Directional Drilling

Directional Drilling – Alfred William Eustes III – Colorado School of Mines

Let’s spend some time talking about directional drilling and the technology that makes it possible.

Historically, it was frowned upon (and often illegal) to drill “slant-hole” wells – these wells were often used to steal oil from neighboring leases.

Although efforts to steer drill bits began as early as the 1920’s, the technology has only really matured in the last thirty years, as operators have gained a better understanding of the benefits and challenges of directional drilling.

Directional drilling technology has several advantages over traditional drilling. For example, by allowing drillers to steer the drill bit, it enables them to drill wells that follow the pay zone for long distances, allowing for extensive hydraulic fracturing of tight shale formations.

Directional drilling also allows drillers to drill multiple wells from one well pad, which saves on the costs and reduces the overall environmental impact.

Finally, directional drilling makes it easier to extract oil located beneath a body of water, a city or some other hard-to-reach spot.

Here, we’ll focus on horizontal wells.

Horizontal wells start out looking just like traditional vertical wells. They go more-or-less straight down for thousands of feet. But once the well reaches a predetermined point, called the kickoff point (or KOP), it begins to angle away from vertical.

To reduce frictional forces acting on the drill string, drillers try to steer the bit so that it makes a nice even curve. The rate at which the angle of the well changes is known as the build rate, and it’s measured in degrees per 100 feet or degrees per 30 meters.

Typical build rates range between 2 and 10 degrees per 100 feet. If you do that math, you can see that some of these curves take 4500 vertical feet to make it from vertical defined as 0 degrees to horizontal defined as 90 degrees.

When we’re doing directional drilling, there are two main challenges: physically steering the drill bit which is an interesting engineering feat, and figuring out where the drill bit is in space – whether it’s going in the direction we want it to be going.

Let’s start with steering.

There are two primary ways to steer a directional drill bit. You either point the bit in the direction you wish to go or you push the bit in the direction you want to go. Typically, both processes are combined to effect the direction.

There are two ways to make that happen. Drillers can use a “positive displacement motor” in a bit. In this method, the end of the drill string, just before the drill bit, has a little bend in it that operators can set.

When it’s time to change the direction of the well, drillers orient that bend so that the drill bit is facing in the direction they want it to go. Then they pump mud through the drill string and that powers a mud motor above the drill bit that rotates the bit but not the rest of the string.

So the bit is spinning independently of the string, cutting the hole, and the non-spinning drill string slides down the hole after the drill bit.

Once the turn is complete, drillers once again begin rotating the entire string. When the whole string is rotating with the bit, the bit goes straight, since it doesn’t point in any one direction for long enough to change the direction of the well. You can visualize this as whirling around the borehole, but since it whirls uniformly, it ends up going straight.

The second way to steer the drill bit is using a “rotary steerable system”. In this case, drillers can control the direction of the bit while the entire drill string is rotating.

This is often done by changing the radius of drill string stabilizers located near the drill bit. These stabilizers act as levers, allowing drillers to change the orientation of the bottom of the drill string with respect to the hole.

Okay, so we can steer the drill bit with a positive displacement mud motor or using a rotary steerable system.

But how do we know if we’re going the right direction? If we can’t tell where we’re going, there’s no point in being able to steer the bit.

Fortunately, methods have recently been developed that help drillers track the bit.

The MWD, or measurement while drilling system, transmits measurements from the downhole sensors to the surface. These measurements include inclination, magnetic bearings, and bit orientation, among other things.

Another set of tools used by directional drillers is the LWD, or logging while drilling system. This system measures attributes of the rock layers the drill is passing through, including natural radioactivity, resistivity, and other rock characteristics.

Geologists can compare these measurements with a geologic model of the reservoir to estimate the bit’s location and orientation and figure out where it should go next. This method is known as geosteering.

There’s one additional problem facing drillers who want to track a bit’s location: how do you get the information collected at the bottom of the hole to the surface? You can’t use traditional methods like radio waves or wires in such a harsh and isolated environment.

If you’ve ever tried to use a cell phone in a tunnel, or in some cases even your basement, you can surmise that similar technology is not going to work very well under thousands of feet of solid rock.

Instead, the information is transmitted either by sending pressure pulsations up to the surface through the drilling mud, or by very low frequency radio waves. In either case, the rate and bandwidth at which information can be brought up to the surface is currently quite limited.

Perspectives on Directional Drilling

What directional drilling or horizontal drilling enables us to do is penetrate huge lengths. I mean, literally miles in some cases of productive formation and expose that formation to production after it’s treated with hydraulic fracturing.

So what you do is expand the interval that you’re able to produce to allow a formation that is very reluctant to give up its gas or oil. So you kind of get the volume you need to make the well economical by having such long productive intervals exposed.

On a per foot basis, you’re getting relatively small input to that well. But on a cumulative basis, when you have several thousand feet of productive formation exposed, of course, that gets you the volume– production volume that you need to make that well economical.