Drilling a Relief Well – Issues and Problems from a Drilling Professional

Posted: June 7th, 2010 by: h2

ROCKMAN puts up another classic posting, this time on the problems you would expect in drilling a relief well.

The relief wells, you might or might not remember, will be what actually stops the oil flow. The top hat thing they are using now is only a temporary measure, and at best will capture only about 90% (and that’s really at best) of the flow. Given that the flow is estimated between 12-20k barrels per day, that leaves a lot of oil spewing out in the Gulf.

So the real solution is, and always was, the relief wells that are being drilled down now Those will intercept the blown out well bore about 50 feet from the top of the actual reservoir, that is, about 18k feet below sea level, and 13k feet below the ocean floor. Once they intersect, which is a very complex process because you are drilling down with maybe a 20 inch hole trying to intersect maybe a 15 inch hole, down at 18,000 feet. Tricky stuff. You can also watch the official BP videos on relief wells.

This entire discussion is well worth reading, because it sheds some light on some parts of this process and industry you are most likely not aware of.

So without further ado, here’ how Rockman and a few other drilling engineers and professionals see the coming problems (theoildrum.com Deepwater Oil Spill – Pressure Tutorial – and Open Thread):

ROCKMAN on June 6, 2010 – 9:35am Permalink | Subthread | Parent | Parent subthread | Comments top
…. [ edited out beginning: not relevant to the thread topic]
I’ll take advantage of Euan’s post and expand on it with regards to recent question regarding the drilling risks associated with the relief wells. This is a matter I have experience with first hand in recent years. Prior to drilling a DW well there’s needs to be an estimate of the pressure gradients Euan has described. If there is not a well close to the new location the pressure gradient model (PGM) has to be estimated from the seismic data. Compared to a PGM generated from a nearby well, a seismic derived PGM is rather crude but it’s all we have to work with sometimes. This is why the PGM is modified while drilling. This was one of my tasks in a former life: well site pore pressure analyst (PPA). As the well is drilling a variety of rock property data as acquired by electronic sensors just behind the drill bit: logging while drilling (LWD). This data is transmitted continuously back to the surface. As simple as it may sound the data is essentially transmitted like a telegraph signal. Pulses are generated in the LWD tool and transmitted to the surface via the mud column. On the rig the LWD data is decoded and ready to use. Though I can’t predict the PGM ahead of the bit I can determine how close it’s matching the pre-drill model. Even when there isn’t a dramatic change in rock pressure there are limits to the range of mud weights used to drill a hole. That’s why we see so many csg sets in the RW’s. Too light a MW and the well flows. Too high a MW and you fracture the rocks and can easily lose the hole.

With the PGM gained from drilling the blow out well they have a pretty good handle on the MW’s and csg points needed in the RW. But the actual intersect event may still be very tricky. I haven’t seen details of the PGM from the blow out well so I can only speculate. Consider drilling the same rocks at this location but assume the is no oil/NG in the reservoir. The MW needed to stop the flow of water out of the reservoir might be 14.0 ppg. The rock might be fracture at a MW of 15.0 ppg. That’s a fairly wide margin and should not be a problem. But now put a 400′ tall column of oil/NG in the reservoir. One big reason the DW plays have attracted so much attention is the very tall hydrocarbon columns encountered out there. This tall hydr. column will raise the pressure in the reservoir to the point that a 14.7 ppg MW is needed to contain it. Now you have only a 0.3 ppg margin before rock failure. And this is where DW drilling offers a challenge seldom seen elsewhere: the ECD factor. ECD is the effective circulating density. The mud might weigh 14.7 ppg but when the mud pumps are running the effective mud weight (ECD) at the bottom of the hole maybe several tenths of a ppg higher. So in order to not fracture the rocks you might pump a 14.5 ppg (with an ECD of 14.9 ppg…less than the 15.0 ppg that would fracture the rocks). But when you turn the pumps off to add drill pipe or pull out of the hole the ECD drops to 14.5 ppg….less than the 14.7 ppg needed to keep the reservoir from flowing oil/NG to the surface. I’ve seen operators drill into such a situation: you can’t raise the MW to stop the well from kicking, less you fracture the rocks, and you can’t turn the pumps off to pull out of the hole because the well will kick. I’ve seen operators pump cement down such a well to kill it and then plug and abandon the well.

This example highlights why watching mud returns is such a critical safety protocol. You’re drilling and everything is fine: the well isn’t trying to kick and you’re not fracturing the rocks. But then you turn the pumps off to add a section of drill pipe and now the ECD isn’t sufficient to keep the well from kicking. And how do you know the reservoir is flowing into the hole? Even with the mud pumps off the mud continues to flow out as it’s being pushed upwards by the oil/NG. This is why checking mud returns is so critical. Even when there isn’t a need to stop the mud pumps you periodically do it anyway to see how close you are to that tipping point. This may be one reason the RW effort will seem to turn aggravatingly slow as the intersect is approached. It may be a very close balance of ECD needed and could take a number of days to fine tune it before the final hole is cut. No doubt we’ll be discussing this in the next 6 or 8 weeks.
aardvark on June 6, 2010 – 10:26am Permalink | Subthread | Parent | Parent subthread | Comments top

Rockman, do you mind expanding on what happens if you fracture the rocks?

