METHOD FOR FRACTURING AND ANALYZING AN EARTHEN FORMATION SURROUNDING A WELL BORE

Abstract

A method of micro-fracturing in a well bore to define the stress field and fracture system for the purpose of optimizing subsequent hydraulic fracturing well completion operations. During or subsequent to drilling of the well bore, a down hole imager takes measurements that allow the operator to select appropriate zones of the well bore for optional micro-fracture testing. The micro-fracturing testing is conducted by stopping the flow of drilling mud and expanding one, or preferably two packers incorporated into a micro-fracture module of the drill string. The pressure in the isolated zone between the packers (or below the packer if one packer is used) is pressurized until fracture occurs. The trend in the pressure in the isolated zone of the bore hole is measured during the test to assess information about the fracturing of the bore hole. After micro-fracture testing, or upon completion of the drilling, the same zone of the bore hole is again scanned by the imager and the natural beak-outs or pre- and post-micro-fracture testing images are analyzed to ascertain further information about the formation. Micro-fracture testing is repeated over different zones of the well bore as the drilling proceeds or subsequent to the drilling operation and the information from these tests is used to optimize the major fracturing in the completion phase of the drilling.

Description

TECHNICAL FIELD

The invention relates to methods for fracturing and analyzing an earthen formation surrounding a well bore and, in particular, a method of fracturing the formation that can be performed during drilling operations and that minimizes the environmental impact on the surroundings, as well as methods for analyzing the effects of such fracturing.

BACKGROUND

Conventionally, some wells drilled in earthen formations to extract oil or natural gas are subjected to fracturing upon completion of drilling operations. Such fracturing involves increasing the borehole fluid pressure so as to create fractures in the formation, either through holes in perforated pipe that are created by explosive charges or else in an uncased hole, that will facilitate the flow of fluid from the formation into the well bore, from which it can be extracted. Following such fracturing, the well, or a portion of the well, is sealed off by one or more expandable “packers” inserted into the well bore. Conventionally, dual packers have been included in drilling assemblies and used to isolate a portion of the well bore during a draw down operation, concurrent with the drilling process, in which fluid is drawn from the isolated portion of the well bore and the pressure monitored in order to determine the pressure in the formation.

Conventionally, after perforating the cased well bore or sometimes in an open hole, the portion of the well bore below the packer (if one packer is used), or the portion of the well bore between packers (if dual packers are used) is then pressurized and formation fractured by pumping large quantities of fluid that contains fracture proppants into the well bore after the conclusion of drilling operations for the purpose of increasing production. The large volume of such fluid tends to further open the factures, resulting in a reduction and then leveling off, of the pressure in the well bore. The variation in the pressure over time would be analyzed to ascertain information about the formation during the prescribed completion operation, such as whether the formation has experienced one major fracture or a number of smaller fractures that open sequentially. Moreover, the fluid generally contains small particles called “fracture proppants”, such as sand or other custom particles, for permanently preserving the fracture flow potential. As the fluid circulates through the well bore and into the formation via the fractures, the particles are deposited into the factures, reducing the tendency of the fractures to close after the pressure in the well bore is reduced and production begins.

In the past, as per Soliman et al. SPE Paper 21062, packer technology has been used in post-drilling to operations to isolate specific zones of interest and perform “micro-frac” pressure tests that gather data which enable the determination of mechanical rock properties (fracture pressure, propagation pressure and closure pressure) from multiple formations which were each clearly differentiated by conventional petrophysical techniques presumed each to have unique mechanical properties. The prior art also used oriented conventional coring techniques to orient the induced micro-fractures. The need for more pre-completion “micro-frac” information that is able to delineate this variability in mechanical properties and orient the stress field along a well bore placed a single stratigraphic reservoir formation, and improve the effectiveness and efficiency of multi-stage completions has increased.

Additional environmental concerns have also been raised suggesting that such massive fracturing completion activity can, in some cases, be too intense and extend beyond the intended reservoir section potentially contaminating fresh ground water resources. For this reason also it would be desirable to provide a method that generates more useful information about the variability of mechanical properties and potential productivity from different intervals along the well bore prior to major fracture completion activity and that allows the fracture completion to be performed in a calibrated manner that reduces the risk of environmental impact.

