Let’s talk about Relief Wells, Part 2 – Under Pressure

First, currently the relief wells are still a couple of weeks away at the earliest. I thought BP might do a quick turn in and attack the well shallower, but for the certainty of the kill, they’re going deeper to make the thing work. While there’s a lot to say about what BP’s engineers are doing right now regarding the relief wells, suffice to say that the specifics are cool but that’ll come in a future chapter.

This post is about the pressure of fluids under the earth. I’m going to generalize this a bit so as to make a bit more accessible.

Feel free to listen to any version of Queen’s famous song, Under Pressure, while you read this.
I prefer the opening number sung by about 75 people in last year’s The Sing Off, located here While it has nothing to do with geology, I still like the tune.

Let’s start with sea water. Think about a plastic milk jug filled with sea water. Minus the weight of the container, it should weigh 8.33 pounds. So, if you do something involving sea water as a fluid, you’re using something that has what they call a mud weight of 8.33ppg (pounds per gallon) or 8.33#. Sea water isn’t that much different from fresh water here, but I’m getting ready to talk about the Gulf of Mexico, so you get the reasoning. The weight of oil differs depending on how dense it is. (The dissolved gas in this oil doesn’t really enter into the problem yet, but it will) The oil in this Blowout Well (BW) is a light crude. 39deg API. They measure it against how much it weighs compared to the same volume of water. Specific Gravity of .830, or that gallon jug of the same oil would be 6.6 pounds. There’s a chart for looking at the different densities of oil here

Okay, these are our starting numbers. Sea water 8.3# and Oil 6.6#
Next, water depth. 5000 ft. That’s the depth to get to the mudline at the Blowout Well.
Now the constant conversion factor. 0.052 if we’re dealing with depths in feet and pressures in pounds per square inch. You know how the language of flying airplanes is English, no matter where you are in the world? Well, with drilling wells, they may measure their depths in meters, but everyone still likes to measure mud weights in pounds per gallon. (The conversion factor for meters is different and won’t be mentioned here.)

Q:What’s the pressure at the mudline, 5000 ft down?
A: 5000ft * 0.052 * 8.33ppg = 2165.8psi (pounds per square inch)
Calculator courtesy of Wolframalpha.com

There Will Be Math

This means that all that oil coming out of the top of the BOP stack is having to fight against 2165psi of seawater pressing back at it.

Pretty easy to multiply all that to come up with a number, isn’t it? Good, because we’re going to try it again. Ready?

Let’s talk about drilling wells with regards to pore pressure. Look at the lower left portion of this capture from an old time well log. Density is listed as 9.6#

You're My Density

9.6# mud is pretty much the standard for normally pressured wells. Drillers Mud is pretty much water and go figure, mud, mixed in with enough other goodies to keep the mud in suspension and kept thick and luscious. The mud is used to circulate down and bring back the well cuttings, which are filtered out through what looks like a screen door. It’s thick (viscosity) and has weight (density). Many wells are drilled quite deep with a mud weight no higher than 9.8#. You can figure out the pressure the being exerted by the static column of mud by that simple equation above, only substituting out the mud weight of your choice. The goal in drilling a well is to drill as close to “balance” as possible. A safe driller would hedge that balanced line by drilling with a slightly heavier mud weight than he has to, perhaps 0.5# heavier than a balanced well.

What happens when you drill under balanced? Say you’re drilling with a 10# mud weight at 10,000ft. What’s the pressure of the column of mud?
10# * 0.052 * 10,000 = 5200psi.

Your drill rate goes up. You’re drilling faster. Probably a sand. A sand is like a rock sponge, filled with fluids.

But there’s a problem. Your mudlogger tells you the mud is coming back a bit more quickly than it should. You stop the pumps. That stops the flow going into the well, and coming out of the well. But in our case, the well is continuing to flow! How fast? How much? What’s flowing into the well? You can only guess what’s flowing into your well, and you can only guess where it’s coming from.

Let’s say it’s a salt water kick from that new sand at 10,000′. Happens all the time. Your mud is pushing down with 5200psi, and so your sand must be pushing back with a pressure higher than 5200psi. You’re out of balance. It’s time to weight up!

You break out the weight materials and add that to your big tank of your current 10# mud. You increase the weight of mud (let’s say a 0.5# increase to 10.5#), but there’s a time lag while the new mud is being prepared. While that’s going on, you start those mud pumps and you pump your current weight mud down the hole.

You’re only pumping the same mud – why bother continuing to pump? Your well is filling with salt water from below, that’s why. The more 8.3# salt water in your column of 10# mud, the less the whole column weighs. The less it weighs, the more your 10,000 deep sand will flow water into the well bore and right at your drillers. They don’t like it when they’re covered with salt water gushing out of the well. You have to dilute the salt water coming up the well bore with your 10# mud. It might take 60 minutes to circulate out this “kick”, to see that salt water at the surface. It’s a long way up that borehole. Your heavy mud is ready, and you immediately begin pumping it down. Another quarter of an hour for that to get down (the volume of the drill pipe where the mud goes down is much less than the volume of the annulus outside the drill pipe where the mud comes up) so you wait and watch. Your new mud goes down, and then on the way up. You’ll have to check to see if that sand is still flowing in at you. You shut the pumps down. No flow? Good. Back in balance. Being cautious, you increase the mud weight another 0.5# to 11.0# and drill ahead.

You really read this far? Congrats. You’re ready for your next lesson.

In the next lesson, I’ll show you the actual well log over the zone that’s flowing all this oil and gas into the Gulf of Mexico.

