Schlumberger Technology Corporation

Sensor Highway Limited

George Albert Brown

Arthur H Hartog

John R Lovell

Glynn R Williams

Kevin J Forbes

Christian Koeniger

Rogerio Tadeu Ramos

Robert J Schroeder

Murtaza Ziauddin

Douglas Pipchuk

Terry Wayne Stone

Jeffrey A Tarvin

Valery Vasilievich Shako

Yves Manin

Vyacheslav Pimenov

Bertrand Theuveny

Waqar Khan

Stephen J Kimminau

Maria Sidorova

Methods for correcting temperatures measured in producing wells are provided. In one embodiment, a method includes receiving formation fluid within a completion string in a well, wherein the formation fluid passes from a formation and radially into the completion string through at least one opening in the completion string. The method also includes measuring temperatures outside the completion string at multiple depths in the well at which the formation fluid passes from the formation and radially into the completion string. The temperatures measured outside the completion string at the multiple depths in the well are converted into axial temperatures inside the completion string at the multiple depths. Additional systems, devices, and methods are also disclosed.

Temperature measurement correction in producing wells

A first water injection into an injection well is carried out followed by a first shut-in of the injection well. A second water injection is carried out, a volume of the injected water exceeds several times a volume of water in the well in an intake interval. Then there is a second shut-in of the injection well, and during the second shut-in transient temperature profiles are registered within the intake interval by temperature sensors. Then a third water injection step is carried out and at an initial stage of the third injection transient temperature profiles in the intake interval are registered using the temperature sensors. The transient temperature profiles registered during the second shut-in period are analyzed and intake zone boundaries are determined. The transient temperature profiles registered at the initial stage of the third water injection are analyzed and a water intake profile is determined.

Method for determining a water intake profile in an injection well

System and method for producing fluids from a hydrocarbon reservoir where an injector well segment and parallel underlying producer well segment are both completed with slotted liners. The injector and producer segments are logically partitioned into corresponding sections to define a plurality of injector-producer section pairs. Injection tubing strings supply stimulating fluid (e.g., saturated steam) to associated sections of the injector segment for injection into the hydrocarbon reservoir. Surface-located control devices control the pressure of the stimulating fluid flowing through the respective injection tubing strings. Production tubing strings (with the aid of artificial lift) carry fluids produced from associated sections of the producer segment. A plurality of controllers is provided for the injector-producer section pairs to control at least one process variable (e.g., interwell subcool temperature) associated with respective injector-producer section pairs over time by adjusting control variables that dictate operation of the control devices for the injection tubing strings.

Hydrocarbon recovery employing an injection well and a production well having multiple tubing strings with active feedback control

A method for determining flow distribution in a formation having a wellbore formed therein includes the steps of positioning a sensor within the wellbore, wherein the sensor generates a feedback signal representing at least one of a temperature and a pressure measured by the sensor, injecting a fluid into the wellbore and into at least a portion of the formation adjacent the sensor, shutting-in the wellbore for a pre-determined shut-in period, generating a simulated model representing at least one of simulated temperature characteristics and simulated pressure characteristics of the formation during the shut-in period, generating a data model representing at least one of actual temperature characteristics and actual pressure characteristics of the formation during the shut-in period, wherein the data model is derived from the feedback signal, comparing the data model to the simulated model, and adjusting parameters of the simulated model to substantially match the data model.

System and method for reservoir characterization

A method of determining the inflow profile of an injection wellbore, comprising stopping injection of fluid into a formation, the formation intersected by a wellbore having a section uphole of the formation and a section within the formation, monitoring temperature at least partially along the uphole section of the wellbore and at least partially along the formation section of the wellbore, injecting fluid into the formation once the temperature in the uphole section of the wellbore increases, and monitoring the movement of the increased temperature fluid as it moves from the uphole section of the wellbore along the formation section of the wellbore. The monitoring may be performed using a distributed temperature sensing system.

Method to measure injector inflow profiles

A method is disclosed of characterizing a well using a series of measurements taken along the sandface of that well in order to optimize a well model. The method may comprise providing a well model with a plurality of adjustable physical parameters, providing a data set made up of a plurality of sandface measurements, and running the well model with different combinations of adjustable physical parameters so that the results of the well model substantially match the results of the sandface measurements. In one embodiment, the method may comprise creating a communication pathway between the surface and the sandface including an inductive coupler. A further step may include pre-processing the plurality of the sandface measurements. In addition, a further step may be to establish or set at least one control device in order to change the flow characteristics of the production fluid in the well.

