Why Deepwater Drilling is Hard and What Statoil is Doing About It

Image: Statoil

Drilling in deepwater is a fairly complicated for a number of reasons.

1) You’re floating in the ocean while maintaining exact position over the well located over a mile and a half below the bottom of the rig.

Dynamic positioning – the industry term for it – is a fairly mature science.  Companies like Kongsberg, which have the vast market share globally in this sort of technology, have largely figured out how to keep 100,000 ton drilling rigs within a few feet of where they are supposed to be in nearly all weather and sea state conditions.  These days, it’s a very reliable system that has taken the guesswork out of how to maintain precise station in deepwater.

2) Try drilling something stationary while moving vertically.

This isn’t an issue particular to deepwater, all offshore floating rigs need to have “active heave compensation” which keeps a steady “weight on bit” however in deepwater, the loads can be extreme requiring huge motors to continuously take up or let out slack on the traveling block which supports the entire weight of the drill string, casing string, or riser plus blowout preventer (BOP).  The bigger the seas, the harder this system works and we’re talking loads over 1 million pounds hanging from the derrick.

Engineers have figured out that issue too though.

One of the most difficult issues for drillers and toolpushers to deal with has to do with mitigating an issue of 500 extra pounds per square inch at the bottom of the well.

In the world of big steel, giant motors and global positioning, 500 psi seems insignificant, however 30,000 feet below the rig where the drill bit is rotating through sand or shale deposited millions of years ago, 500 psi is the difference between drilling another few thousand feet, losing the drillbit, or losing hundreds of thousands of gallons of synthetic drilling mud into the pores of the earth and possibly losing well control.

As you drill a well, mud weighted with a compound called barite is used to maintain the balance between the hydrostatic pressure inside the wellbore and that of the surrounding earth – while at the same time helping remove well bore cuttings, cooling and lubricating the bit and other things.

It’s important to realize that 20,000 feet below the mudline in the Gulf of Mexico, it still looks kind of like mud (very compressed caked up mud), but it’s not hard rock.  You can break it up with your fingers in many cases and in the pores of the tiny mud particles deep in the earth is very salty water.  The deeper into the earth you go, the pressure inside the pores of shale or sand increases.

Ever dug a hole in a beach and watch it fill with water?  The same principle applies in deepwater drilling, however while you’re drilling the well, you’re keeping it filled with heavy liquid mud that maintains the balance and keeps the well from caving in on itself.

If the mud doesn’t have enough barite in it, the hydrostatic column inside the wellbore will be less than the pore pressure of the surrounding rock and it will begin to leak into the wellbore, just like the hole you dug at the beach did.

If you put too much barite in the mud, the heavy hydrostatic column will force itself into the rock and you’ll begin to lose mud into the wellbore, and the the column of mud will begin to drop as it finds a balance.

There is a sweet spot though and drillers are generally able to keep the mud weight within the “margin” so that it neither fractures the formation or underbalances the well.

In ultra-deepwater though, the hydrostatic pressure exerted by the column of mud within the riser, which is the steel pipe that connects the rig to the blowout preventer, begins to play a significant factor by thinning that margin.

Every time the drill bit enters an area of higher pressure while drilling, the density of the mud must be increased in order to balance the pressure.  However, with a very tall riser in place (due to extreme water depth), an incremental increase in mud weight translates in a pressure increase of (Mud Weight Increase x Water Depth x 0.052).

So, say you were drilling along at 16.2 pounds per gallon (ppg) mud weight, and the well began to flow (meaning the formation started to ooze out formation fluid). 16.3 ppg might be the next step up for you.

In order to increase mud weight, you’ll need to circulate out the existing mud that you’re using from out the end of your drill bit and up the annulus of the well bore.

Circulating a vertical column of mud 20,000 feet tall requires a bit of pressure however, and as soon as you start your pumps, the pressure at the tip of the drill bit has now increased to an equivalent level of 16.4 ppg, and you’re now losing mud into the formation because you’ve created an overbalance situation.

Then you stop the pumps and all of a sudden, bottom hole pressure decreases and you’re underbalanced again.

See how this is a bit of an issue?

The equivalent circulating density (ECD) of the mud, due to the pressure needed to circulate the mud through the wellbore has busted through the drilling “margin” which had been thinned out due to the column of mud in the riser.

The drilling engineers at Statoil have come up with a solution to this situation however.

As the pumps come on line to circulate the mud, they have designed special pumps attached to the riser which are used to reduce the level of mud in the riser which will reduce the hydrostatic head within the wellbore by an amount equivalent to the pressure needed to circulate the mud.  This enables the bottom hole pressure to remain constant while circulating.

In addition, for well control purposes, they have also installed a ram directly above the subsea pump module which can close very quickly in order to trap the U-tube pressure in the riser as a contingency if the circulation in the annulus suddenly drops, according to Erik Kirkemo, D&W Engineering Manager at Statoil.

Statoil intends to use this new ECD-Management system on board the Maersk Developer semi-submersible in Q3 2014.

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