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Surface data sensors during drilling
By analyzing cuttings, drilling mud, and drilling parameters for hydrocarbon-associated phenomena, we can develop a great deal of information and understanding concerning the physical properties of a well from the surface to final depth. A critical function in data analysis is familiarity with the different sensors used for gathering surface data. The primary types of surface data sensors are discussed in this page.
Depth-tracking sensors
Current depth-tracking sensors digitally count the amount of rotational movement as the draw-works drum turns when the drilling line moves up or down. Each count represents a fixed amount of distance traveled, which can be related directly to depth movement (increasing or decreasing depth). Moreover, the amount of movement also can be tied into a time-based counter, which will give either an instantaneous or an average rate of penetration (ROP).
Some companies still use a pressurized depth-tracking/ROP sensor. The pressurized ROP system works on the principle of the change in hydrostatic pressure in a column of water as the height of that column is varied. This change can then be indirectly related to a depth measurement. Again, a time-based counter is used to calculate an instantaneous or average ROP.
Accurate depth measurement on offshore rigs such as semisubmersibles, submersibles, and drill ships is affected by both lateral (tidal movement) and axial (the up-and-down motion of the rig, also called “rig heave”) effects. To properly compensate for this, most of these rigs have a rig-compensator system installed on their traveling block. As the rig moves up, the compensator opens, thereby allowing the bit to stay on bottom. Similarly, as the rig moves down, the compensator must shut to keep the same relative bit position and weight on the bit.
The same digital sensors are attached to the compensators so that any change in movement can be taken into account, allowing accurate depth measurement (Fig. 1).
Fig. 1—Example of a typical depth-tracking system.
Flow-in tracking sensors
Flow-tracking sensors are used to monitor fluid-flow rate being applied downhole as well as the pump strokes required to achieve this flow rate. Data gathered from these sensors are essential inputs to calculating drilling-fluid hydraulics, well control, and cuttings lag. Monitoring changes in trends may also indicate potential downhole problems such as kicks or loss of circulation.
Two commonly used types are proximity and/or whisker switches. A proximity switch, activated either by an electromagnet (coil) or a permanent magnet, acts as a digital relay switch when it incorporates electrical continuity. A whisker switch is a microswitch that is activated only when an external rod (called a whisker) forces a piston to raise a ball bearing to initiate contact against it (Fig. 2). Both types are digital counters; an increase in counts will correspond to a specific increase in both flow rate and pump rate.
Fig. 2—Example of proximity and whisker switch.
Pressure-tracking sensors
Pressure-tracking sensors are used mainly to monitor surface pressure being applied downhole. Data gathered from these sensors are used either to validate calculated values or to confirm potential downhole problems such as washouts, kicks, or loss of circulation.
Two types of sensors are available, and both monitor pressure from a high-pressure diaphragm unit (knock-on head) located on either the standpipe or the pump manifold. The first sensor type derives its physical input from mud pressure expanding a rubber (or viton when high temperature is involved) diaphragm within the knock-on head. This expansion proportionally increases the pressure in the hydraulic-oil-filled system and, in doing so, relays the mud pressure to the appropriate transducer. The second sensor type makes a direct connection with the standpipe manifold itself (i.e., the transducer face is in contact with the mud; see Fig. 3).
Fig. 3—Example of pressure transducers.
Flow-out tracking sensor
Commonly called a “flow paddle,” this sensor measures flow rate coming out of the annulus using a strain-gauge analog transducer (Fig. 4). Changes in resistance values are directly related to either an increase or a decrease in mud-flow rate. This sensor provides an early warning of either a kick condition (sudden increase in flow rate) or a loss of circulation (sudden decrease in flow rate).
Fig. 4—Schematic of a flow-paddle sensor.
Drill-monitor sensors
Drill-monitor sensors monitor surface revolutions-per-minute (RPM) values, rotary torque, and hook load. The torque sensor is a clamp (Fig. 5) that sits around the main power cable to the top-drive system (TDS). It works on the principle of the deformation of Hall-effect chips by the magnetic field produced around the cable owing to the current being drawn through it (i.e., the greater the torque being produced as the pipe rotates, the greater the current drawn by the TDS and therefore the greater the Hall effect). (Note: the Hall effect is a transverse voltage caused by electric current flow in a magnetic field.) Torque changes can then be related to either formation lithology or downhole drilling problems such as pipe stick/slip or motor stalling.
