Tag Archives: drill pipe

Casing Wear Series – 1: Causes

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During the drilling phase, the most costly component is the casing. On top of the expensive casing materials and the costs likely to be encountered in cutting, pulling and replacing a worn or damaged string, casing wear creates more serious problems for operators due to its potential catastrophic incidents such as oil spills, blow outs or loss of the well.

To analyze the forces behind casing wear, we need to study the torque and drag (T&D) of the drill pipe during drilling operations. The basic mathematical and physical model of T&D has not changed significantly since Johancsik et al. published their paper on T&D prediction. Pipe movements such as drilling ahead or tripping create drag, while rotation produces torque. The magnitude of T&D is determined by the combination of these two movements.

Since the so-called vertical well virtually does not exist (the whirring action of the bit always creates a micro-helical shape of the well path), the contact of the drill pipe and its tool joint with the casing ID is unavoidable. The gravitational force acting on the drill pipe is always trying to pull the pipe to the lower side of the wellbore, while the axial tension on the drill pipe (in a build-up section) tends to push the pipe to the upper side of the wellbore. Depending on the pipe weight, dogleg severity, and axial force along the pipe, the drill pipe either touches the upper or lower side of the wellbore.

Typical T&D analysis starts by dividing the pipe into small elements. Calculation begins from the bottom element of the pipe, where weight on bit (WOB) and torque on bit (TOB) are expected. For each element, force and torque are balanced and the T&D at the top of the element are calculated. From bottom to top, calculations are performed for each pipe element, until it reaches the rig floor. This step-by-step calculation also determines the direction and magnitude of the side force, which pushes the drill pipe against the wellbore as shown in Figure 1.

Figure 1. Snapshot of Side Force along a Drill Pipe

Figure 1. Snapshot of Side Force along a Drill Pipe

Under this side force, the rotating tool joint on the drill pipe against the casing inside, gradually removes steel from the casing wall and forms a crescent-shaped wear on the casing as shown in Figure 2.

Figure 2. Rotating Tool Joint Wears Crescent Grooves in Casing

Figure 2. Rotating Tool Joint Wears Crescent Grooves in Casing

The seriousness of friction between two contacting surfaces is dependent on the nature of the rubbing surfaces and the mud.

The tool joint coating plays a bigger role here compared to the casing wall. The industry has seen tool joint coating evolve from “casing killer” (rough tungsten carbide) to “casing friendly” as shown by many high-tech hardbanding materials.

Tungsten carbide is applied on the tool joint. While it is a very good protector of the tool joints, it aggressively wears the casing so much that the mud type and its additive will not help much in reducing casing wear if rough tungsten carbide is present.

Once a casing friendly tool joint coating has been selected, the mud type and its additives play an intermediate role in casing wear. Water-based mud causes twice as much casing wear as the oil-based alternative. Lubricant reduces friction and severity of the wear.

Generally speaking, high dogleg will create a high side force and severe casing wear. The wear profile resembles the shape of dogleg severity. Higher RPM and lower ROP make more rotation time between the tool joint and casing and will cause aggressive wear.

The following conditions contribute to casing wear:

  • Well path and dogleg
  • Drill pipe weight
  • Tool joint coating
  • Mud and additives
  • RPM and ROP

Flying Among The Clouds

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Louis D. Brandies once said:

“Most of the things worth doing in the world had been declared impossible before they were done. Impossible means that you haven’t found the solution yet.”

A little over 100 years ago there were things that were considered impossible to do and that there was no way they could ever be achieved. For instance, to be able to fly among the clouds, but was it really an impossibility? Time proved that it wasn’t.

Just like flying among the clouds was impossible to do once, there are many things that thanks to the advancement of technology now are possible. For instance, a few decades ago horizontal or extended-reach drilling was considered impossible as well as casing wear prediction. In these environments, casing design is critical to a safe and successful drilling operations and well production, and unexpected casing wear can result in significant costs or even the loss of the well itself. This is the problem that drilling companies want to prevent.

So the question is: Is there any tool or software to calculate and predict casing wear severity? Yes there is! It’s called CWPRO.

2D wellbore schematic in CWPRO

This casing wear model uses the number of drill string rotations and contact force between the drill pipe and casing to calculate wear. The contact force is calculated using the dogleg severity inside the well. The maximum dogleg severity frequently determines the location and extent of the most severe casing wear. CWPRO helps operators and service companies identify, control and prevent potential problems. In overall the goal of CWPRO is to more accurately quantify casing wear risks and to ensure that the integrity of the casing is maintained during drilling operations.

