The big oil companies have become very safety conscious. That’s all you hear about with them. And most of them mean it. Big change from when I started out as an ARCO drilling foreman in New Mexico in the ‘70s, when the way to deal with hydrogen sulfide gas was to hold your breath. I had to give a roughneck mouth-to-mouth when he collapsed from inhaling it on a drill stem test near Artesia. Surprisingly, he survived. One good whiff of sour gas and you generally croak. A production hand climbed up on our 500 barrel test tank to check the amount of oil in it. He died while peering into the hatch.
Today, the pendulum has swung the other way. The first time the H2S alarm goes off, we evacuate and the designated guy, sometimes me, dons the air tank and facemask and investigates. Hands get written up for no safety glasses, no seatbelt on the forklift, smoking, using a cell phone on the mud pit, no steel-toed boots and lately, not wearing fireproof (cotton) clothes. I always think back on that John Wayne movie about Red Adair where they were installing a wellhead on a “blowing” well, no eye protection, with the high-pressure mud and junk blasting into their eyes – for real – and wonder if anyone lost his eyes making that scene. So, safety is good.
Maybe there’s a reason the company is in such a hurry to get the oil out of the ground. I’d just never heard of drilling more than 8,000 feet in twenty-five bit hours, with water. No drilling mud – just fresh water. Skidding the rig sixteen feet and starting the next one. Twenty-five bit hours (actual drilling), electronic logs, running casing and cementing – three and a half days. Now, a lot of this is due to the easy drilling, obviously. In most places in the country where I’ve worked, 8,000 feet could take ten days, two weeks, or much longer in hard formations. But these guys are running this like a contrived TV program, the different rigs trying to set or break speed records. The hands are only doing what they’re ordered to do by the operator – the oil company.
In February, I was hired as a drilling consultant by a large independent operator based in Texas. After a couple of days spent learning the computerized daily reporting system, my new boss, the senior drilling foreman for the company, called me on my cell phone and told me to drive to a rig that was experiencing high-pressure gas problems, that he wanted “to test my (well-control) skills,” as he put it. He said he would meet me at the rig later.
I drove over, went into the company man’s trailer and introduced myself to my counterpart, the drilling consultant whom I would be relieving. He was doing paperwork. I asked what was going on? He said they were coming out of the hole with the drill pipe and directional assembly to run casing. The bit had quit drilling at 8,000 feet, several hundred feet above TD (intended total depth) and maybe the mud motor had broken. Hard to say. Is there a gas problem? He shrugged and said they’d been fighting it for a couple of days. He said the chief engineer had been there and told him to come out of the hole and start running casing.
Did he mind if I went up on the rig floor? Nope.
Now, this was extremely unusual, for an outsider such as I to be sent to another guy’s jobsite. Why didn’t they test his well-control skills? I’m sure the other company man was irritated that I was there, and I couldn’t blame him. I would have been extremely irritated, especially if I had been given bad orders which I was duly following. It didn’t make any sense. I’m reluctant to tell this story because it really doesn’t make sense. But it is an indicator of what’s going on in this country.
Up on the rig floor, the driller greeted me uncertainly. I asked what was going on? He said they were about half-way out of the hole, at 4,200 feet. I looked out past the rig floor at the mud pits, the huge steel tanks that held the hundreds of barrels of drilling mud. Great gouts and bursts of mud were shooting up twenty feet high from the possum belly, where the mud exits the horizontal flowline from the well and pours back into the rig’s mud system. “What’s that?” I asked rhetorically. “That’s gas, and it gets worse than that,” he answered drily. “Uh, huh. Stop right here.” With a large sigh, he ordered the roughnecks to set the slips. Rather unnecessarily I remarked, “We can’t come out of the hole while we’re taking a kick.” The driller nodded in total agreement. I really couldn’t get this, these guys being ordered to do everything we’re trained not to do. Did the letters “BP” mean anything?
I got on the phone and called my new boss, “Hey, they’re about halfway out and they’re taking a big kick.” He said he’d be there shortly. The toolpusher appeared and we compared notes. I asked if they’d recorded shut-in drillpipe pressure? He said they had, down at 8,000’. They’d first taken the gas kick at 7,600 feet a day earlier but had not performed the routine procedures to bring it under control. In order to figure out what weight your mud needs to be to control a kick and prevent a blowout, you need to shut the well in with the blowout preventer and record the amount of pressure coming up the drillpipe. It’s called SIDPP, or shut-in drillpipe pressure. The formula is pretty simple: you divide SIDPP by .052 and divide that by the true vertical depth in feet and add that number to the current mud weight. That will give you the Kill Mud Weight, or how heavy the mud needs to be to control the gas pressure coming up from down below and prevent a blowout.
