DETERMINING FORMATION WETTABILITY FROM DIELECTRIC MEASUREMENTS

Formation wettability is quantifiably estimated from measurements of dielectric constant and conductivity. In particular, wettability state of formation rock in a subterranean environment is estimated from multi-frequency measurements of rock dielectric constant and conductivity. A dielectric dispersion model is used to invert the measurements and estimate the saturation exponent. The resulting saturation exponent is used to quantify wettability, e.g., by calculating a wettability index.

Method and device for complex permittivity measurements as a function of frequency

An apparatus for use in a system that includes a network analyzer for determining a property, such as dielectric permittivity of a sample material as a function of frequency, the apparatus including: a cylindrical chamber for receiving the sample; a coaxial connector having a first relatively small diameter end coupleable with the analyzer and a second relatively large diameter end communicating with a side of the cylindrical chamber, the connector having inner and outer coaxial conductors; the inner conductor of the connector having a diameter that tapers outwardly from the first end to the second end, and the outer conductor of the connector having an inner surface whose diameter tapers outwardly from the first end to the second end. The chamber can accommodate relatively large samples, such as standard earth formation coring samples.

Formation modeling while drilling for enhanced high angle for horizontal well placement

LWD measurements to be used for proactive well placement while drilling a high angle or horizontal wellbore in a reservoir are defined. An initial reservoir model is provided and a section is extracted for a planned wellbore trajectory. A secondary model is generated for the planned trajectory. An area of interest is identified where statistical uncertainty is high. Possible causes of the statistical uncertainty are identified that are not present in the initial reservoir model. A set of parameters are defined based on the possible causes of statistical uncertainty. The area of interest is logged with LWD tool. Sensitivities of the LWD tool response to a subset of parameters are evaluated by performing tertiary model for a range of the subset of parameters. The most sensitive parameters from the subset of parameters and corresponding measurements are identified. LWD measurements are defined based on the most sensitive parameters.

Fluid minotiring and flow characterization

A wireline logging tool and method for fluid monitoring and flow characterization in individual zones of controlled salinity is disclosed. The tool and method advantageously facilitate zone-specific testing. Sets of packers are used to create hydraulically distinct zones proximate to the tool. Coiled tubing and isolation valves are used to selectively introduce and remove an electrically conductive fluid such as brine to and from a selected zone. Individual sensors are disposed near each zone to make zone-specific measurements while fluid properties are changed, e.g., while salinity is changed to cause salinity fronts in the formation.

MODIFIED PULSE SEQUENCE TO ESTIMATE PROPERTIES

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties. 1. A method to estimate properties of a material , comprising:measuring exponentially decaying data of the material;determining moments of a variable from the measured exponentially decaying data; anddetermining properties from the moments.2. The method of claim 1 , wherein the determining moments comprises taking weighted linear combinations of the data.3. The method of claim 1 , wherein the measured exponentially decaying comprise nuclear magnetic resonance data.4. The method of claim 1 , wherein the properties of the material comprise petrophysical parameters.5. The method of claim 4 , wherein the petrophysical parameter comprises porosity.6. The method of claim 1 , wherein the properties of the material comprise fluid parameters.7. The method of claim 6 , wherein the fluid parameters comprise the mean chain length and viscosity.8. The method of claim 6 , further comprising the obtaining indication of fluid parameters changes over temperature and pressure and determining phase transitions within the sample from the changes in the fluid parameters.9. The method of claim 1 , further comprising obtaining gas chromatography data from the material and determining from the nuclear magnetic resonance data and the chromatography data properties of the material that relate fluid composition to relaxation or diffusion data.10. The method of claim 1 , further comprising ...

Method and apparatus for electromagnetic logging of a formation

A method and apparatus are disclosed for synthesizing desired antenna responses from a combination of measured antenna responses, as well as antenna arrays particularly suited to provide the measurements. Those arrays may include cross dipole and double cross dipole antennas.

Providing a tow cable having plural electromagnetic receivers and one or more electromagnetic sources

To perform marine electromagnetic (EM) surveying of a subterranean structure, a marine cable system is provided including a tow cable, a plurality of electromagnetic (EM) sources coupled to the tow cable, and a plurality of EM receivers coupled to the tow cable. The system is configured for deployment in a body of water to perform marine EM surveying of a subterranean structure.

Method and device for complex permittivity measurements as a function of frequency

An apparatus for use in a system that includes a network analyzer for determining a property, such as dielectric permittivity of a sample material as a function of frequency, the apparatus including: a cylindrical chamber for receiving the sample; a coaxial connector having a first relatively small diameter end coupleable with the analyzer and a second relatively large diameter end communicating with a side of the cylindrical chamber, the connector having inner and outer coaxial conductors; the inner conductor of the connector having a diameter that tapers outwardly from the first end to the second end, and the outer conductor of the connector having an inner surface whose diameter tapers outwardly from the first end to the second end. The chamber can accommodate relatively large samples, such as standard earth formation coring samples.

System and Method for Imaging Properties of Subterranean Formations

A system and method for imaging properties of subterranean formations in a wellbore is provided. The system comprises a formation sensor for collecting currents injected into the subterranean formations, the formation sensor positionable on a downhole tool deployable into the wellbore. The system comprises a controller for controlling the formation sensor and a formation imaging unit. The formation imaging unit comprises a current management unit for collecting data from the currents injected into the subterranean formations, the currents having at least two different frequencies. The formation imaging unit comprises a drilling mud data unit for determining at least one drilling mud parameter, a formation data unit for determining at least one formation parameter from the collected data, and an inversion unit for determining at least one formation property by inverting the at least one formation parameter. 1. A formation imaging unit for imaging properties of at least one subterranean formation in a wellbore at a wellsite , the formation imaging unit comprising:a current management unit for collecting data from at least two currents injected into the at least one subterranean formation, the at least two currents having at least two different frequencies;a drilling mud data unit for determining at least one drilling mud parameter;a formation data unit for determining at least one formation parameter from the collected data; andan inversion unit for determining at least one formation property by inverting the at least one formation parameter.2. The formation imaging unit of claim 1 , wherein the at least one formation property is determined by inverting the drilling mud parameter and the at least one formation parameter.3. The formation imaging unit of claim 1 , wherein the inversion unit is configured to implement forward modeling to determine at least one formation property.5. The formation imaging unit of claim 3 , wherein the inversion unit is configured to ...

Modified pulse sequence to estimate properties

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

Instrumented formation tester for injecting and monitoring of fluids

An example instrumented formation tester for injecting fluids and monitoring of fluids described herein includes a downhole tool which can be deployed in a wellbore via a wireline or a drill string. The downhole tool may facilitate the injection of fluids into an underground formation, and the monitoring of the directions in which the injected fluids flow in the formation in an open hole environment. In particular, the downhole tool may be configured for removing the mud cake from a portion of the wellbore wall for facilitating a fluid communication with the formation to be tested.

FLUID MINOTIRING AND FLOW CHARACTERIZATION

A wireline logging tool and method for fluid monitoring and flow characterization in individual zones of controlled salinity is disclosed. The tool and method advantageously facilitate zone-specific testing. Sets of packers are used to create hydraulically distinct zones proximate to the tool. Coiled tubing and isolation valves are used to selectively introduce and remove an electrically conductive fluid such as brine to and from a selected zone. Individual sensors are disposed near each zone to make zone-specific measurements while fluid properties are changed, e.g., while salinity is changed to cause salinity fronts in the formation. 1. Apparatus for performing tests on a subterranean formation from a borehole comprising:hydraulic isolators which create a plurality of hydraulically distinct zones when actuated;at least one hydraulic conduit for introducing fluid to the hydraulically distinct zones;at least one pressure sensor; anda plurality of electrical or electromagnetic sensors for obtaining measurements of formation responses adjacent to ones of the hydraulically distinct zones as fluids of different conductivity are introduced to those hydraulically distinct zones via the at least one hydraulic conduit.2. The apparatus of further including at least one flow sensor for measuring flow of fluid into the formation.3. The apparatus of further including at least one temperature sensor for measuring temperature of fluid flowing into the formation.4. The apparatus of wherein the electrical or electromagnetic sensors include electrodes disposed in contact with the formation while fluids of different salinity are injected into an adjacent hydraulically distinct zone.5. The apparatus of wherein the hydraulic isolators include packers.6. The apparatus of wherein the sensors include overlapping sectored electrode ring sensors disposed on the packers.7. The apparatus of wherein the electrode rings are segmented in order to acquire azimuthally varying data.8. The apparatus ...

TORSIONAL WAVE LOGGING

A method for torsional wave logging in a borehole of a subterranean formation. The method includes obtaining a torsional wave measurement of the borehole, wherein the torsional wave measurement represents characteristics of a torsional wave propagating within a cylindrical layered structure associated with the borehole, wherein the cylindrical layered structure comprises the subterranean formation and a completion of the borehole, analyzing, by a computer processor, the torsional wave measurement to generate a quality measure of the completion, and displaying the quality measure of the completion.

Method and apparatus for electromagnetic logging of a formation

A method and apparatus are disclosed for synthesizing desired antenna responses from a combination of measured antenna responses, as well as antenna arrays particularly suited to provide the measurements. Those arrays may include cross dipole and double cross dipole antennas.

Instrumented formation tester for injecting and monitoring of fluids

DEEP-READING ELECTROMAGNETIC DATA ACQUISITION METHOD

A method of measuring a parameter characteristic of a rock formation is provided, the method including the steps of obtaining crosswell electromagnetic signals between two wells and using an inversion of said signals to investigate or delineate the presence of a resistivity anomaly, such as brine in a low resistivity background, wherein the resistivity anomaly is assumed to be distributed as one or more bodies characterized by a limited number of geometrical parameters and the inversion is used to determine said geometrical parameters. The method can also be applied to determine the trajectory of an in-fill well to be drilled.

PROVIDING A TOW CABLE HAVING PLURAL ELECTROMAGNETIC RECEIVERS AND ONE OR MORE ELECTROMAGNETIC SOURCES

To perform marine electromagnetic (EM) surveying of a subterranean structure, a marine cable system is provided including a tow cable, a plurality of electromagnetic (EM) sources coupled to the tow cable, and a plurality of EM receivers coupled to the tow cable. The system is configured for deployment in a body of water to perform marine EM surveying of a subterranean structure.

