WO1999004292A1

WO1999004292A1 - Method for monitoring an induced fracture with vsp

Info

Publication number: WO1999004292A1
Application number: PCT/US1998/013595
Authority: WO
Inventors: Donald F. Winterstein; Joseph P. Stefani
Original assignee: Chevron U.S.A. Inc.
Priority date: 1997-07-14
Filing date: 1998-06-30
Publication date: 1999-01-28
Also published as: AU8177898A

Abstract

Method for characterizing an induced fracture in a subterranean reservoir (105). The method utilizes the trait that a fracture held open by a fluid will not transmit shear wave seismic energy. In the method, geophones are positioned with respect to a shear wave seismic energy source such that one geophone (203) will record shear wave seismic energy from the source (201) and the other geophone will be blocked from detecting shear wave seismic energy from the source. The blocked geophone (203) will detect varying amounts of diffracted energy from the source, the amounts depending on ray geometry and wave frequency content.

Description

METHOD FOR MONITORING AN INDUCED FRACTURE WITH VSP

FIELD OF THE INVENTION

This invention pertains to subsurface imaging, and in particular to a method for imaging and monitoring induced subsurface fractures. The method finds particular use in the petroleum production industry.

BACKGROUND OF THE INVENTION In petroleum reservoirs having low porosity, one method of improving the production from such a reservoir is to induce a fracture within the reservoir, thus providing channels for the oil to flow into and towards the production well. Fracturing is accomplished by injecting a fluid such as steam or water into the reservoir at a pressure sufficiently high to overcome the pressure of the overburden, thus allowing the rock to fracture. Typically, fractures lie in a nearly vertical plane with respect the earth's surface. When petroleum engineers induce fractures in tight reservoirs, they need to know where the fractures lie. This is especially true for intensively developed fields, where fractures from one well might interfere with other wells, but it is important everywhere if there is a danger of fracturing into unwanted formations. Approximately 20,000 fracture treatments are performed every year at an estimated cost of $860 million, so a significant improvement in efficiency would have a major economic impact.

Previous methods to image fractures have used tiltmeters and passive monitoring. The former method involves many unknowns, such as accounting for subsidence, thermal expansion, and other physical events which affect the tiltmeter reading, as well as not providing information about the height of the fracture from top to bottom, or the location of the top of the fracture with respect to the earth's surface, or relative dimensions of the fracture wings. Passive monitoring may require that one or more new dedicated wells be installed at particular locations with respect to the well in which the fracturing is initiated. In some cases the receivers must be cemented in the well. Drilling such dedicated wells or cementing geophones can add significant cost which may not be justified. The result is that oil reserves which might otherwise be recoverable are not recovered because the induced fracture is not sufficiently large or properly oriented or its dimensions are unknown. Classical 2D and 3D seismic imaging methods using surface receivers and surface sources do not provide for good imaging of induced fractures since recording surveys requires too much time and the fractures are not properly oriented to give good reflections. Thus, what is needed in the art is a reliable inexpensive method for imaging the orientation and length of an induced fracture, as well as the height of the fracture. BRIEF DESCRIPTION OF THE DRAWINGS Fig. 1 is an environmental view showing a subterranean formation in which the method of the present invention is practiced and shows the concept of shear wave shadowing of a fracture.

Fig. 2 is a schematic plan view of the reservoir of Fig. 1 showing seismic source locations, receiver locations, and the fracture.

Fig. 3 is a schematic diagram of a detail of Fig. 2 showing the concept of regions in which end points of the fracture may be located. Fig. 4 is a seismogram depicting a cross-sectional view of the reservoir showing the fracture and the reflection of shear waves therefrom.

Fig. 5 is a graph showing the amplitude of the shear wave as a function of the angle between the fracture plane normal and the source-receiver azimuth when the fracture is held in a fully opened positioned. Fig. 6 is a graph showing the amplitude of the shear wave as a function of the angle between the fracture plane normal and the source-receiver azimuth when the fracture is only 15 percent open.

Fig. 7 is a seismogram depicting the shadowing effect that the open fracture has on shear waves. Fig. 8 is a seismogram depicting the shear wave signal that is received in the absence of an open fracture.

Fig. 9 is a schematic diagram showing a vertical fracture in a plan view and depicting the reflection and transmission of various seismic wave components therefrom. Fig. 10 is a cross-sectional diagram of a subterranean reservoir depicting how the method may be practiced with geophones that record transmission and absence thereof of shear waves, as well as reflection and absence thereof of shear waves from the fracture.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT It is known that fractures with apertures, even very small apertures, are completely opaque to shear waves with particle motions in the plane of the fracture. See, for example, Vertical Seismic Profiling: Technique, Applications, and Case Histories, by A. H. Balch and Myung W. Lee, International Human Resources Development Corporation, 1984, Chapter 9; Vertical Seismic Profiling: The Hydrofrac, by Roger Turpening and Carol Blackway, p. 361-370. While it was recognized that shear waves would be shadowed by an open fracture, it was not known to use shear waves to completely characterize a fracture.

We have invented a method whereby the orientation (azimuth), length, and height (orientation, shape and size) of an induced fracture may be determined by using multiple shear wave seismic energy sources or source locations, preferably at the surface, in conjunction with receiver arrays in at least two monitoring wells.

