Patent Application
20110188347
1. Field
This patent specification relates generally to hydraulic fracturing characterization in wellbore applications. More particularly, this patent specification relates to three-dimensional imaging for hydraulic fracture characterization.
2. Background
Hydraulic fracturing for stimulation of conventional reservoirs consists of the injection of a high viscosity fracturing fluid at high flow rate to open and then propagate a bi-wing tensile fracture in the formation. With the exception of the near-wellbore region where a complex state of stress might develop, it is expected that this fracture will propagate normal to the far-field least compressive stress. The length of this tensile fracture can attain several hundred meters during a fracturing treatment of several hours. The fracturing fluid contains proppants, which are well-sorted small particles which are added to the fluid to maintain the fracture open once the pumping is stopped and pressure is released. This allows one to create a high conductivity drain in the formation. Examples of these particles includes sand grains and ceramic grains. At the end of the treatment, it is expected to obtain a fracture fully packed with proppants. The production of the hydrocarbons will then occur through the proppant pack. The hydraulic conductivity of the fracture is given by the proppant pack permeability and the retained fracture width.
Hydraulic fracturing is also very successfully applied in very low permeability gas saturated formations (often called unconventional gas reservoirs). These formations include tight-gas sandstones, coal bed methane, and gas shales. While the permeability of tight-gas sandstones is of the order of hundreds of microDarcy, gas shale permeability is of the order of hundreds of nanoDarcies. These reservoirs cannot be produced without stimulation. In these formations, field observations of fracturing treatment do not always support the concept of the creation of the commonly accepted bi-wing tensile fracture. Mine-back experiments (see, Warpinski, N. R. and Teufel, L. W. (1987) Influence of geologic discontinuities on hydraulic fracture propagation, Journal of Petroleum Technology, 39, 2, Aug. 1987: 209-220; Jeffrey, R. G., Byrnes, R. P., Lynch, P. A. and Ling, D. J. (1992) An Analysis of Hydraulic Fracture and Mineback Data for a Treatment in the German Creek Coal Seam, Paper SPE 24362, In Proceedings of the 1992 SPE Rocky Mountain. Regional Meeting, Casper, Wyo., USA, 18-21 May 1992: 445-457 (hereinafter “Jeffrey 1992”); and Jeffrey, R. G., Weber, C. R., Vlahovic, W. and Enever, J. R. (1994) Hydraulic Fracturing Experiments in the Great Northern Coal Seam, Paper SPE 28779, In Proceedings of the 1994 SPE Asia Pacific Oil and Gas Conference, Melbourne, Australia, 7-10 Nov. 1994: 361-371), information obtained from laterals drilled across previously hydraulically fractured zones (see, Warpinski, N. R., Lorenz, J. C., Branagan, P. T., Myal, F. R. and Gall, B. L (1993) Examination of a Cored Hydraulic Fracture in a Deep Gas Well., SPE Production and Facilities, 8, 3, Aug. 1993: 150-158; and Waters, GT., Heinze, J., Jackson, R., Ketter, A. Daniels, J. and Bentley, D. (2006) Use of Horizontal Well Image Tools to Optimize Barnett Shale, In Proceedings of Reservoir Exploitation SPE Annual Technical Conference and Exhibition, San Antonio, Tex., USA, 24-27 Sep. 2006), and the record of microseismic events during a stimulation treatment (see, Fisher, M. K., Wright, C. A., Davidson, B. M., Goodwin, A. K, Fielder, E. O. Buckler, W. S. and Steinsberger, N. P. (2005) Integrating Fracture-Mapping Technologies To Improve Stimulations in the Barnett Shale, SPE Production and Facilities, 20, 2, May 2005: 85-93; and Daniels, J., Waters, G., Le Calvez, J., Lassek, J. and Bentley, D. (2007) Contacting More of the Barnett Shale Through an Integration of Real-Time Microseismic Monitoring, Petrophysics, and Hydraulic Fracture Design, In Proceedings of SPE Annual Technical Conference and Exhibition, Anaheim, Calif., U.S.A, 11-14 Nov. 2007 (hereinafter “Daniels 2007”)) indicate the creation of a complex fracture network geometry. The actual cause of this complex pattern is not yet fully established, but the above mine-back experiments, including those done for mining application (see, Van As, A. and Jeffrey, R. G. (2000) Caving induced by hydraulic fracturing at Northparkes Mines. In Proceedings of the 4th North American Rock Mechanics Symposium, Pacific Rocks 2000 Seattle, Wash. Jul. 31-Aug. 3, 2000, J. Girard, and others, (Eds), 353-360. Rotterdam: Balkema), and field observations of natural hydraulic fractures (see, e.g. Pollard, D. D. and Aydin, A. (1988) Progress in understanding joints over the last century, Geological Society of American Bulletin, 100: 1181-1204; and Cooke, M. L. and Underwood, C. A. (2000) Fracture termination and step-over at bedding interfaces due to frictional slip and interface opening, Journal of Structural Geology, 23: 223-238) suggest that natural fractures prevent the creation of a single tensile fracture and promote the creation of fracture offsets and multi-branched fractures. This is especially true in some shales where tensile natural fractures are not aligned with the current principal stress direction because they were created in an era where the stress directions were different. It is still assumed that the majority of the newly induced fractures propagate normal to the far-field least compressive stress, creating the so-called fracture “fairway”, though shear fractures, mainly through the reactivation of pre-existing discontinuities, bedding planes and natural faults are expected.
