INTELLIGENT DRILLING RISER TELEMETRY SYSTEM

Abstract

An intelligent drilling riser telemetry system includes a mud pulse telemetry transmitter deployed in a drill string. At least one annular pressure sensor is deployed on a drilling riser and is configured to sense mud pulse telemetry signals in an annular region thereof. A surface processor is in electronic communication with the annular pressure sensor via an electrical transmission line that extends along a length of the drilling riser from the annular pressure sensor to the drilling rig. The processor is configured to decode a transmitted mud pulse telemetry signal.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

None.

FIELD OF THE INVENTION

Disclosed embodiments relate generally to drilling risers used in offshore drilling operations and more particularly to an intelligent drilling riser telemetry system and method.

BACKGROUND INFORMATION

Offshore drilling rigs may operate at water depths exceeding 10,000 feet. When operating with a floating drilling unit (such as a drill ship or a semisubmersible drilling rig), the blowout preventers (BOPS) are generally located on the seafloor (rather than on the rig). The region between the BOP and the drilling rig is bridged by a series of large diameter tubes that are mechanically coupled to one another and make up the drilling riser.

During a drilling operation the drill string is deployed in the drilling riser, with drilling fluid occupying the annular region between the drill string and the riser wall. Drilling fluid (referred to in the art as mud) is pumped down through the drill string and flows out into the wellbore via jets in the drill bit. The drilling fluid serves numerous functions including lifting cuttings to the surface, lubricating the drill string and drill bit, providing power to downhole tools, and providing the pressure necessary to prevent blowouts. The drilling fluid also serves as a physical channel for transmitting mud pulse telemetry communications signals to the surface.

In deepwater and ultra-deepwater wells, the mud pulse telemetry rate is often very slow due the low signal to noise ratio (caused, for example, by the total well depth, the water depth, the mud properties, and the pump noise). In very deep wells, the mud pulse telemetry signal to noise ratio may be so low that mud pulse telemetry becomes impractical or even impossible. Therefore, there is a need in the art for an improved mud pulse telemetry system and method, particularly, for use in offshore wells.

SUMMARY

A mud pulse telemetry system is disclosed. The system includes a mud pulse telemetry transmitter deployed in a drill string which is in turn deployed in a drilling riser coupled to an offshore drilling rig. At least one annular pressure sensor is deployed on the drilling riser and is configured to sense mud pulse telemetry signals in an annular region of the drilling riser. A surface processor is in electronic communication with the annular pressure sensor via an electrical transmission line that extends along a length of the drilling riser from the annular pressure sensor to the drilling rig. The processor is configured to decode mud pulse telemetry signals transmitted by the mud pulse telemetry transmitter.

A mud pulse telemetry method is also disclosed. The method includes using the mud pulse telemetry transmitter to transmit a series of pressure pulses in the drill string. The transmitted pulses are detected in an annular region of the drilling riser using the annular pressure sensor. The detected pressure pulses are then transmitted to the surface processor via the electrical transmission line where they are decoded.

The disclosed embodiments may provide various technical advantages. For example, disclosed embodiments may significantly increase the mud pulse telemetry signal to noise ratio in offshore wells having drilling risers which may in turn increase the telemetry data rate. The improved signal to noise ratio may further enable mud pulse telemetry methods to be used at greater water and well depths where the use of conventional mud pulse telemetry techniques may be severely limited or even impossible. Moreover, the disclosed embodiments may significantly reduce the effect of mud pump noise on mud pulse telemetry communications.

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.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts a floating offshore drilling rig employing a prior art drilling riser.

FIG. 2 depicts one example of an intelligent drilling riser.

FIG. 3 depicts a cross sectional view of a disclosed riser section employed in the drilling riser shown on FIG. 2.

FIG. 4 depicts a detailed view of adjacent riser sections connected to one another.

FIG. 5 depicts mud pulse telemetry signal propagation in a drill riser.

FIG. 6 depicts a flow chart of one disclosed method embodiment.

FIGS. 7 and 8 depict acoustic wave transmission and reflection at drill string diameter transitions.

FIG. 9 depicts an example well schematic for an ultra-deepwater well.

FIG. 10 depicts an intelligent riser section including first and second annular pressure sensors.

FIG. 11 depicts mud pump noise in the example well schematic of FIG. 9.

FIGS. 12A and 12B depict example pressure sensor arrays obtained by connecting multiple riser sections.

FIG. 13 depicts an example transformation from the TZ plane to the FK plane.

FIG. 14 depicts example acoustic waves in the FK plane.

FIG. 15 depicts an example FK filter in the FK plane.

FIG. 16 depicts an example BHA including additional flow ports located below a telemetry tool.

FIG. 17 depicts an example BHA including additional flow ports located above a telemetry tool.

DETAILED DESCRIPTION

FIG. 1 depicts a floating offshore drilling rig 30 (also referred to as a modular offshore drilling unit MODU) employing a prior art drilling riser 40. During a conventional drilling operation, drilling fluid (commonly referred to as “mud”) is pumped downhole through a drill pipe 32 and various drilling tools before flowing out into the wellbore through jets mounted in the drill bit (not shown). In the region of the wellbore located below the sea floor 28, the mud carries cuttings back to the drilling rig in the annular space between the drill pipe and the borehole or casing. In the region between the sea floor 28 and the drilling rig 30, the drill string (and therefore the mud and cuttings) are contained in the drilling riser 40. The drilling riser is coupled to the blow out preventer (BOP) 35 at well head 34 via a lower marine riser package (LMRP) 36 and a lower flex joint 37, which allows the drilling riser to be tilted at a small angle (if necessary). The drilling riser 40 is generally connected to the drilling rig 30 (e.g., a floating rig) via a telescoping riser slip joint 42 configured to accommodate heave and tide. The drilling riser 40 is generally maintained under tension to provide a mostly straight and vertical alignment (referred to in the art as a top tensioned riser). An upper flex joint 44 allows the slip joint 42 to be offset slightly from vertical.

The drilling riser 40 is commonly made up of a large number of coupled riser sections 50 (e.g., clamped or bolted to one another as shown at 51). Individual riser sections are commonly very large and heavy. For example, each riser section 50 may be up to about 90 feet long, such that a water depth of 10,000 feet can require over 100 riser sections. A large central tube (also referred to as the riser tube) receives the drill string 32 (FIG. 1) and the return flow of drilling mud. The central tube generally has a diameter significantly greater than that of the drill pipe, for example, a 21 inch outer diameter and a 19.5 inch inner diameter (as compared to a 4 to 8 inch OD drill string). Prior art riser sections commonly include flanges located at their axial ends for connecting to one another. The riser sections may further include a number of smaller high pressure hydraulic auxiliary tubes rigidly connected to the flanges. These auxiliary tubes may include kill, choke, and boost lines and generally have a diameter in a range from about two to six inches.

