A method includes receiving observed seismic data, determining an envelope or magnitude of the observed seismic data as a first observed value, generating a variable noise term based in part upon the first observed value, and utilizing the variable noise term to determine a likelihood function of a stochastic inversion operation. The method also includes utilizing the likelihood function to generate a posterior probability distribution in conjunction with the stochastic inversion operation and applying the posterior probability distribution to characterize a subsurface region of Earth.
G01V 1/28 - Processing seismic data, e.g. analysis, for interpretation, for correction
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
2.
METHOD AND APPARATUS FOR PETROPHYSICAL CLASSIFICATION, CHARACTERIZATION, AND UNCERTAINTY ESTIMATION
Techniques and systems to provide increases in accuracy of property determination of a formation. The techniques include receiving initial well log data, generating augmented well log data including the initial well log data and modeled well log data based on the initial well log data, modifying the augmented well log data to generate a training dataset, training a probabilistic classifier utilizing the training dataset, calculating a probability volume for each lithofluid class of a set of predetermined lithofluid classes utilizing the probabilistic classifier, outputting the probability volume for each lithofluid class of the set of predetermined lithofluid classes as a respective probability of an occurrence of a type of lithofluid class in a reservoir, calculating a posterior probability based on the probability volume for a first lithofluid class of the set of predetermined lithofluid classes, and outputting the posterior probability as a probability of a property of the reservoir.
A choke valve includes an inlet, an outlet, and a cage downstream of the inlet and upstream of the outlet. The cage includes a plurality of ports, and each port of the cage includes a converging-diverging profile.
Provided are compositions and methods for producing dihydrofurans by way of glycosyl hydrolases that can dehydrate 2-keto-3-deoxy-gluconate (KDG) to K4. Provided are also compositions and methods for further processing K4 to create HMFA (5-hydroxymethyl-2-furoic acid) and/or FDCA (2,5-furan dicarboxylic acid).
Techniques to avoid a cycle skip in conjunction with a full waveform inversion are disclosed herein. A method includes selecting a first objective function of a full waveform inversion (FWI) from a set of objective functions, selecting a second objective function of the FWI from the set of objective functions, calculating a first misfit based upon the first objective function using modeled data with respect to observed data, calculating a first search direction based upon the first misfit between the modeled data and the observed data, calculating a second misfit based upon the second objective function using the modeled data with respect to the observed data, calculating a second search direction based upon the second misfit between the modeled data and the observed data, combining the first search direction with the second direction and computing an update to the modeled data based upon the first search direction and the second search direction combination.
A method for modeling fluid flow within a subterranean formation includes (a) receiving a three-dimensional (3D) image of rock from the subterranean formation. In addition, the method includes (b) defining a chemical system for the subterranean formation, wherein the chemical system comprises a plurality of chemical reactions within the subterranean formation. Further, the method includes (c) determining a concentration change within the subterranean formation over time due to solute transport and the chemical reactions of the chemical system. Still further, the method includes (d) determining a change in pore space within the subterranean formation; and (e) determining an updated concentration within the subterranean formation as a result of the concentration change and the change in pore space.
Techniques to allow for increases in the accuracy of the determination of properties of a formation (e.g., a formation's fluid content, porosity, density, etc.) or seismic velocity, shear wave information, etc. The techniques include generating initial input data comprising based at least in part on initial seismic data, modeling the initial input data to generate synthetic seismic data based on different combinations of the initial input data, iteratively updating a value of each particle of a set of particles utilizing the synthetic seismic data to generate a final set of particles and outputting the final set of particles as a target distribution.
A method for planning a subject well includes receiving a well profile for the subject well, the well profile comprising a plurality of sets of attributes, each corresponding to one of a plurality of depths of the subject well; categorizing each of the sets of attributes as being in a first zone or in a second zone to generate a pivoted well profile, where the pivoted well profile includes a number of the sets of attributes in the first zone and a number of the sets of attributes in the second zone; comparing the pivoted well profile of the subject well to a library of well profiles; identifying, based on the comparison, an analog well from the library, where a difference between the analog well profile and the pivoted well profile is less than a threshold; and providing an indication of the identified analog well.
Generally, seismic data may provide valuable information with regard to the description such as the location and/or change of hydrocarbon deposits within a subsurface region of the Earth. The present disclosure generally discusses techniques that may be used by a computing system to analyze a data set including weak-coherence signals (e.g., non-coherent blending noise). In particular, a computing system may detect portion of the weak-coherence signals of a gather due to the overlap of selected seismic source excitations and use a mask to isolate coherent signals and the other weak-coherence signals from the masked portion of weak-coherence signals. The coherent signals and other weak-coherence signals may be iteratively processed and used to predict values of the masked weak-coherence signals.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
G01V 1/00 - Seismology; Seismic or acoustic prospecting or detecting
10.
METHOD AND APPARATUS FOR IMPLEMENTING A HIGH-RESOLUTION SEISMIC PSEUDO-REFLECTIVITY IMAGE
A method for generating a high-resolution pseudo-reflectivity image of a subsurface region includes receiving seismic data associated with a subsurface region and captured by one or more seismic receivers, constructing a velocity model of the subsurface region based on the received seismic data, performing a seismic migration of the received seismic data based on the constructed velocity model to obtain migrated seismic data, computing polarized normal vectors associated with one or more subsurface reflectors of the subsurface region based on the migrated seismic data, and generating a pseudo-reflectivity image of the subsurface region based on both the computed polarized normal vectors.
A method for a completion operation of a well includes performing, by a simulator, an initial simulation based on geological data and an input parameter, the initial simulation providing simulated net pressure values for the well; receiving an indication of an actual net pressure value in the well; adjusting, by an RL agent, the input parameter to the simulator based on a difference between the actual net pressure value and a corresponding simulated net pressure value; performing an updated simulation based on the geological data and the adjusted input parameter, the updated simulation providing updated simulated net pressure values; iteratively adjusting the input parameter to the simulator, with the corresponding simulated net pressure value being from the updated simulated net pressure values; and providing an indication of an event at the well based on the actual net pressure value and the corresponding simulated net pressure value.
Techniques, systems and devices to generate a seismic wavefield solution. This includes receiving a velocity model corresponding to at least one attribute of seismic data, receiving source wavelet data corresponding to the seismic data, generating a guide image based upon at least one attribute of the velocity model, transmitting the velocity model, the source wavelet data, and the guide image to a machine learning system, and training the machine learning system into a trained machine learning system using the velocity model, the source wavelet data, and the guide image.
The present disclosure related generally to a process for removing chloride-containing organic compounds from renewable and bio-feedstocks. Accordingly, in one aspect, the present disclosure provides for a process for processing a liquid feed, the process comprising: providing a liquid feed that comprises one or more fatty acids and/or fatty acid esters, the liquid feed having a first chloride concentration by weight of chloride-containing organic compounds; and contacting the liquid feed with a solid treatment material to remove at least a fraction of the chloride-containing organic compounds to produce a treated liquid feed having a second chloride concentration that is less than the first chloride concentration, wherein the solid treatment material comprises an alkali metal or an alkaline earth metal in ionic form.
The present disclosure relates generally to processes for handling renewable hydrocarbon feeds and conventional hydrocarbon feeds. One aspect of the disclosure provides a process for co-processing a renewable feed and a petroleum feed, the process comprising: hydrotreating the petroleum feed in a first reaction zone, wherein the hydrotreating of the petroleum feed comprises one or more of hydrodesulfurization, hydrodenitrogenation, hydrodemetallization, isomerization, hydrogenation of olefins, and hydrocracking, to form a first reaction zone effluent; conducting the first reaction zone effluent to a second reaction zone; and in the second reaction zone hydrotreating a combination of the first reaction zone effluent and the renewable feed, wherein the hydrotreating of the combination comprises one or more of hydrodeoxygenation, decarboxylation, decarbonylation, isomerization and hydrogenation of olefins of the renewable feed, to form a second reaction zone effluent.