PROVIDING A TOW CABLE HAVING PLURAL ELECTROMAGNETIC RECEIVERS AND ONE OR MORE ELECTROMAGNETIC SOURCES

To perform marine electromagnetic (EM) surveying of a subterranean structure, a marine cable system is provided including a tow cable, a plurality of electromagnetic (EM) sources coupled to the tow cable, and a plurality of EM receivers coupled to the tow cable. The system is configured for deployment in a body of water to perform marine EM surveying of a subterranean structure. 1. A method of characterizing a subsurface marine environment , comprising:deploying a surveying assembly in a body of water, said surveying assembly comprising a tow cable, one or more streamers coupled to the tow cable, a plurality of EM sources and a plurality of EM receivers coupled to each streamer;activating at least one of the EM sources; andin response to activation of the at least one EM source, acquiring measurement data from the EM receivers.2. The method according to claim 1 , further comprising:determining one or more bucking coefficients based on the received measurement data; andattenuating one or more target signal components with the bucking coefficients at the EM receivers.3. The method according to claim 1 , wherein the measurement data comprises at least one of 1) measurement data surveyed in a calibration region lacking a target body of interest claim 1 , and 2) a model.4. The method according to claim 1 , further comprising:determining weighting for application to the measurement data; andbased on the weighting, focusing measurement of measurement data to a target depth in the subsurface marine environment.5. The method according to claim 4 , wherein determining the weighting comprises computing weights such that a sum of weighted measurements peaks at a location in the subsurface marine environment at the target depth in the subsurface marine environment.6. The method according to claim 4 , further comprising directly estimating conductivity of the subsurface marine environment at the target depth based on the focused claim 4 , weighted measurement data.7. The method ...

AUTOMATED FIELD DEVELOPMENT PLANNING

A system for automatically optimizing a Field Development Plan (FDP) for an oil or gas field uses a fast analytic reservoir simulator to dynamically model oil or gas production from the entire reservoir over time in an accurate and rapid manner. An objective function defining a Figure of Merit (FoM) for candidate FDPs is maximized, using an optimization algorithm, to determine an optimized FDP in light of physical, engineering, operational, legal and engineering constraints. The objective function for the Figure of Merit, e.g., net present value (NPV) or total production for a given period of time, relies on a production forecast from the fast analytic reservoir simulator for the entire FDP. The position, orientation and dimensions of analytical model elements for the subsurface oil or gas field, as well as the physical properties associated with these elements, correlate to connected flow volume data from a Shared Earth Model (SEM). Uncertainty in the SEM is considered via stochastic sampling ...

Fluid monitoring and flow characterization

A wireline logging tool and method for fluid monitoring and flow characterization in individual zones of controlled salinity is disclosed. The tool and method advantageously facilitate zone-specific testing. Sets of packers are used to create hydraulically distinct zones proximate to the tool. Coiled tubing and isolation valves are used to selectively introduce and remove an electrically conductive fluid such as brine to and from a selected zone. Individual sensors are disposed near each zone to make zone-specific measurements while fluid properties are changed, e.g. while salinity is changed to cause salinity fronts in the formation.

System and Method for Deep Formation Evaluation

A technique facilitates formation evaluation by deploying tools in a subterranean environment. A logging tool is deployed in a wellbore to obtain formation related measurements. Additionally, one or more mobile robots also are positioned in the subterranean environment at unique positions that facilitate accumulation of data related to the formation. The data obtained from the logging tool and the one or more mobile robots is processed in a manner that enables deep formation evaluation.

Determining formation wettability from dielectric measurements

Formation wettability is quantifiably estimated from measurements of dielectric constant and conductivity. In particular, wettability state of formation rock in a subterranean environment is estimated from multi-frequency measurements of rock dielectric constant and conductivity. A dielectric dispersion model is used to invert the measurements and estimate the saturation exponent. The resulting saturation exponent is used to quantify wettability, e.g., by calculating a wettability index.

Efficiency of Pixel-Based Inversion Algorithms

A method of estimating formation parameters in a directional drilling process by acquiring electromagnetic logging while drilling (LWD) measurements over a non-uniform forward modeling grid and inverting, using a pixel-based inversion method, the LWD measurements over a uniform inversion grid. The inversion algorithm may be applied using a sliding window scheme that allows the formation parameters to be estimated independently and in parallel across a plurality of overlapping windows which span the entirety of the inversion grid. 1. A method of estimating a formation parameter in a borehole of a subterranean formation , comprising:estimating the formation parameter on a uniform inversion grid by applying a pixel-based inversion algorithm to measurements of the formation on a non-uniform forward modeling grid; anddisplaying the formation parameter as a spatial distribution of a survey area.2. The method of claim 1 , further comprising:acquiring the measurements from a LWD tool comprising a source and a receiver.3. The method of claim 1 , further comprising selecting a resolution of the uniform inversion grid to match a resolution measurement.4. The method of claim 1 , further comprising:interpolating, using an interpolation scheme, to map a field distribution from the non-uniform forward modeling grid to the uniform inversion grid.5. The method of claim 2 , wherein the non-uniform forward modeling grid comprises a fine spatial discretization at a near-field distance with respect to the LWD tool and a coarse spatial discretization at a far-field distance with respect to the LWD tool.6. The method of claim 2 , wherein the source is an electromagnetic source.7. The method of claim 1 , wherein the uniform inversion domain comprises a plurality of sub-domains having a first and a second sub-domain;8. The method of claim 7 , further comprising:generating a formation parameter model by estimating the formation parameter for each of the plurality of sub-domains and merging ...

Apparatus and methods for measuring formation characteristics in presence of conductive and non-conductive muds

Tools for investigating an earth formation in the presence of either oil-base or water-base mud include a circuit which induces current into the formation in a focused manner, and a sensor electrode which is isolated from the circuit, at least partially surrounded by the circuit, and located in the area in which the current is focused. The current inducing circuit may be an oppositely polarized double-dipole circuit to which voltage is applied with the two dipoles sharing a common radiating element over which a focused area is formed. Insulators separate the outer electrodes of the double-dipole circuit from the common radiating element. Alternatively, the current inducing circuit is a coil arranged in a partial toroidal configuration in an insulated area that at least partially surrounds the focused area and which separates the focused area from return electrodes.

Estimations of nuclear magnetic resonance measurement distributions

A nuclear magnetic resonance (NMR) related distribution is estimated that is consistent with NMR measurements and uses linear functionals directly estimated from the measurement indications by integral transforms as constraints in a cost function. The cost function includes indications of the measurement data, Laplace transform elements and the constraints, and a distribution estimation is made by minimizing the cost function. The distribution estimation may be used to find parameters of the sample. Where the sample is a rock or a formation, the parameters may include parameters such as rock permeability and/or hydrocarbon viscosity, bound and free fluid volumes, among others. The parameters may be used in models, equations, or otherwise to act on the sample, such as in recovering hydrocarbons from the formation.

METHOD AND APPARATUS FOR ELECTROMAGNETIC LOGGING OF A FORMATION

A method and apparatus are disclosed for synthesizing desired antenna responses from a combination of measured antenna responses, as well as antenna arrays particularly suited to provide the measurements. Those arrays may include cross dipole and double cross dipole antennas.

Apparatus and methods for measuring formation characteristics in presence of conductive and non-conductive muds

Tools for investigating an earth formation in the presence of either oil-base or water-base mud are provided and includes a circuit which induces current into the formation in a focused manner, and a sensor electrode which is isolated from the circuit, at least partially surrounded by the circuit, and located in the area in which the current is focused. The current inducing circuit may be an oppositely polarized double-dipole circuit to which voltage is applied with the two dipoles sharing a common radiating element over which a focused area is formed. Insulators are provided that separate the outer electrodes of the double-dipole circuit from the common radiating element. Alternatively, the current inducing circuit is a coil arranged in a partial toroidal configuration in an insulated area that at least partially surrounds the focused area and which separates the focused area from return electrodes.

MODIFIED PULSE SEQUENCE TO ESTIMATE PROPERTIES

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

MODIFIED PULSE SEQUENCE TO ESTIMATE PROPERTIES

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

Providing a tow cable having plural electromagnetic receivers and one or more electromagnetic sources

To perform marine electromagnetic (EM) surveying of a subterranean structure, a marine cable system is provided including a tow cable, a plurality of electromagnetic (EM) sources coupled to the tow cable, and a plurality of EM receivers coupled to the tow cable. The system is configured for deployment in a body of water to perform marine EM surveying of a subterranean structure.

Methods and Apparatus to Process Time Series Data for Propagating Signals in A Subterranean Formation

Methods and apparatus to process time series data for propagating signals in a subterranean formation are disclosed. An example method described herein for processing measured data comprises receiving a time series of measured data obtained by sensing a propagating signal, the propagating signal having passed through a subterranean formation, transforming the time series of measured data to generate a time-frequency representation of the time series, and processing the time-frequency representation to at least one of reduce noise in the time frequency representation, or enhance a component of the propagating signal present in the time-frequency representation. 1. A method for processing measured data , comprising:receiving a time series of measured data obtained by sensing a propagating signal, the propagating signal having passed through a subterranean formation;transforming the time series to generate a time-frequency representation of the time series; andprocessing the time-frequency representation to at least one of reduce noise in the time frequency representation, or enhance a component of the propagating signal present in the time-frequency representation.2. A method as defined in claim 1 , wherein the time series of measured data is obtained by sensing the propagating signal using at least two receivers.3. A method as defined in claim 1 , wherein transforming the time series of measured data comprises performing at least one of a wavelet transform claim 1 , a Wigner Wille transform or a short time Fourier transform on the time series of measured data to generate the time-frequency representation.4. A method as defined in claim 1 , wherein processing the time-frequency representation comprises stacking a plurality of time-frequency representations generated for a respective plurality of time series of measured data corresponding to a respective plurality of propagating signals generated by successive firings of a source.5. A method as defined in claim 4 , ...

