There is no single, universal completion system that works everywhere and for everyone, and a wide range of reservoir quality, pressure and fluid compositions in unconventional resources means companies must continuously evolve and improve their completion strategies to meet the needs of each circumstance.

Because U.S. tight oil and gas basins have lower rock permeability than in the Montney, producers south of the 49th Parallel use plug-and-perf more so to allow for much tighter fracture stage spacing, noted John Nieto, chief technology officer and co-founder at Canbriam Energy Inc. That is one way completions in the U.S. differ from what works — at least for Canbriam — in the Canadian unconventional space.

“The rocks down in the States tend to be true shales, and so they can be quite ductile — the Montney isn’t like that,” he said, adding with the Montney siltstone characteristics he does not see “a bigger bang for our buck” from pumping the same tonnes per metre of sand and water in Canada as works in the U.S.



Canbriam basically started by using industry-standard plug-and-perf completions on its Montney assets in Canada. However the company eventually moved to sliding sleeve in order to more precisely place sand and water downhole.

“The general industry trend across essentially all unconventional reservoirs is towards tighter spacing and more sand,” said Graham Janega, vice-president of subsurface. “We are no different than most in that perspective, but we have taken it one step further with a shift away from a limited entry or plug-and-perf completion, to what is commonly referred to as a ‘pinpoint’ fracturing system, such as the sliding sleeve.”

Conceptually, Nieto said, while the Montney has responded to tighter spacing and more sand, the improvements have not been as significant with those same completions designs as in the U.S. shale plays. “There is just a geological difference between the two.”

Janega added: “This concept of pinpoint fracturing means you don’t have multiple entry points you are blindly pumping into, hoping they all take fluid. And in reality we only typically achieve about a 60 per cent limited entry efficiency. With a pinpoint system, there is one entry point from the wellbore to the reservoir, and therefore you know where your frac is propagating from.”

Nieto told the Bulletin the sliding-sleeve system also enables the company to omit pumping into areas where there are natural fractures, which would potentially waste sand and water without breaking any new rock.

“You can leave out sleeves with these sliding-sleeve systems if you don’t want to complete there,” he said. “With plug-and-perf you can avoid a fracture system if you want, but by and large you are missing out on a much bigger interval. You can’t really control where the fluid is going as well as on a sliding sleeve.”

Further, according to Nieto, sliding sleeve enables better rock stimulation. With plug-and-perf, not all the perfs may take the volumes pumped, which means those that do will receive more pressure and could grow larger wings of stimulation into the rock. Therefore, there could be more overlap with plug-and-perf, because the operator does not really know how far into the rock goes the fluid. Sliding sleeve is more controllable.

“You are getting more accurate placement of a fracture,” he said. “The tradeoff is we think we are getting better stimulated rock with the sliding sleeve than we would with the plug-and-perf. We are looking at spacing between wells. With a sliding sleeve, we are putting in just enough sand and water for the sleeve.”

Royal Dutch Shell plc started using plug-and-perf with 50-metre spacing in 2010 for its Groundbirch assets. This lasted until 2012 when distributed acoustic sensing and micro-seismic data led Shell to conclude it was getting too many super fracs and inefficiencies in its frac distribution, causing well-productivity impairment.

“We moved to the open hole, and also we liked the competitive position of the open hole at the time — it was considerably cheaper for us where we were,” Mathieu Rae, area manager for Greater Groundbirch, said during a recent Canadian Society of Unconventional Resources (CSUR) B.C. unconventional gas technical forum. In 2016, Shell moved to single-point cemented sleeves for every well it deploys at Groundbirch.

He added: “We are trying various systems there, and why we like the single-point entry is it gives us controlled frac distribution, and we are quite surprised on the predictability on a pad from within the same lobe of finishing at the exact same production. So it is really giving us the frac geometry we wanted and the production expectations we were hoping for. We have over 25 wells to date, and we are growing with every pad that we bring on.”

