Aspects of the technology described herein make legacy hydrocarbon studies accessible to modern computer analysis. Whatever the initial format, the technology described herein analyzes the studies to identify characteristics that are interesting to people who study hydrocarbon environments. As an initial process, various segments within a hydrocarbon study received by the technology described herein are identified. The various segments can include text, maps, charts, and tables. Within each of these segments, specific types of text segments, maps, charts, and tables may be identified. For each segment identified, characteristics of interest may be determined through analysis of the segment. In one aspect, segment-specific analysis is performed on each type of segment. Different technologies may be used for different segments. Once the characteristics are identified, they may be stored in association with both the overall document and with a segment of the document from which the characteristic of interest was extracted.
Offshore systems and methods may be configured for oil production, offshore power generation, ammonia production, and carbon dioxide injection for EOR. For example, a method performed on an offshore facility may include: separating a produced hydrocarbon into a produced gas and a produced oil; combusting the produced gas to produce power and a flue gas; at least partially removing nitrogen from the flue gas to produce a carbon dioxide-enriched flue gas and a nitrogen-enriched flue gas; reforming a portion of the produced gas to produce a stream including hydrogen and carbon dioxide; at least partially separating the carbon dioxide from the stream to yield a carbon dioxide stream and a hydrogen stream; reacting the hydrogen stream and the nitrogen-enriched flue gas to yield ammonia; combining and compressing the carbon dioxide stream and the carbon dioxide-enriched flue gas; and injecting the compressed gas from the gas compressor into the gas reservoir.
C01B 3/02 - Production of hydrogen or of gaseous mixtures containing hydrogen
C01B 3/48 - Production of hydrogen or of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents followed by reaction of water vapour with carbon monoxide
C09K 8/594 - Compositions used in combination with injected gas
B01J 19/24 - Stationary reactors without moving elements inside
E21B 43/16 - Enhanced recovery methods for obtaining hydrocarbons
F02C 6/00 - Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas-turbine plants for special use
A methodology for spatially identifying conductive regions using pressure transience for characterizing conductive fractures and subsurface regions is provided. Hydraulic fracturing is utilized to create fractures within a reservoir, thereby increasing fluid permeability of the reservoir and permitting hydrocarbon fluids to flow into a wellbore and subsequently to be produced from the hydrocarbon reservoirs. The geometry, dimensions, and extent of the fractures may significantly impact the production characteristics of the well. However, given that fractures are thousands of feet below the surface, measuring the properties of the fractures can be difficult. In order to characterize the fractures, including determining locations of conductive fractures in the subsurface, sensors are positioned in monitoring wells. Pressure changes are then induced in a well, with the sensors measuring the effect of the pressure changes. In turn, the sensed data may be used in order to characterize the fractures in the subsurface.
A method of attenuating annular pressure buildup within a wellbore. The method includes running first and second strings of casing into a wellbore, wherein the first string of casing surrounds an upper portion of the second string of casing forming an annular region. The method also includes providing a packing of compressible material within the annular region. The compressible material comprises carbonaceous particles. The particles may reside within a porous sleeve or filter, or they may be packed together in a matrix using a cross-linked polymer or binder. The packing is fixed at a selected depth within the annular region, and is designed so that the compressible material absorbs pressure in response to thermal expansion of wellbore fluids during the production of hydrocarbon fluids from the wellbore. The method further includes placing a wellhead over the wellbore, thereby forming a trapped annulus in the wellbore over the annular region.
Methods of facilitating human interpretation of a plurality of time-series datasets generated from operation of hydrocarbon wells. The methods include obtaining the plurality of time-series datasets and displaying a vector map. The plurality of time-series datasets is generated from an operation of the hydrocarbon well and includes a first time-series dataset and a second time-series dataset, and optionally may include a third time-series dataset. The vector map includes a time axis and a plurality of points distributed along the time axis at a plurality of corresponding times. A color of each point of the plurality of points is defined in a plural-component color space and includes a first color component at a first intensity and a second color component at a second color component at a second intensity, and optionally a third color component at a third intensity when the plurality of time-series datasets includes a third time-series dataset.
Aspects of the technology described herein identify geologic features within seismic data using modern computer analysis. An initial step is the development of training data for the machine classifier. The training data comprises an image of seismic data paired with a label identifying points of interest that the classifier should identify within raw data. Once the training data is generated, a classifier can be trained to identify areas of interest in unlabeled seismic images. The classifier can take the form of a deep neural network, such as a U-net. Aspects of the technology described herein utilize a deep neural network architecture that is optimized to detect broad and flat features in seismic images that may go undetected by typical neural networks in use. The architecture can include a group of layers that perform aspect ratio compression and simultaneous comparison of images across multiple aspect ratio scales.
A computer-implemented geological modeling method is disclosed. Hydraulic fracturing includes pumping fluids through a wellbore/casing and into a formation through perforations, creating fractures that can improve well productivity. Geological modeling may be used to model pumping of fluids into the subsurface to achieve a desired fracturing result. However, the grid used may affect the fracture propagation calculations used for geological modeling. Thus, a methodology is disclosed which reduces the grid dependence when determining various aspects of fracturing, such as pressure and/or aperture. The methodology uses a first correction factor that is based on the grid used to determine fracture propagation and a second correction factor that is not based on the grid used to determine fracture propagation (such as based on an ideal grid). In this way, the two correction factors are derived from different aspects, which when combined, may be used to reduce grid dependence when determining fracture propagation.
A method for classifying a microseismic event, including: analyzing microseismic event files through a combination of two fault tolerant machine learning pipelines, an acoustic machine learning pipeline and a visual machine learning pipeline; and generating a classification prediction for the microseismic event files by combining predictions from the acoustic machine learning pipeline and the visual machine learning pipeline.
Gravel packing particles like sand are commonly used in sand control operations to form gravel packs for controlling the migration of formation particulates into a wellbore and wellbore production equipment. Gravel packing fluids and methods of sand control operations may also use petroleum coke gravel packing particles composed of fluid coke and/or flexicoke material. Such petroleum coke gravel packing particles may have improved transport into wellbores because of their lower density compared to traditional gravel packing material and may produce fewer fines that can plug gravel packs.
A computer-implemented method for analyzing geophysical data is disclosed. Interpretation of geophysical data, such as seismic data, can be performed in multiple stages, such as at an information extraction stage and an information analysis stage. Typically, the information analysis stage is performed by geologists or interpreters, which may be laborious and inconsistent. The disclosed method includes using an information extractor that extracts information indicative of geo-features in a subsurface and an inference engine that analyzes the information indicative of geo-features in a subsurface to generate an output, with the information extractor and the inference engine being integrated and acting in combination. For example, the information extractor may generate summaries of the geo-features or answers to questions. In this way, the information extractor and the inference engine in combination may act synergistically, such as in the context of reasoning, natural language processing, and the outputs generated.
Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of high-flow polyolefin coated mineral particles (referred to as high-flow polyolefin coated mineral proppant particulates). In some instances, the high-flow polyolefin-coated mineral proppant particulates have a particle density of equal to or less than about 1.35 grams per cubic centimeter, and further may be prepared using a one-pot hot melt process.
A method and apparatus for performing geological reasoning, A method includes: obtaining subsurface data for a subsurface region; obtaining a knowledge model; extracting a structured representation from the subsurface data using the knowledge model; and performing geological reasoning with a graph network based on the knowledge model and the structured representation. A method includes performing geological reasoning with a knowledge model that includes a set of geoscience rules or a geoscience ontology. A method includes performing geological reasoning with a structured representation that includes a graph. A method includes performing geological reasoning by one or more of the following: question answering; decision making; assigning ranking; and assessing probability.
G01V 99/00 - Subject matter not provided for in other groups of this subclass
G06F 30/27 - Design optimisation, verification or simulation using machine learning, e.g. artificial intelligence, neural networks, support vector machines [SVM] or training a model
13.
STRUCTURED REPRESENTATIONS OF SUBSURFACE FEATURES FOR HYDROCARBON SYSTEM AND GEOLOGICAL REASONING
A method and apparatus for utilizing a structured representation of a subsurface region. A method includes obtaining subsurface data for the subsurface region; and extracting the structured representation from the seismic data by: identifying geologic and fluid objects in the seismic images, wherein each object corresponds to a node of the structured representation; and identifying relationships among the identified geologic and fluid objects, wherein each relationship corresponds to an edge of the structured representation. A method further includes determining object attributes, edge attributes, and/or global attributes from the subsurface data. A method further includes inferring information from the structured representation.
Methods include providing a natural gas stream; directing a first fraction of the natural gas stream to a bioreactor including a propagating culture of hydrocarbon degrading microbes; directing a second fraction of the gas stream to a local power generator and converting the natural gas stream to electricity and heat; using a dynamic control system to balance of the gas stream to the first fraction and the second fraction based on one or more of the availability of electricity from an electricity grid and the price of electricity from the electricity grid; powering, at least in part, the bioreactor with the electricity generated by the local power generator; and harvesting the hydrocarbon degrading microbes from the bioreactor as a biomass. Related systems are also provided.