Multilevel workflow method to extract resistivity anisotropy data from three-dimensional induction measurements

A multi-step electromagnetic inversion method is provided for determining formation resistivity, anisotropy and dip. An electromagnetic logging tool is used to obtain non-directional, anisotropy, and directional (including symmetrized and anti-symmetrized resistivity measurements) in a formation using an electromagnetic logging tool. Bed boundaries of the formation are first identified. A horizontal resistivity profile is obtained using the non-directional resistivity measurements, and a vertical resistivity profile is obtained using the anisotropy resistivity measurements. The vertical resistivity profile is improved using the directional resistivity measurements, while dip values are also obtained via an inversion using the directional resistivity measurements. Then, an inversion for each of vertical resistivity, horizontal resistivity, dip values, and bed boundaries is performed using all of the non-directional, anisotropy, and directional resistivity measurements to obtain a formation ...

Instrumented formation tester for injecting and monitoring of fluids

An example instrumented formation tester for injecting fluids and monitoring of fluids described herein includes a downhole tool which can be deployed in a wellbore via a wireline or a drill string. The downhole tool may facilitate the injection of fluids into an underground formation, and the monitoring of the directions in which the injected fluids flow in the formation in an open hole environment. In particular, the downhole tool may be configured for removing the mud cake from a portion of the wellbore wall for facilitating a fluid communication with the formation to be tested.

MODIFIED PULSE SEQUENCE TO ESTIMATE PROPERTIES

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties. 1. A method of estimating a property of a material using nuclear magnetic resonance (NMR) , the method comprising:inducing a measurable change in the material using an NMR pulse;after a predetermined time interval, making a measurement of a material response to the induction using NMR, wherein the material response exponentially decays following the induction;repeating the inducing and the measuring at non-uniform predetermined time intervals, wherein the non-uniform predetermined time intervals are determined based on the property to be estimated; andestimating the property based at least in part on the measurements of the exponentially decaying material response.2. A method according to wherein the NMR pulse is a transverse magnetic pulse.3. A method according to wherein the predetermined time intervals are non-uniform in both linear and logarithmic scales.4. A method according to wherein the non-uniform predetermined time intervals follow a power law.5. A method according to wherein the non-uniform predetermined time intervals allow for the property to be directly computed from the measurements of the exponentially decaying material response.6. A method according to wherein the measurements are performed as part of one or more oilfield services.7. A method according to wherein the measurements are made downhole.8. A method according to wherein the material is ...

System and Method for Imaging Properties of Subterranean Formations

A system and method for imaging properties of subterranean formations in a wellbore is provided. The system comprises a formation sensor for collecting currents injected into the subterranean formations, the formation sensor positionable on a downhole tool deployable into the wellbore. The system comprises a controller for controlling the formation sensor and a formation imaging unit. The formation imaging unit comprises a current management unit for collecting data from the currents injected into the subterranean formations, the currents having at least two different frequencies. The formation imaging unit comprises a drilling mud data unit for determining at least one drilling mud parameter, a formation data unit for determining at least one formation parameter from the collected data, and an inversion unit for determining at least one formation property by inverting the at least one formation parameter. 1. A formation imaging unit for imaging properties of at least one subterranean formation in a wellbore at a wellsite , the formation imaging unit comprising:a current management unit for collecting data from at least two currents injected into the at least one subterranean formation, the at least two currents having at least two different frequencies;a drilling mud data unit for determining at least one drilling mud parameter;a formation data unit for determining at least one formation parameter from the collected data; andan inversion unit configured to determine at least one of a drilling mud property and a formation property based on an inversion of the at least one drilling mud parameter or an inversion of the at least one formation parameter.2. The formation imaging unit of claim 1 , wherein the inversion unit is configured to determine at least one drilling mud property and at least one formation property based on an inversion of data from the drilling mud unit or an inversion of data from the formation data unit.3. The formation imaging unit of claim 1 , ...

Method and apparatus for electromagnetic logging of a formation

Using an electromagnetic logging tool, desired antenna responses are synthesized from a combination of measured antenna responses, as well as antenna arrays particularly suited to provide the measurements. Those arrays may include cross dipole and double cross dipole antennas. Direct and derivative responses are used to synthesize the desired response, and the synthesized desired response is used to determine formation properties.

TORSIONAL WAVE LOGGING

A method for torsional wave logging in a borehole of a subterranean formation. The method includes obtaining a torsional wave measurement of the borehole, wherein the torsional wave measurement represents characteristics of a torsional wave propagating within a cylindrical layered structure associated with the borehole, wherein the cylindrical layered structure comprises the subterranean formation and a completion of the borehole, analyzing, by a computer processor, the torsional wave measurement to generate a quality measure of the completion, and displaying the quality measure of the completion. 1. A method for torsional wave logging in a borehole of a subterranean formation , comprising:obtaining a torsional wave measurement of the borehole, wherein the torsional wave measurement represents characteristics of a torsional wave propagating within a cylindrical layered structure associated with the borehole, wherein the cylindrical layered structure comprises the subterranean formation and a completion of the borehole;analyzing, by a computer processor, the torsional wave measurement to generate a quality measure of the completion; anddisplaying the quality measure of the completion.2. The method of claim 1 , further comprising:performing a field operation based at least on the quality measure of the completion.3. The method of claim 1 , further comprising:detecting, based on the quality measure of the completion, a pre-determined failure of the completion; andgenerating, in response to detecting the pre-determined failure, an alert.4. The method of claim 1 , analyzing, using a pre-determined algorithm, the torsional wave measurement to generate a modal spectrum, wherein the modal spectrum comprises a completion quality dependent parameter of the torsional wave as a function of a frequency of the torsional wave, wherein the modal spectrum corresponds to a pre-determined wave mode of a plurality of wave modes of the torsional wave; and', 'analyzing, based on a pre- ...

Determination of downhole pressure while pumping

Tubewaves are used to transmit an indication of the depth at which a condition is detected in a well. In particular, the depth is calculated based on the difference in arrival time at the surface of a first tubewave which propagates directly upward in the borehole and a second tubewave which initially travels downward and is then reflected upward. The tubewaves may be generated by a canister designed to implode at a certain pressure. The canister is carried downhole by gravity and the fluid being pumped. At a depth at which its pressure tolerance is exceeded, it implodes and generates the tubewaves. An analyzer at the surface detects the tubewaves and generates a pressure versus depth profile of the well. Canisters may be acoustically tagged in order to generate tubewaves having particular frequency and amplitude characteristics. Canisters may also be configured to produce multiple implosions.

Wireless logging of fluid filled boreholes

A value of a property of a fluid-filled wellbore system can be detected. This can be accomplished by recording data including at least one of pressure and rate of flow at one or more locations in the wellbore system, and then estimating the value of the property by employing a model for predicting at least one of pressure and rate of flow dependent upon characteristics and locations of disturbances to pressure and flow in the wellbore system, in order to determine a best prediction of some attribute of the recorded data.

Method for calculating a distance between a well logging instrument and a formation boundary by inversion processing measurements from the logging instrument

A method is disclosed for determining a position of a wellbore with respect to layer boundaries in earth formations. The method includes projecting a trajectory of the wellbore onto an initial model of the earth formations, selecting a segment of the trajectory and calculating along the segment expected responses of a well logging instrument. Differences between the expected responses and responses measured by the instrument along the segment are determined. The model is adjusted, the expected responses are recalculated and the differences are again determined. These are repeated until the differences fall below a selected threshold. In one embodiment, the trajectory of the wellbore can be adjusted to remain within a selected distance of a selected one of the layer boundaries.

INVERSION-BASED WORKFLOW FOR PROCESSING NUCLEAR DENSITY IMAGES IN HIGH-ANGLE AND HORIZONTAL WELLS

Methods and apparatus for characterizing a subterranean formation traversed by a wellbore including collecting data from the formation using a tool wherein the tool collects data to form an azimuthal image, characterizing a section of the formation comprising data and images acquired in a high angle wellbore section or horizontal wellbore section using a parametric model, and performing an inversion using apparent densities and volumetric photoelectric factor images to build a formation model wherein the inversion is tailored for high angle wellbore sections and/or horizontal wellbore sections.

Multilevel Workflow Method To Extract Resistivity Anisotropy Data From Three-Dimensional Induction Measurements

A multi-step electromagnetic inversion method is provided for determining formation resistivity, anisotropy and dip. An electromagnetic logging tool is used to obtain non-directional, anisotropy, and directional (including symmetrized and anti-symmetrized resistivity measurements) in a formation using an electromagnetic logging tool. Bed boundaries of the formation are first identified. A horizontal resistivity profile is obtained using the non-directional resistivity measurements, and a vertical resistivity profile is obtained using the anisotropy resistivity measurements. The vertical resistivity profile is improved using the directional resistivity measurements, while dip values are also obtained via an inversion using the directional resistivity measurements. Then, an inversion for each of vertical resistivity, horizontal resistivity, dip values, and bed boundaries is performed using all of the non-directional, anisotropy, and directional resistivity measurements to obtain a formation model. 1. A system comprising:an electromagnetic logging tool having transmitter and receiver antennas oriented as a longitudinal magnetic dipole and at least one of a tilted magnetic dipole or a transverse magnetic dipole, wherein the electromagnetic logging tool is capable of making dipole sensitive electromagnetic measurements within a surface formation; and (a) determining formation layer boundaries and horizontal resistivities of the formation layers based upon longitudinal magnetic dipole measurements obtained using the electromagnetic logging tool;', '(b) determining vertical resistivities of the formation layers based upon anisotropy sensitive electromagnetic measurements obtained using the electromagnetic logging tool;', '(c) inverting the symmetrized and anti-symmetrized electromagnetic measurements obtained using the electromagnetic logging tool to update the vertical resistivities of the formation layers obtained at (b) to obtain improved vertical resistivities of the ...

Pixel based inversion method for surface electromagnetic measurement

A method of determining the nature of a submarine or subterranean reservoir having an electromagnetic characteristic is described. The method comprises analyzing data associated with the application of a time varying electromagnetic field from above the reservoir using a data analysis methodology that does not utilize an estimate of the reservoir's geometry in determining one or more characteristics of the reservoir.

INSTRUMENTED FORMATION TESTER FOR INJECTING AND MONITORING OF FLUIDS

An example instrumented formation tester for injecting fluids and monitoring of fluids described herein includes a downhole tool which can be deployed in a wellbore via a wireline or a drill string. The downhole tool may facilitate the injection of fluids into an underground formation, and the monitoring of the directions in which the injected fluids flow in the formation in an open hole environment. In particular, the downhole tool may be configured for removing the mud cake from a portion of the wellbore wall for facilitating a fluid communication with the formation to be tested.

