MWD Telemetry – Theory, systems, detection and dealing with bandwidth limitations.

Radio crackles to life: “Sorry, can we cycle the pumps please? MWDs missed the survey”. Shout to the drill floor to cycle the pumps. Second attempt missed survey. Again?! Third attempt, success. Drill ahead. What caused that?

What about MWD signal issues after displacing the mud system? Detection was fine before, but something has changed and now we are missing the tool updates, or having to slow the ROP to get the required formation evaluation data. Things improve, but what was the issue with detection?

Or during planning, optimising the bit, the BHA, the shakers, the mud spec, hoping to drill at X ft/hr, only to find out that our ROP will be limited by the MWD data rate.

Have you ever been in one or more of these situations? But what caused these problems? If you’ve found yourself asking these questions, and even better, want to know what can be done to avoid them…this week’s article is for you!

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This week’s MWD article is going to discuss some of the fundamentals of how mud pulse telemetry systems work; how the systems are able to convert and transmit digital data into physical changes in a fluid system (‘pressure pulses’), then once at surface, decode these pulses back into a digital signal.

While each MWD vendor, tool and telemetry system will have variations of the below, the general flow for mud pulse telemetry systems is as follows:

1. Sensors in the down hole tools activate and sample to obtain data (e.g. survey data, gamma ray readings, azimuthal images, etc).
2. The digital data is recorded by the sensors as memory data, to be retrieved once the tools are back at surface.
3. The same data is transmitted through the downhole tools to the telemetry tool, typically at the top of the BHA sensor suite (e.g. positive pulser).
4. The digital signal is then translated into physical movements of the pulsing mechanism to encode the data values as pressure differences in the fluid column (positive pulse, negative pulse, carrier wave).
5. For large amounts of data, signal compression may also take place to allow more data to be sent in the same or smaller sequence of pressure pulses.
6. These pressure pulses travel up through bore of the drill pipe, through the drilling fluid (e.g. drilling mud), to surface.
7. Once these pulses reach the surface, pressure transducers mounted on the surface pipe work (typically on the standpipe and/or gooseneck) detect these pressure fluctuations and send a signal to the MWD cabin, logging unit or surface PCs.
8. The surface software systems then decode the pressure fluctuations and convert this into digital data once again.

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Telemetry Encoding

To help in understanding how digital data is transmitted in Mud Pulse Telemetry systems, let us consider how electrical signals are transmitted. A basic example of signal encoding is Manchester encoding, which was first developed in the 1940s at the University of Manchester (hence the name), and is still widely used today; this type of digital data encoding was actually used in two NASA space probes Voyager 1 and Voyager 2, as well in some RFID systems. By varying the ‘on’ state of a signal (voltage in electronics case, pressure pulses in a Positive Pulse system), we are able to transmit data values based on the timing of the on states.

?A more advance method of data transmission achieves faster data rates by modifying the duration, frequency, or magnitude of the pressure pulses to encode different variables of data. For example with a positive pulser system, each pressure pulse or series of pulses can vary in amplitude, frequency and duration to encode different sensor data packets. The order of each data packet is sometimes referred to as a ‘list’ or ‘frame’ of data.

To illustrate this type of encoding, consider:

• A single pulse might represent a binary "1” or “on”, while the lower pressure value could be considered a “0” or “off” state (consider morse code as an example of this, dots and dashes to communicate data, in the case of language).
• For each pressure pulse, the duration or ‘width’ of the pulse (the time the signal spends in the "on" or “1” state) is modulated to represent different values of information. By varying the width of the pulses while keeping the frequency of the waveform constant, different values of data signal can be represented.
• The number of pulses within a given time interval (pulse rate) can be used to encode numerical values or specific commands. Sometimes called the duty cycle, referring to the ratio of pulses in the overall cycle. A duty cycle of 50% means that the pulse is "on" for half of the period and "off" for the other half.
• The ‘strength’ (amplitude) of each pulse may also vary to encode additional information or serve as a checksum for error detection. For example to signal the start or end of a sequence of data being continuously repeated.

Another method of telemetry encoding used in continuous wave or mud siren systems involves adjusting, or modulating, a carrier signal frequency, with the information encoded either in the frequency of the signal, or its relative phase.