Methods and systems for measuring cluster efficiency for stages of wellbores are provided herein. One method includes selecting a frequency band for generating broadband tube waves within the fluid column of the wellbore and generating the broadband tube waves within the fluid column of the wellbore using a pressure pulse generator that is hydraulically coupled to the wellbore. The method also includes recording data corresponding to the broadband tube waves and reflected broadband tube waves using pressure receivers that are hydraulically coupled to the wellbore. The pressure receivers are arranged into arrays with two or more pressure receivers in each array. The data recorded by the pressure receivers relate to characteristics of reflectors (including perforation cluster/fracture interfaces) within the wellbore. The method further includes processing the recorded data using interferometry and performing full waveform inversion(s) on the processed data to determine frequency-dependent, complex-valued reflection coefficients at each perforation cluster/fracture interface.
E21B 49/00 - 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
E21B 47/26 - Storing data down-hole, e.g. in a memory or on a record carrier
G01V 1/137 - Generating seismic energy using fluidic driving means, e.g. using highly pressurised fluids which fluids escape from the generator in a pulsating manner, e.g. for generating bursts
16.
RESIN-COATED PETROLEUM COKE AS PROPPANT PARTICULATE MATERIAL AND METHODS RELATED THERETO
Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of resin-coated petroleum coke (referred to as resin-coated petroleum coke proppant particulates). In some instances, the resin-coated petroleum coke proppant particulates have a particle density of equal to or less than about 1.7 grams per cubic centimeter and better resistance to creating fines when exposed to uniaxial stress.
Methods for completing hydrocarbon wells using variable rate fracturing are provided herein. One method includes positioning a perforation device within a tubular conduit of a downhole tubular, where the downhole tubular extends within a wellbore, and where the wellbore extends within a subsurface region, as well as perforating the downhole tubular using the perforation device to define perforations within the downhole tubular. The method also includes pumping a slurry including fracturing fluid and a lightweight proppant into the tubular conduit according to a variable pumping rate schedule to fracture zones of the subsurface region that are proximate to the perforations, forming corresponding fractures within the subsurface region. The method further includes flowing the slurry into the fractures, via the perforations, to prop the fractures with the lightweight proppant, where the lightweight proppant includes granules formed from a polyolefin, petroleum coke, and/or a polyaromatic hydrocarbon resin.
E21B 43/267 - Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
E21B 43/119 - Perforators; Permeators - Details, e.g. for locating perforating place or direction
C09K 8/80 - Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
18.
METHOD FOR DETERMINING AND IMPLEMENTING A DATA COLLECTION PROGRAM FOR ONE OR MORE PHASES OF HYDROCARBON EXTRACTION BASED ON SEQUENTIAL SUBSURFACE UNCERTAINTY CHARACTERIZATION
A method for determining and implementing a data collection program is disclosed. Data is typically collected in order to develop a subsurface model that can characterize a subsurface to assist in hydrocarbon management. However, it may be difficult to determine how much, or what type of data, to obtain so that the subsurface model is of sufficient certainty. In particular, parameters that define the model and outputs of the model (defined as quantities of interest (QoIs)) are subject to uncertainty. In order to reduce the uncertainty of the QoIs to an acceptable level, data collection programs are iteratively selected based on sequential subsurface uncertainty characterization. In this way, the data collection programs, when implemented, may collect a sufficient amount of data to reduce uncertainty of the subsurface model for subsequent use in hydrocarbon management.
A device and method for weld root hardening determination compensated for variations in distance between sensor and sample are disclosed. A sensor is used to determine hardness of a weld for weld fabrication quality control. Because of irregular weld protrusion geometry, there may be variations in the tip of the sensor and the surface, resulting in inconsistent measurements. To compensate, one or both of a positional compensation or a software compensation are performed. Positional compensation mechanically moves the tip of the sensor to within a predetermined range of the surface. Software compensation may at least partly compensate for the variation by using one part of the generated sensor data (such as the 1st harmonic signal) in order to modify another part of the generated sensor data (such as the 3rd harmonic signal). In this way, the sensor determination of hardness of the weld may be less dependent on the variations.
G01N 27/80 - Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating magnetic variables for investigating mechanical hardness, e.g. by investigating saturation or remanence of ferromagnetic material
G01N 33/207 - Welded or soldered joints; Solderability
20.
Hierarchical Building and Conditioning of Geological Models with Machine Learning Parameterized Templates and Methods for Using the Same
A hierarchical conditioning methodology for building and conditioning a geological model is disclosed. In particular, the hierarchical conditioning may include separate levels of conditioning of template instances using larger-scale data (such as conditioning using large-scale data and conditioning using medium-scale data) and using smaller-scale data (such as fine-scale data). Further, one or more templates, to be instantiated to generate the geological bodies in the model, may be selected from currently available templates and/or machine-learned templates. For example, the templates may be generated using unsupervised or supervised learning to re-parameterize the functional form parameters, or may be generated using statistical generative modeling.
G06F 30/13 - Architectural design, e.g. computer-aided architectural design [CAAD] related to design of buildings, bridges, landscapes, production plants or roads
21.
METHODS OF CHARACTERIZING ACOUSTIC OUTPUT FROM HYDROCARBON WELLS
Methods of characterizing acoustic output from a hydrocarbon well and hydrocarbon wells that include controllers that perform the methods are disclosed herein. The methods include receiving the acoustic output, determining a plurality of acoustic fingerprints, and electronically clustering the plurality of acoustic fingerprints. The acoustic output includes information regarding a plurality of sound events, and each sound event of the plurality of sound events includes at least one corresponding sound detected at the hydrocarbon well. The plurality of acoustic fingerprints includes a corresponding acoustic fingerprint for each sound event of the plurality of sound events. The electronically clustering includes utilizing a clustering algorithm to generate a plurality of acoustic event clusters. Each acoustic event cluster of the plurality of acoustic event clusters includes a corresponding fingerprint subset of the plurality of acoustic fingerprints, and each acoustic fingerprint in the corresponding fingerprint subset includes at least one similar acoustic property.
G01V 1/40 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
E21B 47/095 - Locating or determining the position of objects in boreholes or wells; Identifying the free or blocked portions of pipes by detecting acoustic anomalies, e.g. using mud-pressure pulses
22.
AGE DIFFERENTIATION OF CRUDE OILS USING CHEMICAL FOSSIL ASSEMBLAGE
Age differentiation of hydrocarbon samples may be achieved using a chemical fossil assemblage approach. For example, a method may comprise: determining a source facies for a hydrocarbon sample; inputting the source facies into a chemical fossil assemblage model; determining, using the chemical fossil assemblage model, one or more candidate chemical fossil assemblages and corresponding age biomarkers for the hydrocarbon sample based on the source facies; measuring a concentration or a related value of corresponding age biomarkers in the hydrocarbon sample to yield an age biomarker fingerprint; inputting the age biomarker fingerprint into a chemical fossil assemblage model; comparing the age biomarker fingerprint to the one or more candidate chemical fossil assemblages using the chemical fossil assemblage model; and estimating an age of the hydrocarbon sample based on the comparison.
A computer-implemented method for augmented inversion and uncertainty quantification for characterizing geophysical bodies is disclosed. The method includes machine-learning-augmented inversion that also facilitates the characterization of uncertainties in geophysical bodies. The method may further estimate wavelets without a well-log calibration, thereby enabling a pre-discovery exploration phase when well log data is unavailable. The machine learning component incorporates a priori knowledge about the subsurface and physics, such as distributions of expected rock types and rock properties, geological structures, and wavelets, through learning from examples. The methodology also allows for conditioning the characterization with the information extracted a priori about the geobodies, such as probabilities of rock types, using other analysis tools. Thus, the conditioning strategy may make the inversion more robust even when a priori distributions are not well balanced. Using the method, a scenario testing workflow may evaluate different candidate subsurface models, facilitating the management of uncertainty in decision-making processes.
Methods for increasing ethane and non-freezing heavier hydrocarbons recovery in natural gas streams for the liquefaction of natural gas to form liquefied natural gas (LNG), and in particular, utilizing scrub columns to treat the natural gas feedstreams, are provided. Other independent variations of the methods are disclosed herein.
An intrinsically-safe sensor system, as well as a method for assembling the intrinsically-safe sensor system and a method for monitoring sound corresponding to a source using the intrinsically-safe sensor system, are provided herein. The intrinsically-safe sensor system includes a number of sensors, including a microphone, as well as a processor for processing sensor data obtained from the sensors. The intrinsically-safe sensor system also includes a memory component for storing the sensor data obtained from the sensors, a power source, a communication connection for communicably coupling the intrinsically-safe sensor system to a remote computing system, and a connector including internal and external connection regions for internally and/or externally connecting one or more additional devices to the intrinsically-safe sensor system on demand. The intrinsically-safe sensor system further includes an enclosure, as well as potting material for encapsulating an internal region of the intrinsically-safe sensor system that resides within the enclosure.
