Geosteering CTD Using The Drill Bit As A Sensor
Placing the wellbore trajectory in the correct formation is crucial to project success. Existing geosteering techniques provide some of the necessary accuracy but can involve drilling a certain amount of unproductive formation. However, a new technology has the ability to give engineers the information they need to geosteer more accurately in real time at a reduced cost.
By Richard Stevens, Coiled Tubing Applications Engineer at AnTech
In today’s oil price environment it’s more important than ever to place the wellbore in the most productive formation. The depth of the formation on a wellpath is never known with absolute certainty until the well is actually drilled.
There are two ways in which this problem can be minimised. The first is to rely on seismic data and as-drilled data combined with a certain amount of linear interpolation and assumptions on the properties of the rock. The second is to use geosteering. The latter is more accurate than the former, but neither offers an optimal solution. Let’s remind ourselves why.
Linear interpolation and its limitations
Figure 1a and 1b show the problems that can occur when relying on linear interpolation.
Knowing the depth and dip of the top of the reservoir and having knowledge of the performance of the directional drilling equipment proposed for the job, it is perfectly possible to plan a wellbore trajectory based on a casing exit depth and a build rate that will land the lateral the required distance below the top of the reservoir combined with a target inclination which will track the top of the reservoir. A modern directional (CT) drilling BHA will be able to feed positional information (inclination and azimuth) to the surface as drilling proceeds. This information can be combined with bit depth to provide an accurate estimation of the borehole’s position in 3D space.
Seismic data and offset wells provide valuable information when planning a well but there are inherent uncertainties in TVD based on the parameters and assessments made by the geophysicist. This is corrected to a certain extent by combining seismic interpretations with formation tops taken as-drilled on nearby wells. However, this still leaves an amount of uncertainty in the exact formation top location and a further problem arises when the formation is too thin for the trajectory to be planned below the lower uncertainty limit of the formation top or if the formation comes in at a different depth to that predicted by the subsurface team. If the seal drops below this line, as pictured in figure 1b, the ‘dead reckoning’ navigated well risks being drilled entirely in the seal.
The issue is not only a problem at the top of the reservoir but also at the bottom. If the formation below is unproductive and comes in shallower than the expected depth, the well profile could pass entirely through the unproductive deeper formation.
What the driller needs, to be able to avoid this non-profitable outcome, is information about what he is drilling through, in addition to pure positional information. This is what geosteering provides.
Geosteering options and challenges
In geosteering, properties of the formation being drilled are measured and used to modify the wellbore plan as it proceeds. It offers a considerable advance on simple interpolation, but there are still drawbacks. We’ll look at these briefly and then consider a new development – RockSense – that overcomes them and offers a greater degree of drilling accuracy at a reduced cost compared to LWD systems.
Observing cuttings at surface
The most basic (though by no means primitive) geosteering technique is to directly observe cuttings at surface. Cuttings are collected as they pass over the shaker, and subjected to optical, chemical, spectrographic or electronic analysis. There is a delay inherent in this process because of the time taken for cuttings to travel from the bit to the surface and the time taken to physically prepare and analyse the sample once it has arrived at surface. In deeper wells this time can be up to an hour. During this time, the wellbore may have progressed 30 ft or more, something that presents complications should the cuttings data not match the prognosis. Another significant drawback to this method is that the resolution is low. By the nature of the cuttings transport, the cuttings are dispersed on their journey to the surface which can make it hard to tell exactly when the bit passed through the formation top.
Adding sensors to the CTD BHA
The CTD BHA can be equipped with sensors that measure parameters which characterise the formations being drilled. They may provide information more quickly than observing cuttings, but they’re also add significant cost to the BHA.
Modern Logging While Drilling (LWD) tools can accurately measure formation gamma signature, resistivity, density and porosity. The above tool-mounted sensors are mature, reliable and offer a high degree of discrimination between formation layers. However, they do suffer from the disadvantage of being located, by necessity, tens of feet behind the bit. The mud motor needs to be nearest the bit, and above that, near bit survey tools, to give the driller earliest possible indication of direction change. In a certain slim hole tool, the formation evaluation sensor is approximately 25 feet behind the bit, which reduces the effectiveness of the information considerably.
The common problem
he distance travelled by the bit between the time when the formation boundary is crossed and the time when the fact of the crossing becomes apparent is a problem. It is especially significant in layered and thin formations or in formations that don’t have suitable markers to distinguish between the different layers or boundaries, situations that are very common in re-entry drilling.
Figure 2a. shows a conventional formation evaluation sensor located in the drilling BHA, a distance, LSense from the bit.
When the bit crosses the boundary from one formation to another an additional Lsense ft will need to be drilled before the change in formation is visible to the sensor. If the thickness of the formation is of the same order then it will not be possible for the driller to execute a steering action before the drillbit has left the formation of interest. This has a cost, in terms of lost production and time wasted drilling unproductive formation.
Were formation discrimination available at the bit, then this depth lag could be eliminated. The latest generation of coiled tubing drilling BHAs provide the data to make this new geo-steering method possible.
A solution to address past challenges
To understand how this new geo-steering method works, let’s take an analogy. Picture yourself a passenger in a moving car. Even with your eyes closed, you know the type of road you’re travelling on (freeway, city street, country road) by the road noise you can hear.
Consider now a motor turning a drill bit which drills a hole in a sample of rock. We can measure the power input to the motor as the hole is drilled to gain an understanding of the type of rock we’re drilling. If it was an electric motor we would simply measure the voltage applied and the current flowing during drilling and multiply them to get the instantaneous power. For a positive displacement mud motor it’s slightly more complicated, but it can be done. If differential pressure and flow rate can be measured then, given knowledge of principal operating constants for the motor, an expression for power in terms of pressure and flow rate can be written.
If we were then to integrate this power as the hole progresses we would have a value of Energy expended per foot of hole drilled and would therefore have a relative indicator of the changes in formation being drilled.
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