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Frac Signals: Using microseismic monitoring to optimize fracture stimulation


As the unconventional sector grapples with its first major industry downturn since the hydraulic fracturing revolution opened up many new North American oil and gas reserves, 
a key to traversing these tough economic times will include lowering costs and improving production through implementation of better fracture monitoring.

“I think the companies that are innovative technology developers, suppliers and service providers—like us—will emerge from this and will help the industry to get back on its feet again, producing at a lower cost,” says Jorge Machnizh, chief executive officer of Sigma Cubed (SIGMA3).

SPARSE NETWORKS A Nanometrics field engineer works with a broadband seismometer. By installing continuously monitoring, permanent networks, Nanometrics can provide immediate, real-time feedback on seismicity and the environment in which operators are producing. (PHOTO: NANOMETRICS)

“We will see jobs coming back into the industry, more complex types of drilling will take place. I see this period as an opportunity for the industry.”

As the emphasis on monitoring becomes more pronounced, for its part, the Microseismic Industry Consortium and its partners are studying the links between hydraulic fracturing and geomechanics, as well as induced seismicity.

“This is now where a lot of companies are focusing their attention—to see what is actually going on during a hydraulic fracturing treatment,” says Mirko van der Baan, a professor in exploration seismology at the University of Alberta.

“We don’t yet understand the long-term efficiency, and that means people are trying to better find out how to make the treatments more effective long term, and as well how, from the monitoring, [to] actually predict what will be the production decline curves. This is something for which a lot of work is being done, as well, in the consortium.”

A partnership between the Universities of Alberta and Calgary, the consortium includes academia and industry advancing know- ledge and practical applications of microseismic methods to monitor hydraulic fracturing operations.

According to David Eaton, professor of geophysics and former head of the Department of Geoscience at the University of Calgary, there
is a scientific disconnect when it comes to truly understanding the geomechanical links between microseismic monitoring recording and what interests reservoir engineers, including fracture size and distribution, as well as proppant placement within the fracture system.

“Bridging that gap by understanding the small-scale processes taking place will significantly advance our ability to make full use of the microseismic data recorded,” he says, noting microseismic events are tiny earthquakes in the subsurface that represent brittle failure in the rock layer.

With pros and cons to either option, the two primary fracture- monitoring methods include placing low-frequency microphones called geophones down a wellbore, or else placing those sensors at the surface using much larger arrays, says van der Baan.

“When people do it inside the boreholes, they must have boreholes available and are therefore essentially restricted by where those bore- holes are. It is quite expensive to drill, and so people don’t want to drill more than they have to for observation wells.

“The advantage is you are closer to the source, because many of these reservoirs are at a two-kilometre depth. If the borehole is nearby, then it makes it much easier to pick up very, very weak signals.”

He adds, “If you are at the surface, the advantage is it’s much cheaper to put thousands of [sensors on] the surface, rather than drilling a borehole specifically. The flexibility is that you can use much, much more equipment, but you are farther away from the source, and so you need this much equipment to pick up the microseismic events.”

Then there are hybrid methods using shallow borehole acquisition that attempt to trade off the advantages of both the borehole and surface approach. Complimenting microseismic monitoring technologies are tiltmeters and satellite remote sensing for microdeformation and surface deformation studies. Eaton says, “There is a lot of scope for scientific and technological enhancements by integrating those different methods.”

In some cases, companies perform microseismic monitoring in real time, meaning analysis occurs during the fracture treatment itself and provides immediate microseismic feedback to the hydraulic fracturing operations. In other cases, Eaton adds, microseismic data is processed following the fracture work. “Any information that comes from that can be incorporated into the design of the next treatment.”


Nanometrics is opting for a sparse network long-term monitoring strategy to provide insight on the natural seismicity of an area, thus illuminating many natural faults, enabling companies to assess or quantify the existing subterranean stress field and therefore run better frac completions.

“If you have a good understanding of the broader geology, stress field and seismicity, then you are better placed to operate in an area,” says Neil Spriggs, co-chief executive officer of global operations for the Kanata, Ont.–based company, which has an Oil & Gas Division in Calgary.

Traditional surface microseismic involves 5,000–7,000 geophones measuring actual frac completion during the brief two- to three-week treatment process, he notes, while Nanometrics typically uses 10–15 stations and continuously monitors the subject environment long term.