G01M 3/28 - Investigating fluid tightness of structures by using fluid or vacuum by measuring rate of loss or gain of fluid, e.g. by pressure-responsive devices, by flow detectors for valves
G01M 3/24 - Investigating fluid tightness of structures by using fluid or vacuum by detecting the presence of fluid at the leakage point using infrasonic, sonic, or ultrasonic vibrations
26.
Cable Guides for Supporting a Fiber Optic Cable with a Sensing Region Relative to a Tube, Hydrocarbon Conveyance Systems Including the Cable Guides, and Methods of Acoustically Probing an Elongate Region with a Hydrocarbon Conveyance System
Cable guides that support a fiber optic cable relative to a tube, hydrocarbon conveyance systems including the cable guides, and methods of acoustically probing an elongate region. The cable guides include a cable retention structure with a first retention region configured to align a first diffraction grating along a first sensing axis and a second retention region configured to align a second diffraction grating along a second sensing axis that is nonparallel to the first sensing axis. The tube defines a tubular conduit configured to convey a hydrocarbon. The hydrocarbon conveyance systems include a tube, a distributed acoustic sensor, and a cable guide. The methods include transmitting an initiated optical signal and receiving a reflected optical signal that includes reflected portions that are reflected by a first diffraction grating and a second diffraction grating. The methods further include analyzing the reflected optical signal to detect an applied mechanical strain.
Methods for utilizing an acid blend to prevent and/or remove blockages encountered during the hydraulic fracturing of a near-wellbore region of a subterranean formation are provided herein. The methods include using an acid blend to dissolve formation mineralogies within close proximity to perforations and corresponding fractures that have experienced or are likely to experience blockages, such as blockages caused by the embedment of proppant into the perforation tunnels and/or the fractures. The acid blend used according to the methods described herein includes an acid mixture including hydrochloric acid and hydrofluoric acid. In addition, the acid blend may also include a chelating agent.
An autonomous surface vessel includes an elongate body, and a sampling system operatively coupled to the body and including one or more sampling modules, wherein each sampling module includes a housing including a storage container, a sampling material receivable within the storage container, an actuation system operatively coupled to the sampling material via a lead line, and an end cap operatively coupled to the lead line and matable with an open end of the storage container. A computer system is in communication with the sampling system to operate the actuation system, wherein each sampling module is actuatable between a stowed state, where the sampling material is received within the storage container and the end cap sealingly engages the open end, and a deployed state, where the end cap is disengaged from the open end and the sampling material is drawn out of the sampling container.
A modular floating platform system includes a detachable floating buoy providing a body tethered to a seafloor with a plurality of mooring lines and coupled to a subsea production system via one or more communication lines, and a plurality of floating surface facilities, each floating surface facility providing a standardized bottom interface matable with the detachable floating buoy. A latching mechanism individually couples each floating surface facility to the detachable floating buoy when each floating surface facility is individually mated to the detachable floating buoy. One or more communication couplings place each floating surface facility in communication with the subsea production system via the one or more communication lines when each floating surface facility is individually mated to the detachable floating buoy.
B63B 22/02 - Buoys specially adapted for mooring a vessel
B63B 21/50 - Anchoring arrangements for special vessels, e.g. for floating drilling platforms or dredgers
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
30.
SYSTEMS AND METHODS FOR COOLING SEAWATER FOR HEAT EXCHANGE PROCESSES
Chilled seawater formed through interaction with a liquefied gas vaporizer may facilitate various types of heat exchange processes. The extent to which the seawater may be cooled is often limited by local environmental regulations for discharging the seawater once heat exchange has taken place. The foregoing issues may be addressed by systems comprising a liquefied gas vaporizer; a supply line configured to distribute seawater upon the liquefied gas vaporizer; a collection reservoir below the liquefied gas vaporizer configured to gather chilled seawater passing therethrough; a heat exchanger in fluid communication with the collection reservoir; and a heat exchanger outlet line configured to discharge heat-exchanged seawater to a sea location. The heat exchanger may be in direct or indirect thermal communication with a flow pathway for air provided to a gas engine or gas turbine, which may alter speed, power or efficiency of the gas engine or gas turbine.
F02C 7/143 - Cooling of plants of fluids in the plant of working fluid before or between the compressor stages
F02C 7/224 - Heating fuel before feeding to the burner
F02C 3/22 - Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products the fuel or oxidant being gaseous at standard temperature and pressure
31.
Methods of Increasing Efficiency of Plunger Lift Operations
Methods of increasing efficiency of plunger lift operations and hydrocarbon wells that perform the methods are disclosed herein. The methods include monitoring an acoustic output from the hydrocarbon well. The methods also include calculating a plunger speed of a plunger of the hydrocarbon well as the plunger travels toward a surface region and calculating a discharge duration of a liquid discharge time period during which liquid is discharged from the hydrocarbon well. The methods further include correlating the plunger speed and the discharge duration to a discharge volume of liquid discharged from the hydrocarbon well
A computer-implemented method for integrating a full wavefield inversion (FWI) solution with a non-FWI solution. Computational costs for generating a large bandwidth FWI solution, such as to 50 Hz, may be considerable. However, limiting the FWI solution to a narrower frequency band, such as up to 20 Hz, renders the FWI solution less useful. To remedy this, an FWI solution that is band limited, such as up to 20 Hz, is integrated with a non-FWI solution. The non-FWI solution may comprise seismic stacks or non-seismic data, and is directed to a different frequency band, with at least part of the non-FWI solution frequency band being greater than 20 Hz. In this way, bandwidth extension may be performed for at least one subsurface physical property parameter by combining a band limited FWI solution with a non- FWI solution.
Disclosed herein are methods that include producing oil and natural gas from a subterranean formation; separating the oil and the natural gas; dissolving at least a portion of the natural gas in water; exposing microorganisms that consume hydrocarbons to the water having the natural gas dissolved therein; and allowing higher-level organisms to consume the microorganisms.
A proppant including polyolefin-coke composite granules, a hydrocarbon well including such a proppant, and methods of forming the hydrocarbon well using such a proppant are provided herein. The hydrocarbon well includes a wellbore that extends within a subsurface region and a downhole tubular that extends within the wellbore and defines a tubular conduit. The hydrocarbon well also includes a number of perforations formed within the downhole tubular and a number of fractures formed within the subsurface region proximate to the perforations. The hydrocarbon well furthers include the proppant positioned within at least a portion of the fractures. The proppant includes a number of polyolefin-coke composite granules, where a characteristic dimension of each polyolefin-coke composite granule is at least 50 micrometers (μm) and at most 3 millimeters (mm), and where each polyolefin-coke composite granule includes a number of polyolefin polymer chains and at least one petroleum coke granule.
C09K 8/68 - Compositions based on water or polar solvents containing organic compounds
C09K 8/80 - Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
C09K 8/88 - Compositions based on water or polar solvents containing organic compounds macromolecular compounds
C09K 8/92 - Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
E21B 43/267 - Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
35.
PROPPANT PARTICULATES FORMED FROM DELAYED COKE AND METHODS FOR USING THE SAME
A fracturing fluid including proppant particulates formed from delayed coke, as well as a method for utilizing such fracturing fluid, are provided herein. The fracturing fluid includes a carrier fluid, as well as proppant particulates composed of delayed coke material. The method includes introducing the fracturing fluid into a subterranean formation and (optionally) depositing at least a portion of the proppant particulates within one or more fractures in the subterranean formation.
A method (400) for determining the geologic age of hydrocarbon samples, such as oils, using novel age biomarkers may comprise: measuring a concentration or related value of triaromatic dinosteranes (triaromatic 4,23,24-trimethyldinosteroids) (TAD) in a hydrocarbon sample, e.g. migrated oil sample, from a North Atlantic conjugate margin (NAM); calculating (426) a TAD index for the hydrocarbon sample based on the concentration or the related value of the TAD; and predicting (428) an age of the hydrocarbon sample based on a correlation (414) between a hydrocarbon age and the TAD index.
Methods and systems for generating a machine-learned model and estimating a performance indicator of a liquefied natural gas production process with the machine-learned model. By estimating the performance indicator, production may be planned, deviations in measured performance indicators may be discovered, and setpoints of process variables for an optimal performance indicator may be generated.
Solvent mixtures for downhole elemental sulfur removal and formation stimulation, and methods for utilizing such solvent mixtures, are described herein. One method includes providing a solvent mixture that includes an elemental sulfur solvent fraction and an odorant fraction that includes a lactate ester solvent. The method also includes injecting the solvent mixture into a hydrocarbon well such that the elemental sulfur solvent fraction of the solvent mixture dissolves elemental sulfur deposited on well components, and contacting the solvent mixture with water such that the lactate ester solvent within the odorant fraction reacts with the water to generate lactic acid. The method further includes stimulating a formation through which the hydrocarbon well extends by flowing the solvent mixture including the lactic acid through the hydrocarbon well and into the formation.
