Abstract
A method for telemetering data from a Remote Data Source (RDS) in a Bottom Hole Assembly (BHA) for subterranean drilling. The BHA has a Bottom Mounted Mud Pulser (BMMP), a Main Processing Unit (MPU) and an acoustic sensor uphole from the BMMP, and an RDS downhole from the BMMP. The method includes encoding RDS data into a first encoded data signal; translating the first encoded data signal into an acoustic data signal; causing the acoustic data signal to follow an acoustic pathway at least partially uphole to the acoustic sensor; causing the acoustic sensor to translate the acoustic data signal into a second encoded data signal; causing the MPU to decode the second encoded data signal into RDS data and send said decoded RDS data to the BMMP; and causing the BMMP to telemeter RDS data received from the MPU in at least an uphole direction.
Claims
1. In a Bottom Hole Assembly (BHA) for subterranean drilling oriented such that downhole is towards a drill bit and uphole is away from the drill bit, a method for telemetering data from a Remote Data Source (RDS), the method comprising the steps of: (a) providing a Bottom Mounted Mud Pulser in the BHA; (b) providing a Main Processing Unit (MPU) and an acoustic sensor uphole from the BMMP; (c) providing an RDS downhole from the BMMP, wherein the RDS is configured to generate RDS data; (d) encoding the RDS data into a corresponding first encoded RDS data signal; (e) translating the first encoded RDS data signal into a corresponding acoustic RDS data signal; (f) causing the acoustic RDS data signal to follow an acoustic pathway at least partially uphole to the acoustic sensor; (g) causing the acoustic sensor to translate the acoustic RDS data signal into a second encoded RDS data signal; (h) causing the MPU to decode the second encoded RDS data signal into RDS data and send said decoded RDS data to the BMMP; and (i) causing the BMMP to telemeter RDS data received from the MPU in at least an uphole direction.
2. The method of claim 1, in which selected ones of the MPU and the BMMP are retrievable.
3. The method of claim 1, in which the first and second encoded RDS data signals are substantially the same.
4. The method of claim 1, in which a Universal Bottom Hole Orientation (UBHO) sub is in the acoustic pathway.
5. The method of claim 1, in which the RDS is configured to generate RDS data at the RDS.
6. The method of claim 1, in which step (e) is performed downhole from the RDS.
7. The method of claim 1, in which the RDS is selected from at least one of the group consisting of: (1) a Diagnostics While Drilling tool; (2) a Logging While Drilling tool; (3) a Measurement While Drilling tool; (4) a Dynamics While Drilling tool; (5) a Rotary Steerable System; and (6) a smart motor.
8. The method of claim 1, in which step (e) includes amplifying the acoustic signal.
9. In a Bottom Hole Assembly (BHA) for subterranean drilling oriented such that downhole is towards a drill hit and uphole is away from the drill hit, a method for telemetering data from a Remote Data Source (RDS), the method comprising the steps of: (a) providing a Bottom Mounted Mud Pulser (BMMP) in the BHA; (b) providing a Main Processing Unit (MPU) and an acoustic sensor uphole in the BHA from the BMMP; (c) providing an RDS downhole from the BMMP, wherein the RDS is configured to generate RDS data at the RDS; (d) providing a piezoelectric translator downhole from the BMMP; (e) encoding the RDS data into a corresponding first encoded RDS data signal; (f) causing the piezoelectric translator to translate the first encoded RDS data signal into a corresponding acoustic RDS data signal; (g) causing the acoustic RDS data signal to follow an acoustic pathway at least partially uphole to the acoustic sensor; (h) causing the acoustic sensor to translate the acoustic RDS data signal into a second encoded RDS data signal; (i) causing the MPU to decode the second encoded RDS data signal into RDS data and send said decoded RDS data to the BMMP; and (j) causing the BMMP to telemeter RDS data received from the MPU, wherein said telemetry by the BMMP is in at least an uphole direction.
