Explore the future of sand separation technology and learn about what makes Sandtinel sand separators different in this Q&A with Chris Johnston, Lead CFD Researcher at Sandtinel.

Question: What are the different types of sand separation technology currently available today?

Chris: There are several different kinds of sand separators out there. Traditionally the options have been an upright vertical cyclonic separator, a horizontal desander, a spherical baffle type separator, or a filter-based separator.

For the most part, these separators have been plagued with issues. Cyclonics turndown at low flow rates. Horizontal separators are a huge hassle to try to clean out. Baffle-type spheres have low storage capacity. These separators are less efficient than we would want producers to see, and are below the threshold of what we think the modern flowback environment demands.

When you use low efficiency sand separators you will require multiple units to try to capture the remainder which leads to problems of its own, like a very high back pressure on the well which reduces overall production.

Question: What makes Sandtinel technology different?

Chris: Sandtinel separators are unlike any you’ve seen before. They have the highest separation efficiency of any mechanical separator on the market. We target a minimum of 95% sand removal at a sand size of 100 mesh and larger – and we can prove it.

It’s common for our customers to remove all measurable sand from their lines, especially because Sandtinel separators do not experience turndown at low flow rates. They have a broad operating curve which allows them to defend your well across its entire lifespan. The units are simple to use and take only minutes to dump. They are safe, reliable, and see virtually no internal erosion or wear because of our Vapor Lock Technology.

Question: How does the VL-TEK™ Vapor Lock Technology work?

Chris: The Vapor Lock Technology inside of a Sandtinel temporarily breaks apart a high velocity multiphase flow so that the gas can be segregated from the rest of the fluid. We’ve found that the gas phase is typically the main driver of the velocity of the flow – often 95% to 99% or more of the superficial velocity of the flow is due to the gas. But it’s typically the remaining 1% to 5% of the liquid which is carrying the sand in it as a slurry. By isolating and temporarily separating the gas from the system, we can slow the flow down and remove the sand very effectively from the liquid phase. The flow recombines at the outlet of the vessel so that from the outside, there is no interruption or change to your processes. We knock the sand into the bottom of the sphere, where the Sand Lock technology traps it prior to periodic dumping.

Question: There’s a lot of talk about how technology is essential to working towards emissions reduction. How does Sandtinel technology help?

Chris: Substantially reducing emissions requires a multi-pronged approach tackling many different parts of the problem. From the perspective of sand separation, what we’re usually talking about is the fugitive emissions released from the sand separator when it’s being dumped. When you’re dumping a large volume of sand slurry, you’re going to get some amount of gas and oil coming out at the same time. If you’re dumping to an open-top tank, as is pretty typical, then that gas is going to be released into the atmosphere. One of the benefits of the Vapor Lock design is that because we are isolating the gas away from the liquid, there is very little agitation of gas into the bottom of the vessel. We’ve estimated some pretty huge reduction in fugitive emissions compared to current technology like cyclones which depend on that agitation to achieve sand removal.

Question: The safety of the environment and people are a priority onsite. How are Sandtinel separators safer than other sand separation technology on the market?

Chris: The main benefit Sandtinel offers is avoiding exposure for operators by providing remote or automated dumping options. Sandtinel separators do not need to be opened up and cleaned out, serviced, or have elements changed out while in the field. They don’t contain sacrificial elements, interchangeable inserts, or filter mechanisms to clean. Instead, operating the unit is as simple as turning the valve at the bottom drain for a minute or two for each dump, not only saving the operator time during their day and reducing the downtime on the well, but also keeping them out of the red zone for longer. Our automated dump solution, the Sandtinel Dispatcher, is a single or multi-well autodump skid package that operates the separators remotely or on a timed basis. We take safety seriously and are always looking for ways to create smarter and safer technology to tackle new challenges in sand removal.

Question: What are some of the challenges that operators are facing in the field?

Chris: We’ve found that the modern flowback environment is becoming more challenging for sand removal and more demanding. There has definitely been a change in mindset to open wells as aggressively as possible, and operators and producers want sand separators that can keep up. If you need to throttle your well just to go through your sand separator, then that starts to become a business decision about how much erosion you can tolerate without a sand separator to maximize your production. Fundamentally, we don’t want a sand separator to be holding you back from getting the most you can out of your well.