Complex fracture patterns have significant consequences for the design of the fracturing treatment. See, Jeffrey 1992; Medlin, W. L. and Fitch, J. L. (1988) Abnormal treating pressures in MHF treatments, Journal of Petroleum Technology, May 1988: 633-642; Daneshy, A. (2003) Off-balance growth: A new concept in hydraulic fracturing, Journal of Petroleum Technology, 55, 4, Apr. 2003: 78-85; and Zhang, X. and Jeffrey, R. G. (2006) The role of friction and secondary flaws on deflection and re-initiation of hydraulic fractures at orthogonal pre-existing fractures, Geophysical Journal International, 166: 1454-1465. The fracture width of each branch of this complex fracture network is smaller than that of a single fracture, and the conventionally used proppant might not be able to be transported to the entire length of the fracture network.
Shear displacement along pre-existing discontinuities or even induced shear fractures might occur, which in turn, due to dilatancy effects, will increase the fracture conductivity without the need for the fracture to be fully propped. Finally, the pressure response during the treatment might be very different from that of a bi-wing fracture
The current approach to estimate the production following the stimulation treatment in a complex reservoir where a fracture fairway has been created is to assume that the stimulation has created an enhanced permeability zone of about the size the microseismicity cloud, the so-called ESV estimated stimulated zone (see, Daniels 2007). The ESV is defined as the reservoir volume which has been contacted by the stimulation treatment as determined by the microseismic event location and density. However, it is not necessarily linked to the enhanced permeability zone. The actual conductive zone is probably much smaller that the ESV because the proppant was not transported very far from the wellbore. Fracture complexity creates pinch points which restrict proppant transport. Use of low viscosity fluid with poor transport properties compounds the problem of poor proppant placement. It is also not clear whether unpropped fracture can be conductive, especially if the amount of shear along the fracture plane is limited. Consequently the obtained production estimated on the ESV is not based on sound measurement of a conductive zone. Ways to properly evaluate the efficiency of the stimulation treatment are lacking and consequently may not be optimized.
There is therefore a need to develop a technique which provides some estimate of the fractured zone which was propped, or at least retained some conductivity.
Various techniques have been developed to estimate the geometry of created fractures. One commonly used technique when the fracture is bi-wing is an indirect evaluation based on the analysis of the pressure response measured during the treatment and the production. This analysis provides very general information about fracture length, fracture conductivity and fracture width when the fracture is bi-wing but fails when a fracture network is created. Moreover, it suffers a lack of uniqueness and therefore does not provide much information about the exact fracture geometry. Production analysis provides information about the effective length of the fracture and its apparent conductivity but cannot give details about the actual three-dimensional nature of fracture conductivities. Its prediction is also non unique.
