What a wild year, while things may have slowed down for the industry in general new ideas and research has been published and there are some revolutionary new technologies now available to the Canadian oil and gas industry which could have major implications on how we complete our wells and on profitability. I will begin by briefly outlining the results of the core through studies performed by Warpinski in 1993 and more recently in the Eagle Ford and Midland Basin Texas. After I will discuss insights gained from the GTI 2019 HFTS 1 and the results published in SPE-194340: The Role of Micro-Proppants in Conductive Fracture Network Development. Lastly, DEEPROP® which Labsite Inc is making available to the Canadian Oil and Gas Industry will be discussed.
Studies performed by Warpinksi et al., 1993 discovered that our hydraulic fractures are not necessarily simple bi-wing fractures as we’ve often thought but can be complex hydraulic fracture swarms. A four-foot sample of core in the MWX, Piceance Basin exhibited over 30 hydraulic fracture strands while core samples taken in the Eagle Ford and Midland Basin in Texas showed 7 tightly spaced hydraulic fracture strands and 8 tightly spaced hydraulic fracture strands in 2.5 ft and 3 ft core samples, respectively.
Hydraulic Fracture Swarms, MWX Piceance Basin (Warpinski et at.,1993).
Hydraulic Fracture Swarms, Eagle Ford Formation, Texas (Raterman et al. 2017).
Hydraulic Fracture Swarms, Midland Basin Texas.
Experiments conducted by U.S Department of Energy, National Energy Technology Laboratory, GTI and Laredo Petroleum have shown with core through experiments that there is high variability in the morphology of hydraulic fractures, creating complex breaks, irregular patterns and stepping planes along with smooth planar features. This would imply that proppant may be forced to take a very tortuous path which can have implications with regards to proppant placement, propped fracture area, screen outs and, ultimately on production.
Hydraulic Fractures in Core (GTI, 2019)
If hydraulic fracture swarms are generated with very complex features, where is the proppant going? The answer is that some of these fractures will receive proppant but most of them won’t, proppant placement is constrained by the physics of proppant transport and selection of proppant sizes. This was proven in the GTI, 2019 experiment which is illustrated below where we can see a huge distribution of natural and hydraulic fractures in the GTI core but a very narrow band of fractures that received proppant. What’s also noteworthy is that we see a larger distribution of smaller proppant, 100 mesh, which illustrates the ability of the smaller proppant to enter more fractures and/or possibly for the smaller proppants to be carried further.
Hydraulic Fracture, Natural Fracture and Proppant Distribution (GTI, 2019).
The theory that smaller proppants are transported further and can enter narrower fractures was supported by modelling performed by the University of Oklahoma and published in SPE-194340 where an advanced 3D simulator “GeoFrac-3D” was used to study the transport and deposition of micro-proppants in propagating fracture networks. The results demonstrated that micro-proppants yield more uniform proppant distribution, have the ability to be carried further and can enter smaller fractures. This results in a relatively higher effective propped area as compared to the larger sized proppants.
DEEPROP: A Revolutionary Way to Prop your Fractures
DEEPROP® is a ceramic micro-proppant whose small diameter allows it to be carried further into the reservoir and allows it to enter smaller fractures. Typical proppant sizes range from 20/40 to 100 mesh which can prop fractures that are between 2.48mm to 0.91mm in width. DEEPROP® can prop fractures that are 0.21mm in width or about the width of a human hair, providing a huge opportunity to prop more fracture area.
To date DEEPROP has been trialed in 5 major U.S shale plays, the Permian, Woodford, Utica, Barnett and the Marcellus. Trials are currently being conducted in the Bakken and the Eagle Ford with initial results showing promise. 4 of the 5 plays have shown significant uplift in total production, unfortunately the Marcellus Shale showed no noticeable benefit of using micro-proppants. It was determined that this was due to the unique stress regime that exists in the formation which limits the micro-fracture structure preventing the development of any degree of fracture complexity. However, the other 4 plays have shown amazing results with an average uplift of 25%-50% in total production.
*Calculated using 45$/bbl & 2.50$/Mcf
*Data collected using FracFocus & Navport, Oklahoma Tax Commission and operating companies
What are the possible mechanisms driving this success? The proposed mechanisms are increase in effective propped fracture area which is critical, according to basic hydraulic fracturing theory for producing from tight plays. The second is near wellbore scouring, third is far field diversion and finally and (possibly most importantly) a reduction in convergent flow effects during production. In discussions about micro-fracture networks and fluid flow with Richard Baker, a world-renowned reservoir engineer with over 37 years of practical experience in reservoir engineering and simulation, one of the most profound statements he made (in a conversation with many profound statements) was that “he would take fracture complexity over length any day of the week in low permeability rock”. His statement was supported by work performed by another legend in the oil and gas industry, Carl Montgomery and the technical team at NSI Technologies, where they performed simulations to measure the affect micro-proppant would have on production and reservoir drainage from models with discrete fracture networks. The results are published in SPE-199741-MS and the simulations results are shown below. In summary, the observation was that the micro-proppant increased the permeability of the unpropped fracture by a factor of 10 times, this resulted in more effective reservoir drainage and a higher EUR.