10. The method of claim 9, in which selected ones of the MPU and the BMMP are retrievable.
11. The method of claim 9, in which the first and second encoded RDS data signals are substantially the same.
12. The method of claim 9, in which the piezoelectric translator is downhole from the RDS.
13. The method of claim 9, in which a Universal Bottom Hole Orientation (UBHO) sub is in the acoustic pathway.
14. The method of claim 9, in which the RDS is selected from at least one of the group consisting of: (1) a Diagnostics While Drilling tool; (2) a Logging While Drilling tool; (3) a Measurement While Drilling tool; (4) a Dynamics While Drilling tool; (5) a Rotary Steerable System; and (6) a smart motor.
15. The method of claim 9, in which step (f) includes causing a reactive mass to amplify the acoustic signal
16. A Bottom Hole Assembly (BHA) for subterranean drilling oriented such that downhole is towards a drill bit and uphole is away from the drill bit, the BHA comprising: a Bottom Mounted Mud Pulser (BMMP); a Main Processing Unit (MPU) positioned an acoustic sensor positioned uphole from the BMMP; an RDS downhole positioned downhole from the BMW, wherein the RDS is configured to generate RDS data; a piezoelectric translator positioned downhole from the BMMP, wherein the piezoelectric translator is configured to translate a first encoded RDS data signal into a corresponding acoustic RDS data signal; an acoustic pathway traveling at least partially uphole from the piezoelectric translator to the acoustic sensor; wherein the acoustic pathway is configured to carry the acoustic RDS data signal to the acoustic sensor; wherein the acoustic sensor is configured to translate the acoustic RDS data signal into a second encoded RDS data signal; wherein the MPU is configured to decode the second encoded RDS data signal into RDS data and send said decoded RDS data to the BMMP; and wherein the BMMP is configured to telemeter RDS data received from the MPU in at least an uphole direction.
17. The BHA of claim 16, in which selected ones of the MPU and the BMW are retrievable.
18. The BHA of claim 16, in which the first and second encoded RDS data signals are substantially the same.
19. The BHA of claim 16, in which the piezoelectric translator is positioned downhole from the RDS.
20. The BHA of claim 16, in which a Universal Bottom Hole Orientation (UBHO) sub is positioned in the acoustic pathway.
21. The BHA of claim 16, in which the RDS is configured to generate RDS data at the RDS.
22. The BHA of claim 16, in which the RDS is selected from at least one of the group consisting of: (1) a Diagnostics While Drilling tool; (2) a Logging While Drilling tool; (3) a Measurement While Drilling tool; (4) a Dynamics While Drilling tool; (5) a Rotary Steerable System; and (6) a smart motor.
23. The BHA of claim 16, further comprising a reactive mass, wherein the reactive mass is configured to amplify the acoustic RDS data signal after translation by the piezoelectric translator.
Description
BRIEF DESCRIPTION OF THE DRAWINGS
[0032] For a more complete understanding of the embodiments described in this disclosure, and their advantages, reference is made to the following detailed description taken in conjunction with the accompanying drawings, in which:
[0033] FIG. 1 is a block drawing illustrating schematically a general arrangement of components discussed in this disclosure;
[0034] FIG. 2 is a flow chart illustrating method 100, a first method embodiment of the acoustic short hop technology described in this disclosure;
[0035] FIG. 3 illustrates an embodiment of BHA section of interest 200 correlated to method 100 on FIG. 2 to show general locations on BHA section of interest 200 where the steps of method 100 are performed;
[0036] FIG. 4 is a general arrangement drawing of an embodiment of BHA section of interest 200 showing portions thereof illustrated by FIGS. 5, 6 and 7;
[0037] FIG. 5 illustrates a portion of BHA section of interest 200 in which an acoustic signal is generated, in which the acoustic signal represents data from Remote Data Sources (RDS) 201;
[0038] FIG. 5A is an enlargement as shown on FIG. 5;
[0039] FIG. 6 illustrates a portion of BHA section of interest 200 in which an acoustic signal pathway AP is shown to traverse UBHO sub 205 so that the corresponding acoustic signal may be received by acoustic sensor 206 and receiver electronics 207;
[0040] FIG. 6A is an enlargement as shown on FIG. 6; and
[0041] FIG. 7 illustrates a portion of BHA section of interest 200 in which an electrical signal representative of data from RDS 201 may be received by MWD MPU 210 and processed for telemetry to the surface via, mud pulser 211.