During make-up of a riser string (the drilling riser 40), the riser sections that have already been made-up may be suspended below the rig floor (e.g., in the sea), with the box end of the central tube facing upwards. The next riser section is brought up in the derrick with the pin end of the central tube facing downwards. Upon alignment of the box and pin ends of the riser tube (as well as the box and pin ends of the auxiliary tubes), the upper riser section is lowered until fully engaged with the made up string. The flanges may then be bolted together. The presence of the hydraulic lines does not interfere with assembling or disassembling, and hence does not generally add to the tripping time. Since three or more auxiliary lines are commonly employed, mechanical alignment of these tubes is critical thereby requiring very tight manufacturing tolerances.

Commonly assigned, co-pending U.S. Provisional Patent Application Ser. No. 62/242,091, which is incorporated by reference herein in its entirety, discloses an intelligent riser that includes a high speed two-way communication system employing inductive couplers at each of the flange couplings. The intelligent riser may further include a plurality of sensors distributed axially along the length of the riser. The communication system may provide electronic communication between the sensors and a surface electronics module located on the rig.

FIG. 2 depicts one example of an intelligent riser 60. Intelligent riser 60 is similar to riser 40 in that it includes a number of riser sections 80 coupled end to end (e.g., via bolting or clamping as described above with respect to FIG. 1). Intelligent riser 60 differs from riser 40 in that it includes a high speed two-way communication system 65 (also referred to as the transmission line or riser transmission line) employing inductive couplers (not shown on FIG. 2) at each of the flange couplings. Intelligent riser 60 further includes a plurality of sensors 62 distributed axially along the length of the riser. The communication system 65 provides electronic communication between the sensors 62 and a surface electronics module 64 located on the rig. The series of cables and inductive couplers (that make up riser transmission line 65) may terminate at the top of the upper most riser section. A flexible electrical cable 66 may be used to connect the communications system 65 with the surface electronics thereby bypassing the riser slip joint.

As described in more detail below, the inductive couplers may be mounted at the axial ends of each drilling riser section and provide an electromagnetic coupling between riser sections. Such a construction greatly simplifies the operations of running and retrieving drilling risers compared to a fully hard wired system. The inductive couplers may be configured to automatically align and may be mated together in a manner similar to the auxiliary lines. Thus, no additional efforts or rig time are required during a trip (e.g., adding or removing riser sections).

FIG. 3 depicts a cross sectional view of one riser section embodiment 80. The box end 82 of the riser section 80 includes a recessed half-coupler 92 located in the flange 98. The pin end 84 of riser section 80 includes a corresponding half-coupler 94 located in the opposing flange 99. As depicted, half-coupler 94 includes a nipple 96 (or pin) for automatically coupling with the corresponding half-coupler 92 located on an adjacent riser section 80. An electrically conductive cable 75 (also referred to more broadly as an electrically conductive segment) is electrically connected to the half-couplers 92 and 94 (e.g., via cable clamps 95) and extends the length of the riser section 80. The cable may include two or more conductors (not shown), for example, in the form of a coaxial cable or twisted pair. The cable may be armored with steel (e.g. as in wireline cable), or may be a rigid or semi-rigid cable. The cable may be strapped to the central tube 85, or located under the flotation (in riser section embodiments employing such flotation). The cable clamps 95 are intended to physically secure the cables 75 and provide an electrical connection with the inductive couplers 92, 94. When the intelligent riser 60 is being assembled during a trip-in, the half inductive couplers 92, 94 are configured to automatically connect with the corresponding couplers located on adjacent riser sections (e.g., as depicted on FIG. 4).

During a drilling operation, drilling fluid is pumped downhole through the drill string (which is located in the central tube of the riser) and flows out through jets mounted in the drill bit. The mud carries cuttings up the annular space between the drill string and the borehole or casing, in returning mud and cuttings to the drilling rig. In the region between the sea floor and the drilling rig, the mud and cuttings are contained in the annular region of the drilling riser.

As is known to those of ordinary skill in the art, the mud serves many functions in drilling the well, for example, including preventing blowouts by keeping borehole pressure greater than formation pressure, lifting cuttings to the surface, lubricating the drill string and drill bit, and providing hydraulic power to downhole equipment such as drilling tools or measurement while drilling (MWD) or logging while drilling (LWD) tools. A mud pump is commonly connected to the drill string via a standpipe, swivel, and top drive and pumps the drilling fluid down through the interior of the drill string as described above.

The use of MWD and LWD tools is ubiquitous in offshore drilling operations. Common downhole measurements include borehole direction and inclination, drill collar shocks, borehole pressure, borehole diameter, and various formation properties, including, for example, natural radioactivity, resistivity, porosity, lithology, saturating fluids' properties, rock mechanical strength, rock stress, acoustic velocity, etc. In many wells, the primary means for transmitting data from MWD and LWD tools to the surface is via a mud pulse telemetry communication link. As is known to those of ordinary skill, data is encoded in fluid pressure waves that travel inside the drill string to the surface, where they are detected by pressure sensors mounted on the standpipe (or other surface locations).

A mud pulse telemetry transmitter may create pressure pulses, for example, by intermittently restricting the flow of the drilling mud. One known mud pulse telemetry transmitter employs a rotary modulator (often referred to in the art as an MWD tool, an MWD telemetry tool, and an MWD siren) that produces a sinusoidal pressure wave (a carrier wave) having a frequency in a range, for example, from about 5 to about 20 Hz. The transmitted data may be encoded via phase modulation of the pressure wave, for example, via quadrature phase-shift keying (QPSK) in which phase shifts of 45, 135, 225, and 315 degrees correspond to binary values of (0,0), (0,1), (1,0), and (1,1). In such embodiments there are commonly four cycles between each phase shift such that a frequency of 12 Hz corresponds to a data transmission rate of six bits per second.

The signal to noise ratio is known to have a significant effect on the data transmission rate. For example, in QPSK, the signal to noise ratio must be sufficiently high to resolve the phase shift into one of the four quadrants. In general, the more cycles between phase shifts, the better the signal to noise ratio, but the lower the data transmission rate. To achieve a desired data rate B, the number of cycles between bits N_c may be expressed mathematically as N_c=2 f/B (where f represents the frequency of the transmitted pressure wave). In low signal to noise circumstances, the data rate may be reduced to allow more measurement time between bits. Signal processing may also be employed to improve the bit rate. The signal to noise ratio may be influenced by the magnitude of both the signal and the noise.

The transmitted signal is attenuated as it propagates upwards in the drill string, for example by internal friction in the drill string and by reflections due to changes in the internal areas of the drill collars, the drill pipe, and any other hardware in the drill string. In deepwater and ultra-deepwater wells, cold sea water between the sea floor and the surface increases the viscosity of the drilling mud and thereby increases attenuation in the drilling riser. Such signal attenuation negatively impacts the signal to noise ratio.

The mud pump tends to be the predominant source of noise in the mud pulse telemetry channel. The noise can be particularly strong in the standpipe (where the mud pulse signal is commonly measured) as the pressure sensors are located close to the mud pump. Numerous techniques may be employed to mitigate the pump noise. For example, a second pressure sensor may be located close to the pump to sample the noise. Software algorithms may be employed to filter/remove the pump noise from the remote (and highly attenuated) signal. Multiple spaced apart pressure sensors may also be deployed on the standpipe. Cross correlation of the detect signals may enable the noise and signal to be separated based upon the travel direction of the detected signals (noise tends to propagate in a downhole direction while the signal tends to propagate in an uphole direction). Such methodologies can improve signal to noise.

