Abstract: A desiccating module configured to be installed in a downhole tool is provided. The desiccating module includes a housing having a containment portion, and desiccant located in the containment portion of the housing capable of retaining moisture therein. The housing is configured to be retained in a downhole tool containing moisture sensitive electronics. The housing is configured to permit passage of moisture from outside the housing to the containment portion and to retain the desiccant within the containment portion. The desiccant have a retention capacity sufficient to hold a predetermined threshold amount of moisture.

Abstract: Systems and methods for processing downhole rotational data. An example method includes commencing operation of a processing device to continually calculate a downhole oscillation index by receiving downhole rotational speed data indicative of downhole rotational speed of at least a portion of a drill string during drilling operations, calculating a fundamental oscillation time period of the drill string, calculating a time length of a time window based on the fundamental oscillation time period, and processing the downhole rotational speed data encompassed within the time window.

Abstract: Methods and apparatus for detecting water in multiphase flows are disclosed. An example apparatus includes a conduit including an inlet to receive a multiphase flow and an electromagnetic sensor coupled to a liquid-rich region of the conduit to measure a permittivity of the multiphase flow, and a water detection manager to determine that water is detected in the multiphase flow based on the permittivity.

Abstract: An electric submersible hydraulic lift pump system is used for removing fluid from a well. The hydraulic lift pump system includes a source of fluid, a tubing string extending from the surface and in fluid communication with the source of fluid, a first pump interposed in the tubing string so the first pump is positioned below the surface and operably arranged to draw fluid from the tubing string upstream of the first pump and to discharge the fluid into the tubing string downstream of the first pump as a power fluid, and a second pump interposed in the tubing string and operably arranged to receive the power fluid from the first pump and be combined with a production fluid to form a return fluid to be discharged into the annulus.

Abstract: Provided herein are systems, methods and apparatuses for a thickness measurement device based on a capacitive array.

Abstract: A portable communication device may include a gas sensor enclosed in an enclosure, a port to allow flow of air into and out of the enclosure, and a light source disposed on an internal surface of the enclosure. The light source is operable to facilitate generation of ozone gas within the enclosure. The enclosure may contain a heating element that allows baseline calibration of the gas sensor by thermally decomposing ozone gas molecules. The gas sensor includes a miniature gas sensor such as a metal-oxide (MOX) gas sensor.

Abstract: Various embodiments of the present technology may provide methods and apparatus for a capacitive sensor configured to detect rain. The capacitive sensor may provide a reception electrode in communication with a drive electrode to form an electric field and a ground electrode surrounding the reception and drive electrodes. The ground electrode may couple the rain to a ground potential resulting in a decrease in the capacitance of the capacitive sensor.

Abstract: A measure of inter-reservoir cross flow rate between adjacent reservoir layers which are productive of hydrocarbons is determined. With passage of time, pressure differentials between reservoir layers can grow due to continuous production from an active layer. In addition, the flow area between an active layer and adjacent layers can grow with time for a given reservoir system. These changing pressure and flow conditions with time can contribute to substantial amounts of cross flow rates, which need to be accounted for when characterizing the commercial producibility of the active layer. The inter-reservoir cross flow rate is based on a measure of specific permeability and of cross flow rate within a reservoir layer which is obtained from pressure transient tests of the reservoir formations.

Abstract: A NMR logging tool is provided and disposed in a wellbore at some desired depth. Packers are provided and actuated to hydraulically isolate a section of the wellbore and form a cavity between the NMR logging tool and the wall of the isolated section of the wellbore. The cavity is evacuated until a first desired pressure within the cavity is attained. Fluid is injected into the cavity until a second desired pressure within the cavity is attained. A plurality of NMR measurements is made on the region of the formation, each of the plurality of measurements being made at different times. Formation properties are inferred using the measurements. A baseline NMR measurement may be made when a first desired pressure is attained. A time-zero NMR measurement may be made when a second desired pressure is attained. Similar measurements may be made in a laboratory on a sample.

Abstract: A method of predicting a property of an earth formation includes: injecting a fluid into at least one pre-existing feature of the formation at a plurality of constant pressures or flow rates; measuring a response from the at least one pre-existing feature at each of the plurality of constant pressures or flow rates; and estimating at least one property of the at least one pre-existing feature based on the response. An apparatus for predicting a property of an earth formation is also disclosed.