Well testing using multiple pressure measurements

A technique includes measuring a first pressure of well fluid in a first region. The well fluid is produced from a formation into the first region. A second pressure of well fluid is measured in a second region. The second region is isolated from the first region, and the well fluid in the second region is in communication with the formation characteristics (skin, horizontal permeability or vertical permeability, as examples) of the formation is determined from the first and second measured pressures.

Automated field development planning

A system for automatically optimizing a Field Development Plan (FDP) for an oil or gas field uses a fast analytic reservoir simulator to dynamically model oil or gas production from the entire reservoir over time in an accurate and rapid manner. An objective function defining a Figure of Merit (FoM) for candidate FDPs is maximized, using an optimization algorithm, to determine an optimized FDP in light of physical, engineering, operational, legal and engineering constraints. The objective function for the Figure of Merit, e.g., net present value (NPV) or total production for a given period of time, relies on a production forecast from the fast analytic reservoir simulator for the entire FDP.

ESTIMATION OF PETROPHYSICAL AND FLUID PROPERTIES USING INTEGRAL TRANSFORMS IN NUCLEAR MAGNETIC RESONANCE

Apparatus and method of characterizing a subterranean formation including observing a formation using nuclear magnetic resonance measurements, calculating an answer product by computing an integral transform on the indications in measurement-domain, and using answer products to estimate a property of the formation. Apparatus and a method for characterizing a subteranean formation including collecting NMR data of a formation, calculating an answer product comprising the data, wherein the calculating comprises a formula 1. A method of characterizing a subterranean formation , comprising:observing a formation using nuclear magnetic resonance measurements; 'using answer products to estimate a property of the formation.', 'calculating an answer product by computing an integral transform on the indications in measurement-domain; and'}2. The method of claim 1 , further comprising calculating integral transform by computing a function k(t) for a desired K(T).4. The method of claim 3 , wherein x is a function of T claim 3 , Trelaxation or diffusion.5. The method of claim 1 , wherein the measurement domain comprises the time domain.6. The method of claim 1 , further comprising computing K(T) using a closed-form analytical solution.7. The method of claim 1 , further comprising computing K(T) using a closed-form numerical solution.8. The method of claim 1 , further comprising computing K(T) using a closed-form solution using method of successive approximations.9. The method of claim 1 , further comprising K(T) using a convolution property.10. The method of claim 1 , wherein the NMR measurements are de-noised before processing.11. The method of claim 1 , wherein an answer product uncertainty can be quantified as a function of the signal-to-noise ratio (SNR) of the measurements.12. The method of claim 1 , further comprising combining functions using a convolution property.13. The method of claim 1 , wherein the measurements are data that are either fully or partially polarized.14 ...

IINTEGRATING RESERVOIR MODELING WITH MODELING A PERTURBATION

A method for characterizing a subterranean formation traversed by a wellbore includes generating a reservoir model using data collected from the formation, generating a perturbation object comprising a perturbation of the wellbore, integrating the perturbation object with the reservoir model, and forming a geological model wherein the perturbation object is integrated in the reservoir model. 1. A method for characterizing a subterranean formation traversed by a borehole , comprising:generating a reservoir model using data describing the formation;generating a perturbation object representing a perturbation of the wellbore;integrating the perturbation object with a geological model; andforming the reservoir model with the perturbation object integrated with the geological model into the reservoir model.2. The method of claim 1 , wherein the perturbation object is an invasion object claim 1 , and wherein the perturbation is an invasion.3. The method of claim 1 , wherein the perturbation object is a borehole object claim 1 , and wherein the perturbation is a shape change of a borehole.4. The method of claim 1 , further comprising:modifying the perturbation object while forming the reservoir model or modifying the data or both.5. The method of claim 1 ,wherein the data is log data gathered while drilling the borehole or after drilling the borehole or both, andwherein integrating the perturbation object with the geological model comprises calculating, from the log data, revised log data accounting for the perturbation.6. The method of claim 1 , wherein integrating the perturbation object with the geological model further comprises:revising a geometry and a physical property of the perturbation object using well logs or images or both.7. The method of claim 1 , wherein integrating the perturbation object with the geological model further comprises:revising a geometry and a physical property of the perturbation object using simulation or inversion of well logs or images or ...

Estimations of nuclear magnetic resonance measurement distributions

A nuclear magnetic resonance (NMR) related distribution is estimated that is consistent with NMR measurements and uses linear functionals directly estimated from the measurement indications by integral transforms as constraints in a cost function. The cost function includes indications of the measurement data, Laplace transform elements and the constraints, and a distribution estimation is made by minimizing the cost function. The distribution estimation may be used to find parameters of the sample. Where the sample is a rock or a formation, the parameters may include parameters such as rock permeability and/or hydrocarbon viscosity, bound and free fluid volumes, among others. The parameters may be used in models, equations, or otherwise to act on the sample, such as in recovering hydrocarbons from the formation.

METHODS FOR DETERMINING A VOLUME FRACTION OF WATER AND WATER SALINITY IN ORGANIC SHALE RESERVOIRS USING MULTI-FREQUENCY DIELECTRIC WELL LOGGING MEASUREMENTS

The subject disclosure relates to a method for determining a volume fraction of water and water salinity in organic shales and other geological formations. The method includes a knowledge of complex formation permittivity at several frequencies and minimizes or excludes dependency on external parameters, such as the permittivity of the formation mineral phase. 1. A method for characterizing a geological formation , comprising:using a downhole logging device to perform multifrequency electromagnetic measurements of the formation;determining a plurality of complex permittivities of the formation at a plurality of frequencies from the multifrequency electromagnetic measurements;determining a plurality of complex permittivities of water in the formation at the plurality of frequencies from the multifrequency electromagnetic measurements; anddetermining a value of at least one formation parameter from the plurality of complex permittivities of the formation and the plurality of complex permittivities of water in the formation, wherein the at least one formation parameter is selected from the group consisting of water-filled porosity of the formation, water salinity, water saturation, tortuosity of water-filled pore space, and combinations thereof.2. The method of claim 1 , wherein:the plurality of complex permittivities of the formation, the plurality of complex permittivities of water in the formation and the value of the at least one formation parameter are determined by a processor.3. The method of claim 1 , wherein:the formation comprises organic shale; andthe value of the at least one formation parameter is determined from the plurality of complex permittivities of the formation and the plurality of complex permittivities of water in the formation without determining or providing as input information characterizing mineralogy and hydrocarbon content including kerogen of the formation.4. The method of claim 1 , wherein:the at least one formation parameter comprises ...

Methods of Investigating Formation Samples Using NMR Data

A methods are provided for investigating a sample containing hydrocarbons by subjecting the sample to a nuclear magnetic resonance (NMR) sequence using NMR equipment, using the NMR equipment to detect signals from the sample in response to the NMR sequence, analyzing the signals to extract a distribution of relaxation times (or diffusions), and computing a value for a parameter of the sample as a function of at least one of the relaxation times (or diffusions), wherein the computing utilizes a correction factor that modifies the value for the parameter as a function of relaxation time for at least short relaxation times (or as a function of diffusion for at least large diffusion coefficients). 1. A method of investigating a sample , comprising:a) subjecting the sample to a nuclear magnetic resonance (NMR) sequence using NMR equipment;b) using the NMR equipment to detect signals from the sample in response to the NMR sequence;c) analyzing a decay of the signals to extract a distribution of relaxation times or diffusion coefficients; andd) computing a value for a parameter of the sample as a function of at least one of said relaxation times or diffusion coefficients, wherein said computing utilizes a correction factor that modifies the value for the parameter as a function of either the relaxation time for at least short relaxation times or the diffusion coefficient for large diffusion coefficients.2. A method according to claim 1 , wherein:said parameter is porosity.3. A method according to claim 2 , wherein:{'sub': '2', 'said distribution of relaxation times or diffusions is a distribution of Trelaxation times.'}4. A method according to claim 3 , wherein:{'sub': '2', 'said correction factor is a function of a normalized bias B(T) of said NMR equipment.'}5. A method according to claim 4 , wherein:{'sub': f', '2', '2, 'said correction factor c(T)=1/(1+B(T)).'}8. A method according to claim 7 , wherein:{'sub': 2', '2, 'said correction factor tends to a value of 1 for a ...

JOINT INVERSION OF DOWNHOLE TOOL MEASUREMENTS

A method includes acquiring measurement values from at least two different types of downhole tools disposed in a portion of a bore in a formation; selecting formation parameters for joint inversion; building a near-bore fluid flow model of at least a portion of the formation that includes at least the portion of the bore; simulating fluid flow based at least in part on the near-bore fluid flow model and the selected formation parameters to generate simulated measurement values; comparing the acquired measurement values and the simulated measurement values; based at least in part on the comparing, revising at least one of the selected formation parameters to generate revised formation parameters and simulating fluid flow based at least in part on the near-bore fluid flow model and the revised formation parameters to generate revised simulated measurement values; and outputting at least the revised formation parameters to characterize the formation. 1. A method comprising:acquiring measurement values from at least two different types of downhole tools disposed in a portion of a bore in a formation;selecting formation parameters for joint inversion;building a near-bore fluid flow model of at least a portion of the formation that comprises at least the portion of the bore;simulating fluid flow based at least in part on the near-bore fluid flow model and the selected formation parameters to generate simulated measurement values;comparing the acquired measurement values and the simulated measurement values;based at least in part on the comparing, revising at least one of the selected formation parameters to generate revised formation parameters and simulating fluid flow based at least in part on the near-bore fluid flow model and the revised formation parameters to generate revised simulated measurement values; andoutputting at least the revised formation parameters wherein the revised formation parameters characterize the formation.2. The method of wherein the formation ...

