But as the unconventional continues to become the conventional, the array of available systems is growing in tandem to help tap into these hydrocarbon resources.
For example, Packers Plus Energy Services Inc. is probably best known for its StackFRAC HD system—a series of open-hole packers combined with ball-activated frac ports that the company developed in 2001 to access and economically produce low-permeability, tight-rock formations.
“What the system does is it allows you to do multiple fracture stages, each done individually, on one segment, and then just by dropping a ball at surface and pumping it downhole, you can simultaneously shut off the lower section and open the next stage up the wellbore,” says president and chief executive officer Dan Themig.
“If you look at the drilling rig count in western Canada, for example, or even in the U.S., now the vast majority of rigs are drilling horizontal wells. Not all of them use our completion methodology, but a lot of them do.”
According to Themig, while northern Alberta’s Duvernay Formation would likely be the major contributor to recoverable hydrocarbons in Canada over the upcoming years, the formation is challenged with expensive, difficult-to-drill wells that are high-temperature and over-pressured, making completions difficult. As far as open-hole systems go, Themig says, Packers Plus is really the only company with the equipment fit for the play.
“What we utilize in there is our Titanium system, which is a super high-pressure, high-temperature series of packers and ports. They are rated to 15,000 psi [pounds per square inch], and I believe we have been, and currently are, the only company in the world that offers those temperature and pressure ratings.”
Another ball-drop alternative to plug-and-perf is Trican Well Services Ltd.’s i-Frac CEM system, which David Browne, vice-president of communications and marketing, says is unlike Packers Plus’ systems because Trican’s is cemented in place instead of being run and set in open-hole.
“It is sliding-sleeve technology activated by dropping a ball. What is on the other side of the sleeve is a port, and when you slide the sleeve, it opens the port, so when you [apply] pressure up against it, you create your fracture at that point. Just like with the plug-and-perf, you are going downhole and perforating where the geologists think is best….
“We pump cement down, just like you would with the plug-and-perf operation to cement the liner or casing into the horizontal part of the hole, but instead of going in with a perf gun and perforating, we are able to drop a ball and open one or many sleeves with the dropping of that one ball.”
With an open-hole packer system, Browne says, every sleeve down the well requires a packer pressing against the rock to isolate sections, making that system a bit more expensive.
“They generally just open one sleeve per ball drop, whereas we can open up to 20 per ball drop, and so we get a bit more efficiency there,” he says, adding that in an open-hole system with a sleeve opening up, for example, a 50-metre section of open-hole behind the casing cannot control where the frac is going to initiate.
“You have the best of both worlds with our system. You can do many pinpointed zones like you do with the plug-and-perf, but you also have the speed of operation and the convenience of the ball-drop system.”
Multistage fracture technologies at NCS Energy Services, Inc. started with the development of a downhole tool allowing operators to abrasively fracture a set of perforations before moving the tool up the hole and repeating the process, which was one of the first multistage systems of its kind.
According to Eric Schmelzl, vice-president of strategic business, NCS perfected that tool’s design and refinement to function properly in a horizontal wellbore—a precursor to developing the company’s Multistage Unlimited system where a frac sleeve is run as part of the casing, and the same bottom-hole assembly (BHA) is used to either open the installed frac sleeves or to jet cut and isolate new perforations at any desired location in the wellbore.
“The use of frac sleeves was a significant step forward in the speed with which one can open up a set of ports and fracture them, rather than abrasive jet cutting, which takes time and fluid. As operational speed went up, of course the number of stages one could do in a day went up, and one of the drivers in the industry is to refine processes to provide ever shorter times to place each stage.”
AUTOMATED ASSEMBLY KEY
Since StackFRAC’s inception, Themig says, the industry has moved to higher and higher stage counts, which is probably one of the biggest drivers leading to technological advancements. With a constant need to bring efficiency and cost-effectiveness to drilling projects of higher stage counts, Packers Plus has invested heavily in robotics and automated assembly at its manufacturing plant in Edmonton.
“When we had five packers in the well, it was not very hard to ensure everything was built correctly, but now when we are doing wells with 40 packers and 40 ports and several other components, reliability factors on equipment becomes extremely important,” Themig says, adding that ensuring quality control is of increasing importance for companies providing multistage fracture systems.