Abstract: A net oil and gas well test system for a set of oil and gas wells includes at least two net oil and gas measurement systems and a plurality of valves that are in fluid communication with the individual wells in the set and independently configurable between a first state, in which the valve routes flow to a first net oil and gas measurement system, and a second state, in which the valve routes flow to a second net oil and gas measurement system. Each net oil and gas measurement system suitably has the capability to measure a multiphase flow including oil, gas, and water without separation. For example, each measurement system can include a multiphase Coriolis meter and a water cut meter. Each measurement system suitably includes the capability to provide dynamic uncertainty estimates related to measurement of the multiphase flow.

Abstract: The invention relates to the optimized management of one or more fluid production units, especially those involving fluid separation treatment, comprising: a) a data collection step, the data being on one or more values of current parameters defining a current operating point of the production unit, on a future production demand and on at least one optimization criterion; and b) a computation step for computing one or more parameters defining a new operating point of the unit, at least in accordance with this demand. The computation step b) comprises at least: 1) an estimation of at least one optimum solution for defining the new operating point; and 2) a validity test carried out on this optimum solution, at least in accordance with an analysis of the transition of the production unit from the current operating point to the new operating point.

Abstract: Whiles moving a pipe string in a wellbore during tripping operations, pressure and temperature are measured. Based on the measured pressure and temperature, such parameters of a bottomhole and a near-bottomhole zone of the wellbore are calculated as skin factor, permeability, reservoir thickness, bottomhole pressure, and outflow or inflow from/to the zone under consideration.

Abstract: A method and system for estimating water cut or water fraction. The method may include independently establishing a production index for a region in a well. An initial flow rate in the region may be computed from the production index. Further, a measured flow rate may also be monitored within the region on an ongoing rate, for example, with a Venturi device. Thus, a comparison of the initial and measured flow rates may also take place on an ongoing basis so as to provide a real time read of fluid density. This, in turn may be used to estimate water cut of anywhere between 0 and 100% for the region in a dynamic manner. As a result, production from the overall well may be optimized with greater accuracy as a determination on the amount of production allowed, if any, is made on a region by region basis with improved water cut accuracy regarding each region.

Abstract: A method includes measuring electrical conductivity of a treatment fluid with one or more sensors at various instants of time. The method is further performed by generating one or more signals indicative of the electrical conductivity of the treatment fluid and transmitting the one or more signals to a computer system. The method is further performed by analyzing the one or more signals to determine a phase change in the treatment fluid based upon a positive or negative change in the electrical conductivity of the treatment fluid from a predetermined electrical conductivity range.

Abstract: A method and apparatus for making real-time measurements of downhole properties during cement plug placement. A wired placement conduit is lowered downhole releasing a sensor package. The sensor package is capable of measuring downhole properties in real-time in the period while the cement plug sets.

Abstract: A meter tube assembly for use with an ultrasonic flow meter is provided. The meter tube assembly includes a pipe spool having an extremely rough first section including an interior surface with a relative roughness (?/D) of 1% or greater. Fluid passing through the extremely rough section exhibits a flow profile that remains substantially constant over the range of Reynolds numbers. As such, ultrasonic flow meters can be simplified as they need not account for different Reynolds numbers.

Abstract: A method to determine a mass proportion of a first component of a multi-component fluid is provided that includes separating the first component in a separation step at least in part from the multi-component fluid, determining at least two reference flow rates, selected from a flow rate of the multi-component fluid supplied to the separation step, a flow rate of a residual fluid resulting from the separation of the first component, and a flow rate of a separation fluid accumulating in the separation step, and determining the mass proportion of the first component from the selected reference flow rates, taking into account a non-separated residual content of the first component in the residual fluid. An extraneous content of an additional separated component of the multi-component fluid is additionally taken into account.

Abstract: A measurement device is configured in a shaped charge package to be utilized in a perforating gun section tool string. The measurement device may include for example thermal conductivity detectors (TCD) configured to measure fluid flow velocity and/or thermal characteristics of the flowing fluid. The measurement device may include for example a pair laterally spaced TCDs each having sensor faces positioned co-planar with a surface across which the fluid flows. The measurement device may include a recessed TCD, having a sensor face recessed below an opening in the exterior surface.