Inversion Techniques For Real-Time Well Placement And Reservoir Characterization

A method is disclosed herein. The method includes disposing an electromagnetic logging tool in a borehole penetrating a formation, the electromagnetic logging tool being part of a drill string in the formation, the drill string having a drill bit. The method includes acquiring measurements using the electromagnetic logging tool. Further, the method includes using a processor, applying a pixel-based inversion to the acquired measurements to determine at least one formation property, wherein applying the pixel-based inversion includes using adaptive regularization. 1. A method , comprising:disposing an electromagnetic tool in a borehole penetrating a formation, the electromagnetic logging tool being part of a drill string in the formation, the drill string comprising a drill bit;acquiring measurements using the electromagnetic logging tool; andusing a processor, applying a pixel-based inversion to the acquired measurements to determine at least one formation property, wherein applying the pixel-based inversion comprises using adaptive regularization.2. The method of claim 1 , wherein the adaptive regularization comprises at least one of Occam's inversion claim 1 , L-curve claim 1 , or generalized cross-validation.3. The method of claim 1 , wherein the at least one formation property comprises at least one of a distribution of layer resistivities for the formation claim 1 , a horizontal resistivity claim 1 , a vertical resistivity claim 1 , or a dip angle.4. The method of claim 1 , wherein the acquired measurements include directional measurements and non-directional measurements at a plurality of spacings.5. The method of claim 1 , comprising steering the drill bit based at least partially on the determined formation property.6. The method of claim 1 , wherein the electromagnetic tool is a wireline tool.7. The method of claim 1 , wherein the electromagnetic tool is a logging while drilling (LWD).8. The method of claim 1 , wherein the electromagnetic tool is a ...

Permeability determinations from wideband em models using borehole logging tools

A permeability log is generated by running borehole tools in a borehole traversing a formation, including at least electromagnetic (EM) tool providing at least a low-frequency complex conductivity measurement at at least one frequency. Data from the EM tool and other data obtained from other tools are provided to a wideband EM model, where a data inversion is conducted to provide a plurality of outputs from which a cementation exponent may be calculated. The cementation exponent is used to find a formation factor at each depth of interest in the borehole, and the formation factor is used to find a permeability value which is used for the permeability log. The permeability log may be generated without the use of core data.

METHODS AND SYSTEMS EMPLOYING LOOK-AROUND AND LOOK-AHEAD INVERSION OF DOWNHOLE MEASUREMENTS

Inversion-based workflows are provided for real-time interpretation of the electromagnetic (EM) look-around and look-ahead measurements. The profile of a look-around zone is determined by interpreting EM measurements of a look-around zone. The profile of the look-around zone characterizes formation dip as well as vertical resistivity or resistivity anisotropy of one or more formation layers of the look-around zone. The profile of a look-ahead zone is determined by interpreting EM measurements of the look-ahead zone. The profile of the look-ahead zone characterizes formation dip as well as horizontal resistivity, vertical resistivity or anisotropy of one or more formation layers of the look-ahead zone. The workflows can also involve interpretation of look-around resistivity measurements to aid in the characterization of the look-around zone. 1. A method of characterizing a geological formation traversed by a wellbore while drilling the wellbore using an electromagnetic (EM) tool , the method comprising:operating the electromagnetic tool to acquire EM measurements of a look-around zone of the formation and a look-ahead zone of the formation;determining a profile of the look-around zone by interpreting the EM measurements of the look-around zone, wherein the profile of the look-around zone characterizes at least formation dip as well as vertical resistivity or resistivity anisotropy of one or more formation layers of the look-around zone; anddetermining a profile of the look-ahead zone by interpreting EM measurements of the look-ahead zone, wherein the profile of the look-ahead zone characterizes at least formation dip as well as horizontal resistivity and vertical resistivity or resistivity anisotropy of one or more formation layers of the look-ahead zone.2. The method of claim 1 , further comprising:updating a reservoir model of the look-around zone based on the profile of the look-around zone.3. The method of claim 1 , further comprising:controlling operation of a ...

Inversion-based workflow for processing nuclear density images in high-angle and horizontal wells

Methods and apparatus for characterizing a subterranean formation traversed by a wellbore including collecting data from the formation using a tool wherein the tool collects data to form an azimuthal image, characterizing a section of the formation comprising data and images acquired in a high angle wellbore section or horizontal wellbore section using a parametric model, and performing an inversion using apparent densities and volumetric photoelectric factor images to build a formation model wherein the inversion is tailored for high angle wellbore sections and/or horizontal wellbore sections.

Methods of investigating formation samples using nmr data

A methods are provided for investigating a sample containing hydrocarbons by subjecting the sample to a nuclear magnetic resonance (NMR) sequence using NMR equipment, using the NMR equipment to detect signals from the sample in response to the NMR sequence, analyzing the signals to extract a distribution of relaxation times (or diffusions), and computing a value for a parameter of the sample as a function of at least one of the relaxation times (or diffusions), wherein the computing utilizes a correction factor that modifies the value for the parameter as a function of relaxation time for at least short relaxation times (or as a function of diffusion for at least large diffusion coefficients).

Methods for Interpretation of Time-Lapse Borehole Seismic Data for Reservoir Monitoring

A method for analyzing a reservoir parameter, the method including obtaining baseline borehole seismic (BHS) measurements and monitor BHS measurements, calculating, by a processor, a baseline velocity model from the baseline BHS measurements, calculating, by the processor, a monitor velocity model from the monitor BHS measurements, and determining a model change in the reservoir parameter by comparing the baseline velocity model and the monitor velocity model. 1. A method for analyzing a reservoir parameter , the method comprising:obtaining baseline borehole seismic (BHS) measurements and monitor BHS measurements;calculating a baseline velocity model from the baseline BHS measurements;calculating a monitor velocity model from the monitor BHS measurements; anddetermining a model change in the reservoir parameter by comparing the baseline velocity model and the monitor velocity model.2. The method of claim 1 , wherein at least one of the baseline velocity model or the monitor velocity model is calculated using a full waveform inversion method.3. The method of claim 1 , further comprising:calculating a baseline image by performing a baseline migration using the baseline seismic data and the baseline velocity model;calculating a monitor image by performing a baseline migration using the baseline seismic data and the baseline velocity model; anddetermining an image change in the reservoir parameter by comparing the baseline image and the monitor image.4. The method of claim 3 , wherein the baseline migration and the monitor migration comprise at least one of a time migration or a depth migration.5. The method of claim 3 , further comprising:updating a reservoir model based on at least one of the model change or the image change;generating, by simulating the reservoir model, a first plurality of reservoir properties corresponding to a first time and a second plurality of reservoir properties corresponding to a second time;calculating a first plurality of BHS simulated ...

INVERSION-BASED WORKFLOW FOR PROCESSING NUCLEAR DENSITY IMAGES IN HIGH-ANGLE AND HORIZONTAL WELLS

Methods and apparatus for characterizing a subterranean formation traversed by a wellbore including collecting data from the formation using a tool wherein the tool collects data to form an azimuthal image, characterizing a section of the formation comprising data and images acquired in a high angle wellbore section or horizontal wellbore section using a parametric model, and performing an inversion using apparent densities and volumetric photoelectric factor images to build a formation model wherein the inversion is tailored for high angle wellbore sections and/or horizontal wellbore sections. 1. A method for characterizing a subterranean formation traversed by a wellbore , comprising:collecting data from the formation using a density tool wherein the tool collects data to form an azimuthal image;characterizing a section of the formation comprising data and images acquired in a high angle wellbore section or horizontal wellbore section using a parametric model; andperforming an inversion using apparent densities and volumetric photoelectric factor images to build a formation model wherein the inversion is tailored for high angle wellbore sections and/or horizontal wellbore sections.2. The method of claim 1 , further comprising post-processing comprising visualizing the inversion built model.3. The method of claim 1 , wherein the formation model further comprises borehole geometry and layer photoelectric models.4. The method of claim 1 , further comprising pre-processing the data.5. The method of claim 4 , wherein pre-processing is selected from the group consisting of log-squaring claim 4 , sinusoid extraction from an image claim 4 , trajectory segmentation claim 4 , and a combination thereof.6. The method of claim 5 , wherein the log is the azimuthal compensated density image acquired at a single measurement depth.7. The method of claim 5 , wherein the log is the bottom quadrant density from the compensated image.8. The method of claim 5 , wherein the sinusoid ...

Methods and Apparatuses to Generate a Formation Model

Systems, methods, and apparatuses to generate a formation model are described. In one aspect, a logging system includes a transmitter to produce an electromagnetic field in a borehole, a receiver in the borehole to detect a first field signal induced by the electromagnetic field at a first depth of investigation and a second field signal induced by the electromagnetic field at a second depth of investigation, and a modeling unit to perform a first one-dimensional inversion on the first field signal and a second one-dimensional inversion on the second field signal, build a two-dimensional model from the first one-dimensional inversion and the second one-dimensional inversion, and perform a two-dimensional inversion on the two-dimensional model to generate a two-dimensional formation model.

Workflow for Navigation with Respect to Oil-Water Contact using Deep Directional Resistivity Measurements

Methods for determining oil-water contact positions and water zone resistivities are provided. In one example, the method may involve performing a 1D inversion on data collected by a resistivity logging tool. Further, the method may involve scanning a resistivity profile of a reservoir generated by the 1D inversion for a boundary position below the resistivity logging tool. Furthermore, the method may involve applying a local residual weighted average on the boundary position to generate an initial estimation of an oil-water contact position and inverting the initial estimation of the oil-water contact to generate water zone resistivity and a modified oil-water contact position. Additionally, the method may involve miming a smoothing local post-processing operation to generate a layered model and performing a 2D inversion on the layered model.

INVERSION-BASED WORKFLOW FOR CONSISTENT INTERPRETATION OF NUCLEAR DENSITY IMAGES IN HORIZONTAL WELLS

Systems and methods are disclosed for well logging using radiation detection and/or emission of gamma rays. A method according to the disclosure includes collecting data from the subterranean formation using a nuclear density tool, wherein the nuclear density tool is configured to collect data to form an azimuthal image. The method further includes characterizing a section of the subterranean formation comprising data and images acquired in a high angle wellbore section, a horizontal wellbore section, or a combination thereof. The method additionally includes performing a parallel inversion using apparent densities and volumetric photoelectric factor images to build a formation model, wherein the parallel inversion comprises a high angle workflow that models high angle wellbore sections and a horizontal workflow that models horizontal wellbore sections. 1. A method for characterizing a subterranean formation traversed by a wellbore , the method comprising:collecting data from the subterranean formation using a nuclear density tool, wherein the nuclear density tool is configured to collect data to form azimuthal images;characterizing a section of the subterranean formation comprising data and images acquired in a high angle wellbore section, a horizontal wellbore section, or a combination thereof; andperforming a parallel inversion using apparent densities and volumetric photoelectric factor images to build a formation model, wherein the parallel inversion comprises a high angle workflow that models high angle wellbore sections and a horizontal workflow that models horizontal wellbore sections.2. The method of claim 1 , wherein performing the parallel inversion comprises processing a plurality of image windows in parallel claim 1 , and the image windows comprise segmented overlapping windows claim 1 , segmented non-overlapping windows claim 1 , or a combination thereof.3. The method of claim 1 , wherein performing the parallel inversion comprises:selecting a middle ...

