involves measuring a formation fluid and determining a second fluid composition data based on the measurement. The second fluid composition data is compared with the first fluid composition data associated with the reservoir fluid map, and a well trajectory is adjusted based on the comparison.

Methods and apparatus to form a well

A method and system for characterizing asphaltene gradients of a reservoir of interest and analyzing properties of the reservoir of interest based upon such asphaltene gradients. The analysis employs a correlation that relates insoluble asphaltene concentration to spectrophotometry measurement data measured at depth.

Methods and apparatus for analysis of downhole asphaltene gradients and applications thereof

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Orgeval, France

Francois Xavier Dubost