ADVANCES IN MWD TECHNOLOGY IMPROVE REAL TIME DATA

Trevor Burgess, Bernard Voisin
Anadrill Schlumberger
Sugar Land, Tex.

Recent improvements in measurement while drilling (MWD) technology have increased drilling efficiency by allowing the driller to steer the bit with real-time formation evaluation measurements and to optimize bottom hole assembly (BHA) performance during drilling.

Significant advances in MWD will come in a viable market that values real-time downhole measurements not only as a replacement for conventional measurements, but also as a means to optimize drilling and increase recoverable reserves. MWD technology will center on improving the real-time capabilities of "geosteering," moving sensors closer to the bit, and reducing the length of the entire BHA.

The key to success is careful planning, cross training for MWD engineers and directional drillers, and a well-prepared team that includes the operator's representative, well site geologist, driller, and reservoir engineer.

The number of directionally drilled wells is expected to increase by 30% over the next 5 years, as will the use of MWD in these wells. Opportunities to apply MWD with steerable technology to horizontal and multitarget wells will approximately double over the same period. However, projected growth in the MWD market is misleading because the market is not as healthy as these predictions imply. Most MWD companies are experiencing low profits or losses.

MWD pricing remains at a low level compared to directional drilling prices. For example, a single drilling motor can earn the same revenue as a complete string of MWD sensors, including geological sensors, for about 20% of the investment with less manpower at the well site. Is the disparate pricing the result of oversupply, or is it the result of an industry perception that MWD is not a service of value?

The market will self-adjust for any oversupply, and companies that provide the most reliable and cost-effective overall services will survive. The value of MWD will rise only if the service companies demonstrate that MWD can consistently provide:

Cost-effective and reliable surveys (the traditional MWD service)
An opportunity to more efficiently steer the bit to stratigraphic targets (to improve safety and drilling efficiency and to increase recovery)
Vital information for geological correlation and formation evaluation
Improved well economics and production.

In these cases, the value of real time MWD is much greater than the additional cost when replacing steering tools or conventional wire line logs.

TOOL RELIABILITY

In the past, MWD tools have been criticized for being neither reliable nor durable. At present, most service companies claim a mean time between MWD failures of more than 250 hr. Based on that number, these tools may be compared to a car running on a rough road at 40 mph for 250 hr without maintenance service. That means MWD tools will go an equivalent 10,000 miles before requiring preventive service-a respectable figure.

The reliability of these tools, however, can be improved further with real-time measurements of downhole shocks. Fig. 1 shows MWD drilling vibration and downhole shock measurements of four bit runs made with an accelerometer sensor in the MWD tool.

The second track shows the shocks measured downhole in real time and transmitted to the surface. One area of high downhole shocks is noted during the first bit run. No significant problems occurred in the second bit run. In the third bit run, where the BHA was changed to make a correction run, high downhole shock levels occurred. These shocks correlate somewhat with the rate of penetration (ROP).

The driller was advised that the downhole shock level was high enough to cause a failure in the drillstring or the MWD tool. In this hole the vibrations were not clearly seen at the surface because they were damped by the friction between the drillstring and the well bore. After less than 10 hr of excessive shocks, a tool failure necessitated a change in the BHA.

During this run, the driller gained experience with the use of these measurements. On the fourth bit run, the MWD engineer, the directional driller, and the driller learned how to solve the problem by making minor changes in the rotary speed to reduce the shocks to an acceptable level. The use of downhole shock measurements improves the reliability of MWD tools and increases the life of bits and the drillstring. 1

In conventional and slim hole development wells, MWD emphasis remains on providing a simple service that does not delay the drilling process and has a low risk of sticking tools in the hole.

To address these needs, the industry is moving toward lightweight tools retrievable by slick line. These tools can often be run by the directional driller, thus reducing the number of personnel at the well.

The small tools can be loaded into a pickup truck or broken down for transport by helicopter to the site. Slick line retrievable tools offer a trade off between retrievability and reliability, depending on the application. Onshore, the technique has proven reliable and cost-effective. While offshore use has been limited to the less hostile environments, improvements in technology will expand its application in the near future.

Some service companies are trying to reduce the operational costs of MWD surveys by developing electromagnetic tools that send the acquired information to the surface by radio waves transmitted through the surrounding formations,

Although this method reduces the cost of operation by eliminating the pulser that is typically used for MWD telemetry, radio waves tend to get lost in formations with resistivities of less than 1 ohm-m. Therefore, current commercial electromagnetic systems are practical only for land operations where resistivities are greater than 1 ohm-m and the target formation is shallow. Although the data rates of these systems are not significantly better than data rates of mud pulsing systems, electromagnetic systems can transmit data when the mud pumps are off.

FORMATION EVALUATION

MWD activity shows good growth in the exploration market, which requires high quality measurements and quantitative formation evaluation. Real-time formation measurements at this stage have several advantages:

Resistivity and porosity logs are obtained in case the hole is lost later.
The hole is in gauge, so conditions are better for logging.
The well is logged before invasion occurs.
The likelihood of missing hydrocarbon zones is reduced because the measurements occur shortly after drilling potential pay zones.

