Completions and Collection. Comes the payoff—our efforts have shown that this hole in the ground holds oil. Now, how to get it out and off to market?
By Jesse Mullins
Editor’s Note: Last issue, as part of this series on “The Making of a Well,” we covered the drilling process. Now that our well bore is drilled, we turn to the business of “completion.” In other words, we’ve decided that this is no dry hole, and that our well is worth the additional dollars it will take to run the casing, do the cementing, and follow up with all the other steps—perforation, well stimulation, flowback, etc.—to bring the crude to the surface and on to market. For the lowdown on these last steps, we spoke with two veteran professionals, each of whom brings a different perspective to the topic. Phil Kendrick, who has been cited in each of the last two installments of this series, is representative of the smaller-to-mid-sized independent. He might be thought of as more of the turnkey, “old school” oilman. Vithal Pai is more of a specialist—he is an expert on completions—and his work takes him to some of the biggest hydraulic fracturing jobs being done in the Permian Basin. Bear in mind that each speaks from his own perspective, and Kendrick’s views are consistent with, typically, conventional plays and vertical wells, while perhaps the majority of Pai’s jobs are horizontal wells tapping unconventional plays. With that, we give you Part III of our primer on that great invention—actually a family of inventions—the American-made and American-perfected (and Texas and New Mexico mastered) oil well.
When PBOG spoke to Vithal Pai, owner and president of Midland-based XACT Technologies, Inc. (the XACT stands for Experimental Advanced Completion Technologies), we thought our conversation would begin where the drilling process left off. In other words, we thought that he’d agree that when a driller had reached TD (total depth), that it was then that completion activity began. But Pai told us that it’s not so simple.
“There’s one little problem, in that the total depth itself is determined by the completion engineering,” Pai said. “In other words, in a horizontal well, it [completion] really starts before you reach total depth. Whenever you bend the straw—a well bore is like a straw—the point where you bend it is very important. The biggest mistake people make is not being in the right bend. The formation could be as much as 1,000 feet in thickness, so, for a completion engineer, one of the duties is to work with the geologist to determine where will be the best point for bending it to get the straw going [in the desired direction]. This needs to be stressed because a lot of people don’t emphasize it. They go directly to fracturing [as the point at which “completion” begins]. But the most critical question is, where do you bend? That’s where completion starts.
Of course, with many wells, completion does begin at total depth—if, for instance, the operation is a vertical well in a conventional play and not a much-larger-scale horizontal well in an unconventional (generally a shale) play.
And in such a vertical well, the business of completion would begin with the setting of the casing pipe and the cementing of that casing pipe to the rock wall of the borehole.
To understand what is occurring when casing pipe is set, it is helpful to consider the difference between drill pipe and casing pipe. Once the drilling effort has achieved total depth, all the drill pipe—the entire drill “string” that has been run downhole—is pulled out for good. The casing pipe, however, is a permanent installation. With the drill pipe, drilling mud is pumped to the bottom of the hole by being forced down the hollow interior of the drill pipe, all the way to the drill bit itself, and there at the teeth of the bit the mud is flowed out of the pipe through some ejection holes. Once the mud is forced out of the drill pipe, it has no place to go but back up to the surface, only this time moving up the outside of the drill pipe, between the pipe and the rock surface, in the space called the “annulus,” carrying with it the rock cuttings it flushed away from the bottom of the hole.
In a similar fashion, cement is circulated through the casing pipe. The cement is pumped downhole through the interior of the casing pipe, and when the cement has exited the casing pipe at the bottom of its run, it has nowhere to go but to be forced back up toward the surface, traveling, again, outside the casing pipe, into the annulus. When sufficient cement has been forced down into the casing pipe, the operator chases out the last of the cement with a plug or plunger-type device that is forced down by water. Any leftover cement in the casing can be drilled out later, but the result will be that all cement is pressed into the annulus, where it bonds the casing pipe to the borehole wall.
“In a vertical well, you’d almost always cement the whole thing,” said Pai. “But with this new technology, you can cement a pipe up to a point and then [go] open hole after that point. In other words, the vertical part is cemented but the horizontal—the ‘lateral’ is what we call it—is not cemented.