“What that allows us to do is capture a lot of the seismic activity over a period of time, which provides a lot of insight into the environment in which we are working. A sparse network is lower cost, requires fewer stations and is less intrusive on the environment.”

According to Spriggs, typical surface frac monitoring requires a lot of equipment densely instrumenting an area, which can be disruptive and may require line cutting. His company requires less obtrusive technologybecause it is only trying to answer a few key questions about the fracturing network.

“We provide our customers with a broader understanding of the environment in which they are operating, and we look for potentially larger events associated with natural seismicity and frac completions. With just a few of those events, we could drill down into the data and then tell a customer whether [he or she] found an existing fault and if the fracturing completion is moving out of zone.”

Nanometrics installs continuously monitoring, permanent networks, which provides immediate, real-time feedback on seismicity and the environment in which operators are producing. Using a smaller subset of data over a longer period of time, the network can answer broader questions such as whether a company is fracturing in expected volumes, or whether proppant and fractures could move out of zone along a pre-existing fault.

“On the list of 20 questions [companies] want answered, you have to bring a big, dense network in order to answer all 20,” Spriggs says. “However, if you only need answers
to the top five or six questions, then we can do that with a sparse network. The beauty is we can then do that on many, many more completions.”

Nanometrics takes many noise measurements in an area and models the whole environment, ascertaining key locations at which to place stations to meet objectives. Since the company is not placing its array randomly, it can design that array for the specific environment, yielding significant gains in signal-to-noise ratios.

The stations themselves use high-end, more sensitive seismometers as opposed to geophones. By placing such sensitive stations in quieter locations and at shallow depths, Spriggs says, Nanometrics achieves significant signal-to-nose ratio gains before monitoring even begins.

“We can use fewer [stations] because we use higher-quality instrumentation and a different approach to sampling the data. To answer the very detailed questions, we wouldn’t need thousands of geophones. Rather, we would use hundreds of seismometers. There is an advantage there.”

He adds, “There is real value in giving customers real-time and immediate feedback on what is going on, but I think what we are looking to do and what we are investing in
is the signal processing in order to basically define smaller and smaller events from sparse networks. We are investing in mining a sparse network for the richest catalogue we can get.”


Have fractures stayed in the reservoir or have they grown outside of it? Is the company wasting fracture completion costs breaking nonproductive rock that does not contain hydrocarbons? These are questions ITASCA Microseismic and Geomechanical Evaluation (IMaGE) strives to answer with its geomechanical models predicting where microseismic activity will occur.

“Our elevator pitch is we extract more information about the microseismic data being recorded so the clients can see more value from that data they are starting to collect,” says Shawn Maxwell, president and chief technology officer of the company, which has principal offices in Calgary, Houston and the U.K.

“The idea is to take these field observations of the snaps and cracks in the reservoir from the fracturing and try [to] take them to the next level—meaning instead of just taking an image that contains individual locations of microseismic events developed during the take these dots and you try conventionally to interpret them in the further fracture patterns that exist.”

According to Maxwell, there is a lot of value for operators simply in understanding the degree to which fracturing results impact geological variability and how much of the reservoir is actually contacted. “If you are looking at where to drill the next well to drain your reservoir, you have to know how far
out the first fractures have grown so you can decide how far away to drill to get uniform reservoir drainage.”

There is much guesswork in the engineering design of hydraulic fractures, Maxwell says, and IMaGE’s combination of microseismic monitoring and geomechanical simulations enables companies to determine fluid injection rates with test designs allowing different fracture stages on a horizontal well to be varied at each stage.

“You can look at the results and use the microseismic to decide which one is most effective.... If you adjust the rate, then you can find the optimal of where the fractures are contained to the reservoir.”

IMaGE performs most of its work on existing data collected from wells already fractured, simply because predicatively modelling reservoirs for real-time operations is problematic given the depth of geological variation and the big difference that even
a small change in the model can make, although Maxwell expects to see improvements in this area as well.

“Ultimately, we want to run it so the project is being done to make the real-time decisions,” he says, adding induced seismicity is another key area for his company.

