Method and apparatus to detect formation boundaries ahead of the bit using multiple toroidal coils

An apparatus and method for a property ahead of a drill bit in a borehole penetrating a formation. The apparatus may include at least one receiver toroid disposed on a carrier and a transmitter toroid configured to induce an electromagnetic signal in the formation and disposed between the drill bit and the at least one receiver toroid. The apparatus may include at least one processor configured to estimate the property using a signal produced by the at least one receiver. The method may include estimating the property using the signal produced by the at least one receiver toroid. The method may also include one or more of: (i) generating a conductivity curve based on signals from at least one receiver toroid, (ii) validating signals from one receiver toroid based on a conductivity curve of another receiver toroid, and (iii) filtering a receiver toroid signal using lateral resistivity information.

FIELD OF THE DISCLOSURE

This disclosure generally relates to exploration for hydrocarbons involving electrical investigations of a borehole penetrating an earth formation.

BACKGROUND OF THE DISCLOSURE

In many drilling applications it may be necessary to stop the drilling process before or shortly after the bit penetrates a new formation. In order to determine the position for stopping the drilling industry uses resistivity tools which are sensitive at or near the bit. Those resistivity tools are normally based on the usage of a toroidal coil for transmitting a current along the drill string and a receiver toroidal coil for measuring the current near the bit in direction of the borehole. Typically, a transmitter toroid and a receiver toroid are used, and the receiver toroid is typically located between the bit and the transmitter toroid. The transmitter toroid generates the current along the drill string while the receiver toroid delivers a measured current at a fixed position within the drill string.

These kinds of tools typically provide only one measurement curve. Small changes in resistivity caused by geological noise and/or small resistivity contrast at a boundary between formations may prevent estimation of some parameters ahead of the bit. Also, conditions like temperature may influence the response of the absolute measured resistivity value. The look ahead of the bit capability may be limited in quality since only small changes in resistivity are usually seen by the tool and the above mentioned factors often render such small changes as not interpretable. The information provided by those tools typically includes only one resistivity curve over the depth provided. If a zone of interest is touched, the resistivity values may change. If the contrast between the actual formation and a new formation is not sufficiently high, a misinterpretation of the resistivity curve is possible because of changes in the permeability of the toroidal carrier material to temperature, mechanical stress, etc.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure is related to methods and apparatuses for estimating at least one resistivity property ahead of a drill bit in a borehole penetrating an earth formation using a transmitter toroid disposed between the drill bit and at least one receiver toroid.

One embodiment according to the present disclosure includes an apparatus for estimating a property ahead of a drill bit in a borehole penetrating an earth formation, comprising: a carrier configured for conveyance in the borehole; at least one receiver disposed on the carrier, responsive to an electromagnetic signal induced in the earth formation, and configured to generate a signal indicative of the property, where each receiver toroid has a unique distance from the drill bit; a transmitter toroid disposed on the carrier closer to the drill bit than the at least one receiver toroid and configured to induce the electromagnetic signal in the earth formation; and at least one processor configured to: estimate the property based on at the least one receiver toroid signal.

Another embodiment according to the present disclosure includes a method of estimating a property ahead of a drill bit in a borehole penetrating an earth formation, comprising: estimating the property using a signal from at least one receiver toroid, wherein: the signal is indicative of the property and generated in response to an electromagnetic signal induced in the earth formation by a transmitter toroid positioned on a carrier closer to the drill bit than the at least one receiver toroid on the carrier.

Another embodiment according to the present disclosure includes a non-transitory computer-readable medium product having stored thereon instructions that, when executed by at least one processor, cause the at least one processor to perform a method, the method comprising: estimating the property using a signal from at least one receiver toroid, wherein: the signal is indicative of the property and generated in response to an electromagnetic signal induced in the earth formation by a transmitter toroid positioned on a carrier closer to the drill bit than the at least one receiver toroid on the carrier.

Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.

DETAILED DESCRIPTION

This disclosure generally relates to exploration for hydrocarbons involving electromagnetic investigations of a borehole penetrating an earth formation. These investigations may include estimating a resistivity property ahead of a drill bit using a transmitter toroid disposed between the drill bit and at least one receiver toroid.

Using a transmitter with at least one toroidal coil between a drill bit and at least one receiver toroid may allow electromagnetic energy from the transmitter to penetrate into the formation ahead of the drill bit. The return current may be estimated by one or more receiver toroids to provide information related to resistivity properties ahead of the drill bit. Each receiver toroid may include one or more coils. These resistivity properties may include, but are not limited to, i) a distance to a resistivity boundary between earth formations with different resistivities and ii) a resistivity of the earth formation adjacent to the resistivity boundary.