Rather than use oriented conventional coring techniques to orient the fractures as in the prior art, borehole images acquired during drilling and then again at some time later to evaluate break-outs and induced micro-fractures can be compared to orient the minimum and maximum stress fields and any potential variability along extended wellbores in unconventional reservoirs.

Conventionally, after perforating a cased well bore or sometimes in an open hole, the portion of the well bore below the packer (if one packer is used), or the portion of the well bore between packers (if dual packers are used) is then pressurized and formation fractured by pumping large quantities of fluid that contains fracture proppants into the well bore after the conclusion of drilling operations for the purpose of increasing production. The large volume of such fluid tends to further open the factures, resulting in a reduction and then leveling off, of the pressure in the well bore. The variation in the pressure over time would be analyzed to ascertain information about the formation during the prescribed completion operation, such as whether the formation has experienced one major fracture or a number of smaller fractures that open sequentially. Moreover, the fluid generally contains small particles called “fracture proppants”, such as sand or other custom particles, for permanently preserving the fracture flow potential. As the fluid circulates through the well bore and into the formation via the fractures, the particles are deposited into the factures, reducing the tendency of the fractures to close after the pressure in the well bore is reduced and production begins.

In the past, dual packer technology has been used repeatedly to pressure up and fracture specific intervals between the dual packers in order to focus the development of fractures and the application of fracture proppants more uniformly along the wellbore as part of the final completion design, but this was not done in an open well bore exposed during drilling with a drilling fluid, for the purpose of gathering specific rock properties (fracture pressure, propagation pressure, closure pressure and fracture conductivity) over multiple depth intervals that can be used to design a more effective and less risky final fractured completion.

More recently, fracturing activity and intensity has increased to include complex multistage hydraulic fractures over the entire reservoir section. Unfortunately, environmental concerns have been raised suggesting that such fracturing activity can, at times, be too intense, extending beyond the intended reservoir sections and, in some cases, potentially affecting the local ground water sources, causing contamination of the fresh water resource. Therefore, it would be desirable to provide a method that generated information prior to major fracturing that allowed the fracturing to be performed more efficiently and with less environmental impact. Similarly, without more information about the mechanical rock properties, fracture completion operations run the risk of penetrating into water-producing strata that result in undesired water production and less hydrocarbon production.

When evaluating a horizontal well in many of the non-conventional shale (and carbonate) formations prior to fracturing, traditional well log measurements have been used for hydrocarbon evaluation (i.e., triple combo). Moreover, bore hole images have been used to identify naturally fractured intervals and intervals damaged during the drilling process, but, conventionally, fracture images from bore hole imagers have not been used to identify candidate intervals for testing with a micro-fracturing operation to gather further geological information that would be useful for optimizing the final completion fracturing operation, reducing the cost of such operations and improving the hydrocarbon productivity with less risk of contaminating or producing water from adjacent formations.

The traditional evaluation techniques using gamma ray, resistivity, bulk density and neutron porosity are not sensitive to small lateral variations in the chemo-stratigraphic makeup, natural fractures and rock stress orientations of these non-conventional reservoir rocks. These variations in elemental makeup can have an impact on the ductility and plasticity of the formation and hydrocarbon flow potential, fracture patterns, stress orientations and, if not understood, can affect the efficiency and effectiveness of the ultimate hydraulic fracturing completion job. Proper evaluation and understanding of the variability of stress profiles, ductility and plasticity along a horizontal well can aid in optimizing the design of the hydraulic fracturing job in non-conventional reservoirs. Unfortunately, conventional petrophysical measurements do not provide enough information to fully define the stress field, fracture initiation, fracture propagation and fracture conductivity relationships of the formation.

Therefore, it would be desirable to develop a method for analyzing data concerning the formation surrounding the well bore that provided additional information that could be used to optimize the fracturing operation.