The MWD industry typically uses 2-mhz logging-while-drilling (LWD) resistivity tools to obtain two depths of investigation and borehole-compensated measurements.

Neutron-density tools, which determine porosity and detect gas, have also come into use in recent years. Both of these nuclear sensors are designed to minimize the exposure of personnel to radiation, and some carry recoverable radioactive sources that can be retrieved by slick line if the drillstring becomes stuck. MWD logs from these tools enhance rather than replace wire line surveys by providing measurements before the well bore deteriorates. 2

The industry is developing high data rate tools that provide more than one or two measurements per foot at typical rates of penetration. Current tools operate at 0.5-3 bits/sec, but an increase can provide more measurements per foot drilled. Most systems currently record much downhole data, which is stored in memory and read at the surface after tripping the tool. The additional data are used to improve the resolution of the logs after drilling.

The offshore well log example in Fig. 2 shows how these measurements can improve evaluation during exploration. When the well was originally drilled, it was logged with a 2-mhz resistivity tool (solid and dotted black lines in the second track). In real time, the geologist and the MWD engineer noted the presence of a sand just above and below 700 ft. The MWD resistivity measurement clearly showed the presence of hydrocarbons in both formations.

Thirteen days later, the well site team (drilling engineer, geologist, and MWD engineer) decided to make a second run while reaming with the same resistivity tool to verify the presence of hydrocarbons. The peak in resistivity disappeared (dotted green line), clearly showing the effects of mud filtrate invasion in these two gas zones. A week later the hole was logged by conventional wire line tools (red line), again missing the hydrocarbons in the two sands. Similar masking effects from invasion have occurred on MWD neutron-density logs taken during and after drilling.

In gauge holes with little or no invasion, high quality formation logs can be made in real time by MWD to improve interpretation and detect hydrocarbon zones that may be missed by logging after drilling or by conventional wire line logs. Wire line logging programs are available after drilling to provide more information to evaluate complex formations.

For the exploration market, MWD services provide two depths of investigation for borehole-compensated resistivity, borehole-compensated density and neutron, ultrasonic caliper, and gamma ray measurements. Improvements will occur in the quality and calibration of the formation evaluation data.

Unfortunately, other measurements, such as seismic checkshots and sonic measurements of formation transit time, will probably not be commercially available in the immediate future. The technical difficulty and accompanying high costs to develop these tools warrant appropriate pricing for service companies to recover their investments.

DRILLING EFFICIENCY

To generate higher revenues, MWD must play a significant role in improving drilling efficiency and detecting drilling problems as they occur. The most significant problems encountered while drilling are kicks, stuck pipe, and drill pipe washouts.

These problems account for 75% of all drilling difficulties. MWD systems can help minimize the risk of these problems and yield substantial cost savings when integrated with a suite of simultaneous surface measurements.

A well-trained MWD crew and a well-informed drilling decision team at the well site are keys to this success.

KICKS

A number of available prototype tools can detect downhole kicks. One example is an ultrasonic sensor used primarily as a caliper measurement for the density tool. Placed in the stabilizer blade in the MWD string, an ultrasonic transducer emits a signal through the drilling mud. This signal reflects off the formation back to the sensor, which measures the transit time of the signal.

Since the material on the blade of the stabilizer has an acoustic impedance very similar to that of the mud, a very small reflection occurs at the face of the stabilizer blade.

However, small quantities of free gas in the drilling fluid significantly alter the acoustic impedance of the mud. This change radically increases the reflection from the interface between the stabilizer blade and the mud and reduces the reflection from the formation to the mud.

By automatically monitoring the amplitude of these two reflections and generating a "smart" alarm, it alerts the driller to the presence of gas in the annulus. This type of measurement has been used in real time to detect the productive fractures from the presence of flowing gas during underbalanced drilling operations in the Austin chalk.

The usefulness of this type of measurement is limited because the gas must enter the annulus below the sensor. Most kicks during drilling, however, tend to be swabbed in while making connections, and gas could come in at any point along the drillstring.

One method for early gas influx detection is based on the increase in sonic propagation time observed when gas is in the annulus. Unlike detection methods based on differential flow or pit gains, the instrumentation required is simple, reliable, and cost effective. Pressure transducers, mounted on the standpipe and on the annulus a few feet from the flow line, monitor the sonic pressure waves generated by the mud pumps. The output from the pressure transducers is used to measure the rate of change of sonic propagation time through the circulating system. This quantity is strongly influenced by the presence of gas.

The instant gas enters anywhere in the annulus it causes a Significant phase shift in the annulus measurement, which automatically alarms the driller to the presence of gas. This technique of combining downhole measurements with surface measurements provides reliable, fast kick detection. 3 4

STUCK PIPE

One method of solving the problem of stuck pipe is to integrate friction measurements made at the surface and downhole. Fig. 3 shows an example of key seating. In the first track, a dogleg of 6/100 ft was computed in real time from the MWD directional surveys.

