GB2443096A - Method and system for wellbore communication - Google Patents

Abstract

A casing while drilling system (100, Fig.1) that advances a bottom hole assembly having a drill bit 218 into a subsurface formation comprises a communication means 262 for generating mud pulses at high frequencies, an assembly 225 for drilling, measurement, or formation evaluation, and a mud motor 210 for converting mud flow into rotation of the drill bit 218. The communication means 262 is positioned uphole relative to the mud motor 210 and is in communication with said evaluation assembly. The communication means 262 may be a modulator. The system 100 may also include a transducer (142, Fig.1).

Description

METHOD AND SYSTEM FOR WELLBORE COMMUNICATION

BACKGROUND OF THE INVENTION

The present invention relates to telemetry systems for use in weilbore operations. More particularly, the present invention relates to telemetry systems for providing power to downhole operations andlor for passing signals between a position in a welibore penetrating a subterranean formation and a surface unit Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. A well is typically drilled by advancing a drill bit into the earth. The drill bit is attached to the lower end of a "drill string" suspended from a drilling rig.

The drill string is a long string of sections of drill pipe that are connected together end-to-end to form a long shaft for driving the drill bit further into the earth. A bottom hole assembly (BRA) containing various instrumentation and/or mechanisms is typically provided above the drill bit. Drilling fluid, or mud, is typically pumped down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in the annulus between the drill string and the borehole wall.

During conventional measurement while drilling (MWD) or logging while drilling (LWD) operations, signals are passed between a surface unit and the BHA to transmit, for example commands and information. Typically, the surface unit receives information from the BHA and sends command signals in response thereto.

Communication or telemetry systems have been developed to provide techniques for generating, passing and receiving such signals. An example of a typical telemetry system used involves mud-pulse telemetry that uses the drill pipe as an acoustic conduit for mud pulse telemetry. With mud pulse telemetry, mud is passed from a surface mud pit and through. the pipes to the bit. The mud exits the bit and is used to contain formation pressure, cool the bit and lift drill cuttings from the borehole. This same mud flow is selectively altered to create pressure pulses at a frequency detectable at the surface and downhole. Typically, the operating frequency is in the order 1-3 bits/sec, but can fall within the range of 0.5 to 6 bits/sec. An example of mud pulse telemetry is described in US Patent No. 5,517,464.

In conventional drilling, a well is drilled to a selected depth, and then the weilbore is typically lined with a larger-diameter pipe, usually called casing. Casing typically consists of casing sections connected end-to-end, similar to the way drill pipe is connected. To accomplish this, the drill string and the drill bit are removed from the borehole in a process called "tripping." Once the drill string and bit are removed, the casing is lowered into the well and cemented in place. The casing protects the well from collapse and isolates the subterranean formations from each other. After the casing is in place, drilling may continue or the well may be completed depending on the situation.

Conventional drilling typically includes a series of drilling, tripping, casing and cementing, and then drilling again to deepen the borehole. This process is very time consuming and costly. Additionally, other problems are often encountered when tripping the drill string. For example, the drill string may get caught up in the borehole while it is being removed. These problems require additional time and expense to correct.

The term "casing drilling" refers to the use of a casing string in place of a drill string. Like the drill string, a chain of casing sections are connected end-to-end to form a casing string. The BRA and the drill bit are connected to the lower end of a casing string, and the well is drilled using the casing string to transmit drilling fluid, as well as axial and rotational forces, to the drill bit. Upon completion of drilling, the casing string may then be cemented in place to form the casing for the welibore. Casing drilling enables the well to be simultaneously drilled and cased. Examples of such casing drilling are provide in US Patent No. 6,419,033, US Patent Application No. 20040104051 and PCT Patent Application No. W000/50730.

Despite the advances in casing drilling technology, current casing drilling systems are unable to provide high speed communication between the surface and the bottom hole assembly. Therefore, what is needed is a system and method to provide a casing drilling system with high speed, low attenuation rate andlor enhanced band width signal capabilities.

SUMMARY OF INVENTION

In accordance with one aspect of the invention, there is provided a casing while drilling system that advances a bottom hole assembly having a drill bit into a subsurface formation, the system comprising: a communication means for generating mud pulses at high frequencies; an assembly for drilling, measurement, or formation evaluation; and a mud motor for converting mud flow into rotation of the drill bit, wherein the communication means is uphole relative to the mud motor and wherein the communication means is in communication with said evaluation assembly.