Although more companies are switching to sliding sleeve, Nieto noted that it is not as if one particular system is the ‘right’ completions technology across the entire unconventional space. “The point to make here is the Montney is not the same everywhere. There are sweet spots and slightly different lithologies and different pressures. In our area we are nearly twice over-pressured, whereas some are normally pressured.”

Moving towards completions perfection at CNRL

Completion strategies for Canadian Natural Resources Limited have been in line with industry trends and have evolved over the years, starting with single-entry plug and perforation, then dual-cluster plug and perf, and now a strategy using open-hole ball drop with current technologies at maximum stages, company spokesperson Julie Woo told the DOB in an email response.

Looking at 2018, CNRL will use cased-hole systems with cemented ball-drop sleeves in the toe of the well and triple-cluster plug and perf operations in the heel. The upcoming strategy is targeting to achieve maximum entry points within the lateral to achieve tighter fracturing spacing.

Through continuous improvement practices and a strong culture of innovation, CNRL achieves operational efficiencies while minimizing land footprint, noted Woo. The company has been a top research and development investor for Canada’s oil and gas sector over the last number of years, demonstrating innovation is key to its focus.

At Septimus, CNRL’s Montney natural gas plant and horizontal well play in northeastern British Columbia, the company’s completions strategy over the last 10 years has been to achieve economical completion costs with tighter fracturing spacing and pumping optimum proppant tonnage per metre.

As a result of the company’s efforts, added Woo, over the last decade CNRL has achieved more effective and efficient completions with costs decreasing more than 80 per cent based on a per-tonne pumped metric. In 2018, the company plans to develop natural gas wells with laterals more than 100-per-cent longer than the 2010-to-2014 average well lengths, resulting in more cost effective drilling and minimized surface footprint.

Thinking inside the box

Encana Corporation has promoted extensively its advanced completions design, which the Canadian producer pioneered in the Eagle Ford and has transferred to all its core assets, including in the Montney and Duvernay. Further, a company spokesperson told the DOB via email, Encana’s “Developing-the-Cube” approach to simultaneous drilling and completions is an innovation that provides great value.

During its second quarter conference call, the company suggested that it outperformed its average 180-day initial production type curves between 20 to 45 per cent, driven by cube development and optimized completions that improve targeting and lower costs (DOB, July 21, 2017).


“We now have enough long-term data to be convinced that our dense well spacing is leading to true incremental recovery,” Mike McAllister, chief operating officer, said at Q2 about advanced completions and cube development. “We’re also encouraged to see … that each cube we have developed has outperformed our previous edition as we continue to progress our designs. The cube approach has benefits both above ground and below ground.”

According to McAllister, the cube is the best approach to maximize corporate returns. In stacked reservoirs, he suggested, there is a clear benefit to drilling and completing an entire cube at once. Crews minimize communication risk with depleted reservoir, and they avoid offset frac hits. Above ground, cube development provides both significant cost and cycle time advantages.

He said: “We can maximize efficiency and get higher utilization from our equipment, crews and infrastructure. Our approach has established us as a leader in stack pay unconventional rocks. I fully expect us to continue to find new ways to tune our approach by embracing technology to create value.”

In addition, added the company spokesperson, Encana has been experimenting with fibre optics in the Montney in order to gather data on completions and fracturing.

A tracer solution

During a recent CSUR Duvernay event, David Bonar, a geophysicist with Encana, highlighted a unique tracer experiment used to characterize stimulated reservoir volumes and identify where fracs perhaps overlap.

“Essentially, we have solid particles that have unique tracers embedded within them, and we mix those with the proppant. When we go to frac the pad, we pump the proppant into a stage and all the proppant gets dispersed into the reservoir. The tracers — solid particles — are mixed with the proppant, and so that is also in the reservoir.”

Hydrocarbons are tagged as they flow past the solid particles. Once produced, ‘tagged’ hydrocarbons show tracers mostly from wells into which those tracers were pumped, but might also show overlap in offsetting wells. Tracers help determine things such as how many stages are interconnected across a pad, or how far a single stage reaches.