Methods for analyzing subsurface process data in order to perform one or more subsurface operations in a subsurface are provided. Generating subsurface models is typically a long and laborious process in which subsurface process data is analyzed in order to generate the subsurface models. In contrast, work in generating the subsurface models may be front- loaded by first using a physics simulator in order to generate a training set of subsurface forward models, and then performing machine learning using the training set to generate one or more proxy models, such as a forward proxy model and an inverse proxy model. The machine learning may be constrained using physics-based rules to better converge on the proxy models. In this way, the already-trained inverse proxy model may input the subsurface process data in order to generate potential inverse models, which may then be used to perform subsurface operations in the subsurface.
A method and a system for volume-based proppant trapping along a fracture surface is disclosed. Hydraulic fracturing involves injecting proppant to ensure separation of the fracture surfaces after the stimulation treatment is completed. The spatial placement of proppant is assumed to be directly related to the fracture conductivity along the hydraulic fracture as well as its connectivity to the wellbore. Fracture conductivity is an important focus of designing fracture treatments since fracture conductivity may be directly related to the well performance. Thus, improving one or more aspects of proppant placement, such as determining the optimal type, size and/or concentration of proppant(s) may enhance fracture conductivity and in turn improve well performance. In order to understand the placement of proppant in the subsurface, a volume-based proppant trapping model is used. The volume-based proppant trapping model may factor in parameters associated with the subsurface, parameters associated with the proppants, and user parameters, such as the total volume of proppant along the fracture surface, thereby assisting in hydraulic fracturing.
Superterranean acoustic networks, methods of forming superterranean acoustic networks, and methods of operating superterranean acoustic networks are disclosed herein. The superterranean acoustic networks include superterranean hydrocarbon infrastructure that extends above a ground surface, defines a waveguide, and contains a fluid. The infrastructure also includes a plurality of acoustic communication nodes spaced-apart along the superterranean hydrocarbon infrastructure. Each acoustic communication node of the plurality of acoustic communication nodes includes an acoustic transmitter and an acoustic receiver. The acoustic transmitter is configured to generate a generated acoustic signal and to supply the generated acoustic signal to the waveguide. Responsive to receipt of the generated acoustic signal, the waveguide is configured to propagate a propagated acoustic signal there through. The acoustic receiver is configured to receive another propagated acoustic signal, which is generated by another acoustic communication node of the plurality of acoustic communication nodes, from the waveguide as a received acoustic signal.
A method and a system for generating and using an Al models to analyze welds is disclosed. Welding is used in the oil and gas industry to obtain and transport oil and gas deposits. One way to analyze weldments is using Radiograph Testing (RT) to generate an image of the weld. Rather than solely relying on an inspector who inspects the image, an artificial intelligence (Al) system is disclosed to perform inspection of the weldments via pattern recognition. In particular, the Al system may include an Al model that is generated via iteratively training of a neural network so that the Al model includes a multi-tier decision hierarchy, such as: identifying defect or no defect; identifying a type of defect; and identifying a sub-type of defect. In this way, the Al model may assist the inspector in identifying failing weldments.
22S scavenger. Moreover, the low-density HGB fluids are suitable for use as lower-density cap fluids for pressurized mudcap drilling (PMCD) operations, alternative drilling fluids for managed pressure drilling (MPD) operations, alternative drilling fluids for conventional drilling operations corresponding to very-low-pressure or highly-depleted reservoirs, and/or lightweight fluids for wellbore workover operations.
Systems and methods for liquefaction of natural gas. The systems include a feed gas compression and expansion module, which includes a work-producing feed expander and is configured to receive a feed stream, which includes natural gas, and to compress and cool the feed stream to generate a cooled and compressed feed stream. The systems also include a mixed refrigerant compression module, which is configured to receive a warmed and expanded refrigerant stream, which includes a mixed refrigerant, and to compress and cool the warmed and expanded refrigerant stream to generate a compressed refrigerant stream. The systems further includes a cryogenic heat exchange module, which is configured to facilitate thermal energy transfer from the natural gas to the mixed refrigerant. The systems also include a mixed refrigerant expansion module. The methods include methods of operating the systems.
A method of conveying a production fluid from an offshore subsea well to an offshore vessel includes deploying an inflatable bladder from the offshore vessel, the inflatable bladder including a bladder valve, and fluidly connecting the inflatable bladder to an offloading port positioned at a seafloor, wherein the offloading port includes a port valve and is in fluid communication with one or more subterranean hydrocarbon-bearing formations. The method further includes opening the bladder and port valves to discharge the production fluid from the offloading port into the inflatable bladder, and thereby resulting in a substantially filled bladder, closing the bladder and port valves, and fluidly disconnecting the substantially filled bladder from the offloading port.
E21B 43/01 - Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
46.
SUBSEA DEHYDRATION OF NATURAL GAS USING SOLID DESICCANT
Techniques described herein relate to a subsea dehydration system including two or more solid desiccant dehydration units. Each solid desiccant dehydration unit includes solid desiccant beds arranged as parallel pipes oriented substantially horizontally and packed with solid desiccant material. The solid desiccant dehydration units are configured to perform a cyclic dehydration process in which at least one solid desiccant dehydration unit performs an adsorption function for selectively adsorbing water from a wet natural gas stream, while at least one other solid desiccant dehydration unit simultaneously undergoes a regeneration function for desorbing adsorbed water from corresponding solid desiccant beds and cooling the corresponding solid desiccant beds to a suitable temperature prior to performing the adsorption function. Moreover, the subsea dehydration system is configured to periodically switch the direction of flow such that the solid desiccant dehydration units alternate between performing the adsorption function and undergoing the regeneration function.
B01D 53/04 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
47.
CONTROL OF ACID GAS LOADING WITHIN GAS PROCESSING SYSTEM
Techniques described herein relate to a method for controlling acid gas loading within a gas processing system. The method includes contacting a sour gas stream including acid gases with a solvent stream within a number of co-current contacting systems to generate a sweetened gas stream and a rich solvent stream including absorbed acid gases. The method also includes measuring the gas flow rate and the solvent flow rate, as well as measuring the liquid and/or gas inlet temperatures and outlet temperatures for each co-current contacting system. The method further includes determining the amount of acid gases absorbed by the solvent stream within each co-current contacting system based on the measured parameters, in combination with the heat of reaction between the acid gases and the solvent stream, as well as adjusting operating parameters corresponding to the gas processing system based on the determined amount of absorbed acid gases.
B01D 53/14 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by absorption
C10L 3/00 - Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclasses , ; Liquefied petroleum gas
48.
Method And System For Generating A Surprisingness Score For Sentences Within Geoscience Text
The invention is a data processing method and system for suggesting insightful and surprising sentences to geoscientists from unstructured text. The data processing system makes the necessary calculations to assign a surprisingness score to detect sentences containing several signals which when combined exponentially, have tendencies to give rise to surprise. In particularly, the data processing system operates on any digital unstructured text derived from academic literature, company reports, web pages and other sources. Detected sentences can be used to stimulate ideation and learning events for geoscientists in industries such as oil and gas, economic mining, space exploration and Geo-health.
22S and low pH) from experiencing sulfide stress cracking (or "SSC") as defined in the ANSI/NACE/ISO International Standard ANSI/NACE MR0175 / ISO 15156-1:2015. In particular, the present disclosure relates to determining operating conditions of a process fluid to determine minimum safe operating temperature to prevent SSC in carbon steel pipe, equipping the carbon steel pipe with an appropriately designed heating supply, and utilizing the heating supply to ensure that the internal wall of the carbon steel pipe (i.e., the face of the inner pipe which is exposed to the process fluid) is maintained at or above the minimum safe operating temperature to prevent SSC from occurring in the carbon steel pipe materials.
A method for calibrated multi-mineral, multi-fluid interpretation is provided herein. The method includes generating a multi-mineral, multi-fluid interpretation model for a number of log types using core and/or specialized log data acquired from subsurface region(s) that relate to components within the subsurface region(s). Generating the model includes: (1) for each log type, calibrating component end-members for the log type via an inversion of the core and/or specialized log data relating to the components across all depths of interest; and (2) incorporating the resulting calibrated end-members for the log types into the model. The method also includes generating component volume fraction profiles using log data acquired from analogous subsurface region(s) using the model, wherein the log data relate to any of the log types used to generate the model. Each component volume fraction profile includes a range of component volume fractions that accounts for a degree of uncertainty within the model.