More reliable are acoustic fracture imaging methods based on event location using passive acoustic emission. See, Barree, M. K. Fisher, R. A. Woodroof, “A practical guide to hydraulic fracture diagnostic technologies”, paper SPE 77442, presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Tex., USA, 28 September-2 October 2002 (hereinafter “Barree 2002”). The acoustic emissions which are recorded during hydraulic fracturing are micro-earthquakes which are generated in the vicinity of the fracture and are caused either by the stress change generated around the fracture or by the decrease of effective stress around the fracture following fracturing fluid leak-off into the formation. In some cases, the events are analyzed to provide some information about the source parameters (energy, displacement field, stress drop, source size, etc.) and when possible, about the source mechanisms. These events are recorded by an array of geophones or accelerometers placed in adjacent boreholes. They never provide direct quantitative information on the main fractures. This technology is common practice in the field and is especially suited to estimate fracture azimuth, dip and complexity. One disadvantage of this technique is that micro-earthquakes occur around the fractures and provide a cloud of events, which does not allow a precise determination of fracture geometry. As mentioned above, recent attempts concern the use of the estimated stimulation volume (ESV) for production estimation assuming that the cloud of microseismic events represents the zone which has been successfully stimulated and remain conductive once the fractures have been closed. But there is not guarantee that the stimulated volume matches the conductive volume. Current studies indicate a two order of magnitude mismatch in term of created surface area because the conductive zone has a much lower extent than the stimulated zone.
Yet another technique of hydraulic fracture evaluation is tiltmeter mapping. See, Barree 2002. This technique comprises monitoring of a deformation pattern of the rock surrounding the induced fracture network. An array of tiltmeters measures the gradient of the displacement (tilt) field versus time. The induced deformation field is primarily a function of fracture azimuth, dip, depth to fracture middle point and total fracture volume. The shape of the induced deformation field is almost completely independent of reservoir mechanical properties if the rock is homogeneous. Surface tiltmeters cannot accurately resolve fracture length and height when the distance between the surface and the fracture is large compared to the fracture dimensions. Downhole tiltmeters placed in the treatment borehole can provide better information on fracture height but they still cannot resolve for fracture length and fracture conductivity. Therefore this technique has some use in shallow reservoir but provides little information in deep reservoirs.
Various authors have worked on the refraction and transmission of waves through natural faults. See, e.g. G. G. Kocharyan, V. N. Kostyuchenko, D. V. Pavlov, “The structure of various scale natural rock discontinuities and their deformation properties. Preliminary results,” Int. J. Rock Mech. & Min. Sci. 34; 3-4, paper 159, 1997. These waves are either initiated from earthquakes or are produced downhole thanks to a seismic source (active acoustic emission). From the attenuation of waves due to fault crossing, one is able to estimate the fault shear and normal stiffness. Similarly, tomography is being used in the laboratory to determine the position of the fracture from refraction and reflection analysis, and again the attenuation can be used to estimate the fracture width. See, Groenenboom, J., vam Dam, D. B. and de Pater, C. J.: “Time-Lapse Ultrasonic Measurements of Laboratory Hydraulic-Fracture Growth: Tip Behavior and Width Profile”, SPE Journal, Vol. 6, No. 3, September 2001, 334-342 (hereinafer “Groenenboom 2001”).
According to some embodiments a method of measuring effects of a hydraulic fracturing process on a subterranean formation surrounding a borehole is provided. The method includes deploying and activating one or more sources of acoustic energy and one or more seismic receivers at known locations at least one of which is downhole so as to provide a plurality of ray-paths between source and receiver pairs traversing portions of the subterranean formation in the vicinity of the borehole. Data measured from the one or more sources by the one or more receivers is processed so as to generate three-dimensional data indicating changes in the subterranean formation resulting from the hydraulic fracturing process. According to some embodiments, the sources of acoustic energy are perforation guns or downhole seismic sources. According to some embodiments the sources and receivers are activated prior to the fracturing process and activated again following the fracturing process. The three-dimensional data can be for example, a three dimensional mapped volume image indicating fracture network conductivity. The mapped volume can be constrained by calibrating the mapped volume to surface seismic data and/or shallow borehole seismic data.
According to some embodiments, the processing includes using changes in sonic velocity, changes in P and S wave velocity, using P to S wave conversions, changes in attenuation, and/or changes in frequency content in generating the three-dimensional data. The sources and/or receivers can be deployed in a well adjacent to the treatment well. According to some embodiments at least one of receivers or sources are deployed in the treatment well. According to some embodiments, the seismic receivers are permanently or semi-permanently deployed in a borehole. According to some embodiments, the processing includes use of sonic logging data relating to the subterranean formation in generating the three-dimensional data.
According to some embodiments a system for measuring the effects of a hydraulic fracturing process on a subterranean formation surrounding a borehole is also provided.