In the second track, the drag is computed from the hook load at the surface while the drillstring is pulled out of the hole on three consecutive trips.

On trip No. 34 the drag increased only slightly because the key seat was just beginning to form. On trip No. 36, drag from the friction was significant-an early signal for the driller to resolve the problem by reaming this section of the well bore.

On trip No. 38 the drillstring stuck.

By using surface data and downhole weight on bit (DWOB) and downhole torque (DTOR) to make an early diagnosis of downhole friction in real time, the driller can take remedial action to avoid sticking problems, optimize bit performance, avoid unnecessary trips, and maximize various hole conditioning techniques. 5-7 The risk of planting tools in the well bore has been significantly lowered where MWD customers have applied these techniques. In 1991, one service company reduced the number of tools lost in hole for each operating hour by more than 50% over each of the previous 2 years.

WASHOUTS

Drill pipe washout, another major problem encountered during drilling, can be detected by use of the MWD turbine as a downhole drill pipe flowmeter. By comparing the voltage generated by the turbine to pump pressure and stroke rate, the field engineer can detect losses of fluid in the drill pipe (Fig. 4).

In Fig. 4, drilling proceeded normally until 6,627 ft. The pump pressure and total flow curves tracked each other, MWD alternator voltage was constant, and downhole delta flow was zero. Below 6,627 ft, pump pressure did not rise with increases in total flow, as indicated by the shaded area, and MWD alternator voltage and downhole delta flow decreased steadily. This indicated that not all the mud flow from the pumps was reaching the MWD tool. When the drillstring was pulled, a 5-in. crack was found in an 8-in. crossover. This could have twisted off, necessitating an expensive fishing job.

GEOSTEERING

With the development of 3D seismic over the last 3 years, the accuracy and resolution of surface seismic have improved. But during the planning stages, uncertainty still exists about the location of bed boundaries, hydrocarbons, and fluid contacts. With real-time MWD measurements, however, the directional driller can refine the assumed earth model and interactively steer the well through the hydrocarbons.

Drilling geologically rather than according to a rigid geometric well plan requires a team approach at the well site. The MWD engineer, well site geologist, reservoir engineer, and directional driller can modify the well plan using MWD measurements to optimize drilling and improve recovery. Careful planning and cross training can simplify such apparently complex operations.

In Fig. 5, the objective was to drill at the oil-water contact to avoid future gas coning. The directional driller used LWD neutron-density and resistivity/gamma ray tools to steer the well path. Each time the resistivity dropped below a target value of 0.6 ohm-m, he nudged the well up; conversely, each time the density measurement indicated a "fining-up" sequence, he nudged the well down. These measurements allowed the directional driller to remain in the right part of the reservoir to increase oil production and minimize gas coning.

Resistivity profiles of the target zones, based on resistivity logs on nearby wells or pilot holes, must be simulated at the planning stage before using resistivity measurements in real time to steer a well. It is now possible to model the response of 2-mhz resistivity tools when drilling through formations in a high-angle or horizontal mode.

The attenuation resistivity from the deep-reading MWD sensor and the phase shift resistivity from the shallow-reading sensor are measured as the well is drilled. In wells with deviations of 70 or more, the phase shift and sometimes the attenuation show a "polarization horn," or a spike at a bed boundary. Although it is not a true measure of resistivity, this polarization horn, when compared with the modeled response, can be used to pinpoint the position of a particular boundary with a similar resistivity contrast between the formations.

A good data base of the resistivity measurements at the planning stage enables the MWD engineer to reliably predict the response of each key bed boundary in a high-angle well. He can then use these features to determine the exact position of the bore in the geological sequence and modify the well plan to land the horizontal drainhole in the best place. 8-11

BHA IMPROVEMENT

The use of formation measurements to steer a well has some limitations. Fig. 6 shows a state-of-the-art BHA for simultaneous horizontal drilling and logging. Because of the 30-ft steerable motor located behind the bit, resistivity/gamma ray measurements are typically made more than 50 ft from the bit. Neutron-density measurements are often made more than 100 ft from the bit. Optimally, these measurements should be made closer to the bit.

The only measurements effectively made at the bit today are DWOB and DTOR. Although the strain gauges in Fig. 6 are placed almost 45 ft from the bit, they have proven reliable for reflecting the torque and weight at the bit. Dimensionless torque (Td) is calculated from DWOB and DTOR and correlates extremely well with lithology indicators, particularly gamma ray and porosity log measurements (Fig. 7):

Td = DTOR/(DWOB x D)

with D = bit diameter

On the left side of Fig. 7, Td is the earliest indicator of the bit entering the cap section. On the right side of the figure, Td indicates that the bit has entered the reservoir. Because Td immediately responds to changes in rock properties at the bit, it is a reliable indicator to the driller of a change in lithology at the bit. The resistivity, density, and neutron measurements lag behind the bit, and they make an average measurement around the well bore which tends to smooth out the effect of a bed boundary in a horizontal well. Therefore, from these measurements alone it is difficult to determine in real time when the bit has left one formation and entered another. 12

REFERENCES

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