In many mud pulse telemetry operations, telemetry bandwidth is limited by the mud pump noise. Even with the use of multiple sensors and the above mentioned cross correlation techniques, telemetry bandwidth can be severely limited, especially for deepwater operations. One aspect of the instant disclosure is the realization that in certain embodiments the mud pulse telemetry signal to noise ratio may be improved by detecting the mud pulse telemetry signal in the annular region exterior to the drill string.

Turning now to FIG. 5, it will be understood that when the downward flow of drilling fluid is interrupted to generate the mud pulse telemetry signal (e.g., by rotation of the rotor in a mud siren) positive pressure pulses are created in the drill string above the telemetry tool. These positive pressure pulses propagate upwards inside the drill string to the MODU and are detected in the standpipe. Corresponding negative pressure pulses are also generated below the telemetry tool (e.g., the siren) that travels downward towards the drill bit. These negative pressure pulses propagate into the borehole through nozzles in the drill bit and uphole in the annular region between the drill string and the borehole wall. This annular region includes an open hole region, a cased (lined) region, and a region including the drilling riser.

FIG. 6 depicts a flow chart of one example mud pulse telemetry method embodiment. Mud pulse telemetry method 100 includes deploying a drill string in a drilling riser and an offshore well at 102. The drill string includes a mud pulse telemetry tool (such as an MWD siren). Mud pulse telemetry pressure pulses are generated at 104 and received at 106 using at least one annular pressure sensor deployed in a drilling riser. The received pressure signal(s) may then be transmitted at 108 to a surface processor using a drilling riser transmission line (e.g., as described above with respect to riser 60). The pressure pulses may then be decoded at 110 at the surface processor.

A simplified mud pulse telemetry model is presented to aid understanding of the disclosed embodiments. Pressure waves in the drill string and annulus may be approximated as plane waves which satisfy the following wave equation:

$\begin{array}{cc}\frac{{\partial }^2P\left(z,t\right)}{\partial t^2}+c^2\frac{{\partial }^2P\left(z,t\right)}{\partial z^2}=0& \left(1\right)\end{array}$

where P(z, t) represents the pressure, c represents the pressure wave velocity, t represents time, and z represents the dimension along the axis of the drill pipe (i.e., the z-axis). It will be understood that Equation 1 is only strictly valid in an unbounded medium and is an approximation for pressure waves in a pipe (drill string). As is known to those of ordinary skill in the art, pressure is the relevant quantity which is measured by the pressure sensors. The phase velocity in mud may be approximated as follows: c=√{square root over (B/ρ)} where B represents the bulk modulus and ρ represents the density of the drilling fluid.

Solutions to the wave equation may be expressed as exponential functions, for example, of the following form:

P(z,t)=P⁺e^j(ωt−kz)+P⁻e^j(ωt+kz)   (2)

where ω=2πf (with f being the frequency) and k=ω/c represents the propagation constant. The constants P⁺ and P⁻ represent complex amplitudes for forward and backward propagating pressure waves. Volume velocities U⁺=P⁺/Z and U⁻=P⁻/Z (where Z represents the acoustic impedance) may also be defined. For pressure waves in a tube with constant cross-sectional area (Z=cρ/A), it will be understood that P, U, and Z are analogous to the voltage, current, and characteristic impedance for an electromagnetic transmission line.

When a forward propagating pressure wave P₁⁺e^j(ωt−kz) encounters a change in impedance (e.g., due to a change in cross-sectional area of the drill string as depicted on FIG. 7), a reflected pressure wave P₁⁺e^j(ωt−kz) propagates in the reverse direction and a “transmitted” pressure wave P₂⁺e^j(ωt−kz) continues in the forward direction. The reflected and transmitted waves may be related to the original forward propagating wave, for example, as follows: P₁⁻=ΓP₁⁺ and P₂⁺=TP₁⁺, where:

$\begin{array}{cc}\Gamma =\frac{\begin{array}{cc}{Z}_2& Z_1\end{array}}{Z_2+Z_1}=\frac{\begin{array}{cc}{A}_1& A_2\end{array}}{A_1+A_2}& \left(3\right)\\ T=\frac{2Z_2}{Z_2+Z_1}=\frac{2A_1}{A_1+A_2}& \left(4\right)\end{array}$

where Γ and T represent reflection and transmission coefficients and A₁ and A₂ represent cross sectional areas of first and second axial regions of the drill string through which the pressure wave propagates.

Consider a special case in which A₂=0 corresponding to a hard termination. In such a case, Γ=1 and the pressure in region 1 is P₁(z, t)=P₁⁺e^jωtcos(kz). Hence, the pressure signal is approximately doubled when k|z|1. This special case corresponds to the pressure sensor in the standpipe, with the mud pump providing the hard termination. Conversely, when k|z|≈π/2 the pressure signal tends to be small. If there is a soft termination, i.e., when A₂A₁, then Γ=1 and the pressure in region 1 is P₁(z, t)=2jP₁⁺e^jωtsin(kz). When k|z|1 the pressure signal tends to be greatly reduced. This situation roughly corresponds to placing the pressure sensor in the annulus at the surface, with atmospheric pressure in the annulus and an air-mud interface. In general, standing waves are established whenever there is a change in impedance.

FIG. 8 depicts a scenario in which there are three regions having differing areas. In such a scenario, the reflection and transmission coefficients further depend on the finite length L of the central region. The reflected and transmitted waves may be related to the original forward propagating wave, for example, as follows: P₁⁻=ΛP₁⁺ and P₃⁺=TP₁⁺, where:

$\begin{array}{cc}\Lambda =\frac{\begin{array}{cc}(Z_2Z_3& Z_1Z_2)\cos \left(\mathrm{kL}\right)+j\begin{array}{cc}(Z_2^2& Z_1Z_3)\sin \left(\mathrm{kL}\right)\end{array}\end{array}}{\left(Z_2Z_3+Z_1Z_2\right)\cos \left(\mathrm{kL}\right)+j\left(Z_2^2+Z_1Z_3\right)\sin \left(\mathrm{kL}\right)}& \left(5\right)\\ T=\frac{2Z_2Z_3\left[\cos \left(\mathrm{kL}\right)+j\sin \left(\mathrm{kL}\right)\right]}{\left(Z_2Z_3+Z_1Z_2\right)\cos \left(\mathrm{kL}\right)+j\left(Z_2^2+Z_1Z_3\right)\sin \left(\mathrm{kL}\right)}& \left(6\right)\end{array}$

When the central region is very short (such that kL1), the reflection and transmission coefficients may be approximated, for example, as follows:

$\begin{array}{c}\Gamma =\frac{\begin{array}{cc}{Z}_3& Z_1\end{array}}{Z_3+Z_1}\\ T=\frac{2Z_3}{Z_3+Z_1}\end{array}$

It will be appreciated that the above described wave equations are lossless (i.e., not accounting for any friction effects between the fluid and the various fluid contact surfaces. The above described wave equations may be modified to include frictional losses, for example, via incorporating a loss coefficient a as follows:

(z, t)=P⁺e^{j(ωt−kz)−az}+P⁻e^j(ωt+kz)+az   (7)

where a represents the loss coefficient and is given as follows for fluid in a pipe (e.g., a drill string):

$\begin{array}{cc}\alpha =\frac{1}{\mathrm{ca}}\sqrt{\frac{\mathrm{\omega \mu }}{2\rho }}& \left(8\right)\end{array}$

and where μ represents the mud viscosity in PaS units and α represents the inner radius of the pipe. Note that attenuation is inversely proportional to the radius such that there is generally less attenuation in large diameter pipes. In the annular region, friction occurs on both the outside of the drill string and the inside of the borehole such that the loss coefficient may be expressed, for example, as follows:

$\begin{array}{cc}\alpha =\frac{1}{c\begin{array}{cc}(b& a\end{array})}\sqrt{\frac{\mathrm{\omega \mu }}{2\rho }}& \left(3\right)\end{array}$

where b represents the inner radius of the borehole (or casing string or drilling riser) and α represents the outer radius of the drill string. The phase velocity in a steel pipe c_p is generally slightly slower than in an unbounded medium and may be expressed, for example, as follows:

$\begin{array}{cc}{c}_p=\frac{c}{\sqrt{1+\frac{\mathrm{BD}}{\mathrm{Ee}}\begin{array}{cc}(1& {\mu }^2)\end{array}}}& \left(10\right)\end{array}$

where E represents the elastic modulus (Young's modulus) of the steel pipe, μ represents the Poisson's ratio of the steel, D represents the pipe diameter and e represents the wall thickness.

Various disclosed embodiments are now described in more detail by way of the following example which is intended to be an example only and should not be construed as in any way limiting the scope of the claims. FIG. 9 depicts one example ultra-deepwater well including a wired riser 120. As depicted, the drilling riser 120 includes at least one pressure sensor 122 configured to measure drilling fluid pressure in the annular region between the drill string 130 and the riser body 150. The pressure sensor 122 is preferably (although not necessarily) located near the bottom of the riser (e.g., the lower end of the riser may be defined as being in the lowermost 1000 feet of the drilling riser) and is used in a hybrid telemetry system that exploits the wired riser described above to improve the mud pulse telemetry rate. The pressure sensor(s) 122 may be attached to the outer surface of the riser body 150 and have hydraulic communication with the riser ID via a small hole 151 (e.g., as depicted on FIG. 10). In the embodiment depicted on FIG. 10, pressure sensors 122A and 122B are in electronic communication with an electronics package 124 deployed in-line with the transmission line 65 (e.g., as described in more detail in U.S. Provisional Patent Application 62/242,091). The received pressure signals may be digitized by the electronics package and transmitted to the surface (the MODU) via the wired riser communication system 120. The pressure sensor(s) 122, 122A, 122B may include, for example, piezoelectric transducers or hydrophones. As is known to those of ordinary skill in the art, piezoelectric pressure sensors generally measure absolute pressures and pressure waves while hydrophones generally measure pressure fluctuations. As such, hydrophones tend to be more sensitive to small variations in pressure than piezoelectric sensors. Notwithstanding the above, the disclosed embodiments are expressly not limited to any particular pressure sensor technology.

FIG. 9 depicts a well schematic (a model well) in which the BOP 35 is located 10,000 ft. below the sea surface. Such wells tend to be quite complex with many sections of casing and liners. Example sections are depicted and described in more detail below in Table 1 (Table 1 has converted the units from SI to English.) The drilling fluid properties and the mud pulse telemetry signal are described in more detail in Table 2.

TABLE 1
		Section	Bottom	Annulus &
Well Section OD	ID	Length	Depth	DP Area	T
21′ riser	19.00	in	10,000	ft	10,000 ft	249	in2	NA
18⅝″ casing	17.78	in	4,000	ft	14,000 ft	214	in2	0.92 (−0.7 dB)
16″ liner	15.01	in	3,000	ft	17,000 ft	143	in2	0.80 (−1.9 dB)
13⅝″ liner	12.38	in	3,000	ft	20,000 ft	86	in2	0.75 (−2.5 dB)
11⅞″″ liner	10.71	in	2,000	ft	22,000 ft	56	in2	0.79 (−2.1 dB)
9⅞″ liner	8.63	in	3,000	ft	25,000 ft	24	in2	0.61 (−4.4 dB)
8¼″ open hole	8.25	in	1,000	ft	26,000 ft	19	in2	0.89 (−1.1 dB)
MWD tool	3	in	30	ft	26,000 ft	7	in2	0.54 (−5.4 dB)
(7.00″ OD)
5⅞″ drill pipe	5.88	in	26,000	ft	NA	27	in2	0.41 (−7.7 dB)
(6.60″ OD)

TABLE 2
Mud density ρo = 1800 kg/m3 Mud bulk modus: B = 1.9 × 109 N/m2
(15 ppg)
Siren frequency: f = 12 Hz  Phase velocity: c = 1027 m/S
Wavelength: λ = 85.6 m      Propagation constant: k = 7.34 × 10−2 m−1
Mud viscosity at seawater   Mud viscosity at downhole temperature:
temperature: μ = 40 centi-  μ = 20 centipoise (0.020 PaS)
poise (0.040 PaS)

An MWD rotary modulator 135 (MWD siren) located near the bottom of the well (just above the drill bit 132) generates a 12 Hz phase modulated signal inside the drill string. The pressure wave is created by cyclically blocking the mud flowing through the MWD tool 135 (for example as described above). When the flow path is blocked, a positive pressure pulse 142 appears on the uphole side of the rotary modulator (siren), and a negative pressure pulse 144 appears on the downhole side of the siren. The positive pressure pulse 142 propagates upwards inside the drill pipe to the MODU, where it is detected by the pressure sensors in the standpipe. The negative pressure pulse 144 travels down through the MWD tool, passes through the nozzles of the drill bit 132 and then travels upward in the annulus between the well bore and the drill pipe 130. It may be detected by the pressure sensors 122 located on the riser.

Signal attenuation of the positive and negative pressure pulses 142, 144 may be computed due to (i) changes in cross sectional area and (ii) mud viscosity. Mud viscosity increases with decreasing temperature, so this simplified model assigns a low viscosity for the earth region and a higher viscosity for the seawater region.

Attenuation due to cross sectional area changes is considered first. The positive pressure wave that travels upward inside the drill pipe encounters small changes in the inner diameter at each tool joint (drill string connector). The effect of these area changes can be shown to be negligible. For example, 5⅞ inch drill pipe with XT57 connections has a 5.88 inch ID in the pipe section, and a 4.25 inch ID in the tool joint. The total length of the 4.25 inch ID tool joint section (pin plus box) is 47 inches. The transmission coefficient may be computed using Equation (5) and yields |T|=0.9998, which is negligible. Moreover, as is known those of ordinary skill in the art, the ID of the drill string includes a gradual taper between at each tool joint, which tends to further reduce reflections.