DETAILED DESCRIPTION
[0042] Reference is now made to FIGS. 1 through 7 in describing the currently preferred embodiments of the disclosed acoustic short hop technology, and its related features. FIGS. 1 through 7 should be viewed as a whole for the purposes of the following disclosure. Any part, item, or feature that is identified by part number on one of FIGS. 1 through 7 will have the same part number when illustrated on another of FIGS. 1 through 7. It will be understood that the embodiments as illustrated and described with respect to FIGS. 1 through 7 are exemplary, and the scope of the inventive material set forth in this disclosure is not limited to such illustrated and described embodiments.
[0043] FIG. 1 is a block drawing illustrating schematically a general arrangement of components discussed in this disclosure. FIG. 1 is intended to orient the reader to a typical drillstring arrangement of components illustrated in more detail on FIGS. 3 through 7. FIG. 1 illustrates drilling operations from rig 10, to which bit 30 is connected via drillstring 20. The embodiment of FIG. 1 depicts a deviated wellbore in which bit 30 is driven by a positive displacement motor (PDM), or “mud motor”. The scope of this disclosure is not limited, however, to drilling operations involving deviated wellbores or PDM deployments.
[0044] The embodiment FIG. 1 further illustrates a section of interest 200 in the Bottom Hole Assembly (BHA). FIGURE depicts BHA of interest 200 including, in order from uphole to downhole: [0045] Measurement-while-drilling main processing unit (MWD MPU) [0046] MWD tool [0047] Receiver Sub [0048] Mud Pulser [0049] Universal Bottom Hole Orientation (UBHO sub) [0050] Acoustic Sub [0051] Remote Data Sources (RDS), e.g. Rotary Steerable System (RSS) or Diagnostics-while-drilling (DWD) tools [0052] PDM and transmission
[0053] The foregoing components will be described in more detail below in context of the acoustic short hop technology described herein. This is with the exception of PDM and transmission deployments, which may be conventional. Comparing FIG. 1 to FIG. 3, the “Acoustic Sub” block shown on FIG. 1 will be understood to correspond to a transmitting tool 202 and an acoustic interface including PEC 203 and reactive mass 204, as shown on FIG. 3 and described further below. Further comparing FIG. 1 to FIG. 3, the “Receiver Sub” block shown on FIG. 1 will be understood to correspond to an acoustic sensor 206 and a receiving tool 207, as shown on FIG. 3 and described further below.
[0054] FIGS. 2 and 3 should now be viewed together. FIG. 2 is a flow chart illustrating method 100. Method 100 represents a first method embodiment of the acoustic short hop technology described in this disclosure. FIG. 3 illustrates an embodiment of BHA section of interest 200 correlated to method 100 on FIG. 2 to show general locations on BHA section of interest 200 where the steps of method 100 are performed.