Using multiple receiver toroids, multiple curves indicative of resistivity properties of an earth formation may be produced for different depths of investigation. Multiple curves for each depth of investigation may reduce the risk of misinterpretation of a resistivity curve by providing at least one additional resistivity curve to act as a check. The different curves may be compared to each other in order to distinguish between artificial outer circumstances like temperature changes etc. and a real approaching boundary ahead of or close to the bit. This functionality may be particularly beneficial if, for example, a casing has to be placed directly at the beginning of a reservoir or a bit has to be exchanged because the new formation is expected to be harder, etc. Therefore it is important to offer a tool which is able to provide an accurate estimate of conditions ahead of the bit.

The present disclosure is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. Indeed, as will become apparent, the teachings of the present disclosure can be utilized for a variety of well tools and in all phases of well construction and production. Accordingly, the embodiments discussed below are merely illustrative of the applications of the present disclosure.

FIG. 1shows an exemplary embodiment of a well drilling, logging and/or geosteering system10includes a drill string11that is shown disposed in a wellbore or borehole12that penetrates at least one earth formation13during a drilling operation and makes measurements of properties of the formation13and/or the borehole12downhole. As described herein, “borehole” or “wellbore” refers to a single hole that makes up all or part of a drilled well. As described herein, “earth formations” refer to the various features and materials that may be encountered in a subsurface environment and surround the borehole. The term “information” includes, but is not limited to, raw data, processed data, and signals.

In one embodiment, the system10includes a conventional derrick14that may supports a rotary table16that is rotated at a desired rotational speed. The drill string11includes one or more drill pipe sections18that extend downward into the borehole12from the rotary table16, and is connected to a drilling assembly20. Drilling fluid or drilling mud22is pumped through the drill string11and/or the borehole12. The well drilling system10also includes a bottomhole assembly (BHA)24. In one embodiment, a drill motor or mud motor26is coupled to the drilling assembly20and rotates the drilling assembly20when the drilling fluid22is passed through the mud motor26under pressure.

In one embodiment, the drilling assembly20includes a steering assembly including a shaft28connected to a drill bit30. The shaft28, which in one embodiment is coupled to the mud motor, is utilized in geosteering operations to steer the drill bit30and the drill string11through the formation.

In one embodiment, the drilling assembly20is included in the bottomhole assembly (BHA)24, which may be disposable within the system10at or near the downhole portion of the drill string11. The system10may include any number of downhole tools32for various processes including formation drilling, geosteering, and formation evaluation (FE) for measuring versus depth and/or time one or more physical quantities in or around a borehole. The tool32may be included in or embodied as a BHA, drill string component, or other suitable carrier. A “carrier” as described herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tubing type, of the jointed pipe type and any combination or portion thereof. Other carriers include, but are not limited to, casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, bottomhole assemblies, and drill strings.

In one embodiment, one or more downhole components, such as the drill string11, the downhole tool32, the drilling assembly20and the drill bit30, include a resistivity tool34configured to measure various parameters of the formation and/or borehole. These downhole tool32may include formation evaluation sensors (e.g., resistivity, dielectric constant, water saturation, porosity, density and permeability), sensors for measuring borehole parameters (e.g., borehole size, and borehole roughness), sensors for measuring geophysical parameters (e.g., acoustic velocity and acoustic travel time), sensors for measuring borehole fluid parameters (e.g., viscosity, density, clarity, rheology, pH level, and gas, oil and water contents), boundary condition sensors, and sensors for measuring physical and chemical properties of the borehole fluid. In some embodiments, the BHA24may include a resistivity tool35configured for estimating one or more lateral resistivity properties (substantially perpendicular to the long axis of the BHA24).

FIG. 2shows an embodiment of resistivity tool34according to the present disclosure. An exemplary drill string11may include five (5) toroids, including a transmitter toroid210and four (4) receiver toroids220,230,240,250and drill bit30. Each toroid may include one or more coils. The transmitter toroid210may be disposed between the drill bit30and the receiver toroid coils220,230,240,250. Resistivity tool34may be disposed in earth formation13which is located adjacent to another earth formation270. Boundary260may represent the division between earth formation13and earth formation,270, where each of the formations13,270differ with regard to at least one resistivity property. The use of four (4) receiver toroids is exemplary and illustrative only, as any number of receiver toroid may be used. Increasing the number of receiver toroid may increase resolution of the formation currents.

Since the transmitter toroid210is closer to the bit30than the receiver toroid220,230,240,250, the receiver toroids220,230,240,250may record lateral resistivity information as well as resistivity information from ahead of the bit30. Because the current is flowing along the drill string11as it returns to the transmitter toroid210, receiver toroids240,250farther from the transmitter toroid210measure current travelling a longer distance through the formation13and providing information from geologic locations more far away (e.g. ahead of the bit) while receiver toroids220,230closer to the transmitter toroid210also include resistivity information from geologic locations closer to the transmitter toroid210. Herein the term “information” relates to one or more of raw data, processed data, and signals.