I have visions of the mud draining away so you need to pump more mud to keep the pressure up until you have no mud left then… kablooey! But I don’t know if this is realistic.
ROCKMAN on June 6, 2010 – 11:07am Permalink | Subthread | Parent | Parent subthread | Comments top

aardy — several bad outcomes. The least serious is that you pump mud (actually the liquid portion of the mud) into a productive reservoir and reduce or completely destroy its production capabilities. Next worse is the sucking action caused by this lost circulation into a porous rock: the drill pipe can get stuck (differential sticking) and you might have to leave some of it in hole and then drill a side track. Next you can actually cause the rocks to break apart and the hole will collapse. More lost drill pipe and a side track. The worse case is when you have such lost circulation in one zone while another zone is kicking you. You lighten mud weight to stop the LC but that makes the kick worse. The primary purpose of the multiple csg runs is to minimize this range of too light/heavy a MW.

Probably the scariest well I’ve been on in the GOM DW was about 6 years ago. They had set csg and were drilling ahead at 22,000′. And then they started to loss circ. They weren’t sure where but it might have been at the previous csg shoe. They lost 60,000 bbls of OBM while drilling. No mud ever returned to the surface. So no mud log telling them if they had drilled oil/NG, no LWD to estimate pore pressure, no mud parameters to tell if the MW was being cut by oil, NG or water. And most importantly, no way to tell if the well was kicking. They put very heavy drill mud on the outside of the drill pipe but that would have not stopped a blow out coming up the inside of the DP. Took me 6 days to log that 2,500′ of open hole. I ran pressure logs in the wet reservoir they cut: 19,000 psi bottom hole pressure. They were probably very lucky they didn’t find oil/NG in that sand: a blow out could have easily happened. How scary was it? Some of the hands were sleeping in the escape capsules when they were off tower. And this insane risk was taken by a well known and very experience operator. Needless to say someone very high up in the company was willing to risk the 130 souls onboard that drillship to get this well down. Equally needless to point out: that person never set foot on that rig. We just finished the job, went home, cashed our pay checks and then tried to forget about it.
E L on June 6, 2010 – 11:59am Permalink | Subthread | Parent | Parent subthread | Comments top

Rockman: “And this insane risk was taken by a well known and very experience operator. Needless to say someone very high up in the company was willing to risk the 130 souls onboard that drillship to get this well down.”

Styno on June 6, 2010 – 4:00pm Permalink | Subthread | Parent | Parent subthread | Comments top

Exactly my question, but I’ll do an uneducated guess: Were the rock conditions known to have the risk that you described here beforehand and the company decided to press ahead anyway?
ROCKMAN on June 6, 2010 – 6:01pm Permalink | Subthread | Parent | Parent subthread | Comments top

sty — If the assumption that the mud was being lost at the csg shoe is correct then it had nothing to do with rock properties. Just a bad cmt job…again.
ROCKMAN on June 6, 2010 – 5:58pm Permalink | Subthread | Parent | Parent subthread | Comments top

EL — Just a guess but I’ve always assumed this project was a career maker/breaker. BTW…I never use the word insane lightly.
marku on June 6, 2010 – 12:00pm Permalink | Subthread | Parent | Parent subthread | Comments top

Unbelievable. I expect this is one reason why you no longer do DW.

It is a complete failure of regulation to allow anything of this sort to occur. This type of profit-at-any-risk thinking made a catastrophe like the one we are in now inevitable, not as Tony would like you to believe, a “one in a million” event.
ROCKMAN on June 6, 2010 – 6:08pm Permalink | Subthread | Parent | Parent subthread | Comments top

I mentioned a while back why I don’t do offshore anymore. My 9 yo daughter had never perceived me being in any danger out there and we let her hang on to that. But then her best friend’s
dad was killed in an oil patch accident. Another human error incident…his. So with tears in her eyes she begged me to not go offshore anymore. So that was an easy call. Oddly, perhaps because she’s been to onshore drill sites, she wasn’t worried about me as long as I stayed on the bank.

I never mention the names of former clients especially if I’m not saying nice things. But let’s say a little karma is at work out in the GOM today.

And there you have it. If you’re really interested in the technical matters, make sure to read R2-3D’s comment on drilling geology/salt etc.. Too technical for this posting, but it’s got graphics and other data you might find interesting.

The Ixtoc Relief Wells and Timeframes

let’s remember that the August/September scenario is the BEST CASE, not the average/median case. Here’s something approaching worst case.

This article also shows how similar Ixtoc and BP Deepwater Horizon actually are to each other. In other words, this is not an unprecedented event, unforeseeable, etc.