[0055] Step 101 on FIGS. 2 and 3 illustrates sending data from Remote Data Sources (RDS) 201 to receiver controller and transmitter electronics located on board transmitting tool 202. As described earlier in this disclosure, it is operationally advantageous to position certain tools, sensors or other data accumulators close to the bit in order to execute commands to tools located near the bit, or to monitor conditions in that region. RDS 201 may include any such tools, sensors or other data accumulators positioned close to the bit, including (without limitation) Rotary Steerable Systems (RSS), diagnostics-while-drilling (DWD) tools, “smart” motors, and other near-bit sensors. In some embodiments, RDS 201 may be configured to generate RDS data at the RDS itself. In other embodiments, RDS 201 may be configured to generate RDS data from sensors etc. located remote from the RDS itself. RDS 201 may send remote data to transmitting tool 202 via any convenient, conventional connection such as hard wiring or electromagnetic (EM) short hop, for example. A hardwiring option is used in embodiments of RDS 201/transmitting tool 202 illustrated on FIGS. 3 through 7 herein. In some non-illustrated embodiments, transmitting tool 202 may also provide its own RDS sensors located on transmitting tool 202's chassis.
[0056] Step 102 on FIGS. 2 and 3 illustrates transmitting tool 202 parsing data received from RDS 201 and generating a corresponding encoded electrical signal. In currently preferred embodiments, transmitting tool 202 uses conventional data encoding techniques to generate an optimized signal into which real-time data from multiple remote data sources are multiplexed. The scope of this disclosure is not limited to encoding or multiplexing techniques used in accumulating data from RDS 201. Further, in some embodiments, encoded electrical data signal generated by transmitting tool 202 may be characterized as a “first encoded RDS data signal” in order to differentiate with Step 109 on FIGS. 2 and 3. As further described below, Step 109 illustrates acoustic sensor 206 translating acoustic signal 104 back into an encoded RDS data signal, which may be characterized herein as a “second encoded RDS data signal.” The scope of this disclosure is not limited to the first and second encoded RDS data signals being substantially identical, although in some embodiments they may be substantially identical.
[0057] Step 103 on FIG. 2 and 3 illustrates transmitting tool 202 passing the encoded electrical signal from step 103 to piezoelectric crystal (PEC) 203. In illustrated embodiments, PEC 203 is positioned uphole from transmitting tool 202. The scope of this disclosure is not limited in this regard, however, and in other embodiments, PEC 203 may be located downhole from transmitting tool 202. PEC 203 translates the encoded electrical signal to a corresponding acoustic signal (step 104). In currently preferred embodiments, a reactive mass 204 amplifies the acoustic signal generated by PEC 203 (step 105). The scope of this disclosure is not limited, however, to embodiments deploying a reactive mass 204 for amplification purposes. Where deployed, reactive mass 204 is preferably made from a high-density material such as tungsten, although the scope of this disclosure is again not limited in this regard.
[0058] Step 106 on FIGS. 2 and 3 illustrates connecting (acoustically) an acoustic interface including PEC 203 and reactive mass 204 to the immediately uphole drillstring tubular. Acoustic interface 215 is described in more detail below with reference to FIGS. 5 and 5A. Referring momentarily to FIG. 5A, acoustic interface 215 also includes a flat face connection 213 and a compression stack 216 for promoting a strong (unattenuated) acoustic signal connection between acoustic interface 215 and the immediately uphole drillstring tubular. Flat face connection 213 and compression stack 216 are described below in greater detail with reference to FIG. 5A.
[0059] Step 107 on FIGS. 2 and 3 illustrates allowing the encoded acoustic signal to travel uphole on connected drillstring tubulars until it reaches Universal Bottom Hole Orientation (UBHO) sub 205. The scope of this disclosure is not limited to the number of drillstring tubulars (or other collared subs or mud motors) that may be in the acoustic signal pathway between acoustic interface 215 and UBHO sub 205 (if any).
[0060] Step 108 on FIGS. 2 and 3 illustrates providing an acoustic signal pathway, or “acoustic pathway”, from UBHO sub 205 to receiving tool 207. Note that although step 108 on FIG. 2 refers to an acoustic pathway from UBHO sub 205 to receiving tool 207, it will be understood with momentary reference to FIG. 3 that the acoustic pathway more precisely terminates at acoustic sensor 206. Acoustic sensor 206 then translates the received encoded acoustic signal into a corresponding encoded electrical signal and passes same to the receiver electronics located on board receiving tool 207 (step 109). As noted above, this encoded electrical signal translated by acoustic sensor 206 may be characterized as a “second encoded RDS data signal”, as differentiated from a first encoded RDS data signal generated by transmitting tool 202 with reference to Step 102. The scope of this disclosure is not limited to the first and second encoded RDS data signals being substantially identical, although in some embodiments they may be substantially identical.
