Patent Description:
The present invention generally relates to drilling and, in particular, to determining a propagation delay in a resistivity measurement system in a drill system.

Boreholes are drilled deep into the earth for many applications such as carbon dioxide sequestration, geothermal production, and hydrocarbon exploration and production. In all of the applications, the boreholes are drilled such that they pass through or allow access to a material (e.g., a gas or fluid) contained in a formation located below the earth's surface. Many different types of tools and instruments may be disposed in the boreholes to perform various tasks and measurements. One type of measurement that is typically made is a resistivity measurement.

Resistivity measurements can be made in several different manners. Regardless of how made, the measurements generally describe the electro-chemical content of the pore space of the formations surrounding the borehole. These measurements can be used to determine, for example, a desired direction of drilling.

In more detail, wellbores or boreholes for producing hydrocarbons (such as oil and gas) are drilled using a drill string that includes a tubing made up of jointed tubulars or a continuous coiled tubing that has a drilling assembly, also referred to as the bottom hole assembly (BHA), attached to its bottom end. The BHA typically includes a number of sensors, formation evaluation tools, and directional drilling tools. A drill bit attached to the BHA is rotated with a drilling motor in the BHA and/or by rotating the drill string to drill the wellbore. An electromagnetic wave propagation logging tool for determining electrical properties of the formations surrounding the borehole is often deployed in the BHA. Such tools are generally referred to in the oil and gas industry as the resistivity logging tools. These tools make measurements of apparent resistivity (or conductivity) of the formation that, properly interpreted, provide information about the petrophysical properties of the formation surrounding the borehole and fluids contained therein. Resistivity logging tools also are commonly used for logging wells after the wells have been drilled. Such tools are typically conveyed into the wells by wireline. The tools that use wireline are generally referred to as the wireline resistivity tools, while the logging tools used during drilling of the wellbore are generally referred to as the logging-while-drilling (LWD) or measurement-while-drilling (MWD) tools. These resistivity logging tools also are referred to as induction logging tools. For the purpose of this disclosure, the term resistivity tool or induction logging tool is meant to include all such and other versions of the resistivity tools.

A typical resistivity tool includes one or more receiver coils or antennas spaced from each other and one or more transmitter coils or antennas. Alternating current is passed through the transmitter coil, which induces alternating electromagnetic fields in the earth formation surrounding the wellbore. Voltages are induced in the receiver coils as a result of electromagnetic induction phenomena related to the alternating electromagnetic fields in the formation.

In order for the measurements to be correct, the timing of the transmitted and received signals may need to be synchronized.

<CIT> discloses a method and apparatus for synchronization between downhole components.

<CIT> discloses a method and apparatus for synchronizing units of a formation evaluation or drilling operation evaluation system.

According to an aspect, there is provided a system as claimed in claim <NUM>.

According to another aspect, there is provided a method as claimed in claim <NUM>.

The subject matter, which is regarded as the invention, is particularly pointed out and distinctly claimed in the claims at the conclusion of the specification. The foregoing and other features and advantages of the invention are apparent from the following detailed description taken in conjunction with the accompanying drawings, wherein like elements are numbered alike, in which:.

Resistivity measurement of the formation in geo-steering applications is often based on electromagnetic wave measurements. This measurement method requires transmitters and receivers to transmit the electromagnetic field and to receive the response from the formation. For some of these measurements synchronization between the transmitters and the receivers is needed. There is technically no problem if both are built in into the same downhole module. For some applications, a transmitter receiver distance, larger than the technology limits for single downhole modules, is needed and this causes the transmitters and receivers be built in into separate, independent downhole modules. In this case the synchronization is affected by the signal propagation delay on the electrical connection between the downhole modules. Herein disclosed are systems and methods that determine this propagation delay, which can be applied to the synchronization signal to correct for the delay.

<FIG> shows a schematic diagram of a drilling system <NUM> that includes a drill string <NUM> having a drilling assembly <NUM>, also referred to as a bottomhole assembly (BHA), conveyed in a borehole <NUM> penetrating an earth formation <NUM>. The drilling system <NUM> includes a conventional derrick <NUM> erected on a floor <NUM> that supports a rotary table <NUM> that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. The drill string <NUM> includes a drilling tubular <NUM>, such as a drill pipe, extending downward from the rotary table <NUM> into the borehole <NUM>. A drill bit <NUM>, attached to the end of the BHA <NUM>, disintegrates the geological formations when it is rotated to drill the borehole <NUM>. The drill string <NUM> is coupled to a drawworks <NUM> via a kelly joint <NUM>, swivel <NUM> and line <NUM> through a pulley. During the drilling operations, the drawworks <NUM> is operated to control the weight on bit, which affects the rate of penetration. The operation of the drawworks <NUM> is well known in the art and is thus not described in detail herein.