BP EXPLORATION OPERATING COMPANY LIMITED (United Kingdom)
Inventor
Pacheco-Rodriguez, Jesus
Ellison, Joshua
Hickey, Greg
Ballard, Adam
Gonzalez, Martin, R.
Abstract
A method for facilitating the management of one or more energy production or processing facilities includes receiving an alert corresponding to an operational anomaly associated with the process equipment, interrogating a data structure linking together and organizing a plurality of distinct data sources, selecting a subset of data sources from the plurality of data sources identified as associated with a potential cause of the alert based on the interrogation of the data structure, statistically analyzing data sourced from the selected subset of data sources, identifying the potential cause of the alert based on the statistical analysis, and recommending a corrective action to resolve the identified potential cause of the alert using the plurality of distinct data sources.
A method of determining cargo characteristics of a water-borne vessel includes obtaining a first Synthetic Aperture Radar (SAR) image of an area of interest, wherein the water-borne vessel is within the area of interest, and obtaining a second SAR image of the area of interest. In addition, the method includes generating an interferogram using the first SAR image and the second SAR image. Further, the method includes determining a height of the water-borne vessel above a surface of water using the interferogram. Still further, the method includes determining the cargo characteristics of the water-borne vessel based on the height.
A method of assessing the response of a reservoir rock to low salinity water includes obtaining a formation core sample of a reservoir rock from a reservoir. In addition, the method includes sequentially washing the formation core sample with a first series of solvents to form a first series of solvent extracts and an extracted formation core sample. Further, the method includes sequentially washing the extracted formation core sample with a second series of solvents to form a second series of solvent extracts and a cleaned formation core sample. The method also includes generating a series of mass spectra of the second series of solvent extracts. The relative abundance of the catecholamine-type structures (CTS) is determined using the series of mass spectra. Still further, the method includes subjecting the formation core sample to analysis by X-ray diffraction to generate a diffraction pattern. The relative abundance of kalonite is determined using the diffraction pattern. Moreover, the method includes assessing a response of the reservoir rock to low salinity water based on the percentage of kalonite and the relative abundance of CTS.
Techniques to match a signature in seismic data with a seismic attribute space. A method includes automatically selecting a first plurality of seismic attributes corresponding to seismic data as first selected seismic attributes, combining the first selected seismic attributes into a first realization of attributes, performing a first cluster analysis on the first realization of attributes to generate a first clustered volume, selecting a region of interest (ROI) in the seismic data, projecting the ROI onto the first clustered volume to generate a first signature, determining a first level of correlation between the ROI and the first signature, and determining whether the first level of correlation between the ROI and the first signature exceeds a predetermined threshold and outputting a first correlation volume corresponding to the first signature when the first level of correlation between the ROI and the first signature exceeds the predetermined threshold.
Casing installation assemblies for installing a casing within a borehole, as well as systems and methods related thereto are disclosed. In an embodiment, the casing installation assembly includes a tubular string, an isolation sub coupled to a downhole end of the tubular string, and a diverter sub coupled to and positioned downhole of the isolation sub. In addition, the casing installation assembly includes a landing string coupled to the diverter sub and configured to be coupled to the casing. The isolation sub includes a valve assembly that is configured to selectively prevent fluid communication between the tubular string and the diverter sub.
A method for performing a seismic survey of an earthen subterranean formation includes deploying a node patch including a plurality of seismic receivers to an offshore seabed in a survey area, deploying a surface vessel towing an array of seismic sources to the survey area located, and activating the array of seismic sources to generate seismic waves as the array of seismic sources are transported in an inline direction through the survey area whereby an imaging activation pattern and a velocity activation pattern are formed, wherein a lateral offset between the velocity activation pattern and the node patch is greater than a lateral offset between the imaging activation pattern and the node patch.
A sand screen assembly for a subterranean wellbore includes a base pipe having a central axis and including a flow port extending radially therethrough. The sand screen assembly also includes a screen element disposed about the base pipe and radially spaced from the base pipe to define an annulus radially positioned between the screen element and the base pipe. In addition, the sand screen assembly includes a manifold formed about the based pipe. The flow port is in fluid communication with the manifold and axially overlaps with the manifold. Further, the sand screen assembly includes a phase change material disposed within the manifold. The phase change material is configured to melt at a temperature below a melting temperature of the base pipe and flow into the flow port.
A method for analyzing a rock sample includes segmenting a digital image volume corresponding to an image of the rock sample, to associate voxels in the digital image volume with a plurality of rock fabrics of the rock sample. The method also includes identifying a set of digital planes through the digital image volume. The set of digital planes intersects with each of the plurality of rock fabrics. The method further includes machining the rock sample to expose physical faces that correspond to the identified digital planes, performing scanning electron microscope (SEM) imaging of the physical faces to generate two-dimensional (2D) SEM images of the physical faces, and performing image processing on the SEM images to determine a material property associated with each of the rock fabrics.
A method for analyzing a rock sample includes segmenting a digital image volume corresponding to an image of the rock sample, to associate voxels in the digital image volume with a plurality of rock fabrics of the rock sample. The method also includes performing image processing on the digital image volume to determine a material property of each of the rock fabrics and selecting, from a set of nomograms, a nomogram having an associated grid size. The selected nomogram associates the material property of each of the rock fabrics with a fractional bounceback parameter (FBP) value between a lower FBP threshold and an upper FBP threshold. The method further includes associating each voxel in the digital image volume with an FBP value based on the selected nomogram.
A method for analyzing a rock sample includes performing scanning electron microscope (SEM) imaging of a plurality of physical faces of a rock sample to generate two-dimensional (2D) SEM images of the physical faces, applying a cross-correlation function to a first 2D SEM image and a second 2D SEM image to generate a three-dimensional (3D) digital model volume based on the first and second 2D SEM images, and determining a probability distribution of a pore size of the 3D digital model volume based on an image intensity value of a pixel in each of the first and second 2D SEM images.
The system includes a washpipe (20), a screen (32), and a circulation sub (100) coupled to the washpipe. The circulation sub includes a central axis (115) and also includes an expansion switch (110) comprising an inner tubular member (112), an outer tubular member (114), and a switch (111) disposed between the inner tubular member and the outer tubular member. In addition, the circulation sub (100) includes a logging tool carrier (120) supporting a logging tool (150) therein. An axial expansion of the inner tubular member and the outer tubular member is configured to actuate the switch, and compression of the switch is configured to activate the logging tool.
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 23/03 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting the tools into, or removing the tools from, laterally offset landing nipples or pockets
26.
METHOD AND APPARATUS FOR PERFORMING EFFICIENT MODELING OF EXTENDED-DURATION MOVING SEISMIC SOURCES
Methods include receiving a set of seismic data including a seismic signal generated over the course of a set period of time as a time scale, partitioning the seismic signal into a predetermined integer number greater than one of partitioned seismic signals each associated with a respective fixed position associated with a respective time interval as a portion of the time scale, applying a pulse compression technique to each partitioned seismic signal of the predetermined number of partitioned seismic signals to generate a compressed partitioned seismic signal corresponding to each partitioned seismic signal of the predetermined, number of partitioned seismic signals, and inserting the compressed partitioned seismic signal corresponding to each partitioned seismic signal of the predetermined number of partitioned seismic signals in parallel into a velocity model builder. In addition, the methods include summing generated results therefrom to model the seismic signal for the time scale.