“The key thing is to keep the well bore clean. It has to be cleaned up because it’s got mud and all in it.”
When the operator begins to set the casing, he uses special spacers called centralizers that ensure that the casing pipe does not touch the wall of the borehole. “They make sure it’s right in the middle of that cavity,” Pai said. This helps maintain a uniform amount of annulus all the way down the hole.
Oilman Phil Kendrick, who was quoted in Parts I and II of our series, supplied some insights into the completion process also.
“Once you’ve reached total depth, you’ve got to decide what diameter of [casing] pipe you want to run, whether it’s 5.5-inch or 4.5-inch,” said Kendrick, president of Kendrick Oil Company, Abilene, Texas. “Unless you get into a deeper well, and then of course you might go with a 7-inch pipe. If you feel like you have a good well, you might want to run a more expensive pipe and a little bigger pipe. Out in [far] West Texas, they probably don’t run a lot of 4.5. They might down to, say, 6,000 feet but not below that.”
For the bigger, more ambitious, multi-lateral, horizontal wells in the Permian Basin, casing pipe can be as big as 13 inches in diameter.
But for the mostly smaller, mostly shallower wells that Phil Kendrick and other small independents like him drill, the smaller casing pipe is common.
“And then of course they run that [pipe] all the way to the surface,” Kendrick noted. Casing pipe is generally set from the bottom up in the well bore.
But “it gets complicated,” Kendrick added. For instance, if you’re talking about a vertical well, and if you drilled to a total depth of 6,000 feet, and if it looks like it’s going to ‘make a well,’ maybe, at 3,000 feet, then you don’t necessarily run your completion string to 6,000 feet. If you have a case like that, you might run only about 3,100 or 3,200 feet. You don’t want to run any more pipe than you have to. If you don’t have anything below 3,000 feet that you think you might want to perforate someday, then you just set enough pipe to cover the zone that you’re interested in, plus some ‘rathole’ [empty casing deeper downhole]. You want to have about 100 feet of pipe below the zone that you’re going to complete.”
The excess 100-200 feet of casing (rathole) provides a space where debris can accumulate, and sand as well, if there is some residue left over from a frac’ing process.
The bottom of the casing is the bottommost point where any cementing would occur, obviously. “We cement there, and, depending on how far up you want to run your cement—whether you want to run it up, say, 600 feet above where you’re going to perforate, or whether you want to run it all the way to surface, that’s a matter of operator preference,” Kendrick said. “Where we have Coleman Junction water, or any kind of bad water like the Coleman Junction water that is going to eat up your pipe, well, they might try to put cement across that shallower zone that has bad water in it. So then you would set what they call a DV tool. You will just set the DV tool below the zone you’re trying to cover with cement—the problem zone with bad water. And you’d probably cement all the way to the surface from that point.
“You can take a chance and not cover the bad zone, but if you got a good well, a bad zone can eat a hole in your casing in as little as a year. Sometimes it might take three or four or five years, but it’s better to stop and get that zone covered up while you’ve got the cement truck and everything out there.”
When a DV tool is set, that is considered a second-state cement job. The second stage can be cement that seals off a bad water zone or it can be cementing that is associated with a payzone that is going to be perforated and stimulated for production. In either case, the cement needs to be in place in those sections. But again, there can be complications.
“If you run too much cement in a hole, cement’s heavy, and you’ve got to calculate how heavy that cement is going to be,” Kendrick said. “Cement can be so heavy it can put way too much hydrostatic pressure down there, and break down your zone, your formation that you want to complete in, and fill it with cement. And that’s not good. That’s bad.”
When there’s too much cement in the target formation, “it’s hard to complete through all that cement,” Kendrick said. “It’ll never make as good a well if that happens to you. So you just want to be sure that you don’t have one solid column of cement that’s going to create too much pressure.”
Once the cementing is done, it’s important to run a “cement bond log” to test the quality of the cementing. If there are points where the cementing is substandard, some “squeezing” of cement into those areas, via perforations in the casing, can resolve those issues.
“These are things the engineers have to figure out,” Kendrick said regarding the cementing tasks. “But once you’ve got a good cement job the way you want it, then you decide how many feet you’re going to perforate and where you’re going to perforate. You decide how big a penetration you want to make and what type of explosive shot you want: a real powerful one or one not-so-powerful, one to try to get deep penetration up to 40 inches or one that just gets 6 inches penetration. And once you done that [perforated], the well might come in natural.”