“Technology is innovation, but it is also reliability.”
According to Themig, another key Packers Plus technology is the SF Cementor stage collar, which enables open-hole, cemented-back completions and allows a fracturing system to run as a monobore.
“Basically, instead of putting a whole series of casing strings in, you’ll typically just put in surface casing to protect the groundwater near the surface, and then you are able to run a single liner or a single piece of pipe all the way to total depth, and then you are able to effectively cement the build and vertical sections to protect other zones while keeping the horizontal section open-hole.
“That really has been a key technology, and we now have additional-stage cementing technologies that are groundbreaking in that their reliability factor is much higher, and we have built in redundancies so that if there are any problems, we have a backup system to provide sealing.
“So really, if you want to look at some of the key technologies, then that would be another one a lot of operators in western Canada would say has made tremendous strides towards cutting drilling time from 20 days to, in some cases, 13 or 14 days. These are the things that have had a really positive effect on the industry.”
Themig says Packers Plus’ QuickFRAC system, now in its fifth generation, allows operators to not only pump a high stage number, but also allows pumping anywhere from three to five stages at a single time.
“If you’re going to do 50 stages, instead of pumping 50 individual jobs, you might be able to pump 10 jobs at the surface and create 50 stages downhole by doing five at a time, three at a time or whatever the number might be,” he says, adding the company is also in the process of releasing ScreenPORT sleeve technology, which is ideal in areas where the rock is not very competent.
“[ScreenPORT] allows us to perform stimulation work, and when the well begins to flow, it actually flows back through a screen that filters any sand that might be produced by a well if we didn’t have those components.”
It is because of natural fractures and permeability—especially in unconventional reservoirs that do not produce uniformly out of the matrix rock—that the Packers Plus open-hole system offers ultimate recoveries in the range of 25–100 per cent higher than a cemented system in certain environments, Themig says.
Packers Plus recently completed a study in the Bakken comparing production of cemented systems fractured with coiled tubing versus open-hole systems. While cemented systems seemed to perform better at first, the data indicated that in the long term there were huge recovery differences favouring open-hole, delivering additional revenue in the range of $2.8 million in 30 months when compared with cement and coiled-tubing fracture completions.
CEMENTED TECHNOLOGY PROVIDES EDGE
Browne says cementing Trican technology in place provides a greater ability to work with a well as it matures, for example, if there is an area that is producing a lot of unwanted water.
“You have the ability to seal off those ports that are causing the water—you could pump in a bit of cement. Future work-overs and future refracturing to get more recovery from the well is more likely with this system than with the open-hole system.”
With an open-hole system, he says, there are limited options regarding scaling problems in a near wellbore area in the formation. “It would be hard to treat that in an open-hole situation, whereas in the cemented situation you could treat that—you put some acid down there and dissolve the scale.
“Cemented technologies are relatively new to the Canadian market-place, but we think that as the fields mature and [operators] want to improve their production, there will be a lot more opportunities for success and ways of doing things when you have a cemented-in system rather than an open-hole system.”
Browne notes that while typically cemented, his company’s i-Frac system can also be employed with packers, which could come in handy in a formation with a lot of natural fractures and permeability contributing to production.
According to Browne, many operators prefer plug-and-perf in a true shale gas play because such systems can pump down the casing at higher rates. Therefore, according to Browne, for very thick shale such as the Horn River, most operators are sticking with plug-and-perf rather than ball-drop systems that are offered by Trican.
However, he says, if an operator is doing work in the Bakken or in the Cardium in Alberta, the oil-producing zones are not as thick, the size of the frac volume does not have to be as big and the whole height of the pay zone is easy to frac with normal rates. In that case, Trican’s system becomes very advantageous over plug-and-perf, as rates need not be as high.
Trican’s record with i-Frac is 122 sleeves, over 23 stages, averaging about five sleeves in each stage, completed in the Eagleford play in Texas, according to Browne.
“Theoretically, we could do up to 400 fracs. One ball could open 20 [sleeves], and with 20 stages, that is 400. We don’t think we will get there anytime soon; we don’t think there is a need to. However, there is always a possibility that there is a formation out there somewhere that needs that many. I’m thinking, though, that we will likely push up to the 150-sleeve range, which is well within the capability of the technology.”