Seismic data may provide valuable information with regard to the description such as the location and/or change of hydrocarbon deposits within a subsurface region of the Earth. The present disclosure generally discusses techniques that may be used by a computing system to interpolate or deblend data utilizing a projection on convex sets (POCS) interpolation algorithm. The utilized POCS interpolation algorithm operates in parallel for frequency of a set of frequencies of a seismic frequency spectrum.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
28.
NON-LINEAR SOLUTION TO SEISMIC DATA CONDITIONING USING TRAINED DICTIONARIES
Techniques to reduce noise in seismic data by receiving a set of seismic data comprising a plurality of input volumes each inclusive of positional data and at least one additional attribute related to the seismic data, selecting a first input volume of the plurality of input volumes having a first additional attribute related to the seismic data, and generating a pilot volume by selecting a range of input volumes of the plurality of input volumes and stacking input volumes of the range of input volumes with the first input volume. Additionally, generating a trained dictionary based upon transformation of the pilot volume, transforming the first input volume into transformed data, imposing a sparse condition on the transformed data utilizing the trained dictionary to generate sparsified data, and inverse transforming the sparsified data to generate an output data volume as a portion of a set of modified seismic data.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
G01V 1/32 - Transforming one recording into another
The present disclosure relates generally to solid/liquid separation processes. One aspect of the disclosure is a process including filtering a solid/liquid mixture comprising a solid crude aromatic carboxylic acid, a monocarboxylic acid solvent, and minor amounts of an oxidation catalyst in a feed zone of a rotary filter (e.g., a rotary pressure filter), the feed zone having at least two filter zones to form a first feed filtrate comprising monocarboxylic acid solvent and solids; and a second feed filtrate separate from the first feed filtrate, the second feed filtrate comprising monocarboxylic acid solvent and solids, the second feed filtrate being lower in solids than the first feed filtrate; and transferring at least a portion of the first feed filtrate to the reactor zone as recycle.
C07C 51/265 - Preparation of carboxylic acids or their salts, halides, or anhydrides by oxidation with molecular oxygen of compounds containing six-membered aromatic rings without ring-splitting having alkyl side chains which are oxidised to carboxyl groups
C07C 51/43 - Separation; Purification; Stabilisation; Use of additives by change of the physical state, e.g. crystallisation
C07C 51/47 - Separation; Purification; Stabilisation; Use of additives by chemisorption
A method includes receiving, via a processor, input data based upon received seismic data, migrating, via the processor, the input data via a pre-stack depth migration technique to generate migrated input data, encoding, via the processor, the input data via an encoding function as a migration attribute to generate encoded input data having a migration function that is non-monotonic versus an attribute related to the input data, migrating, via the processor, the encoded input data via the pre-stack depth migration technique to generate migrated encoded input data, and generating an estimated common image gather based upon the migrated input data and the migrated encoded input data. The method also includes generating a seismic image utilizing the estimated common image gather, wherein the seismic image represents hydrocarbons in a subsurface region of the Earth or subsurface drilling hazards.
A system for stimulating a well extending through a subterranean earthen formation includes a surface pump configured to pressurize a well stimulation fluid to a current surface pressure measurable by a surface sensor package, a well stimulation line extending between the surface pump and a wellhead positioned at an upper end of the well, wherein the well stimulation line is configured to flow the well stimulation fluid into the well, and a monitoring system in signal communication with the surface sensor package and including a screen-out predictor module stored in a memory of the monitoring system, wherein the screen-out predictor module is configured to predict a future surface pressure of the well stimulation fluid based on the current surface pressure measured by the surface sensor package, and wherein the monitoring system is configured to provide an indication of the predicted future surface pressure of the well stimulation fluid.
A device may include a processor that may separate or deblend signals acquired with simultaneous source shooting, in an environment with background noise or other types of noises. The processor may expand a receiver gather before the time of source excitation. The processor may use the expanded time window (e.g., negative time window) to allocate the background noise or other types of noises after removal. The processor may use signal recovery operations to reallocate leaked or misplaced signals created during the separation iterations, including the signals inside the expanded time window, to a correct source excitation and timing. Expanding a receiver gather time window and reallocating leaked or misplaced signals may improve a deblended output used in generating a seismic image.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
System and techniques to position a first source array at a fixed first inline distance from a vessel, position a second source array at a fixed second inline distance from a vessel, wherein the fixed second inline distance differs from the fixed first inline distance, generating a spatial coding, fire the first source array, and fire the second source array.
BP EXPLORATION OPERATING COMPANY LIMITED (United Kingdom)
BP CORPORATION NORTH AMERICA INC. (USA)
Inventor
Thiruvenkatanathan, Pradyumna
Cao, Fei
Abstract
A method of characterizing an inflow into a wellbore comprises obtaining an acoustic signal from a sensor within the wellbore, determining a plurality of frequency domain features from the acoustic signal, identifying at least one of a gas phase flow, an aqueous phase flow, or a hydrocarbon liquid phase flow using the plurality of the frequency domain features, and classifying a flow rate of the at least one of the gas phase flow, the aqueous phase flow, or the hydrocarbon liquid phase flow using the plurality of frequency domain features. The acoustic signal comprises acoustic samples across a portion of a depth of the wellbore.
G01F 1/66 - Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
G01H 9/00 - Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means
G01P 5/24 - Measuring speed of fluids, e.g. of air stream; Measuring speed of bodies relative to fluids, e.g. of ship, of aircraft by measuring the direct influence of the streaming fluid on the properties of a detecting acoustical wave
Estimation of velocity models inclusive of receiving seismic data inclusive of data that corresponds to a seismic image, adding a velocity perturbation to a current velocity model that represents a portion of the subsurface responsible for a distortion in the seismic image to generate a perturbed velocity model, generating an image via seismic migration of the seismic data and the perturbed velocity model, generating and assigning a measure of quality to the image, determining whether the measure of quality assigned to the image is an optimal measure of quality at a particular location of the current velocity model, and updating the current velocity model to generate a revised velocity model utilizing the measure of quality assigned to the image when the measure of quality assigned to the image is determined to be the optimal measure of quality at the particular location of the current velocity model.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
A hot tap assembly for accessing a subsea fluid system includes a landing structure configured to releasably attach to a subsea fluid conduit of the subsea fluid system, a clamp assembly positionable on the landing structure, where in the clamp assembly includes a hot tap clamp including a first jaw and a second jaw, wherein a first annular seal assembly and a second annular seal assembly are disposed on an engagement surface of the second jaw, and a drill assembly positionable on the landing structure, wherein the drill assembly includes a drill disposed in a central conduit that is insertable through a central passage formed in the second jaw of the clamp assembly, wherein the hot tap clamp is configured to actuate between an open position configured to receive the subsea fluid conduit and a closed position configured to sealingly engage the subsea fluid conduit with the first seal assembly and the second seal assembly of the clamp assembly.
F16L 1/26 - Repairing or joining pipes on or under water
F16L 41/04 - Tapping pipe walls, i.e. making connections through the walls of pipes while they are carrying fluids; Fittings therefor
F16L 41/06 - Tapping pipe walls, i.e. making connections through the walls of pipes while they are carrying fluids; Fittings therefor making use of attaching means embracing the pipe
12121-61-6 hydrocarbyl groups, from a compound of formula I: the compounds of formulas I and II being optionally in the form of a salt. The method comprises dehydrating the compound of formula I at: a pH in the range of from 0 to 6 or 8 to 11.5; and a temperature in the range of from 10 to 80 °C. The method is particularly useful for synthesizing substituted furans from compounds derived from sugars.
A system for remediating a blockage in a subsea a subsea fluid system includes a hot tap system connected to an outer surface of a subsea fluid conduit of the subsea fluid system, a first flowpath extending from a fluid source, through the first coiled tubing and the hot tap system, and into the subsea fluid conduit, and a second flowpath extending from the subsea fluid conduit and through the hot tap system, wherein the second flowpath is separate from the first flowpath, wherein the hot tap system is configured to inject a first fluid into the subsea fluid conduit along the first flowpath and receive a second fluid from the subsea fluid conduit along the second flowpath.
