Texaco Inc.

Chevron U.s.a. Inc.

Weatherford/lamb, Inc.

Jackie C Sims

Donald J Dowling

Irwin R Supernaw

Richard S Simpson

Richard Scot Buell

Percy T Cox

William F Howard

Ronald W Schmidt

Dudley L Robinson

Albert P Richter

Theodore W Nussbaum

Thomas Gary Corbett

Krystian K Maskos

Mahdy Shirdel

Larry J Chrusch

Michael John Wells

Luis C Bianco

Richard Scott Buell

Provided herein are embodiments of flow control devices, static mixers, and wellbore assemblies for use in the injection of steam into a formation. Usage of one or more of these items may increase recovery of hydrocarbon from the formation.

Methods, apparatus, and systems for steam flow profiling

Provided herein are embodiments of sealing assemblies for packers and wellbore assemblies for use in the injection of steam into a formation. Usage of one or more of these items may increase recovery of hydrocarbon from the formation.

Provided herein are systems, methods, and computer-readable medium for profiling steam injected into a formation. In one embodiment, the method includes receiving a dataset of temperature surveillance data, acoustic surveillance data, surface injection data, downhole pressure measurement device data, downhole temperature measurement device data, or any combination thereof. The method further include determining annular temperature profiles, tubing temperature profiles, behind liner temperature profiles, or any combination thereof from the dataset based on configuration of the fiber optic surveillance system in the well and design of the well. The method further includes using flow diagnostic results based on the dataset, the annular temperature profiles, the tubing temperature profiles, etc. to select which computational algorithm(s) can be used to determine a steam injection flow profile and associating each selected algorithm with a weight, executing each selected algorithm, and using results and the associated weight to determine the steam injection flow profile.

Methods and apparatus for enhanced and improved viscous oil recovery are disclosed. A horizontal well is drilled through the viscous oil formation. A specially designed tubing string includes outlets that deliver steam more uniformly into the entire horizontal extent of the well borehole. Heat from the steam mobilizes and lowers the viscosity of the heavy crude wherein the crude is then produced to the surface via conventional lift arrangements.

Steam distribution apparatus and method for enhanced oil recovery of viscous oil

The present invention is directed to systems and methods for initiating annular obstructions in wells used in, or in support of, enhanced oil recovery operations&#x2014;particularly enhanced oil recovery (EOR) efforts involving steam injection (e.g., steam flooding). In at least some instances, system and method embodiments of the present invention utilize one or more passively-activated annular obstruction devices (and/or hybrid active/passive devices) for inducing annular obstruction, wherein the associated passive or hybrid activation is at least partially controlled by thermal means such that it can be deemed to be thermally-directed or thermally-controlled. Such thermally-directed passive activation can afford considerably more control over the annular obstruction process and, correspondingly, over the overall steam injection into the formation and associated reservoir&#x2014;thereby providing more efficient recovery of hydrocarbons.

Systems and methods for initiating annular obstruction in a subsurface well

The present invention generally provides a method and apparatus for injecting a compressible fluid at a controlled flow rate into a geological formation at multiple zones of interest. In one aspect, the invention provides a tubing string with a pocket and a nozzle at each isolated zone. The nozzle permits a predetermined, controlled flow rate to be maintained at higher annulus to tubing pressure ratios. In another aspect, the present invention assures that the fluid is supplied uniformly to a long horizontal wellbore by providing controlled injection at multiple locations that are distributed throughout the length of the wellbore. In another aspect, the invention ensures that saturated steam is injected into a formation in a predetermined proportion of water and vapor by providing a plurality of apertures between a tubing wall and a pocket.

Method and apparatus for injecting steam into a geological formation

The present invention generally provides a method and apparatus for injecting a compressible fluid at a controlled flow rate into a geological formation at multiple zones of interest. In one aspect, the invention provides a tubing string with a pocket and a nozzle at each isolated zone. The nozzle permits a predetermined, controlled flow rate to be maintained at higher annulus to tubing pressure ratios. The nozzle includes a diffuser portion to recover lost steam pressure associated with critical flow as the steam exits the nozzle and enters a formation via perforations in wellbore casing. In another aspect, the invention ensures steam is injected into a formation in a predetermined proportion of water and vapor by providing a plurality of apertures between a tubing wall and a pocket. The apertures provide distribution of steam that maintains a relative mixture of water and vapor. In another aspect of the invention, a single source of steam is provided to multiple, separate wellbores using the nozzle of the invention to provide a controlled flow of steam to each wellbore.