In accordance with another aspect of the invention, there is provided method of communicating while casing while drilling in a borehole with a bottom hole assembly comprising a drill bit, a communication means for generating mud pulses at high frequencies, an assembly for drilling, measurement, or formation evaluation and a mud motor for converting mud flow into rotation of the drill bit, the method comprising positioning the communication means uphole relative to the mud motor and establishing communication between the communication means and said evaluation assembly. -

BRIEF DESCRIPTION OF DRAWINGS

The invention will now be described, by way of example only, with reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of the invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIGURE 1 is a schematic view, partially in cross-section, of a rig having a casing drilling system for drilling a wellbore, the casing drilling system provided with a casing drilling communication system.

FIGURE 2A is a detailed view of the casing drilling system of FIGURE 1, the casing drilling system can entail a drilling, measurement, and/or formation evaluation assembly such as a rotary steerable (RSS), measurement while drilling (MWD) and/or logging while drilling (LWD) system and a modulator.

FIGURE 2B is a detailed view of the casing drilling system of FIGURE 1, wherein the casing drilling communication system is run with a mud motor or turbo drill and the communication system is located uphole relative to the mud motor.

FIGURE 3 is a detailed, exploded view of the modulator of Figure 2 having a stator and a rotor.

FIGURE 4A is a detailed view of the modulator of Figure 2 with the rotor in the open position relative to the stator.

FIGURE 4B is a detailed view of the modulator of Figure 2 with the rotor in the closed position relative to the stator.

FIGURES 5A-1) are schematic views of the rotor and stator of Figure 3 depicting the movement of the rotor relative to the stator.

FIGIJRES 6A-D are graphs depicting the relationship between pressure versus time for the rotors and stators depicted in Figures 5A-D, respectively.

FIGURE 7 is a graph depicting signal strength versus depth at a first frequency and bit rate.

FIGURE 8 is a graph depicting signal strength versus depth at a second frequency and bit rate.

DETAILED DESCRiPTION

Referring to Figure 1, a casing drilling system 100 includes a rig 102 with a bottom hole assembly (BHA) 104 deployed into a borehole 106 via a casing 108. The rig 102 has a traveling hook]block 126, top drive 128, guide rail and top drive/block doIly 130 and draw works 131. A casing drive head/assembly 132 operatively connects the casing to the top drive 128. The casing 108 extends through a conductor pipe 134.

Casing slips 136 are used to suspend the casing 108 string when adding a new joint of casing as drilling depth increases.

In one embodiment, the BHA 104 includes a drill bit 118 at a downhole end thereof, a rotary steerable (RSS), measurement while drilling (MWD) and/or logging while drilling (LWD) assembly 125, and an under reamer 122. A BHIA latch & seal assembly 124 operatively connects the BHA 104 to the casing 108. Preferably, the latch & seal assembly 124 and the BI-IA 104 are retrievable through the casing 108.

The MWD/LWD assembly 125 preferably includes or communicates with a telemetry system or modulator, which is described in detail below, for communication with an acquisition and demodulation unit 127. The acquisition and demodulation unit 127 typically resides in a surface unit, cabin or enclosure (not shown).

A surface mud pit 110 with a mud 112 therein is positioned near the rig 102.

Mud 112 is pumped through feed pipe 114 by pump 116 and through the casing 108 as indicated by the arrows. Mud 112 passes through the BHA 104, out the drill bit 118 and back up through the borehole 106. Mud 112 is then driven out an outlet pipe 120 and back into mud pit 110.

The drill bit 118 advances into a subterranean formation F and creates a pilot hole 138. The under reamer 122 advances through the borehole 106, expands the pilot hole 138 and creates an under-reamed hole 140. The BHA 104 is preferably retrievable through the casing 108 on completion of the drilling operation. The under reamer 122 is preferably collapsible to facilitate retrieval through the casing 108.

Referring now to Figure 2A depicts a portion of the casing drilling system 100 of Figure 1 in greater detail. As mud 112 is pumped from feed pipe 114 through pump 116, it passes by a pressure transducer 142 and down through the casing 108 to an RSS, MWD, and/or LWD assembly 125 as indicated by arrows 148, 150, and 152. The mud 112 passes through the BHA 104, exits the drilling bit 118 and returns through borehole 106 as indicated by arrows 154, 156 and 158.

The RSS, MWD, and/or LWD assembly 125 uses a mud pulse system, such as the one described in US Patent No. 5,517,464. The RSS, MWD, and/or LWD assembly 125 includes a modulator 162 adapted to communicate with a surface unit (not shown). As mud 112 passes through the modulator 162, the modulator 162 restricts the flow of the mud 112 and hence the pressure to generate a signal that travels back through the casing 108 as indicated by arrows 160 and 163. The pressure transducer 142 detects the changes in mud pressure caused by the modulator 162. The acquisition and demodulation unit 127 processes the signal thereby allowing the BHA 104 to communicate to the surface through the unit 127 for uphole data collection and use.