Similarly, the negative pressure wave in the annulus tends not to be affected by the external diameter of the tool joint. The drill pipe body OD is 6.60 inches, while the tool joint OD is 7.00 inches. The total length of the tool joint OD is 27 inches (pin plus box). Based on Equation 6, the transmission coefficient over the tool joint may be computed to be |T|=0.9999 in the smallest hole section (8.25 inches). Based on the foregoing, internal and external changes in drill pipe diameters at the tool joints may be ignored.

The transmission coefficient of the positive pressure pulse from the bore of the MWD rotary modulator (having a 3 inch ID) to the bore of the drill string (5.88 inch ID) may be computed to be |T|=0.41 (−7.7 dB) based on Equation 4. The transmission coefficient of the negative pressure pulse from the bore of the MWD rotary modulator through the drill bit nozzles (e.g., five nozzles with 0.25 inch bores by 1 inch long) and into the 8.25 inch borehole may be computed to be |T|=0.54 (−5.4 dB) using Equation 6. The computed transmission coefficient values are also given in Table 1.

The negative pressure pulses in the annulus experience multiple diameter transitions from the borehole to the drilling riser. The rightmost column in Table 1 lists the transmission coefficients resulting from the listed area changes. For example, the transition from 18⅝ casing to the 21 inch riser has a transmission coefficient of 0.92 (−0.7 dB). Neglecting standing waves for the moment, the product of the transmission coefficients gives an estimate of the attenuation due to the changes in areas for the two signal paths. From the MWD telemetry tool 135 to the standpipe pressure sensor(s) 175, the net attenuation is −7.7 dB due to the transition from the telemetry tool 135 to the drill pipe. From the telemetry tool 135 to the bottom of the drilling riser 120, the annular attenuations sum to −18.0 dB. Based on this example, it appears that the annular path tends to be more influenced by geometrical changes than the inside of the dill string.

However, as mentioned above, the changes in diameter represent only a portion of the total signal attenuation for the two paths. The mud viscosity produces frictional losses with the drill pipe, borehole, and casing. According to Equations 8 and 9, the frictional losses decrease with an increasing ratio of the area to the circumference.

The MWD siren 135 to standpipe sensor 122 has two sections, from the bit to the sea floor, and from the sea floor to the MODU. The subsurface borehole temperature is known to increase by about 20-30 C/km in the Gulf of Mexico. At 5 km depths, the bottom hole temperature can be over 100 C. The seawater temperature near the sea floor will be quite low, a few degrees C., while the surface temperature might be 20 degrees C. The mud viscosity varies with temperature and therefore with depth. For simplicity, two values for the mud viscosity are used in this example, μ=20 centipoise in the subsurface, and μ=40 centipoise in the sea (drilling riser). Equation 8 may be used to compute the loss coefficient for each of these regions. For the drilling riser region, the loss coefficient may be computed to be α=3.77×10⁻⁴ m⁻¹. The attenuation due to viscosity over this region was thus computed to be 0.317 (−10 dB). The loss coefficient in the subsurface region was computed to be α=2.67×10⁻⁴ m⁻¹. The attenuation due to viscosity in the subsurface region was thus computed to be 0.272 (−11.30 dB) yielding a total attenuation due to friction of −21.3 dB and total overall attenuation of approximately −29.0 dB.

The loss coefficient in the annulus may be computed for each section of casing using Equation 9. The attenuation in the annulus is largest in the open hole section since the borehole diameter is the smallest. In addition, additional loss mechanisms may be present in the open hole, such as pressure lost to permeable formations or the presence of a high load of cuttings. These other losses are formation dependent, and are not included in this model for simplicity. Table 3 lists the loss coefficients and corresponding attenuation for each section of the wellbore. The total attenuation due to mud viscosity is 0.216 (−15.8 dB) from the MWD siren 135 to the bottom of the drilling riser 120 (from 26,000 ft. to 10,000 foot depth in this example). Including the −18 dB due to area changes gives a total attenuation of −33.8 dB from the MWD siren 135 to the bottom of the riser 120 via the annulus. This is slightly greater attenuation (by about 4.8 dB) than that computed for the MWD siren 135 to the standpipe 172 via the inside of the drill string 130. If the annulus pressure sensors are located near the sea surface, an additional 4.7 dB of attenuation occurs due to mud viscosity. The total attenuation for the annulus path from MWD siren 135 to sea surface is then −38.5 dB.

TABLE 3
Well Section OD	Section Length	Loss Coefficient	Attenuation
21′ riser	10,000	ft	1.79 10−4 m−1	−4.7 dB
18⅝″ casing	4,000	ft	1.40 10−4 m−1	−1.5 dB
16″ liner	3,000	ft	1.87 10−4 m−1	−1.5 dB
13*⅝″ liner	3,000	ft	2.72 10−4 m−1	−2.2 dB
11⅞″″ liner	2,000	ft	3.82 10−4 m−1	−2.0 dB
9⅞″ liner	3,000	ft	7.75 10−4 m−1	−6.2 dB
8¼″ open hole	1,000	ft	9.51 10−4 m−1	−2.5 dB

An MWD siren commonly generates a pressure wave having an amplitude of about 500 psi. Thus, in this example, the signal in the standpipe may be computed to have an amplitude of about 18 psi (S=500×10^−29.0/20≈18). Likewise, the signal amplitude in the annulus may be computed to be about 10 psi (S=500×10^−33.8/20≈10) at the lower end of the drilling riser and 6 psi (S=500×10^−38.5/20≈6) at the surface.

In order to compute a signal to noise ratio the pump noise may also be considered. Propagation of pump noise 165 is depicted on FIG. 11. As depicted, the pump noise propagates through the standpipe 172, downhole through the inside of the drill pipe 130, through the MWD telemetry tool 135 and drill bit 132, and uphole through the annulus 155 from the drill bit 132 to the riser 120. Mud pump noise 165 may be attenuated in a similar manner to the MWD signal (e.g., via friction and pipe diameter changes). Thus in this example (as computed above), the mud pump noise is attenuated as it propagates from the standpipe to the MWD tool via the drill pipe ID by about −29.0 dB and as it propagates from the MWD tool to the bottom of the drilling riser via the annulus by an additional −33.8 dB (for a total attenuation of −62.8 dB).

Assuming that the mud pump noise in the telemetry band is about 15 psi in the standpipe 172 yields a signal to noise ratio at the standpipe pressure sensors 175 of about 1.2 (1.6 dB) (SNR_sp= 18/15=1.2). As is known to those of skill in the art, a mud pulse telemetry system operating at such a low signal to noise ratio may be highly susceptible to data errors. In contrast to the mud pump noise in the standpipe, the noise in the annular region of the drilling riser is miniscule. For example, owing to attenuation, the mud pump noise in this example may be computed to be about 0.01 psi at the downhole end of the drilling riser 120 (N=15×10^{−6 28/20}≈0.01). The signal to noise ratio may then be computed to be about 1000 (60 dB) at the lower end of the drilling riser (SNR_an=10/0.01≈1000). The signal to noise ratio at the top of the riser may also be computed to be about 60 dB since the MWD signal and the mud pump noise are both equally attenuated in the annular region of the riser.

