MWD TOOLS OPEN WINDOW AT BIT

A new measurement while-drilling (MWD) system takes resistivity and directional measurements directly at the bit, allowing drillers and geologists to "see" the true direction and inclination of the bit with respect to the formation drilled.

With real-time resistivity measurements at the bit (RAB), the formation is logged before fluid invasion occurs and the driller can steer directional wells more accurately, than with conventional tools, according to Trevor Burgess, technical sales manager with Anadrill Sclumberger.

The MWD tools comprise an instrumented steerable motor and an instrumented near-bit stabilizer for rotary drilling (Fig. 1).

The tools, developed as part of the Integrated Drilling Evaluation And Logging System (Ideal) by Anadrill Schlumberger, Sugar Land, Tex., have sensors for resistivity, gamma ray, and inclination located in a sub just behind the bit. Agip SpA and Anadrill successfully tested the integrated steerable system in the Barbara 79 D well offshore Italy and in the Cortemaggiore 134 D well in northern Italy in November 1992.

This system with near-bit instrumentation has several advantages over conventional MWD:

• More accurate steering

  With the gamma ray and resistivity at the bit (RAB), the driller can respond rapidly to geological uncertainty and adjust the well path accordingly. With this "geosteering," the driller can make slight course corrections based on geological conditions instead of blindly following the geometric well plan. Fig. 2 shows the resistivity rays emitted from the tool. Drilling a high angle or horizontal well solely according to a geometric plan is risky because the well may miss a faulted out section, thereby reducing the effective pay, or it may pass just outside of a formation with an unexpected slight dip.

  Other MWD systems are used to geosteer wells, but the distance between the bit and sensors may not allow the well to be drilled along the optimum path. For example, if the resistivity and directional sensors are located 50-150 ft behind the bit, the sensors may tell the driller the well is pointed down at an 89 angle. The bit, however, may be facing up at a 91 angle. Fig. 3 is a schematic of a bottom hole assembly with two conflicting inclination measurements. The bit measurement is the true inclination of the front of the well; the MWD measurement is the inclination in a different section of the well bore.

  These systems tell the driller the path of the MWD tools in that section of the bottom hole assembly and not the true path of the bit, or well. This problem is especially acute in wells drilled horizontally through thin beds or in wells drilled very close to a bed boundary or fluid contact.

  With gamma ray, inclination, and resistivity measurements taken at the bit, the lag time (time for the logging tools to pass the point drilled) is effectively eliminated. The driller can detect the thinner zones earlier, giving him the opportunity to guide the bit rather than react to past information.

  With this type of geosteering, the effective length of the horizontal drain hole can be maximized because the well can be more easily kept within the geologic boundaries. An additional benefit is less dogleg severity. The end result is the ability to drill longer-reach wells in thinner beds with optimum positioning of the well in the pay zone.

• Improved logging while drilling

  With the resistivity measurements taken at the bit, the formation is logged virtually before any fluid invasion occurs. Because of the lag distance between the bit and other MWD tools, a small amount of fluid invasion can occur, especially in porous and permeable formations. Wire line logging, of course, takes measurements long after (several hours to many days) the formation was drilled, when fluid invasion can be substantial.

  Geologists and drillers often have conflicting goals in the drilling of directional or horizontal wells. Geologists want as much downhole logging data as possible, and data taken closer to the bit in real time have the greatest value for detecting formations and bed boundaries. Thus, geologists would ideally place the logging-while-drilling tools just behind the bit.

  However, the mechanics of drilling typically preclude this setup. The driller needs stabilizers, and downhole motors where applicable, placed in the proper positions to control the directional tendency of the bottom hole assembly.

  The instrumented near-bit sub is the same length as a standard stabilizer and can be run as the near-bit stabilizer or slick, depending on the directional drilling program. Because the instrumented tool is a functional mechanical component of the bottom hole assembly, it does not interfere with the driller's requirements. In essence, one operational conflict between drillers and geologists has been eliminated.

• Improved drilling efficiency

  The resistivity and gamma ray measurements can be used to optimize drilling by helping detect casing and coring points before the bit drills completely through the formation. With conventional MWD, the bit will have already passed through a large section of the formation before the sensors reach the formation. If the zone of interest is thin, the chance to core could be missed by the time the sensors detect the bed boundary. Likewise, for picking the casing point, the bit could penetrate an overpressured or underpressured zone before the sensors detect the bed boundary.

  The azimuthal sensors are used for picking roof and floor boundaries in horizontal wells.

  Another tool (in the instrumented motor) for improving drilling efficiency is the rotational speed sensor at the bit. This measurement is ideal for improving downhole motor efficiency and for detecting stalls. Ordinarily, the bit speed is estimated based on the downhole motor characteristics, the drilling fluid flow rate, and the drilling fluid pressure. During drilling motor stalling is inferred from pressure readings and flow rate. The drilling conditions are conservatively set below the estimated stalling point.

  With direct bit rotational speed measurements, the motor can be run at maximum mechanical power and hence achieve maximum rate of penetration.

MWD TELEMETRY

The instrumented sub in the near-bit stabilizer and motor send the measured data electromagnetically to the MWD telemetry tool located farther up the string in the bottom hole assembly. The data can then be sent along with other MWD data via a new mud-pulse telemetry system that can transmit data at rates up to 6-10 bits/sec. This high data transmission rate translates into more information at the surface in real time.

With conventional mud pulse telemetry systems, data are transmitted at around 1-3 bits/sec. This slower data rate often requires an intentionally slower rate of penetration to ensure enough data points are sent to the surface in real time. Thus, drilling efficiency may have to be compromised for the highest realtime quality logs. Because of the high cost of drilling operations, it is quite difficult to have a driller slow the drilling rate on purpose. Therefore, with a faster data transmission rate, the penetration rate can be kept high without interfering with log quality.

The data rate problem is addressed by some MWD systems which transmit only the immediately practical information. All the other logging data are stored in computer memory and read after the tools are tripped back to the surface. This setup provides complete logging information, but the data are retrieved after the section is drilled, hindering real-time geosteering. Thus, real-time data transmission at a high data rate is critical to drilling the optimum well path.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.