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VH RESERVOIR MAPPING
CROSS-REFERENCE TO RELATED
This application claims the benefit of expired U.S. Provisional Application No. 60/804,420 filed 9 Jun. 2006 and expiredU.S. Provisional Application No. 60/806,455 filed 30 Jun. 2006.
BACKGROUND OF THE DISCLOSURE
1. Technical Field
The disclosure is related to seismic exploration for oil and gas, and more particularly to processing and displaying seis- 15 mic data.
2. Description of the Related Art
Seismic exploration for hydrocarbons generally is conducted using a source of seismic energy and receiving and recording the energy generated by the source using seismic 20 detectors. On land, the seismic energy source may be an explosive charge or another energy source having the capacity to impart impacts or mechanical vibrations at or near the earth's surface. Seismic waves generated by these sources travel into the earth subsurface and are reflected back from 25 boundaries and reach the surface of the earth at varying intervals of time depending on the distance traveled and the characteristics of the subsurface material traversed. The return waves are detected by the sensors and representations of the seismic waves as representative electrical signals are 30 recorded for processing.
Normally, signals from sensors located at varying distances from the source are combined together during processing to produce "stacked" seismic traces. In marine seismic surveys, the source of seismic energy is typically air guns. 35 Marine seismic surveys typically employ a plurality of sources and/or a plurality of streamer cables, in which seismic sensors are mounted, to gather three dimensional data.
The process of exploring for and exploiting subsurface hydrocarbon reservoirs is often costly and inefficient because 40 operators have imperfect information from geophysical and geological characteristics about reservoir locations. Furthermore, a reservoir's characteristics may change as it is produced.
Data acquisition for oil exploration may have a negative 45 impact on the environment. The impact of oil exploration methods on the environment may be reduced by using lowimpact methods and/or by narrowing the scope of methods requiring an active source, including reflection seismic and electromagnetic surveying methods. 50
Geophysical and geological methods are used to determine well locations. Expensive exploration investment is often focused in the most promising areas using relatively slow methods, such as reflection seismic data acquisition and processing. The acquired data are used for mapping potential 55 hydrocarbon-bearing areas within a survey area to optimize exploratory well locations and to minimize costly non-productive wells.
The time from mineral discovery to production may be shortened if the total time required to evaluate and explore a 60 survey area can be reduced by applying selected methods alone or in combination with other geophysical methods. Some methods may be used as a standalone decision tool for oil and gas development decisions when no other data is available. Preferable methods will be economical, have a low 65 environmental impact, and relatively efficient with rapid data acquisition and processing.
Geophysical and geological methods are used to maximize production after reservoir discovery as well. Reservoirs are analyzed using time lapse surveys (i.e. repeat applications of geophysical methods over time) to understand reservoir changes during production.
In one embodiment a method of locating subsurface hydrocarbon reservoirs or displaying hydrocarbon potential maps includes acquiring seismic data having a plurality of components, dividing the seismic data into time windows, applying a data transform to the seismic data having a plurality of components to obtain transformed data components, determining a ratio of the transformed data components and recording the ratio of the transformed data components in a form for display.
In another embodiment a computerized method for determining a subsurface hydrocarbon reservoir location includes determining the subsurface hydrocarbon reservoir location based on ratio data from a plurality of orthogonal spectral components of naturally occurring low frequency background seismic data. The ratio data that exceed a predetermined threshold value, which may be in a predetermined frequency range, indicate the presence of subsurface hydrocarbons.
In another embodiment a computerized method of mapping a subsurface hydrocarbon reservoir includes selecting ratio data which exceed a predetermined threshold value for map locations indicating a subsurface hydrocarbon reservoir. The ratio data are derived from a plurality of orthogonal spectral components of naturally occurring low frequency background seismic data.
In another embodiment an information handling system for determining subsurface hydrocarbons associated with an area of seismic data acquisition includes a processor configured to determine whether a ratio calculated from a plurality of orthogonal spectral components of naturally occurring low frequency background seismic data exceeds a predetermined threshold value, in predetermined frequency range, wherein the ratio exceeding the threshold value indicates a presence of subsurface hydrocarbons. The information handling system also includes a computer readable medium for storing the determined ratio indicating the presence of subsurface hydrocarbons.