Abstract: A method of well testing to determine properties of oil and gas wells 8 comprises: applying oscillations to the flow rate and/or pressure at multiple wells 8 wherein the oscillations applied at different wells of the multiple wells are at different test frequencies; receiving measurements of flow rate in flows downstream of a production header that combines the flows from the multiple wells 8, and/or receiving measurements of pressure and/or temperature from individual wells 8; carrying out a frequency analysis of the pressure, flow rate and/or temperature measurements to determine pressure, flow rate and/or temperature variations induced by the applied oscillations; and determining properties of the different wells 8 of the multiple wells 8 based on the results of the frequency analysis at the test frequencies for the wells 8.

Abstract: A method of testing an earth formation can include incrementally opening a choke while drilling into the formation is ceased, thereby reducing pressure in a wellbore, and detecting an influx into the wellbore due to the reducing pressure in the wellbore. Another method of testing an earth formation can include drilling into the formation, with an annulus between a drill string and a wellbore being pressure isolated from atmosphere, then incrementally opening a choke while drilling is ceased, thereby reducing pressure in the wellbore, detecting an influx into the wellbore due to the reducing pressure in the wellbore, and determining approximate formation pore pressure as pressure in the wellbore when the influx is detected. Drilling fluid may or may not flow through the drill string when the influx is detected. A downhole pressure sensor can be used to verify pressure in the wellbore.

Abstract: Example methods and apparatus for analyzing operations are disclosed herein. An example method includes disposing a sensor in a fluid flow passageway. The sensor has a heater and a temperature sensor. The example method further includes obtaining a first response of the sensor to a fluid flowing in the fluid flow passageway and transmitting a signal to a tool to operate the tool. Operation of the tool is to affect a fluid parameter of the fluid. The example method also includes obtaining a second response of the sensor to the fluid flowing in the fluid flow passageway and determining if the tool has operated based on the first response and the second response.

Abstract: Device and method for performing distributed fluid velocity measurement. An elongate device comprising along its length, a heated core (200), at least one outer layer (240) around the core, the outside surface of the outer layer (240) defining an outside surface of the device, and a distributed temperature sensor (230) located between the heated core (200) and the outside surface of the device. The method immerses the device in one or more fluids along its length, measures the ambient temperature of the fluids at points along it's length, heats the heated core (200) for a predetermined heating period and measures the temperature again at the same points. Using pre-installed knowledge the device can obtain distributed and/or point fluid velocity measurements.

Abstract: A multi-phase flow metering system for measuring a multi-phase fluid including oil, water, and gas, includes a Coriolis mass flow meter adapted to measure mass flow rate and density of the multi-phase fluid. The system has a water cut meter adapted to measure the water cut of the multi-phase fluid. A processor is configured to determine the oil mass flow rate of the oil, water mass flow rate of the water, and gas mass flow rate of the gas using the mass flow rate and density from the Coriolis meter and the water cut from the water cut meter. The processor is further configured to determine dynamic estimates of the uncertainty of each of the oil mass flow rate, water mass flow rate, and gas mass flow rate.

Abstract: A simple, applicable in the field, and extra-equipment free method is provided for determining steam dryness directly in a thermal recovery of high-viscosity oil. A non-condensable gas is added into a saturated steam being injected into a well. The presence of non-condensable gas changes partial steam pressure. Correspondingly the steam condensation temperature also changes. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

Abstract: A method for monitoring fluid flow through a downhole device, comprises a) providing an acoustic tube wave in fluid in the device; b) measuring the acoustic tube wave after it has passed through the fluid in the device; and c) assessing the permeability of the device by measuring the attenuation of the acoustic signal. Changes in velocity of the acoustic signal may also be measured. The device may be a permeable downhole device such as a sand screen the measurements in step b) are made using a plurality of sensors deployed in the hole. The method may further including the step of cross-correlating a signal received at a first receiver with signals received at additional sensors so as to obtain an effective response as if the signal had been emitted from a source at the position of said first receiver.