During drilling operations a suitable drilling fluid <NUM> (also referred to as the "mud") from a source or mud pit <NUM> is circulated under pressure through the drill string <NUM> by a mud pump <NUM>. The drilling fluid <NUM> passes into the drill string <NUM> via a desurger <NUM>, fluid line <NUM> and the kelly joint <NUM>. The drilling fluid <NUM> is discharged at the borehole bottom <NUM> through an opening in the drill bit <NUM>. The drilling fluid <NUM> circulates uphole through the annular space <NUM> between the drill string <NUM> and the borehole <NUM> and returns to the mud pit <NUM> via a return line <NUM>. A sensor S1 in the line <NUM> provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string <NUM> respectively provide information about the torque and the rotational speed of the drill string. Additionally, one or more sensors (not shown) associated with line <NUM> are used to provide the hook load of the drill string <NUM> and about other desired parameters relating to the drilling of the wellbore <NUM>.

In some applications the drill bit <NUM> is rotated by only rotating the drill pipe <NUM>. However, in other applications, a drilling motor <NUM> (mud motor) disposed in the drilling assembly <NUM> is used to rotate the drill bit <NUM> and/or to superimpose or supplement the rotation of the drill string <NUM>. In either case, the rate of penetration (ROP) of the drill bit <NUM> into the borehole <NUM> for a given formation and a drilling assembly largely depends upon the weight on bit and the drill bit rotational speed. In one aspect of the embodiment of <FIG>, the mud motor <NUM> is coupled to the drill bit <NUM> via a drive shaft (not shown) disposed in a bearing assembly <NUM>. The mud motor <NUM> rotates the drill bit <NUM> when the drilling fluid <NUM> passes through the mud motor <NUM> under pressure. The bearing assembly <NUM> supports the radial and axial forces of the drill bit <NUM>, the downthrust of the drilling motor and the reactive upward loading from the applied weight on bit. Stabilizers <NUM> coupled to the bearing assembly <NUM> and other suitable locations act as centralizers for the lowermost portion of the mud motor assembly and other such suitable locations.

A surface control unit <NUM> receives signals from the downhole sensors and devices via a sensor <NUM> placed in the fluid line <NUM> as well as from sensors S1, S2, S3, hook load sensors and any other sensors used in the system and processes such signals according to programmed instructions provided to the surface control unit <NUM>. The surface control unit <NUM> displays desired drilling parameters and other information on a display/monitor <NUM> for use by an operator at the rig site to control the drilling operations. The surface control unit <NUM> contains a computer, memory for storing data, computer programs, models and algorithms accessible to a processor in the computer, a recorder, such as any nonvolatile mass storage devices, like e.g. tape, hard disc drives, USB sticks, Solid State Disc or any suitable memory device known as state of the art, unit for recording data and other peripherals. The surface control unit <NUM> also may include simulation models for use by the computer to processes data according to programmed instructions. The control unit responds to user commands entered through a suitable device, such as a keyboard, computer mouse, joystick or any suitable manual input device known as state of the art. The control unit <NUM> is adapted to activate alarms <NUM> when certain unsafe or undesirable operating conditions occur.

Referring back to <FIG>, drilling assembly <NUM> also contains other sensors and devices or tools for providing a variety of measurements relating to the formation surrounding the borehole and for drilling the wellbore <NUM> along a desired path. Such devices may include a device for measuring the formation resistivity near and/or in front of the drill bit, a gamma ray device for measuring the formation gamma ray intensity and devices for determining the inclination, azimuth and position of the drill string. A formation resistivity tool <NUM>, made according an embodiment described herein may be coupled at any suitable location, including above a lower kick-off subassembly <NUM>, for estimating or determining the resistivity of the formation near or in front of the drill bit <NUM> or at other suitable locations. An inclinometer <NUM> and a gamma ray device <NUM> may be suitably placed for respectively determining the inclination of the BHA and the formation gamma ray intensity. Any suitable inclinometer and gamma ray device may be utilized. In addition, an azimuth device (not shown), such as a magnetometer or a gyroscopic device, may be utilized to determine the drill string azimuth. Such devices are known in the art and therefore are not described in detail herein. In the above-described exemplary configuration, the mud motor <NUM> transfers power to the drill bit <NUM> via a hollow shaft that also enables the drilling fluid to pass from the mud motor <NUM> to the drill bit <NUM>. In an alternative embodiment of the drill string <NUM>, the mud motor <NUM> may be coupled below the resistivity measuring device <NUM> or at any other suitable place.