“We have been involved in a few projects where there are basic questions and we are trying to assess the seismic risk. Rather than do it in real time, what we are doing there is running a number of models beforehand, and then we use those for pattern recognition based on the microseismic response to try [to] identify what the conditions might be that are riskier from an operational point of view as compared to others.”

According to Maxwell, his clients increasingly want to revisit microseismic data collected on existing wells that either never produced at expected rates or declined rapidly early on, thus facilitating recompletions—a cost-effective practice for companies looking to turn a profit during an industry downturn.

“There have been examples where you could come in and refracture a well, boost production significantly and pay for the costs of the second fracture after a relatively short time period. Microseismic becomes an important diagnostic tool to understand how the fracture system was there originally and how is has been redeveloped a second time.”

Working with existing standard microseismic technology, IMaGE is extending industry standards by using computer modelling that provides context and ultimately predictive models. Maxwell says, “Very much at its heart has been a lot of microseismic being collected, and we are seeing a lot of interest in going back to the existing data and trying to realize more value by gaining a better understanding of what it is telling us.”


Difficult as the current energy sector downturn is for companies and workers in the oil and gas industry, for Houston, Texas-based SIGMA3, it also provides an opportunity to accelerate technology investments as low commodity prices drive demand for greater levels of efficiency.

“The only way to address the next level
of productivity is through technology and innovation, and commercializing those technologies to the market,” says Machnizh. “We are really excited to be well positioned to take advantage of that.”

For example, the company’s CRYSTAL software includes broadband spectral inversion capabilities for resolution enhancement and specialized tools for natural fracture modelling. These enhancements allow users to better resolve structure, stress anisotropy, stratigraphy, texture, rock physics, total organic content, fracture density, porosity and permeability. Ultimately, this improves reservoir understanding and helps target the sweet spot to frac.

“When we perform a microseismic project, the processed data is delivered in the fully interactive CRYSTAL tool, which enables full analysis and interpretation,” Machnizh says, adding that companies can perform integrated analysis that includes the geological, geophysical and engineering information.

“Previously, as much as 40 per cent of frac stages were ineffective, at a huge cost. With fully integrated geo-engineering workflows leveraging microseismic, shale capacity and engineering, oil companies can achieve efficiency and better production, and remain competitive.

“The low commodity price is a new environment companies must deal with, and so adopting some of these concepts becomes really critical for survival.”

According to Machnizh, the company’s 3-D Shale Capacity model for brittleness, permeability, total organic content and natural fractures enables better plans to locate frac stages within specific surface wellbore locations. This can serve as input into simulations, enabling a predictive model as to how the fracture geometry will behave and the potential production of the well.

“Our clients are predicting production
with accuracy as high as 90 per cent. The
 Shale Capacity model, along with integrated geomechanical modelling and proper frac-engineering workflows, delivers increased levels of production. That becomes really important, because at a low-commodity price you can start deciding where to direct your efforts.”

Once hydraulic fracturing begins, SIGMA3 engineers ensure maximum returns on a company’s investment, using an integrated microseismic approach, to enable more accurate event location, as well as enhanced signal processing and detection algorithms. According to Machnizh, high confidence microseismic validates the models.

“That is the uniqueness of our workflow, and because this is our sole focus, it enables us to have a high pace of development and innovation in our company,” he says. “We have developed a foundation with various different types of analytical tools in order to bring in a workflow that addresses the very specific inefficiencies that exist in the marketplace.”

At SIGMA3, the preferred method of micro- seismic data acquisition is borehole monitoring, although the company has a unique way of acquiring the data, Machnizh says. “It all starts with the planning and modelling of what exactly we are trying to achieve and the data we are trying to record. We have a high-density recording system that acquires high-density data with the widest possible geometry.

“So, it starts with the data collection and planning, the customer’s technical and business objectives, as well as what are the answers they are trying to achieve.”

With technology acquiring high-fidelity data, he adds, SIGMA3 transmits the information to its Real-Time Centres and experts, who in turn collaborate with the customers
 to make decisions on frac geometries, where they go and, in some cases, allowing real-time decisions in order to optimize the frac.

Machnizh says, “We are collaborating now with some innovators to bring in some new microseismic technology that leverages the richness of the data we have been able to collect, really taking it to be able to match the fracture propagation as it occurs.

“That is really interesting...and I think in the next six to 12 months we will be commercializing some of these technologies. This is an opportunity.”


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