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The fine margins of success

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Oilfield Technology,

There are a wide variety of downhole logging tools which are used to effectively steer horizontal wellbores within a desired target window. The selection of the required real-time downhole measurements to be used in the geosteering process is largely based on the target formation’s expected log response across the drilling window.

As the development process of an oilfield progresses, new methods for extracting the hydrocarbons are implemented. One of these methods involves extremely precise borehole positioning within the lateral’s target zone to maximise hydrocarbon recovery. Traditionally, operators who wanted to achieve the goal of staying within a geosteering window of <10 ft would utilise a rotary steerable system (RSS) for a decreased bit-to-sensor distance and better inclination control. With commodity prices for oil remaining in the US$30 – US$40/bbl range, the development of certain mature oilfields might not be economically feasible when the extra cost of running a RSS is required for geosteering purposes.

Azimuthal LWD data requirements

While most horizontal wells can be geosteered with a traditional bulk gamma ray logging while drilling (LWD) sensor, there are instances where the target formation does not provide enough gamma ray contrast to adequately determine where the well is positioned by correlation to offset well logs. Azimuthal functionality of downhole LWD sensors provides an accuracy to well placement decisions made in real-time. Determining if an azimuthal gamma ray sensor or azimuthal resistivity tool is needed to stay ‘in-zone’ is usually decided before the well is drilled by looking at offset well data in a pre-well analysis. With a thin geosteering window, target changes in inclination become a critical component to keeping the well within the desired target zone.

Bit-to-sensor offset effects on geosteering methods

A decreased distance between the bit and LWD sensor can allow for a near proactive geosteering approach. Typical bit-to-sensor distances for gamma ray sensors connected to the measuring while drilling (MWD) probe above a mudmotor fall in the 30 – 45 ft range. This will depend on the length of the bit and motor, as well as the tool design offered by the directional service provider. RSSs will have a decreased bit-to-sensor distance of 10 – 20 ft, along with the option of a continuous inclination measurement of less than 10 ft from the bit. The shorter bit-to-sensor distance allows for quicker decisions on target changes to limit the amount of the well drilled out-of-zone by reacting quicker to structural dip changes along a lateral section.

Proactive geosteering methods have normally involved running downhole LWD sensors with a deep depth-of-investigation (DOI) for a ‘look-ahead’ approach of adjacent bed boundaries. Since gamma ray sensors provide a relatively shallow DOI with long bit-to-sensor distances, they are generally used for reactive geosteering programmes. Reactive geosteering can sometimes involve making target changes after the bit has already exited the target zone, resulting in over-correcting and porpoising the well to try and re-enter the ‘sweet spot’.

Figure 1. BitSub schematic showing the length of the collar, as well as the bit-to-sensor distance of 16 in.

With the advent of a geosteering sensor sub which is placed between the mudmotor and drill bit, bit-to-sensor distances can be decreased to less than 2 ft and provide a proactive approach to geosteering. Since the sub is placed below the mudmotor, having a short collar with reliable measurements is the key to success. Scientific Drilling’s BitSub LWD tool is 29 in. long and has azimuthal gamma ray, inclination, and tri-axial vibration measurements 16 in. above the top of the bit (Figure 1). The sub is run in conjunction with a compatible MWD system above the mudmotor and communicates via electromagnetic short hop. This Wi-SciTM technology works in both water-based and oil-based mud systems.

Written by Cory Langford, Scientific Drilling International, USA.

This is an abridged version of an article originally published in the November/December 2020 issue of Oilfield Technology. To read the full article, view the issue here.

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