NEXT-GEN SMART SLEEVES
While the technology is still relatively new to the industry, Schmelzl says the next generation of sliding sleeves is already offering smart technology, which is what NCS, specializing in coiled-tubing-deployed frac technology and services for multistage completions, is currently bringing to its customers.
“We are making downhole measurements during the completion of the well and using the downhole tools to facilitate that data collection. To date, the downhole data has not been recoverable in any other cost-effective manner, preventing detailed knowledge of fracture stage communications in many cases.
“When you do ball drops [for example], you usually start with the sleeve closest to the toe of the well. You drop a ball that shifts it open, and then you frac it and drop a slightly larger ball that lands in the next sleeve up the hole.
“In that kind of operating environment, you have zero indication as to whether the open-hole packer or cement job actually isolated the individual frac stages or not. You are literally blind to what is happening up-hole, so folks are just pumping balls and hoping that everything is going the way it ought to be going.”
With his company’s system, Schmelzl says, the combination of coiled-tubing-deployed sleeves and bottom-hole pressure gauges located at the top and the bottom of the BHA, NCS can tell if there is a hydraulic communication path around either the open-hole packers or a cemented annulus.
“We have seen some wellbores with over 80 per cent of the frac stages communicating. That is extremely valuable data if your purpose is to optimize the frac spacing, well spacing or any of the other key design parameters.”
The principle difference between NCS offerings and many other systems is that with Multistage Unlimited, the fractures are placed one at a time, providing the knowledge of where they are and how big they are, and the peace of mind that the intervals have actually been fractured, Schmelzl says. Recently, NCS engineers developed a close-able option for the Multistage Unlimited frac sleeve.
Schmelzl notes that his company also has a straddle-frac system that can isolate existing openings, either ports or perforations, in order to fracture them individually. “If a re-stimulation was needed, then a straddle BHA would be the appropriate technology for that,” he says, adding that a variant of the NCS Mongoose BHA was recently introduced to facilitate refracturing of previously completed wells.
“While there are other multistage straddle tools that could be used in a pre-perforated casing, those systems do not typically allow operators to add perforations as they proceed, so they were not nearly flexible enough in all situations.”
For that reason, NCS developed the new SpotFrac BHA, which allows both the re-stimulation of existing intervals and the addition and stimulation of new intervals. With this system, according to Schmelzl, switching between jet cutting and fracturing operations takes place in seconds, without the use of balls or seats, making the system fast and effective in targeting bypassed pay.
“What a great many of the other systems do is they force operators to make lots of assumptions that at the end of the day prevent them from knowing what has been done to the reservoir. It can prevent them from knowing how many fractures have been placed, which in turn prevents them from managing the completion and ultimately the reservoir.
“It’s not just the fact that they may be gambling with the well completion—it’s that they don’t even know how the gamble turned out in the end. That is the downside to many of the other systems,” he says, adding the only real limitation of NCS systems would be how far the coiled tubing can reach.
“We have taken some steps to be able to pump the assembly down the hole, and we have done two-mile horizontal laterals with the existing Mongoose system successfully.
“It is largely a function of well geometry more than anything else, and for those instances where coiled tubing can simply not reach the extreme end of a wellbore, the company has introduced a new Ball-Shift cemented frac sleeve system that can place up to 24 frac stages at measured depths beyond the reach of the coiled tubing.”
Schmelzl says the new cemented Ball-Shift frac sleeves will facilitate closely spaced frac stages in even the longest of horizontal wellbores. “In all of the formations that we reviewed in Canada, we haven’t really found any that would not be applicable to this system.”
Kory Galbraith, vice-president of engineering at Elkhorn Resources Inc., says he started working with NCS back in 2011 to complete his company’s first multistage horizontal frac in the Midale Formation, which traditionally had not been fractured.
As a small-cap private producer, Elkhorn could not afford to take too many chances in attaining production, Galbraith says, and so he found NCS initially attractive because its technology very rarely missed stages. He has worked with the service company ever since.
“I’ve pumped over 1,400 stages with NCS, and I think I have only missed three stages out of those 1,400, and so their results speak for themselves. That was because the tool had backup ability in it so that we would never miss a stage.”