Turning to Fig. 1, a subterranean formation 10 is shown. A treatment well 101 is shown into which a fracturing fluid may be injected into a preferred zone 103 which is to be fractured. Fracture zone 103 may be an oil bearing zone in which it is desired to increase production of oil by fracturing the medium of the zone. Fracturing is accomplished by pumping a fracturing fluid into the treatment well at a pressure sufficiently high to overcome the overburden of the various strata above zone 103. When the pressure becomes sufficiently high, the strata will fracture allowing fluid from the treatment well to enter into the reservoir, and vice versa.

Turning to Fig. 2, a plan view of the reservoir 10 is provided, showing the treatment well 101 and fracture 105. Fracture 105 is characterized by endpoints 106 and 107, as well as top 108 and bottom 109 (shown in Fig. 1). End points may change with depth, and top and bottom edge points with location along the fracture. Fracture 105 is also characterized by its orientation, also known as the azimuth, which is the angle between the fracture and a reference direction. For example, as shown in Fig. 2, the reference direction may be a North/South line 110. The azimuth then is the angle θ between line 110 and fracture 105. It is to be appreciated then that the fracture may be considered essentially a near- vertical plane in a subterranean reservoir which is typically oriented essentially perpendicular with respect to the surface 100 of the earth. Although fractures will have deviations in the line of the fracture and the orientation of the fracture plane with respect to the earth's surface, and, therefore, the fracture plane is not truly a plane, for the purpose of the discussion and description of the method herein the magnitudes and expression "fracture plane" will be used for the sake of convenience. Expected variations in the actual shape of the fracture and its orientation should not diminish the efficacy of the invention described herein. Shear waves are particularly advantageous for use of imaging open fractures due to the shadowing property described above. Most shear waves will be severely attenuated if their ray paths cross open fractures, but shear waves whose particle motion lies in the plane of the fracture will be completely stopped. Thus, for shear wave shadowing to be most effective, it is preferred to use shear waves whose motion parallels the fracture plane. As demonstrated graphically in Fig. 9, horizontal shear waves indicated by SH are completely reflected by the open fracture 105. Vertical shear waves (Sv) are partially reflected and partially transmitted by the open fracture. Therefore, waves like the depicted horizontal shear waves are the most effective for determining the presence of a fracture. Due to the property that azimuthally anisotropic rock which is typical of most sedimentary basins naturally aligns the particle motion of the fast shear wave parallel to the likely fracture plane, the method is particularly useful in reservoirs of this type for characterizing and imaging induced fractures. In addition, reservoirs in sedimentary basins are often low in porosity and, therefore, particularly susceptible to use of induced fractures to increase production. Many such oil fields are mature and have a large number of monitoring and injection wells already installed in the field. Due to the fact that the present invention is capable of being practiced using existing wells that are located proximate to the treatment well, thus reducing the need for drilling new wells, the present method is particularly useful in such fields. In the following discussion, the words "geophones," "sensor," and "receiver" are all used interchangeably. Further, in the preferred embodiment of the method, the geophones are located in a geophone string or geophone array which is disposed within a monitoring well. In the following discussion, when it is stated that a signal is "received at a monitoring well," it is understood that the monitoring well has geophone array disposed therein. However, it is understood that geophones may be located at the surface at the monitoring well location. It is also understood that geophones may be located at a surface point where in fact no monitoring well is located. In such an embodiment, a downhole seismic energy source will be provided to generate seismic energy to be detected by geophones on the surface.

Referring again to Fig. 1, a source of shear waves 112 is located at the surface 100 of the reservoir 10. Shear wave sources are well known and will not be described herein. Referring to Fig. 2, it is seen that at least four sources or source locations 119, 112, 121, and 123 in combination with receiving locations 115 and 117 are required to identify the end points 106 and 107 of the fracture 105.

The receivers or geophone arrays are preferably located in monitor wells and are more preferably located in monitor wells close to the injector well which created the fracture, and more preferably within approximately 100 meters of the injection well. In alternate embodiments, geophone arrays may be laid out on the surface with downhole energy sources used. Also, downhole energy sources may be used in conjunction with downhole geophone arrays, especially where sources are deployed in horizontal wells. In the preferred embodiment, surface seismic source arrays are used in conjunction with downhole geophone arrays.

While the invention is described in terms of detecting the relative presence or absence of shear wave seismic energy (i.e., high or low attenuation), in the preferred embodiment nine component seismic energy sources are used in combination with three component receivers. The additional components allow for the acquisition of additional information which is useful in imaging the reservoir and the fracture. For example, in conjunction with recording the shear wave seismic energy, the method preferably includes obtaining a zero (0) offset VSP in order to obtain a good velocity profile from the surface to reservoir depths and to evaluate any change with depth in shear wave polarization. Both types of information are useful for data analysis. Further, before holding the fracture open with steam or water or other fluid opaque to shear waves, a baseline survey with the source at all source offset positions should be recorded. To ensure proper source wavelet stability and zero-time corrections, a three component geophone should be located at sufficient depth to detect a consistent signal from the source but in a location unaffected by the induced fracture. The fracture would then be opened by steaming the fracture or injecting water. During the shear wave shadowing survey, the injection fluid used to hold the fracture open should be held at a constant pressure. No zero offset recording is necessary during the shear wave shadowing survey. It is preferable to place the source locations during the shear wave shadowing survey in the same locations as they were placed for the baseline survey.