Still referring to <FIG>, other logging-while-drilling (LWD) devices (generally denoted herein by numeral <NUM>), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties, etc. may be placed at suitable locations in the drilling assembly <NUM> for providing information useful for evaluating the subsurface formations along borehole <NUM>. Such devices may include, but are not limited to, acoustic tools, nuclear tools, nuclear magnetic resonance tools and formation testing and sampling tools.

The above-noted devices transmit data to a downhole telemetry system <NUM>, which in turn transmits the received data uphole to the surface control unit <NUM>. The downhole telemetry system <NUM> also receives signals and data from the surface control unit <NUM> and transmits such received signals and data to the appropriate downhole devices. In one aspect, a mud pulse telemetry system may be used to communicate data between the downhole sensors and devices and the surface equipment during drilling operations. A transducer <NUM> placed in the mud supply line <NUM> detects the mud pulses responsive to the data transmitted by the downhole telemetry <NUM>. Transducer <NUM> generates electrical signals in response to the mud pressure variations and transmits such signals via a conductor <NUM> to the surface control unit <NUM>. In other aspects, any other suitable telemetry system may be used for two-way data communication between the surface and the BHA <NUM>, including but not limited to, an acoustic telemetry system, an electro-magnetic telemetry system, a wireless telemetry system that may utilize repeaters in the drill string or the wellbore and a wired pipe. The wired pipe may be made up by joining drill pipe sections, wherein each pipe section includes a data communication link that runs along the pipe. The data connection between the pipe sections may be made by any suitable method, including but not limited to, hard electrical or optical connections and induction methods. In case a coiled-tubing is used as the drill pipe <NUM>, the data communication link may be run along a side of the coiled-tubing.

The drilling system described thus far relates to those drilling systems that utilize a drill pipe to conveying the drilling assembly <NUM> into the borehole <NUM>, wherein the weight on bit is controlled from the surface, typically by controlling the operation of the drawworks. However, a large number of the current drilling systems, especially for drilling highly deviated and horizontal wellbores, utilize coiled-tubing for conveying the drilling assembly downhole. In such application a thruster is sometimes deployed in the drill string to provide the desired force on the drill bit. Also, when coiled-tubing is utilized, the tubing is not rotated by a rotary table but instead it is injected into the wellbore by a suitable injector while the downhole motor, such as mud motor <NUM>, rotates the drill bit <NUM>. For offshore drilling, an offshore rig or a vessel is used to support the drilling equipment, including the drill string.

Still referring to <FIG>, a resistivity tool <NUM> made according to the present disclosure may include a plurality of antennas including, for example, transmitters 66a or 66b or and receivers 68a or 68b. In <FIG>, the transmitters <NUM> and receivers <NUM> are illustrated as being part of the same modules <NUM>. It shall be understood, however, that in some instances, the transmitters and receivers may need to be separated by distances that span more than one module.

<FIG> shows a simplified example of a resistivity measurement apparatus <NUM> (tool) is shown with transmitter <NUM> disposed at one end of a first module <NUM>. The module could be a pipe segment or part of a BHA. In this case, second module <NUM> is included and includes a receiver <NUM> disposed at an axially distant end of the second module <NUM>. The second module could be a pipe segment or part of a BHA. Between the first and the second modules <NUM>, <NUM> could be another module <NUM> (shown in dashes). The exact configuration of the transmitters and receivers is not required and is shown as an example. In general, in operation, alternating current is passed through the transmitter <NUM> to produce fields <NUM>. These fields induce alternating electromagnetic fields in the earth formation <NUM> surrounding the wellbore. The induced fields are shown by reference numeral <NUM>. The induced fields cause a voltage at receiver <NUM> as a result of electromagnetic induction phenomena related to the alternating electromagnetic fields in the formation. In some cases, a controller <NUM> is controlling the transmitter <NUM> and may receive information from the receiver <NUM>. The controller <NUM> may be part of the transmitter <NUM>. Also the receiver <NUM> may have a controller <NUM> to control the receiver and to receive information from the transmitter <NUM>. The timing of the signal sent to the formation of (by transmitter <NUM>) and subsequent sensing of signals by receiver <NUM> can be important in some instances and, as such, may require synchronization between the controllers in the BHA modules. In this case, but not limited to this, the controller <NUM> in the transmitter <NUM> and the controller <NUM> in the receiver <NUM> may communicate with each other.

In one embodiment, controller <NUM> (or a processor therein) communicates a signal related to a relative time within the transmitter signal created by the transmitter.