I said to the driller, “We just need to follow standard procedure.”
“Standard procedure! That’s what we’ve been wantin’ to hear from somebody for two days!” I thought, what the hell’s been going on here?
The toolpusher told me that SIDPP was 450 psi and my calculations indicated that our mud weight needed to be raised to around 13 pounds per gallon, a mud weight that was unheard of in the area, where they like to drill with water that weighs about 8.5 pounds per gallon. I reported my calculation to my boss, the senior drilling foreman. He in turn called his boss, the chief engineer, who said to tell me to kill the well where we were, at 4,200 feet, with 12 pound mud. I said, “We can’t. We have to run back down to TD and kill it there.” But those were my orders.
Sure enough, we couldn’t kill it half-way out of the hole with that mud weight. The chief engineer came back out to the rig and I introduced myself. I also introduced the idea that we needed to run all the way back down to 8,000’ and do this correctly. And that it would probably require a mud weight of thirteen pounds per gallon. “Oh, let’s not go there,” he said quickly. I said, “I know we’ve got a frac gradient to worry about but we also have this rig to worry about.” I didn’t really know what the fracture gradient was here, but he nodded, indicating that that was a potential problem, fracturing the formation with mud that’s too heavy and losing circulation and control of the well. That turned out not to be a problem. The problem was that these guys were speed freaks used to drilling with 8.5 pound water and no mud. The problem was that they didn’t like delays such as this.
“How do you figure we’d ever need 13 pound mud?” he wanted to know.
“Well, shut-in drill pipe pressure down around 8,000’ was 450 psi…”
“Where’d you hear that?” I didn’t rat out the toolpusher, who was behind me.
“I just heard that’s what it was.”
“No, it wasn’t. It was never that high.” I shrugged and sat back down while we watched the mud blowing up out of the possum belly. Eventually he gave the order to run back down to 8,000’ and kill the kick. And it took two days and 13.7 pound mud to kill it.
Our problems were just starting. The heavy mud created a condition called differential sticking. The hydrostatic pressure down the hole with that heavy column of mud was higher than the formation pressure and the pressure differential made the drillpipe stick to the wall of the hole. We’d prevented a blowout but were stuck in the hole. So, standard procedure was set in motion. We had about a half-million dollars of equipment stuck down there. If it couldn’t be retrieved, we’d have to leave it and pump cement around it and start over. It’s not something a drilling consultant wants on his CV, even if it wasn’t his fault. So we free-pointed the drillstring by stretching it and measuring the stretch with an instrument we ran down the inside of the drill pipe on a wireline. Then we ran in with an explosive charge of det cord on the wireline, put a left torque on the drillstring and detonated the det cord right at a connection. We backed off the “fish,” (the stuck portion) and came on out with the free drillpipe, leaving the expensive stuff, the mud motor and directional tools, in the hole.
The next step was to run back in with a set of fishing jars and screw into the fish. Then we pulled up and set off the jars, which are supposed to nudge the stuck part up-hole. We jarred and pulled on it for a couple of days, to no avail. So here was where I made my wages, besides preventing the blowout in the first place: I proposed to the company that since we had over 500 barrels of kill-weight mud in storage, plus the 450 barrels of it in the hole, that we change the hole over back to fresh water and induce a gas kick and neutralize the differential pressure that was sticking us. I said, we know how to kill it and we’ve got the kill mud to do it on hand. Well, that was considered too radical. Then, after four more days of fruitless jarring and pulling, they said, Okay, do it. And we did and it worked like a charm. We pumped fresh water down the drillpipe and when a couple of hundred barrels of it started up the annulus the drillpipe started to move. We immediately started pumping the kill mud behind it and prevented the severe gas kick that the company had feared. Apparently never been done before in that area. And we brought out the entire drillstring and the half-million in drilling equipment. But our problems weren’t over!
Since we’d been jarring and generally tearing up the hole, I recommended what’s called a wiper trip, which is just standard procedure. When we got the bit out of the hole and inspected it, we found that the PDC (diamond) bit had been ground down from its original 7.875” diameter to about 5.5”. Not good. But, the company reasoned, the casing we’re running is only 4.5” in diameter. Should be okay. I said, but we really need to wipe it and ream it out to the full hole size, since the hole had been directionally drilled in a big S-curve and there would be a lot of friction on the lateral section. No, just go ahead and run pipe.