F16L 1/26 - Repairing or joining pipes on or under water
F16L 41/04 - Tapping pipe walls, i.e. making connections through the walls of pipes while they are carrying fluids; Fittings therefor
F16L 41/06 - Tapping pipe walls, i.e. making connections through the walls of pipes while they are carrying fluids; Fittings therefor making use of attaching means embracing the pipe
39.
GLUCONATE DEHYDRATASE ENZYMES AND RECOMBINANT CELLS
A method includes receiving modelled seismic data that is to be recognized by the at least one classification and/or segmentation processor. The modelled seismic data can be represented within a transform domain. The method includes generating an output via the at least one processor based on the received modelled seismic data. The method also includes comparing the output of the at least one processor with a desired output. The method also includes modifying the at least one processor so that the output of the processor corresponds to the desired output.
G01V 1/28 - Processing seismic data, e.g. analysis, for interpretation, for correction
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
41.
SYSTEMS AND METHODS FOR PERFORMING INSPECTIONS WITH A HEAD-WORN DISPLAY DEVICE
A method for performing an inspection includes (a) concurrently viewing a real object through a display screen of a head-worn display device worn by a user and a virtual object projected on the display screen of the head-worn display device. In addition, the method includes (b) comparing the virtual object to the real object. Further, the method includes (c) generating an inspection result in response to the comparison in (b).
A method of performing single trace inversion to characterize changes in a subsurface region includes obtaining a base seismic trace and a monitor seismic trace of the subsurface region at different respective times. The method includes generating a predicted monitor seismic trace from the base seismic trace by a process including applying a time shift to the base seismic trace, the time shift being derived from estimated velocity perturbations occurring between the base seismic trace and the monitor seismic trace, compensating for amplitude changes between the base seismic trace and the monitor seismic trace, wherein the time shift is applied to the amplitude changes, and minimizing a difference between the predicted monitor seismic trace and the monitor seismic trace by iteratively estimating the velocity perturbations to obtain final estimated velocity perturbations. Changes of at least part of the subsurface region may be characterized using the final estimated velocity perturbations.
A method, and system to implement the process, of selecting a plurality of sets of source and receiver locations over a survey area, modeling on a subsurface attribute model of a subterranean region each source and receiver pair of the plurality of sets of source and receiver locations to generate low frequency seismic data, performing a reverse time migration on the low frequency seismic data to reposition diving wave energy of each source and receiver pair of the plurality of sets of source and receiver locations to generate a diving wave illumination image, extracting seismic amplitudes from the diving wave illumination image at a region of interest, and computing a contribution of a respective diving wave from each source and receiver pair of the plurality of sets of source and receiver locations to diving waves passing through the region of interest.
In some examples, a method comprises receiving, by a computer system, data from a plurality of equipment of a production facility; displaying, on a display unit of the computer system, a dynamic digital replica of the production facility, wherein accessing a digital replica of one of the plurality of equipment via the dynamic digital replica displays data for the one of the plurality of equipment of the production facility; analyzing the data for the one of the plurality of equipment; and generating, based on the analysis, a report on a health of the one of the plurality of equipment.
A device may include a processor that may recover the signals misallocated in the deblending process of seismic data acquired with simultaneous sources. The processor may update the primary signal estimate based at least in part on a separation operation that separates coherence signals from noise signals in an output associated with the residual determined to be remaining energy for separation. The processor may be incorporated into the iterative primary signal estimate of the deblending process or be applied towards preexisting deblending output. In response to satisfying an end condition, the processor may transmit a deblended output that includes the weak coherence signals recovered from the misallocation or error in the primary signal estimate. The processor may also transmit the deblended output for use in generating a seismic image. The seismic image may represent hydrocarbons in a subsurface region of Earth or subsurface drilling hazards.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
46.
METHOD AND APPARATUS FOR AUTOMATICALLY DETECTING FAULTS USING DEEP LEARNING
A method includes receiving image data that is to be recognized by the at least one neural network. The image data is representative of a fault within a subsurface volume. The image data includes three-dimensional synthetic data. The method also includes generating an output via the at least one neural network based on the received image data. The method also includes comparing the output of the at least one neural network with a desired output; and modifying the neural network so that the output of the neural network corresponds to the desired output.
Fatty acyl-ACP reductase (FAR) enzymes are provided, along with their use in the production of fatty alcohol compositions in heterologous recombinant cells.
Lubricating compositions and base oils are provided including compositions comprising one or more ether moieties and one or more ester/carboxylic acid moieties used in lubricating compositions that may be derived from naturally occurring vegetable oils.
A method includes receiving a first transition probability matrix (TPM) of a subsurface region, wherein the TPM defines, for a given lithology at a current depth sample (or micro-layer), a probability of particular lithologies at a next depth sample (or micro-layer), receiving seismic data for the subsurface region, utilizing the first TPM and the seismic data to generate first pseudo wells, calculating a second TPM from the first pseudo wells, determining whether the second TPM is consistent with the first TPM, and utilizing the first pseudo wells to characterize a reservoir in the subsurface region when the second TPM is determined to be consistent with the first TPM.
A method of seismic exploration above a region of the subsurface of the earth containing structural or stratigraphic features conducive to the presence, migration, or accumulation of hydrocarbons comprises setting a tow depth of a resonant seismic source, producing a resonant frequency at a first amplitude with the resonant seismic source at the tow depth, detecting a depth excursion from the tow depth, reducing an amplitude of the mass from the first amplitude to a second amplitude, preventing the mass from contacting at least one of the first end stop or the second end stop based on reducing the amplitude to the second amplitude, correcting the depth excursion to return the resonant seismic source to the tow depth, and increasing the amplitude from the second amplitude to produce the resonant frequency with the resonant seismic source at the tow depth.
The present invention relates to lubricating compositions comprising sulfur-containing additives as anti-wear and/or extreme pressure additives, methods of preparing the same and uses thereof. The sulfur-containing additive is free of disulfide and polysulfide bonds and/or comprises at least one sulfur-containing moiety, wherein the sulfur-containing moiety comprises vicinal dithioethers. In a particularly preferred embodiment, the sulfur-containing additive is compound of Formula 2 as defined herein.
A method for determining a rate at which solid particles settle from a liquid in a slurry includes (a) mixing the solid particles and the liquid to form the slurry. In addition, the method includes (b) placing the slurry in an inner cavity of a vessel. Further, the method includes (c) measuring a hydrostatic pressure of the slurry at a bottom of the inner cavity over a period of time after (b). The method also includes (d) determining a quantity of the solid particles that settle from the liquid as a function of time over the period of time using the hydrostatic pressure measurements from (c).
A system for remediating a blockage(120) in a subsea component (110) including a riser (60) extending from a surface vessel (12), a flexible jumper (70) having an upper end coupled to the riser and a lower end coupled to a subsea component (110), and a surface system (20) disposed on the surface vessel (12) and including flexible tubing (24) configured to be inserted and advanced through the tubular string (60) and flexible jumper (70) to the blockage (120).
E21B 19/22 - Handling reeled pipe or rod units, e.g. flexible drilling pipes
E21B 37/06 - Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting the deposition of paraffins or like substances
F16L 1/26 - Repairing or joining pipes on or under water
54.