Referring now to Figure 2B, an alternative embodiment is shown wherein a BHA 204 includes a drilling, measurement, and/or formation evaluation assembly 225, such as RSS, MWD, and/or LWD, a mud motor or turbo-drill 210, a drill bit 218, an under-reamer 222, and a data transmission module 224. The mud motor 210 is located downhole or below a casing drilling modulator 262, which is similar to the modulator 162 of Figure 2A. Using a mud or drilling motor, such as the mud motor 210, provides the advantage of reducing the amount of rotations on the casing 108. In one embodiment, the modulator 262 communicates with the transmission module 224, which is in communication with other components or elements of the BHA 204. In an alternative embodiment, the modulator 262 communicates directly with the other elements in the BHA 204 including the RSS, MWD, and/or LWD assembly 225 through various means including wired or wireless such as electromagnetic or ultrasonic methods. The scope of the present invention is not limited by the means used for communication, which includes but is not limited to transmission through wired methods or wireless methods, which could include electromagnetic, ultrasonic or other means, or a combination thereof, such a wired and wireless or ultrasonic and electromagnetic combined with wired communication. Positioning the mud motor 210 downhole relative to the modulator 262 is the present embodiment which limits signal attenuation and produces the higher data rate and depth capability.

Referring now to Figure 3, the modulator 162 of Figure 2A and modulator 262 of Figure 2B are depicted in greater detail. In each of the embodiments set forth herein, the modulator are similar in operation. Accordingly, even though the operation of one of the modulators is discussed in detail, the operation and results are applicable to similar types of modulators shown in alternative embodiments. The modulator 162 includes a stator 164, rotor 166 and turbine 167. The modulator 162 may be, for example, of the type described in US Patent No. 5,517,464. In one embodiment, the modulator 162 is preferably a rotary or siren type modulator. Such modulators are typically capable of high speed operation, which can generate high frequencies and data rates. Alternatively, in another embodiment conventional "poppet" type or vertically reciprocating pulsers may be used, but they tend to be limited in speed of operation due to limits of accelerationldeceleratjon and motion reversal with associated problems of wear, flow-erosion, fatigue, power limitations, etc. As the mud flow passes through the turbine 167, the mud flow turns the turbine 167 and the rotation of the turbine 167 caused by the flow of mud generates power that can be used to power any required part of portion the BHA 104, including the rotor 166 of modulator 162.

Figures 4A and 4B show the position of the rotor 166 and stator 164. In Figure 4A, the rotor 166 is in the open position. In other words, the rotor 166 is aligned with the stator 164 to permit fluid to pass through apertures 168 therebetween.

In Figure 4B, the rotor 166 is in the closed position, such that the apertures 168 are blocked, at least partially. In other words, the rotor 166 is mis-aligned with respect to the stator 164 to block at least a portion of the fluid passing through apertures 168 therebetween. The movement between the open and closed position creates a pressure pulse.' This pressure pulse is a signal detectable at the surface, and is used for communication.

Referring now to Figures 5A-D, the flow of fluid past the rotor 166 and stator 164 is shown in greater detail in Figures 5A-D. In the open position (Fig. 5A), fluid passes with the least amount of restriction past stator 164 and rotor 166.

As the rotor 166 rotates and blocks a portion of the aperture 168 (Fig. SB), fluid is partially restricted, thereby causing a change in pressure over time. The rotor 166 then rotates to a more restricted or closed position (Fig. SC) and restricts at least a portion of the fluid flow. The rotor 166 advances further until it returns to the unobstructed position (Fig. 5D).

Referring now to Figures 6A-D, the change in pressure over time is displayed in graphs of pressure-versus-time plots of the fluid flow for each of the rotor positions of Figures 5A-D, respectively.

The following equations show the general effect of various parameters of the mud pulse signal strength and the rate of attenuation: S = S0 exp [-4 7t F (D(d)2(jiJK)} where -S signal strength at a surface transducer; S0 = signal strength at the downhole modulator; F = canier frequency of the MWD sgnal expressed in Hertz; D measured depth between the surface transduc-er and the down hole modulator; d inside diameter of the drill pipe (same units as measured depth); p. = plastic viscosity of the drilling fluid; and K = bulk modulus of the volume of mud above the modulator, and by the modulator signal pressure relationship S0 (Pmud X Q2)/A2 where S0 = signal strength at the downhole modulator; density of the drilling fluid; Q = volume flow rate of the drilling fluid; and A the flow area with the modulator in the "closed" position The foregoing relationships demonstrate that a larger diameter of pipe, such as the casing 108, makes higher carrier frequencies and data rates possible since the attenuation rate is lower for larger pipe diameters. Thus, for the specific application of casing drilling, the effect of the inside diameter "d", as shown in Fig. 2A, makes higher carrier frequencies (hence, data rates) possible since the rate of attenuation is much less compared to conventional drill pipe. Accordingly, the ability to transmit at high frequencies and, hence the scope of the present invention, is determined by the foregoing relationships. The specific data rates provided below are for illustration purposes and not intended as a limiting example.