As used herein the term “tomography” refers generally to three-dimensional and/or volume imaging.
As used herein the term “seismic” refers generally to acoustic energy capable of travelling through subterranean formation, and includes conventional low-frequency seismic energy as well as micro-seismic energy.
Further features and advantages will become more readily apparent from the following detailed description when taken in conjunction with the accompanying drawings.
The present disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of exemplary embodiments, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:
The following description provides exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the following description of the exemplary embodiments will provide those skilled in the art with an enabling description for implementing one or more exemplary embodiments. It being understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the invention as set forth in the appended claims.
Specific details are given in the following description to provide a thorough understanding of the embodiments. However, it will be understood by one of ordinary skill in the art that the embodiments may be practiced without these specific details. For example, systems, processes, and other elements in the invention may be shown as components in block diagram form in order not to obscure the embodiments in unnecessary detail. In other instances, well-known processes, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments. Further, like reference numbers and designations in the various drawings indicated like elements.
Also, it is noted that individual embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be re-arranged. A process may be terminated when its operations are completed, but could have additional steps not discussed or included in a figure. Furthermore, not all operations in any particularly described process may occur in all embodiments. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function.
Furthermore, embodiments of the invention may be implemented, at least in part, either manually or automatically. Manual or automatic implementations may be executed, or at least assisted, through the use of machines, hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium. A processor(s) may perform the necessary tasks.
According to some embodiments, a method is provided that allows one to access a conductivity image once the treatment is completed based on microseismic tomography using tools and calibration methods developed for the monitoring and interpretation of microseismic events generated during the stimulation treatment. According to some embodiments, surface seismic (and/or shallow borehole data) data is used, if available, to refine the size of the propped reservoir.
According to some embodiments, a calibration process such as used in microseismicity analysis is used to perform microseismic tomography which is then used to construct a map of fracture network conductivity. According to some embodiments this mapped volume is constrained by calibrating it to surface (and/or shallow borehole) seismic data, if such data are available. Microseismic tomography is particularly suitable in gas shale reservoirs where the distance between lateral wells is small (less than 500 ft), either by using an active seismic source, the waves emitted during perforation, or when feasible, acoustic emission events. According to some embodiments, the tomography could use changes in P and S wave velocity or any other wave attributes, such as attenuation. According to some embodiments, the method is used in vertical wells in cases where the well density is suitably high. According to some embodiments, surface seismic data are used to provide spatially varying 3-D information about P-wave velocity, S-wave velocity (if PS data are available) and anisotropy parameters. This information can be used to refine the ESV. This is in contrast to current practice in which a 1-D velocity and anisotropy model is used in microseismic mapping. According to some embodiments the azimuthal variation of amplitude as a function of angle of incidence is used to estimate fracture orientation, fracture density and the nature of fluid in the fracture. See, Bakulin, A., Grechka, V. and Tsvankin I. (2000), Estimation of fracture parameters from reflection seismic data. Parts I, II, III. Geophysics, 65, 1788-1830. Ideally, we would like to acquire surface seismic data before and after a fracturing job.
According to some embodiments, cross-well tomography with various spatial placement of source and receiver is used to study the effects of fractures on P and S wave velocity and attenuation. If the source is strong enough and the surface (and/or shallow borehole) receivers sensitive enough, these surface (and/or shallow borehole) receivers can be used as well.
As mentioned above, most of shale gas completions consist of drilling a lateral in the direction of the minimum principal stress, separating the lateral in several stages, and for each stage, starting from the toe, perforating using 2-4 perforation clusters then stimulating. Due to the small size of the drainage area the distance between laterals is very small, sometimes of the order of 250 feet.
