Baker Hughes, a Ge Compnay, LLC

Baker Hughes Corporation

Radu Coman

Martin Blanz

Holger Thern

Holger Tietjen

Michael Neubert

Sunil Kumar

Holger Mathiszik

Tobias Kischkat

Michael Koppe

Mouin Hamdan

An embodiment of a method of performing a nuclear magnetic resonance (NMR) measurement includes disposing a NMR measurement device in a carrier in an earth formation, applying a static magnetic field into a formation, and emitting a plurality of pulse sequences into the formation, the plurality of pulse sequences including at least a first pulse sequence having a first wait time and a second pulse sequence having a second wait time. The method also includes receiving a long wait-time echo train based on the first pulse sequence and a short wait-time echo train based on the second pulse sequence. The method further includes transforming, by a processor, the echo trains into volumetric portions including a first fluid volumetric portion, estimating a longitudinal relaxation time for the first fluid volumetric portion; and identifying whether the first fluid volumetric portion is gas or light oil based on the estimated longitudinal relaxation time.

Low gradient magnetic resonance logging for measurement of light hydrocarbon reservoirs

A nuclear magnetic resonance (NMR) apparatus includes a carrier configured to be deployed in a borehole, a magnet assembly configured to generate a static magnetic field in an earth formation, and at least one transmitting assembly configured to generate an oscillating magnetic field in a volume of interest within the formation. The apparatus also includes a pulse generator configured to apply a direct-echo pulse sequence to the at least one transmitting assembly, the direct-echo pulse sequence having a plurality of successive pulses including a first pulse and a second pulse configured to generate a first direct NMR echo, and a third pulse, the third pulse selected to at least partially separate a stimulated NMR echo from a second direct NMR echo occurring after the third pulse. The apparatus further includes at least one receiving assembly configured to detect the first and second direct echoes of an NMR echo train.

Magnetic resonance pulse sequences and processing

A system for measuring a property of fluid in an earth formation includes a downhole tool disposed in a borehole and configured to be movable within the borehole and a nuclear magnetic resonance (NMR) measurement device including a transmitter configured to emit at least two pulse trains of magnetic energy into the earth formation and a detector configured to detect a long-TW echo train and a short-TW echo train resulting from the at least two pulse trains. The system also includes a processor configured to combine the information from the at least two pulse trains and a rate of penetration of the downhole tool to form a measurement of the property.

Formation evaluation utilizing dual wait time nuclear magnetic resonance

A method for estimating a property of a subsurface material includes: conveying a carrier through a borehole penetrating the subsurface material; performing at least two magnetic resonance (NMR) measurements in a volume of interest in the subsurface material using an NMR tool disposed on the carrier, wherein (i) a first NMR measurement has a first wait time and a first first-echo time and a second NMR measurement has a second wait time and a second first-echo time, (ii) the first wait time and the second wait time are less than or equal to 500 milliseconds, and (iii) the first first-echo time and the second first-echo time are different; receiving at least the first-echo of the first NMR measurement and receiving at least the first-echo of the second NMR measurement; and estimating the property of the subsurface material by using the at least two measured first-echoes simultaneously.

NMR logging in formation with micro-porosity by using first echoes from multiple measurements

A method for processing nuclear magnetic resonance (NMR) measurement data includes receiving, with a processor, NMR measurement data obtained from an NMR tool, the NMR measurement data having an echo train affected by a motion artifact, wherein the motion artifact is related to a magnetic field magnitude that varies in a volume of interest due to a motion of the NMR tool. The method further includes reducing, with the processor, an effect on the NMR measurement data of the motion artifact by using a correcting inversion method that models the motion artifact to provide a corrected transverse relaxation time constant (T2) distribution, the correcting inversion method having a multiplicative term having a term that includes at least one local maximum and an optional decay term.

T2 inversions with reduced motion artifacts

An apparatus for estimating properties of an earth formation includes a nuclear magnetic resonance (NMR) measurement device including a magnet assembly, at least one transmitting assembly configured to generate an oscillating magnetic field in the formation, and a receiver configured to detect NMR signals from at least a sensitive volume in the formation. The apparatus also includes a processing device configured to receive NMR data corresponding to the detected NMR signals. The processing device is configured to perform combining a geometrical factor of the NMR logging tool with a temperature distribution, the temperature distribution indicating a temperature value at at least one location in the sensitive volume of the formation, correcting the NMR data based on the temperature value, estimating a property of the formation based on the corrected NMR data, and performing one or more aspects of an energy industry operation based on the estimated property.