Aside from that, we’ve also seen some shifts in mindsets in the last few years for the kind of sand which is being used, moving from the best possible frac sand to sand that can be easily sourced. A lot of this is sand that breaks down more easily (e.g. not resin coated). So the push has been for sand separators that can handle more of the small stuff, the fines, and which can do it at higher flow rates, higher gas rates, and tougher conditions. We believe the Sandtinel is the best overall solution for those needs.

Question: What kind of operation would benefit from using a Sandtinel separator?

Chris: Sandtinel separators have been used on a wide variety of operations, from initial drill-outs, all the way through to long-term production. We have a pretty wide fleet of equipment for different needs, including 10K spheres for high pressure operations, our G4 Maverick series for trouble wells, and our 96” Generals for group well applications. Our main goal is to make sure you have the right sand separator for the job. We never want you to have a sand separator you don’t need, and we always want to make sure the unit is providing value while it’s out on the job. We believe that data is king, and that collecting as much information from the field as possible will ensure you can make the operational decisions you need to use our equipment effectively.

Question: It’s not a secret that Sandtinel separators cost more than some other separators. Can you speak to the value of a Sandtinel?

Chris: Sandtinel spheres can cost more up-front, but customers are paying for over 10 years of experience and game-changing technology which not only replaces multiple pieces of existing equipment, but surpasses them. If you’re using traditional cyclonic separators, it doesn’t matter how many of them you put in a row off your well – you’re never going to be able to achieve the same level of efficiency you would get with a single Sandtinel. We’ve always tried to look at the big picture when it comes to the cost of equipment – the cost of not using a sand separator in damage to valves and chargeback; the cost of downtime and operator time when cleaning out equipment; the cost of lost production due to the high back pressure across a hydrocyclone. Sandtinel’s vortex separators are the top of the line when it comes to sand removal, and we have found that their substantial benefits pay for themselves many times over in protecting your well.

Question: As needs continue to evolve, what is Sandtinel doing to keep up and stay on the cutting edge of technology?

Chris: We have an R&D center of excellence which continuously works to develop new solutions to meet customer needs, like our automated Sandtinel Dispatcher. At the same time, we’re working on other cleaner, greener, smarter, and safer solutions to the problems we hear about every day. We support our equipment in the field with industry-leading fluid dynamics modeling, and are constantly working on new products to meet the challenges operators face.

Energera COO David Sobernheim explains the role sand plays in the fracturing process and how Sandtinel separators work to eliminate it from production streams.

Question: How and why did sand make its way into the fracturing process?

David: Sand is the predominant class of proppants used in hydraulic fracturing stimulation, which first began in the 1940’s. A second step-change in sand volumes (the first being tight gas fracturing in the 1970’s) came with the advent of advances in horizontal drilling and multi-stage fracturing beginning around 2002 and really starting to take off in 2005, through to the present day.

The shale revolution, or the “shale-gale,” as its sometimes termed, was when we started pumping millions of pounds of sand into horizontal wells to create “superhighways” of high conductivity production flow into the wellbore. Somewhat analogous to Eisenhower’s interstate road system build-out of the 1950’s, which vastly improved transport in the US. That's hydraulic fracturing, and an analogy for you. The magic behind unconventional extraction is you can take very low permeability rocks, traditionally non-economic, put away a lot of sand, and suddenly you have proved reserves (economic) from previously uneconomic resources in place.

The flip side of pumping these large volumes of sand into a horizontal wellbore is after-stimulation: when you clean-up and flow the well, you'll have sand flowing out of the wellbore. That can cause a lot of expensive problems with your flowlines and production equipment. The good news is that there are solutions available to help.

Question: What are the different types of sand and why is it so important to know what you’re working with?

David: For many years, operators didn’t use sand, but rather ceramic particles, factory produced proppants that acted like sand, but are higher strength. These were more expensive and led to higher costs. Today, most operating companies have moved to sand and generally view near-wellbore duning and large volumes as sufficient to overcome impacts of proppant crushing in ultra-low permeability rocks. The wholesale move to sand, with rare exception, has led to lower costs and higher early productivities in unconventional rocks.

What is important about using sand is getting the perforating strategy, stage size, volumes, schedule, and prop size right. Generally, to get the best flow capacity of the sand, you need a relatively uniform particle size. So, you want a certain micron range size of your sand. Most wells these days are stimulated with what's called hundred mesh sand, a range of 70 to 140 mesh size, which is what the American Petroleum Institute (API) uses. So, it's a range, but it's all around 150-micron grain size, roughly. And that's kind of the status quo or the best combination of permeability placement and flow capacity. In “higher” low permeability reservoirs, 40/70 mesh range is often used as a portion of the treatment.