This example demonstrates that a significant reduction in mud pump noise may be achieved via using pressure sensors in the drilling riser (as described in the present disclosure). Moreover, based on this example, it will be understood that the pressure sensors 122 may be profitably deployed substantially anywhere along the drilling riser. Locating the pressure sensors near the sea floor provides a larger signal pressure, but requires the use of wired riser sections along the full length of the riser. Locating the sensors near the surface results in a slight loss of signal pressure, but with an equal signal to noise ratio and requires only a short section of wired riser.

It will be understood that the above described example may be expanded to consider other propagation pathways for the mud pump noise. For example, mud pump vibration may cause drill string to vibrate in the telemetry band. Another noise path may include radial expansion and contraction of the drill string caused by the mud pump noise. These pathways, while possible, are generally believed to be insignificant in comparison to noise propagation in the drill string and annulus as described above. Moreover, the above described example may also be expanded to account for other noise sources unrelated to the mud pump(s). For example, drill pipe rotation at 180 RPM corresponds to 3 Hz such that the 4th harmonic might be in the vicinity of a 12 Hz carrier signal. While other noise sources are sometimes of concern they are commonly insignificant in comparison to the mud pump noise.

While signal to noise ratio considerations indicate that pressure sensors may be advantageously deployed at substantially any location along the length of the drilling riser, other factors may need to be considered. For example, reflection of the telemetry signal at the top of the riser may generate standing waves in some embodiments. As described above with respect to Equation 3, the reflection coefficient Γ=1 at a mud-air interface such that any signal moving upwards in the annulus tends to be reflected downwards at the top of the riser. Moreover, pressure waves moving downwards in the annulus may be reflected upwards at the locations of each change in well diameter (however these reflected waves are generally small, e.g., having a reflection coefficient less than about 0.1).

Based on the foregoing, the reflected telemetry signal at the top of the riser may be of the form: P(z, t)=P₀e^jωte^αzsin(kz), where P₀ is a constant and α=1.79×10⁻⁴ m⁻¹ for the riser, and k=7.34×10⁻² m⁻¹ (in keeping with the previous example). Such a reflected wave may result in a standing wave pattern in the riser annulus in which the signal pressure is equal to zero (P(z, t)=0) at quarter wavelength multiples (i.e., when kz=nπ at integer values of n). Likewise the pressure signal is at a maximum when kz=(n+½)π at integer values of n.

In order to ensure that a drilling riser pressure sensor 122 is not deployed at a location of the signal minimum (the minimum of the standing wave) it may be advantageous to employ at least first and second axially spaced pressure sensors, for example, spaced at Δz=λ/4. In the example wellbore described above, such sensors may be spaced by about 20 meters (however the exact spacing is not critical). In such an embodiment the largest signal may be decoded or the both signals may be added. Both sensors may be deployed on a single riser section, for example, as depicted on FIG. 10 in which a 27 meter riser section 180 includes first and second pressure sensors 122A, 122B spaced by about 20 meters. The pressure sensors may be electrically connected with an electronics package 124 which is part of the wired riser system 65 previously described. The pressure signals from each sensor may be digitized for transmission to the surface. The disclosed embodiments are, of course, not limited to embodiments in which a riser section includes first and second pressure sensors.

It will be understood that other noise sources may be present (in addition to the previously described mud pulse noise. For example, locations of the standing wave pressure maxima and minima may vary with heave of the MODU, resulting in phase modulation. Moreover, the slip joint stroke may introduce pressure pulses in the annulus that propagate downward. Slip joint stroke can be 10 meters in large waves, possibly causing pressure variations of on the order of 15 psi in the annulus.

The use of a positive displacement motor (a “mud motor”) in the drill string may result in further noise. In such mud motors, the stator is commonly rigidly attached to the drill string while a rotor rotates the drill bit. Mud flowing through the open lobe in the stator creates a torque on the rotor, such that the rotor rotation rate depends on flowrate and the weight and torque on the drill bit. For example, a mud motor may be run at 120 RPM, thereby generating a fundamental frequency of f=2 Hz with corresponding harmonics. The use of such a mud motor may produce upwardly propagating pressure waves inside the drill pipe and in the annulus. As the mud pump flow rate varies, the noise will vary in frequency.

An array of pressure sensors spaced along the drilling riser may be used to increase the detection efficiency of the mud pulse telemetry signal and to further reduce noise. For example, an array of pressure sensors similar to the array of pressure sensors disclosed in commonly assigned U.S. Pat. No. 8,111,171 may be used (the '171 patent is fully incorporated by reference herein). The use of pressure sensors deployed in a linear array may enable various signal processing algorithms to be applied to improve the signal to noise ratio.

For example, in Vertical Seismic Profiling (VSP), velocity filtering is a known technique used to separate upward and downward propagating waves. A similar approach may be used to enhance the MWD signal (upwardly propagating) while decreasing surface noise that is downwardly propagating. The velocities of the pressure waves may be measured by calculating the coherence of pressure signals between spaced sensors. The signals from the various pressure sensors may be time-shifted and stacked to enhance the downward propagating noise. Once this noise is obtained, it may then be subtracted from each of the original pressure signals for each sensor. These “cleaned” signals may then be time-shifted and stacked to enhance the upwardly propagating telemetry signal.

Slowness Travel Time Coherence (STC) techniques similar to those used in acoustic logging operations may also be utilized. Such techniques make use of an array of acoustic sensors to detect, separate, and measure complex waveforms. Such processing can be adapted to separating mud pulse telemetry signals from mud motor noise, for example.

The sensor spacing in an array is preferably small enough to avoid aliasing (in space) of the shortest wavelength (e.g., less than a half-wavelength of the highest frequency component in the telemetry bandwidth). With QPSK encoding, the highest frequency tends to be 1.1 times the carrier frequency. Using the example in Table 2 (in which the carrier frequency is 12 Hertz, the velocity is 1027 meters per second, and the carrier wavelength is 85.6 meters) gives a high frequency component of 13.2 Hertz which implies a maximum sensor spacing of 39 meters. In the previous example of standing waves in the riser, an advantageous spacing between two pressure sensors was stated to be one-quarter wavelength (about 21 meters).

FIGS. 12A and 12B depict riser embodiments in which multiple adjacent riser sections 180 include first and second axially spaced pressure sensors 122A, 122B. For example, in FIG. 12A adjacent 27 meter riser sections each include two pressure sensors spaced by about 13.5 meters providing a sensor array having four sensors located at 0, 13.5, 27, and 40.5 meters. Such an array covers about one-half of one wavelength (depending on the signal frequency). FIG. 12B depicts a riser embodiment including first, second, and third adjacent riser sections 180 each of which includes two pressure sensors 122A, 122B providing an array with six pressure sensors. In the example embodiment depicted, the sensors are spaced by about 13.5 meters providing an array having six sensors located at 0, 13.5, 27, 40.5, 54, and 67.5 meters. It will, of course, be appreciated that substantially any number of additional sensors may be added in like manner. Moreover, is not necessary that the riser sections containing pressure sensors be adjacent. It is also not necessary for the pressure sensors to be equally spaced. The wired riser system allows for flexibility in locating an array of sensors.