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Geologist writing SciFi

4 thoughts on “Let’s talk about Relief Wells, Part 2 – Under Pressure”

  1. Next time you should try serving booze when you serve this stuff up. It won’t make it any easier to read, but it will dull the brain ache. The music selection was a nice touch, however.

    The Perfessor

  2. Well I think the Question on everyone’s mind is Were the pressures really that high, Or was this just a case of BP being negligent?

  3. Toastar, here’s a letter to the editor of the Wall Street Journal from the president of a large independent oil company, Samson Oil and Gas. It’s long, but coming from a very serious source — someone who represents management in the oil industry — This castigation you’ll read below means that anyone with money and wisdom will risk future ventures with BP so high as to not want to make new deals with them. This would be big thing past the penalties for the cleanup

    In response to Tony Hayward’s June 4 op-ed “What BP Is Doing about the Gulf Gusher”: It is time that the publicity spin that BP is putting on this disaster is put into perspective. What is alarming about the content of the article is not so much what it says, but what it does not say.

    Mr. Haywood, chief executive officer of British Petroleum, asks, “How could this happen?” The answer has largely to do with BP’s inability to follow its existing well-construction policies and those of the industry generally.
    The BP testimony to the House Committee on Energy and Commerce on May 25 says it all, but perhaps that material needs to be explained. From looking at that evidence, this is what we know:

    1) When cementing the production casing the cementing crew, which was being supervised by BP, had difficulty landing the top plug into the casing shoe. This was the first “red flag” because a satisfactory cement job to the production string is fundamental to the safe operation on a go forward basis. The fact that the cement job did not go as planned should have caused the testing operation that followed to be carefully scrutinized, it clearly was not.

    2) As is normal practice, the integrity of the pressure tight seal was tested by pressuring up on the casing and observing the pressure response. If pressure bleeds off there is clearly a problem with the pressure integrity of the shoe, However, industry practice dictates that a positive test, that is no pressure drop, is not diagnostic, simply because the reservoir pressure is sufficient to retain the pressure being applied. A negative test is useful because it is diagnostic of a failed cement job. In this
    case the test was positive.

    3) Again, as is normal industry practice a negative pressure test was run, with pressure released from inside the casing and the pressure response was measured. In this case evidence has been bought before the committee that there was a 1,400 psi pressure response. This response is highly diagnostic and is therefore the second “red flag” and at this point the BP supervisors should have concluded that they had what the industry calls a “wet shoe.” That is that the cement job had failed to form a seal at the casing around the reservoir which we know contains high pressure oil and gas.

    4) At this point a decision should have been made to do a remedial cement job; this is an expensive operation, but having seen a 1,400 psi response, there was no choice.

    5) The BP engineers then proceeded with the balance of the operation to temporarily abandon the well. This meant replacing the 14-pound-per-gallon mud that was in the wellbore with 8.5-pound-per-gallon sea water. The denser mud had been, up until this time, the primary pressure control and was keeping the hydrocarbons in place despite the lack of an adequate cement job at the casing shoe. Given the two red flags that had been thrown up previously, one would have expected that as a precaution a cement plug would have been placed somewhere in the wellbore as a secondary pressure seal before this primary pressure control system (heavy mud) was evacuated from the wellbore. But at the very least the mud replacement operation should have been heavily scrutinized. Clearly it was not.

    6) Evidence provided at the hearing, including the pressure data transmitted from the rig for the last two hours before the explosion, is diagnostic. At 8:20 p.m. on the day of the explosion the pressure data suggest there was a constant flow of sea water being pumped into the drill pipe that was displacing the heavier mud system which was the primary pressure control for the well. The rate going in was 900 gallons per minute, but the flow data of mud coming out was steadily increasing from 900 gallons a minute at 8:20 p.m. to a rate of 1,200 gallons per minute at 8:34 p.m. During this 14-minute period one can conclude that hydrocarbons were flowing and pushing more fluid from the wellbore than was being pumped in. This is what this data is supposed to monitor, but the well flow evidence would appear to have been ignored, because at this point the BP rig supervisors should have gone to a well kill operation and started to pump heavy mud back into the well bore to restore the primary control mechanism. Instead the mud continued to be evacuated.

    7) At 9:08 there was another piece of evidence that is very clear cut. The sea water pump was shut down presumably to check the well stability. However, with the pump shut down a pressure increase was seen in the standpipe (SPP). This pressure response has to be associated with the reservoir flowing hydrocarbons and again at this point kill operations should have been initiated by the BP engineers.

    8) From 9:08 p.m. to around 9:30, despite the sea-water pump either running at a constant volume or shut-in, the SPP continued to increase; again this is evidence that the well is producing hydrocarbons and should have caused a kill operation to be initiated.

    9) At 9:30 p.m. the seawater pump was again shut-in to presumably observe what the well was doing, and again there is a notable increase in the standpipe pressure.

    10) At 9:49 the SPP showed a very large increase and the explosion followed — this is obviously the point at which the gas and oil reached the drill floor and found an ignition source.

    Mr. Hayward and BP have taken the position that this tragedy is all about a fail-safe blow-out preventer (BOP) failing, but in reality the BOP is really the backup system, and yes we expect that it will work. However, all of the industry practice and construction systems are aimed at ensuring that one never has to use that device. Thus the industry has for decades relied on a dense mud system to keep the hydrocarbons in the reservoir and everything that is done to maintain wellbore integrity is tested, and where a wellbore integrity test fails, remedial action is taken. This well failed its casing integrity test and nothing was done. The data collected during a critical operation to monitor hydrocarbon inflow was ignored and nothing was done. This spill is about human failure and it is time BP put its hand up and admitted that.

    Terry Barr
    Samson Oil and Gas
    Lakewood, Colo.

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