Although described as "endpoints" 106 and 107, the end points are ideally vertical lines defining the sides of the fracture. In practice the fracture sides will not be vertical. For example, in Fig. 1, the side defined by one of the end points might be the fracture edge shown between top 108 and bottom 109 of fracture 105.

For simplicity the following discussion assumes an absence of wave diffraction that waves are of sufficiently high frequency that diffraction is ignorable. In practice, data interpretation requires taking diffraction into account.

Fracture 105 is characterized by having "wings," a first wing 123 and a second wing 124, being disposed either side of the treatment well 101. Since it is known that fracture 105 must pass through treatment well 101, the plurality of offset sources may be placed on the side of the treatment well 101 opposite the monitoring wells 115 and 117. Since it is not known where endpoints 106 and 107 of fracture 105 lie, the problem would seem to be indefinite since one would not know along which line to place an offset source. For example, offset source 119 and monitor well 115 lie in a line which includes end point 107. However, a line between offset source 125 and monitor well 115 would not pick up the end point 107 of the fracture, nor would a line between offset source 126 and monitor well 115. However, even if an offset source is not placed such that it exactly lies in a line between the monitor well and the end point, one may interpolate to approximate the position of the end point. For example, shear waves from source 125 will not be blocked from monitor well 115 due to the fact that the fracture 105 does not lie in a direct line between source 125 and monitor well 115. However, shear waves from source 126 will be blocked from monitor well 115 by fracture 105. It may therefore be concluded that the end point 107 lies between line 139 and line 140. The location of end point may be further refined by producing a second set of lines 141 and 142 connecting seismic sources 137 and 138, respectively, with monitor well 117, as shown in Fig. 2. That is, assuming that sources are not located at locations 125, 126, 137 and 138, and further assuming that source 125 produces a result at monitor well 115 indicating the absence of a fracture, while source 126 produces no signal at monitor well 115 indicating the presence of a fracture, and further assuming that source 137 and 138 likewise bracket the endpoint 107 of the fracture, then it can be said that the intersection of lines 139 and 140 with lines 141 and 142 will produce a region in which the endpoint 107 of fracture of 105 must be located. With respect to Fig. 3, the region 144 is such a region.

Likewise, endpoint 106 may be located within a region provided sources are not located at 121 and 123 which would precisely locate the endpoint 106. That is, sources would be located at 135 and 136, as well as at either side of source location 121. The result would be a region 145 of Fig. 3 which brackets the endpoint. Since the fracture is assumed to be a straight line with injection well 101 lying along the line, and since the end points must be constrained within regions 144 and 145, we are able to further reduce the possible locations in which the end points may be found by connecting a line through the extremes of each region 144 and 145 with the injection well 101. Performing this exercise produces regions 344 and 345 in which the endpoint must be located.

It is convenient to think of a line connecting a seismic source or a seismic source location with a receiver location as a ray path. In the case where seismic energy propagates from the source location to the receiver location, this is an accurate description since the seismic energy can be traced back along the ray path to the original source. However, in the instance where seismic energy is blocked from the receiver by the fracture, we may nonetheless think of a line connecting the source and the receiver as a ray path, even though seismic energy may not propagate all the way to the receiver. Additionally, we may think of the region bounded by two ray paths as a ray path band. For example, the region bounded by source locations 125 and 126 and monitor well 115 may be considered as a ray path band. That is, the region bounded by lines 139 and 140 is a ray path band. It is the intersection of two ray path bands which produces the region in which the end point of the fracture will lie. It will be further appreciated that in a geophone string for each geophone in the string, a ray path band is produced. In locating the region in which a fracture end point is located, the invention consists essentially of generating two non-parallel ray path bands, and then identifying the region of intersection of the two bands. This region then produces the region in which the end point must lie.

While we have stated that the fracture blocks shear wave seismic energy from receivers which would be located in monitoring wells, in fact some diffraction energy about the edge of the fracture may be detected at geophones which are shielded from shear wave energy by the fracture. Fig. 4 shows such diffraction effects. With respect to Fig. 4, shear wave energy 60 is shown reflecting off of fracture 105 producing reflection 61. Diffraction energy 63 is shown between the 0.25 and 0.3 second marks on the vertical axis. Using known diffraction modeling methods, which typically comprise finite difference modeling diffraction methods which are well known in long wave length seismology, the location of the end point within a region may be further refined. The accuracy with which diffraction modeling may refine the location of the endpoint varies depending on a number of factors, and will not be further described here.

Once the possible range of locations of the end points of the fracture 105 are known, the possible range of azimuth angles of the fracture is also known. Referring to Fig. 3, the angle γ is shown. Referring to Fig. 2, the azimuth Q then becomes the angle γ of Fig. 3 ± oJ2, wherein « is the angle of the range of possible azimuths of the fracture.

It will be appreciated that by using smaller spacing between offset sources, smaller regions 344 and 345 of Fig. 3 will be produced. In the preferred embodiment, an array of seismic sources is radially disposed between 120 and 360 degrees, and more preferably over about 240-270 degrees about the treatment well 101. In one example, an offset source spacing of 10° over a total azimuthal range of 240 degrees was used for sources approximately 200 meters from the treatment well. The radial spacing of the sources may be anywhere between about 1° and about 30°. The geophone spacing in the array is preferably about 7 to 10 m when installed in the monitor well. It should be noted that once the end points of the fracture have been determined or approximated, not only do we know the approximate azimuth of the fracture, but we also know the approximate total length of the fracture as well as the approximate length of each wing of the fracture. Because the receiver array is typically of considerable length we know the fracture dimensions as a function of depth.