So, we ran the casing and it stacked out about two hundred fifty feet above TD. Not good. And it got stuck there. Really not good. Shoulda wiped the hole, boys. But I had the sense not to point that out, since they didn’t seem to like me much at this point. They said, cement it where it is. Now, it got ugly. The company wanted what’s called a weighted water spacer pumped ahead of the cement. Spacer and cement would each weigh over 15 pounds per gallon. Well, what we got when we pumped the cement was almost all of it back. We all had never seen so much cement returns. You’re supposed to get some but what happened was the spacer channeled through the heavy mud, made a little tunnel all the way from 8,000’ to the surface and the cement followed up the little tunnel, instead of displacing the mud and surrounding the casing as it’s supposed to do. That was the problem with the BP Gulf blowout – the Halliburton cement job was no good, just like this one, and the high-pressure gas was allowed to communicate to the surface, also through that little tunnel. You can imagine that all this was going through my mind for all these days.
The cement job was done by late afternoon. Wait on cement to harden up for a few hours and then install the wellhead, secure the well and skid the rig to the next location. At midnight, however, the driller and toolpusher came to my trailer with very bad news. “You better come look at this.”
“We got cement coming out the backside.”
Sure enough, cement was oozing out the casing valve at an increasing rate, which none of us had ever seen before. I called the company and was told to put a gauge on it. We did so and within an hour, pressure had built up on the casing to over 1,000 psi. This was extremely bad news because there was no good way to control this pressure other than to shut it in. But with that kind of gas pressure, with no cement around the casing, we had the potential for the ultimate oilfield disaster: a crater. That’s what can happen if the gas comes up outside the casing, escaping upward between the casing and the formation due to no cement shutting it off, which is the whole purpose of a cement job.
I was asked for my recommendation, which was first, run a cement bond log and then a squeeze job. Very standard procedure for a bad cement job. What had happened on the Deepwater Horizon was similar. They had a bad cement job. And a Schlumberger wireline crew had been on the rig for a couple of days preparing to run a routine cement bond log to find out where the cement bond was good and where it was bad. But my counterpart on that rig, the BP company man, told the Schlumberger guys to go on home, that there’d be no CBL. Even Halliburton was surprised at that, saying, “Well, we’ve got to have a CBL.” Nope. Imagine, on an extreme high-pressure well such as that, the US government agency in charge of overseeing it allowing such a violation of standard procedure – it’s unthinkable.
The cement bond log showed that we didn’t have a cement job, obviously. Since we’d cemented the casing in two stages, we couldn’t run the wireline CBL tool below the stage tool at 2,000’ without drilling it out, which they didn’t want to do. So we shot holes in the casing at 1,700’ and tried squeezing cement through them, but couldn’t get an injection rate. Shot more holes at 1,500’ and got a great injection rate and I pumped four hundred sacks of cement. And then the damndest thing happened: the chief engineer ordered us to open up the casing valve. The whole idea of a squeeze job is to squeeze cement through those holes you shot in the casing against pressure. But with the casing valve opened, there was no pressure to squeeze against, and the cement was pushed out the same damn casing valve by the pump pressure coming from cement pump truck. Again, the gas pressure on the casing built to 900 psi very quickly. We had to explain to the chief engineer that a squeeze job needs the casing valve closed. We had one more chance to do this squeeze job, as we were running out of room on the casing.
So we shot four more holes just below the surface casing shoe at 580’ and were finally successful in getting a cement squeeze there, filling up the annulus with cement and at least temporarily preventing a cratered blowout. Pressure on the backside was at last zero, right where we wanted it.
The company informed me on the last day of my shift, after three weeks of making my wages, that they didn’t think I was a “good fit” for them and didn’t want me back. I agreed and said so. First time I was ever run off, though. The hands weren’t glad to see the “standard procedure” guy leave.
This was an extremely disturbing experience, as the non-oilfield reader might also understand. It could have all been avoided by following standard procedure long before I showed up. Instead of drilling with lightweight water and going after speed records, they ought to be drilling with mud and slowing down a little. Their actions after encountering the serious gas kick were reckless and incomprehensible and frightening to the drilling crews working for them for those two days of blowing gas and mud. All six drillers I worked with over those three weeks pointed south to a location where four hands were burned to death in a blowout a few years earlier. This company wanted these guys to keep coming out of the hole with gas and mud blowing and then rig up and run casing. One spark and it would have all been over.
As it is, I can’t help but wonder if that squeeze job around the surface casing will hold that high pressure gas coming up from around 7,600’?