In another embodiment a system for subsurface hydrocarbon reservoir mapping includes a machine readable medium storing naturally occurring low frequency background seismic data and map values associated with the seismic data. A processor is configured to determine a plurality of map values associated with the seismic data, each map value determined from a ratio of a vertical spectral component to at least one horizontal spectral component of the seismic data. The processor is configured to determine map values greater than a predetermined threshold that indicate the presence of subsurface hydrocarbons.
In another embodiment a set of application program interfaces is embodied on a machine readable medium for execution by a processor in conjunction with an application program for detecting a subsurface hydrocarbon reservoir. The set of application program interfaces includes a first interface that receives ratio data representative of a vertical spectral component relative to a horizontal spectral component, the spectral components derived from naturally occurring low frequency background seismic data. A second interface receives the ratio data for comparison with a predetermined
threshold value to determine whether the ratio data indicates the presence of a subsurface hydrocarbon reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic illustration of a method according to an embodiment of the present disclosure for calculating a spectral ratio;
FIG. 2 illustrates a flow chart related to a method for processing according to an embodiment of the present disclo- io sure for determining parameters related to subsurface hydrocarbon reservoir detection; and
FIG. 3 is diagrammatic representation of a machine in the form of a computer system within which a set of instructions, when executed may cause the machine to perform any one or 15 more of the methods and processes described herein.
Information to enable the direct detection of hydrocarbon 2o reservoirs or forming hydrocarbon potential maps or displays may be extracted from naturally occurring seismic waves and vibrations measured at the earth's surface. These naturally occurring waves may be measured using passive seismic data acquisition methods to acquire naturally occurring back- 25 ground seismic data. Peaks or troughs in the spectral ratio between the vertical and the horizontal components of the background waves may be used as an indicator for the presence of hydrocarbon reservoirs. While references is made to hydrocarbon reservoir maps, it should be understood that the 30 methods apply equally to methods for hydrocarbon potential maps, that is where data indicated the possibility of hydrocarbons in the subsurface.
Low-impact survey methods like passive seismic data acquisition may be used for reconnaissance in frontier explo- 35 ration areas, to monitor reservoirs over the productive life of a field or to cost-effectively upgrade data room information to generate higher license bids. Specific applications forpassive seismic data include monitoring fluid flow, estimating shearwave velocities, site zonation and shear-wave amplification 40 studies for earthquake hazard surveys, monitoring hydraulic fracturing during reservoir stimulation and inversion for earth structure.
Passive seismic data acquisition methods rely on seismic energy from sources not directly associated with the data 45 acquisition. In passive seismic monitoring there is no actively controlled and triggered source. Examples of low frequency ambient waves that may be recorded with passive seismic acquisition are microseisms (e.g., rhythmically and persistently recurring low-frequency earth tremors), microtremors 50 and other anthropogenic or localized seismic energy sources.
Microtremors are attributed to the background energy present in the earth that may be due to non-seismic sources or anthropogenic noise. Microtremor seismic waves may include sustained seismic signals within a limited frequency 55 range. Microtremor signals, like all seismic waves, contain information affecting spectral signature characteristics due to the media or environment that the seismic waves traverse. These naturally occurring relatively low frequency background seismic waves (sometimes termed noise or hum) of 60 the earth may be generated from a variety sources, some of which may be indeterminate.
Survey results from passive seismic surveying demonstrate that the spectral characteristics of microtremor seismic waves often contain relevant information for direct hydrocarbon 65 detection. Direct hydrocarbon reservoir indicators may be extracted from naturally occurring low frequency back
ground seismic data using spectral analysis of these microtremors. Spectral ratios or changes in spectral ratios over geographic areas may be used to delineate subsurface hydrocarbon reservoirs. Microtremor analysis provides a method for identification and mapping of fluid reservoirs or reservoir related parameters directly from data acquired near the earth's surface in land and marine areas using naturally occurring seismic background waves. Collected over time these data highlight changes in reservoir parameters.
Microtremor analysis allows for direct determination of a hydrocarbon reservoir independent of the reservoir structure. Additionally, the thickness of strata associated with a hydrocarbon reservoir may be determined or inferred from microtremor analysis.