SUMMARY

The current invention concerns a method of micro-fracture testing in a well bore to define the stress field and fracture system for the purpose of optimizing subsequent hydraulic fracturing well completion operations. Micro-fracture testing refers to isolating and pressurizing with fluid a relatively small zone of the bore hole so as to induce fracture of the formation surrounding the isolated zone, and then analyzing the pressure in the well bore leading up to, during, and following the fracture in order to acquire information concerning the formation. According to the invention, micro-fracture testing is preferably performed periodically during the drilling operation, and the information acquired during the testing is subsequently used to optimize the post-completion fracturing of the well bore. Micro-fracture testing is to be distinguished from fracturing of the bore hole after completion of the drilling, which is typically much more intense, and potentially damaging to the environment, that micro-fracturing is not, and is done in order to facilitate the extraction of oil or gas from the well, as contrasted with the goal of micro-fracture testing, which is the acquisition of information concerning the formation which can be used to optimize the post-completion fracturing or even the continued drilling of the bore hole.

According to the invention the images of the borehole both prior to micro-fracturing and then again after micro-fracturing would be analyzed to determine the stress profile around the borehole and identify and map the minimum and maximum stresses to determine the stress field relationship and orientation, and from the pressure data directly measure the fracture initiation and propagation pressures along one or, selectively, more sections in a horizontal well. Image interpretation techniques are utilized to determine these stresses. The micro-fracture sensors includes a borehole imager and pressure sensor to map, selectively isolate, initiate and propagate fractures, and then remap to create a delta-image log stress field evaluation and also to assess fracture conductivity. Data recording and transmission systems will be used to allow the data to be recorded downhole and alternatively received and evaluated at the surface in conjunction with surface pressure, flow rate and flow volume data.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram showing a drilling operation that makes use of the current invention.

FIG. 2 is a diagram of the micro-fracture module shown in FIG. 1.

FIG. 3 is a diagram similar to FIG. 2 showing the packers in their expanded configuration.

FIG. 4 is an illustrative graph of bore hole pressure, P, as detected by a pressure sensor, versus time, T.

FIG. 5 is an illustrative image showing resistivity measurements along a length of the bore hole, taken by the imager of the micro-fracture module shown in FIGS. 2 and 3.

FIG. 6 is a flow chart for the software that performs the comparison between the images before and after the micro-fracture testing.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

FIG. 1 depicts an underground drilling operation that makes use of the current invention. The drilling system includes a bottom hole assembly that forms the down-hole end of a drill string 12, and includes a drill bit 13. The drill bit 13 is rotated by the drill collar of the portion of the drill string. The drill string 12 is formed by connecting relatively long sections of pipe, commonly referred to as “drill pipe.” The length of the drill string can be increased as the drill bit 13 progresses deeper into the earth formation 16 by connecting additional sections of drill pipe to the drill string.

Torque to rotate the drill string 12 is applied by a motor 21 of a drilling rig 15 located on the surface. Drilling torque is transmitted from the motor 21 to the drill bit 13 through a turntable 22, a kelly (not shown), and the drill string. The rotating drill bit 13 advances into the earth formation 16, thereby forming a bore hole 17. Although a bore hole slightly off of vertical is shown in FIG. 1, it should be understood that the invention will often be implemented in bore holes that are horizontal or close to horizontal. In addition, a mud motor (not shown) may be incorporated into the bottom hole assembly so that the drill bit 13 is rotated by a mud motor (not shown), either instead of a turntable or in combination with the turntable.

Drilling mud is pumped from the surface, through an central passage 50 (shown in FIG. 2) in the drill string 12, and out of the drill bit 13. The drilling mud is circulated by a pump 18 located on the surface. The drilling mud, upon exiting the drill bit 13, returns to the surface by way of an annular passage 19 formed between the drill string 12 and the surface of the bore hole 17. Operation of drilling rig 15 and the drill string 12 can be controlled in response to operator inputs by a surface control system 20, which includes a processor.

