53 results about "Passive seismic" patented technology

Method for using seismic data from earthquakes to address the low frequency lacuna problem in traditional hydrocarbon exploration methods. Seismometers with frequency response Select Receivers of Desired Frequency Ranges and Design Survey Seismometer Configuration down to about 1 Hz are placed over a target subsurface region in an array with spacing suitable for hydrocarbon exploration (21). Data are collected over a long (weeks or months) time period (22). Segments of the data (44) are identified with known events from earthquake catalogs (43). Those data segments are analyzed using techniques such as trayeltime delay measurements (307) or receiver function calculations (46) and then are combined with one or more other types of geophysical data acquired from the target region, using joint inversion (308-310) in some embodiments of the method, to infer physical features of the subsurface indicative of hydrocarbon potential or lack thereof (26).

A microseismic method of monitoring fracturing operation or other passive seismic events in hydrocarbon wells is described using the steps of obtaining multi-component signal recordings from locations in the vicinity of a facture; and performing a waveform inversion to determine parameters representing a source characteristics of the event.

A method for mapping a fracture network that includes determining a source of at least one seismic event from features in recorded seismic signals exceeding a selected amplitude (“visible seismic event”). The signals are generated by a plurality of seismic receivers disposed proximate a volume of subsurface to be evaluated. The signals are electrical or optical and represent seismic amplitude. A source mechanism of the at least one visible seismic event is determined. A fracture size and orientation are determined from the source mechanism. Seismic events are determined from the signals from features less than the selected amplitude (“invisible seismic events”) using a stacking procedure. A source mechanism for the invisible seismic events is determined by matched filtering. At least one fracture is defined from the invisible seismic events. A fracture network model is generated by combining the fracture determined from the visible seismic event with the fracture determined from the invisible seismic events.

A method of identifying passive seismic events in seismic data that contains at least first seismic data traces acquired at a first seismic receiver and second seismic data traces acquired at a second receiver spatially separated from the first receiver comprises determining an overall measure of similarity for a pair of events in the seismic traces. The overall measure of similarity is indicative of similarity between the events acquired at the first seismic receiver and of similarity between the events acquired at the second seismic receiver. In one method, the overall measure of similarity is an overall cross-correlation coefficient. The overall cross-correlation coefficient is found by determining a first correlation coefficient for the pair of events from the data acquired at the first receiver and determining a second correlation coefficient for the pair of events from the data acquired at the second receiver. The overall correlation coefficient for the pair of events may be obtained from the first correlation coefficient and the second correlation coefficient by an averaging process. The overall measure of similarity may be compared with a threshold to determine whether the pair of events form a doublet. The method makes possible real-time or near-real-time identification of doublets.

A method for seismic event mapping includes selecting a plurality of subvolumes representing possible locations of origin of a seismic event in the Earth's subsurface. For each subvolume a plurality of possible directions of motion of subsurface formations is selected. For each subvolume and each possible direction of motion, polarity correction is applied to seismic signals recorded at a plurality of positions proximate a volume of the Earth's subsurface to be evaluated. The polarity correction is based on the direction of motion and the position of each seismic sensor with respect to the subvolume. The recorded, polarity corrected seismic signal recordings are time aligned. The time aligned recordings are summed. A most likely direction of motion and subvolume position are determined based on a selected attribute of the summed, time aligned seismic signals.

There is provided herein a method of passive seismic acquisition that utilizes real time or near real time computation to reduce the volume of data that must be moved from the field to the processing center. Much of the computation that is traditionally applied to passive source data can be done in a streaming fashion. The raw data that passes through a field system can be processed in manageable pieces, after which the original data can be discarded and the intermediate results accumulated and periodically saved. These saved intermediate results are at least two, more likely three, orders of magnitude smaller than the raw data they are derived from. Such a volume of data is trivial to store, transport or transmit, allowing passive seismic acquisition to be practically used for continuous near-real-time seismic surveillance.