One or more sensors are used to measure vertical and horizontal components of motion due to background seismic waves at multiple locations within a survey area. These components may be measured separately or in combination and may be recorded as signals representing displacement, velocity, and/or acceleration.
The sensors may measure the components of motion simultaneously or asynchronously. As the spectral ratio of the acquired signal for any location may be quite stable overtime, the components of motion may not need to be measured simultaneously. This may be especially applicable in areas with relatively low local ambient wave energy and for data acquired over relatively short time periods (e.g., a few weeks). Spectral ratios determined from asynchronous components at a location may be used as it is the relative difference of spectral components as opposed to specific contemporaneous differences that may be indicative of reservoir characteristics. However, due to anthropogenic or localized seismic energy generated in the vicinity of the seismic survey not related to subsurface reservoirs, relative quiescent periods free of this local anthropogenic seismic energy wherein orthogonal data components are substantially contemporaneously acquired may provide better quality data for delineating subsurface characteristics.
The spectral ratio of vertical to horizontal data components may be calculated to obtain a ratio of at least one horizontal component over the vertical component (a H/V ratio), or the vertical component over at least one horizontal component (a V/H spectral ratio). Characteristics of spectral ratio data may be mapped, for example by plotting geographically and contouring the values. Peaks (or troughs) representative of anomalies within the spectral ratio map may correspond to hydrocarbon or other fluid accumulation within the earth. Changes in V/H ratios over a survey area may be used to detect the boundaries of the reservoirs, and may correspond to areal boundaries of hydrocarbon accumulations. These anomalies may also give an indication of the thickness of fluid reservoirs. This information may be compared, analyzed and integrated with other geophysical and geological knowledge to improve an operator's understanding of the subsurface.
Geophysical survey local conditions may affect a method's results. In many cases the spectral ratio method provides a reliable direct hydrocarbon indicator; in other cases a skilled operator can use the results to improve their interpretation of other geological and geophysical data and generate an improved subsurface model allowing for more efficient exploration and production decisions.
The sensor equipment for measuring seismic waves may be any type of seismometer. Seismometer equipment having a large dynamic range and enhanced sensitivity compared with other transducers may provide the best results (e.g., multicomponent earthquake seismometers). A number of commercially available sensors utilizing different technologies may
be used, e.g. a balanced force feed-back instrument or an electrochemical sensor. An instrument with high sensitivity at very low frequencies and good coupling with the earth enhances the efficacy of the method.
Ambient noise conditions representative of seismic wave 5 energy that may have not traversed subsurface reservoirs can negatively affect the recorded data. Techniques for removing unwanted artifacts and artificial signals from the data, such as cultural and industrial noise, are important for applying this method successfully in areas where there is high ambient 10 noise that has not interacted with a subsurface hydrocarbon reservoir.
The spectral ratio method has several advantages over conventional seismic data acquisition for exploration including that the technique does not require an artificial seismic 15 source, such as an explosion, mechanically generated vibration or electric current. Additionally, the results from spectral analysis are repeatable and the results may be correlated to hydrocarbon accumulations. There is little or no environmental impact due to data acquisition. The method is applicable 20 for land, transition zones and marine areas. The method has application in areas where higher frequencies are greatly affected by geological conditions, e.g. in areas where soft soil layers attenuate high-frequency seismic signals as well as areas where salt formations or volcanic bodies (e.g. basalt 25 flows, volcanic sills) scatter or obscure higher frequencies.
Spectral ratio analysis may take advantage of the selective absorption and hydrocarbon induced relative amplification of relatively low-frequency seismic background waves to enable mapping spectral difference that directly indicate hydrocar- 30 bon reservoirs.
