Patent Application
20160290125
Oil-based mud (OBM) is a drilling fluid commonly used in hydrocarbon well drilling. OBM generally includes an oil base and water, along with other additives such as emulsifiers, wetting agents, and gellants, for example. While OBM is relatively expensive to use in drilling operations, the cost may be outweighed by its advantages when used in certain geological formations, particularly shale. Such advantages may include a higher drilling rate and lower torque/drag on the drill pipe, or a more stable borehole through shale intervals, for example.
Shale is normally considered to be a fracture barrier to OBM during hydraulic stimulation. However, in some instances mud chemistry may weaken the shale, and thus contribute to the shale failure. A bottom hole pressure (BHP) surge effect while running the drill in the borehole or circulating pressures while drilling or reaming may exacerbate or contribute to a drill-induced fracture. Such a fracture may be extended with further surge pressures until a lost-circulation zone is created, in which large volumes of OBM escapes from the borehole into the formation. This may result in several days of lost drilling time, including time trying to identify the interval or location where the fracture, and thus the lost OBM circulation, occurred.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
A tool may be for use in a borehole during drilling with a drilling fluid circulating in the borehole such as OBM. The downhole tool may include a housing, a plurality of spaced apart radio frequency (RF) transmitters carried by the housing, a plurality of spaced apart RF receivers carried by the housing, and a controller to communicate with the plurality of transmitters and the plurality of receivers. The controller may, at a given depth within the borehole, determine a plurality of attenuation resistivity measurements and phase-shift resistivity measurements both corresponding to different radial distances from the borehole. The controller may also determine when a fracture has occurred in the geological formation at the given depth allowing the drilling fluid to intrude into the geological formation based upon the plurality of attenuation resistivity measurements and the plurality of phase-shift resistivity measurements.
A related method for using a tool, such as the one described briefly above, is also provided. The method may include, at a given depth within the borehole, determining a plurality of attenuation resistivity measurements and phase-shift resistivity measurements corresponding to different radial distances from the borehole. The method may further include determining when a fracture has occurred in the geological formation at the given depth allowing the drilling fluid to intrude into the geological formation based upon the plurality of attenuation resistivity measurements and the plurality of phase-shift resistivity measurements.
A related non-transitory computer-readable medium is also provided having computer executable instructions for causing a computer to at least, at a given depth within the borehole, determine a plurality of attenuation resistivity measurements and phase-shift resistivity measurements corresponding to different radial distances from the borehole using a tool, such as the one described briefly above. A determination may be made as to when a fracture has occurred in the geological formation at the given depth allowing the drilling fluid to intrude into the geological formation based upon the plurality of attenuation resistivity measurements and the plurality of phase-shift resistivity measurements.
The present description is made with reference to the accompanying drawings, in which example embodiments are shown. However, many different embodiments may be used, and thus the description should not be construed as limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete. Like numbers refer to like elements throughout.
Generally speaking, an approach is set forth herein to identify borehole fractures that result in lost drilling fluid (e.g., oil-based mud, OBM, or mud) circulation during drilling based upon LWD measurements. The approach may be particularly advantageous in low resistivity regions of a geological formation, in that a contrast between the induced fracture with OBM therein and the formation may be such that there is distinct signature difference from other potential problems that may occur during the drilling process.
Referring now to
During rotation, the pipe 40 is suspended by equipment on a drill rig 50 including a swivel 52, which enables the pipe 40 to rotate while maintaining a fluid tight seal between the interior and exterior of the pipe 40. Mud pumps 54 draw drilling fluid, such as OBM or simply “mud”, 56 from a tank or pit 58 and pump the OBM through the interior of the pipe 40, down through the LWD/MWD system 30, as indicated by arrow 64. The mud 56 passes through orifices (not shown) in the bit 42 to lubricate and cool the bit 42, and to lift drill cuttings in through an annulus 60 between the pipe 40 and the wellbore 44.
The collar sections 32, 34, 36, 38 may include sensors (not shown) therein which make measurements of various properties of the geological formation 46 through which the wellbore 44 is drilled. These measurements may be recorded in a recording device disposed in one or more of the collar sections 32, 34, 36, 38, or communicated to a surface recording system 62 outside of the well illustratively including a controller 68. For example, MWD systems may also provide the telemetry (communication system) for any MWD/LWD tool sensors in the drill string. By way of example, the controller 62 may be implemented using a combination of hardware (e.g., microprocessor, etc.), and a non-transitory computer-readable medium having computer executable instructions for performing the various operations noted herein.
