Data processing: measuring – calibrating – or testing – Measurement system in a specific environment – Earth science
Reexamination Certificate
1999-09-22
2002-12-10
Lefkowitz, Edward (Department: 2862)
Data processing: measuring, calibrating, or testing
Measurement system in a specific environment
Earth science
C367S020000, C367S024000
Reexamination Certificate
active
06493636
ABSTRACT:
FIELD OF THE INVENTION
This invention relates to a method for acquiring and processing three-dimensional (“3D”) marine seismic data.
BACKGROUND OF THE INVENTION
Exploration for hydrocarbons under offshore waters is becoming increasingly important. The prospective hydrocarbon reservoir structures that need to be detected are becoming smaller and are more difficult to image on seismic sections and their commercial value is more difficult to establish with standard seismic data quality. The need to mitigate these difficulties translates into a requirement for higher resolving power of the seismic data.
Further, the depth of the waters where the search is conducted is continually growing deeper. As the water depths grow deeper, the costs and risks associated with exploring for and producing the hydrocarbons increases.
Also, new techniques such as directional drilling have allowed several reservoirs to be produced from a single platform. This significantly reduces the costs associated with recovering the hydrocarbons and allows maximum usage of the installed facilities. To effectively drill and complete directional wells into several reservoirs and to optimally produce hydrocarbons from the reservoirs, it is desirable to have as much information as possible about reservoirs and the sediments that overlie the reservoirs. It is desirable to be able to cheaply and effectively collect and process higher resolution seismic data than is typically acquired today. For these drilling and production requirements it is also desirable to increase both the lateral and the vertical resolution of processed seismic data.
Currently, the most common system used to acquire marine three dimensional (3D) seismic data is shown in
FIG. 1. A
conventional acquisition system
21
utilizes one or more seismic sources
23
, such as air guns or waterguns, which radiate sonic energy into the water. These conventional arrays also utilize a group of streamers
25
that are laterally separated from one another, but lie in approximately the same horizontal plane. Located at regular intervals along the length of each streamer are hydrophones
27
. Normally, seismic source
23
is fired while source
23
and streamers
25
are being towed through water
29
. The sound energy that is produced from source
23
travels downward through water
29
and underlying strata
31
. Hydrophones
27
located on streamers
25
collect the seismic signal that is reflected from strata
31
and travels back through water
29
to hydrophones
27
. The collected seismic signal is recorded and processed by methods known to the industry.
In general, the vertical resolution of processed seismic data is proportional to the effective bandwidth of the processed seismic signal. Streamer noise can be a major factor in limiting the effective bandwidth of the processed seismic signal. Typically, streamers
25
are towed deeper below the sea surface
33
to minimize the noise and thereby maximize the effective bandwidth of the processed signal. However, as the depth at which streamers
25
are towed increases, the adverse effect of Receiver Signal Ghosts (as hereinafter described) on the processed signal increases. For conventional seismic acquisition and processing, the Receiver Signal Ghosts cause deep notches in the wavelet spectrum of the recorded seismic signal. In practice, no sound energy is typically usable at frequencies greater than the first notch (“ghost notch”). The approximate frequency where the first notch occurs can be determined by Equation 1 below:
f
N
=V
W
/2
D
Eq. (1)
Where,
f
N
=Notch frequency
V
W
=Propagation velocity of sound wave in water
D=Depth of the detector
This frequency (f
N
) is approximate because an assumption is made that the sound waves are plane waves propagating vertically in the water. Due to the fact that the velocity of sound in water is much lower than the velocity of sound under the seabed, Eq.(1) is generally a good approximation.
As can be seen from Eq.(1), the first notch moves lower in frequency as the streamers are towed deeper, thereby, reducing the effective bandwidth of the processed seismic signal. Therefore, in conventional 3D marine seismic acquisition, the streamers tend to be towed deeper to minimize streamer noise, but this tends to reduce the effective bandwidth of the processed signal and thereby reduces the vertical resolution of the processed seismic signal.
Seismic acquisition techniques have been developed which use “vertical arrays” in which the hydrophones are vertically offset from one another, but generally lie in the same plane. For example, U.S. Pat. No. 3,952,281 discloses a method for collecting seismic data from a towed vertical hydrophone array that uses one or more towed seismic streamers that are spaced apart vertically. U.S. Pat. No. 3,952,281 does not disclose a method for collecting 3D marine seismic data using streamers separated both vertically and horizontally.
Techniques have been developed in an attempt to reduce the effect of ghost signals on processed seismic data. For example, U.S. Pat. No. 4,992,992 discloses a method for collecting seismic data from a towed vertical hydrophone array that uses a towed seismic streamer having a slanted orientation in the water. The patent also discloses a method for processing the seismic data to reduce the effect of ghost signals on the processed seismic signal. U.S. Pat. No. 4,992,992 discloses that the recorded data is processed to align the primary signals, thereby misaligning the ghost signals. The patent also discloses that the data is also preferably processed to align the ghost signals, thereby misaligning the primary signals. The patent further discloses that the two resulting data sets may be combined. Unfortunately, it is very difficult to maintain a streamer in a straight slanted orientation while it is being towed through the water. The devices necessary to maintain the streamer in a slanted orientation are difficult to operate and create a large amount of noise that can reduce the quality of the processed seismic signal. This can result in seismic surveys that are expensive to acquire and difficult to process effectively.
U.S. Pat. No. 4,992,991 discloses a method for acquiring marine seismic data that utilizes at least three seismic cables that are towed parallel to the surface of the sea and are located at two different depths. Each of the cables has a plurality of hydrophones spaced along its respective length. The patent discloses that the arrangement of the hydrophones in the seismic array allows the directionality of the wavelets entering the network of cable to be determined and that one advantage of the array is that the actual separation distances of the cables within the network of cables can be controlled for maximum wavelet direction identification. However, the patent does not disclose configuring such a network of cables to acquire high density 3D seismic data. Further, the patent does not disclose any particular methods to use for processing the seismic data acquired and does not disclose any method of processing the acquired seismic data to reduce the effects of Receiver Signal Ghosts on the processed seismic.
For a 3D marine seismic survey, the achievable lateral resolution of the processed seismic is proportional to the areal density of the seismic data acquired. It is generally cheaper and therefore more desirable to acquire high density seismic data using a large number of closely spaced streamers in a single pass seismic acquisition layout, than to acquire that data by making several overlapped passes using a boat towing streamers that are not as closely spaced. However, for a conventional marine 3D seismic acquisition, minimum streamer proximity becomes a key obstacle in shooting high density surveys. Typically, a minimum lateral spacing of at least fifty meters (50 m) between adjacent streamers is desirable to avoid collision or entanglement of the streamers. In general, for a single source seismic design, the minimum achievable subsurface line spa
Gutierrez Anthony
Lefkowitz Edward
Shell Oil Company
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