It is now left to determine the height of the fracture. It is desirable to know the vertical height of a fracture to determine the height of the fractured zone of the reservoir.

In a similar manner as we earlier described locating the "end points" of the fracture which are, ideally, vertical lines defining the edges of the fracture plane in the vertical direction, in like manner, when defining the top and bottom of the fracture plane, we describe a method for locating or approximating a point on the upper and lower edges of the fracture plane. It may then be assumed for simplicity that the fracture plane top and bottom edges lie essentially horizontal within the earth's surface. In reality, this is not necessarily true.

Returning to Fig. 1, monitoring wells 115 and 117 are shown with geophone or receiver arrays 114 and 116, respectively. Since the location of offset source 112 is known with respect to the location of treatment well 101 and monitor wells 115 and 117, and since fracture 105 will cast a shear wave shadow on all receivers in receiver rays 114 and 116 falling within shadow zone 150, it is possible to identify the top 108 and bottom 109 of fracture 105. It will be appreciated that only a single geophone or receiver array is required in a single monitoring well to identify the top and bottom endpoints 108 and 109, respectively. However, additional monitoring wells will help define the actual orientation of the upper edge and lower edge of the fracture plane at different points along the fracture's length.

As discussed above for locating the endpoints 106 and 107 (which, as described, are actually indicative of the sides of the fracture plane), it cannot be guaranteed that a receiver will lie in a line between the offset source and the upper edge 108 and lower edge 109 of the fracture plane. However, it will be known if a receiver in the geophone array is blocked by the fracture or not. A geophone in the array which is blocked by the fracture will not detect direct shear wave seismic energy from the source 112. A geophone within the array which is not blocked by the fracture 105 will detect shear wave energy from the source 112. Typically, two geophones in the array will bracket the top or bottom edge of the fracture. It may than be said that the top or bottom fracture edge lies within the imaging region or ray path band bracketed by those two geophones. As with end point detection, finer geophone spacing in the array may produce closer resolution of the upper and/or lower edges of the fracture. Likewise, certain diffraction energy will be detected by geophones which are blocked from shear wave energy. Using known diffraction methods, the approximate location of the upper end or lower edges of the fracture may be further refined.

In all instances it is not always necessary to know the top or bottom boundary of the fracture, or one particular end or the other. It may only be desired to, for example, determine where the end of one wing of the fracture ends or where the top or bottom of the fracture ends. In the instance where it is only desired to determine the top edge or bottom edge of the fracture, geophone arrays need only be positioned so as to record those shear waves which would be shadowed by the desired edge to be determined. Likewise, if only a single end point of a wing is to be determined, seismic shots need only be positioned so as to ensure that an endpoint is detected within the desired range. That is, ray path bands bracketing only one edge may be produced for the edge in interest.

As discussed previously, to accurately determine the edge location of a fracture with the present method, it is desirable to either have some knowledge about where the approximate edge might lie so as to position seismic shots to bracket the edge portion or to deploy an extensive array of seismic sources and receivers. If no information is available which would provide an approximate position as a starting point or extensive surveys are not practical, then one may "hunt" for the edge locations. Typically, at least two seismic sources or shots at different locations will be required for each monitoring well to determine an end point, as described above.

It should be appreciated that monitoring wells and seismic sources need not be located on opposite sides of the fracture. This is demonstrated in Fig. 4 where it is shown that the shear waves 60 are reflected from the fracture 105. Therefore, a geophone on the same side of the fracture as the source, S of Fig. 4, would record the reflected seismic energy as well as the seismic energy incident from the source. This is demonstrated in Fig. 5. Fig. 5 is a graph showing normalized maximum recorded amplitude as a function of source receiver azimuth. It is seen that the amplitude is near zero when the source and receiver are diametrically opposed on opposite sides of the fracture, that is, when the source receiver azimuth is zero degrees. Likewise, when the source receiver azimuth is 180° and the reflection from the fracture as well as the energy propagating directly from the source both pass through the receiver, the amplitude is at its maximum of 1. At this point (azimuth of 180°), the geophone records both the shear wave energy reflected from the fracture, as well as the shear wave energy generated directly by the source. It is also seen that as the receiver moves from a position diametrically opposed to the source on the other side of the fracture to a position at 90° from the source, an increasingly significant amplitude is recorded. This amplitude is the diffraction energy discussed above and shown as 63 on Fig. 4.