PROCESS FOR MANUFACTURING AROMATIC CARBOXYLIC ACIDS
A process for manufacturing a carboxylic acid is provided. In one aspect, process for comprises oxidizing in a reaction zone a feedstock comprising a substituted aromatic hydrocarbon in the presence of an oxidation catalyst and monocarboxylic acid solvent under reaction conditions suitable to form a reaction mixture comprising the aromatic carboxylic acid and a gaseous effluent, the gaseous effluent being at least partially communicated to a first stage of a fractionation zone. The process further comprises determining the reaction temperature and the reaction pressure in the reaction zone (e.g., by directly measuring the temperature and pressure, or by measuring the temperature and pressure of the gaseous effluent and applying a bias), and measuring the oxygen concentration of the gaseous effluent (e.g., to calculate the water concentration in the reaction zone). The process further comprises condensing at least part of the gaseous overhead stream to form a water-containing condensate (e.g., in a second stage of the fractionation zone or in a condensing zone), and transferring at least part of the water-containing condensate to an upper portion of the first stage of the fractionation zone, wherein the rate of introduction of water to the upper portion of the first stage of the fractionation zone is controlled to maintain a water concentration in the reaction zone in the range of 8 wt.% to 20 wt.% (e.g., in the range of 12 wt.% to 16 wt.%).
C07C 51/265 - Preparation of carboxylic acids or their salts, halides, or anhydrides by oxidation with molecular oxygen of compounds containing six-membered aromatic rings without ring-splitting having alkyl side chains which are oxidised to carboxyl groups
Methods and associated systems are disclosed for performing a logging operation within a subterranean wellbore extending within a subterranean reservoir. In an embodiment, the method includes (a) emitting neutrons into the subterranean wellbore or the subterranean reservoir, and (b) detecting gamma rays emitted from atoms disposed within the subterranean wellbore or the subterranean reservoir. In addition, the method includes (c) determining a first gamma ray count within a first energy window of the gamma rays detected at (b), and (d) determining a second gamma ray count within a second energy window of the gamma rays detected at (b). The second energy window is different than the first energy window. Further, the method includes (e) calculating a ratio of the first gamma ray count to the second gamma ray count.
G01V 5/10 - Prospecting or detecting by the use of nuclear radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
56.
MULTI-PART PROJECTILE FOR PERCUSSION SIDEWALL CORING AND METHODS FOR USING SAME TO EXTRACT A CORE
A percussion side wall core (PSWC) bullet has a central axis, a leading end, and a trailing end axially opposite the leading end. In addition, the bullet includes a first portion extending axially from the leading end of the bullet. Further, the bullet includes a second portion removably coupled to the first portion. The second portion extends axially from the trailing end of the bullet. The bullet also includes a sleeve removably positioned in the first portion. The sleeve includes an inner cavity configured to receive a core sample.
E21B 49/04 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by mechanically taking samples of the soil using projectiles penetrating the wall
G01N 23/04 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by transmitting the radiation through the material and forming images of the material
57.
SEPARATION OF MULTIPLE SEISMIC SOURCES OF DIFFERENT TYPES BY INVERSION
A method of seismic exploration above a region of the subsurface containing structural or stratigraphic features conducive to the presence, migration, or accumulation of hydrocarbons comprises accessing at least a portion of a blended seismic source survey, separating the at least two interfering seismic source excitations using inversion separation, producing one or more source gathers based on the separating, and using the one or more source gathers to explore for hydrocarbons within said region of the subsurface. The blended source seismic survey contains at least two interfering seismic source excitations therein, and the seismic source excitations can be produced by seismic source types having different signatures or frequency characteristics.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
G01V 1/00 - Seismology; Seismic or acoustic prospecting or detecting
G01V 1/38 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for water-covered areas
58.
MACHINE LEARNING-BASED ANALYSIS OF SEISMIC ATTRIBUTES
Systems and methods are disclosed that include generating reservoir property profiles corresponding to reservoir properties for pseudo wells based on reservoir data, generating seismic attributes for the pseudo wells, and training a machine learning model by comparing the reservoir property profiles against the seismic attributes. In this manner, the machine learning model may be used to predict reservoir properties for use with seismic exploration above a region of a subsurface that contains structural or stratigraphic features conducive to a presence, migration, or accumulation of hydrocarbons.
Solid/liquid separation processes using a large pore filter. One aspect of the disclosure is a process comprising filtering a solid/liquid mixture of a collection of solid aromatic carboxylic acid particles in a solvent in a first zone of a rotary pressure filter apparatus to form a filter cake on a filter surface, and removing the filter cake from the filter surface.
B01D 33/09 - Filters with filtering elements which move during the filtering operation with rotary cylindrical filtering surfaces, e.g. hollow drums arranged for inward flow filtration with surface cells independently connected to pressure distributors
C07C 51/47 - Separation; Purification; Stabilisation; Use of additives by chemisorption
B01D 33/60 - Handling the filter cake in the filter for purposes other than for regenerating for washing
B01D 33/62 - Handling the filter cake in the filter for purposes other than for regenerating for drying
C07C 51/265 - Preparation of carboxylic acids or their salts, halides, or anhydrides by oxidation with molecular oxygen of compounds containing six-membered aromatic rings without ring-splitting having alkyl side chains which are oxidised to carboxyl groups
60.
SYSTEMS AND METHODS FOR ESTIMATING MECHANICAL PROPERTIES OF ROCKS USING GRAIN CONTACT MODELS
A method for analyzing a rock sample to determine a mechanical property of the rock sample includes (a) segmenting a digital image volume corresponding to an image of the rock sample. In addition, the method includes (b) partitioning the digital image volume to associate a plurality of voxels in the digital image volume with a plurality of grains of the rock sample. Further, the method includes (c) determining the voxels of the plurality of voxels that are adjacent to each other to identify a plurality of contact interfaces between the grains. Still further, the method includes (d) determining a contact area of each of the contact interfaces using adjacent voxels at the corresponding grain-grain interface. The method also includes (e) determining a number of contact interfaces that each grain of the plurality of grains has with each adjacent grain. Moreover, the method includes (f) determining the one or more mechanical properties of the rock sample based on the number of the contact interfaces of each of the plurality of grains and the contact area of each of the contact interfaces.
Bypass devices are disclosed for providing alternative flow paths within an annulus formed around a production string of a subterranean wellbore. In some embodiments, the bypass devices include inlet flow paths and outlet flow paths in fluid communication with the annulus so that fluids may flow through the inlet and outlet flow paths to bypass a blockage in the annulus. The bypass devices are also configured to avoid internal blockages within the internal flow paths defined by the inlet flow paths and outlet flow paths.
A recombinant filamentous fungi that includes reduced 2-Keto-3-Deoxy-Gluconate (KDG) aldolase enzyme activity as compared to the filamentous fungi not transformed to have reduced KDG aldolase enzyme activity is provided. Also provided is a method of producing KDG
A velocity model is generated based upon seismic waveforms via any seismic model building method, such as full waveform inversion or tomography. Data representative of a measurement of a physical attribute of an area surrounding a well is received and an attribute model is generated based upon the velocity model and the data. An image is rendered based upon the attribute model for use with seismic exploration above a region of a subsurface comprising a hydrocarbon reservoir and containing structural or stratigraphic features conducive to a presence, migration, or accumulation of hydrocarbons.
Systems and methods that include receiving reservoir data of a hydrocarbon reservoir, receive an indication related to selection of a wavefield propagator, application of the wavefield propagator utilizing Fourier Finite Transforms and Finite Differences to model a wavefield associated with a Tilted Orthorhombic media representative of a region of a subsurface comprising the hydrocarbon reservoir, and processing the reservoir data in conjunction the wavefield propagator to generate an output for use with seismic exploration above a region of a subsurface comprising the hydrocarbon reservoir and containing structural or stratigraphic features conducive to a presence, migration, or accumulation of hydrocarbons.
A method of determining the identity of a petroleum coke sample including obtaining a nuclear magnetic resonance (NMR) measurement of the sample, determining a relaxation decay value of a fluid in the sample from the NMR measurement, comparing the relaxation decay value to relaxation decay values of known petroleum coke materials in a reference group to determine whether the petroleum coke is one of the known materials.