As shown in FIG. 2, preferably, the method is practiced by incorporating a micro-fracture module 30 into the bottom hole assembly of the drill string 12. A communication system is used that allows two-way communications to the downhole logging/testing device both while circulating drilling fluid during normal drilling operations, and preferably, additionally allows communication while the micro-fracture testing process is occurring and circulation to the surface is not maintained. While drilling mud is being circulated through the drill string 12, communication with the surface can be accomplished by mud pulse telemetry, using techniques well known in the art. In particular, the pulser of the mud-pulse telemetry system can generate pressure pulses in the drilling mud being pumped through the drill string, using techniques known to those skilled in the art of underground drilling. A controller located in the down hole assembly can encode the information from a signal processor as a sequence of pressure pulses, and can command the pulser to generate the sequence of pulses in the drilling mud, using known techniques. A strain-gage pressure transducer (not shown) located at the surface can sense the pressure pulses in the column of drilling mud, and can generate an electrical output representative of the pulses. The electrical output can be transmitted to surface control system 20, which can decode and analyze the data originally encoded in the mud pulses. The drilling operator can use this information in setting the drilling parameters. A suitable pulser is described in U.S. Pat. No. 6,714,138 (Turner et al.), and U.S. Pat. No. 7,327,634 (Perry et al.). A technique for generating, encoding, and de-coding pressure pulses that can be used in connection with the mud-pulse telemetry system is described in U.S. application Ser. No. 11/085,306, filed Mar. 21, 2005 and titled “System and Method for Transmitting Information Through a Fluid Medium.” Each of these patents and applications is incorporated by reference herein in its entirety.

Pressure pulses also can be generated in the column of drilling mud within the drill string 12 by a pulser (not shown) located on the surface. Commands for the micro-fracture module 30 can be encoded in these pulses, based on inputs from the drilling operator. According to one aspect of the current invention, a pressure pulsation sensor in the bottom hole assembly senses the pressure pulses transmitted from the surface, and can send an output to a processor 44, discussed below, that is representative of the sensed pressure pulses. The processor 44 can be programmed to decode the information encoded in the pressure pulses. This information can be used to operate the micro-fracture module 30 so that the operation of the module can be controlled by the drilling operator. A pressure pulsation sensor suitable for use in the mud pulse telemetry system is described in U.S. Pat. No. 6,105,690 (Biglin, Jr. et al.), which is incorporated by reference herein in its entirety.

When there is no flow of drilling mud through the drill string, thereby precluding the use of mud pulse telemetry, one of the alternate methods of communication well know to those skilled in the art can be utilized. Preferably, an electromagnetic (EM) transmission system is used to provide communication with the surface when drilling mud is not being circulated. However, other transmission methods, such as wired pipe, can also be used. In any event, a transmitter/receiver device 32 is incorporated into the micro-fracture module and another transmitter/receiver device 32 is located at the surface so as to allow the micro-fracture module to transmit to the surface and receive from the surface information, including commands for the operation of the micro-fracture module. The downhole transmitter/receiver is in communication with the processor 44 located in the micro-fracture module that controls the transmission of data, as well the execution of commands directed to various components of the module.

A conventional high resolution well bore imager 42 is incorporated into the micro-fracture module. The imager azimuthally scans the borehole and acquires sectored high density measurements, relatively close to the wellbore wall, on a fine axial (high resolution measured depth) scale. Preferably, the imager 52 incorporates resistivity sensors 46 that determine the local resistivity of the formation along with a basic at-bit-resistivity measurement. Under the control of the processor 44, the imager 52 conducts a sectored azimuthal scan as fine as about ½ inch. Alternatively, or in addition to the resistivity sensors 46, the imager 42 may utilizes natural gamma ray sensors (to detect radioactivity in the formation), acoustic sensors (to detect the reflectances or impedance of the formation), bulk density sensors, and/or photoelectric electric sensors (to determine the photoelectric effect of the formation).

The micro-fracture module 30 is also equipped with a highly accurate pressure while drilling (PWD) sensor 48, such as a quartz pressure sensor, conventionally used to monitor pressure in the well bore during production to ensure that the hydrostatic pressure in the well bore is slightly above the pressure in the formation. The pressure sensor 48, along with precision clocks, is in communication with the processor 44, which processes the sensor measurements. A memory device 50 incorporated into the micro-fracture module 30, and in communication with the processor 44, records the time/pressure relationship measurements as they are acquired.