But chances are that well stimulation is going to be necessary.
Pai, for his own part, said that when oil companies began drilling more laterals and began drilling them much farther into the target formations, the early thinking was that less, not more, formation stimulation would be the order of the day, because the wellbore was contacting so very much more payzone than ever before. “These laterals can be anywhere from a mile to two miles long,” Pai said. “And when you factor in the circumference of the pipe times the extended length, well, that’s a lot of [surface] area. You’re contacting a lot of reservoir and therefore you will not need any fancy completion methods. The initial feeling, just by intuition, was that we could produce naturally.”
But that has not been the case.
“They don’t produce naturally. They have to be completed, because you damage it [the formation] during the drilling process,” Pai said. “So the completion engineer’s job is to remove the damage that was done by the drilling process.”
That damage is removed by hydraulic frac’ing. Or perhaps it is better to say that that damage is overcome by hydraulic frac’ing. The frac job puts fissures in the rock that extend so deep into the formation, and so extensively into it, that a significant flowback of oil is produced.
“Now, about 99 percent of the time, hydraulic fracturing is the way to do it [‘repair’ the damage],” Pai said. “And you need a much larger hydraulic fracture than you used to. During vertical drilling you’re in the payzone for a few hours, maybe, that you’re drilling. Let’s say it’s a 100-foot-long payzone. You’re there for maybe two hours. During horizontal drilling you’re in the payzone for 9, 10 days, sometimes two weeks. The drilling mud is constantly doing its job in the formation, so you get a lot of what we call a ‘cone of damage.’ The ‘cone of damage’ must be removed. It’s really large at the heel, and as you go toward the toe, the cone tapers.”
To better see what Pai is saying, it helps to draw a mental picture. The vertical shaft of the well is often called the stem. Where the stem makes its bend, and changes from a vertical orientation to a horizontal orientation—that section is called the “heel” of the well. Then the endpoint of the horizontal dimension, the tip of the wellbore, is called the “toe.” If one thinks only of the horizontal portion of the well as a line that runs left to right, heel to toe, then the “cone,” turned on its side, would overlay that line, and the fat end of the cone would be found at the heel of the lateral, and the pointed end of the cone, the diminished end, would occur at the toe.
And that’s understandable, if we keep in mind the damaging effects that mud can have on a formation. Phil Kendrick already remarked on that tendency, in Part II of this series. And we can understand that the heel of the wellbore might experience many days of mud circulation, but the tip would experience very few days, and maybe even only hours, of contact with drilling mud.
Another way of looking at it is to compare a long lateral in a horizontal well to a shallow wellbore in a vertical well. In the vertical well, the drilling mud does not remain long in contact with the payzone. It can’t—the whole drilling process is relatively quick. Therefore the drilling mud cannot do as much damage to the interval, and the kind of intensive frac’ing that goes on in horizontal wells is not so necessary in a vertical. Or wouldn’t be, except for the fact that an interval in a vertical well might only be a few feet thick. But at any rate, it is not as damaged.
But in a very deep well that also has long laterals, there are parts of the well bore that are kept in contact with the drilling mud not just for hours but for many days.
“A lot of people think that’s why the toe produces better than the heel,” Pai said. “So the formation has to be hydraulically frac’ed. That is a big thing and it’s one of the reasons I’ve stayed in the Permian basin since 1975. I have worked in other basins, but this basin has made significant contribution to this new boom, to the new productivity. That’s what’s developed here, and it has developed here because some of the most experienced people in our industry live here. We have so many different formations here and there’s also a lot of entrepreneurs. Some of the best independent oilmen [in the world] live right here. People like Jim Henry and the people at Concho and all these companies that have started here.”
Pai remarked that there are two kinds of completion technologies: conventional and unconventional.