Example LWD systems include one or more sensors which measure formation properties such as density, resistivity, gamma rays, porosity, etc., as will be described further below. Other sensors may also be included to measure selected drilling parameters, such as inclination and azimuth trajectory of the wellbore 44, for example. Additional drilling sensors may include a sensor for measuring axial force (weight) applied to the LWD/MWD system 30, and shock and vibration sensors.
The LWD/MWD system 30 may further include a mud pressure modulator (not shown separately) in one of the collar sections (e.g., the collar section 34). The modulator applies a telemetry signal to the flow of mud 56 inside the system 30 and pipe 40 where the telemetry signal is detected by a pressure sensor 66 disposed in the mud flow system. The pressure sensor 66 is coupled to detection equipment in a surface recording system 62, which enables recovery and recording of information transmitted in the telemetry scheme sent by the MWD portion of the LWD/MWD system 30. The telemetry scheme may include a subset of measurements made by the various sensors in the LWD/MWD system 30. The telemetry of the logging tools may also be determined using a wireline cable, or electrical MWD telemetry (e.g., using electrical signals transmitted through the formation). Measurements made by the various sensors in the LWD/MWD system 30 may also be transferred to the surface recording system 62 when the LWD/MWD system 30 is withdrawn from the wellbore.
Turning now to
In the illustrated configuration, the receivers R1, R2 are directly adjacent, but spaced apart from, one another near the center of the housing 101. More particularly, an example spacing of six inches is provided between the receivers R1 and R2. The transmitters T1-T5 are arranged such that the odd numbered transmitters (i.e., T1, T3, and T5) are on one side of the receivers R1, R2 (namely the right side in
Furthermore, for the example implementations set forth herein, the resistivity measurement tool 100 operates at two frequencies, namely 400 kHz and 2 MHz. As will be understood by those skilled in the art, different combinations of transmitters and RF frequencies may be used to investigate resistivity characteristics at different radial distances from the borehole. In an example implementation, twenty measurement channels (attenuation and phase shift for five spacing and two frequencies) are provided, though other channel configurations may be used in different embodiments. Also, the tool 100 illustrated in
By way of example, the techniques described herein for OBM-induced fracture detection may be implemented in a resistivity tool such as a compensated dual resistivity (CDR) or array resistivity compensated (ARC) tool from the present Applicant Schlumberger Limited, although these techniques may generally be implemented in other resistivity measurement tools as well that provide coaxial (ZZ coupling) measurements for logging while drilling due to fractures. The techniques described herein may advantageously provide for real-time monitoring while drilling to identify the interval or depth at which lost OBM circulation has occurred. Generally speaking, an OBM fracture pattern may be defined in three dimensions, including a height measured along the borehole axis, a radial length or distance the fracture pattern extends from the borehole 44 into the geological formation 46, and an angular width or aperture of the fracture pattern.
Beginning at Block 71 of the flow diagram 70 of
In the example of
Making a determination that a potential fracture has occurred may be useful in that, if taken at a single instant or if taken when the fracture is just beginning, the signature of a fluid-induced fracture may be confused with other effects, e.g., resistive invasion, conductive shoulder effect, or anisotropy. However, such effects may be excluded or disproven based upon other lithology sensitive measurements to identify the presence of shale to disprove the possibility of invasion, well trajectory and layering to disprove the presence of a nearby layer boundary in the case of high angle/horizontal wells, and well inclination to disprove the presence of an anisotropic response in vertical wells or subsequent (e.g., time-lapse) measurements, for example.
The controller 102 may communicate resistivity measurement data to the surface recording system 62 so that the controller 68 may use the measurements to determine if the conditions in equation (1), and thus a potential OBM-induced fracture, are present. However, it should be noted that in some embodiments, the controller 102 may evaluate the resistivity measurement data on-board the resistivity measurement tool 100, and not transmit the measured resistivity data (or just transmit certain portions of the data) uphole, which may useful in applications where telemetry bandwidth is at a premium, for example.