It will be appreciated that not all noise is systematic (e.g. due to the mud pump). Some noise is random in nature (e.g. shot noise in the sensor electronics). Stacking the pressure signals measured by multiple sensors also allows one to reduce random noise as the square root of the number of sensors. For example, averaging four sensors may reduce random noise by a factor of 2 (6 dB) compared to the use of one pressure sensor. Returning to the discussion of VSP processing, an array of pressure sensors may be used for FK filtering. Suppose, for example, that N sensors are equally spaced at an interval of AZ such that the sensors are located at Z₀=0, Z₁=ΔZ, Z₂=2ΔZ, . . . , Z_N−1=(N 1)ΔZ. The signal at each sensor may be recorded at times T₀=0, T₁=ΔT, T₂=2ΔT, . . . , Z_M−1=(M 1)ΔT. The array of sensors thus generates M·N two dimensional data, p (m, n), where m=0, 1, 2, . . . , M 1 and n=0, 1, 2, . . . , N 1. Such two-dimensional data may be Fourier transformed into frequency wavenumber data P(u, v) for example, as follows:

$\begin{array}{cc}P\left(u,v\right)=\frac{1}{\mathrm{MN}}\sum _{m=0}^{M-1}\sum _{n=0}^{N-1}p\left(m,n\right)e^{-\mathrm{j2}\pi \left(\frac{\mathrm{mu}}{M}+\frac{\mathrm{nv}}{N}\right)}& \left(11\right)\end{array}$

where u=0, 1, 2, . . . , M 1 and v=0, 1, 2, . . . , N 1. Equation 11 is represented schematically in FIG. 13 where upward and downward propagating waves in the TZ plane are transformed to the FK plane. The use of such a methodology advantageously allows the data to be filtered in both frequency and wavenumber.

It will be understood that waves travelling along a drilling riser may fall along characteristic lines in the FK plane, for example, as depicted on FIG. 14 in which waves travelling upwards are in the positive half of the plane (right side) while waves travelling downwards are in the negative half (left side). Consider, for example, the characteristic line that passes through the point (K1, F1) and the origin (0,0). This line is oriented at an angle a with respect to the F-axis where a =arctan(K1/F1) and K1/F1 equals the velocity in the annulus C_an. The line may represent an upwardly propagating mud pulse telemetry wave in the annulus, for example. Similarly, the reflected downwardly propagating mud pulse wave may be represented by the characteristic line at the angle α. The large reflection coefficient at the mud-air interface tends to generate a strong signal at −α, similar in amplitude to the upwardly propagating mud pulse signal.

In an FK diagram (e.g., as depicted on FIG. 14), waves travelling at different velocities map along lines having different angles. For example, the pressure wave travelling inside the drill pipe may have a slightly different velocity than the wave travelling in the riser annulus due to temperature differences or cutting density differences as described above. FIG. 14 depicts one example of a slower wave traveling upwards at C₂. Waves propagating in the steel riser or drill pipe travel at a much higher velocity and may be isolated, for example, as depicted. Similarly, sea noise (e.g., due to low frequency vortex induced vibrations) traveling at lower velocities may also be isolated as depicted.

The application of FK processing to a drilling riser is now briefly explained. The acoustic velocity in the riser annulus is determined and defines an angle θ in the FK plane having an angular width δ as depicted on FIG. 15. The data P(u, v) is multiplied by a filter B(u, v) (e.g., by a filter having value of 1 in the wedge defined by θ and δ and a value of 0 elsewhere). Shaped filters may also be used to reduce aliasing. The angle θ is varied between θ δ/2 and θ+δ/2, corresponding to the lowest and highest possible velocities. At each value of θ, the inverse Fourier transform maps P(u, v)·B(u, v) back into the TZ plane, for example, as follows:

$\begin{array}{cc}\tilde{p}\left(m,n\right)=\frac{1}{\mathrm{MN}}\sum _{m=0}^{M-1}\sum _{n=0}^{N-1}P\left(u,v\right)·B\left(u,v\right)e^{-\mathrm{j2}\pi \left(\frac{\mathrm{mu}}{M}+\frac{\mathrm{nv}}{N}\right)}& \left(12\right)\end{array}$

where the root mean square (RMS) value of p(m, n) is computed over the array. The maximum RMS value provides the best estimate for the angle θ and therefore the best estimate for the annulus velocity C_an.

A frequency band filter (a pass band) may then be applied to the data in the wedge (i.e., to P(u, v)·B(u, v)). The frequency filter may be centered on the mud pulse carrier frequency f_c and may have a bandwidth that corresponds to the required bandwidth for the encoding scheme (see FIG. 15). The intersection of the frequency filter and the wedge results in a trapezoidal “box car” filter shown at 192. The data points in the trapezoidal filter 192 may then be inverse Fourier transformed back to the TZ plane. This final step may remove mud pump noise that propagates at the annulus velocity, but is outside the frequency band.

Alternative FK processing methods may be applied, for example to optimize the signal to noise ratio. In one example methodology, if the carrier frequency is unknown, or if the clock in the MWD telemetry tool has drifted, the frequency filter in the FK plane may be changed, for example, by incrementing the center frequency over a range of frequencies. A new box car filter may be applied, the results inverse transformed, and the RMS value of {tilde over (p)}(m, n) computed. The maximum RMS value may then be taken to give the best estimate of f_c (in a process similar to that described above for determining the velocity C_an).

With sufficient separation between signals in the FK domain, signal recognition and filtering may be performed as described above. It will be understood, however, that practical limitations on the number of sensors N, the sensor spacing ΔZ, and the sample time MΔT may tend to limit the resolution. In one embodiment, the sample time MΔT is preferably greater than or equal to the following quantity: 3N_c+NΔZ/C_an, where N_c represents the number of cycles between bits in the carrier signal.

After processing, the final waveforms in the TZ plane may then be decoded. The waveforms from individual sensors may be processed to determine the phase shifts, for example, via QPSK coding/decoding techniques. It will be understood that after FK filtering, the waveforms in the N sensors may include only upward traveling waves. The signals in each pressure sensor may be similar with the only significant difference being the arrival time (the time lag between adjacent sensors being about ΔZ/C_an). Time shifting and stacking the FK filtered data may be implemented to reduce random noise.

It will be further appreciated that standpipe sensors may be employed to measure the mud pump noise near the source. Such noise may be characterized and used to minimize the mud pump noise in the annular pressure measurements.

The use of a sensor array may also be used to decode pressure signals that are more complex in nature in comparison to the examples described above. For example, the drill string may include tool embodiments above and/or below the MWD telemetry tool that divert (port) drilling fluid to the annulus. Two examples of such tools include the Smith Rhyno™ under-reamer and the MI Swaco Well Commander™ bypass valve. Many other such devices that port drilling fluid to the annulus are known in the industry. When a Rhyno under-reamer is activated, some drilling mud is vented from the center bore of the under-reamer to the annulus through a flow port. Likewise, the Well Commander bypass valve allows mud to flow through ports into the annulus to improve cuttings transport. Either device provides a pathway for the pressure pulses to enter the annulus above the bit. Thus, the composite mud pulse signal in the annulus may have components from the bit ports and from the under-reamer or bypass valve (or other additional tools).