Abstract: A portable monitor used to measure landfill gas and landfill well parameters. The portable monitor includes a control unit and a measuring unit that can communicate wirelessly with one another. The control unit and/or measuring unit can include a heating arrangement to increase the temperature of one or more components in the control unit and/or measuring unit in cold environments.

Abstract: A method of method of determining relative contributions of two or more producing subterranean sources to a total flow is described using the steps of selecting a subset from a set of identifiable components in the total flow and using the subset to determine the relative contributions of two or more producing subterranean sources, wherein the subset is selected based on the sensitivity of the determination step to errors in the measurement of concentrations of said identifiable components.

Abstract: A combination of sensors are strategically placed along a pipeline to measure critical properties such as temperature and pressure of the flow product. The sensors are a combination of fiber optic sensing devices that are specifically designed to measure a range of properties within particular bandwidth, with a method to reduce light attenuation over the long pipeline distances. The pipeline is typically subsea and can range widely in diameter. In many cases the pipeline has a coating that acts as a barrier to the corrosive sea water and additional thermal barriers.

Abstract: A sensor system includes a carrier configured for a specific application; an electronics module mountable in a number of individual carriers; a feedthrough mountable in a number of individual carriers and in operable communication with the interface; a sensor mounting mountable in a number of individual carriers and in operable communication with the feedthrough; and a sensor array articulated to the sensor mounting.

Abstract: Methods and apparatuses are disclosed for measuring and controlling liquid levels in a well. The apparatus may include a plurality of sensors, the plurality of sensors comprising: a first sensor coupled to the well, the first sensor configured to measure a casing pressure, a second sensor coupled to the well, the second sensor configured to measure a tubing pressure, and a third sensor coupled to a motor that is further coupled to the well, the third sensor configured to measure at least one characteristic of the motor, and a processor coupled to the plurality of sensors, wherein the processor calculates a level of liquid in the well based upon measurements of at least two of the plurality of sensors.

Abstract: A device determines the specific gravity of a wellbore fluid flowing into a submersible pump. The specific gravity of the wellbore fluid is determined by measuring the pressure increase across at least two pump stages and then using fluid flow properties and known pump characteristics to back calculate the specific gravity of the wellbore fluid.

Abstract: Although the methods have been described here for, and are most typically used for, hydrocarbon production, fluid diversion measurement systems and methods are described. One method includes inserting a tubular tubing having one more fluid injection ports into a wellbore, injecting a treatment fluid through the injection port, and determining differential flow of the treatment fluid at one or more wellbore based on measuring the concentration of at least one particular component of a wellbore fluid located in the annulus formed between the wellbore and tubular; and using the measured parameters in realtime to monitor, control, or both monitor and control diversion of the fluid.

Abstract: Methods of monitoring various downhole conditions are described, including a system for determining and/or identifying the flow of fluid in a well, determining sand production in a well, identifying localized events in a well, determining the apparent flow velocity of fluid flowing through a downhole conduit, and/or monitoring the strain in downhole tubulars. These determinations may be made by monitoring signals received from one or more sensors located in a well and analysing the signals, such as their frequency and timing.

Abstract: An apparatus and method for monitoring and characterizing the fluid flow in and around the tubing string in a wellbore, preferably using fiber optic componentry. The apparatus includes a signal sensing demodulator device and a skin friction sensing device positionable within the wellbore. Both devices are in informational communication with each other. The method includes exposing the skin friction sensing device to a fluid flow, transmitting a signal obtained as a result of a movement of the skin friction sensing device from the fluid flow to a signal sensing demodulator device, converting the signal to a numerical value, and computing a parameter or parameters of the fluid flow in the wellbore from the numerical value.

Abstract: Formation testing, resistivity and NMR measurements are used concurrently to determine a relative permeability representative of a formation surrounding the borehole. A method and apparatus is provided for accurate determination of the relative permeability for a formation by measuring saturation levels in a region of interest determined from resistivity or NMR readings versus time during formation draw down pressure testing. The method and apparatus determines and effective permeability over time for various saturation levels to determine the relative permeability for the formation at each saturation level and also enables determination of the efficacy of utilizing completion fluids in the formation to increase formation productivity. The method and apparatus enables more accurate determination of effective permeability and the irreducible saturation level.