Temperature correction of magnetic resonance data

An embodiment of a nuclear magnetic resonance (NMR) apparatus for estimating properties of an earth formation includes an NMR measurement device including a transmitting assembly configured to emit a pulse sequence and a receiving assembly configured to detect an echo train based on the pulse sequence, and a processor. The processor is configured to perform receiving input parameters including an axial speed of the NMR measurement device and a Tvalue associated with a selected formation fluid, analyzing polarization data associated with the Tvalue, the polarization data describing a dependency between polarization and axial speed, determining a wait time for the pulse sequence based on the polarization data, applying the pulse sequence with the determined wait time to the transmitting assembly, and estimating a property of the earth formation based on the echo train detected by the receiving assembly in response to the pulse sequence.

Magnetic resonance pulse sequences having wait times based on carrier speed

A nuclear magnetic resonance (NMR) apparatus includes a transmitting assembly configured to emit one or more dual-wait-time pulse sequences, and a receiving assembly configured to detect a long-wait-time echo train and a short-wait-time echo train. The apparatus also includes a processor configured to perform at least one of: estimating a difference between the long-wait-time echo train and the short-wait-time echo train to generate a differential echo-train, inverting the differential echo-train into a differential Tdistribution, and detecting a motion artefact in response to determining that the differential echo-train includes a short-Tporosity fraction that is greater than a threshold value; and inverting two echo trains into two Tdistributions, calculating at least two porosity fractions for each of the two Tdistributions, estimating a shift of a porosity amount between the at least two porosity fractions, and detecting the motion artefact based on the shift.

Motion detection and correction of magnetic resonance data

A method for estimating a property of a subsurface material includes conveying a carrier through a borehole penetrating the subsurface material and performing an NMR measurement in a volume of interest in the subsurface material using an NMR tool having an antenna disposed at the carrier. The method further includes receiving with the antenna a short build-up signal due to a short magnetization build-up time of the NMR measurement, an echo-train signal with short polarization time due to the NMR measurement, and an echo-train signal with long polarization time due to the NMR measurement. The method further includes inverting, simultaneously, the short build-up signal, the short-polarization-time echo-train signal, and the long-polarization-time echo-train signal using a processor to estimate the property; and transmitting a signal comprising the property to a signal receiving device.

NMR T2 distribution from simultaneous T1 and T2 inversions for geologic applications

A method for processing nuclear magnetic resonance (NMR) measurement data includes: receiving, with a processor, NMR measurement data obtained from an NMR tool, the NMR measurement data being affected by a motion artifact and having a first echo train obtained with a long polarization time TWand a second echo train obtained with a short polarization time TWthat is shorter than TW; and at least one of (i) reducing, with a processor, an effect on the NMR measurement data of the motion artifact using the first echo train and the second echo train and (ii) identifying, with a processor, the motion artifact using the first echo train and the second echo train; wherein the motion artifact is related to a magnetic field magnitude that varies in a volume of interest due to a motion of the NMR tool.

The present disclosure is direct to method of performing measurements while drilling in an earth formation. The method may include estimating a location of a seismic reflector using signals from one or more of seismic sensors located at a plurality of locations in a borehole and the drilling depth of the one or more seismic sensors in a borehole. The signals may include information about times when the seismic sensors detect a direct wave and a reflected wave. The method may include storing the information in a memory using a processor.

Method to look ahead of the bit

A downhole tool starts recording seismic energy. During the recording time, a surface seismic source is activated a specified number of times with a nominally defined separation between successive. The downhole sensor receives seismic waves resulting from the activation, but the time of the shooting sequence is not known downhole. The recorded data stream is processed and converted in real-time into seismic traces. A predefined number of traces are stacked and the quality of this sliding stack is used to detect time of the shooting sequence. The method could be used to detect one or several shooting sequences during a measurement window.

Seismic measurements while drilling

A system, method and computer-readable medium for acquiring seismic data, which includes activating a seismic source at a surface location; defining a seismic trace of a seismic wave received at a downhole location on a bottomhole assembly in a borehole in response to the activation of the seismic source; compressing the seismic trace; and recording the compressed seismic trace to a storage medium.

Sending a seismic trace to surface after a vertical seismic profiling while drilling measurement

A drill-bit seismic method where the seismic receivers are located in the BHA. The data detected by these receivers is processed by a downhole processing unit in order to estimate the interval velocity of the seismic wave between the sensors and between the bit and a sensor. Additionally, the processed data might provide the distance to a seismic reflector close to the borehole and the average seismic velocity between the well and this reflector. The processed data can be transmitted to surface location by mud-pulse telemetry. The pilot signal can be also used to process seismic data recorded by receivers located at the earth surface (or close to it).

Drill-bit seismic with downhole sensors

A system for synchronizing components of a downhole system includes: a source assembly including a source clock; an electromagnetic source associated with the source assembly and configured to emit an electromagnetic signal into an earth formation at a transmission time; a receiver assembly including a receiver clock; an electromagnetic receiver associated with the receiver clock and configured to detect the electromagnetic signal; and a processor configured to identify a receipt time of the electromagnetic signal based on the receiver clock and adjust the receiver clock by comparing the transmission time to the receipt time.

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Hannover, Germany

Radu Coman