Over a recent beer or two in Calgary, Canada, with Arvil Mogensen, a well known and regarded Professional Engineer with 35 years international technical experience, we were discussing various applications for Radial Drilling (or Radial Jet Drilling). In this blog we’ll cover one of those applications…..
Let’s begin by stating the obvious. A VERTICAL well completion is a “dot” in a 2-dimensional landscape. As such, the wellbore itself can either be ideally placed or alternatively placed in some less optimal location. The probability of the former is less likely than the latter.
During the last 15-years the industry has experienced the arrival of HORIZONTAL well drilling technology, quickly followed by MULTI-STAGE fracture stimulation of HORIZONTAL well trajectories. The “panacea” solution to all the woes of the drilling and production of wells seemed to have been answered.
In actual fact what we have seen is an advancement from “pathetic” production flow rates from VERTICAL well completions, to “less pathetic” production flow rates from HORIZONTAL MULTI-STAGE fracture stimulated wells. Pathetic might seem rather harsh way of describing results, but with HORIZONTAL wells contacting such long sections of reservoir pay, and yet achieving only about a 2.5-times multiplier on the flow rate, this is hardly earth shattering. So, what has seemingly gone wrong that has made these new Horizontal multi-stage fractured wells produce and cumulate less oil than expected?
We know of a few obvious reasons, although many in the industry continue to ignore them;
- The pump in a vertical well is for all intent adjacent to the producing interval whereas in a horizontal well, the pump is typically some hundred feet above the pay zone, and hundreds and often a thousand feet away from the fracture
- Stage(s) and so fluid column and multiphase flow (transients) are to be expected.
- The pressure drawdown as insinuated in the previous bullet comment is augmented further by problems of effectively unloading completion fluid used for fracture stimulation and thus the entire group of fracture stimulation stages for a Horizontal well is unlikely to be entirely conditioned for optimal flow.
- Now the 3rd, most insidious reason. Undulations in the pay section are common, as is the surface topography we see able to see at surface. Placement of the horizontal trajectory in a optimal position is difficult and staying in the pay equally so. But that only attends to the ”Z” vertical in a 3-dimensional wellbore. The “X and Y” position as mentioned for VERTICAL wells also has not been completely solved using a HORIZONTAL well trajectory because the operator must choose the unique and singular direction from the 360-degrees of compass direction. While more reservoir is contacted with the HORIZONTAL well, the presumption the more reservoir contacted automatically confers that more “quality” reservoir has been contacted is not an automatic.
The three circumstances mentioned are BIG issues and cannot be trivialized. Reflecting on ONE issue is bothering, but reflecting on all THREE in simultaneous fashion together with their compounding affect would seem to provide a pretty compelling evidence to explain the rather modest flow rate improvement delivered from MULTI-FRACTURED HORIZONTAL wells.
We could add a FOURTH bullet to the list above which is somewhat controversial. That is that the propagation of fractures is a lot more complicated, uncertain, and unpredictable than the simple concept used in most fracture stimulation models that describe the fracture as a simple “BI-WING.” What is particularly concerning is that reservoirs of shallow depth seem to have a great deal of trouble propagating downward. We have seen horizontal trajectories placed only a few meters above what might be considered the most optimal sand horizon that produce at very poor flow rates, even though one would presume that the fracture stimulation would have connected to the more optimal pay in some easy fashion. The fact is they don’t and the “why” is yet to be determined, but the production rates speak the “truth.”
So, when considering the prospects of using Radial Drilling technology, we are encouraged on a number of fronts. Let’s spell them out;
- We know where optimum pay sections are as the existing wellbore has almost invariably been logged and a Gamma Log signature at a minimum is available. Thus, we know the exact position of the optimal pay.
- The “rapid” build permitted by Radial Drilling technology, allows the artificial lift (a sucker rod pump) to be placed at or below the juncture of the Vertical and the Horizontal such that literally no fluid head is held on the well, allowing a much-improved drawdown on the formation.
- The possibility of a “radiated” or a “helical” drilling pattern around the well provides not just a “singular” opportunity in terms of accessing better reservoir, but a multiple probability.
At this point, let’s tie all of these ideas together in terms of what Radial Drilling technology might allow.
At present HORIZONTAL wells have been drilled in many lower permeability reservoirs where previous VERTICAL well completions were unable to produce at sufficiently high rates of production to make them economically viable. We know what the “scale-up” production multiplier is comparing VERTICAL to HORIZONTAL completion types and they are not great. Does it not make sense to drill a helical radiating set of laterals from the existing VERTICAL, and compare the cumulative production and flow rates achieved to the HORIZONTAL Multi-stage fractured wells and on a barrel of oil recovered per acre basis. The results may very well prove the improvement in recoverable reserves but also show that the cost of a radiating lateral VERTCIAL well completion may ALSO be less expensive.
Such a test seems important. Results could cause a shift in completion practices for such a very large number of reservoirs and a very large number of producing companies.
This is not idle talk, but a real opportunity in need of being tested and evaluated.