A method for detection of hydrocarbon bearing formations below the bottom of a body of water from seismic signals includes moving a plurality of spatially distributed seismic sensors in a body of water and detecting seismic signals including response to any seismic energy having frequencies down to proximate zero. The method includes stacking the acquired seismic signals from the plurality of the sensors in both longitudinal and transverse directions with respect to motion of the sensors in the body water. The stacked signals are analyzed for presence of passive seismic energy indicative of hydrocarbon bearing formations below the bottom of the body of water.

A microseismic method of monitoring fracturing operation or other passive seismic events in hydrocarbon wells is described using the steps of obtaining multi-component s-wave signals of the event; and using a linear derivative of S-wave arrival times of the signals in a first direction, an S-wave velocity and an s-wave polarization to determine at least two components of the S-wave slowness vector.

A method for determining seismic anisotropy of subsurface rock formations includes measuring passive seismic signals at a plurality of locations above an area of the Earth's subsurface to be surveyed. The compressional- and shear-wave arrival times from at least one origin location of a seismic event occurring in the subsurface are determined from the measured seismic signals. The arrival times are inverted to obtain values of the seismic anisotropy parameters.

A method of imaging the Earth's subsurface using passive seismic interferometry tomography includes detecting seismic signals from within the Earth's subsurface over a time period using an array of seismic sensors, the seismic signals being generated by seismic events within the Earth's subsurface. The method further includes adaptively velocity filtering the detected signals. The method further includes cross-correlating the velocity filtered seismic signals to obtain a reflectivity series at a position of each of the seismic sensors.

The interferometric method of enhancing passive seismic events includes the step of cross-correlation (CC) of the trace recorded at a reference receiver location with the traces recorded at the rest of receiver locations. Next, the CC traces are aligned to zero timing by applying shifts that are calculated by searching for the position of the maximum CC trace value. Subsequently, the aligned CC traces are summed to produce a stacked CC trace that has a signal-to-noise ratio (SNR) better than the individual CC traces. Lastly, the stacked CC trace is convolved with each raw trace to put the MS event at the correct timing. Due to this process, the timing of the MS event on the i-th convolved trace, tccasci, will be equal to the timing of the MS event on the corresponding i-th raw trace, i.e., tccasci=ti.

A system of and method for determining whether a liquid moving in an oil-bearing reservoir rock formation is water or oil is provided. The oil-bearing rock formation includes at production well(s) and source(s) of injected water during normal oil production. A fluid pathway is identified, baseline number of passive microseismic events is established, passive microseismic events in the fluid pathway are monitored during oil production to sense microseismic events, the sensed microseismic events are compared to a baseline number of passive microseismic events. The fluid causing the microseismic events is determined to be water if the sensed number of microseismic events approaches the baseline number of passive microseismic events per the predetermined unit, and if the baseline number of passive microseismic is measured during a time period when the water injection is greater than the rate of water injection during normal oil production.

The invention relates to a passive earthquake monitoring data compression method and a control system. The sampling rate of the existing devices can reach 10KHz as far as possible, accordingly data generated by monitoring are enormous, wireless long-distance real-time data transmission is led to be difficult, and much disc storage space is occupied. The passive earthquake monitoring data compression method is characterized by including steps of: (1) earthquake event recognition; (2) earthquake event intercepting: earthquake events which are already recognized are intercepted and effective earthquake event signals are separated from earthquake original signals; and (3) earthquake monitoring data compression: lossless compression of earthquake monitoring data is achieved by aid of steim-2coding. The passive earthquake monitoring data compression method and the control system can reduce transmission amount and storage space occupation.

A method for passive seismic surveying includes deploying seismic sensors in a plurality of spatially distributed wellbores disposed above a volume of subsurface formations to be evaluated. The sensors in each wellbore form a line of sensors. Each sensor generate optical or electrical signals in response to seismic amplitude. The seismic signals from each sensor are recorded for a selected period of time. The response of the seismic sensor recordings is beam steered to at least one of a selected point and a selected volume in the subsurface. At least one microseismic event is identified in the beam steered response.