System and Method for Imaging Subterranean Formations

Systems and methods for imaging properties of subterranean formations in a wellbore include a formation sensor for collecting currents injected into the subterranean formations and a formation imaging unit. The formation imaging unit includes a current management unit for collecting data from the currents injected into the subterranean formations and a formation data unit for determining at least one formation parameter from the collected data. The formation imaging unit also includes an inversion unit for determining at least one formation property by inverting the at least one formation parameter. The inversion unit is suitable for generating an inverted standoff image and an inverted permittivity image for comparison with a composite image of the formation imaging unit.

HIGH PERFORMANCE DISTRIBUTED COMPUTING ENVIRONMENT PARTICULARLY SUITED FOR RESERVOIR MODELING AND SIMULATION

A distributed computing system and method is described herein. The system and method employ a server node, compute nodes, a network file system server providing shared data storage resources, and client systems. The server node receives and processes a document submitted by a client system. The document specifies a job including a number of compute tasks that are to be executed in a distributed manner by the compute nodes, data for at least one compute task of the job, a shared directory on the network file system server, and a collection of the compute nodes that have access to the shared directory. The server node stores the data for the compute task of the job into the shared directory. At least one compute node that belongs to the collection accesses the directory to process the data for the compute task of the job for execution of the compute task. 1. A distributed computing system for use with a plurality of client systems , the distributed computing system comprising:a server node;a plurality of compute nodes; anda network file system server providing shared data storage resources;wherein said server node is configured to receive and process a document submitted by one of said plurality of client systems, wherein said document specifies a job including a number of compute tasks that are to be executed in a distributed manner by said plurality of compute nodes, data for at least one compute task of the job, a shared directory on said network file system server, and a first collection of said compute nodes that have access to said shared directory;wherein said server node is further configured to store the data for the at least one compute task of the job into said shared directory; andwherein at least one compute node that belongs to said first collection of compute nodes is configured to access said shared directory to process the data for the at least one compute task of the job for execution of the at least one compute task.2. A distributed computing system ...

WIRELESS LOGGING OF FLUID FILLED BOREHOLES

A predetermined condition in a fluid-filled wellbore system can be detected by generating at least one sound in the wellbore system in response to the condition, such that a detectable change is created in some characteristic of the emitted sound, and detecting the at least one sound and the change, the detection being indicative that the predetermined condition has occurred. Equipment for facilitating detection of the condition can include a trigger operable in response to the condition; a generator operable to emit sound in the borehole and to create a detectable change in some characteristic of the emitted sound in response to the trigger; and at least one sensor operable to monitor the sound and detect the change, the detection being indicative that the predetermined condition has occurred. It is also possible to estimate a value of a property of a fluid-filled wellbore system. This can be accomplished by recording data including at least one of pressure and rate of flow at one or more locations in the wellbore system, and then estimating the value of the property by employing a model for predicting at least one of pressure and rate of flow dependent upon parameters detailing at least one of wellbore system geometry, viscoacoustic properties of the fluid and entrained solids contained in the wellbore system, locations of boundaries and entrained solids, and characteristics and locations of disturbances to pressure and flow in the wellbore system, in order to determine a best prediction of some attribute of the recorded data. 1. A method for detecting a predetermined condition in a fluid-filled wellbore system , the method comprising:generating at least one pressure pulse triggered in response to the predetermined condition; anddetecting the at least one generated pulse, wherein the detection is indicative that the predetermined condition has occurred.2. The method of wherein the predetermined condition includes at least one of: (i) a specific level of pressure ...

METHOD FOR DETERMINING FORMATION PROPERTIES BY INVERSION OF MULTISENSOR WELLBORE LOGGING DATA

A method for determining properties of a formation traversed by a well or wellbore employs measured sonic data, resistivity data, and density data for an interval-of-interest within the well or wellbore. A formation model that describe properties of the formation at the interval-of-interest is derived from the measured sonic data, resistivity data, and density data for the interval-of-interest. The formation model is used to derive simulated sonic data, resistivity data, and density data for the interval-of-interest. The measured sonic data, resistivity data, and density data for the interval-of-interest and the simulated sonic data, resistivity data, and density data for the interval-of-interest are used to refine the formation model and determine properties of the formation at the interval-of-interest. The properties of the formation may be a radial profile for porosity, a radial profile for water saturation, a radial profile for gas saturation, a radial profile of oil saturation, and a radial profile for pore aspect ratio. 1. A method for determining properties of a formation traversed by a well or wellbore , the method comprising:obtaining measured sonic data, resistivity data, and density data for an interval-of-interest within the well or wellbore;deriving a formation model that describes properties of the formation at the interval-of-interest, wherein the formation model is based on the measured sonic data, resistivity data, and density data for the interval-of-interest;using the formation model to derive simulated sonic data, resistivity data, and density data for the interval-of-interest; andusing the measured sonic data, resistivity data, and density data for the interval-of-interest and the simulated sonic data, resistivity data, and density data for the interval-of-interest to refine the formation model and determine properties of the formation at the interval-of-interest.2. The method of claim 1 , wherein:the properties of the formation comprise at ...

Automated field development planning

In a system for selecting an optimized Field Development Plan (FDP) a method of estimating the value of acquiring new data to reduce uncertainty of physical variables in a Shared Earth Model (SEM) includes selecting an initial FDP optimized for an initial SEM, where an objective function for the Figure of Merit is degraded by a risk factor in the presence of uncertainty for physical variables in the SEM. The results of one or more measurements are applied to the SEM to generate a new SEM with reduced uncertainty for physical variables. A risk degraded Figure of Merit for the initial FDP is computed based on the new SEM. A new FDP optimized for the new SEM is selected, where the objective function for the Figure of Merit is degraded by the risk factor in the presence of the reduced uncertainty for the physical variables in the new SEM. A risk degraded Figure of Merit for the new FDP is computed based on the new SEM and the Figures of Merit for the initial and new FDPs are compared to determine the value of acquiring new data.

Method and apparatus which uses a combination of fluid injection and resistivity measurements

System and Method for Deep Formation Evaluation

A technique facilitates formation evaluation by deploying tools in a subterranean environment. A logging tool is deployed in a wellbore to obtain formation related measurements. Additionally, one or more mobile robots also are positioned in the subterranean environment at unique positions that facilitate accumulation of data related to the formation. The data obtained from the logging tool and the one or more mobile robots is processed in a manner that enables deep formation evaluation.

Targeted measurements for formation evaluation and reservoir characterization

A downhole-reconfigurable tool string is utilized to obtain targeted measurements for formation evaluation and reservoir characterization. Tool string hardware and corresponding analysis software are dynamically adjusted to meet specific reservoir description needs identified during or before the logging run with the downhole-reconfigurable tool string. A technique for utilizing the downhole-reconfigurable tool string includes four different steps. The first step includes detecting first order features and identifying second order features. The second step includes enhancing measurements relative to the second order features by reconfiguring tool hardware to extract at least the desired information of the reservoir in terms of its static and dynamic properties, and software focusing to enhance the sensitivity to a particular reservoir attribute. The third step is performing an inversion to reconstruct the reservoir property as accurately as possible. The fourth step is using these properties and the planned production/injection data to recommend suitable monitoring schema.

Targeted measurements for formation evaluation and reservoir characterization

A downhole-reconfigurable tool string is utilized to obtain targeted measurements for formation evaluation and reservoir characterization. Tool string hardware and corresponding analysis software are dynamically adjusted to meet specific reservoir description needs identified during or before the logging run with the downhole-reconfigurable tool string. A technique for utilizing the downhole-reconfigurable tool string includes four different steps. The first step includes detecting first order features and identifying second order features. The second step includes enhancing measurements relative to the second order features by reconfiguring tool hardware to extract at least the desired information of the reservoir in terms of its static and dynamic properties, and software focusing to enhance the sensitivity to a particular reservoir attribute. The third step is performing an inversion to reconstruct the reservoir property as accurately as possible. The fourth step is using these properties and the planned production/injection data to recommend suitable monitoring schema.

Targeted measurements for formation evaluation and reservoir characterization

A downhole-reconfigurable tool string is utilized to obtain targeted measurements for formation evaluation and reservoir characterization. Tool string hardware and corresponding analysis software are dynamically adjusted to meet specific reservoir description needs identified during or before the logging run with the downhole-reconfigurable tool string. A technique for utilizing the downhole-reconfigurable tool string includes four different steps. The first step includes detecting first order features and identifying second order features. The second step includes enhancing measurements relative to the second order features by reconfiguring tool hardware to extract at least the desired information of the reservoir in terms of its static and dynamic properties, and software focusing to enhance the sensitivity to a particular reservoir attribute. The third step is performing an inversion to reconstruct the reservoir property as accurately as possible. The fourth step is using these properties and the planned production/injection data to recommend suitable monitoring schema.

Microwave device and method for measuring multiphase flows

A method for measuring multiphase flows in a conduit using series of microwave antennae arranged around the circumference of the conduit so as to transmit microwave energy into, or detect propagated microwave energy in the conduit, the method including the steps of: transmitting microwave energy from each antenna in turn while detecting microwave energy at the non-transmitting antenna and integrating the results from all antennae so as to characterize the flow in the conduit. Apparatus for performing the method includes means for exciting each antenna in turn to transmit microwave energy into the pipe and means for detecting microwave energy at the non-transmitting antennae, and means for integrating the results from all transmitters to characterize the flow in the conduit.

Methods and apparatuses to generate a formation model

Systems, methods, and apparatuses to generate a formation model are described. In one aspect, a logging system includes a transmitter to produce an electromagnetic field in a borehole, a receiver in the borehole to detect a first field signal induced by the electromagnetic field at a first depth of investigation and a second field signal induced by the electromagnetic field at a second depth of investigation, and a modeling unit to perform a first one-dimensional inversion on the first field signal and a second one-dimensional inversion on the second field signal, build a two-dimensional model from the first one-dimensional inversion and the second one-dimensional inversion, and perform a two-dimensional inversion on the two-dimensional model to generate a two-dimensional formation model.