Abstract: In at least some embodiments, a tool may comprise a tool body and one or more tool components. The tool may further comprise tool electronics located within the tool body, wherein the tool electronics are operable to sense and store tool component characteristics and environmental characteristics. At least some of the tool electronics are operable, at least for one week, when exposed to temperatures of at least 200 Celsius. The tool electronics may be integrated circuits formed on a silicon carbide substrate or a silicon on sapphire substrate. One illustrative embodiment of the tool is a drill bit for employment in a high temperature drill well.

Abstract: Methods for estimating formation pressure from data taken during the drawdown cycle are presented. In one aspect, a method of determining a formation pressure during drawdown of a formation comprises sampling fluid from a formation using a downhole tool having a sample volume and a fluid sampling device. At least one time dependent parameter of interest related to the fluid is determined during the drawdown. The at least one time dependent parameter is analyzed using a plurality of calculation techniques to determine the formation pressure. The techniques include (i) a first pressure derivative technique; (ii) a second pressure derivative technique; (iii) a formation rate analysis technique; (iv) a dp/dt-ratio technique; and (v) a stepwise drawdown technique.

Abstract: A tracer release method for monitoring fluid flow in a well utilizes a deformable container having a liquid tracer material which container has an outlet which debouches into the neck portion of a venturi in a well conduit. The container has a wall which is at least partly exposed to the fluid pressure at the relatively wide in- or outlet of the venturi, so that an amount of tracer is injected continuously or discontinuously into the well effluents which is proportional to the pressure difference p across the venturi, which pressure difference p is indicative of the fluid density &rgr; and squared fluid velocity &ugr;.

Abstract: The invention relates to a tool holder serving to receive measurement means (9, 10, 13) for characterizing a multi-phase fluid coming from a deposit (17) through which at least one well (16) passes, and flowing inside said tool holder. According to the invention, the tool holder is provided with an axial cavity (3) and with a first radial opening (4) which opens out in the inside wall of said tool holder and intercepts said axial cavity, said cavity and said opening serving to receive said measurement means. The invention also relates to a device for characterizing a multi-phase fluid coming from a deposit (17) through which at least one well (16) passes, said device comprising: a source unit (9) for emitting gamma rays through said multi-phase fluid, and a detector unit (10) having a scintillator crystal (10a) receiving said gamma rays after they have passed through the fluid.

Abstract: This invention comprises the use of a variable orifice valve as a flow controller and flow meter. Pressure measurements are taken upstream and downstream of the variable orifice valve by way of a differential pressure measurement mechanism. The differential pressure measurement mechanism may comprise two separate absolute pressure measurement devices or a single differential pressure measurement device. Flow rate through the valve is determined from the pressure drop across the valve. In wellbores having multiple zones, a variable orifice valve together with a differential pressure measurement mechanism may be deployed for each zone. The flow rate through each of the zones and at the surface can then be monitored and controlled.

Abstract: System and methods are disclosed for fluid measurements which may be utilized to determine mass flow rates such as instantaneous mass flow of a fluid stream. In a preferred embodiment, the present invention may be utilized to compare an input mass flow to an output mass flow of a drilling fluid circulation stream. In one embodiment, a fluid flow rate is determined by utilizing a microwave detector in combination with an acoustic sensor. The acoustic signal is utilized to eliminate 2&pgr; phase ambiguities in a reflected microwave signal. In another embodiment, a fluid flow rate may be determined by detecting a phase shift of an acoustic signal across two different predetermined transmission paths. A fluid density may be determined by detecting a calibrated phase shift of an acoustic signal through the fluid. In another embodiment, a second acoustic signal may be transmitted through the fluid to define a particular 2&pgr; phase range which defines the phase shift.

Abstract: This invention comprises the use of a variable orifice valve as a flow controller and flow meter. Pressure measurements are taken upstream and downstream of the variable orifice valve by way of a differential pressure measurement mechanism. The differential pressure measurement mechanism may comprise two separate absolute pressure measurement devices or a single differential pressure measurement device. Flow rate through the valve is determined from the pressure drop across the valve. In wellbores having multiple zones, a variable orifice valve together with a differential pressure measurement mechanism may be deployed for each zone. The flow rate through each of the zones and at the surface can then be monitored and controlled.