Each treatment is often monitored using the recording of microseismic events, which are micro-earthquakes related to local failure of the rock, associated with the creation of the hydraulically-induced fracture network. One well or one lateral is used as a monitoring well where a monitoring tool is placed. This tool is composed of several shuttles separated by a distance of about 100 feet, and each shuttle contains at least one three-component receiver. The number of shuttles currently ranges for a few shuttles to 16, but nothing prevents us to use more shuttles, or to change the spacing between shuttles. If required the tool can be moved between each fracturing stage. The main application of recording the microseismic events is to determine the location of the fracture network by locating the events as a function of time (
According to some embodiments, the information obtained during the process of calibration of the monitoring tool and as well as during the stimulation treatment of an adjacent well is used to carry out a tomography analysis before and after the fracturing treatment to provide some insight of the fracture conductivity once the job is completed. According to some embodiments, this tomographic information is constrained by calibrating it to surface (and/or shallow borehole) seismic information, if this information is available. This technique shows whether the fractures in a given zone are closed, either totally, or partially, if proppant is present in those fractures or shear movement along the fracture face occurred. According to some embodiments, the technique can be further improved by adding one or several downhole sources in an adjacent lateral, allowing waves to be sent during the treatment. According to some embodiments, a sonic tool, such as Schlumberger's SonicScanner is run before the fracturing treatment in the cased lateral, and another run may be performed after the treatment is done, so as to provide further determination of the velocity model and attenuation model.
The tomography can be based on several approaches. According to some embodiments, variation of P- or S-wave velocity, or variation of both waves, can be observed, as it is expected that the zone which has been fractured will suffer a decrease in velocity. Analysis of wave refraction is also a good indicator and has been done in the lab to map hydraulic fractures. See, Groenenboom 2001. According to some embodiments, other measurements are used which can be more sensitive like the attenuation of the waves. Depending on the extent of fracturing, the velocity field may not be significantly affected by the stress changes and the presence of the induced fractures (as it is currently assumed during the stimulation treatment to locate the events), allowing us to use microseismic events in the process of tomography, since we will be able to locate the event and determine the attenuation from various sensors. In cases where only one or two fractures are induced, for example, it is easier to detect the attenuation change than velocity changes. High attenuation relates to fracture width. In particular, it is well-known that S-waves cannot propagate in fluids, thus any open section will not be crossed by S-waves. In practice, the S-wave on a seismic scale will not be attenuated by an open fluid-filled fracture as it will travel through the matrix. However, P-waves will be attenuated due to the change of stiffness between the matrix and the fracture.
Prior to fracturing the first lateral well 104 a velocity model is constructed. According to some embodiments, the velocity from the seismic volume is tied to those measured in the wells (e.g., P-wave and S-wave velocity) and produce calibrated 3D velocity volumes. According to some embodiments, 3D volumes of seismic anisotropy parameters will be produced and tied to those measured in a sonic tool. Lateral 104 is perforated and stimulated in three stages 140, 142 and 144. Each time one stage is perforated, the monitoring tool 120 registers the waves emitted by the perforation process to get a new calibration point. Following the perforation of the first stage 140, a first velocity map or attenuation map can be constructed. After perforation of stage 140 is completed, stimulation of stage 140 starts and the tool array 120 records the microseismic events. The fracture area from this stimulation is shown as area 138. Also shown are fracture areas 136 and 134 that result from stimulation of stages 142 and 144 respectively. Once stage 140 is done with both perforation and stimulation, it is isolated using a packer and the same process starts with stage 142, including the calibration process using the perforation process of stage 142. In the case of
In
According to some embodiments the certain techniques can be used to improve the accuracy of the determination. For example, as mentioned above, according to some embodiments, a sonic measurement can be run after the fracturing process in the well which has just been fractured to determine the velocity and attenuation changes along the lateral.
According to some embodiments another monitoring well (or other monitoring wells) either in a horizontal or a vertical section could be added.
According to some embodiments, the monitoring tool can be moved during the process, or even be moved from one well to another one.
According to some embodiments, rather than (or in addition to) using the wave generated by the perforation process one can use one (or several) downhole seismic source which is moved along the lateral, such as described in further detail with respect to
According to some embodiments, P-wave and PS-wave data from surface seismic can also be used in this determination. These waves can be processed with azimuthal information to provide an estimate of fracture orientation, fracture density and fracture-fluid content. Assuming a suitably high S/N ratio, analysis before and after a fracturing job, will provide an independent quantitative estimate of the fluid-filled fractures.
According to some embodiments, the microseismic events are themselves used in the process, which is very efficient and practical some cases, for example where the wave velocity is little affected by the fracture area but if the attenuation is significantly affected.
Current methods of measuring the effective drainage area of a hydraulic fracture stimulation provide only a measure of fracture wing growth, and do not provide information on what portion of the fracture is actually propped and hence able to drain the reservoir.