G01N 24/08 - Investigating or analysing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
G01N 15/08 - Investigating permeability, pore volume, or surface area of porous materials
G01R 33/44 - Arrangements or instruments for measuring magnetic variables involving magnetic resonance using nuclear magnetic resonance [NMR]
A method includes receiving, via a processor, a first seismic dataset generated using a first type of survey system. The method further includes receiving, via the processor, a second seismic dataset generated using a second type of survey system. The method additionally includes determining a frequency band in which to combine the first seismic dataset with the second seismic dataset to generate a combined dataset and generating a seismic image based upon the combined dataset, wherein the seismic image represents hydrocarbons in a subsurface region of the Earth or subsurface drilling hazards.
G01V 1/36 - Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
G01V 1/38 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for water-covered areas
A method for retrofitting a system for recovering paraxylene. The system is retrofitted with a pressure swing adsorption unit and a second isomerization reactor. The retrofit lowers the variable cost of the plant, while providing the opportunity to maintain existing equipment and furnace and refrigeration duty.
C07C 5/22 - Preparation of hydrocarbons from hydrocarbons containing the same number of carbon atoms by isomerisation
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
A method of recovering paraxylene in a crystallization zone. The crystallization zone includes at least two crystallization stages and two reslurry stages. The method provides for lower throughput through the crystallization zone, resulting in lower capital costs, reduced electricity in operating separation equipment, as well as reduced refrigeration duty.
C07C 7/00 - Purification, separation or stabilisation of hydrocarbons; Use of additives
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
C07C 7/14 - Purification, separation or stabilisation of hydrocarbons; Use of additives by crystallisation; Purification or separation of the crystals
69.
METHOD OF RECOVERING PARAXYLENE IN A PRESSURE SWING ADSORPTION UNIT WITH VARYING HYDROGEN PURGE FLOW DIRECTION
A method of recovering paraxylene in a pressure swing adsorption unit with varying hydrogen purge pressures. The pressure swing adsorption zone is adapted to adsorb and desorb paraxylene based on the cycling of partial pressure in the zone. A first hydrogen purge is fed concurrent to the feed. A second hydrogen purge is countercurrent to the feed.
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
A method of recovering paraxyiene in a pressure swing adsorption unit with varying hydrogen purge pressures. The pressure swing adsorption zone is adapted to adsorb and desorb paraxyiene based on the cycling of partial pressure in the zone. A first hydrogen purge fed to the zone is within 50 psi of the adsorption pressure of paraxyiene in the zone. A second hydrogen purge fed to the zone is within 50 psi of the desorption pressure of paraxyiene in the zone. The overall amount of hydrogen necessary to operate the pressure swing adsorption zone is reduced and heat may be recovered from the effluent leaving the pressure swing adsorption zone.
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
A method for recovering paraxylene from a mixture of aromatic hydrocarbons. The process uses a pressure swing adsorption zone followed by a paraxylene recovery zone. The invention provides for lower throughput through the paraxylene recovery zone, resulting in lower capital costs and operating costs.
C07C 5/27 - Rearrangement of carbon atoms in the hydrocarbon skeleton
C07C 7/04 - Purification, separation or stabilisation of hydrocarbons; Use of additives by distillation
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
C07C 7/13 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers by molecular-sieve technique
C07C 7/14 - Purification, separation or stabilisation of hydrocarbons; Use of additives by crystallisation; Purification or separation of the crystals
A method for the recovery paraxylene with reduced crystallization. Paraxylene is recovered from a mixture of C8 aromatic hydrocarbons in a pressure swing adsorption zone and a crystallization zone. The invention provides for lower throughput through the crystallization zone, resulting in lower capital costs, reduced electricity in operating separation equipment, as well as reduced refrigeration duty.
C07C 5/22 - Preparation of hydrocarbons from hydrocarbons containing the same number of carbon atoms by isomerisation
C07C 7/12 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers
C07C 7/13 - Purification, separation or stabilisation of hydrocarbons; Use of additives by adsorption, i.e. purification or separation of hydrocarbons with the aid of solids, e.g. with ion-exchangers by molecular-sieve technique
C07C 7/14 - Purification, separation or stabilisation of hydrocarbons; Use of additives by crystallisation; Purification or separation of the crystals
A method for perforating a tubular string (30) disposed in a wellbore (20) includes transmitting a first firing signal from a control system disposed at the surface of the wellbore along an electrical cable (42) extending to a first addressable detonator assembly (160) of a first perforating tool (100A). In addition, the method includes firing a first shaped charge (150) disposed in a first thermally insulating container (142) of the first perforating tool (100A) in response to the first addressable detonator assembly (160) receiving the first firing signal. The first addressable detonator assembly (160) is ballistically coupled to the first shaped charge (150). Further, the method includes firing a second shaped charge (150) disposed in a second thermally insulating container (142) of a second perforating tool using a second addressable detonator assembly (160) disposed with respect to the second thermally insulating container that is ballistically coupled to the second shaped charge (150).
A method for cementing a borehole includes pumping a collection of fluids into the borehole through a tubular string in the borehole, flowing the collection of fluids up an annulus positioned between the tubular string and a sidewall of the borehole, monitoring a volume of the fluids pumped into the borehole, performing a first estimation of a position of the fluids based on the volume of the collection of fluids pumped into the borehole, and an initial estimate of an average diameter of the sidewall of at least a portion of the borehole, calculating a corrected estimate of the average diameter based on the first estimation and a pressure of the fluids measured at an inlet of the tubular string, and performing a second estimation of the position of the fluids based on the volume of the fluids pumped into the borehole and the corrected estimate of the average diameter.
A system for monitoring a condition of a component of a well system located proximate to a seabed includes a first sensor assembly to couple to a telescopic joint coupled to an upper end of a riser, wherein the first sensor assembly is configured to measure at least one of a vibration, an inclination, and a strain in the riser, and a data processing system in signal communication with the first sensor assembly, wherein the data processing system is configured to estimate the condition of a subsea stack system based on measurements provided by the first sensor assembly.
A hydrocarbon production system includes a well at a remote location. The well is configured to produce hydrocarbon production fluids comprising natural gas. The system also includes a turbo-generator coupled to the well and configured to receive the natural gas and produce electricity from the natural gas. In addition, the system includes a high performance computing (HPC) data center coupled to the turbo-generator and configured to be powered by the electricity from the turbo-generator.
Processes for manufacturing purified aromatic carboxylic carboxylic acids includes: generating high-pressure steam (402) from boiler feed water supplied to a boiler (404); heating a crude aromatic carboxylic acid using the high-pressure steam (402), whereby the high pressure steam (402) is condensed to form a high-pressure condensate (426); and purifying the crude aromatic carboxylic acid to form a purified aromatic carboxylic acid. The boiler feed water includes at least a portion of the high-pressure condensate (426) and makeup boiler feed water from at least one additional source. The recycled high-pressure condensate (426) is pre-heated with an electric heater (480) using electricity generated in an off-gas treatment zone (350).
A method of detecting corrosion in a conduit or container comprises measuring the thickness of a wall of the conduit or container with one or more pulse-echo ultrasound devices, wherein the method comprises the following steps: (i) receiving signals indicative of A-scan data from the one or more pulse-echo ultrasound devices, wherein the A-scan data comprises a plurality of A-scan spectra; (ii) determining which of the A-scan spectra have a distorted waveform such that a reliable wall thickness measurement cannot be determined; (iii) analysing the A-scan spectra identified in step (ii) as having a distorted waveform to determine one or more A-scan spectral characteristics of each spectrum that are causing the distortion; (iv) resolving the waveform characteristics based on the determined spectral characteristics causing the waveform distortion so as to produce modified A-scan spectra; (v) determining thickness measurements of the wall based on the modified A-scan spectra; and (vi) determining the extent to which the wall has been corroded based on the thickness measurements determined in step (v) and additional thickness measurements determined from A-scan spectra.