Natural gas liquefaction processes may be facilitated by incorporating secondary liquid cooling to facilitate an overall pressure decrease and improved throughput at a fixed compressor power. Natural gas processing methods may comprise: providing a natural gas stream to a first compressor, compressing the natural gas stream in the first compressor and, performing air cooled heat exchange, conveying the resulting cooled, compressed natural gas stream to a multiple stream heat exchanger cooled by first and second gaseous refrigerants in first and second closed refrigerant loops and cooling to form a chilled, compressed natural gas stream, expanding the chilled, compressed natural gas stream to form a chilled natural gas stream, and converted the chilled natural gas stream into liquefied natural gas. Secondary liquid cooling is incorporated in at least one of the first or second closed refrigerant loops, and/or upstream from the multiple stream heat exchanger and downstream from the first compressor.
A computer-implemented method for identifying one or more geological features of interest from seismic data is disclosed. Hydrocarbon prospecting attempts to accurately model subsurface geologic structures and to detect fluid presence in those structures. Typically, seismic data of the subsurface is analyzed in order to accurately model the subsurface geologic structures. However, modeling in seismic space can be limiting. As such, a machine learning framework is used to learn a structured and compositional representation space, such as embedding space, where the distinctive features of interests, such as DHI, traps, seals, reservoirs, migration paths, or the like, are separated. In practice, an embedding model is generated, and thereafter tailored, such as by modifying the embedding model or refining the machine learning model using retraining. In this way and in contrast to seismic space, embedding space may better represent the features of interest and measure the adjacency or compositional nature (e.g., distance) of the features from one to another, thereby better modeling subsurface geologic structures.
Disulfide solvents may be particularly effective for dissolving deposits comprising elemental sulfur, but the extreme odor of these solvent may make their use rather problematic. Solvent blends comprising at least one disulfide solvent, amine solvent, ketone solvent, and ester solvent may afford a less obnoxious odor and not appreciably compromise the sulfur dissolution capabilities. Surfaces contacted with such solvent blends or at least partially spent variants thereof may exhibit excessive odor due to loss of one or more of the amine, ketone, or ester solvents. Excessive odor resulting from a solvent residue upon a surface may be alleviated by contacting the surface with at least one oxidant. Odor balance may also be restored to at least partially spent solvent blends by introducing additional ester solvent, which may convert a biphasic mixture into an emulsion comprising the disulfide solvent.
Solids dissolution may be promoted using a solvent blend comprising a disulfide solvent, particularly additional solids present in combination with elemental sulfur deposits. The solvent blends may comprise at least one disulfide solvent, at least one amine solvent, at least one ketone solvent, at least one ester solvent, and optionally water. Solids dissolution methods may comprise: identifying one or more solids in addition to elemental sulfur to be contacted by the solvent blend; adjusting a composition of the solvent blend to afford selectivity for dissolution of at least a portion of the one or more solids; and contacting the solvent blend with elemental sulfur and the one or more solids to promote at least partial dissolution thereof.
C10G 75/04 - Inhibiting corrosion or fouling in apparatus for treatment or conversion of hydrocarbon oils, in general by addition of antifouling agents
Methods for treating a gas stream are provided. The methods include a) passing the gas stream through at least one column, wherein the gas stream comprises one or more acidic components and/or water; b) passing the gas stream in a vertical upflow direction into one or more cyclones located in the at least one column; c) contacting at least one solvent with the gas stream in the one or more cyclones to produce a second gas stream that is substantially free of the one or more acidic components and/or the water; and d) recovering the second gas stream.
B01D 53/14 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by absorption
Natural gas liquefaction processes may be very energy intensive. Even incremental increases in energy efficiency may be very beneficial. Compression-expansion processing of a natural gas stream and return of a recycle stream following natural gas expansion may lower the natural gas temperature and promote easier liquefaction. A compressor-expander may be utilized in combination with another compressor to afford a cooled, compressed natural gas stream, wherein the recycle stream may be optionally expanded and heat exchanged with the cooled, compressed natural gas stream prior to expansion. The compressor-expander may promote natural gas compression upstream or downstream of another compressor in various system and method configurations.
A capacitive cable, as well as a method for operating a downhole electro-hydraulic (EH) tool using the capacitive cable, are described herein. The capacitive cable includes at least one standard conductor and at least one capacitive conductor including integrated wire-shaped capacitors. The method includes inserting a tool string including the capacitive cable and an attached downhole EH tool into a wellbore and conducting power from the surface to the downhole EH tool via the standard conductor(s) of the capacitive cable. The method also includes storing electrical energy downhole within the capacitive conductor(s) of the capacitive cable, and activating the downhole EH tool to provide for the rapid release of the electrical energy from the capacitive conductor(s) into the downhole EH tool, initiating an electro-hydraulic event within the wellbore.
A computer-implemented method for detecting geological elements or fluid in a subsurface from seismic images is disclosed. Seismic data may be analyzed to identify one or both of fluid or geologic elements in the subsurface. As one example, the analysis may include unsupervised learning, such as variational machine learning, in order to learn relationships between different sets of seismic data. For example, variational machine learning may be used to learn relationships among partially-stack images or among pre-stack images in order to detect hydrocarbon presence. In this way, an unsupervised learning framework may be used for learning a Direct Hydrocarbon Indicator (DHI) from seismic images by learning relationships among partially-stack or pre-stack images.
A waveform energy generation system, the system including at least one joint of production casing, and one or more energy generators residing along the joint of production casing. The energy generators are configured to be in substantial mechanical contact with a subsurface formation within a wellbore. The energy generators may include either explosive devices or a piezo-electric material. The system also includes a signal transmission system. The signal transmission system is used to send control signals from the surface down to the energy generators for activation at the formation's resonant frequency. Methods of enhancing the permeability of a rock matrix within a subsurface formation using the wellbore as an energy generator are also provided.
An electric submersible pump (ESP) monitoring system is described herein. The ESP monitoring system includes a base monitoring unit and a discharge monitoring unit that are communicably coupled via a ground path. The discharge monitoring unit is hydraulically coupled to the pump discharge and is configured to measure a discharge parameter relating to the pump discharge and transmit data corresponding to the discharge parameter to the base monitoring unit via the ground path. The base monitoring unit is electrically connected to the motor of the ESP system and is configured to measure a base parameter relating to the motor and/or the pump intake, receive the transmitted data corresponding to the discharge parameter from the discharge monitoring unit, combine the data corresponding to the discharge parameter and the data corresponding to the base parameter, and transmit the combined data to an ESP surface unit via an ESP power cable.
E21B 47/008 - Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
F04B 17/03 - Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by electric motors
F04B 47/06 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
61.
SWING ADSORPTION PROCESSES AND SYSTEMS FOR CONTROLLING PRODUCT COMPOSITION
Provided are apparatus and systems for performing a swing adsorption process. In particular, the method and system involves swing adsorption processes and systems designed to lessen the temperature, pressure and product stream composition fluctuations in the adsorption step of a swing adsorption process, particularly involving preparation of the adsorption bed unit using feed stream cooling in conjunction with splitting the cooled feed stream to the adsorption bed units during adsorption steps while staggering the timing of back- to-back adsorption steps in the swing adsorption process. The process may be utilized for swing adsorption processes, such as rapid cycle TSA and/or rapid cycle PSA, which are utilized to remove one or more contaminants from a gaseous feed stream.
B01D 53/04 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
A method of measuring a pressure of a fluid adjacent a wall of a pipe or vessel. A transducer is attached to the wall of the pipe or vessel. A signal is transmitted by the transducer at a characteristic frequency via a plurality of guided wave modes. The characteristic frequency is a frequency at which the guided wave modes are separated in time from each other when received. The signal is received after the plurality of guided wave modes travel in or through the wall a predetermined number of times. The signal has a signal receipt time after the predetermined number of times. The pressure of the fluid is calculated using the signal receipt time.
G01L 9/00 - Measuring steady or quasi-steady pressure of a fluid or a fluent solid material by electric or magnetic pressure-sensitive elements; Transmitting or indicating the displacement of mechanical pressure-sensitive elements, used to measure the steady or quasi-steady pressure of a fluid or fluent solid material, by electric or magnetic means
63.
APPARATUS AND METHOD FOR NON-INTRUSIVE PRESSURE MEASUREMENT AND EARLY IDENTIFICATION OF SOLIDS FORMATION USING SELECTED GUIDED ULTRASONIC WAVE MODES
A method of measuring a pressure of a fluid adjacent a wall of a pipe or vessel. A transducer is attached to the wall of the pipe or vessel. A signal is transmitted by the transducer at a characteristic frequency via a plurality of guided wave modes. The characteristic frequency is a frequency at which the guided wave modes are separated in time from each other when received. The signal is received after the plurality of guided wave modes travel in or through the wall a predetermined number of times. The signal has a signal receipt time after the predetermined number of times. The pressure of the fluid is calculated using the signal receipt time
Methods and systems for measuring pipe parameters using guided acoustic wave modes are provided. The method includes receiving data corresponding to an acoustic signal, wherein the data are obtained by transmitting an excitation pulse at a specified frequency and detecting the resulting acoustic signal using an acoustic transducer attached to the outer surface of the pipe wall. The method includes analyzing the data to identify guided acoustic wave modes including at least two of: a C-SH acoustic wave mode that travels within the pipe wall; a C-LT acoustic wave mode that travels within the near- surface region of the pipe wall; and/or a CA acoustic wave mode that travels within the pipe cavity. The method includes calibrating the parameter measurement using the C-SH acoustic wave mode and determining the parameter measurement based on the phase velocity and/or the amplitude of the C-LT acoustic wave mode and/or the CA acoustic wave mode.