Bonar said: “Essentially, one of the ways you can interpret tracer data is to just look at the concentrations that come back.”

Seismic inversion to optimize

Canbriam optimizes its completions by integrating completions engineering with geosciences, suggested Nieto. The company is extracting data from 3D seismic and using that information to help guide well placement.

“We are actually placing the wells in a stack, based on the data we are getting from the 3D seismic. This is called ‘seismic inversion.’ We are using this routinely to place our wells and also identify areas of lower porosity, and higher Young’s modulus, which could indicate a healed fracture zone that we wouldn’t be interested in completing.”

The company is basically doing static and dynamic reservoir characterization to understand the size of faults, porosity and saturations of rock between the faults, as well as the reservoir quality of rocks within an area. Nieto said: “The next step is to actually model how the fracs work. You actually frac a well and can simulate that with a very complicated list of input data. It is called a ‘reservoir simulator,’ and we are simulating frac jobs.”

Reservoir characterization helps Canbriam to determine when and where communication between the parent and child wells will occur during completion operations. With that information, the subsurface team and completions team can determine whether the company might want to, for example, drop a stage and skip an area of the wellbore.

“If we know two adjacent wells intersect a natural fracture, the probability of inter-well frac communication is much higher,” said Janega. “What we do is place our sleeves to avoid this type of feature, and never pump into it.  Therefore we would try to mitigate the offset frac communication.”

He added: “It has actually been very accurate. We have had a lot of success predicting when we are going to see frac communication. I think we have a pretty good understanding of what is causing this communication, when it is going to occur, and where it is going to occur between the two wells.”

Development planning so as to avoid offsetting the parent wells several years after they have started producing is key to avoiding parent well damage when stimulating a child well, at least for Canbriam. The longer the company waits to offset parent wells, Janega noted, the bigger the pressure sinks, which can lead to parent well damage. Therefore, the company has a mandate to try and offset its parent wells within one year.

The power of protection pump-ins

Canbriam is taking various measures to mitigate the negative impact of frac operations on the parent wells, including ‘protection pump-ins’ — a newer technology in which high-pressure gas is used to pressure up the parent well proppant pack and temper the impacts of a child well’s offset frac communication.

“This is a huge deal for development,” Nieto said, noting that with as many as 16 wells on pads and well spacing of about 300 metres, protective pump-ins are extremely beneficial when some degree of inter-well communication is quite likely. “A lot of people are just drilling parent wells, and we are actually getting into the development mode where we also have child wells and they will often communicate.”

He added: “What we are really interested in is the [parent] well coming back on at the same pressure and rate as it was before we did the frac.”

According to Janega, one of the main issues with parent-child well communication is damage to the parent well. However, another very important aspect of parent-child communication is the effectiveness of the child well stimulation, which can be compromised by asymmetric fracture geometry due to offset depletion.

“That is another very important aspect of what we are trying to do with protection pump-ins,” he said. “We are trying to ensure we do everything we can in order to effectively stimulate the child well.”

When stimulating a child well, Canbriam simultaneously pumps into the parent well to pressure up the near wellbore using a high-pressure compressor. Holding pressure on the parent well mutes spikes in pressure from the child well’s frac, and reduces cyclic stress on the parent well’s proppant pack.

Janega told the DOB: “We shut the well in because we know we are going to hit it, we protect the well with the protection pump-in, we hit it, bring the well back on, and we’ve seen wells quickly return back to pre-frac rates. So the casing pressure returns to where it was, and the gas rate returns to where it was. That is the primary objective of a protective pump-in.”

Unlike other companies that pump water in to protect their parent wells, Canbriam pumps in high-pressure natural gas from an offsetting well or fuel gas. Whereas pumping water can potentially damage the formation, pumping gas (particularly gas from the same formation) poses far less damage risk.

“Water is quite viscous compared to gas,” he said. “When that water goes into the rock it sticks within the micro-pores of the rock, and it’s very hard to actually get that water out.”

The benefits of choking

Canbriamis an avid proponent of choking back wells, usually at five mmscf per day, Nieto said. Some choked wells have been producing at this rate for years.