The micro-fracture module 30 also includes one or more packers to isolate a section A of the bore hole 17 for pressurization by inflating or otherwise expanding to locally obstruct the annular passage 19 formed between the drill string 12 and the wall of the bore hole 17. Once expanded, the packers can be deflated or otherwise retracted so that the annular passage 19 becomes unobstructed by the packers. The construction and operation of packers is well know to those skilled in the art and such packers, which can be obtained from TAM International, 4620 Southerland Road, Houston, Tex., can be readily adapted by those skilled in the art for micro-fracture testing according to the current invention. In one embodiment a single packer 40 is used to isolate the lower section of the borehole from the upper borehole section above the packer to enable the micro-fracture module 30 to initiate and propagate fractures below the packer. In a preferred embodiment, dual packers 40, 41 are used, one above and one below the zone A of the borehole 17 to be subjected to micro-fracturing, as shown in FIG. 2. Preferably, the two packers are separated by a fixed distance selected for optimum formation isolation, for example, about ten feet (three meters). A non-operational failsafe mode ensures that the packers are in the inflated position except when activated. In some situations requiring very high bore hole pressure to initiate fracture, a number of closely spaced packers can be used in series to minimize the pressure drop against which each packer must seal.

Preferably, the micro-fracture module 30 includes an intensifier pump 52 that pressurizes the bore hole annular passage 19 by pumping a fluid into the passage via an outlet port 54 in the module. Preferably, the intensifier pump 52 operates on drilling mud and directs the flow of drilling mud from the central passage 50 to the outlet port 54. In such an embodiment using an intensifier pump, the volume pumped and flow rate from the intensifier pump would also need to be measured with pressure versus time. However, other fluids could also be used to pressurized the bore hole 17. In an alternate embodiment, the surface mud pumps 18 could be used to pressurize the bore hole 17. In yet another embodiment, specialized pumps with accurate volume displacement characteristics, located at the surface, could be used to pump fluid down the drill string and into the micro-fracture module 30.

The micro-fracture module 30 also includes plumbing, including one or more valves that, under the control of the processor 44, direct fluid to inflate and deflate the packers 40, 41 upon receipt of a signal to do so from the operator via the communication system discussed above or alternatively by following a prescribed timing sequence so as to minimize the requirement for surface operator interaction. The packers 40, 41 can be pressurized using one of the pumping devices discussed above—i.e., the down hole intensifier pump 52, the mud pumps 18, or specialized surface pumps—using drilling mud or other fluid.

Preferably, a “short-hop” communications or hydro-mechanical procedure will be utilized for activating at least the single packer system independently of an MWD tool so that the packer(s) can be located remotely above an MWD tool. A remote dual packer system would require a remote pressure sensor, memory and power, etc. which the single packer device would not.

In the embodiment that uses a downhole intensifying pump the tool could also incorporate a circulation port to allow circulation to the surface to occur when the packers are engaged during which time mud-pulse communication would be enabled.

The surface system 20 also includes well bore imaging software that creates a map of the bore hole formation based on the resistivity or other imaging data. Suitable imaging software is available under the name PowerLog™, available from Fugro-Jason, 6100 Hillcroft, Houston, Tex.

The method of micro-fracture testing and formation analysis according to the current invention will now be discussed. While the drilling is underway, the resistivity sensors 46 in the imager 42 will obtain local resistivity measurements of the formation 16 surrounding the bore hole 17. For example, as the drill string 12 moves further into the formation 16, the resistivity sensors 46 may obtain measurements up to 256 sectors spaced around the circumference of the bore hole—that is, about every 1.4° of rotation of the drill string—at intervals of approximately every ½ inch (13 mm) of travel in the bore hole 17. This data is transmitted to the processor 44 and then to the surface in real-time, for example via mud pulse telemetry, and is also stored in the downhole memory 50 of the micro-fracture module 30 for post-run evaluation.