Very fine sand or crushed particles are generally harder to separate when it comes back in the flow stream, whereas more coarser particles in 100 or 40/70 mesh generally are much easier to handle the separation process with. So, when we do our CFD modeling, knowing the typical size range of the sand that's coming back out of the well, as well as the density, which for quartz is 2.65 is pretty typical. We like to get samples from the well and run a laser diffractometer analysis to nail down the particulate size we’re dealing with.

If you were using a ceramic proppant, as we call it, a factory-made proppant, those can be heavier weight, like in deep offshore, high-pressure wells. Here operating companies might use sintered bauxite, which is 4.2 specific gravity, much heavier than sand. So, we do need to know the density and the size to do the modeling and make sure we size our equipment properly for what's going to come back out of the well.

Question: What makes sand challenging to work with?

David: A lot of the understanding of how much sand you're going to get back from a particular formation, a particular reservoir bench in a particular area, depends a lot on the hydraulic fracturing technique such as what concentrations you're pumping into the wellbore and the volumes. There's a lot more art than science behind sand flowback prediction currently, but we expect that to change with greater digital sand measurement technologies and data science.

So, it's an area we need to learn more about. Today an operating company can have one well making 200 pounds of sand an hour and another well nearby that's making 3 pounds an hour. So, we must be able to handle a range of capacities in terms of what might come back as our sand separation solution and be agile when working with operators and the diversity of their needs based on what the well is producing.

Question: How does sand impact wear and tear on equipment?

David: You're dealing with an abrasive sand-laden fluid in a high-pressure environment which can abrade valves, pipes, equipment, and cause potential for pressure releases and spills because of that abrasion effect. If you're putting sand into tanks that are designed for water, oil or natural gas and you get a bunch of sand in there, that's not a good thing. Sand degrades equipment over time and left uncontrolled you're going to be washing out choke manifolds and pressure equipment piping, sending sand into separators and equipment that's not designed for sand, filling it up and eventually causing blockage and stoppage. This can create a huge safety hazard for any person in the area. It can be dangerous and expensive if you don't remove the sand from your flow properly.

To protect your facilities, you need to have a robust sand separation solution that’s going to minimize erosion effects and potential safety events. It's an important category that's gotten more important as stimulation designs have become more aggressive with more and more sand and water pumped into these wells. Additionally, aggressive flowback of wells, which typically leads to better economics, produces more sand from the well.

Question: How does Sandtinel mitigate that impact?

David: Our VL-TEK™ Vapor Lock Technology is unique in this space, and it's a highly effective sand separation technology that doesn't require any filters or other moving parts. It creates a barrier of gas in the upper part of the hemisphere and a settling area in the lower hemisphere that allows for a long settling path for sand and water while the hydrocarbon and gas is handled in the upper part of the vessel. This unique hydrodynamic effect allows for a very effective separation of sand from the hydrocarbon and water stream coming out of the wellbore, minimizing any entrained gas or liquid hydrocarbon in the sand laden water.

Our vapor lock design also yields a minimal pressure drop across the sand separator. This low delta-P means that you are not holding back your well’s productive capability. Sand can be handled with 95% plus separation efficiency across a range of flowrates, from high to low, with no diminishment of performance, with our technology.

Question: What happens to the sand once it's separated?

David: The sand is separated into a gentle settling area in the lower hemisphere of our vessels which will capture up to 600 pounds of sand, on a 48” vessel, depending upon flow conditions, before requiring draining. When we drain the vessel, the bottom of the vessel is opened via a valve while we're still flowing through the top. Pressure is used to push the sand and water out of the bottom of the hemisphere into a sand handling tank or other sand storage device while still flowing the well in a safe and controlled manner with minimal fugitive emissions.

Question: How does Sandtinel reduce emissions during production?

David: When you're separating the sand out from the flow stream, it's going to accumulate in your separator and there comes a point where you do need to drain the sand out. With Sandtinel units, we have a gentle, long path settling area for the sand in the lower hemisphere below the vapor lock. This allows for the accumulation of sand and water in the lower hemisphere and you don't have the gas bubbles entrained in the water - just sand and some water that's being pushed out to a tank.

Question: How are Sandtinel separators safer than other separators?