A method of imaging the Earth's subsurface using passive seismic emission tomography includes detecting seismic signals from within the Earth's subsurface over a time period using an array of seismic sensors, the seismic signals being generated by seismic events within the Earth's subsurface. The method further includes inducing a seismic event within the Earth's subsurface during at least a segment of the time period over which the seismic signals are detected. The method further includes cross-correlating seismic signals detected at each of the seismic sensors to obtain a reflectivity series at a position of each of the seismic sensors.

Low sensitivity, single vertical axis or uniaxial transducer sensors are deployed along receiver lines across an area of interest to acquire low frequency passive seismic data from the earth. Recordings formed of the acquired low frequency passive seismic data are decomposed in the frequency-wavenumber (F-K) domain according to wavefront dipping angles into mono-dominant velocity seismic records. Resulting seismic waves of different types are identifiable based on the different dipping angles. Wavefields can then be analyzed separately in either time or frequency domains and analyzed or integrated with other data.

The invention discloses a dangerous area detection method and system based on active and passive seismic source signals, a terminal and a readable storage medium. The method comprises the following steps: step 1, acquiring seismic source signals, and arranging a micro-seismic sensor and an active seismic source in a monitoring area; step 2, identifying each seismic source signal as an active seismic source signal or a passive seismic source signal; step 3, positioning the passive seismic source signal to obtain a passive seismic source position and a passive seismic source signal release moment; step 4, inverting a monitoring area wave velocity field of the active seismic source signal and a monitoring area wave velocity field of the passive seismic source signal; and step 5, comparing themonitoring area wave velocity field of the active seismic source signal with the monitoring area wave velocity field of the passive seismic source signal to judge a goaf. According to the method, theactive seismic source and the passive seismic source are combined for positioning, and the goaf judgment precision is improved.

A method of identifying passive seismic events in seismic data that contains at least first seismic data traces acquired at a first seismic receiver and second seismic data traces acquired at a second receiver spatially separated from the first receiver comprises determining an overall measure of similarity for a pair of events in the seismic traces. The overall measure of similarity is indicative of similarity between the events acquired at the first seismic receiver and of similarity between the events acquired at the second seismic receiver. In one method, the overall measure of similarity is an overall cross-correlation coefficient. The overall cross-correlation coefficient is found by determining a first correlation coefficient for the pair of events from the data acquired at the first receiver and determining a second correlation coefficient for the pair of events from the data acquired at the second receiver. The overall correlation coefficient for the pair of events may be obtained from the first correlation coefficient and the second correlation coefficient by an averaging process. The overall measure of similarity may be compared with a threshold to determine whether the pair of events form a doublet. The method makes possible real-time or near-real-time identification of doublets.

The invention discloses a passive seismic source positioning method and system based on active seismic source correction, a terminal and a readable storage medium. The method comprises the following steps: acquiring an active seismic source signal and a passive seismic source signal based on an arranged micro-seismic sensor; carrying out the preliminary positioning of the passive seismic sources based on the passive seismic source signals, and correcting the preliminary positioning of each passive seismic source through employing the active seismic source signals; wherein the correction process comprises the following steps of: based on the actual arrival time difference of passive seismic source signals received by two micro-seismic sensors, and actual arrival time difference of each active seismic source signal received by the two micro-seismic sensors, determining one active seismic source as a target active seismic source; using the wave velocity when the microseismic sensor receives the target active seismic source signal as the velocity constraint when the microseismic sensor receives the passive seismic source signal, and using the velocity constraint to correct the initialpositioning of the passive seismic source. The positioning result of the passive seismic source is corrected by using the information of the active seismic source, and the positioning precision of thepassive seismic source is improved.

A system of and method for determining whether a liquid moving in an oil-bearing reservoir rock formation is water or oil is provided. The oil-bearing rock formation includes at least one production well and at least one source of injected water during normal oil production. A preferential fluid pathway is identified. A baseline number of passive microseismic events is established. Passive microseismic events in the preferential fluid pathway are monitored during normal oil production to sense a number of microseismic events, and the sensed number of microseismic events are compared to the baseline number of passive microseismic events. The fluid causing the microseismic events is determined to be water if the sensed number of microseismic events approaches the baseline number of passive microseismic events per the predetermined unit, and if the baseline number of passive microseismic is measured during a time period when the water injection is greater than the rate of water injection during normal oil production.