Fig. 5—Example of a torque (left) and an RPM sensor (right).
A digital rotary sensor is similar to a proximity sensor used in a pump. It is shaped differently but acts on the same principle. RPM changes are used to drill the well efficiently and minimize downhole vibration effects.
The combined weight of the bit, bottomhole assembly (BHA), drillpipe, etc., is called the string weight (SW). The block weight (BW) is the weight of the lines and blocks (including top drive or kelly). When the bit is on bottom (i.e., drilling), the hook load is seen to reduce. The amount of weight suspended by the bottom of the hole is the amount of weight on bit (WOB), as shown below:
This hook-load sensor uses the same transducer type as in a pressure-tracking sensor. As the deadline experiences strain, the reservoir has load applied across it, which pressures the hydraulic fluid. This pressure increase is translated to a measurement value (Fig. 6). These measurement values are then correlated to potential downhole problems such as kicks or stuck pipe.
Fig. 6—Example of a hook-load sensor.
Pit-monitor sensor
Most pit-monitor sensors use ultrasonic transit time to measure mud level. The sensor is mounted over the pit above the maximum mud level, and sends a sonic wave that is reflected back to the receiver (Fig. 7). The transit-time measurement is then directly transformed to a volume measurement. This critical measurement is actively used to monitor potential kicks (rapid increase in pit volume) or loss of circulation (rapid decrease in pit volume).
Fig. 7—Example of a sonic pit-volume sensor.
Gas-detection sensors
The gas-detection sensors consist mainly of a gas trap, a pneumatic line linking the gas trap to the gas-detection equipment (which is found inside a mud-logging unit), and the gas-detection instruments (chromatograph and total-gas detectors).
The gas trap is basically a floating chamber with a rotating “agitator” inside. It works on the principle that mud flowing through the gas trap is agitated, thereby releasing the vast majority of any gases contained within the mud. This gas is then extracted from the trap through the unit sample line to be analyzed in the unit (Fig. 8).
Fig. 8—Example of a gas trap.
The principle behind gas chromatography is simple. The gas from an oil well consists of several hydrocarbon components, ranging from light gases (methane) to oil. A gas chromatograph then takes a sample of gas and separates out some of these components for individual analysis. Typically, methane (C1) through pentane (C5) are the gases of interest. These can be plotted individually, or they may be used in gas-ratio analysis for reservoir characterization.
Most logging companies currently use a flame ionization detector (FID) gas chromatograph and total-gas detector (Fig. 9). The FID responds primarily to hydrocarbons and has the widest linear range of any detector in common use. The output signal is linear for a given component when concentrations vary from less than one part per million (ppm) to percent levels, and with care, resolution can be obtained in the low part-per-billion (ppb) range. The total-gas detector samples gas in a manner similar to that of a chromatograph, the only difference being that there is no column in the detector and, hence, no separation of components (i.e., it burns the “total” hydrocarbon gas sample as one). This also means that there is no injection time and, therefore, the gas is being sampled continuously (Fig. 8).
Fig. 9—Example of an FID chromatograph and a total-gas detector.
Additional sensors
In addition, exploration and production companies may require specialized services such as formation-pressure monitoring and drilling optimization. To effectively support these services, additional sensors may be required such as fluid temperature, density, and conductivity. In areas of high H2S or CO2 gas, corresponding sensors that exclusively monitor these gases may be required as well.
References
See also
Noteworthy papers in OnePetro
Bill Lesso, Maja Ignova et al. 2011. Testing the Combination of High Frequency Surface and Downhole Drilling Mechanics and Dynamics Data Under a Variety of Drilling Conditions, SPE/IADC Drilling Conference and Exhibition, 1-3 March. 140347-MS. http://dx.doi.org/10.2118/140347-MS.
Elliott, L.R., Barolak, J.G., Coope, D.F 1985. Recording Downhole Formation Data While Drilling, Journal of Petroleum Technology, Volume 37, Number 7. 12360-PA. http://dx.doi.org/10.2118/12360-PA