The spectral ratio of the horizontal over the vertical components (H/V ratio) of seismic background waves has been used as an indicator for soft soil layers and other near-surface structures. Soft soil resonance effects visible in H/V spectra 35 often occur at frequencies (up to 20 Hz). In contrast to the soft soil effect, in the vicinity of hydrocarbon reservoirs, the horizontal earth movements may be attenuated more strongly than the vertical movements as compared to areas distal from hydrocarbon reservoirs. This relative attenuation may result 40 in a trough in the H/V ratio spectrum or a peak in the V/H ratio spectrum. The hydrocarbon related peak in the V/H spectrum may be located at relatively low frequencies (e.g., between 0 and 10 Hz, and often in the range 1 to 4 Hz), though parameters may be case specific. 45
FIG. 1 is a schematic illustration of a method according to an embodiment of the present disclosure using passively acquired naturally occurring background seismic data to determine a spectral ratio related to direct indications of hydrocarbons. The embodiment, which may include one or 50 more of the following referenced components (in any order), is a method of locating subsurface anomalies related to hydrocarbon accumulations that includes obtaining seismic data having a plurality of components 101. The acquired data may be time stamped and include multiple data vectors. An 55 example is multicomponent earthquake type seismometry data, which includes recordings of low-frequency seismic background waves as differentiated from localized or anthropogenic energy related seismicity. The multiple data vectors may each be associated with an orthogonal direction of move- 60 ment. Data may be acquired in, or mathematically rotated into, orthogonal component vectors arbitrarily designated east, north and depth (respectively, Ve, Vn and Vz) or designated Vx, V and Vz according to desired convention. The data vectors may all be the same length and synchronized. 65
The vector data may be divided into time windows 103 for processing. Window lengths may be greater than ten times the
period of the lowest frequency of interest. For example if a frequency of interest has a period around 7 seconds all the windows may be at least 70 seconds long. However, the length of time windows for analysis may be chosen to accommodate processing or operational concerns.
A data transform may be applied to each component of the vector data 105. Seismic data frequency content often varies with time. Time-frequency decomposition (spectral decomposition) of a seismic signal enables analysis and characterization of the signal time-dependent frequency response due to subsurface materials and reservoir parameters.
Various data transformations are useful for time-frequency analysis of seismic signals, such as continuous or discrete Fourier or wavelet transforms. Examples include without limitation the classic Fourier transform or one of the many continuous Wavelet transforms (CWT) or discrete wavelet transforms. Examples of other transforms include Haar transforms, Haademard transforms and wavelet transforms. The Morlet wavelet is an example of a wavelet transform that may be applied to seismic data. Wavelet transforms have the attractive property that the corresponding expansion may be differentiable term by term when the seismic trace is smooth. Additionally, signal analysis, filtering, and suppressing unwanted signal artifacts may be carried out efficiently using transforms applied to the acquired data signals.
One or more orthogonal components of the acquired data may be merged, for example the horizontal data components 107. Horizontal components Ve and Vn may be merged by any of several ways including a root-mean-square average so that horizontal component H may be defined as H= V(V e2+V„2)/2. Whether merging data components is undertaken before or after a data transform is applied to the data is a matter of choice.
Additionally the spectra may be smoothed using a moving average 109. The smoothing parameter defines the width of the window (in Hz) used for calculating moving averages. A large smoothing parameter leads to strong smoothing and a small smoothing parameter leads to less smoothing. Typical values may be between 0.1 Hz and 2 Hz, but will be case dependent. A smoothing parameter for a flow may be selected at the beginning of a processing flow for application prior to calculating a spectral ratio.
The V/H spectral ratio is calculated 111 based on the spectral division (e.g., point-by-point spectral division) between the transformed output of at least two orthogonal components, such as a horizontal spectral component and the vertical spectral component. The horizontal component may be a combination of the measured horizontal components (as in 107). These spectra or the calculated spectral ratios may be averaged over time windows 113. Averaging over time windows may be by arithmetic mean or geometric mean. Averaging of spectra may be undertaken before or after dividing the spectra into spectral ratios. The results after this processing may be output 115 in a form for mapping or other display. Maps of this V/H spectral ratio output may provide direct indications of the geographical extent of hydrocarbon reservoirs in the field survey vicinity. Values indicating the presence of a hydrocarbon reservoir may be selecting using a threshold ratio value which may be determined objectively or subjectively. For example, ratio data that exceed (being greater than) a threshold V/H ratio of 1.5 (or that exceed (lower than) an H/V ratio of 0.67) has been shown to indicate a hydrocarbon reservoir. Greater or lower threshold values may be area or survey dependent. An example of ratio data exceeding a predetermined threshold value indicating the presence of subsurface hydrocarbons over a survey area