Wireless logging of fluid filled boreholes

A predetermined condition in a fluid-filled wellbore system can be detected by generating at least one sound in the wellbore system in response to the condition, such that a detectable change is created in some characteristic of the emitted sound, and detecting the at least one sound and the change, the detection being indicative that the predetermined condition has occurred. Equipment for facilitating detection of the condition can include a trigger operable in response to the condition; a generator operable to emit sound in the borehole and to create a detectable change in some characteristic of the emitted sound in response to the trigger; and at least one sensor operable to monitor the sound and detect the change, the detection being indicative that the predetermined condition has occurred. It is also possible to estimate a value of a property of a fluid-filled wellbore system. This can be accomplished by recording data including at least one of pressure and rate of flow at one or more locations in the wellbore system, and then estimating the value of the property by employing a model for predicting at least one of pressure and rate of flow dependent upon parameters detailing at least one of wellbore system geometry, viscoacoustic properties of the fluid and entrained solids contained in the wellbore system, locations of boundaries and entrained solids, and characteristics and locations of disturbances to pressure and flow in the wellbore system, in order to determine a best prediction of some attribute of the recorded data.

methods and systems employing observation and prediction inversion of downhole measurements

são fornecidos fluxos de trabalho baseados em inversão para interpretação em tempo real das medições de observação e previsão eletromagnéticas (em). o perfil de uma zona de observação é determinado pela interpretação das medições em de uma zona de observação. o perfil da zona de observação caracteriza mergulho de formação, assim como resistividade vertical ou anisotropia de resistividade de uma ou mais camadas de formação da zona de observação. o perfil de uma zona de previsão é determinado pela interpretação das medições em da zona de previsão. o perfil da zona de previsão caracteriza o mergulho de formação, assim como a resistividade horizontal, a resistividade vertical ou a anisotropia de uma ou mais camadas de formação da zona de previsão. os fluxos de trabalho também podem envolver a interpretação de medições de resistividade de observação para auxiliar na caracterização da zona de observação. inversion-based workflows are provided for real-time interpretation of electromagnetic observation and prediction (in) measurements. The profile of an observation zone is determined by interpreting measurements in an observation zone. The observation zone profile characterizes formation diving as well as vertical resistivity or resistivity anisotropy of one or more observation zone formation layers. The profile of a forecast zone is determined by interpreting measurements in the forecast zone. The prediction zone profile characterizes the formation dive as well as the horizontal resistivity, vertical resistivity or anisotropy of one or more prediction zone formation layers. Workflows may also involve the interpretation of observation resistivity measurements to assist in characterizing the observation zone.

Automated field development planning

In a system for selecting an optimized Field Development Plan (FDP) a method of estimating the value of acquiring new data to reduce uncertainty of physical variables in a Shared Earth Model (SEM) includes selecting an initial FDP optimized for an initial SEM, where an objective function for the Figure of Merit is degraded by a risk factor in the presence of uncertainty for physical variables in the SEM. The results of one or more measurements are applied to the SEM to generate a new SEM with reduced uncertainty for physical variables. A risk degraded Figure of Merit for the initial FDP is computed based on the new SEM. A new FDP optimized for the new SEM is selected, where the objective function for the Figure of Merit is degraded by the risk factor in the presence of the reduced uncertainty for the physical variables in the new SEM. A risk degraded Figure of Merit for the new FDP is computed based on the new SEM and the Figures of Merit for the initial and new FDPs are compared to determine the value of acquiring new data.

Determination of downhole pressure while pumping

Tubewaves are used to transmit an indication of the depth at which a condition is detected in a well. In particular, the depth is calculated based on the difference in arrival time at the surface of a first tubewave which propagates directly upward in the borehole and a second tubewave which initially travels downward and is then reflected upward. The tubewaves may be generated by a canister designed to implode at a certain pressure. After being introduced into the flowline at an above ground inlet, the canister is carried downhole by gravity and the fluid being pumped. When the canister reaches a depth at which its pressure tolerance is exceeded, it implodes and generates the tubewaves. An analyzer at the surface detects the tubewaves with a hydrophone array and generates a pressure versus depth profile of the well, i.e., one data point for each implosion. Canisters may be acoustically tagged by controlling volume and orifice size in order to generate tubewaves having particular frequency and amplitude characteristics. Canisters may also be configured to produce multiple implosions, e.g., one implosion at each of a selection of different pressures. Canisters may also be equipped with triggering and arming mechanisms, and may generate tubewaves in response to conditions other than a particular pressure.

Microwave device and method for measuring multiphase flows

A method for measuring multiphase flows in a conduit using series of microwave antennae arranged around the circumference of the conduit so as to transmit microwave energy into, or detect propagated microwave energy in the conduit, the method including the steps of: transmitting microwave energy from each antenna in turn while detecting microwave energy at the non-transmitting antenna and integrating the results from all antennae so as to characterize the flow in the conduit. Apparatus for performing the method includes means for exciting each antenna in turn to transmit microwave energy into the pipe and means for detecting microwave energy at the non-transmitting antennae, and means for integrating the results from all transmitters to characterize the flow in the conduit.

Method and apparatus utilizing a combination of fluid injection and resistivity measurements

Method and apparatus for logging underground formations using radar

A method of logging an underground formation from within a borehole includes the steps of emitting an electromagnetic signal from a first location in a borehole, determining a time at which the signal is emitted, detecting a direct component of the signal which has passed from the first location to a second location without being reflected, determining a time at which the direct component arrives at the second location and determining the speed of the signal in the underground formation from the time at which the signal is emitted, the time of arrival of the direct component and the spacing of the first and second locations. The speed of the signal can be used for radar logging of the formation. A logging tool for performing the method includes a transmitter at a first position in a tool body for emitting an electromagnetic signal, means located in the tool body for determining a time at which the signal is emitted, a receiver at a second position in the tool body for detecting a signal which has passed from the transmitter to the receiver through an underground formation; and means located in the tool body for processing the detected signal using the time at which a corresponding signal is emitted from the transmitter.

Method and apparatus which uses a combination of fluid injection and resistivity measurements

Methods and apparatus for estimating values for formation parameters such as permeability, relative permeability, and skin factors for a plurality of locations in the formation are provided. Fluid is forced into a capped borehole at a measured rate, and a borehole logging tool is run in the borehole to measure indications of pressure and conductivity. Estimates of the parameters and the measured fluid flow rate(s) into the formation are used in conjunction with a jointly inverted pressure transient model and saturation-conductivity model in order to compute indications of expected pressure and indications of expected conductivity-related profiles as a function of depth and time. The expected pressures and expected conductivity related profile indications are then compared to the pressures and conductivity indications measured by the borehole logging tool, and an iterated comparison between the computed values and the measured values is used to provide determinations of the formation parameters. According to a preferred embodiment, the pressure transient model is for compressible flow and provides an estimated calculated fluid flow into the layers of the formation; the estimated calculated fluid flow being an input to the saturation-conductivity model which is for incompressible flow.

Method for determining formation properties by inversion of multisensor wellbore logging data

A method for determining properties of a formation traversed by a well or wellbore employs measured sonic data, resistivity data, and density data for an interval-of-interest within the well or wellbore. A formation model that describe properties of the formation at the interval-of-interest is derived from the measured sonic data, resistivity data, and density data for the interval-of-interest. The formation model is used to derive simulated sonic data, resistivity data, and density data for the interval-of-interest. The measured sonic data, resistivity data, and density data for the interval-of-interest and the simulated sonic data, resistivity data, and density data for the interval-of-interest are used to refine the formation model and determine properties of the formation at the interval-of-interest. The properties of the formation may be a radial profile for porosity, a radial profile for water saturation, a radial profile for gas saturation, a radial profile of oil saturation, and a radial profile for pore aspect ratio.

Automated field development planning

A system for automatically optimizing a Field Development Plan (FDP) for an oil or gas field uses a fast analytic reservoir simulator to dynamically model oil or gas production from the entire reservoir over time in an accurate and rapid manner. An objective function defining a Figure of Merit (FoM) for candidate FDPs is maximized, using an optimization algorithm, to determine an optimized FDP in light of physical, engineering, operational, legal and engineering constraints. The objective function for the Figure of Merit, e.g., net present value (NPV) or total production for a given period of time, relies on a production forecast from the fast analytic reservoir simulator for the entire FDP. The position, orientation and dimensions of analytical model elements for the subsurface oil or gas field, as well as the physical properties associated with these elements, correlate to connected flow volume data from a Shared Earth Model (SEM). Uncertainty in the SEM is considered via stochastic sampling. In the presence of uncertainty, the optimum Field Development Plan (FoM) is selected by maximizing an objective function defining a risk-based Figure of Merit for the entire FDP.

Method for determining a wellbore position with respect to an earth formation layer boundary

Determination of downhole pressure while pumping

Tubewaves are used to transmit an indication of the depth at which a condition is detected in a well. In particular, the depth is calculated based on the difference in arrival time at the surface of a first tubewave which propagates directly upward in the borehole and a second tubewave which initially travels downward and is then reflected upward. The tubewaves may be generated by a canister designed to implode at a certain pressure. After being introduced into the flowline at an above ground inlet, the canister is carried downhole by gravity and the fluid being pumped. When the canister reaches a depth at which its pressure tolerance is exceeded, it implodes and generates the tubewaves. An analyzer at the surface detects the tubewaves with a hydrophone array and generates a pressure versus depth profile of the well, i.e., one data point for each implosion. Canisters may be acoustically tagged by controlling volume and orifice size in order to generate tubewaves having particular frequency and amplitude characteristics. Canisters may also be configured to produce multiple implosions, e.g., one implosion at each of a selection of different pressures. Canisters may also be equipped with triggering and arming mechanisms, and may generate tubewaves in response to conditions other than a particular pressure.

Microwave device and method based on microwave technology for measuring multiphase currents

Workflow for navigation with respect to oil-water contact using deep directional resistivity measurements

Microwave device and method for measuring multiphase flows

Wireless logging of fluid filled boreholes.