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Decoding and Interpretation

Ever missed a MWD survey?

At the surface, the received pressure pulses are analysed and decoded to reconstruct the transmitted data. Signal processing algorithms are used to distinguish between individual pulses, interpret their timing and characteristics, and convert them back into meaningful data values.

Due to the physical properties of the fluid column the pressure pulses are travelling through (such as compressibility), the pressure waves suffer from attenuation of the signal (meaning the signal gets weaker), and over the distances experienced in wellbores of thousands of feet or meters, the attenuation can be significant. In addition to this, signal noise also needs to be filtered out, otherwise the actual MWD signal can be swamped and detection of the true signal lost. Pump noise, or pressure fluctuations in the surface systems may also lead to interference in the signal, leading to loss of data or inability to survey, or steer the wellbore. To counter detection interference, MWD vendors have implemented numerous downhole signal modulation techniques, data compression algorithms and surface receiver noise cancellation techniques to lower bit errors and increase signal-to-noise ratio. These techniques are used to filter, isolate, and enhance the MWD signal and increase detection rates. ?

For mud pulse telemetry to give us a good signal at surface we need a stable consistent pressure in order to detect the pressure pulses. If we’ve just made a connection and are bringing the pumps up slowly, or if there’s an issue with the mud pumps, then this may result in the standpipe pressure readings changing and masking the MWD telemetry signal. To avoid this, turning up the pump rate quicker, as well as the delay before pulsing up the MWD survey can avoid wasted time reshooting surveys!

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How much data can be transferred using the various systems

Ever had to restrict ROP due to telemetry rates?

Telemetry rates, also referred to as data rates, in the context of MWD systems refers to the speed at which data is transmitted from downhole tools to the surface equipment in real-time during drilling or logging operations. It represents the amount of data that can be pulsed up or transmitted per unit of time, typically measured in bits per second (bps) or bytes per second (Bps).

The telemetry rate imposes restrictions on the amount of data that can be transmitted in real-time due to several factors:

• Bandwidth Limitations: The telemetry system's bandwidth determines the maximum rate at which data can be transmitted through the drilling environment. Bandwidth constraints may arise from the physical properties of the drilling fluid, the data encoding method, and the telemetry system's design. Higher telemetry rates require broader bandwidth, and exceeding the available bandwidth can result in signal distortion, data loss, or transmission errors. In general, data rates increase from slowest to fastest: PP < NP < Siren < EM < WP, however each has drawbacks and limitations in certain environments, so the preference is not always as clear cut.
• Signal Interference: In drilling environments, telemetry signals may encounter various sources of interference, including noise from the drilling environment (downhole noise or vibration), drilling equipment/BHA (e.g. pressure differentials through tools), electromagnetic interference (from formations), signal reflections (borehole and pipework geometry), or fluid type inconsistencies and loss events (i.e. air in mud or total losses). For PP and NP, higher telemetry rates generally increase the susceptibility to interference, as the signals become more sensitive to distortion or attenuation. For EM, lithologies with increased metallic content can act as shielding and block the EM waves, resulting in signal interference or complete loss. Interference can degrade signal quality, reducing the effective data transmission rate and limiting the amount of data that can be reliably decoded in real-time.
• Attenuation: Systems that use drilling fluid to transmit signal suffer from signal attenuation due to compressibility in the fluid column. Depending on the fluid characteristics (e.g. water based, oil based, foam systems), the down hole pressure pulse or carrier wave signal will decrease as the signal is transmitted through the mud column, with each interval of fluid causing the signal to attenuate. As a result, especially in deeper wells, the amplitude of the pulse or signal detected at surface is usual a fraction of the pulse size generated down hole. Larger, sharper pressure pulses such as positive pulse or negative pulse designs are typically better at overcoming this effect, while siren systems with lower amplitude signals generally perform poorer, meaning that their effective telemetry rate must be reduced to compensate.
• Downhole Power Constraints: Generating and transmitting telemetry signals require energy, which is supplied by downhole power sources such as batteries or turbine generators which use the drilling fluid. Higher telemetry rates consume more power, potentially leading to faster depletion of battery reserves or increased mechanical stress on downhole equipment. Downhole power constraints may limit the telemetry rate to conserve energy and ensure the longevity of downhole tools. In addition, flow rates and tool set ups must be matched to allow sufficient signal strength at a given flow rate, and should the flow rate be decreased, this will likely mean that the signal strength will also decrease to the point of loss of signal.