Where a potential fracture has been determined at the given depth, further measurements may be taken at a later time (or over a period of time), at Block 75, to determine if or when an actual fracture has occurred, and the extent of the fracture. It may be useful to determine when an OBM-induced fracture has occurred in the geological formation 46 at a given depth, as such a fracture will allow OBM 56 to intrude into the geological formation 46. This may be costly not just in terms of lost drilling time, but also lost OBM. The controller 68 (or controller 102, in some embodiments) may make a determination that, based upon measured attenuation and phase-shift resistivity measurements, a fracture has indeed occurred (as opposed to one of the other above-noted conditions such as anisotropy, etc.), along with an estimated radial length of the fracture, as will be discussed further below. The controller 68 (or 102) may determine the attenuation resistivity measurements and the phase-shift resistivity measurements based upon a ratio of signals received by the plurality of receivers, as will be appreciated by those skilled in the art. Generally speaking, fracture determination may be used upon an order of the phase-shift and attenuation resistivity measurements, the order of the phase-shift resistivity measurements relative to the attenuation resistivity measurements, and an order of the average of phase-shift resistivity measurements relative to an order of the average attenuation resistivity values.
The foregoing will be further understood with reference to
The graph 130 of
The graph 140 of
The graphs 150 and 160 of
As noted above, for shallow or relatively small fractures, the measured effect may be very similar to resistive invasion or conductive shoulder effects. However, OBM fracture-induced invasion is most likely to occur in porous and permeable formations, which may be determined by considering other measurements such as natural gamma-ray, neutron-density porosities, background resistivity values, or spectroscopy measurements, for example. Conductive shoulder or adjacent bed effects may be determined (and conversely, excluded) by considering other factors such as well inclination and bedding dip using programs such as 3DP in conjunction with forward modeling to determine if these effects are present. Thus, such other information may be used to determine if a conductive shoulder or resistive invasion effects are possible, in which case time-lapse measurements using the resistivity measurement tool 100 need not be used. That is, when used in conjunction with such other information, an initial series of resistivity measurements may be sufficient to determine the existence of a fracture using the relationships discussed with respect to
It should also be noted that 400 KHz (or other frequency) measurements may also be used in conjunction with the 2 MHz measurements (or alone in some configurations). Measurements based upon a 400KHz frequency are radially deeper reading and are generally unresponsive to shallow OBM filled fractures. As the fracture radius increases, the 400 KHz measurements begin to be affected in the same manner as the 2 MHz measurements. As such, the combination of measurements at different frequencies may be used to enhance accuracy of the fracture determination in some configurations.
An example logic flow for determining drilling induced fractures (DIF) in accordance with an example embodiment is now described with reference to the flow diagram 70 of
Beginning at Block 71, phase-shift and attenuation resistivity measurements are taken at a given depth within the borehole 44, which may be done at a single time or as time-lapse measurements. A first condition that may trigger setting of a flag is the order of the phase shift and attenuation measurements, at Block 73, and more particularly when an order of at least some of the phase-shift or attenuation measurements flips or reverses order (e.g., the closest measurements to the borehole become larger than those far away, which may be indicative of OMB penetration from the borehole 44. Based upon the occurrence of this condition, a first level spacing order flag may be set, at Block 74. In the code that follows below, DS means deep to shallow with respect to resistivity order, i.e., the deepest reading measurement reads the lowest resistivity and the shallowest reading measurement reads the higher resistivity. For example, if P22H (phase-shift measurement associated with transmitter T3 in
A second flag condition may correspond to an order of a phase measurement with respect to its corresponding attenuation measurement having the same spacing, at Block 75. For example, if the phase vs. attenuation order for P16H vs. A16H (attenuation measurement associated with transmitter T2 in
Similarly, another condition which may trigger a flag is when an order of the average phase-shift vs. average attenuation resistivity values changes or flips, at Block 77. When this occurs, a third level flag may be set, at Block 78. From a combination of the flag values, the presence and type (e.g., shallow, medium, or large radial length, etc.) of DIF may be determined, at Block 79, which concludes the example method illustrated in
The following is an example Python script which may be used for implementing the approach described above with respect to
Many modifications and other embodiments will come to the mind of one skilled in the art having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is understood that various modifications and embodiments are intended to be included within the scope of the appended claims.