If a sensor on the same side of the fracture as the seismic source detected only the incident energy from the seismic shot, it would be appreciated that the seismic energy had propagated into the reservoir rather than being reflected from the fracture. Given favorable ray geometry, this would indicate the absence of a fracture, whereas a reflection would indicate the presence of a fracture. The ray paths generated in the reflection mode, as well as theoretical ray paths, can be used to locate regions in which an edge of the fracture lies. In its simplest embodiment then, the invention consists of a method for determining the approximate location of an edge of a subterranean fracture. A first embodiment consists of determining the location of a horizontal edge of a fracture in a subterranean reservoir. By horizontal edge, we mean either a top or bottom edge. The method comprises generating shear wave seismic energy so as to impinge at least part of the seismic energy on the subterranean fracture, and measuring shear wave seismic energy at at least two locations. The first measurement location is situated so as to record seismic energy affected by the fracture, the second location situated so as to record seismic energy not affected by the fracture. In a first variation, the first location is located so as to measure seismic energy propagating directly from the shear wave source, and the second location is positioned so as to detect the absence of shear wave energy blocked from the detector by the fracture. In a second variation, the first location is positioned so as to detect the absence of shear wave energy reflected by the fracture, and the second location is positioned so as to measure shear wave energy reflected from the fracture. The second variation is less robust, because tilt of the fracture will skew the results. That is, the variation is very sensitive to tilt.

Fig. 10 illustrates this first embodiment of the invention. Shear wave seismic energy is generated at source 201. In the first variation, which is more robust than the second, geophone 203 is positioned so as to detect shear wave seismic energy propagating directly from source 201 and not reflected by fracture 105, while geophone 205 is positioned so as to detect the absence of shear waves which are blocked by the fracture. In the second variation, which is less robust than the first, geophone 207 is positioned so as to detect the absence of shear wave seismic energy reflected from the fracture 105, while geophone 208 is positioned so as to detect the reflection of shear wave seismic energy from the fracture. Geophones 203 and 205 are typically part of an array 215 of geophones which would be inserted into a monitor well 210, while geophones 207 and 208 would similarly be part of a geophone array 217 positioned in a monitor well 211.

The first embodiment further comprises processing the data set to generate images depicting either the absence or presence of shear wave energy recorded by the geophones, the area of the image between seismic traces indicating the presence or absence of shear wave energy being indicative of the approximate location of the top or bottom edge of the fracture.

For example, referring to Fig. 7, in the variation where geophones are positioned so as to detect the absence of shear wave energy which is blocked by the fracture, it can be seen that the geophone positioned at 2300 feet indicates that shear wave energy is still being received and, therefore, the top edge of the fracture is not present along the ray. However, the geophone at 2325 feet clearly shows a strong attenuation of the shear wave energy, and we can therefore conclude that the shear wave energy has been blocked by the upper edge of the fracture. Ignoring for the moment the subtleties of diffraction effects, it can thus be said that the upper edge of the fracture lies between 2300 feet and 2325 feet, a range of 25 feet. Often this level of accuracy is sufficient; however, if more accuracy is desired then either additional geophones, additional receiving positions, additional seismic sources, additional locations of the seismic source, seismic modeling, or some combination thereof, will be required. Fig. 8 shows what the seismogram would look like if no edge were detected.

In a second embodiment, the invention comprises a method for determining a vertical edge of a subterranean fracture. By vertical edge, we mean an edge which is aligned essentially vertically within the reservoir which might otherwise be known as the "sides" of the fracture or the "edge of a wing" of the fracture.

In a first variation of the second embodiment of the invention, the method comprises the steps of generating shear wave seismic energy at a first location so as to impinge at least a portion of the shear wave seismic energy on the fracture, and recording at a first recording location the presence or absence of the shear wave seismic energy, the absence of shear wave seismic energy being indicative of the presence of the fracture. Next, shear wave energy is generated at a second location to impinge at least a portion of the shear wave seismic energy on the fracture, and measuring the presence or absence of shear wave seismic energy from the second location at the first receiving source. Thus, two ray paths are produced which bracket the end point. The first and second locations at which shear wave energy are generated are located such that the first receiving source will receive seismic shear wave energy from one source location and will not receive shear wave seismic energy from the other source location, it being understood that the relative absence of shear wave seismic energy received at the first source being indicative of the fracture intersecting a line or ray path which lies between the receiving location and the source not detected, while the presence of seismic energy detected at the receiving source being indicative of the absence of the fracture intersecting the line or ray path connecting the source and the receiver. The two ray paths thus provide a first ray path band in which the edge point lies.

Likewise, shear wave seismic energy is generated at third and fourth locations and directed so as to impinge at least a portion of the shear wave seismic energy on the fracture. The presence or absence of shear wave seismic energy from the third and fourth locations is measured at a second receiving location. As with the first and second source locations, the third and fourth source locations are located such that shear wave seismic energy from location is detected at the second receiving source, and shear wave seismic energy from the other source location is not detected by the second receiving location. Thus, a second set of ray paths defining a second ray path band is produced. The edge point of the edge to be detected also lies within this ray path band. Since the ray path band is not parallel to the first ray path band but in fact intersects the first ray path band, the region of intersection of the two ray path bands will further constrain the possible locations of the edge point.