[0061] The acoustic pathway disclosed on step 108 through UBHO sub 205 is described below in more detail with reference to FIG. 6A. Referring momentarily to FIG. 6A, embodiments illustrated on FIG. 6A direct acoustic pathway AP through UBHO sub 205 via muleshoe sleeve 217 and muleshoe stinger 218, and then into mud pulser 211. Muleshoe stinger 218 on FIG. 6A provides large seals 219 and small seals 220 for promoting a strong (unattenuated) acoustic signal through muleshoe stinger 218. In other, non-illustrated embodiments, acoustic pathway AP may be directed around or through a “shock miser” tool integrated into muleshoe stinger 218. Embodiments of a “shock miser” tool are disclosed in U.S. Pat. No. 9,644,434.
[0062] Step 110 on FIGS. 2 and 3 illustrates receiving tool 207 decoding the received encoded electrical signal. The decoded signal may be the original RDS data received in step 101, or may be a processed version thereof.
[0063] Step 111 on FIGS. 2 and 3 illustrates receiving tool 207 passing the decoded RDS data to MWD MPU 210. Preferably, the connection between receiving tool 207 and MWD MPU 210 for the decoded RDS data is a hardwired connection, although the scope of this disclosure is not limited in this regard.
[0064] Step 112 on FIGS. 2 illustrates MWD MPU 210 causing the decoded RDS data to be telemetered to the surface by mud pulser 211. Step 112 is not illustrated on FIG. 3 in order promote clarity and to avoid confusion. As described further below with reference to FIG. 7, MWD MPU 210 conventionally causes MWD data received from MWD tool 208 to be telemetered to the surface via mud pulser 211. In accordance with inventive technology described in this disclosure, MWD MPU 210 also causes RDS data to be telemetered to the surface via mud pulser 211 along with MWD data conventionally received.
[0065] FIG. 3 also illustrates battery 209 and drill collar 212 for reference in conjunction with other Figures described below.
[0066] FIGS. 4 through 7 should be viewed together. FIG. 4 is a general arrangement drawing of an embodiment of BHA section of interest 200 showing portions thereof illustrated by FIGS. 5, 6 and 7. The boundaries shown on FIG. 4 between FIGS. 5, 6 and 7 have no technical significance. They are for general reference purposes only, intended to promote a better understanding of BHA section of interest 200 as a whole across FIGS. 5, 6 and 7.
[0067] FIG. 5 illustrates a portion of BHA section of interest 200 in which an acoustic signal is generated, in which the acoustic signal represents data from Remote Data Sources (RDS) 201.
[0068] As described above, RDS 201 on FIG. 5 may include any such tools, sensors or other data accumulators positioned close to the bit, including (without limitation) Rotary Steerable Systems (RSS), diagnostics-while-drilling (DWD) tools, “smart” motors, and other near-bit sensors. FIG. 5 further depicts transmitting tool 202. RDS 201 sends RDS data to receiver electronics located on board transmitting tool 202. Although not specifically illustrated on FIG. 5, non-illustrated embodiments of transmitting tool 202 may provide additional RDS sensors located on transmitting tool 202's chassis. RDS 201 on FIG. 5 sends RDS data to transmitting tool 202 via a hard-wired connection. In other non-illustrated embodiments, RDS 201 may send RDS data to transmitting tool 202 via an electromagnetic (EM) short hop, for example. As also described above with reference to FIGS. 2 and 3, transmitting tool 202 parses RDS data received from RDS 201 and generates a corresponding encoded electrical signal. In currently preferred embodiments, transmitting tool 202 uses conventional data encoding techniques to generate an optimized signal into which real-time data from multiple remote data sources are multiplexed. The scope of this disclosure is not limited to encoding or multiplexing techniques used in accumulating data from RDS 201.