Abstract: A well tester adapted to select among members of an oil well family to provide a purged and clean vessel to receive samples of well production that include gas and oil, and by selective use of production pressure and lease water under pressure, allow for the separation and separate measure of the oil and gas, and optionally to provide for improved sampling of production fluids with high gas/oil ratios.

Abstract: The present invention provides a method for improving the quality of a formation fluid sample by taking the sample at a time when the formation fluid composition contains the most favorable portion of hydrocarbons. This task is accomplished by determining in real-time, the composition of the fluid flowing into a downhole tool from the formation. This method determines the optical density of the fluid as the fluid flows through the tool. An optical density spectrum is generated from the optical density measurement. The optical density spectrum is compared to a composite optical density spectrum generated from a database of known fluid samples. As a result of the comparisons, there is a determination of the derivations between corresponding features of the two spectra. Adjustments are made to the components of the composite spectrum until the deviations between the two spectra are at an acceptable minimum.

Abstract: Sensor modules are provided which are pumped into a well by first being pumped downhole within a drill string, then passing through the drill bit and being circulated uphole in the annulus between the drill string and the borehole of the well. The sensors take measurement readings as they are being pumped uphole through the annulus. The sensors are preferably separated from the mud returns from the well, and then read at an inductive read unit. The sensor modules are provided by semiconductor substrates which measure downhole well parameters, and then store the date for retrieval at the surface. The semiconductor substrates preferably have a plurality of sides on which measurement sensors and circuitry may be formed, allowing the circuitry and the sensors to be made of smaller sizes. Such sensors include temperature sensors, three-dimensional stain gauges, which are also useful as pressure transducers, inductive pressure transducers, inclination sensors, accelerometers, gyroscopes and radiation detectors.

Abstract: A formation fluid sampling probe uses two hydraulic lines to recover formation fluids from two zones in a borehole. One of the zones is a guard zone and the other is a probe zone. The guard zone and the probe zone are isolated from each other by mechanical means, with the guard zone surrounding the probe zone and shielding it from the direct access to the borehole fluids. Operation of the tool involves withdrawal of fluid from both zones. Borehole fluids are preferentially drawn into the guard zone so that the probe zone recovers the formation fluid substantially free of borehole fluids. Separation of the guard zone from the probe zone may be accomplished by means of an elastomeric guard ring, by inflatable packers or by tubing. The device can be adapted for use either on a wireline or in an early evaluation system on a drillstring.

Abstract: A system is provided for monitoring in the real time the wellbore pit volume to promptly determine the occurrence of a wellbore kick and take corrective action to minimize fluid influx volume and/or drilling fluid losses. A system includes one or more level sensors 22 which output signals to a pit volume totalizer 20 and then to a computer 26. Computer 26 may also receive signals from one or more fluid temperature sensors 40 and one or more fluid compressibility sensors 42. The output from the computer may be displayed in real time in various monitors 28, then also may be output to a permanent record 30. Computer 36 may also automatically activate the conventional alarm 32 to alert the drilling operator to the occurrence of a kick. Substantial savings in drilling time and cost may be realized according to the present invention, along with benefits of reduced environmental contamination and enhanced well safety.

Abstract: An apparatus and process for obtaining representative samples of fluids produced from one or more oil wells by means of a closed vessel chamber with lease water supply port connected to a lease water supply line, where a pressure sensor within such internal chamber is used together with a flowmeter and liquid-sensing probe or oil/water interface sensor employed in the fluid flow path lines to determine a rate of well production along with absolute or relative amounts of oil, water and gas contents.

Abstract: The present invention provides a method for improving the quality of a formation fluid sample by taking the sample at a time when the formation fluid composition contains the most favorable portion of hydrocarbons. This task is accomplished by determining in real-time, the composition of the fluid flowing into a downhole tool from the formation. This method determines the optical density of the fluid as the fluid flows through the tool. An optical spectrum is generated from the density measurement. The optical spectrum is compared to a composite spectrum generated from a database of known fluid samples. As a result of the comparisons, there is a determination of the derivations between corresponding features of the two spectra. Adjustments are made to the components of the composite spectrum until the deviations between the two spectra are at an acceptable minimum. Determinations of the fluid composition are made from the composition of the composite spectrum at the minimum deviation.