Thereafter, the results of the seismic survey are plotted graphically or analyzed to determine the approximate vertical edge location of the fracture. Specifically, the first presence of the fracture is indicated by a line or ray path connecting the geophone which detected the relative absence of shear wave seismic energy with the seismic source which generated the seismic energy. A line or ray path connecting that geophone is then connected to the seismic source which generates seismic energy which was detected by the geophone. It is then known that the vertical edge of the fracture lies somewhere between these two lines or ray paths which connect one seismic source and the first geophone and the other seismic source and the geophone. Likewise, for the second geophone, similar lines or ray paths are drawn from the other two seismic sources which show the detection or absence of shear wave seismic energy at the geophone. In the case where more than two seismic source locations are used for each receiving location, the seismic sources which are selected for each geophone should be the two seismic sources which are closest to each other and which produce in combination both a presence and an absence of shear wave seismic energy at the geophone. The lines or ray paths from the first set of seismic sources connecting the first geophone and lines or ray paths from the second set of seismic sources connecting the second geophone will intersect to form a quadrilateral, as indicated by areas 144 and 145 of Fig. 3. It can then be determined that the horizontal edge of the fracture lies somewhere within this quadrilateral, this quadrilateral being previously described as the region of intersection of the two ray path bands.

In a like manner, the other vertical edge of the fracture may be determined in a like manner as the first vertical edge. Additional seismic source locations may be, but are not necessarily, required. Typically, the same two receiving locations will be used to locate the second end point, but other receiving locations may also be used.

The possible position of end points constrained by each quadrilateral will restrain the overall possible locations of the two end points, since the two end points must connect and must pass through the treatment well in which the fracture was generated. Once the approximate locations of the end points of the fracture are known, the approximate azimuth of the fracture is also easily determined merely by measuring the range of angles between the azimuth reference position and the line representing the fracture which passes through the treatment well.

As with the first embodiment, the accuracy of the location of the end points of the fracture can be improved by using more offset sources, closer grouping of offset sources, moving the offset sources to multiple positions, additional receiving locations, diffraction modeling methods, or combinations thereof. In practice, diffraction effects will typically occur during the imaging process. These effects are best accounted for by applying additional known interpretation steps to the image processing as well as by employing known diffraction modeling methods to the results.

The first variation of the second embodiment of the invention is best demonstrated graphically in Figs. 2 and 3.

In a second variation on the second embodiment of the invention, the method comprises the method of the first variation, but comprising the variation of using at least one geophone location which is disposed on the same side of the fracture as at least one of the seismic sources. As with the second variation of the first embodiment, the geophone located on the same side of the fracture as the seismic source is used to detect either the absence of shear wave seismic energy being reflected from the fracture, indicating the absence of the fracture, or the shear wave seismic energy reflected from the fracture, indicating the presence of the fracture.

In yet another variation on the second embodiment both geophone locations could be located on the same side of the fracture as the seismic sources. Another variation would provide for at least one geophone location to be placed along a line containing the fracture. It is to be appreciated that various other variations of position of the geophone locations and the seismic sources may be configured without varying from the essence of the invention. Generally, in the second embodiment, at least three and preferably four seismic source locations are used to generate two sets of non-parallel ray path lines, a first set of non-parallel ray path lines indicating the presence or absence of the edge of the fracture, and a second set of non-parallel ray path lines which also indicate the presence or absence of the vertical edge of the fracture. The intersection of the four lines or ray paths will define a zone or region where the vertical edge of the fracture will lie. Likewise, a third and fourth set of intersecting non-parallel lines indicating the presence or absence of the other vertical edge of the fracture can also be generated to produce a zone of the proximate location of the second vertical edge. As stated previously, once these two zones are known, the approximate location of the fracture can be determined by connecting the possible end points which fall within the zones and also pass through the treatment well which was used to generate the fracture. The third embodiment of the invention, previously alluded to, comprises determining the azimuth of the fracture. The method comprises determining the possible end points of the fracture in accordance with the second embodiment of the invention, connecting the set of possible end points which produce the minimum possible azimuth and also pass through the treatment well which was used to generate the fracture, and connecting the end points which produce the maximum possible azimuth and which also pass through the treatment well. The azimuth then lies somewhere between the minimum and maximum possible azimuths. As with the methods for determining the edges of the fracture, the accuracy of the azimuth can be improved by using finer source spacing, additional source positions, additional receiver locations, seismic modeling methods, or combinations thereof.

The first and second variations of the first embodiment may be combined with the second and third embodiments to completely characterize the fracture, that is, the height and width and azimuth of the fracture and the lengths of each wing of the fracture. This may be considered a fourth embodiment of the invention. In a fifth embodiment of the invention, the invention comprises a method for characterizing attributes of a fracture by analyzing data recorded in accordance with one of the first or second embodiments to determine the location of the horizontal or vertical edges of the fracture, or the azimuth of the fracture, rather than graphically determining the characteristics. Data processing of the results of surveys practiced by the above-described method should include at least the following steps:

1) Kill bad traces;

2) Rotate three component receivers to appropriate azimuths; 3) Rotate shear wave sources to appropriate azimuths;

4) Calculate and apply zero-time corrections;

5) Stack like traces;

6) For impulsive sources, add and subtract data of appropriate source and receiver polarities to obtain compressional waves and shear waves; 7) Rotate shear wave data into natural coordinate frames;

8) Examine shear wave data for shadowing— determine fracture geometry; and

9) Examine compressional wave data for transit time or amplitude changes- interpret changes. While in the preferred embodiment of the invention, the fracture is held completely open by steaming or injection of water, the method may also be practiced with a fairly high degree of accuracy by holding the fracture only partially open. Fig. 6 is a graph of the amplitude versus receiver offset azimuth for a fracture which is held only 15 percent open. Comparing Fig. 6 with Fig. 5 which shows amplitude versus source receiver azimuth for a fracture completely held open, it can be seen that at low azimuths, that is where the receiver lies on the opposite side of the fracture as the source, an amount of leakage of shear wave seismic energy through the fracture occurs. However, very small change in the reflective nature of the fracture is shown when the source receiver azimuth is greater than about 30°. Beyond 90° virtually no difference is noticeable.