[0069] FIG. 5A is an enlargement as shown on FIG. 5, and depicts acoustic interface 215. Acoustic interface 215 on FIG. 5A includes piezoelectric crystal (PEC) 203, reactive mass 204, flat face connection 213 and compression stack 216. As also described above with reference to FIGS. 2 and 3, PEC 203 receives the encoded electrical RDS data signal from transmitting tool 202 and translates same to a corresponding encoded acoustic RDS data signal. It will be understood that PEC 203 will expand in response to current flow. If the current flow oscillates at a given frequency, the PEC will expand and contract at the same frequency, and these movements create vibration that can be encoded with data, creating an encoded acoustic signal.
[0070] With further reference to FIG. 5A and as also described above with reference to FIGS. 2 and 3, reactive mass on 204 amplifies the encoded acoustic data signal generated by PEC 203. In some embodiments, reactive mass 204 may also preferentially adjust the natural frequency modes of the transmission. The scope of this disclosure is not limited, however, to embodiments deploying a reactive mass 204. As noted earlier, where deployed, reactive mass 204 is preferably made from a high-density metal such as tungsten, although the scope of this disclosure is again not limited in this regard.
[0071] FIG. 5A further illustrates flat face connection 213 and compression stack 216 on acoustic interface 215. It will be appreciated that transmitting tool 202 is probe-based (i.e. located inside collar 212 of the drillstring. Acoustic interface 215 serves as a “bridge” from probe-based components to an acoustic signal pathway on the collar of the drillstring itself. Flat face connection 213 and compression stack 216 combine to promote a strong (unattenuated) acoustic signal connection between acoustic interface 215 and the immediately uphole drillstring tubular. Flat face connection 213 provides strong and tight physical contact over a substantial face area. Compression stack 216 forcefully compresses acoustic interface 215 and the immediately uphole drillstring tubular tightly together at flat face connection 213. As a result, an acoustic signal can pass from acoustic interface 215 to the immediately uphole drillstring tubular without significant loss of signal amplitude. Such a flat face arrangement is in distinction, say, to a threaded connection across which greater acoustic signal attenuation night be expected. Compression stack 216 also allows incremental axial deflections between acoustic interface 215 and the immediately uphole drillstring tubular. In this way, compression stack 216 also corrects for any axial misalignment between acoustic interface 215 and the immediately uphole drillstring tubular, thereby keeping flat face connection 213 tight to reduce potential acoustic signal attenuation.
[0072] FIG. 6 illustrates a portion of BHA section of interest 200 in which an acoustic signal pathway AP is established along which encoded acoustic data signals may travel uphole from acoustic interface 215 to acoustic sensor 206 and receiving tool 207. FIG. 6A is an enlargement as shown on FIG. 6, and depicts acoustic pathway AP traversing UBHO sub 205.
[0073] FIG. 6 depicts an initial portion of acoustic pathway AP flowing from acoustic interface 215 to UBHO sub 205. It will be understood from immediately prior description of FIGS. 5 and 5A, that once the encoded acoustic data signal traverses flat face connection 213 on acoustic interface 215, acoustic pathway AP flows uphole until it reaches UBHO sub 205.
[0074] Referring now to FIG. 6A, acoustic pathway AP flows through UBHO sub 205 via muleshoe sleeve 217 and muleshoe stinger 218, and then into mud pulser 211. Muleshoe stinger 218 on FIG. 6A further provides large seals 219 and small seals 220 for promoting a strong (unattenuated) acoustic signal through muleshoe stinger 218. Large and small seals 218, 219 provide acoustic insulation to acoustic pathway AP against background acoustic noise, such as shock, vibration and concussion created elsewhere in the drillstring from drilling operations. As noted above with reference to FIGS. 2 and 3, other, in non-illustrated embodiments, acoustic pathway AP may be directed around or through a “shock miser” tool integrated into muleshoe stinger 218. Embodiments of a “shock miser” tool are disclosed in U.S. Pat. No. 9,644,434.