The surface imaging software uses a color palette to visually represent the variance in resistivity measurements azimuthally 360° around the bole hole along the length of a portion of the bore hole 17. A black and white image showing a typical image created by imaging software based on the data supplied by the imager 42 over zone A of the bore hole 17 is shown in FIG. 5. Since the resistivity data is taken a multiple locations around the borehole, the lower border of the image shows the data at 0° and the upper border shows the data at 360°. The image along a line half way between the upper and lower borders represents the data at 180°.

When, based on information from the imager 42, the operator has identified a zone A of the bore hole that is a candidate for micro-fracture testing, drilling is ceased, the drill string is raised or lowered, as necessary to position the micro-fracture module 30 in zone A. The single packer (above zone A) in the single packer embodiment would be inflated or alternatively the lower packer 40 is inflated in a dual packer configuration. Circulation of drilling mud will continue through the port 54 in the module to insure that the hydrostatic head is uniform. Pressure measurements from the pressure sensor 48 will be conveyed to the surface, for example via mud pulse telemetry, to indicate when a uniform hydrostatic head is established. At that time, the flow of drilling mud will be stopped, and the operator will send a signal to the micro-fracture module 30 to inflate the upper packer 41—that is, the packer at the most uphole end of zone A—for example using the EM communication system and transmitter/receiver device 32. If only a single packer is used, the micro-fracture testing can begin after the deployment of the upper packer 41. If a dual packer arrangement is used, the upper packer 40—that is, the packer at the uphole most end of zone A—will also be inflated prior to commencement of the micro-fracture testing. The module 30 will be able to communicate to the surface the status each of the packers 40, 41 to insure that they are engaged with the bore hole 17. FIG. 3 shows the micro-fracture module 30 with the packers 40, 41 expanded so as to isolate zone A of the bore hole 17.

After deployment of the packers 40, 41, pressure will be applied to the isolated formation in zone A between the upper and lower packers 40, 41 (or below a single packer 40 if a single packer arrangement is used), for example, using the intensifier pump 52 to pump drilling fluid into zone A via outlet port 54 in the micro-fracture module 30. Records of time, flow rate, volume pumped and pressure from the pressure sensor 48 will be recorded in the module's memory 50 and transmitted to the surface via the communication system.

Graphs of pressure versus time and pressure versus pumped volume will be generated by the surface control system 20 and are used by the drill rig operator to control the conduct of the test—for example, the operator will run the pump pressurizing the bore hole until a drop off or leveling out of the pressure becomes evident, indicating that significant fracturing has occurred. After the pump is shut down, the operator will continue to monitor the graph of pressure versus time in the bore hole. Examination of this data, together with surface pressure and flow data, will indicate the pressure at which fracture initiation occurs, when fractures are propagated, when primary and potentially later closure pressures are attained—that is, the bore hole pressure below which the fractures will begin to close, pressures at different flow rates (fracture conductivity) and when the test is completed. A typical pressure curve obtained during a prior art leak off test, which is generally performed only once per hole section in a non-producing formation, is shown in FIG. 4. A similar graph of pressure versus time would be obtained during micro-fracture testing according to the current invention, which, unlike leak off tests, are performed a number of times along the well bore within the producing reservoir. Study of such a graph indicates that when the pressure rose to X, a fracture occurred in the formation 16 proximate zone A of the bore hole, causing a slight decrease in the pressure. This slight drop in pressure was followed by a period of relatively constant pressure, despite the fact that the pump continued to pump fluid into the isolated zone A of the bore hole, indicative of the fact that the crack propagated and fluid continued to seep into the formation through the fracture that was extending, or fluid flow into open fractures at a steady flow rate. At point Y, the pump is stopped and the pressure decays as fluid continues to seep into the formation. The reduction in the rate of pressure decay is indicative of the closure of the fracture as the pressure reduces—in other words, as the fracture becomes smaller, the rate of fluid seepage into the formation, and therefore the rate of pressure decay, decreases.

As shown in FIG. 4, optionally, after the pressure has decayed, the pressurization of zone A can be repeated to gain additional information concerning the pressures at which the fracture(s) in the formation proximate zone A of the bore hole will open and close.