As illustrated, the controller <NUM> and the controller <NUM> are connected by communication line <NUM>. This line can be any type of communication line including a twisted pair, a coaxial, triaxial cable, an optical line or any other type of communication link for downhole use. Communication line <NUM> may comprise of at least two communication line sections that are coupled to each other. Couplers between two communication line sections may be but are not limited to galvanic coupler, capacitive coupler, inductive coupler, or optical coupler. In some cases that communication line <NUM> may be long enough that a delay is imparted as signals are passed from the controller <NUM> in the receiver <NUM> to the controller <NUM>. In addition, delays may be caused by connections, couplers, interfaces or electronic components that are part of the communication line <NUM> or installed between communication line sections. It should be understood that the teachings herein may be applied to any situation where a delay may be imparted and not just between a controller in a transmitter and a controller in a receiver.

As the delay is increased, the synchronization between elements may be lost. To that end, herein disclosed are systems/methods for determining the delay in a communication line. With the delay known, different elements can be synchronized.

With reference now to <FIG>, a communication line <NUM> connects two circuit modules. As illustrated, the modules are the controller <NUM> and the controller <NUM>. It shall be understood, however, that the modules are not limited to just these modules and can be any modules in a drilling assembly in one embodiment.

The controller <NUM> includes receiver main operating logic <NUM> that allows it to receive signals from an antenna <NUM>. The controller <NUM> includes a communication unit <NUM> that allows it to transmit information to and receive information from another BHA module via the transmission line <NUM>. The receiver main operating logic <NUM> may interpret the signals but that is not required. The received signals, or an interpretation thereof, are transmitted by the receiver main operating logic <NUM> and the communication unit of the controller <NUM> or transmitter <NUM> or another BHA module via communication line <NUM>. The controller <NUM> also includes a delay determination circuit <NUM> that determines the delay in the transmission line <NUM> between the controller <NUM> and, in the illustrated embodiment, the controller <NUM>.

The controller <NUM> includes main operating logic <NUM> that causes the controller <NUM> to cause a transmitter to transmit signals into a formation. The controller <NUM> also includes a communication module <NUM> and a reflection generator <NUM>.

The delay determination circuit <NUM> includes a pulse generator <NUM> and a timer <NUM>. The pulse generator <NUM> generates a first pulse <NUM> that travels from the controller <NUM> to the controller <NUM>. That pulse gets reflected back as a reflected pulse <NUM>. The timer <NUM> measures the time from when the first pulse leaves the controller <NUM> until the reflected pulse <NUM> returns to the controller <NUM>. The delay in the line is equal to one half that measured time.

In one embodiment, the determination of the delay is based on a calculated correlation function (Auto correlation) from the sampled data. In another embodiment, a pulse position analysis, such as a peak position determination, a start position determination of the pulse, etc. may be employed. As illustrated, a switch <NUM> couples either the delay determination circuit <NUM> or the communication module <NUM> to the transmission line <NUM>. To cause the controller <NUM> to reflect the pulse, switch <NUM> couples the line <NUM> to a reflection generator <NUM>. In one embodiment, the reflection may be generated by simply opening the switch <NUM>. Of course, the reflection generator could include any termination which is different from the (wave) impedance of the line <NUM> as this will cause a reflection of a first pulse <NUM>. The level of the reflection depends on the difference between the impedance of the line and the impedance of the termination. The maximum of reflection is achieved if the termination is a short (<NUM> resistance) or open (infinite resistance).

In support of the teachings herein, various analysis components may be used, including digital and/or analog systems. The digital and/or analog systems may be included, for example, in the downhole electronics unit or the processing unit. The systems may include components such as a processor, analog to digital converter, digital to analog converter, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs, USB flash drives, removable storage devices), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.

The use of the terms "a" and "an" and "the" and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms "first," "second," and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier "about" used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and / or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc..

Claim 1:
A system for measuring resistivity in a borehole (<NUM>), the system including:
first and second modules configured to be conveyed through the borehole (<NUM>);
a transmitter (<NUM>) connected to the first module, the transmitter (<NUM>) transmitting a transmitter signal that causes an electromagnetic field signal to be created in a formation surrounding the borehole (<NUM>); and
a receiver (68a) connected to the second module configured to sense the electromagnetic field signal;
the system characterised by further including:
a reflection generator (<NUM>);
a delay determination circuit (<NUM>) that includes a pulse generator (<NUM>) and a timer (<NUM>); and
a communication link (<NUM>)
connecting the first module and the second module, and
coupling the delay determination circuit (<NUM>) and the reflection generator (<NUM>);
wherein the delay determination circuit (<NUM>) is configured to cause a pulse to be transmitted to the reflection generator (<NUM>) and to determine an indication that is related to the time until a reflection is received back from the reflection generator (<NUM>); and
a processor to process the sensed field signal to generate resistivity related information based on the indication;
wherein the reflection generator (<NUM>) is an open circuit or a short circuit.