Throughout the months of attempts, Pemex was also drilling two relief wells. The first was completed in the late fall, and workers began pumping salt water and other liquids into it in order to relieve pressure.

It took until March of 1980 for the pressure had subsided enough to allow Pemex to pump cement into the well, creating a 1,650-foot-long plug. The leak finally stopped on March 23, 1980, some 10 months after it began. An estimated 3 million to 3.5 million total barrels of oil were spilled into the Gulf.

We’ve Been There Before
In 1979, the Ixtoc oil spill took 10 months to stop.

One Response to “Drilling a Relief Well – Issues and Problems from a Drilling Professional”

  1. h-1 says:

    Update: a bit more here on relief wells, thanks to the theOildDrum.com daily thread, again.

    aliilaali on June 12, 2010 – 3:44pm Permalink | Subthread | Parent | Parent subthread | Comments top

    just my 2 cents …

    1-there are no extreme presures involved here…..the drilling parameters for the blownout well were not extreme …infact 70% of DW wells have trickeir engineering involved …if at all a case can be made the drill team got too lax in thier apporach based on the routiness of the well.

    2-same goes for the RW’s….there are no extreme pressures involved….

    3- they will not punch into the reservior….a production well punches into a reservior…a RW punches in the leaking well…in this case the RW will try to intersect the leaking well at 18000′ rkb

    4- so essentially both RW’s will be in drill mode (regular drilling operations) until they reach to within a 1000′ of the leaking well when the intersection team from boots and coots will take over and the operations will go into whats called ranging mode….

    5- the 1000′ when the intersection team takes over ….this 1000′ is called the ranging zone …which will allow the intersection team to guide the RW’s to intersect the leaking well….this is the ONLY tricky part here…..because the only data they have they have are wellbore surveys and the intersection team will supplement that with PMR and RGR by vector magnetics ….essentially sending electrical current pulses in the leaking wellbore csg to generate a magnetic field and use sensors in the RW’s to pick up these magnetic fields and guide the RW to intersection

    6- things will switch from ranging mode to intersection mode and they will run a milling bit and time drill into the csg …..

    once pressure communications are established …the intersection mode is done …..now they will attempt a bottom kill
    R2-3D on June 12, 2010 – 5:13pm Permalink | Subthread | Parent | Parent subthread | Comments top

    5) With active magnetics, you can pick up casing as far away as 200′, from what I’ve recently read.

    6) My guess is there’ll be a decision point when the near borehole is reached, as one of two scenarios will be very apparent
    a) In the blowout well, the casing shoe failed because of the water in the casing, or the casing collapsed and the flow is only up the inside of the 7″ casing
    b) The original cement job was “insufficient” (too little, too foamy, too contaminated) and the formation fluids are going up only around the outside of the casing
    c) A combination of a) and b) which is hard to imagine but I’m including it anyway. Hard to imagine because you’d have to then declare which came first and explain the physical forces that caused the other.

    If the case is b), which is what I believe based on a healthy skepticism of all things having to do with trust in your casing cementers and poor engineering failsafes,

    they’ll never have to (nor will they wish to) mill directly into the casing of the blowout well.

    They will work with the electric logs and determine the best shale unit to be in when they encounter the blowout well bore. This will be some distance above the productive formations and below the 9 7/8″ casing. If/when they get close, they’ll encounter pressure and oil. BP has already declared that the productive zones were drilled slightly overbalanced, as they’ve decided the original formation pressure of the productive zones are 12.9#-13.0#. Obviously, the first relief well will be quite above that, but not exceptionally so, for reasons Rockman has already given.

    You then have to be ready to pump mud like mad. The mud will be circulating up the relief well bore, but will quickly leave go into the blowout well and start traveling upwards. The column of mud in the relief well will drop in both the drillpipe and the annulus, and you have to keep both filled. Well, you’re pumping down the drillpipe normally, but instead of someone idly filling the top of the annular space with any old mud or in many situations I’ve seen a water hose, I’m sure they’ll be pumping mud down the annular space as well.

    As Rockman has mentioned, the possibility of fracturing the formation at the bit in the relief well (or any location between the bit in the relief well and the casing shoe of the last casing set in the relief well) is fairly good. This would be a bad thing. In many situations, you back off. I have a feeling with all the mud available at the time, they’ll decide to toss caution aside for the moment and pump mud like mad. If you’re pumping down the annulus AND pumping down the drillpipe, the effect of Effective Circulating Density is lessened slightly. After all, you’re dealing with the ultimate lost circulation zone — The blowout well itself, and above that, the Gulf Of Mexico. In theory, you’d be pumping mud until it came out the BOP and started traveling up the LMRP. In short, they’d better damn well have that Overshot Tool in place to make (at least) a partial seal. Otherwise, the mud U-Tubes up and out into the Gulf, and the mudweight that would balance the well at the mudline is damn high, as we’ve seen the math in previous threads.