Un estado predeterminado en un sistema de agujero para pozo llenado con fluido puede detectarse generando al menos un sonido en el sistema del agujero para pozo en respuesta al estado, de modo que se cree un cambio detectable en alguna característica del sonido emitido y detectando el al menos un sonido y el cambio, siendo la detección indicativa de que ha ocurrido el estado predeterminado. El equipo para facilitar la detección del estado puede consistir en un disparador que puede operar en respuesta al estado; un generador que puede funcionar para emitir el sonido en el agujero y para crear un cambio detectable en alguna característica del sonido emitido en respuesta al disparador; y al menos un sensor que puede funcionar para monitorizar el sonido y detectar el cambio, siendo la detección indicativa de que ha ocurrido el estado predeterminado. También es posible estimar un valor de una propiedad de un sistema de agujero para pozo relleno con fluido. Esto se puede llevar a cabo registrando datos que incluyan al menos uno de los siguientes: presión y velocidad de flujo en uno o más lugares en el sistema del agujero para pozo, y luego estimar el valor de la propiedad empleando un modelo para predecir al menos uno de lo siguiente: la presión y velocidad de flujo dependiendo de los parámetros que detallan al menos uno de lo siguiente: la geometría del sistema del agujero para pozo, las propiedades viscoacústicas del fluido y los sólidos arrastrados contenidos en el sistema del agujero para pozo, los lugares de los contornos y los sólidos arrastrados, y las características y lugares de las perturbaciones a la presión y flujo en el sistema del agujero para pozo, para determinar la mejor predicción de algún atributo de los datos registrados.

Antena de fenda tendo dois elementos nao paralelos,ferramenta de perfilagem,e processo de perfilagem

Methods for determining a volume fraction of water and water salinity in organic shale reservoirs using multi-frequency dielectric well logging measurements

The subject disclosure relates to a method for determining a volume fraction of water and water salinity in organic shales and other geological formations. The method includes a knowledge of complex formation permittivity at several frequencies and minimizes or excludes dependency on external parameters, such as the permittivity of the formation mineral phase.

Method and apparatus for electromagnetic logging of a formation

Permeability determinations from wideband em models using borehole logging tools

A permeability log is generated by running borehole tools in a borehole traversing a formation, including at least electromagnetic (EM) tool providing at least a low-frequency complex conductivity measurement at at least one frequency. Data from the EM tool and other data obtained from other tools are provided to a wideband EM model, where a data inversion is conducted to provide a plurality of outputs from which a cementation exponent may be calculated. The cementation exponent is used to find a formation factor at each depth of interest in the borehole, and the formation factor is used to find a permeability value which is used for the permeability log. The permeability log may be generated without the use of core data.

Slissantenne med to ikke-parallelle elementer

Slissantenne med to ikke-parallelle elementer

Antenne fendue a deux elements non paralleles

UNE ANTENNE FENDUE EST DOTEE D'UNE OUVERTURE CARREE ET DE DEUX SONDES DE COURANT PLACEES EN ANGLE DANS CETTE MEME OUVERTURE. CES DEUX SONDES DE COURANT SONT EXCITEES SIMULTANEMENT OU SEPAREMENT PAR DES SIGNAUX DIFFERENTS. EN AJUSTANT L'INTENSITE OU LA PHASE DES SIGNAUX ENVOYES AUX SONDES DE COURANT, L'ON PEUT REGLER L'ANGLE DU MOMENT MAGNETIQUE DE L'ANTENNE. UN RESEAU D'ANTENNES SIMILAIRES, A L'INTERIEUR D'UN OUTIL DE PROPAGATION, ELECTROMAGNETIQUE FOURNIT UNE MEILLEURE PERFRMANCE D'ISOLEMENT EN REGLANT LE MOMENT MAGNETIQUE POUR QUE CELUI-CI SOIT PARALLELE A L'AXE D'UN TROU DE POING, ET UNE REPONSE-IMAGE PLUS NETTE EN REGLANT LE MMEMENT MAGNETIQUE POUR QUE CELUI-CI SOIT PERPENDICULAIRE AU LIT DE LA FORMATION. LE RESEAU PEUT ETRE EXCITE DE MANIERE A FONCTIONNER EN TANT QUE RESEAU LONGITUDINAL ET TRANSVERSAL D'UN OUTIL DE PROPAGATION ELECTROMAGNETIQUE

Slissantenne med to ikke-parallelle elementer for elektromagnetisk brønnlogging

Antena ranurada que tiene dos elementos no paralelos.

Schlitzantenne mit zwei nichtparallelen elementen

Inversion techniques for real-time well placement and reservoir characterization

Improving efficiency of pixel-based inversion algorithms

Modified pulse sequence to estimate properties

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

High performance distributed computing environment particularly suited for reservoir modeling and simulation

A distributed computing system and method is described herein. The system and method employ a server node, compute nodes, a network file system server providing shared data storage resources, and client systems. The server node receives and processes a document submitted by a client system. The document specifies a job including a number of compute tasks that are to be executed in a distributed manner by the compute nodes, data for at least one compute task of the job, a shared directory on the network file system server, and a collection of the compute nodes that have access to the shared directory. The server node stores the data for the compute task of the job into the shared directory. At least one compute node that belongs to the collection accesses the directory to process the data for the compute task of the job for execution of the compute task.

Microwave device and method for measuring multiphase flows

Slot antenna having two nonparallel elements

A slot antenna has a square aperture and two current probes at angles to each other in the aperture. The two current probes are excited simultaneously or separately with different signals. By adjusting the amplitude or phase of the signals in the current probes, the angle of the magnetic moment of the antenna can be adjusted. An array of such antennas in an electromagnetic propagation tool for a well-logging device simultaneously provides better standoff performance by adjusting the magnetic moment to be parallel to a borehole axis, and better image response by adjusting the magnetic moment to be perpendicular to the formation bed. The array can be excited to function as an endfire and broadside array of an electromagnetic propagation tool. <IMAGE>

Workflow for navigation with respect to oil-water contact using deep directional resistivity measurements

Methods for determining oil-water contact positions and water zone resistivities are provided. In one example, the method may involve performing a 1D inversion on data collected by a resistivity logging tool. Further, the method may involve scanning a resistivity profile of a reservoir generated by the 1D inversion for a boundary position below the resistivity logging tool. Furthermore, the method may involve applying a local residual weighted average on the boundary position to generate an initial estimation of an oil-water contact position and inverting the initial estimation of the oil-water contact to generate water zone resistivity and a modified oil-water contact position. Additionally, the method may involve running a smoothing local post-processing operation to generate a layered model and performing a 2D inversion on the layered model.

Methods of investigating formation samples using NMR data

A methods are provided for investigating a sample containing hydrocarbons by subjecting the sample to a nuclear magnetic resonance (NMR) sequence using NMR equipment, using the NMR equipment to detect signals from the sample in response to the NMR sequence, analyzing the signals to extract a distribution of relaxation times (or diffusions), and computing a value for a parameter of the sample as a function of at least one of the relaxation times (or diffusions), wherein the computing utilizes a correction factor that modifies the value for the parameter as a function of relaxation time for at least short relaxation times (or as a function of diffusion for at least large diffusion coefficients).

Wireless logging of fluid filled boreholes

A predetermined condition in a fluid-filled wellbore system can be detected by generating at least one sound in the wellbore system in response to the condition, such that a detectable change is created in some characteristic of the emitted sound, and detecting the at least one sound and the change, the detection being indicative that the predetermined condition has occurred. Equipment for facilitating detection of the condition can include a trigger operable in response to the condition; a generator operable to emit sound in the borehole and to create a detectable change in some characteristic of the emitted sound in response to the trigger; and at least one sensor operable to monitor the sound and detect the change, the detection being indicative that the predetermined condition has occurred. It is also possible to estimate a value of a property of a fluid-filled wellbore system. This can be accomplished by recording data including at least one of pressure and rate of flow at one or more locations in the wellbore system, and then estimating the value of the property by employing a model for predicting at least one of pressure and rate of flow dependent upon parameters detailing at least one of wellbore system geometry, viscoacoustic properties of the fluid and entrained solids contained in the wellbore system, locations of boundaries and entrained solids, and characteristics and locations of disturbances to pressure and flow in the wellbore system, in order to determine a best prediction of some attribute of the recorded data.

Inversion-based workflow for processing nuclear density images in high-angle and horizontal wells

Methods and apparatus for characterizing a subterranean formation traversed by a wellbore including collecting data from the formation using a tool wherein the tool collects data to form an azimuthal image, characterizing a section of the formation comprising data and images acquired in a high angle wellbore section or horizontal wellbore section using a parametric model, and performing an inversion using apparent densities and volumetric photoelectric factor images to build a formation model wherein the inversion is tailored for high angle wellbore sections and/or horizontal wellbore sections.

System and method for imaging properties of subterranean formations

A system and method for imaging properties of subterranean formations in a wellbore is provided. The system comprises a formation sensor for collecting currents injected into the subterranean formations, the formation sensor positionable on a downhole tool deployable into the wellbore. The system comprises a controller for controlling the formation sensor and a formation imaging unit. The formation imaging unit comprises a current management unit for collecting data from the currents injected into the subterranean formations, the currents having at least two different frequencies. The formation imaging unit comprises a drilling mud data unit for determining at least one drilling mud parameter, a formation data unit for determining at least one formation parameter from the collected data, and an inversion unit for determining at least one formation property by inverting the at least one formation parameter.

Modified pulse sequence to estimate properties

Methods and related systems are described for estimating fluid or rock properties from NMR measurements. A modified pulse sequence is provided that can directly provide moments of relaxation-time or diffusion distributions. This pulse sequence can be adapted to the desired moment of relaxation-time or diffusion coefficient. The data from this pulse sequence provides direct estimates of fluid properties such as average chain length and viscosity of a hydrocarbon. In comparison to the uniformly-spaced pulse sequence, these pulse sequences are faster and have a lower error bar in computing the fluid properties.

Torsional wave logging

A method for torsional wave logging in a borehole of a subterranean formation. The method includes obtaining a torsional wave measurement of the borehole, wherein the torsional wave measurement represents characteristics of a torsional wave propagating within a cylindrical layered structure associated with the borehole, wherein the cylindrical layered structure comprises the subterranean formation and a completion of the borehole, analyzing, by a computer processor, the torsional wave measurement to generate a quality measure of the completion, and displaying the quality measure of the completion.