The signal that propagates through the bit originates as a negative pressure pulse at the telemetry tool as previously described. The signal that propagates through other ports in the drill string may be either positive (if located above the telemetry tool) or negative (if located below the telemetry tool). The two signals (one from the bit and the other from the additional tool) may thus add in-phase or out-of-phase. In addition, the path lengths from the telemetry tool to the annulus are different, and may have different attenuations. They may also have somewhat different spectrums due to dispersion. Ideally, the distance between the telemetry tool and the drill bit, and the distance between the telemetry tool and any other port (e.g., an under-reamer) can be selected such that the two mud pulse signals add in phase. In any event, array processing may improve the telemetry signal.

FIG. 16 depicts an example BHA 210 with additional flow ports 215 located below the telemetry tool 212. The flow ports 215 are located a distance L2 above the bit while the telemetry tool 212 is located a distance L1 above the bit 218. The path length from the telemetry tool 212 through the bit and back up the annulus to the flow port 215 is L1+L2 while the path length from the telemetry tool 212 through the device's flow port is L1 L2 such that the path length difference is 2·L2. In an embodiment in which L1=20 meters and L2=10 meters, the path length difference may be about 20 meters. Using the example propagation constant from Table 2, gives a phase difference between the two paths about π/2 (90 degrees).

FIG. 17 depicts an example BHA 220 with additional flow ports 225 located above the telemetry tool 212. The flow ports 225 are located a distance L2 above the bit 218 while the telemetry tool 212 is located a distance L1 above the bit 218. The path length from the telemetry tool to the flow port annulus 225 through the bit is again L1+L2 while the path length from the telemetry tool 212 through the device's flow port is L2 L1 such that the path length difference is 2·L1. In an embodiment in which L1=20 meters and L2=43 meters, the path length difference may be about 40 meters. The pressure pulse in the annulus due to transmission of the telemetry signal through ports 225 may be given as T1·Pe^{j(ωt−k(L2−L1)z)} where T1 represents the transmission coefficient of the ports 225 and P represents the positive pressure pulse at the telemetry tool. The pressure pulse in the annulus at port 225 due to propagation through the bit 218 may be given as T2·(P)e^{j(ωt−k(L1+L2)z)} where T2 represents the transmission coefficient of drill bit and P represents the negative pressure pulse at the telemetry tool. Using the example propagation constant from Table 2 and the example values for L1 and L2 noted above gives a phase difference between the two paths about 2.7 radians (about 150 degrees).

Based the foregoing it will be understood that other devices including flow ports may be advantageously located in the drill string so as to enhance the annulus signal (via constructive rather than destructive interferences).

Those of skill in the art will appreciate that Helmholtz resonators are commonly deployed at the output of a mud pump to suppress noise. The reflected, downwards travelling pressure wave in the riser may likewise be suppressed by connecting a Helmholtz resonator to the riser near the surface, above the array of pressure sensors. A Helmholtz resonator tuned to the mud pulse frequency may absorb much of the upward traveling pressure wave and hence reduce the reflection. The Helmholtz resonator may be mounted outside the riser and connected to the mud inside of the riser by a port. As is known to those of skill in the art, the Helmholtz resonance frequency depends on the gas pressure and gas volume in the resonator, among other things. The gas is typically nitrogen or air. The gas pressure must also be in the range of the fluid pressure in the riser. A suitable Helmholtz resonator may be installed, for example, at a depth corresponding to a few wavelengths below the surface, typically a few hundred meters or more.

The pressure in the resonator may be controlled with gas fed from the surface or a local pressure bottle. The mud in the Helmholtz resonator is filled while the telemetry tool is transmitting to obtain the best signal to noise in the telemetry bandwidth. This may reduce the amount of reflection and the amplitude of the downward propagating wave.

Although an intelligent drilling riser telemetry system and certain advantages thereof have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.

Claims

1. A mud pulse telemetry method comprising:

(a) deploying a drill string in an offshore drilling riser, the drill string including a mud pulse telemetry transmitter, the drilling riser including an annular pressure sensor in electronic communication with a surface processor via an electrical transmission line;

(b) causing the mud pulse telemetry transmitter to transmit a series of pressure pulses in the drill string;

(c) detecting the pressure pulses in an annular region of the drilling riser via the annular pressure sensor;

(d) transmitting the detected pressure pulses to the surface processor via the electrical transmission line; and

(e) causing the surface processor to decode the pressure pulses.

2. The method of claim 1, wherein (d) further comprises (i) digitizing the detected pressure pulses and (ii) transmitting said digitized pressure pulses to the surface processor via the electrical transmission line.

3. The method of claim 1, wherein the annular pressure sensor is deployed at a lower end of the drilling riser.

4. The method of claim 1, wherein:

the drilling riser comprises a plurality of axially spaced annular pressure sensor in electronic communication with the surface processor; and

(c) further comprises detecting the pressure pulses at each of the plurality of annular pressure sensors.

5. The method of claim 4, further comprising velocity filtering the pressure pulses received at the plurality of axially spaced annular pressure sensors to separate upwardly travelling acoustic waves from downwardly travelling acoustic waves.

6. The method of claim 5, wherein the velocity filtering comprises transforming the pressure pulses received at the plurality of axially spaced annular pressure sensors to an FK plane.

7. The method of claim 6, wherein the velocity filtering further comprises applying a frequency band filter to a wedge of data in the FK plane.

8. The method of claim 4, further comprising stacking the pressure pulses received at the plurality of axially spaced annular pressure sensors to reduce random noise.

9. The method of claim 1, wherein the pressure pulses transmitted in (b) encode data via phase modulation and the surface processor uses a quadrature phase shift keying algorithm to decode the pressure pulses in (e).

10. A mud pulse telemetry system comprising:

a mud pulse telemetry transmitter deployed in a drill string, the drill string deployed in a drilling riser coupled to an offshore drilling rig.

at least one annular pressure sensor deployed on the drilling riser, the pressure sensor configured to sense mud pulse telemetry signals in an annular region of the drilling riser; and

a surface processor in electronic communication with the annular pressure sensor via an electrical transmission line that extends along a length of the drilling riser from the annular pressure sensor to the drilling rig, the processor configured to decode mud pulse telemetry signals transmitted by the mud pulse telemetry transmitter.

11. The system of claim 10, wherein:

the drilling riser comprises a plurality of elongated riser sections connected end to end; and

the electrical transmission line comprises a plurality of electrically conductive segments inductively coupled to one another.

12. The system of claim 10, wherein the at least one annular pressure sensor is coupled to an outer surface of a riser body and is in hydraulic communication with a riser annulus via a hole in the riser body.

13. The system of claim 10, comprising a plurality of axially spaced annular pressure sensors.

14. The system of claim 13, comprising at least four equi-spaced annular pressure sensors.

15. The system of claim 14, wherein the annular pressure sensors are axially spaced apart from one another less than about one quarter of a wavelength of a transmitted mud pulse telemetry carrier signal.