The current monitored by receiver toroid220(closest to the transmitter210) (IR1) is the sum of all formation currents Ii:

If the drill string is equipped with n receiver toroids, the current IRmpassing the receiver toroid number m may be calculated by:

Formation current Immay be determined using the receiver toroid current IRmand the current of the next farther receiver IR(m+1)as calculated by:
Im=IRm−IR(m+1)(3)

After extracting the formation currents Iifrom the receiver toroid currents IRi, information about different depths of investigation may be obtained by examining the currents Ii. If the BHA24with tool34is approaching a boundary260between two formations13,270with different resistivity ahead of the drill bit30, the formation current with the highest index Inwill indicate the change in resistivity as the first. The other formation currents may indicate this change later related to decreasing indices. Since the currents react in a specific order, the risk of misinterpretation of the resistivity information may be decreased and the look-ahead ability improved.

FIG. 3Ashows another embodiment of tool34according to the present disclosure. The toroids210,220,230,240,250may be spaced so that all pairs of adjacent toroids have identical spacing. In some embodiments, such as inFIG. 2, the spacing may increase between adjacent toroids as distance from the drill bit30increases. When tool34includes multiple receiver toroids220,230,240,250, a signal generated by one of the receiver toroids220,230,240,250may be validated using signals generated by one or more of the other receiver toroids220,230,240,250. In some embodiments, signals from one or more other receiver toroids220,230,240,250may be used to estimate a substitute signal for the signal generated by the one receiver toroid220,230,240,250.

FIG. 3Bshows a schematic of the tool34ofFIG. 3Ain earth formation13as used for modeling. The tool34is at least partially surrounded by a small channel310containing conductive mud320with a resistivity ρmud. Earth formation13may have a resistivity ρ1, and earth formation270may have a different resistivity ρ2. The face of drill bit30may define the zero mark for distance in the borehole12. Negative values for distance may indicate that the face of drill bit30is still in front of the boundary260, while positive values may indicate that the bit30has already penetrated the boundary260.

FIG. 4Ashows a chart with modeling results for tool34in the configuration ofFIG. 3Afor the case that the formation contrast is 50 (formation resistivity changes from 20 Ωm (ρ1) to 1000 Ωm (ρ2). The currents I1to I4may be normalized to conductivities by applying an individual 1/k-factor of each current section. The conductivity curves420,430,440,450represent the response of corresponding formation currents (receiver toroid current differences)220,230,240,250to the signal from transmitter toroid210. The use of conductivity curves is exemplary and illustrative only, as one of skill in the art with the benefit of this disclosure would be able to use other related curves, such as resistivity curves. The conductivity curves420,430,440,450may indicate a clear order in response to the approaching boundary260ahead of the drill bit30. Here, conductivity curve450indicates first response, followed, in order, by conductivity curve440, conductivity curve430, and conductivity curve420. The responses are related to the formation currents at the locations of the receiver toroids220,230,240,250within the resistivity tool340. Since the face of the drill bit30is the zero distance reference point, negative values for distance to the boundary260indicate the distance ahead of the drill bit30to the boundary260. In some embodiments, lateral resistivity information for lateral resistivity tool35may be used to filter lateral resistivity information from the currents I1to I4(such as, but not limited to, by subtraction).

FIG. 4Bshows a chart with modeling results for tool34in the configuration ofFIG. 3Afor the case that the formation is 0.05 (formation resistivity changes from 2000 Ωm (ρ1) to 100 Ωm (ρ2). The currents I1to I4may be normalized to conductivities by applying an individual 1/k-factor of each current section. The conductivity curves425,435,445,455represent the response of corresponding receiver toroid220,230,240,250due to the formation currents induced by the signal from transmitter toroid210. The conductivity curves425,435,445,455may indicate a clear order in response to the approaching boundary ahead of the drill bit30. Here, conductivity curve455indicates first response, followed, in order, by conductivity curve445, conductivity curve435, and conductivity curve425. The responses are related to the formation currents estimated by, and vary with the location of, the receiver toroids220,230,240,250within the resistivity tool34. Since the face of the drill bit30is the zero distance reference point, negative values for distance to the boundary260indicate the distance ahead of the drill bit30to the boundary260. Although the order of the conductivity curves425,435,445,455is identical to the order of conductivity curves420,430,440,450, though the range of influence ahead of the drill bit30may be reduced.