Alternatively, the processor 44 could control the micro-fracturing in an automated fashion, causing the intensifier pump 52 to operate until the pressure sensor 48 indicated that the pressure in the bore hole 17 has reached a predetermined level, for example. Such automation eliminates the need for real time data transmission to the surface during the micro-fracturing test so that the mud pulse telemetry system could be used exclusively.

Analysis of this downhole pressure data, or alternatively the surface pressure, during the micro-fracture test, as well as data on the flow rate of the fluid and the cumulative volume of fluid pumped into the bore hole, will provide useful information that aids in the identification of the optimal zones in which to focus the subsequent major fracturing operations and the characteristics of the fracturing methodology that are best employed for each individual zone that is tested during micro-frac operations. After the micro-fracture test is completed, a signal will be sent to the micro-fracture module 30 to retract the packers 40, 41, the flow of drilling mud to the bit 13 by the mud pumps 18 will be restored, and the imager 42 will be directed to perform a second high resolution image scan of zone A of the bore hole 17 that was the subject of the micro-fracture test by reciprocating the entire drilling assembly.

Analysis and comparison of the initial well bore image data, such as that shown in FIG. 5, and post micro-fracture image data of the same zone of the well bore will comprise a traditional image interpretation analysis to determine the dip of the formation (i.e., the angle of the formation relative to horizontal), the strike of the formation (i.e., the horizontal orientation of a direction perpendicular to the plane of the formation), and the primary fracture orientations, and identify faults (along with the input of the micro-fracture imaging module's directional sensor data). According to the invention, software incorporated into the surface control system 20 performs a time lapse comparative image analysis to map the changes over time and over pressure of secondary fractures and borehole stress relief features—“break-outs”.

As shown in FIG. 6, in step 70, the image comparison software receives the data from the imager 42 obtained during the first imaging scan of zone A of the bore hole, taken prior to the micro-fracture test. In step 72, the software receives the same type of data from the second imaging scan of zone A, taken after the micro-fracture testing. In steps 74 and 76, respectively, the software performs a depth matching routine and an azimuthal and axial image intensity matching routine. In step 78, the software performs an image subtractive routine and, in step 80, outputs a remainder image. The primary remainder image will indicate the effects on the borehole of the micro-fracture test, which can be used to determine the aperture of the fracture and the orientation of the maximum and minimum stress axis. This along with the fracture initiation and closure pressures acquired during these tests will enable specific zonal optimization of the subsequent production fracturing operation.

After completion of the micro-fracture testing of zone A, the packers 40, 41 are retracted, the flow of drilling mud restored and the drilling recommenced. Preferably, micro-fracture testing of discrete zones of the bore hole 17 discussed above will be periodically repeated as the drill bit 13 penetrates further into the formation 16 so as to ascertain information concerning the formation adjacent other zones of the bore hole. In particular, micro-fracture testing can be repeated when the drilling indicates that the nature of the formation has changed. The information gained from these tests will not only improve the major fracturing at completion but, in come cases, may provide the operator with geological information concerning the formation that will aid in the drilling process. The micro-fracturing testing can also be performed on multiple zones while the drill string is being retrieved from the well bore upon the conclusion of drilling operations using the same drilling bottom hole assembly, or alternatively the micro-fracturing operation can be performed using an appropriate hole cleaning assembly coupled to the drill string in place of the drill bit, and running the drill string into a bore hole after drilling is concluded on a separate run into the bore hole and prior to any fracture completion operations.

Claims

1. A method of obtaining and analyzing data concerning an earthen formation, through which a drill bit coupled to a drill string drills a bore hole, in order to acquire information useful in fracturing said formation during or upon completion of said drilling, comprising the steps of:

a) inserting said drill string into said bore hole, an annular passage extending through said bore hole being formed between said drill string and said bore hole wall when said drill string is inserted into said bore hole;

b) incorporating one or more packers into said drill string, said one or more packers capable of expanding so as to seal at least a portion of said annular passage extending through said bore hole;

c) rotating said drill bit coupled to said drill string so as to drill a first portion of said bore hole in said earthen formation, said drill string extending further into said formation as said drill bit drills said bore hole;

d) selecting a first zone of said bore hole for micro-fracture testing;

e) expanding said one or more packers incorporated into said drill string so as to isolate said annular passage extending through said first zone of said bore hole;

f) pumping a fluid through said drill string and into said annular passage in said first zone of said bore hole so as to increase the pressurize of said fluid in said first zone until said formation proximate said first zone of said bore hole fractures;

g) measuring the pressure in said first zone of said bore hole over time as said fluid is being pumped into said first zone of said bore hole;

h) analyzing said pressure versus time measurement to acquire a first type of information concerning said formation proximate said first zone.