Propped DFN Simulation Results for Barnett Shale (Montgomery et al, 2020).
By creating and propping micro-fracture networks our designs begin to follow the constructal law which is the statement that for a flow system to persist in time it must evolve in such a way that it provides easier access to its currents. By propping our discrete fracture networks or by propping the complex fracture networks that we are creating, we’re allowing the flow system to persist longer in time by providing a more efficient means of transporting the fluid. Below are some examples of flow systems in nature that have evolved or behave in such a way as to provide easier access to their currents. The structures should appear similar to what we’ve seen previously from the core samples taken at GTI 2019 HFTS #1.
This phenomenon is evident in the production profiles of the wells that have been treated with DEEPROP®. Production tends to decline far more slowly while gas oil ratios remain stable for longer periods. This would indicate a more efficient use of our reservoir pressure. This could also provide slower liquid dropout in dry gas wells and slower development of mobile gas in oil reservoirs, which would impact how quickly relative permeabilities change over time. Below is an example of the production profile and gas/oil ratio profile that we’re seeing in trial wells, this example is from a Woodford 9 well study with 3 wells treated with DEEPROP® vs 6 wells treated without.
Now I know what you’re probably thinking to yourself, “Charles, this isn’t a new idea. We’ve already tried pumping micro-proppants and we saw no uplift in our production”. I have heard this from people in the industry when I’ve mentioned the idea of pumping micro-proppants. What I’d like to point out is that there is a difference between DEEPROP® and what’s historically been considered micro-proppant, which is fumed silica or silica flour. I have not been able to find any conductivity data for fumed silica or silica flour proppants that are on the micro-scale. Often, when we’re considering the importance of dimensionless fracture conductivity for low-perm micro or nano-darcy reservoir, we’re not concerned with exactly what the conductivity of the proppant pack is; as something is often enough to provide flow capacity to the wellbore. But when we consider micro-fractures and micro-proppants it begins to become more important because the dramatic reduction in proppant size and fracture width have a dramatic affect on the fracture conductivity, in fact it can become so low that the matrix may become more effective at transporting the fluid than the proppant pack.
Traditionally ceramic proppants outperform by orders of magnitude over their silica counterparts when it comes to conductivity. I would propose that the silica micro-proppants used in the past provided such low conductivity that the formation fluid preferentially flowed through the matrix or that the proppant pack became damaged so quickly that there was no production benefit governed by using them. While there is no published conductivity data on silica micro-proppants, extensive conductivity testing on DEEPROP® has been performed and we’ve proven that it maintains a relatively high degree of conductivity even at a mono-layer packing arrangement. This is due to its perfect spherical shape and high crush resistance. We don’t need a lot of conductivity for low perm reservoirs, but we need something and DEEPROP® provides something on the micro-scale.
How does this work using the most basic design principles? Here is a thought experiment, lets assume that the micro-fracture network is a subsystem of an entire wellbore-fracture system. Where the micro-fractures are to the primary fracture what the primary fracture is to the wellbore. If we scale things down and assume a primary fracture diameter of 1.51 mm (.005 ft) and drainage radius of 100 ft and propped micro-fracture half lengths of 5 ft, 10 ft and 20ft in micro-Darcy perm reservoir (0.001 mD) and using a proppant pack conductivity values for DEEPROP® of 0.3 mD-ft and assuming an order of magnitude difference for silica micro-proppant we have 0.03 mD-ft, we get the results displayed below. What’s worth noting is that the longer the micro-fracture half lengths become the more important it is to have a large (relatively speaking) proppant pack conductivity to maintain a high FCD. This means that the further the micro-proppant travels into the formation, the more important it is to have a micro-proppant with higher conductivity. Traditional proppants deliver high proppant pack conductivities on the order of hundreds-thousands of mD-ft so to balance the FCD’s to achieve the optimum design of around “10” (for unconventional reservoirs) we try to create as long a fracture as possible.