“The conventional reservoirs are the old, established reservoirs like the San Andreas, the Clear Fork, the Canyon Sand, Brushy Canyon, and Bone Springs, and then there are some unconventional reservoirs that are intermixed with these conventional reservoirs,” he said. “Most of these plays are called shale plays but they’re really not totally shale play. They have some form of conventional rock like limestone, dolomite, and chert that is mixed with sandstones and mixed with shale. If they were predominately shale usually you wouldn’t be able to complete because almost all the completion technology that’s used on it—about 99 percent—requires it to be hydraulically fractured using water, and shales by themselves are very sensitive to water. They start swelling and then they do what we call sloughing. So completion engineers have to be very competent and have to understand that the rock should not be water sensitive because if it is, then you have a bad project on your hands. Hydraulic fracturing will not work on it most of the time because the rock will unconsolidate and it will slough.”
Pai defined hydraulic fracturing as taking a fluid that is either a liquid or gas or mixture of the two and pumping it down into the well bore under high pressures to the rock to crack it open.
“And what happens with that pressure is it’s going through a small pipe into a small area, and as it goes outside the pipe in the formation, it creates a tremendous amount of frac area,” he said. “The principle is the same as is used in a hydraulic jack that lifts up a truck. A repairman can just lift up a truck with a jack. That principle is called Pascal’s Law. It’s applied to break up a tremendous area inside the formation. You are literally moving, or frac’ing, or cracking, rock like a mile by 200 feet so—a tremendous amount. Sometimes millions of square feet of area are being opened. And what we are now realizing is that these [manmade] cracks are also interconnecting with in situ or naturally occurring fractures in the rock.
“When you crack it open you create a pathway for that oil and gas to come to the wellbore. Otherwise it is like a very tight sponge. But when you open that fracture up, you create a pathway for the oil. In other words, as a scientist would say, you’re converting it from a radial flow to a linear flow, which is more efficient. So the oil and gas migrates to the wellbore, but you have to keep the fracture open, because as soon as you stop pumping that fluid in, that frac will start dispersing away into the matrix and the fracture will eventually heal. So what we do is we run some proppant in with the frac fluid, the proppant being usually sand or bauxite or some other material. It’ll help to act like a wedge and keep that formation open. But it also has another very important function: it’s abrasive and it abrades or erodes the rock and etches the rock faces, creating pathways also. When it goes through, it creates almost a ‘cavernous’ type of situation, so a lot of people like to run more sand and we now know that it doesn’t have to be all one size mesh. We’ve done anywhere from 100 mesh to 20. But the [mixture] also creates etching pathways and the fluid also dissolves some of the rock and creates ‘worm holes.’
“What happens, then, is that you get a situation that is almost like a tree, with its tree roots. We are creating something like that pathway that the tree has. The tree is doing it naturally, trying to reach nutrients and water. Every tree has its own root system, so after you do a frac job every well has a natural root system, as it were. And that frac system creates pathways towards the stem of the well, the vertical part of the well. It’s a very simple natural process.”
Pai said he tries to keep the whole process as natural as possible, using a minimal amount of chemicals and only what is necessary and user-friendly. “In other words, the materials are not corrosive or carcinogenic or anything of that nature or should not damage the aquifers or anything like that. That’s why you want to cement a wellbore, too—because you don’t want to damage naturally occurring aquifers.”
“When you do a sand frac, you can do a small one, you can do a big one, or you can do a huge one,” Kendrick said. “You know, it’s just whatever you want, or however much you want to spend. But it’s also about how tight the formation is and how much it’s going to take to break that formation up, to fracture it to the point where it’ll let more oil and gas come to the wellbore.”
Once the frac job has been completed, “you generally keep it shut in for about 24 hours to let everything settle down and try not to flow any sand back. At least you hope you don’t flow any sand back. You hope the sand will stay in the formation, in those fractures that you created, but that isn’t always the case. In fact, I’d say most of the time you do get some sand back, so sometimes you have to go in and take your packer off and go back in, open ended with your tubing in, and then circulate and try to get all the loose sand out of your rathole, if it’s filled with sand. You’ve got to get that all cleaned up to where there is no sand coming out before you go put it on the pump or set it up to flow. If you have a lot of sand coming back, that sand is very abrasive and it can be damaging to your surface equipment.”
At that point, the well should be ready for flowback. The pressures can be released and, as Kendrick indicated, one hopes that the well will flow.