i) repeating steps (d) through (h) in one or more additional zones of said bore hole so as to acquire additional information of said first type concerning said formation proximate said additional zones of said bore hole;

j) using said first type of information acquired in step (i) to conduct fracturing of said bore hole for completion and production purposes.

2. The method according to claim 1, wherein said first type of information concerning said formation acquired in step (h) comprises the pressure in said bore hole when said fracture of said formation initiates in step (f).

3. The method according to claim 1, further comprising the step of stopping pumping said fluid into said first zone of said bore hole and continuing to measure the pressure in said first zone of said bore hole for an additional period of time after stopping said pumping.

4. The method according to claim 3, wherein said first type of information concerning said formation acquired in step (h) comprises the pressure in said bore hole when said fracture in said formation begins closing.

5. The method according to claim 1, further comprising the steps of:

k) incorporating an imager into said drill string, said imager capable of sensing data of a first type concerning said formation proximate said bore hole;

l) scanning at least a portion said bore hole drilled by said drill bit using said imager so as to obtain said first type of data concerning said formation proximate said scanned portion of said bore hole.

6. The method according to claim 5, wherein the step of selecting said first zone of said bore hole for micro-fracture testing in step (c) is based at least in part on said data obtained from said scanning in step (l).

7. The method according to claim 5, wherein said first type of data comprises the resistivity of said formation.

8. The method according to claim 5, wherein said first type of data comprises the density of said formation.

9. The method according to claim 1, further comprising the steps of:

k) incorporating an imager into said drill string, said imager capable of sensing data of a first type concerning said formation proximate said bore hole;

l) scanning said first zone of said bore hole using said imager prior to performing step (f) so as to obtain said first type of data concerning said formation proximate said first zone prior to said fracture of said formation proximate first zone in step (f);

m) repeating said scanning of said first zone of said bore hole using said imager subsequent to performing step (f) so as to obtain said first type of data concerning said formation proximate said first zone after said fracture of said formation proximate said first zone in step (f).

10. The method according to claim 9, further comprising the step of:

n) comparing said first type of data concerning said formation proximate said first zone before said fracture with said first type of data concerning said formation proximate said first zone after said fracture to acquire a second type of information concerning said formation proximate said first zone.

11. The method according to claim 10, further comprising the step of:

o) using said second type of information acquired in step (n) to conduct fracturing of said bore hole upon completion of said drilling.

12. The method according to claim 10, wherein said second type of information concerning said formation acquired in step (n) concerns the strike of said formation.

13. The method according to claim 10, wherein said second type of information concerning said formation acquired in step (n) concerns the dip of said formation.

14. The method according to claim 10, wherein said second type of information concerning said formation acquired in step (n) concerns the primary fracture orientation of said formation.

15. The method according to claim 10, wherein said second type of information concerning said formation acquired in step (n) concerns the orientation of the maximum and minimum stress axis of said formation.

16. The method according to claim 10, wherein said second type of information concerning said formation acquired in step (n) concerns the aperture of said fracture in said formation.

17. The method according to claim 1, further comprising the step of ceasing said rotation of said drill bit prior to expanding said one or more packers.

18. The method according to claim 1, wherein step (b) comprises incorporating at least first and second packers into said drill string spaced a predetermined distance apart, said first and second packers capable of expanding so as to seal a portion of said annular passage extending between said first and second packers; and wherein step (e) comprises expanding said first and second packers so as to isolate said annular passage extending between said first and second packers and wherein said first zone of said bore hole is disposed between said first and second packers.