“There are lots of good reasons for choking, but one of the fundamental reasons is our wells come in at such high initial rates and formation pressures, that we could pull sand out of the completion. It is expensive to place sand, and so we are trying to keep it in the formation.”

For its part, at Groundbirch Shell has a very strict process on its flowback to keep it below the velocities that will actually mobilize the sand, noted Rae.

“We keep a close eye and actually have a real-time calculation with the pressure we have to get the right velocity to avoid sand production,” he said. “In terms of compaction of the sand, we are very particular with which mine we use, and we have controlled that to ensure we have less crushing. We haven’t seen major issues on crushing at the moment.”

For Canbriam, according to supplemental information in October’s corporate presentation, better sand management through downhole chokes also protects surface pipe integrity. Choking is primarily applicable in liquids-rich reservoirs — the higher the pressure differential between the initial reservoir pressure and the two-phase region of fluid, the more beneficial is choking, because the longer liquids remain entrained in the natural gas stream, said Nieto, the better.

“When you draw the pressure down, the liquid can drop out. As you reduce pressure, the liquid comes out of the system. That means you have sort of a liquid annulus surrounding the wellbore, which can limit or decrease the flow.”

He added: “The other thing is if you are drawing down the reservoir, then you are actually reducing the pore pressure and effectively compacting the rock. When you compact the rock, you lose some of the permeability too.”


Completions evolution from the oilfield services sector seat

With evolving completions strategies come more requirements on oilfield service companies, according to Mark Salkeld, president and chief executive officer of the Petroleum Services Association of Canada (PSAC).

“On some of these more complex multi-well pads and completions processes, we are showing up to 42 different service companies,” he said, adding companies offer services such as fluid management for producers increasingly concerned about freshwater and reusing produced water and frac fluids. “There are companies that have popped up that are specialized in managing that water and treating it like a commodity almost — like a drilling fluid.”

Salkeld told the DOB that service companies give customers much more effective wells than was possible even a few years ago. He attributes improvements to longer wellbores and the ability to stage fractures and experiment with different fracture types. He noted industry is also using more ‘green’ fluid and less sand in completions.

“They are experimenting with every single wellbore. Water is still a concern, and an obvious concern, and so we are trying to come up with alternatives — different fluids, green fluids, saltwater and brine from deep reservoirs, produced water from saline formations that would never see the light of day otherwise. It’s a whole variety.”

He added: “The completion techniques are changing all the time with different formations and different kinds of formations. There are different kinds of tools and different fluids.”

For oilfield service companies, currently their biggest challenge is the price that customers will pay for services, suggested the PSAC president. “[Producers] want more efficiency, more productivity, but they are not willing to pay more for it. The challenges for the services side of things is that we can do it, but healthy margins give us that extra money to do R&D. Right now, we are not experiencing healthy margins.”

He added: “It is the same thing with the hydraulic fracturing companies. [These companies] are using information to get their equipment better suited to withstand longer fracking periods, but this all comes with healthy margins, and while some of the bigger companies have the wherewithal to do it, some of the smaller companies are just providing the basic services.”

Going global

According to Salkeld, industry certainly takes “gains and wins” from the U.S. energy sector and applies those in a Canadian context, and vice versa. “There is definitely an information swap going on,” he said, adding producers such as EnCana have operations in plays across North America and they definitely share information. In fact, Salkeld noted, the knowledge sharing is going beyond Canada and the U.S.

“Fundamentals like walking rigs, hydraulic fracturing and directional drilling … are applicable anywhere in the world, and are more applicable because they are accessing tight rock where there are the economics. The U.K. is a perfect example — they are going to frac pretty quickly over there, if they haven’t done so already.”

In Britain, as well as elsewhere internationally, there are different styles of rock than in North America, Salkeld said, and thus producers must still experiment to see how practices from Canada and the U.S. will apply in those other contexts. “Lots of countries are very interested in learning more about these technologies and applying them, because they have these resources under their own feet with the shale plays they have.”