Now with micro-proppants, the proppant pack conductivity is already very small, so if we have a very long micro-fracture half length our FCD becomes very small, and we create an inefficient design. Below we can see this effect where I’ve increased the micro-fracture half lengths and calculated the FCD and corresponding FOI. We can see that the FOI for running the silica micro-proppant does not increase as efficiently as the FOI for DEEPROP®. The reality is I have no idea how long micro-fracture half lengths are, but simulations predicted 10-20ft for 200 mesh. By design we want to carry micro-proppants as far into the formation as possible so it’s critical to have a micro-proppant that has a high conductivity. I honestly believe I’m being very generous by giving the silica micro-proppant a conductivity of 0.030 mD-ft. Just as an exercise I lowered the silica micro-proppant pack conductivity by another order of magnitude to 0.003 mD-ft. As you can see the effective well-bore radius becomes so small that it’s ineffective. Finding a balance between micro-proppant size, transport-ability and conductivity appears to be critical to successfully utilize micro-proppants.
There are some limitations to where DEEPROP® can be effective, as I mentioned before there have been 5 U.S. shale plays where DEEPROP® has been trialed, it has been successful in 4 of them. A 16 well study on two pads with 6 wells treated with DEEPROP® was conducted in the Pennsylvania Marcellus while a 14 well study on 4 pads with 7 wells treated with DEEPROP® was conducted in the West Virginia Marcellus. The results showed no noticeable production difference between the wells pumped with DEEPROP® versus the offset wells. Subsequent modelling work has shown that the stress regime in the Marcellus is relatively isotropic which doesn’t allow the development of a complex fracture network. So, for DEEPROP® to be successful we need to be either developing a complex fracture network or be dilating a natural fracture network during our treatments. Other considerations are permeability and rock stiffness, for DEEPROP® to be successful the formation permeability should be less than 5µD and the rock modulus should be greater than 17GPa to prevent embedment.
The results of pumping DEEPROP® in U.S . have been astounding. DEEPROP® has been run in over 200 trial wells in 5 major U.S shale plays over 3 years and the results have been presented at SPE and HFTC conferences. Below is the most recent production data from a three-year study that’s just concluded in the Ohio, Utica. The study consisted of three 44 stage wells, one well treated completely with DEEPROP® in every stage, one well completed partially with DEEPROP® in approximately half the stages and an offset well that was completed without DEEPROP®. It’s clear that the production declines much more slowly for the wells treated with DEEPROP®. The well treated completely with DEEPROP® outperforms the partial and offset while the well partially completed with DEEPROP® also outperforms the offset. The difference in cumulative production was phenomenal with the well completed with DEEPROP® producing 49,675bbl more liquids and 334,772 mcf more gas at the end of the study (943 days) versus the offset without DEEPROP. At $45.00 USD/bbl and $2.50 USD/mcf this is a production value of $2,235,375 USD in liquids and $836,930 USD in gas versus the offset for an investment of $130,000 USD in DEEPROP®. This is an ROI of $23.60 USD per $1.00 USD spent on DEEPROP®. Sure, I haven’t applied a discounted ROR but still, good luck finding a better return on investment in oil and gas.
What does this mean for the Canadian oil and gas industry? We have an opportunity to apply this technology early in the development of our unconventional shale plays, potentially maximizing our recovery efficiency and profitability. If the results from the U.S are repeatable in Canadian plays, what could that look like? Well I’ll use Paramount Resources data as it’s easily accessible via their corporate presentation. Assuming a 1000 day cumulative liquid production of 400,000 bbl and 800,000 boe or 2,400,000 mcf of gas production, a 25% uplift would be an additional 100,000 bbl in liquids production and 600,000 mcf of additional gas production. Assuming $45.00/bbl and $2.50/mcf this could generate an additional $6,000,000.00 in production value, if the results are equivalent to the U.S trials. For Paramount Resources, the completion costs are $650.00/tonne of proppant pumped, with a total cost of $4.1MM/well, this would give a total proppant tonnage of approximately 6,300 tons/well. For utilizing DEEPROP®, we recommend replacing 2.5% of the total proppant mass with DEEPROP®. This would give a DEEPROP schedule of 157.5 tonne’s which would require an investment of approximately $250,000, a small investment for a potentially huge payoff, $6MM, which is more than their total completion costs. This isn’t even considering the potential offset in savings of pump time or horsepower costs if DEEPROP® can deliver a 1000psi to 1200psi reduction in surface treating pressure, similar to U.S trials.
If you’re interested in learning more about DEEPROP® you can get in touch with me at 1-403-682-7552. Lab Site is the official representative for DEEPROP® in Canada and we’d love to work with you to explore the possibility of applying this new technology to your play here in Canada. I’ll leave you with that!
Thank you for reading!