According to some embodiments, a pre and post fracture stimulation borehole seismic technique is provided that maps the induced stress in the reservoir created by the propped fracture creation. As such it can provide a measurement of effective fracture radius.
According to some embodiments, the technique utilizes cross-well seismic technology, such as used in Schlumberger's DeepLook-CS tools and service, to acquire the time-lapse stress image. A downhole source is placed in one well and a receiver array is placed in another well. The source is activated or swept creating energy which is transmitted through the formation. The energy is recorded at the receiver array and processed using specialized and proprietary software to yield a tomographic velocity image. This same process is repeated post hydraulic fracture stimulation and the resultant tomographic velocity image is compared with the pre-stimulation or baseline velocity. The resultant difference image is an indication of propped fractures in the reservoir.
Referring to
Also shown in
Seismic source 210 preferably transmits very high bandwidth sound waves (e.g. 30 to 800 Hz) to the receiver array 220, as the source 210 is moved up the wellbore 212.
Upon completion of the hydraulic fracture stimulation treatment from well 230, a second crosswell seismic image is acquired using the methods described above.
Although the surface 302 is shown in
According to some embodiments the source and receiver can be in the same well. For example, in the context of
According to some embodiments, the raw data collected in the field through the processes described above is processed to produce a baseline velocity image.
Data 410 is acquired and in step 412 is being conditioned and quality checked. A processing plan 416 is decided based on the data input, and desired objectives are decided during the kickoff meeting 414. Two parallel routes are followed. Automatic or manual time-picking 450 is used to define arrival times and generate the travel time tomography per se 452, from which a velocity image 454 is derived. If logs can be correlated, a velocity map 458 may be generated. The parallel route starts with wavefield separation 420 and various geophysical processing steps (including amplitude correction 422, VSP-CDP mapping 424, angle transform 426, angle selection 428, brute stack 440, wavefield separation iteration 442, reflection residual alignment 430, stack and combine 432, and data enhancement 434) has an objective to create a reflection image 436 which can be combined with the velocity image 454.
According to some embodiments, a three-dimensional image of the difference in the velocity, attenuation, or other wave attribute, between the baseline and post hydraulic fracture treatment is produced. This difference image is a result of the saturated rock stiffness and of the residual stress post fracture treatment. In particular, the change is mainly due the presence of new fractures, saturated with water, which changes the rock stiffness as well as creating strong discontinuities in stiffness (i.e. matrix vs. fractures). The residual stress is an indication of the fractures that have been created and remain propped versus created and then closed in. The propped or open fractures are the key criteria for evaluating the drainage radius created by the hydraulic fracture stimulation. According to some embodiments, this technique can be used in any well configuration; vertical, slant or horizontal.
Once the analysis is completed, with the availability of either a fluid-filled fracture map, a velocity map, an attenuation map or any other wave attributes, it is staight forward to determine which part of the ESV remains conductive and therefore what is the real stimulated volume hence moving from ESV to RSV.
According to some embodiments, the three-dimensional maps can be derived as a function of time as well, especially if downhole sources in adjacent laterals are used. For example, such a map can be constructed just at shut-in and one a few hours after shut-in. Similar maps can also be generated months after the treatment to see if proppant embedment or fracture clean-up have occurred.
Whereas many alterations and modifications of the present disclosure will no doubt become apparent to a person of ordinary skill in the art after having read the foregoing description, it is to be understood that the particular embodiments shown and described by way of illustration are in no way intended to be considered limiting. Further, the disclosure has been described with reference to particular preferred embodiments, but variations within the spirit and scope of the disclosure will occur to those skilled in the art. It is noted that the foregoing examples have been provided merely for the purpose of explanation and are in no way to be construed as limiting of the present disclosure. While the present disclosure has been described with reference to exemplary embodiments, it is understood that the words, which have been used herein, are words of description and illustration, rather than words of limitation. Changes may be made, within the purview of the appended claims, as presently stated and as amended, without departing from the scope and spirit of the present disclosure in its aspects. Although the present disclosure has been described herein with reference to particular means, materials and embodiments, the present disclosure is not intended to be limited to the particulars disclosed herein; rather, the present disclosure extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.
This patent application claims the benefit of U.S. Ser. No. 61/299,847, filed Jan. 29, 2010, which is incorporated by reference herein.
| Number | Date | Country | |
|---|---|---|---|
| 61299847 | Jan 2010 | US |