During planning, its wise to balance between telemetry technology, the potential limiting factors discussed, and data requirements so that no one part of the system is holding back the other. There is reduced benefit in optimising drilling for 300ft/hr if the telemetry system can only deliver the agreed data densities at 100ft/hr. Similarly, there’s minimal benefit in specifying a 100ft/hr telemetry system if the planned ROPs are 10-50ft/hr.

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?Technical Advisory

Displaced the mud and now lost MWD signal?

Some key considerations when assessing which telemetry system and vendor is right for your operation, either during tender evaluation process or operational planning:

• Drilling environment: Consider the likely environmental parameters for your well. This may define which system, or combination of systems are used. For ERD or ultra deep wells, signal strength is a priority to ensure that the downhole pressure pulse is of sufficient amplitude to overcome down hole noise and attenuation in the mud system. Don’t be fooled by headline grabbing data rates when they only apply in tophole drilling when data requirements are minimal!
• Drilling fluid system: Depending on the mud systems in use, this may also define what telemetry system is required or preferred. If using oil or water based mud systems, then multiple telemetry systems are available and suitable, however if foam or air drilling systems are planned for, this will severely limit the ability of systems that rely on pressure pulses to create a signal.
• Data objectives and BHA complexity: For top hole or non data intensive tool strings, the telemetry system requirements may be minimal, giving multiple options to meet the data objectives. However, with more complex wells, increased logging requirements and larger more data intensive BHAs, telemetry capabilities become of more importance. If running a quad combo BHA while geosteering through a thin bed reservoir section, the ability to obtain all sensor data as well as react swifty is contingent on a suitably data rich telemetry system.
• LCM and/or loss treatment plan: While potentially not the most obvious factor in evaluating your preferred telemetry system, spare a thought for how LCM will react or limit your options. If the risk of loss events is anticipated on your well, then LCM limitations, and the risk of plugging the pulser and or string become a very real and potentially costly risk! The various telemetry systems will have published LCM tolerance, although often in reality these are lower than real life examples ?or case studies from the field. Ask for case studies for maximum LCM concentrations (with recipes, where available, not just headline figure) to get a better understanding of your contingency planning. With modern technology, pumping cement through the pulser is possible!
• ?Cost Vs Benefit: As with most services, each system comes with a cost. Enhanced data rates require more advanced or newer technology to achieve. While the principles of MWD telemetry are time served, the technology, equipment and cost to provide these services is often prohibitive. A consideration on the cost Vs benefit of each system should help define what system is a minimum, and what is a preferred for your operation. Running basic gamma and directional? Then no need for 20bps data rate capable systems, or their costs. Geosteering with ultradeep resistivity tools and want to maximise ROPs while that expensive BHA is in the ground, then an advanced telemetry system to allow optimised drilling rates will likely prove worth the extra investment. ?

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Mud pulse telemetry systems generally excel with a steady flow of homogeneous drilling fluid. Good condition, warm, sheared and consistent mud systems will allow pulsers to do their best work. If displacing to a cold, unsheared, aeriated heterogenous mud system with light spots, this will interfere with the telemetry signal and result in signal deterioration until the mud condition improves. There's a reason why you’ve potentially heard the phrase coming from an MWD hand, “blame the mud”!

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Closing Remarks

MWD telemetry systems are designed to meet customer requirements. There is no one size fits all solution, however by defining your wants and needs, this will help you evaluate which system, or systems, will best serve your operations. With detailed planning, selection and set up, telemetry systems can be configured up to facilitate high ROPs while obtaining all the drilling and subsurface data for the well objectives. Don’t let headline figures confuse each systems abilities or limitations, due to signal attenuation at depth reducing data rates, power consumption limiting BHA life in hole, or LCM sensitivity restricting your options, each system has its place.

To discuss any of the information in this article, or if you have any specific questions, you’ve always wanted to ask but never had the chance to, get in touch with one of one&zero’s experts to find out more.

For now, back to the logging shack, pumps are coming back on and its survey time!

#MWD #MLWD #Pulser #Telemety #Drilling #Logging #LCM #Detection