The invention relates to a seismic prospecting method via elastic wave resonance, and belongs to the fields engineering construction, resources and environment. The technical method in which active tri-component seismic prospecting data is used to obtain the wave impedance rate of S waves comprises the steps including data collection and construction and a data processing flow. The method can be used to solve the problems that passive seismic prospecting precision in specific areas (as in a town and an engineering construction place) is low in precision and slow in construction, boundaries ofa target object in surface wave prospecting are fuzzy and a spatial geometric position of the target object is hard to define; and the rapid solution is provided for seismic prospecting in areas of complex construction, especially in the shallow layer.

The invention discloses an active-passive hybrid seismic control method for a cultural relic and a free-standing platform. The active-passive hybrid seismic control method is first applied to a seismic proof research on preservation of cultural relics. The control method combines an active seismic control technology and a passive seismic control technology, can achieve a control effect superior to one of the active seismic control effect and the passive seismic control effect, and can overcome the defect of only relaying on the active seismic control or the passive seismic control. The influence of seismic waves on the cultural relics in a sudden earthquake is reduced, and the cultural relics are not overturned, do not glide and are not impacted, so that the integrity of the cultural relics is protected. The control method is mainly used for inhibiting vibration transmission in the horizontal direction, that is, transverse waves in the seismic waves. The propagation velocity of the transverse waves is lower than that of longitudinal waves in seismic waves, but the damage effect of the transverse waves is much higher than that of the longitudinal waves. Active control of the X direction and the Y direction, which are orthogonal, in the horizontal direction is realized, the horizontal acceleration component, the velocity component and the displacement component, which are transmitted to the cultural relics by the transverse waves, are effectively controlled and inhibited through active vibration, vibration of the cultural relics is reduced, and the safety of the cultural relics is protected.

The invention provides a description method of the crack fracture scale based on seismic wave full-waveform characteristics. The description method of the crack fracture scale comprises the followingsteps: generating a composite seismic source time function through modeling of the crack fracture scale, obtaining a Green function from a seismic source to an observation station through logging and / or three-dimensional seismic data, obtaining a synthetic micro seismic wave according to the composite seismic source time function, the Green function and a seismic moment tensor, and obtaining a composite micro seismic wave; calculating correlation coefficients of the synthetic microseismic waves and the microseismic waves recorded by the observation station based on the full waveform characteristics of the seismic waves, and selecting the fracture fracture scale recorded by the synthetic microseismic waves with the correlation coefficients within a preset coefficient allowable range as thefracture scale. The invention has the beneficial effects that the problem that the fracture dimension of the crack cannot be quantitatively described in passive earthquake monitoring can be solved.

The invention discloses a porous lead rubber bearing with high damping capacity and large bearing capacity and relates to a passive seismic reducing device. The porous lead rubber bearing comprises multiple steel plate layers, multiple rubber layers and cylindrical leads, wherein diameters of the steel plate layers and the rubber layers are the same, the steel plate layers and the rubber layers are alternately arranged from top to bottom, the multiple cylindrical leads penetrate through the steel plate layers and the rubber layers and are uniformly distributed in the circumferential direction of the bearing, circle centers of all the leads are located on a concentric circle of the bearing, and the diameter of the concentric circle is 56%-66% of that of the bearing. The porous lead rubber bearing has properties superior to the requirement for high seismic energy absorption, self-centering and normal functions under thermal deformation of a traditional bearing and meets an average ground displacement (about 500 mm) limit value under the action of M9 earthquake (with the peak acceleration of 0.62 g) in the code for seismic design of China, and the bearing capacity meets the requirement that vertical bearing capacity is not lower than 10,000 KN under the condition that surface pressure of the bearing for major precautionary category engineering is not higher than 12 MPa. The porous lead rubber bearing with high damping capacity and large bearing capacity can be widely applied to fields of seismic reduction and seismic isolation and the like of a large LNG (liquefied natural gas) storage tank, a large-span and single-pier bridge, a super high-rise building and a nuclear island of a nuclear power plant.