Combining reservoir modeling with downhole sensors and inductive coupling

A method of measuring fluid properties such as flow velocity, flow rate, and fluid composition comprises positioning a heat exchange element with a temperature sensor, such as an optical fiber temperature sensor, arranged centrally inside the element in thermal contact with a fluid of interest, heating or cooling the heat exchange element to cause a temperature difference and exchange of thermal energy between the element and the fluid, using the temperature sensor to measure the temperature of the heat exchange element during the exchange of thermal energy, and determining properties of the fluid from the temperature measurement. A second temperature sensor can be provided offset from the first sensor to provide additional measurements to improve accuracy, and a plurality of heat exchange elements with temperature sensors can be used together to determine fluid properties over a large region.

Method and apparatus for measuring fluid properties

A system to determine the mixture of fluids in the deviated section of a wellbore comprising at least one distributed temperature sensor adapted to measure the temperature profile along at least two levels of a vertical axis of the deviated section. Each distributed temperature sensor can be a fiber optic line functionally connected to a light source that may utilize optical time domain reflectometry to measure the temperature profile along the length of the fiber line. The temperature profiles at different positions along the vertical axis of the deviated wellbore enables the determination of the cross-sectional distribution of fluids flowing along the deviated section. Together with the fluid velocity of each of the fluids flowing along the deviated section, the cross-sectional fluid distribution enables the calculation of the flow rates of each of the fluids. The system may also be used in conjunction with a pipeline, such as a subsea pipeline, to determine the flow rates of fluids flowing therethrough.

Use of fiber optics in deviated flows

A fiber optic sensor system provides sufficient thermal information to determine the mass flow rates of produced fluids within a well bore, using an optical fiber placed within or adjacent to the well bore without interference with production or prejudicing the integrity of the well. Mass flow rates of fluid in a conduit () located in a heat sink differing in temperature from the fluid are determined by obtaining a distributed temperature profile () of fluid flowing along a length of conduit () by using optical data obtained from a length of optical fiber in thermal contact therewith, obtaining a profile of the heat sink temperature external to the conduit, and deriving mass flow rates of fluids in the conduit from the said profiles and from measured thermal transfer parameters.

Method and apparatus for determining flow rates

A method and apparatus is disclosed for measuring the flow of fluid in the conduit, giving the example of oil in a well bore ( ). A heat exchanger such as a cooling station ( ) is placed in the well bore ( ) and caused to create a slug of cooled oil whose passage, through the well ( ) can be monitored by a temperature sensor in the form of a continuous fiber optic loop ( ). Knowledge of the movement of the cooled slug of oil and of the free cross-section of the conduit ( ) wherein the oil is flowing permits the volume flow-rate of oil to be calculated. Cooling stations ( ) are cooled by Joule-Thompson cooling employing high pressure nitrogen gas. Cooling stations ( ) may be placed at plural locations within the well bore ( ) to monitor individual flows ( ) from multiple flow sources.

Method and apparatus for flow measurement

A technique usable with a subterranean well includes deploying a first optical sensor downhole in the subterranean well. The technique includes observing an intensity of backscattered light from the first optical sensor to measure a distribution of a characteristic along a portion of the well. The technique includes deploying a second sensor downhole to measure the characteristic at discreet points within the portion. The second sensor is separate from this first sensor and includes at least one interferometric sensor.

Technique and system for measuring a characteristic in a subterranean well

A fiber optic sensor system provides sufficient thermal information to determine the mass flow rates of produced fluids within a well bore, using an optical fiber placed within or adjacent to the well bore without interference with production or prejudicing the integrity of the well. Mass flow rates of fluid in a conduit ( ) located in a heat sink differing in temperature from the fluid are determined by obtaining a distributed temperature profile ( ) of fluid flowing along a length of conduit ( ) by using optical data obtained from a length of optical fiber in thermal contact therewith, obtaining a profile of the heat sink temperature external to the conduit, and deriving mass flow rates of fluids in the conduit from the said profiles and from measured thermal transfer parameters.

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Beaconsfield, United Kingdom

George Albert Brown