Referring now to Figures 7 and 8, graphs comparing the signal strength (y-axis) at various depths (x-axis) for a drill pipe in comparison to a casing. Figure 7 shows the signal strength for a 5" (12.7 cm) drill pipe (170) and a 7" (17.8 cm)casing (172). A minimum level (174) for detecting signal strength is also depicted. The graph illustrates the effect diameter has on signal strength in a 24hz-12 bit/second deep water application using synthetic oil based mud. This shows that with the larger internal diameter of casing, 12 bit/sec telemetry rate is possible to about 20000 feet (6096 m) as compared to the smaller drill pipe diameter where 12 bit/sec is limited to about 13000 feet. Thus, the communication system described herein in this example can operate in the range of 1 bit/sec up to I 2bits/sec depending on the casing diameter and depth.

Figure 8 shows the signal strength for a 5" (12.7 cm) drill pipe (180) and a 7" (17.8 cm) casing (182). A minimum level (184) for detecting signal strength is also depicted. The graph illustrates the effect diameter has on signal strength in a 1hz-I bit/second deep water application using synthetic oil based mud. Typically, telemetry with drill pipe will be limited to I bit/see, hence there is one order of magnitude higher data rate possible in these conditions with casing as compared to drill pipe. There is also an approximately four-fold increase in signal amplitude with casing as compared to drill-pipe for 1 Hz telemetry.

It should be noted that both of the examples illustrated in Figures 7 and 8 are for comparison purpose only and that by changing the relevant parameters in the previously stated relationships, an increase in depth and/or data rate capability is possible, It will be understood from the foregoing description that various modifications and changes may be made in the preferred and alternative embodiments of the present invention without departing from its true spirit. Furthermore, this description is intended for purposes of illustration only and should not be construed in a limiting sense. The scope of this invention should be determined only by the language of the claims that follow. The term "comprising" within the claims is intended to mean "including at least" such that the recited listing of elements in a claim are an open set or group. Similarly, the terms "containing," having," and "including" are all intended to mean an open set or group of elements. "A" or "an" and other singular terms are intended to include the plural forms thereof unless specifically excluded.

Claims (12)

1. I. A casing while drilling system that advances a bottom hole assembly having a drill bit into a subsurface formation, the system comprising: a communication means for generating mud pulses at high frequencies; an assembly for drilling, measurement, or formation evaluation; and a mud motor for converting mud flow into rotation of the drill bit, wherein the conmiunication means is uphole relative to the mud motor and wherein the communication means is in communication with said evaluation assembly.
2. 2. The drilling system of claim 1, further comprising a transducer adapted to detect the mud pulse generated by the communication means.
3. 3. The drilling system of claim I or claim 2, wherein the communication means comprises a modulator adapted to generate the mud pulses by selectively restricting mud flow passing therethrough.
4. 4. The drilling system of claim 3, wherein the modulator comprises: a stator defining a plurality of apertures; and a rotor defining a plurality of apertures; wherein the rotor is coaxially aligned with the stator and rotates to define an variable aperture resulting from the relative alignment of the plurality of apertures and the plurality of mating apertures to generate the mud pulses.
5. 5. The drilling system of any preceding claim, wherein the communication means is in wireless communication with the evaluation assembly.
6. 6. The drilling system of any one of claims I to 5, wherein the communication means uses wired and wireless communication.
7. 7. A method of communicating while casing while drilling in a borehole with a bottom hole assembly comprising a drill bit, a communication means for generating mud pulses at high frequencies, an assembly for drilling, measurement, or formation evaluation and a mud motor for converting mud flow into rotation of the drill bit, the method comprising positioning the communication means uphole relative to the mud motor and establishing communication between the communication means and said evaluation assembly.
8. 8. The method of claim 7, further comprising using a transducer to detect the mud pulse generated by the modulator.
9. 9. The method of claim 7 or claim 8, wherein the communication means comprises a modulator adapted to generate the mud pulses are generated by selectively restricting mud flow passing through a modulator.
10. 10. The method of claim 9, wherein the modulator comprises: a stator defming a plurality of apertures; and a rotor defining a plurality of apertures; wherein the rotor is coaxialiy aligned with the stator and rotates to define an variable aperture resulting from the relative alignment of the plurality of apertures and the plurality of mating apertures to generate the mud pulses.
11. 11. The method of any one of claims 7 to 10, wherein the communication means is in wireless communication with the evaluation assembly.
12. 12. The method of any one of claims 7 to 10, wherein the communication means uses wired and wireless communication.