FIG. 5Ashows a flow chart of a method500according to one embodiment for the present disclosure. In step510, the BHA24with resistivity tool34may be conveyed in the borehole12. The BHA24may include transmitter toroid210and at least two receiver toroids220,230,240,250. The transmitter toroid210may be disposed between the at least two receiver toroids220,230,240,250and drill bit30. The toroids210,220,230,240,250may have equal or unequal spacing between adjacent toroids210,220,230,240,250. In step520, energy may be transmitted into the earth formation13using transmitter toroid210. The transmitted energy may induce an electric current in the earth formation13. In step530, signals may be generated by each of the receiver toroids220,230,240,250, the receiver toroids220,230,240,250being responsive to the electric current in the earth formation13, and the signals being indicative of a resistivity property of the earth formation13. The toroids210,220,230,240,250may be moving along the borehole12while the signals are generated. In step540, a conductivity curve may be estimated for each signal of the receiver toroids220,230,240,250.

In step550, a conductivity curve420,430,440,450from a first receiver toroid220,230,240,250of the at least two receiver toroids220,230,240,250may be validated using a conductivity curve420,430,440,450from a second receiver toroid220,230,240,250of the at least two receiver toroids220,230,240,250. Validation may include comparison between conductivity curves for variances. In some embodiments, validity may include comparing the variance with one or more threshold values. In some embodiments, the signal from a first receiver toroid may be validated using a signal from another receiver toroid without conductivity curves being generated from the signals. In some embodiments, step550may include an optional substitution of an estimated conductivity curve to replace a conductivity curve420,430,440,450from a first receiver toroid220,230,240,250where the estimated conductivity curve is based on conductivity curves420,430,440,450of the at least two receiver toroids220,230,240,250. An invalid conductivity curve may be due to, but not limited to, the effects of temperature and/or mechanical defects in one or more of the receiver toroids220,230,240,250. These environmental factors and/or defects may affect the signals generated by one or more of the receiver toroids220,230,240,250. Validation may include comparing the characteristics of a conductivity curve420,430,440,450based on signals from one receiver toroid220,230,240,250with the characteristics of the conductivity curve420,430,440,450based on signals from one or more other receiver toroids220,230,240,250. Estimating a conductivity curve for substitution may include, but is not limited to, interpolating the estimated conductivity curve at a position at a distance from the transmitter using signals from at least one receiver toroid located closer to the position and signals from at least one receiver toroid farther than the position. For example, interpolation between conductivity curves420and440may be used to estimate a substitute for conductivity curve430. In some embodiments, an invalidity result and/or substitution may be triggered by a threshold difference between two or more conductivity curves. In step560, one or more resistivity properties may be estimated using the signal of the first receiver toroid. In some embodiments, the first receiver toroid of steps550and560may be in a receiver toroid position not limited to closest to the transmitter210. In some embodiments, steps540and550are optional.

FIG. 5Bshows a flow chart of a method505according to one embodiment for the present disclosure. In step515, the BHA24with resistivity tool34may be conveyed in the borehole12. The BHA24may include transmitter toroid210and at least one receiver toroid220,230,240,250. The transmitter toroid210may be disposed between the at least one receiver toroids220,230,240,250and drill bit30. The toroids210,220,230,240,250may have equal or unequal spacing between adjacent toroids210,220,230,240,250. In step520, energy may be transmitted into the earth formation13using transmitter toroid210. The transmitted energy may induce an electric current in the earth formation13. In step535, signals may be generated by each of the receiver toroids220,230,240,250, the receiver toroids220,230,240,250being responsive to the electric current in the earth formation13, and the signals being indicative of a resistivity property of the earth formation13. The toroids210,220,230,240,250may be moving along the borehole12while the signals are generated. In step545, lateral resistivity information may be generated by a resistivity tool35configured to acquire lateral resistivity data. In step555, lateral boundary information may be filtered from at least one receiver toroid signal using the lateral resistivity information. In step560, one or more resistivity properties may be estimated using the signal of a first receiver toroid of the at least one receiver toroid220,230,240,250. In some embodiments, steps545and555are optional.

In some embodiments, steps545and555may be performed in method500. Steps545and555may be performed before step540or after step550. Similarly, steps540and550may be performed in method505(before step545or after555) when method505is performed using at least two receiver toroids220,230,240,250.

In some embodiments, the distance from the drill bit30of the at least one toroid220,230,240,250may be less than the distance from the drill bit of another toroid220,230,240,250. The one or more resistivity properties may include, but is not limited to, a distance to a boundary260.

Implicit in the processing of the data is the use of a computer program implemented on a suitable non-transitory machine-readable medium that enables the processor to perform the control and processing. The term processor as used in this application is intended to include such devices as field programmable gate arrays (FPGAs). The non-transitory machine-readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. As noted above, the processing may be done downhole or at the surface, by using one or more processors. In addition, results of the processing, such as an image of a resistivity property, can be stored on a suitable medium.

While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.