A sonde in a well logging system of the present invention includes caliper means providing a diameter signal corresponding to the diameter of a borehole traversing an earth formation. First and second transducers which, when so controlled, transmit an ultrasonic acoustical pulse into fluid flowing in the borehole or provides an electrical pulse in accordance with a received acoustical pulse from the fluid. A control network controls both transducers so that during one part of a measurement the first transducer transmits an acoustical pulse into the fluid while the second transducer receives an acoustical pulse after it has passed through the fluid. During another part of the measurement the second transducer is controlled to transmit an acoustical pulse into the fluid while the first transducer is controlled to receive the acoustical pulse after it has passed through the fluid and provides a signal in accordance with the received acoustical pulse. A signal circuit connected to both transducers provides a travel time signal corresponding to the travel times of the acoustical pulses for both parts of the measurement. A conventional well logging cable carries control signals from the surface to the control network and the travel time signal and the diameter signal to surface electronics. The surface electronics includes processing apparatus which provides the control signal to the cable and which derives the flow rate of the fluid flowing in the borehole in accordance with the travel time signal and the diameter signal.

Downhole ultrasonic transit-time flowmetering means and method

The control system and method of the present invention controls a heat treater receiving wet gas from a pipeline. The heat treater reduces the water content of the gas to provide dry gas to the pipeline. A sensor monitors the wet gas and provides a signal corresponding to the water content of the wet gas. A second sensor monitors the dry gas and provides a signal corresponding to the water content of the dry gas. A difference signal corresponding to the difference between the two water content signals. Apparatus controls the flow of fuel to the heat treater, so as to control the drying process, in accordance with the water content signal of the wet gas and the difference signal.

Means and methods for controlling the drying of wet gas

The present invention is a density meter which includes a well logging sonde that is inserted into a borehole traversing an earthen formation. The sonde includes within it a source which emits gamma rays into the borehole fluid and a detector assembly which detects gamma rays from the borehole fluid and provides a count signal corresponding to a count of the detected gamma rays. A caliper is also located in the sonde and it continually measures the diameter of the borehole as the sonde moves through the borehole and provides a caliper signal corresponding to the diameter measurement. A cable connected to the detector assembly and to the caliper conveys the count signal and a caliper signal to the surface where surface electronics includes apparatus which processes the count signal and the caliper signal to provide a signal corresponding to the density of the fluid in the borehole.

Borehole fluid density well logging means and method

A well logging system which monitors the flow rate of a fluid flowing in a borehole traversing an earth formation includes a sonde. A transmitter located in the sonde transmits acoustical waves into the fluid at a predetermined frequency. A receiver also located in the sonde receives reflected acoustical waves. The receiver also provides a signal corresponding to the received reflected acoustical waves. The provided signal is processed for being sent uphole by way of a cable. Electronics at the surface include circuitry which derives the velocity of the fluid in accordance with the frequency of the processed signal and the predetermined frequency. The circuitry provides an output signal corresponding to the derived velocity of the fluid flowing the borehole.

Downhole doppler flowmeter

A fluid capacitance sensor includes a device, receiving a stream of fluid, which converts the fluid flow to annular fluid flow. A capacitance sensing network has an internal capacitance substantially greater than the capacitance of the fluid. The capacitance sensing network measures the capacitance of the annular flowing fluid and provides a signal corresponding to the sensed capacitance of the fluid.

Fluid capacitance sensing means and method

A steam quality monitor measures the quality of steam flowing in a steam pipe. A measurement cell is connected in the steam pipe so that steam flows through the measurement cell. The cell has two windows aligned along an axis which is traverse to the flow axis of the steam. A source spatially arranged with the windows of the measurement cells provides IR energy which enters the measurement cells through one window and leaves through the other window so that the IR energy passes through the steam flowing in the measurement cell. An IR detector detects the IR energy as it leaves the measurement cell and provides a corresponding signal. The temperature of the steam flowing through the measurement cell is also sensed and a temperature signal provided. Circuitry derives the steam quality of the steam flowing in the steam pipe in accordance with the signal from the IR detector and the temperature signal.

Radiant energy absorption steam quality monitoring means and method

A system of the present invention monitors the quality of steam flowing in a pipeline includes a test cell which is connected inline into the pipeline and has the steam flowing through it. A plurality of electrodes are located within the test cell and cooperate with the test cell to provide capacitance signals corresponding to capacitances of the steam passing between the electrodes and the test cell. The electrodes have different spacings between them and an interior wall of the test cell. A sensor senses the temperature of the steam flowing through the test cell and provides a temperature signal corresponding to the sensed temperature. Another sensor senses the pressure of the steam and provides a pressure signal corresponding to the sensed pressure. Circuitry connected to the test cell, to all the electrodes, to the temperature sensor and to the pressure sensor measures the quality of the steam in accordance with the temperature signal, the pressure signal and one of the capacitance signals.

Multi-sensor steam quality monitoring means and method

A steam quality monitor monitoring the quality of steam flowing in the pipe includes capacitance sensing apparatus which senses the capacitance of the flowing steam and provides a capacitance signal corresponding to the said capacitance. Another sensor which may be either a temperature sensor or a pressure sensor senses either the temperature or pressure of the steam and provides a representative type signal. Circuitry connected to the capacitance sensor and to the temperature or pressure sensor provides an output corresponding to the quality of steam in accordance with the capacitance and the temperature or pressure signal.

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Houston, TX, United States of America

Jackie C Sims