“If not, you try to make it flow by treating it with something to stimulate the flow,” he said. “If it’s a limestone, you generally go in and treat it with a lot of acid. You break it down in an acid frac, without any sand. But now they’re sand-frac’ing limestones, which was unheard of until about ten years ago, and they’re getting good results. All that we used to do was acidize the limestone.”
At that point, the well will either flow or it will need to be pumped.
“If you have to put it on a pump, you will now have to run in your tubing, and your rods,” Kendrick said. “With that will come the need to make a pad for the pumping unit. When you’ve gotten your pumping unit all leveled out and installed and you’ve got electricity, then you can rod-pump it. Meanwhile, if you know you’re going to have a well, you’ll want to have your tank battery and everything already in place so that you can go ahead and flow the thing without having to shut it in for a long period of time. But if you’re not sure you’re going to make a well, of course, you don’t go out and spend on all that infrastructure—not till you know that you got a well. If you’re going to get a well and it makes, say, 150 barrels a day, then you got to have probably 300-barrel tanks and maybe a fiberglass water tank in case it’s going to make water. Also, in case you’ve got to have a gas separator, you’ll need that plus what you call a gun barrel or saltwater lockout. That’ll separate the water and then the gas separator separates the gas off.”
Asked if a pipeline connection would be needed next, Kendrick said that it likely would not.
“No, it’s nearly all trucked now. There are a few areas where there’s a pipeline close by, but it’s very rare that you’re going to be close enough that you can go connect to a pipeline. And even if one is close enough, it might be such high pressure that it would cost you too much money to try to get into the pipeline, so everybody pretty well hauls all their oil now.”
So… out of all of this, what is the most critical part?
Said Kendrick: “Oh, it’s all critical. And you’re probably in trouble already. It always seems like something goes wrong—that’s the unfortunate part about this business. You’ve got a lot of people that aren’t that experienced out there working today, too, and that’s a factor. And as for completion work, well, people that are good at completion—they don’t have to be engineers but they do have to have a lot of experience completing wells—and they are in short supply. All the good ones are being paid a bunch of money out in West Texas and in the Eagle Ford and in places like that. It’s hard to get good completion consultants, especially around here. So when you’re using so much inexperienced help, why, there’s a lot of things that can go wrong unfortunately.”
“You’ve gotta find a purchaser—you have to find who will give you the best deal.”
“One other thing about fracturing is that there are different aspects. You can fracture one well or you can fracture two or three wells at the same time in a process called simul-frac. There are also methods called zipper frac. I refer to all these terms as ‘saturation fracturing’ or ‘carpet fracturing.’ Initially, we used to do a single stage frac. Now we are doing anywhere from eight to ten stages to maybe 50 stage fracs. Per lateral. That’s one of the jobs I do. I pick where to perforate. I design the frac jobs and decide how much it takes. One of my approaches is to handle it like a manufacturing process. So I don’t treat every well separately. I try to do all my fracturing in a given field. I standardize things, where I can fracture several wells as a rapid pace. By developing a manufacturing process of my gun assemblies, my fracture treatments, they’re all identical. It’s like a template. What you find many of the people doing here is treating each well separately. The geology may be different but they all can be treated similarly, so you can cut your cost. One of the biggest problems right now is the cost have gone up tremendously. The costs have gone anywhere from $2 to $3 million a well to as much as $14 million a well.
“What happens for me is I have to coordinate things,” Pai concluded. “It’s like an orchestra. You’ve got so many different things you’ve got to watch, and if one of them fails the whole process fails.
“You know, before the boom started, there were only about three companies that were doing frac jobs. Now we have over 30 companies. It’s a tremendous boost. Take Texas Tech, for example. Before this boom started they had probably 100 to 200 engineering students. Now there are over 600 students in the engineering department.”
PBOG Magazine would like to extend special thanks to the four sources whose input enabled us to present this three-part series on “The Making of a Well.” For all three installments we shared the acumen of veteran oilman Phil Kendrick of Abilene, Texas, president of Kendrick Oil and Gas. For Part I we interviewed Mike Cure, of Cure Consulting, in Midland. For Part II, Geologist Tommy Blair of Abilene, Texas. For this concluding Part III, Vithal Pai of XACT Technologies of Midland, Texas. Thanks to all.