David: Taking the sand out of your flow stream is important for general pressure integrity and facility protection and not having problems with pressure or fluid releases. Sandtinel vapor lock separators safely and effectively handle particle separation over a broad operating curve determined by computational fluid dynamics (CFD) modeling.

The only time you need an operator at a Sandtinel vessel is when you're draining (dumping) the vessel. And that's generally just a 15 to 20 second process of opening a valve at the bottom and then closing it. That's the limit of the exposure that the operator must be in the high pressure during the dump cycle. Pressure areas are typically called the “red zone” and it is a best practice to try and keep people out of these pressurized regions wherever possible.

New technologies including the Sandtinel Dispatcher automated dumping system which will remotely operate those valves and take care of the dumping process for you. This means no operator is required during that process, reducing exposure to zero and mitigating any safety hazards of the red zone.

Question: What are some of the factors operators should consider when choosing a separator?

David: A lot of times operators may not know how much sand the well will produce. And so, one challenge is the size of flowback iron they should use. Do they need to have more than one Sandtinel out there? Parallel separators? A series of multiple separators? What size of flowback iron? 3”? 4”?

The configuration can vary quite a bit and obviously impacts cost, trucking, personnel, and other factors that affect your bottom line and budget. What’s important is that we take our time from the outset and get it right the first time, because if you get it wrong, it's going to cost more money to correct that error.

We typically will request a “pre-install” datasheet, with such items as expected pressures, flowrates, sand type, and other pertinent data with which a CFD operating curve is constructed. Additionally, a post-install CFD model is run to validate the configuration with exact well data and sand diffractometer analysis of the flowback particulate concentration and size range.

Question: What kind of operation would benefit the most from using Sandtinel?

David: Just about any hydraulically fractured unconventional well completed today will have sand in the flow stream. So, all unconventional basins where horizontal well drilling and multi-stage hydraulic fracturing is deployed can benefit from Sandtinel technology (Permian, Eagle Ford, Haynesville, Mid-Con, Bakken, Powder River, Marcellus/Utica, Montney, Duvernay). These reservoirs are very sand prone following the fracturing treatment. In addition, unconventional basins in Argentina and other areas of the world where operators are becoming more active such as in Australia, China, and the Middle East are starting to see the benefits from effective sand separation in the production stream.

Operators who demand the highest possible sand separation efficiency, simple operation, minimal fugitive emissions, minimal back pressure, low variable costs, small footprint, and a broad operating curve are typically the ones who benefit most from our vapor lock sand separation technology.

Learn how Sandtinel technology optimizes separation and prevents equipment degradation in this Q&A with Chris Johnston, Lead CFD Researcher at Sandtinel.

Q. Let’s start with the basics - what is sand?

A. Sand is a blanket term that covers a wide range of different types of granular solids. Most sand has a big component of crystalline silica, or quartz.

Q. What are the different types of sand and why is it important to know what type you’re working with?

A. There’s all sorts of different types of sand, like river sand taken from river banks, concrete sand made from crushed concrete, and even manufactured sand which production companies smash and crush from larger rocks. We are most interested in frac sand which is made from high purity sandstone, and is pretty pure crystalline silica, or quartz.

Q. Why and how is sand used in the fracturing process?

A. In the fracturing process, frac sand is mined before it’s transferred to a wet plant to remove all the silt, debris, and other contaminants from it. It gets dried and screened in a dry plant before being sent to site. During the drilling and completion process, a rig drills a hole several thousand feet down, then turns 90 degrees and drills through a layer of shale; this is the wellbore. A pressurized mix of water and frac sand are forced into the well which fractures perforations in the shale layer. This releases hydrocarbon liquids which flow up the wellbore to the surface.

Q. Is there a difference between the sand that’s in-situ and sand used in the fracturing process?

A. There definitely is. There’s a mix of sand that returns to the surface along with the oil that needs to be safely and effectively separated. The frac sand is usually high quality and very hard so it maintains its shape well. If it’s coated in resin during its production process, it will be even more durable to stand up to large stresses. However, that’s not the only source of sand in the mix. There’s also formation sand that breaks off underground which can come up through the wellbore as well. This is usually based on the geographic region, and it has all the impurities and other minerals which are screened out of frac sand. This formation sand usually breaks down a lot more, getting crushed up and broken into needle-like fragments.

Ultimately it is a mix of frac sand and formation sand which we need to deal with for sand removal.