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
G01F 15/02 - Compensating or correcting for variations in pressure, density, or temperature
A continuous thermal hydrogen compression system, and methods of thermally compressing hydrogen, are disclosed. A hydrogenation module accepts a hydrogen gas stream to be absorbed or adsorbed to a lean carrier stream through heat removal, thereby producing a heat output and a rich carrier stream containing absorbed or adsorbed hydrogen. A pump, connected to an output of the hydrogenation module, increases the pressure of the rich carrier stream to produce a pressurized rich carrier stream. A dehydrogenation module separates, via an addition of heat, a pressurized hydrogen gas stream from the pressurized rich carrier stream to produce a lean carrier stream. A pressure reducing device reduces the pressure of the lean carrier stream before it is returned to the hydrogenation module. The carrier stream is cycled continuously between the hydrogenation module and the dehydrogenation module.
Container systems for the transportation and/or storage of Liquefied Natural Gas (LNG) are provided. The container systems include: a) an outer shell; b) an inner pressurized container, wherein the inner pressurized container comprises a first chamber having a first vent and at least one other chamber having a second vent; c) at least one heat exchange zone in thermal communication between the first chamber and the at least one other chamber; and d) an interstitial space between the outer shell and the inner pressurized container including at least a partial vacuum. Methods for transporting and/or storing LNG using the aforementioned container systems are also provided.
A method of predicting hydrocarbon production from one or more artificial lift wells is disclosed. Test data is obtained from the artificial lift well. A decline curve model, representing well performance, is generated for one or more fluids in the artificial lift well. Measurement values are obtained from an artificial lift operation. For each of the obtained measurement values, a measurement model is generated that correlates the measurement values to the decline curve. A Kalman filter is used to predict production outputs of at least one of oil, gas, and water for the well, and to generate an uncertainty range for the predicted production outputs. The Kalman filter uses the decline curves to predict the production outputs, and uses the measurement models to correct and/or update the predicted production outputs. Hydrocarbon production activities are modified using the corrected and/or updated predicted production outputs.
Offshore systems and methods may be configured for offshore power generation and carbon dioxide injection for enhanced gas recovery for gas reservoirs. For example, a method may include: providing an offshore facility including a gas turbine, and a gas separator; producing a produced gas from a gas reservoir to the offshore facility; combusting the produced gas in a gas turbine to produce power and a flue gas; at least partially removing nitrogen from the flue gas in a gas separator to produce a carbon dioxide-enriched flue gas and a nitrogen-enriched flue gas; compressing the carbon dioxide-enriched flue gas in a gas compressor to produce a compressed gas; and injecting the compressed gas from the gas compressor into the gas reservoir, wherein 80 mol% or more of hydrocarbon in the produced gas is combusted and/or injected into the gas reservoir.
Offshore systems and methods may be configured for oil production, offshore power generation, ammonia production, and carbon dioxide injection for EOR. For example, a method performed on an offshore facility may include: separating a produced hydrocarbon into a produced gas and a produced oil; combusting the produced gas to produce power and a flue gas; at least partially removing nitrogen from the flue gas to produce a carbon dioxide-enriched flue gas and a nitrogen-enriched flue gas; reforming a portion of the produced gas to produce a stream including hydrogen and carbon dioxide; at least partially separating the carbon dioxide from the stream to yield a carbon dioxide stream and a hydrogen stream; reacting the hydrogen stream and the nitrogen-enriched flue gas to yield ammonia; combining and compressing the carbon dioxide stream and the carbon dioxide-enriched flue gas; and injecting the compressed gas from the gas compressor into the gas reservoir.
C01B 3/38 - Production of hydrogen or of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
A method of producing LNG. According to the method, a natural gas stream is compressed using first and second compressors. A cooler cools the natural gas stream so that the second compressor produces a cooled, compressed natural gas stream, which is liquefied in a liquefaction process. The liquefaction process uses a refrigerant compressor configured to compress a stream of refrigerant used to chill, condense, or liquefy the cooled, compressed natural gas stream. Using a heat recovery steam generation (HRSG) system, heat is recovered from a power source of the refrigerant compressor. A stream of pressurized steam is generated from the recovered heat. At least one of the first and second compressors is powered using at least part of the stream of pressurized steam.
F25J 1/00 - Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
F25J 1/02 - Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen
71.
CLASSIFYING GEOLOGIC FEATURES IN SEISMIC DATA THROUGH IMAGE ANALYSIS BY NEURAL NETWORK
Aspects of the technology described herein identify geologic features within seismic data using modern computer analysis. An initial step is the development of training data for the machine classifier. The training data comprises an image of seismic data paired with a label identifying points of interest that the classifier should identify within raw data. Once the training data is generated, a classifier can be trained to identify areas of interest in unlabeled seismic images. The classifier can take the form of a deep neural network, such as a U-net. Aspects of the technology described herein utilize a deep neural network architecture that is optimized to detect broad and flat features in seismic images that may go undetected by typical neural networks in use. The architecture can include a group of layers that perform aspect ratio compression and simultaneous comparison of images across multiple aspect ratio scales.
The present techniques are directed to a multiphase separation system. The system includes a liquid-liquid separator configured to receive a separated liquid that is further separated into a separated oil and a separated water within the liquid-liquid separator. An oil pump and a water pump, both with adjustable speeds, are configured to pump the separated oil and the separated water, respectively, from the liquid-liquid separator. An interface level in the liquid-liquid separator is regulated by adjusting the speed of the oil pump and the speed of the water pump.
B01D 17/12 - Auxiliary equipment particularly adapted for use with liquid-separating apparatus, e.g. control circuits
C02F 1/00 - Treatment of water, waste water, or sewage
C02F 1/40 - Devices for separating or removing fatty or oily substances or similar floating material
73.
METHODS OF MONITORING A GEOMETRIC PROPERTY OF A HYDRAULIC FRACTURE WITHIN A SUBSURFACE REGION, WELLS THAT PERFORM THE METHODS, AND STORAGE MEDIA THAT DIRECT COMPUTING DEVICES TO PERFORM THE METHODS
Methods of monitoring a geometric property of a hydraulic fracture within a subsurface region, wells that perform the methods, and storage media that direct computing devices to perform the methods provided. The methods include repeatedly measuring, at a plurality of measurement times, fiber strain as a function of position along a length of an optical fiber. The optical fiber is positioned within a wellbore that extends within a subsurface region and the repeatedly measuring is performed during a change in the geometric property of the hydraulic fracture. For a given measurement time of the plurality of measurement times, the methods also include differentiating the fiber strain as the function of position to generate a strain differential as a function of position along the length of the optical fiber. The methods further include determining the geometric property of the hydraulic fracture based, at least in part, on the strain differential.
E21B 47/002 - Survey of boreholes or wells by visual inspection
E21B 47/135 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range using light waves, e.g. infrared or ultraviolet waves
E21B 47/007 - Measuring stresses in a pipe string or casing
74.
METHODS OF INTERPRETING A PLURALITY OF TIME-SERIES DATASETS GENERATED FROM OPERATION OF HYDROCARBON WELLS
Methods of facilitating human interpretation of a plurality of time-series datasets generated from operation of hydrocarbon wells. The methods include obtaining the plurality of time-series datasets and displaying a vector map. The plurality of time-series datasets is generated from an operation of the hydrocarbon well and includes a first time-series dataset and a second time-series dataset, and optionally may include a third time-series dataset. The vector map includes a time axis and a plurality of points distributed along the time axis at a plurality of corresponding times. A color of each point of the plurality of points is defined in a plural-component color space and includes a first color component at a first intensity and a second color component at a second color component at a second intensity, and optionally a third color component at a third intensity when the plurality of time-series datasets includes a third time-series dataset.
G06F 16/26 - Visual data mining; Browsing structured data
75.
METHODS OF MONITORING A GEOMETRIC PROPERTY OF A HYDRAULIC FRACTURE WITHIN A SUBSURFACE REGION, WELLS THAT PERFORM THE METHODS, AND STORAGE MEDIA THAT DIRECT COMPUTING DEVICES TO PERFORM THE METHODS
Methods of monitoring a geometric property of a hydraulic fracture within a subsurface region, wells that perform the methods, and storage media that direct computing devices to perform the methods provided. The methods include repeatedly measuring, at a plurality of measurement times, fiber strain as a function of position along a length of an optical fiber. The optical fiber is positioned within a wellbore that extends within a subsurface region and the repeatedly measuring is performed during a change in the geometric property of the hydraulic fracture. For a given measurement time of the plurality of measurement times, the methods also include differentiating the fiber strain as the function of position to generate a strain differential as a function of position along the length of the optical fiber. The methods further include determining the geometric property of the hydraulic fracture based, at least in part, on the strain differential.