Like mentioned before, there are many things that were considered an impossibility not too long ago like for instance, flying among the clouds. Likewise, thanks to software like CWPRO, predicting casing wear is no longer impossible; it is a fact.

"Being a deepwater well driller—what's it like?"

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Source: excerpted from A Sea In Flames, published by Crown Publishers, New York.

On a recent trip to South Korea, I spent most of my time in the airplane reading Carl Safina’s non-fiction book “A Sea in Flame”. I liked it very much.  Among many things, the following section attracted my eyes, because it describes the deepwater drilling in a easy-to-understand format.

I contacted Carl Safina and got his permission to publish this section in our blog.

Pegasus

                                                                                                                                             

Being a deepwater well driller—what’s it like? To simplify, imagine pushing a pencil into the soil. Pull out the pencil. Slide a drinking straw into that hole to keep it open. Now, a little more complex: your pencil is tipped not with a lead point but with a drilling bit. You have a set of pencils, each a little narrower than the last, each a little longer. You have a set of drinking straws, each also narrower.

PencilYou use the fattest pencil first, make the hole, pull it out, then use the next fattest. And so on. This is how you make the hole deeper. At the scale of pencils-as-drills, you’re going down about 180 feet, and the work is soon out of sight. As you push and remove the pencils, you slide one straw through another, into the deepening hole. You have a deepening, tapering hole lined with sections of drinking straw, with little spaces between the hole and each straw, and between the sections of straw.

You have to seal all those spaces, make it, in effect, one tapering tube, absolutely tight. And here’s why: the last, narrowest straw pokes through the lid of a (very big) pop bottle with lots of soda containing gas under tremendous pressure. As long as the lid stays intact and tight, there’s no fizz. But only that long. Everyone around you is desperate for a drink of that pop, as if they’re addicted to it, because their lives depend on it. They’re in a bit of a hurry. But you have to try to ignore them while you’re painstakingly working these pencils and straws. And you’d better keep your finger on the top of the straw, or you’re going to have a big mess. And you’d better seal those spaces between sections of straw as you go down, or you’re going to have a big mess when you poke through that lid. And before you take your finger off the top of the straw, you’d better be ready to control all that fizz and drink all that pop, because it’s coming up that straw. And if, after poking a hole in this lid that’s been sealed for millions of years, you decide you want to save the soda for later, then you’d better—you’d better—have a way to stopper that straw before you take your finger off. And you’d better have a way to block that straw if the stopper starts leaking and the whole thing starts to fizz. If it starts to fizz uncontrollably, and you can’t regain control, you can get hurt; people can die.

The real details beggar the imagination of what’s humanly and technologically possible. Rig floor to seafloor at the well site: 5,000 feet of water, a little under one mile. Seafloor to the bottom of the well: about 13,360 feet—two and a half miles of drilling into the seabed sediments. A total of 18,360 feet from sea surface to well bottom, just under three and a half miles.

Equally amazing as how deep, is how narrow. At the seafloor—atop a well 2.5 miles long—the top casing is only 36 inches across. At the bottom it’s just 7 inches. If you figure that the average diameter of the casing is about 18 inches, it’s like a pencil-width hole 184 feet deep. Nine drill bits, each progressively smaller, dig the well. The well’s vertical height gets lined with protective metal casings that, collectively, telescope down its full length.

At intervals, telescoping tube of casing gets slid into the well hole. The upper casing interval is about 300 feet long. Some of the lower ones, less than a foot across, are 2,000 feet long. The uppermost end of each casing will have a fatter mouth, which will “hang” on the bottom of the previous casing. You will make that configuration permanent with your cementing jobs.

The casings and drill pipes are stored on racks, awaiting use. Casings are made in lengths ranging from 25 to 45 feet; the drill pipe usually comes in 30-foot joints. They are “stacked” in the pipe racking system. You assemble three at a time and drop approximately 90 feet in, and then repeat. When you get and drop approximately 90 feet in, and then repeat. When you get ready to put the casing in, you pull all the drill pipe out. Rig workers also remove the drill pipe from the hole every time the drill bit gets worn and needs changing or when some activity requires an open hole. Pulling the entire drill string from the hole is called “making a trip.” Making a trip of 10,000 feet may take as long as ten or twelve hours. When you want to start drilling some more, you have to reassemble the drill pipe and send it down.