[0075] Returning now to FIG. 6, a final portion of acoustic pathway AP flows from UBHO sub 205 to acoustic sensor 206 via mud pulser 211. The final portion of acoustic pathway AP may also include other tools car components immediately uphole of mud pulser 211 (note that the scope of this disclosure is indifferent to the presence of any other such tools or components). As shown on FIG. 6, acoustic pathway AP in this final portion is preferably through the casing of mud pulser 211 etc., although it will be understood that acoustic pathway AP may also flow through collar 12 in this portion of drillstring
[0076] Once acoustic sensor 206 receives the encoded acoustic data signal on acoustic pathway AP, acoustic sensor 206 translates the encoded acoustic signal into a corresponding encoded electrical signal. Acoustic sensor 206 then passes the encoded electrical signal to the receiver electronics located on board receiving tool 207. In currently preferred embodiments, acoustic sensor 206 is an accelerometer, although the scope of this disclosure is not limited in this regard. As noted above with reference to FIGS. 2 and 3, receiving tool 207 decodes the encoded electrical signal received from acoustic 206. The decoded signal may be the original RDS data received from RDS 201 by transmitting tool 202, or may be a processed version thereof.
[0077] FIG. 7 illustrates a portion of BHA section of interest 200 in which receiving tool 203 sends the decoded electrical RDS data signal further uphole to MWD 210. Preferably, the data connection between receiving tool 207 and MWD MPU 210 a hardwired connection, although the scope of this disclosure is not limited in this regard.
[0078] MWD MPU 210 processes the decoded electrical RDS data signal for telemetry to the surface by mud pulser 211. It will be understood that during conventional MWD operations, MWD MPU 210 receives MWD data generated by MWD tool 208 on FIG. 7. MWD MPU 210 encodes the MWD data signal for mud pulse telemetry, and then passes the encoded MWD data signal downhole to mud pulser 211. Mud pulser 211 telemeters the MWD data to the surface.
[0079] According to inventive technology in this disclosure, MWD MPU 210 is configured also to encode the RDS data signal (as received from receiving tool 207) for mud pulse telemetry. MWD MPU 210 may then send the encoded RDS data signal to mud pulser 211 along with encoded MWD data. Mud pulser 211 telemeters the RDS data to the surface.
Variations
[0080] 1. An acoustic datalink in which there is bi-directional communication (thereby enabling surface personnel to both listen to and command the remote data sources). In such variations, transmitter and receiver components would require transceiver capability.
[0081] 2. An acoustic datalink having wider application than facilitating RDS data communication with MWD systems located further uphole. The acoustic datalink described generally in this disclosure is not limited to such RDS/MWD+pulser deployments.
[0082] 3. This disclosure describes an embodiment in with the acoustic sensor and receiving tool are substantially integral with the MWD system+pulser. In other embodiments, the acoustic sensor and receiving tool could be located or mounted elsewhere in the BHA or on the drillstring, internally or externally. Alternatively, the acoustic sensor and receiving tool could be a separate tool or sub.
[0083] 4. As described above, embodiments of the acoustic datalink methodology described in this disclosure may be characterized to work with a shock-absorbing UBHO/pulser sub (aka “shock miser” tool) as described in U.S. Pat. No. 9,644,434.
[0084] Although the inventive material in this disclosure has been described in detail along with some of its technical advantages, it will be understood that various changes, substitutions and alternations may be made to the detailed embodiments without departing from the broader spirit and scope of such inventive material. Claimed embodiments follow.