E21B 49/00 - 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
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
A computer-implemented geological modeling method is disclosed. Hydraulic fracturing includes pumping fluids through a wellbore/ casing and into a formation through perforations, creating fractures that can improve well productivity. Geological modeling may be used to model pumping of fluids into the subsurface to achieve a desired fracturing result. However, the grid used may affect the fracture propagation calculations used for geological modeling. Thus, a methodology is disclosed which reduces the grid dependence when determining various aspects of fracturing, such as pressure and/or aperture. The methodology uses a first correction factor that is based on the grid used to determine fracture propagation and a second correction factor that is not based on the grid used to determine fracture propagation (such as based on an ideal grid). In this way, the two correction factors are derived from different aspects, which when combined, may be used to reduce grid dependence.
Methods of stimulating a hydrocarbon well are disclosed herein. The hydrocarbon well includes a wellbore that extends within a subterranean formation and a tubular that extends within the wellbore and defines a tubular conduit. The methods include retaining a sealing structure within the tubular conduit and, during the retaining, stimulating a zone of the subterranean formation. Subsequent to the stimulating, the methods include fluidly isolating the zone of the subterranean formation from the uphole region by at least partially sealing the plurality of perforations. Subsequent to the fluidly isolating, the methods include moving the sealing structure in a downhole direction within the tubular conduit. The methods also include repeating the retaining, the stimulating, the fluidly isolating, and the moving a plurality of times to stimulate a plurality of corresponding zones of the subterranean formation.
A method for learning and applying a similarity measure between geophysical objects is provided. Similarity measures may be used for a variety of geophysics applications, including inverse problems. For example, an inverse problem may seek to minimize or maximize an associated objective function, which summarizes the degree of similarity between observed data and simulated data. However, when comparing between two or more geophysical objects in the context of the inverse problem, it is difficult to determine whether the observed difference between the two or more geophysical objects is due to noise or intrinsic dissimilarity between the objects. In this regard, an application-specific similarity measure, which may be tailored to the specific application, such as the specific inverse problem, may be generated and applied in order to better solve the inverse problem.
A method and apparatus for performing geological reasoning, A method includes: obtaining subsurface data for a subsurface region; obtaining a knowledge model; extracting a structured representation from the subsurface data using the knowledge model; and performing geological reasoning with a graph network based on the knowledge model and the structured representation. A method includes performing geological reasoning with a knowledge model that includes a set of geoscience rules or a geoscience ontology. A method includes performing geological reasoning with a structured representation that includes a graph. A method includes performing geological reasoning by one or more of the following: question answering; decision making; assigning ranking; and assessing probability.
A method and apparatus for utilizing a structured representation of a subsurface region. A method includes obtaining subsurface data for the subsurface region; and extracting the structured representation from the seismic data by: identifying geologic and fluid objects in the seismic images, wherein each object corresponds to a node of the structured representation; and identifying relationships among the identified geologic and fluid objects, wherein each relationship corresponds to an edge of the structured representation. A method further includes determining object attributes, edge attributes, and/or global attributes from the subsurface data. A method further includes inferring information from the structured representation.
A computer-implemented method for analyzing geophysical data is disclosed. Interpretation of geophysical data, such as seismic data, can be performed in multiple stages, such as at an information extraction stage and an information analysis stage. Typically, the information analysis stage is performed by geologists or interpreters, which may be laborious and inconsistent. The disclosed method includes using an information extractor that extracts information indicative of geo-features in a subsurface and an inference engine that analyzes the information indicative of geo-features in a subsurface to generate an output, with the information extractor and the inference engine being integrated and acting in combination. For example, the information extractor may generate summaries of the geo-features or answers to questions. In this way, the information extractor and the inference engine in combination may act synergistically, such as in the context of reasoning, natural language processing, and the outputs generated.
Chelating acid blends for stimulation of a subterranean formation, methods of utilizing the chelating acid blends, and hydrocarbon wells that include the chelating acid blends
Chelating acid blends for stimulation of a subterranean formation, methods of utilizing the chelating acid blends, and hydrocarbon wells that include the chelating acid blends are disclosed herein. The chelating acid blends include an acid mixture and a chelating agent or set of chelating agents. The acid mixture includes hydrochloric acid and hydrofluoric acid. The methods include providing the chelating acid blends to a wellbore of a hydrocarbon well, flowing the chelating acid blends into a subterranean formation, dissolving a fraction of a formation mineralogy of the subterranean formation with the acid mixture, and chelating poly-valent metal ions with the chelating agent. The hydrocarbon wells include a wellbore that extends within a subterranean formation, a downhole tubular that extends within the wellbore, a fracture that extends into the subterranean formation, and a chelating acid blend positioned within the fracture.
A lock mandrel is described herein. The lock mandrel includes an upper connector and a lower connector. The upper connector includes locking keys configured to attach the lock mandrel to a landing nipple on a tubing within a hydrocarbon well. The upper connector also includes a spring-loaded locking collar configured to prevent the locking keys from disengaging from the landing nipple by pressing radially against the locking keys from the inside when in a seated position, and allow the locking keys to disengage from the landing nipple by retracting away from the locking keys when in an unseated position. The lower connector includes a tool adaptor configured to attach a downhole tool to the lock mandrel.
E21B 23/02 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing
A lock mandrel is described herein. The lock mandrel includes an upper connector and a lower connector. The upper connector includes locking keys configured to attach the lock mandrel to a landing nipple on a tubing within a hydrocarbon well. The upper connector also includes a spring-loaded locking collar configured to prevent the locking keys from disengaging from the landing nipple by pressing radially against the locking keys from the inside when in a seated position, and allow the locking keys to disengage from the landing nipple by retracting away from the locking keys when in an unseated position. The lower connector includes a tool adaptor configured to attach a downhole tool to the lock mandrel.
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
E21B 4/06 - Down-hole impacting means, e.g. hammers
E21B 23/01 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
E21B 23/02 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
85.
CASING ATTACHMENT SYSTEM FOR ATTENUATING ANNULAR PRESSURE BUILDUP
A method of attenuating annular pressure buildup within a wellbore. The method includes running first and second strings of casing into a wellbore, wherein the first string of casing surrounds an upper portion of the second string of casing forming an annular region. The method also includes providing a packing of compressible material within the annular region. The compressible material comprises a plurality of carbonaceous particles. The particles may reside within a porous sleeve or filter, or they may be packed together in a matrix using a cross- linked polymer or binder. The packing is fixed at a selected depth within the annular region, and is designed so that the compressible material absorbs pressure in response to thermal expansion of wellbore fluids during the production of hydrocarbon fluids from the wellbore. The method further includes placing a wellhead over the wellbore, thereby forming a trapped annulus in the wellbore over the annular region.
A self-destructible frac ball is described herein. The self-destructible frac ball is configured to seal a hydraulic flow path through a fluid conduit of a frac plug when engaged on a ball seat of the frac plug. The self-destructible frac ball includes an activation mechanism configured to activate a destructive medium in response to the satisfaction of at least one predetermined condition. The self-destructible frac ball also includes the destructive medium, which is configured to destroy the self-destructible frac ball and a corresponding destructible ball retainer when activated by the activation mechanism. The destruction of the self-destructible frac ball and the corresponding destructible ball retainer reestablishes the hydraulic flow path through the fluid conduit of the frac plug.
E21B 29/00 - Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
E21B 33/128 - Packers; Plugs with a member expanded radially by axial pressure
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 34/06 - Valve arrangements for boreholes or wells in wells
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
A hydrocarbon well includes a wellbore with a surface casing string that couples the wellbore to a wellhead located at the surface and a production casing string that extends through a reservoir within the subsurface. A fluid column is present within the wellbore. The hydrocarbon well also includes a high-frequency tube wave generator that is hydraulically coupled to the wellbore and is configured to generate high-frequency tube waves that propagate within the fluid column. The high-frequency tube waves include a selected waveform containing a specific bandwidth of high-frequency components. The hydrocarbon well further includes a receiver that is hydraulically coupled to the wellbore and is configured to record data corresponding to the generated and reflected high-frequency tube waves propagating within the fluid column, wherein the recorded data relate to characteristics of the wellbore. Moreover, such techniques may also be applied to a pipeline.
E21B 47/16 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
88.
Method for attenuation compensation utilizing non-stationary matching filters
A method and apparatus for generating attenuation-compensated images of subsurface region, including: computing an image of the region utilizing elastic wave propagation, based on field data and subsurface model; generating forward-modeled data utilizing forward viscoelastic wave propagation, based on the image; computing secondary image by migration; computing NMF based on the images; and applying the NMF to the image to generate the attenuation-compensated image. A method and apparatus includes: iteratively computing attenuation-compensated gradient of the region utilizing an elastic wave propagation operator in the back-propagation and a viscoelastic wave propagation operator in the forward modelling, based on field data and subsurface model; computing search direction based on the attenuation-compensated gradient, searching for an improved model, and checking the improved model for convergence.
