Communications – electrical: acoustic wave systems and devices – Seismic prospecting – Well logging
Reexamination Certificate
2002-08-06
2004-06-08
Moskowitz, Nelson (Department: 3663)
Communications, electrical: acoustic wave systems and devices
Seismic prospecting
Well logging
C367S025000, C367S040000, C367S057000, C175S001000, C175S040000, C175S050000, C166S249000, C166S254200, C166S250160, C181S102000, C181S104000, C181S106000
Reexamination Certificate
active
06747914
ABSTRACT:
FIELD OF THE INVENTION
The invention relates to the downhole generation and recording of seismic waves for use in investigation and monitoring of earth formation reservoir characteristics surrounding a well borehole. In particular, the invention relates to a method and system for monitoring seismic energy radiated from well boreholes into surrounding earth formations. The seismic body waves radiated into the surrounding earth formation, which may be converted from borehole tube waves, are used for cross well type projects and reverse VSP type projects to investigate and monitor hydrocarbon or other mineral deposits over the productive lifetime of a producing reservoir.
BACKGROUND OF THE INVENTION
This is a system for monitoring the distribution of the contents of a subsurface mineral deposit over its economic life span for long-term resource management. The system employs acoustic waves generated when borehole tube waves impinge upon minor borehole obstructions. Time varying changes of selected attributes of those acoustic waves that have transited the deposit between boreholes, may be indicative of the temporal changes in the mineral content.
Geophysical surveys are used to discover earth structure, mineral deposits, and the subsurface extent of mineral deposits such as oil, natural gas, water, sulphur, etc. Geophysical methods may also be used to monitor changes in the deposit, such as depletion resulting from production of the mineral over the economic lifetime of the deposit. The usefulness of a geophysical study depends on the ability to quantitatively measure and evaluate some geophysical analogue of petrophysical parameters related to the presence of the mineral under consideration.
Seismic methods may be applied to production-management monitoring as well as to exploration of hydrocarbon reservoirs. As is well known to geophysicists, an acoustic source at or near the surface of the earth is caused periodically to inject an acoustic wavefield into the earth at each of a plurality of source survey stations. The wavefield radiates in all directions to insonify the subsurface earth formations. The radiated wavefield energy is reflected back to be detected by seismic sensors (receivers) located at designated stations also usually located at or near the surface of the earth, but which may also be in the subsurface, for example, in well boreholes (herein, also called wellbores). The seismic sensors convert the mechanical earth motions, due to the reflected wavefield, to electrical signals. The resulting electrical signals are transmitted over a signal-transmission link of any desired type, to instrumentation, usually digital, where the seismic data signals are archivally stored for later processing.
The travel-time lapse between the emission of a wavefield by a source and the reception of the resulting sequence of reflected wavefields by a receiver is a measure of the depths of the respective earth formations from which the wavefield was reflected. The relative amplitudes of the reflected wavefields may be a function (an analogue) of the density and porosity of the respective earth formations from which the wavefields were reflected as well as the formations through which the wavefields propagated. The phase angle and frequency content of returned signals in the reflected wavefields may be influenced by formation fluids, the sought-for minerals or other formation characteristics.
The processed seismic data associated with a single receiver are customarily presented as a one-dimensional time scale recording displaying rock layer reflection amplitudes as a function of two-way wavefield travel time. A plurality of seismic traces from a plurality of receivers sequentially distributed along a line of survey at intervals, such as 25 meters, may be formatted side by side to form a two dimensional (2-D) analog model of a cross section of the earth. Seismic sections from a plurality of intersecting lines of survey distributed over an area of interest provide three-dimensional (3-D) imaging. A series of 3-D surveys of the same region made at successive time intervals, such as every six months, would constitute a 4-D, time-lapse study of the subsurface that would be useful to monitor, for example, the fluid-depletion rate of hydrocarbon reservoir.
The term “signature” as used herein, means the variations in amplitude, frequency and phase of an acoustic waveform (for example, a Ricker wavelet) expressed in the time domain as displayed on a time scale recording. As used herein the term “coda” means the acoustic body wave seismic energy imparted to the adjacent earth formation at a particular location. The coda associated with a particular seismic energy source point or minor well bore obstruction in this invention will be the seismic signature for that seismic energy source point. The term “minor borehole obstruction” or “borehole discontinuity” or “discontinuity” means an irregularity of any shape or character in the borehole such that tube wave energy transiting the well borehole will impart some energy to the irregularity in the borehole and thus radiate body wave energy into the surrounding earth formation while continuing to also transmit and reflect some the tube wave energy along the borehole. The term “impulse response” means the response of the instrumentation (seismic sensors and signal processing equipment) to a spike-like Dirac function or impulse. The signal energy of an acoustic wavefield received by seismic sensors depends upon the texture of the rock layers through which the wavefield propagated, from which it was reflected or with which it is otherwise associated, whether along vertical or along lateral trajectories. The term “texture” includes petrophysical parameters such as rock type, composition, porosity, permeability, density, fluid content, fluid type and intergranular cementation by way of example but not by way of limitation.
From the above considerations, it is reasonable to expect that time-lapse seismic monitoring, that is, the act of monitoring the time-varying characteristics of seismic data associated with a mineral deposit such as a hydrocarbon reservoir of oil or gas over a long period of time, would allow monitoring the depletion of the fluid or mineral content, or the mapping of time-varying attributes such the advance of a thermal front in a steam-flooding operation.
Successful time-lapse monitoring requires that differences among the processed data sets must be attributable to physical changes in the petrophysical characteristics of the deposit. This criterion is severe because changes in the data-acquisition equipment and changes in the processing algorithms, inevitable over many years may introduce differences among the separate, individual data sets from surveys that are due to instrumentation, not the result of dynamic reservoir changes.
In particular, using conventional surface exploration techniques, long-term environmental changes in field conditions such as weather and culture may affect the outcome. If time-lapse tomography or seismic monitoring is to be useful for quantitative hydrocarbon reservoir monitoring, instrumentation and environmental influences that are not due to changes in reservoir characteristics must be transparent to the before and after seismic data sets. Successful time-lapse tomography requires careful preliminary planning.
One way to avoid many time-dependent environmental changes and updated state-of-the-art instrumental changes is to permanently install seismic sources and seismic detectors in one or more boreholes in and around the area of economic interest. Identical processing methods are applied to the data throughout the monitoring period using cross-well (cross-borehole) tomography rather than conventional surface type operations. One such method is disclosed in U.S. Pat. No. 5,886,255, filed Oct. 14, 1997 and assigned to the assignee of this invention and which is incorporated herein by reference as a teaching of cross-well tomography.
U.S. Pat. No. 5,406,530, issued Apr. 11, 1995 to Tokuo Yamamoto, teaches a no
Baker Hughes Incorporated
Madan Mossman & Sriram P.C.
Moskowitz Nelson
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