This invention may be embodied in other specific forms without departing from the essential characteristics as described herein. The embodiments described above are to be considered in all respects as illustrative only and not restrictive in any manner. The scope of the invention is indicated by the following claims rather than by the foregoing description. Any and all changes which come within the meaning and range of equivalency of the claims are to be considered within their scope.

Claims

What is claimed is:

1. A method for approximating the location of an edge of a subterranean fracture, comprising: generating seismic energy at a first and a second source location so as to impinge seismic energy on at least a part of said fracture; measuring for any of said seismic energy generated at said first and said second source locations to be received at a first receiving location to produce measurements from each of said first and said second source locations; analyzing said measurements produced at said first receiving location by said first and said second source locations to identify one source location which caused a relatively unattenuated seismic signal to be received at said first receiving location, and one source location which caused a relatively highly attenuated seismic signal to be received at said first receiving location, to identify a first band which intersects said edge of said fracture; generating seismic energy at third and a fourth source location so as to impinge seismic energy on at least a part of said fracture; measuring for any of said seismic energy generated at said third and said fourth source locations to produce measurements at said second receiving location; and analyzing said measurements produced at said second receiving location to identify one source location which caused a relatively unattenuated seismic signal to be received at said second receiving location, and one source location which caused a relatively highly attenuated seismic signal to be received at said second receiving location, to identify a second band which intersects said edge of said fracture, said second band intersecting said first band in a region where said edge of said fracture lies.

2. A method for approximating the location of an edge of a subterranean fracture, comprising: generating seismic energy at a first source location so as to impinge seismic energy on at least a part of said fracture; measuring for any of said seismic energy generated at said first source location to be received at a first and a second receiving location to produce measurements at each of said first and said second receiving locations; analyzing said measurements produced at said first and said second receiving locations to identify one receiving location at which a relatively unattenuated seismic signal is received from said first source location, and one receiving location at which a highly attenuated seismic signal has been received from said first source location, to identify a first band which intersects said edge of said fracture; generating seismic energy at a second source location so as to impinge seismic energy on at least a part of said fracture; measuring for any of said seismic energy to be received at a third and a fourth receiving location to produce measurements at each of said third and said fourth receiving locations; and analyzing said measurements produced at said third and said fourth receiving locations to identify one receiving location at which a relatively unattenuated seismic signal is received from said second source location seismic energy, and one receiving location at which a highly attenuated seismic signal has been received from said second source location, to identify a second band which intersects said edge of said fracture, said second band intersecting said first band in a region where said edge of said fracture lies.

3. The method of claim 2 wherein at least one of said receiving locations is located so as to detect the presence or absence of seismic energy generated from at least one of said source locations being reflected from said fracture to said receiving location, the reflection of said seismic energy being indicative of the presence of said fracture.

4. Method for approximating the location of an edge of a subterranean fracture, comprising: generating a first ray path band and second ray path band, said first and said second ray path bands intersecting in a region where said edge of said fracture lies, wherein each of said ray path bands are bounded by a first ray path which intersects said fracture, and a second ray path which does not intersect said fracture.

5. The method of claim 4 wherein said ray paths are representative of seismic energy ray paths which connect seismic energy source locations to seismic energy receiving locations.

6. The method of claim 4 wherein at least one of said ray path bands has a first end and a second end, said first end defined by a seismic source location, said second end defined by least two seismic receiver locations.

7. The method of claim 4 wherein at least one of said ray path bands has a first end and a second end, said first end defined by a seismic receiver location, said second end defined by least two seismic source locations.

8. Method for approximating the location of an edge of a subterranean fracture, comprising: generating a first set of ray path bands and second set of ray path bands, each set of ray path bands intersecting in a region where said edge of said fracture lies, wherein each of said ray path bands is bounded by a first ray path which intersects said fracture, and a second ray path which does not intersect said fracture.

9. The method of claim 8 wherein each of said ray path bands has a first end and a second end, said first end defined by a seismic receiver location, said second end defined by least two seismic source locations.

10. The method of claim 9 wherein said seismic receiver locations are located below the earth's surface, and said seismic source locations are located on the earth's surface.

11. The method of claim 9 wherein said seismic receiver locations are located at the earth's surface, and said seismic source locations are located below the earth's surface.

12. The method of claim 9 wherein the set of receiver locations defining said first ends of each of said first and said second sets of ray path bands corresponds respectively to a first and a second seismic geophone array.

13. The method of claim 12 wherein said geophone arrays comprise three component geophones.

14. The method of claim 9 wherein said seismic source locations correspond to individual seismic sources in an array of seismic sources.

15. The method of claim 14 wherein said fracture was produced by hydrofracturing via a treatment well and said fracture lies essentially in a near vertical plane, said treatment well intersecting at least a portion of said plane, and wherein said array of seismic sources is radially disposed in a sector about said treatment well.