A method and apparatus for generating a high-resolution seismic image, including extracting a reflectivity distribution from a geological model; utilizing the reflectivity distribution to label features of the model; generating forward-modeled data from the model; migrating the forward-modeled data to create a migrated image; and training a deep neural network with the labeled synthetic geological model and the migrated image to create a reflectivity prediction network. A method and apparatus includes: selecting a first subset of the field data; applying a low-pass filter to the first subset to generate a first filtered dataset; migrating the first filtered dataset to create a first migrated image; applying a high-pass filter to the first subset to generate a second filtered dataset; migrating the second filtered dataset to create a second migrated image; and training a deep neural network to predict a target distribution of high-frequency signal.
A method and system are described for communicating within a system, which may be along tubular members and used during cementing installation operations. The method includes constructing a communication network and installing the communication nodes along a wellbore. The communication nodes are used to monitor the fluids adjacent to the communication nodes during the cementing installation operations. Once the cement is installed, the cementing installation operations may be used for hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.
E21B 47/005 - Monitoring or checking of cementation quality or level
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
E21B 33/14 - Methods or devices for cementing, for plugging holes, crevices, or the like for cementing casings into boreholes
E21B 47/16 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing
E21B 47/18 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid
91.
Discontinuous Interpolation Using Continuous Formulation, C1 or C0 FEM Discretization, and Scalable Solver
A methodology for discontinuous smooth interpolation in order to generate a curve of a discontinuous volume due to one or more faults in a subsurface is disclosed. Faults in a subsurface result in discontinuities in the subsurface. Hydrocarbon management may seek to determine various surfaces in the subsurface, including across the faults in the subsurface. To generate the various surfaces, a continuous formulation of the interpolation method is followed in which discontinuous smooth interpolation is viewed as a variational optimization problem (such as an energy optimization problem) for the surface curvature function. In this way, the methodology does not require that the input data be located at grid points and discretized with a structured regular grid. Rather, because a continuous function is used, an unstructured grid may also be used to discretize the resulting equation.
A method for approximating an inverse Hessian is provided. One methodology to generate the inverse Hessian is to precondition the gradient, such as by using point-spread function deconvolution, T-power, or source-illumination compensation, prior to using non-stationary matching filters (NMF) to generate the inverse Hessian. Various types of NMF are contemplated, including using filters for different windows in the subsurface or using filters assigned to specific locations in the subsurface. Further, the number of filters for NMF may vary from iteration to iteration. For example, the filters assigned to the specific locations in the subsurface may be generated in a multi-scale manner, in which an initial iteration uses longer scale/longer wavelength features for inversion and subsequent iterations use finer scale/smaller wavelength features for inversion.
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
G06F 30/20 - Design optimisation, verification or simulation
A methodology for extending bandwidth of geophysical data is disclosed. Geophysical data, obtained via a towed streamer, may have significant noise in a certain band (such as less than 4 Hz), rendering the data in the certain band unreliable. To remedy this, geophysical data, from a band that is reliable, may be extended to the certain band, resulting in bandwidth extension. One manner of bandwidth extension comprises using machine learning to generate a machine learning model. Specifically, because bandwidth may be viewed as a sequence, machine learning configured to identify sequences, such as recurrent neural networks, may be used to generate the machine learning model. In particular, machine learning may use a training dataset acquired via ocean bottom nodes in order to generate the machine learning model. After which, the machine learning model may be used to extend the bandwidth of a test dataset acquired via a towed streamer.
E21B 49/00 - 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
E21B 47/002 - Survey of boreholes or wells by visual inspection
94.
Downhole completion assemblies and methods of completing a hydrocarbon well
Methods include positioning a downhole completion assembly in a tubular conduit of a downhole tubular of a hydrocarbon well. The downhole completion assembly includes a downhole sub-assembly and an uphole sub-assembly. The methods also include forming a fluid seal within the tubular conduit with the downhole sub-assembly, decoupling the uphole sub-assembly from the downhole sub-assembly, translating the uphole sub-assembly in an uphole direction, perforating the downhole tubular with the uphole sub-assembly, translating the uphole sub-assembly in a downhole direction, coupling the uphole sub-assembly to the downhole sub-assembly, ceasing the fluid seal, and translating the downhole completion assembly in the uphole direction.
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
95.
HIERARCHICAL BUILDING AND CONDITIONING OF GEOLOGICAL MODELS WITH MACHINE LEARNING PARAMETERIZED TEMPLATES AND METHODS FOR USING THE SAME
A hierarchical conditioning methodology for building and conditioning a geological model is disclosed. In particular, the hierarchical conditioning may include separate levels of conditioning of template instances using larger-scale data (such as conditioning using large-scale data and conditioning using medium-scale data) and using smaller-scale data (such as fine-scale data). Further, one or more templates, to be instantiated to generate the geological bodies in the model, may be selected from currently available templates and/or machine-learned templates. For example, the templates may be generated using unsupervised or supervised learning to re-parameterize the functional form parameters, or may be generated using statistical generative modeling.
An oil-water fractionation system is positioned within a wellbore on a subsurface end of a production tubing proximate to a production region. The fractionation system includes a permeable hydrophobic media for preferentially conveying an oil-enriched stream (reduced water-cut presence) from the production region into the production tubing, and a permeable oleophobic media for preferentially conveying a water-enriched stream (reduced oil-cut presence) into a second flow path. The permeable hydrophobic media and the permeable oleophobic media are in simultaneous hydraulic communication with the production region. The permeable hydrophobic media is manufactured with a relatively high effective permeability to oil, allowing the oil-enriched stream to flow through the permeable hydrophobic media into the production tubing. In contrast, the permeable oleophobic media is manufactured with a relatively high effective permeability to water, allowing the water-enriched stream to flow through the permeable oleophobic media into the second flow path.
A semi-elimination methodology for simulating high flow features in a reservoir and wells is disclosed. The reservoir and wells may be divided into a plurality of cells, including small cells in wells and the reservoir and bulk cells in the bulk of the reservoir, where the small cells are smaller (e.g., by pore volume) than the bulk cells. Processing of all of the cells, including all of the small cells, may be too computationally expensive, particularly when processing is iterative. In that regard, at least some of the small cells are partly processed in an iteration, such as for flow rates, compositions, or flow derivatives. After which, some or all of the small cells are eliminated from further processing in the iteration. In that way, high flow features in a reservoir and wells may be simulated effectively.
A semi-elimination methodology for simulating high flow features in a reservoir and wells is disclosed. The reservoir and wells may be divided into a plurality of cells, including small cells in wells and the reservoir and bulk cells in the bulk of the reservoir, where the small cells are smaller (e.g., by pore volume) than the bulk cells. Processing of all of the cells, including all of the small cells, may be too computationally expensive, particularly when processing is iterative. In that regard, at least some of the small cells are partly processed in an iteration, such as for flow rates, compositions, or flow derivatives. After which, some or all of the small cells are eliminated from further processing in the iteration. In that way, high flow features in a reservoir and wells may be simulated effectively.
G06F 30/28 - Design optimisation, verification or simulation using fluid dynamics, e.g. using Navier-Stokes equations or computational fluid dynamics [CFD]
99.
Engineered production liner for a hydrocarbon well
Techniques described herein relate to a well completion including an engineered production liner extending into a reservoir. The engineered production liner includes limited-entry liner (LEL) valves configured to open to allow an acid solution to jet into the reservoir during an acid stimulation process, and close to prevent production fluid from flowing through the LEL valves when the well completion is put into production. The engineered production liner also includes pre-packed chemically-infused material (CIM) cartridges including production chemicals, and openings that align with the pre-packed CIM cartridges. The openings are plugged during the acid stimulation process to force the acid solution to flow through the LEL valves. The pre-packed CIM cartridges and the openings are configured to allow the production fluid to absorb a portion of the production chemicals as it flows from the reservoir into the engineered production liner when the well completion is put into production.
Aspects of the technology described herein make legacy hydrocarbon studies accessible to modern computer analysis. Whatever the initial format, the technology described herein analyzes the studies to identify characteristics that are interesting to people who study hydrocarbon environments. As an initial process, various segments within a hydrocarbon study received by the technology described herein are identified. The various segments can include text, maps, charts, and tables. Within each of these segments, specific types of text segments, maps, charts, and tables may be identified. For each segment identified, characteristics of interest may be determined through analysis of the segment. In one aspect, segment-specific analysis is performed on each type of segment. Different technologies may be used for different segments. Once the characteristics are identified, they may be stored in association with both the overall document and with a segment of the document from which the characteristic of interest was extracted.
patents