Processes for manufacturing purified aromatic carboxylic acids include: generating high-pressure steam from boiler feed water supplied to a boiler, the boiler producing a flue gas; removing a portion of the flue gas from the boiler and pre-heating the boiler feed water with removed flue gas and/or pre heating at least a portion of the boiler feed water prior to its introduction into the boiler with a first portion of the high-pressure steam; heating a crude aromatic carboxylic acid in a heating zone using the high-pressure steam, whereby the high pressure steam is condensed in the heating zone to form a high-pressure condensate; and purifying the crude aromatic carboxylic acid to form a purified aromatic carboxylic acid; wherein the boiler feed water comprises at least a portion of the high-pressure condensate.
A process for manufacturing a purified aromatic carboxylic acid is provided. The process comprises purifying a crude aromatic carboxylic acid in a purification zone to form a purified aromatic carboxylic acid; crystallizing a purified aromatic carboxylic acid in a crystallization zone to form a solid/liquid mixture comprising purified aromatic carboxylic acid solids; filtering the solid/liquid mixture through a filter member of a rotary pressure filter apparatus to form a filter cake comprising the purified aromatic carboxylic acid solids; removing the filter cake from the filter member; rinsing the filter member to produce a filter rinse product, wherein the filter rinse product comprises purified aromatic carboxylic acid; and directing at least a portion of the filter rinse product downstream of the purification zone for recycle to the rotary pressure filter apparatus.
A method for drilling a wellbore with an offshore, riserless drilling system, the method includes pumping a drilling fluid from a drilling vessel down a first drillstring and into an annulus within a subterranean wellbore, pumping the drilling fluid from the annulus of the wellbore to the drilling vessel with a subsea pump, applying backpressure to the drilling fluid in the annulus of the wellbore with the subsea pump, and preventing fluid flow from the annulus of the wellbore to the surrounding environment as the drilling fluid is pumped from the drilling vessel into the annulus of wellbore.
A method for mitigating a fluid flow from a target wellbore using a relief wellbore includes receiving wellbore geometry information of the target wellbore, receiving an initial interception point of the target wellbore, simulating a change in a three-dimensional flow characteristic of a kill fluid flow from a simulated relief wellbore and a target fluid flow from a simulated target wellbore resulting from an interaction between the kill fluid flow and the target fluid flow at the initial interception point, the simulated target wellbore designed using the received wellbore geometry information, and determining a final interception point of the target wellbore based on the simulation.
A method for drilling a wellbore includes pumping a drilling fluid from a drilling vessel (102) into a wellbore through a drillstring (142) extending through a marine riser (106) into the wellbore with a surface pump (112). The marine riser (106) extends from the drilling vessel (102) to a subsea blowout preventer (104). The method also includes pumping the drilling fluid from a first annulus (146A) in the riser (106) to a second annulus (146B) in the riser (106) with a subsea pump (126) positioned between the blowout preventer (104) and the drilling vessel (102). The first annulus (146A) is disposed below the second annulus (146B). Further, the method includes adjusting a pump rate of the subsea pump to control the amount of backpressure trapped in the wellbore.
E21B 33/076 - Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
84.
PROCESSES FOR MANUFACTURING AROMATIC CARBOXYLIC ACIDS
A process for manufacturing a carboxylic acid is provided, in one aspect, the process comprises oxidizing a feedstock comprising a substituted aromatic hydrocarbon to form a liquid-phase aromatic carboxylic acid; crystallizing at least a portion of the liquid- phase aromatic carboxylic acid in the presence of oxygen and an oxidation catalyst in a first crystallizer to form solid aromatic carboxylic acid, under reaction conditions suitable to oxidize unreacted feedstock to form additional aromatic carboxylic acid; and crystallizing at least a portion of the first crystallization effluent in the presence of oxygen and an oxidation catalyst in a second crystallizer to form additional solid aromatic carboxylic acid, under reaction conditions suitable to oxidize unreacted feedstock to form additional aromatic carboxylic acid, wherein the oxygen is present in a gaseous phase inside the second crystallizer in an amount of no more than 11 % by volume on a dry basis.
C07C 51/265 - Preparation of carboxylic acids or their salts, halides, or anhydrides by oxidation with molecular oxygen of compounds containing six-membered aromatic rings without ring-splitting having alkyl side chains which are oxidised to carboxyl groups
A process for optimising the removal of calcium from a hydrocarbon feedstock in a refinery desalting process, the refinery desalting process comprising the following steps: (a) mixing one or more wash water streams with one or more hydrocarbon feedstock streams; (b) at least partially separating the wash water from the hydrocarbons in a refinery desalter; and (c) removing the separated water and hydrocarbons from the refinery desalter as one or more desalted hydrocarbon streams and one or more effluent water streams; the process optimisation comprising: (i) providing at least one x-ray fluorescence analyser at at least one point in the refinery desalting process; (ii) measuring the concentration of calcium at the at least one point in the process using the at least one x-ray fluorescence analyser; and (iii) optionally adjusting at least one process condition of the refinery desalting process in response to the calcium concentration measurement in step (ii). An apparatus comprises a desalter; a line through which one or more hydrocarbon feedstock streams are passed to the desalter; optionally a line through which one or more wash water streams are passed to the desalter; and one or more x-ray fluorescence analysers configured so as to measure the concentration of calcium in water or hydrocarbons at one or more positions within the apparatus.
C10G 31/08 - Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
G01N 23/223 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by measuring secondary emission from the material by irradiating the sample with X-rays or gamma-rays and by measuring X-ray fluorescence
86.
TOOLS FOR SELECTING AND SEQUENCING OPERATING PARAMETER CHANGES TO CONTROL A HYDROCARBON PRODUCTION SYSTEM
BP EXPLORATION OPERATING COMPANY LIMITED (United Kingdom)
Inventor
Dumenil, Jean-Charles
Heddle, Richard
Wang, Shaojun
Abstract
A process for use in managing a hydrocarbon production system includes: selecting, from among a plurality of changes proposed to operating parameters of the hydrocarbon production system, the proposed change with the greatest estimated positive change in production; assessing whether the selected change violates an operating constraint; based on said assessment, producing a valid change based on at least the selected change or identifying the selected change as an unusable change, iterating the above steps, the iteration excluding the valid change from the plurality of proposed changes; and implementing at least one valid change, the number of implemented valid changes being less than the number of proposed changes.
Processes for recovering a purified aromatic carboxylic acid include contacting a crude aromatic carboxylic acid with hydrogen in the presence of a catalyst in a hydrogenation reactor to form a purified aromatic carboxylic acid; crystallizing the purified aromatic carboxylic acid to form a solid/liquid mixture comprising purified aromatic carboxylic acid solids; filtering the solid/liquid mixture in a rotary pressure filter apparatus to remove a liquid filtrate, washing the solid/liquid mixture in the rotary pressure apparatus with a wash fluid to form a washed solid/liquid mixture, and drying the washed solid/liquid mixture in the rotary pressure apparatus with an inert gas to form a filter cake comprising purified aromatic carboxylic acid solids and a wet gas stream; withdrawing the wet gas stream from the rotary pressure filter apparatus while maintaining the wet gas stream at a pressure above ambient; and recovering the purified aromatic carboxylic acid solids from the filter cake.
A method for stimulating a well extending through a subterranean formation includes (a) introducing a first fracturing fluid into the subterranean formation, and (b) introducing a second fracturing fluid into the subterranean formation that is different in composition from the first fracturing fluid, wherein the second fracturing fluid comprises a temporary diverting agent.