16. The method of claim 14 wherein said fracture was produced by steam fracturing via a treatment well and said fracture lies essentially in a near vertical plane, said treatment well intersecting at least a portion of said plane, and wherein said array of seismic sources is radially disposed in a sector about said treatment well.

17. The method of claim 16 wherein said seismic sources generate shear wave seismic energy.

18. The method of claim 17 further comprising injecting a fluid opaque to shear wave seismic energy into said fracture and maintaining said fluid at a pressure sufficient to maintain said fracture in at least a partially open position during a period in which seismic energy is generated to produce said ray path sets.

19. The method of claim 17 wherein said seismic sources are multi- component seismic energy sources.

20. The method of claim 17 wherein said seismic sources are spaced between 1 and 30 degrees apart.

21. The method of claim 17 wherein said seismic sources are spaced approximately 10 degrees apart.

22. The method of claim 17 wherein said geophone arrays are disposed in monitoring wells.

23. The method of claim 22 wherein said seismic sources are located on the earth's surface.

24. The method of claim 17 wherein the location within said region of said edge of said fracture is further refined by using modeling methods.

25. The method of claim 24 wherein said modeling method is a finite difference diffraction modeling method.

26. The method of claim 8 wherein said first and said second set of ray path bands define a first region in which a first edge of said fracture lies, the method further comprising: generating a third ray path band and a fourth ray path bands, said third and said fourth ray path bands intersecting in a second region where a second edge of said fracture lies, wherein each of said third and said fourth ray path bands are bounded by a first ray path which intersects said fracture, and a second ray path which does not intersect said fracture.

27. The method of claim 26 wherein said first edge and said second edge of said fracture are essentially parallel.

28. The method of claim 27 wherein said fracture was produced by hydrofracturing via a treatment well and said fracture lies essentially in a near vertical plane, said treatment well intersecting at least a portion of said plane to bifurcate the plane into two wings disposed about said treatment well, and wherein said first and said second edges of said fracture correspond to the sides of said fracture, the method further comprising defining the approximate length and azimuth of said fracture plane from side to side, by: delineating the points in the first region which pass through said treatment well and connect with the points in the second region to render maximum and minimal azimuths and lengths of said fracture.

29. The method of claim 26 wherein each of said ray path bands has a first end and a second end, said first end defined by a seismic receiver location, said second end defined by least two seismic source locations.

30. The method of claim 29 wherein said seismic source locations correspond to individual seismic sources in an array of seismic sources.

31. The method of claim 30 wherein said seismic sources generate shear wave seismic energy.

32. The method of claim 31 further comprising injecting a fluid opaque to shear wave seismic energy into said treatment well and thereby into said fracture and maintaining said fluid at a sufficient pressure to maintain said fracture in at least a partially open position during a period in which seismic energy is generated to produce said ray path bands.

33. Method for characterizing an induced fracture in a subterranean formation, said fracture lying in a plane at an angle to the surface of the earth, and characterized by having a treatment well disposed therein, and having first and second side edges, wherein said subterranean formation is characterized by having a first and second monitoring well disposed therein, said monitoring wells having geophone arrays disposed therein, said geophone arrays comprising a plurality of geophones, wherein a plurality of seismic energy sources is disposed on the surface such that said treatment well lies between lines connecting selected ones of said seismic energy sources and said monitoring wells, said seismic energy sources being capable of producing shear wave seismic energy, and wherein said fracture is held in at least a partially open position by the injection of a fluid into said fracture, said fluid being at least partially opaque to shear wave seismic energy, the method comprising: generating shear wave seismic energy to produce ray path bands defining primary regions in which said edges of said fracture lie, each said ray path band being bounded by a first ray path defined by a line which connects a first defining seismic energy source and a defining geophone and which also intersects said fracture, and a second defining ray path defined by a line which connects a seismic energy source adjacent to the first defining seismic energy source with said defining geophone and which does not intersect said fracture; identifying sets of intersecting ray path bands, the intersections defining two secondary regions, each said secondary region defining the range of possible locations of said edges of said fracture; defining the range of possible azimuthal orientations and possible lengths of said fracture by connecting points between the two regions which produce the minimal possible azimuthal orientation of said fracture and which also pass through said injection well, and connecting points between the two regions which produce the maximum possible azimuthal orientation of said fracture and which also pass through said injection well.

34. Method for approximating the location of an edge of a subterranean fracture, comprising: configuring seismic energy receivers and seismic energy sources, said seismic energy sources being capable of generating shear wave seismic energy, so as to produce measurements at said seismic energy receivers indicative of the presence or absence of said fracture, the absence being due to the opacity and high reflectance of a open fracture to shear wave seismic energy; identifying actual and hypothetical ray paths generated by said seismic energy which bracket an endpoint, said bracketing being achieved by one ray indicating the presence of said fracture, and another ray indicating the absence of said fracture, said bracketing producing edge intersection bands; determining the region of intersection of two edge intersection bands, said region being a region in which said edge of said fracture lies.

35. The method of claim 34 wherein at least one of said seismic energy receivers and at least one of said seismic energy sources which are used to produce an edge intersection band are located on the same side of the fracture.

36. The method of claim 34 wherein said seismic energy receivers are located below the earth's surface, and said seismic energy sources are located on the earth's surface.

37. The method of claim 34 wherein said seismic energy sources are located below the earth's surface, and said seismic energy receivers are located on the earth's surface.