Q. What makes sand challenging to work with/remove?

A. Sand has a tendency to get everything and can be extremely abrasive, especially at high velocities. Once it gets into your system it will accumulate everywhere – strainers, tanks, elbows, seals – and pretty much anywhere else the fluid touches.

Sand is measured in “mesh size” which is sort of like the fineness of a filter that would let the sand pass through it. But in reality any given sand blend has a huge range of different sizes. Knowing the frac sand blend (often 100 mesh) doesn’t tell you what size the formation sand is that’s coming back, nor does it tell you how the sand might have broken down during fracturing.

One of the challenges we face is that as sand has grown in demand, companies use whatever sand is available instead of the perfect grade of frac sand. This lower quality sand causes issues with removal afterwards. Smaller sand, getting down to “fines,” can be really challenging to remove by mechanical means (without the use of a filter and without external power, chemicals, etc). Bigger sand causes more damage, but smaller sand is harder to catch because it builds up everywhere and can be expensive to remove.

The trends we have seen are for producers to try to open their wells more aggressively and as quickly as possible because that’s been seen to maximize production. However, that also often ends up pulling more sand out of the wellbore, which needs to be effectively dealt with on the surface before it wrecks all of your equipment.

Q. What are the risks that come with sand separation?

A. Sand separators are safe pressure vessels as long as they are built and maintained properly, and receive regular NDT to ensure their ongoing integrity. The biggest risk is that it might not work effectively for you to remove the sand you’re hoping to remove. Other problems that can arise include:

•  Fugitive emissions released during dump processes
•  Plugging up with sand so that it can’t be cleaned out
•  Experiencing high back pressure holding back your production
•  Slugging and surging in the separator causing a cyclical “pull” on the wellbore which increases the sand production

Q. How does Sandtinel technology mitigate these risks?

A. Sandtinel sand separators have a very wide operating curve to match the operating conditions over the entire lifespan of a well so that you don’t need to be constantly changing out separators or inserts. There are no sacrificial elements like filters to replace or any external power requirements, making it a very simple piece of technology to incorporate into your process.

Sandtinel spheres provide high separation efficiency, targeted at a minimum of 95% sand removal for sand of 100 mesh and larger. Fugitive emissions are extremely low on Sandtinel separators as a consequence of the Vapor Lock technology in the vortex separator design. They also experience a very low back pressure and do not pull on a well, resulting in a sand separator that gets out of your way and lets you operate your well the way you want to.

Q. How does sand affect the degradation of equipment?

A. There are different approaches to dealing with the risk of sand erosion but some producers have given up on finding a sand separator that will really work for them, because there have been so many false promises in this field in the past. In fact, it’s common for sand separator vendors to just claim 99% or 100% sand removal with no data and nothing to back that up.

We’ve done some modeling to understand the effect of sand on erosion for pipe walls. It’s hard to quantitatively prove how effective sand separators are, so it doesn’t become apparent that these are false promises until you see the damage afterwards. This is why we are so excited not just to bring a new sand separator to the market which can handle the modern flowback environment, but to be able to prove it with extensive case studies, modeling, and data collection in the field.

This is why we are so excited not just to bring a new sand separator to the market which can handle the modern flowback environment, but to be able to prove it with extensive case studies, modeling, and data collection in the field.

Q. What happens to the sand once it’s been separated?

A. That depends on local practices and regulations. But in general, sand collects inside of a Sandtinel separator until it’s drained. The liquid sand slurry is sent to a downstream holding tank, or blowdown tank. We can use load cells and/or guided wave radar to monitor the collected sand, and then when it’s full, you would get it emptied out and disposed of safely.

Q. What makes Sandtinel spheres unique from other separators?

A. Sandtinel sand separators are a style of “vortex separator” which use patented Vapor Lock Technology to isolate gas in the upper hemisphere of the vessel. They’re radically different from other spherical separators which typically use a deflector baffle to try to knock sand out of the incoming fluid. By temporarily isolating the gas, we drastically slow down the liquid which has the sand entrained inside of it, providing a really long settling distance and retention time in a pretty small footprint (our separators are typically 48” inner diameter spheres). The Vapor Lock system also significantly reduces fugitive gas emissions during dump operations compared to other sand separators and experiences very little back pressure across the unit. Sandtinel separators provide the highest sand separation efficiency possible using mechanical means, aiming for a minimum of 95% sand removal at a sand size of 100 mesh and larger, over a broad operating envelope.