Processes for manufacturing a purified aromatic carboxylic acid include contacting crude aromatic carboxylic acid with hydrogen in the presence of a catalyst in a hydrogenation reactor to form a purified aromatic carboxylic acid; separating vapor effluent from the purified aromatic carboxylic acid; scrubbing the vapor effluent to form a scrubber effluent; treating the scrubber effluent vapor to form a gaseous treated scrubber effluent and a liquid treated scrubber effluent; and removing at least a portion of organic impurities from the liquid treated scrubber effluent.
Processes for manufacturing a purified aromatic carboxylic acid include oxidizing a substituted aromatic compound in a reaction zone to form a crude aromatic carboxylic acid and a gaseous stream; heating the crude aromatic carboxylic acid in a pre-heating zone, contacting the crude aromatic carboxylic acid with hydrogen in the presence of a catalyst in a hydrogenation reactor to form a purified aromatic carboxylic acid, crystallizing the purified aromatic carboxylic acid in a crystallization zone to form a slurry stream comprising solid purified aromatic carboxylic acid and a vapor stream. At least a portion of the vapor stream is directed to the pre-heating zone and at least a portion of the vapor stream from the pre-heating zone is vented to the off-gas treatment zone in order to achieve energy savings.
C07C 51/265 - Preparation of carboxylic acids or their salts, halides, or anhydrides by oxidation with molecular oxygen of compounds containing six-membered aromatic rings without ring-splitting having alkyl side chains which are oxidised to carboxyl groups
C07C 51/42 - Separation; Purification; Stabilisation; Use of additives
A method for predicting the critical solvent power of a visbroken residue stream of interest, CSPVisRes(OI) comprises predicting CSPVisRes(OI) from the critical percentage titrant of an atmospheric residue stream, CPTAR, the atmospheric residue stream being derived from the same crude oil as the visbroken residue stream of interest. A method for predicting the solvent power of a visbroken residue stream of interest, SPVisRes(OI), comprises predicting SPVisRes(OI) from the critical solvent power of the visbroken residue stream, CSPVisRes, and the critical percentage titrant of the visbroken residue stream, CPTVisRes. CPTVisRes is derived from the critical percentage cetane of the visbroken residue stream, CPCVisRes, which, in turn, is calculated from the P-value of the visbroken residue stream. The methods may be used to predict the stability of a fuel oil containing the visbroken residue.
A method for use in seismic exploration includes: obtaining a diving wave illumination image of a subterranean region from a set of seismic data representative of the subterranean region using a selected acquisition geometry; clipping an inverse of the diving wave illumination image to a range of values; and performing a weighted full-waveform inversion. The weighted full-waveform inversion further includes: weighting a full-waveform inversion gradient with the clipped inverse of the diving wave illumination image; and performing the full-waveform inversion using the weighted gradient.
A technique for estimating a depth of investigation of a seismic survey includes in various aspects a method and an apparatus. The method is for use in seismic exploration and includes: forward modeling on a subsurface attribute model of a subterranean region to generate a set of low frequency seismic data, the subsurface attribute model being generated from data representative of the subterranean region; performing a reverse time migration on the low frequency seismic data to obtain a plurality of gathers with large opening angles; stacking the gathers to yield a diving wave illumination image; and estimating a full-waveform inversion depth of investigation from the diving wave illumination image. The apparatus may include a computing apparatus programmed to perform the method and/or a program storage medium encoded with computing instructions that, when executed, perform the method.
A method is provided for gravel packing an open hole section of a hydrocarbon producing well (10). The method includes injecting a slurry comprising particulates dispersed in a carrier fluid into an annular space (60) in the open hole section of the wellbore, and depositing the particulates in the annular space to form a gravel pack (70). Typically, inter-granular bonds form among the particulates, and thus form the gravel pack. In some embodiments, the inter-granular bonds generate grain-to-grain compressive strength which is strong enough to keep the gravel pack immobile.
A method for analyzing a rock sample includes segmenting a digital image volume corresponding to the rock sample, to associate voxels in the digital image volume with pore space or solid material. A distance transform is applied to each pore space voxel. The distance transform assigns a distance value to the pore space voxel specifying distance from the pore space voxel to a solid material voxel. Drainage is numerically simulated by, for a pore space, selecting each distance value assigned to a pore space voxel that is greater than a predetermined threshold value to represent a radius of a sphere of a non-wetting fluid introduced into the pore space. The sphere is centered at the pore space voxel corresponding to the distance value. The digital image volume is numerically analyzed to characterize a material property of the rock sample at a non-wetting fluid saturation produced by the drainage.
A method comprises correlating - in a system which comprises a non-aqueous phase comprising a hydrocarbon fluid, and an aqueous phase - partitioning levels of a basic contaminant and/or an acid of interest into the aqueous phase with the pH of the aqueous phase. The partitioning levels of the basic contaminant and the acid of interest, as well as the pH of the aqueous phase, are obtained under conditions which are representative of those used in a partitioning process in which a basic contaminant is removed from a hydrocarbon fluid. The correlations may be used in a method for selecting an acidic environment for use in a partitioning process, for estimating corrosion risk downstream of a partitioning process, or for controlling a partitioning process.
C10G 31/08 - Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
C10G 33/00 - De-watering or demulsification of hydrocarbon oils
C10G 17/00 - Refining of hydrocarbon oils, in the absence of hydrogen, with acids, acid-forming compounds, or acid-containing liquids, e.g. acid sludge
C10G 21/06 - Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
97.
SYSTEM AND METHOD FOR DRILLING RIG STATE DETERMINATION
A system and method for drilling a borehole in a subsurface formation. A method includes receiving measured values indicative of operations performed by drilling equipment. The measured values include hookload values. The hookload values are analyzed to identify hookload values acquired while connecting a drill pipe, and a block weight value is set based on such a hookload value. The block weight value is subtracted from the hookload values to produce rebased hookload values. A rig state model produces a value for a state of the drilling equipment based on the measured values and the rebased hookload values. Responsive to the state of the drilling equipment, an operation performed to drill the subsurface formation is changed.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 7/02 - Drilling rigs characterised by means for land transport, e.g. skid mounting or wheel mounting
98.
CONDITIONING A SAMPLE TAKEN FROM A HYDROCARBON STREAM
A process for analysing a hydrocarbon stream comprises: withdrawing a hydrocarbon sample from a hydrocarbon stream (12); passing the hydrocarbon sample to an analysis device (16) at a target temperature of greater than 120 °C and a target flow rate of greater than 20 litres per minute; and returning the hydrocarbon sample to the hydrocarbon stream (12). The process may be used for the on-line analysis of crude oil, in order to optimise a refinery operation.
A method for aligning a plurality of seismic images associated with a subsurface region of the Earth may include receiving the seismic images and determining a first respective relative shift volume between a first seismic image and a second seismic image, a second respective relative shift volume between the first seismic image and a third seismic image, and a third respective relative shift volume between the second seismic image and the third seismic image. The method may include determining a first shift volume associated with the first seismic image and a second shift volume associated with the second seismic image based on the first, second, and third respective relative shift volumes. The method may then apply the first shift volume to the first seismic image and the second shift volume to the second seismic image.
A method for determining a displacement seismic image between two seismic images may begin with receiving a first seismic image and a second seismic image. The method may then include generating a first scaled image based on the first seismic image and a second scaled image based on the second seismic image and determining a scaled displacement volume between the two scaled images using an optical flow algorithm. The method may then involve calculating a displacement volume based on the scaled displacement volume and a scaling function used to generate the scaled images. The method may then generate a third seismic image by applying the displacement volume to the second seismic image. The method may then involve determining the difference volume between the first seismic image and the third seismic image.
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